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FERC Winter 2019/20 Assessment Finds Strong Gas Supplies
13 November 2019
FERC staff's "2019-2020 Winter Energy Market
Assessment" was presented at the Commission's open meeting on
October 17, and it came to the same conclusion that other analyses
have done so far this fall: with abundant gas supplies and a mild
or normal winter forecasted, all indications are that prices will
remain low and shortages will not emerge.
"Going into this winter, natural gas storage levels are close to
the five-year average and natural gas futures prices are lower than
last winter. Also, pipeline additions in the Permian and Marcellus
Basins have bolstered the fuel supply chain, allowing additional
natural gas supplies to reach markets," staff said. "However,
certain regions are more dependent on natural gas than others, and
pipeline outages have the potential to increase both electric and
natural gas price volatility. Coal and oil-fired generation
continue to play an important role in maintaining electric
reliability during the winter, especially in the Northeast, where
winter demand for natural gas can exceed pipelines' capacity."
Those latter comments—again bringing up the sore spot of the
Department of Energy telling FERC nearly two years ago that it
should find a way to prop up coal and nuclear power
generators—brought out some comments by FERC Commissioner
Richard Glick and rebuttals from his fellow commissioners (more on
their exchange below). But otherwise, the three commissioners
seemed satisfied that the market is in good shape this winter,
especially in gas.
First, the weather. Staff reported that the National
Oceanographic and Atmospheric Administration is forecasting warmer
than average winter temperatures are in the Northeast, West, Texas
and Florida. The Upper Midwest is expected to experience normal
conditions.
But, being ever cautious, FERC staff tempered this prediction of
a calm winter with the following: "However, as seen in previous
winters, acute cold weather events can occur during warmer than
average seasons. These events increase the short‐term demand for
natural gas and electricity, which could create significant
operational and market challenges."
Natural gas continues to grow its share of the heating and power
market, so the condition of gas inventories and delivery capability
are critical in winter. FERC staff reminded the commissioners that
total US gas inventories on April 1 were about 30% below the
five-year average, but record gas production has led to the fastest
injection rate since 2015, and as of the week ending October 11,
EIA reported that the gap was basically eliminated.
More injections are expected in the next few weeks before the
deeper cold of winter starts to create a net pull on gas, and so
inventories are expected to exceed the five-year average (see
graph).
Figure 1: Natural gas storage levels expected to be slightly
above five-year average.
But staff nonetheless returned to the issue of "fuel
availability," stating that "availability of coal and fuel oil" can
be important in cold-weather periods. This drew a rebuke of sorts
from Glick, who asked how coal, which he said provides 2% of power
in New York and less in New England, can have an impact. Staff
avoided giving a response by falling back on the term "fuel
diversity."
Regardless of the coal-nuclear-gas debate, in the short term,
gas users and traders have recognized that gas is abundant, and
prices are well below those of a year ago. "As of October 4, 2019,
the NYMEX Henry Hub futures price, which measures the general cost
of the natural gas commodity, was 73 cents below last winter's
average futures settlement price, with an average price of
$2.56/MMBtu for January and February 2020," staff said.
But regional differences are immense, as measured by basis from
Henry Hub. "In Boston, basis futures prices averaged $6.54/MMBtu, a
$1.16 rise from last winter. New York City experienced the largest
declines from last winter. Basis futures prices in New York City
averaged $2.92/MMBtu, down $1.56 from last year," staff said.
Figure 2: Futures market signals lower natural gas prices
this winter.
Chatterjee asked about the high prices in New England, which
have been blamed for many years on a lack of sufficient gas
pipeline infrastructure. Staff response addressed this only
indirectly, by noting that both Algonquin and Texas Eastern have
said that they will have to reduce deliveries for periods of time
this fall to conduct integrity testing, and this this could account
for some of the price discrepancy.
Meanwhile, gas production records continue to be set, with EIA
marking the first half of 2019 as having production 12% above the
same period last year, at 90 Bcf/d. But demand also is rising, as
EIA forecasts a record 112 Bcf/d demand in January 2019, or about 3
Bcf/d above last January's record.
Where is record demand coming from? FERC staff said electric
power generation "is a driver of the forecasted increase in
domestic demand this winter, with an expected year-to-year increase
of 6% to 27 Bcfd. Industrial natural gas demand is also expected to
increase, but only by 2% to 25 Bcfd. However, residential natural
gas demand, which is typically the biggest driver of peak winter
demand, is expected to decrease 3% to 25 Bcfd."
The other demand factor, of course, is LNG exports. "Since the
beginning of 2019, the consumption of feedgas, which is natural gas
used as a raw material for LNG liquefaction, has grown over 1.5
Bcfd—from 4.5 Bcfd to more than 6 Bcfd. From March to October
2019, more than 3 Bcfd of new LNG export capacity went in-service,
representing the largest concentration of capacity additions in the
short history of U.S. LNG exports," staff noted.
This led Chatterjee to ask if the trend will continue, or it's
peaked. Staff said that they see another 1.5 Bcf/d of LNG capacity
coming online by mid-year 2020, but that the next wave of large
capacity additions is not likely until 2023.
Glick vs. McNamee
In addition to expressing his skepticism that coal power is
important in New York or New England, Glick listed a few other
complaints with both the process to develop the winter assessment
and its contents. This laid bare the rift between him and the
Republican commissioners, and McNamee answered Glick in several
instances.
Twice Glick said that FERC broke with prior practice by having
staff present the winter assessment without the commissioners
having a chance to review it and comment in advance. He criticized
this new policy and said it would lead to a report that is less
comprehensive and accurate. "This has been true for every single
report beforehand—before someone complained about it—that
the commissioners had a chance…to comment if there were questions
or maybe some numbers that might not seem correct…" he said.
McNamee took the bait after Glick's second comment, saying that
while he believes the commissioners should have input into the
report, it should come after it is released. "I think it's very
important for the staff to give us their unvarnished view of these
issues and for us not to scrub what you want to tell us," he said.
"We can respond to it…but I think it's very important that you
present this information."
Chatterjee answered more succinctly: "That's why we have this
opportunity to ask questions."
And so, Glick did ask questions. In a slide on the report, FERC
staff noted that 3.4 GW of coal power plants retired from March
2019 to June 2019 and another 6.2 GW are expected to retire from
July 2019 through February 2020. To some degree, this is offset by
5.6 GW of gas-fired capacity that's been added in the last
year.
So far, so good. But Glick asked staff why their assessment did
not also state the even greater increases in wind power (12 GW) and
solar (6 GW) since last winter—basically, challenging their
report for overstating the impact of the coal retirements.
McNamee responded by saying that those capacity additions are
misleading because coal power plants can run at 85%-90% capacity
for long periods of time (and higher when needed), while solar and
wind have run rates of 25%-50% of capacity. "You can't just measure
the megawatt capacity, the nameplate capacity, but have to look at
its availability to run when you're considering how to meet energy
system need," McNamee said.
McNamee's comment also referenced to Glick observing that
looking at reserve margins as the measure of system reliability
could lead to "over-procurement" of power production in
general.