Slower growth in world coal demand, lower international coal prices, and higher coal output in other coal-exporting countries have all led to a decline in U.S. coal exports, said the U.S. Energy Information Administration in the Sept. 9 version of its monthly Short-Term Energy Outlook.
Lower mining costs, cheaper transportation costs, and favorable exchange rates will continue to provide an advantage to mines in other major coal-exporting countries compared with U.S. producers, EIA added. Coal exports for the first half of 2015 are down 20% compared with the same period in 2014, and U.S. steam coal exports fell by 21%, or 4.1 million short tons (MMst). The 5.8 MMst of coal exports for June 2015 was the lowest monthly volume for coal exports since February 2010. EIA is projecting that coal exports will fall by 18 MMst, to 80 MMst, in 2015, and then decrease by another 7 MMst (9%) in 2016.
U.S. coal imports, which increased by more than 2 MMst in 2014 to 11 MMst, are expected to average near that level in 2015 and 2016.
EIA said it expects a 7% decrease in total coal consumption in 2015, with electric power sector consumption also falling by 7%. Lower natural gas prices are the key factor driving the decrease in coal consumption. Projected low natural gas prices (power sector natural gas prices are 27% lower in 2015 compared with 2014) make it more economical to run natural gas-fired generating units at higher utilization rates.
The retirements of coal-fired power plants, many of them done earlier this year, in response to the implementation of the federal Mercury and Air Toxics Standards (MATS) also reduces coal-fired capacity in the power sector in 2015. But because the retirements are occurring throughout 2015, the full effect will not be evident until 2016.
Projected rising electricity demand and higher natural gas prices next year are expected to contribute to higher utilization rates among the remaining coal-fired power plants. Even with continued implementation of MATS, which the U.S. Supreme Court in June sent back to the U.S. Court of Appeals for the D.C. Circuit for further review, coal consumption in the electric power sector is forecast to increase by 1.5% in 2016.
Rising renewable energy tide puts a damper on any coal rebound
Expected growth in renewable-based generation is one barrier to a larger rebound in coal-fired generation in 2016, EIA reported. Non-hydropower renewable-based electricity generation is expected to grow by 12% in 2016, with the largest growth occurring in the South (21%).
Lower domestic coal consumption and exports, combined with a slight increase in coal imports, are projected to contribute to an 86 MMst (9%) decline in production in 2015. Coal production is expected to decrease in all coal-producing regions in 2015, with the largest decline (on a percentage basis) occurring in the Appalachian region. U.S. production is expected to decrease slightly (3 MMst) in 2016.
Electric power sector stockpiles were 168 MMst in June (the most recent month for which data are available), a 4% decrease from the level in May. This decrease in coal stockpiles from May to June follows the normal seasonal pattern, where coal stockpiles begin to decrease as the U.S. enters the summer months. Coal inventories in June 2015 were 35 MMst higher than in June 2014 when inventories were still recovering from the effects of colder-than-normal temperatures during the 2013-14 winter season.
The annual average coal price to the electric power sector increased from $2.34/MMBtu in 2013 to $2.36/MMBtu in 2014. EIA expects the delivered coal price to average $2.27/MMBtu in both 2015 and 2016.
Nearly 9,800 MW of coal capacity retired in first half of 2015
The electricity industry retired nearly 9,800 MW of conventional steam coal-fired capacity during the first six months of this year. These retirements represent 3.3% of the amount of operating steam coal capacity existing at the end of 2014. The states with the largest amount of retired coal capacity include Ohio (2,659 MW), Georgia (1,861 MW), and Kentucky (1,409 MW). The industry plans to retire an additional 3,133 MW of coal capacity this year and nearly 6,000 MW during 2016.
While the retirement of some coal-fired capacity has contributed to the decline in coal-fired generation over the past year, the relatively low cost of natural gas has been a more significant driver in coal’s declining share and the increase in the share generated by natural gas. During the first half of 2015, coal accounted for 34% of total generation compared with 40% during the same period last year, while natural gas accounted for 30%, up from 25% during the first half of 2014. For all of 2015, EIA expects the annual amount of coal generation will be 8.2% lower than in 2014, and the annual level of natural gas generation will rise by 14.5%. The forecast for coal generation increases slightly (1.4%) in 2016, and natural gas generation falls (3.0%) in response to projected higher natural gas fuel costs.
EIA’s forecast of U.S. total natural gas consumption averages 76.5 Bcf/d in 2015 and 76.6 Bcf/d in 2016, compared with 73.5 Bcf/d in 2014. EIA projects natural gas consumption in the power sector to increase by 14.4% in 2015 and then decrease by 3.3% in 2016. Natural gas prices, which are expected to remain below $3 per million British thermal units (MMBtu) through November, support increased use of natural gas for electricity generation in 2015.
EIA expects that marketed natural gas production will increase by 4.2 Bcf/d (5.7%) and by 1.7 Bcf/d (2.2%) in 2015 and 2016, respectively. EIA expects moderate production growth through 2016, with increases in the Lower 48 states expected to more than offset continuing production declines in the Gulf of Mexico. Increases in drilling efficiency will continue to support growing natural gas production in the forecast despite relatively low natural gas prices. Most of the growth is expected to come from the Marcellus Shale as the backlog of uncompleted wells is reduced and as new pipelines come online to deliver Marcellus natural gas to markets in the Northeast. Increases in domestic natural gas production are expected to reduce demand for natural gas imports from Canada and to support growth in exports to Mexico.
The Henry Hub natural gas spot price averaged $2.77/MMBtu in August, a decrease of 7 cents/MMBtu from the July price. The current Short-Term Energy Outlook report lowers the projection for prices slightly from last month’s forecast; monthly average spot prices remain lower than $3/MMBtu through November, and lower than $4/MMBtu through the remainder of the forecast. The projected Henry Hub natural gas price averages $2.84/MMBtu in 2015 and $3.11/MMBtu in 2016.
Natural gas futures contracts for December 2015 delivery traded during the five-day period ending Sept. 3 averaged $2.91/MMBtu. Current options and futures prices imply that market participants place the lower and upper bounds for the 95% confidence interval for December 2015 contracts at $2.08/MMBtu and $4.06/MMBtu, respectively. At this time in 2014, the natural gas futures contract for December 2014 delivery averaged $4.07 /MMBtu, and the corresponding lower and upper limits of the 95% confidence interval were $3.09/MMBtu and $5.35/MMBtu, respectively.