SECTOR REPORT GEOTHERMAL GROWTH DRIVEN BY OPPORTUNITIES

Indonesia is expected to overtake the US in leading the global geothermal power sector.

Despite milder growth in the global geothermal sector, Asia is slated to be one of the regions with the largest amounts of geothermal capacity installed over the coming decade alongside Central and Eastern Europe.

Together, Fitch expects these regions combined to account for approximately 74% of the global total geothermal capacity additions between 2020 and 2029.

However, geothermal growth will be driven by only a few key markets— particularly in Indonesia—as these resources are restricted to tectonically active areas, and remain fairly dispersed across regions.

Indonesia is expected to overtake the US to become the largest geothermal market globally by 2022, with its geothermal capacity projected to rise from an estimated 2.1GW in end-2019 to 3.6GW by 2029.

The country is situated in Southeast Asia at the intersection of many tectonic plates, giving it considerable geothermal potential, but most of its potential reserves remain unexplored. The main geothermal plants are spread

across Java, North Sumatra, and North Sulawesi, constituting less than 3% of the total installed generation capacity.

Expanding the geothermal industry is said to be a key priority for the Indonesian government given the vast potential for geothermal power generation in the country, estimated at about 28GW, the baseload nature of the resource and continued elevated power demand across the country.

Just in 2019, Indonesia added about 185MW, following the 135 MW installation in 2018. The Indonesian government has set a target of 23% renewable energy in the energy mix by 2025, meaning that its geothermal power capacity is expected to reach 7GW by 2030.

“Many government policies and resolutions are helping to explore reserves of geothermal energy. Approximately 80% of the country’s geothermal reserves are in conserved forests, and the development of projects in these areas requires a presidential decree,” said Ankit Mathur, GlobalData's Practice Head of Power.

According to IEEFA analysts, theseis includes changing regulations i.e. geothermal energy is not categoriszed as part of the mining sector, hence giving it a better playing field when applying for forestry use permits.

Aside from these, the Ministry of Energy and Mineral Resources is also looking to complete a regulation on electricity tariffs and geothermal drilling and exploration by the end of this year to mitigate some of the risks and encourage more investments into the sector.

“The implementation of the country’s feed-in tariffs (FiT) for geothermal is expected to offset the high capital costs associated with geothermal production and promote more investment in the region and is considered a successful initial move for the geothermal sector,” said Mathur.

Under its “Roadmap for Geothermal Resources,” Indonesia pursues a strategy of managing geothermal work areas (GWAs) selected by private companies and offers unique tax incentives for the geothermal industry. The programme provides incentives for the private sector to use certified emission reductions (CER) to raise carbon revenue.

GlobalData estimates that the country will represent around 60% of the new installations in the APAC

Sources: EIA, IRENA, National Sources, Fitch Solutions

region by 2025. In a highly optimistic scenario, this could even represent a 75% share in the new installed capacity within the APAC region.

However, IEEFA analysts noted that the problem with geothermal projects in Indonesia for the past three years has been around the economics of the project, that cannot compete with the current Building Performance Prediction (BPP) regulation. Also, 80% of geothermal potential lies in conservation forest, making forestry permits a real headache for developers.

Geothermal is not expected to hasten unless the new tariff regulation is set in the upcoming Presidential Regulation for Renewable Energy. It is said that the geothermal players are lobbying to get fixed feed-in tariff instead of maximum price limit, to avoid having prolonged negotiations with PLN.

Other obstacles in developing geothermal energy in Indonesia include policy inconsistencies, bureaucracy, lack of decent infrastructure, high investment costs such as high exploration, engineering and procurement costs, as well as higher than average risks.

By 2025, the majority of the growth amongst the APAC geothermal markets is likely to come from Indonesia, Philippines, and Japan. In the longer term, China is also likely to join the group as it improves its technology and formulates the policy landscape during the learning curve, according to Mathur.

The pre-development risks associated with geothermal technology are high, which is a key reason for the slow development of this technology. Policy measures, which are mostly targeted at solar and wind sectors, need to be geared towards tackling the challenges in the way of geothermal energy development.

Japan can look to continue favourable FiT as fundamental policy, a better energy mix policy, as well as reduced time taken for environmental assessment in developing renewable energy sites to extract more renewable energy from geothermal.

On the other hand, China is still at an early stage in developing of geothermal power generation. However, the country has took the lead in developing geothermal resources for heating purposes. This has resulted in enabling the government to put forth concrete steps towards carbon mitigation and decarbonisation across the power sector.

Many integrated energy companies have also laid down expansion plans for geothermal heating development plans. Reduction in the subsidy and preference to wind and solar projects than other renewables, huge upfront capital requirement for geothermal as compared to wind and solar are just some of the factors that holds wide spread of geothermal development for power generation.

IEEFA analysts noted that China may formulate support for geothermal power generation and on-grid tariff policies to address these issues, as well as strengthen the geothermal energy production and generation management systems and technical standards and enhance geothermal energy creation and usage planning and project management.

Meanwhile, the Philippines is highlighted as one of the global geothermal outperformers, with the country having some of the highest installed geothermal capacity levels across the globe. In fact, by 2029, the country is expected to have the fourth largest installed geothermal capacity in the world.

On an annual average basis, the Philippines will have the second largest geothermal capacity in the Asia region and fourth largest globally over the next decade, according to Fitch Solutions. The country showed a strong existing capacity despite the limited growth forecast for the country posing a downside risk with growth coming mostly from the country’s strong existing geothermal capacity and forecast limited growth in the renewables sector.

Mathur believes that implementing guaranteed power purchase price under FiT for geothermal can help the Philippines to boost its efforts in unearthing currently unexplored geothermal potential.

Amidst the pandemic, the outlook for the geothermal sector has barely derailed. On the contrary, GlobalData firmly believes that the pandemic has increased the intent of the governments to diversify away from fossil fuel generation to planning increased participation from renewable energy sources.

The APAC geothermal market seems to be hitting the right notes with the pandemic providing the ample push for the APAC nations rich with geothermal resources to develop the resources for both power and heating purposes, said Mathur.

The market, which has been stagnant due to lack of policy measures and development intent from the governments, is likely to gather steam as renewables gather higher importance amidst the COVID-19. Energy security and dependence along with de-carboniszation of the generation mix will help expand the geothermal resources at a faster pace.

IEEFA analysts further noted that the private sector will play a larger role in delivering large investments and expertise required for the development and maintenance of geothermal projects amongst others, particularly in Asia if it is willing to take on the somewhat higher risks.

Globally, geothermal power capacity is expected to grow by an annual average rate of 2.5% between 2020 and 2029, to reach slightly over 18GW by 2029, Fitch Solutions said. This total installed capacity is notably lower compared with other renewable energy technologies, particularly in wind and solar power.

By the end of the 10-year forecast period, the geothermal segment will comprise just 0.7% of global installed non-hydroelectric renewables capacity and around 2.0% of total non-hydro renewables generation.

Offshore activity levels in Asia keep increasing, with China now taking the lead

Activity and development of the industry continues to grow within the region.

With 6.1 GW new capacity added, 2019 was the best year in history for the global offshore wind industry, according to Global Wind Energy Council’s (GWEC) Global Offshore Wind Report.

The global offshore market grew on average by 24% each year since 2013, bringing the total installations to 29.1 GW, which accounted for 5% of total global wind capacity at the end of 2019. The UK, Germany, China, Denmark, and Belgium were noted as the top five offshore wind markets in total installations.

Meanwhile, Europe remains the largest offshore market as of the end of 2019, making up 75% of total global offshore wind installation. However, the activity level in Asia keeps increasing with China taking the lead followed by Taiwan, Vietnam, Japan, and South Korea.

Development in the Asian offshore markets was remarkable with China achieving a new record in 2019, installing 2.4 GW offshore wind in a single year and Japan accelerating offshore wind development with its first offshore wind auction launched in summer 2020.

Positive steps were also made in Taiwan as it connected its first utility-scale offshore project to the grid. A further 10 GW is also planned to be built offshore from the island between 2026 and 2035, on top of the 5.6 GW offshore wind to be installed by 2025.

project with two units of V47-660kW turbines in 2003. However, GWEC notes that the Asian offshore market was not ready to take off in earnest until 2014, when the Chinese central government released the National Offshore Wind Development Plan (2014-2016).

In 2017, China passed the 1GW annual installation milestone; one year later, it surpassed the UK as the world’s top market in new installations.

At present, project developers and investors are rushing to commission their projects before the end of the 2021 deadline in order to capitalise on the 0.85RMB/kWh FiT for offshore wind.

Considering the extraordinary volume of new capacity (4-5 GW/year) will be built in 2020 and 2021, GWEC Market Intelligence expects China will surpass

the UK as the world’s largest offshore market in total installations by 2021, if not 2020. However, new installations will decline dramatically from 2022, when the central government will terminate the subsidy for offshore wind. Annual offshore wind growth in China in the future will depend on whether subsidies provided by provincial governments will be available and whether offshore wind industry can reach grid parity before 2025.

GWEC Market Intelligence’s market outlook predicts that China will continue to dominate the Asian offshore wind market in the first half of this decade, with more than 70% market share, whilst Taiwan is expected to be the largest offshore market in Asia after China.

However, the report notes that the scales will tip from 2025, when more utility-scale offshore wind projects get connected in Japan, South Korea, and Vietnam. China’s market share in this region is likely to drop to 58% in 2025 and will continue to decline when offshore projects expand to new markets with high resource potential, like India and the Philippines, towards the end of the decade.

Moreover, the average annual growth rate in Asia will stay at the level of 1.7% in the first half of this decade, but is likely to increase to 8.4% in the second half. China (52 GW), Taiwan (10.5 GW), South Korea (7.9 GW), Japan (7.4 GW), and Vietnam (5.2 GW) are expected to be the top five markets in this region for new installations in the decade.

However, the report notes that excluding China, the Asian offshore wind market is still at the early stage of development. Each market is facing the challenge of developing a local supply chain and the necessary competencies and capabilities to build an offshore wind industry.

The early experience from Taiwan has proven that collaboration with European partners across markets in this region is essential for success. .

GWEC Market Intelligence predicts that Europe will still remain as the largest

Source: GWEC Market Intelligence

regional offshore wind market in terms of total installations by 2025 and 2030. Nevertheless, Asia’s share of the global market is expected to grow from 24% in 2019 to 42% in 2025, where it is likely to remain until the end of the decade.

Taiwan Taiwan is heating up as the secondlargest offshore wind market in the Asia-Pacific region, after Mainland China. Ambitious capacity targets set by the DPP government have attracted eager interest from leading offshore wind developers and technology providers. Already, 128 MW of offshore capacity has been installed at Formosa 1, Taiwan’s first commercial-scale offshore wind farm in Miaoli County, and a further 109 MW is due to come online from the Changhua County project by the end of 2020.

Offshore wind is a key component of Taiwan’s green economy vision, which charts a nuclear-free pathway to generate 20% of electricity through renewable energy by 2025. The government is aiming to install 5.7GW of offshore wind by 2025, and in late 2019 announced that it would double its ambitions to 10 GW over the 2026-2035 period. While the 5.7GW tranche was procured across a selection round and auction, the next 10 GW (termed Round 3) will likely be conducted across two phases.

Following government delays due to COVID-19, a draft version of the Round 3 framework, including how much volume will be allocated and when, is due to be published by end of this year, with the first phase of allocation conducted from Q2 2021 to Q2 2023.

Critical to the steady progression of the market will be the government’s localisation strategy, which aims to consolidate the entire supply chain in Taiwan, from turbine components to submarine cables to shipbuilding. The industry must balance growth with local content requirements that are expected to

be higher in Round 3.

Within the year, positive signs have already been marked by announcements for an MHI Vestas-Tien Li blade manufacturing facility in Taichung, an SGRE nacelle production facility in Taichung and CDWE’s work on the first Taiwan-built offshore wind installation vessel. But how flexible the localisation requirements are in the forthcoming Round 3 framework will be key to determining whether the nascent offshore wind industry can develop into a sustainable and competitive market.

Over the next decade, Taiwan will achieve more than 10 GW of installed offshore wind capacity, becoming an experienced market with an established domestic supply chain.

Japan Japan’s offshore wind market has taken time to develop, with the first pilot projects going into the water back in 2003. In the years following the Fukushima nuclear accident in 2011, there was renewed commitment and activity, with both fixed and floating foundations being deployed at faster rates.

To date, no commercial-scale offshore projects greater than 20 MW have been installed and the development of a viable market structure is emerging at a slow pace. But 2020 marks an inflection point for Japan’s offshore wind sector.

The government launched the first offshore wind auction in the general common sea in June 2020 and the other four promising sea areas nominated in July 2019 are ready for auction after the approval on 21 July 2020, four more sea areas were nominated as promising area in the same month.

In March, GWEC and the Japan Wind Power Association (JWPA) set up a new Japan Offshore Wind Taskforce (JOWTF), which will play a key role in working with the government to develop a sustainable wind industry, as well as produce a detailed Cost Reduction

Study to identify different price/ volume scenarios and investment and industrialisation opportunities.

The feed-in tariff (FiT) for wind power was approved in Japan in 2012, but the tailor-made offshore FiT was not available until March 2014, when the Ministry of Economy, Trade and Industry (METI) approved the ¥36/kWh (€0.28/kWh) FiT for offshore wind. Despite the rate being the highest available anywhere in the world for offshore wind, Japan only had 66 MW of offshore wind installed by the end of 2019, including five floating turbines (totaling 19MW) and 23 nearshore wind turbines.

The slow uptake is attributed to Japan’s overly complex Environment Impact Assessment (EIA) system and market uncertainty. It can take four to five years to pass through Japan’s strict environmental assessment process, and the lack of clarity and coordination between different government bodies has prompted industry to call for a “one-stop shop” approach. As of January, 14.8 GW of offshore wind projects were recorded in the EIA pipeline.

To address these challenges, the government has been streamlining regulation since 2017. Further progress was made in 2019 with METI and MLIT announcing the first nomination of 11 offshore wind promotion zones in July for fiscal year (FY) 2019. Four of these zones (Goto in Nagasaki, Choshi in Chiba, Yurihonjo in Akita, Noshiro in Akita) have been nominated as promising areas where local authorities and residents have agreed to cooperate to develop offshore wind projects.

Although COVID-19 prolonged public consultations, METI and MLIT launched Japan’s first auction in July for a floating offshore wind farm (8 turbines, not less than 16.8 MW) off Goto City in Nagasaki Prefecture, to run until December 2020.

According to METI, the operator will be selected in June 2021. The other three promising areas nominated for FY2019, were nominated as the zones for promotion of offshore wind on 21 July 2020. Of these areas, the Yurihonjo area in Akita has been divided into two areas, Yurihonjo North and Yurihonjo South, to promote competition.

Furthermore, METI & MLIT announced the second nomination of 10 offshore wind promotion zones in July 2020 for FY2020. Four of these zones (Aomori Japan Seaside North, Aomori Japan Seaside North South, Happou and Noshiro in Akita, Saikai in Nagasaki) have been newly nominated as particularly promising areas.

Offshore wind in Japan’s long-term energy strategy Japan has hesitated to announce a long-term offshore wind

Source: METI, MLIT, JWPA

target because the METI still maintains its commitments with the nuclear and coal industries. The official wind power target in Japan is only 10 GW by 2030, including both onshore and offshore, representing 1.7% of the country’s annual electricity production. This situation, however, is expected to change gradually. The trends of global energy transition and decarbonisation have made the Japanese government change their future energy plan. METI’s minister Hiroshi Kajiyama recently declared the closure of 100 old & low performance coal-fired power plants by 2030 (out of 140 existing coal-fired power plants) and announced that the country’s energy strategy would prioritise decarbonisation over the current “energy mix” plan (fossil, nuclear and renewables). This change will be reflected at the next “Japanese long-term energy vision,” which is due to be revised in 2021 (it is revised every three years).

As coal-fired generation supplies about one-third of Japan’s electricity,renewable energy and particularly offshore wind is expected to play a big role to fill the gap.

A more streamlined regulatory environment has drawn the attention of large local utilities including TEPCO, which signed an MOU with leading offshore wind developer Ørsted to work jointly on offshore wind projects in Japan and abroad. In addition, Kyuden Mirai, a subsidiary of Kyushu Electric Power Co, J Power and Tokyo Gas Co. also signed the partnership with RWE, Engie and Principle Power respectively with the focus on offshore development.

Local and international suppliers are also entering the offshore wind value chain. However, the government may need to find a new strategy to revive its local offshore turbine manufacturing industry as two local turbine OEMs, Japan Steel Works (JSW) and Hitachi, have discontinued turbine production in recent years; this could leave room for MHI Vestas (a joint venture between

Mitsubishi Heavy Industries and Vestas), SGRE, GE Renewable Energy, and others to move in.

This year is expected to be an important year for Japan’s offshore wind sector, with the launch of the first wave of commercial projects and the announcement of the framework for further tenders.

South Korea Nearly a decade ago, South Korea adopted an ambitious Green Growth Strategy that aimed to reduce greenhouse gas emissions by 30% by 2020. This strategy marked the beginning of “green growth” as the direction of travel for South Korea’s economic growth, sparking the interest of domestic industrial conglomerates (such as Samsung, Hyundai, Doosan and STX) in renewable energy project development and equipment supply.

Following a 2.0 MW STX direct drive offshore turbine and a 3.0 MW Doosan geared drive turbine installed in early 2010s for testing purposes, the 30 MW Tamra offshore wind farm came online off Geumdeung-ri in Jeju Island in 2016. However, the sector has been generally slow to take off, due to public opposition on environmental and livelihood (fishing) issues. Long permitting periods and a low initial feed-in tariff, prior to the introduction of the Renewable Portfolio Standard scheme, also dampened growth.

As a result, South Korea’s initial foray into “green growth” and a clean energy transition saw little translation into action for the better part of the last decade. South Korea prepares to push the reset button on offshore wind.

Nonetheless, at the start of a new decade, the momentum for offshore wind in South Korea is picking up with the passage of President Moon Jae-in’s Green New Deal and a groundswell of interest from ambitious consortia of local and international wind energy developers.

As of June, there are currently five operational offshore wind projects

totalling 132.5 MW, including the latest and largest 60MW demonstration Southwest Offshore Wind Project completed in January – the first phase of a massive 2.5 GW project. Over 23 offshore wind projects are in preliminary development, totalling 7.3 GW.

Despite its slow start, South Korea’s offshore wind sector is now benefiting from the financial clout coming from both state-owned and foreign investors, and even further buoyed by its existing industrial infrastructure.

GWEC Market Intelligence forecasts that a total of 7.8 GW of offshore wind is likely to be built in South Korea by 2030, of which 1.2 GW is expected to be floating wind. However, South Korea remains a challenging market with respect to terrain complexity, turbulent wind conditions and strong incumbent energy and marine industry actors.

Coupled with criticism that government rhetoric does not always match action, the market will need steadfast public steering and ambitious long-term targets to drive decarbonisation and diversify the power mix. Still, with sufficient government commitment and industry experience from neighbouring countries to smooth the learning curve, the future of South Korea’s offshore wind sector looks bright.

Vietnam Since commissioning its first 16MW intertidal wind farm in Bac Lieu in 2013, Vietnam has emerged as the offshore wind market to watch in South East Asia. Now with 99MW of offshore wind installed capacity, and 200MW due to come online in 2020, Vietnam has drawn significant interest amongst international developers, investors, and financiers as a rapidly growing market for wind.

Vietnam’s market growth is supported by strong fundamentals including a steep rise in energy demand, rapid industrialisation and a growing population. While currently dependent on fossil fuel generation, the Vietnamese government has sought to accelerate the production of electricity from renewable sources, targeting 10% renewables in its 2030 power mix in PDP 7, the country’s master energy plan.

Steady strengthening of Vietnam’s wind project pipeline PDP 7 aims for 800MW of onshore and offshore wind energy by 2020 and 6GW by 2030 – which pales in comparison with the country’s technical potential. With a coastline of more than 3,300 kilometres and average wind speeds of 8-9m/s in the south, up to 475 GW of fixed and floating offshore wind resource potential has been identified by the World Bank Group.

Due to growing industry appetite to develop offshore wind power in Vietnam, the market is expected to reach around 2.0

GW of offshore wind capacity by 2025 and 5.2 GW by 2030. Offshore wind is prioritised in the government’s plan to build a “blue economy” – developing marine-based renewables to meet energy needs – and achieve energy security.

Since revising PDP 7 in 2016, the Vietnam government has been reorienting its reliance on coal to prioritise clean energy sources.

Whilst Vietnam remains a net coal importer for now, the declining economics of new coal generation vis-àvis wind and solar power are driving the shift to utility-scale renewable generation.

Despite the ambition for decarbonisation and attractive resource potential, pursuing a least- cost transformation of the energy system will require transparent policy, streamlined administration and a flexible grid. The lack of policy differentiation between onshore, nearshore and large-scale offshore wind projects of Vietnam is holding the sector back.

PDP 8 is expected to deliver more concrete policy frameworks for large-scale offshore wind developments, including zoning, marine spatial planning, and ports infrastructures plans and permitting processes. A key issue will be the design challenges for grid upgrades, and whether public or private bodies will be responsible for making investments in grid connections and broader transmission infrastructure.

Promising developments for PDP 8, expected by the end of 2020, will outline a two-year extension to the current FiT framework for offshore wind, as well as higher capacity targets out to 2030. In April, the Ministry of Industry and Trade of Vietnam (MOIT) officially proposed an extension of the FiT mechanism for wind projects from 1 November 2021 to 31 December 2023. By 2024, the government is planning to transition wind procurement to an auction system.

This development followed policy engagement with GWEC Asia, which highlighted the supply chain disruptions, labour shortages and construction delays brought by the Covid-19 outbreak, as well as the permitting delays to several wind projects which made it infeasible to meet the 2021 commissioning deadline under the original FiT framework.

A direct power purchase agreement (DPPA) pilot programme could also generate new revenue opportunities and demand for renewable energy from industrial consumers. Currently, national utility Vietnam Electricity (EVN) and its subsidiaries act as the sole offtaker of electricity from generators. However, the government has announced its vision for a competitive power market, with this DPPA pilot scheme operating from 2021 to 2023, paving the way for a retail electricity market.

Offshore wind is set to play a critical role in Vietnam’s clean energy transformation, bringing in local and foreign investment, creating local and sustainable jobs, delivering carbon reduction and positioning the country as an energy leader in South East Asia.

The COVID-19 pandemic has shocked the global energy sector, forcing projects to suspend work to comply with social distancing regulations, challenging the investment conditions of markets bracing for economic recession, and slashing power demand by up to 10% in some regions in 2020. The size of that decline is around seven times greater than during the 2008- 2009 global financial crisis, according to the IEA, and has hit demand for oil, natural gas and coal the hardest.

But renewable energy will see an overall increase in its share of global power generation this year, due to its costcompetitiveness and priority dispatch in many markets. And the offshore wind sector, with longer project development timelines, will largely be shielded from the short-term supply chain disruptions which impacted project execution in onshore markets across the world.

In 2020, the wind capacity lost to the pandemic is estimated by GWEC Market Intelligence at around 15 GW, with volume shifting to come online by 2021 instead.

Over the next five years, the leader for offshore wind installations by far will be Mainland China. Driven by an offshore wind FiT for projects which will be grid-connected by 2021, the market has sufficient runway and production capacity to rebound from the slowdown in activity during H1. The delay for offshore wind project construction in China is estimated at six months, due in part to restrictions on imported bearing materials from Europe

and imported blade materials.

Since the grid-connection deadline extension proposal sent by the local wind industry to the National Energy Administration (NEA) seems unlikely to be approved at the time of writing, the Chinese offshore industry is currently running in full steam in project construction. Based on the latest offshore wind market dynamics and feedback from suppliers and developers in China, GWEC has kept its 19 GW pre-COVID forecast unchanged for China for at least the next five years.

GWEC Market Intelligence forecasts more than 6 GW installed in markets like South Korea, Japan, France, Norway and the UK. Turbine technology is another area to watch, with European and Chinese OEMs improving capacity and resilience to achieve LCOE reductions and application in a wider range of marine environments. The average size of installed turbines is on track to be 10-12MW by 2025. As hydrogen costs fall and crossindustry collaboration takes place, Powerto-X offers a potential solution to allow offshore wind to scale exponentially and support the decarbonisation of fossil fueldependent sectors.

However, these require adequate policy coordination and supportive frameworks, a formula which allowed renewables to take off over the last decade. As summarised in this report, there are already plenty of lessons to be gleaned from early offshore wind markets regarding support schemes, grid integration, cost reduction and industrial development. There are still areas for R&D and investment, with GWEC and industry players continuing to scan the horizon for opportunities to innovate, learn and improve offshore wind in order to accelerate its deployment. Combined with collaboration with the government, the industry can build on these to deliver offshore wind’s potential as a core pillar of the global energy transition.

be used to build more power plants, finance will also be mobilized to deliver these investments.

However, the report notes that accelerating deployment also calls for better coordination on land issues to ensure that grid availability matches the commissioning of new power projects.

Simplifying land acquisition procedures and digitizing land records would remove a bottleneck affecting the sector today.

Furthermore, the financial health and resiliency of power distribution public sector enterprise like SECI, many positive actions have been taken. The most recent being the removal of tariff caps on bids, reflecting the government’s faith in the sector’s maturity,” he added.

With an expanding economy and growing population, India’s power demand continues to rise and become the world’s third-largest power consumer, behind China and the United States. The country has consumed 1,285TWh in 2019, up from 851TWh per year at the beginning of the decade. Domestic and industrial consumers together constitute 56% of power demand, followed closely by agriculture. In March 2019, the government achieved India’s net power generation capacity rose 212GW over the last decade 100% household electrification and aims to deliver uninterrupted, 24x7 power for Acceleration in India’s clean all consumers. BloombergNEF notes that even as power demand was expanding, the generating capacity supply deficit narrowed from 79TWh in 2010 to 6TWh in 2019. The transformation of its power sector brings a $633b investment opportunity to of generation capacity, fast rollout build more power plants and expand grid infrastructure of transmission and distribution India is now hailed as one of the most vibrant clean energy markets in the world with its ambitious targets, The government is banking on India’s that they will not face payment delays and retroactive contract negotiation. Procurement of clean energy by infrastructure, and the connection of millions of people to the grid. In the last decade, India’s net power generation capacity increased by comprehensive government policies and renewable sector corporates looking to reduce their costs 212GW, with roughly 42% coming from economics, according to a report from to transform the also provides an opportunity to offer renewable energy sources including large BloombergNEF. As the energy transition country’s energy alternative bankable offtakers for clean hydro. India’s wind and solar installed accelerates, this decade is said to bring landscape energy project developers. capacity also quadrupled in a decade, to new challenges and opportunities for all “The renewable energy sector in reach 82GW by 2019. players in India’s clean power revolution. India has tremendous potential, and The two main reasons for the

The country is currently the world’s the government recognizes its ability sharp jump in capacity have been largest and most competitive clean to transform India’s energy landscape. falling technology costs and proactive energy auction market, which allows Hence it has tried to create an enabling government policies to achieve the target it to procure some of the cheapest policy framework to achieve the of 175GW renewables by 2022. renewable power. India’s new auction aggressive targets it has set for the Furthermore, renewables deployment designs also allow the replacement of sector,” said Sumant Sinha, chairman doubled over five years, with solar at the fossil fuels through better integration. and managing director, ReNew Power. heart of this boom. From 2017, 15GW

The transformation of India’s power “From trying to ensure easier of renewables have been added each sector in this decade brings a $633b availability of land through solar and year. More than two-thirds of this came investment opportunity, which will wind parks, to setting up a dedicated from PV, followed by wind. However, as well as to replace and expand grid infrastructure. Public and private Electricity consumption has risen every year

This was a result of rapid expansion companies will also need to be improved to give investors confidence Source: Bloomberg Finance (2020)

Source: Bloomberg Finance (2020)

installations of hydropower remained low due to long construction timelines, environmental concerns, and social pushback from local communities.

At the end of 2019, the country had 143GW of clean generating capacity, including large hydro—representing about 38% of all the power installed in the country.

The continuation of India’s clean power revolution is critical to global climate efforts. Coal’s role in the mix will continue to drop despite rising power demand. Retiring older coal plants will improve utilization rates for the coal fleet and significantly reduce CO2 emissions. New clean power generation will help India avoid more than 499 million tons of CO2 emissions a year by 2030, and bring peak emissions within reach in the next decade.

India has been one of the world’s largest coal markets with at least 15GW coal generation capacity added every year until 2016, driven by plentiful domestic coal supply and a large power deficit. However, capacity additions have tipped decisively toward clean power generation since at least 2016.

India’s coal power fleet delivered just over half its maximum generation output in the fiscal year ending March 2020. This is a historical low, marking a 21ppt decline over the course of a decade, from 78% in 2010.

Projects owned by the federal government were used far more than those owned by private IPPs or state governments. This is because federal plants typically have lower fuel costs as they are located closer to the coal mines.

A key factor behind this overcapacity is the government’s overestimation of the growth in national power demand. This led to over-investment in new coal capacity, with 96GW of coal plants added to the grid over 2011-2016 alone.

At the same time, renewables capacity grew, with the introduction of the 2022 targets and its falling costs. Renewables have priority dispatch and the newer installations have lower levelized costs of energy, helping them secure a larger share of growth than coal.

India’s emission norms for new coal and gas power projects are among the strictest in the world, but enforcement is weak. The initial deadline to meet these was December 2017. It has now been extended to December 2022 due to widespread non-compliance.

The International Institute for Sustainable Development estimated that India’s coal plants need $12b to install SO2, NOx and particulate matter control equipment. This may increase tariffs by 0.32-0.72 rupees/kWh, adding to coal’s competitiveness challenge.

The clear shift to renewables capacity is a lasting one as it is primarily driven by economics. The gap between the cost of new coal versus clean power generation continues to widen in favor of the latter.

Solar and wind have been the cheapest sources of bulk power generation in India for the past three years. Since 2014, the mid-case levelized cost of energy (LCOE) has dropped by 80% and 66% for solar and wind generation respectively.

In theory, the best-in-class wind farms and solar plants can generate power at $27-29/MWh, a third cheaper than our LCOE estimate for best-in-class new coal-fired power stations, at $41/MWh at the current time.

Moreover, renewable energy sources, including large hydro, supplied 21% of India’s grid electricity needs in 2019. This share has increased by 5 ppt within five years, driven by combined additions in solar and wind of between 5GW and 13GW annually.

The share of gas power generation remains below 5% as high prices for imported natural gas, and a lack of adequate gas distribution infrastructure make it more expensive to generate and distribute than coal power plants.

Private companies are the main investors in India’s clean power projects The majority of coal power plants in India are owned by central government companies, such as National Thermal Power Corp (NTPC) Ltd. and a variety of state government entities active in the power sector.

In contrast, private independent power producers (IPPs) have built 90% of the wind and solar power projects in the past five years. Government companies are now increasingly participating in clean energy auctions too. Because of this, the growth of renewables has started eating into coal’s share of generation, which was the dominant fuel for power generation throughout 2019 and earlier.

Coal remains the workhorse of India’s electricity supply system, providing close to three-quarters of the country’s power needs in 2019. However, it was also the first year in which the absolute energy generated by coal saw a YoY decline due to a slower growth in power demand, and record growth in clean power generation.

Furthermore, efficiency gains and technology are reducing employment in the coal sector worldwide. The Council for Energy, Environment and Water, together with the Skill Council for Green Jobs, estimated that more than 105,000 jobs were lost in India’s coal sector between the years 2000 and 2015, due to increasing mechanization.

Meanwhile, a report by the International Climate Initiative expects that India’s renewable energy sector could employ five times more people in 2050 than the entire Indian thermal generation sector, comprising coal, gas, nuclear, employed in 2020. The study expects coal sector employment to decline by 52% in the next 30 years.

Renewables growth is adding jobs at the fastest pace in the power sector. According to a report on growth in green energy, around 100,000 employees worked in India’s wind and solar sector, at the end of March 2019.

“The renewable industry, especially solar, has progressed tremendously in the last decade and is continuously evolving. With the increase in the renewable energy share in the energy mix and the drop in storage prices, the sector is moving rapidly towards 24/7 supply from renewables power sources,” said Ranjit Gupta, CEO, Azure Power.

“With the recent integrated bids, like RE hybrids, round-the-clock supply and peaking power supply, designed to serve the needs of the grid, the sector is

Source: Bloomberg Finance (2020)

set for a massive leap forward. Providing dispatchable power to the grid is the only way the renewables sector will sustain its growth in years to come,” he added.

Renewables also need to be associated with storage to displace coal more widely in the future. We expect that midcase new onshore wind and new solar combined with battery storage will outcompete new coal plants on a levelized basis by 2023 and 2029 respectively. The coal LCOE includes the costs of meeting emission norms.

Li-ion battery prices have fallen by 87% over the past decade. By 2024, BloombergNEF expects prices to be below $100/kWh on a volume-weighted average basis.

The report further notes that increasing the emphasis on decentralized small renewables and boosting domestic manufacturing have the potential to create more employment opportunities.

The levelized tariffs at India’s auctions are among the lowest in the world. The levelized tariff calculation converts a local currency structured tariff to a common 2019 $/MWh base after accounting for inflation, currency of payment, project life and expected date of commercial operation. This enables like-for-like comparison between auctions over time and different geographical locations.

India’s levelized auction tariffs for both wind and solar are among the lowest in the world, despite relatively higher borrowing costs and the absence of hidden subsidies.

These prices are a reflection of India’s hyper-competitive auctions and extreme project optimization by its IPPs. It is not uncommon for auctions in India to attract several times more bids than the capacity on offer.

Accelerated depreciation attracted companies with taxable profits from other industries to invest in clean energy projects. As the sector matured, pure-play IPPs have taken the lead in building new capacity. The announcement of a further decrease in the tax rate will boost investor appetite anew.

Capital subsidies are still needed for segments that are relatively less developed, for example residential roof top solar and small scale solar within the agriculture industry.

The federal government’s RPO trajectory has not been implemented by all states, but it remains a key driver of distribution companies signing longterm PPAs for renewables.

The government is also considering a separate Hydropower Purchase Obligation to increase the utilization of existing large hydro plants and provide investment signals for new capacity.

Record volumes of auctions and competition have driven down tariffs India is the world’s largest renewables auctions market (cumulatively till 2019). In India, utility-scale wind and solar projects are primarily contracted through competitive auctions. A national target of having 175GW renewables installed by 2022 has ensured that the volume of auctions remains high.

India’s renewables auctions are conducted in a transparent process that follows standardized guidelines issued by the federal government. Tenders can go through multiple rounds of stakeholder consultations and amendments to encourage participation and help IPPs make informed bidding decisions.

The 2019 average auction tariffs for solar are less than half of their 2015 levels. The decline has been less steep for wind, but for both technologies, the average tariff in 2019 was below 3 rupees/kWh ($0.04 in June 2020).

Extreme competition has led to IPPs optimizing each stage of project design, construction, maintenance and operation. They have devised complex financial strategies to lower their cost of capital, and India’s large pipeline of tenders gives developers strong bargaining power when negotiating prices with equipment suppliers.

Federal auctions have overtaken statelevel auctions since 2018. The poor financial health of state-governmentowned electricity distribution companies makes IPPs reluctant to sign contracts directly with them. This led to state auctions being undersubscribed and delivering higher tariffs as IPPs factored in the bigger offtaker risks.

At federal auctions, a federal agency such as Solar Energy Corp of India (SECI) acts as an intermediate procurer, and thus protects the IPPs from payment delays, giving them a quasi-sovereign guarantee on timing.

Contracting structure for federal auctions SECI maintains a payment security fund that can absorb the delay between the moment IPPs need to be paid, and that where power distribution companies can pay.

As a last resort, federal agencies can also invoke the tripartite agreement between itself, India’s central bank and the state governments. This arrangement allows the federal government to withhold financial assistance payments to state governments if distribution companies repeatedly fail to pay their dues to SECI for delivered power.

The introduction of a new goods and service tax (GST) in July 2017 caused temporary confusion for the solar industry with regards to the applicable tax rate. Similarly, the safeguard duty (SGD) for cells and modules imported from China, Malaysia, and developed countries introduced in July 2018 caused a spike in capex costs.

IPPs whose projects were under construction complained that they were unfairly penalized by the GST and SGD after their tariff had been fixed. These developers are currently being compensated by the offtakers for the additional costs arising from these taxes.

Furthermore, the insistence of electricity offtakers on low tariffs has led to five solar auctions, totaling 4.7GW, being partly or fully canceled in 2018, after bidding had been completed. This created a degree of uncertainty for participating developers.

In 2019, the southern state of Andhra Pradesh sought to renegotiate renewable power purchase agreements to reduce the cost of power for its loss-making discoms. However, the federal Ministry

of New and Renewable Energy strongly opposed the move, warning that future investment will dry up if contracts are not honored.

Despite this, the Andhra Pradesh High Court granted temporary relief to IPPs and the matter is still sub judice.

The rapidly falling tariffs at renewable auctions have raised concerns that IPPs will be forced to build low- quality projects. The continual stream of mergers and acquisitions in India, typically involving international investors, suggests that underperformance of projects is not common.

As most projects have been added only in the past decade, it is still too early to make large-scale assessments of their long-term financial and operational performances.

However, the market has continued to grow and successfully completed auctions eased the concerns resulting from these cancellations. Newer auction designs to make power output closely match demand should reassure discoms.

In 2015, India announced a target of building 175GW of clean energy by 2022, a more-than-fourfold increase in installed capacity in just seven years. By 2030, Prime Minister Narendra Modi wants India to reach a new goal of 450GW of renewables.

“We have already crossed 37%, and are expecting to get to 55-60% by 2030. The question before us as a country, and as the world, is whether the environment is important or not, and whether we want to leave behind a livable world for our great grandchildren,” said Shri Raj Kumar Singh, Union Minister of State (Independent Charge), Ministry of Power and Ministry of New and Renewable Energy, and Minister of State, Ministry of Skill Development and Entrepreneurship.

Integrating such volumes of variable generation needs a flexible power system, apart from battery storage and peaker gas plants, lessons from around the world highlight the importance of demand-side measures, grid investments, as well as significant market reforms for India.

BloomberNEF notes that India’s clean power revolution has made a good start toward 450GW with the power demand growing by 50% and installed capacity more than doubled in the last decade.

Furthermore, New Energy Outlook (NEO) 2019 projects investment requirements of $410b to 2030, of which $281b is in renewables. India attracts 9% of the world’s total investment in generation and energy storage. This makes it the second-biggest investment destination after China.

Wind and solar put together need $188b of capital. To put this in context, new-build asset finance for the two technologies totaled $77b from 2010 to 2019. So, India will need to mobilize different sources of capital to finance the power sector’s expansion until 2030.

BloombergNEF estimates that India would need $335b of investment in the grid by 2034 to cater for 450GW of renewables. Almost 60% of this money would be needed in the transmission grid, with the remainder required for distribution networks.

Grid expansion and building of interconnectors for new generation units will require about $231b by 2034. Meanwhile, replacement of ageing existing transformers, substations and cables will require another $104b, whilst lot of additional investment would be required to digitize future grids

Meanwhile, the Central Electricity Authority (CEA) projects 2,518TWh of gross electricity generation by FY202930, compared to a 9% higher figure of 2,747TWh for 2030 in NEO 2019. The plant capacity factors are higher in NEO 2019, leading to more generation from lower capacity compared to the CEA's current projections.

CEA expects India to source 54% of electricity from coal, 19% from solar and 12% from wind by 2029-2030. NEO 2019 projects that coal would supply 55%, and solar and wind with just 15% and 11% respectively by 2030.

India’s power demand in 2030 is also expected to be around 2,700TWh, up from 1,500TWh in 2020. Increasing population and GDP per capita will continue to drive power demand growth in the next decade. Newly connected rural consumers will also expand their use of electrical appliances. Rising demand for air conditioning will push up its power usage by 25% by 2030.

The share of demand from electric vehicles is also expected to be less than 0.5% by 2030, despite early signs of growth by 2030.

Despite the rise in power demand, per-capita electricity consumption in India will continue to remain below that of many developed and developing economies. Even by 2030, India’s percapita demand is still expected to be lower than Brazil’s today.

This suggests that there is room for power demand to grow well beyond 2030, as India catches up with global trends in per-capita electricity best practices and requirements.

Although coal plants remain the top supplier of electricity, their utilization and share in the generation mix is declining with annual additions of renewables outstripping coal since 2017.

The report notes that one of the factors is India’s focus on cost, which made it the world’s largest renewables auction market at the end of 2019. The massive auction programs have allowed Indian developers to optimize their projects, and have attracted private sector investment. The country’s levelized auction tariffs are also amongst the lowest in the world.

Furthermore, solar and wind have been the cheapest sources of bulk power generation in India since 2018. The success of auctions and falling equipment prices globally, have made wind and solar cheaper than new coal plants on a levelized cost of energy basis.

In addition, the government complemented its goal for 175GW of renewables by 2022 and its auction programs with policies that have given a wide group of investors, national and international, private and public, the confidence to commit for the long term.

India’s auctions are also taking renewables closer to 24x7 power. The newer types of auctions force renewables to match coal plants on dispatchability.

ELISE DO Associate Director at Augusta & Co.

Offshore wind has truly spread in recent years, with Asian markets such as Japan rapidly developing their offshore capabilities. International investors and developers are starting to get involved in Japanese offshore wind, but to capitalize on opportunities in this growing market, they must show that they can work with domestic partners, leverage current Japanese partnerships from shared projects in other regions.

Japan’s energy policy has undergone a number of changes in the past 10 years. Following the nuclear accident at Fukushima in 2011, a review of regulatory standards resulted in the decommission of multiple nuclear reactors and a power generation shortfall.

To compensate for this, the Japanese government undertook measures to increase the role of renewables in the country’s energy mix.

In 2015, Japan’s Ministry of Economy, Trade and Industry (METI) indicated in their energy plan that renewables would make up 24% of Japan’s energy mix, representing 10GW of offshore wind capacity, by 2030. As the transition to clean energy continues to gain momentum in Japan—particularly in offshore wind—the market is quickly getting on the radars of both domestic and international developers such as Marubeni and RWE Renewables. To support the 2030 target, the Japanese government has implemented a number of further initiatives to accelerate the growth of offshore wind—a new legal framework for the use of Japan’s general territorial waters, identification of 11 potential areas for offshore wind development, as well as competitive auctions granting 30-year leases for offshore renewables installations.

Unlike European markets with established offshore wind sectors, Japan still faces multiple barriers which could limit the growth of offshore wind. These must be overcome to spread risk and avoid bottlenecks which could constrain project construction.

In particular, developing both specialist vessels and port infrastructure capable of turbine pre-assembly, construction, and maintenance is key. International developers who can add value in these areas through financial investment and leverage Japanese industrial capability by adapting production facilities for offshore wind will be ahead in Japan’s offshore industry.

With multiple domestic industries competing for Japanese marine space, the government is keen to support both the local economy and the growth of offshore wind. International developers looking to enter the space should take government objectives into consideration and look to deliver a net positive

impact on the local economy.

The scope of Japan’s offshore wind sector, along with a generous FiT scheme has attracted a network of banks and developers, now willing to finance large amounts of capital.

To unlock this capital and encourage domestic players to invest in projects, international developers need to reduce uncertainty stemming from their lack of experience operating in Japan by forming partnerships with their domestic counterparts, leveraging their current Japanese relationships from shared projects in other regions and demonstrating their experience in offshore project development.

With the Japanese market still in the early stages of development, the lack of opportunities to merge with or acquire local businesses will require foreign offshore wind developers to be more flexible in their approach. To mitigate their inexperience, international players would benefit from working with local businesses with high levels of expertise in these areas to conform to Japanese design standards and obtain ClassNK certification.

By combining expertise in large-scale offshore project development and local market conditions, partnerships give international players a strong position to compete in auctions tenders.

Forming those partnerships should be a key goal of early relationship building for aspiring foreign market entrants.

Many Japanese players have gained offshore wind experience by acquiring stakes in projects in Taiwan and Europe. Offering participation in an offshore wind project abroad to a Japanese partner can be a pathway to development collaboration and access to opportunities in Japan.

This is a significant opportunity for established international offshore wind developers looking to enter Japan’s offshore wind space. Even in early stages of development, organisations would benefit from developing strong ties to leverage the relationship when their counterparts secure any of the increasing opportunities in Japan.

Utility-scale offshore wind farms have only begun to emerge in Japan within the last few years, and the domestic market has relatively little experience compared to Europe. This has left an experience gap which international developers can fill. To take advantage of this, international developers and investors need to identify where they can be of most benefit to Japanese offshore wind developers and then demonstrate how they can help develop the industry in these areas.

For example, due to Japan’s challenging bathymetry, international developers can demonstrate their floating offshore wind capabilities and introduce domestic developers to international investors and manufacturers who are keen to invest in this technology.

International developers looking to get involved in Japan’s offshore wind market must take into account the operating and development landscape of the sector and seek to benefit the local economy as well as the offshore wind industry. By sharing lessons learned and providing clear direction to the market’s domestic developers and investors, international players can help establish best practices—paving the way for future offshore project development in Japan.

Against the backdrop of the COVID-19 pandemic, Vietnam appears to be forging ahead with its commitment to renewable energy development across the country.

Vietnam is set for another year of positive economic growth, which may temper the demand projections for new electricity with the baseline scenario being an increase from 42,080 MW in 2020 to 90,651 MW in 2030. However delivery delays impacting thermal power projects in the country and suspension of investment in the Ninh Thuan nuclear power plant augur well for a continued role for its renewable energy sector to meet demand.

Four key proclamations this year—Resolution No.55, MOIT Report No.1931, MOIT Report No.2491, and Decision No.13—provide guidance on the role renewable energy could play in meeting demand growth.

The 9.35 US cents / kWh feed-in-tariff (FIT) for ground mounted solar energy issued in 2017 triggered an unprecedented rush of solar energy investment in Vietnam. Prior to the COVID-19 pandemic total installed solar capacity was expected to reach 5,500MW by the end of 2020. Unfortunately, most of the solar power development has been in the southern provinces of Binh Thuan and Ninh Thuan that have the highest irradiation rates in the country, leading to grid overload and a mandatory reduction of power output of between 38-65% of installations’ design capacity. With solar tariff qualification having expired or near expiry, investment has stalled due to uncertainty surrounding returns on investment due to the tariff uncertainty.

Meanwhile, the development of wind power has lagged behind solar PV despite Vietnam having one of the longest coastlines and strongest average wind speeds in the region. Asides from approvals delays, many have pointed to less unattractive FITs and lack of visibility on the FIT several years ahead. The current FITs only apply to projects completed prior to 1 November 2021 and prior to the MOIT Report No.2491 there had been no indication what FIT will apply to projects completed after that date, which is needed given the higher investment costs and longer construction time required for wind power projects.

Resolution No.55 focuses on the orientation of Vietnam’s National Energy Development Strategy to 2030 with a vision to 2045 is only a guideline for the coordination and implementation of tasks and solutions within the energy sector. It proposes prioritising renewable energy sources to “replace

BREE MIECHEL, Partner at Reed Smith LLP

fossil energy sources to the largest possible extent” as a solution.

The MOIT Report No.1931 has no mandatory effect, although it does make a number of recommendations to the Prime Minister for his consideration and decision in relation to addition of further wind power projects into the power master plan, including: (i) approving an adjustment to the wind power development target for 2025, from 4,800MW under the Power Development Plan VII (PDP VII), to 11,630MW, (ii) supplementing the proposed wind power projects in the PDP VII with specific connection plans and capacity release conditions, (iii) supplementing and accelerating existing power grid projects to develop an adequate grid infrastructure fully coordinated with power projects, and (iv) having People’s Committees of provinces with wind power projects urgently review land use plans/master plans and other master plans under their mandate

The MOIT Report No.2491 also has no mandatory effect although it does make a number of recommendations to the Prime Minister for his consideration and decision in relation to extension of the application period of FITs for wind power projects, including: (i) extending the timing for application of FITs for wind power projects until the end of 31 December 2023, (ii) delegating to the MOIT to calculate and propose the new FITs for wind power projects having COD in the period from 1 November 2021 to the end of 31 December 2023, and (iii) after 2023, wind power projects to be subject to competitive tendering and an auction mechanism.

In contrast to Resolution No. 55 and the MOIT Reports Nos.1931 and 2491, Decision No.13 has legal effect from 22 May. It brings into force the MOIT’s recommendations in its report of 6 February, including the draft mechanism for encouraging the development of solar power in Vietnam. Decision No. 13 confirms: (i) FITs of 7.69 US cents / kWh and 7.09 US cents / kWh will apply to grid connected floating solar and ground mounted solar power projects respectively that were approved for investment policy by the relevant authorities prior to 23 November 2019 and that achieve a COD in whole or part between 1 July 2019 and 31 December 2020, (ii) a FIT of 9.35 US cents / kWh will apply to grid-connected solar power projects in Ninh Thuan province up to a total accumulated capacity not exceeding 2,000MW, (iii) the power purchase price for grid-connected solar power projects not meeting conditions set out in and above will be determined through a competitive process, and (iv) a FIT of 8.38 US cents / kWh will apply to roof top solar power projects where EVN is the offtaker and the time for operation and generation of power, and electricity meter is confirmed between 1 July 2019 and 31 December.

Together, the proclamations paint a picture of a government working towards a cohesive renewable energy strategy and an identification of the need for synchronous development of grid infrastructure. However, the time frames for award of the FITs under Decision No. 13 do not seem to take account of supply chain and labour disruptions as a result of lockdowns and border closures.

Further, successful future wind and solar PV capacity deployment will be contingent on approval of appropriate MOIT recommendations and, for solar PV, the terms of the auction processes adopted.

RIZKY ADITYA PUTRA, Senior Officer, APAEC, ASEAN Centre for Energy DYNTA TRISHANA MUNARDY, Technical Officer, APAEC at the ASEAN Centre for Energy ALFRED GURNING, Technical Officer, APAEC at the ASEAN Centre for Energy

actions in post-pandemic recovery plans

The level of uncertainty resulting from the pandemic in the economic packages should not only be intended for the good of national restoration, but context is still considerably high. Most countries in the region have also need to consider the future challenges. already enacted containment measures in order to control and mitigate On 14 April, ASEAN Leaders held the Special ASEAN Summit on the spread of the virus. COVID-19 to encourage the development of a post-pandemic recovery plan

The GDP growth of ASEAN+3 could be reduced from 4.8% in 2019 to zero by exploring the arrangements to preserve supply chain connectivity amongst growth in 2020, estimated by the ASEAN+3 Macroeconomic Research Office the ASEAN Member States. Recovering from this current hard time can be (AMRO) in August. a pivotal moment for ASEAN to redirect the priority of the regional energy Covid-19 impacts in the energy sector ensuring energy security and resilience. The impact of the pandemic is also heavily felt in the energy sector. The global energy demand has plummeted by 3.8% in Q1 and is predicted to decline up Cleaner energy and energy efficiency pathway to 6%, according to the Global Energy Review 2020 by IEA. Directing the energy development into a cleaner energy pathway will ensure

As highlighted by the ASEAN Centre for Energy, the most dominant a long-term secure, sustainable, and diversified energy system, as well as consequence of this pandemic is the sharp declines in oil demand from travel provide affordable solutions that align with climate targets. By accelerating and commerce restrictions and reduced operations in many industries. clean energy deployment, ASEAN can achieve multiple economic and social

Similar to the oil sector, the decline of coal demand is unavoidable, objectives in the pursuit of a resilient future. associated with lower demand in the electricity sector. Although the electricity In the regional level, the creation of a regional clean energy supply chain demand has shifted from the industrial sector to the residential sector, should be accelerated to accommodate a higher penetration of renewable increase in demand was outweighed by the massive reductions in commercial energy into the ASEAN Power Grid and ease the regulation of intra-biofuel and industrial sectors. However, this does not mean that the effect from the trade. ASEAN can also strengthen its cooperation by enhancing the regional increase in the residential sector was insignificant. In some ASEAN countries, market of energy-efficient products. Investments in RE and EE&C will the governments provided incentives to ease the electricity bills of vulnerable stimulate job creation in trades and manufacturing which can lead to a more people and communities. resilient region.

In the renewable energy (RE) sector, Global Energy Review 2020 of IEA reported that renewables became the only energy source experiencing a Decarbonisation of conventional energy system demand growth during this pandemic. However, in the ASEAN region, the Amidst pressure to reduce greenhouse gas emissions, the pandemic allowed economic disruption in China may create supply chain bottlenecks for clean us to reflect on how vulnerable the current conventional energy system is. energy technologies. Several RE projects in the region are at risk of major Based on the 5th ASEAN Energy Outlook of ASEAN Centre for Energy, delays due to changes in energy markets and safety of the workers. the region is projected to still have a high dependency on fossil fuels. Import The urgency of low carbon energy in the pandemic needs to consider strategic measures in transforming the current conventional Economic recovery would be the main priority and focus of governments energy systems to be more environmentally conscious. once the pandemic is under control. Moreover, with the growing issues on climate change, the impact of the economic recovery and stimulus plans to Digital adoption and technology transformation energy transition should be considered as well. This pandemic taught us how digital and emerging technologies can

The chance of fossil fuels to strike back is still most likely to happen if minimise the impacts of the pandemic. During the 37th ASEAN Ministers on the government allows massive fossil fuel usage in the industries for their Energy Meeting (AMEM) last year, ASEAN has recognised the importance business recovery. Moreover, placing the investment of a carbon-intensive of digital and emerging technology in energy development. Opening the energy system into the economic stimulus packages might be considered as collaboration with broad partners to respond to the risks and opportunities of imprudent action which would only lead to the same mistake. digitalisation in the energy sector can benefit ASEAN in the long-term future.

The most frequently asked question is on how the pandemic is affecting Therefore, economic recovery strategies should also include investment in climate change. The short-term emissions reductions resulting from technology transformation. containment measures have lulled people into a false sense of understanding. cooperation and to start moving forward through decarbonisation whilst dependency for oil and natural gas is also estimated to increase. Thus, ASEAN Therefore, governments should think rigorously on which strategy to take and Leveraging regional cooperation what type of policies and structural measures to be included in the economic Currently, ASEAN is preparing the new phase of ASEAN Plan of Action for stimulus packages to ensure a long-term, secure and diversified energy system Energy Cooperation (APAEC) which is the APAEC Phase II: 2021-2025. In for each of their populations. preparing the strategies to recover from this pandemic, ASEAN can leverage the role of APAEC to accelerate the energy transition and increase the energy Regional actions for the post-pandemic recovery plans resiliency. The long-term measures to mitigate such unexpected events like Observing the broad global range of infections in many sectors caused by this pandemic can be included in the strategies of APAEC Phase II that can be this pandemic, the long-term strategic measures in the economic stimulus eventually translated into more tangible action plans.