Asian Power (January - March 2020)

Issue No. 95

ISSUE 95 | DISPLAY TO 31 March 2020 | www.asian-power.com | A Charlton Media Group publication

US$360P.A.

VENA ENERGY’S

AMBITIOUS RENEWABLES DRIVE

Asian Power

CEO NITIN APTE LEADS THE DEVELOPMENT OF TAIWAN’S LARGEST GROUND-MOUNTED SOLAR FARM, WHICH IS ONE OF THE LATEST PROJECTS TO DRIVE THE IPP’S GROWTH.

WHY INDIA NEEDS TO SPEED UP COAL PLANT CLOSURES HOW VIETNAM IS DOMINATING WIND AND SOLAR QUIET BUT NOT DEAD: CHINA’S NUCLEAR PROGRAMME HOW ELECTRICITY PACKAGES GET AUCTIONED IN SINGAPORE 1 ASIAN POWER

FROM THE EDITOR The second issue of Asian Power for 2020 tackles China’s ascent towards dominance of the $1t global offshore wind sector. It now comprises 40% of global net offshore wind capacity. With the offshore wind project pipeline strengthening over the coming years, China’s power footprint could expand further. Find out more on page 22.

PUBLISHER & EDITOR-IN-CHIEF Tim Charlton PRODUCTION EDITOR Danielle Mae V. Isaac GRAPHIC ARTIST Simon Engracial II

ADVERTISING CONTACT Reiniela Hernandez reiniela@charltonmediamail.com

ADMINISTRATION Accounts Department accounts@charltonmediamail.com ADVERTISING advertising@charltonmediamail.com EDITORIAL ap@charltonmedia.com

Asia is set to be the next solar capital, but China is not the only country bringing the region under the spotlight. China and Vietnam are expected to add over 300GW of solar capacity by 2021. These are part of more than 700GW of global solar power capacity that will be added in the next eight years, marking a 150% expansion in global solar capacity. Read more on page 14.

We also sat down with Vena Energy’s CEO Nitin Apte who shared how the company grew its renewables portfolio to 11GW in a span of seven years. One of the projects contributing to the portfolio is the 70.2MW Mingus Solar Project in Taiwan’s Chiayi County, which is now the country’s largest ground-mounted solar project. Read on what Apte has to say on page 13.

Start flipping the pages and enjoy!

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ASIAN POWER 1

CONTENTS

22

26

INTERVIEW 12 CEO VENA ENERGY GROWS RENEWABLES PORTFOLIO TO 11GW

FIRSTS

SECTOR REPORT EYES ON THE EAST: CHINA ASSERTS POWER OVER GLOBAL OFFSHORE WIND SECTOR

SECTOR REPORT ASIA RISES AS GLOBAL CAPITAL FOR SOLAR POWER

ANALYSIS

06 First movers boost offshore wind industry

14 Non-performing assets burden India’s thermal power sector

07 Singapore auctions power packages

18 China’s nuclear programme to swing back into full gear

08 Handling coal fleet retirement 10 China scales back on wind subsidies

OPINION 28 The buzz about lithium-ion batteries 30 How Asia can get its energy transition right 32 Vietnam bets on solar auctions to develop its renewable energy market

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

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

www.asian-power.com

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

REGULATION

Indonesia eyes replacing 69 old coal plants with renewable plants The government of Indonesia plans to replace coal-fired power plants 20-years and older with renewable energy power plants, according to Energy and Mineral Resources Minister Arifin Tasrif. Up to 69 units of coal-fired power plants and coal gasfired power plants may be replaced.

POWER UTILITY

India’s NTPC greenlights acquisition of stakes in 2 generation companies The board of NTPC approved the acquisition of the majority stakes held by the Indian Ministry of Power in two power generation companies: NTPC will acquire 100% of North Eastern Electric Power Corporation, which operates hydropower, thermal and solar power plants in Northeast India.

4 ASIAN POWER

REGULATION

Vietnam retains FiTs for solar rooftop until 2021 Following recommendations by the Ministry of Industry and Trade, Vietnam’s power utility Electricity of Vietnam (EVN) has agreed to maintain the current feed-in tariffs for solar rooftop installations at US$9.35c/kWh until 2021, in order to encourage solar development.

REGULATION

China, India need renewables boost as displacement for coal miners looms A study in the journal Environmental Research Letters found that China and India would need to boost their renewables capacity in coal-producing areas in order to accommodate the transition of workers into renewablesrelated jobs, as out-of-work coal miners typically do not migrate for work.

REGULATION

Private developers to play greater role in Indonesia’s power expansion Private producers are expected to play a greater role in Indonesia’s power expansion in the coming years, with over 65% of upcoming capacity additions allocated to independent power producers (IPPs) in its 10-year Electricity Supply Business Plan 2019 (RUPTL), according to a Fitch Solutions report.

POWER UTILITY

India crowned as top emerging market for clean energy India climbs to the top spot amongst emerging markets for clean energy investment thanks to its ambitious 175GW renewable energy target for 2022, according to BloombergNEF. The analysis scored countries according to their Fundamentals, Opportunities, and Experience in clean energy.

ASIAN POWER 5

FIRST sea conditions and proximity to load.

Vietnam, with its long coastline, has a lot of the ingredients needed to make the offshore wind sector work. Another interesting point is that its oil and gas supply chain is already established and that’s a good base from which to build the new industry of renewable energy.

JAPAN’S FIRMS CRY OUT: X SOUTHEAST ASIA DITCH COAL PLANS JAPAN

You mentioned that Vietnam has extremely high growth figures for its power sector and offshore wind. How long is this growth period likely to last?

In terms of timing, renewable energy capacity, construction and grid capacity hasn’t quite caught up with the targets in place; these have been increased, but more capacity is needed. The regional renewables sector has only just started, and I wouldn’t be surprised if in the next 10-20 years we see sustained growth.

Dr Bikal Kumar Pokharel, Wood Mackenzie 1 in 5 firms want to ditch coal

As Japan mulls opening more coal-fired power plants, a poll by Reuters shows that Japanese attitudes are changing: 62% of firms urge the government to curb coal-fired power projects, 20% said coal plans should be ditched altogether, and a third said this would harm their business. A manager at a manufacturer said, “I don’t think we should give it up immediately, but Japan must clarify its energy policy in the way that will reduce environmental burdens in the medium to long term.”

With limited resources and especially after the 2011 Fukushima nuclear disaster, the government feels it needs all options and coal is cheap and abundant. Backers of coal-fired power argued that a resource-poor Japan has no choice but to stick with coal plans for the time being, the survey showed.

However, Environment Minister Shinjiro Koizumi told a United Nations conference last month that global criticism of Japan’s “addiction to coal” was hitting home, even as Japan remains a big financier of new coal plants in Southeast Asia and the only G7 nation still building coal plants at home.

“Critics merely base their argument against coal-fired power on their outdated technology that emits CO2. Such a cry that lacks objective and scientific viewpoints is nothing but ‘environmental fascism’, which is even dangerous,” a wholesaler manager wrote.

Side effects of abandoning coal A third of the Japanese firms that said abandoning coal plans would harm their business raised the issue of electricity bills and squeezing profits. “It could increase electricity costs and sacrifice the stability of power supply to a degree, but these can be technically resolved eventually,” a machinery maker manager wrote in the survey.

Whilst 60% saw no impact at all from abandoning coal, the remainder expected it to bring positive effects. Prime Minister Shinzo Abe’s cabinet approved a plan last year to cut greenhouse-gas emissions, including support for hydrogen and carbon capture technology, but made no mention of coal financing.

A study by Global Energy Monitor also showed Japan plans to finance $4.8b of investment in coal plants in Vietnam, Indonesia and Bangladesh.

The Reuters Corporate Survey was conducted from 25 December to 10 January by Nikkei Research and canvassed 502 big and midsize non-financial companies. Roughly half of them answered questions on coal plans on condition of anonymity to express opinions freely.

6 ASIAN POWER

Growth could be sustained in the next 10-20 years.

First movers boost offshore wind industry

O VIETNAM

ffshore wind is shaping up to be one of Vietnam’s growth drivers for achieving its power generation target of 130GW by 2030, thanks to its resource-rich coasts, and a steady oil & gas supply chain to support future power plants. The local industry will not be the only one steering the wheel with an increasing number of investors seeing Vietnam as an opportunistic space.

Elise Do, associate director at Augusta, talked to Asian Power about the motivations of these investors for investing in Vietnam’s offshore wind market, the government’s direct involvement in incentivising investment, as well as a glimpse into the process of facilitating transactions in the market.

How great is the potential for investment and return in Vietnam’s offshore wind sector?

We’re looking at power generation that is currently at 47,000MW, and Vietnam will need to reach 60,000MW by 2020 and even double that by 2030. This rising underlying demand for power is obviously a huge enabler for renewable energy, but more specifically offshore wind, which can bring large increases in capacity in little time.

The offshore wind sector offers scale, but what is also important is that you need to have good wind resources, which Vietnam has. It also needs benign

Elise Do

Which factors will support that growth?

The Vietnamese government is heavily involved in making renewables investments attractive. There is a 20year feed-in tariff (FIT) in place, and the government works to approve and review infrastructure, especially offshore wind farms.

Efforts have also been made to facilitate direct power purchase agreements (DPPAs), with a pilot setup in place to support industrial power demand and guide firms towards clean energy. All in all, however, there is still more work to be done. I know that they’ve also done some direct power purchase agreement (DPPA) work. They have a pilot setup for DPPAs to support the demand structure and the industry that has a high need for power and also to guide them into clean energy.

Can you describe the profile of the European and US investors with whom you have interacted?

European renewables are pretty welldeveloped and a lot of the players are looking towards Asia, initially Taiwan, and now other markets, to continue their growth. It really depends on the type of investor and their appetite.

For the utilities, it’s more of a question of diversifying into new markets. For IPPs, this is also a yield play, as they are looking to increase their yields and returns on investment. Asia does offer that and it’s becoming more and more interesting for investors. Taiwan has been a key growth region, and now people are looking for the next market. Although it’s still developing progressively, I think people look at Vietnam as something of an opportunistic space that might not be one of their primary markets.

FIRST

Tan Liang Ching

Powered-up platform PowerSelect condenses the procurement processes in its platform by housing data from the wholesale and futures electricity markets, having an in-house team assist businesses in understanding and navigating the contract terms and conditions of the electricity retailers and advise them in areas like the reserve price for the auctions and contract durations.

For the future, EMC is looking to expand the PowerSelect platform as it has observed that businesses are increasingly looking for other energy-related products and services. “Whilst there were plans to roll out additional, value-added services on PowerSelect at later stages, we intend to bring forward our plans to better support our customers. We are in the process of evaluating our options for PowerSelect,” Tan said.

The EMC is also expects more differentiated packages from the remaining retailers like green electricity packages as they gain more experience, and as consumers’ awareness and expectations increase over time.

EMC has conducted over 50 live auctions since its launch.

Singapore auctions power packages

T

SINGAPORE

he operator of Singapore’s wholesale electricity market, Energy Market Company (EMC), wanted to cut the time it took companies to find their electricity retailer from one to two months to just 15 minutes when it launched its procurement portal PowerSelect in 2018.

Since the launch of PowerSelect, EMC has successfully conducted over 50 live auctions for businesses in the industries of manufacturing, transportation & storage, accommodation, and food services, shared Liang Ching Tan, senior vice president for business development at EMC. “On average, these businesses enjoyed savings of about 30% off the regulated electricity tariff (based on prevailing tariff rates at time of auction)

regulated tariff, which was higher than the 25% rate it had with its incumbent retailer.

“Most businesses prefer Fixed Price Plans as there is certainty in their electricity spending which is helpful for budgeting purposes. They usually compare 12- and 24-month contracts, and decide based on the prevailing fixed rates.

In the current market situation, 24-month fixed rates are lower for businesses,” Tan said. Most of the time, the electricity procurement process is still very manual and time consuming—the businesses contact electricity retailers individually for quotes, and then try to make sense of the various electricity packages which often come with detailed and complex terms and conditions.

when they procured electricity through PowerSelect. Compared against the businesses’ reserve prices (or starting bids for the auctions), the amount of additional savings ranged between 3% and 15%,” he said in an exclusive interview.

PowerSelect allows business to shortlist their retailers based on retailers’ packages as well as their track record of performance. After the round of shortlisting, the retailer that offers the most competitive price in PowerSelect’s 15-minute auction ultimately wins the contract.

He recalled a customer in the Food and Beverage sector which conducted a Live Auction for a Discount Off Tariff plan.

The live auction allowed the customer to secure a final discount of 28% off the

THE CHARTIST: POWER JAPAN’SSECTOR SOLAR INDUSTRY LED SOUTHEAST IS DIMMER ASIA’S WITH INFRASTRUCTURE JUST 20GW PROJECTED LEAGUE TABLES TO COME IN 2019 ONLINE The power sector took up thewill chunk of at Japan’ s solar power sector expand Southeast Asia’ s largest Sector breakdown by deal value robust rates through toinfrastructure 2020 as a large x projects as transport developers backlogin of2019 projects supported by feedeschewed their plans amidst and in tariffs come online.

Afterpolitical 2020, BMI regulatory risks.that According to Inframation Research said the transition to a and SparkSpread’ s 2019 League big-ticket reverse auctions system willTables, slow growth, as energy deals like the $1.1b refinancing of the the Japanese government looks to regulate Mong Duong 2 plantin inorder Vietnam pushedsubsidy the capacity additions to reduce region’ total transaction value to $21b. costs sand support grid stability.

David Zemans, a partner at lawrobust firm Milbank, “We expect Japan to register solar said that agrowth tested through commercial structure capacity to 2020 as a result allows credit agencies and commercial of theexport implementation of a substantial players participate together in power pipelinetoof projects that benefit from a projects.

Asia’support s largestscheme. transaction generousSoutheast feed-in tariff inOur 2019 was the a 69.11% stake of forecast is sale thatof out of a 50GW backlog ENGIE’ s Thai IPP portfolio, Glow to of such projects, only 20GW willEnergy, actually Global Power Synergy come online, as most Public will notfor be$3.87b. able to The transaction was followed insubsidies the ranking by the Source: Inframation take advantage of the FiT amid development of Vietnam’ s 1,320MW coalstringent government requirements and Source: BMI Research fired Van 1 power” plant for $2.58b. delays inPhong development, BMI Research added.

Top 5 SE x Asia Greenfield Projects by Value (2019)

Source: Inframation Source: BMI Research

ASIAN POWER 7

FIRST

Handling coal fleet retirement

Coal-fired generation capacity to 2042, all scenarios

INDIA

A

AUSTRALIA

ustralia eyes retiring 63% of its coal-fired capacity by 2040, but it will need 30GW of utilityscale renewables to fill the gap and satisfy growing grid demand, according to an analysis by the Australian Energy Market Operator (AEMO). “Whilst overall grid demand is being held constant by distributed energy resources (DER), we will still need generation capacity to meet peak demand and to replace retiring plants,” it said.

This means Australia has to invest largely in variable renewable energy (VRE) including solar, wind, battery and other resources at the utility level to be supported by essential storage, gas-powered generation (GPG), demand side participation (DSP), and transmission. This additional supply will be needed to make up for the losses that occur during the energy storage cycle, AEMO said.

Scenario establishment There are currently 6GW of renewable energy resources installed, with another 6.5GW expected to be operational in the next two years. Economics and state renewable energy targets are continuing to drive this development.

The AEMO established a Central scenario—in which retirement is determined by market forces and PLANT WATCH

Source: AEMO

current policies—which translates to an optimal split of 56% solar and 44% wind for new renewable energy resources, in order to minimise the need for dispatchable storage and generation.

It also had a Step Change scenario where consumer and technology transitions occur amidst aggressive decarbonisation, in which 47GW is required and Queensland and New South Wales are projected to add 15-18GW and Victoria over 6GW by 2040.

In all but the Slow Change scenario, in which economic growth and emission reductions slow, existing coal-fired plants are not forecast to continue beyond their planned retirement dates. “In fact, in the Fast and Step Change scenarios, we expect them to exit earlier if competition from renewable generators and carbon budgets reduce their revenue below what is economic for them to continue,” AEMO said.

Australia has to invest largely in variable renewable energy (VRE) including solar, wind, battery and other resources at the utility level to be supported by essential storage, gaspowered generation (GPG), demand side participation (DSP), and transmission.

830MW expansion for Bangkok plant

Japan’s first-scale offshore wind farms

Taichung’s 2 gas-fired units in the works

THAILAND

JAPAN

TAIWAN

The Electricity Generating Authority of Thailand is looking to start the North Bangkok Power Plant’s first phase of expansion by adding a 830MW natural gas-fired power plant that will operate commercially in 2028.

The power plant will be constructed in the same area of the present North Bangkok Power Plant, at EGAT headquarters, Bang Kruai District, Nonthaburi Province.

The North Bangkok Power Plant (Extension) Phase 1 has been incorporated in Thailand Power Development Plan 2018 to enhance power security.

Japan’s first large-scale offshore wind farms at Akita Port and Noshiro Port in Akita Prefecture have now entered their construction, operation and maintenance phase, according to Marubeni Corporation.

It signed a project finance agreement for a $913.70m loan. The deal was inked with partners including Obayashi Corporation, Tohoku Sustainable & Renewable Energy Co.Inc., Cosmo Eco Power Co., Ltd., The Kansai Electric Power Co., Inc., and Chubu Electric Power Co., Inc.

Two new natural gas-fired generators can now be added to Taiwan’s Taichung power plant after the country’s Environmental Protection Administration approved the environmental impact assessment for the units, Taiwan’s central news agency reports. The generators will have an installed capacity of 2.6 million kW, according to Taiwan Power Co. (Taipower). They will be built on Taipower’s existing land.

The projects went through three EPA reviews between October 2018 and June 2019 and were subjected to a fourth review.

8 ASIAN POWER

DIVERSIFICATION ON THE CARDS

State utilities still largely rely on coal

India’s state-owned enterprises (SOE) are grappling with the pressure placed on thermal power and are resorting to diversification into renewables in order to stay relevant, according to the Institute for Energy Economics and Financial Analysis (IEEFA).

The need to diversify becomes more urgent as the Ministry of New and Renewable Energy (MNRE) had asked all SOEs to prioritise renewable projects in their investment plans as part of larger efforts to reduce carbon emissions.

The government directed SOEs to either set up their own capacity, or participate in tariff-based bids for renewable energy projects floated by the Solar Energy Corporation of India (SECI).

To address risks in land acquisition and power transmission issues, SOEs are required to acquire more than two lakh hectares of land through fully-owned special purpose vehicles (SPVs)—a subsidiary created by a parent company to isolate financial risk—in order to set up 47GW of green power projects, with PowerGrid tasked with setting up transmission infrastructure for these locations.

State governments are also being incentivised with payments of $0.028 (Rs0.02) per kWh for electricity generated from the projects over their lifetime to facilitate the requisite clearances.

Diversification is not only being undertaken by energy producers but also by equipment suppliers and end users.

Coal India announced plans to set up 20GW of solar capacity over the next ten years, entailing investment of $14b. It is also investing in other energy sources like coal bed methane (CBM) and underground coal gasification (UCG).

NTPC Limited aims to invest $3.5b to set up the world’s largest proposed solar park at Kutch in Gujarat. The solar park will be developed in phases over the next five years with an end target of 5GW. NTPC also plans to bundle generation of power from renewable energy sources with coal-based generation, and shut coal-based plants during the day when solar energy is available.

It also participated in the CPSU Scheme Phase II and issued a tender for 1GW of solar projects in June 2019. The end user of the power generated from these projects will be CPSUs, state PSUs, government entities either directly controlled or under the administrative control of the state or the central government, or a company in which the government has a controlling shareholding.

Another SOE diversifying into renewables is NLC India, which has set up total renewable energy capacity exceeding 1GW, including 1GW of solar capacity and 51MW of wind capacity.

FIRST

China scales back on wind subsidies CHINA

Lorem ipsum dolor sit amet China moves to withdraw subsidies.

C

hina’s wind power developers could face lower returns for their projects as the state moves towards grid parity and proceeds with the withdrawal of subsidies with its new 2020 wind power policy. In a report, UOB Kay Hian analysts said that whilst grid parity would be positive to the industry in the long term, there may be transition pains.

China’s new wind power policy is encouraging the prioritisation of gridparity wind power projects by having them voluntarily switched from subsidised to non-subsidised. China’s largest wind producer, Longyuan Power, indicated that although some subsidised projects may switch to being non-subsidised, the projects’ internal rate of return (IRR) should also meet the companies’ required IRR. Effect on big developers Big developers should not immediately feel the bite of the policy in 2020, according to Shen.

Huaneng Renewables (HNR) and Longyuan now own 6.5GW and 4GW of wind power projects that were approved before end-2018 and should be grid connected by end-2020.

“Longyuan said that it did not have many

approved grid-parity and competitive tender projects in 2019 and it is focusing on the construction of subsidised projects. We believe earnings of HNR and Longyuan should be intact in 2020, given enough subsidised projects in their pipelines. In addition, Longyuan said it heard the rumour that the grid connection deadline may be postponed by half a year. If so, wind farm operators can connect more subsidised projects, which will enhance their earnings,” Shen said.

Orderly construction schedule The withdrawal of subsidies is not the only highlight of China’s new policy. The policy aims to have an orderly construction of wind power projects by not allowing them to surpass the target under the 13th Five Year Plan (FYP).

Provinces that have already exceeded FYP targets for offshore projects are to suspend tenders and new approvals.

However, Shen said the cap is not a concern for developers and that there is still sufficient room for capacity additions.

The analyst cited a 2017 paper that projects total wind power capacity to reach 258GW by end-2020; however, actual capacity is still at 198GW as of September 2019. “Note that the government was aiming to cap the annual capacity addition as the connection ability of the grid network is limited, according to Longyuan.”

Even with concerns of lower returns on the horizon, Shen noted developers should look out for positives, like the higher utilisation hour (UH) that would lower the levelised cost of energy (LCOE), thanks to technological improvement and the government’s efforts to guarantee renewable energy’s consumption; and subsidy withdrawals by wind farm operators.

X PROJECTS PUSHED BACK XXX ASEAN

Negative public sentiment is rising xxx

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The project commercially viable, uninhabited and unprotected company, PT Tanjung Jati Power development Company has sites for prospective hydropower executed a Power Purchase (PPA) still available in most of theseAgreement markets, developers with PT PLN (Persero) December 2015. We have increasingly beeninrequired to develop are always on or themore lookout for new opportunities sites with one of these factors at in generation whether it ison bidding for existing play; motivating pushback both local and assets or investing inthe newreport projects. international levels,” stated.

INDIA

India’s specialised developers get boost as market for open access PPA doubles India’s specialised project developers have shown a growth in market share as the open access PPA solar market grew 2.5 times to 2.9GW for the past two years. With the growth of the open access market, large-sized IPPs with a national presence, such as ReNew and Avaada, and other specialised project developers, such as CleanMax, Amplus and AMP Solar, have begun to considerably increase their market share.

According to a report by the World Business Council for Sustainable Development, these national developers have the competitive advantage of having access to large corporate buyers as well as financing sources with a lower cost of capital.

But the market share of regional players has contracted. They have been responsible for structuring most early open access renewable PPA projects, as they had easier access to land and was better placed to deal with local DISCOMs and regulators. India remained the second largest market for corporate PPAs with a global share of 7.4% or 440MW installed, but estimates suggested that the annual corporate PPA renewable addition in India contracted 30-35% for the full year.

10 ASIAN POWER

Installations and project pipeline for key developers under open access and group captive models, as of 31 August 2019

Source: JMK Research

Power supplier segmentation for open access solar markets in India

Source: JMK Research Note: This chart includes only open access PPA solar projects, not captive projects.

CO-PUBLISHED CORPORATE PROFILE

The award-winning solution from Indonesia to improve performance through control system redesign

PT. Pembangkitan Jawa-Bali receiving the Power Utility of the Year - Indonesia at the Asian Power Awards

T

he Generation Unit and Combined Cycle Power Plant (CCPP) Muara Karang, which was established in 1992, is a power plant that supplies electricity needs in the State Capital of Indonesia, namely, the Jakarta Special Capital Region.

The CCPP itself is owned and managed by PT Pembangkitan Jawa-Bali or PT PJB, one of the subsidiaries of Indonesia’s top state-owned enterprise, PT PLN. As the centre of government, The Jakarta Province is a priority area in fulfilling electricity supply in Indonesia, such as the State Palace, the MPR/DPR Building, Soekarno Hatta Airport and Halim Perdanakusuma Airport.

CCPP Muara Karang Block 1 operates with a 3-3-1 configuration—three gas turbine generators (GTG), three heat recovery steam

machinery. GTG uses the GE Speedtronic Mark VIe control system that was built in 2012. The HRSGs use the ABB Infi 90 control system that was built in 1992. The STG control system uses the GE Speedtronic Mark V control system that was built in 1995.

All of these control systems must be well integrated in a system called the Distributed Control Integrated System (DCIS). DCIS functions for monitoring, controlling and safety of generating machinery so that they can operate safely and reliably.

At present, the integration of the DCIS GTG Control System and HRSG is experiencing performance degradation. Performance degradation can result in suboptimal unit operations, such as STG Trip or Derating, HRSG Trip, and GTG Trip or Not Ready to Start.

On the key performance indicators (KPI) side,

the performance contract value is not achieved based on the unit’s readiness (i.e., equivalent availability factor or EAF) benchmarks and unit reliability (equivalent forced outage rate or EFOR and sudden outage frequency or SdOF) at PT PJB UP Muara Karang in 2016 and 2017.

One of the causes of KPI not being achieved is due to the disruption of the control system integration design.

Performance degradation comes from the complexity of the control system integration architecture design that is configured serially.

The complexity of the design occurs because of differences in technology implementation between GTG and HRSG. Based on the problems of the design of the integration of the GTG and HRSG control systems, an improvement is needed by implementing the “Re-Design of the Integration of the GTG and HRSG Control Systems.”

PT PJB said that a strategic study of “ReDesign of Integration of GTG and HRSG Control Systems” is important to do because it has several advantages. First, the control system integration design is very simple. Meanwhile, Ethernet-based control system integration technology has a high-performance speed module and very low implementation costs, without causing shut down to CCPP Muara Karang Blok 1.

After an alternative recommendation was made to redesign the integration of the GCG and HRSG control systems, it was found that the redesign was able to prevent disruption and solve the disruptive technology problems of the GTG and HRSG control system integration. In addition, the redesign is also proven to increase the readiness and reliability of CCPP Muara Karang Block 1.

“CCPP Muara Karang Block 1 operates with a 3-3-1 configuration—three gas turbine generators (GTG), three heat recovery steam generators (HRSG) and one steam turbine generator (STG).” generators (HRSG) and one steam turbine generator (STG).

Each GTG has a maximum power production capacity of 107 MW, whilst the STG has a maximum power production capacity of 185 MW so that the total electricity production power is 500 MW. Each power plant engine has a control system in controlling the operational ASIAN POWER 11

Since I was appointed as CEO in 2018, we have been busy expanding our portfolio with a 45% increase in operating capacity and integrating our capabilities across the region, leveraging the unique strengths we have in each of the nine countries where we have a presence, to be an integrated growth engine.

Nitin Apte CEO Vena Energy 12 ASIAN POWER

CEO INTERVIEW

Vena Energy grows renewables portfolio to 11GW CEO Nitin Apte eyes adding more projects in massive Asian energy markets like South Korea, Japan, and India.

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n the span of seven years, Asian independent power producer (IPP) Vena Energy has grown its portfolio capacity from 92MW in 2012 to 11GW in 2019 spread across several landmark solar and wind projects in various phases of development. In 2019, the IPP was able to build the 70.2MW Mingus Solar Project in Taiwan’s Chiayi County, which is now the country’s largest ground-mounted solar project.

In an interview with Asian Power, Vena Energy CEO Nitin Apte shares his strategies in leading the company to its key projects, milestones that the company has reached, as well as forays into Asia’s power giants, South Korea, Japan, and India.

Can you tell us about your experience that led you to become CEO of Vena Energy?

Prior to joining Vena Energy last year, I had been associated with businesses around the world in the specialty materials industry for GE, SABIC and most recently as President and Chief Executive Officer of Materia, a specialty materials company.

Apart from the fundamentals of running a business, which have been quite translatable to the renewables, the most relevant experience I have brought to Vena Energy is to scale a growth business to integrate a loosely collected set of diverse country platforms focused on the development of solar and wind farms into a sustainable growth leader in renewable energy across the Asia Pacific region.

What strategies have you employed to drive Vena Energy to success over the years?

Since I was appointed as CEO in 2018, we have been busy expanding our portfolio with a 45% increase in operating capacity and integrating our capabilities across the region leveraging the unique strengths we have in each of the nine countries where we have a presence, to be an integrated growth engine.

This has meant using our well-established capabilities of developing projects locally, from initial concept through to construction with local management teams, to provide expertise in origination, development, land acquisition, grid assessment, permitting, system design and investment feasibility; and utilising our scale to drive synergies across the company as “One Vena”.

This has yielded dividends in efficient procurement, best practice translation in project and construction management, operational efficiency and customised financing solutions.

What are you working on for the rest of 2019 and 2020?

Vena Energy is a development business—so we are always working on progressing projects through the pipeline and calendar years don’t really matter! Currently, we have several projects that are in construction in Japan—continuing our growth in solar and adding our first Japanese onshore wind projects that are about to commence construction.

We are also adding to our robust wind portfolio in India with construction commencing for 97MW in Amreli, Gujarat. In other parts of Asia, we have advanced projects that will go into construction in the coming months—including our first energy storage projects in Australia. This activity requires us to recruit and develop talent and so we are constantly on the lookout for high energy individuals.

What were your company’s milestones for the past 9-10 years?

We started out in 2012 with just 10 solar projects totalling 92MW in Thailand. Fast forward to 2019, we have grown to 11GW of solar and wind assets in operation, construction and various stages of development across the Asia-Pacific region.

The commissioning of the 132MW Pollo Solar Project in 2016 was a significant milestone, as it was—and still is—the largest ground-mounted solar project in the Southeast Asia region. In 2017 we commissioned what was back then the largest ground-mounted solar project in Taiwan, the 5MW Davis Solar Project. It has since been dwarfed by the recently commissioned 70.2MW Mingus Solar Project in Chiayi County.

Our team in Japan grew to over 100 associates as we have built 15 solar plants using our own engineering and construction management teams and operate them with an internal staff of operations and maintenance professionals.

We reached financial close for the 127MW Tailem Bend Solar Project in Southern Australia in 2018, and it was commissioned the following year in 2019. This year we also completed our first projects in Indonesia with 114MW across five solar and wind assets including the impressive Tolo wind farm in South Sulawesi.

We opened an office in Seoul, South Korea, in October 2018 with an experienced team on the ground, and we have already added several projects to the pipeline.

What challenges has the company faced in terms of supplying power to its key markets?

We operate in nine jurisdictions across Asia Pacific and have been one of the renewable pioneers in many of these markets. This presents some unique local challenges that we need to creatively address. For example, we experience adverse events such as typhoons, earthquakes and storms across some of our projects. Our operating teams are equipped to respond to these events in a safe and effective manner.

For example, our plants in North Japan have experienced record snowfall during the last two winters which could have impacted generation—however, our teams have deployed snow removal strategies such as expanding our fleet of owned and leased equipment as well as reinforcing our local O&M team with seasonal additions, all of which resulted in no material snow accumulation. Being an early mover means we have had to develop supply chains and bring engineering, construction and financing capabilities together to execute projects. We have also had to work with regulators with permitting processes for many “firsts” such as land conversion.

What are the most important lessons you’ve learned from operating in huge (and crowded) markets like Japan and India?

Every market we operate in is unique to a large extent—Japan has had rapid growth in the solar sector whilst onshore and most recently offshore wind is starting to develop—and is transitioning from a feed in tariff regime to competitive tenders. On the other hand, India has been running central and state auctions in both solar and wind, with projects being significantly larger in size.

Hence, the most important lesson for us is to approach each market with a team that understands local regulations and can adapt to the conditions that allow us to develop and build the most competitive projects for that market. At the same time, we utilise our experience to bring best practices such as plant design, equipment selection and asset monitoring across all our projects.

What are your ambitions for Asia and what do you think are the key factors to achieve these?

We are one of the largest IPPs in Asia-Pacific and we are purely focused on clean renewable energy. Our ambition is to continue to be the engine that accelerates the transition of the energy sector to sustainable renewable sources in the region, and we are committed to grow our presence whilst empowering and enriching local economies and communities.

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ANALYSIS 1: INDIA COAL

Out of 40GW of stressed coal projects, 15GW has yet to be commissioned.

Non-performing assets burden India’s thermal power sector

Thirty-four stressed coal assets with a capacity of 40.1GW were hit by legal issues, lack of PPAs, bankrupt developers, and coal supply issues, says the IEEFA.

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ndia’s thermal power generation sector continues to pose trouble for Indian banks, accounting for $40-60b in potentially stranded assets. A variety of factors can lead to thermal power generating assets becoming stranded—or economically non-viable and unable to deliver a viable return on investment over its useful life. These include changes in demand, new government regulations, fuel supply, availability of financing, capital cost and timeline blowouts in construction, and even legal action.

The thermal power generation industry is seriously underperforming, despite dominating India’s electricity generation sector, with 61% of total installed capacity and 75% of generation coming from thermal sources in 2018/19.

Unsustainably low capacity utilisation rates of less than 60% over the past three years, combined with excessive financial leverage, makes debt servicing extremely difficult.

The industry’s distress is exacerbated by loss-making electricity distribution companies (discoms) that have often failed to make timely payments, or have sought to renegotiate tariffs on existing power purchase agreements (PPAs)— electricity power supply agreements between the generator and buyer.

Out of some 40GW of stressed coalfired projects in India, 15GW has yet to be commissioned, according to a report by the government’s Standing Committee on Energy in March 2018. Further, some 14 ASIAN POWER

The thermal power generation industry is seriously underperforming, despite dominating India’s electricity generation sector, with 61% of total installed capacity and 75% of generation coming from thermal sources in 2018/19.

16.2GW of coastal power plants built to operate 100% on imported coal have been severely affected by the doubling of imported coal prices since 2016.

Whilst delays in project implementation related to land acquisition and permit approvals have resulted in cost overruns, the unavailability of coal supply contracts has also been an issue. Insufficient coal railway capacity has kept Coal India—the primary supplier—from consistently keeping up with the demand. Higher prices for domestic and international coal in recent years, a declining exchange rate, and rising railway freight charges for coal transportation over distances of more than 500 kilometres (km), have also inflated the variable generation costs for many coal-fired power plants at a time of

renewable energy deflation.

Coal is increasingly challenged from a cost-competitiveness perspective. New 25-year, zero indexation, renewable energy PPAs are consistently being signed at Rs2.60-3.00/kWh, some 20-30% below the first year cost of existing coal-fired power plants in India.

In this report, IEEFA examines 12 non-performing or stranded thermal power plants that are proposed or under construction from India’s thermal power generation sector. Five are from the list of 34 stranded assets (40GW in generation capacity) formally identified as nonperforming assets by the Reserve Bank of India (RBI).

Although the remaining seven plants reviewed in the report are not formally identified as non-performing or stranded assets, IEEFA views them as equally financially exposed. In short, the issues impacting the sector go much deeper than the 34 projects officially identified as stranded. Of the 12 case studies, IEEFA notes common themes emerging as to why the thermal power assets have become stranded: • Amarkantak Thermal Power Plant: Stranded due to the company overexpanding in too many directions and the poor financial health of discoms affecting the company.

Highlights the need for an effective bankruptcy process.

• Buxar Thermal Power Station: Stranded due to promoter inexperience in thermal power, the high cost of new emissionscompliant coal plants, and the inability to find lenders whilst the banks are weighed down with nonperforming assets.

• Cheyyur Ultra Mega Power Plant: Stranded due to a lack of interest in Ultra Mega Power Project construction, and concern over the cost of imported coal. Now undercut by lower cost, deflationary renewables.

Non-Performing Assets in India’s Thermal Power Generation Sector

Source: 37th Parliamentary Standing Committee’s Report on Energy.

ANALYSIS 1: INDIA COAL thermal power sector, construction of new coal-fired power plants without subsidy support from the government will be highly risky and unviable.

India’s largest thermal power developer—NTPC—recently announced that it will not undertake any new thermal power plant development beyond its current portfolio. India’s largest private power company, Tata Power, reached the same conclusion in 2018. IEEFA projects India’s net coal-fired capacity to be lower that the government estimate at 230GW

by FY2029/30, up a net 26GW from today.

India’s Freshwater-Cooled Thermal Utilities Mapped Against Baseline Water Stress

Source: Adapted from WRI Report.

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Godda Thermal Power Plant: On the brink of being stranded, propped up by multiple government favours (e.g., tax free zones) and subsidies.

Gulbarga Thermal Power Station: Stranded due to Karnataka’s lack of instate coal-mining capacity and the company’s failure to deliver coalfired power projects.

GVK’s Gas-fired Power and Coalfired Power Plants: Stranded as the company over-expanded in too many directions, and due to coal and gas supply issues. Highlights the need for an effective bankruptcy process.

Khurja Thermal Power Plant: Stranded due to the lengthy coal freight distance resulting in high tariffs, overcapacity risk, and promoter inexperience in thermal power. This plant will be unable to compete with cheap renewables.

Koradi Thermal Power Station: Stranded due to lengthy coal freight distances as well as existing spare capacity already in Maharashtra.

Serious air pollution issues have also hurt this project.

Korba West Thermal Power Plant: Stranded due to technical issues and the lack of PPAs. Highlights the need for an effective bankruptcy process.

Prayagraj Thermal Power Plant: Stranded due to low coal supply, a lack of working capital, and cost overruns, whilst subsequent operational issues occurred as a result of the low plant load factor Sinnar Thermal Power Plant: Stranded due to outdated technology, no PPA, and land acquisition issues resulting in the absence of a rail link.

Tata Mundra Thermal Power Plant: An operating plant with an overaggressive tariff bid now impacted by higher-than-expected imported coal prices.

Various government reports project 90-110GW of net new coal-fired plant additions on India’s grid by financial year (FY) 2029/30.

IEEFA’s analysis aims to be a cautionary note for investors, developers and the Government of India to cease pursuing stranded projects. Non-pithead coal power projects that are being established at distance from coal mines should be seriously re-evaluated, and non-coal states would do well to instead invest in cheaper, sustainable renewable energy options and, if need be, import electricity.

Various government reports project 90-110GW of net new coal-fired plant additions on India’s grid by financial year (FY) 2029/30, such as the National Electricity Plan 2018 (NEP) and the Central Electricity Authority’s (CEA) February 2019 report.

CEA’s optimal energy mix by FY2029/30 report projects India’s coalfired capacity to be 266.8GW—a net 64GW addition on the current installed capacity of 203.9GW (as of October 2019). This is 17GW in addition to India’s NEP2018 which projects India’s net coal-fired capacity to be 249GW

by FY2026/27. NEP identified 49GW of end-of-life capacity retirements, and capacity that should be retired due to age plus space constraints preventing the implementation of emission control systems on plant facilities.

Given the dire financial situation of the

Committee report on stranded assets Stranded or non-performing assets in India’s thermal power generation sector has been worrying the Indian government for some time. In FY2017/18, the government set up a special Parliamentary Standing Committee on Energy tasked with reviewing a country-wide list of 34 non-performing assets in India’s thermal power sector.

The committee found that of those 34 assets with a total generation capacity of 40.1GW, only 24.4GW had been commissioned, with the remaining 15.7GW deemed ‘under construction’. Of the fully commissioned capacity, 8.2GW had yet to secure PPAs. The committee found the ‘stressed’ value of the 34 stranded assets to be Rs236,619 crore ($33.5b) in total, with stranded loans of Rs176,130 crore ($25b) and an equity value of Rs60,489 crore ($8.5b), as of March 2018. In their final report, the Parliamentary Committee identified key reasons for stress in India’s thermal power sector, including: • Lack of fuel due to cancellations in assigned coal linkages or projects set up without any coal linkages; • Lack of PPAs with state discoms; • Inability of promoters to infuse equity and working capital; • Contractual and tariff-related disputes;

Reports project 90-110GW of net new coal-fired plant additions on India’s grid by FY2029/30.

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ANALYSIS 1: INDIA COAL India’s Electricity Sector Composition FY2029/30

Source: CEA, IEEFA estimates.

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Issues related to banks and financial institutions; • Delays in project implementation leading to cost overruns; • Overaggressive tariff bidding by developers to win PPAs. The Indian thermal generation sector has faced multitudes of problems this past decade. A far too ambitious expansion programme was undertaken, almost entirely funded by financial leverage.

Financial problems were compounded by cost overruns, project delays, floods, earthquakes, fuel supply interruptions, PPA contract cancellations, and a lack of accountability by promoter groups.

Obtaining a fuel-supply linkage is one of the most important prerequisites for getting regulatory approval, environmental approval, and contract PPAs with power discoms. Projects tend to rely on Coal India Ltd (CIL), a stateowned coal mining giant supplying more than 80% of India’s thermal coal demand to generators. The company however has struggled to expand its mining operations, mainly due to being unable to get environment and forestry clearances for proposed mines, land conflict issues, coal evacuation complications, and other law and order problems arising from protests against mining.

Like many countries, future power demand was vastly overestimated in India, resulting in many of the 34 stranded assets. On average, 18-20GW of coal-fired capacity was added between FY2011/12 and FY2015/16. Electricity demand growth has not kept pace.

At the same time, renewable energy wholesale tariffs have become increasingly cheaper due to the introduction of reverse bidding auctions, and supported by falling costs in solar modules and wind turbines.

As a result, state discoms have increasingly preferred to procure power through cheaper renewable energy contracts to meet incremental demand. IEEFA expects this trend to continue as renewable energy tariffs continue to decline over the 16 ASIAN POWER

coming decade, and whilst India strives to build massive renewable energy capacity, targeting up to 450GW by 2030 (over 50% of its total installed capacity).

RBI’s “12th February Circular” In 2018, the Reserve Bank of India (RBI) revised its framework on measuring whether an asset had become stressed, reflecting its deep concern for the level of debt being carried. According to a bank circular distributed on 12th February 2018, lenders were to classify a loan as stressed on just one day of default, whilst bankers were required to mandatorily refer all accounts holding over Rs2,000 crore ($280m) in loans to the National Company Law Tribunal (NCLT) or bankruptcy court, if those companies had failed to resolve non-payment problems within 180 days of default.

Previously, the bankruptcy code had allowed 270 days for lenders and asset owners to resolve non-payments through mechanisms such as corporate or strategic debt restructuring. RBI’s 12th February circular ruled out such provisions.

RBI’s new rules were deemed unfair by proponents of stressed assets. They argued that much of the pressure in the sector was due to reasons outside of their control, such as delays in assigning coalsupply linkages from the Ministry of Coal, and issues with land acquisition. Previous RBI schemes had failed to address issues around bankruptcy, and had been misused by borrowers and lenders to help hide the non-performing asset (NPA) status of their stressed assets.

RBI’s new circular called for a faster resolution process and substantial haircuts on lenders’ debts, without the loopholes.

As a result, 10 projects with total loans of Rs39,400 crore ($5.6b) were reported to have been referred to the NCLT for bankruptcy proceedings, with a further eight projects with loans of Rs36,500 crore ($5.2b) set to be referred.

RBI’s passage of reform was not to last.

In April 2019, the Supreme Court of India

Lenders were to classify a loan as stressed on just one day of default, whilst bankers were required to mandatorily refer all accounts holding over $280m in loans to the National Company Law Tribunal (NCLT) or bankruptcy court.

quashed RBI’s 12th February circular on project owners’ appeal, and also ruled to invalidate all actions taken since its inception.

This was no doubt a relief to stressed asset owners and lenders, but it leaves the Indian financial sector hostage to open-ended promoter delays and gaming of the system, and prevents the speedy resolution of decade-old poor investment decisions. As a result, the banking system remains hamstrung, stymying India’s enormous economic growth potential.

Coal supply issues The Indian coal-fired power sector is struggling with coal supply issues. India’s domestic coal deposits are concentrated in central and eastern Indian states: the states of Jharkhand, Odisha, Chhattisgarh, West Bengal and Madhya Pradesh produced ~80% of the country’s thermal coal in FY2017/18. States such as Karnataka and Gujarat with high electricity demand growth have almost no in-state black coal mining capacity (Gujarat produced 13.3 million tonnes (mt) of lignite in FY2017/18). These states are dependent on imported coal, or domestic inter-state coal hauled via railways from distant coal mines—with both mechanisms contributing to high marginal fuel costs in power production.

Coal India Ltd (CIL), a state-owned coal mining giant, supplies more than 80% of India’s thermal coal demand, yet it has consistently failed to meet its production growth targets. CIL is aiming to produce 625 million tonnes per annum (mtpa) in FY2019/20 (growth of 3.6% year-on-year), more than 10% below its original target for the year, after missing production targets of 600mt and 660mt over the last two fiscal years.

CIL has struggled to expand its mining operations to meet coal supply demand due to difficulties in getting environment and forestry clearances for proposed mines, land acquisition issues, community protests against mining, coal evacuation problems, poor planning and the rising cost of coal and coal transportation.

Coal mining and evacuation activity is impacted by India’s annual monsoon season (June-September) which further impacts coal supply and the reliability of coal-fired power stations.

The impacts of the monsoon in the current fiscal year have been particularly severe. Coal India’s 30mtpa Dipka mine in Chhattisgarh was flooded due to the diversion of an overflowing river in its vicinity. Operations at this mine remained stalled for both August and September, severely limiting its output. Relatively smaller flooding has also affected thermal coal mines in other states such as Jharkhand and Maharashtra.

ANALYSIS 1: INDIA COAL India’s attempt to rationalise assigned coal linkages to power plants was assigned to Ujjwal Discom Assurance Yojna (UDAY), a national scheme introduced in FY2015/16 to assist financially stressed state-owned discoms. India hoped to minimise the distance between the mine and the power plant to reduce the cost of power production.

This initiative grew in significance when the price of coal and coal transportation surged in FY2018/19. Coal prices across all grades increased by 17%, whilst railway transportation charges increased 21% in January 2018, and then another 8.75% effective November 2018.

Brookings India found Indian railways were overcharging coal freights by 31% to offset losses from passenger coaches, resulting in an increased cost of power, on average, of about Rs0.10/kWh on the basis of all electricity generated in India.

As a result of many of the input costs described, the power costs of state discoms increased during FY2018/19.

After dropping to Rs4.19/kWh in FY2017/18, the average power purchase cost increased to Rs4.42/kWh in FY2018/19.

IEEFA notes that whilst India remains reliant on thermal coal-fired power generation, it needs to prioritise the development of lower cost mine-mouth coal-fired power plants built close to the supply of coal. A coal supply travelling 500km can increase delivered coal costs by 50%, whilst 1,000km doubles the cost of the delivered coal, which becomes a massive extra cost to Indian consumers.

Risks from water stress India’s thermal power sector is very dependent on water, as ~90% of thermal power generation is dependent on freshwater for cooling. The country’s thermal coal-fired power plants are withdrawing around 22 billion cubic metres of freshwater per year (on 2016 figures), more than half of India’s domestic water requirements.

According to the World Resources Institute (WRI), ~40% of India’s current thermal capacity is located in waterstressed areas, with water shortages leading to losses in electricity generation and significant revenue losses for power producers. WRI found India lost about 14 terawatt-hours (TWh) of thermal power generation due to water shortages in 2016, cancelling out more than 20% of growth in the country’s total electricity generation from 2015. Similarly, a study by Vasudha Foundation revealed losses of 5TWh a year between 2012 and 2017 on account of water scarcity, with strong annual variation year to year.

Losses in power generation due to water shortages have impacted the profitability

Coal prices across all grades increased by 17%, whilst railway transportation charges increased 21% in January 2018, and then another 8.75% effective November 2018.

of various companies. An October 2019 study by WRI analysing data from three of the five companies in their sample revealed significant negative impacts to earnings before interest, tax, depreciation and amortization (EBITDA) on account of water-induced shortages.

To address increasing water shortages in India, particularly as it impacts thermal power generation, the Ministry of Environment Forest and Climate Change (MoEF&CC) issued a notification in December 2015 tightening standards around air pollution and water consumption in thermal power plants. These were incorporated into the legal framework in June 2018 through an amendment to the Environment (Protection) Rules, 1986 issued under the Environment Protection Act. Unfortunately, the standards were diluted and limits for water consumption were increased to 3 cubic metres per megawatthour (MWh), 20% higher than the cap of 2.5 cubic metres of water per MWh initially notified.

The basins where thermal power plants are located are expected to face acute water shortage in coming years.

IEEFA notes water stress may become an increasingly constraining factor for sustained strong economic growth in India. This will affect coal-fired power generation whilst increasing operating costs into the future, thereby increasing stranded asset risks.

Slowing electricity demand growth India’s recent economic slowdown has considerably impacted electricity demand growth. As of November 2019, year-to-date electricity demand for FY2019/20 grew at just 1.9% compared to 6.2% for the same period in FY2018/19.

The slowdown in electricity demand has meant non-coal power generation sources have fulfilled the entire demand growth, and more. Generation from hydro, nuclear and renewables

grew significantly over the first half of FY2019/20—15%, 26% and 6%, respectively. Generation from coal dropped 1% in the same period.

The sudden decline in coalfired power generation continued throughout October 2019. By the end of the month, the annual increase in coal consumption by the power sector, which had previously averaged 6.3% or 27 million extra tons each year for the last 12 years, fell to zero, not only for the financial year to date but also for the full 12 months to 31 October 2019, compared to the previous year.

In IEEFA’s view, this sudden decline in coal-fired generation is not primarily a consequence of coal shortages. Power plant stocks in October 2019 were 8.5mt (66%) more than in October 2018 when coal-fired generation was much higher, despite 29 plants having ‘critically low’ stocks. Rather, these figures may be impacted to some extent by the seasonal nature of some noncoal power sources, particularly hydro and wind, which generate more during the first half of the fiscal year than the second.

The much lower-than-expected electricity demand growth, combined with the cost competitiveness of wind and solar—with wholesale electricity tariffs consistently below Rs3.00/kWh, and zero indexation and zero marginal costs—are driving the dramatic turnaround in coal consumption for the power sector in 2019.

IEEFA notes with renewable energy set for further cost reductions over the next decade, wind and solar will further undercut thermal power, mopping up most of the incremental electricity demand growth. From “Seriously Stressed and Stranded: The Burden of Non-Performing Assets in India’s Thermal Power Sector” by Tim Buckley, Vibhuti Garg, Simon Nicholas, and Kashish Shah, Institute for Energy Economics and Financial Analysis

Declining Bankability of Coal-fired Power Plants

Source: Global Coal Plant Tracker, IEA database, IEEFA calculations

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ANALYSIS 2: CHINA’S NUCLEAR PROGRAMME

China’s nuclear power industry comprised 47 operational reactors.

China’s nuclear programme to swing back into full gear

Delayed reactor tech deployment and missed capacity targets are not holding back local firms from innovating designs and next-gen plants, says The Lantau Group.

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or worldwide proponents of nuclear power as a low-emission, baseload power source, China’s ambitious nuclear power deployment programme has served as a solitary beacon of light in an otherwise glum industry. Considering Japan’s industry restart remains stuck in a policy and regulatory quagmire; Europe’s previously seemingly resurgent industry has been beset by project slowdowns; Southeast Asia’s ambitions have largely been set aside or cancelled; and a large portion of the US industry is teetering on the brink of insolvency due to unfavourable market and policy shifts, the tremendous build projections of the Chinese industry offer a tenuous lifeline to nuclear power technology firms around the world. Unfortunately, nuclear power projects remain notoriously vulnerable to cost and schedule overruns and shifting policies, and the Chinese nuclear power programme in recent years has been no different.

Following a multi-year run of rapid and successful power project development from 2008 to 2013, the years since 2014 have seen China struggle with behindschedule deployment of third-generation reactor technologies, missed targets for capacity installation, and an expanding and already three-year gap since the last commercial power reactor broke ground (2016-present).

Beyond this, China continues to face electricity oversupply problems complicated by slower economic growth 18 ASIAN POWER

In Q3 2019, the Chinese nuclear power industry comprised 47 operational power reactors, for a gross installed total of roughly 49GW of electricity.

and grid capacity constraints in various regions around the country—indeed The Lantau Group has covered solar and wind curtailment issues in China previously— which begs the question whether these projected new nuclear plants are even necessary. Accordingly, one could be forgiven for taking a bearish view on the future growth of the China nuclear programme.

The Lantau Group put China’s recent nuclear industry challenges in perspective and noted that China still appears committed to its nuclear programme and has made more progress behind-thescenes managing technology shifts and deployment plans than might first seem.

The Lantau Group acknowledges the slowdown in recent years, but considers an uptick in nuclear sector activity to be more likely looking ahead. Some of the knock-on effects of the future growth in nuclear are discussed, including the potential impact on China’s renewables targets and current power oversupply; as well as on the worldwide nuclear fuel supply ecosystem.

In Q3 2019, the Chinese nuclear power industry comprised 47 operational power reactors, for a gross installed total of roughly 49GW of electricity. Three different companies are responsible for nuclear power plant development, with the majority of the fleet split between China General Nuclear (CGN) and China National Nuclear Company (CNNC) and the third company—the

State Power Investment Company (SPIC)—just starting out with its first reactor sites. With a few exceptions, the fleet consists of multiloop pressurised water reactors (PWRs) based on French, Russian, American, and indigenous Chinese designs. After years of delays, the first wave of 3G plants at the Sanmen, Haiyang, and Taishan sites have all successfully connected to the grid.

The completion of the Sanmen and Haiyang NPPs serves as the crucial demonstration of concept for Westinghouse’s AP1000 reactor technology, whilst the completion of the Taishan NPP serves the same purpose for Areva’s EPR reactor design.

In addition to the current operating fleet, another 12 power reactors are under construction, again mostly of PWR design. Amongst these underconstruction reactors are China’s first indigenously-developed 3G plants—the two pairs of demonstration HPR1000s at Fuqing and Fangchenggang NPPs, as well as the “Integrated Version” of this HPR1000 at Zhangzhou NPP. There are also two next-generation (4G) designs under construction—a high-temperature gas cooled reactor and a sodium cooled reactor, as well as a handful of older 2G designs.

Aside from under-construction units, a further 45 units have already secured site approval and are in various stages of preconstruction standby, including several that have already completed all necessary preparations to begin pouring concrete and are simply waiting for issuance of their construction license. Beyond this, the long-term pipeline includes at least 60 more reactor units proposed by provincial governments or local municipalities currently making their way through the regulatory requirements for site approval (seismic safety reports, environmental impact evaluations etc). Amongst the approved and planned reactors are at least 36 units located in inland regions where development has been frozen since the Fukushima accident in 2011. This includes approved inland sites that were just months away from pouring concrete in 2011 but will now have to wait until the next 14th FYP period begins in 2021 to start construction. All currently underconstruction and future PWR reactors will be at the gigawatt level or larger.

Batch construction of AP1000s Now that the demonstration AP1000s at Sanmen and Haiyang have been connected to the grid and come up to full power, all subsequent AP1000 builds and derivatives are theoretically opened up for mass deployment. This includes some 10-12 reactor sites that have already been approved at the central planning level, not

ANALYSIS 2: CHINA’S NUCLEAR PROGRAMME Essentially, the development of the Integrated Version of the HPR1000 gave the Chinese industry a backdoor option to build more HPR1000 plants in 2019 before the first demonstration unit HPR1000s complete in 2021.

China Nuclear Reactor Technology Trees

Source: Nicobar Group

including inland plants. The explanation as for why construction on these plants isn’t already underway hasn’t been officially addressed anywhere but is most likely related to the ongoing and wellpublicised problems with Sanmen Unit 2’s primary coolant pump, requiring a replacement to be shipped from the US. If the primary pump issue can eventually be resolved to the satisfaction of the Chinese safety regulator, then construction licenses will ostensibly be issued for a slew of backlogged AP1000 projects, probably starting from 2020. Aside from the AP1000s, SPIC has developed its own design for a larger version of the AP1000, called the CAP1400. The demonstration unit for this plant in Shidaowan has already poured concrete for its first unit, with the second unit to follow soon.

Possibilities from design merger As mentioned previously, the first two sites for the 3G HPR1000 reactor (i.e., Fuqing for CNNC and Fangchenggang for CGN) are under construction and have thus far seen on-schedule construction and smooth development.

A little-publicised fact about these two plants is that the CGN and CNNC variants of the HPR1000 reactor contain significant design differences, as they were originally developed independently and forced to merge into one brand name for resource efficiency and promotional purposes.

More recently, the two designs have been fully merged into a so-called “Integrated Version” HPR1000, a unified design that China hopes to export to the UK, Argentina, and others. Because China follows the industry principle of “demonstration plant first, batch deployment second”, this new Integrated Version of the HPR1000 must now have its own demonstration units.

CGN’s first Integrated Version HPR1000 will be at Taipingling, in Guangdong Province, whilst CNNC achieved a major milestone by pouring

concrete for its first Integrated Version HPR1000 at Zhangzhou in October of 2019. Essentially, the development of the Integrated Version of the HPR1000 gave the Chinese industry a backdoor option to build more HPR1000 plants in 2019 before the first demonstration unit HPR1000s complete in 2021. Once those company-specific demonstration units demonstrate successful and stable operations, the backlog of approved HPR1000 units will also get the green light, likely from 2022 onward.

Nuclear policy targets Chinese nuclear power capacity targets for 2020 have increased over the years, starting at 30GWe in 2008 and seeing adjustment upward to 70-80GWe in the period just before Fukushima. In the post-Fukushima Energy Development Strategy Action Plan 2014-2020, issued in November 2014, the nuclear capacity target for 2020 was revised downward to 58GWe, a number that was reaffirmed in the 13th FYP documents in 2015.

This number was repeated consistently

by Chinese industry, policymakers, and media from 2014 onward, despite the fact that achieving this goal became a mathematical impossibility somewhere around 2016. In 2019, the China Electricity Council formally acknowledged that 53GWe by 2020 is a more realistic figure, which matches with TLG’s independent build tracking efforts.

Thus, the final tally will thus miss the mark, but not by far, with a shortfall of less than 10%.

Missing this target was surely an industry setback, but it is also easy to read too much into it. There was no associated weakness or failure of Chinese construction capabilities or a loss of policy support for nuclear in general. Meeting the 2020 goal would have required a significantly higher number of new reactors to pour concrete back in 20142016, but this didn’t happen. The shortfall was caused by two specific industry

initiatives working in tandem: • Firstly, China’s post-Fukushima nuclear plan designated safer 3G technology to be preferred over 2G or 2G+ units, and that no further 2G+ units would be approved (several 2G+ units began construction in 2015, but they were grandfathered in from approval prior to 2013).

• Secondly, the Chinese industry follows a “demonstration plant first, mass deployment second” development model, meaning that all under-construction first-of-akind (FOAK) plants are required to prove successful commercial operation before they could proceed with what the industry calls “Nth of a kind” (NOAK) construction.

Taken together, this meant that China’s already under-construction 3G units needed to be completed before any new builds could be approved.

Unfortunately, the FOAK 3G reactors under construction at the time in China met with numerous schedule overruns, supply chain hiccups, and technological hurdles—hardly atypical for FOAK technology. FOAK reactors have greater risk of taking longer and costing more to build than NOAK reactors.

When the Chinese-designed 3G reactor HPR1000 had its design finalised and approved in 2015, it was allowed to swiftly begin construction of demonstration sites.

Thus, from 2013 to 2019, the entirety of China’s under-construction fleet consisted of either grandfathered 2G+ reactors that would be the last of their kind, or demonstration plants for 3G designs that were the first of their kind. With no proven 3G technologies available for batch deployment, it was inevitable that China would miss its 2020 deployment goals, but without any kind of policy shift or change of leadership commitment to nuclear energy.

Within the next year, China should release a draft version of the 14th Five Year Plan, which will set out policy for goals and plans across the entire economy from 2021 to 2025, including energy development. For the Chinese nuclear industry specifically, the 14th FYP should provide insight into several more key questions: • What are the new, realistic industry construction goals to 2025 and beyond, and will they demonstrate continuing strong commitment to the nuclear power programme? Will the inland plant sites finally be opened up for development after going into long-term stasis following the Fukushima accident?

ASIAN POWER 19

ANALYSIS 2: CHINA’S NUCLEAR PROGRAMME •

Will the new Westinghousedesigned AP1000 still be added into China’s nuclear fleet once the Hualong One demonstration reactors are finished and ready for batch deployment?

• Will the domestically-developed extension of the AP1000 (the CAP1400) be treated as a legitimate domestic and/ or export competitor for the domestically-developed Hualong One? Will Chinese nuclear firms compete head-to-head for export opportunities?

• What attitude will be adopted with regard to the 4G technologies currently applied in China? How much will energy policymakers prioritise diversification into reactor technology that does not use enriched uranium?

Aside from the nuclear-specific goals, the narrative on broader energy climate goals for the country will also be relevant.

For instance, the 13th FYP (2016-2020) included a commitment to achieve 20% of primary energy consumption and 50% of electricity consumption from non-fossil sources by 2030—this figure will likely be updated for the 14th FYP, with nuclear to play an important role in that transition.

Capacity oversupply problem Depending on the province, Chinese regional electricity markets generally range from moderately to severely oversupplied. Although the curtailment of renewable assets has reduced in recent years due to restrictions on capacity additions and other favourable policies, the power sector remains largely oversupplied, with aggressive coal capacity additions approved back in 2015 still coming online through 2019 and more projects in the pipeline.

Although the growth in power demand has remained strong over the past few years, the first half of 2019 saw industrywide demand slow to just 4.6% YoY, with the industrial sector growing just 2.8%.

With China’s notable power oversupply

issues unlikely to resolve themselves anytime soon, those bearish on the Chinese nuclear power programme may understandably wonder whether these future planned plants will ever see the light of day.

Fortunately, from the perspective of the Chinese nuclear industry, there are several supportive conditions that contribute to the protection of the industry’s future, even in severe electricity oversupply conditions: 1. Maintaining a robust domestic build programme and healthy supply chain is crucial to China’s efforts to export nuclear reactor technology abroad, especially to developing nations with extremely limited domestic manufacturing capabilities; 2. A healthy, well-maintained reactor will supply clean baseload power without additional carbon or other air emissions for 40-60 years (and even longer with life extension).

This means nuclear builders are inevitably more long-term focused and less inclined to be deterred by near-term economic disruptions or short-term supply demand balance issues.

Although there are other reasons, it is mostly for these two that nuclear power enjoys prioritised dispatch in many regions of China, usually to the detriment of local coal. This prioritised dispatch was reaffirmed in the NDRC’s Clean Energy Consumption Plan for 2018-2020, issued in late 2018. Despite this, nuclear is not totally immune from restrictions on loading; for instance, in freezing northern Liaoning Province, combined heat and power plants still enjoy the highest priority of dispatch through the cold months.

Load cycling is considered to be a highly undesirable way to operate nuclear power plants, owing to certain operational/technical features of the nuclear fission fuel cycle, so it’s generally not done if possible (France is a notable exception, owing to nuclear power’s

Operating, Under Construction, Approved, and Planned NPPs in China

Source: TLG/Nicobar Group Research 20 ASIAN POWER

Although the curtailment of renewable assets has reduced in recent years due to restrictions on capacity additions and other favourable policies, the power sector remains largely oversupplied, with aggressive coal capacity additions approved back in 2015 still coming online through 2019 and more projects in the pipeline.

majority percentage of electricity generation in that country).

Prioritised nuclear dispatch is unlikely to bump heads with prioritised renewables dispatch in the near future, primarily because Chinese nuclear plants are all located in eastern coastal regions whilst the most severely oversupplied renewables regions are mostly located in the north, northwest, and western parts of the country. If inland plant sites are opened up for development in the 14th FYP, this may become more of a relevant issue.

For the time being, however, they are treated as virtually “different but equal” forms of clean energy options for consumers. An example of how this is borne out in policy was seen in June 2019, when the power supply and consumption plan for commercial and industrial users was issued by the NDRC. In this plan, nuclear power was highlighted as a power source that would enjoy prioritised dispatch and end-users were encouraged to procure nuclear power via clean energy trading exchanges.

Nuclear fuel supply China’s nuclear industry is divided into three major nuclear conglomerates, each of which boasts a full complement of subsidiary companies to specialise in individual scopes of work, including research and design, EPC, construction, O&M, technical services, etc. Fuel cycle services, however, are unique in that they are mostly concentrated with one company: China National Nuclear Corporation (CNNC), which sets CNNC up to be the only Chinese nuclear player that can claim a complete nuclear fuel cycle solution for its plants.

Whilst China General Nuclear (CGN) does have some upstream investments in uranium mining, and the State Power Investment Company (SPIC) has an equity stake in a Kazakh facility that produces EPR reactor fuel assemblies for the Taishan plant, the rest of the fuel cycle activities are monopolised

by CNNC. CNNC fabricates almost all the fuel assemblies used within the Chinese industry as a licensee of the various countries where the technology originated and sells them to CGN and SPIC fuel buyers. Some fuel assemblies for the Russian-supplied Chinese reactors are still imported from TVEL. Although China’s officially stated goal is to diversify its uranium sourcing amongst domestic production, equity stakes in foreign mines, and spot market purchases in a 1/3-1/3-1/3 split, in practice, domestic mining is likely to lag significantly behind the other two areas. Chinese domestic uranium resources are fairly modest, with production from CNNC’s SinoU totalling

ANALYSIS 2: CHINA’S NUCLEAR PROGRAMME Approved Plants in China’s Nuclear Build Pipeline

*First Concrete Dates are TLG projections.

Source: TLG Research based on various sources

just 1,650 tonnes in 2018 and further exploitable resources fairly limited. In contrast to other power fuels, nuclear power plants reload their fuel at highly predictable intervals and with highly precise volumes.

Historically, this has meant that the majority of uranium fuel contracts were signed for very long periods and extremely little or no volume was traded on spot markets. In recent years, however, global industry disruptions and slower than expected growth have opened up attractive spot market trading and sourcing opportunities. Since the early 2010s, Chinese fuel buyers have taken advantage of low spot uranium prices to stockpile significant quantities, serving as a hedge against future price fluctuations.

Chinese equity participation in overseas mining projects has also been significant in recent years, with both SinoU and CGN-URC snapping up stakes of mines in Niger, Namibia, Kazakhstan, Uzbekistan, and Canada.

With the spot price of uranium well below the cost of recovery and uranium miners in the USA and Canada already shuttering unprofitable mines, these are not profit-driven investments for SinoU and CGN-URC, but, rather, efforts to ensure the stability and security of their current and future nuclear fuel supply.

Uranium mined at locations with Chinese equity are almost always earmarked for China via long-term supply contracts. So, whilst Chinese nuclear deployments will continue and even pick up in pace, it may not be prudent to infer a short-term recovery in the price of uranium.

Next generation of nuclear tech The next generation (i.e., the 4th Generation) of nuclear fuel technology primarily focuses on technology types that will either move away from fission as a thermal heat source entirely (e.g., fusion reactors) or apply nuclear physics in an advanced way to allow fission reactions

to release so-called “fast neutrons” that will be able to sustain a chain reaction in normally non-fissile materials like natural uranium or thorium. The basic premise invigorating the development of 4G technology is that enriched U-235 as a fuel is problematic, because: 1. Natural uranium is relatively scarce in the earth’s crust, and the fraction of natural uranium that is the most usable isotope (i.e., U-235) comprises only a very small percentage of what is available. The majority of naturally occurring uranium is the more stable U-238 isotope.

2. Consequently, the enrichment of natural uranium is necessary to create a concentration of U-235 sufficient to sustain a chain fission reaction. Unfortunately, enrichment technology that works to produce low enriched uranium (LEU) for nuclear reactors works just as well to create highly enriched uranium (HEU) for use in a fission bomb.

3. The inevitable consequence of the LEU PWR fuel cycle is a mass of mostly useless, highly radioactive spent nuclear fuel, comprised of an unpleasant cocktail of fission products, natural uranium, and various transuranic elements, including plutonium.

Reprocessing is possible, but technologically tricky and very expensive.

4G technologies seek to alleviate one or more of these three issues, and some claim to be able to resolve all three at once. Sodium-cooled fast reactors, for instance, are theoretically capable of utilising natural uranium, plutonium, and other transuranic elements, or even the non-fissile and far more common element thorium as a fuel source.

China’s demonstration sodium-cooled fast reactor has been running for several years in Beijing and a commercial scale

The next generation of nuclear fuel technology primarily focuses on technology types that will either move away from fission as a thermal heat source entirely or apply nuclear physics in an advanced way to allow fission reactions to release so-called “fast neutrons” that will be able to sustain a chain reaction in normally nonfissile materials like natural uranium or thorium.

prototype is now under construction in Xiapu. Whilst 4G technologies hold great benefits for non-proliferation as well as the efficiency and safety of nuclear power, their rise would theoretically not bode well for companies with extensive or exclusive exposure to the continued use of the uranium fuel cycle. Fortunately, from the perspective of those companies, China’s 4G technology push is intended to be complementary to its fleet of PWRs, not a replacement, at least not in the first half of the 21st century.

The rise of 4G technology in China is not expected to play a significant role in fuel demand in the near future, and mid-term deployments in China will likely be modest, with 4G technologies not expected to truly take over until 2050 or beyond, according to some conceptual planning documents. Thus, the more compelling story associated with China’s 4G technology in the coming years will probably not be the domestic deployments, but rather the export potential. If the HTGR can see a successful demo run in Shidaowan, true export opportunities for this technology will immediately solidify, with Saudi Arabia and Indonesia currently showing the most promise.

Closing thoughts Despite the relatively unexciting performance of the Chinese nuclear industry over the past few years, the case for nuclear power in China remains attractive, with continuing policy level support. The expansion of the industry over the coming years is likely to pick up and gain even more focus upon publication of the 14th FYP. Zhangzhou NPP pouring concrete in October 2019, the first new Chinese plant in over three years, is just the first instance of what will be a major wave of new build over the next few years.

It will be important to keep an eye on the development of inland sites, as the deployment of more nuclear in relatively economically depressed regions would create a scenario where nuclear and renewables compete for dispatch.

As for knock-on effects, the outcome for the uranium future cycle is complex, as Chinese demand for refuels and new reactor cores will certainly grow, but will be mitigated to some extent by Chinese stockpiling and equity acquisition efforts.

4G nuclear generation technology will emerge on the scene within the next three to five years, but will realistically fill only a niche role in the near term given the size of the overall fleet or be tapped for export to new nuclear economies. From “Quiet But Not Dead: China’s Nuclear Program Now Poised to Swing Back Into Full Gear”

by David Fishman, The Lantau Group ASIAN POWER 21

SECTOR REPORT 1: WIND

Eyes on the East: China asserts power over global offshore wind sector Despite being a newcomer in the global scene, China added more capacity than any country in the last two years.

W

hen the UK began construction on the world’s largest offshore wind farm in early January, the global power sector looked on with great anticipation. One of the most eager onlookers is China, whose offshore wind project pipeline, especially for the province of Guangdong, could give the UK and other European countries a run for their money.

UK’s 3.6GW Dogger Bank Wind Farms, the world’s largest to date, is expected to power over 4.5 million homes, but China’s plans for Guangdong now amount to 12GW for 2020 alone. This, in addition to Chinese aspirations to become subsidyfree by 2022, is pushing the sector to lower costs, adopt modern technology, and become even more strategic in choosing and operating its wind sites.

Offshore wind accounts for a measly 0.3% of global electricity generation, but recent regulatory and technological developments showcased offshore wind’s potential to become one of the world’s central energy sources in the coming years.

As the UK and China race for dominance in this space, other global leaders are also breaking new ground.

Vietnam is another market to watch, as the

Global offshore wind power capacity is set to increase by as much as 15 times over the next 20 years. This will turn the global offshore wind sector into a $1t business.

government aims to make offshore wind a primary energy source.

Dr. Fatih Birol, executive director, International Energy Agency, said that global offshore wind power capacity is set to increase by as much as 15 times over the next 20 years. This will turn the global offshore wind sector into a $1t business, the leading source of electricity in Europe, and a viable source of hydrogen to reduce emissions from the iron, steel, and shipping sectors.

Whilst the UK and the rest of Europe remain on top of the global offshore wind game, China and other players from the Asian region could eventually emerge as winners if they fulfil their potential for wind power. According to a report

by Fitch Solutions, China is expected to become a global offshore wind power frontrunner over the coming decade as it accelerates offshore wind capacity deployment in Guangdong and Jiangsu.

“China’s offshore wind capacity growth since 2015 has seen the country grow its share of total installed capacity globally from 9% as of end-2015, to more than 25% as of end-2018, aided by the market comprising 40% of global net offshore wind capacity growth over 2018.

China is expected to become a global offshore wind power frontrunner as it accelerates deployment to Guangdong and Jiangsu.

22 ASIAN POWER

With the offshore wind project pipeline strengthening over the coming years, we believe China’s global offshore wind power footprint will expand further,” analysts at Fitch Solutions said.

Favourable conditions China is catching up to Western Europe with rapidly falling offshore wind power costs and markets like the United States and Taiwan in terms of competitive technology. Analysts believe that China’s aim is to eventually export technology, after decarbonising power supplies near the country’s coastal consumption hubs.

Danish company Ramboll designed the world’s biggest and heaviest monopiles for State Power Investment Corporation’s Guangdong Offshore Wind Power project last year. Weighing 1,600 tonnes, the monopiles are being installed at a depth of 37 metres, one of the deepest in the market to date.

Apart from China, other Asian countries are moving towards increased offshore wind capacity. Vietnam, for instance, has been looking to European expertise for developing many of its offshore wind projects. The country’s largest offshore wind farm at 3,400MW will be developed

SECTOR REPORT 1: WIND Installed Offshore Wind Capacity, 2018, MW

Source: GWEC

by UK-based Enterprize Energy in Thang Long, off the coast of the south central province of Binh Thuan.

“Primarily, Vietnam’s wind resources are some of the best in the world. The water depths are within the range that is manageable with current engineering, and our understanding of what makes commercial development possible. There is a developing onshore wind sector with technical expertise in operations and maintenance and so we believe this will be capable of expansion to serve the offshore projects over time,” said Ian Hatton, chief executive officer, Enterprize Energy.

Elise Do, associate director, Augusta, said that Vietnam has power generation needs of 60,000MW by 2020 and 120,000MW by 2030. She added that the growing demand will be a huge enabler for renewable energy, specifically offshore wind, which can help increase capacity almost immediately. The country also has a 20-year feed-in-tariff (FiT) in place, part of the government’s efforts to make renewable investments more attractive.

“The offshore wind sector offers scale, but what is also important is that you need to have good wind resources, which Vietnam has. It also needs benign sea conditions and proximity to load.

Vietnam, with its long coastline, has a lot of the ingredients needed to make the offshore wind sector work. Another interesting point about Vietnam is that its oil and gas supply chain is already established and that’s a good base from which to build the new industry of renewable energy,” Do added.

However, before Vietnam piqued the interest of giant developers, some investors have already looked to Taiwan as a launching pad for their expansion into the Asia Pacific. In Taiwan, Enterprize Energy has also been working on the 1,000MW Hai Long offshore wind project.

The country already boasts of an encouraging regulatory framework despite the Taiwan Strait being a

technically demanding environment to build an offshore wind project in. Hatton said that Taiwan’s geographic location makes it vulnerable to seismic activity and typhoons, requiring projects to have strong foundations to cope with seismic liquefaction risk and deeper water of up to 50 metres.

“For the utilities, it’s more of a question of diversifying into new markets. For IPPs, this is also a yield play, as they are looking to increase their yields and returns on investment. Asia does offer that and it’s becoming more and more interesting for investors. Taiwan has been a key growth region, and now people are looking for the next market,” Do said.

Money trail Many investors are looking at Australia, Japan, Korea, and countries in Southeast Asia with growth potential in renewables, and Do said that the investment potential will depend on which market each investor is familiar with.

Tim Buckley, director of energy finance studies, Institute for Energy Economics and Financial Analysis (IEEFA), said that wind, utility-scale solar and distributed rooftop solar generation made up 14.7% of Australia’s energy mix

Vietnam has power generation needs of 60,000MW by 2020 and 120,000MW by 2030.

in 2019, compared to just 1% in 2009.

Buckley noted that offshore wind power in particular has been slow to take off, but has eventually gained ground in the country’s national energy market.

Like Vietnam, Australia is taking inspiration from European leaders in offshore wind. The country’s first ever offshore wind project, The Star of the South, is a 2.2GW wind farm located off the coast of Gippsland, Victoria.

Proposed by Copenhagen Infrastructure Partners (CIP), it is the country’s largest electricity project worth around $5.4b in investments. CIP’s capital comes from institutional investors such as pension funds and insurance companies that prefer investing in infrastructure with long-term cash flows.

“An interesting trend to follow will be how well the support mechanisms that are going to be in place will meet the criteria of international investors and what they’re familiar with. The PPA is not bankable as it stands, but I understand that the Vietnamese government is working on the structure to see what can be done so I would say it’s progressing,” Do added.

Over the last year, another Asian country has seen an upsurge in the number of investors flocking to its offshore wind sector. A report by GlobalData reveals that Vietnam’s offshore wind can grow to more than 770MW from just 68MW at present. Major foreign developers such as Ørsted, Equinor, wpd and CIP have expanded their global footprints in Japan, proof that the country has huge potential for offshore wind generation.

Harminder Singh, director of power, GlobalData, said, “The offshore wind market in Japan, though presently at a nascent stage, is increasingly showing positive signals to investors. The recent joint venture between Canadian Energy Company Northland Power and Shizen Energy is a testimony to this.”

In addition, Japan passed the Marine

Total wind capacity & wind share of total generation, 2010-2028

e/f = Fitch Solutions estimate/forecast.

Source: EIA, Fitch Solutions

ASIAN POWER 23

SECTOR REPORT 1: WIND Larger turbines will also increase the capacity factors of new offshore wind projects, from as low as 26% to as high as 50%.

Public Auction Process

Source: Linklaters

Renewables Energy Act to enhance the government’s energy policy and hit 2030 energy targets. This piece of legislation will require multi-stakeholder collaboration in utilising parts of the sea for renewable energy projects.

“Having the supply chain developed in Vietnam could also be a gateway to the supply of other Asian markets when they do come on stream. The opportunities will also evolve as technology evolves.

For example, we’re seeing technological advances in floating offshore wind, and that will help strengthen the business case, and the realisation of other Asian markets where the waters are much deeper and more advanced technology would be needed,” Do said.

Analysts from the International Energy Agency (IEA) are closely watching Korea, which may play catch up with China if it strives to achieve its ambitious policy targets. Under the country’s Renewable Energy Plan 2030, offshore wind targets will account for more than 10% of the country’s electricity by 2040 or 25GW, the largest outside the European Union.

In terms of specific investors to watch, Buckley and his team at IEEFA noted that Macquarie Group has become a leading renewables investor across Asia and is the key investor in Taiwan’s offshore wind sector. In fact Macquarie Group announced that they could be the world’s largest renewable infrastructure investor within the next few years, due to their global target of 20GW of new capacity.

Tech rollouts As projects move further away from the shore and get installed in deeper waters, Birol said that floating turbines are becoming the norm. A geospatial analysis conducted by IEA showed that with just offshore wind, the electricity demand can already be met in Europe, the United States, and Japan.

And since the cost for offshore wind projects has been steadily declining, companies can invest in better technology 24 ASIAN POWER

and innovate faster than before. In 2018, the IEA reported that the average upfront cost to build a 1GW offshore wind project, including transmission, will need over $4b.

Over the next decade, analysts at IEA said that the cost is set to drop by more than 40% as a result of cheaper turbines, foundations, and installation costs.

“The technological advancements in offshore wind turbines have been dramatic. The rotor diameter of offshore turbines has doubled from 80 metres to more than 164 metres and average turbine capacity has more than quadrupled, climbing from 1-2MW in 2012 to 8-12MW today. Leading players like Vestas, Siemens Gamesa and Goldwind have already implemented offshore wind turbine upgrades and are betting on reaching 14MW turbines by 2024,” Buckley said.

Larger turbines will also increase the capacity factors of new offshore wind projects, from as low as 26% to as high as 50%. Despite not being available at all times, offshore wind can, at this level, match the capacity factors of gas- and coal-fired power plants in many regions.

In fact, offshore wind is in a league of its

Indicative annual capacity factors by technology and region

Source: IEA Offshore Wind Outlook

own in terms of baseload technology.

“Offshore wind can generate electricity during all hours of the day and tends to produce more electricity in winter months in Europe, the United States and China, as well as during the monsoon season in India. These characteristics mean that offshore wind’s system value is generally higher than that of its onshore counterpart and more stable over time than that of solar PV,” Birol added.

Countries with extremely deep waters such as Japan will also benefit from innovations in offshore wind technology.

According to Norwegian energy firm Equinor, floating installations could be the gamechanger in the country, as there are few to no sites for bottom-fixed turbines.

Why diversify?

Hatton said that for their part, they are looking at how liquefied air energy storage (LAES) can work best with wind farms and other renewables. Enterprize Energy is also developing its own hybrid concept, which means offshore wind and natural gas are co-developed and converted to electricity on-site.

“We are party to three gas fields that can be developed this way where we plan to co-locate offshore wind turbines.

Our concept is a commercially sensitive business model but I can say that we have a patient strategy to incorporate hydrogen production powered by wind which can then be stored, transmitted or converted to electricity by combustion at site,” he said.

Leaders, however, can use offshore wind to inject greater reliability on the grid. It has a utilisation rate of 50-55%, which means it offers supply diversity.

In this scenario, offshore wind can help countries reach their ambitious targets on time, especially as investment costs fall and make it a more accessible renewable energy source.

ASIAN POWER 25

SECTOR REPORT 2: SOLAR

China is expected to add 300GW of solar capacity by 2021.

Asia rises as global capital for solar power As renewables take over the world’s energy mix, the region will continue to grow its global PV capacity at full speed.

L

arge-scale solar farms have become a more common sight in Asia over the last few years. Technology costs have been decreasing significantly to the point that analysts forecast that by 2050, photovoltaic (PV) systems will cost a measly $0.42 per watt or as much as 4354% less than today’s price tag. This has sent Asian countries on a construction spree as they aim to hit ambitious renewables targets and meet the growing energy demand in the region.

China and Vietnam are now Asia’s brightest solar spots, with China expected to add over 300GW of solar capacity by 2021. Analysts from Fitch Solutions report that these are part of more than 700GW of global solar power capacity that will be added in the next eight years, or almost 150% expansion in global solar capacity.

As Asia and countries like the United States, Spain, and Brazil gear up for a solar boom, total installed solar capacity will likely overtake total installed wind capacity within the next two years. Fitch Solutions forecasts that over the next ten years, the biggest names in solar will in fact be China, the United States and India.

Markets to watch China is now a mainstay in renewable energy headlines around the world amidst 26 ASIAN POWER

China and Vietnam are now Asia’s brightest solar spots, with China expected to add over 300GW of solar capacity by 2021.

its aggressive takeover of sectors such as solar, offshore wind, and hydropower.

Last year, solar power in China became cheaper than electricity supplied by the national grid through coal power. This means that over the next few years, solar power will likely find its way to the industrial and commercial space.

Meanwhile, Vietnam’s high solar irradiation levels will soon be leveraged to meet a 4GW solar capacity target for 2025 and 12GW target for 2030. To move closer to the target, the country invested in Southeast Asia’s first largescale floating solar project, a 47.5MW

facility in Vietnam’s Da Mi plant. Jackie B. Surtani, Asian Development Bank’s director of Infrastructure Finance - East Asia, Southeast Asia and the Pacific, said that the project was financed on a nonsovereign basis and completed in two years.

“This is relatively new for Southeast Asia. It’s quite straightforward, and so it’s not overly complex. DHD, which is a subsidiary of an EVN subsidiary called GenCo-1, has three large hydro projects which have been in operation for a considerable period of time. They’ve decided to put this floating solar on one of

Heat Map Of Solar Capacity Additions By Country Between 2018e & 2028f, MW

*Grey colour means no new capacity, or outside of coverage. e/f = Fitch Solutions estimate/forecast.

Source: Fitch

SECTOR REPORT 2: SOLAR Top Five Solar Markets By Installed Capacity In 2028f

e/f = estimate/forecast.

Source: EIA, Fitch Solutions.

their reservoirs and it actually only takes up around 8% of one of the reservoirs.

What it does is that it increases the overall output during the dry seasons where the hydro plant will not be running,” Surtani said.

Taiwan, on the other hand, developed its largest ground-mounted solar project the same year, the result of an IPP’s goal to minimise its ecological impact. Singaporebased Vena Energy won a competitive tender to build a solar project on an abandoned salt product farm in Chiayi.

Called Mingus, Vena Energy’s 70MW project will help achieve Taiwan’s 20GW renewables target by 2025. “We worked with local and international banks to finance the project which is particularly attractive as it is the first large-scale solar project tender by the government, and the Mingus Solar Project was the largest ground-mounted development when the tender was introduced in 2017,” said Sam Ong, group CEO and country manager of Taiwan, Vena Energy.

The challenge of land Whilst many countries have encouraging regulatory and physical environments where solar power can thrive, others are not as lucky. Singapore, for example, does not have as much land as Vietnam or India, so the government has resorted to artificial islands, solar generation facilities, and vertical solar installations to achieve the goal.

Analysts at Fitch Solutions reported that Singapore’s solar sector will expand over the next decade, as the government moves away from thermal energy and upholds its Paris Agreement pledge to reduce emissions intensity by 36% below 2005 levels. The transition to solar is perfect for Singapore, which has an annual solar irradiance of 1,580kWh/ m2/year, 50% greater than neighbouring temperate countries and highly suitable for the deployment of PV cells.

“Solar energy can be harvested through floating solar farms, the installation of

solar panels on rooftops and via solar energy imports. Various policies have been implemented to promote growth of the sector – for example, the Energy Market Authority of Singapore (EMA) had lowered the fixed component of the licence fee for larger generators (ranging from 10MW to 400MW), reducing the cost of installation of solar panels,” analysts at Fitch Solutions said.

On the other hand, whilst India does have the land for solar power, a complicated regulatory environment has made it difficult to implement solar projects at the ideal pace. According to JMK Research Analytics, a bloated bureaucracy requires 6-9 months to procure land for solar or wind projects.

Other states may even stretch this to 1824 months, making it an extremely costly endeavour.

Due to this challenge, many states have already instituted a single window clearance mechanism to improve land acquisition. Project delays now stem from other issues, such as the lack of a formal policy to allocate land in some key states, the non-agricultural conversion of land, and delay in registration under the Solar Park scheme, amongst others.

Singapore, for example, does not have as much land as Vietnam or India, so the government has resorted to artificial islands, solar generation facilities, and vertical solar installations to achieve the goal.

“As land is a state subject, there is a need for better coordination between state and central government agencies whilst evaluating and announcing tenders.

The expected due dates should match the reality on the ground. Digitisation of land records is the key to streamline and expedite the land allotment process, thereby reducing any chance of stalling of projects due to legal hurdles. Lastly, to speed up the process of approvals and permissions, the number of agencies involved should be minimised or a better coordination among these agencies has to be established,” analysts at JMK Research Analytics said.

No two markets are the same Developers have to recognie that despite almost similar physical environments, each market in Asia is significantly distinct. Surtani said that Asia is not like Europe or the US, where projects can be proposed in general terms.

“If you come into Vietnam and you say, I want a project with the structure that is exactly what I got in the US or Europe, you’re not going to get it, you have to be flexible. You have to adapt to various local governments, local cultures, and local regulations and make it work,” she explained.

Going forward, however, countries will be in the same direction as they explore large-scale floating solar. Surtani said that due to the issue of land, floating solar projects will eventually make sense for most governments and will be a significant point of interest in the next few years.

“I have seen personally that Indonesia is planning something like a 200MW floating solar project. Even in the Philippines, I believe there is a small pilot system project here already. I think countries are beginning to explore this as a concept. I think you’ll see a lot more of this going forward,” Surtani added.

Solar Power Capacity & % y-o-y Growth

e/f = estimate/forecast.

Source: EIA, IRENA, Fitch Solutions

ASIAN POWER 27

OPINION

ISABEL CHONG

The buzz about lithium-ion batteries

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Country Manager Eaton East Asia

lmost 300 years since the discovery of electricity, 65 million of Southeast Asia’s population still goes without access to the electrical grid. The lack of energy holds back progress on many levels such as food security, health, education, work and poverty reduction. Yet the next frontier in Southeast Asia’s efforts to sustainably and efficiently power its communities is already within reach: lithium-ion batteries.

For most, lithium-ion batteries are a silent, but ubiquitous feature of modern-day living. Average consumers are most familiar with these small battery packs as the power source for everyday appliances, from laptops to the television remote control. Electrical grids and generators have superseded batteries as the main source of electricity and power distribution in the last century. However, in recent years, technological advances have allowed batteries to address enduring energy and development problems in Southeast Asia, in ways that grids and generators are unable to.

Off the grid and in the dark Traditionally, extending the main electrical grid gives communities access to electricity, but this is challenging for households in disparate and isolated areas. These areas suffer from a lack of power infrastructure, and the logistics involved with building power generation and distribution infrastructure can amount to a hefty sum. The difficulty rises exponentially for Southeast Asia’s communities, which are scattered across thousands of islands.

Now, lithium-ion batteries are becoming the force behind solutions that aim to electrify these remote communities. Between 2018 and 2027, Southeast Asia is expected to invest $9.8b in smart grid infrastructure.

Modern microgrids comprise larger, stationary energy storage batteries that can accommodate the integration of local energy resources such as diesel with newer, sustainable energy sources like hydropower, solar and wind renewables. Increasingly, these batteries are made of lithium-ion.

Lithium-ion batteries are a significant progression in battery technology, which for decades has been dominated by valve-regulated lead-acid batteries. Its superior energy density makes it beneficial for electric vehicles and portable electronics, whilst stationary energy storage batteries become easier to transport, deploy and install in rural areas.

Energy storage batteries are essential for microgrids and portable solar energy systems because the production of renewable sources is subject to weather and environmental conditions. The batteries store solar energy that is harnessed in the day, and returns the necessary supply to the microgrid during periods of low energy generation, such as when a cloud passes over the solar power panel. It is also a temporary source of energy during short duration blackouts.

The energy unserved often reside within poorer communities that struggle with the initial cost of installation for microgrids and renewable energy infrastructure. While lithium-ion batteries have a higher initial cost, they are less vulnerable to damage and discharge energy at better rates than lead-acid batteries. Where the latter needs to be replaced every three to four years, lithium-ion batteries offer a lifespan of up to 15 years.

Implemented with renewable energy sources, lithium-ion batteries give communities a reliable, sustainable energy source that requires less maintenance, and that is more affordable in the long run.

Beyond microgrids, energy storage batteries also have other applications.

Disaster-prone areas often find themselves out of power in the wake of a natural disaster. In such situations, lithium-ion batteries in cars provide a source of power that can be tapped on to run smaller, emergency appliances.

Even urban cities may find that functioning power infrastructure is now no longer sufficient as they need to brace themselves for rising energy 28 ASIAN POWER

demands. Singapore recently launched a second public consultation to discuss regulatory frameworks for 5G, as the region looks to roll out the next-generation network in 2020.

Energy-aware smart cities Whilst 5G will unlock the full potential of compute-intensive technologies, it will also push service requirements and network capacities to the limit.

Network carriers will need to look into upping mains supply capacity and streamlining power distribution and cooling. As is, countries in the region already have huge energy guzzlers in data centres. A study by the Asian Development Bank found that in 2017, Indonesia used up to 3% of all electricity capacity to keep its data centres running, constricting alreadytight supply capacities across the country. Singapore foresees data centres will consume up to 12% of the country’s total energy demand by 2030.

Data centres already deploy uninterruptible power supply (UPS) systems to safeguard against potentially damaging power anomalies. UPSs serve as vital battery backup to ensure business continuity during a blackout or unexpected power outage.

The adoption of lithium-ion batteries paves the way for advanced data centre UPSs. Previously an underutilised back-up resource, UPSs can now perform the added benefit of supporting the grid as a distributed energy resource. Lithium-powered UPSs are being transformed into a storage device, allowing operators to respond to grid-level demands with battery power to keep frequencies stable. The data centre chooses how much capacity to offer to the grid and when, and benefits through additional revenue generated through a feed-in tariff.

Parallel to the use of car batteries as an energy source in rural communities, we are now witnessing the rise of vehicle-to-grid (V2G) technology. As more cities implement the necessary power infrastructure to support electric vehicles, V2G technology will allow electric vehicles such as the Nissan Leaf to store power in the car’s lithium-ion batteries, and send it back to the grid in times of need.

Lighting up the future with lithium-ion The costs of lithium-ion battery packs have plummeted by 90% in just 10 years. Its affordability sets it up well to replace lead-acid batteries and achieve widespread adoption. With multiple benefits such as a longer lifecycle and better sustainability, lithium-ion batteries can truly light up Southeast Asia’s energy-poor households sustainably and optimise energy usage. By providing power to make what matters work, these batteries can make a positive impact in driving the region’s economic growth and digital transformation.

ASIAN POWER 29

OPINION

CAMILLE LEVY

How Asia can get its energy transition right

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hen I arrived in Singapore to look into the growth opportunities in the energy landscape in the Asian Region, I was aware of some of the well-trodden discussions on the challenges that this region faces: “Asia will continue to lag behind Europe and the US in embracing newer forms of energy, especially clean energy”; “policy bottlenecks will make energy transition painfully slow and dependence on oil and gas inevitable.”

Yet, what I find fundamentally different here from my time in Europe is the potential for Asia to borrow from the world’s energy transition lessons—and more importantly its pacing—to set an agenda that balances affordability, reliability and environment.

Before delving into the details on how countries can tailor their transition to renewables efforts to meet their development goals; I would like to give way to some background about the region. The region consists of various economies, ranging from developed to least-dev eloped ones; and not surprisingly, fossil fuels including coal, oil and natural gas, are primary energy resources, occupying 85.2% of regional energy mix in 2014.

Rapid urbanisation, industrialisation, and economic growth have led to an increasing regional demand for electricity. Without any doubt, how the region tackles and balances its energy demands, vi-a-vis their sustainable energy targets under the United Nations’ sustainable development goals, will re-shape the vision, production and consumption of energy across Asia Pacific.

Though electrification has made progress in previous years, the reality is that rural areas still have difficulty accessing reliable electricity at affordable prices. The pressing challenge is to ensure a steady energy supply whilst, at the same time, spur regional economic growth whilst maintaining checks on the environmental impact of the existing and future energy infrastructures.

To further illustrate the point, in 2018, 99 out of the 100 most polluted cities in the world were located in Asia. Extremely high pollution in many Asian cities have raised public concerns about the overall impact to human wellbeing.

Therefore, it is essential to take into account environmental and social risks during planning, construction, and operation of energy power plants.

Government budgets, especially in developing countries, are often insufficient to address the challenge due to paramount costs of building and maintaining energy infrastructure. Various countries have introduced new energy policy mechanisms supported by initiatives such as public-private partnerships to incorporate the latest technologies to enhance power plants.

These partnerships have proven to be the most cost-effective approach to enhance electricity access with more efficiency and lower emissions.

There has also been an increasing investment in renewable energy with most investment pouring in developing and emerging economies in recent years.

Yet, the current outlook of the energy infrastructure indicates that the region continues to lag behind in terms of achieving energy efficiency. According to the World Bank, on average, Asia Pacific requires annual investment of $221b to achieve the 2030 SDG 7 on efficiency.

Whilst there is an increased need to reach the sustainable targets, we learned as children that “slow and steady wins the race,” and this adage now seems particularly true for Asian leaders running in what appears to be an ambitious energy race and relentless pressure to achieve sustainable development goals.

Australia is an illustrative example where its fast switch to renewables led to a series of blackouts and grid instabilities.

Australia’s experience shows how the path to renewable energy is not so straightforward and likely requires a more balanced approach in line with countries’ available energy sources. The challenge is making sure that we are progressing in the right direction, maintaining our responsibilities to our planet but also not compromising grid stability. This is a conversation I have every day with decision makers across Asia. It often means understanding the total 30 ASIAN POWER

Regional Leader GE Steam Power APAC

cost of electricity against systems costs, and the quality of power—and finding harmony between the two.

If there is one thing that I have seen leaders in Asia do well, it’s building consensus. Here, more than any other region I have worked in, making sure a potential solution is well accepted is mission critical and building consensus is how that happens.

I recently visited the Manjung 4 power plant in Malaysia. Manjung 4, which was the first unit in South East Asia to use ultra-supercritical (USC) technology, produces stable electricity for nearly two million households up to 10% more efficiently than the global average. And each additional percentage point in efficiency reduces carbon dioxide emissions by 2%.

Many outside of our industry are surprised to hear that this is a coal-fired plant because of the negative associations with coal and environment. But leveraging advanced air quality control technology has allowed the facility to become part of Malaysia’s solution in reducing SO2 and NOx emissions up to 70% compared to earlier Manjung units.

Across the region, leaders are trying to find the right balance. In the Philippines, the debate on how to negotiate existing contracting structures and to continue adoption of cleaner energy technologies while maintaining low electricity prices to fuel economic growth is raging. On the other hand, continued media reports that delays from Japan nuclear restart – or not – may bring 20% to 22% setbacks to its energy mix by 2031 are putting increasing pressure on energy security.

Such debates mirror those that I have heard over and over again in Europe, where hasty energy policies have led to unintended consequences. Germany for example has spent 160 billion euros on the shift to renewables in the last five years alone, and CO2 emissions have remained stagnant at 2009 levels for many years. In the meantime, German consumers have seen their bills soar, as Germany’s electricity price has risen to be the second most expensive in the European Union.

A recent study suggests that CO2 emissions have dropped in 2019, but also saying that they may rise again as factors like wind conditions are not predictable and renewable capacity isn’t growing as fast as needed. Some argue, Germany has failed in its “Energiewende”, because its targets were so ambitious.

As I take part in Asia’s energy transition, I am inspired by the pragmatic conversations I continue to hear on striking that right balance of energy sources with a mindfulness of the long game of affordability, reliability, and sustainability. What others might call ‘painfully slow’, I see as a region being deliberate in its energy transition and learning from the global experience. I look forward to seeing what 2020 brings and contributing as much as I can to its success.

CO-PUBLISHED CORPORATE PROFILE

Inside ENGIE’s 42MW district cooling system in Manila ENGIE and local conglomerate Filinvest Group have tied up to replace a business park’s power intensive airconditioning with high-efficiency, centralized chilled water cooling systems.

Philippines DCS Development Corporation

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tilities are pressed to find efficient and sustainable alternatives to emissionintensive airconditioning systems as demand for district cooling systems (DCS) in the Asia Pacific continues to grow. Setting the path for innovation in this space, the Asia Pacific unit of French power utility ENGIE tied up with local conglomerate Filinvest Group in 2015 to build a 42MW DCS that now serves Northgate Cyberzone, an IT park in Muntinlupa City.

The Northgate Cyberzone DCS is the largest of its kind in the Philippines. Its developer, the Philippine DCS Development Corporation (PDDC), a joint venture by ENGIE-Filinvest Group, is also a certified utility enterprise under the Philippine Economic Zone Authority (PEZA). In July 2019, members of the Asian Power team had an extensive look inside the plant to understand its functions and how it serves the IT park.

The DCS uses chilled water in place of

refrigerants, which have been traditionally used for airconditioning of buildings but are being phased out due to their significant contribution to ozone depletion. The Northgate Cyberzone DCS has gotten this down to a science by operating in a cycle: its cools its water supply, sends it to the buildings through a 3.4-km underground distribution network of steel pipes, and then receives it back as water heated via the buildings’ heat exchangers.

This hot water becomes chilled again for another round of use in the system. The temperature of the hot water sent back from the heat exchangers gets cooled down from 12 degrees to 6 degrees celsius.

The DCS plant is a brownfield project with 61% of the existing load connected. Nelson Lebato, energy engineer at the plant, said the plant’s performance is assessed through key indicators such as guaranteed efficiency, Chilled Water & Hot

“ENGIE and Filinvest have initially invested $29.47m (PHP1.5b) into the project as part of its capex.”

The cooling plant is powered by turbines

Water (CHW) supply temperature, and equipment availability. Having a unified cooling system has also resulted in a 13% overall cost savings for their clients as well as a 39% reduction in electricity consumption per year. The system also saves up to 12,000 tonnes of refrigeration (TR) and slashes carbon dioxide emissions by up to 11,500 tonnes.

Currently, the distribution network is connected to 14 buildings, most of which are occupied by Business Process Outsourcing (BPO) companies. By 2020, PDDC eyes adding four more buildings to the network. The installation of the DCS has made cooling more convenient and continuous for the buildings, which hosts firms like call centres.

The rest of the plant is compactly installed within the IT park. The building’s Ground Floor is utilised to hold a chiller with a cooling capacity of 4x2,000 TR. The DCS is powered by 2x2.5MW diesel generators as a back up located next to a 2x7.5MVA power substation.

Work in progress Even if it has already done substantial strides in saving energy consumption and emissions, PDDC is far from done with their landmark DCS in the Philippines. The project is still going through three phases of completion. In 2017, it had already a total installed cooling capacity of 8,000TR. It will have an additional 1x2,000TR by its second phase in 2020, and another 1x2,000TR by its final phase in 2022.

ENGIE and Filinvest have initially invested $29.47m (PHP1.5b) into the project as part of its capex. According to ENGIE, this will eventually add up to $58.96m (PHP3b) after 30 years. PDDC is now riding on the back of the success of the Northgate Cyberzone DCS in order to develop more projects for more IT parks and developments of scale, and boost their tenancy prospects with the usage of clean energy.

ASIAN POWER 31

OPINION

BREE MIECHEL

Vietnam bets on solar auctions to develop its renewable energy market Partner, Reed Smith

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ver the past two years, Vietnam’s renewables sector has experienced unprecedented growth, with the installation of solar PV capacity far exceeding government targets. This growth is largely attributable to the 9.35 cents per kWh solar feed-in tariff (FIT) that applied to plants commissioned by 30 June 2019, and which will continue to apply to projects in Ninh Thuan province until the earlier of the government’s capacity target of 2GW for the province is reached on and 31 December 2020. Despite the installation success, however, unless addressed, the lack of coordinated governmental supervision and synchronous grid infrastructure development is likely to impact future development in Vietnam.

Previously, notices were issued to the wind and solar PV installations in Vietnam requesting reductions in output by between 38-65% from their design capacity, severely impacting projected investment returns. This impact on investment returns stems from the “take and pay” rather than “take or pay” nature of the mandatory form of Power Purchase Agreement (PPA) that applies to solar PV projects under the FIT. EVN is essentially only required to pay for dispatched electricity and whilst the installation success demonstrates that this deviation from international bankability norms has not to date held back investment in the sector, it has limited the group of market participants to players with access to less risk-averse financing sources. The requests to reduce capacity and lower tariff proposed under various iterations of a draft law, however, has given even some of these investors and lenders pause and heightened scrutiny of grid infrastructure in the country.

Transitioning to auctions Against this backdrop, and with neighbouring Cambodia achieving a tariff of 3.87 cents per kWh in its recent auction for ground-mounted solar PV, the Vietnamese Prime Minister in November announced the intention to abandon a second-round FIT for ground-mounted solar PV in favour of an auction process. Further, news of an ADB-backed pilot auction for floating solar PV capacity has just come to market with tenders anticipated for up to 400MW over 2020 and 2021 and potential tender launch between June and September this year.

A World Bank Scaling Solar programme has been anticipated by market participants for ground-mounted capacity; however, whether ADB or World Bank-supported, the development of solar PV in Vietnam can move forward in a sustainable manner.

MOIT report and its Draft Mechanism On 31 December 2019, the Ministry of Industry and Trade (MOIT) submitted to a report including its draft mechanism for the encouragement of the development of solar power in Vietnam for the Prime Minister’s review (Draft Mechanism).

Pursuant to the Draft Mechanism: (a) a tariff of 7.69 cents/kWh is proposed for floating solar power projects and 7.09 cents/kWh for ground-mounted solar power projects for which a PPA has been signed, provided an implementation of construction commenced prior to 23 November 2019 and COD is achieved by 31 December 2020; (b) the position for solar projects in Ninh Thuan province be as stated above (i.e., subject to the 2GW capacity cap a tariff of 9.35 cents/kWh apply to projects having COD before 1 January 2021); (c) a tendering process apply to grid-connected solar power projects not meeting the conditions set out in (a) or (b); and (d) a tariff of 8.38 cents/kWh is proposed for roof solar power projects.

The Draft Mechanism attached to the MOIT report has not been officially approved or issued yet and the above tariffs remain as MOIT proposals only.

32 ASIAN POWER

There are advantages and disadvantages of any auction process and key issues to consider in designing the optimum auction mechanism for any market.Based on the experience of other countries that have implemented renewables auction processes, Vietnam may witness major changes in the profile of developers that undertake solar projects in the country. Utility players and energy majors with greater logistical capacities, able to squeeze their supply chain and optimise costs to reduce their tariff bids, are well suited to auction competition and tend to push smaller and local players out of markets.

Structuring an auction process In the Cambodian auction process the lowest electricity tariffs were submitted

by ACWA Power (Saudi Arabia), Prime Road Alternative Co (Thailand), and a Sinohydro (China) and SchneiTec (Cambodia) joint venture. Ultimately, Prime Road Alternative Co placed the lowest bid. Similarly, in the World Bank’s Scaling Solar auction in Zambia, bidders included the likes of EDF (France), Enel Green Power (Italy) and Mulilo Group (South Africa).

Where the procuring authority does not provide the site for the development of projects under an auction process, there will be greater capacity for local participation. The scheme may also specify stringent minimum local participation and content requirements as we are seeing in the latest Large Scale Solar 3 (LSS3) solar PV tender in Malaysia.

Geographically further afield, capacity auctions under the South African Renewable Independent Power Producer Procurement (SA REIPPP) Programme over the past eight years have been highly effective at delivering fasttracked additional capacity to the grid across various regions of South Africa.

Participants’ tender submissions included their proposed tariff alongside project details (including land rights) and expected benefits to the local community.

Successful SA REIPPP Programme bidders have been able to self-build parts of the required transmission infrastructure, something Vietnam may look to in assessing the benefits of any liberalisation of the State’s transmission infrastructure monopoly. Last month the Vietnamese Prime Minister directed the MOIT to look into private participation in transmission infrastructure on a pilot scheme basis.

Also incorporated into the SA REIPPP Programme documentation, have been appropriate incentives/disincentives to ensure the timely completion of projects and restrict the transfer of development rights, mitigating the risk of speculation and flipping of PPAs seen across many markets in this region.

For approved projects in Vietnam that failed to achieve the round one FIT deadline, there is an appeal in the SA REIPPP Programme auction structure.

Subject to prudent site selection, a scheme akin to the REIPPP Programme would allow the developers of those projects to bid under the auction and not forfeit their pre-development investment. The Vietnamese Government will, however, require control over the location of capacity awarded under an auction process for it to be successful in reducing electricity costs, or EVN will be left paying for electricity it cannot take due to lagging transmission infrastructure development.

MOIT had requested late last year that provincial authorities and EVN temporarily suspend further agreements on solar power projects. MOIT has however just issued a letter to EVN agreeing for EVN to continue receiving and resolving requests for power purchases from rooftop solar power projects. It is also understood that rooftop solar projects will continue to benefit from FITs, whilst ground-mounted and floating solar PV transitions to an auction scheme.

We await confirmation as to whether the Draft Mechanism will be accepted and the form of auction mechanism that will apply for the future development of Vietnam’s solar sector. Co-authored with Nguyen Thi Xuan Trinh, Partner VNA Legal

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