IEEE Power & Energy Magazine - January/February 2017 - 67

january/february 2017

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In New England, the past few winters have seen some interesting issues concerning the interaction between gas and
electricity markets, whereby a stretched natural gas grid
has translated into very high gas and electricity prices. Gas
delivery occurs via pipelines from the south and the north
(Canada), including liquefied natural gas (LNG). Average gas
capacity suffices during the winter, but the system becomes
stretched on particular peak-demand days. Because of market
dynamics, which are a consequence of cheap shale gas in the
United States since 2010 and thus gas price differentials with
other world markets, LNG imports into New England have
seen a reduction; therefore, the winter supply of LNG from
Massachusetts's Everett and Canada's Canaport has declined,
leading to winter spike prices. In addition, because of the low
average U.S. shale gas prices and the environmental drive to
reduce CO2 emissions through the cap-and-trade system of
the Regional Greenhouse Gas Initiative (RGGI), over the last
few years natural-gas-fired electricity generation in New England has increased, along with the retirement of other plants
(using nuclear, coal, and oil).
This increase in gas-fired electricity generation has,
indeed, led to lower average wholesale electricity prices,
but it transfers the physical stress in the gas network to fuel
adequacy/reliability concerns in electricity generation, giving rise to sometimes very high electricity peak prices. The
situation requires the full attention of system operators, who
need to take both long-term and short-term actions, such
as increasing gas-transmission capacity (although this is
hampered by insufficient interest among capital investors
desiring to see long-term commitments from shippers but

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Energy-System-Integration Challenges in U.S. Markets

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To illustrate that energy-system integration challenges are
global and require careful consideration internationally,
we include here a few examples from the United States and
China. Due to lack of space, some elements/cases are only
cited without a full discussion.

figure 6. The decreasing tendency of forward electricity
wholesale prices in the CWE market (France, Germany, and
Benelux). [Source: Commission de Régulation de l'Électricité
et du Gaz (CREG), Belgium, Sept. 2016. The arrows have
been added by the authors.]

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Observations on Flexibility Challenges
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In the meantime (and as part of European promises for
the Paris COP21 Agreement), the EU has "sharpened" its
commitments toward 2030-albeit in a different way, not
unimportant for system interaction. The firmest commitment is the 40% reduction of GHGs with respect to 1990,
again split between an ETS part with an annual reduction
of 2.2 percentage points of the cap toward a 43% reduction
with respect to 2005 and an EU-wide non-ETS part of 30%
compared to 2005. For renewables, a 27% end-energy goal
by 2030 has been set, as well as an efficiency-improvement
goal of 30% compared to a baseline. For both the renewables
and efficiency goals, there are no binding national targets
but only an overall EU-wide objective.

hesitating to accept the financial liability, as well as by lack
of public acceptance and complicated permitting), increased
flexibility on the electricity-generation side by means of
multifuel units (gas and oil), and demand-response programs, among others.
On the other side of the United States, major energy-system integration problems arose in 2000-2001 in California
(later referred to as the "California electricity crisis"). As
the first state to fully introduce liberalized markets (often
inappropriately called "deregulation"), California experienced a combination of events and circumstances that
led to the world's richest country's richest state having to
"turn off the lights" (actually, cut all power-called rolling blackouts) to keep the system from collapsing. There
are many reasons for this then unprecedented failure, but it
was clearly a mix of many interacting factors, conditions,
and regulations. We mention, among others, a regulated

01

European Targets Toward 2030

figure 7. Typical retail electricity prices in Belgium for average customers with annual consumption of 3,500 kWh/a.
The different curves are for the same supplier (Electrabel)
but different distribution-grid regions. The dip from April
2014 through September 2015 is somewhat artificial; it is
due to a temporary reduction of the VAT from 21% to 6%
and back (by different governments). (Source: CREG, 2016.)
ieee power & energy magazine

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Table of Contents for the Digital Edition of IEEE Power & Energy Magazine - January/February 2017

IEEE Power & Energy Magazine - January/February 2017 - Cover1
IEEE Power & Energy Magazine - January/February 2017 - Cover2
IEEE Power & Energy Magazine - January/February 2017 - 1
IEEE Power & Energy Magazine - January/February 2017 - 2
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IEEE Power & Energy Magazine - January/February 2017 - 91
IEEE Power & Energy Magazine - January/February 2017 - 92
IEEE Power & Energy Magazine - January/February 2017 - Cover3
IEEE Power & Energy Magazine - January/February 2017 - Cover4
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