NREL is a national laboratory of the U.S. Department of Energy, Office of Energy 

Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

Contract No. DE-AC36-08GO28308

The Role of Pumped Storage 

Hydro Resources in Electricity 

Markets and System Operation

Preprint

E. Ela

National Renewable Energy Laboratory

B. Kirby

Consultant

A. Botterud and C. Milostan

Argonne National Laboratory

I. Krad

National Renewable Energy Laboratory

V. Koritarov

Argonne National Laboratory

To be presented at HydroVision International

Denver, Colorado

July 23–26, 2013

Conference Paper

NREL/CP-5500-58655

May 2013
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Abstract --- The most common form of utility-sized energy storage system is the pumped storage hydro system. 

Originally, these types of storage systems were built to assist with providing generation during peak times with the 

energy they stored while pumping during nighttimes, as well as a backup to nuclear power plants. Recent trends of 

differing electricity market design and increasing amounts of variable renewable generation have allowed for 

pumped storage hydro to provide other services to support the power system, and earn additional revenue. While the 

market design topics have been evolving since their inception, there are still ways that the designs can be improved 

to better value all of the capabilities that pumped storage hydro has to offer, while still maintaining a fair and 

impartial perspective. This paper will introduce some of the issues that may limit the ability to fully value pumped 

storage hydro plants in today’s markets and propose some solutions to those problems.

I. Introduction

Utility-sized energy storage systems are a small percentage of the total generating 

capability of the United States power system, but are gaining more and more attention for their 

role in enabling higher penetrations of variable renewable resources into the grid. Currently, the 

most common type of utility-scale storage is pumped storage hydro (PSH). The majority of the 

nation’s 20 GW of PSH was established in the mid- to late 1970s (ASCE 1993) in response to a 

significant increase in oil and gas prices as well as concerns about the security of supply 

(Denholm 2010). This led to the Power Plant and Industrial Fuel Use Act, which paved the way 

for serious consideration of PSH (Energy Information Administration 2009b). In recent years, 

there have not been significant additions of PSH in the United States. However, there has been 

recent interest in PSH, due to the introduction of restructured electricity markets, increased 

market penetrations, and new PSH technologies. This resurgence of PSH may require changes in 

electricity market practices and modifications to its role in system operations for it to ensure its 

full value is being utilized and full revenue potential is being received. 

There are two types of electricity markets: regulated and restructured. Both markets 

operate on the same principle. The lowest-cost generators are scheduled to reliably serve the 

expected load and then operated to meet the actual load based on security-constrained unit 

commitment and economic dispatch. However, regulated markets do not divulge their exact 

market rules. As a result, this paper will focus more on restructured markets because their 

information is more readily available. These markets treat storage systems very differently. 

Assume, for example, a storage facility large enough to completely flatten the system net load. 

This would allow generation to operate at a constant level by charging during periods of low 

demand and returning that energy during times of high demand. This would allow cheaper base 

generation to be used to supply the majority of the load at its most efficient operation levels. This 

would completely eliminate the need for expensive peaking plants to meet demand. If the 

generation savings exceed the cost of the storage system, this would be attractive in a regulated 

environment. However, because generators and storage are paid based on the marginal cost of 

energy in any hour, this type of storage system would not be practical in a restructured 

environment. Although the extreme cost of peaking generators would have been enough to 

justify the installation of the storage system, the price difference would collapse as soon as the 

storage system became operational. As a result, compensation for the storage system would 

significantly decrease until the storage system ultimately financially fails if its source of income 

was the energy arbitrage payments to recover initial capital costs.
2 

II. Energy Arbitrage

Net generation and load must be continuously balanced in real time to maintain system 

reliability. This is accomplished through a combination of unit commitment and economic 

dispatch of generation and ancillary services to compensate for fluctuations that are faster than 

the economic dispatch schedules. Restructured markets typically operate sequential energy 

markets that clear day-ahead hourly, hour-ahead hourly, and every five minutes. Because 

electricity is a real-time commodity in which production and consumption occur simultaneously, 

the production cost varies with consumption quantity. This potentially allows storage systems to 

engage in energy arbitrage.

Energy arbitrage and ancillary services both require the flexible control of real power that 

storage can provide. Energy arbitrage involves charging storage at times when energy is plentiful 

and inexpensive and returning that energy to the power system when it is scarce and expensive. 

Ancillary services typically refer to active power operating reserves, voltage support, and blackstart services. Operating reserves involve resources that are standing ready to inject energy into 

the power system when a major disturbance occurs (contingency reserves) or constantly injecting 

or removing energy from the power system to compensate load variability, conventional 

generators, and renewable generators (regulating and following reserves). Operating reserves can 

also be classified by when they are used (in response to a system event, or continuously 

operating). Figure 1 shows different categories of operating reserves and why and when they are 

needed (Ela 2011).

Figure 1. Operating reserves and why/when they are needed

Energy arbitrage can be done in vertically integrated, regulated markets based on the 

marginal cost of generation (system lambda) or in restructured markets based on energy market 

prices. Time frames can be as long as seasonal to as short as every five minutes, with daily 
3 

arbitrage being common. For energy arbitrage to be financially practical, the ratio of the cost of 

charging the energy to discharging it must exceed the round-trip efficiency of the storage system. 

There must also be a sufficient number of viable arbitrage opportunities to cover the capital and 

operating costs of the system. Obviously, the shorter the time frame, the more arbitrage 

opportunities there are, but the market must operate in this time frame. Storage can also provide 

spinning (contingency) and regulation reserves. Markets typically value flexibility through 

energy and ancillary service prices. Ten years of average annual ancillary service prices from 

five market areas (California, Electric Reliability Council of Texas, New York, Midwest 

Independent System Operator, and New England) show that market operators typically value 

regulation reserves the most, followed by spinning reserves (Kirby 2012). Recent technological 

advances in PSH technology have allowed them to potentially take advantage of the ancillary 

services market. Conventional fixed-speed pumped storage plants typically cannot provide 

regulation while pumping or when idle. They must be generating and operating above the 

minimum load and below full load so that they have room to move up and down in response to 

the system operator’s automatic generation control signal. New, adjustable speed plants have the 

ability to provide both regulating and following reserves while in pumping mode. They can also 

provide spinning reserves when generating below full load or when idling in condensing mode 

with the turbine spinning air and while in pumping mode. They also have the potential to provide 

nonspinning reserves depending on the system ancillary service requirements. Daily ancillary 

service price patterns show that spinning and nonspinning reserves are typically lowest 

overnight, when a storage system would most likely be charging (i.e., pumping). Therefore, a 

flexible plant can maximize profits by not only responding to the expected daily pattern of 

energy and ancillary service prices, but by changing how it responds based on how energy and 

each of the ancillary service prices change in real time (Kirby 2012). 

III. Pumped Storage Hydro Modeling and Quantitative Analysis 

The scheduling and dispatch of PSH in power systems has been a topic of investigation 

for a long time. For example, McDaniel and Gabrielle (1966) discussed daily operation of the 

Smith Mountain PSH plant analyzing commitment and dispatch decisions. Aoki et al. (1987) 

proposed an efficient unit commitment algorithm with detailed PSH representation via 

Langrangian Relaxation. More recently, research is being done on the challenges and 

opportunities for PSH. Deane et al (2010) performed a techno-economic review of existing and 

purposed PSH plants in Europe, Japan, and the United States. They show that current drivers for 

new PSH capacity include the large-scale expansion of variable, renewable energy; a growing 

demand for energy and peak power; increasing interconnections and closer coordination between 

regional markets giving more opportunities; security of supply; and refurbishment of existing 

equipment for improved efficiency. PSH plants can be remunerated through ancillary services, 

capacity markets, and energy. However, it is argued that for energy arbitrage to be profitable the 

pumping price has to be at least 25% to 30% lower than the selling price.

The authors of a 2012 white paper by the National Hydropower Association’s Pumped 

Storage Development Council indicated that development of new PSH, particularly in areas with 

increased wind and solar capacity, would significantly improve system reliability while reducing 

the need to construct new fossil-fueled generation. They suggested new regulatory policies, 

including presenting bulk energy storage as a new asset class, forming a streamlined licensing 
4 

process for low-impact PSH, and allowing regional transmission organizations and independent 

system operators to enter into long-term, fixed-price contracts with energy storage owners. The 

National Hydropower Association’s summary of a 2010 PSH technology summit addressed 

issues and barriers along with purposed actions, including establishing a pumped storage design, 

siting, and demonstration project; creating working groups to evaluate mechanisms to ensure 

revenue streams such as rate base financing and grid stabilization payments; financing projects 

under federal loan guarantee programs; and exploring ways to reduce time required to develop 

PSH plants and reduce upfront developer risk. Miller and Winters (2010) suggested the Federal 

Energy Regulatory Commission allow pumped storage to qualify as transmission facilities for 

purposes of determining eligibility for future incentives and possible creation of storage credits.

There has been extensive research in the area of proper PSH bidding strategies in 

restructured, competitive electricity markets. Deb (2000) discussed the need for PSH to 

participate in energy markets as well as ancillary service markets. The revenue of PSH is no 

longer dictated by the avoided costs of other power plants. Using the California market as an 

example, he showed that PSH can obtain a large increase in profits by participating in ancillary 

services markets (spinning and nonspinning), as opposed to only seeking arbitrage opportunities 

in energy markets. Kanakasabapathy and Swarup (2004) proposed a more realistic description of 

the PSH operating constraints in determining the optimal bidding strategy. They assumed that the 

PSH can participate in energy, spinning reserve while pumping, and nonspinning reserve while 

offline. Using the Lewiston-Niagara PSH plant in New York, they demonstrated that a weekly 

operating strategy gives higher profits than a daily strategy as a result of more flexibility in 

scheduling decisions because the storage constraint is imposed at the end of the planning horizon 

(week versus day). Connolly et al. (2011) investigated the profitability of a potential PSH plant 

in more than 10 different electricity markets assuming all revenue comes from energy arbitrage. 

They found that accurate price predictions are important for PSH plants to recoup potential 

energy arbitrage profits. There was also large variability in the profitability of PSH plants in 

different markets as a result of differences in the magnitude of price variations. In most markets, 

there was also a large variance in year-to-year profits. They concluded that PSH is a risky 

investment without a more predictable profit or additional revenue, which may come from

ancillary services. Schill and Kemfert (2011) attempted to model strategic interactions between 

PSH and electricity markets with a focus on potential strategic utilization of PSH in the German 

electricity market. They found that ownership influences the usage of PSH. Strategic storage 

owners generally underutilize their storage capacity, particularly if a large share of PSH is owned 

by an oligopolistic generator. The strategic behavior is much less prominent when the storage 

capacity is distributed between multiple market participants. PSH leads to arbitrage profits for 

the owner, but its price-smoothing effect decreases generation-related producer surplus for all 

generating firms; whereas demand surplus and total welfare increases. Therefore, investments in 

new PSH capacity may not be attractive for market participants that also hold other generation 

capacity. Their analysis did not consider revenue from ancillary services. Tsai et al. (2009) 

showed that a PSH unit has the ability to make profits in a competitive energy market because of

its outstanding response time, ramp rate, and start-up and shutdown times. 

Pumped storage specialists concur on how growing wind power penetration in the United 

States energy supply system supports hand-in-hand the development of pumped storage. Miller 

and Winters (2010) suggested how pumped storage is proving to be an establishing technology 
5 

for wind power because it can absorb excess generation and release it during peak demand times. 

They cite the 2006 Wind Integration Study performed by the Public Service Company of 

Colorado that states that doubling pumped storage capacity in the Public Service Company of 

Colorado system could reduce the cost of wind integration by as much as $1.30/MWh in a 20% 

wind penetration case analysis. Suul et al (2008) found that for isolated power systems with 

renewable generators, pumped storage is important for its provision of primary frequency control 

during times of low demand and high output from fluctuating renewable sources. Castronouovo 

and Lopes (2004) showed that a combined wind generator and pumped storage plant can increase 

its operational profits anywhere from 12% to 22%, depending on the deviation penalty level by 

co-optimizing the wind generator and the pumped storage operation together as opposed to 

optimizing only a wind generator. Ding et al. (2012) performed a similar analysis but considered 

the number of daily starts/stops along with the start/stop costs of the PSH and also included the 

subhourly variations in wind power fluctuations. They compared the results of a deterministic, 

chance-constrained, and stochastic optimization formulation. They found small differences 

between all the results, but the underlying trend was that the combined operations of a wind 

generator and PSH plant can increase profits by as much as 25% compared to stand-alone 

operations of a wind farm. Black and Black (2007) analyzed the impact of wind power 

forecasting uncertainty on the value of PSH in the United Kingdom power system assuming 

wind power supplies more than 20% of the energy. They focused on the potential contribution of 

PSH toward nonspinning reserves and their impact on other reserve providers such as gas 

turbines. They found that using the PSH to meet the reserve requirement can increase system 

efficiency, enhance wind power absorption, and reduce CO2 emissions. The benefits of storage 

are most significant in systems with low generation flexibility and large wind penetration. 

Donalek et al. (2009) showed that properly designed pumped storage facilities could assist in 

integrating intermittent wind energy resources into the regional dispatch. They concluded that 

pumped storage units with the newest technology, such as adjustable speed and ternary units, can 

supply load following and become the fastest response stations in the power system. They can 

also be used to mitigate the frequency of industrial load shedding caused by system disturbances.

IV. Treatment of PSH in Electricity Markets

In the United States, nearly 66% of electricity consumed is within restructured electricity 

markets. These markets have evolved into the standard market design (Hogan 1998). This design 

reflects a pool-based market where there exists a two- or three-settlement system for forward and 

real-time markets, with co-optimized energy and ancillary services, locational marginal pricing 

for energy, and financial transmission rights markets in place for hedging. Energy is sold in 

forward (e.g., day-ahead hourly markets) and balanced in hour-ahead and five-minute real-time 

markets with locational marginal prices. Financial transmission rights are a hedging instrument 

put in place to collect the locational differences in energy price. In some of the U.S. markets, 

capacity markets are also put in place to incentivize investment in installed capacity and to 

ensure peaking units can recover fixed costs. Current ancillary service markets typically include 

regulation, spinning, nonspinning, and sometimes supplemental reserve. Following and 

frequency response services are being considered as explicit ancillary services that may be 

appropriate for market procurement by several regional transmission organizations (Ela 2012a). 

Although following reserve has been getting attention as a new payment source (Navid 2012), 

primary frequency response is not incentivized in any of the market regions (Ela 2012b). Voltage 
6 

support and black start are ancillary services that are required for system reliability but have not 

proved to be amenable to hourly market procurement. Instead, these services are obtained 

through interconnection requirements (voltage support and reactive power) and through longerterm contracts (black start).

The concept of pricing in the United States is for uniform marginal pricing. Marginal 

pricing reflects the cost of serving the next increment of demand, whether it is for energy or for 

ancillary services. The prices differ depending on the location in the system. For energy, the 

prices differ at every generating bus-bar. For ancillary services, there are less location 

requirements, and prices are either the same throughout the market region or there are zonal 

differences when large interfaces are constrained. In a lossless system without transmission 

congestion, the price at every bus in the system will be the same. When transmission congestion 

is apparent, it causes more expensive resources to be needed on one side of the constraint, 

because the cheaper units are constrained by the transmission limits. This causes the price to be 

higher where the expensive unit is needed and lower at the location of the cheaper unit. This is 

typically determined via direct current power flow equations. Prices will also be higher at 

locations that are closer to the load, even without transmission congestion. The ancillary service 

clearing price is the total increase in system cost if an incremental amount of operating reserve is 

required. Ancillary service markets will also have a pricing hierarchy (Oren 2001). This is in 

place because some ancillary services are more important than others. This way there are 

incentives always in place so that market participants will always want to provide the most 

valuable ancillary service. Most ancillary service clearing prices are paid to market participants 

for the provision of capacity to provide that ancillary service rather than how they perform in 

providing that service. There has been recent motivation to allow for payment based on 

performance for regulating reserve, such as Federal Energy Regulatory Commission Order 755. 

This will allow faster responding units to be paid more. Independent System Operators also have 

rules that ensure that no participant receives a negative profit that may arise from nonconvex cost 

curves, commitment constraints, or out-of-market reliability rules. The participant will receive a 

make-whole payment to ensure that it does not lose money. Because PSH is not fully optimized, 

nor does it have official “costs,” the make-whole payment rules may not fully apply. However, if 

PSH is fully optimized by the market and ends up losing money by paying more during pumping 

periods than it makes during generation periods, make-whole payments may be necessary.

Power systems require significant flexibility to operate reliably. The increased variability 

and uncertainty of wind and solar generation are increasing the need for flexibility. Capacity is 

required to meet the maximum net load. Ramping capability is required to follow the daily net 

load fluctuations and is supplied through subhourly scheduling (5-minute scheduling) when there 

is an abundance of ramp capability. A dedicated ramp or following service with separate 

payments for ramp services may be required if the economic energy supply generation does not 

inherently have sufficient ramping capability. Midwest Independent System Operator and 

California Independent System Operator are considering implementing dedicated following 

services. Regulation is required to match the short-term variability. Contingency reserves are 

required to respond to sudden failures of large generators and transmission lines. All of this 

flexibility is absolutely required. Specific resources and specific technologies are not required, 

however. Markets have proven very effective at obtaining the required flexibility from a host of 

available resources and technologies. Storage has technical capabilities that closely match the 
7 

power system’s need for flexibility, but storage must deliver that flexibility at a cost that is lower 

than the alternatives to be economically successful.

Storage systems have a unique difficulty in today’s market environment in that they are 

unable to capture the benefit they provide to other power system users. Because storage can 

collapse its own market (reduce the marginal cost of electricity), it will receive a lesser payment 

than it would have if it did not participate. This would ultimately lead to the financial demise of 

the storage system. Therefore, distinction must be made about the system value versus the 

market value. The total system benefits will always increase with increased storage, but the 

benefits per unit of storage size will decrease. This means there is a point where increasing the 

storage system’s size beyond this point would be counterproductive in today’s market. This is 

similar to the problem faced by new transmission line construction where the new transmission 

lines alleviate the congestion differential that might be used to finance them. 

V. Market Design Topics for PSH

Based on the recent report by the Electric Power Research Institute (2013), the following 

suggestions are made regarding the market treatment of PSH:

1. PSH should be fully optimized in the day-ahead markets. This will allow the day-ahead 

market to schedule the mode of PSH based on minimizing costs over the full horizon. 

The length of the horizon may be important as well. Currently, only PJM does this. 

2. PSH should be fully optimized in real-time markets. This will allow the real-time market 

to schedule the mode of PSH based on minimizing costs and information that has been 

updated since the day-ahead market. Currently, no market performs this in the real-time 

commitment models.

3. PSH should be compensated for lost opportunity costs based on multiple hours for 

ancillary service clearing prices. Because the PSH depends on its optimal operation over 

long time periods of at least a day, the lost opportunity costs of the resources are highly 

complex. If by providing ancillary services in one hour it loses an opportunity to provide 

energy in another, those pricing mechanisms should be accounted for. 

4. PSH should receive make-whole payments. When the PSH is fully optimized in the 

market, they should receive guarantees that if they follow the schedules given to them by 

the independent system operator, they will be made whole. 

5. PSH should be compensated based on subhourly settlements. If settlements are made on a 

subhourly level, the PSH plant will have opportunities to utilize fast response to meet 

real-time pricing swings that can greatly benefit the system. With hourly settlements, the 

PSH has little incentive to follow prices within the hour, only to follow the average 

hourly price. 

6. PSH should be paid for its performance as well. PSH can benefit from providing superior 

regulating reserves, when the response is needed. By paying for the performance of 

regulating reserves, they can earn additional revenues compared to if they are paid the 

same as slow-moving regulating resources. All of the independent system operators and 

regional transmission organizations have modified rules for Federal Energy Regulatory 

Commission Order 755 and are beginning to implement the market design modifications.
8 

7. PSH should be compensated for primary frequency response. Primary frequency response 

is not necessarily incentivized in current markets. It could be an additional revenue 

stream for PSH because conventional and especially advanced PSH can provide this 

service.

8. PSH should be compensated for following reserves. Following service is being proposed 

in Midwest Independent System Operator and California Independent System Operator, 

and discussed more broadly throughout the industry. It can bring additional revenues to 

PSH plants and especially adjustable-speed PSH that can provide it during both 

generation and pumping modes. 

9. PSH should be compensated for voltage control. There are currently no markets for 

voltage control in the United States, only cost-recovery mechanisms. A pricing 

mechanism for voltage control could bring additional revenues for PSH and advanced 

PSH.

VI. Conclusion 

Much of the nation’s PSH plants were initiated during the mid- to late 1970s, at a time 

when they could assist in providing cheap power during peak periods that they stored during 

low-cost nighttime periods. In the United States, there have not been significant additions of PSH 

since this early time period. PSH can provide many services to the power system that are not 

captured in today’s market structure, such as increased flexibility, primary frequency response, 

following reserves, and fast-acting regulation reserves. A similar issue is that PSH is typically 

not adequately represented during the optimization of the commitment and dispatch formulations 

in most restructured electricity markets. These issues were discussed along with the current state 

of electricity market designs and how PSH is part of these designs. The way the market structure 

currently stands and the way PSH fits into that market structure was shown. Finally, potential 

market changes that can help PSH in today’s restructured markets were presented and discussed 

in this paper. 

VII. Acknowledgment

This work was supported by the U.S. Department of Energy under Contract No. DE-AC36-08-

GO28308 with the National Renewable Energy Laboratory. 

VIII. References

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10

Author Biographies 

Erik Ela is a senior engineer with the National Renewable Energy Laboratory. Ela joined the 

Transmission and Grid Integration Group to work on different renewable resource integration 

issues. Ela previously worked for the New York Independent System Operator developing and 

improving products in the energy markets and operations areas. 

Brendan Kirby is a private consultant with numerous clients including the National Renewable 

Energy Laboratory, Oak Ridge National Laboratory, Electric Power Research Institute, and 

others. He served on the North American Electric Reliability Corporation Standards Committee. 

He has 38 years of electric utility experience and more than 170 publications. Brendan is a 

licensed professional engineer with an M.S degree in electrical engineering from CarnegieMellon University and a B.S. in electrical engineering from Lehigh University. 

Audun Botterud is an energy systems engineer at Argonne National Laboratory. He has a M.Sc. 

in industrial engineering (1997) and a Ph.D. in electrical power engineering (2004), both from 

the Norwegian University of Science and Technology. He was previously with SINTEF Energy 

Research in Trondheim, Norway. His research interests include power system economics, 

integration of renewable energy, wind power forecasting, hydropower, stochastic optimization, 

and agent-based modeling. 

Cathy Milostan is an energy policy scientist at Argonne National Laboratory. Milostan was 

previously an equity research analyst for more than 20 years for New York– and Chicago-based 

financial firms including Morningstar, LaSalle Bank, and Goldman Sachs. Milostan uses 

experience in analyzing energy industry trends, regulation, and earnings potential to evaluate 

energy project economics and market potential. Milostan has an MBA-finance from Wharton 

School, University of Pennsylvania, and a B.A. in geology from Wellesley College. 

Vladimir Koritarov is the deputy director of the Center for Energy, Environmental, and 

Economic Systems Analysis at Argonne National Laboratory. He has 30 years of experience in 

the modeling and analysis of power systems. He has managed numerous projects and provided 

technical assistance to more than 30 countries. Before joining Argonne in 1991, Mr. Koritarov 

worked for eight years as power system planner in the Union of Yugoslav Electric Power 

Industry.

Ibrahim Krad is an engineer with the National Renewable Energy Laboratory. He received a 

master’s degree in power engineering from the Illinois Institute of Technology and a B.S. in 

electrical engineering from Louisiana State University.