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 CO
2
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 CO
2
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.”
24
|
World Coal
|
January 2016
