Japan shows coal’s dilemma: More needed now, less in future
The dilemma facing thermal coal miners is neatly encapsulated by the current dynamics of Japan, where robust short-term demand contrasts with a diminishing long-term outlook.
Japan, the world’s third-biggest coal importer behind China and India, is planning on returning coal-fired power plants with a combined capacity of more than 10 gigawatts (GW) in the next few weeks in order to meet peak summer demand.
The countries utilities are preferring to restart coal generation than use cleaner burning liquefied natural gas (LNG), which is considerably more expensive.
A gigawatt of power generation requires about 3.5 million tonnes of a coal a year, so it’s likely that Japan’s imports of the polluting fuel will rise for the next few months.
Already vessel-tracking and port data compiled by Refinitiv suggest a boost in imports, with 13.4 million tonnes offloaded in June, up from 12.9 million in May and 12.5 million in June last year.
While subject to revision, Refinitiv estimates that Japan will import about 14.3 million tonnes of coal in July, which would be the strongest month since March, although lower than 15.3 million tonnes in July last year.
These figures include coking coal used to make steel, but it’s likely that the gains will be concentrated in thermal coal given that Japan’s steel output is expected to remain largely steady over the northern summer.
If the Refinitiv data for June is borne out by official numbers when they are released at the end of this month, it will mark a reversal of the trend this year to lower coal imports.
Japan’s total imports dropped 3% to 75.3 million tonnes in the first five months of the year from the same period in 2018, with thermal coal slipping 2% to 45.9 million tonnes, according to official data.
But while coal exporters, particularly Japan’s biggest suppliers Australia and Indonesia, may relish the return of coal-fired power for summer, the longer-term outlook for Japan isn’t nearly so rosy.
Japan’s pipeline of coal-fired power projects is shrinking as utilities, trading houses and banks become increasingly reluctant to propose and finance new generators.
The pipeline of new plants has dropped from 12.67 GW in January 2015 to just 4.58 GW as of January this year, according to a report published earlier this month by the Institute for Energy Economic and Financial Analysis (IEEFA), a pro-renewables think tank.
Of the remaining projects, IEEFA said about half of the planned capacity appears to be in doubt, with Kansai Electric Power’s 1.3 GW Akita coal-fired power project, due to come on line in 2024, now under review, and Osaka Gas withdrawing from the 1.2 GW Ube coal-fired power project, which has two units scheduled to come on line in 2023 and 2025.
Stricter environmental rules are a factor in the diminishing coal pipeline, with Japan’s environment ministry saying it March it would likely be opposed to new coal projects or expansions at existing plants.
Japan currently has 8.7 GW of coal-fired generation under construction, but these are mainly replacing 8.2 GW of older units that are due to be decommissioned by 2025.
Given that the new units are more advanced and efficient, they will burn less coal than the units being retired, which may result in lower demand for imported coal to generate the same amount of electricity.
It’s likely that over the next decade or so Japan’s demand for thermal coal will drop, although the long life of existing coal-fired plants will ensure that it doesn’t plummet.
The greater risk for coal in Japan is that it loses some of its competitive edge against LNG, and that more idled nuclear units are returned to service.
Converting coal to its energy value shows that Japan paid about $4.26 per million British thermal units (mmBtu) in May, which is less than half the $9.41 per mmBtu paid for LNG in the same month.
But spot LNG is hovering around the same price as coal and its likely that over time the price Japan pays for the super-chilled fuel will decline.
This is because legacy oil-linked contracts will come to an end and likely be replaced by natural gas-linked, or hybrid deals that ultimately serve to lower the cost of LNG.
LNG supplies are also likely to increase by as much as 50% from current levels in the next decade, given the raft of recent project approvals and the expectation that many more will gain final investment approval in the next year or two.
In contrast, major thermal coal projects aimed at supplying the seaborne market are in short supply and increasingly difficult to get off the ground, as witnessed by the ongoing struggles of India’s Adani Enterprises to build its Carmichael mine in Australia.
The opinions expressed here are those of the author, a columnist for Reuters.
Source: Reuters (Editing by Richard Pullin)