robust power markets for the 21st century

An analysis of current market policies to strengthen U.S power markets

Creating Robust Electricity Markets for the 21st Century

Since the emergence of the first electric power markets in the early 1990s, power

deregulation has become a little discussed economic issue that has seen significant growth and

development. Nevertheless, higher concentrations of new renewable sources of generation have

threatened reliability in the flow of electricity across the grid and many markets are still facing

financial concerns in developing new generating assets. Therefore, there are two primary

developments that must take place within the power markets in order to deal with these most

pressing issues. The first of these is to deal with renewable power generation in a way that is free

market oriented and that gives consumers the freedom to choose where their energy comes from

while at the same time, is able to implement currently used market policies to protect reliability

across the grid. The second is to promote development of new power infrastructure by using one

of two market oriented models already being implemented in the Texas and the Midwest

electricity markets.

Over the last several years the price of renewable energy in deregulated markets has

fallen exponentially. With the help of government subsidies and increased innovation these

sources of energy have become increasingly desirable. Pair this with the intensifying public and

political pressure to increase the level of renewable energy generation and the clean energy

industry is able to take off. Nevertheless, there are some downsides to these renewable sources of

energy.

In order to better understand the significant impact and strain that these resources put on

our power grid it is important to explain just how the electric system works. Contrary to popular

belief, no electricity is able to be stored on the grid. Instead, energy is generated and consumed

instantly, so scheduling entities must exist to ensure that power supply always matches power

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demand. In order to do this, these grid operators call on power generators to turn up or turn down

their energy supply as the day goes on, but for many generators this can be a costly thing to do

because of the wear that it causes on their plants and because the speed at which they are able to

shift demand can sometimes be slower than grid operators expect. Looking at renewable

generating sources and their sporadic ability to provide a reliable stream of power therefore

shows that these new sources of energy can create uncertainty in a market focused around

reliability. Thankfully, several market based approaches have been created in order to deal with

this issue, and using the strongest aspects from these models can truly lead to a market that is

reliable, robust, and that ensures clean, inexpensive power to its ratepayers.

California was the first system to feel the strain of renewable energy on its grid. With an

aggressive goal of 50% of its energy coming from renewable sources by 2030, many people at

the grid operating entity, the California Independent System Operator (CAISO), began to voice

concern about the future reliability of the grid with such a heavy mix of unpredictable

renewables. In order to better prepare for this shifting paradigm, the CAISO needed to look at its

ramping capabilities. Ramping is known as the ability of a generating facility to start and stop

when told to do so (i.e. can the facility start or not, and if so how much capacity can it add to the

grid). The ramp rate refers to how quickly a station can add or remove capacity from the grid. As

one might expect, a flexible ramp rate is highly valuable in a system such as CAISO where

intermittent power supply from renewable sources force the system to respond to unpredictable

supply changes within a matter of minutes to maintain grid reliability. Unfortunately, under

standard market conditions, many power producers are not willing to ramp their plants up and

down several times a day because of the wear and tear that doing so causes to expensive plant

equipment. Because of this, the CAISO needed to create a new market function that could

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balance the needs of their many stakeholders. The solution was the Flexible Ramping Product.

According to the CAISO’s own market operations manual for this new Flexible Ramping

Product, this system works as follows: if a power plant increases the need for ramping (adds

renewable or unreliable power supply), it will be charged the flexible ramping product. On the

other hand, if a power plant decreases the need for ramping, they will receive a payment for

adding the economic value of reliability to the system. California decided on this model for a few

main reasons. First and foremost, the CAISO realized that there were significant costs involved

with making a plant ramp its supply up and down. To deal with this, the grid operator wanted to

fairly and adequately compensate plants that were providing the benefit to the market of

reliability and supply if and when it was unexpectedly needed. On top of this, the CAISO

realized that although renewable energy source offers several significant benefits to the power

grid, they operate with the fundamental weakness of being unable to provide a steady stream of

energy when it is needed, and because of this need to pay for their lack of reliability. By

matching these two economic impacts on the power system, CAISO was therefore able to create

a clear supply and demand for ramping capabilities in the market, fulfilling the important aspect

of tying renewable energy into the grid in a manner that is market oriented. Second, since its

existence, the CAISO has encouraged power producers in the state to focus on creating a diverse

mix of power sources, but in recent years, the large majority of power plants being built in

California were renewables. By adding the supply and demand of reliability to the price of some

energy sources, the grid operator has encouraged companies that own only reliable generating

stations to invest in wind and solar development, while on the other hand it is also able to

encourage companies that own only wind and solar plants to invest in more reliable power

sources to offset their costs. Over the long term, this gives consumers of energy in the state of

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California the power to choose between a wide variety of energy sources from any company they

decide to buy power from because of each company’s diverse power generating mix.

Another system that has seemingly taken a completely different approach from an

economic perspective was the electric grid operator in New York known as NYISO. New York

has a unique issue that it has to deal with when it comes to power generation, and that is that the

majority of the power being generated for the state comes from the Northern and Western parts

of the state while the majority of the power is used in the densely populated centers of Southeast

New York. Because of this, there is a unique constraint that comes into play and it is how much

power the system operator is able to move over such long distances to the population centers of

New York. The simplest, and most ideal way to deal with this would ultimately be to build more

power lines to move renewably generated power to the population centers of Southeast New

York. Furthermore, by the nature of of renewable energy, supply comes quickly and being able

to move that power easily over lines that are available at any given moment is valuable in the

system. Nevertheless, this model does have some fundamental flaws. The most pressing of these

flaws came from the New York Department of Public Service, the body that regulates electric

rates in the state of New York. Their concern was that using the power line development model

to unlock renewable energy would create a system that was only used at times when demand was

extremely high, which was only a problem for a few days a year, and that all of the costs for

creating this mostly underutilized power line system would be passed on to New York

ratepayers. Instead, the state of New York saw that in many parts of the state, homeowners and

businesses had put up small solar panels, generators, battery storage systems, and wind energy

solutions that were sometimes producing more energy than the buildings which they were

powering consumed. Along with this, technological advancements were occurring that gave

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utilities more power to control demand in the system. NYISO saw these two fundamental shifts

as opportunities, and used them to reform the way that utilities in New York would do business.

Whereas before, New York had a traditional electricity market in which energy would either be

generated by a large power plant or purchased in the electricity market by a utility and then sold

to end customers by the utility, the system was changed so that electric utilities would become

Distributed System Platform Providers (DSPPs). In the DSPP model, the goal of electric utilities

is no longer to minimize costs and maximize reliability within each of their individual plants and

to then figure out how to get that power to end users. Instead, utilities would take a distributed

approach in which they become entities that procure excess energy produced from those solar

panels, generators, battery packs, and wind solutions that homeowners and businesses around the

state built, and tie it into regional markets where they could sell that energy to demanders nearby.

Doing this allowed the NYISO to keep up with the aggressive goal of having half of all of its

energy come from renewables, while incentivizing market based development in energy at the

local level that was inexpensive and green. Furthermore, this model fulfilled the important

evolution that energy markets must make by giving ratepayers the ability to choose how much

energy they could receive from renewables based on how much they were able to generate on

their own. On top of this, New York took advantage of new technology available to electric

utilities that allowed them to control the amount of energy that certain home appliances were

using during times of heavy demand known as demand response. In an example that Michael

Pollitt and Anaya Karim give in their report Can Current Electricity Markets Cope with High

Shares of Renewables? A Comparison of Approaches in Germany, The UK and The State Of

New York, someone could opt into a service that gave their utility company control over their

thermostat during certain times of the day. When energy demand got to levels high enough that

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the reliability of the grid was threatened because of a lack of available supply, the grid operator

was able to step in and lower the usage of the air conditioners of those that opted into the plan

Those who opted into the plan were also compensated or the ability to do so. On the other side of

this, the NYISO also had control over too much electricity in the system, such as times when

high volumes of renewables began adding unnecessary power to the grid. In this case, the

NYISO was given the ability to increase electricity usage of those air conditioners to stabilize the

supply of energy on the grid. This change gave the utilities and the NYISO control over not only

supply in the system, but also real time demand, and allowed these entities to better control

electricity rates and grid reliability. The NYISO and utilities therefore now had the ability to

choose between adding more power to the system, removing power usage from the system, or

some combination of the two, all while protecting New York ratepayers and the grid from

blackouts. These significant changes to electric utilities ultimately turned power companies from

producers and sellers of energy directly to consumers into companies that operate a

transportation system for energy and act as a middleman for exchanges of power between

different retail customers. Normally, renewable energy sources like these can create serious

strain on the electric system as too much power being allowed to enter the system can lead to

blackouts, non-optimal weather for renewables can lead to the need to force power plants to turn

on quickly, and unexpected renewable energy being produced can congest the transmission

system. However, when the NYISO implemented this model for its utilities to follow, the system

saw greater stability. One reason for this is because this model emphasizes community scale

grids, or microgrids. Utilities realized that the areas that the old business model wasn’t able to

control were those that were high density, and with a lot of power going to them. Going back to

the way New York’s grid looks, you find that most of the power that the state uses is generated

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in the West and moved to the East. Because of this, most of the power produced in the state gets

sent down a limited, fixed set of power lines, and once these power lines reach capacity there is

little that can be done to completely fulfill demand. Essentially what was happening in New

York city was a significantly higher price of power than areas surrounding the city simply

because of the laws of supply and demand applied to the amount of power lines available to

move that energy into the city. In this situation, ratepayers were therefore left not with paying for

the power itself, but instead paying for the ability to move that power into the state over a fixed

set of power lines. The DSPP implementation though did give utilities the ability to buy excess

distributed energy from solar panels, small generators, and other sources within the city of New

York, and sell it to demanders in New York City. Therefore, this model unlocked a source of

energy that before, was only sitting in the city unused or being wasted while prices for other

ratepayers in the city rose drastically. Because of this, the system operator found that they had

created prices that were much closer to what was found in different parts of the state as more of

the energy that New York City needed could be used without needing to access the transmission

line system going into New York City. Furthermore, the NYISO was able to encourage new

investments in green power at the local level as the owners of these types of small energy

sources could now get paid for selling excess power back to their utilities.

By the laws of basic microeconomics, perfectly competitive markets in which most

commodities are sold have had a tendency to historically become more and more efficient, with

excesses being shaved off and with prices falling dramatically. When the power markets were

first deregulated this was no different. Unfortunately, within the power markets space, grid

operators are very hesitant to allow excesses to fall too much because of the impact that a single

power plant is able to have on a grid’s already fixed supply availability. If a power plant is to

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suddenly shut down, the system could face blackouts that could impact millions of people

because the balance between supply and demand would be interrupted, while other plants turned

on to sufficient levels to return supply to where it needed to be. Because of this, an excess

capacity has always been seen as a better alternative to blackouts paired with markets that run

more efficiently. Furthermore, electricity prices have remained volatile in most deregulated

power markets, with the ability to swing from very high to very low in a matter of minutes.

When you consider the high fixed costs that it takes to build new power plants, utilities and

power producers have therefore been reluctant to build new plants as they are unsure of how well

their investment will pay off in the future because of this heavy price uncertainty. In fact, In his

interview with the Bipartisan Policy Center, Tom Fanning, CEO of The Southern Company, one

of the nation’s largest electric utilities, said “We have the kind of [government sponsored

monopoly] regulatory environment that supports the kind of long-term, high-capital-cost big

bets. In merchant markets you don't have any pricing that will support that kind of investment,

and that's a shame” (21:56). The business driven decisions explained by Fanning illustrates the

fundamental flaw of deregulated markets most clearly. He, and every other shareholder

conscious CEO in the industry is fearful to make bets that often cost many billions of dollars and

that can take up to 30 years to build, because they are unsure of how the market will look years

in the future when their new plant is finally operational. Furthermore, in several organized

electricity markets, existing plants have been closing at a constant rate because of their high

costs, inefficiency, public and political pressure, or some combination of these factors. This

along with the unwillingness of power producers to build new plants, and the slowly increasing

demand for power has begun to threaten the reserves that grid operating entities depended on to

provide reliability to the grid.

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One of the first areas to prove how dire the situation had become for new plant

investments in competitive electricity markets was the state of Texas and its electric grid. In

2011, the Texas grid was pushed to the limits. Several winter cold fronts and a hotter than

average summer forced some formerly closed plants to restart. Nevertheless, because of high

economic growth and several events occurring that year, the system still did not have enough

power and ended up facing blackouts. The Public Utilities Commission of Texas and the Energy

Reliability Council of Texas (ERCOT), the two organizations tasked with power reliability and

fair pricing for consumers in Texas, were stunned that such an event could occur to such a

historically stable electric system, and hired the consulting firm The Brattle Group to look into

what went wrong. In their report the Brattle Group found one central issue. As expected it was

the amount of reserves that were available to the market during a given operating day. More

specifically, The Brattle Group was able to pinpoint what kind of incentives power producers

needed in order to build new plants. The Brattle Group in their Brattle Report found that prices

would need to rise to approximately $100 per megawatt for the system to build new power

plants. Unfortunately for them, power prices only rose that high during periods of great scarcity,

or in ERCOT’s mind to a level where about 90% of power in the entire system was being used.

In this case, only about 10% more power could be produced for the entire state of Texas, and if a

plant needed to shut down for some emergency, hundreds of thousands of people could be left

without power. Comparatively, the ERCOT and the Public Utilities Commission of Texas had

set a required minimum reserve level at around 14% of power to be kept available in the event of

an unexpected plant shutdown. These two organizations could therefore see just how important it

would be to balance the interests of power producing companies, and their financial concerns in

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developing new generating assets at a level below their economic costs, with the interests of

millions of Texans who relied on consistent power flow 24 hours a day.

The electric regulators of Texas as well as economists working at the Texas power

market, the Electric Reliability Council of Texas (ERCOT), realized that power producers had

significant financial concerns in building power plants at a reserve power level above 10%.

Therefore, the ERCOT created an economic model with the fundamental goal of promoting

development of new generating plants. The model that the organization came up with is known

as the operating reserve demand curve (ORDC). According to William Hogan in his report

Electricity Scarcity Pricing Through Operating Reserves, this system adds the value of taking

power to every unit of power that is consumed. The basis for creating this additional price is to

make the buyers of power pay for the risk of blackouts that they add to the system by removing

power from the grid, and to pay generation owners for the economic benefit of bringing extra

power to the market. There are two primary objectives in doing this. First, as consumers are

forced to pay an ever increasing amount for taking reserve power out of the system they begin to

become increasingly disincentivized from consuming more power, preserving reserves from

depletion that without this added price, would be taken free of any thought of the implications on

reserves left in the system. Furthermore, by paying generation owners the ORDC prices that

consumers pay into the market, ERCOT was able to provide a level of price stability, and some

guaranteed income to power producers, incentivizing those entities to build new power plants in

the Texas electric system. Most importantly, by matching the interests of ratepayers and

consumers in this way, the Texas electricity market was able to deal with the issue of financial

concerns in building new plants by creating a market based approach in which economic benefits

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are paid to their rightful owners to create a stronger and more robust market that promotes

formidable energy infrastructure investment.

Texas was hardly the only competitive power market that faced narrowing reserves in the

years following deregulation of the electric system. One of the most significant examples of an

electric system facing shortfalls in its power availability was the Midcontinent Independent

System Operator (MISO). The MISO is the electric grid operator responsible for the Midwestern

region of the US, and has a fundamental goal similar to that of the ERCOT. When the market

was first organized and the MISO was first formed, the entity faced an issue in which it looked

like significant population growth and stagnating electric supply growth would lead to a shortfall

in the amount of power needed in the future. When asked why they wouldn’t build new

generating assets even though future electricity needs looked like a certainty, electric power

producers signaled their concern with the amount of inexpensive renewable sources-especially

wind-that were being built in the system. Many power producers that owned fleets of traditional

natural gas plants were concerned that with this significant growth in inexpensive sources of

power would bid them out of the market with lower prices and render their large investments in

new generation obsolete. Nevertheless, the MISO didn’t want to disincentivize wind farm

construction. Instead, they wanted to provide a level of price security for traditional generation

facilities that were more reliable than clean energy in order to act as a hedge against the chance

that wind energy could not provide necessary output. In order to do this, the MISO came up with

the idea of a capacity market. As Adam James says in his report, How Capacity Markets Work,

“The basic idea is that power plants receive compensation for capacity, or the power that they

will provide at some point in the future” (“Explainer: How Capacity Markets Work”). In this

market, the grid operator, MISO, holds an auction based on what projected demand will be at

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some point in the future. After this, each power plant is able to bid their plants in at each plant’s

cost to produce power. Once the projected future demand for the market that the grid operator is

reached, the market closes to all remaining bidders. At this point a line is drawn at the highest

bid made into the market, and every power plant that bid into the market is given that price per

unit of power, called the strike price. Although this may seem inefficient at first glance, when

you look at this model over the long term, generators individually begin to look at how they can

lower their cost to produce power as it would give them a greater profit, which is taken as the

difference between the strike price and the price that they bid into the market. Therefore, with

every generator in the market looking at how they can lower their costs to produce to maximize

profits, the market sees a long term shift down in the strike price of power during the capacity

auction. Furthermore, this model addresses the key challenge of the electricity market to ensure

reliable power at all times and does so with a market based approach similar to futures markets

for corn or oil. On one side, generators are guaranteed a price for power that they lock in years in

advance based on forecasts given by a neutral party, and the grid operator can fulfill its mission

to provide reliable power flow and consistent development of new power assets.

Over the last several years, several regions in the United States and abroad have broken

free of the shackles of monopolies controlling their ability to choose where their energy came

from, and how much they would pay, doing so in a way that has unleashed the power of the free

market. These types of markets have given customers the ability to decide where their energy

comes from and how much they pay. In many areas of the country, it has also shown that it can

work more efficiently and less expensively than the monopoly system in place before it.

Nevertheless, there are still several issues that many markets in the U.S. and abroad face, and

that are vital to fix if customers are to believe in a market that works for them, and that works

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efficiently. The two most pressing of these are the effective integration of renewable energy into

the grid, and the incentivizing of new generating investments in deregulated power markets. As

the report outlined, there are several models already in place where sweeping changes are

already occurring to make renewables work in these markets, as well as to encourage

investments in new power plants. Although many power markets are still developing and there is

legitimate concern in how to evolve with market circumstances that grid operators, utilities, and

speculators are only beginning to understand, looking at the strongest aspects from these models

can keep the power markets on a course of consistent improvement that has strengthened them

since their founding.

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Work Cited

CEO Tom Fanning on Importance of Company’s Commitment to Innovation at Bipartisan Policy

Center. Perf. Tom Fanning. Youtube. Bipartisan Policy Center, 2 Oct. 2015. Web. 18

Nov. 2016. <https://www.youtube.com/watch?v=wtJhw6dgnGE>.

"Flexible Ramping Product Revised Draft Final Proposal." Flexible Ramping Product of the

CAISO (n.d.): n. pag. The California ISO Corporation. CAISO, 17 Dec. 2015. Web. 15

Nov. 2016. <https://www.caiso.com/Documents/RevisedDraftFinalProposal-

FlexibleRampingProduct-2015.pdf>.

Hogan, William W. "A Market Power Model with Strategic Interaction in Electricity

Networks." The Energy Journal 18.4 (1997): 107-41. Harvard.edu. John F Kennedy

School of Government. Web. 29 Oct. 2016.

<https://www.hks.harvard.edu/fs/whogan/Hogan_EUCI_090115.pdf>.

--- "Electricity Scarcity Pricing Through Operating Reserves." Economics of Energy &

Environmental Policy 2.2 (2013): n. pag. Harvard.edu. John F Kennedy School of

Government, 18 Apr. 2013. Web. 28 Oct. 2016.

<https://www.hks.harvard.edu/fs/whogan/Hogan_Austin_041813.pdf>.

--- "Financial Transmission Rights, Revenue Adequacy and Multi Settlement Electricity

Markets." Lecture Notes in Energy (2013): n. pag. Harvard.edu. Harvard University, 8

Mar. 2014. Web. 29 Oct. 2016.

<https://www.hks.harvard.edu/fs/whogan/Hogan_FTR_Rev_Adequacy_031813.pdf>.

James, Adam. "Explainer: How Capacity Markets Work." Midwest Energy News. RE-AMP, 18

June 2013. Web. 14 Nov. 2016. <http://midwestenergynews.com/2013/06/17/explainer-

how-capacity-markets-work/>.

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Newell, Samuel A., Kathleen Spees, and Johannes P. Pfeifenberger. "Estimating the

Economically Optimal Reserve Margin in ERCOT." Brattle.com. The Brattle Group, 31

Jan. 2014. Web. 29 Oct. 2016.

http://www.brattle.com/system/news/pdfs/000/000/613/original/Estimating_the_Economi

cally_Optimal_Reserve_Margin_in_ERCOT.pdf?1391445083

Pollitt, Michael G., and Karim L. Anaya. "Can Current Electricity Markets Cope with High

Shares of Renewables? A Comparison of Approaches in Germany, The UK and The State

Of New York." Energy Journal 37. (2016): 69-88. Academic Search Premier. Web. 28

Oct. 2016.

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