American Electric Power (NYSE: AEP) said May 18 that it is seeking offers for the supply of eastern coal, delivered by barge, to one or more of its generating stations.
AEP is seeking proposals for up to 2 million tons of Northern Appalachia coal per year, beginning as early as January 2013 and ending as late as December 2017. It is also looking for up to 25,000 tons of Central Appalachia coal per month, beginning in January 2013 and ending in December 2013. Proposals with alternative terms will be accepted. Accepted bids will be at AEP’s discretion. Proposal packages must be received by AEP no later than 5 p.m. on May 31.
The specs for the Northern Appalachia coal, on a half-month basis, are 12,200 Btu/lb, 7% moisture, 9% ash and 6.5 lbs/mmBtu of SO2. The Central Appalachia coal specs, also on a half-month basis, are 12,000 Btu/lb, 8% moisture, 13% ash and 1.6 lbs/mmBtu of SO2.
The company, which buys coal through its American Electric Power Service Corp. subsidiary, didn’t specify which power plants this coal might go to. It has several fully-scrubbed power plants, including Mountaineer and Amos in West Virginia, that can take high-sulfur Northern App coal. It also has several plants that can take low- to mid-sulfur Central Appalachia coal, though that number has shrunk due to new scrubbers at Amos and several old, unscrubbed plants that have been shut lately or are about to be shut.
AEP’s Appalachian Power unit recently reported that a major contract for Northern Appalachia coal from CONSOL Energy (NYSE: CNX) began in January. This contract expires in December 2021, is for 1.25 million tons in 2012 and then 2.1 million tons in every contract year thereafter, and is to be used at Amos and Mountaineer, with a range of 5.96 to 6.68 lbs/MMBtu of SO2 content.
Jason Rusk, Director, Coal Procurement at American Electric Power Service, outlined recent events in the coal markets and APCo’s coal position in April 24 testimony filed at the Virginia State Corporation Commission.
“A strong and robust coal market in 2008 resulted in high market prices for coal,” Rusk reported. “As a result of the economic downturn, which came into play in late 2008 and early 2009, there was a significant reduction in coal prices, as well as lower market prices for electricity. This was followed by a moderate upward trend in coal prices, matched with lower coal market volatility that was present from the fourth quarter of 2009 through the first half of 2011. The market did not experience decreasing coal prices for the majority of 2011 because demand for coal in other countries continued to support the price of coal from the Central Appalachian Basin, the main type of coal consumed by APCo. Starting in the fourth quarter of 2011, Central Appalachian coal prices in the spot market did begin to drop in response to weak domestic demand. However, this recent downward trend in market coal prices has not materially affected APCo’s coal costs as APCo has not had a need to purchase significant amounts of coal in the spot market in recent months.”
Although coal production costs continue to rise, as a result of increased regulation, decreases in the issuance of mining permits, and the difficulties related to mining more challenging reserves, spot market coal prices are currently “suppressed” due to a lack of domestic demand, Rusk added. In general, coal prices are expected to trend upward as supplies of Central Appalachia coal decline. Additional market pressures include the uncertainty regarding future U.S. Environmental Protection Agency rules and how the implementation of those rules may affect future coal consumption.