As coal producers continue to report increased volatility in demand, just over half of the coal sold to U.S. utilities in 2017 was delivered on spot deals or through contracts with less than a year remaining.
Persistently low and competitive prices for natural gas have led many utilities to run coal plants at varied rates to match demand, and industry observers have reported the days of long-term contracts to feed baseload coal-fired power plants are gone. Just 21.3% of the coal sold to electricity generators in 2017 was delivered on contracts with more than three years remaining at the time of delivery, according to an S&P Global Market Intelligence analysis of U.S. Energy Information Administration data.
"The reality is the industry has changed massively from where it was five or six years ago when utilities used to know what they were going to burn through their coal plants and would buy accordingly," Cloud Peak Energy Inc. President and CEO Colin Marshall said on a call with analysts in April. "There is a lot more variability, which is what we're coming to terms with."
Thermal coal producers like Cloud Peak are hoping the rapid rate of coal-fired power plant closures will slow and give some opportunity for supply and demand to come back into balance. The problem for the coal sector is natural gas remains cheap and plentiful and the existing coal fleet, most of which is not designed for ramping generation up and down, is getting older with few signs of any new coal construction in sight.
An executive with a company now part of Evergy Inc. recently said the company has adapted its baseload power operations to "flex and cycle with market opportunities." Vistra Energy Corp. has plans to upgrade a legacy coal fleet it acquired to be better able to ramp up and down to "create more flexibility and value." Other companies including Duke Energy Corp. and Ameren Corp. have said power plants being run as baseload sources of energy will be increasingly less likely as utilities seize on cheaper sources of power when they are available.
"The level of volatility you will see in the system has never been seen before. It's getting ready to happen," Duke Energy Corp.'s managing director of fuel procurement, Brett Phipps, said at a recent coal conference when talking about supply and demand factors in today's coal market. "The way that we have constructed things in the past is not going to work."
Between 4.4% and 10.7% of the coal delivered to U.S. utilities on a monthly basis was sold on short-term, spot contracts from 2008 to 2012. That started trending upward in 2013 and by December 2017, spot coal deals made up 16% of coal sales, according to federal data.
During a recent peak in August 2012, coal delivered on contracts with two years or more remaining constituted 45.7% of the coal sold to U.S. utilities. That then trended downward before hitting a low of 25.2% of coal delivered in April 2017. Since then, the trend has reversed slightly and more coal has been delivered through contracts with more than two years remaining before expiration.
Long-term contracts provide certainty to producers who must decide when and where to deploy capital. With coal readily available and cheap, utilities have hesitated to sign contracts for coal they are not sure they will be able to use.
Pricing has been so weak in some cases that Marshall recently said Cloud Peak was "very close" to the point where the company does not want to sell at prices utilities are willing to pay.
Daniel Scott, executive director of MKM Partners, wrote in a June 12 note that while normal U.S. utility coal inventory levels were about 140 million tons a decade ago, today that number, on an equivalent days of burn basis, needs to be closer to 100 million tons before coal companies can wield pricing power with domestic utility customers. Currently, he noted, nationwide utility coal inventory levels are around 126 million tons.
The Powder River Basin, where Cloud Peak operates, is particularly sensitive to utilities turning to natural gas power plants, Moody's recently noted.
"Surface mines with significant scale help keep costs down, which is important considering the freight considerations, but the basin is vulnerable to fuel switching by utilities, particularly since low sulfur content means that PRB coal can be used in older and unscrubbed power plants," a May 31 note said. "New gas-fired generation will continue to replace these plants."
Meanwhile, Central Appalachia's significance in thermal coal markets has been sharply reduced due to a steep decline in demand for the region's costlier coal. While producers in the basin have seen a resurgence in demand for metallurgical coal used to make steel, utilities now buy significantly less coal from the region to make electricity. According to EIA data, nearly three-quarters of the coal delivered from Central Appalachia producers in 2017 was to fulfill spot deals or through contracts with less than a year remaining on their term.