IEEE Power & Energy Magazine - November/December 2019 - 62

markets are designed to align with the physics of electricity
generation and delivery, existing designs differ across the
globe. Will these designs continue to provide the right incentives for industry to deliver reliable and affordable power? Will
continued tweaks be necessary to accommodate the changing
characteristics? Or will the industry see large restructuring
efforts, such that existing designs are no longer feasible given
the substantial changes needed to supply this much energy
from resources with the characteristics described? We do not
have the answers but provide insights on where some of the
discussion has been to date.
Although market designs differ across the globe, most
regions have a central focus on prices based on marginal
operating costs to supply energy. By reducing energy supply costs, typically through heat-rate improvements and
fuel-cost reductions on thermal plants, the participant earns
a higher profit when the cost of the marginal providers is
unchanged. For a system with primarily renewable resources
supplying energy, the incentive to reduce operating costs is
not necessary; the operating costs are generally as low as
they can be. So to answer the market-design question, we
start by asking what other attributes and behaviors a market
should incentivize on this future system. This may include
the following characteristics:
✔ lower costs for capital, operations, and maintenance
✔ locating supply so energy can be delivered where it is
needed and reducing the infrastructure (e.g., transmission) costs
✔ providing the most energy per installed unit of capacity (increasing capacity factors, which is similar to
lowering capital costs)
✔ reducing the impact of variability and uncertainty
and potential for load shedding or other reliability
consequences
✔ providing sufficient reliability services
✔ demand-side participation.
Many of these attributes are incentivized in existing market
designs. With different outcomes and participant behavior,
it is unclear whether the features that incentivize these attributes today will still be there tomorrow. We review three
components of the electricity-market suite of products: the
energy market, the reliability services markets, and other
products or services that may or may not yet exist.

The Bread and Butter of Electricity
Markets: The Energy Market
In nearly all electricity markets around the world, the
energy market is the prime source of revenue for market
participants. All other services are there to support the
energy market. Prices are typically based on the marginal
operating cost of supplying energy, approximated as the
variable cost of the most expensive resource selected to
supply energy. Energy markets have gone through various reforms since their inception, with some significant
changes. U.S. markets use locational marginal pricing for
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every generator node on the system, with centralized unit
commitment and economic dispatch as well as prices that
often include three-part offer costs (startup cost, minimumload costs, and energy-offer curve). European markets typically have zonal prices with decentralized unit commitment
and single-part offers (startup and no load must be included
in the single offer). In markets like ERCOT and AEMO, the
only revenues available are from the energy and reliability
services markets, whereas others have capacity payments
of some form. Although there have been some substantial
changes, not many are due to increasing levels of variable
renewables entering the market.
With increasing zero-variable-cost VRE, we may observe
more periods of lower prices during high VRE production,
which can make it difficult for the remaining generators to
recover their costs. These generators may either increase
their offer prices to recover those costs (which may trigger
automatic mitigation of offers or make them uncompetitive),
have other administrative "adders" to the price, earn greater
revenue in other products where they exist (e.g., capacity
markets), or face "missing money" and potentially withdraw
from the market. If the resources that withdraw due to insufficient revenue are still needed by the grid operator, it is possible that the market design is flawed and needs modification. In existing designs, when this happens, out-of-market
actions may take place.
Although lower energy prices are anticipated on systems
with higher renewables, this is not necessarily proven in all
cases. Today, when a system is at greater risk, prices are
set by administrative "shortage" prices, values that often
exceed US$1,000/MWh in the United States. Typically,
the system is short in operating reserve, and this reserve
shortage price is then reflected in the energy price. If these
conditions occur more frequently than today or if market
operators adjusted the set of conditions that trigger these
prices, the overall average energy price may not necessarily be lower. With the existing market design, there could
be a situation where the price is either zero or set at the
high-shortage value. Since this discontinuity may not be
politically desired, designs can be modified by triggering price increases as the system approaches, rather than
exceeds, shortage conditions. Alternatively, consumers can
set those shortage prices as opposed to having the market
operator (with the agreement of stakeholders and regulatory
agencies) set administrative values. As can be seen in Figure 4, there is no clear trend on increasing shortage pricing due to increased renewables. However, in some regions,
such as CAISO, shortages are often triggered by a lack of
ramp available during the evening (when load picks up and
solar photovoltaic declines) rather than a capacity shortage.
It will be essential to observe the frequency and causes of
these shortage prices in the future and see whether demand
plays a more defined role.
Traditional approaches to demand response (DR) have
focused on incentivizing load reduction. However, recent
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IEEE Power & Energy Magazine - November/December 2019

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