Municipal Water Leader February 2020

Volume 7 Issue 2

February 2020

Emrgy: Turning Canals Into Hydropower Installations

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Emrgy: Turning Canals Into Hydropower Installations

Municipal Water Leader is published 10 times a year with combined issues for May/June 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 SUBMISSIONS: Municipal Water 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 municipal.water.leader@waterstrategies.com.

Contents

February 2020 Volume 7, Issue 2 5 R enewables and Energy Recovery

By Kris Polly 6 Emrgy:

Turning Canals Into Hydropower Installations 10 How

the Nation’s Largest Water Wholesaler Benefits From Renewable Energy 16 E astern Municipal Water District's Solar Initiative

20 B onneville Power Administration: The Backbone of the Pacific Northwest Grid 24 C olumbia Basin Hydropower’s Major Pumped Storage Plans 30 I mplementing Oceanus’s Pumped StorageDesal Plant in Chile 34 A ECOM’s Holistic Solutions to Cities’ Water, Waste, and Energy Problems

ADVERTISING: Municipal Water Leader accepts one-quarter, half-page, and full-page ads. For more information on rates and placement, please contact Kris Polly at (703) 517-3962 or municipal.water.leader@waterstrategies.com.

CIRCULATION: Municipal Water Leader is distributed to irrigation district managers and boards of directors in the 17 western states, U.S. Bureau of Reclamation officials, members of Congress and committee staff, and advertising sponsors.

For address corrections or additions, please contact our managing editor, Joshua Dill, at joshua.dill@waterstrategies.com.

Copyright © 2019 Water Strategies LLC. Municipal Water 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 Municipal Water Leader magazine, its editors, or Water Strategies LLC. The acceptance and use of advertisements in Municipal Water Leader do not constitute a representation or warranty by Water Strategies LLC or Municipal Water Leader magazine regarding the products, services, claims, or companies advertised.

MunicipalWaterLeader.com

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

4 | MUNICIPAL WATER LEADER

MuniWaterLeader

COVER PHOTO:

Emily Morris, founder and CEO of Emrgy Photo courtesy of Emrgy.

PHOTO COURTESY OF EMRGY.

Coming soon in Municipal Water Leader: March: Dam Safety

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Renewables and Energy Recovery

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ransporting, delivering, cleaning, and treating massive quantities of water requires a lot of energy. Yet it also provides many opportunities for recovering energy, deriving energy from renewable sources, and achieving energy use efficiencies. Renewable energy is a perfect fit for many municipal water and wastewater agencies. In this issue of Municipal Water Leader, we inspect how agencies are using solar power, hydropower, pumped storage, the generation of biogas from the codigestion of biosolids with wastewater, and resource recovery to improve their services and lower their energy use and reduce the waste they create.

Hydropower and solar generation are two of the bestknown renewable energy sources. In our cover story, we speak with Emily Morris of Emrgy about her company’s modular hydropower units, which can be easily installed in any outdoor water conveyance channel. Shawn Bailey of the Metropolitan Water District of Southern California, the nation’s largest wholesaler, tells us about the 15 hydropower stations the agency uses to recover energy from the millions of gallons of water that surge through its system, as well as its solar installations.

On the topic of solar power, we speak with Dan Howell of Eastern Municipal Water District about how the agency’s large solar installations provide it with energy flexibility.

We also focus on two major hydropower generating and marketing agencies. Elliot Mainzer, the administrator of the

By Kris Polly

Bonneville Power Administration (BPA), tells us how the federal agency he runs provides dispatchable, carbon-free, round-theclock power to municipal and private users across the Northwest.

Like the BPA, Columbia Basin Hydropower is also addressing the challenge of providing a reliable backstop for fluctuating solar and wind generation, in this case through the construction of a giant pumped storage installation at Banks Lake.

Finally, we look at two companies helping install new renewable energy facilities. Oceanus Power and Water has invented a new combined pumped storage and desalination facility that can be powered by solar energy. And AECOM is working on a wide variety of waste-to-energy installations.

Across the water and wastewater industries, agencies are adapting their infrastructure in order to derive energy and resources from flowing water, sunlight, storage capacity, and waste. I hope that this issue of Municipal Water Leader will help you start thinking about how your agency can take advantage of these energy sources, too. M Kris Polly is the editor-in-chief of Municipal Water 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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Emrgy: Turning Canals Into Hydropower Installations

Emrgy's first array, installed for Denver Water.

S

olar and wind power have exploded in popularity in recent years as facilities have become cheaper to build, but up until now, this has not been true of a third renewable power source, hydropower. This is primarily because hydropower relies on large installations that require civil construction.

Atlanta-based Emrgy is seeking to change all this with its small, modular, distributed hydropower installations, which can be installed without civil construction. A new partnership with General Electric (GE) will allow Emrgy to build its hydropower modules at scale and market them around the world.

In this interview, Emily Morris, the founder and chief executive officer (CEO) of Emrgy, speaks with Municipal Water Leader about the nuts and bolts of her company’s product and why it is appropriate for municipal water suppliers around the country and the globe.

Municipal Water Leader: Please tell us about yourself and your company.

6 | MUNICIPAL WATER LEADER

PHOTO COURTESY OF EMRGY.

Emily Morris: I’m the founder and CEO of Emrgy. My background is not in the water industry but in technology development, and in defense contracting in particular. In one of my previous roles, I worked with a team of engineers to

build Emrgy’s core technology as part of a project funded by the U.S. Navy. I was personally inspired by the kind of value that the technology we were developing could have.

Our product had modular, flexible, standardized attributes similar to those found in solar power, yet used the medium of water, which is controllable, reliable, and predictable. That combination could result in more sustainable and reliable baseload power and presented an economically attractive and affordable energy solution. I acquired the intellectual property from the company where I helped build this product in 2014.

In 2015, we were awarded additional research funding from the U.S. Department of Energy to continue building out the product. I was able to leverage that research sponsorship to bring on venture capital and impact investment, and we were able to secure pilot projects with the City of Atlanta’s Department of Watershed Management; Southern Company; and most recently, Denver Water. Those pilots will allow us to showcase and demonstrate our product’s performance and efficacy. Now we have partnered with GE Renewable Energy to manufacture our product and sell it around the world.

With our partners at GE, we’re deploying our products to municipalities as well as to the agricultural or irrigation sectors here in the United States.

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Emrgy's devices can be installed without civil construction.

Municipal Water Leader: Would you describe your product, especially the ways in which it differs from conventional hydropower installations?

Emily Morris: Typically, hydropower installations work by converting potential energy, which is stored in head pressure, into electric power. Emrgy has realized that there are many places around the country and around the world where natural head pressure doesn’t exist and where there are environmental, regulatory, and cost barriers to

artificially creating that head pressure by building a dam or impoundment. Emrgy’s product is intended to integrate directly into water conveyance or treatment infrastructure and convert not head pressure but kinetic power into electricity. We take the natural movement of the water flowing through a system and use that to generate clean, reliable, renewable electric power.

Our product is about the size of a large sport-utility vehicle. It essentially looks like a precast concrete box culvert. That box is simply placed into a channel with MUNICIPALWATERLEADER.COM

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ADVERTISEMENT flowing water, whether that channel is used for water treatment, as was the case in the installation we did in one of the Atlanta Department of Watershed Management’s UV effluent channels, or for water conveyance, as in the case of our project with Denver Water. That box culvert just sits on the channel bed. It doesn’t require any anchoring or any diversion or impoundment of water. As water flows through the box, it activates two vertical-axis turbines that convert that mechanical energy into 10 kilowatts (kW) of electric power. Each module has relatively low power density compared to your conventional hydropower installation. The power density of a conventional hydropower installation depends on the head pressure created by water impoundment. However, these water infrastructure channels typically have a reliable and continuous flow. That means that even if the power density is low, these modules provide an opportunity for high energy generation over the course of time. That can make for extremely cost-effective electricity. Our product provides the opportunity for water asset owners to harvest energy from their flowing water.

Municipal Water Leader: How much energy capacity does each module have?

Emily Morris: The amount of energy that a module generates depends the speed of the water in the channel.

Our most common nameplate is 10 kW per module. That’s because the water flows we typically see in municipal water treatment and water conveyance are in the 3-foot-persecond to 5-foot-per-second speed range. If the water flow is faster, the exact same module can generate up to 20 kW with no modification.

Just as a customer rarely buys a single solar panel, we don’t expect our customers to buy one single module. Our modules are intended to be deployed in arrays. For example, in our project with Denver Water, we installed 10 of these modules over approximately 1,000 feet of canal, resulting in the first distributed hydroelectric array in the United States. While each individual module may be relatively low in power density, it’s important to note that by deploying an array, you can amass the same amount of power that you could get from a bigger solar, wind, or biomass installation.

Municipal Water Leader: Can your modules only be used in open channels?

8 | MUNICIPAL WATER LEADER

Municipal Water Leader: Please tell us more about your partnership with GE. Emily Morris: We’re excited to have formalized a partnership with GE Renewable Energy that will help us with the growth and scalability of our product. The partnership with GE has two main principles. One of them is manufacturing. GE will manufacture Emrgy’s product for sales in the United States as well as globally.

This is an exciting opportunity for a small and growing company like Emrgy to benefit from GE’s manufacturing reliability, expertise, and quality. All our turbines will be manufactured by GE and will have manufacturing and design warranties provided by GE and Emrgy, respectively. In addition, GE and Emrgy have identified significant opportunities to take advantage of water infrastructure globally for power generation using Emrgy’s product, so we’re partnering with GE to sell this product internationally. The sales efforts in our partnership are mostly focused on nations that want to use their existing infrastructure to generate clean energy.

Municipal Water Leader: Who are some of the potential clients that you’ve identified?

Emily Morris: Here in the United States, our potential projects are similar to our existing partnership with Denver Water. We see opportunities for Emrgy’s product in municipal settings across the West, including in large, well-known municipalities in Arizona, California, Oregon, and Washington. We are also in a number of exciting conversations regarding projects in Europe, where water conveyance is quite common and small distributed energy facilities are also a familiar part of the energy mix. In addition, we’re looking at a number of opportunities in developing areas in Asia, Southeast Asia, and Africa, because while our product can provide reliable, grid-connected baseload power, it can also provide new energy supplies to areas that do not have access to an existing grid. Each one of our modules’ outputs is grid-ready, 480-volt, three-phase AC power.

It is a good solution for areas that are building energy infrastructure for the first time.

Municipal Water Leader: If a municipal water agency bought some of your modules, what process would it have to go through in order to connect them to the grid?

Emily Morris: It’s quite simple to do. Practically speaking, our systems can be connected to the grid or to your onsite load by your local electrician, as we do not innovate in the electrical system and use commercially available, proven

PHOTOS COURTESY OF EMRGY.

Emily Morris: That’s correct. While there is energy to be captured in pressurized pipes or other infrastructure that you may see inside municipal facilities, Emrgy specifically focuses on open conveyance or treatment channels, where we can install our product with little disruption to the channels’ primary purpose. At Emrgy, we pride ourselves on our ability to deploy our modules in our customers’ waterways without causing major hydraulic disruptions or

requiring modifications to the infrastructure or diversions or impoundments of any kind.

ADVERTISEMENT equipment. Emrgy prides itself on its innovative engineering approach to power generation and in-channel installation, but we see no advantage in innovating in the electrical conversion and transmission of power. That is something that has been developed in the distributed energy space over many decades with the development of solar and wind power. Of course, we can guide a new customer and provide all the support they need. Regarding the monetization of the power, municipalities can use the power to offset their existing grid load, sell power to a utility, or use it for other purposes, just as they can with other distributed renewables like solar and wind.

Municipal Water Leader: What kind of maintenance do your modules require?

Emily Morris: Like any other type of machinery, Emrgy’s modules will perform at their best and last longest if they are appropriately maintained. We use the same materials and types of components and mechanisms that you see in conventional hydro, including turbine blades, shafts, and bearings. System maintenance can be scheduled along with the customer’s other water infrastructure maintenance. We don’t expect the maintenance of our product to require forced outages.

It will need to be inspected, cleaned of debris, and maintained at regular intervals. There are no special maintenance concerns for Emrgy’s modules relative to conventional hydropower infrastructure.

Emily Morris speaks with workers at an installation site.

Municipal Water Leader: Is there anything else you wanted to add about why your products might be appropriate for use by municipal water providers?

Emily Morris: Emrgy’s product represents a new way to either recapture existing energy within your water system or generate a new revenue stream to offset your existing electric costs or sell back to the grid. It can help ensure energy reliability, resiliency, and price stability over the long term. In addition, because Emrgy’s product does not require civil construction, the modules can be moved or relocated based on changes in water flow. They represent a longterm investment that can evolve along with a municipality.

We would be excited to partner with any municipal water organization that has open-channel water flows to help them achieve their sustainability goals and to provide them with cost-effective energy in the face of rising electricity needs and costs in future years. M

Emrgy's modules can be installed without modification to existing infrastructure.

Emily Morris is the founder and CEO of Emrgy. She can be contacted at emily@emrgy.com or (770) 595-9018.

A close-up view of the hydropower device’s turbine.

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How the Nation’s Largest Water Wholesaler Benefits From Renewable Energy

A solar installation at the Weymouth water treatment plant In La Verne.

PHOTOS COURTESY OF METROPOLITAN.

10 | MUNICIPAL WATER LEADER

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he Metropolitan Water District of Southern California is the nation’s largest water wholesaler, providing water to 19 million Southern Californians. Transporting this water from the Colorado River and Northern California and distributing it requires tremendous amounts of energy.

Fortunately, Metropolitan is able to generate a substantial amount of energy from renewable sources, including solar and hydropower stations that are built into its system at convenient locations.

In this interview, Shawn Bailey, the power operations and planning section manager at Metropolitan, speaks with Municipal Water Leader about the district’s energy portfolio and the role played in it by energy recapture and renewable energy.

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

Shawn Bailey: My background is in gas and power markets.

I started off in power plant engineering and development in the electric sector. I was involved with different departments at Southern California Edison and spent about 5 years with Southern California Gas Company before moving to the unregulated side of the gas and power industries. I worked in gas-fired generation development for Sempra U.S. Gas and Power, and then in renewable development. Altogether, I’ve got about 18 years of experience on the regulated side and about 19 years of experience with unregulated energy businesses. I joined Metropolitan in August 2018 as the manager of power operations and planning.

Municipal Water Leader: Please tell us about Metropolitan and its services.

Shawn Bailey: Metropolitan is the nation’s largest water wholesaler. We import water from the Colorado River and from Northern California via the State Water Project and distribute that water to 26 member agencies, which in turn distribute it to about 19 million Southern Californians.

Metropolitan also invests in local water resource development and in regional conservation measures that benefit all Southern Californians and help them use water more efficiently.

Municipal Water Leader: Would you tell us about the size and scale of Metropolitan’s energy portfolio?

Shawn Bailey: Metropolitan has two main energy focus areas. One is the distribution system, which uses energy to treat and transport water within Southern California. The second is the Colorado River Aqueduct (CRA), which moves water from the Colorado River 242 miles across the desert to Southern California. The pumping operation on the CRA involves up to 300 megawatts (MW) of load at five different pumping stations and is our largest energy consumption activity. It uses about 2 million megawatt-hours (MWh) of energy in a typical year. We have a high-voltage transmission

A solar installation at Metropolitan’s Skinner Water Treatement Plant.

system that brings enough power in from Hoover and Parker Dams to supply about half the CRA’s pumping needs. We buy the rest of the energy for the CRA from the wholesale power market in the Southwest, either from the California Independent System Operator or from other suppliers, primarily in Arizona and southern Nevada.

Within our distribution system, Metropolitan has 15 hydroelectric plants. They were mostly built in the late 1970s and early 1980s, with the most recent one coming online in 2001. These 15 hydroelectric plants generate about 250,000 MWh of energy per year and have a total capacity of about 130 MW. We sell that energy under term contracts to utilities and other load-serving entities throughout California.

This renewable energy counts toward their renewable portfolio standards and generates $12–$18 million a year in revenue for us, depending on the water year and whether the flows in the system are conducive to generating power. We also have 5½ MW of solar capacity, primarily generated by installations located at three of our treatment plants. We use that energy behind the meter to displace retail power purchases at the treatment plants. We also have ½ MW of solar production at our Diamond Valley Lake Reservoir. All told, these plants produce about 10,500 MWh a year and offset 20–30 percent of the treatment plant retail power load. That saves us a lot of money.

Municipal Water Leader: Where are those 15 hydroelectric plants located?

Shawn Bailey: They’re located along the distribution system at locations with suitable flow and pressure characteristics.

The Metropolitan distribution system is largely a gravity-feed system, which makes recovering energy at certain points in the system attractive. For example, our Yorba Linda hydro plant is located at the Diemer Treatment Plant. We take a portion of the water that’s flowing into the treatment plant, bypass it to the generator, and generate power with it. It MUNICIPALWATERLEADER.COM

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Work being done on one of Metropolitan’s hydroelectric plants.

when there was a national push to find other non-oil-based sources of energy. In addition to serving those original objectives, during the California energy crisis of the early 2000s, the revenue from those plants helped offset some of our CRA pumping energy costs. With the renewable portfolio standard that kicked in about 10 years ago, those plants have again provided value for us and the buyers of the renewable energy they produce.

Municipal Water Leader: Do those hydro plants resemble small-scale dams, or are they enclosed?

Municipal Water Leader: Please tell us about your energy sustainability plan and what it entails.

Shawn Bailey: They look like a smaller version of the largescale generators you would see at a facility like Hoover Dam. They’ve got a turbine and a generator on the same shaft. At some locations, like Diamond Valley Lake, the generators also function as pumps when needed for water transport.

They’re pretty substantial machines, with capacities ranging from 2 to 20 MW each. The fleet generates an average of about 30 MW per hour.

Shawn Bailey: The primary resources that we’re looking at in this effort are energy efficiency, renewables, energy storage, and load-shifting flexibility in our system. We’re exploring options to reduce our overall costs and avoid price volatility. Metropolitan is doing a lot to manage energy price risk, but we’re also looking at improving energy efficiency and reducing our carbon emissions. The effort includes evaluating the incremental value of more solar generation at our treatment plants and hydroelectric generation on our distribution system as well as the potential for wind and solar generation along our CRA system. We’re also looking at the effect of the high renewable portfolio standards in California and the value of energy storage at our treatment plants and along the CRA.

Municipal Water Leader: Does energy recapture or recovery play a significant role in Metropolitan’s portfolio?

Shawn Bailey: In terms of our overall energy strategy, yes.

These plants were developed during the 1970s energy crisis,

12 | MUNICIPAL WATER LEADER

PHOTOS COURTESY OF METROPOLITAN.

doesn’t affect the reliability of the treatment plant operation.

If you have to work on the hydro plant, you can take it out of service without a lot of difficulty and without affecting the treatment plant. It is strategically located at a point where we need to reduce the pressure on the system anyway. Being able to recover energy is a real bonus. One of our active energy projects is looking at how we can reconnect the Yorba Linda plant to serve our treatment plant load directly.

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Within its distribution system, Metropolitan has 15 hydroelectric plants.

The cost of fossil generation as a whole is rising because it incorporates the cost of carbon, in accordance with the California Air Resources Board’s cap-and-trade program. That increases the cost of power during those hours when fossil generation is at the margin. We’re looking at ways to increase the flexibility of our system to take advantage of low energy prices when there’s a lot of solar generation at midday and to avoid the higher fossilbased prices at the end of the day. Storage can help us manage costs, whether using batteries or some other form such as water storage.

The energy sustainability plan will essentially develop measures to reduce both energy costs and carbon emissions. This effort includes most of the departments within Metropolitan. We’re also coordinating this work with Metropolitan’s development of a climate action plan, which is a broader framework on how Metropolitan can reduce its carbon footprint. Those are the two major energy-related initiatives that we have going on right now.

Municipal Water Leader: What is your message to Congress regarding hydropower and renewables?

Shawn Bailey: We at Metropolitan see a lot of benefits in the development of hydro and renewable generation

here in the West. We’re looking at ways we can shift our energy use to take advantage of economical periods of high solar energy production. Our message would be that renewable development is a real positive, as long as it is complementary to our goals of providing reliable, highquality water deliveries.

Municipal Water Leader: What advice do you have for other water providers considering energy recapture and hydropower?

Shawn Bailey: We would suggest looking for locations where existing electric infrastructure can be used for interconnecting hydropower. Even if a project is not economically viable right now, evaluating these projects can create the option to take advantage of a project in the future if conditions change. M

Shawn Bailey is the power operations and planning section manager at the Metropolitan Water District of Southern California. He can be reached at sbailey@mwdh2o.com.

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A 1-MW solar installation at EMWD’s San Jacinto Valley Regional Water Reclamation Facility.

Eastern Municipal Water District's Solar Initiative

E

astern Municipal Water District (EMWD) provides water, wastewater, and recycled water to more than 825,000 people in Riverside County, California, and in so doing uses more than 100 million kilowatt-hours (kWh) of energy a year. In order to save money, diversify its energy portfolio, and reduce emissions, EMWD is moving forward with an ambitious set of solar power installations that by the end of 2020 will produce around 58.6 million kWh per year.

In this interview, EMWD Senior Director of Administrative Services Dan Howell tells Municipal Water Leader about the district’s renewable energy initiative and the lessons it holds for other municipal water service providers.

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

16 | MUNICIPAL WATER LEADER

Municipal Water Leader: Please tell us about EMWD and its services.

Dan Howell: We are a water, wastewater, and recycled water agency covering the western third of Riverside County. Our service area is 555 square miles. We have four operating regional water reclamation facilities with tertiary treatment

PHOTO COURTESY OF EMWD.

Dan Howell: I’m the senior director of administrative services and have now been at EMWD for 28 years. My background is in the contracts and procurement field. Fairly early in my career here, I took a detour into operations, which is how I got involved in energy management. At the time, the district was quite a bit smaller and we didn’t really have anyone keeping track of our energy expenditures. That was also the time when electric deregulation in California was occurring, around 1996. As deregulation moved

forward, we needed someone to focus on the changes, and I received a crash course in all things energy management. I subsequently returned to the contracts side of our district as a department director but retained responsibility for energy management. The administration and business aspects of energy had become much more prominent in the wake of deregulation and were becoming as important as the engineering and operational components. For several years, I also managed procurement and contracts, customer service, meters, fleet services, billing, and records management, among other things, until about 2 years ago, when we realized that we needed a dedicated resource to manage our energy activities. That’s when we created a position and brought Sam Robinson, our energy program manager, into the department. Sam handles our day-to-day energy management responsibilities and coordinates energy-saving projects and initiatives throughout the organization.

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Riverside, California.

that average 45 million gallons of wastewater per day. We also operate two water filtration plants, 86 water pumping facilities, 16 domestic wells, and 82 storage facilities serving our potable water customers.

Municipal Water Leader: How much energy does EMWD consume on a yearly basis?

Dan Howell: In 2018, the district purchased just over 95 million kWh of electricity from our primary utility, Southern California Edison. We self-generated about 24 million kWh.

PHOTO COURTESY OF VLASTA2.

Municipal Water Leader: What are the district’s existing renewable energy sources?

Dan Howell: Back in 2009, we implemented our first biogas fuel cell at our Moreno Valley Regional Water Reclamation Facility. It is a 900 kilowatt (kW) unit. That was our first significant step into renewable generation. We followed that up in 2012 with a second biogas fuel cell installation at our Perris Valley Regional Water Reclamation Facility, this one with an output of 600 kW. We have always aimed to have a flexible energy portfolio.

We are a significant customer of the Southern California Gas Company, and we operate a large number of internal combustion engine–driven pumps throughout our service area. The regulatory environment here in Southern

California is making it increasingly challenging to operate internal combustion engines, which motivated us to further diversify our energy portfolio by getting into renewables.

Most directly, our board of directors established a strategic plan initiative in 2016 focusing on energy independence.

That involved cost-effectively planning and implementing local renewable energy projects with sufficient generation to meet the district’s entire net energy demands while minimizing our carbon footprint. We updated our triennial strategic plan in 2019. Our current objective is to plan and implement cost-effective energy projects and programs to optimize EMWD’s energy portfolio and to minimize its carbon footprint.

Municipal Water Leader: Would you tell us about EMWD’s planned solar projects?

Dan Howell: In 2014, we implemented a 500 kW solar installation at our headquarters facility here in Perris. We refer to that as our phase 1 project. In addition to that, we operate microturbine generation at the headquarters facility.

That generation is not renewable—the microturbines don’t operate on biofuel, they operate on natural gas—but we do recover heat off of those microturbines and use them to produce over 100 tons of chilled cooling for our administrative headquarters as well.

We followed our phase 1 project in 2015 with our phase 2 solar projects. Those projects effectively installed 1 megawatt MUNICIPALWATERLEADER.COM

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ADVERTISEMENT generation and fuel-cell operations produce approximately 24.3 million kWh of renewable energy a year. The combined total is anticipated to be about 58.6 million kWh per year.

For comparison, we used about 116.5 million kWh of energy in 2018, including electricity purchased from Edison and electricity from our natural gas–driven microturbines.

Municipal Water Leader: Why is a solar power project of this nature appropriate for a municipal water provider?

One of EMWD’s solar facilities.

(MW) of solar generation at each of our four operating wastewater treatment plants as well as our desalination facility in Sun City.

We are now working on our phase 3 project, which includes five additional installations that will generate a significant amount of electrical power. These facilities add a combined total of 16 MW of solar generation to our portfolio. The phase 3 project currently underway is being done under a power purchase agreement. Phases 1 and 2 were directly funded by the district.

Municipal Water Leader: What does that mean in practice?

Are you going to own the phase 3 projects?

Dan Howell: Phases 1 and 2 were capital expenditures— capital projects that the district built, paid for, and owned from the beginning. Our solar phase 3 projects are being installed under a power-purchase agreement whereby a third party, REC Solar, owns the assets, leases property from us, and sells us power for the duration of the contract. There are opportunities for the district to procure those assets at different points over the course of that term. Ultimately, we may choose to own those assets ourselves. Today, it’s purely a power purchase agreement.

Municipal Water Leader: How is phase 3 being funded?

Dan Howell: Energy procured under phase 3 will be paid for through operating costs, no different from how we pay our utility bills. Purchasing power from REC Solar will be just like paying our Southern California Edison bill.

Dan Howell: Our phase 3 project is anticipated to produce approximately 34.3 million kWh per year when all five installations are completed in 2020. Our existing solar-

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Municipal Water Leader: What advice do you have for other municipal water districts considering similar projects?

Dan Howell: Given the size of our organization and the number of activities that we have going, it made sense to establish a dedicated position to manage and coordinate our energy activities. Having a dedicated set of eyes responsible for managing an organization’s energy portfolio and the related moving pieces is important. Specifically with regard to renewable projects, I would advise districts to use a good consultant who will keep apprised of the ever-changing rules and developments in the market. Things today move quickly!

Municipal Water Leader: Is there anything else you wanted to discuss before we wrap up?

Dan Howell: In addition to the projects we’ve discussed, EMWD has been an active participant in demand-response programs over many years. These programs provide financial incentives to discontinue or adjust the use of energy at certain times. This not only reduces operating costs for the district, but helps the state avoid the construction of costly generation to meet peak demands. We have approximately 5 MW of power enrolled in demand-response programs today. For perspective on our operations, we currently have 253 Southern California Edison electric accounts with about 40 Southern California Gas Company accounts as well. We have quite a few facilities, and our service area is only 40 percent built out at this time. M

Dan Howell is the senior director of administrative services at Eastern Municipal Water District. He can be contacted at howelld@emwd.org.

PHOTOS COURTESY OF EMWD.

Municipal Water Leader: When phase 3 is complete, how much of the district’s entire energy needs will its solar projects cover?

Dan Howell: Energy source flexibility is key in the market and in the world we live in today. To have all your eggs in one basket is not the best solution. Also, our board of directors sees the value of the cost savings that solar power provides to our community and ratepayers, as well as its environmental benefits. That message has been consistently reflected in our strategic plans over the last 6 years.

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Bonneville Power Administration: The Backbone of the Pacific Northwest Grid

John Day Dam, one of the 31 federal dams the power from which BPA markets.

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

Elliot Mainzer: I have a background in business and environmental studies and have been working at Bonneville for over 17 years. I started at BPA in 2002 and spent my first 10 years working in different parts of the organization, including energy trading, transmission policy and rates, customer service engineering, and strategic planning. I worked on a variety of regional issues, including wind energy integration, market design, and technology innovation and was fortunate enough to develop collaborative working relationships with a wide variety of regional partners, including our customers, tribes, environmental organizations, regulators, and the members of the Northwest’s congressional delegation. Bonneville provided me with many opportunities to learn and grow. After several years as the executive vice president of corporate strategy, I served briefly as the deputy administrator and then took on the role of administrator and chief executive officer in 2013 during

PHOTOS COURTESY OF BPA.

he Bonneville Power Administration (BPA) is a nonprofit federal power marketing administration based in the Pacific Northwest that is congressionally mandated to market and transmit the power created by all the federally owned hydroelectric projects on the Columbia River. BPA has marketing responsibility for 31 dams as well as the Columbia Generating Station nuclear plant. BPA also operates and maintains 15,000 miles of high-voltage transmission lines in its service territory. BPA’s territory includes Idaho, Oregon, Washington, western Montana, and small parts of California, Nevada, Utah, and Wyoming. Although BPA is part of the U.S. Department of Energy, it is self funding and covers its costs by selling its products and services. As with many water and power utilities, its top issues include maintaining its infrastructure, adapting to a changing market, and balancing environmental concerns with fulfilling its mission.

In this interview, Administrator Elliot Mainzer tells Municipal Water Leader about how his organization provides affordable, reliable, carbon-free power to municipal, public, and investor-owned utilities across the Northwest.

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Parts of BPA’s high-voltage transmission infrastructure.

a time of significant external and internal challenges for BPA. Over the past 6 years, my leadership team and I have taken important steps to manage costs and sustain BPA’s role as an engine of the Northwest’s economic prosperity and environmental sustainability.

Municipal Water Leader: Please tell us about BPA and its history.

Elliot Mainzer: Bonneville was established through the Bonneville Project Act of 1937 during the administration of Franklin Delano Roosevelt. BPA was initially established to market and transmit power from Bonneville Dam, and eventually Grand Coulee and the other federal hydroelectric projects on the Columbia River, and give preference and priority in the use of electric energy to public bodies and cooperatives. We were a big part of the recovery from the Great Depression and the electrification of the rural Pacific Northwest. From the 1930s to the 1970s, the hydroelectric system continued to expand.

Today, there are 22,000 megawatts (MW) of federal

hydro capacity on the Columbia River. The dams that supply the power are owned and operated by the Bureau of Reclamation and the U.S. Army Corps of Engineers.

Bonneville serves as the exclusive marketing agent for the power from the Federal Columbia River Power System.

Our core customers, known as our preference customers, are the municipal utilities, public utility districts, rural electric cooperatives, and other public power customers spread throughout the Pacific Northwest. We are currently selling power to our preference customers under longterm contracts that expire in 2028. Today, BPA owns and operates over 15,000 miles of high-voltage transmission, including lines that run up to Canada and down to California. You can think of us as the backbone of the Northwest’s high-voltage grid.

BPA is a self-funded power marketing administration.

We do not receive federal appropriations. Rather, we cover the capital and operating costs of the federal system through sales of power and transmission. We deliver on our public purposes by operating a commercially successful business.

MUNICIPALWATERLEADER.COM

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ADVERTISEMENT Municipal Water Leader: What are some of Bonneville’s current top issues?

Elliot Mainzer: We have marketing responsibility for 31 federal dams. We’re also the exclusive marketing agent for the 1,100 MW Columbia Generating Station, a nuclear power plant in Richland, Washington, that was built in the 1980s and is owned and operated by Energy Northwest.

Elliot Mainzer: Our major focus at the moment is adapting to changes in the electricity market and sustaining our financial strength. There has been quite a bit of new legislation and policy advanced throughout the region in recent years requiring utilities to use much higher concentrations of clean energy. Bonneville, of course, provides power from a carbon-free hydroelectric system.

We are looking for new ways to not only meet the needs of our preference customers but to better capture the value of the clean, flexible attributes of our hydro resource. To this end, we have been establishing some new trading partners and helping open up a new market for clean and flexible capacity.

We have also had to adapt to reductions in wholesale electricity prices over the last 5–7 years. We’ve made significant progress on managing our costs and maintaining our competitiveness and working with our customers and constituents to make sure that we stay on a healthy financial trajectory.

Another key issue that we’re working on is modernizing our assets and system operations. We’re investing over $800 million a year to sustain and expand the core assets of the federal power and transmission system. We’re also engaged in a significant technological modernization of our system, investing in new digital technologies, automation, and what we call state-awareness tools.

The way that energy is traded in the western United States is also changing. A few years ago, the California Independent System Operator (ISO) in Sacramento established the Western Energy Imbalance Market, which allows many of the utilities in the West to exchange energy with each other on a real-time, 5-minute basis. Earlier this year, we signed an implementation agreement with the California ISO to allow us to potentially join that market in 2022. We still have some final steps to complete before deciding whether to go live.

Things are looking positive, and we’re encouraged by the way the market is creating value for consumers.

We continue to work actively with stakeholders throughout the Pacific Northwest to make progress for salmon on the Columbia River. The fundamental challenge is to craft solutions that balance the needs of salmon with affordability, reliability, our ability to meet the multiple statutory purposes of the Federal Columbia River Power System. We’ve been working on a court-ordered environmental impact statement known as the Columbia River System Operations Review, which we will complete in 2020. I am hopeful that through careful listening, collaboration, and creative thinking, the Northwest can ultimately come together around a long-term plan for salmon recovery that maintains power system reliability and affordability and meets the needs of the many people who depend on the dams for their livelihoods.

Municipal Water Leader: How many people get power from Bonneville?

Parts of BPA’s high-voltage transmission infrastructure.

Elliot Mainzer: We sell wholesale power directly to 136 preference customers and also sell surplus electricity and transmission capacity to six Northwest investor-owned utilities and other wholesale market participants in California and other western states. Those customers then deliver the power to millions of end users. Our preference customers cover a broad range of size and geography and include Seattle City Light, the Snohomish County Public Utility District (PUD), and Tacoma Power in the Interstate 5 corridor of Washington; Franklin PUD and Benton PUD in the TriCities region of Washington; Eugene Water and Electric Board in Oregon; Idaho Falls Power in southeastern Idaho; Flathead Electric Co-op in western Montana; Lower Valley Energy in southwestern Wyoming; and the Wells Rural Electric Company in Wells, Nevada. We provide surplus power and transmission for investor-owned utilities, including PacifiCorp, Portland General Electric, Puget Sound Energy, Avista, Idaho Power, and Northwestern Energy. We also transmit energy for independent power producers, including wind and solar developers and natural gas providers.

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PHOTO COURTESY OF BPA.

Municipal Water Leader: How many dams are in Bonneville’s system?

ADVERTISEMENT Finally, because we are a large transmission provider, it is important for us to try to understand the future needs of the grid. As we see large-scale renewable energy development, coal plants being retired, and changes in technology, we need to anticipate the kinds of generating and demand-side resources that are going to develop over the next decade. We need to get ahead of those changes through planning and expanding our transmission system so that we can continue to provide reliable service. I often say that transmission is the gateway to the future. As the backbone of the region’s highvoltage transmission system, we need to make sure that we are flexible and responsive to the future needs of the region.

Municipal Water Leader: What have been the recent changes in electricity prices, and why are they changing?

Elliot Mainzer: In last decade, we’ve seen a general reduction in the wholesale price of electricity with intermittent price spikes reflecting short-term shortages. This has been driven by a significant increase in the amount of natural gas available in this country and the consequent reduction in natural gas prices. Historically, natural gas prices have tended to set the price of electricity in the wholesale market.

There have also been significant buildouts of wind and solar energy and occasional periods of oversupply, which has had a dampening effect on wholesale electricity prices. We’re also still dealing with the after-effects of the Great Recession of 2008. Certain sectors and loads have not recovered from that economic hit. All those changes in supply and demand have affected the spot price of wholesale power.

However, it is important for people to understand that the comparison between the product we provide to our preference customers and what they can buy on the wholesale spot market is an apples-to-oranges comparison.

The firm power product we provide to our preference customers and deliver via transmission is a fully reliable, around-the-clock source of affordable, clean, flexible capacity that, for many of our customers, follows their load up and down throughout the entire course of the year. It also comes with strong commitments to energy efficiency and fish and wildlife protection, and of course, it is a virtually carbon-free product. While we’re big supporters of wind and solar energy and have worked hard to get them on the grid, those resources are variable. Their output fluctuates with the time of day and with wind patterns and doesn’t provide firm, dispatchable capacity. The firm, dispatchable, carbon-free, round-the-clock product we provide is different from what you find on the spot market.

We also establish the price of our service every 2 years, rather than every day or month, providing additional price stability—something that was highlighted last March when the spot price of power skyrocketed to $1,000 per megawatt-hour (MWh) during a period of high loads and tight supplies. At approximately $36/MWh, firm federal power is a solid deal for our customers.

As decisions are made to remove large numbers of coal plants and pass new policies that make it more difficult to build gas plants, the fundamentals of the market and regional supply-demand balance are shifting again. As supplies tighten up, wholesale electricity prices will respond accordingly, but it is becoming harder to guarantee what we refer to as resource adequacy—making sure that we have enough power capacity in the energy system to keep the lights on all the time. Resource adequacy is an economic, political, and moral challenge that the region has fortunately begun to address with a strong sense of urgency.

Municipal Water Leader: You mentioned that you are investing $800 million a year in your infrastructure. Does that come from your revenue, or is it federal money?

Elliot Mainzer: Our overall capital program is focused on sustaining and maintaining the core federal assets: the dams, turbines, rotors, generators, transmission towers, and control centers where we operate the transmission system. We also invest capital in information technology, facilities, and fish and wildlife programs. The money to cover the costs of the capital that we invest in federal assets is all collected from our customers. Although we are able to borrow through the U.S. Treasury, we do not receive appropriated dollars from Congress for the investments we make in the federal system.

Every dollar we spend is recovered through our rates and paid for by our power and transmission customers.

We’re also spending about $25 million every 2 years on an ambitious grid modernization initiative. That effort is focused on the application of modern technology and automation to system operations so that we can effectively participate in the emerging markets that are much more computerized than was historically the case.

Municipal Water Leader: What is your message to Congress?

Elliot Mainzer: For over 80 years, Bonneville’s role has been to serve as a steward of important federal infrastructure that serves as a fundamental underpinning of the health and vitality of communities in the Pacific Northwest. Our goal is to continue meeting our stewardship responsibilities and to maintain our role as an engine of the Pacific Northwest’s economic prosperity and environmental sustainability for years to come. We place great value on our strong working relationships with Congress and our colleagues throughout the federal government. Their ongoing support will continue to be a vital part of our success in the future. M Elliot Mainzer is the administrator of the Bonneville Power Administration.

For more information about BPA, visit bpa.gov.

MUNICIPALWATERLEADER.COM

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Columbia Basin Hydropower’s Major Pumped Storage Plans

Banks Lake, Washington.

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

Tim Culbertson: I have 49 years of utility experience, primarily in the Northwest. I worked for three large investor-owned utilities for 30 years and then worked for 12 years on the public utility side before moving to the irrigation district, where I’ve been for 7 years. I primarily focused on existing hydro projects but also worked to increase the portfolio of hydro projects of the three irrigation districts that make up the Columbia Basin Project. Today, I am manager of project development for Columbia Basin Hydropower.

Municipal Water Leader: Please tell us about Columbia Basin Hydropower and its history.

PHOTO COURTESY OF ERIC PRADO.

cross the Pacific Northwest and California, coal- and gas-fired thermal combustion power plants are being retired and replaced by renewable wind and solar power facilities. This environmentally friendly policy, however, is causing a logistical problem. The intermittent nature of wind and solar generation threatens to result in a 7,500–10,000 megawatt (MW) shortfall in power generation capacity. There is only one technology that can reliably address a problem of this scale: pumped storage. Columbia Basin Hydropower is planning a major pumped storage project at Banks Lake in Central Washington with a capacity of 500 MW. In this interview, Columbia Basin Hydropower’s manager of project development, Tim Culbertson, tells Municipal Water Leader about the genesis of the Banks Lake project, the arduous permitting process his agency is now going through, and how the Northwest can address its energy dilemma.

Tim Culbertson: Columbia Basin Hydropower is a subdivision of the three irrigation districts that make up the Columbia Basin Project: East Columbia Basin Irrigation District, South Columbia Basin Irrigation District, and Quincy–Columbia Basin Irrigation District. We are considered a municipality under the statutes of the State of Washington. Our job is to operate and maintain five of the seven hydroelectric projects that the three irrigation districts own. The other two projects that the three districts own are operated and maintained by Grant County Public Utility District. I came on board because the irrigation districts had filed to develop a number of small conduit projects ranging in size from 1 to 3 MW. We are currently proposing the development of five of those conduit projects in the near future, when and if we find the right technology to make them economical. Along with that, we have been working on the development of a large pumped storage project known as the Banks Lake Pumped Storage Project.

Municipal Water Leader: What is the motivation for the Banks Lake Pumped Storage Project?

Tim Culbertson: The motivation is twofold. To provide some context, in November 2013, there was a circuit-breaker explosion in the Keys Pumping Plant, which is responsible for moving water from Lake Roosevelt into Banks Lake, the priming reservoir for all the water that supplies the approximately 700,000 acres of the Columbia Basin Project.

It took the Bureau of Reclamation 4–5 months to repair the circuit breaker in the Keys powerhouse. Fortunately, at the time that the explosion occurred, the irrigation season was over, but we had to ask what would have happened had it occurred in May or June, when the irrigation season was in full swing. It could have resulted in all 700,000 acres of the Columbia Basin Project running out of water, with losses potentially reaching $6 billion. So one of the motivations to build another pumped storage plant is to serve as a primary or backup facility to move water from Lake Roosevelt into Banks Lake.

Right now, however, the real driving force for looking at pumped storage is the needed for flexible capacity, especially in the Northwest, but along the entire West Coast. What’s driving that is the ongoing construction of renewable power facilities, primarily wind and solar. In addition to that, a lot of the states have taken an aggressive approach to doing away with thermal-based combustion turbines, primarily fired by coal, gas, and oil. In the Northwest, thermal-based coal plants will disappear entirely sometime between 2025 and 2030. The forecast right now is that the Northwest alone will be short around 7,500–10,000 MW of flexible capacity. A lot of people are discussing solving this issue with batteries. However, battery technology hasn’t advanced to the state where you could count on them to provide 7,500–10,000 MW of capacity. The only other resource that can provide that kind of flexible capacity is pumped storage.

There are probably three or four pumped storage projects on the drawing board across the Northwest, including ours. Ours is distinctive because we already have two large reservoirs. Most pumped storage projects would have to construct one or two new reservoirs.

Municipal Water Leader: What kind of new infrastructure would the Banks Lake Pumped Storage Project require?

Tim Culbertson: It would require an intake, an outlet, and a penstock that would connect Banks Lake, which has a storage capacity of 700,000 acre-feet, to the lower reservoir, Lake Roosevelt, which has a capacity of 5.2 million acrefeet. In fact, there would be two penstocks, 35 feet in diameter and approximately 7,000 feet long. On the lower side of the penstocks, in between Banks Lake and Lake Roosevelt, there would be an underground powerhouse capable of generating more than 500 MW of energy.

Directly above the powerhouse, on the surface, there would be a substation connected to the Grand Coulee substation, which is one of the major substations in the Northwest. It’s important to note that pumping the water between these two lakes would be a nonconsumptive use.

We envision generating power primarily in the daytime and then pumping water back into Banks Lake at night.

One of the other real advantages of this project is that whereas most pumped storage projects are built to provide capacity for 7–10 hours a day, this facility could, under the right operating conditions, generate 500 MW for up to 70 continuous hours.

Municipal Water Leader: How would this project be funded?

Tim Culbertson: We estimate that the project will cost $1.2–1.5 billion. There is a lot of equity capital out there looking for looking for a home. We are in discussions with a number of large financial investors, and we hope to have some in place shortly—one, two, or three of them, but the fewer, the better—to provide the development capital. We will need around $30 million and about 2 years to get through the licensing/permitting phase and be ready for construction.

One of the complicating factors is that this project, unlike others, requires more than just a Federal Energy Regulatory Commission (FERC) permit. We are under a FERC licensing process framework and we have a FERC preliminary permit, but we will also require a lease of power privilege with the Bureau of Reclamation.

That is because Reclamation has jurisdiction over Lake Roosevelt and FERC has jurisdiction over Banks Lake.

Those two processes are lengthy and do not align well, meaning that they will require additional time and money. We initially thought that FERC would relinquish jurisdiction, allowing us to escape its licensing process, but that turned out not to be true. The only way to avoid this duplicative process would be through legislation. We MUNICIPALWATERLEADER.COM

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ADVERTISEMENT had legislation that passed the House of Representatives in 2017 but never passed the Senate. Now we’re starting over. Senator Maria Cantwell has proposed S. 1751, and it has gone through the Energy and Commerce Committee in the Senate. She’s pushing for that bill to be acted upon. On the House side, H.R. 537 has been proposed by Congressman Doug Lamborn. Senator Cantwell is working with the office of Congressman Frank Pallone, who is the chair of the House Energy and Commerce Committee, to move it as well. Those bills state, in pretty simple language, that if the project uses two Reclamation reservoirs, which Banks Lake and Lake Roosevelt are, then the project falls under the jurisdiction of Reclamation. The bills also include a draft memorandum of agreement negotiated with the Colville and Spokane Tribes to support the Banks Lake Pumped Storage Project. If those bills pass, we would be exempted from the FERC licensing process. We’ve been working on licensing nonstop for over 3 years.

Municipal Water Leader: How would the Banks Lake Pumped Storage Project help address fluctuations in the energy provided by various renewable sources? Would Columbia Basin Hydropower be selling power to the grid?

Tim Culbertson: We’re in discussions right now with three utilities in the Northwest, two public and one investor owned. They would sign up for a 40-year power purchase agreement. We would be a part owner of the project along with the other equity investors, and all the output of the plant would go to these three utilities. They would have the ability to generate power based on their individual needs.

Municipal Water Leader: How does project compare to other pumped storage facilities in the region or across the country?

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Municipal Water Leader: What is your vision for the future of the project?

Tim Culbertson: Well, my vision is that this is not just a good thing for the irrigators. I’ve been in the industry for almost 50 years. I don’t see a lot of good answers right now to the question of how we’re going to meet the capacity needs of this region alone. The situation in California— with which we’re inextricably linked when it comes to energy supply and demand—is even worse. Those of us who have worked in this industry for a long time have seen this train wreck coming. Unfortunately, policymakers have been telling us to get from point A to point B without any clear idea of how to get there. We’re doing away with all the coal plants and replacing them with wind and solar facilities whose generation is intermittent. Simultaneously, the commissions that regulate investor-owned utilities have banned new combustion turbines, and some utilities believe they will soon be required to get rid of existing combustion turbines. If that happens, the 7,500– 10,000 MW capacity shortfall we are already dealing with is going to increase significantly. People are wondering where that capacity is going to come from.

Today, everybody’s talking about pumped storage.

They’d better get serious about it, because pumped storage projects take a long time to permit and construct. If you get the right kind of development company, you can construct one in 4–5 years, but you also have to add 2 years of permitting. It’s 2020, and we’re facing a huge capacity shortfall that will get even larger in 2025. We need to be taking action. Three or four other pumped storage projects have been proposed in the Northwest. I don’t necessarily view them as competitors to our project, because most of them have a capacity of 300–500 MW. Even if we had five pumped storage projects, each with a capacity of 500 MW, we’d still be facing a capacity shortfall of at least 5,000 MW. Where’s the rest of it coming from? We have to do better at planning for our future. This can’t remain just a discussion. We need to start taking action, or we’re going to have a real problem. M

Tim Culbertson is the manager of project development at Columbia Basin Hydropower. He can be contacted at tculbertson@cbhydropower.org.

PHOTO COURTESY OF COLUMBIA BASIN HYDROPOWER.

Tim Culbertson: The only other pumped storage project in the Northwest is the Keys plant, which is quite old. There were six original units that were built strictly for pumping.

Later, they built six additional units for generation. As you may know, it takes more energy to pump the water up the hill than the amount of energy you generate by letting the water down again, but it’s the value of capacity that makes pumped storage projects worthwhile. The Keys pumping plant is 60 percent efficient. It loses 40 percent of its efficiency pumping the water up the hill. Our new facility will use a variable-speed pump generator that has been used in Europe for probably 20 years but has not been previously deployed in the United States. Depending on the elevation of the reservoirs and the differential between the two reservoirs, which we call head, our units would be 75– 82 percent efficient—significantly more efficient than the Keys pumping plant. The U.S. Department of Energy has a loan program with $4 billion available for large projects that use new technology. You’re effectively allowed to borrow

money from Energy at a 2 percent discount rate to our borrowing rate. The equipment we propose to use would likely qualify for its low-interest loan program. That could could be significant for the overall long-term financing of the project.

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Implementing Oceanus’s Pumped StorageDesal Plant in Chile

Oceanus's IPHROCES system.

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esalination plants typically deal with two major problems: the desalination process requires a large amount of energy, and it results in a large amount of brine, which is difficult to dispose of safely. Oceanus Power & Water has come up with an innovative solution to this problem: combining a pumped storage facility, which stores power in the form of elevated water that can be used to drive turbines, with a desalination facility. Gravity power alone can dramatically reduce the energy demands of the desalination process, while the resulting brine can be reinjected into the stored seawater as it is released back into the ocean, diluting it on site. Chile, a country that has been suffering from decades of drought and which is also moving forward with an ambitious decarbonization plan, has turned out to be a prime location for Oceanus’s technology.

In this interview, Joan Leal, the chief development officer of Oceanus Power & Water and the president of its South American subsidiary Oceanus Energía y Agua de Sudamérica, tells Municipal Water Leader about the benefits of Oceanus’s solution and why it is such a good fit for Chile.

Joan Leal: Working in engineering and management consultancy for many years in several emerging economies

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PHOTO COURTESY OF OCEANUS.

Municipal Water Leader: Tell us about your background and how you came to be in your current position.

gave me a chance to see how important infrastructure and energy developments can be for society when the primary focus is on serving people’s needs through sustainable and innovative solutions. Looking for the right integration between society and infrastructure, I went to Stanford University to immerse myself in an innovative and entrepreneurial environment. My time in Silicon Valley took me to the roots of the world’s energy and water challenges, giving me a deep understanding of the nexus of infrastructure, energy, water, and technology.

My journey in the infrastructure and energy sectors and my passion to make a difference in society led me to become an entrepreneur. I joined Oceanus Power & Water and developed an integrated, global, and sustainable solution capable of addressing the major challenges of the world today—fresh water supply and clean energy storage. As chief development officer, I’ve led the development of an integrated energy storage and water production solution, filed several patents, built relationships with power and water utilities, negotiated offtake agreements and term sheets, raised capital, led project development, and participated in the definition of regulatory frameworks in different regions.

I hold a bachelor of science and master of engineering in civil engineering from universities in Chile, and I am a graduate of Stanford University’s Graduate School of Business.

ADVERTISEMENT Municipal Water Leader: Tell us about Oceanus and its history.

Joan Leal: Oceanus Power & Water is an infrastructure development company focusing on delivering new water, carbon-free energy, and energy security. The company was first envisioned in 2014, inspired by the challenge of delivering cost-effective energy storage to help manage the growing supply of solar energy in California. In 2015, Oceanus Power & Water was formed to pursue the development of a new kind of large-scale pumped hydro storage facilities.

In April 2016, it completed a desktop study evaluating the integration of seawater pumped hydropower energy storage and seawater reverse osmosis (RO) desalination into a single facility. The study found that the integration and colocation of these existing, bankable technologies would have significant economic and environmental benefits. The resulting idea was named the Integrated Pumped Hydroelectric Reverse Osmosis Clean Energy System (IPHROCES). In 2016, Oceanus launched Oceanus Agua y Energía México, its first subsidiary, and started looking for project opportunities in Mexico. In 2017, Oceanus launched its first project in the Mexican state of Sonora. In 2018, Oceanus launched its South American subsidiary, Oceanus Agua y Energía de Sudamérica, in Chile; I took the role of president.

In 2018–2019, Oceanus completed conceptual engineering studies for the sites in Mexico and Chile, concluding that the selected sites are viable locations for the IPHROCES technology. In addition, Oceanus has identified several locations in the United States to implement IPHROCES, including sites in Southern California, Puerto Rico, and Hawaii. The facilities are appropriate for any location where a large population resides in a semi-arid coastal area.

Municipal Water Leader: Please describe IPHROCES and how it differs from existing installations.

Joan Leal: The Oceanus IPHROCES solution combines seawater pumped storage with seawater RO to create a single, integrated water-production and energy-storage system.

IPHROCES has a seawater-intake facility located on the coastline, which feeds seawater into the powerhouse. From the powerhouse, the seawater is pumped into the upper storage reservoir using conventional hydropower technology, typically reversible pump turbines, using surplus electricity from the power grid during times of peak renewable-energy generation, or alternatively electricity from onsite renewable generation. During times of low renewable-energy generation, this water is released downhill, driving the pump turbines in generate mode and producing clean, carbon-free electricity. A portion of the water in the upper reservoir is also constantly discharged via the IPHROCES system’s powerhouse to feed the RO desalination plant, taking advantage of the pressure provided by the water column’s elevation to remove the salt molecules and create fresh water.

IPHROCES has a number of advantages over conventional systems. It provides safe and robust energy storage and generation. The colocation and integration of pumped storage hydro with RO desalination achieves demonstrable cost reductions, energy efficiency, and emissions reductions. Depending on the location and on site-specific conditions, Oceanus expects to be able to reduce capital and operating costs by 20–30 percent, thereby providing the lowest levelized cost of energy storage and lowest levelized cost of water.

In addition, the pumped hydro outflow quickly and efficiently dilutes the waste brine from the desalination process. The brine discharge is blended with discharge flows from the pumped storage facility so that the total discharge is diluted to ambient salinity levels by the time it flows back into the ocean. This brine management system allows IPHROCES to operate in compliance with California Ocean Plan standards.

The fact that IPHROCES performs desalination using the hydraulic head created by storing water at a higher elevation means that it has a smaller energy footprint than conventional seawater RO plants. It uses 2.4 kilowatt-hours (kWh) of energy per cubic meter (m3) of water, versus the 3–5 kWh/m3 used by conventional plants. In addition, the 100 percent hydraulic RO system allows for a recovery rate of over 55 percent, higher than that of conventional plants.

The IPHROCES process allows for the efficient use of excess renewable energy generation, using it to power a safe storage system and to create clean water without the need for exotic material batteries or fossil fuel consumption.

Municipal Water Leader: Please tell us about the project you are currently developing in Chile. How much water and energy will it produce?

Joan Leal: When I first joined Oceanus in early 2017, I evaluated market opportunities for Oceanus’s solution around the globe. There are two important aspects to consider when evaluating where in the world IPHROCES could be viable.

First, our solution requires a specific geography: elevations of around 350 meters (1,150 feet) close to the coast, including a topography that allows us to build on-surface penstocks so that we can avoid tunneling and boring and thereby minimize costs and construction risks. Second, there must be a demand for both fresh water and energy storage. This dual demand is more common that one might think, since water needs in arid or semiarid regions of the world occur in the same areas where renewable energy resources are abundant and hence the need for storage is growing. Our initial focus has been the Americas; we have been able to identify many potential markets for our solution, including in Southern California, northern Mexico, the Caribbean, southern Peru, and northern Chile.

Why is Chile an appropriate location? First, it is experiencing one of the most severe droughts ever recorded.

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The benefits of Oceanus’s IPHROCES system.

32 | MUNICIPAL WATER LEADER

Municipal Water Leader: Why is Oceanus’s product appropriate for municipal water agencies or providers?

Joan Leal: One of the limitations that municipal water agencies in Chile face when implementing desalination projects is the high cost of desalinated water in comparison to current regulated potable water tariffs. Oceanus’s IPHROCES facility delivers the desalination of water at a low levelized cost, enabling its implementation not only for industrial users but also for municipal water agencies.

Oceanus’s primary focus is to pass the benefits of our innovative and proprietary solution to the final users of both potable water and electricity. Besides the economic benefits, Oceanus’s solution is superior in terms of energy consumption and brine management, key challenges of the current desalination industry.

Municipal Water Leader: Where are your other planned projects?

Joan Leal: Oceanus’s flagship project is Oceanus IPHROCES Chile. We are also developing projects in Southern California and in northern Mexico. Oceanus’s solution can be applied globally and at different scales.

We are constantly looking for new opportunities in other regions, including Australia and Central America. M Joan Leal is the chief development officer at Oceanus Power & Water and the president of Oceanus Energía y Agua de Sudamérica. He can be contacted at joan@oceanus.pw.

PHOTOS COURTESY OF OCEANUS.

The precipitation deficit in 2019 in the north of the country, according to Chile’s Directorate General of Water, was around 80 percent. Northern Chile is where most of the country’s mining activities are located, which has historically increased the need for new sources of water while also contributing to population growth. In addition, desalination in Chile is a mature market. Currently, 5,500 liters per second (l/s) of desalinated water are produced in Chile (around 194 cubic feet per second, or cfs). In the next 5 years, that figure will grow by 160 percent. There are 24 desalination plants in operation in the country, as well as 22 other projects at different stages of development. Around 80 percent of the existing installed desalination capacity is used by industrial users and mines. The municipal water agencies in the north have already started implementing desalination as the main source of potable water. Aguas Altiplano and Aguas Antofagasta already operate RO desalination facilities in the cities of Arica and Antofagasta, respectively, and Aguas Chanar/Econsa is building a 1,200 l/s (42 cfs) desalination facility in the region of Atacama.

The electric market in Chile has been designed in such a way that the investment in and operation of the energy infrastructure are carried out by private operators, promoting economic efficiency through competitive markets in all the nonmonopolistic segments. Today, the energy sector is fully deregulated. The electrical grid in northern Chile used to be highly dependent on coal, and around 20 percent of current installed capacity still comes from coal thermo plants. However, Chile is committed to an aggressive decarbonization plan that aims to decommission 100 percent of coal thermo plants by 2040 in favor of renewable generation. As of 2019, photovoltaic solar installations represent over 10 percent of the country’s energy capacity, and renewable generation capacity as a whole makes up close to 20 percent. This transition in the energy sector is increasingly creating a need for longduration and large-scale energy storage solutions. Chile is

also one of the first countries in the world to regulate energy storage. Its new energy storage regulation is intended to promote new energy storage facilities, including pumped hydro storage facilities.

Oceanus is focusing on northern Chile due the severe water scarcity there; the fast penetration of renewable energy into the local market; the lack of energy storage capacity; and the region’s geography, which is characterized by high cliffs along the coast. Oceanus has teamed up with one of the largest municipal water agencies in the country to evaluate and develop a desalination facility using Oceanus’s IPHROCES solution. The desal plant will produce over 1,000 l/s (35 cfs) of reliable freshwater and will cover 100 percent of the municipal water agency demand. The facility can also produce water for industrial users in the region.

In addition, the facility will produce 200 megawatts of dispatchable energy to enable renewable energy penetration in the region and to further the country’s decarbonization plan. It will produce up to 16 hours of energy storage per day. According to the new Chilean energy storage regulation, the Oceanus facility will receive revenue from energy arbitrage, capacity payments, and ancillary services.

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AECOM’s Holistic Solutions to Cities’ Water, Waste, and Energy Problems

AECOM has been partnering with the New York City Department of Environmental Protection for over 40 years.

AECOM is helping to build a centralized wastewater treatment plant in Hong Kong.

A

Municipal Water Leader: Please tell us about your backgrounds.

34 | MUNICIPAL WATER LEADER

Beverley Stinson: I’m a senior vice president with AECOM and have been with the company for 22 years. My primary area of technical focus is wastewater treatment, and I currently lead AECOM’s North American wastewater team and also serve the other leads across the globe. One of the areas our group focuses on is waste to energy.

Paul Storella: I’m a senior vice president as well and have been with the company for 34 years. I work in our water business line and focus on running the water business in the New York City area. I have also been AECOM’s client account manager for the New York City Department of Environmental Protection (DEP) for 21 years. I’ve worked with it on some of its biggest water and wastewater projects, from its nitrogen-removal program to its combined sewer overflow program. AECOM has been partnering with the New York City DEP for over 40 years.

PHOTOS COURTESY OF PIXABAY.

ECOM is one of the largest consulting companies in the world, and works with major companies and municipalities to design, finance, build, and operate transportation, water, and energy infrastructure. Its immense spectrum of activities means that it can often find innovative solutions to big problems by integrating solutions from a number of its divisions. For example, by colocating and integrating solid waste, wastewater, and energy recovery services, it can create smaller and more efficient facilities. It is involved in projects of this nature from New York to Hong Kong and Singapore.

In this interview, AECOM Senior Vice Presidents Beverley Stinson and Paul Storella tell Municipal Water Leader about how the company is pushing progress by finding new ways to use proven technologies and by integrating its various services.

ADVERTISEMENT Municipal Water Leader: Please tell us about AECOM. Beverley Stinson: AECOM is one of the largest consulting companies in the world. We work in over 135 countries.

Our business lines and service offerings include transportation, which covers everything from airports and railways to roads, ports, and harbors; water; environmental services; buildings and places; and energy. We have our own construction services as well, including our own inhouse construction company. AECOM works in a broad range of fields, and in general, it is number 1 in all the markets it does business in, according to Engineering News Record. We connect expertise across services, markets, and geographies to deliver transformative outcomes. We have designed, financed, operated, and managed projects and programs that significantly improve people’s lives. The tagline for AECOM is that we are built to deliver a better world. We are strongly committed to enhancing the built environment globally.

Municipal Water Leader: Please tell us about your work in the waste-to-energy sector.

Beverley Stinson: The way we look at waste to energy is increasingly connected to the concept of a circular economy. One thing Paul has done is to integrate some of our services across our energy and business lines.

Previously, coming from the water side, I was familiar with biosolid energy recovery from wastewater, the codigestion of food waste and organic material, and the recovery of energy from food waste. Under Paul’s leadership, we’ve been looking a lot more at waste in general—solid waste, wood waste, landfill waste—and asking how we can integrate that into our business using technologies such as gasification, pyrolysis, and codigestion. How can we recover more energy and resolve many of the big issues that our clients are facing in urban areas?

Paul Storella: One of the big challenges in a place like New York is the limited space in landfills for solid waste. Cities are running out of space, so it’s great that they’re thinking about separating their organic waste. New York does some composting now, and it is piloting adding food waste to the digesters in its wastewater treatment plants. AECOM is involved with the DEP and with the National Grid on a project to take the digestor gas and cleaning it up to put back into the grid for home heating.

Beverley Stinson: They have been using the excess capacity at wastewater treatment plants for the codigestion of emulsified food waste. That boosts the amount of carbon going to the digesters. Paul’s team has used a relatively novel gas cleanup mechanism to inject the gas that is produced by codigestion directly into the gas pipeline.

That sustainable, green waste source can produce enough

energy to power 5,000 homes in New York City. It reduces greenhouse gas emissions while addressing the limitation on natural gas supplies in the New York metro area. This is the largest installation of this pressure stream absorption technology in the nation.

Municipal Water Leader: What role do new legal regulations or restrictions on landfill waste play in this development?

Beverley Stinson: Seven states now have some regulations with regard to the diversion of organics, or food waste, from landfill, but more will have them soon. Those seven states, along with seven municipal agencies, are setting a leadership standard for the redirection of food waste. The issue of landfill capacity is pressing in places like Florida, where nitrogen and phosphorus from biosolids were leaking back into waterways and creating huge algal blooms, which ultimately forced the governor to call a state of emergency.

More generally, there’s a huge push to address greenhouse gas emissions and to introduce renewable energy sources and zero-carbon electricity. Many states are on a mission to lower greenhouse gas emissions from their power sources; Los Angeles, for instance, wants to be using entirely zerocarbon electricity by 2045, which is a huge commitment.

Paul Storella: New York City wants to reduce its greenhouse gas emissions by 80 percent by 2050, with an interim goal of reducing them by 40 percent by 2035. There are a whole set of ripple effects involved: For example, by making a building more energy efficient, you can reduce the amount of energy and fossil fuels needed downstream.

Beverley Stinson: AECOM is supporting Metro Vancouver in a project it is considering, which would involve taking all the biosolids, food waste, fats, oils, and greases that often clog up the sewers and using it to produce what it calls biocrude. It would use a high-pressure, high-temperature treatment to produce what is essentially crude oil. After going through the refinery process, that biocrude would enter the conventional hydrocarbon cycle as jet fuel or petroleum or whatever. A process like that would leave zero waste left behind. It would also allow for the recovery of phosphorus, which is a finite resource as well. We’re seeing innovative technologies like these that would allow us to go from recovering 40–50 percent of the carbon energy in our biowaste all the way to 80–100 percent, while recovering things like phosphorus and nitrogen, which are great fertilizers, as well. There is also a lot of innovation in the treatment of solid waste and wood waste involving gasification and pyrolysis.

Paul Storella: To reflect that shift, New York City has actually renamed its water treatment plants water resource recovery facilities.

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ADVERTISEMENT Municipal Water Leader: Have these new processes been enabled by new discoveries, or are they the application of technologies that have always been known to be theoretically feasible?

Beverley Stinson: It’s a bit of a mix. Thermoliquefaction was being tested under the auspices of the U.S. Department of Energy for 30 years, but with fuel sources such as algae. Five years ago or so, we started to wonder if the same technology, which was well advanced by that stage, could be used on biosolids. We adopt technologies that were perhaps developed for one particular application and use them for other types of waste that are causing a concern in our business. Technologies such as gasification have been around for a long time—the gas lamps in Victorian London were powered by the gasification of coal. Now we’re using similar technology to produce highquality gas that can be stored and easily transported in pipelines. It doesn’t actually involve burning the carbon— we recover the carbon energy in the form of a gas without incinerating or burning it. We’ve known about a lot of these technologies for a long time, but we haven’t always developed them. New materials, new challenges, and an emphasis on sustainability and energy recovery have pushed them forward.

There are some new technologies as well. Per- and polyfluoroalkyl substances (PFAS) leaching from landfills are an increasing concern. We’ve always known that these compounds are difficult to manage and contain. But now that we can completely avoid putting some of this waste into landfills and instead immediately recover energy while also eliminating PFAS contamination, why would we not begin to move in that direction? The increasing salience of that issue helps advance the discussion.

Municipal Water Leader: Is there a size at which deriving energy from waste treatment starts to make sense for a municipal water utility?

36 | MUNICIPAL WATER LEADER

Paul Storella: The vision is to take a whole metro area and incorporate our solutions to food waste, algae, and wastewater treatment to create a zero-waste, carbon-neutral city powered by renewable energy. By combining our technologies, we can provide a comprehensive solution to a lot of the waste problems that a major city has.

Beverley Stinson: I would add that the opportunity to recover finite resources like phosphorous from waste, rather than putting it in a landfill, adds to the incentives to move forward with some of these innovative technologies.

We currently import 10 percent of our phosphorus from overseas every year.

Another part of our vision is to centralize and regionalize a lot of these facilities, thus making them more efficient.

One of the places where we’ve been doing this is Hong Kong, where we are combining multiple facilities into a centralized regional facility. Because a lot of the innovative technologies in wastewater treatment allow for smaller, faster, cheaper facilities, we’re able to open up all sorts of waterfront property in Hong Kong that was once used for an old-fashioned wastewater treatment plant. We are actually putting our new facilities inside a man-made cave in a nearby mountain. The entire facility will be hidden from view. It will have a smaller footprint and be more sustainable in its energy use. We will colocate the source-separated organics and fats, oils, and greases. This facility will be similar to one we’re building in Singapore.

I think the beauty of the way we do things at AECOM is that we can bring together the skill sets of our environmental group, which is looking at solid waste; our water team, which is looking at water and wastewater; and our energy team, which is looking at the cutting edge of energy recovery technologies and produce holistic solutions to multiple problems and yield benefits such as recovering waterfront property, parkland, and green space. I think we’re going to see a lot more of that type of activity across all of North America. By bringing together multiple skill sets, we can deliver on this vision. M

Beverley Stinson and Paul Storella are senior vice presidents at AECOM. For more information about AECOM, visit aecom.com.

PHOTOS COURTESY OF AECOM.

Beverley Stinson: According to an energy optimization evaluation research study we did for the Water Research Foundation, wastewater treatment facilities that process 5 million gallons per day (MGD) or more can costeffectively implement proven technologies such as anaerobic digestion and combined heat and power. That is a purely economic analysis. When you add in other drivers, such as the desire to reduce greenhouse gas emissions, trucking, waste, sludges, and so forth, it could look even more attractive today than it did 5 years ago. Some of these new technologies tend to be a little more complicated than just straightforward anaerobic digestion or combined heat and power—they tend to be the types of technologies that larger facilities, maybe in the 20–30 MGD range, would be thinking about.

Municipal Water Leader: What is your vision for the future?

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Upcoming Events February 4 Winter Meeting, Kansas Water Congress, Topeka, KS February 5–7 Annual Conference, Montana Water Resources Association, Anaconda, MT February 10–13 Annual Conference, Nevada Water Resources Association, Las Vegas, NV February 11–13 34th Annual Water Expo and Conference, Fargo, ND February 20–22 Annual Meeting and Conference, Family Farm Alliance, Reno, NV February 22–27 New Zealand Education and Trade Tour, Irrigation Leader February 25–27 Annual Washington, DC, Conference, Association of California Water Agencies, Washington, DC February 26–28 Annual Salinity Summit, Multi State Salinity Coalition, Las Vegas, NV March 3–4 Annual Conference, Texas Water Conservation Association, Fort Worth, TX March 12 Legislative Symposium, Association of California Water Agencies, Sacramento, CA March 16–18 Annual Workshop, Utah Water Users Association, St. George, UT March 23–25 Texas Water Day, Texas Water Conservation Association, Washington, DC

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