IEEE Power & Energy Magazine - January/February 2021 - 23

End-user retail rate making also requires a modification from
pricing energy to pricing capacity as well as equitably designing
fixed charges needed to avoid inefficient self-supply.
to the initial euphoria to invest in CCGTs in the United Kingdom (the so-called " dash for gas " ), Italy, and Spain.
At the same time, unfortunately, some problems that
were supposed to be healed as markets matured persist after
three decades. It is not just that many of these factors have not
turned upside down, but it is that many other new and critical
ones have arisen. Next, we review some of these issues.

The Persistent " Original Sin " : the Inaction
of the Demand
One of the basic factors for a market to function is obviously that both supply and demand participate properly in
the market. Fundamental to maximizing the net social benefit in both the short and long term, demand plays an active
role in the market by reflecting, through its offers, the true
value that an asset has in each moment. In economic terms,
that means the demand purchase offers reflect an asset's true
utility function at all times.
In times of generation shortage, if demand does not actively
declare its actual utility function in the market, the price could
theoretically rise to levels well above what most consumers
would actually be willing to pay. For this and other reasons,
since the first electricity markets were implemented, regulators
designed artificial price limits. Conversely, in most cases, these
caps have been well below the levels that demand would be willing to pay. Thus, price caps not only affect the optimal programming in the short term but also negatively condition investment
decision-making processes as they lead to underinvestment. As
Joskow has repeatedly argued in his publications, short-term
prices are distorted not only by price caps but also by many outof-market actions by an independent system operator to reduce
demand administratively, such as voltage reductions and nonprice rationing of demand (rolling blackouts).
In the long term, electricity prices, like those of many other
assets or services, are subject to a growing number of uncertainties. These especially affect investors in generation resources
due to the capital-intensive nature of these assets. Given this
reality, theoretically, it is expected that the demand seeks
to sign some type of long-term hedge, which in turn would
allow investors to mitigate their risk aversion. The fact that
this does not happen is the main cause that provides regulators
with a justification to intervene in the market, imposing on
the demand the obligation to contract a long-term guarantee,
or buying such a guarantee on its behalf. These regulatory
" solutions " include not only the so-called capacity remuneration mechanisms (CRM, the name commonly accepted in
the EU context) but also other centrally designed long-term
january/february 2021

mechanisms, such as the RES support mechanisms developed worldwide, auctions for long-term energy contracts
implemented in South America, the Hinkley Point C contract
signed by the U.K. government, or California's storage mandate (mentioned previously).
Price Caps and the Missing Money Problem

The main theoretical argument that originally justified the need
to design capacity mechanisms (payments/markets) was that the
existence of price caps and other out-of-market actions previously
mentioned led to the well-known " missing money problem. "
Under scarcity conditions, the market price should be equal to
the price the demand is willing to pay for not being interrupted.
According to its original formulation, the problem arises when
investments made under the expectation to benefit from high
prices when the system is tight cannot actually receive this income
because the regulator decides to set a maximum price limit.
Although the missing money problem has not ceased to be
pointed out as key to the need to implement a CRM, experience
does not seem to prove that it has really been instrumental.
In fact, the largest investment period in electricity generation
occurred in the late 1990s and early 2000s, just when administratively defined maximum prices were far more restrictive.
For instance, despite the existence of price caps, according to
the data provided by the U.K. Department of Energy and Climate Change in 2005 (Digest of U.K. Energy Statistics), the
installed capacity in 1993, two years after the market started,
was close to 65 GW and 10 years later it amounted to 75 GW
(around 25 GW of new CCGTs were installed in that period).
For example, similar phenomena took place in Spain and
Italy after the market was implemented in the late 1990s.
A similar effect took place in Texas (US$1,000/MWh price
cap), where the reserve margin increased during the first
decade of market functioning.
Paradoxically, the investment slowdown took place later,
when these maximum prices in most markets had been gradually growing. For example, at present, the top price in the
European day-ahead market is €3,000/MWh (in the intraday
market it is ±€9,999 and there is no price cap in the subsequent market segments; in this case, prices have been freely
above €10,000/MWh a good number of times). In the dayahead energy markets of other continents, high maximum
prices have been designed, such as the Electric Reliability
Council of Texas in the United States, where the maximum
price is US$9,000/MWh, or the National Electricity Market
in the southeast of Australia, where it is AUD$14,500/MWh
(approximately US$10,000/MWh). This does not mean that
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IEEE Power & Energy Magazine - January/February 2021

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