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With Global Coal Shortage, Gas-to-Coal Switching May Switch Back

Since Russia began its invasion of Ukraine, global coal prices have seen a parabolic rise. The European coal benchmark at Rotterdam set a new record at the outset of hostilities, remaining elevated on the announcement that the European Union would ban Russian coal imports effective in August. These rising prices have coincided with rising natural gas pricing, making coal-to-gas switching (or vice versa) much more complex this summer. This analysis focuses on how the recent rise in international coal prices could keep upward pressure on Henry Hub into this summer.

Among international coal pricing points, Rotterdam coal pricing has historically trailed the benchmark for Asia and the Pacific (Newcastle). However, since the invasion of Ukraine, the European price has frequently topped the international market and driven the upward price trend, as shown in the chart above. Domestically, the spot price at Central Appalachia has run up 29% since Ukraine was invaded at the end of February. Though domestic demand pushed coal prices upward in 2021, this does not appear to be the case in 2022. When adjusted for seasonality and coal plant retirements, US power plant coal stocks have recovered from their acute 2021 shortage.

As for supply, Powder River Basin coal production has been rising, contributing most of the 5% YoY growth in US thermal coal production. Though Powder River coal pricing had seen gains in 2021, the rising costs of diesel and rail-freight have isolated this region from the coastal and export markets. In fact, as the price for Central Appalachia coal has risen, the lower quality Powder River coal has actually fallen 27% since the end of February. Much like their oil & gas counterparts, major US coal producers have stressed in recent investor materials a focus on capital discipline. Some, like Arch Resources, have initiated a gradual divestment from thermal coal assets. To the extent growth investment is planned, as for Peabody Energy, it is being directed toward the Powder River rather than other basins. However, due to the added cost of freight, any marginal production from the Powder River does not appear to be tamping down prices in demand regions.

As a result of these dynamics, some interior regions of the US near the Powder River Basin may retain access to inexpensive coal. Coastal regions, in contrast, will be more exposed to international prices. With Rotterdam leading the international market, the most immediate effects would be expected along the Atlantic and Gulf Coasts. Virtually all 2021 exports to the EU originated from ports along these coasts, with the largest share coming from the Port of New Orleans. The Gulf Coast also imports a significant amount of thermal coal from Latin America, mostly through the Port of Mobile. If some of these imports were diverted to Europe, the Southeast would be further exposed to the global market disruptions.

It is unclear how much upside remains for US coal pricing. Even before the Ukraine conflict, coal exports ended last year 13% above their pre-pandemic level. With the exception of Powder River, US coal prices have so far shown no signs of downward pressure from infrastructure limitations. Measuring correlation over the past 10-years suggests that US spot prices tend to lag the Rotterdam price by 6 to 7 months. Given that Rotterdam has moved up nearly $90 in the past 6 months, US prices could continue to gain through the summer so long as there is incremental capacity at port terminals.

Of course, natural gas pricing has also been on the rise this spring. Strong gas pricing may have contributed to a recent increase in thermal coal burn, with March generation from coal plants up 3% YoY. However, rising international coal prices could reverse this trend. A regression model can be used to estimate regional price sensitivities for coal and natural gas. Assuming a flat $6.50/MMBtu Henry Hub price through the summer, the chart below shows three coal price scenarios in the Atlantic and Gulf Coast regions which are expected to be most affected by the Ukraine crisis. In the first scenario, the Central Appalachia spot price remains near today’s level at $120 through the summer. In the second, Central Appalachia increases to $140 by August. In the third scenario, it reaches $160 by August.

In all three scenarios, power demand for coal would fall well below its summer 2021 peak. Whereas last summer saw widespread gas-to-coal switching, higher coal prices make it unlikely that this trend would repeat. Even at current coal prices, with Henry Hub at $6.50, the generation mix would be modeled to shift back towards gas, enough that peak gas-fired generation would surpass last year. If coal continued rising to $160/t, an additional 0.9 Bcf/d of coal-to-gas switching would be modeled for August.

Tempering these scenarios are regional considerations, such as gas pipeline capacity and local pricing dynamics. For instance, high utilization of gas pipelines in parts of the Southeast may limit the potential for incremental gas deliveries. However, on the macro level, the rising price of coal means the power sector will be less sensitive to Henry Hub. At least in the short term, power demand for gas will be strong even in the face of high gas prices. 

For more forecasts and analysis on the US gas market, contact BTU to sample the Henry Hub Outlook.

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Nick Jones is an Energy Analyst for BTU Analytics, researching natural gas demand fundamentals and emerging effects from the energy transition. Additionally, Nick tracks upstream trends in the Rockies. He earned his bachelor’s in economics from the University of Michigan.

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