Asian Power (July - September 2019)

ISSUE 93 | DISPLAY TO 30 SEPT 2019 | www.asian-power.com | A Charlton Media Group publication

US$360P.A.

JAPAN DOublES DOwN ON NuClEAR OvERHAul FOR $6.33b TEPCO CEO TOMOAKI KObAyAKAWA SEEKS TO REDEEM VIEWS ON NuCLEAR POWER uSING NEW REACTOR TECH & SAFETy STANDARDS

HOw RulES HAmPER INDONESIA’S 17Gw PIPElINE wHy HONG KONG SEEKS lNG POwER HOw CAN mAlAySIA KEEP uP wITH POwER lIbERAlISATION? wHy ARE GEOTHERmAl TARGETS TOO lOw?

Leading Developer, Owner and Operator Power (Including Renewable Energy) and Desalinated Water

30 GW of Power 5.3 Million m3/day of Desalinated Water 23% Portfolio in Renewable Energy

Reliably delivering power and desalinated water at low cost KSA • UAE • China • Egypt • Indonesia • Jordan • Morocco • Oman • South Africa • Spain • Turkey • Vietnam

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FROM THE EDITOR The Asian Power team closed the first half of 2019 with the Asian Power Utility Forum, which marked another year of in-depth discussions with Indonesia and Malaysia’s power experts on the challenges and opportunities in the sector.

Publisher & EDITOR-IN-CHIEF Tim Charlton ASSOCIATE PUBLISHER Rochelle Romero production team Danielle Mae V. Isaac

Indonesia has a project pipeline for 17GW of generation capacity designed to meet its supply targets. But IPPs are struggling to get new projects off the ground ever since the government changed its tender selection process in 2017.

Read about the challenges that developers are facing on page 24.

Arianna Danganan Giullian Navarra

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Over to Malaysia, experts and executives are now preparing for market liberalisation, expecting that it will intensify competition and make it all the more challenging to maintain customer loyalty. Other utilities are now resorting to messaging apps and salesforce channels to keep their customers hooked. Learn more about the discussions on page 26.

This issue also features an exclusive interview with TEPCO CEO Tomoaki Kobayakawa, who recounted the lessons they have learned eight years after the Fukushima Daiichi incident in 2011 and introduced the latest addition to their nuclear cleanup fleet — robots.

Enjoy the read!

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ASIAN POWER 1

CONTENTs

interview 16 ceo Japan doubles down on nuclear overhaul for $6.33b

FIRSTS 08 Financing hurdles delay project progress

26

Asian power utility forum Indonesia seeks 17GW of power projects to hit ambitious electricity supply targets

28

Asian power utility forum Malaysia’s power companies revamp strategies for full market liberalisation

SECTOR REPORT 24 Are Asia’s geothermal power targets too low?

12 $6.5b of coal assets stranded 12 Utility-scale solar projects to take off 14 Subsidy cuts drive blow to rise of solar PV

OPINION 30 Vietnam’s solar FIT 2 and overcoming financing challenges 32 Taiwan offshore wind series part 2 – Lessons learned

Country report 20 Can renewables and gas support a coal-free Hong Kong?

22 Renewables strain could shatter dreams to exit coal and nuclear

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

PROJECT

South Korea picked as site of APAC’s first floating offshore wind project Equinor, Korea National Oil Corporation, and Korea East-West Power formed a consortium to develop a 200MW floating offshore wind project Donghae 1 off Ulsan in South Korea.

If completed by 2024, the 200MW Donghae project will be the first and largest of its kind in the region.

power utility

Taipower losses extend to $955m in H1 Taiwan Power Corporation has witnessed its losses escalate over the past year, losing up to $955m (NT$29.7b) in H1 2019, or $180m more than the $771m (NT$24b) loss it incurred in H1 2018. The negative trend was due to a combination of factors, such as rising fuel prices and government anti-pollution measures.

4 ASIAN POWER

PROJECT

Philippines switches on pilot 200kW floating solar power project The Philippines has switched on its first 200kW floating solar power project. The pilot facility is the first non-hydro project of SN Aboitiz Power-Magat (SNAP). Located in the 1,170-hectare Magat reservoir, the purpose-built facility was designed to withstand disruptive weather conditions and strong typhoons.

regulation

India could overachieve its Paris Agreement goals by 60%: report India is projected to overachieve its Paris Agreement targets by 60% thanks to projections that it will likely obtain 63% of its installed power capacity from non-fossil fuel sources including hydro by 2029-2030, a report by the Institute for Energy Economics and Financial Analysis (IEEFA) revealed.

power utility

Coal stress puts 20GW of India’s private projects on hold Coal-based capacity addition, which fell to a low of 3.6GW in FY2019, is expected to remain subdued at 5GW6GW per year in FY2020 and FY2021, India Ratings and Research said. In FY2013-2017, excess capacity in the thermal power sector had increased to an average of 42%.

regulation

Asia’s coal plants flounder as banks give them the cold shoulder Asia’s coal developers and coal-fired power plants are struggling to build new markets and keep afloat as global financial institutions turn their backs on them to avoid criticism over climate change. Over 100 major financial institutions have divested from thermal coal projects by February.

CO-PUBLISHED CORPORATE PROFILE

Hilliard Corporation: An unrivalled reputation built on groundbreaking filtration technology With its line of cutting-edge filtration solutions and peerless customer service, HILCO is the trusted partner of the world’s largest companies, including GE Power, Siemens and Mitsubishi Hitachi Power Systems to name a few..

HILCO has partnered with manufacturers such as GE Power and Siemens.

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hen it comes to manufacturing state-ofthe-art filtration systems for gas turbine installations, few names are as trusted across the world as HILCO. With over nine decades of expertise under its belt, HILCO is the partner of choice of the largest gas turbine manufacturers such as GE Power, Siemens, and Mitsubishi Hitachi Power Systems. Additionally, it also has a HILCO Licensee, 17 distribution agents, and three resellers in the Asian market.

“HILCO has been manufacturing gaseous fuel filters for over fifty years. These filters are designed and manufactured based on the requirements of ASME Code Section VIII, Division 1,” said Michael Long, vice president of HILCO Sales and R&D. Filtration extends the life of equipment used in industrial processes. A robust filtration system is crucial to protect investment by preventing downtime due to contamination and incomplete filtration.

Contaminant issues Contaminants in the fluid result to wear and tear on the systems they are part of, resulting in more downtime for repairs and lower productivity.

Lower productivity, in turn, results to lower revenue. The bottomline benefit of filtration is longer use of fluids, longer use of components, and greater productivity.

Whether a client needs fluid filtration and

conditioning or fluid recovery, reclamation and restoration for re-use, HILCO’s filtration systems are used in a wide range of applications for various industries. HILCO’s full range of engineered filters, cartridges, reclaimers, coolant recyclers & fluid conditioning systems brings fluid contamination problems under control in a cost-effective manner.

“We go beyond filters to provide a full service fluids management process, from obtaining samples, to fluid analysis, consulting on equipment, field techs, startup help, and more,” Long noted.

Further, HILCO’s filtration systems are offered with a variety of options, including work mezzanines, transmitters for pressure, temperature or level, local controls, various communication protocols, stainless steel or carbon steel construction, and solids removal only or liquid drip gas/moisture coalescing. Through their innovative design and unbeatable quality, HILCO products reduce the cost of new oil purchases, decrease disposal costs, lessen component wear,

HILCO’s range of filtration systems include coalescer separators, reclaimers, ceramic membrane systems, portable filters, as well as custom filtration systems.

reduce downtime and help curtail environmental contamination.

HILCO’s range of filtration systems include coalescer separators, reclaimers, ceramic membrane systems, portable filters, as well as custom filtration systems. “In recent years, all the major gas turbine OEMs such as GE, Siemens, and MHPS have begun utilising superheated fuel gas in order to boost firing temperatures and overall gas turbine efficiency,” Long explained. “As a result, HILCO offers high temperature fuel gas elements that can successfully operate at demanding temperatures as high as or exceeding 600F.” Cutting-edge filtration technology The HILCO Coalescer Separator removes moisture and contamination from steam turbine lube oils which have good water separability and are commonly found in the power generation industry.

Other applications may include refineries, chemical plants, heavy industry and steel mills.

Meanwhile, HILCO’s reclaimers are ideally suited for reclaiming insulating or refrigeration compressor oils or for any application which requires a high degree of purification. Reclaimers restore contaminated oils to a like-new condition.

Dirty oil can be purified and re-used to save on oil costs.

Simple to operate and easy to maintain, this system extends fluid life and greatly decreases

CO-PUBLISHED CORPORATE PROFILE

costs for waste disposal and purchase of new fluids. No matter what degree of purification or type of contaminants the application involves, HILCO has a reclaimer to fit the situation.

Further, the Ceramic Membrane Filtration System utilises high-velocity fluid “crossflow” across the face of the membrane. The oil-free water passes through the ceramic membrane whilst the oily waste is concentrated in a process reservoir. Further, HILCO portable filters are an economical solution for removing water and particulate from oils, fuel and other fluids. Filters can be built to ASME Code standards.

HILCO portable filters can be used for many different fluids, including mineral-based lubricating, hydraulic, and insulating oils; synthetic lubricating and hydraulic (EHC) fluids; fuel oils, kerosene, gasoline; ethylene glycol mixes; solvents; coolants; cutting oils; and vacuum pump oils.

“HILCO engineers utilise computational fluid dynamics (CFD) in order to optimise performance and to get accurate predictions of equipment pressure loss once in service. CFD can estimate the performance that a customer will see in the field with a completed system, such as pressure drop and velocity for optimum performance,” Long explained.

Each filter/separator is equipped with highperforming HILCO filtration elements. A variety of element ratings are available depending on the specific requirements of the equipment, he added.

Durable and advanced cartridges However, the reliability and efficiency of any filtration system is chiefly dependent on the quality of the cartridges used in it. In response, HILCO has a full line of filter cartridges for virtually every application depending on size, filtration efficiencies and dirt-holding capacity. Most fluids can be restored to a like-new condition. HILCO’s on-site testing facility is continuously examining and improving cartridge performance as customer needs evolve. HILCO is a major supplier to original equipment manufacturers worldwide.

HILCO’s durable cartridges stand up to continued use without softening and deterioration as a result of exposure to water. The key is an advanced synthetic media that provides maximum filtration with minimum pressure drop. Meanwhile, HILCO Microgard™ cartridges provide reliable, long-life contamination control.

These efficient filter cartridges feature three filtration layers: outer cellulose-media layer for coarse filtration, an intermediate glass-media layer for microfiltration, and an inner cellulose-media layer for added support.

HILCO Safegard™ single-layer pleated paper cartridges are economical for use in applications requiring general filtration. Disposable cartridges feature molded urethane ends on various sizes.

Plated metal end caps are also available with controlled radius pleats to maximise useable filtration area.

Other cartridge types manufactured by Hilliard include Hilsorb dryer cartridges for controlling moisture and particulate levels; high pressure hydraulic fluid filter cartridges engineered for 1,500psi pressure; coreless cartridges; Hilite

cartridges for acid reduction in petroleum-based transformers and turbine lube oils; coalescer cartridges; bag filter cartridges and Selexsorb GT cartridges for phosphate ester fluids.

“HILCO filters are available in simplex design and in duplex arrangements for continuous operation.

This configuration allows for uninterrupted engine operation during filter element servicing. HILCO duplex filters are available in opposing or same side connections. HILCO ball valves are manufactured and tested to ANSI/FCI 70-2 Class VI leakage requirements,” Long said.

“HILCO® offers several designs and sizes of seal gas filters for the purposes of particulate and liquid removal. Each one of our units is designed to the requirements provided by the customer.

With our many years of experience, we are able to determine the best option for the application whether it is an initial startup or an aftermarket retrofit,” he added.

The company’s current projects include new gas turbine installations where gas infrastructures are being developed and where gas turbines are replacing older coal-fired generators. One particular project recently installed in Asia is Unit 3 of the Ghorashal power plant in Bangladesh.

Ghorashal is the largest power station in Bangladesh, and the repowering of Unit 3 costs a staggering US$117m.

The Hilliard Corporation has also recently launched the new HILCO Laboratory Services. It provides a full suite of rigorous world-class test capabilities to support industrial filtration and fluids analysis. It can be used for product development, evaluating customer problems or needs, and improving competitive performance. HILCO’s proprietary testing mechanisms help clients identify current challenges and the best solutions to filters and filtration equipment.

A tradition of excellence HILCO is one of the divisions of Hilliard Corporation, an independently-owned, New

York-based company known for its range of technical solutions. Founded in 1905, the Hilliard Corporation has evolved from a one-product business into a special-applications engineering company serving customers worldwide. The Hilliard Corporation offers a broad line of motion control clutches, drivetrains and industrial brakes.

Its products include oil filtration and reclaiming equipment, starters for industrial gas and diesel engines and gas turbines, and plate and frame filter presses used in the food and beverage industry.

“Hilliard products are designed, manufactured, and sold according to our customers’ applications.

As a result, we have a large range of customengineered products that can be modified to meet new applications. With a sound understanding of engines and filtration devices, Hilliard engineers design complete systems, including electromechanical interfaces. Hilliard often works with customers to research and test products, acting as a lab for specific applications,” Long noted.

At Hilliard, quality is a way of doing business.

This is why it is an ISO 9001:2015 certified organisation. “Each of our processes is documented to regulate operation, even on very short production runs. Experienced machinists and code welders work efficiently to keep operating costs low whilst transforming blueprints into products,” Long said.

Moreover, these craftsmen use bar-coded, computerised production controls to guarantee high-quality output, in line with following documented processes.

“Our goal is to manufacture products that solve customer problems. Over the years, we’ve found that the only way to reach that goal is to be flexible. We’re willing to modify existing products, or develop new ones, respond quickly to requests, and take on complicated projects for sophisticated applications. In short, we will work with you to get the job done,” Long added.

HILCO has a full line of filter cartridges for virtually every application depending on size, filtration efficiencies and dirt-holding capacity.

HILCO engineers utilise computational fluid dynamics.

FIRST Permitting issues also need to be ironed out added Djojonegoro, who said that in one of their projects, the permits at the provincial level and regency level were different. “There’s some criss-cross in the data. That is something that you cannot take for granted in Indonesia, you really have to check at all levels,” he said.

x building green loans SOUTHEAST ASIA singapore

Dr Bikal Kumar Pokharel, Wood Mackenzie Erwin Maspolim, ING

I

n April, ING and Singaporean developer Sunseap sealed a green loan that will finance a portfolio of brownfield and greenfield rooftop solar projects with sizes from 100kW to 5MW. The solar projects will be contracted to over 20 commercial and industrial customers.

In an interview with Asian Power, Erwin Maspolim, head of utilities, power & renewables for Asia Pacific at ING, gives an overview of the bank’s process in creating a structure for financing renewables projects and tackling an issue for small projects that has been discussed for years.

How did you assess the developer’s profile and how was it deemed creditworthy?

One of our first questions to Sunseap Group was: “Tell us about the challenges you faced in the past few years.” Their answers revealed their vast experience as the market leader in the Singapore rooftop solar space and they are well positioned to take on the projects.

To ensure the bankability, we created a model whereby we identify and analyse the credit quality of off-takers and their power purchase agreements. For the portfolio, the C&I customers/ off-takers are categorised based on their credit profile, most of whom are reputable international and domestic corporates in Singapore.

Can you explain how financing the portfolio on a limited-recourse basis and having a single loan facility will help limit its uneconomic nature?

If the sponsor funded its projects one by one on a project financing basis, the lender will have to conduct several/separate due diligence (which typically could extend to legal, technical, insurance and model audits) and documentation process, hence incurring significant costs to the sponsor. It makes less economic sense to finance each project individually.

Our financing is unique in that its accordion structure allows Sunseap to finance multiple projects, greenfield or brownfield, as long as they meet both the technical and financial parameters pre-set by ING in conjunction with ING’s consultants on aspects such as on engineering, procurement of panels/inverters, construction and operational/maintenance and insurance terms.

What other renewable energy initiatives can we expect from the bank?

In the region, we will continue to see large offshore wind farm financing in Taiwan and a number of solar PV and onshore wind in neighbouring ASEAN countries. Vietnam is a space to watch.

8 ASIAN POWER

PT Tanjung Power Indonesia in progress

IPP projects trip over financing hurdles

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indonesia

s Indonesia’s state utility PLN changes the rules of procurement for power projects, independent power producers (IPPs) are struggling to get new projects off the ground. Securing finance has also become more difficult, especially with land acquisition issues that have delayed projects, according to Adaro Power’s deputy CEO Dharma Djojonegoro.

He cited land acquisition issues that Adaro Power encountered with the development of its 2x100MW circulating fluidized bed (CFB) coalfired power plant, Tanjung Power Indonesia, and its 2x1,000MW ultra supercritical (USC) coal-fired power plant, Bhimasena Power Indonesia.

“Land acquisition was a huge challenge, it still is to a certain extent,” he said, citing the drawn-out process between the power purchase agreement (PPA) and financial close (FC) for Tanjung Power Indonesia that lasted five years largely due to land issues.

“We basically acquired 95% of the land whilst the remaining 5% was not acquired for proprietary reasons. That is what prevented us from reaching financial close. We were helped by a fairly recent law which allowed the government to enforce the purchase of land for public interest. We were one of the first major projects that made use of this law,” he said.

Securing finance has also become more difficult, especially with land acquisition issues that have delayed projects.

Currency troubles Another pressing issue is a government law that created a mix up in currency transactions. Six months before FC of Tanjung Power Indonesia, the Indonesian central bank insisted all local banks to settle transactions in Indonesian rupiah “which then threw everything into chaos,” Djojonegoro added. As a result, Adaro Power had to come up and adhere to a tri-partite conversion agreement which took some time to negotiate between PLN and the involved lenders.

“In the more recent PPAs, PLN has verbally said that they no longer want to use this tri-partite conversion agreement,” he said, adding that in the future, more FX risk could be transferred from PLN to the project sponsors.

Resolving zoning issues, staffing concerns and ensuring high quality of local companies’ EPC performance also presented challenges for Adaro Power.

The company was further impeded by the expiration of its government guarantee, for which the company did not get a quick solution from authorities.

“The Finance Ministry doesn’t know how to extend the government guarantee because they haven’t done that before,” Djojonegoro said.

The CEO also shared some unique issues to their projects’ engineering, procurement, and construction (EPC) phase. For commissioning, he said that “close coordination with PLN is crucial.”

“For our 2x100MW project, we are at the commissioning stage. It is pretty much one of the first IPPs in Tanjung, and for a lot of times, the PLN in the region is not quite sure how to proceed,” he said, adding that they have to closely coordinate with both the PLN offices in the province and Jakarta.

Adaro Power project map, Indonesia

Source: Adaro Power

FIRST China has an outstanding payment of nearly $18b, in part due to the lack of transmission capacity curbing renewables integration into the grid.

It’s harder for projects to be profitable as bidding gets more aggressive.

Auctions to spur race to the bottom

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Asia pacific

sian governments’ transition towards competitive capacity procurement for non-hydro renewables has heightened the risks of certain projects, where some find it challenging to be profitable due to aggressive bidding and high risk taking, Fitch Solutions said.

China’s subsidy phaseout Notably, the Chinese government announced its plans to phase out renewable energy subsidies by 2020.

Firstly, renewables projects must match, or be lower than that of the coal electricity price benchmark which varies at the provincial level.

Projects are also required to show that the grid can deal with their variable

output, in an attempt to reduce grid bottlenecks and thus prevent renewables generation wastage. Moreover, local governments will still be allowed to subsidise renewables projects, with provinces with less optimal natural conditions set to be able to provide incentives to attract investment.

Lastly, green certificates are set to be awarded to renewables generators, that can be sold to more polluting power generators which will be required to acquire a set amount of certificates to make the footprint of their operations cleaner.

However, little additional information is given for this mechanism to date.

According to Fitch Solutions, governments in both developed and developing markets are switching to

reverse auction mechanisms to procure power and capacity from non-hydropower renewables, in a bid to (I) drive down the costs associated with subsiding renewable energy and (II) better calibrate the amount of capacity procured in order mitigate the bottlenecks of integrating intermittent wind and solar power supply into the grid.

“The initial FiT driven renewables boom has also led to an oversupply problem in some markets, as the significant increase in renewables power capacity has not been adequately accompanied with investment in new grid infrastructures, or a comparable match in power demand. This has resulted in bottlenecks and a low power generation utility rates in some wind and solar parks, creating generation losses for power developers,” the firm said.

For example, China has an outstanding payment of nearly $18b, in part due to the lack of transmission capacity curbing renewables integration into the grid.

India’s solar auction squeeze The phaseout of subsidies toward a competitive auction mechanism heightens the risk for a race to the bottom amongst bidders, the firm noted. “This aggressive bidding and rapid fall in tariff prices in many markets squeezes margins for project developers, which in turn could jeopardise the economic feasibility of parts of the project pipeline.”

In India’s solar sector, the government continues to push for lower tariffs in the tender process, which have already resulted in the undersubscription and cancellation of a few auctions across FY2018-2019. “Most recently, Tamil Nadu, one of India’s largest renewable energy states, have decided to cease wind and solar auctions for the time being due to undersubscription in the previous two,” Fitch Solutions concluded.

the chartist: china’s JAPAN’S renewables SOLAR INDUSTRY investment IS DIMMER slumped WITH JUST 39% 20GW as feed-in PROJECTED tariff TOregime COME ONLINE fades

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energy into Japan’senewable solar power sectorinvestment will expand at robustChina rates through 202039% as a large slowedto down to $28.8b xGlobal clean energy investment, $b backlog projects byfigure feedinof H1 2019,supported the lowest (China in red) in tariffs come online.

Aftersince 2020,2013, BMI for any half-year period Research said the transition to a according to that BloombergNEF. reverse auctions system growth, The plunge in activitywill in slow China, as as the Japanese government looks to regulate the country shifts this year away from capacity additions in order to reduce subsidy government-set tariffs to auctions costs and support grid stability. for new wind and solar capacity, also “We expect Japan to register robust solar depressed the through global investment capacity growth to 2020 as afigure result tothe $117.6b, down 14% H1 2018. of implementation of afrom substantial pipeline projects that benefit fromfor a Justinof Wu, head of Asia-Pacific generous feed-in tariff support scheme.

BNEF, commented, “The slowdown in Our forecast in is that out a 50GW backlog investment China isof real, but the figures of projects, onlyprobably 20GW willoverstate actually its forsuch first-half 2019 come online, most will not be ablesolar to severity.

Weas expect a nationwide take advantage of the FiT subsidies amid auction happening now to lead to a rush of Source: BloombergNEF stringent government requirements and Source: BMI Research new PV financings. ” delays inproject development, ” BMI Research added.

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Solar x and wind penetration in the energy mix, 2018

Source: BloombergNEF Source: BMI Research

ASIAN POWER 9

CO-PUBLISHED CORPORATE PROFILE

Going autonomous: How ABB is supporting utility companies on their digital journeys With digital products and solutions complemented by deep domain knowledge and expertise, ABB is helping utility companies in Asia embrace possibilities in digitalising their operations for a more sustainable world.

Adopting autonomous utilities requires an entirely new level of digitalisation.

M

Arup Sen, Head of Power & Water Business, Asia, ABB

any global utility providers have been adopting Industry 4.0 technologies and making the switch to autonomous operations over the last decade, amidst fluctuating commodity prices, deregulation, stricter emissions compliance and higher use of renewables.

Traditional power companies are adopting digital solutions and rethinking their plant processes and business models to increase operational efficiency, boost productivity, lower costs and promote sustainability. ABB, a major player in the power generation business for more than 130 years, has been the partner of choice for many of the world’s top utility companies as they journey towards autonomous operations.

Leveraging rich engineering and automation expertise, the company has been installing its advanced digital technologies, converging operational technology (OT) and information technology (IT) to enable remote monitoring of equipment and processes, real-time diagnosis of asset performance, optimization of plant functioning and predictive maintenance.

Autonomous utilities require envisioning of a new level of digitalisation, with plants increasingly learning to operate without operators, according to Arup Sen, Head of ABB’s Power and Water business in Asia.

“Right now, there is already the possibility of remotely controlling and monitoring a power plant that is not easily accessible, due to geographical or environmental reasons. All the data is fed into the main control centre. Remotely, experts can access the plant for their day-to-day tasks.

“For a plant to run unmanned, the vast amount of data collected on-site needs to be analysed and integrated with the latest Internet of Things (IoT) technologies, enabling the plant to predict and plan. An example might be predicting and planning for the next maintenance activity, based on the result of data analysis, self-learning and artificial intelligence,” said Sen. Along with data, a complex correlation of different parameters for smooth operations is key to achieving such a “self-healing” power plant. ABB has the required expertise to understand this and

The factory of the future An autonomous power plant is possible only with the integration of IT technologies such as smart sensors, big data, cloud computing, artificial intelligence (AI) and augmented reality, and OT technologies such as advanced pattern recognition software, machine learning capabilities and AIassisted predictive maintenance software.

ABB, a major player in the power generation business for more than 130 years, has been the partner of choice for many of the world’s top utility companies as they embark on their digital journey.

10 ASIAN POWER

support optimal improvements for the future.

ABB, a major player in the power generation business for more than 130 years, has been the partner of choice for many of the world’s top utility companies as they embark on their journey toward autonomous operations.

Implementing control systems After years of research, ABB has identified the optimal stages for running a self-healing power plant. “Firstly, it must have a world-class control system that runs application software that uses function codes and algorithms best suited to the utility. The next step is that the best process engineers to tune the plant to be fully automated and to run in the best fit curve of performance,” explained Sen. “Data capture must come with long-term historization and data analysis. Fortunately, today we hold the power in computing both in terms of hardware as well as software to handle enormous amounts of data, run complex algorithms, AI and machine learning.”

A strategy of implementation must be in place so that the control system and the system atop learn from their own best practices, operate based on them, and send essential monitoring data and information to a central place so that necessary actions can be taken when required.

For a developer, this presents a picture of better efficiency and hence cost benefits and higher ROI. “With feed-in information about market data,

CO-PUBLISHED CORPORATE PROFILE

these may all be possibilities with how autonomous power plants can operate,” Sen said. “Some examples of such ‘feed-in information’ include market level fuel price, emission control standards and grid requirements. These may suggest optimal periods to purchase fuel or switch fuels, optimise combustion efficiency and performance and improve grid stability when it comes to integration with renewables. Grid stability may be improved, for example, by balancing peak load demand and generation capacity.”

Even though a plant has a distributed control system (DCS), often it may run on manual mode or even in auto mode, with loops not tuned to provide the best benefits. ABB Ability™ Performance Optimization for control loop tuning uses control data already gathered, analysed and stored to quickly identify issues, so that corrective tuning can take place to fully use the control system and availability of a production process.

“It gives process engineers the ability to create accurate models to predict events, so they can reduce or eliminate potentially disruptive process bump tests in control loop tuning, enhancing operational efficiency,” Sen explained.

OEMs develop equipment based on principles encompassing the capabilities of AI and software and build in all required algorithms for selflearning, self-operation, self-maintenance, selfoptimisation or ordering for routine maintenance, service or spare parts. With the capability built-in and machine learning from the operation data, virtual power plants are only expected to be more powerful and efficient.

ABB Ability™ – sparking transformation From device to edge to cloud, ABB Ability™ is the company’s all-in-one digital platform that can give utilities valuable insights into asset and plant performance, enabling greater visibility and control over machines, systems and facilities.

ABB has established ABB Ability™ Collaborative Operations Centers across the globe, with ABB experts remotely monitoring plants and processes, collecting real-time data on assets and systems, and providing actionable information that can help minimise unplanned downtime, lower operational and maintenance costs and optimise plant reliability and safety.

Solutions for utilities can send notifications when assets or processes are not performing optimally, prompting action from either ABB experts or plant operators. According to Sen, ABB is supporting a shift from reactive-based maintenance to condition-based predictive maintenance, potentially resulting in timeand cost-savings for utility companies.

“One such remote services solution helped a customer lower boiler start-up costs by as much as 15%, saving over $175,000 annually, improving efficiency, and reducing NOx emissions by 5-15%.

Another solution will allow a major city in Vietnam to supply clean drinking water and reduce leakage in its water distribution network from 30% to 10% over a five-year period,” he shared.

Solutions for utilities also provide optimisation for virtual power plants and correlation of day-ahead load schedules with updated actual load schedules of the units, forecast deviations, intra-day trading

of free capacity, and disturbances/downtimes for each Balance Group in the district. The additional scalability of the system allows thousands of units and customers to implement their own models.

Solution-based data optimisation Moreover, the solutions for utilities allow better prices for produced energy on the spot and derivatives markets, as well as optimised internal production. They also enable a lower cost of energy compensation and an improved fulfilment of the nominated load schedule. Balancing the infeed of renewables before balancing costs are generated is also made possible. A major challenge on the road to autonomous plants of the future is government regulations, which are particularly stringent when it comes to granting permissions for fully unmanned facilities for nuclear and thermal power plants.

Sen shared, “This is evident, for example, where there are several metrics to be considered, including high pressures and temperatures that might contribute to catastrophic accidents in the absence of human operators or control.”

Getting ahead of challenges On the other hand, authorities’ regulatory support is also instrumental in the survival and longevity of a power plant. It is necessary to be prepared to keep up and get ahead of constantly changing regulatory frameworks and the key risks associated with virtual power plants.

Cybersecurity is one of the major contention points for virtual power plants that are being regulated and monitored by authorities. Other aspects of regulation may also include the energy pathway to the end users, incentive schemes for older power plants compared with new ones that may operate in the same grids and such.

Pertinent also to power plant developers is the slow but steady withdrawal or reduction of government control and subsidies in the sector. This is expected to transform a lot of traditional patterns

as new solutions are becoming increasingly available, like the autonomous running of power plants.

“Whilst renewable energy growth is on the fast track, intermittency has been a key factor in the instability of the grid. This is being addressed through generation scheduling impacting grid stability, where generation mix and intermittency and fragmentation is an issue,” said Sen. In response, traditional plants must catch up quickly to stay competitive and relevant.

“ABB is continuously revamping offerings to keep up with and complement constantly changing regulatory schemes that assure safety and endurance of the autonomous power plant. This is driven by new strategies that have to keep evolving with new regulations and developments in the sector,” said Sen. An autonomous future for utilities in Asia With over 7,000 distributed control systems, ABB has one of the largest installed base of control systems in power generation worldwide. The company is piloting and testing new technologies that use AI and machine learning, with a goal of making ABB solutions more intelligent and enabling safer and more secure operations of utilities in Asia and more widely.

Sen said, “Dedicated research and development centres have been set up closer to customers and internationally to work on big data and AI solutions that can allow utility operators and ABB experts to monitor power and water plants from remotely located control rooms. This work-in-progress technology can enable ABB engineers to interact with on-site assets, using advanced video systems to coordinate with utility customers in their facilities.”

ABB, which has been installing digital solutions for customers for over 40 years, is ready to customise its technologies for utilities in Asia, as the continent’s population continues to grow, demand rises, and end users depend on reliable, safe and uninterrupted power and water supply.

With over 7,000 distributed control systems, ABB has one of the largest installed base of control systems in power generation worldwide.

ASIAN POWER 11

FIRST

$6.5b of coal assets stranded

utility-scale solar projects to take off

Marginal cost of Vietnam’s coal fleet

indonesia

V

vietnam

ietnam is urged to create a retirement schedule for its coal-fired power plants in order to avoid risking $6.5b of stranded assets, which is equivalent to 2.7% of its GDP in 2018, according to financial research firm Carbon Tracker. Stranded asset risk is the difference between the cash flow that utilities may receive in the current power market and what they would receive in a below 2°C scenario, which sees capacity closed prematurely to meet the goal in the Paris Agreement.

Plans for 32GW of coal Regulatory structures effectively guarantee coal generators’ high returns, Carbon Tracker said. Beyond the operating coal units and the new coal units under construction, Vietnam also intends to build a further 32GW of coal capacity. The firm argued that coal in Vietnam could be economically obsolete over time when renewables outcompete new, under-construction, and existing coal and when new firm or dispatchable renewables outcompete existing coal.

It is expected that it will be cheaper to invest in new solar PV than new coal and new onshore wind by 2020 and 2021, respectively. “These changing cost dynamics post a significant stranded asset risk if plant WATCH

Source: Carbon Tracker

investors and policymakers decide to go ahead with the 32GW of coal capacity in the project pipeline,” Carbon Tracker said.

Moreover, it could be cheaper to build new solar PV and onshore wind than operate existing coal plants as soon as 2022. Both solar PV and onshore wind deployments in Vietnam have experienced cost reductions over the past four years, declining around 50% and 30%, respectively. The challenge for policymakers at this point is no longer whether renewable energy will be the least-cost option, but rather how to integrate wind and solar to maximise system value, it added.

“Vietnam should stop investing in new coal now and plan to develop a retirement schedule for the existing coal fleet. If policymakers remain committed to coal power the nation will face a dilemma: continue to subsidise coal generators to maintain their financial viability, or keep tariffs artificially low to shelter consumers from higher costs,” the firm said.

Both solar PV and onshore wind deployments in Vietnam have experienced cost reductions over the past four years, declining around 50% and 30%, respectively.

Australia-Singapore link greenlighted

Bankruptcy hits Datang’s coal plant

Medco sells 49% of geothermal plant

australia

china

indonesia

Sun Cable’s Australia-Singapore Power Link (ASPL) has been awarded ‘Major Project Status’ by the Northern Territory government.

The proposed Australia-Singapore Power Link is a $19.16b, 10GW solar farm with a 20-30GWh storage facility near Tennant Creek. It will supply loads in the Darwin and Singapore markets via a high voltage DC transmission.

This is said to be the largest solar farm under development in the world, and will seek to supply long term, competitive, stably priced renewable electricity to the Darwin and Singapore markets.

A subsidiary of power giant Datang Group in the northwestern Gansu province that operates a coal-fired power station applied for bankruptcy and liquidation after a $2.39m debt default.

Datang International Power Generation Liancheng Power Plant in Gansu, which has a total installed capacity of 660MW, had total assets of about $86.54b (RMB594m) and $260m (RMB1.77b) of debt by end-May. Datang previously announced the bankruptcy of its Baoding Huayuan coal plant after it failed to pay out billions in debt.

PT Medco Energi Internasional Tbk is selling a 49% stake in its subsidiary Medco Cahaya Geothermal (MCG) to New Yorklisted Ormat Geothermal Power for an undisclosed amount.

MCG owns a 110MW geothermal power plant in Blawan-Ijen, East Java, which is under a power purchase agreement with PLN for 30 years. The project is currently still in the development phase and commercial operations are expected to start by the end of 2022. MCG is entitled to a 35-year geothermal concession.

12 ASIAN POWER

I

ndonesia will be one of the key drivers of solar installations in Southeast Asia, which is expected to have electricity consumption growth double the rate in China. Dieter Billen, principal at Roland Berger, talks about the types of solar projects set to take off in the country.

What opportunities and challenges lie ahead for solar power developers in Indonesia?

The biggest opportunities are utility-scale solar projects. If you have a large-scale utility-scale solar, especially in economies of scale, you can have competitive solar production costs.

Besides that we also see opportunity in corporate and industrial (C&I), basically providing solar generation to corporate and industrial clients, but also the Googles or Facebooks of this world. Third opportunity: rooftop solar, and finally decentralised solar opportunities for areas that are currently still off-grid.

What is your outlook on solar power in Indonesia?

Solar power is only one key development across the region and in Indonesia. Another major booming source is gas given the availability and the abundance of gas at cheap prices. That’s why solar and renewables, in general, are very complementary with gas; it perfectly fits together.

These are exactly the two major trends that are occurring right now in the region.

We are very confident of the deep potential for solar power across in Southeast Asia. This is driven, first of all, by a boom in electricity consumption growth, which is expected to increase by 3.2% per year, that’s double as fast as China. This will require massive capacity additions across the region and we believe that renewables and in particular solar can be very promising opportunities to fill that gap.

At its current state, can solar power go beyond its intermittent nature?

This is one of the biggest challenges is the flexibility, the variability of solar power. There are different solutions for it. One is relying on other kinds of baseload, for example, gas, which is very complimentary and a very good solution to complement solar.

Other developments that we see is improving battery and other storage technologies, which are very new or emerging technologies. The price of batteries are going down tremendously, so this also provides fair opportunities to increase the share of renewables. But of course, in the short term, there are limitations to the percentage that solar power can have.

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FIRST

Subsidy cuts deal blows to rise of solar PV china

China installed 172GW of solar power in 2018.

A

midst China’s move to encourage subsidyfree development of power projects and slowly let go of its expensive feed-in tariff (FIT) regime, solar power capacity additions are expected to moderate the rest of the year, according to analysts. In 2018, solar photovoltaic (PV) additions fell to 44.3GW, from a record 53GW in 2017, triggered by a reduction in subsidies.

By the end of 2018, China accounted for 35% of global solar capacity, with 172GW, and 32% of total wind capacity, with 181GW. “However, as it moves away from its expensive FiT regime towards unsubsidised energy, the rate of solar additions is likely to moderate, according to analysis from Fitch Solutions, whilst those from wind are likely to increase,” Alex Zhu, EY’s Greater China power & utilities market segment leader and partner for corporate finance, explained.

Fitch Solutions estimated that solar capacity will grow at an annual average of 36GW between 2019 and 2028.

Cut off from solar Chinese developers are not being cut off from subsidies entirely yet, Zhu noted. “In solar, regulators are once more approving groundmounted projects, after halting approvals in June 2018 in a bid to reduce subsidy bills, at which point there was a backlog of at least $18b (RMB120b) in unpaid subsidy payments, and to achieve lower curtailment levels,” he added.

According to Citigroup, China is expected to allocate around $400m (RMB3b) of subsidies to solar projects in 2019, and it forecasts 42GW of new capacity under its base case, with the potential to rise to 50GW. Meanwhile, the Chinese government reportedly continues to support wind energy through its FiT regime, although rates are continuing to decline. Since 2017, the tariffs have decreased by 5% to 15%, depending on an area’s wind resource. Authorities are also actively supporting its offshore wind sector, which continues to qualify for attractive subsidies.

Wind is expected to grow at an average of 23GW/year. China added 20.6GW of new wind power in 2018, compared with 15GW in 2017.

The government is also promoting subsidy-free renewables projects as technology costs fall, EY noted, with the National Energy Administration (NEA) proposing to set up an auction system, backed by 20-year offtake contracts, guaranteed grid connections, lower transmission fees, protection against curtailment, and eligibility for an expanded green certificate programme, amongst other things. “Qualifying projects would be expected to sell power at the same price as nonsubsidised coal-fired plants,” Zhu added.

Fitch Solutions added that crucial to the success of unsubsidised projects will be China’s ability to reduce wastage.

Despite subsidy cuts which dramatically stalled the growth of solar installations, China retained the global distinction as the most attractive renewable energy market in 2019, according to EY’s latest Renewable Energy Country Attractiveness Index (RECAI) report.

The report found that whilst policymakers in China have reversed course on some of their harshest moves to slow the sector, they are also moving forward with measures to encourage subsidy-free development, demonstrating the growing viability of clean energy technologies.

procurement delays indonesia

Nadia Soraya, HHP Law Firm partner

I

n an exclusive interview with Asian Power, Nadia Soraya, partner at HHP Law Firm, discusses the delays in Indonesia’s procurement processes for renewable energy projects.

What are the biggest hurdles in the development of renewables in Indonesia?

At the moment, from a regulatory perspective, it is related to the procurement process of renewables which has been delayed for two years. Although results came out a few months ago, it has been two years since the project for renewables.

Why do these regulatory hurdles exist?

Historically, because it’s been there. I think it’s more of the need for synchronisation between what the business needs as well as what the government needs to do in terms of accommodating what’s in the market. I think what needs to be done is for there to have a discussion amongst the stakeholders, the key players, as well as the government.

How should Indonesia change its approach on renewables in order to resolve its issues?

It’s more on making the regulations more lenient towards renewables, more stringent especially with respect to the procurement rules as well as tariff. Tariff is also an important thing. It would be less attractive to investors, in addition to other regulations which limit the capability of investors to invest in Indonesia.

MALAYSIA

Thermal power capacity to grow by 5GW in 2019-2030 as public resistance to nuclear power mounts

T

hermal power capacity in Malaysia is expected to significantly grow by 5GW in 2019–2030 to meet increasing consumption, and nonhydro renewable power is estimated to follow with a 2.8GW capacity addition during this period, according to analytics firm GlobalData. This growth will be driven by an immature renewable power market and strong public resistance to the proposed adoption of nuclear power.

Harshavardhan Reddy Nagatham, GlobalData power analyst, commented, “Progressive economic reforms and a continuous increase in industrial activity are expected to boost economic progress in Malaysia, driving the country’s GDP at a compound annual growth rate (CAGR) of 4.8% during the forecast period. In addition, an increasing population will result in a significant increase in electricity consumption.”

As of 2018, gas-fired thermal power dominated the country’s power portfolio, with a share of 43% of the total installed capacity. Coal and oil followed with a share of 30.4% and 5.9%, respectively.

Whilst hydropower held a 17.2% share, other 14 ASIAN POWER

renewables together accounted for less than 4% of the total capacity.

The government had considered adopting nuclear power in order to establish energy independence and at the same time avoid greenhouse gas (GHG) emissions. The government also set up a Nuclear Power Development Steering Committee and deployed three working groups to plan and coordinate the development of nuclear power.

“Due to wide public resistance over the idea, the plans did not materialise and may not see traction anytime soon. This leaves renewable power as the only other option to generate electricity without increasing GHG emissions,”said GlobalData.

The share of thermal power is estimated to decrease slightly from 79.2% in 2018 to 71.2% in 2030; whilst that of non-hydro renewable power is estimated to increase from 3.6% in 2018 to 8.7% in 2030. In the meantime, the country will continue to embrace and develop its thermal power capacity in order to meet the growing demand for electricity, Nagatham said.

Cumulative installed capacity by fuel type (%)

Source: GlobalData

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We are leveraging the lessons learned and regrets from the Fukushima Nuclear Accident as we move forward with preparations to recommence operation of the KashiwazakiKariwa Nuclear Power Station, which will only be done after all safety requirements have been fulfilled.

Tomoaki Kobayakawa CEO Tokyo Electric Power Corporation (TEPCO)

CEO INTERVIEW

Japan doubles down on nuclear overhaul for $6.33b TEPCO CEO Tomoaki Kobayakawa talks about using robots to assist in the cleanup of the Fukushima Daiichi’s reactors, improving the safety of the Kashiwazaki-Kariwa power plant, and the lessons they learned in operating nuclear plants.

E

operators more efficiently than we could on our own.

ight years after the Fukushima Daiichi accident, TEPCO is still working to decommission the power plant and upgrade the safety measures of its other plant Kashiwazaki-Kariwa, all whilst meeting Japan’s increasingly strict compliance requirements. This has cost Japan’s power giant a total of $6.33b (¥680b), TEPCO CEO Tomoaki Kobayakawa said in an interview with Asian Power.

Following the backlash of the 2011 accident, the power giant has learned its lesson as it treads more carefully in its bid to harvest power from nuclear sources. Kobayakawa talked about the robots they are using as part of the decommissioning, their plans to recover the nuclear safety costs they’ve accumulated over the years and as well as diversification into renewables which could bring 2 to 3 million kW of capacity into Japan’s energy mix.

Do you still plan to invest in nuclear in the future? What is your outlook on nuclear power in Japan?

We look to nuclear power as a way to provide low-CO2 electricity in an inexpensive and stable manner to our country with few natural resources. We are leveraging the lessons learned and regrets from the Fukushima Nuclear Accident as we move forward with preparations to recommence operation of the Kashiwazaki-Kariwa Nuclear Power Station, which will only be done after all safety requirements have been fulfilled. In regards to the Higashidori Nuclear Construction, we are continuing to examine the possibility of a co-venture with other operators whilst at the same time building a strong relationship of trust with the community.

The government’s long-term energy supply/demand forecast indicates that nuclear power accounts for 20% to 22 % of the demand in the year 2030. So, we consider that nuclear power in Japan would be promoted in accordance with this policy.

Can you walk us through the process of removing the fuel from the Fukushima Daiichi? Which safety standards are in place?

TEPCO is taking a step-by-step approach to fuel debris removal which allows us to flexibly adjust our direction based upon the information we obtain in the course of work done in accordance with the Mid- and- Long-Term Roadmap stipulated by the government. We plan to begin removing fuel from reactor units 1 to 3 during 2021.

To date, we have conducted various investigations needed to remove fuel debris, such as using robots to obtain visual images of the conditions inside the containment vessels. Moving forward, we plan to take small samples of deposits from the bottom of the containment vessels of Units 1 and 2 in order to ascertain the nature of fuel debris. When we begin removing fuel debris in 2021, the information obtained through such investigations shall be used to start the task on a small scale after which the scale of fuel debris removal shall be gradually enlarged.

As we engage in these activities, we are paying special attention to managing the exposure doses of workers, and preventing any discharges of radioactive substances to avoid any impact on areas outside the site from the perspective of the physical protection of nuclear material. Each project we engage in is executed only after consulting with, and receiving permission from, regulatory agencies based upon the stipulations of the Nuclear Regulation Authority so as to ensure safety when engaging in each and every task.

How does TEPCO plan to support baseload power requirements and government generation targets in the coming years?

Nuclear power is a vital energy source for not only meeting baseload power demands but also fulfilling the 3E’s. Nuclear power can also achieve the S component of the “3E+S” strategy for energy sources, and it is expected to account for 20% to 22% of Japan’s supply/demand in the year 2030 according to long-term forecasts. Japan’s greenhouse gas-causing emission reduction goals are a reduction of -26% compared to FY2013 levels by FY2030, and -80% by 2050.

TEPCO believes it is important to sustain a certain level of nuclear power in consideration of the fact that renewable energies alone will not allow us to achieve these goals even if we are able to promote and spread the use of multiple renewable energy sources. Therefore, it is necessary for TEPCO to work together with other companies and address various issues, such as the cultivation of engineers.

Can you share with us the progress of your work on offshore wind in Japan?

Over the next 10 years, TEPCO aims to develop offshore wind power plants with a capacity of between 2 to 3 million kW. We are performing seabed ground surveys off the coast of Choshi, which is a candidate location for an offshore wind farm, in order to examine the feasibility of such a project.

TEPCO and Ørsted A/S, the world’s leading offshore wind developer, have signed a memorandum of understanding in January 2019 to work jointly on offshore wind projects.

How have rising costs for nuclear standards affected the company’s performance and metrics in the past few years?

TEPCO is steadily moving forward with safety measures at Kashiwazaki-Kariwa based upon the lessons learned from, and regrets over, the Fukushima Daiichi Accident, and we’re earnestly complying with all new regulatory requirement compliance inspections. At current time, we estimate that the cost to the company has been a total of approximately ¥680b.

How does TEPCO plan to recover the rising cost of nuclear safety standards?

TEPCO and the entire TEPCO Group are engaged in thorough cost-cutting initiatives. In the Nuclear Power Division, we are dealing with these cost increases by implementing kaizen activities to improve safety and quality whilst also engaging in initiatives to double productivity and cut costs.

We are also taking advantage of the Atomic Energy Association (ATENA), which examines safety improving-related technical issues common to the nuclear power industry. This enables TEPCO to resolve issues common to all nuclear power

Over the next 10 years, TEPCO aims to develop offshore wind power plants with a capacity of 2 to 3 million kW.

What can we expect from TEPCO’s venture into renewables?

In particular, we look to achieve the following: • Develop technical prowess to address the risks associated with unique weather conditions (earthquakes, typhoons, etc.) in the Asia-Pacific region, such as technology for developing floating wind turbines.

• Establishment of a business that benefits not only the power production side but also the demand-side user. We hope to contribute to the creation of a value chain that extends all the way to the consumer by investing in the demand/supply adjustment field, and selling renewable energies to RE100 member companies, for example.

ASIAN POWER 17

ANALYSIS: India’s solar target

Solar power capacity additions of 48-50GW are to be expected between 2019 and 2023.

Dark clouds over India’s 100GW solar target The slowdown in India’s solar capacity additions are caused by inconsistent government actions, argues CRISIL Research.

S

olar power capacity additions of 4850GW are to be expected between 2019 and 2023, according to a report

by CRISIL Research. However, developer sentiment has been negatively impacted by the lack of clarity on several policy issues and arbitrary bid cancellations, which is contrary to a supportive policy stance from the government.

Whilst previously tendered capacities continued to be commissioned apace, certain risks to future project implementation manifested. There were frequent bid cancellations, lack of clarity on GST procedures, and cost pressure from the imposition of the safeguard duty on imported cells/modules. Whilst GST clarity was lacking for over a year with a final decision taken in December by the GST council, it ended with an increase in taxation compared to what was expected by the industry.

Similarly, the safeguard duty has turned out to be a double whammy of sorts, impacting costs of solar power projects and not resulting in any significant offtake for the domestic manufacturing sector.

This was coupled by cancellation of bids post auctions as state utilities/SECI found tariffs to be higher than expectations.

Close to 4.7GW was cancelled in such a manner over March - December 2018.

In such a scenario, CRISIL Research’s 18 ASIAN POWER

The safeguard duty imposition has affected project costs by 10-15% and consequently led to a rise in bid tariffs.

outlook factors in the prevailing market dynamics, where regulatory/policy support is itself emerging as a key risk.

Considering the current regulatory haze, outlook has been revised downward.

Further, adequate land availability, timely implementation of grid infrastructure, and the ability of players to raise low cost funds will also be crucial enablers.

Pricing impasse slows momentum The safeguard duty imposition has affected project costs by 10-15% and consequently led to a rise in bid tariffs.

Though exemption via change in law is available as an option for projects already bid out prior to the duty, the regulatory process developers have to follow has also turned out to be long and arduous.

Additionally, as fresh bid allocations factored in this increase in costs, there was much posturing by state utilities. Already allocated capacities were cancelled at the pre-power purchase agreement (PPA) signing stage. This lowered developer/ investor confidence, further discouraging participation in auction activity.

As a result, there is a pile-up of tenders in the market with frequent delays in auctioning due to poor bid response.

Consequently, the capacity addition pipeline has turned weaker for fiscals 2019 and 2020, as commissioning is

getting delayed.

Taxes and duties add to developer woes The GST imposition has increased taxation rates across all components required to develop a solar power plant.

For instance, pre-GST, solar modules were exempt from any additional custom duties and value added tax (VAT) in several key states. However, GST imposition now implies an additional IGST component (apart from existing BCD) on imports and CGST + SGST for modules procured domestically (replacing VAT/CST). This caused a rise in taxes (apart from BCD which is zero) from zero earlier.

Consequently, there was much confusion over the final tax rates applicable on a solar power project. The Ministry of New and Renewable Energy (MNRE) did issue a clarification last fiscal that entire solar projects should be taxable at 5%. However, if an engineering, procurement, and construction (EPC) contract included both supply and services it would be adjudged on a case-to-case basis.

This created further concern, as most projects were set up on an EPC basis, whether in-house or outsourced. The issue lacked clarity for over a year, until the GST Council in December 2018 clarified with regards to EPC contracts by setting a ratio of 70:30 of the entire value of the

ANALYSIS: india’s solar target Capacity additions subdued in April-December FY2019 (MW)

The duty has had a direct impact on capital costs raising it by 10-15%, despite module prices falling from 30 cents/Wp in March 2018 to 24 cents/Wp in December 2018.

•

Source: MNRE, CRISIL Research

EPC contract, where 70% will be taxed at 5%, and 30% at 18%, to factor in both the supply and service component.

This has caused much consternation in the sector as most projects are set up in EPC mode (both procurement and services). Even a simple supply order usually involves a service component, which would again attract the GST rates applicable to EPC contracts. The final tax rate works out to 8-9% instead of the earlier expected 5%, causing a cost increase of 3-4% on final capital costs.

The sector is also under pressure from an additional safeguard duty on modules, a key component in solar projects. The Directorate General of Trade Remedies imposed a safeguard duty of 25% on all imported cells/modules, except from developing countries (but including China and Malaysia) in July 2018, with the duty rate set to decline.

The duty has had a direct impact on capital costs raising it by 10-15%, despite module prices falling from 30 cents/Wp in March 2018 to 24 cents/Wp in December 2018. As a consequence, bid tariffs have moved up in the range of INR 2.7-2.9 per unit, to be able to sustain current capital costs of INR 34m-35m per MW. As the rate would be 20% from July 2019, it would give developers who participate in auctions post January 2019 the leeway to procure when the rate is lower. The same would hold true when rates go down to 15% after January 30, 2020. Hence, over the long term, once duty rates decline, as they should in a time bound manner, cost pressures would ease and tariffs would also start easing by ~510 paise per unit, ceteris paribus.

CRISIL Research expects that the duty trajectory, which outlines a decline in safeguard duty rates over a two-year period, would help in lowering cost pressure. But this again has to be coupled with regulatory support that recognises prevailing market dynamics.

There are other issues as well, where overall policy coherence from the

government is imperative. On one end, there is ample government support in terms of allocations and incentives, on the other, confusion has been created by policies under other government agencies.

Supportive policy delivery crucial For instance, clarification on the GST procedures and its implementation for solar was not forthcoming for over a year, impacting commissioning schedules and project costs across developers. However, the outlook still remains fairly positive for the sector as the government remains ambitious about its fiscal 2022 target.

Further, recent amendments have provided fillip for the renewable energy market in India. One, is the upward revision in solar Renewable Purchase Obligation (RPO) achievement target from 8% earlier to 10.5% by fiscal 2022 (Ministry of Power notification dated 14th June 2018). Two, is the waiving off of the interstate transmission charges and losses on solar power until fiscal 2022. As earlier emphasised, implementation and enforcement of these policies remains critical.

A few key schemes that will drive additions are: • NSM: Under NSM Phase II, Batch III and Batch IV, the Solar Energy Corporation of India (SECI) has tendered out ~6GW of capacities (150MW pending allocation) through its state-specific viability gap funding scheme. Of this, CRISIL Research expects ~2.2GW to be commissioned over fiscals 20192021.

• Other central government schemes: The SECI has also started tendering and allocation under the Inter-State Transmission System (ISTS) scheme, wherein projects are planned for direct connection with the ISTS grid.

Under this, the SECI has already allocated 2.6GW and another 1.2GW is in the tendering phase.

Besides, it has allocated ~800MW

•

•

of wind-solar hybrid projects in December 2018 and floated another tender for ~1.2GW. Yet another ~1.2GW has been tendered/allocated

by SECI under various other schemes outside of JNNSM. State solar policies: Given the central government’s thrust, states have also come out with aggressive targets to be achieved by FY2022 under their respective solar policies. Whilst ~6.7GW is under construction based on already allocated schemes, another ~7.5GW is expected to be tendered and allocated over fiscal 2019, based on upcoming tenders under various state policies as on July 2018.

Public sector units (PSUs): The government is also encouraging cash-rich PSUs to set up renewable energy projects. NTPC has already commissioned ~870MW of capacity and has tendered/ allocated another 2,750MW. Similarly, Indian Railways has committed to 5GW of solar power by FY2025. Other PSUs, including National Lignite Corporation (NLC), National Hydroelectric Power Corporation (NHPC), defence organisations and government establishments, are also expected to contribute.

Rooftop solar projects: CRISIL Research expects ~8GW of rooftop projects to commission by fiscal 2023, led by high industrial and commercial tariffs and declining levelised cost of energy for solar rooftop projects. The capacity addition would be supported by improvement in discom infrastructure, continuation of net metering regulations/ benefits, and other regulatory incentives.

Whilst, commissioning is expected to slowdown in FY2019 due to the impact of the duty and GST issues, FY2020 is weak due to delay in auction as several tenders got delayed/cancelled. However, FY2020 onwards, additions are expected to pick up due to several factors: Subsiding of/ removal of the safeguard duty would ease cost pressures; commissioning of capacities auctioned with amended commissioning schedules of 21-24 months coupled with tenders now allocated with schedules of 15-18 months and aggressive tendering expected prior to FY2022 which is milestone year.

However, consistent regulatory support, adequate land availability, timely implementation of grid infrastructure, and the ability of players to raise low cost funds are key risks which constrain the outlook. From “Cloud over 100 GW target” by CRISIL Research ASIAN POWER 19

country report: hong kong HK Electric echoed this positive sentiment and said, “Natural gas will become the primary fuel for our power generation. The new offshore LNG terminal project will enable us to mitigate fuel supply risk and to have direct access to the international market for costcompetitive LNG supplies.” It added that it expects that natural gas generation in its overall fuel mix will increase to ~70% by 2023 from ~30% at present.

The government is introducing more gas and renewables into the energy mix.

Can renewables and gas support a coal-free Hong Kong?

With the aim to cut coal reliance, HK Electric and CLP Power are building an offshore LNG terminal and have introduced feed-in tariff schemes that are gaining interest.

P

rogress is underway for Hong Kong’s first offshore LNG terminal, a joint venture between Castle Peak Power Co. (CAPCO), which is owned by CLP Power, and Hong Kong Electric Co. (HK Electric). In June, the joint venture inked an agreement with Japan’s Mitsui O.S.K for the charter of a Floating Storage Regasification Unit (FSRU) for 10 years.

In April, CLP Group told Asian Power that they have received the environmental permit from the Government and that the public consultation on Foreshore and Sea-bed (Reclamations) Ordinance is underway. “Good progress has also been made in finalising the contractual arrangements for the supply of LNG and the chartering of the FSRU vessel for the project,” the company said.

Developments for the project continuously come as Hong Kong firms up its plans to import LNG for the first time, so as to reduce reliance on coal and reduce carbon emissions, said Fitch Solutions. “Efforts to develop LNG import capabilities in Hong Kong are spearheaded by billionaires Li Ka-Shing, who owns a 33.37% stake in HK Electric via his utility firm Power Asset Holdings, and Michael Kadoorie, owner of the city’s biggest electricity firm CLP Group, which holds a 70% stake in CAPCO.” Hong Kong’s LNG plans are also supported by external LNG market fundamentals. Fitch Solutions said, “The current prolonged downturn in spot LNG prices, next to projected ample supply over the next few years, makes it more 20 ASIAN POWER

Customers are incentivised to install solar photovoltaic or wind power systems at their premises for selling their renewable energy output at rates ranging from 38-64 cents per kWh.

palatable for Hong Kong to partake in LNG trading for the first time. The wide array of supplies available, coupled with market’s embracing of greater flexibility and diverse pricing exposure in LNG contracts, also lowers risk and increases leverage for buyers, such as Hong Kong, during negotiations with suppliers.”

Moreover, the soured trade relations between the US and China, and the latter’s shunning of energy imports from the former irrespective of cost, could also act to Hong Kong’s advantage, as uncontracted US LNG cargoes that would otherwise head to China seek new markets.

“Indeed, apart from Hong Kong, Myanmar, the Philippines, Vietnam and even Australia are set to become first time importers of the fuel within the next five years, both to complement domestic production and to meet growing demand,” Fitch Solutions added.

Hong Kong’s renewables push Apart from the growth of natural gas as baseload power in the city’s energy mix, the government is also targeting more renewables with the introduction of feedin tariffs (FIT) for renewables installations amongst developers and customers alike.

Under the FiT scheme, customers are incentivised to install solar photovoltaic or wind power systems at their premises for selling their renewable energy output at rates ranging from 38-64 cents (HK$35) per kWh. “Since the launching of our FiT Scheme in August 2018, the market response has been positive. We also observe that the PV industry has been much stimulated with the number of PV companies and practitioners participating in the local RE market substantially increased,” HK Electric said.

CLP Power said that since it opened applications in May 2018, they have received over 2,500 applications as at the end of March 2019. “Around 83% of the applications have been approved, and so far, 234 applications have been completed and are successfully connected to our grid to enjoy FiT. Despite the operational challenges, CLP endeavours to do everything possible to support the development of RE in Hong Kong,” the company said.

HK Electric projects that the local RE market will grow healthily and the number of distributed grid-connected RE systems on customer side will increase notably. “At the end, a vibrant RE market will help further decarbonise local power sector and help Hong Kong combat climate change,” it said.

Hong Kong - % share of electricity generation

Source: Hong Kong Climate Action Plan 2030

ASIAN POWER 21

country report: taiwan

Taiwan aims to cut coal dependency to 30% and be nuclear-free by 2025.

Renewables strain could shatter dreams to exit coal and nuclear Despite having the largest project pipeline for offshore wind in Asia, Taiwan is threatened by supply issues and uncertain commercial operation dates.

W

hilst Taiwan aims to cut down its coal dependency to 30% and achieve a nuclear-free target by 2025, some are skeptical that the renewed focus on renewables—particularly on offshore wind projects that are expected to fill the generation gap left behind by nuclear and coal by mid-2020—will be enough to pick up the momentum.

The nuclear phase out and coal reduction appear to be stressing on the Taiwanese grid with increasing power demand, with gas fired power stations and LNG terminals struggling to come online on-time, Zi Sheng Neoh, principal consultant at Wood MacKenzie, told Asian Power. “As well, the commercial operation date (COD) of CPC’s Taoyuan’s LNG import terminal remains uncertain, whilst Taipower’s 1,000MW gas-fired power stations in Tatan may potentially face gas supply issues,” she noted.

According to Daine Loh, analyst for Fitch Solutions, Taiwan’s electricity market is increasingly strained, and have faced increasing risks of shortages and rising electricity prices.

She highlighted how in August 2017, Taiwan experienced a significant power 22 ASIAN POWER

The commercial operation date (COD) of CPC’s Taoyuan’s LNG import terminal remains uncertain, whilst Taipower’s 1,000MW gasfired power stations in Tatan may potentially face gas supply issues.

blackout which affected nearly seven million households and also hit offices and factories on the island. Whilst the outage had a limited impact on industrial consumers and power was restored fairly quickly, the blackout has threw Taiwan’s energy security into the spotlight. “This has been largely a result of the reduction in coal and nuclear power generation, with the inability to replace it quickly enough with alternative sources,” she said.

Higher electricity rates The country’s electricity consumption is projected to edge up 1.86% annually from 2018 to 2025, with electricity prices forecasted to jump 29% to $0.11/kWh by 2025, the Ministry of Economic Affairs revealed. The estimated 1.86% annual growth was an upward revision from the 1.26% forecast by the ministry in 2017 after factoring in large scale investments in the semiconductor sector, more overseas Taiwanese businesses returning and investing at home, climate change, and the emergence of electric vehicles.

Following along this forecast in April, the electricity rates for the country’s 1.91 million households and 170,000 small

businesses witnessed an average hike of 3% or $0.09 (NT$2.6253)/kWh. “Given that Taiwan has limited experience in the sector, it requires more investments from foreign companies which increases costs in the short term, hence the backlash from developers as they are potentially facing higher costs than initially anticipated,” Robert Liew, senior analyst from Wood MacKenzie, said. In January, MOEA finalised its feed-in tariffs (FiT), slashing it by 5.71% instead of the proposed 12.71% to $0.18 (NT$5.516) per kWh for the next 20 years, prompted by fury from offshore wind developers concerned that the reduction in subsidies would threaten the viability of their projects.

Neoh added that as Taiwan undergoes a market liberalisation, in which the overall process may take up to eight to 10 years, Taipower will need to realign its long-term strategic plans as competition in the market stiffens up and customers gain access to open corporate power purchase agreements (PPAs). This could potentially corrode their earnings in the short-term as consumers move away from the grid (rooftop solar) or go into a direct corporate PPA with a renewable energy generator, he explained.

In January, Google signed its first PPA in Asia, inking a deal to purchase the output from a 10MW PV installation in Tainan City to power its Changhua County data centre on the island’s west coast. “This is the first step that has been taken in Taiwan to liberalise the power market and end the

country report: taiwan Taiwan power generation by fuel type

Zi Sheng Neoh

Daine Loh

Source: Fitch Solutions

monopoly by Taipower in the distribution of power. No doubt other large industrial customers, particularly those with zero emission policies, may follow suit as corporate PPAs would enable them to source power from a verified renewable energy source,” John Yeap, partner for Pinsent Masons, said.

But whilst market liberalisation may dampen the average costs of generation, it still will not shield consumers from the expected hike in electricity retail tariffs in the short-term as Taiwan moves away from coal and nuclear and transitions to LNG for power generation.

Denuclearisation delay “It’s a difficult balance for the government at a time when the national energy plan is to open up the power market. If power prices do not drop, expectations are that denuclearisation will be further delayed with less space for more renewables investments,” Neoh said.

Taiwan’s electricity generation is largely sourced from thermal sources such as coal and gas, which made up 83.6% in total of their power mix in 2019. MOEA’s Bureau of Energy also admitted that traditional power plants are still an important source of electricity in the country’s market, although a spokesperson for the agency stressed that it is fully committed to promoting Taiwan’s energy transformation to reduce the emissions of air pollutants.

“In the past few years, we have seen nuclear-power generation continue to decline, from 12.4% in 2016 to an estimated 9.7% in 2019, and this was replaced largely by gas and non-hydro renewables which have risen by 2.74% and 1.78%, respectively,” Loh said.

“We forecast the share of non-hydro renewables generation in the total power mix to rise from 4.4% in 2019 to more than 13% in 2028.”

According to Fitch Solutions’ Key Projects Database, Taiwan has the largest project pipeline for offshore wind in Asia,

amounting to 4.8GW, or 27% of the total project pipeline in Asia. That said, Loh noted that she does not expect all of it to come online.

Project pipeline flaws Yeap echoed this sentiment, adding that the hurdles facing power companies will be on ensuring that the various approved offshore wind projects they clinched can in fact be financed and constructed.

“As with developing power projects in any jurisdiction, the PPA is always vital for the lenders to determine the bankability of the project. The model PPA in Taiwan has many risks, for example there is no deemed COD, no protection for grid curtailment, no relief for force majeure, and lack of termination payment,” he said.

In terms of construction, Yeap explained that with the Taiwan strait still being a relatively new area for developers, there is a shortage of vessels and experienced personnel. “As the supply chain is still being developed, it remains to be seen whether the projects will be constructed according to plan,” he commented.

He further highlighted how other challenges also remain on meeting localisation requirements, such as the recent suggestions that only locally flagged vessels should be permitted to be used for these projects.

“There are also ongoing concerns over the availability of transmission for the evacuation of the offshore wind generation - a concern that will have to be addressed by Taipower if all the proposed offshore generation is to be transmitted through the transmission and distribution network,” he noted.

Coal and nuclear still dominant Following the country’s No. 8 referendum, which asked ‘Do you agree that Taiwan should establish an energy policy that undertakes not to construct any new coal-fired power plants or generators or expand existing facilities (including

Robert Liew

John Yeap

the expansion of the Shen’ao Power Plant)?’, a majority of the population voted to reduce coal output and to stop the construction and expansion of coal facilities.

“However, at the same time, some government officials have defended the need for coal-fired power plants for grid stability and continued economic development in Taiwan, especially so given the economy’s dependence on industries such as semiconductor manufacturing,” Loh explained. Wood MacKenzie also forecasts that Taiwan’s coal generation would remain around 40% by 2025.

In November 2018, the Taiwanese electorate voted to repeal the Democratic Progressive Party’s (DPP) Nuclear PhaseOut Act, which stipulated that all nuclear power generation facilities ‘shall cease to operate by 2025’. The referendum was held together with the country’s local elections, with the DPP performing poorly and president Tsai Ing-wen’s resigning as the chairwoman of the DPP as a result. In May 2019, the Legislative Yuan amended the provision of the Electricity Act following the results of the referendum.

Another referendum proposal is also said to be underway to address the question of Taiwan’s fourth nuclear power plant, which has been stalled since 2014 due to public opposition.

“The result of the referendum must have caught the government by surprise. Now it seems that majority of the Taiwanese people prefer the commissioning of the fourth nuclear power plant and decommission some of the larger thermal power plants to reduce pollution, for example the 5,824MW Taichung Power Station, which was the largest thermal power plant in the world for a long time but now second largest.

Now that the voters have spoken, perhaps this is something the government will consider in the future,” Yeap said.

That said, Loh noted that the nuclear phase-down policy will continue for the time being despite the developments, as the government remains committed to achieving a nuclear-free Taiwan.

“Most notably, in February 2019, it was announced that the decommissioning of the Chinchan units will continue, and the operating licences of the Kuosheng and Maanshan units will not be extended.” Loh said. “The current licensing schedules align with our view, as they only enable Taiwan’s nuclear reactors to operate until 2025.”

The deletion of the relevant provisions in the Electricity Industry Law does not mean that the government has an obligation to actively promote nuclear power, it merely allows the nuclear power plants to be decommissioned later.

ASIAN POWER 23

sector report: geothermal

Government-regulated electricity tariffs are set artificially low, therefore restricting potential returns on investment.

Are Asia’s geothermal power targets too low?

Despite efforts to ease policies, geothermal leader Indonesia only uses up 2GW of its 29GW potential capacity.

I

ndonesia has been slowly but surely ramping up its geothermal power generation capabilities, especially in 2018. “With the third and final unit of the ADB-financed Sarulla geothermal power project, with a capacity of 320MW, coming online, Indonesia now has the world’s second largest installed geothermal power generation capacity after the US,” Yuichiro Yoi, principal investment specialist at Asian Development Bank’s (ADB) private sector operations department, told Asian Power.

This sentiment was echoed by a recent report by Fitch Solutions, which went as far as estimating that Indonesia could surpass the US as the world’s largest

Indonesia’s total geothermal generation is expected to average 9.2% YoY between 2019 and 2022.

Electricity generation by source, Japan 1990-2016

Source: IEA Renewables Information 2018

24 ASIAN POWER

geothermal market by 2022.

The report, which forecasted growth in Indonesia’s total geothermal generation to average 9.2% YoY between 2019 and 2022, noted that Indonesia’s location along a convergent tectonic plate boundary has made it ideally suited for geothermal power production.

“However, with 29GW potential the current 1.9GW is only a fraction of the country’s geothermal potential,” Yoi said. Fitch Solutions’ report also noted that despite the firm’s bullish outlook on the industry, its forecasts only represent about half of the capacity currently included in its key projects database for Indonesian non-hydropower renewables.

This reflects the global issue of the geothermal power sector, which requires a high initial capacity outlay required to explore and engage in high-risk drilling for potential resources.

Low geothermal tariffs The report underlined how governmentregulated electricity tariffs are set artificially low, therefore restricting potential returns on investment, and likely deterring risk-averse investors from entering the market. The landscape seems to have not changed much, as this sentiment was echoed by a 2015 ADB report, which added that efforts to scale

up renewable energy use, particularly geothermal energy, are constrained by implementation challenges, lack of capacity, environmental issues, permitting delays, and a history of low pricing.

“The challenges are related to the risks and financial burden associated with exploration to find geothermal resources,” Yoi said. “Anyone intending to develop a geothermal site has to spend tens of millions of dollars in exploration drilling without any certainty the resource exists, what its characteristics might be, and its commercial exploitability.”

By 2025, the country is targeting geothermal production capacity to reach 5GW. Plans to loosen foreign direct investment (FDI) restrictions are said to be underway, with FDI being able to reach up to 100% in 54 sectors. That said, there will be no change in respect to ownership (67%) of geothermal power generation of up to 10MW. Yoi noted that in order to expedite Indonesia’s untapped geothermal potential, ADB committed $175.3m for the second phase of another geothermal power project, the Rantau Dedap Geothermal power project, in March 2018. The project in South Sumatra is said to have a total capacity of approximately 90MW and will be implemented under a 30-year power purchase agreement (PPA)

SECTOR REPORT: GEOTHERMAL Global geothermal outperformers (capacity by country, 2018-2028)

Source: Fitch Solutions estimate/forecast, IEA, IRENA

with state-owned electricity distribution corporation PLN. He further added that there are efforts being made to support projects implemented by GeoDipa, the Indonesian state-owned enterprise in charge of geothermal development, on a sovereign basis. Earlier in July, PT Geodipa Energi conducted its groundbreaking ceremony for a planned 10MW small scale geothermal plant on the Dieng Plateau Geothermal Field in Central Java.

Two Indonesian geothermal power plants—the 55MW Lumut Balai plant and the 40MW Sorik Marapi plant— also went online in March 2019. The 5MW Sokoria geothermal plant is also expected to come online in H2 2019, whilst a project in West Sumatra, the 80MW Muara Laboh plant, is currently undergoing construction. Together, the four projects are expected to add up to 180MW of capacity to the national grid.

Philippines’ geothermal potential Further west, Yoi noted that the Philippines is another “Ring of Fire” country with considerable potential. The Philippines’ non-hydro renewable power capacity accounted for 16.9% of its total energy mix, led by geothermal, a report

by GlobalData revealed.

In its proposed Philippine Energy Plan 2017-2040, which aims to increase the country’s renewable energy installed capacity to at least 20,000MW, the Department of Energy (DOE) noted that around 16,949MW of potential renewable energy capacities are expected within the horizon - of which geothermal is expected to account for 684MW. In March, the DOE gave the green light to 11 power firms to proceed with the conduct of a grid impact study (GIS) on their respective planned power projects with over 1.2GW of capacity. This included the 120MW geothermal power project of Aragorn Power & Energy Corp in Pasil, Kalinga Province which announced almost two weeks later that it

was ready to start drilling.

“However, since the building of hydro and geothermal facilities usually takes three to five years, many are more excited about the prospects of solar facilities, which are easier to put up and scale, and are relatively unobtrusive,” the agency noted. GlobalData’s report also noted that the country’s cumulative installed capacity for geothermal is expected to drop to 4.5% in 2030, from 7.8% in 2018, as investors and developers turn to hydropower, wind and solar.

Elsewhere, other countries in the region are making moves to tap further into their geothermal potential. Japan fired up its first large-scale geothermal power station after 23 years in late May. The 46MW Wasabizawa geothermal power plant, a joint project between Electric Power Development (J-Power), Mitsubishi Materials Corporation and Mitsubishi Gas Chemical Company, had reportedly been in the works since May 2015.

The firms estimated that the country’s geothermal potential stands at 23.4MW, placing Japan at third place behind the US and Indonesia. The local government has also set a target of renewable energy sources supplying between 22-24% of electricity by 2030, with geothermal providing 1.6GW or 1% of Japan’s power.

Project pipe dream However, this looks to be a pipe dream compared to the current situation, with Japan having only installed a geothermal capacity of some 5MW, placing in 10th worldwide. “We think the target for geothermal is too low,” Tatsuya Wakeyama, a senior research fellow at the Tokyo-based Renewable Energy Institute, said in a report, adding that 2.6GW could be a realistic goal for 2030.

Meanwhile, Fitch Solutions noted that growing competitiveness in the research and design of low-temperature and lowpressure geothermal power generation technology has begun to present significant potential for medium-term

By utilising heat exchangers to vaporise specialised fluids with low boiling points in closed cycle, binary ORC units can generate electricity at temperatures as low as 70°C, considerably broadening the feasibly exploitable geothermal resources around the world.

growth in the market.

Recent innovation in the development of binary-cycle generation, which uses medium-high temperature water to heat a liquid with a lower boiling point than water, has reportedly significantly reduced the requisite temperature of geothermal resources. The firm noted in its report that ongoing innovations in binary organic rankine cycle (ORC) generators will offer a particularly pertinent bright spot for investors in the near-medium term.

Binary cycle generators “By utilising heat exchangers to vaporise specialised fluids with low boiling points in closed cycle, binary ORC units can generate electricity at temperatures as low as 70°C, considerably broadening the feasibly exploitable geothermal resources around the world,” the report’s researchers explained.

“With private-sector geothermal power corporations standing to gain significantly from broadening the availability and reducing the cost of geothermal power development around the world, we expect that this will become a key area of competition in the market. Furthermore, we note that this will pose a considerable upside risk to our geothermal power forecast in the medium-long term, as we only forecast a total of 4.2GW of capacity to be installed between the end of 2018 and 2028.”

As well, Yoi observed that one potentially interesting area is the development and proliferation of geothermal exploration insurance products to de-bottle-neck exploration efforts. “There seems to have been a few cases where such insurance was provided by insurance companies. If they can build a critical mass of portfolio to create diversification effects, and thereby bring down the still-very-expensive insurance premium, that could potentially boost the geothermal sector,” he said.

Philippines’ installed capacity by fuel type, 2018 and 2030

Source: GlobalData

ASIAN POWER 25

ASIAN POWER UTILITY FORUM: JAKARTA

Panel discussion in Asian Power Utility Forum’s Jakarta leg

Indonesia seeks 17GW of power projects to hit ambitious electricity supply targets But IPPs face regulatory hurdles that hamper the development of renewables and other energy sources.

A

t the Jakarta Leg of the 2019 Asian Power Utility Forum, executives as well as thought leaders in Indonesia’s massive power industry exchanged strategies that aim to address the country’s growing demand for power and push its ongoing electrification project into completion.

Indonesia has a project pipeline for 17GW of generation capacity designed to hit the targets identified by the Electricity Supply Business Plan (RUPTL), according to Dharma Djojonegoro, deputy CEO of Adaro Power. However, developing IPP projects in the past few years has been fraught with difficulties amidst policy changes, he said.

IPP challenges Indonesia’s IPPs are struggling to get new projects off the ground since the government changed its tender selection process in 2017. Under the new rules tenders are now being run

by PLN subsidiaries and often they are demanding a majority ownership stake whilst demanding the IPP puts up a majority of the equity.

Djojonegoro said that two years ago, state utility PLN decided to change its normal tender procedure. Under its new

26 ASIAN POWER

Under the new rules tenders are now being run by PLN subsidiaries and often they are demanding a majority ownership stake whilst demanding the IPP puts up a majority of the equity.

scheme, PLN will assign projects to its subsidiaries, PT Indonesia Power (IP) or PT Pembangkitan Jawa-Bali (PJB), which also have their own selection process for their partners.

“In recent projects, IP or PJB demand to own 51% of the project and ask the partner to finance most of the equity portion,” Djojonegoro said. “To be honest, it’s been very challenging for the past few years,” he added.

Another issue concerning IPPs is the recent trend in power purchase agreements (PPA) which are now given

by PLN for a shorter duration. “We’ve also seen a worrying trend in the latest PPAs. The take-or-pay commitment (ToP) is now reduced,” Djojonegoro said.

This means that PLN now only offers ToP commitment for the tenor of the senior loan, which previously was offered for the entire term of the PPA. “Previously it was up to 25 years, now the ToP is only offered for 10 years or below,” Djojonegoro added.

Moreover, for terminations caused by grid errors, PLN could only guarantee a return of 10% or less under the revised scheme. “Obviously, this is difficult for sponsors to accept even if the grid is completely out of power,” Djojonegoro

commented, citing that previous PPAs provided for 15% of sponsors’ return.

New procurement process Whilst coal-centric Adaro Power is mostly keen on exploring solar photovoltaic (PV) and other renewables, development is largely difficult due to PLN’s new procurement scheme or the DPT prequalification process (DPT), Djojonegoro said. This view was shared by Nadia Soraya, partner at HHP Law Firm, who noted that delays in the DPT have put development on hold and has even caused the two-year absence of renewable project tenders after the first DPT. However, it’s not only the DPT that’s hindering the installation of renewables in Indonesia. Soraya said that issues lie in the renewable tariff that, in practice, is still capped at regional electricity generation costs (BPP) even if regulations allow for B2B negotiation.

Hamstrung solar C&I projects Apart from the interest from IPPs, experts have observed an increased attention towards solar rooftop projects from commercial and industrial (C&I) businesses, especially from companies with facilities or partners in the country.

ASIAN POWER UTILITY FORUM: JAKARTA LNG IN EASTERN INDONESIA

Gas to fire up demand for power in Eastern Indonesia amidst generators’ low utilisation rates

S

tate power utility PLN and other gas companies are looking to procure facilities for breaking liquefied natural gas (LNG) and distributing it to Kalimantan, Sulawesi, and other islands in Eastern Indonesia. Indonesian gas company PT Energi Nusantara Merah Putih (ENMP) is developing an LNG bulk-breaking terminal on the regency of Bantaeng, which would be the first of its kind in Eastern Indonesia. The firm is banking on the growing electricity demand brought about by four nickel smelters being developed in the region and its status as a Special Economic Zone.

“In 2019, there will be 1.5GW of existing capacity across Eastern Indonesia that will need 101.7 billion cubic feet a day of gas. By 2025, it will be 2.5GW thanks to planned projects or projects in execution as we speak,” said Bret Mattes, vice president for gas of ENMP’s consultant Numada.

In order to hit this capacity forecast, there are 15 planned receiving stations in

Bret Mattes, vice president for gas, Numada

Solar rooftop C&I projects are expected to shed some load off Indonesia’s national electricity grid and become a captive power plant that independently powers a growing number of large industrial factories, which could grow to 9,000 in the next 30 years.

However, Indonesia’s C&I clients need to overcome various regulatory hurdles as the process for building projects and selling excess electricity to the grid is not as straightforward compared to other jurisdictions like Singapore and Australia.

Developers may find it hard to navigate complexities in the two prevailing models used for Indonesia’s solar C&I projects - the power purchase agreement (PPA) model and operating rental, Soraya said.

One delegate told Asian Power that a large American footwear manufacturer had plans for 15 factories worth of capacity but was insisting these had to be all 100% carbon-free powered, and that this was proving difficult to achieve in Indonesia.

As a consequence, they were examining the option of shifting to Vietnam.

As a general rule, all of Indonesia’s territories are franchise areas of state utility PLN, which has the sole mandate of selling electricity to these locations. The exception to this emerges with the PPA model, which entails that the factory site is “carved out” from PLN’s franchise area and turned into a business area for the factory only.

Consequently, the factory owner has to own the factory building and the solar rooftop plant. The factory owner

Solar rooftop C&I projects are expected to shed some load off the national grid and be a captive power plant that independently powers a growing number of large industrial factories, which could grow to 9,000 in the next 30 years.

Eastern Indonesia that will be supplied by LNG liquefaction plants. However, PLN and gas companies have to first resolve the existing issue of duel fuel generators, which are not fully serving their purpose.

“Those facilities will need that amount of gas (101.7 billion cubic feet a day), if they were being run on gas,” Mattes said. “They can run on gas or diesel. To date, they haven’t generated a single electron using gas,” he added.

Low utilisation capacity The existing generator sets have low utilisation capacity, which is currently below the typical 80%. Mattes said, “The daily low curves are up and down, and it makes it difficult to average more than 50% in most of the areas where these plants are located.”

Moreover, there’s a “cynical view” that PLN may have an incentive not to grow its business in Eastern Indonesia if the tariff that they’re receiving is below the cost. “Because they’re using diesel, they’re always losing money. There’s no incentive to take the capacity factor up to be more efficient or to use the grid more efficiently,” he added.

The levelised cost of power using diesel is about 60 cents per kWh. “It’s losing vast amounts of money on this deal,” Mattes said.

However, Mattes argued that PLN can raise the utilisation capacity to 80%. In order to meet this demand growth, Indonesia has to move away from gensets.

Mattes laid out potential infrastructure that can be built across Eastern Indonesia in the coming years. He raised the possibility of using receiving stations for plants with over 50MW capacity, which could have one to four storage tanks of 2,000-5,000 sqm of gas. “Small-scale regasification is relatively cheap and efficient,” he said.

With these facilities, Mattes said that the total cost across the LNG supply chain could fall within the range of 9.8-16.8 cents per kWh, with illustrative fuel costs at 7.6-13 cents per kWh.

will need to provide a reliable supply to everyone within the area and will be unable to buy power from PLN. Existing opportunities “Regulations tend to be changed very, very often in the last few years,” said Surya Darma, chairman of Masyarakat Energi Terbarukan Indonesia (METI).

In order to keep regulations in place, organisations including METI are lobbying to standardise regulations through legislation.

This was also raised by Dieter Billen, principal at Roland Berger, who said that Indonesia is one of the Southeast Asian countries that lack ambition in terms of renewable energy and have no clear targets in spite of projections that estimate power demand to grow 3.2% to 3.8% yearly, nearly double of energy giant China.

Mathieu Geze, head of Asia business

development at HDF Energy, presented the concept of Renewstable, which attaches hydrogen storage to a plant with intermittent energy sources such as renewables, removing the need for traditional distribution facilities.

According to Geze, HDF Energy was able to raise their plants’ capacity factor to 8090%, much higher than 20% and above in renewables plants.

Aside from renewables, liquefied natural gas (LNG) also presents opportunities for addressing power demand especially in Eastern Indonesia, wherein geography issues make it difficult to build transmission lines and only portable gas-fired generation sets are present in remote islands. Bret Mattes, vice president for gas at PT Energi Nusantara Merah Putih, discussed the prospects of an LNG terminal in Eastern Indonesia that could promote energy security and bring down electricity costs.

Nadia Soraya, partner, HHP Law Firm

ASIAN POWER 27

ASIAN POWER UTILITY FORUM: kuala lumpur

Panel discussion in Asian Power Utility Forum’s Kuala Lumpur leg

Malaysia’s power companies revamp strategies for full market liberalisation As the possibility of new players in the market arises, utilities need to get ahead using pricing and customer services.

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t the Kuala Lumpur leg of the 2019 Asian Power Utility Forum, over 60 executives and decision makers from 25 IPPs in Malaysia’s power sector as well as players from Singapore strategised about structuring their businesses amidst market liberalisation and meeting the country’s energy demand.

Dr. Jochen Krauss, managing partner at Simon Kucher, said that market liberalisation will intensify competition and make it all the more challenging to maintain customer loyalty. He cited Germany’s situation post-liberalisation, in which the market share of the Big Four energy suppliers shrank from 85% in 2007 to 62% in 2015.

To stay ahead of rapidly changing industry trends, Krauss advised utilities to compete through a bipolar sales structure, in which B2B clients and mass customers are involved. “The first companies to transition and streamline their organisation will have a temporary competitive advantage and be able to gain additional market share,” he said.

Zhen-Hui Eng, sales manager, Energy Portfolio Management, ABB, shared how Malaysia is setting rules of liberalisation carefully through its incentive-based

28 ASIAN POWER

Malaysia is setting rules of liberalisation carefully through its incentivebased regulation (IBR), the Imbalance Cost Pass-Through (ICPT) tariff.

regulation (IBR), the Imbalance Cost Pass-Through (ICPT) tariff. Tenaga Nasional Berhad (TNB), Malaysia’s state utility, can still remain neutral as single buyers and grid system operators are ring-fenced whilst the ICPT reflects changes in fuel and generation costs in consumers’ electricity tariffs.

Krauss also urged utilities to digitise highly repetitive processes in order to improve the bottom line as well as improve their omnichannel sales approach, so that customers can expect touch points over multiple channels. “In the long-term, when full liberalisation takes place, organisational changes and pricing measures will come into focus,” he said.

Digitisation initiatives TNB’s chief retail officer Ir Megat Jalaluddin Bin Megat Hassan shared how they are changing their verticallyintegrated utility value chain into a disruptive digital value chain. The latter prioritises a communication platform that will connect transmission and distribution (T&D) networks to consumers, producers, and prosumers.

Megat Hassan explained that given the possibility of new entrants in the power sector and the need to get ahead,

there will be cooperation between the communication and the power industry.

“There is some kind of convergence with respect to communication facilities as a whole in the new integrated business model. This actually gives utility a different kind of perspective, different kind of investment decision as we move forward,” he said.

TNB is applying these changes by creating customer interactions through four offerings: e-mail tracker tools, messaging apps like WhatsApp, salesforces in their digital channels, and their own myTNB portal and apps. The executive also noted that improving on customer interactions has raised productivity, as seen in their initiative to use WhatsApp for bill rendering, which resulted in cost reductions between 40-50%. He also illustrated how the use of data analytics has improved customer retention by about 5%.

“In view of that, we think that communication is going to play a very big role. Accessibility of power will be complemented by the accessibility of communication to the whole population that will enable the new business model to flourish,” Megat Hassan said.

Pricing and digitalisation structures aside, decision makers in a liberalised

ASIAN POWER UTILITY FORUM: kuala lumpur digital customer service

Click, call, come over: TNB optimises consumer interactions with digital initiatives

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enaga Nasional Berhad is moving away from traditional electricity retail in their aim to increase engagement with consumers. The utility now offers e-mail tracker tools, integration into messaging apps like WhatsApp, salesforces in their digital channels, and their own myTNB portal and apps.

According to TNB’s chief retail officer Ir Megat Jalaluddin Bin Megat Hassan, improving on customer interactions has raised productivity, as seen in their initiative to use WhatsApp for bill rendering which resulted in cost reductions between 40-50%. He also illustrated how the use of data analytics has improved customer retention by about 5%.

These digital initiatives are the product of the utility’s triangulation for channels of interaction with customers, Megat Hassan said. TNB is looking to create digital customer interactions, give customer solutions through digital technology, and improve the back-end of their digital enterprise.

Ir Megat Jalaluddin Bin Megat Hassan, chief retail officer, TNB

market should also take into consideration energy policy debates on sustainability and connectivity, said Peter Godfrey, managing director for Asia Pacific at Energy Institute. In order to facilitate energy transition from traditional power sources to renewables, he highlighted that Malaysia must be geared towards decarbonisation, decentralisation, digitalisation, and decreasing consumption.

Pushing sustainability Godfrey noted that there is no such thing as a sustainable product. “There can only be sustainable product service systems,” he said, adding that when talking about sustainability, renewables easily come to mind. He further explained that sustainable product service systems can be executed using the concept of the circular economy.

“Perhaps you might have heard about it in the context of waste. It’s actually how we optimise our resources in the supply chain. That’s important to discuss when we design things, we produce things, we develop things, we operate things as it is to do with waste. Let’s think about the circular economy from the point of view of how we look at the complete supply chain - from resource utilisation right to the decommissioning,” he said.

Godfrey also shared how the Energy Institute has established a joint venture with Universiti Teknologi PETRONAS (UTP) to start building continuous professional development courses

Malaysia can tap into renewables as its energy intensity is still at par with its neighbours Thailand and Cambodia, even if it is quite ahead of them and its other ASEAN peers in terms of industrialisation.

“We call it ‘click, call, and come over’, a combination of digital as well as face to face interactions. We can see that today that interactions is moving from face to face into a digital platform. Today, we can see almost 35% of customers are being interacted through digital channels,” Megat Hassan said.

“We have this important element of customer interactions and we think that the technology like WhatsApp will give us the competitive advantage with respect to customer interactions. We have also created apps for the ease and convenience of our customers,” the executive added.

At the moment, most of TNB’s processes are already done online. However, most of the applications are coming from the developers of the housing estate or even the level of consulting or B2B. “The developers have access to the portal and they will have to submit online applications in the hundreds,” Megat Hassan said.

At the customer level, not all features are readily accessible yet, but the executive has mentioned that they are trying to merge the features on the application. “We have an online portal for applications. We do have apps for current payments and so forth,” he said.

TNB has to ensure that the network infrastructure would actually be able to accept the workload in the new business model. Megat Hassan said, “In the future, we think that this will create a peer-to-peer network for the electricity business. This is an important element for the grid to be digitalised, so we will accept dual workflow and at the same time, because many of the renewable energy sources are actually intermittent - we have to ensure that we have the mechanism of supply.”

As more people obtain the ability to generate power themselves, Megat Hassan said that this will create a micro-grid of electricity. “We are going to see that generation is more localised comparatively to centralised today and we are going to see that it’s going to be a community grid rather than a national grid as we see today,” he added.

alongside them. “We’re hoping to do the same with Unitem and Tenaga Nacional Berhad in time,” he said.

Apart from tapping into improving sustainability systems, Dieter Billen, principal at Roland Berger, said that Malaysia can tap into renewables as its energy intensity is still at par with its neighbours Thailand and Cambodia, even if it is quite ahead of them and its other ASEAN peers in terms of industrialisation.

Malaysia is one of the countries expected to boost the region’s additional capacity requirements to 250GW, he added.

According to Billen, Malaysia can capture the potential of renewables, especially solar power, through five action steps: promoting the appropriate mix of project sizes, reviewing targets and quotas, supporting infrastructure development, developing standardised PPAs, and de-risking development.

Meanwhile, the future for gas continues to look rosy for a number of reasons, Godrey noted, one of which is the fact that it is a transition fuel. “Gas is plentiful and will continue to play a lead role as a replacement for coal. I don’t think coal could die completely, but I think we are increasingly going to see gas take a role. However, I think it has still some challenges, one of which it needs to hybridised most closely with renewables and to work much closely with renewables in the future,” he said.

Most of traditional resources still have a role to play to keep up with the increasing demand of the economy, Megat Hassan said. “It’s not actually easy to plan to the size of the capacity immediately. We still need more traditional sources like gas and coal. In the future, I think we are going to complement the role of traditional sources with the role of new resources,” he said.

Peter Godfrey, managing director, Energy Institute

ASIAN POWER 29

OPINION

BREE MIECHEL

Vietnam’s solar FIT 2 and overcoming financing challenges

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n 12 April 2019, the Ministry of Industry and Trade of Vietnam published the final draft decision of the prime minister, intended to replace the current Decision 11 promoting the development of solar power plant projects in Vietnam. The final draft of the decision has extended the duration of the second feed-in tariff, from 1 July 2019 to 31 December 2021 (FIT 2 Deadline).

Whilst the first round FIT provided for a single 9.35 cents per kWh tariff, the draft decision, in its current form, has differentiated tariff levels according to the type of technology used on a solar project, and its location: the MOIT has divided Vietnam into four regions, based on irradiance levels. Projects completed in regions with lower irradiance will be granted a higher tariff, in an effort to encourage solar projects in Vietnam’s Northern provinces.

Bankability issues surrounding the Standard Solar PPA To accompany FITs, the MOIT issued the Standard Power Purchase Agreement for Solar Projects (Standard Solar PPA) in September 2017.

The Standard Solar PPA is relatively short compared to conventional solar project PPAs, and departed from international market standards, raising a number of bankability issues, notably: • Off-taker obligations and Government guarantees: there are no “take or pay” provisions governing compensation if Vietnam Electricity (EVN), as sole off-taker, fails to take the electricity (by its own failure to cooperate or otherwise). EVN’s obligations are further not guaranteed by the government, exposing projects to EVN payment risk.

• Commissioning risk: in order to qualify for the FIT, the project would need to achieve the commercial operation date by the FIT 2 Deadline, without any allowance for commissioning delays attributable to EVN. • Force majeure: similarly, EVN’s obligations are suspended in a number of force majeure circumstances, as well as interruptions and outages due to grid overhauls and maintenance by EVN. • Termination payments: in the event of EVN’s default, there are no specific provisions regarding the calculation of damages, which are therefore governed by Vietnamese law. These are limited to the value of the actual electricity output in the termination year, and are unlikely to fully compensate investors.

• Currency fluctuations: the FIT is payable in Vietnamese dong, adjusted only annually based on the State Bank of Vietnam’s VND/USD exchange rate, presenting a risk for repayment of USD denominated debt. The Standard Solar PPA further does not contain an indexation clause to protect investors against increased costs or inflation.

• Dispute resolution: the governing law is Vietnamese law and Vietnamese courts have exclusive jurisdiction. There are no provisions for international arbitration.

Practical solutions to the PPA bankability issues Whilst such concerns are widely acknowledged, the general consensus remains that the FIT offers an attractive incentive to invest in Vietnam’s solar power industry. Although one project has been able to obtain amendments to the Standard Solar PPA to address some of the bankability issues, most project sponsors will not be in a position to obtain such concessions. In order to mitigate the bankability risks posed by the Standard Solar PPA and facilitate funding for the development of solar PV projects in Vietnam, several practical solutions have and are being explored: • Local bank letter of credit One structure developed to insulate international commercial banks from 30 ASIAN POWER

BREE MIECHEL Partner, Reed Smith

Draft decision amendments

Source: Reed Smith

EVN payment risk and allow participation in the market, includes lending by to a top tier Vietnamese bank secured against a Letter of Credit effectively guaranteeing EVN’s payments under the PPA as well as the full amount of project debt outstanding in the event of a payment default. The local bank would be granted rights of recovery over the project’s assets and cash flows up to the amount of debt which they are securing. Non-payment insurance would be procured to cover the Letter of Credit issued by the local bank.

Some reservations regarding this insurance solution include the reliance by the bank on insurance without (i) strong knowledge of the asset, (ii) comfort on the contractual (PPA) structure, and (iii) any ability to play a role if the project performs badly. However, the cost of insurance is offset by the prospective rate of return offered by the FIT, allowing sponsors and lenders to explore such a strategy.

A similar product is also being developed by multilateral banks however without the same level of risk transfer. The product contemplated would cover EVN non-payment risk but not shield international commercial lenders from the other underlying bankability concerns under the PPA. • EPC contractor financing The EPC contractor can fund the development of the project and recover these costs out of the project revenue following commercial operation of the power plant. Where this structure is adopted, the contractor has applied a significant premium of approximately 20%–with the opportunity to supply its own modules and inverters to the project–with the anticipation of being repaid within the first few years of operation.

EPC contractors have also accepted liability for commissioning of the project by the FIT deadline. The EVN risk of curtailment is potentially lower in the early years, before competitor projects come online and potentially lower tariffs are implemented. Despite the premium charged by the EPC contractor, who benefits from a very favourable position, the attractive FIT and fast growing energy demand in Vietnam (around 12% per year) are attractive enough to incentivise investment.

Some structures in other markets have seen the EPC contractor bear significantly more risk–they are provided with a minimal down payment from the owner (around 15% of project costs), with the remainder payable on commercial operation but only if the financing is in place or the power plant has been sold. In this case, the EPC contractor is entitled to project revenue and if not repaid, can enforce its comprehensive security package.

However, Vietnamese law does not allow foreign persons to take security over land, which could prove to be a barrier for such a structure. This article was co-authored by Hugo Le Ridou, Reed Smith.

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OPINION JOHN YEAP, NICK WANG, JAMES HARRIS

Taiwan offshore wind series part 2 – Lessons learned

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aiwan’s well-regulated framework coupled with cost-reflective tariffs has allowed the island to attract some of the biggest names in the offshore wind sector. However, progress to date has not been without some hiccups. In Part 2 of this two-part series, we look at some of the challenges that have arisen and consider the implications for the future development of the offshore wind sector in Taiwan.

Reduction in FIT year-on-year Policy-driven subsidies such as feed-in tariffs are expected to reduce over time, a reflection of reducing unit costs. However, reductions that are arbitrary signal regulatory risks for sponsors. The tariff for 2019 for offshore wind PPAs saw a reduction of around 5.7% compared to the 2018 tariff.

The current tariff is an average of $0.1788/kWh (NT$5.5160/kWh) for 20 years, with the first 10 years being $0.2036/kWh (NT$6.2795/kWh) and the remaining 10 years being $0.1343/kWh (NT$4.1422/kWh).

This reduction in the tariff is widely seen as a political response to domestic concerns that the tariff was unreasonably high when compared to similar projects around the world. However, it is difficult to compare project costs and returns based solely on the regulated tariff. Other key factors such as marine and site conditions and the availability of a local supply chain will need to be considered in order to fully determine a cost reflective tariff.

Taiwan does not have an established local supply chain, but as projects are built and commissioned, allowing a local supply chain to develop, unit costs should reduce, and when that happens, tariffs should reduce to reflect lower unit costs. The fact that the government had apparently so rapidly acquiesced to public concerns has instead led to the perception that the voice of public opinion will be an influencing factor on the island’s energy policy.

Grid connection Offshore wind projects often give rise to at least two grid connection challenges. Firstly, it is unlikely that areas with high wind resource will have high load. It will therefore be necessary to develop the grid network to connect the turbines to the main grid, which may be of some distance.

Secondly, the introduction of large intermittent generation will usually require grid augmentation to absorb such generation. Taiwan faces similar challenges.

Taipower has said that it will provide grid connection to all the projects allocated with capacity. However, it falls short of making any commitment to provide grid connection on time nor agreeing to provide any compensation if grid connection is delayed. The PPA does not provide for compensation from Taipower. There is therefore uncertainty for sponsors on the ability to test and commission the plant when they are ready to do so.

An underlying policy element in Taiwan’s offshore wind programme was

Wind tariffs were reduced over domestic concerns on pricing.

32 ASIAN POWER

John Yeap Partner, Pinsent Masons

Nick Wang Associate, Pinsent Masons

James Harris Partner, Pinsent Masons

to establish the island as a regional supply hub for offshore wind projects.

The requirement for localising the supply chain was therefore an important factor for the Taiwanese government in the selection of the winning projects for the 3,836MW allocated in Phase 2 allocation in April 2018.

Local content requirements However, the ability of developers to meet such local content requirements has been impeded by the shortage of experienced local talent and domestic fabrication capabilities. Taipower has said that it is working with local universities and technical colleagues to train talent, although this will take time. The greater challenges instead will be in sourcing domestically the sophisticated machinery required, such as wind turbine installation vessels.

Nevertheless, there is indication that both sides of the project are working towards finding a solution. For instance, it has been reported that despite Ministry of Economic Affairs reprimanding a developer for failing to meet the local content requirements in two areas, namely submarine foundations and foundation piles, it has accepted the developer’s interim measures and action plan to address these issues, such as obtaining proof from the relevant supplier attesting that the failure to meet the local content requirements is due to lack of production capacity, setting up an industry fund to help subcontractors and to train electric welding workers, and expediting its plan to set up local assembly plants (to work with local suppliers) in Taiwan.

Local vessels Unlike some other places in Asia, Taiwan currently does not make the use of locally-flagged vessels mandatory. Whilst China and Japan, for instance, restrict the usage of foreign-flagged vessels, no such restriction currently exists in Taiwan. There is a restriction on the use of People’s Republic of China-built and PRC-flagged vessels, but not on other foreign vessels.

However, recently two government agencies in Taiwan have been considering a mandatory requirement for the use of Republic of Chinaflagged vessels for certain offshore wind farm construction activities. It would appear that this has been a response to some local shipowners and operators who have complained about the use of foreign vessels when local vessels are available.

The Bureau of Energy is discussing with developers, contractors, vessel operators, and industry experts, on vessel specifications required for offshore wind construction and the availability of qualified ROC-flagged vessels. The Maritime Port Bureau is also considering restrictions on the use of nonROC-flagged vessels for offshore wind construction, as well as a possible liberalisation of the requirements for a vessel to fly the ROC flag. Under Taiwan’s Law of the Ships, a vessel can qualify to fly the ROC flag only if it is owned by a ROC national or by a company which has over half of its capital or shares owned by ROC nationals.

Going forward The third phase of allocation is expected to be announced later this year, and some key players have already expressed their interest in participating. The third phase will allocate capacity to come online during 2026-2030.

Some players are already reported to be considering entering into corporate power purchase agreements for future projects. With the amendment to the Electricity Act in 2017 allowing renewable energy to be sold directly to non-utility companies (Google being a party to the first of such corporate PPAs), more corporate PPAs can be expected to be entered into as increasing number of local and international companies become more conscious with their carbon footprint.

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