(from Various EIA Sources)
The Obama administration announced in January 2016 that the Interior Department will halt new coal leases on public lands. Under the plan, companies can continue to mine their existing leases.. Though an insult to injury, considering the damage done in 2015, the lease freeze may not make a difference as the coal industry is struggling to sell what it already has.
Mining and Exploration
Mining and exploration investment declined 35% in 2015, the second largest year-over-year decline since the U.S. Bureau of Economic Analysis (BEA) began reporting the series in 1948. Most mining and exploration investment reflects petroleum exploration and development, but the category also includes natural gas, coal, and other minerals. Mining and exploration investment declined from $135 billion in 2014 to $87.7 billion in 2015, weighing down investment growth more than any other segment of nonresidential investment. Total private fixed investment, of which mining and exploration is a small subset, grew 4% in 2015 to $2.7 trillion. Low commodity prices remain a significant factor in U.S. firms’ investment decisions.
U.S. gross domestic product (GDP) grew 2.4% in 2015, according to fourth-quarter and annual 2015 advance estimates by BEA, the same rate as in 2014. Gross private domestic investment contributed 0.8% to the 2.4% GDP growth in 2015. BEA tracks several types of private investment, broadly split into residential and nonresidential. Within nonresidential are three categories: equipment (such as industrial and transportation equipment), intellectual property products (such as software and entertainment), and structures (which includes mining and exploration but also commercial, manufacturing, power, and communication structures).
Mining and exploration investment as a share of total private investment declined from 5.2% in 2014 to slightly more than 3% in 2015. Low oil prices remain a major factor in oil exploration and production firms’ decisions to reduce capital expenditure. Fourth-quarter earnings statements from U.S. oil companies indicate plans to further reduce capital expenditure to balance spending with lower cash flows until crude oil prices increase enough to make investments economic. These oil-company reductions could continue to put downward pressure on investment spending in the broader U.S. energy sector.
Principal contributor: Jeff Barron, EIA
The United States remains a net exporter of coal, exporting 74.0 million short tons (MMst) and importing 11 MMst in 2015. Coal exports fell for the third consecutive year in 2015, ending the year 23 MMst lower than in 2014 and more than 50 MMst less than the record volume of coal exported in 2012. Slower growth in world coal demand, lower international coal prices, and higher coal output in other coal-exporting countries contributed to the decline in U.S. coal exports. Lower mining costs, cheaper transportation costs, and favorable exchange rates (compared to the U.S. dollar) continue to provide an advantage to producers in other major coal-exporting countries such as Australia, Indonesia, Colombia, Russia, and South Africa.
One of the only increases in U.S. coal exports in 2015 was for exports to India, which increased by almost 2 MMst, bringing its share of U.S. coal exports to 9%, up from 5% in 2014. Coal exports to the rest of Asia fell. Europe has traditionally been a leading destination for coal exports, but exports were down 14.6 MMst (28%) in 2015.
U.S. coal exports are mainly shipped from six customs districts that together accounted for 90% of U.S. exports in 2015. Norfolk, Virginia, the largest coal port, shipped 26.2 MMst of coal, accounting for 35% of total U.S. exports. Baltimore, Maryland, was the only major customs district (districts that generally export more than 1 MMst of coal annually) to increase exports in 2015, largely driven by increased exports to India.
U.S. coal imports totaled 11.3 MMst in 2015, the same as in 2014, with 85% of imports being steam coal that is primarily used to generate electricity. Although the amount of imports did not change in 2015, the source and point of entry of these imports changed from 2014. The biggest changes in the origin of U.S. imports involved imports from Colombia and Indonesia, which increased by 8% and decreased by 42%, respectively. Colombian coal is highly competitive with domestic coal at power generators located along the Gulf of Mexico and southern Atlantic coasts. Metallurgical coal, which is used in the steelmaking process, was primarily imported from Canada.
Tampa, Florida, overtook Mobile, Alabama, to become the largest recipient of coal imports in 2015. The closure of coal-fired electricity generators in New England led to a 41% (0.5 MMst) decrease in imports into the Boston, Massachusetts, customs district. Increased Canadian imports drove the increase of imports (0.1 MMst, 55%) into the Portland, Maine, custom district. Imports into the Honolulu, Hawaii, custom district remained nearly unchanged as declines in Indonesian imports were offset by imports from Canada and Australia.
Principal contributor: Elias Johnson, EIA
Since reaching a high point in 2008, coal production in the United States has continued to decline. U.S. coal production in 2015 is expected to be about 900 million short tons (MMst), 10% lower than in 2014 and the lowest level since 1986. Regionally, production from the Appalachian Basin has fallen the most. Low natural gas prices, lower international coal demand, and environmental regulations have contributed to declining U.S. coal production.
The United States has five major basins or regions that produce coal. The largest decline in coal production was in the Central Appalachian Basin, largely because of its difficult mining geology and high operating costs. Coal production in the Central Appalachian Basin in 2015 was 40% below its annual average level over 2010-14. In three other main areas, the Northern Appalachian Basin, Rocky Mountain region, and Powder River Basin, production in 2015 was 10% to 20% below their corresponding regional annual average levels over 2010-14. By contrast, coal production from the Illinois Basin in 2015 was 8% higher than production levels over 2010-14.
In the United States, almost all coal is used to generate electricity. Recently, coal’s share of electricity generation has fallen as its market share of natural gas and renewables increased. The average daily natural gas spot price at the Henry Hub, a key natural gas benchmark, fell from $4.38 per million British thermal units (MMBtu) in 2014 to $2.61/MMBtu in 2015, resulting in greater natural gas-fired electricity generation. In April 2015, natural gas-fired electricity generation surpassed that of coal-fired generation on a monthly basis for the first time in history, and it did so again in each of the months from July through at least October, the latest monthly data available. The most recent Short-Term Energy Outlook estimates that 2015 power sector coal consumption will be about 764 MMst, the lowest level since 1988.
With the exception of the Rocky Mountain region, steam coal prices in major basins experienced double-digit percentage declines in 2015. Central Appalachian coal continued to be economically challenged compared with natural gas for electricity generation, and average steam coal spot prices dropped by another 22% in 2015, following a decline of 13% the year before. Coal prices in the Powder River, Illinois, and North Appalachian basins, which had remained largely unchanged during 2014, decreased 18%, 26%, and 29%, respectively, in 2015.
Nearly 18 gigawatts (GW) of electric generating capacity was retired in 2015, a relatively high amount compared with recent years. More than 80% of the retired capacity was conventional steam coal. The coal-fired generating units retired in 2015 tended to be older and smaller in capacity than the coal generation fleet that continues to operate.
Coal’s share of electricity generation has been falling, largely because of competition with natural gas. Environmental regulations affecting power plants have also played a role. About 30% of the coal capacity that retired in 2015 occurred in April, which is when the U.S. Environmental Protection Agency’s Mercury and Air Toxics Standards (MATS) rule went into effect. Some coal plants applied for and received one-year extensions, meaning that many of the coal retirements expected in 2016 will likely also occur in April. Several plants have received additional one-year extensions beyond April 2016 based on their role in ensuring regional system reliability.
Much of the existing coal capacity in the United States was built from 1950 to 1990 during a time when electricity sales were growing much faster than population and gross domestic product. In more recent years, electricity sales growth has slowed or fallen, and net capacity additions (of all fuel types) have been relatively low. The coal units that were retired in 2015 were mainly built between 1950 and 1970, and the average age of those retired units was 54 years. The rest of the coal fleet that continues to operate is relatively younger, with an average age of 38 years.
The coal units retired in 2015 also tended to be smaller than the rest of the coal fleet. The net summer capacity of the average retired coal unit was 133 megawatts (MW), compared with 278 MW for the rest of the coal units still operating.
The amount of coal capacity retired in 2015 was about 4.6% of the nation’s coal capacity at the beginning of that year. Nearly half of the 2015 retired coal capacity was located in three states—Ohio, Georgia, and Kentucky—and those states each retired at least 10% of their coal capacity in 2015. Other states that traditionally have had high levels of coal-fired electricity generation, such as Indiana, West Virginia, and Virginia, each retired at least one GW of coal capacity in 2015.
Principal contributor: Owen Comstock, EIA