As the agency noted earlier this month, the scenario was again linked to the first-half balancing act of higher demand with lower supply. Electric companies chose to burn off their large inventories instead of purchasing additional coal. Because international coal prices were also weaker, spot markets were still.

“The continued rise in natural gas prices drove more use of coal for electricity generation,” EIA officials said.

“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 the same period of 2012.”

While second quarter 2013 data is not yet available for analysis, the agency noted domestic consumption increases in the first half of the year would probably more than offset the weaker coal exports anticipated from the second quarter.

This, in turn, will result in a greater overall year-on-year demand.

Additionally, the EIA said, federal statistics from the US Mine Safety and Health Administration along with its estimates showed total coal production in the first half of this year was down 4% from 2012 to 21Mt.

“Coal imports dropped 500,000t 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,” EIA experts said.

“As a result, overall supply of coal was less than in 2012.”

On the inventories front, the electric power sector realized a drop in April to below the monthly five-year average. It was the first time that had occurred since December 2011, the middle of the northern winter season.

An overhang of plants’ coal stockpiles that existed during 2012’s first half was significantly reduced in first half of this year.

“Coal inventories at power plants have been steadily declining from January to April and shed a total of 28Mt by the end of April 2013 compared with the year before,” the EIA said.

In fact, the drawdown of subbituminous coal – mostly from the Powder River Basin region of Wyoming and Montana – of 18Mt, or 18%, was greater than the drawdown of bituminous coal of 10Mt, or 11%.

“Although the changes in supply-demand balance suggested that prices should rise, this did not happen,” the EIA said.

“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.”

The picture adds up to some fundamental changes in the industry, but those adjustments have varied by region, according to the agency.

Supply-demand balances tightened for coal in general, although changes in coal consumption and production from different mining regions were varied.

First half-year average natural gas prices at Henry Hub of $3.76 per million British thermal units in 2013 are probably part of the reason behind overall stronger growth of consumption of the lower-cost Powder River Basin and Illinois Basin coals.

“Although Appalachian and PRB coal production all declined in response to lower demand for deliveries, central Appalachian coal production was cut deeper than all other mining regions [at]10.3Mt, or 13%, compared with the first half of 2012,” the EIA said.

As has been seen clearly, the steadily declining domestic demand for steam coal from the central Appalachian region along with weaker met exports versus 2012 left producers announcing closures of their higher-cost mines.

“In contrast, Illinois Basin coal production increased year-on-year as the coal expanded its market both domestically and overseas,” the analysts noted.

“Higher gas prices and the lower cost of Illinois Basin coal relative to Appalachian coals supported more use of Illinois Basin coal for power generation in the domestic market.

“Geographic proximity to coal-exporting infrastructures also enabled the coal to benefit from international demand.”