- Guest blogger Joshua Macey is here to discuss his new paper on how electricity regulators and grid operators are responding to increased solar and wind power, and how their interventions raise old questions that were supposed to be resolved by electricity deregulation. You can also hear an Energy Tradeoffs interview with Joshua about his piece here.
In Rate Regulation Redux, forthcoming in the University of Pennsylvania Law Review, Jackson Salovaara and I consider whether the American system for compensating electric power generators can accommodate high levels of renewables. We find that the current market structure is ill-suited to a high-renewables world. Regulators and grid operators (grid operators are the utilities that manage the power grid), it seems, are aware of the challenges renewables pose. However, instead of developing a payment system that would preserve competition in the energy sector and allow renewables to enter the market, regulators have begun an ad hoc process of reregulation that raises rates, leads to excess capacity, and prevents renewables from competing with traditional energy sources.
For
most of the twentieth century, FERC treated electricity as a natural monopoly.
To ensure that suppliers met demand, regulators gave utilities exclusive
franchises over their service territories and permitted them to charge rates
sufficient to cover their costs. In exchange, generators agreed to provide
electricity to customers in their territories and cap prices. For years, this
system provided reliable electricity. Nonetheless, critics complained that it
limited consumer choice, failed to promote innovation, rewarded utilities for
overinvesting in supply, and reduced incentives to retire uneconomic
generators.
In
the 1990s, FERC began to encourage a “market-based” approach to promote
competition and control costs. Under this “restructured” model, which has been
adopted in two-thirds of the country, an independent grid operator determines
demand for electricity, solicits bids from generators, and clears enough bids
to meet demand. The grid operator clears bids starting with the lowest bid but
ultimately pays every generator the price bid by the highest clearing bidder. In
this system, generators bid at their marginal cost. If a generator bids below
its marginal cost, it risks having to provide electricity even when it would
lose money in doing so. Above-marginal cost bids risk failing to clear when it
would be profitable for the generator to operate.
This
system promotes competition and keeps short-run costs low, but it is
ill-equipped to integrate significant volumes of renewables. Generators that
are dispatched infrequently or operate on the margin cannot make a profit or
recover their costs. These plants are known as “peaking plants” and operate a
few times in a year when demand is high (often on the hottest days of the
summer or the coldest days of the winter when Americans consume a lot of
electricity). Without them, grid operators would not be able to meet peak
demand.
In
theory, peaking plants would be able to make enough money to operate. While
generators bid their variable costs almost all of the time, that assumption
does not apply to peaking plants that bid only when demand is high. In most
circumstances, a generator risks losing out on profitable bids if it submits a
bid above its marginal costs. Because peakers are the last plants to be
dispatched, they do not need to worry that they will be outbid because there are
no plants available to outbid them. They can therefore
submit bids that significantly exceed their marginal costs. As a result,
peaking plants can drive prices to levels that would allow them to recover
their fixed costs and make a profit despite the fact that they operate only a
few times a year
However,
a system that relies entirely on energy markets can lead to rampant market
manipulation and excessive price volatility. Peaking plants have market power.
Because they are the last units dispatched, if they do not operate, there will
not be enough electricity to meet demand (these incentives contributed to the
California energy crisis in the beginning of the twenty-first century). Peaking
plants can therefore drive prices to extremely high levels. To avoid these
problems, every regulator in the United States sets a ceiling on its energy
market’s clearing price.
Unfortunately,
a system that imposes price caps on energy markets is ill-equipped to integrate
significant volumes of renewables. Renewables have a different cost structure
than other generators. While the marginal costs for most generators are above
zero, wind and solar facilities have very low operating costs. As renewables
provide an increasing percentage of electricity, they suppress revenues for all
generators. Imagine if four generators had been providing electricity to a
region. Two bid $20 MWh, one bid $40 MWh, and one bid $50 MWh. All four
generators were paid $50 MWh. If, however, a solar plant replaces the $50 MWh
generator and offers $0 MWh, it will reduce revenues for all generators. That
is because it will drive out the $50 MWh generator, making the $40 MWh
generator the clearing bid, which means that every generator would be paid $40
MWh.
The
challenge with this system is that as renewables suppress prices, energy
markets become increasingly reliant on price spikes to ensure that all
generators receive sufficient revenue. But if regulators do not increase price
caps, then energy prices will not increase enough during scarcity to allow
generators to make enough money to continue to operate.
There
are a few possible solutions to this problem. One would be to increase price
caps, but no regulator (with the possible exception of Texas) has expressed a
willingness to let spot market prices rise enough to allow generators to
recover their costs. Regulators have been reluctant to allow prices to rise to
extremely high levels out of fear that doing so would encourage market
manipulation.
Another
option is to develop other markets that would ensure that crucial generators
are able to survive. To date, most regulators seem inclined to adopt this
approach. Unfortunately, the markets regulators are developing do not allow
meaningful competition between energy sources and instead prevent renewables
from competing with traditional generators. For example, grid operators in the
east coast have begun to rely on capacity markets, which pay generators for
being available to provide
electricity instead of for actually providing
electricity, to make sure that generators receive enough revenue to continue
operating. The problem with this this system is that capacity markets do not
actually reward generators for providing the services the grid needs. Not all
electricity has the same value. Generators that can turn on and off quickly,
that can provide electricity when it is most needed, and that provide electricity
to areas that are resource-constrained should be rewarded for providing these services.
Energy markets are uniquely effective because they reward generators that
provide electricity where and when it is really needed. Capacity markets fail
to do this. To make sure that the “right” generators are being compensated in
capacity markets, some grid operators have taken steps to make it more difficult
for some types of generators (often renewables and nuclear) to enter capacity
markets.
Equally
problematically, it is difficult for generators to exit the market once they
clear a capacity markets. Generators that clear capacity markets commit to operating
for a period of time (often three years). During that period, they are not
permitted to exit the market unless they receive regulatory approval to do so. Thus,
customers are often stuck paying for dirty electricity that is no longer
necessary for the grid.
Worse
still, grid operators have begun to rely on “reliability-must-run” (RMR)
agreements to provide even more competition to the generators that are
perceived to be critical to grid reliability. When capacity markets are not
able to retain generators perceived to be critical to grid reliability, grid
operators have simply bailed individual generators, and they have done so
without any kind of competitive bidding procedure.
In
our view, these interventions resurrect many of the principles of rate
regulation. Under that approach, regulators gave generators a rate of return
intended to make sure that the electricity companies would be able to meet all
of a region’s electricity needs. In exchange, power companies provided service
at agreed-upon rates. Today, regulators have begun identifying the generators
that the grid needs, making sure those generators receive enough money to
operate, and preventing them from retiring prematurely. Rather than rely on
market forces to determine which generators operate, regulators shield
preferred generators from competition in order to ensure that those generators
are financially viable. And these generators are required to provide the
services the grid needs.
A
superior option, which we endorse in the paper, is to design a system based on
long-term contracts that would impose penalties on generators that fail to
perform as promised. Some of the problems with capacity markets are that they
do not compensate generators that provide the services that the grid needs, they
prevent generators from competing with each other, and they make it difficult
for uneconomic and superfluous generators to exit the market.
Regulators
and grid operators want to ensure that there is enough capacity to provide
electricity to consumers throughout the year. A bidding process would allow
utilities to purchase the electricity that they need. Utilities would have an
incentive to keep cost down because doing so would allow them to lower their
own costs. And, by penalizing generators that fail to provide services they
agreed committed to, this approach would preserve short-term price signals that
create incentives for generators to provide electricity where and when it is
needed.
