IN DEPTH: Japan's nuclear options

Shortly after the tsunami triggered the destruction of the Fukushima Daiichi nuclear plant in March 2011, Prime Minister Naoto Kan was told that radioactive contamination could potentially render the entire Tokyo metropolitan area — a region of 43 million people — uninhabitable.

“If things had reached that level, not only would the public have had to face hardships but Japan’s very existence would have been in peril,” he later told Reuters.

As 160,000 people near Fukushima were evacuated from their homes, unsure if they would ever be able to return, the public in the earthquake-prone country turned firmly against nuclear power.

The previously pro-nuclear Kan immediately scrapped plans to build new atomic plants and began shutting down the country’s 50 reactors, a process that was completed in May 2012 under his successor, Yoshihiko Noda, also of the centre-left DPJ.

This meant that Japan was switching off 30% of its baseload power, about 44.6GW. While Kan and Noda were convinced that this shortfall should eventually be filled by renewable energy, immediate practical measures had to be taken to meet electricity demand, and the country began importing huge amounts of oil, coal and liquefied natural gas (LNG).

Japan is now the world’s largest importer of LNG, spending a staggering $100m per day, according to some estimates. In 2012, it spent ¥6trn (almost $60bn) on LNG, compared to ¥3.5trn in 2010, while the most recent figures showed that petroleum and LNG imports rose by 34.9% and 37.4% respectively in the 12 months to November.

This increased reliance on imported fossil fuels has led to Japan scaling back its emissions targets, increased national power-generation costs by more than 40% and helped raise its trade deficit to a record ¥1.29trn in November. The weakening of the yen against the dollar in recent months has made energy imports even more costly.

The current prime minister, Shinzō Abe, of the reactionary centre-right LDP, acknowledges that the situation is unsustainable and his government is drafting a new national energy plan. Under pressure from Keidanren, the country’s most influential business lobby; the ten powerful regional utilities; and Japan’s three mega-banks, Tokyo-Mitsubishi UFJ, Mizuho and Sumitomo Mitsui, which have all invested heavily in nuclear generation, it seems likely that the government will authorise at least some reactors to be restarted this year, possibly as soon as the spring.

Tokyo has already given in-principle approval for Tokyo Electric (Tepco) to restart its 8GW Kashiwazaki-Kariwa plant in Niigata prefecture, although geological clearance still needs to be given, which is by no means certain.

The energy plan may even call for new nuclear plants to be built, as some of the current facilities are approaching the end of their 40-year lifespans.

“The banks have invested a lot of money in utilities and their assets, but if the government says ‘no nuclear’, those assets will disappear,” a Japanese Wind Power Association (JWPA) official tells Recharge. “So we have to resolve this asset problem.”

But as well as announcing the return of nuclear power, Abe’s energy plan — which was expected to be revealed in January or February — could include some benefits for the renewables industry, such as national green-energy targets and a much-needed feed-in tariff (FIT) for offshore wind.

Japan’s FIT scheme, which was launched in July 2012 by Noda’s government, was a direct response to the energy crisis. Its generous rates immediately turned the country into one of the world’s most attractive renewables markets, and foreign developers and manufacturers raced to get a foot in the door.

Green-energy development exploded, with 5.85GW installed in the scheme’s first 16 months, including 3.83GW of utility-scale PV and 1.84GW of residential solar — yet only 70MW of wind — bringing the nation’s cumulative renewables capacity to about 26.4GW.

Domestic solar companies such as Solar Frontier, Kyocera and Panasonic have benefited the most, although as Deutsche Bank recently noted: “Every major [PV] module manufacturer has a presence [in Japan] to varying degrees.”

Yet while a growing number of foreign players are taking the fight to Japanese incumbents on their own turf with increasing success, big obstacles still stand in their way.

Access to land and an inability to forge contacts at the prefectural and municipal level have been a barrier to entry, while the major Japanese banks have been wary of lending to foreign firms with no local track record.

“There are a lot of challenges here; many companies have come, tried and withdrawn,” says Ean Mac Pherson, co-head of law firm Baker & McKenzie’s renewable-energy practice in Tokyo. “The ones who are succeeding are the ones who really commit strongly, set up a local presence and employ Japanese staff. The sort of ‘fly in, fly out’ model just has not worked very well for foreign companies. But you do see foreign companies succeeding, even if they’re somewhat behind the big Japanese players. And I think we’ll soon see a lot more projects being put into construction by foreign companies.”

While the Ministry of Economy, Trade and Industry (METI) has approved more than 22GW of renewables projects, a huge number of these have yet to be developed. Utilities that had been counting on this power to be in place could be left with an even bigger hole in their generation portfolio — one that may have to be filled by a further $3.5bn of coal and LNG imports a year, according to Reuters.

This issue has arisen largely because a number of small, would-be developers secured approvals for projects at first-year FIT rates, with the likely intention of selling them to more capable developers if and when the FIT price dropped. Last April, the government indeed lowered the solar FIT from ¥42 per kWh to ¥37.8, in response to declining installation costs, and is widely expected to drop it further this April, with Bloomberg New Energy Finance speculating that it will fall to ¥32/kWh.

But the METI is losing patience with the non-developers, and may introduce time limits for completing these projects.

This could “change the market dynamics”, says Mac Pherson, noting that it may force local players to sell their project approvals to foreign developers, which would be better placed to meet the deadlines.

Although only 66MW of wind were added in the FIT’s first 12 months — bringing the country’s installed capacity to 805MW — about 3GW of wind projects were authorised and are under development. According to the JWPA, 3.9GW of onshore are currently in development at 78 sites.

“It’s largely because of the environmental impact assessments [EIAs],” explains Naoaki Eguchi, head of Baker & McKenzie’s banking and financing practice in Tokyo.

EIAs typically take three to four years to complete, requiring environmental studies and consultations with prefectural and municipal authorities, and can cost as much as ¥100m. The JWPA points out that this has “severe” implications for developers, and means that most of the project pipeline will not come into operation until 2015 or 2016.

“Japan is quite a mountainous country and there is limited access. And the onshore wind resources are rather limited,” says Michio Hashimoto, director general of new technology at government R&D body Nedo, confirming the consensus that the future of Japanese wind lies offshore.

The Ministry of the Environment (MOE) estimates that the nation has 280GW of onshore potential and 1,570GW offshore, including both fixed foundations and floating structures, while the METI puts onshore potential at 290GW, with fixed offshore at 330GW and floating wind at 1,170GW.

Because Japan has a very narrow continental shelf, with more than 80% of its waters being too deep for traditional fixed-foundation turbines, it has swiftly become the world leader in floating wind farms.

The METI is investing ¥53bn in a major pilot project off Fukushima, while the MOE is putting ¥6bn into another off Kabashima in the western Goto islands.

However, the cost of energy for floating wind farms is expected to be up to six times higher than for fixed-foundation projects, so Nedo is keen to develop large-scale shallow-water projects first. Consequently, it has invested ¥4bn in two pilot fixed-foundation projects at Choshi and Hibikinada.

But perhaps the largest barrier to massive renewables expansion is the electricity market. To start with, transmission is problematic because the western Japanese grid runs on 60Hz frequency, while the eastern grid is 50Hz. Transferring electricity between the two relies on three frequency converter stations, which were shown to be insufficient to help the energy-starved east in the aftermath of Fukushima.

The bigger problem, however, is the near-monopolies that Japan’s ten utilities have over generation, transmission and distribution in their respective regions — and their reluctance to bring more renewables into their energy mix. All have nuclear facilities they would like to restart.

Smaller power producers and suppliers claim just 3.6% of Japan’s 280GW electricity market, according to the METI.

“Japan has to sort these things out with the utilities,” says Tomas Kåberger, the Swedish chairman of the Japan Renewable Energy Foundation, noting that the utilities do not want renewables capacity competing with their “phantom” nuclear assets and coal-fired power stations. “It would be key to substantial [renewables] development [if] you could force them by law to receive the electricity... or you could simply do full ownership unbundling and ensure that the grid and the [power] market is separated from the old monopolies.”

To illustrate the utilities’ stance, Kåberger points to Hokkaido Electric Power rejecting 4.6GW of the 5GW of wind project applications it received last year. “It’s not a cost issue,” he says, “it’s that they would outcompete their nuclear and coal facilities.”

But market reform is in the pipeline. Last April, Abe’s government introduced a new set of policy measures to stabilise power supplies, reduce electricity rates and open the market to competition within the next six years. It also set up the Organization for Cross-Regional Coordination of Transmission Operators (OCCTO) to spearhead market reform efforts.

In addition, the METI introduced rules forcing utilities that want to build new thermal generation plants to allow other companies to bid for them.

“There’s been a recognition of the need to change the current structure,” says Mac Pherson. “It’s just a question of how best to rearrange everything.”

The OCCTO intends to liberalise the retail electricity market between 2016 and 2018 — offering consumers the opportunity to choose their providers — and expects to finish legally separating the utilities’ generation, transmission and distribution assets by 2020.

However, doubts remain about how smoothly the reform process will proceed. “The so-called electricity market reform has been rather controlled by the electric power companies,” complains Kåberger. “In this country, they’re really ‘power’ companies in that they have political power. So they have unjustifiable influence over market regulation, and that is very costly to Japanese industry and society.

“The difficulty at the moment [for renewables] is that as the government is still giving the impression that the nuclear reactors will start, so the power companies are still protecting the potential production of nuclear.”

If, when and how much nuclear capacity will be restarted remain key questions. In any scenario, however, there is no turning back for Japan’s renewables sector.