American Oil and Gas Reporter - June 2022 - 35

SpecialReport: PowerGen And LNG
After an uptick in 2017, coal production
fell for three straight years. By
2020, with the pandemic raging, production
slid to only 535 MMST (orange
line in Figure 3), the lowest in more
than five decades. Volumes recovered
somewhat in 2021 to about 575 MMST,
but remained well below pre-pandemic
levels. Through the first 16 weeks of
2022, production totaled 181 MMST,
about 5% more than year-ago levels but
still 19% lower than the same period in
2019.
At the same time, outright volumes of
domestic coal consumption (dark gray
bar segments in Figure 3) and coal exports
(light gray segments) rose a combined
81.7 MMST (16%) year-on-year in 2021.
Coal's share of total power sector fuel
demand was also higher year-on-year for
most months in 2021, until November,
when it began losing ground to other
fuels, including natural gas.
Notably, exports of steam coal or
thermal coal (the kind burned by power
plants to produce steam for electricity
generation) climbed 47% year-on-year
in 2021 and were nearly back to 2019
levels. Moreover, quarterly EIA data
shows that steam coal exports in the
fourth quarter of 2021 totaled 9.7 MMST,
not only about 25% more than the same
period in 2020, but also up 13% from
the same quarter in 2019.
The lag in production relative to domestic
demand and exports in 2021 left
U.S. coal stockpiles at their lowest levels
in decades and coal prices at historical
highs (Figure 4), particularly in the U.S.
Northeast, which accounts for about 60%
of the country's coal exports. Coal stocks
for the U.S. electric power sector in the
SHEETAL
NASTA
Sheetal Nasta is managing editor and writer at RBN Energy LLC, with more than a decade
of experience analyzing natural gas markets. She is a regular contributor to RBN's " Daily
Energy Post " articles and publishes the daily RBN NATGAS Billboard supply-demand outlook
and RBN NATGAS Appalachia weekly update. Nasta previously served as manager of
energy analysis for the North American natural gas market at Bentek Energy, and as a senior
editor on the natural gas desk at Platts. She holds a bachelor's from Southwestern University
and a master's from Northwestern University.
JUNE 2022 35
second half of 2021 fell to the lowest on
record, according to EIA data going back
to 1973, and were sitting below 100
MMST in December for the first time
since 1974.
Relative Cost Comparison
As a result, Appalachian and Midwest
coal prices have surged to their highest
levels in more than a decade. As the light
brown line in the right graph in Figure 4
shows, Central Appalachia (CAPP) coal
prices averaged more than $90 a short
ton (ST) in December, the highest in
more than a decade, EIA indicates, and
prices have continued to rise. CAPP prices
for the week ending April 15 averaged
$117.05/ST, nearly double the $59.70/ST
in the comparable week last year. For the
same week, Illinois Basin coal prices averaged
$117.85/ST, more than triple the
price of $34.50/ST at the same time in
2021 and also the highest level in EIA
data dating to January 2011.
A look at coal pricing on a gas-equivalency
basis in Appalachia specifically
shows the cost of burning coal has been
higher and less economical than gas in
most recent months, despite soaring gas
prices. Figure 5 shows Big Sandy barge
prices from Bloomberg (brown line) versus
gas priced at Texas Eastern Transmission
M-3 hub (blue line), courtesy
of Natural Gas Intelligence.
Big Sandy coal prices are representative
of the CAPP delivery zone and reported
in dollars per short ton ($/ST). To convert
them into gas terms of dollars per MMBtu,
RBN Energy has added the transportation
cost of $5 to the coal price, then converted
tons to MMBtu by dividing the coal price
by 25. And finally, to make the comparison
apples-to-apples, the difference in coal
versus gas plant efficiency rates (i.e.,
heat rates) is accounted for by multiplying
the price by the heat rate ratio of a typical
coal plant (10.5) versus a typical gas
plant (7.2 in our model).
So as tight as the gas market has
been lately, the coal market has been
even tighter, raising the price at which
switching to coal makes economic sense.
Despite natural gas price premiums and
supply concerns (in the absence of a
stronger production response so far),
the economic incentive and flexibility
to switch to coal has been limited by a
supply-constrained market, especially
as the Ukraine war drags on and maintains
pressure on European consumers
to replace Russian coal.
What does this mean for the Lower48
gas injection season? Well, fuel
switching potential is typically greater
during lower-demand periods for power
generation (winter and shoulder months)
when outright demand is lower, than
during higher-demand periods (the hottest
summer months) when plant utilizations
tend to rise across the board. However,
assuming that coal market conditions
are unlikely to ease in the immediate
future, the lack of that switching mechanism
suggests gas burn for power is
likely to remain elevated at higher gas
prices even during the shoulder months.
That, in turn, raises the stakes for ongoing
volatility and price spikes throughout
the injection season.
❒
Editor's Note: For updated analysis
on the U.S. natural gas and crude oil
markets, see RBN Energy's daily blogs
and reports at rbnenergy.com.

http://www.rbnenergy.com

American Oil and Gas Reporter - June 2022

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