Does seaborne thermal coal’s future depend upon CCUS or NH3 co-firing?

While the commercial shipping sector has been focused on the IMO’s 2023 GHG Strategy discussions, and upcoming discussion of mid-term measures, it may have been distracted from environmental developments affecting important downstream markets, such as seaborne coal.

The Ukraine war has led to a limited revival in thermal coal consumption in Western Europe, but longer-term discussions involving the financial community revolving around definitions of emissions abatement appear to be introducing a deadline for the closure of existing power generation capacity.

Singapore is currently finalising a Singapore Asia Taxonomy, which is likely to require existing thermal coal capacity to close by 2040 at the latest. Much of the discussion revolves around definitions of abatement, as proponents of net zero technologies (such as carbon capture or ammonia injection) endeavour to include these solutions among acceptable options. The current discussions focus on measures to accelerate the closure of existing capacity, which poses significant challenges for southeast Asian and south Asian economies struggling to increase power supply to meet growing demand.

Ammonia abatement

Japanese researchers have been active developing solutions to permit supercritical coal plants to reduce their CO2 emissions by co-firing with ammonia. A 2019 study by IHI Corporation found that in some cases, an injection of 20% ammonia into coal boilers could also reduce their output of nitrous oxide (NOx), a gas that has significantly global warming potential than CO2.

IHI expects that coal co-firing with green ammonia could reduce carbon emissions, enough to bring those from an ultra supercritical coal powerplant down to 636g-CO2/kWh – below the level of an oil-fired plant – and would provide a cheap way of cutting emissions without completely rebuilding infrastructure, or increasing Japan’s reliance on nuclear power.

But leaving aside the vexed issue of accessing funding to permit such retrofits, there are reasons to believe that countries may not want to do this. In the US, research by Energy Innovation discovered that in 72% of cases, just continuing to run existing coal powerplants would be more expensive than building and running new renewable energy from scratch. That analysis, conducted before the Inflation Reduction Act passed in 2022, was later updated to 99%, after the Act provided $370bn in tax credits and other inducements for renewable energy.

Crucially, the study made no mention of carbon capture utilisation and storage (CCUS), which is being touted as coal’s Hail Mary. Since 2009, the US Department of Energy has invested some $684m in CCUS projects at 8 coal-fired powerplants, only to find that seven of the projects were never built when their operators could not make the economics stack up.

A further one, Petra Nova, situated at the W A Parish Generating Station, was shut down in 2020, soon after it was built, citing prohibitive operating costs. By this time, it had accrued a total capex cost after private investment of over $1bn, in exchange for a maximum CO2 abatement of 4%. In general, CCUS is expected to add millions of dollars in running costs to beleaguered powerplants, meaning that in due course, not only will the balance tip even further against coal and in favour of new renewables. According to the latest studies from Bloomberg NEF, the global average levelised cost of energy (LCOE) for onshore wind and solar ranged between $42-$48/MWh, while even new windfarms offshore now carry a cost equivalent to coal, at $74/MWh, BNEF finds.

High on its own supply

The thermal coal has been volatile in recent months. At the height of combined pandemic and war supply chain disruptions, in September 2022, coal prices reached $439/ tonne, substantially more expensive even than crude oil prices had been in the early pandemic. Then, coal prices reached their lowest ebb since mid-2021. This prompted predictions by the World Bank that for the rest of 2023, both coal prices and coal demand will stay elevated over pre-pandemic levels, but “…are expected to decline in the medium term.”

However, longer-term considerations are likely to play a greater role in the evolution of the seaborne thermal coal market than short-term market fluctuations. China remains the single largest consumer of thermal coal in the world – accounting for around 53% of global consumption – while by opting to effectively ban imports of lower-cost Australian thermal coal until February 2023, it chose to prioritise higher cost domestic production and regional imports, including Russian imports from Vanino and other Russian Far East bulk ports, as well as Mongolian coal imports.

While China is seeking to diversify its import sources to reduce its reliance upon low-cost Australian thermal coal, Anglo-Australian mining major BHP increasingly sees the future growth in its metallurgical coal business supplying material to Indian steel mills, as BHP’s chief commercial officer Vandita Pant told the Financial Times at the end of July. 

Goodbulk wants to get off the ride. It shed ten capes in 2022, and ten more this year. “Capesize rates were volatile over the quarter, starting off at $13,561 per day on 23 January 2023 then falling to their lowest at $2,246 per day on 17 February 2023 before rebounding up to $13,806 per day at the end of March and continuing to increase to $19,283 per day on 4 May 2023,” Goodbulk’s Q1 results noted.

For the time being, demand for shipping coal to China is rebounding dramatically, even though domestic production is once again increasing. Surging imports from Mongolia have had an effect, while capesizes benefit from growing Chinese imports from Indonesia, and to a lesser extent Russia and Australia. The latter resumed exporting coal to China in early February.

These add up to an increased total coal supply in China of 15%, as of end June. “Despite China’s strategy of pursuing increased domestic coal production, which has meant that year to-date production stands 5.8% higher than last year, its seaborne imports of coal have nevertheless surged 73% year on year so far,” said BIMCO chief shipping analyst Niels Rasmussen.

Norden is presumably feeling smug. It sold four bulkers at the top of the market in 2022, and in March, acquired six secondhand capesizes at knock-down prices which will arrive just in time to take advantage of this latest surge in China coal and iron ore imports. “During [Q1], we… captured significant profits from vessel sales, while widening our portfolio to cover all dry cargo segments with the purchase of Capesize vessels,” said CEO Jan Rindbo.

Yet if pre-pandemic trends are any guide, in July 2019, coal prices had more than halved year-on-year, to $50 per tonne. In fact, such was the spread between the price of coal and the cost of the fuel needed to transport it that shipowners were questioning the economics of these bulker trades even then. Now, the IMO is targeting (or perhaps it is suggesting, “national circumstances” permitting) that ships will need to switch to net-zero fuels – which shipowners will be lucky to source at double today’s prices.

At the end of June, CSSC Qingdao Beihai Shipbuilding held a naming ceremony for the first two – in a series of ten – 210,000dwt newcastlemaxes to be built for Belgian shipowner Compagnie Maritime Belge (CMB), which will be capable of running on ammonia. Based on the WinGD X72DF design, their engines will burn ammonia, allowing for voyages with zero funnel emissions – provided that WinGD’s engineers deliver NOx abatement solutions (as they expect).

The trade of last resort

But as exhibited by Goodbulk, the fundamental nature of dry bulk trades means that the line between profitability and loss is a razor’s edge, and unlike container ships, bulkers are almost never profitable enough to warrant investments in innovative technologies. Clarksons data finds the bulk carrier fleet not standing out as particularly prime stock for the total rejuvenation that will be necessary to use new zero-emission fuels: the average bulker is around 12 years old, the average capesize nearly ten. Norden paid $28m each for its 2012-built capesizes; compare with the now infamous case study of Hapag-Lloyd’s Brussels Express retrofit, which cost $35m. Given the volatility in freight rates, and concerns about the long term future of the specialist coal carrier trade, there will be questions about how smaller ship owners and operators in the Asian market will be incentivised to improve the efficiency of their vessels?