Hydro Leader April 2022

Leader ydro H VOLUME 3 ISSUE 4

april 2022

Matthew Shapiro of rPlus Hydro: Pursuing New Pumped Storage Projects Requires Playing the Long Game

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Matthew Shapiro of rPlus Hydro: Pursuing New Pumped Storage Projects Requires Playing the Long Game

Contents April 2022 Volume 3, Issue 4

5 T he Promise of Pumped Storage Hydropower

By Kris Polly 8 Matthew

Shapiro of rPlus Hydro: Pursuing New Pumped Storage Projects Requires Playing the Long Game 14 V oith Hydro’s Alexander Jung: Harnessing Data for Hydro and Pumped Storage 18 P rogress on Idaho’s Cat Creek Energy and Water Project 22 T he International Forum on Pumped Storage Hydropower: Exploring How to Scale Up Investment and Adaptation

24 H ow an Ice Boom Is Aiding Operations at the New York Power Authority’s Vischer Ferry Project

Hydro Leader is published 10 times a year with combined issues for July/August and November/December by

an American company established in 2009.

STAFF: Kris Polly, Editor-in-Chief Joshua Dill, Managing Editor Elaine Robbins, Copyeditor Tyler Young, Writer Stephanie Biddle, Graphic Designer Eliza Moreno, Web Designer Caroline Polly, Production Assistant and Social Media Coordinator Tom Wacker, Advertising Coordinator Cassandra Leonard, Staff Assistant Eve Giordano, Media Assistant William Polly, Media Assistant Milo Schmitt, Media Assistant Amanda Schultz,Media Assistant

HALF-CENTURY LEADERS 28 J ohn Eastwood on His Half-Century in Energy Development and the Future of Pumped Storage

SUBMISSIONS: Hydro Leader welcomes manuscript, photography, and art submissions. However, the right to edit or deny publishing submissions is reserved. Submissions are returned only upon request. For more information, please contact our office at (202) 698-0690 or hydro.leader@waterstrategies.com.

HYDRO LAW 34 I n the Transition to a LowCarbon Economy, Pumped Storage Will Be Critical

By Chuck Sensiba and Elizabeth McCormick

ADVERTISING: Hydro Leader accepts half-page and full-page ads. For more information on rates and placement, please contact Kris Polly at (703) 517-3962 or kris.polly@waterstrategies.com or Tom Wacker at tom.wacker@waterstrategies.com.

39 JOB LISTINGS

Do you have a story idea for an upcoming issue? Contact our editor-in-chief, Kris Polly, at kris.polly@waterstrategies.com.

CIRCULATION: Hydro Leader is distributed to all hydroelectric facility owners in the United States, to hydrorelated businesses, and to every member of Congress and governor’s office. For address corrections or additions, or if you would prefer to receive Hydro Leader in electronic form, please contact us at admin@waterstrategies.com.

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COVER PHOTO:

Background: the Seminoe Reservoir in Wyoming.

Inset: Matthew Shapiro, CEO, rPlus Hydro.

Photos courtesy of rPlus Hydro.

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PHOTO COURTESY OF rPLUS HYDRO.

Copyright © 2019 Water Strategies LLC. Hydro Leader relies on the excellent contributions of a variety of natural resources professionals who provide content for the magazine. However, the views and opinions expressed by these contributors are solely those of the original contributor and do not necessarily represent or reflect the policies or positions of Hydro Leader magazine, its editors, or Water Strategies LLC. The acceptance and use of advertisements in Hydro Leader do not constitute a representation or warranty by Water Strategies LLC or Hydro Leader magazine regarding the products, services, claims, or companies advertised.

4 | HYDRO LEADER | April 2022

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The Promise of Pumped Storage Hydropower

By Kris Polly

P

umped storage is an efficient, established, long-duration energy storage method that will become an increasingly crucial part of the grid in coming years as more and more variable renewable generation comes online. This issue’s focus on these facilities begins with a cover interview with Matthew Shapiro, the CEO of development firm rPlus Hydro, which is currently working on 10 different pumped storage projects, about the challenges of siting and permitting these facilities and lays out the benefits they offer the grid.

We also speak with Dr. Alexander Jung, the head of Digital Hydro Solutions at Voith Hydro, about the data collection and analysis services his division provides for pumped storage facilities and other hydro plants as well as the research that is being carried out through the European Commission–funded XFLEX HYDRO program.

Next, Peggy Beltrone of Cat Creek Energy and Water updates us on the organization’s efforts to develop a major pumped storage facility in Idaho’s Treasure Valley.

Alex Campbell of the International Hydropower Association tells us about the International Forum on Pumped Storage, a roughly 80‑member multistakeholder platform that led a 1‑year series of discussions aimed at identifying obstacles to pumped storage development and providing policy recommendations to resolve them.

Given their location, ice is a major problem in winter for the New York Power Authority’s 16 generation facilities.

Jairo Florez tells us about how a new ice and debris boom manufactured by Worthington is improving the operations of the Vischer Ferry facility.

We also bring you the first installment in our HalfCentury Leaders series. John Eastwood’s career, which stretched from 1962 to 2017, covered hydro projects large and small; distributed pumped storage projects; solar, wind, and flywheel development; and much more.

Finally, Chuck Sensiba and Elizabeth McCormick of law firm Troutman Pepper update us on recent legislation that stands to affect pumped storage.

Pumped storage will only become more critical as years pass. I hope this issue provides you with an idea of the excellent work that is already being done in this field. H Kris Polly is the editor-in-chief of Hydro Leader magazine and the president and CEO of Water Strategies LLC, a government relations firm he began in February 2009 for the purpose of representing and guiding water, power, and agricultural entities in their dealings with Congress, the Bureau of Reclamation, and other federal government agencies. He may be contacted at kris.polly@waterstrategies.com.

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Matthew Shapiro of rPlus Hydro: Pursuing New Pumped Storage Projects Requires Playing the Long Game

The Seminoe Reservoir in Wyoming, where rPlus is working on developing the Seminoe Pumped Storage Project.

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s states and utilities move rapidly toward their climate goals of getting 50 or even 100 percent of their energy from renewable sources, the demand for ways to store that energy is growing. Pumped storage hydro is one solution, currently accounting for 95 percent of all utility-scale energy storage in the United States. According to the U.S. Department of Energy, the United States currently has 43 plants and the potential to more than double its current capacity. Hydro Leader spoke with Matthew Shapiro, the CEO of rPlus Hydro, one of the few companies with the experience to locate those rare new sites and shepherd projects through the long feasibility review and development process.

Matthew Shapiro: I first got interested in the wind energy field in 1990, when I was 22 years old. I started contacting

Hydro Leader: Tell us more about Gridflex Energy and rPlus Energies.

8 | HYDRO LEADER | April 2022

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PHOTOS COURTESY OF rPLUS HYDRO.

Hydro Leader: Please tell us about your background and how you came to be in your current position.

wind developers. At roughly the same time, it occurred to me that with pumped storage, we could store wind energy and create a more dependable product and compete against gas-fired generation, so I started reaching out to independent pumped storage developers and trying to get wind developers interested. At that point, during the 1990s, I was unsuccessful because the market for energy storage was not strong. It really wasn’t on people’s radar screen in relation to renewable energy.

But in 2009, seeing that the industry was changing and renewable energy penetration was greatly increasing, I decided to start a company called Gridflex Energy to begin identifying the best new pumped storage sites in the country and building the business case for combining them with renewable energy.

In 2019, we formed a partnership with rPlus Energies, a new renewable energy development firm, to form rPlus Hydro.

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Matthew Shapiro: rPlus Energies is a diversified renewable energy development firm, developing utility-scale solar, wind, and solar plus battery facilities. rPlus Energies is working on a multigigawatt pipeline of projects, separate from the pumped storage side. On the rPlus Hydro side, we’re currently working on 10 projects, which are in different stages of development. They range from 500 to 1,000 megawatts (MW) and are almost all in the western United States, though we do have one project in Kentucky.

Eight of them are closed-loop projects, meaning that they don’t involve any existing bodies of water, and two involve existing reservoirs. The two projects farthest along in development are the White Pine Pumped Storage Project, near Ely, Nevada, which is a 1,000 MW closed-loop project, and the Seminoe Pumped Storage Project at Seminoe Reservoir in Wyoming, which is targeted for 900 MW. Most of these projects are sized for 8 hours of full-output storage, though Seminoe is sized for 10 hours. We’ve also filed interconnection applications for several projects, which is a key step in any type of energy storage development.

Hydro Leader: Do you always begin the development process with an entity that will be the ultimate owner or operator of the facility? hydroleadermagazine.com

Matthew Shapiro: We begin with a good understanding of the market for a project and a target market involving specific utility offtakers. We don’t necessarily begin with agreements in place, but we seek to develop relationships with those potential offtakers. Because we’re going to be investing a large amount of money in project development, we want to know that at the end of the day, there will be a customer. In some cases, those utilities would likely want to own and operate the projects. In other cases, they may continue to be owned and operated by rPlus. It all depends on the market situation.

Hydro Leader: Has the market for new pumped storage hydro projects changed over the last few years?

Matthew Shapiro: Yes. The first generation of pumped storage in the United States was built from the 1960s through the early 1990s. Those projects were all built by utilities or the federal government and were used mainly to shift off-peak nuclear baseload production, which had a low market value, to on-peak periods, when the cost of fossil-fired generation was high. That arbitrage drove the market for all the original projects. Today, the market is driven by the need to store solar- and wind-generated power April 2022 | HYDRO LEADER

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ADVERTISEMENT and make it available when needed. That’s because at the state level—and in some cases, the utility level—a shift is underway to source 50, 80, or 100 percent of energy from renewable generation. That means that you need a way to keep the electrical supply system reliable and stable. In some cases, utilities may still be planning to add a certain amount of gas-fired generation, but those situations are becoming less frequent. If you’re not building fossil generation facilities to keep the system stable, then you need energy storage, and the alternatives for commercialized energy storage available today are few in number. Lithium-ion batteries have advanced and are declining in cost, but pumped storage will be an attractive part of the mix in places where it is developable and where there are good sites.

complications. At another site, though, you may uncover a sensitive species or geotechnical complications that you need to work through. Permitting and licensing with the Federal Energy Regulatory Commission (FERC) is a several-year process itself. It involves federal-level reviews—typically an environmental impact statement—as well as additional local and state permitting. If you’re on federal land, you must obtain other permits as well, such as rights of way from the Bureau of Land Management.

It’s a process, and it takes time to de-risk the project and get questions answered. It takes patience to work with the multiple parties that have jurisdiction over a given project site. You need what is referred to as patient capital, and you have to know the development fundamentals of what makes a project real. You have to hit those milestones while at the same time working on your marketing and obtaining market commitments so that there will be a contract at the end of the day. It’s an interesting balancing act—one that relatively few firms are good at or have been willing to undertake.

Hydro Leader: Under what circumstances is a FERC license not required for a pumped storage project?

Lac d'Emosson Dam, which forms the lower reservoir of the Nant de Drance Pumped Storage Project in Switzerland.

Hydro Leader: What are some of the biggest challenges in the development of new pumped storage hydro projects?

10 | HYDRO LEADER | April 2022

Hydro Leader: Given that many of the easiest sites for pumped storage projects have been taken, how do you identify new sites?

Matthew Shapiro: It used to be thought that there were no more undeveloped pumped storage sites in the United States. That was completely erroneous. It’s just a matter of cost threshold: The cost profile of one pumped storage site may be $1,500 per kilowatt while that of another may be $3,000 per kilowatt. It’s all driven by the unique features of the location. The size of the project makes a difference as well: There are economies of scale. Having screened hundreds of potential sites across the country, we’ve become quite good at that process, which goes way beyond topography. It requires an understanding of environmental sensitivity, water, transmission, geology, and the market. We are happy with the portfolio we’ve hydroleadermagazine.com

PHOTO COURTESY OF GE RENEWABLE ENERGY.

Matthew Shapiro: First, you need to find outstanding sites, which require a rare combination of characteristics.

The basic topography that you’re looking for is a high vertical drop over a short distance with the right geological conditions. A developable pumped storage site must have the right combination of physical features, low to moderate environmental sensitivity, proximity to transmission lines, a source of fill water, and a nearby market.

Development and construction takes roughly 8–10 years, so for current projects, we’re looking at completion in the late 2020s or early 2030s. Once you’ve got a good site, you have to begin the process of engineering, permitting, and licensing. The engineering process is strongly iterative. If most of your features—your powerhouse and your tunnels— are underground, then you have a lot of geotech work to do, which is expensive. It takes time and investment capital to go through the various stages of engineering, one at a time, to better define the cost and the design. Each project is unique.

One site may have virtually no land-use or environmental

Matthew Shapiro: There are some circumstances under which your location or project doesn’t trigger any of the jurisdictional factors for FERC licensing. These are sites, for example, that are entirely on private property and don’t involve any headwaters or tributaries of navigable waterways. You can still qualify for FERC licensing on a voluntary path if you desire. We look for that opportunity in unique cases. For one site that we’ve been looking at, we’ve confirmed that a FERC license would not be required if we use groundwater to fill the project, but would be required if we were to buy the water from an agency. It’s an interesting aspect of pumped storage licensing that applies to relatively few sites. We weigh those sites on a case-by-case basis to see if a non-FERC path is worth pursuing.

ADVERTISEMENT assembled. We may be adding a few other potential sites that involve unique circumstances, such as the Maysville project in Kentucky, which involves an almost vertical drop to a spacious limestone mine 1,000 feet below ground, but those opportunities are rare. There are folks looking at seawater pumped storage, which involves finding a location with a high vertical drop near the ocean and using the ocean as your lower reservoir. Only one has been built, a demonstration product in Okinawa that I believe has since been dismantled. Several other projects involving the creation of an underground reservoir have been proposed.

The advantage of that idea is that you could get a high, ideal vertical drop and avoid the environmental impacts of surface construction. On the other hand, the site would have to be ideal from a geological point of view. We don’t have any purely underground projects in our portfolio.

Hydro Leader: Have new technologies been developed over the past few years that might make pumped storage projects more feasible?

Matthew Shapiro: The construction methods and technology that were used in the 1960s, 1970s, and 1980s are still quite viable today. The biggest innovation that has occurred in pumped storage is variable-speed pump turbines, which were developed in the 1990s in Japan and have now been used in some 20 plants around the world. Variable-speed motorgenerators allow you to have a wider range of operation, primarily in the pumping mode. Fixed-speed units, which are the most common type, already have a wide range of operation in generating mode, but in pumping mode, you’re set at the unit size. With a variable-speed motor, you can vary the pumping significantly and provide a wider range of ancillary services to the grid. That can be attractive in certain markets or under certain circumstances.

PHOTO COURTESY OF rPLUS HYDRO.

Hydro Leader: You talked about the need for financing these projects with patient capital. Have investors shown more interest recently in funding these kinds of projects?

Matthew Shapiro: Our backer for rPlus Hydro and rPlus Energies, the Gardner Company, is one of the largest developers of commercial real estate in the intermountain West. The folks who started that company were concerned about global warming, so they decided to begin investing in renewables. Pumped storage became part of the vision because they recognized the need for storage to provide reliability. The Gardner Company is a particularly visionary group. Some other investors in traditional energy have also stepped into the pumped storage space. Copenhagen Infrastructure Partners purchased a couple of projects under development by Rye Development. NextEra, one of the largest renewable energy firms in the country, got involved with the Eagle Mountain project in California. Several firms have seen the long-term potential of pumped storage and recognize the attraction of hydroleadermagazine.com

investing in projects that have an experienced development team, great sites, and a good market.

Hydro Leader: What more can you tell us about the importance of pumped storage for the electrical grid?

Matthew Shapiro: In addition to being a firm generating resource, pumped storage is a dispatchable load that can be an important asset for grid stability. The grid currently relies on large rotating machines in the form of fossil fuel generation plants to maintain stability and regulate frequency and voltage levels. As those coal- and gas-fired plants get retired, pumped storage can help fill the need for that type of stability in the system.

It also enables a more efficient use of the transmission that’s delivering renewable energy. For example, wind energy generally has a capacity factor (average generation level) of 35–45 percent. That means new transmission that’s being developed to deliver wind is not really going to be optimally used. But when you add a pumped storage project to the mix, it can help optimally load the transmission by taking surplus off-peak wind and shifting it to times when the wind is not blowing. That’s one of the major drivers for our Seminoe project in Wyoming, which is at the epicenter of Wyoming wind development. That principle applies to solar as well: Pumped storage helps better use the transmission system by being able to absorb and then deliver solar-generated power on demand. Strategically located pumped storage facilities can help manage that grid balancing effectively.

Hydro Leader: Please tell us about your vision for the future.

Matthew Shapiro: I see the transition toward low-carbon or no-carbon resources continuing. Utilities will try to figure out how to make that work while keeping the lights on and keeping the grid stable. It’s widely acknowledged that energy storage will be a major part of the solution. I envision that most, if not all, of the pumped storage developments in our pipeline will become operational, as will several projects that are under development by other firms. The market is quite large. The number of developable pumped storage projects is probably finite, but I think it will be an important part of the mix. I think more and more utilities are realizing that, and I think that for the first time since the early 1990s, we will see several new pumped storage projects come into operation around the end of this decade and the beginning of the next. H Matthew Shapiro is the CEO of rPlus Hydro. He can be contacted at mshapiro@rplushydro.com.

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Voith Hydro’s Alexander Jung: Harnessing Data for Hydro and Pumped Storage

Alexander Jung in Voith Hydro’s OnPerformance.Lab.

V

Venda Nova Lake, the upper reservoir of the Frades 2 pumped storage scheme in Portugal.

oith’s Digital Hydro Solutions team helps customers reduce downtime and operate hydro plants more efficiently. As more countries add a mix of renewables to meet carbon reduction goals, the team continues to research how hydro plants can maximize performance and deliver power grid flexibility. In this interview, Dr. Alexander Jung, Voith Hydro’s head of Digital Hydro Solutions, talks with Hydro Leader about his company’s solutions and its involvement in XFLEX HYDRO, a European Commission–funded demonstration project on flexible hydropower technologies.

In 2010, I took over the responsibility for hydraulic design methods at Voith Hydro, and in 2016, I became responsible for all methods required to design hydropower turbines and generators. In 2019, we launched the Digital Hydro Solutions organization to create diagnostic and monitoring solutions for the power plants, and I became the head of that team, with overall responsibility for the respective product build activities.

Hydro Leader: Please tell us about your background and how you came to be in your current position.

Alexander Jung: Voith started in the middle of the 19th century, when a German locksmith invented a device to shred logs for the paper-making industry. His invention was a big machine that needed a lot of power. A nearby river had the potential to provide the required power, but up to then it had only been tapped by traditional water wheels, so he developed modern and more-efficient hydro turbines. The company was incorporated in 1867, and today, it has three divisions: Voith Hydro, Voith Paper, and Voith Turbo. A large share of the world’s paper is produced on our paper machines, and a quarter of the energy generated worldwide from hydropower is produced with turbines and generators from Voith Hydro.

Voith has grown into one of the largest family-owned companies in Germany. We have about 20,000 employees in 60 countries and 4.5 billion euros ($5 billion) in sales.

14 | HYDRO LEADER | April 2022

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PHOTOS COURTESY OF VOITH HYDRO.

Alexander Jung: I studied mechanical engineering at the University of Stuttgart and Northwestern University. I got my doctorate degree from the University of Stuttgart in 2000.

I’ve been in the hydropower business for 18 years. I was a research assistant at the University of Stuttgart, and after I got my doctoral degree, I worked for Siemens Power Generation in the development of gas turbines for power generation purposes. In 2004, I joined Voith as a hydraulic design engineer for water power turbines. I was involved in projects such as the design of a big Francis turbine for a project in Canada, the largest reversible pump turbines in South Africa, and a very-high-head single-stage pump turbine in Austria.

Hydro Leader: Please tell us about Voith Hydro.

ADVERTISEMENT Hydro Leader: Please tell us about the services provided by Digital Hydro Solutions.

Alexander Jung: As part of ongoing discussions with our customers about how we could assist them in their move toward digitalization, we have worked closely with our customers to collect and structure plant and operation data, detect anomalies, and find the right solutions. One of the products we offer is OnCare.Diagnostic. This product takes automation data and condition monitoring data from a plant, of which there are a vast amount available. We understand customers’ systems, their components, the related signals, and the different operating modes, so we can analyze the data and identify anomalies that may signal problems that could lead to failures. This helps plants transition from scheduled maintenance to condition-based maintenance, thus reducing maintenance costs and avoiding unplanned outages.

Based on all these insights, we deliver periodic digital health assessment reports. We analyze the data with our diagnosis system, making use of our 155 years of hydropower experience.

That experience helps us understand what the data describe.

Other, more general data collection service providers don’t necessarily understand what the data are about. Our promise is that if we have the data, we can give you actionable advice on what’s likely to fail in which component and at what time.

We’re receiving excellent feedback from our initial customers, and now we’re doing a larger-scale launch for this product as well as for a more basic, on-premise variation.

Another facet of our service is advanced monitoring capabilities. We offer our own condition monitoring system for things like vibrations, air gaps, or partial discharge and all the additional data needed to protect the machine and monitor the behavior of the units during operation.

We focus on some advanced topics, such as monitoring cavitation in hydropower units, and we now have a solution that can identify the strength of cavitation in turbines.

Additionally, we are looking into radar-based sensors, which offer high-accuracy and high-resolution data, among many other advantages. For example, if it is used on a motor generator, a high-frequency, multiple-gigahertz radio signal is not affected by disturbances such as high electric fields and currents. It is a reliable method for providing high-quality data.

Hydro Leader: Please tell us about the personal and technical resources of the Digital Hydro Solutions team.

Alexander Jung: We have an interdisciplinary team of hydro experts with many years of experience designing and developing turbines and generators and commissioning hydropower plants. We are located in Heidenheim, Germany, where the technological hub of Voith Hydro is also based, so we can get input and support from a wide range of experts.

We have data analysts who can support us with state-of-theart analytic methods and developers and programmers to code these findings into commercial software. hydroleadermagazine.com

We’ve also established what we call the OnPerformance.Lab, a central data hub that provides diagnostic services to improve our clients’ asset performance management. We constantly have experts going through the results and adding to the value of these periodic assessments. The professional version of the solution involves our colleagues in the performance labs working on the data. If clients are looking for a simpler solution, we also have an automated method that provides only recommendations based on our diagnostic framework; if there are additional questions on how to interpret the data or the automatically provided recommended actions, the customer can call for expert support or do additional analysis on their own.

Hydro Leader: How does Voith Hydro’s work on pumped storage facilities intersect with the work of Digital Hydro Solutions?

Alexander Jung: Voith is a supplier for all types of hydropower stations, so we are also a full-line supplier for pumped storage plants. We do everything except for civil works. Our products and services cover all major components of power plants, including hydromechanical equipment; eletromechanical equipment; and even heating, venting, and air conditioning systems. We also provide spare parts, maintenance, and training services as well as our digital solutions for all types of hydropower facilities.

Hydro Leader: What kinds of digital solutions do you provide to pumped storage facilities, and how do those differ from the needs of conventional facilities?

Alexander Jung: A run-of-river power plant might run for weeks or months on a straight line, providing constant baseload power. A pumped storage plant, on the other hand, may start and stop to pump or generate multiple times a day.

It may do this with separate pumps and turbines or with reversible-pump turbines. In the latter case, the same unit operates in different rotational directions depending on the operating mode. A pumped storage plant can either generate power or extract power. This provides room for a wide range of possibilities to stabilize the electrical grid. Further, if your units are equipped with power electronics and variable-speed technology, you have the opportunity to provide all kinds of additional ancillary services for grid frequency support, such as virtual inertia or fast frequency response. All this requires a more sophisticated kind of monitoring to make sure that you’re not harming your power plant. Finally, to have a proper overview of all aspects of the plant’s operations, you need advanced instrumentation in the units to close data gaps and generate the required information.

Hydro Leader: Would you tell us about the work you are doing through the European Commission–funded XFLEX HYDRO program?

April 2022 | HYDRO LEADER

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Inside the Frades 2 powerhouse.

Alexander Jung: The growth in variable renewables is changing how power grids operate, with potential effects on the stability and security of energy supply. This will increase demands on the hydropower sector to provide flexible, reliable power services that can adapt to changing supply and demand levels. New and innovative technologies will help hydropower adjust to its critical role of integrating variable renewables into the system. This will also ensure that hydropower operators can maximize their performance and access future energy markets.

We are one of 19 organizations involved in XFLEX HYDRO, an 18 million euro ($20 million) project funded by the European Commission to demonstrate how hydropower can contribute to the flexibility of our electricity grid. We have a high penetration of new renewable energies, such as wind and photovoltaic solar. Volatile energies present major challenges to the electric grid. They do not add inertia to the electric grid as do conventional power plants with synchronous generators; they just add additional energy and power. Hydropower, with its ability to inject and store power in pumped storage plants that still have by far the highest recorded cycle efficiency of all storage technologies, at almost 80 percent, has the potential to do much more than just provide and store energy.

At our demonstration site for this project, the Frades 2 pumped storage power plant, which belongs to Energias de Portugal, the largest utility in Portugal, we are demonstrating a hydraulic short circuit, a smart power plant supervisor, additional ancillary services, and the reduction of auxiliary power consumption.

Hydro Leader: What is a hydraulic short circuit?

16 | HYDRO LEADER | April 2022

Dr. Alexander Jung is the head of Voith Hydro’s Digital Hydro Solutions. He can be contacted at alexander.jung@voith.com.

hydroleadermagazine.com

PHOTOS COURTESY OF VOITH HYDRO.

Alexander Jung: A hydraulic short circuit is an operation mode with which you can increase the operating range of a power plant. You can also generate or extract very low amounts of power. In this case, we use variable-speed technology with double-fed induction machines. Unlike in generation mode, in pump mode, flow physics requires a good amount of power close to the pump’s nominal power for the pump to function. If the excess energy in the grid is insufficient, then even with variable-speed technology,

the plant cannot be used to store energy. In a hydraulic short circuit, one unit in a plant runs in generation mode while another unit runs in pump mode. A portion of the energy runs in a short circuit between the units, providing the missing energy the second unit requires to pump. This way, you can go down to zero pumping power, which is not possible without this hydraulic short circuit mode. This is a big enhancement for the capability to provide control power.

The other technology we are demonstrating at the Frades 2 site is the development of smart joint control between the units. This approach optimizes the joint operation of the two units based on selectable objective functions. In periods when water is scarce and it makes sense to run as efficiently as possible, you use every drop of water to produce the maximum amount of energy. As a secondary objective, you can maximize the time between maintenance outages. You can then set the operating points and the operating times of the units to minimize wear and tear on all the units. At times when the power market requires maximum flexibility, there is generally an increase in the monetary return for the services that provide the fastest and highest power gradients. The set points of the units can be optimized for that scenario. This is something we call the smart power plant supervisor methodology.

The third innovation we want to demonstrate is our additional ancillary services. Double-fed induction machines are asynchronous machines, so they do not provide inertia, as the excitation frequency and power controllers can follow the changes in the grid immediately. But you can implement the controller in such a way that the unit behaves as if it were a synchronous machine. This provides additional inertia to the electric grid to stabilize it.

Last but not least, we’re exploring how best to optimize plant efficiency. We want to achieve this through smart control and the optimization of auxiliary systems. Cooling water pumps are among the largest consumers in a hydropower plant.

When you analyze how these pumps are operated throughout the year, considering all the seasonal changes in temperature and the operation history of the power units, you find that there is room for improvement. Here we close the loop to the intelligent monitoring and analyses we addressed at the beginning. Based on this insight, we are continually developing smarter optimization strategies for how to run the unit at an optimal temperature in its various operating modes. This, in turn, affects the unit’s efficiency. With this optimization and increase in efficiency, you can add many megawatt-hours of energy a year to the plant output. H

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Progress on Idaho’s Cat Creek Energy and Water Project

A rendering of the completed Cat Creek project, with the proposed Cat Creek Reservoir above and the existing Anderson Ranch Reservoir below.

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he Cat Creek Energy & Water project (CCEW) is a major pumped storage and renewable energy generation project that is scheduled to be built north of Mountain Home, Idaho, on the South Fork of the Boise River. The project, which will use the Bureau of Reclamation’s Anderson Ranch Reservoir as its lower reservoir, will have a total of 1,100 megawatts (MW) of generation capacity—380 MW of on- and offsite wind and solar and 720 MW of pumped storage hydropower—and its large upper reservoir will be able to support 5 full days of full hydropower generation. In addition to the obvious benefits of power storage and generation, CCEW’s design will provide additional water storage to a region that needs it, particularly as reductions in snowpack affect its yearly water supplies, and it could even help avoid a cutoff in water supplies during a potential dam raise at Anderson Ranch Dam. In this interview, CCEW’s public policy advisor, Peggy Beltrone, updates us on the project’s progress.

with a new upper reservoir on private ranchlands. Its sheer scale, customized ternary hydro turbine technology, advanced electronics, and dual mission distinguish it from other pumped storage hydropower projects. Combined with its sister variable renewable energy resource component, CCEW will become Idaho’s largest electricity generator, providing a nameplate capacity of 980 MW of renewable power generation. With an additional 120 MW of offsite generation under our ownership, CCEW’s total capacity is 1,100 MW. The facility will be a vital tool in the transition to a carbon-free electrical grid with over 3,000 gigawatthours of energy production annually and 87,120 megawatthours of large-volume, long-duration energy storage.

CCEW’s new reservoir will increase the Boise River system’s water storage by a whopping 10 percent, enabling water to be put to multiple beneficial uses downstream and promoting the burgeoning growth of the Treasure Valley.

Hydro Leader: Please introduce CCEW.

Hydro Leader: What convinced you to add a water storage component to CCEW?

18 | HYDRO LEADER | April 2022

Peggy Beltrone: Here is the problem: Every climate model for the Pacific Northwest, and for southwestern Idaho in particular, predicts increasing temperatures over the next 50 years, even if global warming can be limited to 1.5 degrees hydroleadermagazine.com

PHOTOS COURTESY OF CCEW.

Peggy Beltrone: CCEW delivers simultaneous daily and multiday energy storage through an advanced configuration of pumped storage hydropower. It is also an important water storage facility for southwestern Idaho. The project will pair the existing federal Anderson Ranch Reservoir

ADVERTISEMENT centigrade. As a result, there will be less snowpack, which serves as the largest water storage system in the Northwest.

There will be more winter rains; snow will melt earlier; the warmer weather will lengthen the growing season by a month on average; and without significant new storage, there will be less irrigation water available. Paradoxically, the annual average amount of precipitation is forecast to grow around 9 percent in the Upper Boise River basin, making harmful earlier-season flooding more and more probable. We’ve seen such flooding occur over the past 5 years in Idaho, Oregon, and especially Washington. The obvious way out of this paradox is to store excess runoff in the spring, mitigating flood damage, and release it later in the summer, when it is much needed for irrigation. We have already signed memorandums of understanding with forward-looking irrigation districts and municipalities downstream from our project.

Cat Creek Energy & Water Unit Cross Section

Hydro Leader: Please tell us about the current status of CCEW. What recent progress has been made?

Peggy Beltrone: Progress has been steady. With local permitting secure, we are now well into the federal permitting slipstream. We are advancing our preferred federal hydropower licensing plan, working through our water rights applications, and deciding on our technology acquisition.

Our interconnections are secured. That places the project at precisely the right pace to reach commercial operation when the western transmission grid is seeking new grid stabilization services to replace fossil-fuel generators and can take advantage of what CCEW offers for the clean energy transition. Our location provides the entire West a solar and wind daily overproduction sink. Our large storage capabilities, exceptional generation, and power services mean that our facility covers all the requirements of the energy evolution.

We have advanced the hydropower licensing and water supply process within the past month by filing a 241‑page preapplication document with the Federal Energy Regulatory Commission (FERC) and an equally extensive draft work plan with the Bureau of Reclamation. The FERC submission is required for a license to operate; the Reclamation submission, for a lease of power privilege authorization to use Anderson Ranch Reservoir as our lower reservoir. The documents submitted describe the proposed facilities, contain information on the natural resources that are affected, and give a preliminary analysis of the effects of operation. Due to the special location of CCEW’s new reservoir, CCEW was able to apply to the State of Idaho for a right to previously unallocated spring flows to fill the CCEW reservoir storage facility.

A cross section of the Voith Hydro ternary units to be used in the Cat Creek project.

Hydro Leader: Please tell us about recent policy and market changes related to long-duration energy storage and how they stand to affect CCEW.

market. There is growing acknowledgement that longduration storage and generation technologies, such as pumped storage hydropower, are crucial for reaching a decarbonized economy. Such long-duration energy storage is indispensable if variable renewable energy resources—principally wind and solar—are to make up a dramatically increased share of electricity generation. For example, Strategen Consulting found that progress toward California’s goal of 60 percent renewable energy by 2045 will require 2–11 gigawatts of long-duration energy storage by 2030 and 45–55 gigawatts by 2045. State regulators in California and elsewhere are requiring utilities to add this vital storage to their portfolios. Elsewhere in the Northwest, firm decarbonization goals have also been set by both legislatures and utilities themselves. Idaho Power Company, for example, has announced a goal of 100 percent clean energy by 2045. Additionally, growing evidence that meeting climate and clean energy goals will require additional and longer-duration energy storage has led to an uptick in private investment in a host of long-duration energy storage projects and technologies. Given its unrivaled location at a multidirection transmission hub, CCEW can serve markets all over the West.

As a result of continuing drought conditions in the West, there are calls for increased water storage. Offstream pumped storage facilities that involve an existing reservoir can address this water storage need cost effectively while also providing the most efficient, economical, and long-term method for regulating the grid.

Peggy Beltrone: State and corporate clean energy goals continue to drive the long-duration energy storage

Hydro Leader: Have there been changes in the public perception of the value of new pumped storage projects?

hydroleadermagazine.com

April 2022 | HYDRO LEADER

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ADVERTISEMENT Peggy Beltrone: Several years ago, I noticed that the national labs and universities were digging deeper into pumped storage. It is, after all, the most widely used, thoroughly tested, and cost-competitive energy storage technology available. It accounts for roughly 95 percent of the world’s electrical energy storage and has been thoroughly tested over the past 100 years. This increased attention coincides with the increased development of pumped storage hydropower.

A dozen years ago, FERC had granted 39 preliminary and pending permits for pumped storage hydropower. Today, the total is 91. And there’s an uptick in stories about pumped storage hydropower in traditional news outlets. All of this drives interest from regulators, advocates, and policymakers.

Whereas pumped storage hydropower facilities were once one-off construction projects, many have been proposed today, and only a few, such as CCEW, can serve the dual purpose of new water storage in addition to power storage and generation.

Hydro Leader: Please tell us about the discussions of raising the level of Anderson Ranch Reservoir.

Hydro Leader: In what other ways will CCEW’s water storage component benefit Idaho?

20 | HYDRO LEADER | April 2022

Hydro Leader: Where are we in the timeline of the construction of Cat Creek? What are the next steps that need to be taken?

Peggy Beltrone: We expect the building of wind and solar modules to commence in 2022. We anticipate a clearly defined process with FERC that will allow us to complete the full pumped storage hydropower facility and begin commercial operation by the end of 2026 or early 2027.

The earlier FERC can approve the facility and CCEW can commence the formal lease of power privilege with Reclamation, the better the chances that we can complete the reservoir earlier, thus allowing us to provide water storage during the Anderson Ranch Dam raise cycle.

Hydro Leader: How has public perception of the Cat Creek project changed? What public communications efforts are you carrying out?

Peggy Beltrone: We have updated our communication plan to reach more people more often. This involves a refreshed web presence at catcreekenergy.com and more targeted communications. We have entered a phase in our long development cycle in which we can respond more specifically to questions. It is a difficult to keep a project in the public eye when there are long periods between milestones, but now, with technology partners aboard, designs locked in, and federal review underway, all is changing rapidly. The hard part is getting people to see that CCEW is more than just another pumped storage hydropower project, not simply because it stores more energy for longer periods of time than any other pumped storage hydropower project (or for that matter, any other chemical battery project), but also because it stores large amounts of increasingly needed water in a drought-stricken part of the country and is also uniquely able to ensure the resource adequacy, capacity flexibility, and grid resiliency required by a decarbonized 21st-century electricity transmission system. H Peggy Beltrone is the public policy advisor for Cat Creek Energy & Water. She can be contacted at info@ccewsrps.net. For more on CCEW, visit catcreekenergy.com.

hydroleadermagazine.com

PHOTO COURTESY OF CCEW.

Peggy Beltrone: One would expect raising a dam by only 6 feet to be a simple exercise, especially since at the time when it was built, Anderson Ranch Dam was the tallest earthen dam in the world. But the process of doing so is quite involved, and Reclamation is fastidious about making sure that all consequences of a raise are addressed. In this case, the effect on shoreline areas and the modification of the infrastructure surrounding those areas has been addressed, as have the questions of traffic over the dam during its construction and the effects on recreation.

The nagging problem is that during those construction years, less water will be available to downstream irrigators, many of whom raise some of the world’s most vital seed crops. According to Reclamation, the Anderson Ranch Dam raise will require a drawdown and reduction in overall water availability for downstream agricultural uses for at least three growing seasons.

Downstream irrigators might lose as much as 97,000 acre-feet a year during the dam raise. Sources say that the irrigators do not want cash to offset their losses, but water to continue their operations during this minimum-3‑year period.

CCEW could provide an immense benefit to these ag producers by using its new reservoir to replace the water storage of Anderson Ranch Reservoir during the construction project to raise Anderson Ranch Dam. If Cat Creek Reservoir is built before the dam raise, even before our powerhouse and other appurtenances are complete, it could store and deliver that water, resolving a major hurdle for the dam raise and preserving those irreplaceable irrigated farmlands, which otherwise would go dry and take up to an additional 3 years to fully reconstitute themselves.

Peggy Beltrone: Using new water storage, rather than additional groundwater, to increase the Treasure Valley’s water supply will facilitate the region’s expansion while allowing it to continue to irrigate the seed crops it sells around the world.

In addition to the needs of irrigation, resources are required to support the economic expansion of the Treasure Valley. For example, tech giant Micron is deciding where to expand its facilities. It is a major investment. A facility like CCEW can ensure both the water necessary for its expansion and netzero-emission energy for its sustainability mission.

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The International Forum on Pumped Storage Hydropower: Exploring How to Scale Up Investment and Adaptation

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s the use of renewables grows globally, why hasn’t pumped storage hydro been more widely adopted as a way to store energy and provide flexibility to the grid?

In 2020, the International Hydropower Association (IHA) convened the government-led International Forum on Pumped Storage Hydropower to identify the obstacles to scaling up this technology, to make recommendations, and to spur investment.

In this interview, Alex Campbell, the IHA’s head of research and policy, tells Hydro Leader about the forum’s findings. His key message to policymakers is to start planning now for the best options in the future.

Hydro Leader: Please tell us about your background and how you came to be in your current position.

Secretary of Energy Jennifer Granholm speaks remotely to a meeting of the International Forum on Pumped Storage Hydropower.

Alex Campbell: I joined the IHA in 2020 as the head of research and policy. I lead the association’s research and policy work across the whole suite of issues of interest to the hydropower sector. Prior to joining the IHA, I held a variety of energy policy positions in the UK government for about 9 years. During that time, I worked on smart meters, international nuclear policy, and renewables auctions, including some of Britain’s large-scale auctions for offshore wind. In these positions, I was involved with a range of lowcarbon electricity and climate change mitigation policies.

Before my work in energy, I was in regulation for about 10 years in the technology and media sectors.

developed at scale and then to put forward policy proposals and options to change that dynamic—especially, though not exclusively, when it comes to private-sector investment.

The forum was a multistakeholder platform that involved around 80 organizations, including national governments; academics; nongovernmental organizations (NGOs); and international institutions, such as multilateral development banks and international energy agencies. We included players who have concerns about hydropower but recognize the potential benefits of pumped storage hydropower. Members were organized into working groups on markets and policies; on sustainability; and on capabilities, costs, and innovations.

The forum ran from November 2020 to November 2021.

Hydro Leader: Why did the IHA launch the International Forum on Pumped Storage Hydropower?

22 | HYDRO LEADER | April 2022

Alex Campbell: One of the key findings was that in several markets around the world, some of the services provided by pumped storage hydropower, such as inertia services and black start, aren’t remunerated at the moment. That obviously poses a problem for the case for investment. Another problem is that in many systems around the world—even in some of the most-developed economies, such as the UK—people weren’t properly planning for future grids with high levels of solar and wind. They were only just beginning to think about what the system demands might be in a few decades’ time and how storage might come into play.

Pumped storage facilities are large projects with high upfront capital costs, similar in some ways to offshore wind farms. But if you’re trying to build an offshore wind farm in Europe, you’ve got a pretty good understanding of the prices you’re going to be paid over the 15 years or so during which you need to pay hydroleadermagazine.com

PHOTOS COURTESY OF THE IHA.

Alex Campbell: A few years back, we looked at the situation with pumped storage hydropower and saw a bit of a conundrum. We could see a rapid increase in the use of renewables such as solar and wind—a move that is essential for tackling climate change by decarbonizing the power sector, which is one of the major sources of carbon emissions. Wind and solar have a huge amount of potential, but you need sufficient grid flexibility to make sure that the lights stay on. Ideally, you’re also capturing any excess energy generated by those forms of technology.

So why hasn’t more pumped storage hydropower been built when the demand for that kind of flexibility seems to be increasing, not decreasing?

In 2020, with the support of the U.S. Department of Energy and several other governments, the forum was created to try to move the needle on pumped storage hydropower. We wanted to understand why it wasn’t being

Hydro Leader: What did you find were some of the obstacles to the adoption of pumped storage?

ADVERTISEMENT back your initial costs. With pumped storage hydropower, in so many places around the world, investors don’t know that.

Hydro Leader: Would you tell us about the XFLEX HYDRO project?

Hydro Leader: In addition to facilitating information sharing among the participants, did the forum aim to send a message to national regulators and international groups?

Alex Campbell: XFLEX HYDRO is an ambitious 18 million euro ($20 million) energy innovation project demonstrating how more flexible hydropower assets can help countries and regions to meet their renewable energy targets. The 4‑year, European Commission–funded project involves seven demonstration sites and 19 organizations and will conclude in 2023. It is the largest hydropower project funded by the European Union to date, and the IHA was instrumental in its development. Several of the demonstrations are focused on enhancing pumped storage hydropower: Grand Maison in France, Europe’s largest pumped storage plant at 1,800 megawatts (MW), and Alqueva in Portugal (520 MW) are testing hydraulic short-circuit pumped storage hydropower; Frades 2 in Portugal (780 MW) is testing variable-speed and hydraulic short-circuit pumped storage hydropower; and Z’Mutt in Switzerland (88 MW) is testing variable-speed pumped storage hydropower. While XFLEX HYDRO is focused on Europe, there will be learnings for hydropower globally in regard to improving flexibility and system support, or ancillary, services and how to optimize plant operations and maintenance. More information and reports can be found at xflexhydro.net.

Alex Campbell: Definitely. We had policymakers and regulators involved on the steering committee, and we encouraged them to start planning ahead of time and to think about their long-term storage needs. If we get to X gigawatts of wind and solar, how much storage do we realistically need?

What are the contract time limits? Are they stacked together so that you can get somebody competing across the suite of contracts on offer? It may be that one provider isn’t the most competitive on specific services but offers a better value overall. These are the types of processes that we were trying to get the policymakers to think about.

Hydro Leader: What results did the forum have?

Alex Campbell: We have seen positive changes, although I don’t want to claim that they are all because of the forum.

For example, the China Renewable Energy Engineering Institute actively participated in the forum, and shortly after it concluded last year, the Chinese government came up with a forward-leaning position on pumped storage hydropower. The Chinese government’s targets on pumped storage hydropower went through the roof, to over 100 gigawatts in the 2030s. Although the UK government did not actively participate, the IHA engaged with it, and we saw the UK reframe its long-duration energy storage policy. In 2021, it issued a call for evidence, signaling an important policy change to look at market mechanisms for supporting long-duration energy storage.

Our sustainability working group took a deep dive into the environmental impacts of pumped storage hydropower.

It recommended that the suite of internationally recognized tools developed by the Hydropower Sustainability Council for hydro could be applied to pumped storage as well. The tools were developed not just by industry but by NGOs and international institutions, such as the World Bank.

Hydro Leader: Please tell us about some of the research and development that the forum highlighted.

Alex Campbell: The forum identified a wide range of innovative uses for different types of pumped storage hydropower. One is the use of saltwater. A coastal cliff might be a perfect spot for a pumped storage facility using saltwater.

Disused mines provide another innovative opportunity to use existing infrastructure, and as an added benefit, these facilities will often be in communities that are suffering from the closure of major employers, meaning that they have the potential to reinvigorate the economy by providing jobs. hydroleadermagazine.com

Hydro Leader: What is your vision for the future of pumped storage hydropower and of IHA’s role in promoting its expansion?

Alex Campbell: We’ve now gotten to a place where most power and energy policymakers around the world understand the trajectory of wind and solar. We’ve seen costs come down so much in some of those technologies. That argument has been won. Now, we need to get those policymakers to think about what happens when those variable renewables aren’t available, when the weather conditions aren’t quite right.

Batteries are great for short-term energy storage, but for those longer-duration periods, we need a backup. We don’t want blackouts, and we don’t want to fall back on gas, or even worse, coal. Our role is to get people to plan now for those long-duration storage technologies. Without that, it’s going to be difficult to get to net zero globally. The power generation sector is one area in which we already have the technology.

We don’t have to rely on theoretical solutions like hydrogenpowered airplanes. Let’s just get a net-zero, low-carbon electricity system in place, along with backup services. That’s my vision, and that’s what I’ll be pushing. H

Alex Campbell is head of research and policy at the International Hydropower Association. For more about the IHA, visit hydropower.org.

April 2022 | HYDRO LEADER

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How an Ice Boom Is Aiding Operations at the New York Power Authority’s Vischer Ferry Project

The installation of a boom at the Vischer Ferry project has resulted in a dramatic reduction in forced outages and time spent raking trash and ice.

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ydropower makes up more than 80 percent of the electricity produced by the New York Power Authority (NYPA), the largest state public power organization in the nation. What happens when winter ice flows threaten to clog up those critical operations? NYPA recently installed an ice boom at its Vischer Ferry small hydroelectric facility, located on the Mohawk River near Troy, New York. In this interview, the regional manager for NYPA’s Central Region, Jairo Florez, tells Hydro Leader about the need for the boom, how it was selected, and the results the facility is seeing from it.

Hydro Leader: Please tell us about your background and how you came to be in your current position.

24 | HYDRO LEADER | April 2022

Hydro Leader: Please give us some general information about NYPA. Jairo Florez: NYPA is the largest state public power organization in the nation, operating 16 generating facilities and more than 1,400 circuit-miles of transmission lines. NYPA generates nearly 25 percent of the state’s power, and more than 80 percent of the electricity that NYPA produces is clean, renewable hydropower.

Hydro Leader: How do ice and snow affect your hydropower facilities? hydroleadermagazine.com

PHOTOS COURTESY OF NYPA.

Jairo Florez: I am originally from Colombia. I came to the United States and obtained a bachelor’s degree in electrical engineering here. I worked for Rolls Royce as a software engineer before joining NYPA in 2012. After joining NYPA, I worked as an engineer and as a manager in the operations department at the Blenheim-Gilboa Pumped Storage Power Project in Schoharie County in New

York’s Mohawk Valley, focusing on dam safety and other critical NYPA initiatives. In 2018, I became operations superintendent and assumed the position of regional manager for NYPA’s Central Region last year. In my current position, I oversee the operations of the Blenheim-Gilboa Pumped Storage Power Project, NYPA’s Crescent and Vischer Ferry small hydroelectric plants on the Mohawk River, and other small power projects in the area.

Jairo Florez: In the Central Region, we face challenges associated with ice buildup at our Vischer Ferry and Crescent small hydroelectric facilities. On warmer days during the winter months, the ice layer tends to break and start moving, creating ice jams upstream of the Vischer Ferry project. We deal with big chunks of ice, up to 2 feet thick, that can clog the project’s forebays, reducing the amount of water that flows through our generating units. This forces us to reduce the units to half power to avoid unit trips. Our operators spend a lot of time raking ice. In addition to creating problems for our power plants, the ice jams can sometimes be associated with downstream flooding.

Hydro Leader: What do you do to address these issues?

Jairo Florez: We used to have an operator constantly raking ice and debris so that we could run the units at full power and avoid unit trips. This task was time consuming and required many overtime hours from our operators, particularly at the Vischer Ferry facility.

Due to river dynamics, more floating ice and debris tend to flow into the Vischer Ferry intake than to that of Crescent, which is a nearly identical facility located a few miles downstream. At times, it was not possible to keep the Vischer Ferry intakes clear using the trash rake. Flow through the turbines sometimes needed to be reduced by 50 percent or more to prevent the intakes from becoming completely clogged. The result was that Vischer Ferry produced notably less power than Crescent in a typical year. That difference has been reduced with the success of the new boom.

Hydro Leader: Have you noticed any changes in ice conditions as a result of climate change?

Jairo Florez: Ice conditions for the Mohawk River still pose a challenge. There are good years when we have no ice and bad years when we have a lot. This year we have also introduced special icebreaker boats to help break the ice upstream of the Vischer Ferry project.

We are encouraged by the results of this pilot project so far and are hopeful that it will help alleviate some of the challenges associated with ice-jam formation in the future.

Hydro Leader: Please tell us more about the Vischer Ferry facility.

Jairo Florez: Vischer Ferry Dam is located approximately 14 miles upstream of the confluence of the five branches of the Mohawk River with the Hudson River near the city of Troy in New York’s Capitol Region. The construction of Lock 7 and Vischer Ferry Dam was completed in 1913, and the hydroleadermagazine.com

The boom at Vischer Ferry is approximately 300 feet long and consists of 13 BoatBuster sections, each of which consists of a 6-foot-tall debris screen backed by a tubular steel frame.

April 2022 | HYDRO LEADER

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ADVERTISEMENT construction of the two‑unit powerhouse was completed in 1925. NYPA purchased the two-unit powerhouse from the New York State Department of Transportation in 1984. The powerhouse was upgraded to four units in 1993. Today, the Vischer Ferry facility has four turbine generating units and a total output of about 12 megawatts, which is enough to power about 10,000 average-size homes. This hydropowergenerated electricity is delivered into the state’s electric grid. It is a run-of-river plant operating 24/7 when there is water available. When there is no water available, the plant is forced to shut down. We operate the plant remotely from the Blenheim-Gilboa Power Project control room and have one operator stationed at Vischer Ferry with an 8-hour shift during the week; this person is responsible for keeping an eye on the units and making sure they run smoothly and sometimes gets called out after hours to take care of emerging issues.

Hydro Leader: You recently installed a new ice boom there.

How did you decide on that solution?

Hydro Leader: You referred earlier to the need to remove trash and ice from the forebay. Do you also have to remove ice and debris from the boom?

26 | HYDRO LEADER | April 2022

Hydro Leader: What results have you seen from the Vischer Ferry ice boom?

Jairo Florez: We had some challenges with the initial installation of the ice boom because of high water flows.

With run-of-river units, you’re at the mercy of water flows.

You can have the people you need and have everything aligned, but if you don’t have the appropriate water levels, you can end up waiting for weeks at a time. Unfortunately, due to faulty installation by a third party, the first sheet of ice that came through after the boom was installed in December 2019 broke it. High river flows and ice conditions prevented us from investigating what had happened, and we had to wait until we could get divers in the water. We were able to correct the problem and reinstall the boom, but it took weeks. Last winter, the ice boom worked very well.

We have seen a dramatic reduction in forced outages and time spent raking trash and ice, especially when we compare Vischer Ferry with Crescent. When you look at the time currently spent on raking trash and ice at the two facilities, there is a dramatic difference. We are no longer seeing much accumulation at Vischer Ferry because of the boom.

Hydro Leader: Do most of NYPA’s facilities have similar ice booms in place?

Jairo Florez: Right now, NYPA only has ice booms at Vischer Ferry and at its flagship plant, the Niagara Power Plant in Lewiston in Western New York. The ice boom at Niagara is much larger, but it serves the same purpose: to prevent ice from building up in the intakes and inhibiting power generation. The Niagara Plant also utilizes specialized icebreaker boats that break ice upstream of the intakes all winter long. Vischer Ferry has allowed us to make a strong business case: The boom has saved man-hours, reduced equipment wear and tear, enhanced personnel safety, increased annual plant output, and decreased forced outage hours. We will continue monitoring the boom at Vischer Ferry as ice conditions change from year to year and look into more options in the future. H Jairo Florez is the regional manager for the New York Power Authority’s Central Region. For more on NYPA, visit nypa.gov.

hydroleadermagazine.com

PHOTO COURTESY OF NYPA.

Jairo Florez: The idea of installing an ice boom was discussed for many years prior to my arrival at NYPA. There were several analyses focused on the loss of generation due to unit trips or power disruptions caused by ice and debris clogging the forebay intake and the amount of overtime operators had to spend raking ice and debris. We also had trees and other debris collecting in the forebay during highwater events. Invasive water chestnuts also clog the river each year with a thick, dense mat that almost resembles algae. All of that comes down the river and clogs the strainers for the units. If there is ice accumulation, we can end up with a unit shutdown, and we have to pay overtime and get a person there to deal with it. The situation was putting a lot of strain on the operation of the facility.

To solve these persistent issues, we looped in NYPA engineering to investigate the design and installation of an ice boom. At the time, there were challenges with anchoring the boom to the concrete structure at the intake of the forebay. Later, we found an engineering company with an innovative design that satisfied our concerns. The design we ended up choosing was Worthington Products’ BoatBuster 20 heavy-duty debris and ice boom system. The boom is approximately 300 feet long and consists of 13 BoatBuster sections, each of which consists of a 6‑foot-tall debris screen backed by a tubular steel frame. Buoyancy is provided by several polyurethane barrel floats attached to each frame. The line is anchored on each end with slider-type anchors, which allow the line to rise and fall with the river and pond elevation. The boom has a vertical range of 10 feet.

Jairo Florez: Yes, that’s one of the challenges. The debris accumulates and sometimes stays there. We are trying to figure out a way to flush some of it out. Last winter, we had to shut the units down and let the water accumulate so that we could flush the debris out; we’re looking into better solutions.

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John Eastwood on His Half-Century in Energy Development and the Future of Pumped Storage

J

ohn Eastwood has spent more than 50 years in the energy development industry, with experience on many continents in fields including civil and hydraulic engineering; turbine and pump manufacturing and sales; and wind, solar, and hydro project development. Mr. Eastwood’s long experience gives him insight into the development of the hydro market over the past decades, the decisive role of government regulations and subsidies, and the importance of pumped storage for the integration of renewable generation into the grid.

Hydro Leader: Would you please tell us about the phases of your long career?

28 | HYDRO LEADER | October 2021

These cooling-water pumps at the Diablo Canyon nuclear power plant, located near Avila Beach, California, were supplied by Axel Johnson Engineering Corporation.

rapid deployment of wind and solar generation (cofounder and chairman, 1986–1991); Bering Electric Company, which supplied Soviet-built turbines and generators to the United States (cofounder and president, 1989–1992); Trinity Flywheel Power, which developed high-speed carbon-fiber flywheels for energy storage in conjunction with the Lawrence Livermore National Laboratory and subsequently became AFS Trinity (cofounder and president, 1992–2002); and finally SunLink Corporation, originally Eastwood Energy, which became a leading U.S. supplier of large, commercialscale roof-mounting systems for solar generators (founder and executive chairman, 2002–2014). In 2017, I retired, retaining the position of advisor to the board of directors.

Hydro Leader: You did quite a lot of work on pumped storage back in the 1980s. Would you tell us about what you saw?

John Eastwood: The early 1980s was a period of dramatic progress and frenetic activity in what was called low-head hydro, though that was true of high-head hydro as well. It was stimulated, in the first instance, by the Arab oil embargo of the 1970s, which in turn stimulated regulations related to the development of private hydro projects. Around 1980– 1985, the company that I was then the president of, AJEC, became a leader in that field, providing what were called water-to-wire packages. The lesson that emerged out of that hydroleadermagazine.com

PHOTOS COURTESY OF JOHN EASTWOOD.

John Eastwood: I joined Boving and Company Ltd. in London in 1962, after graduating from London University with a bachelor of science in civil engineering. I was a hydraulic engineer and worked in close collaboration with KMW’s hydraulic turbine laboratory in Kristinehamn, Sweden. My work focused on large hydro projects, such as Kariba Dam in present-day Zimbabwe, and reversible-pump turbines, such as those at the Cruachan and Villarino projects in Scotland and Spain, respectively. This provided the background to all my subsequent efforts in the fields of water turbines and large pumps.

In 1968, I moved from London to California, where I established Axel Johnson Engineering Corporation (AJEC) on behalf of the Swedish Axel Johnson Group, the owners of Boving and Company. My efforts were focused on the California Department of Water Resources’ California State Aqueduct, which we supplied with large spherical and butterfly valves. Building on this, AJEC subsequently supplied large valves and cooling-water pumps for nuclear power plants, including Diablo Canyon and Palo Verde. After the Three Mile Island incident, AJEC pivoted to focus on the emerging lowhead hydro market in response to the enactment of the Public Utility Regulatory Policies Act of 1978. From 1982 to 1986, AJEC worked successfully to establish itself as the leading U.S. supplier of water-to-wire packages for small hydro.

Of note were pioneering efforts, undertaken with Jim Besha, to supply Pit Kaplan units for ultra-low-head installations, such as Fort Miller on the Hudson River.

In 1985, I accepted the position of president of Energy Unlimited Inc., a wind development company. I left Energy Unlimited in 1986 to pursue energy development, subsequently founding and presiding over a number of businesses, including John Eastwood Associates, a hydro developer (cofounder and chairman, 1986–1993); Peak Power, a modular pumped storage developer that aimed to build distributed energy storage projects to facilitate the

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Construction of the upper dam of the Cruachan Power Station in Argyll and Bute, Scotland.

was that it was the in best interest of the United States to pursue renewables. Since there was no solar at the time and wind was in its infancy, hydro got a lot of support, including subsidies and production tax credits.

When Ronald Reagan became president, he decided that renewables, including low-head hydro and wind, were a waste of time, so in 1985, the boom became a bust over a relatively short period of time. There were many projects that had been identified in the United States that never happened because of the elimination of the necessary incentives. Fossil fuels, in particular coal and subsequently natural gas, were developed instead of low-head hydro and renewables. Now, we’re reaping the consequences in the form of global warming. The lesson is that renewable energy industries, like hydro, are the children of regulatory action. If there isn’t regulation that in some way favors or supports them, they just don’t happen.

In 1986, when I founded Peak Power, we had a concept of deploying modular pumped storage throughout the United States to serve what I felt to be the emerging need for the ability to store energy and provide peak power in conjunction with renewables. It was the right thing at the wrong time—it was simply 35 years too early!

Hydro Leader: Would you tell us about the Cruachan pumped storage project’s importance for the further development of hydro technology?

John Eastwood: Cruachan was an interesting case because prior to it, the majority of the pumped storage projects that had been developed in the world were in Europe. Such installations usually involved separate pumps and turbines, often on a common shaft. The installations were enormous in size, often with long vertical shafts topped by a motor generator. Below that would be a water turbine, and at the bottom, a multistage pump. That technology is perhaps best exemplified by the hydroleadermagazine.com

HALF-CENTURY LEADERS

Vianden project in Luxembourg and the Ffestiniog project in northern Wales. Both construction costs and equipment costs were high. It was all driven by the fact that at that time, the pump fraternity, dominated by companies in Switzerland, weren’t comfortable with high-head single-stage machines.

They preferred multistage machines.

Gradually, the idea of using single-stage machines advanced, which would reduce the overall size and cost of an installation. The use of single-stage machines required deep submergence because of cavitation considerations, but the real problem was that high-head, single-stage pump technology had not been developed by the pump industry.

The pump industry, when faced with high heads, used multistage pumps, so, ironically, it was the water turbine industry that was left to develop these single-stage highhead machines. It was basically a new technology, and it enabled the development of pumped storage at a lower price than multistage installations.

Cruachan was a groundbreaker in the mid-1960s. It had a total dynamic head of 1,196 feet, which was very high for a single-stage pump. In fact, machines of that size had never been built. A similar installation with perhaps even higher head called Cabin Creek was simultaneously developed in Colorado.

There were a lot of unknowns, but everything went well after we commissioned Cruachan until we had an accident.

The accident was directly attributable to the fact that there was no prior experience of large single-stage pump turbines with movable guide vanes. The guide vanes spun around and went into and destroyed the impeller—in this case, a 25‑ton stainless-steel casting. It was a bad event, but like a lot of accidents, it provided a mass of information that ended up being useful. Besides that, Cruachan has been an unqualified success and has been running continuously since we commissioned the first unit back in the late 1960s. In fact, I think there have been additions.

Today, heads on the order of 2,000 feet have been achieved, and projects with significantly higher head than that have been entertained. However, not as much has happened as might have been anticipated judging by the need, which is certainly there. That’s entirely because of the difficulty of getting permits. It’s not a technological problem or even an economic problem—it’s a regulatory problem.

Hydro Leader: In speaking about regulatory problems, are you referring primarily to the absence of incentives or the onerous process of getting the needed licenses?

John Eastwood: I’m talking about the onerous process of getting a Federal Energy Regulatory Commission (FERC) license. The FERC licensing process is slow. As a result, people are loath to consider developing hydro and pumped storage projects. The uncertainty associated with licensing affects the whole field of development and impinges on a developer’s ability to get financing.

April 2022 | HYDRO LEADER

| 29

HALF-CENTURY LEADERS

ADVERTISEMENT Hydro Leader: You mentioned that the Bering Electric Company transported equipment from the Soviet Union to the United States. Was that newly constructed equipment?

A worker at LMZ in Leningrad (today St. Petersburg) carries out the preliminary machining of a runner blade for the Long Falls project in New York State.

30 | HYDRO LEADER | April 2022

Hydro Leader: Please tell us about the changes in technology that you have seen over the course of your career in hydropower.

John Eastwood: I started in 1962, and I still was involved in 2017, so I have a reasonably lengthy perspective. I think the biggest change has been the shift from an analog to a digital world. When I started, everything was analog. At that time, no computers were involved in the design process, and all designs were done manually. Likewise, the turbine performance parameters were determined with laboratory test rigs, which are essentially analog computers. Today, a hydroleadermagazine.com

PHOTOS COURTESY OF JOHN EASTWOOD.

Energy policy today doesn’t really make sense. It’s driven by expediency—meaning what can be built—rather than by technological considerations or true economics. I’ve been a developer of hydro, wind, and solar projects, so I’m aware of the pitfalls. You don’t pursue something unless you believe you can get it built. Today, I would be reluctant to embark on developing a hydroelectric energy storage project. The risk is so great. You can find yourself cut off at the pass at any moment because of the perceived objections of some small group, even if they are not necessarily legitimate objections.

The regulatory factor is, in my opinion, the single biggest factor in the slow progress of hydro-based energy storage. It’s incredible that today we are obsessed with battery technology. Battery technology is fine, but its current capabilities are limited, it’s expensive, and it’s not particularly safe. It is not cost effective compared to hydro.

The idea behind Peak Power was simple: Rather than looking for a location with a water source and an elevation difference that could support a hydro project, we simply looked for a place where there was an elevation difference of around 1,000 feet. By locating a project where there was no river, we hoped to avoid the FERC licensing process, since FERC only has jurisdiction over navigable waterways. Having found a suitable location in terms of elevation difference, we would then establish whether we could bring water in, whether physically or by drilling and locating an aquifer that could charge the system. Once the system had been charged, we just had to make up for evaporation. The idea was to scatter relatively small, 25–100 megawatt installations around the grid to provide peak power, frequency regulation, power factor improvement, and other dynamic operating benefits. That would be hugely valuable today because of all the solar and wind facilities that are going in—it’s the necessary adjunct that protects a renewable energy grid from the problems of losing energy during periods when the wind doesn’t blow and the sun doesn’t shine. That vision hasn’t moved forward in the way that it should have simply because of the restrictions of the regulatory environment.

John Eastwood: During the Gorbachev years and after the fall of the Berlin Wall, we were idealistic about the possibilities for a rapprochement between the United States and the Soviet Union. I had the idea of starting a company, because I knew that one of the largest water turbine manufacturers was a Soviet company called Leningradsky Metallichesky Zavod (LMZ), or Leningrad Metalworks. Few people had heard of it, but because I was a hydro fan, I knew about it. My business partner at the time, Alvin Duskin, had a couple of friends who were going over to Moscow in 1988 for a conference.

Coincidentally, at that conference, Gorbachev made a speech in which he welcomed people into the Soviet Union to help rebuild the economy. My friends asked me what we could do, and I suggested they go to LMZ in Leningrad (today St. Petersburg) and make a deal to buy water turbines and ship them to the United States. They asked me whether I could get to Leningrad by the following week. At the time, I was in San Francisco, so that was a bit of a daunting prospect, but we rushed over to Leningrad and formed a joint company, Bering Electric Company. It was named after the Bering Straits.

The Soviets put in money, and we put in money. I ended up being the individual who had to run the company and sell Soviet-built turbines. For that reason, I contacted my friend, Jim Besha, with whom I had worked in the 1980s, and he was willing to consider Soviet turbines. We ended up providing Soviet-built turbines for some projects in New York State. I also sold a high-head Kaplan unit to the City of Takoma for the Wynoochee Project. That all ended with the 1991 coup attempt in the Soviet Union, during which Gorbachev was kept under house arrest in Crimea. Soviet credit ratings dropped to zero, and that was the end of selling turbines from the Soviet Union. We did that for about 4 years total. It was an interesting experience because nobody had been to LMZ before we had.

It was, in fact, the facility that made the first nuclear weapons and Sputnik for the Soviet Union. I didn’t know this at the time, but the facility had the ability to machine propellers for submarines using five-axis machine tools acquired from Japan.

As a result, we found ourselves being asked questions by entities like U.S. naval intelligence about what was going on there.

ADVERTISEMENT huge amount of work is done digitally. Computational fluid dynamics (CFD) has been translated into a numerical format so that it can be computerized. The profiling of turbine blades is done digitally and then passed to tools that can machine complex shapes. Back in the 1960s, everything was done by hand and template. The new way is much more efficient. For instance, if you were making a large water turbine impeller for a pump turbine back in the 1950s or 1960s, it would have been a single piece casting in stainless steel, it would have been hand ground, and the profiles would have been religiously copied from blown-up photographs of the model that had been used to determine the performance. Today, you make the turbine runner by welding together a bunch of components. The blades themselves are complicated, threedimensional shapes that have often been determined by CFD and machined on a five-axis milling machine. As a result, they are precisely representative of the designed profile of the blades. These blades are then inserted into and welded to the other elements of the impeller. You end up with a much more accurate facsimile of the required shapes than used to be the case, because so much previously depended on the skills and abilities of the people who carried out the laborious handgrinding process. It was an incredibly labor-intensive process and was also quite unhealthy because of the dust it created.

Hydro Leader: To what extent did the demand for products change over the same period?

John Eastwood: The market changed dramatically, of course. Back in the 1950s and 1960s, traditional hydro projects were still being developed in North America. That market dried up. By the 1970s and 1980s, the market in the United States and Canada had essentially evaporated. In the 1960s, for example, there were four main manufacturers of water turbines in the United States; now, there is only one.

The South American market was still relatively healthy, with large projects in Brazil and Argentina, and there was still development in Africa and China. The ironic thing is that there have been a lot of big projects built in the last 20 years.

The Chinese have developed big projects using low-cost labor and low-cost financing and have also successfully developed thousands of small projects. The bottom line is that hydro is an inherently limited resource because of the limited number of economically viable locations. I thought the day of large hydro had ended in the 1970s. Surprisingly, there have been some very big projects developed in the last 20 or 30 years. How long will that continue? In my opinion, it depends on the balance between environmental considerations and the need for power. Although I’m a hydro energy enthusiast, I also acknowledge that hydro isn’t always beneficial and may have negative effects on the environment.

Hydro Leader: Would you tell us about the importance of pumped storage in integrating renewables? hydroleadermagazine.com

HALF-CENTURY LEADERS

John Eastwood: Solar takes up a lot of space, and there is a lot of empty space in the center of the United States. To satisfy the entire energy needs of the country, you could fill a relatively small section of the United States with solar and hardly notice it. It’s an almost ideal technology, but you need energy storage to use it effectively.

The need for storage is bigger than ever before, and we have a well-established, highly efficient technology available in pumped storage that we are not deploying the way we should. In particular, it should be considered that the roundtrip efficiency of a pumped storage installation can be as high as 75 percent. The round-trip efficiency, capital cost, and longevity of most battery technologies and other energy storage technologies can’t compare, even today. A hydro project can easily provide 6–10 hours of storage, which is unthinkable in the context of battery energy storage, unless capital cost is of no significance.

Hydro Leader: What are the lessons that brought you success over your years as a hydropower and energy professional?

John Eastwood: You must be courageous. Hydropower isn’t for the faint hearted. It’s risky. As I mentioned, I’ve been a developer and an equipment supplier, so I’ve seen it from both sides. When I look back on the hydro projects that I developed myself, I see significant risks. I built three projects that had tunnels, which is very risky for a private developer—those sorts of risks are almost unacceptable unless you’re slightly crazy. Risk was the biggest concern both in construction and with the equipment itself. You’re always pushing the limits of the technology. The Cruachan project, for instance, was risky. We were pumping 1,196 feet of head in a single stage. Nobody in the world had pumped to that elevation at the time, so nobody knew what was going to happen. In addition, there was the unknown cavitation risk, which increases dramatically as you increase the head. Today, you can overcome cavitation risks because you can make turbine blades more accurately, thereby minimizing potential cavitation damage. Overall, being a hydro developer requires a willingness to accept risk of a different order of magnitude than being a wind or solar developer. In the case of solar, the insolation at a project location is predictable within a band of 2 percent; with hydro, the hydrological risk can be as high as 100 percent. H

John Eastwood is a longtime energy professional who was most recently the founder of the SunLink Corporation. He can be contacted at jeastwood@sprintmail. com or (415) 990‑3176.

April 2022 | HYDRO LEADER

| 31

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HYDRO LAW

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In the Transition to a Low-Carbon Economy, Pumped Storage Will Be Critical

By Chuck Sensiba and Elizabeth McCormick

A

s the United States moves toward a low-carbon economy, zero-carbon emitting sources of electricity will be increasingly critical to stabilize the electric grid and prevent outages, including those associated with extreme weather events. Wind and solar resources are, of course, necessary to achieve this goal, but their intermittent nature poses a challenge to maintaining grid reliability, particularly when utility-scale battery storage remains quite costly. By providing energy storage and generation in a way that takes advantage of peak demand times, pumped storage hydropower provides a way to optimize the availability of wind and solar generation at a fraction of the cost of battery storage. Over the last several years, Congress has passed legislation that seeks to increase the deployment of pumped storage hydropower, including by providing funding opportunities and directing the Federal Energy Regulatory Commission (FERC) to develop an expedited licensing process for closed-loop hydropower facilities. These opportunities, in addition to the fact that closed-loop pumped storage facilities are likely to have fewer environmental and natural resource issues, make pumped storage an attractive proposition for developers.

Background

34 | HYDRO LEADER | April 2022

The America’s Water Infrastructure Act of 2018

First, in 2018, President Trump signed the America’s Water Infrastructure Act (AWIA), which, among other things, directed FERC to initiate a rulemaking establishing an expedited licensing process to issue and amend licenses for closed-loop pumped storage projects and to hold a workshop on and issue guidance on potential opportunities for the development of closed-loop pumped storage projects at abandoned mine sites. In response, FERC issued guidance defining a closed-loop pumped storage project as one that uses reservoirs situated at locations other than natural waterways, lakes, wetlands, and other natural surface water features, and may rely on temporary withdrawals from surface waters or groundwater for the sole purpose of initial fill or the periodic recharge needed for project operation.

The guidance described the extent and types of abandoned mines in the United States and included information relevant to identifying appropriate mine sites at which to develop hydropower facilities, including information on the state and federal agencies with responsibilities associated with abandoned mines.

In April 2019, FERC issued a final rule establishing an expedited licensing process for closed-loop pumped storage projects as proscribed by AWIA. To qualify for FERC’s expedited hydroleadermagazine.com

PHOTOS COURTESY OF TROUTMAN PEPPER.

Pumped storage hydroelectric facilities generate electricity by moving water between two reservoirs. When demand for electricity is low, typically at night, excess electric generation capacity is used to pump water from the lower reservoir to the upper reservoir, where it is stored until demand for electricity increases during the day. When demand rises, the stored water is released back to the lower reservoir through a turbine to generate electricity.

Open-loop pumped storage facilities maintain a continuous connection to a naturally flowing water feature, while closedloop facilities do not. Currently, there are 43 pumped storage projects operating in the United States, all of which are openloop facilities. Of those 43 projects, 25 are nonfederal projects that hold either licenses or exemptions from FERC, while the remaining 18 are operated by the Bureau of Reclamation, the U.S. Army Corps of Engineers, the Tennessee Valley Authority, or the California Department of Water Resources.

Additionally, there are approximately 25 active or pending preliminary permits for pumped storage facilities before FERC. Preliminary permits grant permittees priority status to file a license application for a given project while conducting feasibility studies and developing a license application.

Due to their unique two-reservoir configuration, pumped storage facilities provide significant benefits to the electric grid, including the ability to provide energy storage in

the upper reservoir. Indeed, pumped storage hydropower facilities currently provide approximately 95 percent of utility-scale energy storage in the United States. Due to the intermittent nature of wind and solar generation, the energy storage provided by pumped storage hydropower facilities is critical to integrating intermittent renewable resources into the electric grid, particularly at a utility scale.

With the Biden administration’s goal of achieving 100 percent carbon-pollution-free electricity generation by 2035, additional energy storage in the form of pumped hydro will be critical to integrating more carbon-free electricity onto the grid, particularly as most of the currently operating pumped hydropower facilities were constructed over 30 years ago. To this end, the U.S. Department of Energy’s (DOE) 2018 Hydropower Vision report estimates that U.S. hydropower could grow from 101 gigawatts (GW) of capacity to approximately 150 GW by 2050, which includes approximately 36 GW of new pumped storage capacity.

Recognizing the need to supplement the nation’s existing pumped storage hydropower fleet, Congress has in recent years enacted two notable pieces of legislation that seek to provide additional funding for pumped-storage hydropower and to streamline the permitting process for those facilities.

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licensing process, a developer of a closed-loop pumped storage project must demonstrate that the proposed project would (1) cause little or no change in existing surface and groundwater flows and uses; (2) be unlikely to adversely affect threatened or endangered species or their designated critical habitat under the Endangered Species Act (ESA); (3) use only reservoirs situated at locations other than natural waterways, lakes, wetlands, and other natural surface water features; and (4) rely only on temporary withdrawals from surface waters or groundwater for the sole purposes of initial fill and periodic recharge needed for project operation.

The regulations also require FERC to issue a final licensing decision for closed-loop pumped storage projects that meet the above-listed criteria no later than 2 years after FERC’s receipt of a completed license application.

To facilitate this process, FERC’s regulations require applicants to submit documentation at the time the application is filed to show that the applicant consulted with stakeholders, including the tribes and federal and state agencies that are part of required authorizations under the Clean Water Act, the ESA, and the National Historic Preservation Act. For projects using public parks, recreation areas, and wildlife refuges, the applicant must submit documentation showing that the managing entity does not oppose a pumped storage project at that location.

However, to date, this program has not resulted in the successful development of a closed-loop pumped storage project.

Only one project has requested expedited treatment under the revised regulations, and FERC denied that request in 2020. As a result, additional policy-level work will likely be needed to fully realize the potential for more pumped storage facilities.

funding opportunities, there are other significant benefits to developing pumped storage hydropower facilities, particularly closed-loop projects that do not have a connection to a natural water feature. First, the developer has the flexibility to select a site, which can help to avoid issues associated with threatened or endangered species or critical habitat or the mandatory conditions under section 4(e) of the Federal Power Act that are typically required for hydroelectric projects located on a federal reservation.

However, not every location is suitable. For example, sites generally need to have an elevation difference between upper and lower reservoirs. Additionally, while it is important to consider a project’s potential effects on ground and surface water and the degree to which the two may be hydrologically connected, closedloop pumped storage projects typically have fewer effects on aquatic resources and, importantly, do not present issues associated with anadromous fish passage or minimum flows.

Rather, project developers should consider other issues that may be relevant to constructing and operating a pumped storage project, including proximity to seismically active areas, access to transmission, risk of ground subsidence, real property and/or mineral rights issues, and culturally significant areas and Native American interests.

Additionally, sites such as national parks, wilderness areas, or Superfund sites are generally prohibited from being used for new development. Additionally, developers of projects to be colocated with a wind or solar facility should consider whether and to what extent the construction and operation of the project might affect wind and solar facilities and whether there may be other resource considerations, including effects on terrestrial wildlife or birds.

The Infrastructure Investment and Jobs Act

To effectively take advantage of the expedited licensing process established by FERC and the new funding opportunities included in the IIJA, it will be increasingly important to know what factors to look for when considering a pumped storage facility. A familiarity with FERC and DOE’s processes and the siting factors described above will help to ensure that developers of pumped storage projects are able to offer significant benefits to both the electric grid and the environment. H

In fall 2021, Congress passed the Infrastructure Investment and Jobs Act (IIJA), also known as the Bipartisan Infrastructure Law, which among other things authorized $10 million to be appropriated by the U.S. Department of Energy (DOE) in $2 million increments in fiscal years 2022 through 2026 for pumped storage hydropower, wind and solar integration, and system reliability. It also provides for a demonstration project pursuant to which DOE will “provide financial assistance to [an] eligible entity to carry out project design, transmission studies, power market assessments, and permitting for a pumped storage hydropower project to facilitate the long-duration storage of intermittent renewable electricity.” The IIJA also includes authority for pumped storage hydropower development using Reclamation reservoirs. As of the writing of this article, DOE has not announced how it plans to allocate the funding or issued any additional guidance on the demonstration project, but it is expected to do so in the coming months.

Benefits to Developing Closed-Loop Pumped Storage Projects

Conclusion

Chuck Sensiba is a partner in Troutman Pepper’s Washington, DC, office. He can be contacted at charles.sensiba@troutman.com.

Elizabeth McCormick is an associate in Troutman Pepper’s Washington, DC, office. She can be reached at elizabeth.mccormick@troutman.com.

In addition to FERC’s expedited licensing process and DOE’s hydroleadermagazine.com

April 2022 | HYDRO LEADER

| 35

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SENIOR ENVIRONMENTAL ENGINEER Salary: Dependent upon qualifications Location: Horsham, PA Deadline: Until filled Summary: Will support our local and regional teams with a mix of environmental and civil engineering design. The applicant will have 7+ years of experience working on environmental projects, including remedial investigations, feasibility studies, remedial designs, and implementation of remedial action.

Apply: https://www.anchorqea.com/ careers/careers-open-positions/

MULTIPLE DAM AND LEVEE INDUSTRY OPPORTUNITIES Salary: Dependent upon qualifications Location: Throughout the United States Application Deadline: Until filled Summary: The USSD envisions a world in which all dams and levees are safe and valued by the communities they serve, and the organization embraces a mission of empowering professionals to advance sustainable benefits of dams and levees for society. In the furtherance of these objectives, multiple positions within this industry sector are posted on the USSD’s website.

Apply: https://www.ussdams.org/ resource-center/job-postings/ hydroleadermagazine.com

TRANSMISSION MODELING POSTDOC RESEARCHER Salary: Dependent upon qualifications Location: Golden, CO Deadline: Open until filled Summary: Accomplished transmission modeling engineer within the Grid Planning and Analysis Center (GPAC). GPAC research staff contribute to an exciting portfolio of energy analysis, applying advanced modeling and simulation tools to optimally plan for, design, and analyze the distribution and bulk power systems.

Apply: https://www.nrel.gov/careers/

PROJECT MANAGER II Salary: Dependent upon qualifications Location: Saginaw, TX Deadline: Until Filled Summary: Responsible for the design, development and deliver of effective water transmission applications and must have the demonstrated ability to manage multiple, parallel projects.

Apply: http://www.nwpipe.com/careers

TECHNICAL MARKETING MANAGER Salary: Dependent upon qualifications Location: Orem, UT or Salt Lake City, UT Deadline: Until Filled Summary: Responsible for developing, maintaining, and improving relationships with the engineering and specification community in all viable markets; creating marketing plans and coordinating with the sales team.

Apply: http://www.nwpipe.com/careers

Title: Technical Sales and Business Development Salary: Dependent upon qualifications Location: Remote/Hybrid Deadline: Open until filled Summary: Presenting our product and our values accurately and enthusiastically while maintaining existing lines of business and effectively building new relationships.

Apply: https://nustreem.com/careers/ April 2022 | HYDRO LEADER

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Upcoming Events

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