Hydro Leader May 2021

Leader ydro H VOLUME 2 ISSUE 5

Chuck Sensiba on Troutman Pepper’s Expertise in Hydro Law

may 2021

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Chuck Sensiba on Troutman Pepper’s Expertise in Hydro Law

Contents May 2021 Volume 2, Issue 5

5 T he Multidisciplinarity of Hydropower

By Kris Polly 8 Chuck

Sensiba on Troutman Pepper’s Expertise in Hydro Law 14 Restoring

the Thermalito Pumping-Generating Plant After a Catastrophic Fire 20 B uilding a Hydropower Engineering Master’s Program at the University of Toronto

26 R estoring Utah’s Historic Olmsted Power Plant 32 T he Bright Future of Innovative Dam Construction: Pumped Storage, Twin Dams, Off-River Reservoirs, and More

By François Lempérière and Luc Deroo 38 JOB LISTINGS

Hydro Leader 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 Tyler Young, Writer Stephanie Biddle, Graphic Designer Eliza Moreno, Web Designer Caroline Polly, Production Assistant and Social Media Coordinator Cassandra Leonard, Staff Assistant 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.

hydro.leader

Coming soon in Hydro Leader: June: Juliann Blanford of NuSTREEM 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 | May 2021

hydro_leadr

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COVER PHOTO:

Chuck Sensiba, Troutman Pepper Partner.

Photo courtesy of Troutman Pepper.

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PHOTO COURTESY OF TROUTMAN PEPPER.

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The Multidisciplinarity of Hydropower

H

ydropower is multidisciplinary by nature: It involves civil and electrical engineering, turbine design, and hydrology, but it also touches many fields of law, including environmental and endangered species law, historical preservation regulations, natural resources law, and administrative law. All that means that hydro law is no simple field. In our cover story, we speak with Chuck Sensiba, a partner at law firm Troutman Pepper, which has the nation’s largest hydropower practice, about current issues in hydro law and his advice for aspiring hydro lawyers.

After California’s Thermalito Pumping-Generating Plant suffered a catastrophic fire in 2012, the process of restoring it intersected with many of these fields. In addition to restoring the plant under hazardous conditions, the California Department of Water Resources aimed to upgrade it to meet new climate change investment goals.

Meanwhile, a new master’s program in hydro engineering at the University of Toronto (U of T) has hydropower’s multidisciplinarity at its core. We speak with U of T professor Bryan Karney, U of T Waterpower Program Coordinator Sharon Mandair, and Ontario Waterpower Association President Paul Norris about the motivation behind the creation of the new program and what is distinctive about it.

The Central Utah Water Conservation District recently replaced its historic Olmstead power plant while preserving

By Kris Polly

the original plant in museum form. The complicated water right situation surrounding the Olmstead plant is a good example of how hydropower intersects with water supply and historic water law.

Finally, we feature a fascinating article by French hydro engineers François Lempérière and Luc Deroo.

Mr. Lempérière is well known for coming up with innovative concepts that include fusegates and piano-key weirs. In this article, Mr. Lempérière and Mr. Deroo present several ambitious ideas for how innovative pumped storage facilities and off-river reservoirs can help meet the world’s growing energy storage, water supply, and flood control needs. If adopted, these ideas could signal the beginning of a new golden age of dam building.

The multidisciplinary nature of hydropower engineering is both what makes it so challenging and what makes it so exciting and rewarding for its practitioners. The stories we feature in this month’s Hydro Leader make that clear. 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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Chuck Sensiba on Troutman Pepper’s Expertise in Hydro Law

Troutman Pepper staff visiting the Thompson Falls Project in Montana

T

he law firm Troutman Pepper has the largest hydropower practice in the country in terms of professionals who devote all or a substantial part of their law practice to hydropower matters. Dating to its earliest beginnings over 100 years ago, the firm has been deeply involved in energy and natural resources issues on behalf of its clients, and the recent merger between Troutman Sanders and Pepper Hamilton enhances the firm’s ability to offer services nationwide. In this interview, Troutman Pepper Partner Chuck Sensiba tells Hydro Leader about his experience in the field of hydro law and the top regulatory and policy issues for hydro law today.

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

8 | HYDRO LEADER | May 2021

Hydro Leader: Please tell us about Troutman Pepper and what makes it distinctive.

Chuck Sensiba: Energy law is an essential part of the DNA of Troutman Pepper. Recently, the law firm went through a major merger: Troutman Sanders merged with Pepper Hamilton. That brought together two firms, each with a national presence but with different legacy regional footprints. Troutman Sanders was headquartered in Atlanta and had a strong tradition and presence in the South and the hydroleadermagazine.com

PHOTO COURTESY OF TROUTMAN PEPPER.

Chuck Sensiba: I’ve always had an interest in water and natural resources issues. I grew up on my family’s homestead in southern New Mexico, and I remember, even as a small child, listening to conversations around the family dinner table about the water disputes between Texas and New Mexico and understanding the finite resource that water is. When I went to college, I decided to study environmental and natural resources issues because of this upbringing.

I attended law school in Colorado and had the chance as a law clerk to do some work on behalf of the City of Boulder, which at the time was planning to develop a small hydropower facility to capture energy from its water supply

as it is captured from the Arapaho Glacier and transported down the mountain into the city’s water supply system. I was captivated by the interdisciplinary proceedings, which brought together all the different interests that touched on water resources: federal and state resource agencies, the city, and environmental advocates. Based on that experience, I decided to try to pursue hydropower as the focus of my legal career. I reached out to law firms that specialized in this unique area of the law, and I considered government service in the Federal Energy Regulatory Commission (FERC) as well. I was fortunate to find a firm in Washington, DC, where I was able to get exceptional training and build my law practice. Over the 20‑plus years since I began my legal career, I’ve been fortunate to focus my practice almost exclusively on hydropower, and about 3 years ago, I moved my growing practice to Troutman.

southeastern United States. By contrast, Pepper Hamilton was headquartered in Philadelphia and was strong in the Northeast and upper Midwest. Both firms had a strong presence on the West Coast as well.

Interestingly, both legacy law firms had a strong tradition in hydropower. Troutman Sanders was founded over a century ago, and from its earliest beginnings, it served utility companies on energy and natural resources issues. The firm has long been associated with hydropower law. In fact, it was the firm’s strong presence and reputation in the hydropower sector that attracted me to move my practice there.

Pepper Hamilton also has a storied history in hydropower. When FERC’s predecessor agency, the Federal Power Commission (FPC), was first reorganized as an independent agency, founding partner George Pepper successfully represented the first independent FPC chairman before the U.S. Supreme Court when the Senate attempted to withdraw its consent to the appointment.

George Pepper also represented Gifford Pinchot, who served as Theodore Roosevelt’s United States Forest Service chief and was an early architect and supporter of the Federal Water Power Act of 1920, in a dispute that helped to define the U.S. conservation movement in the early 20th century.

Today, Troutman Pepper is one of the largest law firms in the United States and serves its clients through 23 offices across the nation.

Hydro Leader: Please tell us about Troutman Pepper’s hydro practice.

Chuck Sensiba: In terms of the number of professionals who devote their law practices to hydropower clients, I believe that Troutman has the largest hydro practice in the country. We have four senior-level attorneys—Angela Levin, Andrea Wortzel, Hallie Meushaw, and me—who spend all or a considerable amount of our time in the hydropower space. Our clients also have the benefit of a number of associate attorneys who represent the next generation of legal leaders in this field: Elizabeth McCormick, who joined us from FERC’s Office of General Counsel a few years ago; Melissa Horne, Houston Shaner, and Morgan Gerard. We have a deep bench that allows us to quickly and efficiently meet our clients’ needs.

Along with this depth, we have incredible breadth in our hydropower practice. Hydropower touches on many areas of the law, and our clients appreciate how the firm can serve as a one-stop shop for all regulatory issues facing hydropower projects, including those related to FERC electric and transmission regulation and federal programs such as the National Environmental Protection Act (NEPA), the Endangered Species Act (ESA), the Clean Water Act (CWA), and the National Historic Preservation Act (NHPA).

Of course, hydropower issues are strongly tied to public policy as well, and our clients appreciate our ability to help hydroleadermagazine.com

them resolve challenges through engagement on Capitol Hill and with departmental leadership. For example, Dave Ross, who served as assistant administrator for the Office of Water at the U.S. Environmental Protection Agency (EPA), recently joined the firm.

When regulatory and policy advocacy are unable to meet our clients’ objectives, they can turn to us for litigation support, with confidence that our litigators have direct experience in hydropower issues. Misha Tseytlin, for example, currently leads the hydropower industry’s effort, on behalf of the National Hydropower Association, in defending the EPA’s recent rulemaking under section 401 of the CWA. Finally, the firm has a strong transactional practice involving utilities and energy projects. Hayden Baker, for instance, recently managed environmental and project due diligence and negotiated key aspects of a major transaction involving multiple hydroelectric facilities on the East Coast.

So, in a couple of words, our hydropower practice at Troutman is multidisciplinary. It is comprehensive. And most importantly, we have found that our clients greatly appreciate the economic value of having institutional knowledge of their individual needs and objectives applied across many different sectors—and with the skill sets to apply these objectives in a multidisciplinary way to achieve their business objectives. We are honored that our clients have trusted us to provide counsel and representation on a wide variety of projects—from some of the largest, most high-profile, and most complex FERC relicensing projects in history to small run-of-river and conduit facilities.

Hydro Leader: Are you are seeing any big regulatory trends or rule changes in the hydropower world at the moment?

Chuck Sensiba: In its closing years, the Trump administration was prolific in issuing new rules aimed at reducing governmental red tape and streamlining federal approvals of infrastructure projects, including hydropower.

For instance, the Council on Environmental Quality (CEQ) issued new regulations on environmental NEPA review. In my practice, hydropower projects face NEPA review all the time—it is required for FERC hydropower licensing and relicensing and for major license amendments. The Trumpera NEPA rules, which remain in force though they are being challenged judicially, are starting to have an effect as regulators and the regulated industry seek to understand and implement them.

One area in which this occurs is the determination of the effects of a project that need to be studied for environmental impact. Under the prior rules, project effects were categorized as direct effects, indirect effects, and more nebulous cumulative effects. The Trump-era rules have done away with those categories and instead look more holistically at the reasonably foreseeable effects of a proposed project. We’ll see if these regulations survive judicial review or if the Biden administration decides May 2021| HYDRO LEADER

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ADVERTISEMENT to propose further changes. Until then, one of the new challenges related to this change in NEPA terminology will be to discern the true scope of the changes it has on individual proceedings as they move forward.

Beyond CEQ’s new NEPA rules, the Trump administration updated EPA regulations governing state water quality certification under section 401 of the CWA. Water quality certification is an important tool that states and, in some instances, Native American tribes use to ensure that hydropower projects and other federally licensed activities meet certain requirements of the federal CWA and state water quality standards. If the states or tribes issue a water quality certification, their conditions become mandatory conditions of the FERC license.

This ability to condition the federal license is a powerful regulatory tool.

The Trump-era regulations under section 401, which had not been updated for decades, attempt to discipline the water quality certification process in several important ways. The first relates to timing. In some states, water quality certification takes years or even decades to complete.

Although the statute itself provides a maximum time of 1 year for states to decide on an application for water quality certification, states found ways around this requirement by requesting or directing applicants to withdraw their application before the 1‑year deadline expired and then to resubmit the same applications to trigger the 1‑year clock again. A series of cases at the U.S. Court of Appeals recently invalidated this practice, and the new Trump EPA regulations codify these court rulings.

In addition to that, the new EPA regulations establish substantive requirements for what the states should be looking at when they issue their certifications. In the past, states have used their certification conditioning authority to broadly regulate entire projects—including aspects related to power generation, public recreation, fish and wildlife resources, and water quality standards—under the broad umbrella of water quality. And, in fairness, the U.S. Supreme Court endorsed a broad interpretation of section 401 in its 1994 Public Utility No. 1 of Jefferson County ruling.

However, the EPA’s rule points out that, in that case, the Supreme Court did not have the benefit of the EPA’s own interpretation of section 401. The rule then articulates a narrower interpretation of water quality certification, concluding that it applies only to a project’s discharge, not to the entire licensed activity, and only to more traditional, standard water quality requirements.

While the EPA’s CWA section 401 rule is currently in effect, it is being challenged in federal court. The litigation proceedings are being held in abeyance while the Biden administration decides how it plans to address them. Also, there are various cases that are still pending that will provide further guidance on the 1‑year requirement under section 401 itself. CWA section 401 is an important issue that continues to evolve.

10 | HYDRO LEADER | May 2021

Hydro Leader: What have you seen from the Biden administration so far in terms of regulations and policies that relate to hydropower, and what do you expect to see in the next few years?

Chuck Sensiba: With the Biden administration, a principal focus is climate. It is encouraging that the proposed Clean Future Act recognizes that hydropower needs to be part of a climate solution. That makes sense for a number of reasons.

First and foundationally, hydropower is our country’s most reliable and well-established renewable resource. It’s been around much longer than other renewables. We understand it—both its immense benefits and its potential environmental effects—and it offers products and has characteristics that are unlike those of other renewable resources. Hydropower is a flexible resource. Grid operators can schedule when the generating facility will be online and when it won’t be. It has the ability, through pumped storage projects, and even conventional hydropower with flexible operations, to store energy. Everyone recognizes that a modern, clean energy grid needs energy storage, and while there’s been tremendous effort and advancement in the research and development of utilityscale battery technologies, the hydropower industry has been raising its hand on this issue for a long time, trying to help policymakers understand it has long been a solution for energy storage and that there are immense opportunities for growth.

Another emerging policy of the Biden administration is placing significant emphasis on environmental justice. In the hydro space, this will likely translate to opportunities for Native American tribes to have greater involvement and influence in the FERC licensing process.

Hydro Leader: Do you expect to see an increase in green credits or an extension of credits to hydropower that it previously was not given access to?

Chuck Sensiba: That is absolutely needed. Right now, there is great variation in how states’ renewable energy requirements treat hydropower. Some states view all hydropower as renewable, which it is. Other states exclude larger hydropower projects. Still others exclude older facilities and selectively deem only incremental hydropower (i.e., development at an existing project that increases capacity or production) as eligible—seemingly based the idea that renewable energy credits should be available only to help spur the economic growth that comes from construction and new project development and not to meet overarching climate goals.

We need policies that are consistent across the board and do not pick winners and losers in the renewable energy space.

Hydropower already faces significant regulatory disadvantages compared to other renewables due to licensing and permitting requirements. That disadvantage is amplified when policymakers don’t extend the same economic incentives to hydropower they do to other renewable project development. hydroleadermagazine.com

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PHOTO COURTESY OF TROUTMAN PEPPER.

Hydro Leader: Have there been recent changes in the treatment of small hydro?

Chuck Sensiba: The most recent policy advances came in 2013, when Congress, in the Hydropower Regulatory Efficiency Act (HREA), did two things to streamline small hydropower authorization. First, many conduit hydropower projects with a capacity of 5 megawatts (MW) or less, which the statute terms qualified conduit hydropower facilities, were completely removed from the jurisdiction of the Federal Power Act (FPA) and were no longer required to have a FERC license or authorization. The 2013 HREA required FERC to determine whether or not a project was a qualified conduit hydropower facility, but that process was designed to be quick. Then, in the America’s Water Infrastructure Act (AWIA) of 2018, Congress expanded this program to include conduit projects of up to 40 MW. This has great potential to prompt water managers across the United States to take another look at hydropower. It’s possible that without the inherent risks of a burdensome federal regulatory overlay, hydropower development—perhaps in place of pressure-release valves—could be a viable means to increase revenue.

Next, the HREA required FERC to complete a pilot program for determining the feasibility of completing the licensing process for hydropower at existing nonpowered dams within a quick, 2‑year time frame.

More recently, the AWIA extended benefits to small hydropower by extending the time periods for preliminary permits and giving project developers more time to begin construction after FERC issues a license.

We still need to do more to help small hydropower.

For example, there are many small vintage projects, particularly in New England, that are coming off 30‑, 40‑, or 50‑year FERC licenses and need to be relicensed.

These small projects’ economies are sometimes marginal, and the prospect of going through a long and burdensome relicensing proceeding is daunting. Not only might these projects face new environmental requirements, but the relicensing process itself could challenge the continued economic viability of a small project. One idea to address this situation is to allow small hydropower projects facing relicensing to instead swap out that license for a different type of federal authorization, called a FERC exemption.

Exemptions come with their own challenges, but one of their advantages is that they are perpetual, which some project owners may find attractive. This working proposal is to find ways for a licensee in some situations to quickly trade in their license for an exemption without having to incur the expense of FERC relicensing.

Hydro Leader: Why should young lawyers or current law students consider hydro law, and what kinds of courses, studies, or experiences should they seek out to pursue a career in that field? hydroleadermagazine.com

Chuck Sensiba: What is great about a career in hydropower law is that it is diverse. The issues that we see in this highly specialized area are unique to each project. It requires multidisciplinary experience in a number of different programs. The FPA is the base of our practice, but like other federally licensed activities, it pulls in NEPA, ESA, NHPA, and dozens of other federal programs.

On top of that diversity, there are regional differences in resource issues. In the Pacific Northwest, there are issues related to salmon, steelhead, and ESA-listed species as well as important Native American treaties that in many cases predate statehood. In the Southeast, there are issues related to American eel and Atlantic sturgeon. This regional diversity makes the practice vibrant and exciting.

In terms of coursework, I don’t think any law school offers a class in hydropower law. I would encourage law students interested in hydro law to take courses that focus on environmental law and natural resources law. Some law schools offer classes in energy law, and it’s important for students to begin to understand the business underpinnings of energy projects. Coursework in administrative law is essential as well.

Hydro Leader: What should everybody know about Troutman Pepper?

Chuck Sensiba: Our hydropower practice is made up of a diverse group of energy and environmental lawyers, transactional attorneys, and litigators. We are skilled in this focused practice area of the law in a highly regulated industry. We are passionate about what we do, and we are committed to serving the industry that we represent.

I have the honor of serving on the board of directors for the National Hydropower Association, and several of the lawyers in the firm are actively involved in various of the association’s committees. My partner Angela Levin serves as general counsel to the Northwest Hydroelectric Association.

We’re involved in other regional hydropower associations as well, and we try to keep our industry informed by contributing to Hydro Leader, keeping our clients and colleagues informed in our own Hydropower Report, and spending time with colleagues at industry conferences and meetings. While some of these activities have looked a bit different during the COVID‑19 pandemic, we very much look forward to renewing these relationships as we return to more normal operations. H Chuck Sensiba is a partner at Troutman Pepper. He can be contacted at charles.sensiba@troutman.com or (202) 274‑2850.

May 2021| HYDRO LEADER

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Restoring the Thermalito PumpingGenerating Plant After a Catastrophic Fire

An aerial view of the Thermalito Pumping-Generating Plant and the Thermalito forebay.

C

alifornia’s Department of Water Resources (DWR) is charged with overseeing the State Water Project (SWP) through the constructing, operating, maintaining, and ensuring the safety and efficiency of the SWP’s dams and hydropower infrastructure. The SWP provides water and power to millions of Californians and their homes, farms, and businesses. This charge was tested in 2012, when the Thermalito Pumping-Generating Plant caught fire on Thanksgiving Day, effectively wiping out the plant’s power generation abilities. In this interview, Tim Kennelly, the assistant division chief for engineering services in the division of operations and maintenance at the DWR, tells Hydro Leader about the damage caused by the fire, the extensive rebuilding and modernization effort the department undertook after it, and how those efforts have improved safety and are reducing the environmental effects of California’s water infrastructure.

Tim Kennelly: I’ve been with the DWR for 22 years, all in the division of operations and maintenance and most

14 | HYDRO LEADER | May 2021

Hydro Leader: Please describe the Thermalito plant and its role in the Oroville-Thermalito complex.

Tim Kennelly: The plant itself is located about 70 miles north of Sacramento, on the western side of the city of Oroville. It was built in the late 1960s and became operational in 1968. It is owned and operated by the DWR. The Thermalito plant is one of three plants in the Oroville-Thermalito complex.

There are four units in the Thermalito plant, three of which are pump-generator units and one of which is a generationonly unit. The Thermalito power plant can produce about 118 megawatts (MW), which is enough to power about 100,000 households. The complex also includes the Hyatt power plant, which is located next to the Oroville Dam, and a smaller power plant called the Thermalito diversion dam power plant. Hyatt is able to produce 714 MW and the diversion dam power plant can produce about 3.3 MW.

PHOTOS COURTESY OF THE DWR.

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

recently for the Thermalito project. I served as the principal hydroelectric power utility engineer in charge of the electrical engineering services office. As part of those duties, I was the project/program manager for the Thermalito power plant restoration program.

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The Thanksgiving Day 2012 fire.

Adding all that up, the complex can produce about 835 MW of electricity, which is enough to power 1.6 million homes.

Hydro Leader: Please tell us about how the 2012 fire occurred and what damage it did.

Tim Kennelly: The exact cause, unfortunately, was never determined. All the investigations were inconclusive, mainly because the fire incinerated and destroyed most of the evidence. The forensic and laboratory analysis wasn’t sensitive enough to detect the cause. We suspect that the fire started in the wiring in a cable tray located on the floor directly below the plant’s control room. It basically destroyed the plant’s entire operating capacity. There was no way to generate any power with the plant afterward. It destroyed all the electrical systems, the communication and control systems, and the protection system. The fire was so intense that it did some structural damage to the concrete walls and floors inside the plant. Luckily, there were no staff members present because it was Thanksgiving Day. There were no injuries during the fire.

It happened that one of the plant’s employees was a local volunteer firefighter and responded to the fire and assisted the firefighting response team. That employee, Kevin Mefford, received the governor’s medal of valor, the state’s highest safety award, for his assistance to the firefighters during that fire. Only one-third of the Thermalito power plant is above ground—all the other floors are below ground—so Mr. Mefford’s knowledge of what was where in the plant was invaluable. He helped make sure they were safe by guiding them to where they needed to be and helping them safely find their way out safely.

Hydro Leader: What were the effects on the broader electricity supply, on water delivery, and on the operations of the complex more generally? hydroleadermagazine.com

Tim Kennelly: Because the plant could not generate any power, the SWP had to purchase additional power on the grid market. Our generation generally goes to help pay for the costs of pumping and moving the water. We were still able to maintain water deliveries because the plant has a bypass gate that allows us to move water from the Thermalito forebay to the Thermalito afterbay. While we were not able to move as much flow as we could have if all four units were in operation, we were still able to maintain water flows to meet the demands of local agriculture, to provide for fish habitat, and to meet other supply needs.

Hydro Leader: After the fire, how did the DWR analyze the plant, and why did it decide to restore the entire plant rather than fixing some parts of it?

Tim Kennelly: Once the plant was deemed safe to enter, there was a full assessment of the plant and an inventory of all the damage. Then there was an analysis of all the alternatives and a weighing of the options, and the option of returning the plant at least to its prefire operation was selected over decommissioning.

There were two main reasons for that. First, the generation that Thermalito provides benefits not only the grid in California as a whole, but also helps lower the amount of energy we need to buy, and thereby lowers costs to our customers, the state water contractors. Second, three of the facility’s units have both pumping and generating capacity, which means they have the ability to pump water back from the afterbay to the forebay during times of low energy demand to use again during times of high energy demand. It is possible that that function could become more useful in future years to combat climate change, so having that ability was highly desirable.

Hydro Leader: Was it possible to salvage any of the equipment from the plant?

May 2021| HYDRO LEADER

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ADVERTISEMENT Tim Kennelly: As I mentioned, the electrical, communications, control, and protection systems were all pretty much destroyed and had to be replaced. The units themselves were salvageable.

As part of the plant’s restoration, we refurbished a lot of the units’ major components.

now, such as asbestos. When you add heat and water to the mix, it can create a kind of toxic soup. All the wiring was destroyed, and if you combine wiring and plastic with heat and water, it creates an acidic compound. The smoke and its byproducts were corrosive, creating a soot that coated pretty much anything it touched within the plant. It had to be dealt with carefully and in a contained manner. We instituted a rigorous cleanup and recovery program using the U.S. Environmental Protection Agency’s hazardous materials guidelines. It included wearing all necessary layers of personal protective equipment; decontamination procedures; medical checks; and, of course, hazardous waste disposal. All that was well planned, documented, and strictly adhered to.

Hydro Leader: Was the plant rebuilt exactly as it had been before the fire, or did you take the opportunity to change anything?

Fire damage inside the Thermalito plant control room.

Hydro Leader: What was the timeline of the rehabilitation?

Tim Kennelly: The fire happened Thanksgiving Day 2012.

The bulk of 2013 was dedicated to fire cleanup, and plant recovery took place during 2013 and 2014. The cleanup stage was deemed complete by October 2014. Then, we began recovery of some of the essential systems, such as lighting and heating, ventilation, and air conditioning (HVAC). That was complete by July 2015. The design for the restoration and return to full operations began in 2015, ran throughout most of 2016, and really was completed by January 2017. The construction phase started in 2016 and continued through 2020. The plant was returned to normal operations and maintenance in September 2020.

Hydro Leader: Is that a pretty standard timeline for this kind of rehabilitation?

Tim Kennelly: I believe it is. I’ve done a few plant projects, plant startups, and new facilities, and it generally takes about 5–7 years in total, including design, procurement, construction, startup, and commissioning.

Tim Kennelly: With the age of this plant, a lot of the materials that were in there were materials that are deemed hazardous

16 | HYDRO LEADER | May 2021

Hydro Leader: Have you implemented any new regulations, fire warning devices, or other measures and technologies to avoid future fires or incidents like this?

Tim Kennelly: It was an untimely coincidence that the DWR was actually beginning to embark on a fire modernization program for all our SWP facilities in early 2012, starting at Thermalito’s companion plant at Hyatt. Of course, the fire at Thermalito drove home the need to bring all plants up to modern fire codes. During the rehabilitation of Thermalito, we engaged the California state fire marshal at every step, from design all the way to our return to full operations. We had numerous conversations with the office of the fire marshal, and it reviewed all our plans and signed off on them. Throughout the construction, its staff came out numerous times to perform inspections, to make sure the systems were operating as intended, and to sign off on the hydroleadermagazine.com

PHOTOS COURTESY OF THE DWR.

Hydro Leader: Would you talk about the safe environment challenges that were posed to the recovery workers by fire damage and contamination?

Tim Kennelly: We did take the opportunity to change a number of things. One of the options identified as part of the analysis I mentioned earlier was to return the plant to its prefire condition. A second option was to return the plant to operation but to do enough work to extend the life of the plant and equipment, adding essentially another 30 years, which was the option deemed the best value. We refurbished the units, for the most part, and upgraded and replaced all the destroyed equipment, such as the governor systems; voltage-regulation systems; and protection, control, and communication systems. We also took the opportunity to replace the turbine in the pure generation unit with a more efficient one. That helped with our goals for climate change investments. Replacing that turbine alone increased the efficiency of that unit from 86 to 93 percent. In addition, we focused on our fire monitoring and suppression system. New systems were added, and our existing fire monitoring system was completely revamped and expanded. We brought the plant back to its preexisting condition and then went beyond.

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DWR staff perform restoration work on the fire-damaged Thermalito plant.

whole plan before we turned it over to normal operations. We greatly expanded the fire alarm system throughout the plant; it now has even better monitoring capability than it did before. We installed things such as smoke dampers in the HVAC systems to slow the progression of smoke in case of future incidents. We installed a high-pressure water mist system, which is a fairly new technology, in the lubrication room. We installed an inert gas system in the control room for better fire containment. Since access to the plant was limited by the old design, we added three new exits to the outdoors. We upgraded the lighting system and the emergency lighting system using modern technology with LED lights. The fire modernization program will proceed from plant to plant throughout the SWP. We also implemented a robust inspection, testing, and maintenance program for our fire systems. With every design and every facility upgrade, the California state fire marshal is reviewing the designs, inspecting the systems, and making sure that they meet today’s fire codes.

Hydro Leader: Has the DWR changed operations at any other facilities based on this experience?

Tim Kennelly: The SWP’s fire system modernization program is ongoing. We’re actually getting ready to finish up Oroville and its division in their entirety. We’re going to embark on the construction phase for the next field division hydroleadermagazine.com

this summer. The inspection, testing, and maintenance program is strictly adhered to, tracked, monitored, and audited to make sure we’re keeping all the equipment in order. The other thing we did after the fire was a survey throughout our other plants. We looked for any fire risks, including materials that potentially could be fuel for a fire or help spread it, and had a plant cleanup to get rid of potential combustible materials.

Hydro Leader: Is there anything else you would like to add?

Tim Kennelly: The SWP is a major supplier of water throughout California, and it provides water to about 27 million Californians and 750,000 acres of farmland.

The SWP is an extremely important resource for the state of California. H Tim Kennelly is the assistant division chief for engineering services in the Division of Operations and Maintenance at the California Department of Water Resources. He can be reached at tim.kennelly@water.ca.gov.

May 2021| HYDRO LEADER

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Building a Hydropower Engineering Master’s Program at the University of Toronto

H

ydropower engineering is a specialized and highly multidisciplinary field, but perhaps because of the longestablished nature of hydropower as a technology, there are now few university programs dedicated specifically to it.

Bryan Karney, a professor at the University of Toronto (U of T), Sharon Mandair, the program coordinator for waterpower at the U of T, and Paul Norris, the president of the Ontario Waterpower Association (OWA), are trying to change that. They are working to establish a full master’s program focusing on the many aspects of hydropower engineering. In this interview, they tell Hydro Leader about the need for such a program, their work to create it, and their visions for the future.

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

Sharon Mandair: I completed my PhD last September under the supervision of Bryan Karney and Hydro Québec’s Research Institute. I was studying water hammer in the context of load rejection at a large hydropower station. As I was wrapping up my PhD, Bryan was kicking around the idea of developing a master’s-level curriculum for hydropower. He asked me if I wanted to run with it after I was done with my PhD. I did, and the day after I defended my PhD, I presented the idea to the OWA and its membership, and it was met with a lot of support.

Bryan Karney: I have been a professor at the U of T since 1987. I have been interested in water for as long as I can remember, and I was first interested in irrigation and other water supply systems. As a part of my graduate studies, I specialized in water hammer and transient-type events. Some of my first consulting jobs were in the hydro area. That area went pretty quiet for a while, but recently, there has been a renaissance in hydro as a result of the push toward renewable energy, the desire to make the electrical grid both more stable and more sustainable, and the recognition that hydropower is dispatchable. As a result, hydro has become a growing passion for me. The core of my work throughout the whole time has been engineering consulting, engineering education, and engineering of water and energy systems.

20 | HYDRO LEADER | May 2021

Hydro Leader: Would you please tell us about the size and importance of the U of T? Bryan Karney: The U of T is the largest university in Canada and is ranked as one of the top 20 universities in the world in a great many subject areas. More than 80,000 students are associated with its programs. The engineering program has a long tradition and is heavily involved in all aspects of teaching, research, and education in engineering.

Hydro Leader: Mr. Norris, would you tell our readers about the OWA’s history and current activities?

Paul Norris: The OWA was founded in 2001, after the Province of Ontario decided to commercialize our electricity sector, as many other jurisdictions, including in the United States, have done. After making that decision, the provincial government was faced with the question of how to regulate the industry in the absence of a dominant, vertically integrated utility. The industry decided to create the OWA to represent its common and collective interests. We were founded by eight generator members, and our membership now exceeds 140 entities, including generators; environmental, engineering, legal, and financial firms; product manufacturers and providers; municipalities; and indigenous communities.

Hydro Leader: Please tell us about the proposed master’s program.

Sharon Mandair: Right now, we are building what’s called a technical emphasis in waterpower, which is similar to a minor, for master’s of engineering students. As part hydroleadermagazine.com

PHOTO COURTESY OF U OF T.

Paul Norris: I am the president of the OWA. I’m a graduate of the U of T, and my background is in public policy. I came to the industry from government in the early 2000s. I have been really fortunate to have the opportunity to work with a bunch of passionate people in the industry. We represent the waterpower industry in the province of Ontario through advocacy, public outreach, and work with various communities and stakeholders.

The University of Toronto, with downtown Toronto in the background.

ADVERTISEMENT of that, we’re building two new courses. One of them is a comprehensive introduction to waterpower, and the second focuses on the special challenges associated with refurbishment. A student in the proposed full program would typically take 10 courses, 4 focused on waterpower and the remaining 6 on related topics of their choice.

Bryan Karney: The U of T’s master’s in engineering program has two streams: the so-called master of applied science degree, which is focused on research and often leads to a PhD, and the master of engineering programs, which are more practically focused and are targeted toward people who are already working in the industry and would like to learn something new or enhance their education.

Hydro Leader: What was the motivation behind the creation of the program?

Bryan Karney: Canada has had a huge historical commitment to hydropower. Although this has grown gradually over time, hydropower is often viewed as solved, with an attitude of “been there, done that.” A lot of universities in the English-speaking part of Canada historically had a strong interest in hydropower, but they no longer have a strong emphasis on hydropower. There are graduate programs that focus on wind, solar, and other renewables, but hydropower is largely neglected. There is a need for a more dedicated form of preparation than what we’ve been providing. In Ontario, there was a change in the overall structure of the hydropower industry within the province. The graphic below illustrates the age of the current hydro fleet and it clearly shows both the historical commitment and the more recent relative neglect.

available, initially in Ontario, and then maybe to expand its scope so that it can play a strategical role, nationally and even—to some extent, at least—worldwide.

Sharon Mandair: At the U of T, there is a strong focus on sustainable energy, but as Bryan said, it is often focused on new and emerging technologies—solar, wind, and fuel cells, for example. But waterpower is distinctive because it is location specific, it requires a long-term investment, and it has a long history. Those themes don’t come out in typical sustainable energy courses.

Paul Norris: The industry has several motivations in supporting this program. First, we want to help educate the next generation of professionals and the future leadership of this industry and to address the demographic shift that is already happening in our industry. Second, Ontario’s hydro assets are quite different from those in other jurisdictions. We have 225 operating facilities spread all across the province, ranging in size from 35 kilowatts to 1,200 megawatts. That diversity is linked to Sharon’s point about the site-specific and facility-specific nature of hydropower. Both of the hydro-specific courses we’re designing will address the diversity that defines our industry.

Bryan Karney: I think one of the key things that defines the hydro industry is that it’s so multidisciplinary—any successful hydro project will involve hydrology, geology, civil engineering, turbine design, electrical engineering, and generators and controls. Hydropower is also a pretty highly regulated industry, and there are a lot of environmental and social concerns that have to be addressed on a regular basis, including those related to fish and land development.

Compared to that, solar and wind are often more straightforward. I think that educating master’s students on all the different things that are applicable in the hydro business is really positive. It gives them a good base to understand all the aspects of the industry.

PHOTO COURTESY OF THE OWA.

Hydro Leader: How did the U of T and the OWA go about developing the concept for the master’s program? Did you solicit ideas from industry groups?

A breakdown of the ages of Ontario's waterpower facilities.

Thus, we’ve had a gap, and we think we can move in and strategically fill that gap. That is important and exciting. We want to make a first-class, English-speaking hydro program hydroleadermagazine.com

Paul Norris: I’m really fortunate to have 140 members across a vast array of disciplines in the industry. We worked with the university to identify what the skeleton of the program would look like in terms of the expertise required. I did the outreach to our members. It came as no surprise to me that many stepped forward to volunteer, not just because they had expertise to offer, but because they thought it was the right thing to do. Pretty quickly, we put together a multidisciplinary team with expertise in fields including civil and electrical engineering, turbines, generators, the regulatory process, financial considerations, and electricity markets. All of them are volunteering their time to work May 2021| HYDRO LEADER

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ADVERTISEMENT with the OWA and the U of T to develop this program.

We have representatives from utilities, manufacturers, construction companies, and engineering firms. There are 12 lessons per course per semester, and several of the individual lectures are actually going to be put together by some of the team members based on their expertise.

Inside the University of Toronto’s Myhal Centre for Engineering Innovation and Entrepreneurship.

Hydro Leader: How did you find the funding for the new program?

Sharon Mandair: Bryan has been generous in using his available funds to support my work and my efforts to create this program. We are also looking to find more funding through the university and through industry and government programs. One of the things that the university looks for when it is funding startup-type projects is connection to the industry, so we’re hopeful that we’ll be able to get some funds.

Hydro Leader: How will this program differ from other existing programs?

22 | HYDRO LEADER | May 2021

Hydro Leader: What are the main goals of this program, and how do you propose measuring its success?

Sharon Mandair: Its goal is to encourage lifelong learning, no matter where students are in their careers. I have in mind two demographics of students. The first would be those who have no experience in the industry: students who perhaps are not quite sure where they want to go or what they’re interested in. I want to foster a learning environment in which they can explore ideas, find out whether they’re interested in joining in the industry, decide where they might fit in, and make connections that would allow them to gain meaningful employment. The second group of students would be those who are coming from the industry with a bit of experience. I’m hoping that those students will be able to come to the U of T and find the tools that they need to add value to their companies. As for measuring the program’s success, I think it would really be as simple as following up with students about their experiences and asking them if they found what they were looking for and if the program helped them in their careers.

Bryan Karney: One straightforward metric would be the number of people who are completing the emphasis each year. We want to grow for some time until we reach a steady state. We want the reputation of the program to grow. We want employers to come to us seeking our graduates, and we hydroleadermagazine.com

PHOTO COURTESY OF U OF T.

Bryan Karney: Putting this program together reminds me of an old community barn building, where a whole bunch of people see a need and get together to meet it. It has mostly occurred on a volunteer basis. Paul has done outreach through the OWA, and I’ve been interacting with academics and researchers for several decades in this area. I’ve been fortunate enough to have good students and reasonable funding. I can support the program for a bit as a sort of bootstrap operation. We’re hoping to get seed funding, mostly from the U of T, but perhaps from other sources. too, to build a foundation for the program.

Sharon Mandair: That question is a great opportunity to dig into what the two new courses will look like. Our introductory course to waterpower—what we’re informally calling Waterpower 101—will take an interdisciplinary frame. We’re trying to expose students to all the different systems that come together to make waterpower possible, including the civil, mechanical, and electrical engineering aspects; economics and financing; environmental and social license issues; and how waterpower fits in with the market structure. The challenge with an interdisciplinary frame is stitching the pieces together to make sure that a student comes away with an appreciation for each of the components and its role with respect to the whole. We’re also developing a course on refurbishment; I do not think there are any existing courses on this topic.

Refurbishment is an interesting problem, because you need to understand the history of the technology, how facilities were initially designed and for what purpose, and how they can be adapted to a new dynamic role in the grid. It was announced the other day that Ontario Power Generation is going to spend $2.5 billion over the next 20 years just on repairs and upgrades to its fleet, which indicates how big the market for refurbishment is. We’re designing our refurbishment course to be as hands on as possible, and we’re planning on including a real-world project. Because of our partnership with the OWA, we have tremendous support and enthusiasm from folks from the industry, and we’re benefiting from their resources and their time as we build this unique course.

ADVERTISEMENT want engineers to come to us seeking this credential and this preparation. I’m hopeful that we will achieve all those goals and reach our program’s desired capacity within a few years.

Hydro Leader: How will the OWA and its membership network support this program?

Paul Norris: First, by contributing subject-matter expertise from our membership to the design and development of the program. Industry members have already actively engaged in helping design the two courses that Sharon talked about.

Second, through marketing. Our annual Power of Water Canada conference is being held on May 25–27, and Sharon and others are going to present the program to the industry.

As Sharon mentioned, this isn’t just a program for students entering academia, it’s also an opportunity for individuals in the industry to broaden their educational experience and expertise and use that to advance their careers. Third, we want to help graduates of this program find advanced employment within the industry through our membership network by communicating the value of the graduate program to companies across our membership.

Hydro Leader: When will this program open to students?

Sharon Mandair: The program begins this fall.

Waterpower 101 will start in September, and the refurbishment course will begin in January 2022.

Waterpower 101 is a prerequisite for the others, so hopefully students will take the two courses sequentially.

Hydro Leader: What is your vision for the future of the program?

PHOTOS COURTESY OF SHARON MANDAIR AND THE OWA.

Sharon Mandair: I think the program could grow in a couple of ways. One is to offer more courses within engineering.

Perhaps we’ll develop electrical engineering courses that are a bit more appropriate for waterpower. Another one that I’d love to see within the environmental engineering umbrella is something that pulls together hydrology and ecology to provide a better understanding of the aquatic ecosystem.

Another direction it could go is to offer an emphasis or something similar for other faculties, like the school of the environment or the faculty of law.

Bryan Karney: One of the things I’d love to see, and I haven’t really even broached this with the committee yet, is to have a field school. I’d love to have a 2‑week program during which students tour hydro sites that are in the process of being commissioned or refurbished and get hands-on exposure.

These sites are exciting to visit and can be inspirational. I’d love to have a program that’s good enough that people want to make their way to our doors to get the experience that it can give and to have the careers it fosters. I think that it could grow to include literally hundreds of students, not necessarily all in the official U of T program, but through a variety of hydroleadermagazine.com

extension courses and continuing education courses that are supplements to the academic program.

Paul Norris: For me, I look at this as our Field of Dreams.

If we build it, they will come. Right now, we are nose to the grindstone, working through Sharon’s leadership and Bryan’s support and the efforts of the various teams to build something successful for September 2021 and January 2022 that will be recognized as an outstanding contribution and set the path forward. But I think we all share a longer-term vision of attracting not only people from the engineering program, but people in the business program, people in the environmental program, and people in the industry. All of us have gotten excited about what this could be in the future, but we are really focused on what it needs to be within the next 6 months at this point.

Bryan Karney: I think one of the appeals of the hydro business is that it really is a legacy business. There are more than 100 plants in Ontario that are more than 75 years old, and only 56 that are fewer than 25 years old. Many people are in the fourth, fifth, or sixth generation of their family to be involved in hydropower. There is a lot of work to be done, but huge potential for these projects and plants to help modernize and decarbonize the electrical systems.

Hydro systems are each unique, specific to their location and context. That’s a really exciting aspect of hydro—it is not just putting up the same wind generators or solar farms over and over again; instead, each site and each refurbishment has its own challenges. That creates a tremendous number of creative opportunities. I hope this will attract creative people who are good at problem solving.

We need technical and administrative and communication virtuosity. That’s a really exciting group to put together. H Bryan Karney is a professor in the Department of Civil and Mineral Engineering at the University of Toronto. He can be contacted at bryan.karney@utoronto.ca.

Sharon Mandair is the program coordinator for waterpower at the University of Toronto. She can be contacted at sharon.mandair@mail.utoronto.ca.

Paul Norris is the president of the Ontario Waterpower Association.

He can be contacted at pnorris@owa.ca.

May 2021| HYDRO LEADER

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Restoring Utah’s Historic Olmsted Power Plant

O

ver the last 7 years, the Central Utah Water Conservancy District (CUWCD) has replaced the historic Olmsted power plant and transformed the century-old original building into a heritage feature. The earlypriority-date water right associated with the full capacity of the original plant means that its continued operation is critical to the CUWCD’s continued ability to store sufficient water for the federal Central Utah Project (CUP). In this interview, CUWCD General Manager Gene Shawcroft discusses the complex water right situation and the intricacies of restoring and replacing a National Register of Historic Places–listed facility.

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

Gene Shawcroft: I am the general manager of the CUWCD. We operate the federal CUP, which is the largest water development project in the state of Utah. We have tremendous employees who work hard to operate and maintain a project that is important to the state of Utah and the region. I’ve been with the district since 1991, when I started as a staff engineer. I became an assistant general manager a number of years ago, then deputy manager, and I’ve been the manager now for a little over 5 years. I’ve been involved with water my entire career. I grew up on a little farm in Colorado and enjoyed working in water while I was there. I felt that if I could have a career in the water world, life would be fabulous, and it has been. The CUWCD is a wonderful place to work, and I’ve enjoyed all I do here.

Hydro Leader: Please tell us about the CUWCD. A vertical turbine from the historic Olmsted plant.

26 | HYDRO LEADER | May 2021

the assistant secretary of water and science, which improves the efficiency of the construction of the CUP and the efficiency of its operation and maintenance today.

Hydro Leader: What is the distinction between the CUWCD and the CUP? Gene Shawcroft: The CUP is a federally owned project. The CUWCD is a state agency that has the contracts for the use of the water and is also responsible for the repayment of the CUP. Hydro Leader: What role does hydropower play in the CUWCD’s overall operations?

Gene Shawcroft: We have an allocation of power from the Colorado River Storage Project, which we use at various locations throughout the district. In addition, we have a power plant at Jordanelle Reservoir, which we own under a lease of power privilege, and the Olmsted plant, which is a hydroleadermagazine.com

PHOTOS COURTESY OF THE CUWCD.

Gene Shawcroft: The CUWCD was created in 1964 to be the sponsoring and repayment entity of the federal CUP. At the time we were created, there were 12 counties in the district. We have 8 counties now, since 4 withdrew from the district as the CUP was reformulated. Over the course of time, as the Bureau of Reclamation was constructing the CUP, it became obvious that additional funds would be needed from Congress. In 1992, Congress passed Public Law 102‑575, the Central Utah Project Completion Act, which made some landmark changes. First, the CUWCD rather than Reclamation became responsible for the completion of the CUP, and we were required to come up with a 35 percent local cost share. We had to have 90 percent subscription for the water in order to build the project. For the purposes of various environmental laws, principally the National Environmental Policy Act (NEPA), we became a federal agency. Our construction responsibilities changed dramatically, as did our coordination with the U.S. Department of the Interior. Rather than reporting through Reclamation, we now report directly to

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The operating floor of the new Omsted plant, with a bypass line visible in the background.

federal facility and generates federal power. Both of these power plants make up a small portion of the value of the facilities we operate. We operate around $3.5 billion worth of federal facilities, and the Olmsted plant is valued at about $42 million. It is a relatively minor portion of the capital investment of the project, but it is critical to our operations.

Hydro Leader: Tell us about the history of the Olmsted plant.

Gene Shawcroft: The historical value of the Olmsted power plant can’t be overstated. It is one of a kind and was the first of its kind in many respects related to power. At one point in time, it was a hands-on educational facility for operators and held state-of-the-art technology. George Westinghouse himself was here for several years as he developed the concepts of alternating current. The plant is on the National Register of Historic Places. In our work on Olmsted, the Utah State Historical Preservation Office required us to not restore but to maintain the equipment in a heritage preservation–type fashion. We’ve spent quite a bit of time and money to do that.

The power produced by this plant is incidental to our operations. However, the water right associated with the power is critical to the operation of the CUP. The Olmsted hydroleadermagazine.com

power plant and facilities became part of the federal project in the mid-1980s for two purposes. First, there was a pipeline that took water from the Provo River into our distribution system. The right of way for that pipeline was key for getting water to our facilities. Second, the power plant’s water right was early priority. Even though it was a nonconsumptive right, the power plant, combined with other CUP rights, preserved our ability to store water in upstream reservoirs. An important settlement purchase agreement of the power plant and water rights in 1990 paid the owner, PacifiCorp, about half the settlement value.

PacifiCorp continued to operate the plant and receive energy it produced to make up for the remaining capital cost until at least 2015 while allowing the CUWCD to store the water in Jordanelle Reservoir, where it formed an important part of the CUP water supply.

When the agreement we had with the power company expired in 2015, in order for us to maintain the water right that allowed us to store water in Jordanelle Reservoir, the power plant had to be operational. Parts of it were over 100 years old, so it was much more efficient to rebuild it than to refurbish it. Even though there are times when it does not generate power because we’re storing the water in Jordanelle for delivery to customers, the power plant’s water May 2021| HYDRO LEADER

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The installation of a penstock trifurcation fitting.

right is what actually maintains our ability to store water.

That will continue to be the case in the future. The ability to generate power firms up our water right, which we mainly use to store water for the CUP.

is that everyone is kept whole, and yet we are able to store water in Jordanelle that allows us to make deliveries during July, August, and September when there otherwise would not be enough water for the project.

Hydro Leader: In other words, the early priority water right is directly linked to the generation of power and cannot be transferred to another use without losing its priority date?

Hydro Leader: Tell us about the process of replacing the older power plant.

28 | HYDRO LEADER | May 2021

Gene Shawcroft: A few years before the expiration of the contract with the power company in 2015, we began preliminary investigations into whether it made sense to rehabilitate the old plant. As we looked at the equipment and the penstocks, it became obvious that the equipment had reached the end of its useful life. The power company knew that its contract terminated in 2015, so its level of maintenance was not what it otherwise would have been. We began a design process for the equipment and installation of a new plant.

In addition to the water from the natural Provo River drainage, we get water to this point from another source that comes through a pipeline from Strawberry Reservoir. This water has enough head to be connected to the penstocks to generate power at the power plant. If we turn the power plant off, there’s enough pressure to run the water from Strawberry up the penstock into our distribution system. We saved a lot of money by designing a system to allow flow in both directions. The power plant was taken out of commission in 2015. We had part of the design done prior to that time, hydroleadermagazine.com

PHOTOS COURTESY OF THE CUWCD.

Gene Shawcroft: Correct. Let’s say that in the early spring, when the water in the river starts to increase because of runoff, the water could be diverted from the river and put in the power plant to generate power. At times, we physically store the water in a reservoir above the diversion, preventing it from coming to the diversion and storing it for use at a different time. We could allow the power company to continue to generate on the remaining water or pay a minimum guaranteed revenue to the power company to offset the revenue it would otherwise have made by generating power with that water. The power company is made whole to the total valuation of the settlement plus any additional generation, and we can store the water for delivery at a later time. The water right for the water that would have otherwise gone through the power plant is a nonconsumptive right.

To replace that water, we purchase water downstream of the plant. That way, we keep everybody whole while having the ability to store water that we otherwise would not have been able to store. It’s a complicated exchange, but the bottom line

ADVERTISEMENT because we didn’t want to have the plant shut down for a long period of time. That could have jeopardized our water right. We issued a notice to proceed on the prepurchase of equipment contracted in September 2015 and started installation 1 year later, in 2016. The construction occurred from September 2016 to August 2018. It was an investment of about $42 million. We began generation in July 2018 and started commercial production in October 2018.

Hydro Leader: You mentioned that you had to preserve elements of the historic plant in a heritage preservation form. Were any elements of it preserved in working form?

Gene Shawcroft: There were four different penstocks in the old project. Each penstock led to one individual generating unit. One of the penstocks had been completely shut down because the pipe had rusted through and had holes in it. We removed all four penstocks and replaced them with one larger penstock. Just prior to reaching the new plant, the penstock bifurcates to run two larger units and two micro units. The scroll cages and the runners for the four units in the old power plant are still there, but nothing in the old power plant is operational. The water and power have been completely disconnected. There are a couple of places in scroll cages where we’ve cut out a section so you can see into the runners and the wicket gates. The primary improvements to the historic building were for seismic performance.

Hydro Leader: What were the results of the project? How is the current project operating? Is it making you money?

Gene Shawcroft: It’s operating as we anticipated. It’s a run-of-river plant. We do not have the authority to run water through it solely for the purposes of generating power. Power generation is really incidental to it. As far as making money is concerned, because we rebuilt it in order to maintain our water right, there was never an expectation that we would generate a positive revenue stream. Whatever we generate goes straight to the Western Area Power Administration (WAPA), and a formula determines who gets how much power from the generation. The cost of that power is based on the district’s annual operational and maintenance costs for the year, plus WAPA’s oversight costs.

It varies depending on the cost to operate and the amount of energy generated.

The district, with assistance of Interior, put capital into the power plant, but the district doesn’t anticipate getting it back.

Our priority was maintaining the CUP water rights with the early priority date. If the power plant didn’t have the capacity for the full water right, we would not be able to store that amount of water when it is available. Our design engineers had a tough time understanding the need to design it for this large capacity when, in fact, the full amount of water is not available the majority of the time. We had to maintain the capacity of the plant in order to maintain our water right. If hydroleadermagazine.com

the most efficient size for the plant were only half the water right and we had built it at that size, we would have lost the other half of the water right. Because we had to build units large enough to carry the full capacity of the water right, those units may only run at full capacity for a few weeks a year, or in a dry year, perhaps not at all. In a wet year, they might run at full capacity for 2–6 months. The figures for return on investment were different from those of a normal power plant’s, simply because we designed the plant based on our desire to maintain the water right, not generate revenue.

Hydro Leader: What lessons about restoring historic power plants have you drawn from your experience with the Olmsted plant?

Gene Shawcroft: There are a lot of intricacies, and the expenses are not low. The district staff, consultant engineers, and contractors did a tremendous job maintaining the historic value of the power plant. There are many other buildings there, including an old classroom and the house of ideas, where they had some electric appliances that were among the first in the country. Some of those have hazards in them, such as asbestos, so we did not restore all of them.

We only restored the old power plant, which is what we were required to do under our environmental commitments.

The district also completed 3-D LIDAR surveying of all the miscellaneous outbuildings that had to be demolished where the new plant was constructed. It takes a little longer than you expect, and it takes a little more money than you expect.

In the end, it was well done. We’re still trying to piece together all the information and all the plaques and other materials that we’ll need for the heritage center.

I’ve also learned that there are people who are passionate, and rightly so, about historic buildings and their historic value, including some of our staff, who have absolutely loved working on the project. It’s been interesting to see how some of our staff have adopted it as their own crusade to maintain as much historic value as possible.

Hydro Leader: Is there anything else you would like to add?

Gene Shawcroft: It’s always wonderful to me when the general public, to whatever degree, learns of the complexity that goes into making our lives convenient. An incredible amount of effort and expense went into this power plant as part of a larger picture to make sure people in our area get a safe and clean drink of water. I’m always thrilled that people are interested enough to learn about the complexity of what it takes to develop and use our natural resources, especially our water. H Gene Shawcroft is the general manager of the Central Utah Water Conservancy District. He can be contacted at gene@cuwcd.com.

May 2021| HYDRO LEADER

| 29

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The Bright Future of Innovative Dam Construction: Pumped Storage, Twin Dams, Off-River Reservoirs, and More

By François Lempérière and Luc Deroo

A

lmost all countries have built dams across rivers, mainly for supplying hydropower or storing water.

The reservoirs are filled by gravity. The average per capita world hydropower supply is about 500 kilowatt-hours (kWh) per year, making up about 10 per cent of the total use of energy. The average per capita useful storage of drinkable or irrigation water worldwide is about 100 cubic meters (m3), or 3,531 cubic feet (ft3). That figure is being reduced by the siltation of reservoirs.

The global need for power and water is increasing dramatically, but traditional dam construction is now much reduced in most countries for three reasons: Most of the best sites in rivers for traditional dams are already taken; the direct costs of wind and photovoltaic (PV) energy are now lower than those of hydropower; and there is increasing criticism of the environmental impact of dams, especially the 500,000 square kilometers (km2), or 19,305 square miles (mi2), of drowned areas along rivers. If current situations continue, these factors may significantly reduce the rate of traditional dam construction within 20 years. However, there is also the possibility that innovations in the use of dams may increase the rate of dam construction and launch a new golden age for dams. One key innovation may be the use of pumping to fill reservoirs for purposes including energy, water storage, and flood mitigation.

The Need for Pumped Storage Facilities

The need for electric energy storage is presently low, because most electricity is generated by flexible coal or gas thermal plants. However, the need will be high within a few decades, because most energy will probably be electricity from intermittent wind and solar PV installations. The storage need will be especially important in the sunny countries located on average around 1,500 km (932 mi) from the Equator, which are currently home to 5 billion people and will have 7 or 8 billion in 2050. The revenue per capita and use of energy per capita of these countries in Africa, South Asia, and Latin America are only 20 percent of those in the United States and Europe.

For centuries, the sunny countries had fewer easily used energy sources than Europe, which may be a key reason for their lower economic progress. The future availability throughout the year of unlimited PV energy in sunny countries at a direct cost of $20–30 per megawatt-hour (MWh), however, is a miracle that should be quickly taken advantage of, but which requires a huge amount of energy

32 | HYDRO LEADER | May 2021

storage to store energy generated during the day for use at night. An increase in energy production from the current level of 8,000 terawatt-hours (TWh) for 5 billion residents to a potential future level of 50,000 TWh for 8 billion residents could be the engine of enormous economic progress. The figure of 50,000 TWh would be based on 40,000 TWh of low-cost PV generation. One half of that generation would be used directly during the 10 hours of sunlight per day, but most needs beyond daytime will rely on stored energy, which would be stored primarily by pumped storage plants. Assuming that these pumped storage plants would need to store 10,000 TWh of energy over 3,000 hours, we are looking at a needed storage capacity of 3,000–4,000 gigawatts (GW).

During peak times, electricity storage needs may also be met with batteries, but pumped storage is probably a better solution for daily storage: The investment by stored kWh would not be too different, but the life of batteries can be counted in years, while the life of pumped storage projects may last centuries.

The 1.3 billion people who live in the countries of the Organisation for Economic Co-operation and Development (OECD), mainly in North America and Europe, live on average 5,000 km (3,107 mi) from the Equator and have fewer hours of sun but much more wind than the sunny countries. They presently use 10,000 TWh a year of electricity, mostly thermally generated, although with about 20 percent generated by nuclear facilities and about 15 percent by hydropower. The population of these countries is not increasing, so their total energy use may not increase much, but the energy share of electricity will likely increase, possibly up to about 15,000 TWh a year, including 2,500 TWh of hydro, perhaps a few thousand thousand TWh of nuclear, little fossil energy, offshore and onshore wind power, and some PV energy during the sunny parts of the year. Wind generation may vary day by day, but spreading windmills across a large area will reduce the OECD nations’ storage needs to around 1,000 GW. For 40 years, China has increased its revenue per capita tenfold, thanks to an increase of electricity per capita from almost nothing to 6,000 kWh for 1.3 billion people, mainly produced with coal. In the future, China will use mainly wind and PV energy and its population, energy use, and need for energy storage may approach those of the OECD nations.

All told, the world need for pump storage plants may surpass 5,000 GW, which will need to be implemented from 2030 to 2080, i.e., at a rate of over 100 GW a year. The hydroleadermagazine.com

ADVERTISEMENT rate of investment in traditional hydropower has only been 20 GW a year for the past 70 years, and the cost of dams per GW is not much different. The necessary yearly investment in dams for electric energy storage in 2040 may thus be five times the investment in hydropower during the golden age of dams around 1970. The likely increase in the total world revenue in 70 years is also about fivefold.

How Can 5,000 GW of Pumped Storage Plants Be Built?

The traditional solution that has been employed in the 200 GW worth of existing pumped storage plants involves using tunnels to link two reservoirs whose level differs by several hundred meters. Using mountainous terrain where the level differs even more has huge extra potential, but this solution has two drawbacks: The use of rather long tunnels prevents a quick adjustment in plant operations to respond to quick changes in PV or wind availability, and this solution can only be implemented in rather steep areas in the upper parts of large catchment areas. However, there are two other pumped storage solutions with significant potential: twin dams along rivers and pumped storage plants along sea cliffs.

Fig. 2: A concept illustration for the conversion of Lake Kariba into a twin-reservoir system.

Twin Dams

PHOTOS COURTESY OF FRANÇOIS LEMPÉRIÈRE.

A typical example of a large traditional hydropower scheme is a 100-m-high (328-ft-high) dam creating a 20-km-long (12.4-mi-long) reservoir on a river. Throughout most of the year, the power plant uses most of the river flow under a head close to 100 m (328 ft). An alternative is the use of two 50-m-high (164-ft-high) dams, creating two nearby 10-kmlong (6.2-mi-long) reservoirs and using two plants under a 50-m (164-ft) head for a power supply similar to that of the basic solution. In the latter case, it may be possible to use a pumped storage plant to exchange water between the two reservoirs on a daily basis (fig. 1). The water volume pumped yearly may be 10–50 times the yearly river flow, and while it is used under a head of 50 m instead of 100 m, the yearly pumped energy may be 5–20 times the supplied power. After 2030, this may be a cost-effective solution for supplying full-time intermittent solar or wind energy in many countries. A significant quantity of PV elements may be set on the reservoirs themselves. This twin dams solution should be studied for most new large schemes; it may also replace an existing reservoir, add a new reservoir upstream or downstream of an existing reservoir, or associate a reservoir in a main river with a higher reservoir in a tributary.

Fig. 1: A diagram of the twin dam concept, with a pumped storage plant (labeled PSP) in the center.

hydroleadermagazine.com

Fig. 3: A concept illustration for the conversion of Egypt’s Lake Nasser into a triple-reservoir system.

The 5,000-km2 (1,930-mi2) Kariba Reservoir in Africa, which supplies 7 TWh a year, could be adapted to store over 200 TWh a year (fig. 2). Along similar lines, the 300-kmlong Aswan Reservoir in southern Egypt, which has a useful water storage of 100 billion m3 (81 million acre-feet) and supplies 7 TWh a year of hydropower, could be divided into two reservoirs and supplemented with a 100-km-long (62-mi-long) reservoir in an old tributary that is now fully dry.

The Aswan Reservoir’s huge water storage capacity could be preserved while simultaneously allowing it to store 500 TWh a year of low-cost PV energy generated in a region where there are never clouds (fig. 3). Egypt could have enough low-cost energy for all its needs and to export to Southern Europe or the Middle East. This Aswan scheme could be May 2021| HYDRO LEADER

| 33

Fig. 4: A diagram of a seaside reservoir.

implemented over 50 years in 10 steps of 20 GW each. This is the largest possible pumped storage scheme; the usual capacity of most projected twin dams schemes is 1–10 GW.

Sea Cliff Pumped Storage Projects

Worldwide, there are over 100,000 km (62,137 mi) of seaside cliffs. Usually, the sea within 1–2 km (0.62–1.24 mi) of the cliff toe is not particularly deep, and the seabed is rock for several hundred meters and thus favorable to pumped storage plant construction. Building 100-m-high (328-fthigh) dams along the seacoast could be used to create high reservoirs along cliffs, using the ocean itself as the low reservoir. This solution is too expensive for small capacities, but appears to be cost effective for schemes of at least several GW. This concept can also be adapted for very large natural lakes. In many sites, the high reservoir may be partly or totally above the cliff, thus reducing its cost per GW. The construction of the dam at sea may occur behind a rockfill breakwater, which can be used later as the downstream toe of the dam. Construction in calm water may be easier than it was for many existing dams in large rivers (fig. 4). The potential for pumped storage projects on islands is lower, as the cost per kWh would usually be higher.

The Cost of Pumped Storage and of Future World Electricity

34 | HYDRO LEADER | May 2021

The Promise of Large, Low Off-River Dams

The total world capacity of reservoirs created by dams is over 7,000 km3 (5.67 billion acre-feet), but most is devoted to hydropower. The capacity devoted to seasonal water storage is reduced by siltation and evaporation to under 1,000 km3 (810.7 million acre-feet); that is, about 100 m3 (3,531 ft3) per capita for the world’s 8 billion people. Today, billions of people lack water storage, especially in sunny countries, and considering population increase and the increase in food quality, the world’s future needs for seasonal water storage could double within 50 years.

Traditional water storage by dams on rivers requires a minimal river slope and does not apply to rather flat areas where storing water off rivers by pumping may be a costefficient alternative. The cost of low-head pumping is low; most of the cost is for the dikes surrounding reservoirs. The cost per cubic meter of stored water may be acceptable for reservoirs with a surface area of 1–10 km3 (0.38–3.8 mi3) or more and with an average depth of 5–10 m (16.4– 32.8 ft). Surprisingly, this is close to or greater than the average depth of existing dammed reservoirs devoted to hydroleadermagazine.com

PHOTO COURTESY OF FRANÇOIS LEMPÉRIÈRE.

Most future world energy is likely to be electricity, primarily supplied by PV and windmills, with about 10 percent supplied by flexible hydropower supply. After 2050, the direct cost of PV will be 2–3 cents per kWh in sunny countries and 4–5 cents elsewhere. The direct cost of wind power and hydropower will be on average under 5 cents per kWh. The average direct cost of electricity will thus probably be 3–4 cents per kWh in sunny countries and about 5 cents elsewhere.

Thirty or forty percent of that energy will be stored, mainly through pumped storage, with a loss of about 25–40 percent, i.e., an increase of 10 percent of the direct

cost. The cost of storage by pumped storage projects derives mainly from the initial investment; their total yearly cost may be 6–7 percent of this investment. The investment for future pumped storage facilities will usually be $1,000– $1,500 per kW. The cost per kW for the pump turbines will likely be reduced by the huge quantity of similar equipment that will be produced worldwide each year. These costs are high for hydropower today because a scheme requires a small number of units of a specific design. The yearly cost per kW of a pumped storage plant will likely be 6–7 percent of $1,000–$1,500—that is, $60–$100 for 2,500 hours of pumping, or 3–4 cents per stored kWh or about 1 cent per kWh used. Adding the cost of some additional battery or hydrogen storage and storage losses, the total future cost of electricity per kWh may be about the direct cost of PV or wind power plus 2 cents.

ADVERTISEMENT water storage, which is about 20 percent of the dam height.

Fifty percent of existing large water storage dams are less than 30 m (98.4 ft) tall, and there are many hundreds of thousands of small dams under 15 m (49.2 ft) tall. This solution has great potential and could be used to meet a huge part of future needs. An off-river reservoir of this type may be close to the river or within a few kilometers of it and could be a dozen meters above it. Off-river reservoirs filled by pumping have been used for over a century, but usually for rather small volumes and thus at a much higher cost per cubic meter than would be the case with the proposed large reservoirs. Off-river reservoirs would also be more environmentally friendly that traditional on-river reservoirs.

Large off-river dams can also serve for flood mitigation.

Today, there are many fewer fatalities from floods than in the past, thanks to flood forecasting and efficient communications, but property damage is likely to increase along with population, home values, and climate change.

Using on-river dams to store floodwater is efficient in steep portions of rivers, but not in flat areas where many people live close to the river. Using pumping to fill large, off-river reservoirs for water storage may be cost efficient. It would require large pumping capacity, but the power needs would be limited by the low head. Such reservoirs may also be used for seasonal water storage. It may be difficult to find a reservoir with a surface area of dozens of square kilometers in the downstream, populated sections of large rivers, but several smaller reservoirs on tributaries may be an efficient alternative.

PHOTOS COURTESY OF FRANÇOIS LEMPÉRIÈRE AND ISL.

Increasing the Water Speed of Large Rivers

In the downstream sections of large rivers, the slope is usually less than 0.5 m/km (2.64 ft/mi), the water depth 5–10 m (16.4–32.8 ft), and the water speed during extreme floods about 2 m (6.5 ft) per second. Increasing the water speed by 10–20 percent would reduce the water level by 0.5–1 m (1.6–3.2 ft) and thus avoid most damage. If a dam on a river downstream of a large city is paired with a pumping plant that pumps river flow upstream to downstream during a flood, it could reduce the water level by 2 m (6.4 ft) close to the dam and by an average of 1 m (3.2 ft) over 10–20 km (6.2–12.4 mi), avoiding most damage. This solution seems cost effective for rivers with a slope under 0.5 m/km (2.64 ft/mi). In terms of power, it would likely require several dozen MW. This solution may also be used in large deltas. Examples of locations where this solution may be used include Paris, Bangkok, and the Mekong Delta, where tens of millions of people live.

Environmental Effects

The environmental effects of the innovative uses described above are much better than those of traditional dams. For example, • Off-river water storage avoids the effects on rivers that traditional dams have. hydroleadermagazine.com

• Twin dam reservoirs of the type described above occupy one-tenth of the surface area per GW that traditional dammed reservoirs do.

• Pumped storage plants along the sea have comparative lower effects per GW. Most criticisms of PV and wind energy focus on the need to store intermittently generated energies, especially on the surface areas of the pumped storage reservoirs that would be necessary. However, media presentations by experts on these topics often refer to the surface area per GW of existing reservoirs supplying hydropower— on average, 300 km2 (115.8 mi2) per GW. Actually, the surface area needed for pumped storage reservoirs is only about 10 km2 (3.8 mi2) per GW. Five thousand GW of pumped storage will require 50,000 km2 (19,305 mi2), 10 percent of the present reservoir area for 1,300 GW of hydropower supply.

Future Investments in Dams

The investment in future energy generation and storage dams may include 500 GW of traditional hydropower supply, 200 GW of tidal plants, and 5,000 GW of pumped storage plants. Investments for water storage may reach 1 trillion m3, much of which could be offriver storage. Flood mitigation needs may be met by traditional solutions in the upstream sections of rivers and by pumping in the downstream sections, either by storage or by water speed increase. Most needs and investments will be in the sunny countries within 1,500 km (932 mi) of the Equator. The innovative uses we have described here are generally based on traditional dam design and construction methods, but they may be significantly more cost effective. These innovative solutions are also less susceptible to the main cause of failure of traditional dams, namely exceptional floods. There is a bright future for the construction of new, innovative dams, especially large, environmentally friendly pumping schemes of the type that will be in great demand in future decades in the world’s sunny countries. H

François Lempérière is the president of HydroCoop.

Luc Deroo is the managing director of ISL. For more about ISL, visit www.isl.fr/en.

May 2021| HYDRO LEADER

| 35

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PRODUCTION CONTROL PLANNER ADVANCED TECHNOLOGY HYDRO POWER EQUIPMENT Location: Mansfield Center, Connecticut Deadline: Until Filled Salary: $40,000–$60,000 RESPONSIBILITIES: +S cheduling usage of production materials to ensure optimal production levels +Q uoting, purchasing, and purchase planning; evaluation of suppliers +M anaging stockroom and inventory levels, identifying and resolving problems relating to inventory and production schedule +T racking and issuing all materials and ensuring appropriate locations REQUIREMENTS: +E xcellent verbal and written communication, organizational, and time-management skills +S trong regard for product quality and safety standards +C ompetency with standard office computer applications +A bility to read technical drawings such as machine drawings, product specifications and similar For more information: email hr@nustreem.com or info@nustreem. com or visit https://nustreem.com.

PURCHASING AGENT/BUYER Location: Orem, UT Deadline: Open until filled RESPONSIBILITIES: +R esponsible for procurement and the purchasing functions for all of the Geneva Pipe Plant operations. +M aintains professional relationships with a variety of vendors in order to purchase products or services at the best possible prices. +M aintains up-to-date vendor records and purchase order records and follows all company policies and directives. +P rocesses requisitions for MRO, RFQ and raw material items and administrates purchase orders. +R esearches products and vendors to optimize value and performance.

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REQUIREMENTS: +A bility to effectively present information and respond to questions from groups of managers, clients, customers, and the general public. +H ighly detail oriented. + I ntermediate skills working with computers and software packages such as Outlook, Word, Excel, and SAP. +A bility to prioritize and manage multiple tasks and projects.

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EHS LEAN SPECIALIST Location: St. George, UT Deadline: Open until filled RESPONSIBILITIES: +T his new role will support the team by implementing and championing Safety, Lean, Production, and Environmental initiatives. +T rain and implement solutions to improve productivity, safety activities, and quality. +L ead Safety Program to ensure employee safety and compliance with OSHA standards. +C onduct weekly safety meetings with the team. +P rovide direction for the production team in the event that unsafe acts or conditions are observed. +O ptimize manufacturing processes to attain maximum safety, product quality, efficiency, and repeatability.

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QA MANAGER Location: Parkersburg, WV Deadline: Open until filled RESPONSIBILITIES: +P lans, coordinates, and directs quality control program for the Parkersburg manufacturing facility. +D evelops and analyzes statistical data and product specifications to determine present standards and establish proposed quality and reliability expectancy of finished product. +F ormulates and maintains quality control objectives coordinated with production procedures to maximize product compliance and minimize costs. +D irects workers engaged in inspection and testing activities to ensure continuous monitoring of production in progress as well as finished product.

REQUIREMENTS: +A bility to work with mathematical concepts such as probability and statistical inference; and the fundamentals of plane geometry, solid geometry, and trigonometry. +A bility to apply concepts such as fractions, percentages, ratios, and proportions to practical situations. +B achelor’s Degree (B.A.) from a four-year college or university and five years related experience or 10 years equivalent combination of education and experience with a minimum of five years managerial experience. +R equires an active AWS CWI certification.

For more information: Contact Nick Hidalgo, Talent Acquisition, at nhidalgo@nwpipe.com or visit www.nwpipe.com/careers.

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JO B RLTI ISSTEI M NG AD VE ES NT REGIONAL SUPERVISOR PLANT OPERATIONS Location: Adelanto, CA; Tracy, CA; and Portland, OR (Travel 30%) Deadline: Open until filled RESPONSIBILITIES: +T his position is part of Northwest Pipe Company’s training and development process and will receive hands on training in a variety of departments. +D irects and coordinates activities concerned with manufacturing of Company products by performing the essential job functions personally or through their subordinates. +P romotional opportunities may not be located at the facility in which this position is initially located and may require relocation.

REQUIREMENTS: +T wo-year College or technical school; or three to five years related experience; or equivalent combination of education and experience. +P revious supervisory experience in a manufacturing environment required. +E xperience in a heavy-industrial manufacturing environment preferred.

For more information: Contact Nick Hidalgo, Talent Acquisition, at nhidalgo@nwpipe.com or visit www.nwpipe.com/careers.

PROJECT/SENIOR LEVEL STRUCTURAL ENGINEER Location: Greensboro, NC RESPONSIBILITIES: +P erform and/or review stability analyses, reinforced concrete design, and steel design for water and earth retaining structures associated with dams, spillways, and other hydraulic structures +P repare and/or review design drawings, reports, and technical specifications +P erform inspections of dams and hydraulic structures +P rovide periodic construction observation and consultation +P erform task and project-level management and coordination duties +M entor junior level structural engineering staff hydroleadermagazine.com

REQUIREMENTS: +B achelor’s Degree in Civil or Structural Engineering from an ABET-accredited university +P rofessional Engineering license to practice structural engineering or ability to seek reciprocity upon employment +R elevant work experience of at least eight (8) years in structural engineering +H igh proficiency with AutoCAD Civil 3D and Revit +E xperience with computer-aided structural analysis and finite element modeling +E xcellent oral and written communication skills +W illingness and ability to perform field work and travel +A bility to lift 60 pounds and be physically able to negotiate construction sites, enter trenches, climb ladders and work outside in various weather conditions.

For more information: Visit www.schnabel-eng.com.

GEOTECHNICAL ENGINEER – SENIOR LEVEL Salary: $95,000–$100,000 RESPONSIBILITIES: The person in this position will work on a variety of geotechnical engineering consulting projects, with emphasis on work related to dams, flood control projects, and hydraulic structures.

In addition to providing technical expertise and engineering oversight of geotechnical investigations, numerical modeling, analysis, and design, this person will also be involved in preparing plans and specifications for construction, writing reports, and cost estimating.

Administrative responsibilities such as project management, mentoring and coaching, and developing and maintaining client relationships are also expected to be part of this role.

Minneapolis, Denver, and Salt Lake City are the preferred office locations, but the position is open to other locations in the U.S. The position will require travel for project assignments or business development activities.

REQUIREMENTS: +B achelor’s degree in civil engineering with a geotechnical emphasis + 1 0+ years of relevant work

experience in analysis, design, and construction of dams, flood risk reduction infrastructure, and hydraulic structures +P rofessional Engineer (PE) certification +S trong technical skills in a wide range of civil engineering disciplines such as structural and water resources +W illingness to travel to support project needs +L egal authorization to work in the U.S. without the need for sponsorship +E xperience working in consulting engineering +A cceptable driving record For more information: www.barr.com/careers.

DAM SAFETY ENGINEER RESPONSIBILITIES: This position involves a combination of structural or geotechnical design and dam safety responsibilities.

The immediate need will have the candidate participating as part of a team of technical professionals working on various civil structure design and dam safety projects associated with hydroelectric and civil works water projects.

RESPONSIBILITIES: +P rior approval from Federal Energy Regulatory Commission (FERC) as an Independent Consultant to conduct Part 12 Dam Safety Inspections or ability to receive this designation within three years. +E xperience with design of structures in and around water including submerged environments. +E xperience with structural aspects of concrete and steel construction and/or geotechnical analysis of earthen embankments and canals. +E xperience in concrete and earthen dam, canal, or levee safety inspections. +E xperience in seismic design and analysis +P ermitting experience on large and diverse projects. +E xcellent problem-solving skills and capable of working collaboratively with clients and co-workers. +R egistration as a Professional Engineer. +B S in engineering with minimum of 10 years’ experience in structural or geotechnical engineering.

For more information: Visit www.kleinschmidtgroup.com.

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