While coal market fundamentals changed in first-half 2013 compared with the same period of 2012, spot prices remained largely unchanged, the U.S. Energy Information Administration reported in the July 26 version of its “Today in Energy” feature.
Demand for coal was higher and supply was lower in the first half of 2013, but because power generators chose to burn off large coal inventories instead of buying more coal and because international coal prices were weaker, the spot market remained largely unchanged.
The continued rise in natural gas prices drove more use of coal for power generation. This, combined with higher electricity demand, resulted in total coal consumption for electricity generation in all sectors of 31 million tons, or 13%, more in the first four months of 2013 than in January-April 2012. Although data for the second quarter of 2013 are not yet available, the increase in domestic consumption for the first half of 2013 is likely to more than offset the weaker coal exports anticipated in the second quarter of 2013, resulting in higher year-on-year total coal demand.
Total coal production in the first half of 2013 was 21 million tons, or 4%, lower than in the same period of 2012, according to U.S. Mine Safety and Health Administration (MSHA) data through the first quarter of 2013 combined with EIA estimates for second-quarter 2013.
Coal imports dropped 0.5 million tons year-on-year in the first four months of 2013 and are likely to remain largely unchanged year-on-year for the first half of 2013. As a result, overall supply of coal was less than in 2012.
Inventories in the electric power sector dropped below the monthly five-year average in April 2013 for the first time since December 2011. A big overhang of coal stockpiles at power plants seen in the first half of 2012 was largely reduced in first-half 2013. Coal inventories at power plants have been steadily declining from January to April and shed a total of 28 million tons by the end of April 2013 compared with the year before. The drawdown of subbituminous coal (mostly Powder River Basin coal) of 18 million tons, or 18%, was greater than the drawdown of bituminous coal of 10 million tons, or 11%.
“Although the changes in supply-demand balance suggested that prices should rise, this did not happen,” EIA pointed out. “Increased demand was largely met through inventory withdrawals rather than through increased purchases from coal producers. That, plus lower international coal prices, put downward pressure on domestic coal prices.”
EIA said that at the end of June, spot steam coal prices for Central Appalachia (CAPP) and Northern Appalachia (NAPP) coals were around $2.50/MMBtu, with Illinois Basin (ILB) coals coming in at a little less than $2/MMBtu, Rocky Mountain coal (Utah and Colorado) at around $1.50/MMBtu and PRB coal at a little over $0.50/MMBtu.
While the supply-demand balance tightened for coal in general, changes in consumption and production of coal from different mining regions varied. The rise of first-half-year average natural gas prices at the Henry Hub to $3.76/MMBtu in 2013 is likely to have resulted in overall stronger growth of consumption of the lower-cost PRB and ILB coals, EIA said.
Although Appalachian and PRB coal production all declined in response to lower demand for deliveries, CAPP coal production was cut deeper than all other mining regions—10.3 million tons, or 13%, compared with the first half of 2012. Steadily declining domestic demand for steam coal from CAPP and weaker exports of metallurgical coal compared with the year before forced producers to close higher-cost mines in the CAPP region.
In contrast, ILB coal production increased year-on-year as the coal expanded its market both domestically and overseas. Higher gas prices and the lower cost of ILB coal relative to Appalachian coals supported more use of ILB coal for power generation in the domestic market. Geographic proximity to coal-exporting infrastructures through the Gulf Coast region also enabled the coal to benefit from international demand.