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A challenging outlook: US coal in 2015

Published by
World Coal,

Jeff Archibald, ICF International.

US thermal coal markets continue to face challenges due to changing electricity generation fuel needs, as well as uncertainty from an aggressive regulatory environment and pending US Environmental Protection Agency (EPA) regulations. The retirement of uneconomical coal-fired generation continues to be replaced by less expensive gas-fired generation technologies. Older coal plants face economic difficulties from both high capital cost upgrades of foundational equipment and the expensive pollution control technology implementation that would be required to operate in a stringent regulatory environment.


The share of projected electricity generation from coal-fired plants through 2015 remains in the 35 – 40% range and this is expected to remain stable through 2020. However, as regulatory impacts and the cost of carbon increase, generation from coal is significantly overtaken by natural gas beyond 2020 and is projected to decrease to 20% by 2040.

As advanced technologies for sulfur reduction have been and are being deployed, there is an increase in demand for high sulfur coal supplies from the Northern Appalachia (NAPP) and the Illinois Basin. Demand for low sulfur grades, which typically cost more, are expected to decrease as this trend continues.

Overall domestic demand for coal is expected to be gradually declining over the next ten years to about 750 million short t. In the longer term, coal demand will be influenced by the Clean Power Plan final rule and natural gas prices, and is expected to decline to 600 million short t by 2035.

Global demand for coal is expected to increase by 2.5 to 3%/yr through at least to 2020, which presents opportunities for domestic coal suppliers once international coal prices climb. However, without additional terminal capacity in the Pacific Northwest, the opportunity for exports will be significantly dampened.

International coal trade will become increasingly influenced by China’s actions and policies on in-country coal consumption. China’s new energy plan aims to bring coal's share of the energy mix to less than 65% in 2014, a target that was earlier set for 2017. Chinese imports declined 2% through July 2014 and strict policy measures were put in place to cut production volumes to contain inventory growth, which imply softening demand.

ICF’s analysis assumes slow development of West Coast port capacity, with 20 million short t of new capacity by 2018 and an additional 30 million short t by 2023.


As coal plants continue to retire over the next three years and exports fluctuate around 100 million short tpy, domestic production will remain flat for the next decade at an average of 915 million tpy.

In 2013, coal producers closed or idled 35.8 million short t of production. Approximately 56% and 23% of idled production is in Central Appalachia (CAPP) and NAPP, respectively, while Southern Appalachia and the Rockies account for 7% each and Illinois Basin 4%. This is on top of over 100 million short of production that was idled or closed in 2012.

Continued weakness in international metallurgical benchmark prices forced producers to announce 11 million short t of production cuts/mine closures in 2014; however, no new thermal coal production cuts were announced in CAPP.

Continued low natural gas prices and depressed electric demand coupled with the implementation of MATS in 2015 are collectively expected to result in nearly 63 GW of coal retirements from 2014 – 2016. However, most of the units that will be retired are smaller, less efficient units. These factors will put downward pressure on domestic coal demand and thus production.


A variety of EPA regulations are pending, including a recent decision by the US Supreme Court to look at one of the elements of the MATS regulations pertaining to whether the EPA considered cost as a factor in their decision. This matter is expected to be heard during the spring of 2015 with a decision following near summer.


Nationally, delivered coal costs will increase before flattening out in real terms as consumers shift from higher cost CAPP coal to lower cost NAPP and Illinois Basin coal. PJM COMED delivered coal costs will increase over time as Powder River Basin minemouth prices increase slightly due to increasing stripping ratios and as transportation costs continue to rise. Low natural gas prices will continue to pressure coal prices as well as uncertainty in the regulatory realm.

Written by Jeff Archibald. Edited by .

About the author: Jeff Archibald is a Senior Technical Specialist at ICF International with more than 18 years of experience performing asset valuations for power plants, coal prices and production forecasting, economic assessments, financial analyses, environmental site investigations and remediation and environmental management system evaluation.

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