IEEE Power & Energy Magazine - January/February 2021 - 22

Research efforts should focus on what modifications of market rules
are needed to allow for efficient interaction between short-term
market prices and long-term complementary signals.
Two paradigmatic examples among the many others that could
be mentioned include the contract to build Hinkley Point C,
signed by the U.K. government, which is currently considering a regulated asset based (RAB) model to finance additional
nuclear plants, and the AB 2514 and AB 2868 energy storage
mandates in California. Next, we develop an in-depth review
of the factors that characterize a power sector context totally
different than the one reigning at the time most market-driven
restructuring processes started.

Old and New Factors Conditioning
Electric Power Markets
The Change in the Framing Conditions
Many instrumental framing conditions have changed since
electricity markets were originally designed and implemented.
First, politics have changed dramatically. The 1980s and
early 1990s were times when economic liberalism was much
more " popular " among policy makers. Also, power system liberalization was seen as a helpful tool to support other policy
decisions, such as the closure of the mining industry in the
United Kingdom.
Currently, the situation is totally different since economic
liberalism has lost momentum in a good number of jurisdictions and, more importantly, higher-order objectives (that
is, decarbonization via electrification of the economy) are
assumed to require tighter control of the investment decisions in the power sector.
At the same time, there was an underlying perception that
the degrees of freedom in the decision-making process to plan
the future expansion of power systems were rather limited. At
the start of the century, nearly all of the new investment alternatives in generation consisted of gas-fired and coal plants
with nuclear and hydro in some places. Many expected the
expansion of power systems to be led almost exclusively by
combined cycle gas turbines (CCGTs). The actual competition was, in fact, assumed to be built along two complementary dimensions. CCGT manufacturers were on one end and
gas suppliers on the other via the different contract formats,
such as the take-or-pay contracts that prevailed at the start
of the liberalization in the European Union (EU) context. The
risks that investors were supposed to face were also perceived
as largely controllable. Since investing in CCGTs seemed like
the only option, leaving these decisions to the market was perceived to be worth a try. At the same time, politicians did not
perceive that they were losing much control of one of the key
levers they had been using to gear economic policy.
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Currently, the number of variables of the capacity expansion problem has skyrocketed. Now, besides the traditional
generation technologies subject to new risk factors, such
as carbon prices and environmental constraints, there is a
diverse portfolio of new alternatives all linked to extremely
uncertain learning curves: renewable energy and demand
response sources, new nuclear technologies, carbon capture
and sequestration, different sorts of storage, hydrogen, and
so on. It is not just that there is a diversity of alternatives
but that these new choices are qualitatively different from
conventional technologies.
Gas-fired generation plants had other relevant expected
advantages. There was a consensus that CCGTs turned down
the marginal cost of electric energy supply over the long
term. In the EU case, in the second half of the 1990s, the levelized cost of energy assumed for CCGTs was in the range of
US$40/MWh, well below the energy component embedded
in end-user retail rates at the time. CCGTs' higher relative
efficiency, lower capital costs, and short building times (it
was expected that they could be installed in two or three
years), particularly in a context of high-interest rates, were
perceived not to have any technological competitor. In addition, CCGTs were supposed to be almost fully scalable and
could be sited almost anywhere, so there was no significant
need for transmission expansion.
Some of these key advantages, such as building times,
did not fully materialize. Relevant uncertainties, such as
environmental regulations, have been larger than expected.
Scalability has not been significant either, and due to greenhouse gas limitations (for example, carbon taxes), prices
will not be as low as originally assumed. Besides, building
transmission is increasingly more difficult for a number of
well-known reasons.
In a good number of power systems (mainly in the EU
case) where liberalization was implemented, there was a
significant overcapacity as, until that time, policy makers
took care to maintain reliability in a very risk-averse manner. In others, capacity mechanisms, in the form of capacity
payments or capacity markets, were implemented in a large
number of jurisdictions almost from the very beginning.
Only some European countries did not implement capacity
mechanisms, but it should not be forgotten that in such jurisdictions, the key incumbents were still publicly owned (such
as EDF in France, Enel in Italy, and Vattenfall in Sweden).
Finally, compared with the current state of affairs and financial situation, the willingness of equity to fund investments in
generation was much better than it is now. This led, for instance,
january/february 2021

IEEE Power & Energy Magazine - January/February 2021

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