China’s nuclear programme to swing back into full gear

China’s nuclear power industry comprised 47 operational reactors.

China’s nuclear programme to

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

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

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

The Lantau Group put China’s recent nuclear industry challenges in perspective and noted that China still appears committed to its nuclear programme and has made more progress behind-thescenes managing technology shifts and deployment plans than might first seem. The Lantau Group acknowledges the slowdown in recent years, but considers an uptick in nuclear sector activity to be more likely looking ahead. Some of the knock-on effects of the future growth in nuclear are discussed, including the potential impact on China’s renewables targets and current power oversupply; as well as on the worldwide nuclear fuel supply ecosystem.

In Q3 2019, the Chinese nuclear power industry comprised 47 operational power reactors, for a gross installed total of roughly 49GW of electricity. Three different companies are responsible for nuclear power plant development, with the majority of the fleet split between China General Nuclear (CGN) and China National Nuclear Company (CNNC) and the third company—the Delayed reactor tech deployment and missed capacity targets are not holding back local firms from innovating designs and next-gen plants, says The Lantau Group. In Q3 2019, the Chinese nuclear power industry comprised 47 operational power reactors, for a gross installed total of roughly 49GW of electricity.

State Power Investment Company (SPIC)—just starting out with its first reactor sites. With a few exceptions, the fleet consists of multiloop pressurised water reactors (PWRs) based on French, Russian, American, and indigenous Chinese designs. After years of delays, the first wave of 3G plants at the Sanmen, Haiyang, and Taishan sites have all successfully connected to the grid. The completion of the Sanmen and Haiyang NPPs serves as the crucial demonstration of concept for Westinghouse’s AP1000 reactor technology, whilst the completion of the Taishan NPP serves the same purpose for Areva’s EPR reactor design.

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

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

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

China Nuclear Reactor Technology Trees

Source: Nicobar Group

Essentially, the development of the Integrated Version of the HPR1000 gave the Chinese industry a backdoor option to build more HPR1000 plants in 2019 before the first demonstration unit HPR1000s complete in 2021.

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

Possibilities from design merger As mentioned previously, the first two sites for the 3G HPR1000 reactor (i.e., Fuqing for CNNC and Fangchenggang for CGN) are under construction and have thus far seen on-schedule construction and smooth development. A little-publicised fact about these two plants is that the CGN and CNNC variants of the HPR1000 reactor contain significant design differences, as they were originally developed independently and forced to merge into one brand name for resource efficiency and promotional purposes.

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

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

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

This number was repeated consistently by Chinese industry, policymakers, and media from 2014 onward, despite the fact that achieving this goal became a mathematical impossibility somewhere around 2016. In 2019, the China Electricity Council formally acknowledged that 53GWe by 2020 is a more realistic figure, which matches with TLG’s independent build tracking efforts. Thus, the final tally will thus miss the mark, but not by far, with a shortfall of less than 10%.

Missing this target was surely an industry setback, but it is also easy to read too much into it. There was no associated weakness or failure of Chinese construction capabilities or a loss of policy support for nuclear in general. Meeting the 2020 goal would have required a significantly higher number of new reactors to pour concrete back in 2014- 2016, but this didn’t happen. The shortfall was caused by two specific industry initiatives working in tandem: • Firstly, China’s post-Fukushima nuclear plan designated safer 3G technology to be preferred over 2G or 2G+ units, and that no further 2G+ units would be approved (several 2G+ units began construction in 2015, but they were grandfathered in from approval prior to 2013). • Secondly, the Chinese industry follows a “demonstration plant first, mass deployment second” development model, meaning that all under-construction first-of-akind (FOAK) plants are required to prove successful commercial operation before they could proceed with what the industry calls “Nth of a kind” (NOAK) construction. Taken together, this meant that China’s already under-construction 3G units needed to be completed before any new builds could be approved. Unfortunately, the FOAK 3G reactors under construction at the time in China met with numerous schedule overruns, supply chain hiccups, and technological hurdles—hardly atypical for FOAK technology. FOAK reactors have greater risk of taking longer and costing more to build than NOAK reactors.

When the Chinese-designed 3G reactor HPR1000 had its design finalised and approved in 2015, it was allowed to swiftly begin construction of demonstration sites. Thus, from 2013 to 2019, the entirety of China’s under-construction fleet consisted of either grandfathered 2G+ reactors that would be the last of their kind, or demonstration plants for 3G designs that were the first of their kind. With no proven 3G technologies available for batch deployment, it was inevitable that China would miss its 2020 deployment goals, but without any kind of policy shift or change of leadership commitment to nuclear energy.

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

• Will the new Westinghousedesigned AP1000 still be added into China’s nuclear fleet once the Hualong One demonstration reactors are finished and ready for batch deployment? • Will the domestically-developed extension of the AP1000 (the CAP1400) be treated as a legitimate domestic and/ or export competitor for the domestically-developed Hualong One? Will Chinese nuclear firms compete head-to-head for export opportunities? • What attitude will be adopted with regard to the 4G technologies currently applied in China? How much will energy policymakers prioritise diversification into reactor technology that does not use enriched uranium? Aside from the nuclear-specific goals, the narrative on broader energy climate goals for the country will also be relevant. For instance, the 13th FYP (2016-2020) included a commitment to achieve 20% of primary energy consumption and 50% of electricity consumption from non-fossil sources by 2030—this figure will likely be updated for the 14th FYP, with nuclear to play an important role in that transition.

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

Although the growth in power demand has remained strong over the past few years, the first half of 2019 saw industrywide demand slow to just 4.6% YoY, with the industrial sector growing just 2.8%. With China’s notable power oversupply issues unlikely to resolve themselves anytime soon, those bearish on the Chinese nuclear power programme may understandably wonder whether these future planned plants will ever see the light of day.

Fortunately, from the perspective of the Chinese nuclear industry, there are several supportive conditions that contribute to the protection of the industry’s future, even in severe electricity oversupply conditions: 1. Maintaining a robust domestic build programme and healthy supply chain is crucial to China’s efforts to export nuclear reactor technology abroad, especially to developing nations with extremely limited domestic manufacturing capabilities; 2. A healthy, well-maintained reactor will supply clean baseload power without additional carbon or other air emissions for 40-60 years (and even longer with life extension). This means nuclear builders are inevitably more long-term focused and less inclined to be deterred by near-term economic disruptions or short-term supply demand balance issues. Although there are other reasons, it is mostly for these two that nuclear power enjoys prioritised dispatch in many regions of China, usually to the detriment of local coal. This prioritised dispatch was reaffirmed in the NDRC’s Clean Energy Consumption Plan for 2018-2020, issued in late 2018. Despite this, nuclear is not totally immune from restrictions on loading; for instance, in freezing northern Liaoning Province, combined heat and power plants still enjoy the highest priority of dispatch through the cold months.

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

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

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

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

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

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

Whilst China General Nuclear (CGN) does have some upstream investments in uranium mining, and the State Power Investment Company (SPIC) has an equity stake in a Kazakh facility that produces EPR reactor fuel assemblies for the Taishan plant, the rest of the fuel cycle activities are monopolised by CNNC. CNNC fabricates almost all the fuel assemblies used within the Chinese industry as a licensee of the various countries where the technology originated and sells them to CGN and SPIC fuel buyers. Some fuel assemblies for the Russian-supplied Chinese reactors are still imported from TVEL.

Although China’s officially stated goal is to diversify its uranium sourcing amongst domestic production, equity stakes in foreign mines, and spot market purchases in a 1/3-1/3-1/3 split, in practice, domestic mining is likely to lag significantly behind the other two areas. Chinese domestic uranium resources are fairly modest, with production from CNNC’s SinoU totalling

Approved Plants in China’s Nuclear Build Pipeline

*First Concrete Dates are TLG projections. Source: TLG Research based on various sources

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

Historically, this has meant that the majority of uranium fuel contracts were signed for very long periods and extremely little or no volume was traded on spot markets. In recent years, however, global industry disruptions and slower than expected growth have opened up attractive spot market trading and sourcing opportunities. Since the early 2010s, Chinese fuel buyers have taken advantage of low spot uranium prices to stockpile significant quantities, serving as a hedge against future price fluctuations. Chinese equity participation in overseas mining projects has also been significant in recent years, with both SinoU and CGN-URC snapping up stakes of mines in Niger, Namibia, Kazakhstan, Uzbekistan, and Canada. With the spot price of uranium well below the cost of recovery and uranium miners in the USA and Canada already shuttering unprofitable mines, these are not profit-driven investments for SinoU and CGN-URC, but, rather, efforts to ensure the stability and security of their current and future nuclear fuel supply. Uranium mined at locations with Chinese equity are almost always earmarked for China via long-term supply contracts. So, whilst Chinese nuclear deployments will continue and even pick up in pace, it may not be prudent to infer a short-term recovery in the price of uranium.

Next generation of nuclear tech The next generation (i.e., the 4th Generation) of nuclear fuel technology primarily focuses on technology types that will either move away from fission as a thermal heat source entirely (e.g., fusion reactors) or apply nuclear physics in an advanced way to allow fission reactions to release so-called “fast neutrons” that will be able to sustain a chain reaction in normally non-fissile materials like natural uranium or thorium. The basic premise invigorating the development of 4G technology is that enriched U-235 as a fuel is problematic, because: 1. Natural uranium is relatively scarce in the earth’s crust, and the fraction of natural uranium that is the most usable isotope (i.e., U-235) comprises only a very small percentage of what is available. The majority of naturally occurring uranium is the more stable U-238 isotope. 2. Consequently, the enrichment of natural uranium is necessary to create a concentration of U-235 sufficient to sustain a chain fission reaction. Unfortunately, enrichment technology that works to produce low enriched uranium (LEU) for nuclear reactors works just as well to create highly enriched uranium (HEU) for use in a fission bomb. 3. The inevitable consequence of the LEU PWR fuel cycle is a mass of mostly useless, highly radioactive spent nuclear fuel, comprised of an unpleasant cocktail of fission products, natural uranium, and various transuranic elements, including plutonium. Reprocessing is possible, but technologically tricky and very expensive. 4G technologies seek to alleviate one or more of these three issues, and some claim to be able to resolve all three at once. Sodium-cooled fast reactors, for instance, are theoretically capable of utilising natural uranium, plutonium, and other transuranic elements, or even the non-fissile and far more common element thorium as a fuel source.

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

The next generation of nuclear fuel technology primarily focuses on technology types that will either move away from fission as a thermal heat source entirely or apply nuclear physics in an advanced way to allow fission reactions to release so-called “fast neutrons” that will be able to sustain a chain reaction in normally nonfissile materials like natural uranium or thorium. prototype is now under construction in Xiapu. Whilst 4G technologies hold great benefits for non-proliferation as well as the efficiency and safety of nuclear power, their rise would theoretically not bode well for companies with extensive or exclusive exposure to the continued use of the uranium fuel cycle. Fortunately, from the perspective of those companies, China’s 4G technology push is intended to be complementary to its fleet of PWRs, not a replacement, at least not in the first half of the 21st century.

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

Closing thoughts Despite the relatively unexciting performance of the Chinese nuclear industry over the past few years, the case for nuclear power in China remains attractive, with continuing policy level support. The expansion of the industry over the coming years is likely to pick up and gain even more focus upon publication of the 14th FYP.

Zhangzhou NPP pouring concrete in October 2019, the first new Chinese plant in over three years, is just the first instance of what will be a major wave of new build over the next few years. It will be important to keep an eye on the development of inland sites, as the deployment of more nuclear in relatively economically depressed regions would create a scenario where nuclear and renewables compete for dispatch.

As for knock-on effects, the outcome for the uranium future cycle is complex, as Chinese demand for refuels and new reactor cores will certainly grow, but will be mitigated to some extent by Chinese stockpiling and equity acquisition efforts. 4G nuclear generation technology will emerge on the scene within the next three to five years, but will realistically fill only a niche role in the near term given the size of the overall fleet or be tapped for export to new nuclear economies. From “Quiet But Not Dead: China’s Nuclear Program Now Poised to Swing Back Into Full Gear” by David Fishman, The Lantau Group

Eyes on the East: China asserts power over

global offshore wind sector

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

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

Offshore wind accounts for a measly 0.3% of global electricity generation, but recent regulatory and technological developments showcased offshore wind’s potential to become one of the world’s central energy sources in the coming years. As the UK and China race for dominance in this space, other global leaders are also breaking new ground. Vietnam is another market to watch, as the government aims to make offshore wind a primary energy source. Dr. Fatih Birol, executive director, International Energy Agency, said that global offshore wind power capacity is set to increase by as much as 15 times over the next 20 years. This will turn the global offshore wind sector into a $1t business, the leading source of electricity in Europe, and a viable source of hydrogen to reduce emissions from the iron, steel, and shipping sectors.

Whilst the UK and the rest of Europe remain on top of the global offshore wind game, China and other players from the Asian region could eventually emerge as winners if they fulfil their potential for wind power. According to a report by Fitch Solutions, China is expected to become a global offshore wind power frontrunner over the coming decade as it accelerates offshore wind capacity deployment in Guangdong and Jiangsu. “China’s offshore wind capacity growth since 2015 has seen the country grow its share of total installed capacity globally from 9% as of end-2015, to more than 25% as of end-2018, aided by the market comprising 40% of global net offshore wind capacity growth over 2018. With the offshore wind project pipeline strengthening over the coming years, we believe China’s global offshore wind power footprint will expand further,” analysts at Fitch Solutions said. Favourable conditions China is catching up to Western Europe with rapidly falling offshore wind power costs and markets like the United States and Taiwan in terms of competitive technology. Analysts believe that China’s aim is to eventually export technology, after decarbonising power supplies near the country’s coastal consumption hubs. Danish company Ramboll designed the world’s biggest and heaviest monopiles for State Power Investment Corporation’s Guangdong Offshore Wind Power project last year. Weighing 1,600 tonnes, the monopiles are being installed at a depth of 37 metres, one of the deepest in the market to date.

Apart from China, other Asian countries are moving towards increased offshore wind capacity. Vietnam, for instance, has been looking to European expertise for developing many of its offshore wind projects. The country’s largest offshore wind farm at 3,400MW will be developed Despite being a newcomer in the global scene, China added more capacity than any country in the last two years. Global offshore wind power capacity is set to increase by as much as 15 times over the next 20 years. This will turn the global offshore wind sector into a $1t business.

Installed Offshore Wind Capacity, 2018, MW

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

Source: GWEC

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

“Primarily, Vietnam’s wind resources are some of the best in the world. The water depths are within the range that is manageable with current engineering, and our understanding of what makes commercial development possible. There is a developing onshore wind sector with technical expertise in operations and maintenance and so we believe this will be capable of expansion to serve the offshore projects over time,” said Ian Hatton, chief executive officer, Enterprize Energy. Elise Do, associate director, Augusta, said that Vietnam has power generation needs of 60,000MW by 2020 and 120,000MW by 2030. She added that the growing demand will be a huge enabler for renewable energy, specifically offshore wind, which can help increase capacity almost immediately. The country also has a 20-year feed-in-tariff (FiT) in place, part of the government’s efforts to make renewable investments more attractive. “The offshore wind sector offers scale, but what is also important is that you need to have good wind resources, which Vietnam has. It also needs benign sea conditions and proximity to load. Vietnam, with its long coastline, has a lot of the ingredients needed to make the offshore wind sector work. Another interesting point about Vietnam is that its oil and gas supply chain is already established and that’s a good base from which to build the new industry of renewable energy,” Do added.

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

The country already boasts of an encouraging regulatory framework despite the Taiwan Strait being a technically demanding environment to build an offshore wind project in. Hatton said that Taiwan’s geographic location makes it vulnerable to seismic activity and typhoons, requiring projects to have strong foundations to cope with seismic liquefaction risk and deeper water of up to 50 metres.

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

Money trail Many investors are looking at Australia, Japan, Korea, and countries in Southeast Asia with growth potential in renewables, and Do said that the investment potential will depend on which market each investor is familiar with. Tim Buckley, director of energy finance studies, Institute for Energy Economics and Financial Analysis (IEEFA), said that wind, utility-scale solar and distributed rooftop solar generation made up 14.7% of Australia’s energy mix

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

in 2019, compared to just 1% in 2009. Buckley noted that offshore wind power in particular has been slow to take off, but has eventually gained ground in the country’s national energy market. Like Vietnam, Australia is taking inspiration from European leaders in offshore wind. The country’s first ever offshore wind project, The Star of the South, is a 2.2GW wind farm located off the coast of Gippsland, Victoria. Proposed by Copenhagen Infrastructure Partners (CIP), it is the country’s largest electricity project worth around $5.4b in investments. CIP’s capital comes from institutional investors such as pension funds and insurance companies that prefer investing in infrastructure with long-term cash flows.

“An interesting trend to follow will be how well the support mechanisms that are going to be in place will meet the criteria of international investors and what they’re familiar with. The PPA is not bankable as it stands, but I understand that the Vietnamese government is working on the structure to see what can be done so I would say it’s progressing,” Do added. Over the last year, another Asian country has seen an upsurge in the number of investors flocking to its offshore wind sector. A report by GlobalData reveals that Vietnam’s offshore wind can grow to more than 770MW from just 68MW at present. Major foreign developers such as Ørsted, Equinor, wpd and CIP have expanded their global footprints in Japan, proof that the country has huge potential for offshore wind generation.

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

In addition, Japan passed the Marine

Public Auction Process

Source: Linklaters

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

“Having the supply chain developed in Vietnam could also be a gateway to the supply of other Asian markets when they do come on stream. The opportunities will also evolve as technology evolves. For example, we’re seeing technological advances in floating offshore wind, and that will help strengthen the business case, and the realisation of other Asian markets where the waters are much deeper and more advanced technology would be needed,” Do said.

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

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

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

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

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

and innovate faster than before. In 2018, the IEA reported that the average upfront cost to build a 1GW offshore wind project, including transmission, will need over $4b. Over the next decade, analysts at IEA said that the cost is set to drop by more than 40% as a result of cheaper turbines, foundations, and installation costs. “The technological advancements in offshore wind turbines have been dramatic. The rotor diameter of offshore turbines has doubled from 80 metres to more than 164 metres and average turbine capacity has more than quadrupled, climbing from 1-2MW in 2012 to 8-12MW today. Leading players like Vestas, Siemens Gamesa and Goldwind have already implemented offshore wind turbine upgrades and are betting on reaching 14MW turbines by 2024,” Buckley said.

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

Indicative annual capacity factors by technology and region own in terms of baseload technology.

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

Countries with extremely deep waters such as Japan will also benefit from innovations in offshore wind technology. According to Norwegian energy firm Equinor, floating installations could be the gamechanger in the country, as there are few to no sites for bottom-fixed turbines.

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

“We are party to three gas fields that can be developed this way where we plan to co-locate offshore wind turbines. Our concept is a commercially sensitive business model but I can say that we have a patient strategy to incorporate hydrogen production powered by wind which can then be stored, transmitted or converted to electricity by combustion at site,” he said.

Leaders, however, can use offshore wind to inject greater reliability on the grid. It has a utilisation rate of 50-55%, which means it offers supply diversity. In this scenario, offshore wind can help countries reach their ambitious targets on time, especially as investment costs fall and make it a more accessible renewable energy source.

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

Asia rises as global capital for solar power

Large-scale solar farms have become a more common sight in Asia over the last few years. Technology costs have been decreasing significantly to the point that analysts forecast that by 2050, photovoltaic (PV) systems will cost a measly $0.42 per watt or as much as 43- 54% less than today’s price tag. This has sent Asian countries on a construction spree as they aim to hit ambitious renewables targets and meet the growing energy demand in the region.

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

As Asia and countries like the United States, Spain, and Brazil gear up for a solar boom, total installed solar capacity will likely overtake total installed wind capacity within the next two years. Fitch Solutions forecasts that over the next ten years, the biggest names in solar will in fact be China, the United States and India. its aggressive takeover of sectors such as solar, offshore wind, and hydropower. Last year, solar power in China became cheaper than electricity supplied by the national grid through coal power. This means that over the next few years, solar power will likely find its way to the industrial and commercial space. Meanwhile, Vietnam’s high solar irradiation levels will soon be leveraged to meet a 4GW solar capacity target for 2025 and 12GW target for 2030. To move closer to the target, the country invested in Southeast Asia’s first largescale floating solar project, a 47.5MW facility in Vietnam’s Da Mi plant. Jackie B. Surtani, Asian Development Bank’s director of Infrastructure Finance - East Asia, Southeast Asia and the Pacific, said that the project was financed on a nonsovereign basis and completed in two years.

“This is relatively new for Southeast Asia. It’s quite straightforward, and so it’s not overly complex. DHD, which is a subsidiary of an EVN subsidiary called GenCo-1, has three large hydro projects which have been in operation for a considerable period of time. They’ve decided to put this floating solar on one of As renewables take over the world’s energy mix, the region will continue to grow its global PV capacity at full speed. China and Vietnam are now Asia’s brightest solar spots, with China expected to add over 300GW of solar capacity by 2021.

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

Top Five Solar Markets By Installed Capacity In 2028f

e/f = estimate/forecast. Source: EIA, Fitch Solutions.

their reservoirs and it actually only takes up around 8% of one of the reservoirs. What it does is that it increases the overall output during the dry seasons where the hydro plant will not be running,” Surtani said.

Taiwan, on the other hand, developed its largest ground-mounted solar project the same year, the result of an IPP’s goal to minimise its ecological impact. Singaporebased Vena Energy won a competitive tender to build a solar project on an abandoned salt product farm in Chiayi. Called Mingus, Vena Energy’s 70MW project will help achieve Taiwan’s 20GW renewables target by 2025. “We worked with local and international banks to finance the project which is particularly attractive as it is the first large-scale solar project tender by the government, and the Mingus Solar Project was the largest ground-mounted development when the tender was introduced in 2017,” said Sam Ong, group CEO and country manager of Taiwan, Vena Energy.

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

Analysts at Fitch Solutions reported that Singapore’s solar sector will expand over the next decade, as the government moves away from thermal energy and upholds its Paris Agreement pledge to reduce emissions intensity by 36% below 2005 levels. The transition to solar is perfect for Singapore, which has an annual solar irradiance of 1,580kWh/ m 2 /year, 50% greater than neighbouring temperate countries and highly suitable for the deployment of PV cells.

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

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

On the other hand, whilst India does have the land for solar power, a complicated regulatory environment has made it difficult to implement solar projects at the ideal pace. According to JMK Research Analytics, a bloated bureaucracy requires 6-9 months to procure land for solar or wind projects. Other states may even stretch this to 18- 24 months, making it an extremely costly endeavour.

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

Solar Power Capacity & % y-o-y Growth

Singapore, for example, does not have as much land as Vietnam or India, so the government has resorted to artificial islands, solar generation facilities, and vertical solar installations to achieve the goal. “As land is a state subject, there is a need for better coordination between state and central government agencies whilst evaluating and announcing tenders. The expected due dates should match the reality on the ground. Digitisation of land records is the key to streamline and expedite the land allotment process, thereby reducing any chance of stalling of projects due to legal hurdles. Lastly, to speed up the process of approvals and permissions, the number of agencies involved should be minimised or a better coordination among these agencies has to be established,” analysts at JMK Research Analytics said.

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

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

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

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