Changing population demographics and slow economic growth are forcing Japan to reassess its optimum power sector fuel and technology mix. It seems to spell the end of the country’s nuclear era.
Japan’s energy policymakers have begun dramatically to revise their thinking on the country’s optimum power sector fuel mix. Effective immediately, nuclear is being strongly downgraded as the sector’s main primary energy source. It will be replaced from here on by coal, gas, probably wind and ultimately hydrogen.
The shift has been prompted by fundamental demographic changes that trump the usual considerations of economic efficiency, energy security and environmental suitability. In essence, beginning 2006 the Japanese population will shrink and age at globally unprecedented rates. Since this development will entail little need for new large volumes of centrally generated power but will require comparatively small increments of increasingly distributed generation, GW-scale current nuclear technology is out. Meanwhile progressively smaller capacity options – coal, gas and fuel cells that must still meet the conventional considerations – are in.
Each of these three options has in the Japanese context its own distinctive cost, environmental and energy security profile such that no clear main fuel is likely to re-emerge until the advent of hydrogen. Even then, nuclear, coal, gas and renewables will still vie as hydrogen sources. However these shifts support Japan’s so far sluggish power sector reform and are in line with domestic political sentiment. They thus have profound and so far incalculable implications for domestic power engineering.
The demographic warning flag was first hoisted by Japan’s Institute of Energy Economics (IEE) in its January 2003 long term energy demand and supply outlook. The outlook’s key assumption, based on National Institute of Population and Social Security Research (NIP) data, was that “population peaks at 128 million in 2006 and gradually declines thereafter”. Since a population of only 117 million is expected in 2030, and since its median age will be significantly higher than at present, “ageing will progress at a rate unprecedented in the world”.
Consequent IEE primary energy demand growth rate projections to 2020 including planned energy conservation and structural changes to the economy are therefore 0.3 per cent per year from 2000-2010 and 0.2 per cent per year between 2010-2020. Updated Ministry of Economy, Trade and Industry (METI) projections to 2030 released January 2004 essentially concur even though its expected median GDP growth rates are significantly higher (Table 1). In both projections, annual power demand growth rates shrink to under one per cent per year by 2020.
METI’s projections were prepared for an ad hoc joint committee formed on 21 January between its Advisory Committee for Natural Resources and Energy (ANRE) and Keidanren’s private sector Industrial Structure Council (ISC). In the light of the new projections, this committee is setting new energy policy directions that necessarily impact the power sector’s fuel mix framework.
The committee’s full report was due in August 2004 but it released an interim report at the end of June that urged no more than four new nuclear power plants by 2010. Since all these are already under construction and since only ten new plants are foreseen to 2030, new nuclear construction could come to a virtual halt after the present four are commissioned. The implication is that all new nuclear plant would incorporate advanced technologies.
Coal is meanwhile enjoying an extraordinary Japanese resurgence. Quite apart from a quiet but very significant switch to coal since 1990 (Table 2) it is on historic cost data both cheaper and more secure than LNG. Thus steaming coal imports into Japan at around ¢0.75/1000 kCal since the early 1980s have been consistently cheaper and more evenly priced than the much more volatile LNG whose import prices have typically exceeded ¢1.3/1000 kCal over the same period. Coal’s average levelized busbar kWh costs at constant 1992 prices are consequently up to 20 per cent below those for LNG.
Much more important for coal however is a new IEE perception that a limited nuclear/gas fuel combination would on its own not be clean enough to meet Japan’s Kyoto Protocol commitments. It thus makes better strategic sense to focus on cheaper, safer coal and meet its heavier CO2 emissions burden through a combination of clean coal technologies and carbon trading. Very significantly, domestic CO2 sequestration from coal is now emerging as Japan’s cheapest carbon abatement option after trading. Consequently carbon sequestered coal would be the next best fuel option after nuclear.
In presenting this perception in March 2004, IEE pointed out that Japan has a combined underground CO2 storage capacity in depleted oil and gas fields and salt water aquifers along its coasts equivalent to at least 75 years of total national CO2 emissions at 1990 levels. Moreover, not only is this geological storage capacity conveniently close to many Japanese power stations but CO2 separation and recovery from coal is already commercially feasible. Meanwhile coal fired power generation at 133 million t CO2/year produces Japan’s third largest volume of emissions after steel plants, 178 million t, and gas fired power generation 142 million tons. Because coal fired flue gas CO2 concentrations at 13.2 per cent of total exhausts are higher than those for natural gas (around ten per cent) power sector sequestration from coal is much more economic than from gas.
On this basis, IEE developed three comparative cost studies for sequestration from a 1 GW coal fired power plant whose CO2 would be stored in either a domestic coal mine (pipeline delivery, case 1), an overseas oil field (tanker delivery involving CO2 liquefaction, case 2) or a domestic aquifer (also involving liquefaction/tankers, case 3). The assumed transport distances are 100 km for the pipeline/domestic tanker and 4300 km (to Malaysia) for overseas tanker delivery. A fourth ‘control’ study involving a 1 GW gas fired power plant with pipeline CO2 delivery to a domestic coal mine was also developed (case 4).
The various cost elements are shown in Table 3 where higher CO2 separation/recovery costs for gas make it more costly than all the other three options. Table 4 then compares the total carbon abatement costs of cases 1 and 2 with those of other possible means of abatement. The table shows that although sequestration would cost more than carbon trading, it is as cheap as or cheaper than all other options including ‘non-power’ ones. The IEE therefore concludes that “even under the current [high gas separation] cost structure, [coal fired] carbon sequestration would be fully practicable”.
It also points out that whereas carbon trading and domestic energy conservation are likely to become more expensive in future, sequestration costs and those for CO2 abatement via renewables would decline. But since such costs from all renewables except large-scale RDF and wind are unlikely to decline to the point where they would compete with coal fired sequestration, the latter and hence coal itself is in a very strong position.
A further plus is that although it is generally accepted that uncertainties remain over the long-term geological behaviour of underground carbon repositories, Japan could very easily begin storage in depleted oil and gas fields whose proven storage capacity and behaviour are known. This approach would give the country 1.833 trillion t of interim CO2 storage capacity while other much larger repositories, particularly underground salt water aquifers, were being investigated.
Thus the only major barrier to immediate coal fired CO2 sequestration is lack of international protocols for it. The intergovernmental panel on climate change (IPCC) is expected to provide guidance on this in 2005.
Gas meanwhile has its own profile that will certainly continue to assure it a major role in Japanese power generation. Most important, long-term LNG production costs are tumbling. Thus IEA’s Security of Gas Supply in Open Markets: LNG and Power at a Turning Point released 8 June 2004 says, “Total [LNG supply chain] capital requirements have fallen from around $700/ton in the mid-1990s to around $500 today. Costs are projected to fall to $420/ton by 2010 and $320/ton by 2030 assuming a shipping distance of around 4000 km.” It also points to likely additional cost reductions of roughly the same magnitude over the same timeframe from new production technologies that are just beginning to enter the market. When all these reductions are placed against current high international coal prices, new LNG must now be cost competitive with coal.
Unfortunately, existing long-term Japanese LNG purchase contracts combined with limited new demand mean that these sharply lower costs will penetrate the local market only slowly. Moreover, whenever LNG demand catches up with present oversupply its prices can be expected to bounce back. Thus coal may well still be the best long-term buy. Therefore construction of additional central Japanese gas fired generation capacity would be driven by the fuel’s balancing role vis-à-vis coal in an uncertain market. This role would only be constrained by the continuing lack of a Japanese gas pipeline grid.
A second consideration however is that gas will increasingly fuel distributed generation. This market is finally taking off as Japanese power sector reform gradually takes hold. Typically, manufacturers of high technology products that require large volumes of good quality power are installing 4-6 MW gas engines (as opposed to gas turbines) that match their heat demand. They sell any excess power generation to the grid. On this basis, some 2.14 GW of mainly industrial distributed cogeneration capacity had been installed by end-2002 with prospects for up to 4.64 GW by 2010, according to Energy Advance. This capacity would represent just under two per cent of total planned Japanese installed capacity in 2010.
Thirdly, natural gas (as LNG and later gas hydrate-based town gas) will also provide a crucial bridge to the hydrogen economy. It will in fact be the initial energy source beginning 2005 for most early fuel cells. This places it in a pivotal position in the Japanese context. Keidanren for example has urged “high priority for development of hydrogen energy and dispersed power sources including fuel cells”. These should be “the main electricity supply source by 2030”.
Happily, all these thrusts already have strong public and private sector support. Thus an Asahi Shimbun editorial welcomed the joint committee’s June announcement as “at long last, a realistic approach to energy policy”. Much more positively and in line with the Keidanren position, both electronics manufacturers and the electrical industry as a whole are already gearing up for widespread distributed generation which they see as an enormous business opportunity.
Electronics manufacturers in particular expect to be key players in fuel cell manufacture thereby possibly supplanting heavy plant engineering and machinery manufacture at the heart of the energy sector. Electronic components will also be needed to commercialize fuel cells which, once grid connected in massive numbers, will require further electronics-based networking systems. Electronics could also play a core role in hydrogen production.
However, it is not yet clear how this will evolve. One long-term option that is already in its second year of intensive investigation would be to use abundant cheap offshore wind power to electrolyse hydrogen from (sea)water. Given coal’s attractive credentials, another obvious path (that China will also likely follow) is carbon sequestered polygeneration. A third likely candidate is hydrogen production direct from biomass while the now severely battered Japanese nuclear industry could still be a major player.
This was made clear when Atomic Energy Commission of Japan (AECJ) chairman Shunsuke Kondo, speaking in Hawaii 22 March 2004, faced up to the unwelcome truth that “justifying the construction of such capital intensive [nuclear] plant of current designs is extremely difficult in times of emergence of innovative and neighbour-friendly modular power generation technologies”. He also believes METI’s low case forecast in Table 1 is the most likely, thereby further foreclosing on nuclear.
But he also believes the industry can re-invent itself, mainly by devising “future reactor systems that are consistent with ‘reduce-reuse-recycle’ by burning not only most of U-238 from excavation but also minor actinides generated during operation”. In such a case, nuclear could regain public acceptance. It could then address “the possibility that the demand for modular nuclear heat source reactors that can synergistically coexist with facilities to generate hydrogen from hydrocarbon material will be significant”.
But whatever happens, the old paradigm of nuclear first backed by whatever other fuels seem appropriate at the time has been swept away by demographic considerations. From now on coal and gas with perhaps wind in third place are going to be Japan’s primary power generation energy sources of choice for increasingly distributed new generation capacity. Shifts away from this profile will be driven by the comparative competitiveness of emerging hydrogen production technologies. In short, power engineering in Japan is entering an entirely new era. It will never be the same again.