Hydro Leader February 2021

Leader ydro H VOLUME 2 ISSUE 2

february 2021

Martin Sintak on Mavel’s Low-Head Malczyce Dam in Poland

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STAFF: Kris Polly, Editor-in-Chief Joshua Dill, Managing Editor Stephanie Biddle, Graphic Designer Eliza Moreno, Web Designer Caroline Polly, Production Assistant and Social Media Coordinator Cassandra Leonard, Staff Assistant

Martin Sintak on Mavel’s Low-Head Malczyce Dam in Poland

Contents

February 2021 Volume 2, Issue 2 5 H ydro Rehab, Large and Small

By Kris Polly 8 Martin

Sintak on Mavel’s Low-Head Malczyce Dam in Poland 14 Del Shannon of Schnabel Engineering on Dam Construction and Rehabilitation 20 R ehabilitating the U.S. Army Corps of Engineers’ Hydropower Fleet

26 D ifficult Conditions Make for a Challenging Rehabilitation of a Small Hydroelectric Plant 32 E nvironmentally Friendly Epoxy Coating System Offers Big Benefits to Hydroelectric Station

By Max Silva WATER LAW 34 F ERC Regulatory Considerations for Project Modifications

By Chuck Sensiba and Elizabeth McCormick

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.

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 hydro.leader@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.

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.

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

4 | HYDRO LEADER | February 2021

COVER PHOTO:

Martin Sintak, Founder, Owner, and Managing Partner, Mavel.

Photo courtesy of Mavel.

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PHOTO COURTESY OF MAVEL.

Coming soon in Hydro Leader March: Malcolm Woolf, National Hydropower Association

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Hydro Rehab, Large and Small

M

aintaining hydroelectric facilities in good working order is critical for several reasons. Hydroelectric facilities are major power producers for our nation and will only become more important as renewable energy standards become more stringent. Moreover, hydroelectric facilities that fall into poor repair can pose significant hazards to life and property. Across the nation and the world, owners and operators of hydro projects, both large and small, are engaging in rehabilitation to make their facilities better, safer, and more efficient.

In our cover story, we speak with Martin Sintak, a founder, owner, and managing partner of the Czech hydroelectric company Mavel, about the Malczyce Power Plant, a new lowhead power plant on the Oder River in Poland.

We also speak with Del Shannon, a principal and senior vice president at Schnabel Engineering, who tells us about the many, varied dam rehabilitation projects undertaken by his firm and about new trends in risk analysis and monitoring.

The U.S. Army Corps of Engineers is also in the middle of a major, multiyear rehabilitation of its biggest-in-the-nation hydroelectric fleet. We get an insider’s view on that effort from Steven Miles and Daniel Rabon, respectively the director of the Army Corps’ Hydroelectric Design Center and the Army Corps’ national hydropower business line manager.

We also feature the story of the rehabilitation of a small hydro unit in New England. Rehabilitating its century-old penstock, which now lies under a road and along the foundations and under the deck of an operating restaurant, was no easy task, but sliplining the penstock with HOBAS pipe provided a

By Kris Polly

solution. Marty Greco, the new owner of the hydro project, and Paul Becht, an engineer who worked on the project, explain.

Max Silva of A&W Maintenance tells us about one of his company’s recent rehab projects. Two existing penstocks at a hydroelectric facility were lined with a Warren Environmental epoxy system to transform them into fishpassage structures.

Finally, in our Water Law section, we hear from Chuck Sensiba and Elizabeth McCormick of law firm Troutman Pepper about elements of federal regulatory law that are relevant to hydroelectric rehabilitation work.

Notably, under section 36 of the Federal Power Act, which was added to the law in 2018, owners and operators of facilities licensed by the Federal Energy Regulatory Commission can apply to have the investments and improvements they have made during a previous license term count toward a longer license term at relicensing.

Rehab work ranges from replacing the generators in huge dams to making use of existing penstocks in small hydro projects. When done with care and foresight, it ensures that our nation’s hydro fleet will continue to be a source of reliable, green energy for decades to come. 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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Martin Sintak on Mavel’s Low-Head Malczyce Dam in Poland

An aerial view of Mavel’s low-head Malczyce hydroelectric plant on the Odra River in southwestern Poland. A lock is visible on the left.

F

ounded immediately after the fall of communism in the former Czechoslovakia, Czech Republic-based Mavel has grown to be a world leader in hydroelectric equipment.

While the company provides a full range of turbines, one of its specialties is low-head hydro. Much of Mavel’s low-head hydro expertise was gained through designing and providing turbines for 10 projects on the Odra River, also known as the Oder, which flows through the Czech Republic, Poland, and Germany. In this interview, Martin Sintak, a Mavel founder, owner, and managing partner, tells Hydro Leader the story of the Malczyce hydroelectric plant, one of Mavel’s current projects on the Odra, and provides further details about other similar low-head projects in Central Europe.

Hydro Leader: Tell us about your background and how you started Mavel.

8 | HYDRO LEADER | February 2021

Hydro Leader: What are your responsibilities at Mavel?

Martin Sintak: My responsibilities have evolved during my time here. Originally, we all did some of everything. I did engineering, sales, administration, and hiring—pretty much anything that needed to be done. As the company grew over time, my line responsibilities evolved and shifted, but my focus on low-head opportunities in Central Europe remained unchanged. Now, my responsibilities are split between regional market leadership and oversight of line management. My regional focus has been and remains Central and Western Europe. Originally, I did hands-on work, and my strong relationships within Europe remain, but today I lead a team focused on this region.

In terms of line management, I was the sales director for many years and managed the project management department. Now, however, we are lucky to have strong leaders in both sales and project management, and my role has evolved to that of supporting and overseeing their work.

This allows me the flexibility to focus on developing and maintaining customer relationships and to work on sales, corporate strategy, technical innovations, and problem solving.

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PHOTO COURTESY OF MAVEL.

Martin Sintak: I am a Czech citizen and grew up under communism, finishing my studies at the Czech Technical University in 1988, just 2 years before the wall came down.

My degree was in civil engineering. After graduation, I started working with a small engineering company in Prague that focused on small hydroelectric power. When the political system changed in 1990, one of my professors brought together a few of his students and we established

Mavel. Now, 30 years have passed, and I’ve been with Mavel pretty much my whole working life.

ADVERTISEMENT Hydro Leader: Where is your office?

Martin Sintak: My office is at Mavel’s corporate headquarters in Benešov, a small city 50 minutes from Prague. By design, all management is located in the same complex as sales, engineering, production, purchasing, project management, research and developoment, and service. This has allowed for the seamless interaction of all departments and for a team approach to every project. We have over 110,000 square feet of production space, utilizing state of the art technology, which has provided us with both quality and cost advantages in our markets. The team at the Benešov headquarters is integrated with personnel in North America and at our second production facility near Brno, Czech Republic.

Hydro Leader: What is the meaning of the name Mavel?

Martin Sintak: It is an acronym for the Czech phrase malé vodní elektrárny, which means small hydropower plants. Ma comes from malé, meaning small; the V comes from vodní, meaning water; and el comes from elektrárny, meaning power plant. Together, that makes Mavel.

Hydro Leader: Would you tell us about Mavel’s recent hydroelectric project in Poland, the Malczyce power plant?

Martin Sintak: It has been a politically important project in Poland. The project, owned by local water authority Regionalny Zarząd Gospodarki Wodnej we Wrocławiu (Wrocław Regional Water Management Authority), is located at a new lock and dam structure on the Odra River in southwestern Poland. The project combines an upgrade of the transportation capability of the Odra river and the addition of 9 megawatts (MW) of renewable energy.

The total project includes a new dam with tilting gates, locks, and a new powerhouse with hydroelectric equipment. Mavel was awarded the project in June 2005 as leader of a consortium with Energoprojekt-Warszawa s.a., a local design and engineering company. Energoprojekt provided the design, engineering, electro system, and steel construction. Mavel provided project oversight and equipment design, production, delivery, the turbine and mechanical parts, and commissioning.

Hydro Leader: How many turbines are there, and how big are they?

Martin Sintak: The Malczyze project uses three Mavel Kaplan pit turbines. This is a typical lock and dam project, with a large flow of water and relatively low head.

Successfully optimizing power at a lock and dam project like this depends on low-head hydroelectric turbine technology, such as Kaplan turbines, which, fortunately, were invented in the Czech Republic. These double-regulated turbines were

hydroleadermagazine.com

invented by Austrian professor Viktor Kaplan in 1912 in what is now the region of South Moravia in the Czech Republic. The Czech Republic continues to be the global center of excellence for Kaplan turbines.

The Malczyce lock and dam site has a flow of 240 cubic meters (8,475 cubic feet) per second and a head of 4–6 meters (13.1–19.7 feet). Mavel is providing three Kaplan pit turbines, each with a power output of 3 MW, giving the whole facility a maximum output of 9 MW. The turbines have a diameter of 3.4 meters (11.15 feet) and three runner blades. For each unit, Mavel is also supplying a gearbox, a generator, a hydraulic power unit, and a control system.

Hydro Leader: How long have you been working on the project?

Martin Sintak: Mavel started working on this project 15 years ago. We won the tender for the design and supply in June 2005. For the first decade, we worked on design, prepared documentation about the position of powerhouse, did modeling work, and then started to produce the turbine technology. Each year, an additional increment of work was authorized by the client.

When we signed the contract in 2005, Malczyce was the biggest project we had ever signed in terms of dollar value, and more importantly, in terms of the size and the power output of the individual turbines. Now, however, we have supplied turbines with significantly larger runner diameters and installed power.

Hydro Leader: Is this project technically distinctive, and was it difficult compared to other projects you’ve done?

Martin Sintak: The project is distinctive in that it is an example of a type of hydroelectric project that is now being developed in many countries of the world, particularly in Europe and North America, where most high-head projects have already been built. Many of the projects we have completed or have underway are lock and dam projects, which involve powering existing infrastructure and improving its environmental effects while contributing to baseload renewable power. The permitting that governs adding power to existing facilities almost always mandates environmental studies, which result in the mitigation of any existing effects.

As for whether Malczyce is difficult compared to other projects, absolutely not. The design and production of Kaplan turbines, particularly low-head Kaplan turbines, is at the heart of our capabilities. This was a big project, but we worked in a consortium with Energoprojekt. Our responsibility was to design the project and to construct the turbines, a generator, a gearbox, a hydraulic power unit, and a control system. Energoprojekt was responsible for the electrical part and for steel construction.

February 2021| HYDRO LEADER

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A low view of the Malczyce dam and lock.

Hydro Leader: Were there existing turbines at the site that you improved on, or was this a wholly new project?

Martin Sintak: This was a new greenfield project. The Odra River has around 25 dams, weirs, and locks on it, and the Malczyce Dam is the newest. The previous one, Brzeg Dolny Dam, was finished in 1959. At the current rate, a dam is repaired or newly built on the river every 50–60 years.

Hydro Leader: Are there plans to put turbines on some of the other nonpowered dams or locks on the Odra River?

10 | HYDRO LEADER | February 2021

Hydro Leader: Are you currently building the seven additional turbines you mentioned?

Martin Sintak: We are only doing preliminary work. We expect to get the full go-ahead for the design and production of all three power stations between May and October of this year.

We will work on all three projects with a design company we cooperate with often and with our existing customer.

Hydro Leader: At 4–6 meters (13–19.7 feet), these are all fairly low-head projects. Is that the standard drop on almost all the locks?

Martin Sintak: That is the maximum for the Odra River.

Normally, the head is only about 2 meters (6.5 feet).

The normal range for our turbines on the Odra River is 1.5–4 meters (5–13 feet). It is fairly unusual for turbines to be able to operate at such low heads. Using three-blade hydroleadermagazine.com

PHOTOS COURTESY OF MAVEL.

Martin Sintak: Good question. Not all the Odra River dams have powerhouses, but most do. Our first project on the Odra River in Poland was the Krepna project, which we signed in 2003. To date, Mavel has provided equipment for a total of 10 power plants on the Odra, and we are beginning another 3 now. Typically, each project has 2 turbines.

The 10 power plants currently using Mavel equipment have a total of 22 turbines under operation. The three additional power plants will have 7 turbines. Eventually, we will have 13 power stations on the Odra with a total

of 29 turbines. All the projects we are working on now are new construction, not the rehabilitation or replacement of existing turbines.

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A barge passes through the lock.

technology, our turbines are efficient and have a wide operating range, with wicket gate openings from 20 percent up to 100 percent. We have a few other power stations in operation that operate safely and generate power with head as low as 1 meter (3.3 feet).

Mavel’s many projects on the Odra in Poland are really what built our expertise in very-low-head installations. That experience has made us the global leader in low-head hydro, which is applicable to other markets.

Hydro Leader: Would you tell us about the typical timeline for a project like this and why this one took 15 years to complete?

Martin Sintak: A typical timeline for Mavel to design and deliver turbines and related equipment for a similar hydropower plant is 10–20 months from contract signing, depending on the size of the turbines, the scope of work, and the customer’s preferences. The construction of a new dam and lock certainly take longer. The Malczyce project took so long because the client is a state-owned company that had to resolve many complications, including the location of the new dam, flood water flow, and restrictions hydroleadermagazine.com

related to fishing and the environment. The government was concerned about fish passage, the impact on groundwater, and all the usual obstacles.

Electronic protection against fish and fish passage is popular now. All our new installations have electronic protection against fish. This protection, together with fish passage, enables the safe migration of fish.

The Malcyze hydroelectric power plant is now operated within and integrated into the control room of the Malczyce lock and dam system. The lock and dam system will perform the final testing and technical inspection of the turbine/ generator unit, electrical and control system, gates, and cleaning machines. H

Martin Sintak is a founder, owner, and managing partner of Mavel. He can be contacted at sintak@mavel.com.

February 2021| HYDRO LEADER

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Del Shannon of Schnabel Engineering on Dam Construction and Rehabilitation

North Fork Dam, Asheville, NC: Schnabel has worked with the City of Asheville, North Carolina, since 1996, performing dam engineering services ranging from dam safety inspections to design and construction of dam safety modifications. Schnabel recently completed comprehensive engineering design services and oversaw the construction of rehabilitation measures to address identified safety issues at the North Fork Dam.

S

chnabel Engineering is an engineering firm that does significant dam design and rehabilitation work across the United States, focusing on geotechnical, structural, hydraulic, and mechanical issues and other important factors.

Del Shannon is a principal at Schnabel Engineering and a senior vice president in its dam and levee engineering group. In this interview, he tells Hydro Leader about his work in dam rehabilitation, the advantages of various project delivery methods, and the increasing importance of risk-based dam assessments.

Del Shannon: My undergraduate degree is in journalism, but I turned out to be the world’s worst journalist. I got a job at an engineering firm helping write proposals and turned out to be pretty good at it. I started hanging out with engineers and realized that I was confident that with the proper training, I could do the same work they did. So I went back

14 | HYDRO LEADER | February 2021

Hydro Leader: Did your civil engineering master’s program specialize in dams?

PHOTOS COURTESY OF SCHNABEL ENGINEERING.

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

to school, got a master’s degree in engineering, and then I got a job at a firm that designed dams.

Early in my career, around 2005–2006, I was the lead designer and engineer of record for one of the first design-build dams in the country. That got me interested in having engineers work with contractors. I thought that there could be tremendous benefit for the industry in creating a team that approached projects from a holistic standpoint, not just from a design or construction standpoint. After working for an engineering firm for 20 years, I worked for contractors for 10 years. That has given me a unique perspective not only on how to design these structures, but also on how to build them. I’m now back in the consulting business. I am a senior vice president of Schnabel Engineering and one of the senior managers in our dam and levee engineering group.

ADVERTISEMENT Del Shannon: No. Few if any master’s programs in the United States focus on dams. That is seen as postgraduate work. My focus in grad school was geotechnical engineering, which is the study of soil, rock, and earthen materials as engineering and construction materials. Working on dams is a natural fit for geotechnical engineers because 90 percent of dams are earthen, and concrete is a lot like rock.

Hydro Leader: Please tell us about Schnabel Engineering.

Del Shannon: Schnabel Engineering was formed in the mid‑1950s along with a slew of other firms, since geotechnical engineering was becoming more and more important at the time. Building foundations and complex structures requires a thorough understanding and knowledge of the soils, rocks, and materials they are built on. Schnabel is primarily based on the East Coast, and recently, it has started expanding into the West. In the 1990s, it formed its dam engineering group. This arm of the company has about 160 people. We’re one of the top dam design engineering firms in the country.

Hydro Leader: What percentage of Schnabel’s work is on dams?

Del Shannon: Schnabel has about 400 people as a whole, and in addition to the 160 people in the dam engineering group, several experts from our geotechnical and tunneling groups work on dam projects, so about 50 percent of our employees

work to support projects in the dam and levee engineering group. The dam market is growing by leaps and bounds. The peak of dam building in the United States occurred around the 1960s. Since then, there has been some societal pushback related to the effects of construction on the environment.

However, the need for water and power has never subsided, even with the contraction in building. That’s created a bit of a shortfall as the population continues to grow. We need to do some catching up, and it is essential that we maintain our existing structures as they continue to age. That’s one of the main reasons for our tremendous growth.

Hydro Leader: Who are the clients you work with on your dam projects, and who are the owners of the dams Schnabel works on?

Del Shannon: There is a wide range of owners. There are 90,000 dams in the United States, including hydropower dams owned by utilities or municipalities, private owners, states, and the federal government. There are probably a dozen federal agencies that work on and own dams, including the Federal Emergency Management Agency, the National Resources Conservation Service, the U.S. Army Corps of Engineers, and the Bureau of Reclamation. All these entities have dam-safety arms, and we work with all of them.

Hydro Leader: What are the most common types of dam rehabilitation projects Schnabel works on?

Peachtree City, Georgia, proactively elected to upgrade the low-hazard dam and spillway at Lake Peachtree to meet state dam safety criteria for a high-hazard structure. Of the alternatives Schnabel evaluated for increasing spillway capacity, a three-stage piano key weir (PKW) met all key project objectives. Completed in June 2018, it is the first PKW put into service in the United States and the first known multistage PKW in the world.

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February 2021| HYDRO LEADER

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After conducting a forensic study of the 2010 failure of Hope Mills Lake Dam in Hope Mills, North Carolina, Schnabel provided comprehensive design and construction observation services for a complete replacement of the structure, featuring a five-cycle labyrinth spillway.

16 | HYDRO LEADER | February 2021

to happen. The logical next question is, what don’t we know about other structures? How many other structures out there are on the verge of failure?

Hydro Leader: What are some of the major trends in dam construction and rehabilitation today?

Del Shannon: First, there is actually new construction going on. For the first time in a long time, we’re seeing an uptick in new storage, motivated by the facts that water is becoming scarcer and that our population continues to grow. Climate change is part of that. It used to be that you could count on snowpack serving as a supply source to fill reservoirs. It would melt, and you would store it. However, as our climate changes, many entities are realizing that they can no longer rely on snowpack. You need to shift your thinking to more of a runoff scenario where reservoirs are filled year round during periods of high flows. Offstream storage is becoming popular, as is raising existing dams.

Hydro Leader: The cost of replacing infrastructure is always a major concern for dam and reservoir owners. Is Schnabel involved at all in advocating for federal funding for infrastructure? hydroleadermagazine.com

PHOTOS COURTESY OF SCHNABEL ENGINEERING.

Del Shannon: Dams have a number of failure modes related to the ways in which they are most vulnerable. For example, are the foundations and the material underneath the dam stable? Is the dam structure itself stable? Is it degrading over time? Then there’s the hydraulic element. One of the most vulnerable parts of a dam is its spillway. It’s got to be able to pass a storm. If it can’t, it’s vulnerable to failure. We look at spillways and their abilities to pass floods a lot. We do a lot of looking at the quality of concrete. Internal erosion and filters are another major issue with embankment dams and foundations. There are also hydromechanical issues related to elements like gates. If steel gates and valves are poorly maintained over the years or if they are not exercised because they are rarely operated, problems can arise. A rehabilitation project may involve replacing a vulnerable part of a structure, like a spillway or gate. The difficulty is that you have to be able to isolate or shut these things off in order to work on them.

The Oroville spillway failure in 2017 spooked a lot of people in the industry. That failed during a relatively routine spillway release/flow event. Nobody thought there was a significant problem with that structure, but if you start looking into the history of its design, its geology, and its construction, you can see that there was a problem waiting

ADVERTISEMENT Del Shannon: We’re acutely aware of the massive costs of infrastructure construction and maintenance. We do advocate for funding for these structures, but we have to be careful to remain politically neutral and offer only our technical expertise. We simply argue for the safe operation of the structures.

element of the dam throughout its three dimensions. You have to have specific, high-quality data from hundreds of thousands, if not millions, of points throughout the structure. It’s not feasible to do that, and as a result, we’re ending up with an incomplete view of the structure from a deterministic standpoint.

Hydro Leader: You spoke earlier about being involved in some of the first design-build dams and the advantages of a holistic perspective that brings together design and construction. Would you expand on those advantages?

Del Shannon: While I’m a big fan of the design-build method, I should clarify that not everybody is. If done correctly, that method can allow you to put downward pressure on costs. Much of the cost of a new construction project relates to risk. In my opinion, in order to effectively manage that risk, you need to assign it to the entity that’s best suited to manage it. For instance, owner-related issues should be managed by the owner. If an owner abdicates responsibility and makes either the contractor or the engineer manage the risk, that drives the price up. The same thing is true of a contractor. If there are a lot of unknowns about the design or there are many things out of the contractor’s control, the contractor will increase its price to cover its risks. The same thing is true of the engineer. If the engineer has a lot of uncertainty, they will be conservative and design an expensive structure.

If you can bring all those entities, including the regulator, to the table and discuss how to appropriately allocate and manage risk, you can lower those prices. Consider the example of the Pine Brook Dam in Boulder, Colorado, which I designed. We designed and built that dam in 18 months for about $4.5 million. A comparable dam was constructed around the same time by the same contractor and a different engineer through the design-bid-build process, meaning that it was designed and then put out to bid and was built by the lowest-bidding contractor. That dam cost $7.5 million. In that particular case, by bringing the right people to the table to manage the risks, we reduced the cost by about 40 percent.

Hydro Leader: What trends do you see in the field of dam construction and rehabilitation?

Del Shannon: When it comes to the evaluation of existing structures, the hydropower world is increasingly shifting to a risk-based outlook. Traditionally, engineering has been deterministic. You derive a specific number from a series of calculations and modeling exercises, and you rely on that number for an idea of what’s going on with your structure.

However, the size and complexity of these structures puts limits on the usefulness of that approach. In order to really understand how your dam is performing, you have to have an intimate understanding of the materials used in every hydroleadermagazine.com

Schnabel designed an auxiliary spillway for the North Fork Dam near Asheville, North Carolina.

The way to address that is by adopting a more-risk-based or probabilistic standpoint, which involves dealing with known vulnerabilities that we call potential failure modes.

We evaluate individual potential failure modes using a risk framework to determine whether or not there is a problem.

This approach is being promoted by the Federal Energy Regulatory Commission, and it is becoming much more prominent. That’s a big shift.

While risk is an increasingly important element of the evaluation of existing structures, I don’t think deterministic work is going to be supplanted by risk-based work in the design and construction of new structures. We’re still going to do what we’ve always done; however, the potentialfailure-modes analysis and risk framework allow us to better design and build new structures with appropriate protective measures. H Del Shannon is a principal at Schnabel Engineering and a senior vice president of Schnabel’s dam and levee engineering group.

He can be contacted at dshannon@schnabel-eng.com.

February 2021| HYDRO LEADER

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Rehabilitating the U.S. Army Corps of Engineers’ Hydropower Fleet

The Dalles Dam on the Columbia River, on the border between Oregon and Washington.

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he U.S. Army Corps of Engineers runs the country’s biggest hydroelectric fleet, generating 23 gigawatts of clean, renewable energy. Keeping that fleet in good operating condition and ensuring that it can provide power at competitive rates requires continual maintenance and efforts to upgrade and rehabilitate generators and dams. Currently, the Army Corps is in the middle of a major, multiyear rehabilitation effort. In this interview, Steven Miles, the director of the Army Corps’ Hydroelectric Design Center (HDC), and Daniel Rabon, its national hydropower business line manager, tell Hydro Leader about the importance of that effort and what it entails.

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

20 | HYDRO LEADER | February 2021

Daniel Rabon: My current position is the national hydropower business line manager. I am based in our Washington, DC, headquarters. I have worked for the Army Corps for about 15 years with a bit of a break. I started in hydroleadermagazine.com

PHOTOS COURTESY OF THE U.S. ARMY CORPS OF ENGINEERS.

Steven Miles: I am a civil engineer and licensed as a professional engineer. I have two advanced degrees: an MBA and a master’s in strategic studies. After I graduated college, I spent 27 years in the army as an engineer officer. My last job in the army was district commander of the Portland district of the Army Corps.

It was in that position that I fell in love with hydropower.

The Portland district has almost 7,000 megawatts (MW) of hydropower, harnessing the power of the Columbia River and its tributaries.

When I transitioned off active duty, I was a consultant for a couple years for a firm in Portland, Oregon, that had an energy business line. About 8 years ago, this army civilian job with the Army Corps became available, and I was fortunate enough to be selected. Hydropower is one of the industries that I really hoped to be able to work in after my army career. It’s a green, non-carbon-emitting, sustainable resource that brings together computer engineers, civil engineers, mechanical engineers, electrical engineers, and hydraulic engineers, to name a few.

My current position is director of HDC, a national center of expertise for the engineering side of the Army Corps.

HDC is predominantly based in Portland, Oregon, with other offices east of the Mississippi divide. It employs about 175 engineers and scientists, and its primary role is to serve the 16 Army Corps districts with hydropower, engineering, and analytics work. We do the major engineering of the power train for the Army Corps’ hydropower plants, and we form part of the product delivery teams of the geographic districts where those power plants are located.

ADVERTISEMENT one of our district offices in Mobile, Alabama, where I was pursuing an engineering degree at the University of South Alabama. The reason I ended up with the Army Corps was that my grandmother was part of the original plant staff at the hydropower plant we have at the location where the Chattahoochee and Flint Rivers come together to form Lake Seminole in Florida.

I started out as an engineering co-op, meaning that I alternated semesters of studies with semesters of work. I ended up working at all 14 of the hydropower plants in our South Atlantic Division, so I gained a lot of hands-on experience. My last job in that region was to operate our regional engineering groups. I had about six plant engineers who worked for me across the region. After that job, I left the Army Corps and came to Washington, DC, to work for the U.S. Department of Energy (DOE) in its Waterpower Technologies Office. My current job came open in 2017, so I’ve been in this role about 3½ years.

Staff perform hub seal repair on Kaplan units at John Day Dam, located on the Columbia River, on the border between Oregon and Washington.

Hydro Leader: What are your duties as the Army Corps’ hydropower business line manager?

Daniel Rabon: My section is responsible for the budget and policy of the Army Corps hydropower program. We handle the appropriated budget for 54 of our 75 hydropower projects; the rest are directly funded by the Bonneville Power Administration. We are responsible for creating, defending, and executing the budget and for all the policy that relates to the operations and maintenance of our program.

Hydro Leader: Please tell us about the Army Corps’ hydro fleet.

Daniel Rabon: The Army Corps’ hydropower fleet is the largest in the country. We have 75 hydro plants, 356 gridconnected generators, and around 23 gigawatts of installed capacity. We serve regional customers across the nation.

Our power is marketed by the DOE’s Power Marketing Administrations (PMAs). Our fleet is quite old. The average age of our equipment is around 50 years. Our fleet is really important for various reasons. Historically, it played a crucial role in rural electrification. Since then, the electrical grid has changed a bit, and we’re seeing the value of using our hydropower in a lot of new ways. One of those ways is the integration of renewables, whether by participating in energy imbalance markets; by serving our customers on a more flexible; on-demand basis; or by performing ancillary services like ramping or voltage support.

Steven Miles: The average person in our country does not necessarily recognize the importance of hydropower. They may just think of hydropower facilities in the middle of rivers and think we have to get rid of them. But as Daniel pointed out, hydropower will play an important role in addressing climate change. It is a completely sustainable resource that is dependable and dispatchable, unlike hydroleadermagazine.com

Personnel at Ice Harbor Dam, located near Burbank, Washington, installed an advanced fixed-blade turbine runner, the first of its kind, on June 8, 2018.

February 2021| HYDRO LEADER

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ADVERTISEMENT solar and wind power, which are great but intermittent.

Hydropower provides grid stability as well as frequency regulation. It is critical to keeping stable electricity moving.

As our transmission system improves, independent system operators are able to benefit from hydropower assets outside their balancing areas to supplement MW demands and grid stability services that hydropower can provide on demand.

One of hydropower’s advantages over nuclear, coal, and gas combustion generation is that it can fluctuate quickly, and flexibility is critical in the new emerging energy market. A hydropower plant can reduce or increase its output in just minutes, in contrast to a nuclear plant, the output of which is difficult to adjust once set at its base level.

Hydro Leader: How do you adjust the output of a hydro plant while it is in operation?

Crews rewind a generator at the McNary Dam on the Columbia River, on the border between Oregon and Washington.

Steven Miles: There is a control-room operator for each of the Army Corps’ 356 generators and 75 power plants, some of whom are remote and some of whom are on site at the plant.

They get signals from our partners at the DOE through the PMAs, telling them how many MW they need or what services they need for the grid. The operators can use SCADA to communicate with individual plants and to adjust the turbines and turn them on or off. A lot of that is done automatically through computers and monitored by the operators. That process is called automatic generation control (AGC).

Steven Miles: There are two funding streams for our fleet.

One comes from the public, nonprofit power utilities in the utility associations that partner with DOE’s four PMAs. Congress has allowed these partners to fund the capital rehabilitation of our plants, which is great. A few decades ago, we had to rely on congressional appropriations. That posed problems for keeping up with the demands of the system.

The challenge for us is that those power utilities are

22 | HYDRO LEADER | February 2021

Daniel Rabon: We tend to lag behind the industry in terms of forced outages, rates, and availability. We are trying to address that through these rehabilitations. We are also working to become more data informed. We want to make use of the data we generate to make smart decisions about additional instrumentation, to decide how to perform our day-to-day maintenance, and to consider different operational regimes as the grid continues to change. If we operate our machines differently, how is that going to change our needs for maintenance, replacement, modernization, or rehabilitation? Data can also help us predict when something is going to break and to replace it.

Hydro Leader: In addition to replacing physical components of the power plants, does rehabilitation involve software upgrades?

Steven Miles: Yes. We are now in the business of replacing digital systems with new versions. We are also working to make our turbines and power trains smart machines. That means that we are incorporating sensors and gauges for advanced diagnostics and machine condition monitoring technologies.

If our operators have better diagnostics, they can save time on maintenance and avoid forced outages. Predictive and hydroleadermagazine.com

PHOTOS COURTESY OF THE U.S. ARMY CORPS OF ENGINEERS.

Hydro Leader: Please tell us about the Army Corps’ ongoing rehabilitation and modernization of its hydro fleet.

open to buying all sorts of generation, including natural gas, solar, and wind in addition to hydropower. They’re looking for the most inexpensive power available, so we need to keep hydropower as economically competitive as possible.

Hydropower is cost challenged because of its complexity, large rotating machines, and secondary environmental mitigation costs. By contrast, a natural gas plant can be set up within short period, and natural gas is fairly cheap because of fracking and directional drilling technology.

Of our 75 power plants, 10–15 have already been modernized, and we’re working on another 20–25 right now. They’re in all different phases of rehabilitation: Some are in planning, some are in design, and some are actually being rehabilitated as we speak. Our average power plant has 5–10 generators. These are big power trains with a vertical shaft and a generator on the top, on the dry side, and a big propeller runner on the wet side that is driven by the falling water that’s coming through the dam. It takes roughly a year to completely replace a generator and put in a new turbine and generator rebuild.

We replace the generators one at a time, so if a plant has five generators, four will still be running as we replace one. These projects were generally designed to be able to have at least one unit out of service at any given time. At one of our big plants, whose rehabilitation we’re designing right now, we’re considering doing two turbines at once.

There are limitations to how many turbines we can rehabilitate at once—for example, there is limited space inside the plants in which to put all the turbine parts as we disassemble them. The other limiting factor is how much power our partners can do without. At the end of the day, the PMAs still need to meet their customers’ demands.

ADVERTISEMENT condition-based maintenance allows us to do maintenance when it is needed, not just when an arbitrary time period has passed. We’re already seeing high payoff from these devices, including vibration sensors, pressure sensors, and temperature sensors. What we really want to avoid are forced outages, where a machine breaks or must be taken offline without warning.

That puts our partners in a bind and forces them to buy power on the short-term market, which can be rather expensive.

HDC staff also go to industry training events and learn about what our industry partners around the world are researching and developing. We also take part in a forum called the Center for Energy Advancement through Technological Innovation that brings hydropower owners together to share and exchange lessons they have learned.

I’ll be speaking at a virtual conference in February, giving the designer’s long-term perspective on keeping hydropower generation cost competitive. The design work that HDC is doing is part of the long game—setting up our fleet to remain cost competitive years into the future.

Our main lines of effort are condition monitoring, leveraging our operational data, centralized control, and reducing the oil profile of our plants. We want to avoid the accidental release of oil from our projects. A lot of oil is involved in hydropower plants, both in the turbine hubs and in the oil cooling systems around high-bearing temperature surfaces. HDC is looking at technologies that would reduce oil use at our plants. Some of that involves new, improved designs for the propellers, which are also called turbine runners. One option is to convert some of our propellers to fixed blades. A propeller with a fixed blade doesn’t need oil inside its blades because there are no moving mechanical parts. Converting to fixed blades would reduce oil use in some cases by almost 2,000 gallons of oil per unit. The downside to the fixed-blade runner is reduced operational flexibility for ramping up and down unit generation. We’re also installing sensors and gauges on the large oil tanks in the plants to automatically warn us if there is an unintended level change.

Finally, we are working on our transformers. The transformers in a hydro plant can be as big as a two-car garage.

Most of them are cooled by oil, but we are commissioning our first gas-filled transformer at Dennison Dam. It is now using SF6 insulating gas to cool its transformers. This is another way to reduce the oil profile and the risk of leaks.

Hydro Leader: How do new trends in technology, cybersecurity, and renewable energy affect the Army Corps’ modernization effort?

Daniel Rabon: We have an entity called the Hydropower Analysis Center that tries to research what kind of modernization is needed in specific places. It looks at factors like our customers’ needs, changes in the grid, the importance of flexibility in specific areas, and water availability. We work collaboratively with our PMAs and our customers to find the right solutions. hydroleadermagazine.com

As Steve mentioned, one important factor is cost. In a lot of regions, the cost of our energy is right around the market price for natural gas–generated power. One of the ways that we are trying to reduce our prices is through centralized control. We typically sell power at the region level, and we’re seeing a big push to centralize control at the regional level, mimicking what we see a lot of other hydropower utilities do. Cybersecurity is also increasingly important. We need to keep our projects secure while we begin to shift to more centralized control.

Steven Miles: When it comes to the technology and material science that goes into these power plants, we don’t necessarily want to be on the bleeding edge of new technology, but we do want to be on the leading edge of the industry, implementing new innovative solutions. It’s critical to make sound engineering judgement, because these investments will potentially remain in service for 50–75 years.

Another area of security concern relates to the source countries where hydropower components are manufactured.

It is very important that all cyber components of the hydropower system be vetted and cleared through all the appropriate country-of-origin and security screenings to ensure that they are not compromised and are cyber safe.

Hydro Leader: What is your vision for the future of the Army Corps’ hydro fleet?

Daniel Rabon: Our vision for the future of our hydropower fleet is for it to be reliable, available, dependable, and low cost. Those are lofty goals, but we’re putting a lot of effort into all of them. By working on high-quality designs and rehabilitations and becoming more data informed, we are aiming to lower costs on the operations and maintenance side and make good decisions on the capital investment side.

Steven Miles: We want to keep hydropower a reliable, competitive, and dependable resource. I feel lucky to be in the renewable energy business, particularly hydropower. Our fleet produces 23 gigawatts of clean, renewable energy— hydropower will play a critical role in decarbonizing our national grid. H Steven Miles is the director of the U.S. Army Corps of Engineers’ Hydroelectric Design Center. He can be contacted at steven.r.miles@usace.army.mil or (503) 808‑4200.

Daniel Rabon is the Army Corps’ national hydropower business line manager. He can be contacted at daniel.w.rabon@usace.army.mil or (202) 761‑4889.

February 2021| HYDRO LEADER

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Difficult Conditions Make for a Challenging Rehabilitation of a Small Hydroelectric Plant

The Noone Falls Mill Dam on the Contoocock River in Peterborough, New Hampshire.

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

26 | HYDRO LEADER | February 2021

Marty Greco: I am an industrial electrical construction contractor and own a utility relay protection engineering group. In addition to the Noone Falls Mill hydro project, we own three additional hydroelectric projects in the state of New Hampshire. We’ve owned hydroelectric projects for around 10 years and have had decent success. The State of New Hampshire; the Federal Energy Regulatory Commission (FERC); our electric utility, Eversource NH; and the community of Peterborough, New Hampshire, have all been extremely supportive.

Paul Becht: I’m a registered professional engineer. I have been with the H.L. Turner Group of Concord, New Hampshire, for 20 years. The Turner Group has a structural hydroleadermagazine.com

PHOTOS COURTESY OF MARTY GRECO.

he Noone Falls Mill hydroelectric project, located in Peterborough, New Hampshire, was in need of an upgrade.

Marty Greco, its new owner, replaced its generators, its electrical switchgear, and its turbine units. The penstock, however, posed additional challenges. Dating back more than a century, the penstock ran under a road, along the foundation of a restaurant, and under the restaurant’s deck, making excavation impractical.

In this interview, we speak with Mr. Greco and with Paul Becht, a principal and the vice president of structural engineering at the H.L. Turner Group, about how they addressed and successfully solved this challenging problem.

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engineering division with a hydro subdivision that does a lot of work providing design and construction assistance on turbine generator installations, related civil works, dam and penstock rehabilitations, and similar projects for independent power producers like Marty. We have also assisted independent power producers in licensing applications and renewals.

which is fairly large. We also got it as a distressed project and completely redeveloped it. It has been highly successful.

We also have a minimum-flow generation project at the Wilton Reservoir in Wilton, New Hampshire, in addition to the Noone Falls Mill hydroelectric project in Peterborough, New Hampshire. It was also a somewhat distressed project that we redeveloped.

Hydro Leader: Mr. Greco, How did you get into the business of owning and operating hydroelectric projects?

Hydro Leader: Please tell us about the Noone Falls Mill project and its history prior to your acquisition of it.

Marty Greco: I’ve been an industrial electrical contractor for my entire professional life and have worked around utility generation projects for more than 30 years. I had always had a great interest in the field. At one point, the owner of the Boston Felt hydroelectric project in East Rochester, New Hampshire, had a lot of trouble with the project. It had been destroyed in the Mother’s Day flood of May 2006. I was able to essentially take over that project. My company, Salmon Falls Power & Light Company, completely redeveloped it—rebuilt the dam and all the electrical work—and put it back into operation. I subsequently did the same with three other hydroelectric projects. One was the Pine Valley Mill hydroelectric power project in Milford, New Hampshire,

Marty Greco: The project is located in Peterborough, New Hampshire, on the Contoocook River. There is a small head pond. It has been in hydroelectric operation since 1981, when it was developed, and it was operated fairly successfully for many years. A few years ago, the Cobb family took it over, but by then, the machinery was ailing.

The equipment was somewhat damaged and essentially worn out, and repairing it was more than the Cobb family wanted to deal with, so about 3 years ago, they decided to sell it. The Cobbs got my name because we had just completed the redevelopment of the Pine Valley Mill hydro project, which is located around 13 miles away from Noone Falls Mill, and they essentially offered me

hydroleadermagazine.com

February 2021| HYDRO LEADER

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Centrifugally cast cementitious and fiberglass combined pipe manufactured by HOBAS Pipe USA.

the facility. We were glad to take it on; it was right up our alley. We completely overhauled the generators, the electrical switchgear, and the turbine units. During the redevelopment process, we determined that the penstock itself had eroded away to a level that was likely hazardous.

FERC and Paul helped us evaluate it, and we determined that it wasn’t safe to run the facility in the state it was in. With Paul’s help, we reached out to HOBAS Pipe to replace the penstock. HOBAS was attractive for a variety of different reasons, including ease of installation and readiness of delivery.

Hydro Leader: How much flow is diverted from the river for the project?

28 | HYDRO LEADER | February 2021

Hydro Leader: Would you tell us about the difficulties of replacing this particular penstock?

Marty Greco: The penstock has been in this location in some form or another since the 1800s. Back then, it powered a mechanical line shaft, which was pretty popular in the woolen mill industry. I don’t know what type of hydroelectric operation may have existed in the same location in the early 20th century before the installation of the current equipment in 1981. After 1981, a nearby restaurant was expanded and decks were installed around it.

All of this was built over the aging penstock. The penstock received some attention over the years, but I don’t believe there had ever been a complete replacement. Some parts of the penstock underneath the building, for example, were probably fairly close to original. They probably dated back at least 100 years. FERC, our federal regulator, was fairly concerned about the difficulty of determining the structural integrity of the penstock, particularly since it was underneath a building. FERC ordered us to perform some evaluations, and we were already aware that the penstock needed attention. Paul came in and helped us determine the structural integrity of the penstock. We determined that it made a lot of sense to replace it. hydroleadermagazine.com

PHOTOS COURTESY OF MARTY GRECO AND PAUL BECHT.

Marty Greco: This is a run-of-river project that involves a dam across the entire river. The generating equipment generally uses around 120 cubic feet per second (cfs) of water, but because the river flows at a rate that is higher than that most of the time, we usually have quite a bit of water spill over the dam. We sell the power we generate through an aggregator, Standard Power of Nashua, New Hampshire, under New Hampshire’s Group Net Metering Plan; 25 other projects also sell to that aggregator. The aggregator, in turn, sells the energy to municipalities and businesses that want to participate in the renewable energy portfolio. Under that plan, we receive payment from the power company and

the aggregator refunds a portion to the electric customer for all the energy that we generate in our aggregator’s cell.

ADVERTISEMENT Paul Becht: We knew we either had to reline the penstock or replace it in its entirety, because in many locations, there were pinholes in the metal. I have experience with a few different methods of penstock replacement and rehabilitation. One option is to apply a shotcrete liner on the inside of a penstock. This project didn’t lend itself to that method because of its small size—the penstock was only 5½ feet in diameter on the inside. Another option is to completely replace a penstock using steel pipe. That wasn’t feasible for this penstock, because it goes under a roadway and approaches the restaurant’s foundation before going under the outdoor deck used for dining. We didn’t want to dig up the roadway, excavate near the fragile foundation of an old mill building, or have to remove the deck of an operating restaurant. Of the 200 feet of penstock that we had to deal with, approximately half was buried underground.

That lends itself well to a sliplining process, which is what we selected. We used centrifugally cast cementitious and fiberglass combined pipe manufactured by HOBAS Pipe USA of Texas. One of the many advantages of HOBAS pipe is that it has such a slick inner surface with such a low Manning’s coefficient that even though we used a 54-inch-inside-diameter pipe to slipline the existing 66-inch penstock, hydraulic calculations showed the loss in gross head was less than 10 percent. This was determined to be within acceptable limits for maximum power production. The HOBAS pipe was also easy to put together. The joints simply had to be pushed together, and unlike steel pipe, it did not have to be welded. The price was also attractive compared to steel.

Marty Greco: We were extremely fortunate. We had support from everyone. The municipality wrote letters of support.

FERC reviewed Turner’s design quickly. The State of New Hampshire contributed funding to this project in the form of a renewable energy portfolio grant.

Hydro Leader: How do you slip the pipe inside the existing pipe? Is there a mechanism that pushes lengths of pipe down the existing pipe one after another?

Paul Becht: This is the first time that I’ve worked with HOBAS. The staff was extremely helpful. HOBAS’s sales representative, John Mele, was knowledgeable about the product and provided all the backup information we needed to make our presentation to FERC. HOBAS delivered the product in less time than it had originally quoted. It was a good company to work with, and I will certainly consider HOBAS for future projects. H

Marty Greco: It’s not a whole lot more complicated than that. The inside diameter of the existing pipe varied quite a bit actually over its length. At its largest, it was was probably 66 inches, and at its smallest, it was probably closer to 60 inches. The HOBAS pipe had an outside diameter of 57 inches. We carefully pushed the sections of the new pipe uphill to the dam. After they were pushed in and connected up, the annular void space between the HOBAS pipe and the existing penstock was filled in with a cement grout product.

Paul Becht: FERC was very receptive to this project. The engineers at FERC had limited experience with HOBAS pipe, but based on the information that Turner and HOBAS supplied, FERC completed its review and authorized construction in an extremely tight time frame to allow Marty’s crew to get started. Normally, it would take about 3 months for review and approval. I think we got approval in about 3 weeks.

Hydro Leader: Would you tell us more about the grant you received from the state?

Paul Becht: The New Hampshire Public Utilities Commission (NHPUC) has a program called the Renewable Energy Fund to provide grants for renewable energy projects. Turner assisted Mr. Greco in applying for the grant, and we were grateful to receive it.

Marty Greco: The NHPUC put out a request for proposals.

A number of project owners applied, and they interviewed us all. At the end of the process, the fund granted money to five worthy recipients.

Hydro Leader: What was your experience working with HOBAS?

Marty Greco is the owner of Noone Falls Energy, LLC. He can be contacted at mgreco@evergreenelectric.com or (207) 878‑2000.

Hydro Leader: How much energy will this facility generate?

Paul Becht: The Noone Mills Hydroelectric Facility has a capacity of 150 kilowatts.

Hydro Leader: How important was it to get the buy-in of the local government and other local entities to carry out this project? hydroleadermagazine.com

Paul Becht is a principal and the vice president of structural engineering at the H.L. Turner Group. He can be contacted at pbecht@hlturner.com.

February 2021| HYDRO LEADER

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Environmentally Friendly Epoxy Coating System Offers Big Benefits to Hydroelectric Station

By Max Silva

I

32 | HYDRO LEADER | February 2021

The interior of one of the penstocks before and after the application of Warren Environmental’s aquatic-safe, nonhazardous, structural epoxy system.

to a thickness of only 1/10 of an inch. The project took 10 days from start to final inspection, thanks to the epoxies’ single-coat capabilities and fast cure times (4–6 hours from application). The short duration of the coating process enabled other portions of the work to begin immediately and shortened the overall project schedule.

In addition to their quick cure times, the epoxies’ nonhazardous nature helped keep the project on schedule.

Because the epoxy was nonhazardous (free of volatile organic compounds, solvents, styrene, and isocyanates), the A&W Maintenance team could apply the coating at the same time that other work was conducted. There was no risk to the applicators or other workers on site. The replacement of the penstock or the use of multicoat epoxy products could not have offered these advantages.

Another reason Warren’s product was selected is that it is aquatic safe. Rigorous lab testing demonstrated a 100 percent survival rate for fragile aquatic life that came into contact with the product. It also has a proven history of being used in fisheries in New England and other parts of the United States. The project team was confident that the product would have no effect on the American shad and blueback herring using the passage.

The epoxy coating system provided the structural repair needed while saving significant amounts of time and money and without negatively affecting the larger project or the surrounding area. More importantly, the nonhazardous, aquatic-safe epoxy has none of the harmful effects of more traditional solutions. It will contribute to the electric company’s goal of increasing the native fish species’ historical populations. H Max Silva is a senior project manager at A&W Maintenance. For more on A&W Maintenance, visit www.awmain.com.

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PHOTOS COURTESY OF A&W MAINTENANCE.

n 2015, one of the largest electric power holding companies in the United States, which has provided clean, renewable energy since 1912, began a project focusing on the protection, mitigation, and enhancement of select hydro stations and the areas surrounding them. The improvements on one particular structure, which had been operating safely and reliably for over 100 years, included measures to ensure dam safety and to provide additional passage for migratory fish, with the goal of reestablishing historical populations of American shad and blueback herring in the river upstream of the hydroelectric station.

To do this, the company planned to install a downstream passage on the spillway to allow juvenile fish to move around the dam. This passage would be created using two existing 48‑inch steel penstock headwall pipes, which were original to the facility and were inactive. However, the pipes would require either replacement or trenchless rehabilitation, as they had deteriorated from their original wall thickness and needed structural repair.

With guidance from its engineer, the electric company evaluated all potential methods based on factors such as safety, risk, schedule, impacts, cost, and constructability. After much consideration, the company decided that the best solution would be to rehabilitate the pipes using an epoxy coating system. A trenchless rehabilitation method would allow for the pipes’ structural capacity to be quickly restored without the disruption and high costs associated with open-cut pipe installation. The company selected Warren Environmental’s aquatic-safe, nonhazardous, structural epoxy system. It was the only epoxy coating on the market that could be sprayapplied to a thickness of 500 mils in a single coat, providing the high build and the rapid return to service needed to maintain the critical path schedule.

Warren Environmental’s master applicator, A&W Maintenance and Coatings LLC, was chosen to apply the coating due to its previous experience using Warren’s products to structurally rehabilitate similar assets. The A&W Maintenance team prepared the steel pipe by sandblasting residue and silt until the ideal profile was created. Then, 375 mils of Warren’s 301‑14 highperformance epoxy was spray-applied to the two 23‑foot sections of 48‑inch pipe, the walls of which had deteriorated

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WATER LAW

FERC Regulatory Considerations for Project Modifications

By Chuck Sensiba and Elizabeth McCormick

I

34 | HYDRO LEADER | February 2021

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PHOTO COURTESY OF THE US NATIONAL ARCHIVES.

Chelan Public Utility District’s Rock Island Project. The licensee requested and received a determination from FERC that investments made during the prior license term would count toward a longer license term at relicensing under the newly enacted section 36 of the Federal Power Act.

t is well known that hydropower is one of the oldest forms of electricity generation in the United States, with hydropower plants accounting for 99 percent of all currently operating capacity built before 1930.

Incredibly, the average hydroelectric facility has been operating for over 60 years, and the 50 oldest electricity-generating plants in the United States are all hydroelectric generators that have been in service since 1908. For projects under the jurisdiction of the Federal Energy Regulatory Commission (FERC), licenses are issued for terms of at least 30 and up to 50 years. It is unsurprising, then, that these facilities are frequently in need of repairs to maintain or improve their safety and stability or to bring them into compliance with everchanging environmental requirements. As technology advances, many of the owners and operators of these FERC-licensed facilities are also looking to improve their efficiency, reliability, and modernization.

Given the near-limitless variety of improvements and repairs that can be implemented over a hydroelectric facility’s long lifetime, it is critical for the owners and operators of hydropower facilities to understand the most efficient and costeffective ways to achieve these repairs and improvements, which for FERC-licensed facilities are primarily achieved through a license-amendment proceeding. As discussed more fully below, we suggest that licensees consult with FERC regulatory counsel when determining whether a license amendment application may be required; what type of amendment is appropriate; and what other processes, such as consultation with resource agencies or an environmental review process, may be required. Additionally, recent amendments to the Federal Power Act (FPA) provide a significant opportunity for FERC licensees to leverage certain amendments or other improvements to their facilities toward receiving a longer license term upon relicensing.

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Licensing Amendments

PHOTO COURTESY OF RYAN MCKNIGHT.

When considering repairs or upgrades to a FERC-licensed hydroelectric facility, the first consideration for licensees is whether an application for a license amendment is necessary at all. Engaging outside counsel on this question is often helpful in making this determination because, as FERC has stated, “Every change to a license is an amendment,” but importantly, “not all amendments trigger the full panoply of rights and procedures applicable to a license application proceeding.” Articles 2 and 3 of FERC’s standard license require prior FERC approval for substantial changes to the project specifications approved in the license. Insubstantial changes, however, require only that the licensee file as-built exhibits so that FERC can amend the license to reflect the actual specifications. Generally speaking, FERC has found that changes that involve “no substantial modification of the authorized scheme of development” generally do not require an amendment application. For example, FERC has found that a change in the method of estimating project inflows was not a material change in the scheme of development and did not require an amendment application. In these instances,

WATER LAW

a license amendment application is unnecessary, and a simplified approach—such as a notification letter to FERC staff—would be appropriate.

However, if a licensee determines that a repair or upgrade would involve a “substantial modification of the authorized scheme of development,” then an amendment application is required and the next consideration is whether the proposed change constitutes a capacity or noncapacity amendment. A capacity-related amendment is one that increases the project’s authorized installed capacity by 2 megawatts (MW) or more and increases the hydraulic capacity by 15 percent or more. FERC’s regulations require that applications for capacity-related amendments also include additional information, including an environmental report known as Exhibit E. Applications for noncapacity amendments, on the other hand, must include “only those exhibits that require revision in light of the nature of the proposed amendments.” The exhibits that are required to be filed as part of a noncapacity amendment application can vary considerably depending on the nature of the proposed amendment.

The Washington, DC, headquarters of the Federal Energy Regulatory Commission.

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February 2021| HYDRO LEADER

| 35

WATER LAW

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Consultation and Environmental Review

Another major difference between capacity and noncapacity-related license amendments is the amount of prefiling consultation required for each. FERC’s regulations require that applicants for capacity-related amendments undertake a three-stage prefiling consultation process with the appropriate federal and state resource agencies, affected Indian tribes, and members of the public likely to be interested in the proceeding. In the case of a license amendment application, this frequently involves providing these stakeholders with a description or draft of the proposed amendment and soliciting their feedback on the proposal prior to filing the amendment application with FERC for its approval. An applicant for a noncapacity license amendment is only required to consult with resource agencies, tribes, and other stakeholders to the extent that the proposed amendment would affect their interests. In addition to engaging outside counsel to determine what type of amendment and prefiling consultation may be required for a proposed project, it is also helpful to discuss the proposal with FERC staff who can provide additional guidance on what type of amendment application is needed.

Once the necessary prefiling consultation has been completed and an amendment application has been filed with FERC, FERC will issue a notice soliciting interventions and comments from interested parties and will determine whether an environmental assessment or environmental impact statement is required under the National Environmental Policy Act (NEPA). FERC’s regulations also include several categories of actions that are “categorically excluded” under NEPA, such as license amendments that do not require ground-disturbing activity or changes to project works or operation. Following the completion of the environmental review process, FERC or its staff will issue an order regarding its determination on the pending amendment application and providing aggrieved parties the opportunity to seek rehearing and appeal.

Opportunity to Leverage Amendments

“shall give equal weight to: (1) investments by the licensee to implement the new license… including investments relating to redevelopment, new construction, new capacity, efficiency, modernization,

36 | HYDRO LEADER | February 2021

In addition to requiring FERC to consider these investments, made over the course of the existing license term, FPA section 36(c) provides an opportunity for hydropower licensees to obtain a FERC determination at any time as to whether any planned, ongoing, or completed investment meets the criteria of subsection (b)(2) above.

Section 36(c) provides that a determination under this subsection shall be issued within 60 days following receipt of the licensee’s request.

Since section 36 of the FPA was enacted just over 2 years ago, licensees have taken advantage of this new statutory program to identify major investments made during the projects’ license terms, in some cases dating back over 30 years. These improvements—all of which FERC found satisfied the section 36(b) criteria—ranged from seismic upgrades and other dam safety improvements to the rehabilitation and replacement of turbine-generator units.

Thus, any licensee that has completed or plans to make significant license amendments or other improvements during its current license term should consult with counsel to determine how to most effectively make a request for a determination under section 36(c) to amortize the cost of these measures over a longer license term. H Chuck Sensiba is a partner in Troutman Pepper’s Washington, DC, office. He can be reached 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.

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PHOTOS COURTESY OF TROUTMAN PEPPER.

While the procedures required to file a license amendment application with FERC are often time and resource intensive, a recent amendment to the FPA provides an opportunity for licensees to leverage the amendment process—along with other types of investments—to obtain a longer license term. In late 2018, Congress passed the America’s Water Infrastructure Act, which, among other things, adds a new section, section 36, to the FPA. Section 36(b) provides that FERC, when establishing the term of a new license,

rehabilitation or replacement of major equipment, safety improvements, or environmental, recreation, or other protection, mitigation, or enhancement measures required or authorized by the new license; and (2) investments by the licensee over the term of the existing license (including any terms under annual licenses) that— (A) resulted in redevelopment, new construction, new capacity, efficiency, modernization, rehabilitation, or replacement of major equipment, safety improvements, or environmental, recreation, or other protection, mitigation, or enhancement measures conducted over the term of the existing license; and (B) were not expressly considered by the Commission as contributing to the length of the existing license term in any order establishing or extending the existing license term.”

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USSD MISSION: Empower professionals to advance the sustainable benefits of dams and levees for society

USSD Members Represent: - Dam and levee owners - Consulting firms - Water districts - Utilities - Contractors - Government agencies - Colleges and universities - International organizations

USSD VISION: A world where all dams and levees are safe and valued by the communities they serve

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USSD offers a wide variety of technical knowledge exchange through an annual conference, workshops and webinars. It also publishes a quarterly members only USSD Dams & Levees Bulletin.

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Upcoming Events

February 4 American Public Power Association, Joint Action Conference (virtual) February 4 & 11 Idaho Water Users Association, Annual Convention (virtual) February 17–18 Northwest Hydroelectric Association, Annual Conference/Hydro Camp (virtual) March 1–2 American Public Power Association, 2021 Legislative Rally (virtual) March 3–5 Texas Water Conservation Association, Annual Convention, Bastrop, TX CANCELED: March 13–17 Nebraska Natural Resources Districts, Washington, DC, Meeting March 23–24 American Public Power Association, Engineering and Operations Conference (virtual) CANCELED: March 26–27 American Public Power Association, Lineworkers Rodeo, Pasadena, CA April 11–14 Edison Electric Institute, Transmission, Distribution, Metering, and Mutual Assistance, Houston, TX, and virtual April 12–16 U.S. Society on Dams, Safety, Security, and Emergency Response in the 21st Century, Charleston, SC April 21–23 P3 Water Summit (virtual) April 28–30 National Hydropower Association, International Conference on Ocean Energy (virtual) April 28–30 National Hydropower Association, Water Power Week (virtual) May 4–7 Association of California Water Agencies, Spring Conference and Exhibition, Monterey, CA May 4–7 Texas Ground Water Association, Annual Convention and Trade Show, San Marcos, TX May 7–19 Utah Water Users Association, Annual Workshop, St. George, UT May 23–26 Edison Electric Institute and American Gas Association, Spring Accounting Conference, Pueblo, NM

Join us for the Israel Water Education and Trade Tour, June 27–July 7, 2021 (Contingency dates: October 3–13, 2021)

Sponsored in part by Hydro Leader magazine.

Register by March 29, 2021.

To sign up to receive Hydro Leader in electronic form, please contact our managing editor, Joshua Dill, at joshua.dill@waterstrategies.com. hydroleadermag

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