IEEE Power & Energy Magazine - January/February 2021 - 26

example, between 2010 and 2014 in Italy, the production of
the new combined cycle units was reduced by almost half;
the load factor, which was 44% in 2010, was 26% in 2014
(see Figure 3).
The Temporal Lumpiness of Solar and Storage

There is an inherent disadvantage to investments in solar
PVs and particularly in storage. The learning curve of
both technologies keeps improving, so costs keep falling.
Contrary to conventional generation, these technologies
are fully scalable and can be planned and installed in a
few months.
If a solar PVs investor makes a business case analysis
today in the face of energy market prices, he or she could
reasonably conclude that investing in a solar farm could
be in the money. But at the same time, one could quickly
conclude that, at the current speed of cost reduction of
solar PVs, in a year the investment very likely will be
out of money. Thus, if investors cannot find some way to
capitalize/hedge the value of their investment, the rational decision is to wait. This is particularly acute in the
case of storage. Storage is supposed to be financially justified by its ability to capture off-peak/peak spreads. But
it is well known that a modest amount of storage quickly
reduces the spread, so the deployment of storage negates
its own use case.
The Perennial Market Incompleteness

In principle, the above-mentioned lumpiness should not be
an issue in a perfectly functioning and complete market
when a fully informed and elastic demand side would be
willing to enter into long-term contracts with solar and storage providers, allowing them to proceed with the investment
and locking in the benefits their installations would bring to
the system. But even optimistically assuming that electricity
end users can soon become elastic in the short term (thanks
to digitalization, the Internet of Things, and so on), it is far

160

Year
CCGT Installed Capacity (GW)
CCGT Production (TWh)

figure 3. CCGT capacity and production in Italy.
26

ieee power & energy magazine

2019

2018

2017

2016

2015

2014

20
2013

2012

25
2011

100

2010

(TWh)

35
120

(GW)

140

from clear that demand will ever be willing to enter into
long-term commitments. This market incompleteness is at
the core of the global relevance not only of capacity markets
(even in the EU, where they were originally perceived as
an anathema; see Figure 4) but also of long-term auctions
for renewables.
In the particular case of RESs, it is increasingly argued
that, due to the extreme improvement of the learning curves,
there is no longer a need to design any sort of support
mechanism, not even auctions for long-term contracts. This
argument, in our view, does not properly take into consideration two still relevant key factors: vertical integration
(generation and retail) and the need to organize access,
thus allowing for the coordinated expansion of the transmission network. Vertical integration, a factor in the majority of systems where retail business has been liberalized,
can become an entry barrier for new investors in RESs as
they have larger difficulties finding counterparties to sign
the power purchase agreements required to properly finance
their projects. At the same time, long-term auctions are also
a helpful tool to guide future transmission network needs.
For example, in the Spanish power system where the peak
load is currently lower than 50 GW, the transmission system operator has applications for connecting up to 80 GW
of new RESs. While direct subsidies might be no longer
needed, keeping some sort of longer-term tendering is still
advisable. For the aforementioned reasons as well as some
others, it should not be expected that RESs are going to be
deployed efficiently if investors do not have access to longterm contracts of any kind.
In summary, a core criterion for designing a proper
decision-making procedure is that risks should be allocated
among those best prepared to manage them. In the early
1990s, the main risks that investors had to face were linked
to construction, fuel contracting (take-or-pay, tolling, and so
on), operation and maintenance (O&M), and competitors'
decisions. These risks could reasonably be expected to be
managed by the private sector. Currently, business investors
face significant technological uncertainties and changing
public policies and regulations. As market agents struggle
with these risks, we argue that policy makers and regulators
need to become involved with shaping the marketplace.

Conclusions and Recommendations
There is little doubt that the questions addressed in the
seminal works of the 1980s need to be revisited: the interplay between regulation (centralized planning) and market
forces must be reconsidered, and the relations among transaction characteristics and contractual and other governance
structures need to evolve with the times. In addition, shortterm pricing mechanisms will continue to be instrumental
in guiding optimal operation and investment decisions and
will need to be capable of involving power system agents
all the way down to the last kilometer as well as to properly
coordinate with regulatory-driven, long-term signals. These
january/february 2021

IEEE Power & Energy Magazine - January/February 2021

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