Asian Power (January - March 2022)

Issue No. 103

ISSUE 103 | DISPLAY TO 31 MARCH 2022 | www.asian-power.com | A Charlton Media Group publication

INDIA

IS AGGRESSIVE IN PRIVATISING

Asian Power

DISCOMS

MOST PUBLIC DISCOMS ARE ON THE VERGE OF BANKRUPTCY BECAUSE OF HIGH AT&C LOSSES AND POLITICAL POPULISM INNOVATIVE POWER PROJECTS AND INITIATIVES RECOGNISED AT THE ASIAN POWER AWARDS 2021 HOW DOES CHINA’S PLANS TO STOP BUILDING COAL POWER ABROAD AFFECT COUNTRIES RELIANT ON COAL? HOW SINGAPORE’S FIRST DIGITAL TWIN ATTEMPTS TO PREVENT POWER GRID FAILURES HOW CAN INDONESIA DECARBONISE AMIDST EXPECTED ENERGY CONSUMPTION GROWTH?

US$360P.A.

FROM THE EDITOR

I

n this issue, we highlight the ongoing net-zero goals and sustainability initiatives of the Asia-Pacific region.

After the UN Climate Change Conference (COP26) in October brought together world leaders to accelerate action towards these goals, the spotlight is on APAC governments leading the charge on renewables investments and energy transitions.

PUBLISHER & EDITOR-IN-CHIEF Tim Charlton PRODUCTION EDITOR Janine Balleteros PRODUCTION TEAM Djan Magbanua Jeline Acabo Tessa Distor Vann Villegas Charmaine Tadalan GRAPHIC ARTIST Simon Engracial

ADVERTISING CONTACT Reiniela Hernandez

Vietnam returns to coal power, which puts the country’s renewable energy transition at risk (page 14); Singapore’s Energy Bill sparks concern amongst stakeholders (page 16); and The Philippines is poised to lead Southeast Asia in sustainability efforts (page 24).

reiniela@charltonmediamail.com

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We sat down with Barnik Maitra, Managing Partner in Arthur D. Little, discussing India’s move of aggressively privatising discoms, which are on the verge of bankruptcy because of aggregate technical and commercial losses and political populism. See the full interview on page 30.

We cover the Singapore International Energy Week where representatives discussed climate ambitions and clean energy transitions in Southeast Asia. See the full event coverage on page 32. We also recognise the ground-breaking projects and trailblazing initiatives in Asia’s power sector at the Asian Power Awards 2021. See the full list of winners on page 40.

Read on and enjoy!

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ASIAN POWER 3

CONTENTS

30

CEO INTERVIEW INDIA IS AGGRESSIVE IN PRIVATISING DISCOMS

20

GENERATION REPORT WIND POWER FINDS NICHE IN ASIAN MARKETS, FITCH REPORTS

24

COUNTRY REPORT THE PHILIPPINES IS POISED TO LEAD SOUTHEAST ASIA IN SUSTAINABILITY

INTERVIEW

FIRSTS 08 China needs RMB200t to reach net-zero by 2060

18 Quezon Power supply deal extension in limbo

09 Power supply crunch in 2022 looms in the Philippines

26 Scaling up India’s storage capacity will be slow: IEEFA

10 PacificLight’s 100 MW solar import project

28 Direct PPAs should be scaled up: Asia Clean Energy Partners

11 ADB ID, PH team up for ETM launch

VOX POP

EVENT COVERAGE 32 Emerging and developing Asia needs to increase RE contributions by 50%

12 How do China’s plans to stop building coal power abroad affect countries reliant on coal?

33 Should governments invest in available technology today to reach net-zero?

34 Carbon pricing of $75 per tonne to ‘shock’ global economy: ADB

REPORT & REACTION 14 Vietnam’s return to coal puts renewable energy transition at risk

35 How Singapore’s first digital twin attempts to prevent power grid failures 36 How can Indonesia decarbonise amidst expected energy consumption

LEGAL BRIEFING 16 Will the energy bill reduce competition in SG’s electricity generation market?

growth?

38 Bidding thermal power goodbye? It will be a long journey 40 Innovative power projects and initiatives recognised at the Asian Power Awards

Published Quarterly on the Second week of the Month by SG Charlton Media Group 101 Cecil St. #17-09 Tong Eng Building Singapore 069533 4 ASIAN POWER

HK: Room 1006, 10th Floor, 299QRC, 287-299 Queen’s Road Central, Sheung Wan, Hong Kong

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

www.asian-power.com

ASIAN POWER 5

News from asian-power.com Daily news from Asia MOST READ

POWER UTILITY

Solar power to push Malaysia’s renewables growth The strong growth of solar power in the country will be the key driver in achieving Malaysia’s 2025 target of having 31% of its total power capacity coming from renewables. The government has yet to advance biomass and waste growth and introduce wind power,” said Fitch Solutions.

POWER UTILITY

5GW of Australia’s coal capacity will close sooner than expected Australia’s coal-fired generation capacity, as projected by its government, should be 14GW by 2030, the Institute for Energy Economics and Financial Analysis (IEEFA) reported. In its updated projection, the Department of Industry, Science, Energy and Resources (DISER) announced a 35% emissions reduction by 2030.

6 ASIAN POWER

POWER UTILITY

China tops world’s solar market China is the global outperformer in solar power with installed capacity projected to increase to 690 gigawatts (GW) by the end of 2030, Fitch Solutions reported.

The country is forecasted to add 436.9GW of solar capacity by 2030.

Overall, the market accounts for 42% of the global forecasted solar capacity growth.

IPP

Amazon, Mitsubishi inks 22MW power purchase deal Amazon and Mitsubishi Corporation have entered into a power purchase agreement for a 22MW solar project in Japan.

Operated by MC’s retail subsidiary, MC Retail Energy, the unique solar project is aggregated, and currently in development across Greater Tokyo and Tohoku areas.

POWER UTILITY

Agrivoltaics could become a new key RE sector in India Agrivoltaics, the generation of solar power on farmlands, whilst complementing agricultural production, has the potential to become an important new renewable energy sector in India, according to the Institute for Energy Economics and Financial Analysis (IEEFA).

REGULATION

UAE to improve energy efficiency by 40% in 2050 The Minister of Energy and Infrastructure of the UAE Suhail bin Mohammed Al Mazrouei has launched the National Water and Energy Demand Management Programme that aims to improve the energy efficiency of transport, industry, and construction by 40% in 2050.

FIRST “The recent power crunch suggests that cutting coal production alone will not be enough to help China achieve carbon neutrality by 2060. Much more needs to be done, and investing in the transformation of the energy and industrial sectors will play an essential role in the greening of the economy,” HSBC said.

It cited the estimates of the IEA that China needs to expand the capacity of its wind power by nine times and solar energy by seven times come 2060, whilst reducing 80% of its coal usage to achieve its target. It added that grid infrastructure and energy storage are also keys to meeting China’s targets.

ROUND-THE-CLOCK X TENDERS LIKELY TO FILL INDIA’S FIRM RE NEED INDIA

Dr Bikal Kumar Pokharel, Wood Mackenzie India has pledged to meet 50% of energy requirements from renewables by 2030

R

ound-the-clock (RTC) renewable energy tenders could respond to the growing demand for the firm and uninterrupted renewable power from electricity distribution companies (discoms), a report found.

RTC power can be provided by blending renewable energy with either conventional thermal power sources or energy storage systems, according to the Institute for Energy Economics and Financial Analysis (IEEFA) and the JMK Research.

“There is increasing emphasis on firming of variable renewable energy-integrated power,” Jyoti Gulia, lead author of the report and Founder, JMK Research, said.

“This will be even more the case now that India has pledged at COP26 to install 500 gigawatts of non-fossil fuel capacity and to meet 50% of energy requirements from renewables by 2030.

Gulia also said discoms now have a new set of tenders, which have minimum annual capacity utilisation factor requirements of 80% and 85%.

Mixing energy sources and tech The report also noted out of the possible mixes of generation sources and technologies, a blend of renewable and thermal may be best to meet the assured power supply power supply conditions in the RTC tenders of the Solar Energy Corporation of India in the short term.

“Growth in new thermal power capacity is neither viable nor sustainable,” IEEFA Energy Economist Vibhuti Garg said.

“The thermal power sector in India is already grappling with numerous stranded coal-based assets and an increasing amount of coal capacity that is being left idle.

She noted that bundling renewable energy with electricity generated in coal-based plants is one way to make use of some of this idle capacity.

In the long run, the report added that the battery energy storage systems will likely become a more viable option to provide a non-intermittent as the cost of battery storage declines steeply.

“To make round-the-clock a reality in India,” JMK Research founder Gulia said.

“The renewable energy industry needs to work alongside policymakers, investors and other stakeholders to provide cost-effective power procurement models that target grid imbalancing, along with improvement of capacity utilisation and reliability of power infrastructure.”

8 ASIAN POWER

The recent power crunch suggests that cutting coal production alone will not be enough to help China achieve carbon neutrality by 2060

China needs RMB200t to reach net-zero by 2060

C CHINA

hina has to secure at least RMB200t of investment to reach its goal of carbon neutrality by 2060, with an average investment of RMB5t a year, according to a report by HSBC, citing the International Energy Agency (IEA).

Of the green investment, two-thirds will go to the power and industrial sectors, whilst in terms of technology areas, electrification, and electricity, systems will account for more than half of the investment, it said.

“Massive investment is required in the development and large-scale deployment of frontier technologies,” HSBC said. “The estimated total investment is in the magnitude of hundreds of trillions of dollars. For example, the IEA (2021) estimated US$33trn (RMB211.6t) for new investment from now to 2060.”

HSBC said capital from the private sector will be key in supporting environmental projects.

“Green financing has so far been government-led, and we think Beijing will likely invest more in research and also attract private sector investment.

For example, it could introduce a regulatory system to engage institutional investors, provide stronger incentives for green finance, and encourage innovation across a wider range of sectors,” it said.

The estimated total investment is in the magnitude of hundreds of trillions of dollars

Net-zero goals President Xi Jinping, last month, said that China will stop building new coal power plants projects abroad as it targets to reach net-zero carbon dioxide emission before 2060. He noted that the county plans to peak its emissions before 2030.

HSBC cited the recommendation of the IEA to craft proactive public policies for incentives for private investors to direct capital to clean technologies.

It cited, as an example, carbon pricing either through a form of carbon tax or an emissions trading system, which can help in accelerating green transformation.

As of end-2020, China’s green loans at US$1.8t and green bonds outstanding at US$125b, “were the largest and secondlargest in the world, respectively, but the efforts are predominantly top-down,” HSBC said.

HSBC also cited the recommendation of Tsinghua University Institute of Financial Research to scale up green finance, which includes greening institutional investors, mainstreaming environmental risk analysis, introducing stronger incentives for green finance, greening investments under Belt and Road initiatives, promoting the harmonisation of green finance standards in China and Europe, and supporting green finance innovation across multiple sectors.

Green financing has so far been government-led (Photo: Xi Jinping)

FIRST

Power supply crunch in 2022 looms in the Philippines

T

PHILIPPINES

he Philippines may experience a power crunch in the summer of next year as no new supply enters the market amidst growing demand, Quezon Power Managing Director Frank Thiel said.

A 660-megawatt (MW) supercritical power plant in the North of Luzon was added into the country’s energy mix, whilst no new power station is expected to come into the market next year, Thiel said. He added that this comes as demand returns to its pre-pandemic level.

“I think it’s going to be a very difficult summer. When people ask me what my forecast is for next year’s power supply situation, I think it’s going to be very tight,” Thiel said at the Asian Power Thermal Energy Conference.

Thiel said Quezon Power will be undergoing three years’ worth of maintenance at once in 2022 after the health crisis prevented the generator from consulting its technical advisors.

Quezon Power is looking at scheduling a 45-day outage or maintenance, which is longer than the usual 25- to 30-day shutdowns it sets for maintenance.

A 660 MW supercritical power plant in North Luzon was added into PH’s energy mix

Quezon Power will be undergoing three years’ worth of maintenance at once in 2022

“We have no choice. We have to do the maintenance. We’ve been deferring for two years already. We cannot keep running the plant, if we don’t do the right maintenance, we could have potentially bigger problems,” he said.

He noted other power generators likely have the same expectations, especially as the government is set to impose a ban on shutdowns during the election season.

The ban will be in effect two months before and after the 9 May national elections next year.

Quezon Power is also in talks with the Energy Regulatory Commission regarding the new rule that sets limits on the allowable planned and unplanned outages for power plants.

“We understand the purpose, and I think prospectively will work really well.

But, trying to apply that and basically apply it to plants that have been online for 20 years presents a bit of a challenge,” Thiel said.

“We are talking to the regulator and we will approach them as need be.”

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ASIAN POWER 9

FIRST

PacificLight’s 100 MW solar import project

3 KEY AMENDMENTS IN SG’S ENERGY BILL

SINGAPORE

SINGAPORE

S

ingapore’s Energy Market Authority (EMA) has granted in-principle approval to PacificLight Power, a Singapore-based power generation and electricity retail company, working with a consortium comprising of Indonesia’s Medco Power, and Salim Group’s Gallant Venture, on a 100-megawatt (MW) pilot solar import project from Indonesia to Singapore.

The consortium signed a joint development agreement during the Singapore International Energy Week on 25 October, witnessed by the Minister of Energy and Mineral Resources of the Republic of Indonesia and the Second Minister for Trade and Industry of Singapore.

The project will supply renewable electricity exclusively to Singapore through solar panels at Bulan Island, 2.5 kilometres southwest of Batam Island, Indonesia. The project will have an installed generation capacity of 670 MW-peak in the initial phase, which will provide 100 MW equivalent of nonintermittent electricity. The renewable electricity generated will be supplied via a dedicated plant-to-grid 230 kilovolt HVAC subsea connection to Singapore.

“PLP is committed to providing our PLANT WATCH

PacificLight gets in-principle approval on a 100-MW pilot solar import project from Indonesia to Singapore

customers with long term efficient energy solutions that are costcompetitive and sustainable,” said PacificLight CEO Yu Tat Ming.

Medco Power CEO Eka Satria added the company are delighted to be working with PacificLight and the Salim Group in developing the Bulan Project. “In addition to the benefits that the project brings to Singapore in achieving its renewable energy targets, this project also provides many benefits to Indonesia through the investment commitment, job and industry creation, and technology transfer, especially in the Province of Kepulauan Riau,” Satria noted.

The electricity generation will be sufficient to power over 144,000 four-room HDB flats per annum and offset over 357,000 tonnes of carbon emissions annually. The project will play a pivotal role in meeting the Singapore government’s objectives to increase power generation from renewable sources and reduce the nation’s reliance on fossil fuels.

PLP is committed to providing customers with longterm efficient energy solutions that are costcompetitive and sustainable

Taiwan’s Hai Long wind projects

Largest hydrofloating solar farm

Sembcorp’s solar project in Indonesia

TAIWAN

THAILAND

INDONESIA

Vietnamese consortium, led

by Semco Maritime and PTSC Mechanical & Construction Co. Ltd., won the preferred supplier agreement for the construction of two offshore substations for the Hai Long wind projects in Taiwan.

Hai Long 2 and Hai Long 3 substations, which are located off the Taiwanese coast, will deliver more than 1GW of green wind energy once commissioned in 2025 to 2026, according to a statement by Hai Long Offshore Wind Project and Semco Maritime.

The world’s largest hydrofloating solar farm, with a capacity of 2.7 GW, has started operations in Thailand, 31 October. The $34m solar farm is as big as 70 soccer fields combined. It is located at Sirindhorn reservoir, 660 km east of Bangkok.

In the morning, its 145,000 solar panels will generate power from the sun, and whilst three turbines will produce energy from flowing water at night. The hydro-floating solar farm is the first of Thailand’s 16 projects in its key reservoirs.

Sembcorp Industries will jointly develop a solar and energy storage facility in Indonesia that can generate approximately 1 GW-peak of renewable power.

The Singaporean company signed an exclusive joint development agreement to develop the facility in Indonesia’s BBK region.

The renewable power generated in the BBK facility was proposed to be transmitted to Singapore via subsea cables.

10 ASIAN POWER

The proposed bill empowers the Energy Market Authority

S

econd Minister for Trade and Industry Tan See Leng highlighted the three key amendments proposed under the energy bill which was read for a second time at the Parliament on 2 November.

The proposed bill empowers the Energy Market Authority (EMA) in three ways; the first is by amending Section 3 of the Electricity Act and the Second Schedule of the EMA Act. By doing so, Leng said EMA will be able to “acquire, build, own and/or operate critical infrastructures” like generating units, energy storage solutions, and transmission infrastructure.

To be specific, Leng said EMA could buy Open Cycle Gas Turbines (OCGT) to “augment any shortfall in generation capacity, such as when there are unplanned outages among other generation units.

“These quick response units are necessary for the security and reliability of our electricity system.” Leng said.

The bill also allows EMA or a subsidiary to directly operate, if needed, the said critical infrastructure.

Safeguarding against unfair competition Leng, meanwhile, allayed fears that allowing EMA to own and operate generating units would “depress wholesale electricity prices.”

“Our preference is for the private sector to build, to own, and to operate the electricity infrastructure. I would like to assure this House that, before exercising this power, EMA would have explored alternative solutions to provide the critical infrastructure needed,” Leng said.

Safeguards will also be put in place to ensure that there would be no unfair competition against the private generation companies, Leng added.

The second key amendment proposed under the energy bill is to penalise those who will damage infrastructure housing of electricity cables, gas transmission pipelines, or submarine gas pipelines in the territorial waters of Singapore.

Currently, sections 80 and 85 of the Electricity Act and sections 32, 32A, and 32B of the Gas Act only impose penalties on those who damage the actual cables and pipelines.

“EMA will be expanding the scope of the offences in these sections to cover such protective infrastructure as well. The offences carry the same penalties as those for damaging the actual cables and pipelines,” Leng said.

The last proposed change under the energy bill expands EMA’s regulatory functions under the Electricity Act. Under the bill, the regulatory body can implement “policies and strategies connected with the reduction of greenhouse gas emissions“ on parties licensed under the Electricity Act.

FIRST

ADB ID, PH team up for ETM launch

WILL RENEWABLES BECOME INDIA’S MAIN POWER SOURCE? INDIA

A

ASIA PACIFIC

sian Development Bank (ADB), Indonesia, and the Philippines announced the launch of a new partnership to establish an Energy Transition Mechanism (ETM) in Indonesia and the Philippines.

The announcement was made by ADB President Masatsugu Asakawa, Indonesian Finance Minister Sri Mulyani Indrawati, and Philippine Finance Secretary Carlos G. Dominguez at the COP26 summit on 3 November.

The partnership was endorsed by senior cabinet-level officials from Denmark, the UK, and the US, as well as leading global financial institutions and philanthropies. Vice-Minister for International Affairs Masato Kanda announced Japan’s Ministry of Finance committed a grant of $25m to ETM, the first seed financing for the mechanism.

“ETM is an ambitious plan that will upgrade Indonesia’s energy infrastructure and accelerate the clean energy transition toward net-zero emissions in a just and affordable manner,” said Indrawati.

“A clean energy transition in the Philippines will create jobs, promote national growth, and lower global emissions,” added Dominguez. “ETM

India aims to increase renewables total power capacity to 40% by 2030

I

ETM partnership announcement at the COP26 summit

has the potential to accelerate the retirement of coal plants by at least 10 to 15 years on average.”

Energy demand in Asia is set to double by 2030, and Southeast Asia is one of the regions continuing to build new coal-fired capacity. Some 67% of Indonesia’s electricity and 57% of the Philippines’ power generation comes from coal. Indonesia has committed to reducing emissions by 29% by 2030 and achieving net-zero emissions by 2060. The government of the Philippines recently announced plans to place a moratorium on new coalfired power plants.

Energy demand in Asia will double by 2030, and SEA continues to build new coal-fired capacity

Singapore to phase out unabated coal power by 2050

S

SINGAPORE

ingapore joined the Powering Past Coal Alliance (PPCA) at the 26th Conference of Parties (COP-26) to the United Nations Framework Convention on Climate Change (UNFCCC) in Glasgow on 4 November.

Singapore is one of the 27 new members and one of the first countries in Asia to do so. Singapore also signed the Global Coal to Clean Power Transition statement initiated by the UK COP-26 Presidency.

Under the PPCA Declaration, Singapore has committed to continue phasing out the use of unabated coal in its electricity mix by 2050 and to restrict direct government finance of unabated coal power internationally. Since independence, Singapore’s reliance on coal has been marginal and makes up

less than 2% of its power generation capacity today.

“The burning of coal is putting billions of people at immediate risk. It is why Singapore has decided to join the Powering Past Coal Alliance, one of the first countries in Asia to do so.

Singapore is fully committed to accelerating the transition to a low-carbon future. We will transform our industry, economy, and society to be more energy and carbonefficient, and to adopt more low-carbon energy in support of the goals of the Paris Agreement,” said Minister for Sustainability and the Environment Grace Fu. In addition to its membership in the PPCA, Singapore has signed the Global Coal to Clean Power transition statement. The country committed to

The burning of coal is putting billions of people at immediate risk

international efforts and collaboration to shift away from unabated coal power generation in the 2040s, cease issuances of new permits, and end direct government support for new unabated coal-fired power generation projects worldwide.

ndia’s renewable installed capacities have grown to 148 gigawatts (GW) by the end of September 2021, comprising 38% of India’s total installed power capacity.

However, CreditSights reported that the share of renewable power generation to India’s total electricity generation of 21% falls below its share in the country’s total installed capacity.

The difference between its generation ad capacity has sparked questions on whether renewables can become India’s dominant power source.

Analysts said they are confident that the “share of green power in meeting India’s power needs will only increase going forward,” but not as swift as envisioned by the country.

India aims to increase the shares of renewables in its total power capacity to 40% by 2030.

The country’s renewable power assets have grown from 18GW in June 2010 to 148GW by end-September 2021, according to the Ministry of Power.

CreditSights also underscored that renewable facilities generate less power per gigawatt than thermal assets.

This is mainly because renewable power has a lower average capacity utilisation factor (CUF) “owing to intermittency issues.”

Renewable power assets Analysts said during the monsoon season in India, which occurs during the second quarter of every fiscal year, solar assets see a 20% drop in CUF, whilst wind assets’ CUF jumps as high as 35%.

During the dry season, however, wind assets can fall to as low as 16%.

“Consequently, output from renewable sources can be extremely seasonal, intermittent, volatile, and generally low,” the analysts said.

For the LTM period ended August 2021, renewables’ CUF was at 23%, which paled markedly compared to the CUF of nonrenewable energy plants at 55%.

“Considering renewable facilities generate lesser power per gigawatt than thermal assets, we can conclude that, despite the rapid growth in the industry, it still has a long way to go in becoming the dominant source of power in the country,” CreditSights said.

The analysts however said that renewable power in India is “here to stay” and will remain “well-supported.”

ASIAN POWER 11

VOX POP

How do China’s plans to stop building coal power abroad affect countries reliant on coal?

CHINA

Fabian Ronningen Analyst, Rystad Energy: China has been one of the biggest funders of coal in Asia, together with ADB and development banks in Korea and Japan. We have seen already that several of the large financiers are pivoting their investments away from fossil generation, predominantly coal, to more green investments in Asia in the last few years. Now that China also has made it clear they will not finance any new coal power plants or coal mines, that could make it harder for several Asian countries. Countries that could be affected by this are especially Vietnam, Indonesia, Pakistan, the Philippines, and Bangladesh, which all have rapidly growing power demand and still plan to add more coal power to a larger or smaller extent. How dependent they are on Chinese financing depends on the country, but it is clear that all of them will feel it in some way.

Cutting abroad financing will maybe not impact Chinese emissions and emissions targets directly, but it sends a clear message that future coal power will be difficult to finance. As for the domestic emissions in China, we have also seen several signs that China is increasing its pace of renewable investments and development, to directly displace coal in the generation mix. If we only consider power sector emissions, the target of reaching peak emissions before 2030 is definitely feasible with the current pipeline and projections we expect for China. Whether or not China will reach carbon neutrality by 2060 is an open question. Focusing on reducing the dependence on coal is definitely a step in the right direction, but how fast emissions can drop after the peak depends on how effective China is in cutting coal out of its power generation mix.

It is unclear from the current statement how the financing ban will affect projects already under construction or the planning phase. Probably most of these projects will be completed, due to contractual obligations, but projects in the early planning phase have the risk of being cancelled or finding other financiers, which may be difficult.

China’s coal plant investments Using data from the Global Coal Public Financing Tracking website, it is stated that China financed a total of 53.1 gigawatts (GW) of foreign coal plants in the period 2013 to 2020 for a total financing cost of 50.1 BUSD. The data also shows that China represented 56% of foreign investments in coal plants in the period, so removing this financing source will create a “financing gap” for some of the countries we mentioned earlier.

Let’s assume similar Investments pr MW of coal capacity, we see that the cost is roughly 945 MUSD/GW in investment for a new coal plant (CAPEX). Let’s also assume that China would have continued to finance 56% of foreign investments in new coal power in Asia. Rystad Energy expects roughly 70GW of newbuilds in Asia the next decade (excluding China), and if China financed 56% of that they would finance 39.2GW. This translates to a total investment need of US$37b.

Therefore, it can be expected that since China stops financing new coal it can leave an investment gap in the order of US$30b-40b.

If we use Indonesia as an example, Rystad Energy estimates that Indonesia has around 19GW of coal capacity in the concept phase, early planning or under construction between now and 2030. If we assume that all of that will come online, and be financed with similar financing ratios as before, that result in a financing gap of US$10b in Indonesia’s case alone.

12 ASIAN POWER

Narsingh Chaudhary, Black &Veatch’s Executive Vice President & Managing Director, Asia Power Business.

Harry Harji, Associate Vice President for Black & Veatch management consulting business in Asia: Decarbonisation commitments, such as China’s pledge to stop building new coal-fired power projects overseas, present an opportunity to increase support for countries developing green and low carbon energy and accelerate Asia’s energy transition.

With fewer financing options available for coal developments, we anticipate more proposed coal plants will be cancelled. Consequently, countries reliant on China for coal financing will need to review their energy plans to scale up alternative power solutions including renewables.

To accommodate more renewable energy generation, the region will need more integrated solutions across generation, transmission, and distribution; as well as the expansion of gas-fired generation and energy storage, to improve grid efficiencies and stability. In the longer term, integrating hydrogen to support baseload generation could be another approach to decarbonise the electric sector.

The China Electricity Council has reported that the electricity consumption of the country reached 6,165.1 terawatt-hours from January to September this year, a year-on-year increase of 12.9%. Countries with high demand growth rates such as China will need to balance economic developments and carbon neutral commitments.

China’s renewable energy portfolio Whilst China is still dependent on coal generation, it has also expanded its renewable energy portfolio. According to the International Renewable Energy Agency, China is the global leader in terms of wind energy deployments, installing 72GW of new capacity in 2020 alone rivalling the second largest country, the United States, which has a total capacity of about 95GW. Furthermore, with 253GW of installed solar power capacity as at end of 2020, China also has the world’s most capacity and this compares with about 151GW of solar power capacity across the European Union, according to International Energy Agency data.

However, too much intermittent renewable energy by itself can threaten reliable grid operations and performance. Given China’s continued growth in electricity needs, coal appears to remain a near-term option domestically to balance the grid; lessons from the recent grid challenges across China bear this out. Long-term, however, to meet its 2060 goals and address renewable energy variability, China will benefit from more integrated solutions across generation, transmission and distribution, like the rest of Asia, to effectively manage the energy transition and provide stable and reliable power. Gasfired generation, energy storage and in time hydrogen and potentially nuclear are likely to see an increasing share of deployment.

Independent Power Producer of the Year - Indonesia Innovative Power Technology of the Year - Indonesia

PT. GH EMM Indonesia strives to maintain highest performance in supporting Indonesia’s electricity sector The company was recognised with the Independent Power Producer of the Year and Innovative Power Technology of the Year trophies at the Asian Power Awards

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stablished on 11 March 2008, PT GH EMM Indonesia, a 70:30 consortium between China Shenhua Energy and PT Energi Musi Makmur, is committed to providing enough power for the national electricity company (PLN), the government and the Indonesian people.

As one of the Independent Power Producers Company in Indonesia, PT. GH EMM Indonesia owns the Simpang Belimbing coal-fired power plant with a capacity of 2 x 150 MW. It is Indonesia’s first mine-mouth power plant in the remote area of Muara Enim Regency, South Sumatera Province.

PT. GH EMM Indonesia successfully obtained two prestigious awards from Asian Power Awards 2021, the “Independent Power Producers of the Year” and “Innovative Power Technology of The Year”.

The spirit of "pursuing excellence" has once again made the name of the CHN Energy Group in the power generation, transmission, and distribution industries in the Asia-Pacific region.

The company always tries to adopt the latest technology in supporting company business processes. Continuous improvement programmes, innovation and breakthrough projects are the pulses of the company’s progress. With a good operation and management system, the company has successfully utilized extremely low-quality lignite coal with the calorific value of 1800-2200 kcal/ kg and total moisture content of 59-63 % as the power plant's main fuel. In addition, the company also succeeded in recycling and reusing coal wastewater as additional fuel for the power plant in line with the company’s plans for green business development.

In terms of availability and reliability, the power plant has been at full capacity 94% of the time (equivalent availability factor or EAF), with an equivalent forced outage rate (EFOR) of less than 1%, since it was put in operation. The company continues to work with a focus on best results by emphasizing earnest and sustainable excellent execution, enabling our company to achieve optimal performance continuously.

PT.GH EMM Indonesia also has an “Environmental Awareness” commitment in carrying out every operational activity and

PT GH EMM Indonesia team

Simpang Belimbing coal-fired power plant

maintenance of the power plant unit. The company conducts environmental management and monitoring regularly which is conducted through measurement of air emissions, ambient, noise, wastewater, and raw water quality in each Generation Unit. PT. GH EMM Indonesia has a role to achieve sustainable development goals in terms of the environment. PT. GH EMM Indonesia always strives and focuses to prove its consistency in preserving environmental protection, especially during this COVID-19 pandemic.

With various efforts, we continue to look for solutions so that important programmes continue to run to ensure ecosystem sustainability and national electrical energy security PT. GH EMM Indonesia continues to implement sustainable programmes aiming to reach the sustainable development goals, such as implementing a pro-environmental operations programme (Green Power Plant). Green Power Plant is implemented through the development of water and energy efficiency as well as proper waste disposal and management

The global climate change issue has become the largest challenge today. All countries in the world strive to look for cleaner and safer energies. We implement transformation towards an excellent business process in supporting the achievement of the company target through a new vision and mission, overall efficiency programme and sustainable growth. The company will further focus on fuel costs, financial costs, labour costs, and maintenance costs control as well as arrange the investment of special resources such as scientific and technological innovation, energy conservation, environmental protection, and safety technological transformation. On the other hand, our company's next development will promote the transformation of the company and gradually shift to non-fossil energy power generation. At present, it is planned to promote the trial of palm shell biomass blended combustion for power generation or generally we call it "Co-Firing”, and try to promote the transformation of coal-fired power projects to serve the needs of Indonesian society.

The development of renewable new energy will be the main direction and goal of our company's next overseas development. The company will focus on strengthening communication with the Indonesian government, strive to get supporting documents and establish communication channels with domestic professional institutions to explore the feasibility of photovoltaic projects in our ex-mining area. Promote the construction of photovoltaic projects and push renewable new energy power generation to the power market to serve Indonesian society, thereby ensuring the core competitiveness of enterprises.

The challenges of the COVID-19 pandemic required us to change work patterns, innovate and implement new ways of working by adjusting the company’s strategy. With various efforts, we are able to survive and continue to look for solutions so that important programmes continue to run to ensure ecosystem sustainability and national electrical energy security. We commit to being the trusted leader company in sustainable energy in South East Asia.

ASIAN POWER 13

REPORT & REACTION: VIETNAM PDP8

Vietnam’s return to coal puts renewable energy transition at risk Vietnam should craft incentives to carry out cost-competitive renewables, argues IEEFA.

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new draft version of Vietnam’s much-delayed Power Development Master Plan 8 (PDP8) began to circulate earlier this month [September 2021] with revisions that put the country’s closely watched energy transition at risk. In a surprising shift, the planners have raised the installed capacity target for coal-fired power by 3 gigawatts (GW) to 40GW by 2030, with an additional, and final, 10GW to be deployed by 2035. To make room for this pivot back to coal, the planners sacrificed 6GW of wind power that was expected to come online by 2030. Offshore wind was removed entirely from PDP8’s base case scenario.

Between 2016 to 2020, coal power project sponsors delivered only 52% of the capacity expected in the master plan, undermining the security of the power supply for Vietnam’s fast-growing economy.

For Vietnam’s energy planners, the lessons from this mistake are still fresh. By opting to push ahead with an expanded coal power pipeline, Vietnam risks shunning globally recognised clean project sponsors who have credibility in delivering cost-competitive projects.

Its energy planners might have underestimated the strategic impact of the sector’s reliance on overseas financing and the trends reshaping global capital flows. In particular, any plan to launch an aggressive build-out of new coal power will feel the impact of policy shifts. This includes the cut

By pushing ahead with an expanded coal power pipeline, Vietnam risks shunning globally recognised clean project sponsors

The forecast coal capacity now expected to come online in PDP8 seems unrealistic

14 ASIAN POWER

off of access to capital for new coal power projects that previously turned to Asian and North American governments and banks for financing.

Based on this change in capital market lending habits, the forecast coal capacity now expected to come online in the draft PDP8 seems unrealistic. Of the 30GW of coal-fired power in the pipeline, IEEFA estimates only less than 12GW are realisable capacity because they represent projects that are already under construction or have reached financial close. The remaining 19GW will have to face the test from more climate-conscious investment mandates that global investors and governments have recently implemented. The exodus of Japanese and South Korean export credit agencies and major banks from coal financing poses a particular challenge to Vietnam’s new ambition to continue seeking finance for coal deals that conflict with carefully monitored public commitments.

Vietnam’s coal money – a review The governments of Japan, South Korea, and China, via their export credit agencies and policy banks, have facilitated stateguaranteed credits to coal power projects in Vietnam to support their equipment suppliers and contractors.

A review of 12 coal power projects that concluded financing arrangements between 2015-2021 alone suggests that ten of them are backed by public financing from Japan,

South Korea, and China. This is irrespective of the project’s sponsor and ownership.

The reliance on foreign funding reflects the limited role that domestic banks have played in supporting Vietnam’s coal power plants because they are constrained by inadequate long-term funding, high-interest rates, and single borrower limits. In the few instances when they have been involved, the banks—typically the four majority state-owned banks—have partnered to meet sectoral and single client exposure limits.

With limited domestic funding, Vietnamese policymakers will face a much less accommodating funding scenario internationally. Governments of Japan, South Korea, and China have faced a backlash from global investors, asset managers, and activists for their poor climate track record and their support for polluting coal power plants in developing countries, including Vietnam, over the past decade.

The global investment community is increasingly focused on how these institutions are implementing their coal exit policies. Even if permitted, Vietnam’s energy planners should be mindful that abated coal power plants would have significantly higher costs and performance risks, likely rendering electricity tariff cost-prohibitive for EVN and its ratepayers.

China: lender of last resort?

Until recently, the default view of local analysts has been that Chinese banks and their equipment providers would fill in the funding gap left behind by their North Asian counterparts. This was already a high-risk bet, and President Xi Jinping’s speech at the United Nations General Assembly on September 21 has lowered the odds even further.

Following the footsteps of his South Korean counterpart, Xi made the official declaration on the international podium that China would “not build new coal-fired power projects abroad” as it steps up support for developing nations to develop green and low-carbon energy.

Data has shown that China’s overseas coal project investments have been shrinking since 2015, with no new investment in the first half of 2021. In July, China’s largest bank, the Industrial and Commercial Bank of China, announced its withdrawal from a US$3b coal power project in Zimbabwe, marking the first time “a Chinese bank has proactively walked away from a coal-power project”.

Several high-profile projects in Vietnam

REPORT & REACTION: VIETNAM PDP8 Vietnam’s 19GW of Unfinanced Coal Power Pipeline

Vietnam should focus on devising policies that incentivise the market to deliver more cost-competitive renewables

Source: IEEFA

could see their fates put at risk, including Nam Dinh 1, Song Hau 2, An Khanh Bac Giang, Cong Thanh, and Vinh Tan 3. These are projects still at the pre-investment phase but with previously confirmed backing from Chinese banks or sponsors.

It remains to be seen how China will implement its overseas coal exit strategy.

With a much narrower pool of capital available, Vietnamese senior officials could put themselves in an undesirable position at the negotiation table by harbouring false expectations. Policymakers should also expect questions about whether the Vietnamese government and EVN are prepared to offer concessionary terms to get these coal projects across the line to offset rising carbon abatement costs that could undermine traditionally fixed project financing terms.

This raises a potentially awkward question about how regulators will handle the new moving parts in the coal financing puzzle. Will they have the authority to insulate project sponsors from Vietnam’s upcoming emissions trading scheme, and as a result potentially limiting the effectiveness

of the market, or will they accept a higher, emissions-adjusted cost of electricity?

Plans to develop coal power assets inhouse should also be assessed with care.

Unlike its peers from Indonesia or the Philippines, EVN does not have the luxury of accessing international capital markets for cheap funding, given Vietnam’s low sovereign credit rating. Equally important, global investors will also be reluctant to support EVN’s commitment to coal lock-in at a time when cost-competitive clean alternatives are readily available.

Choosing the right solution The Vietnamese government’s pivot back to coal raises questions about whether key insiders are aware of the new economics of energy transition. Cost pressures are a natural policy concern, but it appears that PDP8 planners have made a common modelling mistake by focusing on a narrow menu of outdated generation choices and overlooking system-level options that improve long-term economic outcomes for consumers in Vietnam.

In particular, they have opted for

coal power at its face value, overlooking externalities and underestimating the risks associated with the development and use of emissions-heavy power.

Instead of opting for a baseload-only strategy dependent on more coal power plants, Vietnam should focus on devising policies that incentivise the market to deliver more cost-competitive renewables. Lack of experimentation with reverse auctions for new solar and wind power plus storage has robbed EVN of more cost-competitive options for system development.

Vietnam’s decarbonisation efforts For a dynamic economy highly exposed to global investment and consumer markets, Vietnam has a lot to gain by building credibility for its decarbonisation effort.

The growing pool of sustainable finance has the potential to unlock the new sources of capital that Vietnam needs to scale up renewable energy and grid infrastructure to generate reliable and affordable electricity.

Over the past year, Vietnam has dominated headlines as the Southeast Asian country where investors believe has made the greatest strides in renewable energy adoption. There is broad agreement that steady progress on curtailment and power market reform would open the door to larger investments offering more costcompetitive terms.

With the United Nations Climate Change Conference COP26 looming ahead, the pivot back to coal seems certain to raise uncomfortable questions about whether Vietnamese policymakers have misjudged global political and financial trends. Until PDP8 gets its final sign-off, there is still a limited window of opportunity for them to set the record straight.

What analysts say: Harshid Sridhar Senior Analyst, Rystad Energy: Whilst the focus on renewables is still active, it looks like Vietnam is trying to hedge its position by banking on some coal additions to support the base load power requirements. This is because, irrespective of its clean nature, renewables still have lower capacity factors and its variable nature leads to operational issues with the grid.

The future of coal power projects which depends on Chinese funds is unclear and might lead to cancellation. With a deficit in local financing options, the addition of coal based plants is definitely challenging. The implications of carbon tax too is one of the concerns for Vietnam.

Whilst the Ministry of Industry and Trade claims that the draft is still open for comments and subsequent revisions before final approval, it remains to be seen how they will secure their expansion plans.

Minh K Le Senior Research Analyst on Renewable Energy, Rystad Energy: Vietnam will not see the renewable boom like it has seen in the past few years, mainly due to the phasing out of the FiT policy. Much of the growth will depend on what the follow-up policy is. Reverse auction will be the best going forward. Renewable Portfolio Standard and CfD/Feed-in-Premium are not really applicable to Vietnam, as it still has no spot market and it is still quite centralised. However, auctions need to be well designed, there have been auctions that have failed and many are quite successful, so plenty of learning experience for Vietnam here. Whilst currently the PDP8 draft doesn’t seem to be as favourable for renewable energy, things can still change in the next few years depending on the progress of many power projects (thermal plants, renewable plants, and grid expansion/upgrade).

Nancy Nguyen Consulting Manager, Asia Clean Energy Partners: By adding more coal to the nation’s energy mix, Vietnam would lose the possibility to steer its policies towards a power development pathway that is compatible with the Paris Agreement’s 1.5 temperature limit. CO2 emissions from coal in Vietnam have jumped up almost 700% within ten years, from 20 million tons in 1999 to 135 million tons in 2019. Vietnam’s current emission targets appear critically insufficient, bringing the country closer to the scenario of 4 degrees Celsius warming if Vietnam does not take actions to set more ambitious targets.

Under no circumstances should Vietnam proceed with the current proposal in the revised PDP8.

Capital markets now have a value of $200t globally, and investors are keen to invest in low- or zerocarbon infrastructure projects.

ASIAN POWER 15

LEGAL BRIEFING

Will the energy bill reduce competition in SG’s electricity generation market?

Under the bill, the Singapore regulator will be allowed to be a market player. borrow which allows EMA to raise capital or issue bonds to finance the construction of critical energy infrastructures.

“If interest rates were to become volatile, this can give rise to huge fluctuations in bond prices and yields. This can have an adverse effect on wholesale electricity prices,” Jafaar said.

Allowing EMA to issue commercial bonds could also expose EMA-owned or operated generation units to market forces and risks relating to the fund-raising, which, according to Jafaar, could thereby directly affect the already small electricity market.

The extensive powers given to the EMA under the bill, however, can be justified for several reasons, according to Jafaar. Singapore’s energy market is “far too small,” and EMA will allow the country to “ safeguard the reliability” of its energy generation sector.

Apart from the Energy Bill, laws such as the Electricity Act and Carbon Pricing Act 2018 also have measures that encourage the adoption of green technologies, standards, and practices

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he Energy (Resilience Measures and Miscellaneous Amendments) Bill—particularly section 3(i) that allows the Energy Market Authority (EMA) to be a market player in the electricity generation market—has sparked concerns amongst stakeholders.

RHTLaw Asia LLP Managing Partner Azman Jaafar told Asian Power that under the said provision, section 6 of the Electricity Act will be amended, such that EMA “will not be required to obtain an electricity license to acquire, build, own, and operate critical infrastructure that generates electricity.”

“As a regulator, it appears that EMA may block, deter, or stop competitors under the Singapore Wholesale Electricity Market from competing against EMA-owned or operated energy units,” Jaafar said when asked about the possible conflicts which could arise from the bill.

“It can also pass regulations, which can favour energy generation units that it has acquired or built, as well as those that it owns or operates,” he added.

This advantage given to EMA could also give rise to the depression of wholesale electricity prices.

Citing feedback from the public consultation held for the bill, the lawyer said: “Energy generation units operated by the EMA are likely to compete with existing units in the Singapore Wholesale Electricity Market.”

“In addition, imposing high technological barriers for newcomers to enter the market can be construed as an abuse of dominance and can be deemed as an anti-competitive behaviour,” Jafaar said, emphasising that this counters the law’s chief aim to create a competitive market framework for the industry.

Jafaar also warned that the new law would give rise to a monopoly of the electricity generation market. “Given the lack of competition, there will not be scope for resellers in the market for locally-generated electricity.”

On the flip side, Jafaar mentioned that a lack of competition might encourage resellers to tap on greener sources of electricity exported from foreign grids.

Furthermore, a provision of the energy bill repeals section 12 of the Energy Market Authority of Singapore Act or the power to 16 ASIAN POWER

Azman Jaafar

The Bill enables EMA to implement policies, strategies, measures, and standards to reduce emission of greenhouse gas in the generation, transmission, import, export, or supply of electricity

‘Too early to tell’ Drew & Napier LLC, for their part, told Asian Power that whilst concerns raised about the bill are legitimate, it may be premature at this stage.

“The Ministry of Trade and Industry has reiterated their commitment to ensuring a competitive wholesale electricity market, and to put in place proper governance structures to ensure fair competition and mitigate any potential conflicts of interests,” Christopher Chong, Drew & Napier LLC’s head of Construction & Engineering, said.

Chong added that the bill also has positive implications, such as energising the project finance space for energy infrastructure in the country that will benefit, rather than handicap, competitors.

“As we have seen in other markets such as the offshore wind sector in Taiwan, investments will follow wherever the funds go, and the funds will go where there is future money,” he said.

It could also allow Singapore to explore “obtaining interests in major infrastructure projects overseas such as mega-solar farms in Australia, or geothermal plants in the Philippines, or hydropower plants in Laos, with a view to piping or transporting electricity into Singapore and obtaining greater security over Singapore’s energy needs through importation,” added Chong.

“This could also help spur developments in Singapore and the region, in complementary industries such as in hydrogen, battery, power transmission; and in the carbon/renewable energy credits space,” he said.

More importantly, Chong said allowing EMA to acquire, build, own, and operate power plants and infrastructure, and to fund these steps are also “extremely helpful” towards Singapore’s Clean Energy Transition.

This was also underscored by Jafaar, saying the bill can bring about much-needed change to transform Singapore’s local energy sector and reduce greenhouse gas emissions.

This is provided for by section 3 (g) of the bill which amends section 3(3) of the Electricity Act, enabling EMA to implement (whether through regulation or otherwise) policies, strategies, measures, standards or any other requirements on any matter for or connected with the reduction in emission of any greenhouse gas in the generation, transmission, import, export, or supply of electricity.

Chong said it is unlikely that EMA will take an overly aggressive approach in its implementation of strategies and measures to support Singapore’s energy transition.

Apart from the Energy Bill, Chong said laws such as the Electricity Act and Carbon Pricing Act 2018 also have measures that encourage the adoption of green technologies, standards, and practices.

CO-PUBLISHED CORPORATE PROFILE

Kalehan Energy’s hybrid power plant lauded at Asian Power Awards 2021 Lower (Aşağı) Kalekoy Dam and HEPP by Kalehan Genc Enerji Uretim A.S., a Kalehan Energy company, was recognised with the Hydro Power Project of the Year - Silver award.

Lower Kalekoy project

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alehan Energy is a group of energy companies that was founded by two of the pioneering Turkish construction companies—Cengiz Construction and Ozaltin Construction—solely for the utilisation of renewable energy. Kalehan Energy executes its projects with a vision of Turkey that is able to supply its energy demand in an environmentallyfriendly and sustainable manner using clean, renewable and domestic resources.

Lower (Aşağı) Kalekoy Dam and HEPP is the first hybrid power plant in Turkey, the largest one in Europe and was awarded the 2021 Asian Power Silver Award for Hydro Power Project of the Year.

As of 2021, Kalehan’s 1788 MW of installed capacity in operation makes Kalehan Enerji the largest renewable energy producer amongst the private sector in Turkey. The total investment cost of Lower (Aşagı) Kalekoy Project is approximately US$700m, financed by Turkish Banks with the guarantee of parent companies.

The project includes 500MWe installed capacity of hydropower and 80MW installed capacity of solar power. Whilst the main purpose of the project is to produce electricity with the approximately 1,300GWh/year energy production, it also supplies 9,450,000m3 of irrigation water per year. The civil works include a 107m-high composite type dam body composed of Asphalt Core Embankment Dam

(ACED) and Roller Compacted Concrete (RCC) body. The ACED is 510m long at crest level, 107m high and 480m wide at the bottom.

The embankment volume is 3.37 million m3, and the asphalt core volume is 14,600m3. The asphalt core is 1.20m-wide at the bottom and 0.5 m-wide at the top. The RCC dam is 435m long at crest level, 110 m high and has a volume of 1.6 million m3. Additionally, 1.1 million m3 of CVC is used. The spillway is 80 m wide

Kalehan Energy executes its projects with a vision of Turkey that is able to supply its energy demand in an environmentally-friendly and sustainable manner using clean, renewable and domestic resources

and radial gate-controlled with a maximum discharge capacity of 9,247 m3/s. There are four radial gates of 19.3 m height and 14.0 m width, which make them Turkey’s highest radial gates.

In June 2020, renewable energy legislation in Turkey was revised and it was permitted to

install auxiliary resources in addition to the primary resource. With this, Kalehan decided to utilise 1,100,000m2 of unused area located downstream of the project by installing an 80MW solar power plant as the auxiliary energy resource. This solar power plant, which was completed in May 2021, is Turkey’s Largest Solar Power Plant licensed by EMRA (Energy Market Regulatory Authority).

The solar power plant was constructed downstream of the powerhouse around the tailwater area. Approximately 200,000 pieces of solar panels were installed within the project area. Installation of the solar power plant was completed in only 3.5 months despite the conditions of the COVID-19 pandemic, which is another record short duration for a solar project of this size.

The installed capacity of the powerhouse from hydro is 500MWe with four Francis type turbines: three large units with 155.49MWe and one ecological unit with 33.53MWe installed capacity. The 80MW Solar Powerplant is also connected to the powerhouse, from which energy is connected to the national grid. The project has a total of approximately 6,500m-long grouting galleries and approximately 1,000m of diversion tunnels.

The impounding created a reservoir with a surface area of 15.9km2 which required the relocation of around 90 houses in five partially-inundated villages. The land acquisition procedures were carried out in accordance with the Expropriation Law and Kalehan undertook a series of social assistance projects in the partially-inundated villages to aid the households. These social aids are comprised mainly of: • Construction of infrastructure in the new settlement areas such as water supply, electricity transmission lines and new roads; • Provision of construction machinery and construction materials for new houses free of charge, or provision of monthly rent aids to those that could not start construction of their new houses; • Construction of two mosques and a new larger elementary school; • Payment of monthly scholarships to the approximately 300 university students from the villages that are directly affected by the project.

Further to above, during the construction peak period, more than 3000 people were employed directly at the site, most of whom were from nearby villages. Currently, the planning of three more HEPP projects in Bingol and Elazig provinces as well as auxiliary resource solar projects in connection with them are underway.

ASIAN POWER 17

CEO INTERVIEW

Quezon Power supply deal extension in limbo

The power generator’s power purchase agreement is due to lapse in May 2025.

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oal-fired power plant, Quezon Power, which has been in operation for over two decades, is looking for alternative routes with the looming expiration of its power supply agreement (PSA) with local distributor Manila Electric Co. (Meralco).

In a fireside chat with Asian Power Editor-in-Chief Tim Charlton at the Asian Power Thermal Energy Conference, Quezon Power Managing Director Frank Thiel shared the plant is looking at either selling to retail energy suppliers or operating within the wholesale electricity market.

Quezon Power forms part of the EGCO Group from Thailand, which also owns assets around the globe. In the Philippines, Thiel also manages the first supercritical plant, the San Buenaventura power project, on top of the Quezon Power station.

We don’t know yet what the Philippine government will do after COP26. But for Quezon Power Plant, your power purchase agreement (PPA) with Meralco will expire in a couple of years. Could you walk us through how competitive it’s going to be to get renewed? How long is it for?

The agreement is due to lapse in May of 2025. Ten years ago, 15 years ago, when we’re looking at the future, we’re thinking that we’re going to get an extension to our current PPA because we’re a very reliable power station. We’re cost-competitive. Five years ago, we began to realise that market conditions are changing. Three years ago, we said, the world is going to look vastly different from what we anticipated 10,15 years ago.

What do we want to do with Quezon? Do we want to try and get another PPA or PSA? The answer is yes. We embarked on a program to try and determine what would it take to refurbish our plant, to extend the life of the plant beyond the 25 years of the current power supply agreement. In the Philippines, Meralco has instituted what they call a competitive selection process (CSP).

They will look to contract for a certain amount of megawatts (MW) to be delivered on a certain date and go through a very rigorous process. We saw an opportunity for our project for Quezon Power in this case to try and compete. We’re looking to see if there will be room for us in the future when Meralco starts contracting for additional power for 2026, and beyond; If we’re successful, the outcome of that will be perhaps a 20-year PSA. If we’re not successful, because obviously, the CSP is very competitive, then we have to look for alternatives.

The things that we’re evaluating right now involve, perhaps selling our power to retail energy suppliers. Our plant has one advantage, that is that we were fully amortised. At this point in time, we can be very competitive with our power rates. If that’s the case, we may be able to latch on to shorter-term contracts with retail energy suppliers. The other alternative is to operate within the wholesale electricity market here in the Philippines, and basically become a merchant plant. Although there are a lot of challenges, we’re trying to position ourselves as best as we can. We would have to adjust our strategy, or how we operate the plant, how we maintain the plant, depending on what we’re able to get.

The Philippines has issued a moratorium or a ban on new power projects. And there are two stakeholders here, Meralco 18 ASIAN POWER

Frank Thiel, Managing Director, Quezon Power

Although there are a lot of challenges, we’re hoping to get either a long-term contract with Meralco or shorter-term contracts with retail energy suppliers

and the government. Both of them must also be a little bit concerned about energy security, and about effectively cutting off coal-fired power plants without alternatives in place. Do you think that this will be considered to extend the life so they have that energy security?

Within the moratorium, Energy Secretary Alfonso Cusi indicated that any coal-fired plants that were currently in the stages of development will remain in the pipeline. The biggest fear is whether or not you can get financing for those projects. There are about 3,500MW worth of coal-fired plants in the pipeline.

But anything after that, the moratorium prevents new coal plants from coming into the Philippines.

The Department of Energy, in particular Secretary Cusi, has been very clear and very vocal about the fact that coal and thermal power has to remain in the energy mix of the Philippines.

We’re currently 52% of the energy mix for the country. Secretary Cusi recognises that we’re not going to be able to transition overnight. We’re not going to be able to get away from thermal power for quite some time. I think he realises that the transition is going to take place, but it’s going to take quite a bit of time. Now, our customer, Meralco, is very interested in the most competitive power prices that they can get because, obviously, they want to pass that on to the consumers. That’s where consumers are looking for reliable, inexpensive power. Meralco has different goals in mind. At the same time, Meralco has a mandate on renewable portfolio standards. They have to source a certain amount of their energy from renewable energy sources. So they’re trying to balance those things out.

Gas Engine Combined Cycle Power Project of the Year - Gold and Dual Fuel Power Plant of the Year - Bronze

PT PP (Persero) Tbk recognised with 2 accolades at the Asian Power Awards The company continues to gain trust to work on prestigious projects across Indonesia, such as the Gas Engine Power Plant in Bangkanai.

Land clearing started in February 2018. Engine foundation was ready before the first engine arrived at the site in June 2019. Then finally the engine 1 was completely first fired on March, 19th 2020. All engine first firing was completed in November 2020.

Bangkanai Gas Engine Power Plant

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stablished in 1953 under the name NV Pembangunan Perumahan, PT PP (Persero) Tbk is entrusted to build houses for the officers of an Indonesian cement company in Gresik. Along with improved performance and growing trust from our customers, the company was able to build large scale projects in Jakarta, Bali, and Yogyakarta.

The EPC Division of PT PP (Persero) Tbk. continues to gain trust to work on prestigious projects across Indonesia, such as in Bangkanai and in Lombok. Up

2021 is the lowest compared to other provinces in Borneo, which is 96.07%, whereas other provinces in Kalimantan have reached 98-99%. So, electricity demand in this area is estimated to be high for the next five years. Therefore, Bangkanai GEPP (Peaker) Stage 2 (140 MW) Project is developed in Central Kalimantan, to provide and enhance electricity supply in this area, especially for the Kalimantan Island.

The power plant uses dual-fuel engine technology

All the challenge is new learning for us and becomes our motivation to provide sufficient electricity in rural areas and its surrounding until now, the company has worked on several types of power plants from coal-fired, simple cycle gas engine, simple cycle gas turbine, and combined cycle to renewable projects such as 72 MW Windfarm in Tolo, 30 MW Geothermal in Kamojang, and 42 MW Solar PV in Lombok & Manado.

Bangkanai Gas Engine Power Plant Located in Karendan, a village in Lahei District, North Barito Regency, Central Kalimantan where the agricultural sector, palm oil plantations, coal mining, and business trade contribute positively to Central Kalimantan's economic growth. These five sectors grow prospectively supported by adequate natural resources in this world's third-largest island.

These sectors consecutively play a significant role in the increasing demand for electricity in Central Kalimantan.

Based on the data presented in the RUPTL 2021-2030, the ratio of the number of households using PLN electricity in Central Kalimantan is still relatively low. Besides, the electrification ratio in Central Kalimantan as of the second quarter of

as a main source of electricity. The engine can be operated with natural gas as the main fuel and diesel fuel as backup and pilot fuel.

During the project, the company was facing some obstacles. The major constraint is transportation due to poor access roads. We need extra effort, detailed engineering, meticulous planning and solid team coordination for the execution in shipping the Engine and Generator which was sent from Finland through sea using a mother vessel. Total 16 engines and generators were sent to the Luwe Jetty through the Barito River.

GECC Lombok Peaker Located at the heart of the capital city of West Nusa Tenggara, GECC Lombok Power Plant is the biggest power plant in Lombok Island which can supply 40% of the total Lombok Load at peak time. This power plant uses selected technology which is the largest combined cycle in Indonesia using a gas engine instead of gas turbines and the efficiency is well maintained.

The EPC phase of this project was started in August 2017. Even though the project finished on schedule, it doesn't mean this project goes without a hitch. We encountered some challenges during the construction.

In August 2018, a destructive earthquake struck the island of Lombok. It indeed affected our project works and the plant itself. Besides, the soil condition of the project site is also quite challenging as well as the subsea pipeline works. Then 2 years later, in March 2020, the Corona outbreak was confirmed to have spread to Indonesia. However, this challenging moment did not discourage us to give our best and achieve our goal. The milestone was successfully completed on 24th December 2019 for Simple Cycle-1, followed by completion of Simple Cycle-2 on 27th March 2020 and completion of Performance Test of Combined Cycle on 31st July 2021.

Despite the various challenges, the company maintained safety work in the project. Safety is the priority in all our activities. Overall, Bangkanai and Lombok Power Plant have achieved Best of HSE Implementation for 1.8 & >2 mio. total safe man-hours with Zero LTI (Lost Time Injury). We are optimistic that the completion of Bangkanai Gas Engine Power Plant and Lombok Gas Engine Combined Cycle Power Plant will bring an economic value not only for us or for the Project Owner, but also to the surrounding societies' economy. One of our guiding principles in undertaking our project is persistence. All the challenge is new learning for us and becomes our motivation to provide sufficient electricity in rural areas and its surrounding.

GECC Lombok Peaker ASIAN POWER 19

GENERATION REPORT: WIND ENERGY

India and Vietnam are projected to increase their wind capacity by 2030

Wind power finds niche in Asian markets, Fitch reports India and Vietnam are projected to increase their wind capacity 2030.

I

ndia and Vietnam are amongst the investment hotspots for the wind power sector, Fitch Solutions reported, as the two Asian markets are poised to see significant growth in their wind capacity in the next decade.

In its Global Wind Power bi-annual report, Fitch Solutions sees India and Brazil as the outperformers in the wind power sector. This comes as the two already large markets are both expected to double their wind power capacity over the coming decade. Vietnam, meanwhile, is the market to watch in the fourth quarter, as the report forecast its capacity growth will increase by over 400% over the coming decade.

Fitch said that rapid deployments in both onshore and offshore wind support its outlook, with the latter attracting large scale investments posing further upside risks.

In this case, Fitch Solutions defines ‘outperformers’ as the wind power markets that have a significant capacity base installed, and/or will register substantial growth in capacity over its 10-year forecast period to 2030.

Outperformers The new climate targets announced at the United Nations’ Climate Change Conference (COP26) summit by Indian Prime Minister Narendra Modi pose an 20 ASIAN POWER

India and Vietnam amongst wind power markets that will register substantial growth in capacity over a 10-year forecast period to 2030

upside risk to the outlook for wind sector growth in the market, Fitch noted. To hit these targets, the market will aim to increase its low carbon power capacity to 500 gigawatts (GW) by 2030 and meet 50% of its total energy requirements with low-carbon energy sources by 2030. The report highlighted that these pledges pose a mounting upside risk to our forecasted 43 GW of wind capacity growth expected between 2021 and 2030.

Despite this growth being the thirdlargest globally and sizable upside risks over the long term, India’s wind power sector is projected to face near-term challenges and underperform relative to government targets for 2022. Notably, India’s wind power sector is forecast to add only 8.2GW of wind power capacity between year-end 2020 and 2022, with wind power capacity set to reach 47GW by 2022–well below the 60GW government target.

The combination of several challenges in the country’s wind power sector will hit near-term growth momentum, including land availability hurdles, grid access bottlenecks, and concerns over the viability of low tender bids. In this light, Fitch’s cautious outlook relative to the government target is informed by the challenges the country is facing in

tendering and delivering the necessary capacity to meet ambitious expansion plans.

Delays to the implementation of tendered projects and more muted interest in new auctions, Fitch noted, will present a substantial hurdle to fulfilling these envisioned expansion plans.

Meanwhile, Brazil is a global wind outperformer with 23.7GW of wind power capacity additions expected to begin operations between 2021 and 2030–doubling the market’s installed wind capacity.

Fitch forecasts growth in the segment of 17.1% in 2021 to take capacity to 20.4GW, followed by average annual growth of 8.2% from 2022 onwards to reach a total capacity of 41.1GW in 2030. By the end of the forecast period, wind power is seen to account for 18% of Brazil’s total power generation mix.

The upward revision on the previous forecasts reflects an increasingly strong project pipeline, particularly in the medium term with around 14.5GW due to come online between 2021 and 2025. The sizable pipeline is the result of both private power purchase agreement deals as well as large renewables auctions which have resumed following their suspension in 2020 amidst early impacts from the pandemic.

The Brazilian government awarded 873MW in non-hydropower renewables capacity through the country’s A-3 and A-4 power auctions that concluded in July 2021, including 419.5MW of wind power, Fitch Solutions noted. The projects selected in the A-3 auction are scheduled to begin operations by 1 January 2024 whilst projects from the A-4 auction are set to begin operations by 1 January 2025.

Market to watch Fitch Solutions expects Vietnam’s wind power capacity to increase from under 3GW in 2021 to just under 13GW by 2030.

This growth is supported by project momentum across 2021, despite initial expectations for supply chain disruptions.

State-owned entity Vietnam Electricity (EVN) reported that there are over 106 wind projects with a total combined capacity of over 5.6GW that have registered to begin commercial operations before 1 November 2021. Fitch Solutions noted that this is as the feed-in tariffs for wind projects expired after this date, and as such developers rushed to complete the projects to attain more favourable power purchase rates.

In addition, Vietnam is looking to establish a new goal of developing 3GW to 5GW of offshore wind power by 2030 and 21GW of offshore wind by 2045. This will be supported by an offshore wind power purchase mechanism to stimulate the market and there are major projects that are in development.

Gas Power Project of the Year - China

Huadian Fuxin Guangzhou Energy Co., Ltd recognised with Gas Power Project of the Year - China at Asian Power Awards It manages China’s first SGT 8000H Gas Turbine Power Plant in commercial operation

Huadian Fuxin Guangzhou Energy Co., Ltd

Huadian Fuxin’s project launch marks the largest Combined cooling, Heating and Power (CCHP) project in China.

To pursue the policies of promoting clean energy utilisation, accelerating decarbonisation, improving gas power projects and advancing central heating, the first H-class gas turbines project in China with total installed capacity of 1340MW had been put into commercial operation successfully on 30 September 2020 by Huadian Fuxin Guangzhou Energy Co., Ltd. (Huadian Fuxin). The launch marks the largest Combined cooling, Heating and Power (CCHP) project in China.

As the pioneer of H-class gas turbine power

China’s first SGT 8000H Gas Turbine Power Plant

plants in China, the project is equipped with Siemens Energy state-of-the-art SGT5-8000H gas turbines, SST5-5000 steam turbines, SGen52000H generators and SGen5-100A generators.

The plant’s efficiency of pure condensing mode exceeds 62%, and its efficiency of energy utilisation surpasses 76%, contributing around 4.4 billion kWh of electricity per year. Its high-pressure main steam parameter reaches 16.7Mpa (a) / 600 ℃ / 610 ℃, the highest one of the combined cycle units in China ever. In addition, the waste heat boiler is equipped with SCR denitration devices which makes the average NOx emission less than 10mg / Nm3.

Each year, it contributes to the reduction of smoke and dust emission by 1437 tons, CO2 emission by 2.4 million tons and SO2 emission by 2230 tons, equivalent to planting 5 million trees.

Moreover, the gas and steam turbines of the project are arranged in a combined main building at a medium position with separate shafts, which represents the first of its kind worldwide. Thanks

to the excellent design and high management standards, the land use index of the power plant is only 0.073sqm/KW, 10% less than that of similar projects, and the unit kilowatt cost of the project is lower than 2000 RMB /KW, reaching the advanced level nationwide.

The unit also applied Siemens Energy SPPA-T3000 control systems, ensuring the maximum reliability, the highest efficiency, and the largest flexibility of the power plant’s control system. Furthermore, the power plant developed a set of digital platforms, such as APS (Automatic Plant Start-up and Shut down System), trends early warning systems, performance monitoring and analysis systems, robot inspection etc., which make the power plant stand for the highest intelligence level in China.

In late 2020, China’s government announced its commitment by reaching carbon peak in 2030 and carbon neutrality in 2060, which will bring a profound change in production and lifestyle, and will reshape the pattern of China’s energy and power industry. Clean energy production and electrification will become an inevitable trend. Huadian Fuxin’s project, located in Zengcheng District, Guangzhou City, Guangdong Province, is playing a key contributory role in support of the development of the Guangdong-Hong Kong-Macau Greater Bay Area with a supply of clean energy.

ASIAN POWER 21

COUNTRY REPORT: INDIA variable costs than some of the 20- to 35-year-old coal-fired power plants.

Similarly, plants younger than five years old operated at plant load that was 20% lower, despite having a lower variable cost than some of the oldest plants. The uncontracted capacity is, either, typically treated as merchant power and sold on the exchange or through other open market mechanisms.

The open market transactions contribute about 10% of the total procurement of electricity in the country.

Discoms need to pay fixed charges to thermal plants for the capacity contracted, regardless of the amount of power drawn from the plant. The variable charges are only paid for the quantity of power drawn from the plant. Once the discoms have committed the sunk cost of the fixed charges, then it is about choosing the lowest variable cost for drawing power. So even renewable energy sources with zerofixed charges but slightly higher variable charges would be more expensive than contracted coal-fired plants.

Ultra-low-cost renewables have been extremely disruptive for the Indian power market (Photo by Simone D. McCourtie)

India readies for cross-state electricity trading

This could pave way for cheaper power, but hurdles surrounding profitability remain.

T

he Government of India’s plan to commission 450 gigawatts (GW) of renewable energy capacity by 2030 has set the country’s power market on a transitionary path. Ultra-low-cost renewables have already been extremely disruptive for the Indian power market.

Whilst the expensive and emissionintensive coal-fired power generation assets have been affected most by the disruption, some has also trickled down to India’s power distribution sector, wrote Institute for Energy Economics and Financial Analysis (IEEFA) Analyst Kashish Shah.

India’s state-owned power distribution companies (discoms) are now confronted with the challenge of adhering to contractual obligations of legacy coalfired power purchase agreements (PPAs) whilst there is an availability of solar and wind power in the market at 40% to 50% cheaper tariffs than that of coal-fired power.

The response to this challenge by the discoms has been regressive to a large extent, IEEFA believed. Discoms have cancelled auctions that resulted in already 22 ASIAN POWER

India’s stateowned power discoms are confronted with the challenge of adhering to contractual obligations of legacy coal-fired PPAs

low-cost renewables striking deals at even lower prices.

In some cases, PPAs have been cancelled or forced to be negotiated to bring tariffs lower than the signed PPAs. This has significantly derailed India’s near-term target of 175GW of renewable energy capacity by the financial year 2021-2022; the renewables capacity stood at about 100GW as of July 2021.

The Ministry of Power’s recent proposal of a market-based economic dispatch (MBED) mechanism for procuring bulk power to begin in April 2022 aims to optimise the country’s power generation resources. By moving away from just state-level pooling of resources and dispatching power through a central clearing mechanism, MBED aims to reduce power procurement costs

by Rs12,000 crore (US$1.6b) annually.

A recent study from the Council for Energy Environment and Water found that the newer coal-fired power plants, commissioned between five and 10 years ago, had lower plant load factors in the 30 months leading up to the COVID-19 pandemic in India, despite having lower

India’s power system Discoms in India currently schedule generation on a day-ahead basis from amongst their portfolio of contracted generators. Self-scheduling has proven to be a suboptimal outcome for the power system in the country, with relatively higher costs being borne by ratepayers and, eventually, consumers. In some instances, it is also noted that the states have violated their own merit dispatch orders.

Self-scheduling restricts the discoms to share the generation resources across the country. This also leads to technical constraints on the amount of variable renewable energy (VRE) that a state can deploy within its boundaries. Centralised market-based scheduling and dispatch will ensure enlarging of the balancing area from the state boundaries to regional or national boundaries, bringing the desired flexibility for reliably deploying much higher levels of VRE. As the market becomes more competitive, cheaper plants will get dispatched first, raising the stranded asset risk on expensive thermal power plants.

The Indian Energy Exchange (IEX) has suggested an alternative mechanism of gross bidding to overcome the regulatory and structural changes required to implement the MBED model.

IEEFA referenced the example provided

by IEX to explain the gross bidding mechanism: Assume that a discom has a demand of 500 megawatts (MW), has entered into a PPA with a generator, and contracted a capacity of 400MW at energy charges of Rs2.50 per kilowatt-hour

COUNTRY REPORT: INDIA Gross Bidding Mechanism

Kashish Shah

Source: IEX

(kWh).

As per the existing practice, the discom will self-schedule 400MW of capacity under the PPA and will look to buy the additional 100MW capacity from the open market. In the proposed gross bidding mechanism, the discom will place sell bids of 400MW at Rs2.50/kWh in the market and buy bids of 500MW. The discom would ideally choose to buy the 400MW at a price equal to or lower than its contracted tariff of Rs2.50/ kWh and the remaining 100MW at the best price available in the open market.

Similar to the MBED practice, the settlement of capacity charges for thermal generators will happen on a bilateral basis between the discoms and the generators.

Depending on the demand and supply scenario, the sell bids of 400MW will get cleared and the generator will be despatched.

Consider a scenario where the MCP in the spot market is Rs3/kWh and the PPA tariff from the discom’s contracted generator is Rs2.5/kWh: Since the PPA price is lower for the contracted 400MW capacity, the discom will choose the contracted capacity at a tariff of Rs2.5/kWh. The discom will incur a procurement cost of Rs24m per day for buying power at Rs2.5/kWh and Rs7.2m per day for buying 100MW of capacity from the spot market.

In the gross-bidding scenario, the discom’s sell bid of 400MW will get cleared as it would be offered at a lower tariff of Rs2.5/kWh. On paper, the discom will sell this power to the open market and pay Rs24m per day to the generator while buying the additional 100MW from the spot market at a tariff of Rs3.0/kWh, incurring a cost of Rs7.2m per day.

Under either mechanism, the discom’s total power procurement cost turns out to be Rs31.2m per day. Hence, discoms neither gain nor lose in the scenario

where MCP is higher than the PPA. The below table compares discoms’ gain and loss between the two mechanisms for different scenarios for tariffs from the open market and the PPA. To get the discoms and the generators up to speed on this new mechanism, India’s Central Electricity Regulatory Commission has planned for a phased implementation. India’s largest stateowned power generation company, NTPC, will begin operating through the MBED route with its thermal generation fleet on 1 April 2022.

A similar pilot entailing securityconstrained economic despatch (SCED) of interstate thermal generation capacity was performed between April 2019 and January 2021. The pilot registered savings of Rs1,624 crore (US$210m) of generation costs.

Battery development in India power plants The Frequency Control and Ancillary Services (FCAS) Regulations to Drive Up Battery Deployments There are currently two utility-scale batteries operating in India. A 10MW/10MWh (megawatthour) battery is operated by Tata Power’s power distribution business in Delhi.

An 8MWh battery is reportedly being commissioned by L&T and owned by the Niyveli Lignite Corporation of India Ltd in the Andaman & Nicobar Island, colocated with a 20MW solar plant.

Recently, the Solar Energy Corporation of India rolled out a tender to procure 2,000MWh of a stand-alone energy storage system. Similarly, NTPC has issued a similar tender to procure 1,000MWh of capacity. Other battery projects are being developed by Renew Power, supported by long-term, timeof-day differentiated tariffs with 25-year PPAs. There also are more than 4GW of operational pumped hydro storage (PHS) projects with roughly 3GW under

construction.

The tariffs for the operational PHS projects exceed Rs7/kWh and are typically operated by the states to meet peak demand. Batteries and PHS projects could be supported by long-term price signalling and would predominantly operate to shave peak-demand loads.

The profitability of these battery assets is reliant on price arbitrage—charging during the time of low-price periods and dispatch during the high-price, peak demand periods.

The presence of a formal FCAS market puts value and merit to accuracy and speed of response to grid management requirements, further improving grid reliability. It would eliminate the grid operator’s cheapest avenue of managing the grid in adverse grid events—load shedding. The development of a formal FCAS market will open up another substantial revenue stream for utilityscale batteries and allow them to operate as an important grid management asset.

Coal Power Plants Age, PLFs, Variable Costs

Source: CEEW

Based on the demand and supply situation in the spot market, three different scenarios may emerge: Market clearing price (MCP) < energy charge: In this scenario, sell bids will be rejected, since power will be available at a cheaper price at the exchange. Discoms will buy the entire 500MW from the market at a price lower than the contracted energy charges. As the sell bid will not get cleared and the generator will not get despatched, the discom will not pay any energy charges to the generator. Discoms will gain in this scenario by procuring power at a cheaper price.

MCP = energy charge: In this scenario, both buy and sell bids will get cleared. The discom will buy from the market at the same price as energy charges and pass it on to the generator under the PPA. The discom will not have any loss or gain.

MCP > energy charge: In this scenario, both buy and sell bids will get cleared. However, the pay-in and pay-out of the discom will get exactly netted out with no additional obligation for the discom.

ASIAN POWER 23

COUNTRY REPORT: PHILIPPINES

The Philippines is poised to lead Southeast Asia in sustainability

It could 'leapfrog' to be a regional leader with renewables projected to be worth $30b by 2030.

S

outheast Asia could find a new leader in the Philippines in sustainability, should it reap its renewables’ potential projected to grow into a $30b market by 2030, Bain & Co. reported.

Bain & Co’s Perspective on the Green Economy report, conducted with Microsoft and Temasek, noted that of this projected renewable market, around 35% will be solar power. This could pave the way for investors to build infrastructures, such as electric grids and photovoltaic (PV) recycling plants.

The Philippines could also rise as a wind energy powerhouse with a 160-gigawatt (GW) wind energy potential in offshore areas within 200 km of its shores, making it one of only eight emerging markets across the globe. On top of this, it is also an ideal destination as global wind technologies can easily be adapted in the Philippines, considering it has no technological transfer limitations.

The Philippine government has yet to join Southeast Asian countries, like Indonesia and Laos, that have committed to net-zero. Despite this, the Philippines has set a 2030 target to reduce its carbon emissions by 75%. It has also planned

The Philippines has set a 2030 target to reduce carbon emissions by 75% and raise total installed renewable capacity to 38% by 2035

to raise the total installed renewable capacity to 38% by 2035.

Further, into its clean energy plans, the government declared in November 2020 a moratorium on new coal-fired power plant projects. This is followed by reports that the Philippines spent approximately $64b (P318b) in green projects, whilst its central bank invested some $550m in sustainable bonds.

Phasing out coal Currently, the Philippines is pushing to reduce emissions by phasing out coal and attracting green financing, Bain and Co’s report read in part. It added that in line with the government’s commitment, private firms have also taken part by being signatories to Science Based Targets Initiatives or setting their own net-zero or carbon-neutrality targets.

The moratorium will result in the suspension of about 8 GWs of prepermitted coal projects, the majority of which are expected to come online by 2026, according to Fitch Solutions, citing government sources.

Meanwhile, the coal projects that have been able to comply with environmental requirements will still be allowed to

The Philippines’ projected renewables market to grow to $30b by 2030, 35% of it being solar power 24 ASIAN POWER

proceed. Nearly 20-GW coal-fired capacity were in pre-completion stages as of end-2020, which is around 39% of the total capacity in the pipeline.

Also emphasising that coal is still the cheaper and more reliable option to meet the Philippines’ demand surge, Fitch predicts that coal will still dominate the energy mix in the country, reaching 59% by 2029.

“We now forecast coal-fired power generation to increase by an annual average of 5.2% between 2020 and 2029, amounting to approximately 93.6terawatthour by 2029,” it said. Fitch, however, said that its forecasts are subjected to “significant downside risks” as coal projects are being opposed by the public.

It also noted that key utilities in the country, such as AC Energy and Meralco, have intended to shift from coal.

By 2033, based on Rystad Energy Research, coal capacity in the Philippines is expected to have reached its peak and will be set to decline. Coal’s share in the country’s power capacity mix will likely drop to approximately 35% by 2030 and further down to 13% by 2050.

“The decline in baseload coal generation will need significant

COUNTRY REPORT: PHILIPPINES Addressing rural electrification issues will be critical to create opportunities for distributed power generation

Coal moratorium has been widely lauded by anti-coal groups and climate change advocates

compensating capacity from solar and wind sources,” Rystad Energy Senior Analyst Harshid Shridhar said.

Shridhar backed the report’s findings that the Philippines could lead the region with the appropriate financing and technology transfer terms as it set “ambitious” targets in PV module recycling and wind turbine recycling.

He added that the emphasis on green energy sources could benefit businesses, as well as manufacturing entities through incentives, such as the imposition of a reduced carbon tax.

According to a separate report by the Economic Research Institute for ASEAN and East Asia, coal generation could peak at 56% by 2030 despite the moratorium, due to power plan project developments that have already been approved.

“Whilst the coal moratorium has been widely lauded by anti-coal groups and climate change advocates, its effects will not be instantaneously felt,” Asia Clean Energy Partners Research Associate Ralph Justice Apita claimed.

“But with increasing public pressure, continued downward trend in the cost of renewable energy technologies, likely ADB financing for coal power plant retirements, and full foreign ownership of geothermal exploration in the Philippines, continued construction of even the greenlit plants will come under pressure, and the share of coal generation in the country’s power mix will decline.”

Attaining ambitious targets “For the country to achieve its ambitious sustainability targets, they will need to start with effective government leadership in establishing a research body like the Philippine Energy Research and Policy Institute, and soliciting groundlevel opinions from think tanks, to complement existing and upcoming policies with a scientific and evidencebased approach for a well-thought-out

public policy,” Apita said. He added the government should follow through with stricter implementation and constant monitoring. New administrations should also opt to recommit to these programmes to ensure continuity, instead of focusing on “less effective populist programmes.”

Moreover, the Philippines could also invest more in its grid capabilities as well as address challenges in giving far-flung areas access to electricity, as recommended by Black & Veatch’s executive vice president and managing director, Asia Power Business, Narsingh Chaudhary, and associate vice president for management consulting business in Asia, Harry Harji.

The Philippines will require increased grid flexibility and management capabilities to respond to sudden fluctuations in supply caused by changes in weather and time of day.

One way to approach this is by developing distributed energy resources (DER), such as solar and battery energy storage systems, Chaudhary and Harji

said. These could also include wind, microgrids, combined heat and power systems, backup generators, as well as technologies that enhance demand response offerings.

“These solutions are often installed behind the meter and funded by utilities, capital markets, or customers themselves,” Chaudhary and Harji said.

Rural electrification Addressing rural electrification issues, which is prominent in the Philippines as an archipelagic state, will also be critical as this will create opportunities for distributed power generation. For instance, microgrids can provide the power reliability that remote locations need whilst ensuring the facilities are commercially viable.

In addition, Black & Veatch said renewable energy can be paired with energy storage to enhance grid resilience. It can also be integrated into grid balancing solutions to balance generation variability whilst meeting decarbonisation targets. DER can also boost energy resilience by functioning as independent nodes to support interconnected power and grid solutions distributed across traditional networks.

“Whilst nations, like the Philippines, build their sustainable energy portfolios, they will also need to review their opportunities to transition away from coal,” Chaudhary and Harji said.

Black & Veatch noted coal plant owners may also consider the long-term economic viability of their facilities which have several alternatives, such as a full or partial fuel conversion to fuel sources like natural gas, biomass or hydrogen, retrofitting emissions control equipment or adopting carbon capture, use and storage solutions, and decommissioning aged coal assets for repurposing or repowering.

Renewable energy can be paired with energy storage to enhance grid resilience

ASIAN POWER 25

INTERVIEW

Scaling up India’s storage capacity will be slow: IEEFA India will need 27GW of grid-scale battery, the Central Electric Authority said.

I

ndia’s continued pursuit to attain its ambitious 450-gigawatt (GW) renewable source by 2030 gives rise to the need to ramp up its storage capacity to 27GW. In Delhi alone, 600 megawatts (MW) of storage capacity is needed—a drastic increase from 10MW currently.

Asian Power sat down with the Institute for Energy Economics and Financial Analysis Energy (IEEFA) Economist Vibhuti Garg to tackle the RE+ approach India should adopt.

What does India’s shift to renewable energy mean for the coal sector and how is this affecting coal plants?

During the months of mid-August to early November, there has been some coal shortage crisis happening in China, as well as in India. India also witnessed the electricity demand dropping in the financial year 2020 and during the early months of 2021. As a consequence, coal stocks in India hit a new record high of 132 million tonnes at the end of the financial year 2021, exceeding the average of 80 million tonnes in the previous five years. There was an expectation that India might witness another COVID lockdown, and as a result, the power plants were playing safe. They feel that they did not need to increase the coal stockpiles at their end because the plant load factors (PLFs) would go down and they won’t need or there won’t be enough demand to increase the generation.

In September and October 2021, India witnessed increased coal shortages with the majority of plans with critical coal supplies.

The government realised that and sprang into action. They asked captive mines to ensure maximum use of their mines and supply power to coal-powered plants. Further, the government ramped up production and even uptake of coal by increasing the rate for coal transportation. India witnessed an increased energy demand, but supply was becoming a bottleneck because of the extended monsoons and uptake. By the second-third week of November, the situation has improved and, fortunately, the temperatures have gone down in the northern part of India leading to reduced demand because the air conditioning load has substantially gone down.

With all this crisis, few states like Punjab, Delhi, and Maharashtra, agreed that they will buy power from imported coal-based plants to meet the energy deficit in their state and import fuel. Further, there is a push for increasing domestic coal production, but there are limitations given that there is no global financing for funding any new coal mines or coal-fired power plants.

If you now compare renewable energy with the cost of coalbased power plants, they are far cheaper, but definitely, there are grid integration costs involved. The batteries are still expensive for Indian consumers and the government has come up with certain production incentives. SECI, the Solar Energy Corporation of India, and NTPC Limited are also coming up with big energy storage projects. We are expecting more players to enter the market and more storage capacities to be developed. We will see a downward trajectory in energy storage prices in India, the same as what we are seeing in other parts of the world. We are hopeful that, in the future, storage or other newer technologies, like green hydrogen industries will have a much bigger role to play.

26 ASIAN POWER

Vibhuti Garg, Economist, Institute for Energy Economics and Financial Analysis Energy (IEEFA)

States like Punjab, Delhi, and Maharashtra, agreed to buy power from imported coalbased plants to meet the energy deficit in their state and import fuel

Can you tell us about the companies that are investing in storage and their plans?

So far, we just have a very small-sized battery plant of 10MW from Tata Power in the state of Delhi. The Delhi power minister talked about a plan to create a storage capacity of 600MW daily in the form of power banks. This would be a huge setup from the city’s existing battery storage capacity, which is the only existing capacity in India. Then we also have Tata Power that has bagged another big storage project in the city of Leh, in the newly formed union territory of Ladakh, which comprises 50MW hours of storage capacity. It’s going to be co-located with 50MW of solar capacity and this capacity is likely to be commissioned by 2023. Starting with 50MW hours, Tata Power has planned 13GW hours of gridscale battery storage in Ladakh.

We also have large players like Reliance, Adani setting up huge Giga factories in India for battery storage. But it will take some time. It won’t be in the next year itself. Reliance has acquired a lot of companies for both solar module manufacturing, and even battery storage companies, which will help them to access these newer technologies. Till the time domestic manufacturing picks up, we will have the Indian players tying up with companies in China and other parts of Asia for import. It’s gonna be a mix for a while and then maybe, with all these factories becoming operational, we’ll have more domestic solar modules and storage manufacturing happening in India. For the cost of battery storage, I can tell you in rupees per kilowatt-hour (kWh) what is the likely price if you combine solar with four hours of battery storage. So, the tariff turns out to be INR6.8 to INR7 per kWh, which is on the higher side.

INTERVIEW

The Delhi power minister plans to create a storage capacity of 600MW daily in the form of power banks

Just on raw solar, how much is that at the moment without the battery storage?

Solar tariff is now ranging between INR2.2 to INR2.4 per kWh. There was an imposition of safeguard duties, which was done away with, effective only until July 2021. Then, there will be the imposition of Basic Custom Duties from April 2022. So, the developers are factoring in the impact on the tariff of those duties when they are bidding. The module costs have gone up in the last five to six months on account of COVID supply disruptions. Such high module costs would be temporary. It is expected that the cost may go down to INR1 per kWh by 2030 for solar because of the efficiency in technology and then with the domestic manufacturing picking up will drive the costs down further. We’ll have a downward trajectory, both for solar and the battery prices going forward.

More importantly, with a lot of global financial institutions (FIs) announcing fossil fuel exit policies, there is a big pool of money available. India will be able to access finance at lower costs, which is also one of the big costs for India. Now, if you compare it to the Western world, the cost of finance is much lower, but global players are interested to invest in India as it provides higher return opportunities.

How achievable are India’s RE targets and what can India do to speed up their transition towards clean energy?

Quite achievable. The road ahead is very difficult, but India has made huge progress and provided the right set of policy signals. We shifted to the reverse bidding auction mechanism for these market reforms to guide the growth in renewable energy. And with the cost economics improving, any additional new demand is being seen to be met through renewable energy. We have seen an increasing decline in new coal-based capacity being set up. It looks like a lot of companies are now on board to help India achieve these renewable energy ambitions. I would say, these decisions are also being made because the board is also asking the companies to reinvent themselves and shift to clean energy to make a profitable business given that the coal-based assets in India were running at very low PLFs. The commercial viability of coal-based projects is becoming a big question mark, and the existing projects are incurring huge losses. Some of these assets around 40GW are, in fact, stranded, with an investment of US$40b to US$60b as stranded coal-based capacity in India. The board decisions are driving these companies to take the plunge and diversify themselves, adopting these cleaner technologies. As I said before, given that global finance is shifting towards these cleaner, newer technologies, raising any debt for new coal-based power plants or mining is becoming increasingly difficult.

The renewable energy target looks ambitious but likely that India will achieve that target if we see a continued increase in energy demand growth.

Do you think the Adani mine is really going to go ahead and come on stream or that it might not actually happen? Is the Adani mine proposed in Queensland to provide thermal coal?

Whilst Adani has been making huge targets for renewable energy

India needs to strengthen its green industrial policy. The government is expected to invest in India’s capacity to manufacture for the green energy ambition

generation, unfortunately, they do have some of these coal-based assets in India. I believe the assets in which they’ve already invested so much, might continue. There was huge back and forth with a lot of FIs backing out of that project, including a huge pressure on the State Bank of India. None of the private FIs in India is supporting any new coal-based power plants. To some extent, I believe Adani mine is already functional so it might operate. But if there is less and less demand for coal, I don’t know what they will do with that coal mine.

If Adani may want to build that asset further, there’ll be very few off-takers. One way or the other, maybe not immediately, but a few years down the line, that asset is likely to get stranded.

They were planning to use that coal for a power plant to supply power to Bangladesh. But I think Bangladesh has also realised, and they are further renegotiating power from that coal-based power plant because it’s expensive. Whilst that power project is built on a government-to-government agreement, approval of such high tariffs will face a lot of pressure going forward and there will be increasing pressure to reduce the cost. It’s just not worth importing that coal from Australia, firing it in India and then supplying that power to Bangladesh. Consumers do not have that appetite to buy expensive power. And yes, in the long run, it’s not viable to sell power from that project. Going forward with all the net-zero commitments coming from large parts of the countries, they will increasingly have a big issue in importing coal, not only to India but any other country.

The IEEFA said in its reports that financing is important for India’s decarbonisation goals. How can India attract more financing or lending for projects toward this goal?

India needs to strengthen its green industrial policy. As part of restarting the economy, we were expecting the government to invest in India’s capacity to manufacture for the green energy ambition.

Now, increasingly, huge factories are being set up for electrolysers because green hydrogen has again been touted as one of the big new areas as clean energy alternatives. India is coming up with huge state-level policies to boost more electric vehicles adoption and storage. Further, India needs to build and invest in large scale RE grid integration. India needs to start investing in the systems of tomorrow.

To unlock finance, India already needs to have a stable policy environment. It needs to work on resolving policy and the legacy issues to attract the FIs to bring in more capital to the deflationary domestic renewable energy sector. This would also involve undertaking some of the market reforms, like time of day pricing etc.

We need system-wide reform to improve the financial health of the distribution utilities because this will enable them to transition to the real-time market to meet energy demand. Very recently, the Ministry of Power announced another concessional loan in distribution companies to meet their working capital requirements so that they are able to make payments to generators. The government has come up with financial support measures to help discoms tie-up with the current crisis. In the past as well, the government had to bail discoms out of the financial crisis. We really need to improve the operational and financial health of the distribution company for India to achieve its renewable energy target.

India witnessed the electricity demand dropping in the financial year 2020 and the early months of 2021 ASIAN POWER 27

CEO INTERVIEW

Direct PPAs should be scaled up: Asia Clean Energy But doing so poses financial risks to the operator due to the longevity of contracts.

T

he lack of feed-in tariffs or regular competitive auctions serves as a barrier to the clean energy transition in the region, and this can be at least partially addressed through a direct power purchase agreement (PPA).

Asian Power spoke with Asia Clean Energy Partners’ Managing Partner Peter du Pont on how DPPAs are done and why these should be scaled up in Southeast Asia in response to the lack of open access to grid generators.

Du Pont has over 30 years of experience in sustainable energy and efficiency both in the US and Asia. He is Southeast Asia Regional Coordinator for the Private Financing Advisory Network and has previously served as Senior Climate Change Advisor for the US Agency for International Development in Asia.

In a May report, Asia Clean Energy Partners found that the AsiaPacific region is amongst the most challenging markets in the world for businesses seeking to shift to renewable energy. Is this still the case in the region and what are the remaining challenges for businesses switching to renewables?

Yes, there are continued barriers to the scale-up of renewable energy in Southeast Asia. It’s not easy to get renewable energy installed in a way that you can use it on-site and also sell it to the grid. You can install solar rooftops in most countries in Southeast Asia, but you cannot always sell the excess of the solar capacity onto the grid, and this creates a problem.

In Thailand, where there’s not a feed-in tariff in place for large commercial and industrial customers, there’s a huge market—the “behind-the-meter” market, where solar companies come in, and they install systems, with say 300 kilowatts (KW) or 500KW of solar panels on the rooftop, and they cannot export to the grid because regulations don’t allow that. They have to undersize the system, so the amount of electricity that they are producing, even at the peak time, will not be more than what they are using in the factory. If it’s more than the use of the factory, they have no place to put it, so you have sub-optimal systems. The fundamental problem is the lack of a feedin tariff or net-metering mechanism, which can allow facilities to sell electricity to the grid at a good price; and also the lack of open access to the grid for third-party solar project developers.

In Vietnam, the government is testing out something called a direct PPA, which could really unlock a lot of activity in the region.

A direct PPA would allow a renewable energy developer to put in a small solar farm, sell it to the grid and wheel the power over the grid, and then somebody else could raise their hand and say, I want to buy that power. So that ability to enter into a contract with a producer of renewable energy, and to buy that power through the grid, having it wheeled through the grid, does not exist in most Southeast Asian markets. So you have a very closed market. And that’s a fundamental problem—the lack of open access to the grid for generators, and therefore consumers pay higher prices for electricity.

If they can’t feed into the grid, at what point would it be economic to store excess power in batteries?

Let’s say the average price that a factory in Thailand would pay for electricity is about four baht. That’s about 13 cents a KW-hour. There are many project developers who can go in and put a solar rooftop onto a factory. And there are thousands of megawatts (MW) of solar rooftop PV being installed across Thailand. They put solar PV 28 ASIAN POWER

Peter du Pont, Managing Partner, Asia Clean Energy Partners

With the lack of open access to the grid for generators, consumers pay higher prices for electricity

on the rooftop of a factory, shopping centre, or building. The solar electricity that the owner of the factory or the store will buy from the solar company is about two baht, which is about eight US cents a KW-hour. Meanwhile, the factory owner is paying about 4 baht per KW-hour—which is about 13 US cents per KW-hour—to the electric utility. So a solar project developer is coming in to put on a solar rooftop and the electricity that this provides is about one-third cheaper than the electricity they are getting from the grid. That’s a great deal. Does it make sense to put a battery in? Generally, no. I am not aware of companies coming in and saying we’re going to make a bigger system and make it twice as big and put a battery in because the economics are not there for that.

One of the biggest problems in this whole dilemma is how the Thai utilities, PEA and MEA, can continue to pay for the upgrading and maintenance of the grid, whilst they are losing load from customers who are putting in solar rooftops. The best thing that could happen is, instead of putting a battery at the site, you can allow the export of power from the solar rooftop to the grid and use the grid as a battery.

So if you have that excess power from your solar rooftop, then that just goes into the grid, a feed-in tariff, or net metering process. But the reason that the Thai utilities are not accepting power exports into the grid is that they have an oversupply in most regions of the country, and they do not have a way of being compensated by customers for the value of using the grid as a battery.

What other policies should be implemented by governments in Southeast Asia to attract more investments to clean energy?

For utility-scale solar power, there’s a trend away from feed-in tariffs

CEO INTERVIEW toward competitive procurements across the region, and this is a good thing because it brings down costs.

For rooftop solar, stores and factories need to get a fair rate.

In some of the customer segments, Thailand is doing net billing for rooftop PV. For some customer segments, such as the small commercial, and residential, the utilities only pay customers about 2.1 baht (about 6-7 US cents) per unit when they buy electricity from rooftop solar systems. But the utilities charge customers about 4 baht (or 13 cents) per unit for electricity that the utility sells to them. So if you have your solar on your rooftop, and you’re selling it to them, you only get about half the rate for selling your electricity to the utility, compared to what the utility charges you for their electricity. That’s not a good deal. There needs to be a fairer deal for the solar rooftop customer.

The rate that utilities pay to solar rooftop owners needs to be increased to make economic sense. But at the same time, it is clear that the utilities should be able to charge a reasonable fee for the service of allowing solar rooftop owners to inject electricity into the grid, and essentially use it as a battery.

What we’re trying to do is just get renewable energy into the system by allowing for direct PPAs, which I described earlier. Wheeling of electricity is a common practice, and it is being implemented in other parts of the world, and it is an approach that can be tried and scaled up across the Southeast Asia region.

With regard to utility-scale solar, where companies are setting up solar farms, one of the biggest limiting factors to reducing the cost of production is the cost of capital. In Thailand, the typical cost of capital for renewable energy is in the range of 3% to 5%; in Vietnam and Indonesia, and the Philippines, it’s a bit higher, at 5% to 7%. If it costs you 6% or 7% to borrow the money, then it will make a big difference in a five-year or 10-year contract, compared to someone who gets the money at 3% or 4%.

What are the risks in implementing direct PPAs? The fundamental risk of allowing direct PPAs and wheeling is the financial health of the utility that operates the grid. The problem that the utilities are facing is that many of the utilities operating the power systems have entered into long-term contracts to get stable power, and they are typically locked into the prices in these contracts for 10 years or more.

If the electricity regulator allows direct PPAs and wheeling, then you will have new generators coming in and selling power at rates significantly lower than the utility’s current tariff. When this happens, the off-takers, the utilities who have committed to these long-term contracts, have financial risks because they’ve already committed and they may not be able to enter into direct PPAs at lower rates. In my view, direct PPAs are a good tool, but they should be gradually phased in.

What is the current pricing of battery storage per MW-hour that you’re seeing in the market?

Actually, the fundamental challenge that utilities have is to meet demand at peak times over a relatively limited number of hours, typically hundreds of hours over the course of a year. We are increasingly seeing that it is cheaper to provide peak power using battery storage coupled with solar or wind energy, as opposed to having gas peaking plants. It’s quite likely now, definitely going forward, that battery storage and solar will be more cost-effective than peaking gas plants as a way of meeting peak demand in Thailand, and many other Southeast Asian countries. If solar and storage are not more cost-effective than peaking gas now, they will be in a year or two, and it will depend upon the specific use case, such as the size of the plants and the number of peak hours you’re trying to cover.

Why has the market been strong in Thailand and why hasn’t it taken off in other markets such as Indonesia?

Actually, the market for solar has taken off in Vietnam, where they

Developed countries have no business putting pressure on developing countries to go net-zero faster when they haven’t lived up to their commitments for financing

have installed more than 10,000MW of both utility-scale and rooftop solar over the past two years. Vietnam has a lot more solar rooftops than Thailand because there’s been a government policy with a feedin tariff for solar rooftops. Thailand’s market is almost exclusively behind the meter and it has taken off because the cost of solar is onethird less than the utility tariff. There are at least 100 or more really large companies that each have scores of megawatts of solar rooftop in their portfolios, in markets such as Indonesia, Malaysia, Thailand, and Vietnam. I expect that this activity will only increase.

Thailand’s solar rooftop market is very active because the economics are so good, but it’s very inefficient. The amount of solar rooftop is much smaller than it could be if you didn’t have undersized systems due to the lack of net metering. So you basically end up with having undersized systems on many factories when you could have many, properly sized systems if you had net metering. But this would put a big strain on the utilities. The markets, to the extent they’re active in other countries in the region, are mostly like this, behind the meter, and this greatly limits the amount of rooftop solar getting built.

What additional pressures will be put on Asian governments that are still reliant on coal, following the COP meeting in Glasgow?

There seem to be a lot of caveats to the net-zero pledges and no new coal plant pledges.

Let’s separate net-zero for countries versus companies. We’re talking about developing countries in Southeast Asia, where the discussion around climate change is a very different discussion from that of developed countries. It’s really about equity between how developed and developing countries address climate change and how quickly countries move to reach a decarbonisation target.

For example, most of the climate targets that developing countries have set are highly conditional upon financing that was pledged by developing countries as part of the Paris Agreement. That’s supposed to be $100b a year by 2020 to help fund decarbonisation. If you look at the climate targets or the nationally determined contributions or NDCs, they have two targets. One is the target for what they will achieve with their own resources, and this is typically a smaller number. The other target is the amount that countries will achieve if they have international climate finance support, and this target will be many times higher.

I think developed countries have no business putting pressure on developing countries to go to net-zero faster when they haven’t lived up to their commitments for financing. Where’s the $100b, right? You have to take care of that first.

Furthermore, the discussion should not be about net-zero, it should be about net-zero with development, which we call ‘Beyond Net-zero’. How do you meet the development needs of countries such as the Philippines, Thailand, Vietnam, Cambodia, Laos, Myanmar?

How do you get people out of poverty, create good-paying jobs, and meet development objectives, including the UN Sustainable Development Goals? I think the discussion around net-zero should be focused on how we can do net-zero for Thailand, Indonesia, and all of these other countries in a way that meets their development objectives first and foremost.

Discussion should be about net-zero with development, ‘Beyond Net Zero’ ASIAN POWER 29

INTERVIEW

India is aggressive in privatising discoms

Most public discoms are on the verge of bankruptcy because of high AT&C losses and political populism.

I

n India, most public distribution companies (discoms) are facing bankruptcy due to aggregate technical and commercial (AT&C) losses, but these are expected to decline as the government moves to privatise distribution and enable discoms to collect revenues better.

NITI Aayog, a state-owned policy think tank, reported in August 2021 that the discoms’ total loss is estimated to be ₹90,000 crores (US$12.1b approximately) and the accumulated overdue payment stood at ₹67,917 crores (US$9.13b), as of March 2021. Moreover, according to the Ministry of Power in August, the AT&C losses fell to 21.83% in 2019-2020 from 23.5% in 2016-2017.

Arthur D. Little’s Managing Partner Barnik Maitra discussed with Asian Power the state of India’s power sector. He also touched on the topic of discoms’ privatisation and shed light as to why the country is prioritising it.

Can you give a brief overview of where India is now in terms of its renewable targets? How is it faring compared to other countries?

Most markets, like Indonesia, the Philippines, China, and Vietnam, are very coal-dependent. The challenge has been how to increase the share of renewable energy (RE) without shutting down coal plants because all of these are dynamic growing markets. The strategy adopted by most countries, India, in particular, is to not add more coal capacity unless it’s completely needed or critical. The post-COVID economic recovery in India has been much faster than anticipated, yet mining productivity and the coal supply chain has not kept pace. Again, things like these just emphasise the need to move away from it. Amongst a lot of countries, India has done quite well. They’ve set reasonably aggressive targets. I think they’re currently at an installed capacity of RE of over 100 gigawatts (GW), which they’re planning to quadruple to 450GW by 2030.

The approach that India has taken is two-fold. One is there are very reasonably attractive subsidy mechanisms put in the earlier phase and now they’ve also completely relaxed foreign direct investment (FDI) norms to push RE. It’s a calibrated, slow journey but you have to realise that in emerging markets, it’s very difficult for you to do a dramatic shift; but India’s adding the capacity. India is able to deliver because of the subsidy mechanism, the FDI mechanism. A couple of Indian conglomerates, like Adani Energy, have also made big bets on RE. Tata Power is the largest private utility player that made a big bet on renewables. Tata Power had set a 2025 goal of having 35% of its generation capacity from renewables. I think they’re already at 32% of generation capacity from clean energy sources, which is a noteworthy mix. Adani recently picked up all of SoftBank’s RE portfolio.

I don’t think we will get to a place where coal will completely be phased out. But fast forward to 10 years from now, you should be able to see at least 35-40% renewable in markets like India. The last mega coal-fired project in India was commissioned or was announced in 2010. Since then, there have been no big projects announced. These are the measures that governments are taking. Will this be enough?

Probably not. But again, it’s a good start and good progress in a country like India.

How viable are the targets of India in reducing emissions?

Six to seven years back when the push towards solar started, the total cost of production was around ₹8 to ₹10 a unit per kilowatthour, compared to coal, which is around ₹3. Now, if you’re going to also store it, because what this does not include is the battery costs 30 ASIAN POWER

Barnik Maitra, Managing Partner, Arthur D. Little

Most markets are very coaldependent. The challenge is how to increase the share of renewable energy without shutting down coal plants

and often that becomes 50% to 60% more when it started seven to eight years back, there was a five, six times delta between the two sources. Now because of technology and innovation, what was ₹8 to ₹9 is already down to ₹3 and the battery’s also down from ₹7 or ₹8 to another ₹3; So, if you look at the cost curve, it is not below coal, but it is at least on a comparable basis and getting more competitive as storage costs improve.

In distributional markets in India, the industry and the commercial segments cross-subsidise the agriculture and residential segments, which means industrial users and commercial users pay ₹8 to ₹9 per unit of power. If you supply power to them at ₹6 to ₹7, you are actually not losing money, making the business case in itself viable.

The government is also now pushing incentives to encourage home users to do rooftop solar. With the capital subsidy, the cost numbers look very different. The nature of the power grid itself is shifting, but if you fast forward 10 years from now, rooftop solar becomes more important because all utilities are going to move to micro-distribution or microgrid models. There are already pilots beginning on how to do microgrids, generate closer to demand and not generate centrally and transmit long distances. As we move towards microgrids, I think you will have rooftop solar becoming an integral part of grids and India has put subsidy mechanisms in place to encourage installations. The government has now realised that the nearly bankrupt public distribution, cannot be made financially viable. They have actually realised it’s better to gradually privatise distribution than recapitalise public distribution companies.

INTERVIEW Why are they bankrupt?

One is obviously the classic AT&C losses, which are very high because of theft. Most markets are operating above 20%; whereas the benchmark is 6% to 7%. Reason number two is political populism.

In a lot of states, agricultural power is free and residential power is subsidised extensively. In a few states, in the residential sectors, the first 100 units are given free. So there is a lot of adventurism on behalf of local politicians who actually announced free power with the public discoms left to collect the tab. The problem of inadequate collections and high AT&C has driven these discoms to the verge of bankruptcy.

I think that the government, a couple of years back, pumped in several billion dollars into the public distribution sector, all of which has disappeared because collections and AT&C losses were not addressed, and they are again bankrupt or on the verge of bankruptcy.

What value do you think could be unleashed in privatisations?

If you look at the performance of a private sector distribution, the AT&C losses can get to as low as 6%, whether currently operating at over 20%. If the government wants you to subsidise power, they pay you the subsidy and you don’t bet on a customer’s behalf. That model is proven. You will not lose money if your power mix is 50% renewable and 50% coal because you will be able to realise tariffs, which are ₹4 to ₹5 from the residential segment minimum and ₹8 to ₹10 from the commercial sector. If you look at Tata Power’s strategy, they’re already ahead on the generation piece where they’ll get to probably 40-50% renewable mix in 2025 or 2026. And as a private distribution company, as they reduce AT&C losses to 6%, even distribution becomes financially viable.

Then there’s another big movement, which involves smart meters.

A lot of electricity losses are not really theft but driven by archaic manual measurement practices. The New Electricity Bill, which is going to get passed in India soon, actually mandates the compulsory installation of smart meters in every single household.

So what will happen is that by 2027-2028, 80% or 90% of Indian households and commercial establishments will have a smart meter.

This will help distribution companies collect more. How? Say, you’re a resident with a shop in your garage and you are running heavy electricity guzzling equipment like multiple A/Cs, refrigeration equipment and you need to be rated at 10 Ampere and not 5 Ampere. Automatically there are some implied tariff losses that happen because customers are fundamentally not really rated as for the usage and smart meters will plug this by providing accurate consumption and load data to the discom. Not only will smart meters plug AT&C losses, but these revenue losses also.

For the plants coming to the end-of-life cycle, the government is considering creating disincentives for renewals

By 20272028, 80-90% of Indian households and commercial establishments will have a smart meter

Do you have any idea how much the market will be for smart metering in India once this new law comes through and if there is full privatisation of the distribution networks?

I don’t think the government is going to pay $5b needed for installing

The market for smart meters in India is going to come up to 250 million smart meters in the next 10 years

smart meters. I think the government will give it for free in a way to the consumers with the discoms bearing the initial deployment cost and the discoms, in turn, recovering it from end customers gradually. Remember, these are all debt-laden public discoms that have no financial viability today to roll out smart meters at scale. I think the market for smart meters in India is going to come up to 250 million smart meters in the next 10 years. investors are looking to create smart meters manufacturing facilities because they see this $5b opportunity and they say, listen, even if we get a 20% share, that’s like 50 million smart meters. That’s the other step. Coming back to the fundamental shift, the moment privatisation happens, everybody can collect better. With the push for privatisation, better capitalised private discoms will only accelerate smart meter deployment. With at-scale, smart meter deployment discoms will have higher collection efficiencies and better AT&C losses. This in turn will also indirectly fund a greater renewable energy mix in the end-customer consumption portfolio. So, in a way, privatisation of discoms and smart meter adoption can become interesting catalysts for India’s push towards more clean energy adoption.

Do you think there’ll be no more large power plants built in India? Or do you think the existing ones coming to the end of their life will be renewed with another plant?

There will be no new mega coal-powered greenfield projects because there are no incentives for them. For the plants, which are coming to the end-of-life cycle, I think the government is considering creating some disincentives for those power plants to be renewed or incremental capital to be put in because the strategy has been all-new demand serviced by green energy. As plants come up for renewal, we should be able to shut most of them down. Now, whether everyone will do it or not, is another question. But if you look at major private generation companies, I think most of their plants will come end-of-life in another five to 10 years.

Some of the coal-fired plants may get renewed, but the economics of that will be different from the original economics.

Remember initially when these plants got set up, the reason why coal is at ₹2 a kilowatt-hour is that they were built on very attractive capital subsidies. If you look at the big Tata Mundra, it’s an ultra megawatt power plant of 4,000MW. It was commissioned in 2012.

The original bid tariff was ₹2.26 per unit and the unit needed government support with future offtakes negotiated at ₹4 to 5.

Now, the government is clear that there’s no capital subsidy for coalfired plants. So six years from now, there is a very possible scenario in which as you’re renewing a plant like this, the ₹2 suddenly begins to look like ₹4 to 4.5 (as happened with Mundra), because there’s no government subsidy, no capital subsidy, and no tax subsidy.

And the solar power may be close to ₹4 to 7, I think at that point in time, every single such plant will getting renewed will be an unlikely outcome.

ASIAN POWER 31

EVENT COVERAGE: SIEW

Emerging and developing Asia needs to increase RE contributions by 50%

Energy demand is expected to grow by 3% annually over the next two decades, the IEA projected.

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n today’s policy settings, renewables in 2040 are expected to meet around 30% of the demand growth; but in the case of emerging and developing countries in Asia, renewables will need to be increased by more than 50% to meet the same goals, said International Energy Agency (IEA) Head of Energy Supply and Investment Outlooks Michael Waldron.

“This would need to be combined with dramatic efforts to improve the energy intensity in terms of the use of energy to slow the energy demand growth,” he said.

At present, energy demand will likely grow rapidly in emerging and developing countries in Asia. In particular, energy demand could rise by 3% annually over the next two decades, whilst electricity demand could grow at a faster rate of 4% per year over the same period.

This will come as Asia continues to industrialise, urbanise, and electrify, Waldron said, citing Vietnam and India, where governments have put in place policies that have expanded access to energy and increased uptake of energy efficient appliances, respectively.

Meeting net-zero goals On top of this, he said the growth will also be driven by a doubled demand for cooling households with air conditioners in Southeast Asia in the next 20 years.

“In order to keep the door open for the world to meet its net-zero emissions goals, this progress would need to be even stronger. This means a massive acceleration in energy in order to help curb oil-use for transport, to narrow gas demand to areas 32 ASIAN POWER

Climate ambitions have never been higher, but the energy and emissions data does not yet match the rhetoric

where it helps to bring down emissions,” he said.

Waldron was speaking at the 2021 Singapore International Energy Week during which the IEA officially launched its World Energy Outlook (WEO) report for 2021 in Southeast Asia. The report found that climate ambitions have risen to new heights with 120 countries that account for more than half of global emissions, announcing new policies in the last year.

Turning pledges into action “What is absolutely clear is that climate ambitions have never been higher, but the energy and emissions data does not yet match the rhetoric,” IEA Deputy Executive Director Mary Burce Warlick, said.

If implemented, the pledges could result in a “substantial change” in the current emissions trajectory, but would still leave a gap to limit temperature increase to 1.5 degrees Celsius. Warlick said the new pledges only closes 20% of the gap between the current trajectory and the net-zero target. This leaves an “ambition gap'' of almost 14 gigatonnes (Gt) of greenhouse gases in 2030. This is also nearly equivalent to the emissions of the Organisation for Economic Co-operation and Development states.

Further, the pledges will only close 40% of the gap by 2050, which as Warlick said, could pose risks of hitting “irreversible climate tipping points,” such as sea level rise and acidification. She also reiterated that to attain the Paris agreement commitment of limiting warming to 1.5 degrees, net-zero emissions should be reached by 2050.

“Without global concrete commitments now to reach net-zero by 2050, we will lock in emissions and we will not make sufficient progress in innovation and clean energy technologies to get us there,” she said.

Despite this, Warlick said there are policies and cost-effective technologies that could help narrow the ambition gap by almost half in 2030. The IEA estimated that up to 60% of the gap could be closed through cost-effective expansion of wind, solar, and hydropower as well as the lifetime extension for nuclear power facilities already online. The WEO found this could reduce the need for coal by 350 gigawatts (GW) and pave the way for the retirement of an additional 150 GW of coal without threatening either electricity security or prices.

Warlick added that reducing methane emissions from fossil fuel operations could lessen about 1.7 Gt of CO2 emissions through measures that are technically feasible and well known. On top of this, another 1 Gt could be cut from emissions through end-use efficiency that can be achieved through stronger fuel economy standards, particularly in trucks, appliances efficiency, and industrial energy efficiency.

Others may come from combined energy demand reductions in investments in technologies such as hydrogen, advanced batteries, carbon capture, utilisation and storage or CCUS, and advanced biofuels.

“Enhancing the near-term deployment of these known technologies can spur innovation and accelerate the deployment of complementary enabling infrastructure and this, in turn, can allow these technologies to play a much larger role in the longer term after 2030,” Warlick said.

The path to a net-zero world The IEA projected that driving the world towards the net-zero pathway would incur an annual cost of US$4t by 2030 in terms of investments in clean energy projects and infrastructure. However, whilst that is the case, she said the cost of investment needs to “more than triple.”

“The bottom line is that, substantially, more clean energy investment is essential to maintain reliable energy supply, if and whilst oil and gas investment remains stable, or declines along with demand,” she said.

The IEA also estimated that the cumulative market opportunity for manufacturers of wind turbines, solar panels, lithium-ion batteries, electrolyser fuel cells could be worth US$27t, should the net-zero target be attained by 2050.

EVENT COVERAGE: SIEW

Should governments invest in available technology today to reach net-zero?

Wait for technologies with enough economic feasibility, Senoko Energy chairman advises.

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ith all eyes set on transitioning to clean energy, governments are taking a technology-led approach, with hydrogen and carbon capture emerging as the key technologies in achieving their net-zero targets. However, experts argue that investing in these technologies today could be a premature move.

Economic feasibility and recovery period of investment are the major concerns that governments and companies should consider in investing in technologies that will aid them in their decarbonisation goals, Senoko Energy Chairman Akihiro Fukuda said.

In Singapore, for instance, although the energy market is expecting hydrogen power generation to become financially feasible by 2030 or 2035, Fukuda said it is too early for power generators to invest in hydrogen power plants due to the lack of economic feasibility.

Fukuda said investors should instead consider the “sustainability of the existing energy-only market and the existing power generator.”

“The existing generating companies need to survive until such date that the hydrogen power that technology achieves economic feasibility so that the existing generator themselves becomes the platform to convert the existing power units into hydrogen compatible infrastructure switching from gas fuel to hydrogen fuel, switching from existing gas turbine to hydrogen turbine,” he said during a session in the Singapore International Energy Week.

Investing in renewables Investors should also consider the sustainability of the newly invested renewable infrastructure, as new technologies in renewables that are so innovative “often become obsolete or less competitive in a short period of time.”

Fukuda noted that a new investment to implement an infrastructure for the renewable energy input that is not recoverable within a 10 years time frame at a competitive price setting would need a longer period of time to recover returns.

“Hence, ensuring a level playing field is essential to secure the economic sustainability of both the existing power generator and the newly invested renewable infrastructure,” he said. “Before that, we need invention, if you will, in the regulatory and financial framework in tandem with an invention of new technologies to help mitigate the risk that the investor might

Our technology, not taxes, approach will allow us to reduce emissions without damaging our reliability as an energy supplier

face with the rapid evolution of the new technology.”

Present situation “A technology-led approach is the only way we can maintain energy security in our region, and at the same time, drive economic growth,” Angus Taylor, Australia’s Minister for Industry, Energy, and Emissions Reduction said, as his country is on its way to achieving its net-zero target by 2050.

“Our technology, not taxes, approach will allow us to reduce our emissions without damaging our reliability as an energy supplier, and the thousands of jobs that depend on those exports. We've already seen renewable energy technologies deliver extraordinary reductions in costs in our electricity sector,” he added.

Taylor said that the growth of renewable energy use in households such as solar and wind has been rapid, adding that they expect renewables to account for more than half of its electricity within a decade.

Australia also plans to reduce emissions as well in other sectors like agriculture, mining, and manufacturing but the technology solutions are still expensive to deploy or are still in the research and development (R&D) stage. This includes clean hydrogen, carbon capture and storage, and low emissions materials like steel and aluminium, he said.

Taylor added that they are aiming to cut the production cost of under $1.48 (AUS$2) per kilogram for clean hydrogen and under $14.79 (AUS$20) per tonne for carbon capture and storage. The Australian government is investing $14.8b(AUS$20b) this decade for the deployment of low emission technologies which is expected to leverage at least $59.2b (AUS$80b) of public

and private investment by 2030 and in turn create over 160,000 jobs.

Australia is also partnering with other governments for low emission technologies such as Singapore, Japan, Germany, and the United Kingdom, committing over $417.8m (AUS$565m) this year, he said.

The State Grid Corporation of China, meanwhile, aims to build a power system based on new energy and become an “energy internet” company. It also plans to create new business models and expand industrial and value chains.

“In technical innovation, we have launched R&D framework and are building our power system based on new energy aimed to work, make breakthroughs in source grids, low storage coordination, and the green power markets, active support of the new energy generation is central, and to advance the next zero power projects on energy internet,” President Zhang Zhigang said.

Zhigang also said that they plan to integrate its large grid, microgrids, and local VC grids. The SGCC also plans to build a digital system or equipment management powering the transmission, transformation, and distribution.”

“We will provide our customers with high quality, diversified and interactive and personalised energy services and through the efficient allocation of our core resources,” Zhigang said.

Emerging technologies Technology and digitalisation also play a vital role in the transition of Keppel Offshore & Marine to cleaner products and renewables, according to CEO Chris Ong, noting that aside from having installed about 21,000 rooftop solar panels, they are also delving into battery storage.

ASIAN POWER 33

EVENT COVERAGE: SIEW

Carbon pricing of $75 per tonne to ‘shock’ global economy: ADB

With such a price, the 36.4 Gt of carbon emissions in 2019 would amount to about 4% of the world GDP.

A

proposal to impose carbon pricing worth $75 per tonne on average by 2030 could lead to a “huge shock” to the economy that is comparable to oil shock in 1974, the Asian Development Bank (ADB) said.

During the Singapore International Energy Week, ADB Principal Economist Lei Lei Song said that whilst carbon pricing is necessary to advance the transition to the green economy, the proposed carbon pricing is such a big number.

Assuming that a $75 per tonne pricing is implemented, Song said the 36.4 gigatonnes (Gt) of carbon emissions generated in 2019 would be equivalent to 3% to 4% of the world’s gross domestic product (GDP) in the same year.

Song noted that in 1974, oil prices jumped to $11 per barrel from about $3 to $4 per barrel, which amounted to about 3.5% of world GDP in the 1970s.

“We have already seen some indication signals from the global shortage of gas and coal. And with such a big negative shock to the economy then definitely, unfortunately, it will represent a huge structural shift in the world economy,” he said.

Further, Wong pointed out that along with this comes a structural shift in jobs, which could either be displaced as carbonintensive industries are hit by the transition, or created as the green economy expands.

Job gains and losses Based on estimates, Wong said the renewable energy sector is expected to create some 24 million jobs by 2030. He, however, noted that much still needs to

34 ASIAN POWER

We have already seen some indication from the global shortage of gas and coal. This negative shock to the economy will represent a huge structural shift in the world economy

be learned on how many jobs will be lost in carbon-intensive industries, both in manufacturing and services.

In this light, he raised the need to invest also in retraining people as he expects the green economy to be highly serviceoriented.

“It needs a lot of services, not only to service those final products, but also service for these energy sources because our new green energy might be a very distributed and decentralised source,” he said, citing the installation of solar power for instance. He added other renewables, such as wind and hydrogen, may eventually require more service as it is likely to become widely distributed in the future.

He also expects small and medium enterprises to be at the forefront, in terms of providing these kinds of services.“They have a comparative advantage against big companies because they can provide localised, tailored services and can respond really fast to each of the consumers,” he said.

Energy transition On the part of ADB, Wong shared that it is working on an energy transition mechanism, which will accelerate the transition from coal to cleaner energy in Southeast Asia. He explained the initiative will combine concessional financing resources and commercial financing to retire coal generation assets earlier and to later reinvest in renewable energy.

The ADB has also raised its climate financing for developing member states to $100b from 2019 to 2030 from only $80m

previously. Wong noted this is a significant share of ADB’s investment in the region.

Safety of renewables Jen Tan, Sembcorp Industries’ head of Integrated Solutions, Singapore and SEA, raised the need to put more emphasis on general work, noting that whilst clean energy is not as complicated as coal, it is easy to commit mistakes in renewables.

Tan said good installations have been seen in countries, like Vietnam, but there are instances where the installation is subpar and can be likened to building lego blocks.

“I think that is something that we need to be worried about because the more you have of that and the more safety and fire incidents that you have, the more it will make people very defensive towards solar in the country,” she said.

Moreover, in the case of Luxembourg, as shared by its ambassador to Thailand, Jean-Paul Senninger, state intervention was instrumental in how it ushered workers through the transition.

“Because if you lose jobs in the old economy, and you do not start retraining your people early enough in the process, you lose them forever. And then you do not only lose jobs, you not only lose economic possibilities, but the society as a whole loses heavily in not taking all its members along on the journey to the new economy,” Senninger said.

He added that the cost incurred in retraining were offset by savings in other aspects, making it bearable both for the private and public sectors.

EVENT COVERAGE: SIEW

How Singapore’s first digital twin attempts to prevent power grid failures The Grid Digital Twin is being developed in anticipation of the increasing electrification complexities.

S

ingapore is developing its first digital twin for its National Power Grid, designed to identify potential asset failures for an early intervention, in anticipation of an increasingly complex grid as electrification expands.

Alvin Lim, SP PowerGrid Deputy Director, Digital Grid, said the average interruption duration in the Lion City is currently less than a minute, with its power grid comprising 18,000 transformers with more than 27,000 kilometres of underground cables that interconnects some 11,000 substations.

The two key issues Singapore needs to address are the need to expand to cater to the growing demand and the need to plan for the maintenance of existing assets to uphold the current level of reliability Singapore enjoys.

“With the deployment of more distributed energy resources, we can expect the power flow in the network to be more variable and intermittent and this makes the planning operation of electricity more complex going forward,” Lim said.

“We want to gain a better insight into asset degradation, as well as causes of failures. With this technical understanding, we want to identify potential asset failure and prioritise these risks for timely intervention.”

Thus, the Grid Digital Twin has been initiated by the Energy Market Authority, SP Group, and the Science and Technology Policy and Plans Office of the Prime Minister’s Office.

Amongst the key benefits of the Grid Digital Twin include improving network planning analysis and remote monitoring of asset conditions, thereby saving manpower resources in carrying out extensive physical inspections. As the Grid Digital Twin

A key benefit of the Grid Digital Twin is improving network planning analysis and remote monitoring of asset conditions

Grid Digital Twin comprising the Asset Twin and Network Twin

Source: Energy Market Authority

provides a more holistic model of the grid, it can facilitate planning of infrastructure for different needs, such as installation of electric vehicle chargers and connection of solar photovoltaic (PV) systems and energy storage systems.

It comprises two models, which are the Asset Twin and the Network Twin. The first is made for the health management of grid assets, such as substations, transformers, cables; whilst the second is designed for the assessment of impact on the grid when connecting new energy sources or consumers to the grid. It is currently still in a prototype stage and is expected to be fully developed over the next few years.

Asset Twin and Network Twin Lim explained the Asset Twin will allow the SP Group to perform analytics to automatically provide an accurate diagnosis of the conditions of the assets every day.

This is executed through the integration of historical and live data that will create virtual representations of assets health statuses. This data is sourced from the substation and asset registry, maintenance and inspections data and through real-time sensors.

“This helps our field crew to prioritise the daily maintenance tasks, which involves substation checking around the island.

And lastly, in the long run, with this set of knowledge, we are able to formulate optimal schedules for meetings and renewal of assets,” Lim said.

As for the Network Twin, Desmond Cai, A*Star, Group Manager, Institute of High-Performance Computing, said it looks into recent developments in the energy ecosystem to gauge how it can affect the distribution system.

“We are beginning to see a proliferation of active distribution endpoints due to the growth of distributed energy resources, such as solar PV and energy storage systems, as well as flexible loads, such as electric vehicle charging,” Cai said.

“Therefore, to plan for the future distribution system, we need to be able to evaluate the impact of different technologies rapidly and at low cost, to assess the tradeoffs and risks to the system.”

Cai said the Network Twin uses an advanced software framework, called the Multi Energy System Modelling & Optimisation (MESMO).

MESMO The MESMO was built to tackle emerging challenges and capture future opportunities in the distribution system. It also functions to facilitate modelling of distributed energy resources, perform a system-wide optimal dispatch of those resources and analyse its impact to the network.

“This provides a breadth of data and allows deep analysis of infrastructure impact, gives us a better view of network utilisation under future electrification loads, and helps to improve network planning and analysis and prioritise Infrastructure Renewal based on system risks,” he said.

He added the Network Twin also enables optimisation of investment by enabling the study of synergies between renewal and upgrades across the network, whilst also maintaining the resilience of the network.

The Network Twin is being developed by the Institute of High-Performance Computing at the A*STAR, and its technology partner TUMCREATE. ASIAN POWER 35

EVENT COVERAGE: SIEW

How can Indonesia decarbonise amidst expected energy consumption growth?

Energy consumption is expected to be four times higher in 2060.

use.

“Aiming to a two-degree (Celsius) target, Indonesia has the opportunity to transition its energy system by steeply reducing the carbon intensity in all sectors of the economy. And this transition is known as a deep decarbonisation,” Dewi said.

To achieve this, there is a need for a negative carbon dioxide emission technology such as biomass energy and carbon capture and storage (CCS) or carbon capture, utilization, and storage (CCUS), Dewi said.

I

ndonesia targets to be a developed country by 2045—a goal that will entail a significant increase in energy use, an expert said during the Singapore International Energy Week. With energy consumption being the highest contributor to carbon emissions, will the country’s 2060 net-zero goals then be compromised?

“We will have high economic development. If we increase our economic growth, and the implication is we know that this significant increase also in energy use,” Retno Gumilang Dewi, head of Center for Research on Energy Policy at Bandung Institute of Technology said.

Indonesia needs an economic growth of 5.64% annually from 2021 to 2025 and 6.15% from 2026 to 2030. Upon achieving this, Dewi forecasted that by 2060, final energy consumption will be 3.81 times higher compared to 2010, whilst electricity consumption will be 10.33 times higher than in the same period.

In the past decade, eIndonesia’s energy systems already contributed 38.3% to total carbon emissions.

Furthermore, according to a report

by Climate Transparency, Indonesia’s emissions, excluding land use, increased 140% between 1990 and 2017, with the energy sector increasing the highest.

Energy-related emissions in 2019 reached 581 metric tons of carbon dioxide equivalent, with the industrial sector 36 ASIAN POWER

Decarbonisation of electricity and the use of low carbon-emitting fuels would cut electricity emission intensity by 92% in 2050

contributing the most at 37% of the total emissions, followed by transport (27%), and electricity and heat generation (27%).

Reducing emissions To address decarbonisation especially in the energy sector, Dewi said there is a need to aggressively improve efficiency in both the demand and supply side, which will lead to a 73% decline in the energy intensity of the gross domestic product by 2050, compared to 2010.

Decarbonisation of electricity through provisions of clean-/green-/low- and zero-carbon emissions energy, as well as the use of low carbon-emitting fuels and carbon capture and storage would also cut electricity emission intensity by 92% in 2050 from 2010.

She also said that electrification of end-uses such as the adoption of electric vehicles and substation of fossil-fuel based energy systems to electricity will also help in reducing fossil fuel combustions and reduce emissions “as long as the power generation is deeply decarbonised.”

This will then increase the electrification of end-uses by 23% in 2050 from 2010, she said.

Deep decarbonisation will also be a key driver in its transition to clean energy, noting that Indonesia is facing “a situation of uncertainty in deciding a transition” as the country is reliant on fossil fuels, particularly coal, when there is a need to increase renewable energy

Deep-decarbonisation challenges For the implementation of deep decarbonisation, Dewi said Indonesia needs to develop local capacity in renewables as it is difficult to install solar PV at homes, as well as wind power and bioenergy. “[There is a] need to reduce coal use significantly because we know that our economies rely on coal and then the coal itself is related to the power stranded assets,” Dewi said.

“The negative impact could be lessened by [continuously] using coal but with a high efficiency system and also equipped with CCS or CCUS and co-firing with biomass,” she added.

Dewi said there is a need for the development of deep biofuels such as fatty acid methyl esters or FAME biodiesel, bio-hydrocarbons, bioethanol, palm oil gasoline, amongst others for transportation. It should also consider the use of sustainable raw materials.

Non-renewable power that uses more efficient fossil fuels such as integrated gasification combined cycle, along with renewable energy such as biomass cofiring and CCS/CCUS should also be practiced.

Aggressive development of renewable energy, like the introduction of solar panels, is also amongst the challenges in the implementation of deep decarbonisation. Aggressive decarbonisation will reduce the carbon footprint of electricity from the grid network, which will then result in a reduced carbon footprint of products manufactured using the same electricity from the grid.

Dewi noted that aggressive decarbonisation will reduce the barriers for Indonesian export materials to countries that have policies relating to the carbon footprint.

Coal Power Project of the Year - Gold Fast-track Power Plant of the Year - Gold

Jawa 7 CFPP: Most Successful Plant Construction in Indonesia and World’s Leading Coal-Fired Power Plant It received both the Coal Power Project of the Year - Gold and Fast-track Power Plant of the Year - Gold trophies at the Asian Power Awards

J

awa 7 Coal-Fired Power Plant (Jawa 7 CFPP) is the first Ultra-Supercritical (USC) Power Plant to operate in Indonesia. It is built under the Independent Power Producer (IPP) Scheme by China Shenhua Energy, as the winner of Mega Project CFPP open bid that was held by PT PLN (Persero) in 2015, that later on merged to become China Energy Investment Company (CEIC). With 70% of shareholding CEIC joining the subsidiary of PT Pembangkitan Jawa-Bali, that is PT PJB Investasi with 30% of the shareholding, set up a Special Purpose Company under the name of PT Shenhua Guohua Pembangkitan Jawa Bali (PT SGPJB) which is officially established on 13 January 2016.

Jawa 7 CFPP Project has the capacity of 2 x 1.050MW located in Ternate Village, Kramatwatu District, Serang Regency, Banten Province with an investment value reaching US$1.88b or approximately IDR 26.8t. It has a high plant efficiency at ±45.04% with the largest installed MW capacity and uses the latest technology in Indonesia. The financial close of this project was achieved on 29 September 2016, becoming the first IPP in Indonesia to have its financial close process done in just 6 months.

Jawa 7 CFPP is the first project to build a power plant on deep volcanic ash and mud layer in Indonesia which adopts vacuum preloading, various types of pile foundation, post-grouting technology for cast-in-place piles and semi excavation and backfill back to the terminal embankment. A series of combinations of technological innovations, such as the combination of backfill and dynamic compaction resulted in successfully building a high-quality project under special geological conditions with a seismic acceleration of 0.33 g, as well as winning various

Jawa 7 CFPP Management uphold the mission to provide high-quality electricity that is safe, sustain, and environmental friendly with the corporate culture concept “One Family” provincial and ministry awards and QC results in foundation treatment.

The first casting of the Jawa 7 main building was carried out on 30 June 2017, and only required about 26 months to generate electricity for the first time on 03 September 2019. Through the series of continuous perfection processes during its construction, Unit 1 of Jawa 7 CFPP with capacity 1.050MW succeeded operate commercially on 13 December 2019, so that it is recorded to reach the Commercial Operation Date (COD) phase five months earlier from the target becoming the most successful project in the history of the construction of a power plant in Indonesia. After its COD, Unit 1 immediately operated for 302 days without shutting down, this is a new record for the longest operation for a 1000MW class plant. Meanwhile, Unit 2 of Jawa 7 CFPP started its production commercially on 23 September 2020.

Jawa 7 CFPP consumes low and medium calorific value coal ranging from 4000 to 4600 kcal/kg HHV (typically 4348 kcal/kg) with the largest mediumspeed coal pulverizer and the largest lignite boiler in the world (output of 3100 ton/hour, weighing 37,000 ton) that adopts the spiral water wall and rifled tubes technology which can increase the safety and reliability of the boiler along with combustion efficiency technology that results in low NOX

emissions and stable combustion even under low load conditions. It also uses Flue Gas Desulfurization (FGD) technology with an efficiency of more than 82% to reduce SOX concentration in the flue gas (<495 mg/Nm3). The three-phase integrated transformer has a maximum capacity of 1330 MVA and the double-row primary fan can power up to 4600kW. The tubular belt conveyor transports the coal from the wharf to the power plant with the longest sea transportation distance in the world (about 4 km), the largest coal transportation volume per hour (2 x 3000 ton/hour), the fastest speed (5.6 m/s) and the largest pipe diameter (600 mm) in the world. This type of conveyor keeps coal dust from spilling into the environment and also protects the quality of coal from rain and heat caused by the hot sun. In the coal yard, a windbreaker dust net controller is also installed, it can protect coal from strong winds.

Jawa 7 CFPP Management uphold the mission to provide high-quality electricity that is safe, sustain, and environmental friendly with the corporate culture concept “One Family” that focus on work safety, innovation, environment protection, responsibility, and caring to create a harmonious relationship bet ween the company, employees, and local communities to become number 1 in Indonesia and the world.

ASIAN POWER 37

EVENT COVERAGE: ASIAN POWER THERMAL ENERGY CONFERENCE

Bidding thermal power goodbye?

It will be a long journey Asia’s 1.5TW coal-fired capacity is still at a ‘youthful state’, The Lantau Group’s Mike Thomas says.

W

hilst emerging technologies are in place to support the energy transition, experts from various Asian countries argue that veering away from thermal energy, like coal, in Asia will take at least 20 more years as there is a need to ensure energy security.

In Asia, China has the largest coal capacity at 1,050 gigawatts (GW), followed

by India at 198.6GW. Overall, the region’s coal-fired capacity is currently at 1.5 terawatts, with most of its power plants at 15 years old and less.

“I think given the youthful state of thermal capacity in Asia, If you think about the long goodbye, we're still talking about 20 years, [maybe around] 2040s,” Mike Thomas, managing director of The Lantau Group, said at the Asian Power Thermal Energy Conference.

“Thermal capacity is essential to energy security, competitiveness of industry, and affordability of tariffs. If you want to speed that transition up, then it will cost more money. That's just a decision that needs to be taken,” he said, adding that most of the coal capacity is new, efficient, and super or ultra-supercritical design.

Asian countries’ energy status In China, Thomas said coal capacity runs at an average utilisation of 50% and when there is more demand and there are fewer renewable energy sources such as hydro generation, coal will take over.

“Usually, it's some other [energy source],

38 ASIAN POWER

Thermal capacity is essential to energy security, competitiveness of industry, and affordability of tariffs

like gas, or peaking capacity in other parts of the world. But in China, it's coal. So again, this fits the whole energy security call, viable supply chain, and financial sustainability.

Everything has to fit together. You can have an energy transition, but everything has to be orderly along the way,” he said.

China has recently undergone a power crisis wherein power rationing measures were imposed in 20 provinces from late September 2020. The reasons for the rationing vary per province but include strong power demand growth due to high industrial consumption and unseasonal weather.

There was also insufficient domestic coal production which resulted in high coal fuel prices, leading to coal-fired generators being unwilling to operate their plants.

There were also provincial restrictions and energy consumption and intensity to meet environmental goals, as well as poor generation from hydropower and other generation such as wind.

Thomas noted coal is going to be sold in open markets where commercial and industrial power users are going to buy them.

Thailand, meanwhile, is not a ‘coal country,’ mostly reliant on gas and growing renewables. Its commercial and industrial solar capacity grew 22% to its peak of 976 megawatts (MW). But Thomas said its limited coal remains and will only be out of its generation mix when it reaches the end of technical life or until the policy turns

‘antagonistic.’

Thomas also said that Vietnam’s peak electricity demand is expected to register a compound annual growth rate of 7.8% between 2025 and 2030. There is a significant increase in renewable energy, but there is still the building of some coal and gas.

“It's very difficult because of the rate of growth to nudge conventional [power] out in Vietnam. The coal is actually mostly less than 10 years old, and quite a bit of this is just a little bit more than five. So we are talking about fairly efficient and very new coal plants,” he said.

Malaysia, meanwhile, has pledged not to build new coal plants and there will be some coal retirements around 2030, he said.

However, the existing coal base will only go down when the power purchase agreements expire.

Coal remains important in energy mix Thomas noted that there may be an opportunity for existing coal to come back if there is a wholesale market or the plants can be phased out when the deals expire. It also depends on the emerging carbon policy.

“But from a lifetime point of view, most of the coal will continue to operate in Malaysia through the end of the 2030s and into the early 2040s,” he said, adding that one of the reasons for this is that gas has been the marginal fuel. Thomas also said that the entry of solar energy can displace gas, whilst integration of more renewable energy can address coal.

Coal also remains to be an important part of Indonesia’s energy mix, said Adaro Power CEO Dharma Djojonegoro.

“I think Indonesia, at some point, has to come to a choice. whether we want to keep our very competitive electricity costs and therefore, still stick with coal, or no, we forgo this and we go to the other renewable energies? And I think we haven't gotten to the timing of that choice yet,” he said.

In the Philippines, Frank Thiel, managing director of coal plant Quezon Power, said the Department of Energy, particularly Secretary Alfonso Cusi, recognises that coal and thermal power has to remain in the energy mix, with coal comprising 52% of the country’s energy mix.

Thiel said that there is a moratorium against the building of new coal plants in the country but the around 3,500MW in the pipeline may proceed.

Quezon Power has an existing power supply purchase agreement with Manila Electric Co., the power distributor in the capital region, that will expire in May 2025.

Thiel said they will work on securing another PSA that will run for 20 years.

If the bid will not be successful, Quezon Power will look for other alternatives, such as selling power to retail energy suppliers, or it will operate within the wholesale electricity market in the Philippines.

EVENT COVERAGE: ASIAN POWER THERMAL ENERGY CONFERENCE If fossil fuels are more expensive, then this will accelerate the increase in renewable energy on a commercial and policy level

Future trends in the climate include temperatures reaching over 1.5 Celsius higher by 2040 under all emission scenarios

‘Final resting point’ One way for thermal units to find their “final resting point” is through incursion, Thomas said. He cited as an example the battery storage which “could cannibalise the higher value evening period.” This could result in rising operation costs, reduced efficiency, and increased maintenance.

Another way is by displacing thermal units during off-peak by other energy sources such as wind or excess capacity, amongst others.

Thomas said that these two ways can occur at the same time which can result in investment risk review of the plant or its value being weakened by other factors, leading to the retirement of the coal plant rather than the reinvestment.

Timing is also another crucial part of the shift away from thermal units as several factors have to be considered before taking action such as policy settings, capacity, cost, and alternatives, he said, noting, however, that this equation takes a long time to pay out in Asia.

Thomas also said that there has to be a “framework for structured exits” for the energy transition, as there are “lumpy power stations coming in or going out in the market all at once.”

He cited EnergyAustralia Holdings Limited which entered into an agreement with the State Government of Victoria, Australia for the orderly retirement of Yallourn coal-fired power in 2028, four years before the end of its technical life.

Under the agreement, EnergyAustralia committed to build by 2026 a new utilityscale battery of 350MW capacity in Victoria and it will provide a “comprehensive workforce transition package.”

“We have markets that are supposed to meet capacity targets and develop energy efficiently. But we don't really have frameworks for the energy transition where we're actually trying to transform by way of exit and entry simultaneously,” he said.

Alternatives, emerging technologies Thomas said the most “commercially

attractive standalone opportunities” are the displacement of liquified natural gas (LNG) costs.

LNG-based energy is often the next best option as it is “both highly variable and generally more expensive than the most efficient coal plants would have been.

He also noted that a lot will depend on fuel prices because, if coal, gas, and other fossil fuels are more expensive, then this will accelerate the increase in renewable energy on a “commercial and policy level.”

Green hydrogen is also a technology that has a good opportunity for growth as there have been a lot of wind farms that have been built, according to Owl Energy Managing Director Tony Segadelli.

“In the UK, for example, there's excess wind power during some times of the year, there's an opportunity to build large solar in desert areas, which can be used for taking hydrogen out of the air, you can mine hydrogen,” Segadelli said, comparing it to carbon capture storage (CCS).

Quezon Power’s Thiel also noted that CCS continues to be a developing technology as it is expensive. He said that to capture carbon from a 100MW plant, there is a need to put in an additional plant to provide power for the technology.

Meanwhile, Djojonegoro also noted that the transition to clean energy and phasing out coal in Indonesia can be solved by existing technology but the cost is “prohibitive.” He also noted that hydropower is in remote places, whilst geothermal is small and expensive.

Rooftop solar is also emerging in some markets like Thailand where the price is high but Indonesia has not embraced it yet, according to Segadelli.

“If you go into say Java, Bali, the grid price is so low, that is no real incentive to build huge amounts of rooftop solar,” he said.

Climate change impact Climate change would also have an impact on project developments, particularly on the power sector, Sean Purdie, CEO of ERM, said.

Purdie noted that greenhouse gases have increased and among its effects include a glacial retreat and the warmer climate also lead to sea level rising. He noted that physical climate changes increased in “frequency and intensity with every marginal increase in global warming.”

Climate changes will result in frequency and increase in the intensity of heavy one-day precipitation over land as well as agricultural and ecological droughts in the drying region, he said, noting that this is dependent on the rate of temperature changes.

“These will increasingly mean demands on water. Difficulty or increased difficulties in being able to finance projects if you're unable to prove the availability of water supply or confirm that you will be able to access water backed up by scientific confirmation of the predictions for the availability of water for example, across the life of the project, 20 years 25 years, etc,” he said.

Future climate trends Future trends in the climate include temperatures reaching over 1.5 Celsius higher by 2040, from 1800 levels, under all emission scenarios. There may be no summer sea ice in the Arctic, at least once by 2050, fire weather will be more likely in many regions, changing monsoons, and more precipitation for higher altitudes and less for higher altitudes.

“More drought, less water, more difficulty to ensure water supply for cooling systems for example and thermal power plants.

Higher temperatures mean lower ambient to operating temperature deltas so more cooling is required, [hence] more power required to keep the system operating,” he said.

In East Asia, Purdie noted that precipitation extremes have increased in parts of the region and will increase in frequency and intensity, which leads to more frequent landslides.

Droughts have become more frequent in continental East Asia, whilst Eastern Central Asia has become wetter. He also noted that the rate and increase in the intensity of strong tropical cyclones have risen. Tropical cyclone tracks are also likely going to traverse northward.

In Southeast Asia, future warming will be slightly less than the global average, whilst rainfall will increase in northern parts and decrease in western Pacific areas. The region also experiences fewer but more extreme tropical cyclones.

“This means greater analysis and emphasis and understanding of maximum wind speeds which will affect the design parameters, the essential the right design parameters of any infrastructure project, including all types of power stations,” he said.

ASIAN POWER 39

Innovative power projects and initiatives recognised at the Asian Power Awards

T

he Asian Power Awards is back for the 17th year to once again recognise ground-breaking projects and trailblazing initiatives in the power sector in Asia. Dubbed as the Oscars of the power industry, the Asian Power Awards is the sector’s most prestigious awards programme.

With the continuing climate crisis and growing demand for renewable energy, industries are shifting their focus on the development of a more sustainable business model. This paradigm shift has resulted in innovative solutions, and this year, the programme has awarded 54 outstanding power companies for their successful initiatives.

The esteemed panel of judges for this year’s nominations consisted of Mike Thomas, Partner at The Lantau Group; Wen Bin Lim, Director, Asia Pacific Renewable Sector Lead at KPMG Advisory; John Yeap, Partner at Pinsent Masons; Petteri Harkki at Regional Director for Asia at AFRY; and Gervasius Samosir, Partner at YCP Solidiance.

ASIAN POWER AWARDS

Flexible Gas Power Project of the Year • Gold - CLP’s D1 Combined Cycle Gas Turbine Power Project at Black Point Power Station by CLP Power Hong Kong Limited • Silver - Relocation of Gas Power Plant to Support the Blackstart System of Coal-fired Power Plant Punagaya 2 X 125 MW by PJB Services

Battery Storage Project of the Year • Gold - Highlights, Status and Future of Taipower’s Kinmen Smart Grid and Energy Storage System by Taiwan Power Company • Silver - Utility-Scale Energy Storage Systems by DEWA • Bronze - Community Energy Storage System by TATA Power Biomass Power Project of the Year • Gold - Absolute Clean Energy PLC (ACE) Thailand Biomass Plant by Metito • Silver - Integrated Palm Waste Management Facility (IPWMF) by BAC Biomass (Kg Gajah) Sdn Bhd • Bronze - North Negros BioPower, Inc. Coal Power Project of the Year • Gold - Jawa 7 Coal-Fired Power Plant by PT Shenhua Guohua Pembangkitan Jawa Bali • Silver - Jawa - 9&10, 2 x 1000 MW OECD-Class USC CSFPP by PT Indo Raya Tenaga • Bronze - Sujin Energy Shuozhou by Emerson Corporate Social Responsibility Initiative of the Year • Bangladesh - 114 MW HFO Fired Power Plant by Feni Lanka Power Limited • India - Project Pragyan – a Sterlite EdIndia Foundation (SEF) Initiative by Sterlite Power Transmission Limited (SPTL) • Indonesia - Documentation of Pempek Bakar Program Community for Waste to Energy by PT PLN (Persero) Kantor Pusat • Philippines - Microenterprise Program for Tugbo Women’s Organization by DMCI Power Corporation Dual Fuel Power Plant of the Year • Gold - CLP’s D1 Combined Cycle Gas Turbine Power Project at Black Point Power Station by CLP Power Hong Kong Limited • Silver - Husk’s Chanpatia Project: 100% Renewable with PV, Biomass by Husk Power Systems • Bronze - Gas Engine Power Plant Bangkanai (Peaker) Stage 2 (140 MW), PT PLN (Persero) by Consortium of PT. PP (Persero) Tbk - Wartsila Environmental Upgrade of the Year • China - Technical Insight of TAIHAN 550MW Aqua-PV Farm in Wenzhou China Chint Solar (Zhejiang) Co., Ltd • Indonesia - Jawa - 9&10, 2 x 1000 MW OECD-Class USC CSFPP by PT Indo Raya Tenaga • Vietnam - Vu Phong Energy Group - Lac Long, Vietnam by PROINSO Fast-track Power Plant of the Year • Gold - Jawa 7 Coal-Fired Power Plant by PT Shenhua Guohua Pembangkitan Jawa Bali • Silver - Safety-Related Enhancement of Tank Seismic Capacity at the Maanshan Nuclear Power Plant by Taiwan Power Company • Bronze - Proton Commercial & Industrial (C&I) Solar Project by MFP SOLAR SDN BHD 40 ASIAN POWER

Awards presentations was held virtually from 12 November 2021.

Congratulations to the winners!

Gas Engine Combined Cycle Power Project of the Year • Gold - Lombok Gas Engine Combined Cycle (Peaker) Power Plant (130 150 MW), PT PLN (Persero) by Consortium of PT. PP (Persero) Tbk Wartsila Gas Power Project of the Year • Gold & Hong Kong - CLP’s D1 Combined Cycle Gas Turbine Power Project at Black Point Power Station by CLP Power Hong Kong Limited • Silver & Malaysia - Project Melaka by Edra Energy Sdn Bhd • Bronze & Taiwan - The Datan Combined-Cycle Power Plant Expansion Project – Unit 7 Combined - Cycle Power Plant Addition by Taiwan Power Company • China - The First SGT 8000H Gas Turbine Power Plant in Commercial Operation in China by Huadian Fuxin Guangzhou Energy Co.,Ltd, Geothermal Power Project of the Year • Gold - 1 x 85 MW net Geothermal Power Plant by PT. Supreme Energy Muara Laboh • Silver - PT Indonesia Power Kamojang POMU - 375 MW by PT PLN (Persero) – PT Indonesia Power Hydro Power Project of the Year • Gold - Hatta Pumped Storage Hydro Power Plant, 250 MW by EDF Renewables Middle East • Silver - Lower (Aşağı) Kalekoy Dam and HEPP by Kalehan Genc Enerji Uretim A.S. • Bronze - PLTM Sampean Baru by PJB Services Independent Power Producer of the Year • India - The Tata Power Co. Ltd. • Indonesia - PT. GH EMM INDONESIA • UAE - ACWA Power Information Technology Project of the Year • Indonesia - Digital Power Plant Program - Automatic Failure Detection by PT PLN (Persero) - PT Indonesia Power • Maldives - The Residence Falhumaafushi Photovoltaic Plants - Maximum Inverter Power Tracking Technology by DHYBRID Power Systems GmbH • Pakistan - KE Live App – A Consumer Centric Journey by K Electric • UAE - AI Based Distribution Asset Criticality Ranking (DACR) by DEWA Innovative Power Technology of the Year • Bangladesh - 114 MW HFO Fired Power Plant by Feni Lanka Power Limited • India - Conversion of Hydrogen Generation Plant at 2x600 MW RGTPP, Khedar, Hisar by Haryana Power Generation Corporation Limited • Indonesia - Simpang Belimbing Coal Fired Powerplant by PT. GH EMM INDONESIA

• • • •

Korea - Korea Southern Power Co., Ltd (ShinIncheon Power Plant) by Emerson Malaysia - TNB Integrated Learning Solution by Tenaga Nasional Berhad (TNB) Centre of Excellence for Solar Energy Philippines - South Negros BioPower, Inc. Thailand - BIC Cogeneration Power Plant Cooling Tower Optimization by CK Power Public Company Limited

Power Plant Upgrade of the Year • Hong Kong - Castle Peak Power Station Turbine Control, Protection & Mechanical System Upgrade Project by Emerson • India - Adhunik Power and Natural Resources Limited • Indonesia - Heat Recovery Steam Generator Tambak Lorok CCPP Block 2 Life Extension and Upgrades by PT Indonesia Power Semarang Power Generation Unit Power Project Finance House of the Year • Gold - 145 MW Cirata Floating Solar Photovoltaic Power Plant by Standard Chartered Bank (Singapore) Limited

CK Power Public Company Limited

Power Utility of the Year • Bangladesh - Summit Power international • India - ReNew Power • Indonesia - PT Pembangkitan Jawa Bali • Pakistan - K Electric • UAE - FUJAIRAH ASIA POWER COMPANY PJSC Smart Grid Project of the Year - India • The bleeding-edge of gridtech: Husk Power by Husk Power Systems Solar Power Project of the Year • Australia - 256.5 MWp Kiamal Solar Farm by Total Eren • China - TAIHAN 550MW Aqua-PV Farm in Wenzhou China by Chint Solar (Zhejiang) Co., Ltd • India - 110 MW Solar Power Plant, Pokhran, Rajasthan by ReNew Power • Indonesia - Cirata Floating Solar Power Plant by Abu Dhabi Future Energy Company PJSC - Masdar • Japan - Hohoku Solar Farm by CEF CO., LTD. • Malaysia - 50 MWac Large Scale Solar (LSS) Power Plant at Kuala Langat, Selangor by TNB Renewables Sdn. Bhd. • Maldives - The Residence Falhumaafushi Photovoltaic Plants - Maximum Inverter Power Tracking Technology by DHYBRID Power Systems GmbH • Nepal - 25 MW Solar Power Project at Nuwakot District of Nepal by Promentute Incorporation (P) Ltd • UAE - MBR Solar Park Phase III: a technical prowess in UAE by EDF Renewables Middle East • Vietnam - Vu Phong Energy Group - Lac Long, Vietnam by PROINSO Standby Power Plant of the Year • Gold - Highlights, Status and Future of Taipower’s Kinmen Smart Grid and Energy Storage System by Taiwan Power Company • Silver - Line Charging PLTD Suppa from 11 KV to 150 KV System by PJB Services

Kalehan Genc Enerji Uretim A.S.

PJB Services

Transmission & Distribution Project of the Year • Gold - Applying XR (Extended Reality) to the Tutoring on Substation O&M

by Taiwan Power Company • Silver - Ma Sik Road 132kV Substation by CLP Power Hong Kong Limited • Bronze - Value added Services & Demand Side management by The Tata Power Company Limited Wind Power Project of the Year • India - Ostro Kutch Wind Pvt. Limited by ReNew Power • Sri Lanka - Mannar Wind Power Project - Phase 1 by Ceylon Electricity Board • Thailand - LomLigor Project by BCPG Public Company Limited PJB Services ASIAN POWER 41

PT. GH EMM Indonesia

PT Indo Raya Tenaga

PT Pembangkitan Jawa Bali

PT PLN (Persero) Kantor Pusat

PT PLN (Persero) - PT Indonesia Power

CLP Power Hong Kong Limited

Fujairah Asia Power Company

Feni Lanka Power Limited 42 ASIAN POWER

PT Shenhua Guohua Pembangkitan Jawa Bali

Summit Power international

Taiwan Power Company

Abu Dhabi Future Energy Company PJSC - Masdar

Sterlite Power Transmission Limited

PT. PP (Persero) Tbk

PT. PP (Persero) Tbk

Abu Dhabi Future Energy Company PJSC - Masdar

Huadian Fuxin Guangzhou Energy Co.,Ltd ASIAN POWER 43

Gas Power Project of the Year - Gold Flexible Gas Power Project of the Year - Gold Dual Fuel Power Plant of the Year - Gold Transmission & Distribution Project of the Year - Silver Gas Power Project of the Year - Hong Kong

Engineering a Brighter, Greener Future

CLP Power is driving a mission to make Hong Kong carbon neutral by 2050, and won five awards at the Asian Power Awards for its ground-breaking infrastructure projects and innovative efforts to bring bluer skies to the city.

Hong Kong’s journey to a carbon neutral future and won a total of four awards, including three gold awards, in the following categories of the Asian Power Awards 2021: Dual Fuel Power Plant of the Year, Flexible Gas Power Project of the Year, Gas Power Project of the Year, and Gas Power Project of the Year in Hong Kong.

Increasing the ratio of gas-fired generation is an important near-term measure in CLP Power’s energy transition strategy and aligns with the company’s updated Climate Vision 2050 mission statement which commits it to achieving net-zero greenhouse emissions across its value chain by 2050.

Fuel efficiency and flexibility are central to the design of unit D1. It is engineered to use a wide range of gas supplies, and is also a dual fuel unit with the capacity to switch to emergency back-up fuel and with capability for automatic on-load fuel transfer to ensure reliable supply of electricity to its customers.

The commissioning of Unit D1 in 2020 at Black Point Power Station has seen CLP Power’s gas-fired power generation ratio increase to around 50% of the fuel mix.

H

ong Kong – one of the world’s most dynamic, advanced, and densely populated cities – has embarked on an ambitious mission to achieve carbon neutrality by the middle of the century.

As the city’s largest power company and a business at the heart of the Hong Kong community for more than 120 years, CLP Power is central to the success of that mission, and is adopting state-of-the-art technology across the city to create clearer, bluer skies.

From ground-breaking infrastructure projects to community energy-saving initiatives, CLP Power is leading the way in a green energy movement that is transforming the way Hong Kong people and businesses think about the electricity they use.

The jewel in the crown of CLP Power’s decarbonisation drive is Black Point Power Station, which has used natural gas for power generation for more than a quarter of a century to gradually reduce the city’s dependence on energy generated by coal.

2020 was a milestone year in the company’s green energy transformation. A more advanced and efficient Combined Cycle Gas Turbine has been deployed in the first new 550-megawatt gas-fired generation unit called D1 at Black Point Power Station, raising the proportion of natural gas in CLP Power’s overall fuel mix to around 50% from a previous level of less than 30%.

Its successful launch has reduced CLP Power’s carbon intensity to around 0.37 kg per kilowatt-hour of electricity consumption 44 ASIAN POWER

in 2020, outperforming the carbon reduction achievements of developed countries such as Japan and South Korea, and on a par with the performances of Germany and the US. Highly efficient carbon-cutting technology Unit D1 at Black Point Power Station has a generation capacity of 550 megawatts, the largest of all existing gas-fired units in Hong Kong and sufficient to power 900,000 homes.

The new generation unit deploys state-of-theart H-class gas turbine technology and has an efficiency rate of around 60%, making it one of the most efficient gas-fired power plants in the world. It cuts annual carbon dioxide emissions by around one million tonnes, equivalent to the planting of more than 42 million trees.

Unit D1 is a hugely significant step forward in

The new generation unit deploys state-of-the-art H-class gas turbine technology and has an efficiency rate of around 60%.

A global workforce Putting unit D1 into service was a multidisciplinary mega-project that combined engineering and construction expertise and involved equipment and material supplied from countries around the world, including Europe, the US, and Asia.

Its completion was a massive feat of ingenuity and resource management. By the middle of 2018, more than 1,200 deliveries of major components had been delivered to the site which, because of its size, had only a limited area available for storage and assembly.

The highly advanced H-class gas turbine weighing more than 450 tonnes was shipped in from the factory in Berlin. To avoid impact on the environment and roads, project components weighing a total of more than 10,000 tonnes were delivered by sea.

The workforce involved in the project comprised more than 20 different nationalities, and safety messages and communications were conducted in a variety of languages including Chinese, English, and Nepalese to ensure clear

Gas Power Project of the Year - Gold Flexible Gas Power Project of the Year - Gold Dual Fuel Power Plant of the Year - Gold Transmission & Distribution Project of the Year - Silver Gas Power Project of the Year - Hong Kong greater efficiency.

Building Information Modelling and simulation technology were deployed to improve the cost effectiveness of the project and determine the best building configuration to mitigate the impacts of wind amplification, sun shading, and light pollution.

The award for the new substation reflects CLP Power’s ability to develop people-centric, sustainable substations which provide safe, reliable electricity to the Hong Kong community while supporting the city on its journey to a smart future.

CLP Power organised an opening ceremony for unit D1 in October 2021. The ceremony was officiated by Hong Kong SAR Chief Executive The Honourable Mrs Carrie Lam Cheng Yuet-ngor (6th from left) and Chairman of CLP Holdings The Honourable Sir Michael Kadoorie (6th from right).

understanding by everyone involved.

At the peak period of construction in 2019, work was being carried out around the clock seven days a week over a period of two months with more than 1,500 people on site to ensure it met the project schedule.

Even the emergence of COVID-19 in early 2020 could not slow the project’s progress with stringent anti-pandemic precautions swiftly implemented to ensure that work continued and unit D1 went into service on schedule.

Throughout the mammoth undertaking, the project team used advanced technology to keep international experts and the site team closely connected, often operating in locations thousands of miles apart and in different time zones.

The technology included remote online monitoring from manufacturers’ premises overseas and mobile communications on the ground. The team’s resilience and resourcefulness were key factors in the smooth and successful completion of the project in mid-2020.

Embracing a green vision Transforming Hong Kong into a low-carbon smart city is a holistic effort that covers every aspect of CLP Power’s power supply network, from generation to distribution to the millions of homes and businesses it serves.

As well as the four awards for unit D1, the company won a silver prize in the Transmission and Distribution Project of the Year category of the Asian Power Awards 2021 for its new Ma Sik

Road 132kV substation.

The modern, green substation has been created for a new town development in Hong Kong’s northeast New Territories and will serve a diversity of homes, businesses, retail outlets and services, as well as public facilities and agricultural enterprises.

It has an eco-friendly design with extensive greening to blend into its environment and reduce urban heating, including solar panels, a

CLP Power keeps abreast of developments in technologies that utilise renewable energy for electricity generation, and is working on ways to convert local gas generation infrastructure to support the use of green fuels rainwater harvest system, a drip-pipe irrigation installation, and energy-efficient electrical appliances to promote energy saving and sustainability.

The substation features low noise and low loss design 132kV/11kV transformers and modern vacuum-type tap changers to reduce the need for maintenance. It also has a new generation of control and supervision systems for the transmission plant capable of communicating with numerous Intelligent Electronic Devices for

The challenge of our times CLP Power’s success at the Asian Power Awards underscores the company’s determination to be at the forefront of technological advance and to play a key role in Hong Kong’s continuing energy transformation.

Speaking at the New Gas-fired Generation Unit Opening Ceremony in October last year, Chairman of CLP Holdings The Honourable Sir Michael Kadoorie said, “CLP firmly supports the Government’s mission to make our city carbon neutral by the middle of this century, and as part of our relentless effort, the CLP Group has committed to achieving net-zero greenhouse gas emissions by 2050. The addition of this new generation unit continues our commitment to play a small part as the world addresses the challenges of climate change.”

In its decarbonisation journey, CLP Power continues to adopt careful planning to maintain high levels of safe and reliable supply for its customers. It is currently building a second new gas-fired generation unit at Black Point Power Station, which is expected to go into operation in 2023 as part of an ongoing programme to gradually phase out the remaining coal-fired capacity at the Castle Peak ‘A’ Power Station.

The company also keeps abreast of developments in technologies that utilise renewable energy for electricity generation, and is working on ways to convert local gas generation infrastructure to support the use of green fuels such as zero-carbon hydrogen.

The 2050 carbon neutrality target is an important milestone for Hong Kong. Together with the Hong Kong SAR Government, CLP Power will also explore ways to enhance regional cooperation on zero-carbon energy and identify sources of green energy in neighbouring regions, including joint investment and development opportunities for zero-carbon energy projects near Hong Kong.

CONTACT

The design of Ma Sik Road 132kV substation incorporates a variety of green, sustainable features.

CLP Power Hong Kong Limited Address: 8 Laguna Verde Avenue, Hung Hom, Kowloon, Hong Kong Contact number: (852) 2678 8111 Email: clp_info@clp.com.hk Website: www.clp.com.hk

ASIAN POWER 45

Innovative Power Technology of the Year - Bangladesh Corporate Social Responsibility Initiative of the Year - Bangladesh

Feni Lanka Power Limited wins 2 accolades at the Asian Power Awards 2021

The Independent Power Producer took home the Corporate Social Responsibility Initiative and Innovative Power Technology of the Year.

Feni Lanka Power Limited (FLPL)

F

eni Lanka Power Limited (FLPL) is a 114 MW HFO Fired Power Plant which is located at Feni, Bangladesh. Feni Lanka Power Limited is a remarkable achievement by the engineering talent of Lakdhanavi Limited, a power generating arm of LTL HOLDINGS and one of the leading engineering companies in Sri Lanka. As an Independent Power Producer, Feni Lanka Power Limited started its commercial journey on 25 November 2019.

FLPL has seven of the four-stroke diesel engines with direct fuel injection from Wartsila, Finland. These engines are fused with cuttingedge technologies which include single-stage turbochargers from ABB, intercoolers and a control system from Wartsila. Here, electricity is generated by seven 11KV synchronous three-phase air-cooled generators from ABB, Finland which is equipped with an anti-condensation heater. Two 85MV 11/132KV main power transformers from Jiangsu Huapeng Transformer Co. Ltd are there to evacuate the power through a 5km long 132kV power transmission line.

FLPL has ten numbers of tank lorries from TATA for an uninterruptible supply of fuel.

The plant itself has a fuel storing capacity of 10000m3. Cleansing of oil and fuel is achieved by integrating ten numbers of heavy-duty oil separators from Alfa Laval whilst steam is generally produced by three vertical type exhaust gas boilers. FLPL also has a horizontal type diesel fired boiler from Aalborg, Alfa Laval, Sweden for generating steam at plant standby conditions.

After a successful operation for one contractual year, FLPL is now continuing its second contractual year with Bangladesh Power Development Board.

Due to remarkable achievements during its construction phase, FLPL won the Asian Power Award 2020 and this year’s programme as well, taking home both the Corporate Social Responsibility Initiative and Innovative Power Technology of the Year. It has also achieved a British safety award and ISO certification for maintaining high-class standards.

FLPL always believes in continuous development and implementing innovative technologies to enhance its beauty, safety, efficiency, and environmental aspects. Right after coming into operation FLPL started working with performance development of the plant, energy-saving, eliminating or reducing environmental impacts, developing green environment, social responsibilities, social welfare, etc.

With the thought of reducing its internal energy consumption, FLPL introduced an online electric heater in the fuel supply line in 2020. As HFO is highly viscous, a high temperature is required to be maintained in the fuel tank. Maintaining a very high temperature of a bulk amount of fuel throughout the day requires vast heat energy which is usually recovered from the exhaust gas of the engines by means of heat recovery boilers. During summer exhaust is available as engines run a lot. But during the winter season when the plant factor goes down, exhaust gas does not always remain available. In

such a situation diesel boiler is normally used for heat generation which causes extra cost and extra air pollution. To solve this issue FLPL technical team installed an online electric heater in the fuel supply line. This electric heater is used only when exhaust heat is not available. As fuel is heated up instantly, it is no more required to maintain a high temperature in the fuel tank throughout the day. After implanting this technique, FLPL diesel consumption has become less than half of the previous consumption resulting in a big amount of cost-saving for the company and also reduction of air pollution.

Furthermore, FLPL management decided that FLPL will not discharge any effluent water to eliminate adverse impacts on nearby aquatic ecosystems. This unique project was named the “zero discharge plan” where FLPL prepared a large pond in its premises to store effluent water which will eventually be used for gardening purposes. Thus, groundwater extraction has also been reduced and the nearby aquatic ecosystem is kept unaffected.

With a target to contribute to local socio-economic development, FLPL management decided to build a school building for the nearby primary school.

So, FLPL took it as a CSR project and started building a four-storey school building. With all these achievements, the energetic O&M team and the experienced, innovative leadership who are fashioned about engineering excellence, socioeconomic flourishment and environmental aspects, FLPL will continue its journey for years to come.

FLPL always believes in continuous development and implementing innovative technologies to enhance its beauty, safety, efficiency, and environmental aspects 46 ASIAN POWER

Power Utility of the Year- UAE

Fujairah Asia Power Company PJSC recognised at Asian Power Awards 2021

Its Fujairah F2 Project and commitment to safe operations made it a great representative of the UAE utility sector.

F

ujairah Asia Power Company PJSC’s (FAPCO) Fujairah F2 Independent Power and Water Project (IWPP) was one of the largest IWPPs at the time of its construction. Since its inception, it has continued to be an important part of the utility landscape in the UAE, not just because of its size and scale, but because the Fujairah Power and Water Complex was one of the first power and water facilities to be developed in the Emirate of Fujairah.

In 2021, Fujairah F2 continues to play a critical role in the UAE’s power and water sector. TAQA, the majority shareholder and one of the largest integrated utility companies in the Europe, Middle East and Asia (EMEA) regions, holds interests in a portfolio of generation assets in the UAE and abroad. Fujairah F2 represents around 12% of its UAE fleet.

According to Alawi Al Jefri, the Executive Managing Director of FAPCO, power and water is the backbone of any industrialisation in the modern era. “Bringing utility-scale power and water development spurred on industrialisation in the community, it brought with it jobs and career opportunities, as well as access to power and water sources for industry and agriculture,” he said.

2.1GW

Power generation capacity

from the Asia Power Awards 2021

You can’t achieve operational excellence without a strong safety culture, and this can only be achieved through visible felt leadership

past incidents on every anniversary of its occurrence.

Every employee and contractor onsite are involved in going over the learnings and details of the incident.

Al Jefri states that often there is fear around looking at the incidents that happen at your POWERING A THRIVING FUTURE site and many focus on examples from outside. “Real examples of what has happened at our plant FUJAIRAH F2 and involving our employees, A combined-cycle power plant and hybrid multi-effect distillation and make it relevant and keep the reverse osmosis desalination plant reality of the inherent risks of this job fresh in our minds,” he adds.

This commitment to a safety culture has paid off. The plant has achieved a strong safety record, including 1,500 days without a MIGD lost-time incident (LTI). It has also Desalinated water capacity won the gold award from the Royal Society for the Prevention of Accidents (ROSPA) in 2017, 2018, 2019, and 2020.

Beyond safety, the plant Gold Award also has a track record for from the Royal Society for the Prevention of Accidents investing in its people through 2020, 2019, 2018 and 2017 robust succession planning and knowledge transfer Emiratization Award from the Ministry of Human processes. Since commencing Resources and Emiratization operations, it has focused on a development programme for UAE nationals. An important factor for futureproofing one of the country’s most critical sectors.

The programme has seen dozens of Emirati talents come

60% 132 TAQA stake

Awards Power Utility of the Year (UAE)

Fujairah F2 is a combined-cycle power plant and hybrid multi-effect distillation and reverse osmosis (RO) desalination plant. It has 2.1 GW of gross power generation capacity and has a gross water generation capacity of 132 MIGD. However, it is the plant’s commitment to safe, reliable, and responsible operations that make it a great representative of the UAE utility sector. This commitment is ingrained in the culture and the people at the plant.

Safety is always a topical subject in the sector; however, it has been a key focus area for the team.

“You can’t achieve operational excellence without a strong safety culture, and this can only be achieved through visible felt leadership,” adds Al Jefri. One of its safety initiatives involves revisiting the details of

Electricity Sector Award Winner

from the Royal Society of Prevention of Accidents 2021

Award of Excellence from the Marubeni Stakeholder Asset Excellence Award Winner 2019

In partnership with

Location

2011

Fujairah, UAE 5 km south of Khor Fakkan

TAQA.com | Media.HQ@taqa.com |

@TAQAGroup

Start of operations

Alawi Al Jefri, Executive Managing Director of FAPCO

through the plant. It is a flexible programme that offers everything from internships and work experience, to graduate positions as well as job opportunities for untrained employees.

“We bring in nationals across all levels of our organisation, from untrained to PhD educated employees and offer an opportunity for a career here. We have had people start on the reception desk who now work in HR or finance. And I hope I can be an example for the next generation as the Executive Managing Director and a proud UAE National,” he adds.

Al Jefri sees UAE nationals as essential to improving the performance of the plant for future generations and ensures that Emiratis are exposed to opportunities in utilities. This development supports the economic aspirations of the UAE to diversify its economy and cultivate a knowledgebased market. It also supports succession planning for the next 50 years.

Al Jefri’s passion for his people and the sector shines through, making it clear why Fujairah F2 is such an important part of the UAE’s utility sector.

“There is so much value in these power and water assets that needs to be tapped into and not just the economics. To realise its full potential, we must see the value that can be extracted through the development of people and a culture of excellence, that is where we can contribute to society,” he concluded.

ASIAN POWER 47

OPINION

TIM BUCKLEY Who will grab regional leadership in the global energy transition?

TIM BUCKLEY Director Energy Finance Studies, Australia/South Asia, IEEFA

Policy, economic and financial forces are now combining to drive the rapid adoption of renewable energy worldwide

T

he global transition to clean energy has ended its initial phase of incremental growth and is on the brink of transformational change.

However imperfect may be the outcomes of November’s COP26 meeting in Glasgow, policy, economic and financial forces are now combining to drive the rapid adoption of renewable energy around the world even where arguments for climate action have faltered.

Australians are pragmatic and recognise that taking anything less than a serious and credible emissions reduction plan to Glasgow would be detrimental to our world standing. But Australia’s future role in the region is a tangible and immediate concern.

Australia could inject into the diplomatic activity that surrounds Glasgow a constructive and mutually beneficial plan for its role in regional energy transition.

What elements could this include?

To be taken seriously, a credible emissions reduction plan and an acceptance that fossil fuel exports will, over time, be phased out are prerequisites.

Australia’s energy exports will continue but will increasingly take the form of minerals critical to battery manufacture, not just lithium and rare earth metals but nickel, copper, zinc and other less exotic but equally important minerals, ideally with some degree of processing here. Hydrogen and ammonia will progressively supplant gas exports. Even the direct export of solar electricity is being pioneered by SunCable, with its Australia-toSingapore high voltage subsea cable route having just received approval by Indonesia.

As the country with by far the largest expected electricity demand increase in coming decades, and the world’s biggest democracy, India deserves special attention, and the complementary nature of Australia and India invites much deeper collaboration.

One obstacle to an even more rapid roll-out of renewable energy than India has already achieved is finance.

More significant than any contribution of public funds is the opportunity for some of Australia’s three trillion dollars in retirement savings to accelerate India’s renewable and grid infrastructure investment program.

India’s Foreign Direct Investment regime grants automatic approval status for renewable energy projects. Replacing the annual Australia-India Energy Dialogue with a much higher priority and continuous diplomatic engagement could identify specific opportunities for investment and ensure appropriate safeguards.

Energising India with renewables will not only alleviate energy poverty, energy security and water scarcity issues better than would coal exports, but by powering India’s dynamic rural economy as well as its industries and 48 ASIAN POWER

start-ups, it would put Australian dollars into constructive economic activity, far more constructive than further inflating Australia’s bloated housing market.

Technical, engineering and research collaboration should be taken to an altogether higher level, through academic institutions, think tanks, the Australian Renewable Energy Agency (ARENA), Clean Energy Finance Corporation (CEFC) and industry bodies. These direct exchanges of knowledge and experience, mediated by the development of personal relationships, would pay dividends well beyond the specific projects. This is an area that can be rapidly expanded with appropriate funding and, as COVID conditions permit, streamlined visa arrangements to leverage the close partnership Australia and India already share in tertiary education.

Journeying together through the coal phase-out Collaboration can even extend to India’s coal industry and still benefit energy transition.

India’s coal production is likely to peak within just a few years. Improving the efficiency of production and supply, enhancing health and safety whilst limiting environmental damage could focus on the larger open-cut mines which are likely to remain in production for some while.

Coal’s phase-out will first affect the 84% of India’s 459 mines which we know, thanks to the work of the University of British Columbia’s Sandeep Pai, together contribute less than one-fifth of India’s coal but employ large numbers of people directly and indirectly. Mine-site reclamation, diversification of the state-owned enterprises that dominate Indian coal mining (being actively contemplated by Coal India Ltd) and creating new economic activities for these communities will be challenges for India and other countries. Meeting them would benefit from sharing experiences and international partnerships.

As Australia deepens security ties with India via the Quad, it is important that the broader common interest be front of mind. Alliances succeed to the extent they reflect mutual interest, and by making the success of energy transition a joint project, the relationship between Australia and India can be put on firmer ground. India is leading aspects of this transition not only through its renewable energy growth but internationally, as host to the International Solar Alliance, of which Australia is a founding member.

Opportunities for investment and collaboration will rapidly follow in Vietnam, Indonesia, Malaysia and other countries in the region, and they are looking to emulate India’s experience.

To benefit from technical, commercial, and research leadership in all aspects of energy transition, Australia should partner with India as a matter of strategic priority, and not pass on a unique opportunity.

Technical, engineering and research collaboration should be taken to a higher level

ASIAN POWER 49

OPINION

CHRISTINA NG Accepting gas as sustainable will hurt Korea’s green finance credentials

CHRISTINA NG Research and Stakeholder Engagement Leader, Fixed Income

or even the long term, under the EU’s taxonomy.

South Korea’s Gas-fired Power Plan Could Be Funded with Green Proceeds

Source: Ministry of Trade, Industry and Energy’s 9th Basic Plan for Long-term Electricity supply and demand, published December 2020

A

fter six months of resisting industry calls to add liquefied natural gas (LNG) to its green taxonomy, the South Korean government last week finally succumbed to gas lobbyists.

This is surprising as, only two weeks ago, President Moon Jae-In made a wellreceived, new emissions pledge—cutting the country’s greenhouse gas emissions to 40% by 2030.

The obvious dichotomy here is that recognising gas and LNG as an environmentally sustainable “transition” fuel will likely lock South Korea into a high-emitting future, which directly contradicts the policy and market incentives created by President Moon’s new emissions reduction targets.

The draft green taxonomy, known locally as the K-Taxonomy, prescribes an end-use emission technical screening criteria of 320g of carbon dioxide (CO2) per kilowatt hour (kWh). A life-cycle emission standard is also expected, but it will only apply from 2025.

This means that new unabated LNG-power projects, of which around 10 gigawatts are expected to flood South Korea’s energy market by 2025, would qualify for green bond and loan financing if the draft K-Taxonomy is finalised without changes.

Emissions-wary ESG investors should be on alert.

South Korean green debt amounted to US$42.8 billion on 30 September 2021, according to Bloomberg New Energy Finance. A third of it, around US$14.22 billion, funded power and energy companies.

If the current draft of the K-Taxonomy proceeds as is, ESG investors may find themselves inadvertently backing gas.

The problem is the undisputable fact that, in addition to coal, gas is the fossil fuel most troubling climate-aware investors looking at the emissions of long-life infrastructure investments.

Gas contributes carbon and methane to the atmosphere through its combustion, with lifecycle emissions that are dangerous and significant.

Moreover, methane from gas has a warming effect up to 80 or 90 times more powerful than carbon over a 20-year period, making gas worse for the climate than coal in the short term.

The tension around the limited role for gas in energy transition is evident in the taxonomy work playing out in all global markets.

After much controversy, the European Union (EU) has accepted gas-powered generation as a ‘transitional’ asset class under its Sustainable Finance Taxonomy, provided that a project’s lifecycle carbon emissions are limited to 100g CO2 per kWh. At this specification, gas-powered projects in the EU will likely require the use of carbon capture technology (CCS), which is yet to be proven economically or technically viable at scale anywhere in the world.

Under these conditions, gas is unlikely to be funded in the short to medium, 50 ASIAN POWER

The K-Taxonomy gas policy bind: Make lobbyists happy but damage green leadership options With the gas question a high-stakes dance for investors and policymakers in Europe, Korea’s policymakers will now have to weigh the odds carefully.

The K-Taxonomy is expected to be finalised by the end of 2021, and with its current draft not consistent with the gold-standard EU Taxonomy, investors are right to be wary.

With the inclusion of gas in the K-Taxonomy, Korean policymakers have effectively signalled they aren’t up to the task of leading market development with a green taxonomy.

Instead, they are showing a preference for remaining in lock-step with emerging market Southeast Asian counterparts who have flagged their intention to recognise gas-powered generation as “green”.

This puts South Korea at risk of deterring serious ESG investors who typically prefer “dark green” assets—solar, wind and geothermal for example.

The United Kingdom’s (UK) inaugural sovereign green bond issued in September 2021 demonstrated that risk when it provided a mixed portfolio of green and controversial assets like “blue hydrogen”, which uses methane gas in its production. Several leading debt investors immediately expressed criticism over the sovereign’s opportunistic ‘green’ bond and avoided it entirely.

By contrast, China—the largest green debt market in the region—took a different and much more strategic approach, learning from market trends and adapting.

Its first green taxonomy in 2015 categorised “clean coal” as a green project that qualified for the issuance of green bonds, drawing widespread criticism, particularly from foreign investors.

Recognising the significance of a truly green taxonomy, in mid 2021, China removed fossil fuel-related projects and the new Green Bond Endorsed Project Catalogue—its equivalent green taxonomy—now excludes gas, LNG and coalfired power activities.

Like South Korea, China relies on burning fossil fuels to power the country.

However, President Xi Jinping’s pledge to accelerate the country’s transformation to a green and low carbon economy, and to achieve carbon neutrality before 2060, has opened the door to a much more strategic view on how China’s green finance market should develop, and which technologies should be incentivised.

China is also working with the EU to harmonise their respective taxonomies by the end of 2021. This is a positive initiative between jurisdictions in response to investor requests for a common standard on green or sustainable projects.

The move also indicates that the Asian giant is ready to compete for global green capital.

Green Bonds and Loans on The Rise Among South Korean Power and Energy Companies

Source: Bloomberg NEF