IEEE Power & Energy Magazine - January/February 2021 - 75

to meet certain minimum preconditions to form a market,
such as
✔✔ adopting a cost-reflective end-user tariff
✔✔ unbundling the sector and imposing market share limits to reduce concentration in generation
✔✔ strengthening institutional capacity, especially in the
areas of regulation and system operation
✔✔ developing effective rules for electricity grid access
and expansion.
Under an energy spot market for power, prices exhibit
some degree of volatility, including periods of high and
low-if not very low/zero-prices. Such volatility is typical
of markets and has its role in creating the necessary signals
to induce investment in generation, with both fixed and variable costs, and flexible/peaking capacity, which is coupled
with capacity remuneration in some markets to avoid underor overinvestment.
Attracting investment for low-cost generation traditionally requires access to long-term financing, which,
in turn, depends on the predictability of revenue that the
market architecture delivers to investors. A careful balance must be achieved between attracting competitive
investments by shifting risks away from investors and
achieving low-cost outcomes for consumers in the short
and long terms.
In the choice of market design, this issue needs to be
considered within the broader context of preconditions. If a
market is highly concentrated and there is inadequate regulatory oversight, especially of state-owned utilities operating in competitive environments, even the most sophisticated market design is unlikely to contain market power
and, hence, likely to fail.
Even if these preconditions are met, price volatility entails
risk for buyers as well as sellers. Market participants need to
develop a risk appetite and have access to financial products
to manage risk. Without a well-developed financial market, it
is unlikely that these products would be available. Generators,
retailers, and distributors unable to manage their spot price
risk resorting to the safety of long-term contracts or power
purchase agreements (PPAs), which, depending on their
design, could be very inflexible and more advantageous to one
of the parties.
While PPAs have been very effective at attracting investment, the extent to which they can be relied upon depends on
each country's conditions and, especially, on expected demand
growth projections. With the advent of higher shares of renewables moving away from PPA contracts, there is additional
uncertainty in spot markets. Also, in many developing countries, pure spot markets have challenges simply because, in
many instances, it is not socially acceptable or politically manageable to charge consumers highly variable monthly electricity bills.
In some developing countries, expenditures on energy bills
can be costly. Even in higher-middle-income countries in Latin
America, such as Mexico and Chile, the poorest quintiles of
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the population spend 6.9% and 8.3% of their income on energy
(see Carvajal et al. in the " For Further Reading " section). Subsidies administered via electricity bills are still widespread in
the developing world, which complicates retail price formation
alternatives and, with that, the effectiveness of some market
design options.
Objectives, institutional capacity, social acceptance
of price fluctuations, and the risk appetite of policy makers vary across countries, signifying that market design
should adapt to local conditions and balance them to achieve
desired outcomes. Clear objectives are especially important
in this process, and the tradeoff of design options needs to
be weighted properly.
In this article, the experience of development bank
practitioners in supporting sector reform and financing
private generation assets in deregulated electricity markets of the developing world is described. The article also
shows that an increased share of renewables is already
demonstrating the need for a redesign of how electricity
markets function.
When structuring the project financing of generation
assets, such as renewables, lenders assess many associated
risks to determine the bankability of the project, such as
✔✔ transmission-curtailment risk
✔✔ balancing cost risk inherent to VRE generation
✔✔ dispatch risk (in countries that have stranded PPAs
and must-run thermal plants that bite into the merit
stack before zero-variable-cost renewables)
✔✔ contractual risk, including a volume-risk mismatch of
contractual commitment and VRE generation
✔✔ energy yield risk, banking on P90, P75, or P50 production (where Px means that, with probability x, the
output of a given power plant will be above a certain
level; energy output risk is key in project financing)
✔✔ engineering procurement and construction risk
✔✔ demand risk (when the offtake contract is " pay as demanded, " and distributed generation is a threat)
✔✔ payment risk (when the offtake is not in good financial standing)
✔✔ foreign exchange risk (when the contract is not in the
currency of the loan, usually U.S. dollars)
✔✔ environmental and social risk, including cumulative
impact on the watershed, airshed, and community
✔✔ technological disruption risk.
These are the main risks, and there are others, depending
on the country and sponsor of the project, such as reputational risks. Different banks have various ways of perceiving, assessing, and weighing these risks. As such, they may
perceive the same project differently. To attract investment in
power systems, it is important for market designers to consider that, on top of market risks-the ones addressed by
market design-most of the listed risks are also assessed by
investors and lenders. More complexity may add to efficiency
gains in market outcomes but may make projects riskier,
given the overall risk assessment.
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IEEE Power & Energy Magazine - January/February 2021

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