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The evolving face of coal

Published by
World Coal,

Andrew Moore

The US Environmental Protection Agency's (EPA) Clean Power Plan (CPP) could not have come at a worse time for a US coal industry already looking vulnerable in the face of low natural gas prices and other regulatory challenges. While it is too early to say what the impact of the CPP will be – and whether it will withstand legal challenges – the long-term outlook looks fairly bleak for coal. Still, it looks set to remain a major energy source for the US and the world for decades to come.

Last July, Minnesota Power said it would idle and eventually close its coal-fired Taconite Harbor power plant on the shore of Lake Superior.

It followed up the announcement in September with an integrated resource plan filed with the state of Minnesota, noting the closure would be accompanied by plans to increase natural gas generation and add renewable power – all of which would help the utility “to position itself for compliance with” the CPP.

At 150 MW, the relatively small plant burned only 684 000 short t of coal in 2014 – a drop in the ocean compared with the 999.7 million short t of coal mined in the US last year. But it was enough to catch the attention of Peabody Energy, the largest US coal producer, which cited the closure in an August filing with the US Court of Appeals for the District of Columbia in support of an emergency stay petition brought against the EPA by 15 states opposing the CPP.

“EPA tries to brush off the Taconite shutdown as ‘likely part of the general shift away from coal,’ but the unrebutted evidence is that the [CPP] was a precipitating factor,” said the Peabody filing. “Indeed, a sector already weakened by market forces and pre-existing environmental regulations is even more vulnerable to draconian regulatory measures like the [CPP].”

Vulnerable seems an apt description for the US coal industry. While it is too early to tell what impact the CPP might have, it could not have come at a worst time. Low natural gas prices have made coal uneconomical to burn in many parts of the country. Meanwhile, in markets where coal can compete, producers are often pitted against each other.

The outlook could look even gloomier if utilities begin to view carbon dioxide as a risk regardless of what happens with the CPP. “Generally speaking, utilities are obviously looking at the CPP, and you know, there is some pretty clear handwriting on the wall here, and some are starting to take some action,” said one utility official who did not want to be identified.

What seems clear is the US coal industry faces an uncertain future, though by no means is it going away.

US coal production

In 2008, US coal production peaked at 1172 million short t, with roughly 94% consumed by industry and the electric power sector, where coal-fired generation made up 48.2% of the US power market.

That same year, prices reached an all-time high for the physical coal underlying the two Central Appalachia futures contracts: the 12 500 Btu/lb CAPP rail (CSX) contract, which hit US$160.60/short t, and the 12 000 Btu/lb CAPP barge contract, which hit US$143.25/short t.

Seven years later, it is a much different picture. According to the US Energy Information Administration (EIA), US coal production is estimated to total 914 million short t in 2015 – a 22% drop from the recent peak and the lowest annual total since 1986.

Coal generation is expected to make up 35% of the US power market in 2015, with the most share lost to natural gas, which made up 21.4% of US generation in 2008 but is expected to make up 31.6% in 2015.

And prices for the physical coal underlying two of the three major coal futures contracts are at multi-year lows: in early October, the CAPP rail contract fell to US$35.40/short t, a 78% drop from its 2008 peak, while the CAPP barge contract dropped to US$40.75/short t, down 72% from its 2008 peak.

All this has happened before the CPP has been made official and despite it facing an uncertain future. Already, 26 states and a number of industry groups have filed legal challenges to the plan, which would take effect in 2022.

Clean Power Plan impact

But the EPA’s projections do not bode well for the coal industry. According to the agency’s regulatory impact analysis for the plan, US thermal coal production could drop to 729 million short t by 2025 in its base case review. The figure could drop as low as 606 million short t under a more stringent scenario.

“The [CPP] turned out to be worse than we thought it would be,” said Paul Bailey, Senior Vice President for policy and affairs at the American Coalition for Clean Coal Electricity. “Coal is down a lot, and the EPA likes to claim that’s because of natural gas prices, and some is due to that, but a great deal of it from the analysis we’ve done is due to EPA regulations.”

In 2008, the net summer capacity of US coal-fired generation totalled roughly 313 GW, according to the EIA. As of October, Platts-unit Bentek Energy estimated net summer capacity for US coal-fired generation at roughly 300 GW, with another 24 GW of announced retirements by 2025.

Bailey and much of the industry attribute the recent closures to the EPA’s Mercury and Air Toxics Standards Rule, which mandated certain emissions controls be installed by April 2015. Even though the Supreme Court remanded the rule in June, utilities had already made the decision to close roughly 13 GW of coal-fired generation that was not economical to retrofit.

With the CPP, Bailey believes utilities could possibly shutter 40 – 50 GW of coal-fired generation, resulting in the closure of roughly a quarter of the US coal fleet compared with 2008.

“I think it’s a little premature to say how it will really impact the industry, and whether it will be actually implemented,” said Betsy Monseu, the CEO of the American Coal Council. “We know there is opposition to it far beyond just coal; there are utilities concerned states concerned […] and there is going to be a great deal of push back.”

Coal is not going away

Regardless of the outcome, Monseu rightly points out that coal generation is not going away. The surviving plants will likely run at higher capacity factors, “but I don’t believe we’ll resign to a smaller market,” she said.

“We’re existing in a smaller market because of regulation in large part, and changes in energy markets, and we’re adapting to that,” Monseu said. “You’re seeing lots of restructuring on the coal side and with efforts to improve balance sheets and restructure as a leaner, more efficient, segment for the future.”

Robert Moore, President and CEO of Foresight Energy LP, a major producer of Illinois Basin coal, wrote in response to emailed questions from Platts that he believes the US thermal coal market might drop to 600 – 650 million short tpy if the CPP is implemented.

“It is too early to tell what the coming restructuring of the coal industry will do to overall production levels in each region, but it is evident that the CPP encourages using higher Btu thermal coal from the Illinois Basin,” wrote Moore. “The 8400 Btu/lb and lower production in the Powder River Basin will likely be negatively impacted.”

In the base case review of the EPA’s regulatory impact analysis for the CPP, the agency projects coal production from the US’s Interior region, which includes the Illinois Basin, would total 250 million short t in 2025. In 2014, Interior production totalled 188.7 million short t.

And in the Powder River Basin, the nation’s largest coal-producing region, the EPA forecasts 2025 production to total 379 million short t – down from 430.4 million short t in 2014.

Without the CPP, Moore noted that US coal production will likely remain robust, referring to the EIA’s most recent long-term projections.

In its 2015 Annual Energy Outlook issued earlier this year, the EIA forecast in its base case review that US coal production would total 1105 million short t in 2025 and 1118 million short t by 2030, though it did not include the CPP in its modelling. The EIA’s forecast points to the fact that coal-fired generation historically has been an inexpensive baseload power source and will likely remain so in the future, especially as natural gas prices are forecast to increase due to greater industrial and power demand as well as increasing LNG exports.

In 2008, when coal production peaked, the average price for the NYMEX Henry Hub natural gas futures contract was US$8.891/million Btu. As of 15 October, the 2015 contract price averaged US$2.744/million Btu, and the average price for the 2020 contract was US$3.224/million Btu.

In the base case review in its annual forecast, the EIA put spot natural gas price at US$4.88/million Btu by 2020 and US$7.85/million Btu by 2040, in 2013 dollars.

Technology solutions needed

Even if states and utilities work to eliminate carbon emissions, coal remains integral to the reliability of the power grid.

Minnesota Power made headlines with its plan to close Taconite Harbor, but the utility will still have more than 11 GW of net summer coal-fired generation capacity in its fleet by 2020, according to its recent integrated resource plan.

“Even though gas prices are still low, coal is still very economical in many places,” said Joe Nipper, Senior Vice President of Regulatory Affairs and Communications for the American Public Power Association. “It’s available to run. Some are not running because of gas prices, but it is available. So we have lots more capacity to generate electricity from coal-fired plants, but utilities are often choosing to generate or dispatch from other sources, but may be keeping coal capacity maintained and up to date, and running those units some of the time.”

There is also the possibility that commercial-scale carbon capture could become economically viable, enabling coal-fired power plants to reduce their carbon emissions. At the moment, however, carbon capture is generally confined to areas of the country that contain oil fields. The captured CO2 is pumped into existing oil wells to help increase production, a process known as enhanced oil recovery (EOR). But the costs of capturing and transporting the CO2 are high.

Further down the road, the coal industry faces a daunting reality. The last US coal plant entered service in 2012 and, while there are several coal plants in various stages of planning, only one is under construction: Southern Co.’s Kemper plant in Mississippi, which gasifies locally-mined lignite to fire an integrated gasification combined-cycle power plant.

Despite the addition of carbon capture technology, the plant is likely to serve more as a warning than a sign of progress, as it is more than US$4.7 billion over its initial US$2.2 billion budget.

Furthermore, in 2014 the EPA issued stringent carbon emissions guidelines for new power plants that essentially rule out the construction of any new coal-fired plants, given that coal would be physically unable to come under the emissions limits. That means that by 2040, most of the plants in the existing US coal-fired fleet will have reached the end of their useful lives of 70-plus yr. While plants can be maintained and their lives extended, costs go up, while efficiencies go down, making it a less attractive option.

Exports also remain an option, but not in the current environment. A global oversupply of coal has pushed down prices worldwide, and new demand from Asia is not likely to materialise for several years.

“Looking at this strategically, and for the longer term, one thing that is very important is technology and continuing to advance [carbon capture] and support for that at the federal level,” said the American Coal Council’s Monseu. “There is a recognition that coal is going to be a major fuel source for the US and the world for decades and, if that’s the case, then if there are goals for emissions reductions, there needs to be commitment to technological solutions to making that happen.”

Edited by Harleigh Hobbs.This article first appeared in the January 2016 issue of World Coal

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