Through the agreement, which kicked off in July, FirstLight will deliver Burlington more than 54 GWh of hydropower and associated VT-1 renewable energy credits through 2025 from FirstLight’s Shepaug Generating Station in Connecticut.

Shepaug is Connecticut’s largest hydroelectric generation station and is also the second largest source of carbon-free electricity in the state, located on the Housatonic River in Newtown and Southbury. Built in 1955, it has a 42.6 MW capacity.

“Our new collaboration with FirstLight serves as another example of Burlington Electric Department’s and the City of Burlington’s commitment to continuing to source 100% of our power from a mix of different types of renewable generation, while maintaining reliability for our customers,” said Darren Springer, BED General Manager.

BED has purchased 100% of its power supply from renewable sources since 2014. As the city transitions away from fossil fuels in the thermal and ground transportation sectors largely through electrification, it expects electricity demand to grow.

To support this increased demand while ensuring its energy mix remains 100% renewable, BED is looking to strategic partnerships like this new PPA with FirstLight to secure additional clean power generation.

“As we electrify more of our heating and transportation needs, BED will continue to look for opportunities to source renewable power to meet demand,” he said.

“We are grateful for thoughtful partners like FirstLight, whose reliable, cost-competitive, clean electricity generation supports our climate goals in Burlington and helps to decarbonize the New England grid.”

FirstLight has a diversified portfolio that includes over 1.65 GW of operating renewable energy and energy storage technologies and a development pipeline with more than 4 GW of solar, battery, hydro, onshore wind and offshore wind projects. FirstLight specializes in hybrid solutions that pair hydroelectric, pumped hydro storage, utility-scale solar, large-scale battery and wind assets. The company’s mission is to accelerate the decarbonization of the electric grid by supporting the development, operation and integration of renewable energy and storage to meet the world’s growing clean energy needs and deliver an electric system that is clean, reliable, affordable and equitable.

Georgia Power is celebrating Generation Appreciation Month, a time to recognize the more than 1,100 team members who “work tirelessly in power plants across state to keep reliable energy flowing to the grid on hot summer days, cold winter mornings and every hour in between.”

“In life, as well as with Georgia Power’s power generation facilities, there is no one-size-fits-all option,” said Rick Anderson, senior vice president and senior production officer for Georgia Power. “From the existing facilities that have powered Georgia for decades, to newer sources of generation such as renewable energy, cleaner natural gas and battery storage, Georgia Power’s diverse generation mix continues to evolve to meet the needs of a growing Georgia. To keep the energy flowing, we need a workforce that is just as advanced and diverse.”

Based on available opportunities, a career in power generation offers many possibilities for those who join the team, Georgia Power said. Career paths exist in the areas of operations, maintenance, electrical, instrumentation, engineering and more. Last year, the company hired over 80 team members across generation facilities and expects the hiring trend to continue in the coming years. Strong training programs exist in Operations, along with apprenticeships in Mechanical and Electrical, which develop experienced journeymen who work safely to keep energy flowing to the grid, 24/7.

Georgia Power also highlighted the “continuous learning” it offers, including the Rockmart training facility where electrical, mechanical, and instrumentation and control technicians hone their skills each year. In 2023, this facility conducted nearly 3,000 hours of both hands-on and classroom instruction. Subject matter experts from both Southern Company and external entities visited to assist in this training program.

The U.S. Department of Energy (DOE) conducted supply chain “deep dives” on renewable energy technologies, including hydropower and large power transformers. Since the deep dives were published, the Water Power Technologies Office (WPTO) has focused on improving its understanding of the hydropower supply chain and developing strategies for addressing supply chain challenges. The report, Hydropower Supply Chain Gap Analysis, was prepared by NREL for DOE and WPTO.

Because the challenges outlined in the deep dives are most acute for large systems greater than 100 MW, NREL’s report focuses on large systems but expects that its recommendations will improve the supply chain for all hydro systems regardless of scale. Additionally, since the federal government owns almost 50% of the nameplate capacity for conventional hydropower systems with 40% (18 GW) of these units being at least 100 MW, the federal fleet is used to prime the development of the supply chain for the rest of the industry, NREL said.

State of the supply chain

The analysis focused on the upstream and midstream sectors of the hydropower supply chain, as they have “limited” domestic capacity, NREL said.

Upstream supply chain components include raw material extraction, concentration, and processing into engineered materials. The U.S. has strong iron mining and steel production capabilities, NREL said, but it has limited to no mining of the trace metals used in steel, and it imports more than 40% of its copper. Additionally, there are only two domestic facilities with forging capabilities for large hydropower shafts (50-75 tons) and a single domestic foundry that can cast large turbine runners greater than 10 tons.

In the midstream supply chain, the first stage is composed of the manufacture and assembly of hydropower components like hydrogenerators and turbines. Some U.S. companies manufacture components, but international competition is “intense,” NREL said, and acquiring components for 100-MW or larger systems is difficult to procure domestically — only one foundry is capable of producing castings greater than 10 tons, and no domestic manufacturers exist for hydrogenerators greater than 20 MW.

Gap analysis

Five “major” gaps in the domestic hydropower supply chain were identified in the report.

1. Unpredictable and variable demand signals

The development of a domestic hydropower supply chain is held back by an unpredictable and highly variable demand for materials and components, NREL said. Hydropower systems typically have long lives, so replacements and refurbishment schedules have cycles that last years or decades.

2. ‘Severely’ limited or nonexistent domestic suppliers for hydropower
materials and components

There are no domestic facilities for hydrogenerator manufacturing greater than 20 MW, and a single facility for less than 20 MW.

The following materials and components only have a single domestic facility or supplier:

• Windings greater than 100 MW for large hydrogenerators
• Large forgings (50-75 tons) for large hydropower shafts
• Foundry with casting capabilities greater than 10 tons for large turbine runners
• Grain oriented-electric steel (GOES) for U.S. transformer manufacturers

Additionally, there are two domestic suppliers of non-oriented electric steel (NOES) for U.S. hydrogenerator manufacturers

3. Federal contracting procedures and domestic content laws

The report identified several procurement regulators and/or general practices that NREL says inhibit the development of the domestic hydropower supply chain, including bonding requirements, specifying pre-contract design work, all-inclusive contracts, and focusing exclusively on the initial capital outlay rather than the total project life cycle cost.

4. Foreign competition, foreign subsidies, and ‘ineffective’ trade policies

NREL said discussions with companies in the hydropower industry highlighted “inequitable” competition from foreign companies and “ineffective” trade policies as other issues in the hydropower supply chain.

Several companies noted that other countries subsidize their steel industries, and China develops “pods” of manufacturing capability to shorten the supply chain, making it more cost-effective.

5. Shortage of skilled workers

Hydropower manufacturing and upstream support industries suffer from a “significant” lack of workers with appropriate expertise, the report said. These industries have been offshored over the last 40 years, leaving skilled workers to retire or move to other industries.

NREL’s recommendations

NREL said DOE and the WPTO should consider the following recommendations to address hydropower supply chain concerns:

Lead with the federal fleet to prime the development of an aggregated, consistent demand signal with the largest producers by examining federal procurement processes and developing best practices for the refurbishment of the domestic fleet. Improve federal procurement processes to include multi-entity or multi-project long-term contracts and ensure that small businesses can compete for federal contracts. Develop best practices for refurbishments to ensure a predictable, steady, demand.

Develop domestic supply chain and end-user datasets to increase awareness of current and expanding capabilities of the domestic supply chain and installed hydropower fleet. WPTO is funding the development of two databases at Oak Ridge National Laboratory: a comprehensive database of suppliers in the hydropower supply chain, and an expansion of the HydroSource tool to provide unit and component-level information on the existing domestic fleet.

Work with other low-carbon technologies to create a “significant,” steady, and predictable demand signal for common materials.

Continue workforce development, including continuing collegiate competitions like the Hydropower Collegiate Competition and Marine Energy Collegiate Competition; in addition to acting on recommendations from the Hydropower Workforce report.

Originally published in Hydro Review.

“Looking backwards, why it was built, it was because there were people who took a bold decision,” said Dr. Klaus Engels, Director of Hydropower Germany for Uniper Kraftwerke.

Dr. Engels spoke as part of a utility executive roundtable at the HYDROVISION opening keynote. Minutes earlier he had accepted the honor of the Walchensee plant being inducted into the Hydro Hall of Fame.

The roundtable focused on challenges and opportunities for utilities with hydropower assets and the greater hydro industry. Dr. Engels said one of the industry’s single biggest challenges today is navigating community and political opposition to projects, along with lengthy re-permitting or re-licensing processes.

“Obviously it was possible to find a compromise,” he said, speaking of when Walchensee was build a century ago. “This is something which I personally miss very much in our society.”

Tom Roode, Chief of Operations and Maintenance for Denver Water, spoke of challenges his utility faces, including the availability of water in the West, long lead times and availability of parts and finding skilled labor. Maintaining the health of assets under inflationary pressures might be the most difficult, he said.

“As a broader water supplier that has hydropower, I think one of our biggest challenges is just aging infrastructure, and the demands for capital and to be able to replace and replenish and maintain that,” he said.

Other challenges included how the increasingly favorable economics of other renewables are driving decisions on the hydro side. Roode said Denver Water has a couple of projects that five years ago, it would have been a “no-brainer” to re-build or re-license.

“Now the question really is, do we put something solar-wise right next to it and not maintain the facility?” he said.

As thermal plants are retired and other renewables continue to come online, both Engels and Roode cited the need to balance environmental stewardship with producing the energy a modern industrial society needs.

“[Hydro] is, for me, the enabler of the energy transition, because it’s flexible, it can be stored and it’s baseload ready,” said Engels. “What we are heavily lobbying for is to put a price tag on flexibility.”

Both speakers highlighted the challenge of attracting and recruiting skilled employees. Engels said years of cost-cutting and restructuring, while not replacing old positions has brought us to this point.

“The problem is that we have a workforce which is condensed to 15 to 20 years,” he said. “That is not a healthy distribution of your workforce.”

Engels said like every company, Uniper Kraftwerke needs to navigate diversity, equity, and inclusion (DEI) while attracting strong talent. He said the utility is focused on the younger generation and recruiting in schools.

Roode said Denver Water has struggled to find enough electricians, mechanics and plumbers. He believes this is the product of trying to steer students toward college, rather than the trades, over the last 30 years.

“Hopefully, the market will start to reward the folks that do take the leap into that industry,” he said, “And they’ll be well-compensated to do it.”

In a call to action, he asked the HYDROVISION keynote audience to be a hydro “evangelist.”

“Hoping this group can go out and talk to their friends, talk to their neighbors, encourage people you know, kids that are going to look for a career in the trades,” said Roode.

Engels circled back to the need for the industry to “do hard things.”

“The easy jobs are for others,” he quipped.

From there, the 2.6 MW Robert V. Trout hydropower plant was born, coming online in 2012. Dozens of HYDROVISION International attendees on Monday toured the facility, which is located at Carter Lake, a reservoir of about 110,000 acre-feet of water.

The run-of-river plant, which consists of two Francis turbine-generator units, delivers raw water to local treatment plants and generates some electricity along the way.

“Right now, as you might imagine, we are delivering a lot of water to hot, hot cities,” said Jeff Stahla, Public Information Officer for Northern Water.

The Robert V. Trout facility is part of the Colorado-Big Thompson project, with six original hydropower plants owned by the Bureau of Reclamation and two added more recently by Northern Water. The project spreads over 250 miles and stores, regulates and diverts water from the Colorado River on the western slope of the Continental Divide to the eastern slope of the Rocky Mountains.  

While the plant itself isn’t huge, Stahla told tour attendees the surrounding area has grown immensely.

“Because of the amount of growth in northern Colorado, it runs quite a bit,” he said.

In the afternoon, tour attendees visited a larger hydropower plant. The 45 MW Estes plant, operated by the Bureau of Reclamation, is also part of the Colorado-Big Thompson project. The three-unit plant is remotely operated from Wyoming.

Estes began operating in 1950 with a single Francis turbine-generator unit and takes diversion water delivered from the Marys Lake Power Plant and holds it in Lake Estes for the project.

Lake Estes is formed by Olympus Dam. Reclamation said the afterbay storage in Lake Estes and the forebay storage in Marys Lake enable the Estes powerplant to meet daily variations in energy demand. 

The Inflation Reduction Act sunsets the existing Production Tax Credit (section 45 of the tax code) and Investment Tax Credit (section 48 of the tax code) by limiting their availability to projects beginning construction before 2025 and transitioning to the Clean Electricity Production Credit (section 45Y of the tax code) and the Clean Electricity Investment Credit (section 48E of the tax code) for projects placed in service after December 31, 2024.

These new Clean Electricity credits provide incentives for the first time to any clean energy facility that achieves net zero greenhouse gas emissions. The credits also allow for new zero greenhouse gas emissions technologies to be developed and are intended to provide long-term clarity and certainty to investors and developers of clean energy projects.

The Notice of Proposed Rulemaking (NPRM) identifies specific technologies that meet the environmental standards set out in the Inflation Reduction Act and would categorically qualify as zero greenhouse gas emissions for the purposes of the Clean Electricity Production Credit and Clean Electricity Investment Credit. The technologies recognized in the NPRM include wind, solar, hydropower, marine and hydrokinetic, nuclear fission and fusion, geothermal, and certain types of waste energy recovery property (WERP).

The proposed guidance also clarifies how energy storage technologies would qualify for the Clean Electricity Investment Credit. The statute requires clean energy technologies that rely on combustion or gasification to produce electricity undergo a lifecycle greenhouse gas analysis to demonstrate net-zero emissions. The proposed rules seek comment on a range of questions related to this required lifecycle analysis for combustion and gasification technologies. Treasury, in consultation with interagency experts, will review comments received and continue to evaluate how additional clean energy technologies, including combustion and gasification technologies, will be able to qualify for the clean electricity credits. 

“President Biden’s Inflation Reduction Act has driven an investment boom that is adding historic levels of new clean power to the grid while keeping consumer energy costs in check, reducing greenhouse gas emissions, and bolstering energy security,” said U.S. Secretary of the Treasury Janet L. Yellen. “The Clean Electricity Tax Credits created under the Inflation Reduction Act provide certainty to the market and are poised to drive substantial further growth and lower utility bills over the long run.”

The guidance also proposes that any future changes to the set of technologies that are designated as zero greenhouse gas emissions or the designation of lifecycle analysis models that may be used to determine greenhouse gas emissions rates must be accompanied by an analysis prepared by the U.S. Department of Energy (DOE)’s National Labs, in consultation with agency technical experts and other experts. The NPRM also proposes a process by which taxpayers can request a Provisional Emissions Rate, which DOE would administer in consultation with the National Labs and other experts as appropriate.

Additionally, the NPRM includes proposed rules meant to clarify the inclusion of costs of interconnection-related property for lower-output clean energy facilities that take the Clean Electricity Investment Tax Credit. Eligible costs include the costs of upgrades to local transmission and distribution networks that are necessary to connect facility to grid. The proposed rules continue the approach taken in the proposed rules for the Section 48 Investment Tax Credit, which was modified by the IRA to cover qualified interconnection costs. 

Originally published in Renewable Energy World.

This contrasts with last year, when U.S. hydropower generation fell to its lowest since 2001.

Northwest and Rockies

More hydropower is generated in the northwest and Rockies than any other region of the U.S. In 2023, 43% of all U.S. hydropower generation occurred in this region. However, last year’s hydropower output was the region’s lowest since at least 2010. Water supply, particularly in Washington and Oregon, was affected by a May heatwave that quickly melted the snowpack and reduced water supply for the rest of the year.

On April 4, the National Oceanic and Atmospheric Administration’s Northwest River Forecast Center (NWRFC) released its latest water supply forecast for the Pacific Northwest, which is part of the larger northwest and Rockies region. The NWRFC forecasts normal to more-than-normal water supply in the southern part of the region, around the Snake River Basin, and normal to less-than-normal water supply in the northern part by the Upper Columbia River Basin.

Because water supply and subsequent hydropower generation can vary widely from year to year, EIA uses these NWRFC forecasts as inputs to the STEO model. EIA expects 106 billion kWh of hydropower this year to be produced in the northwest and Rockies, or 3% more than in 2023.

EIA expects hydropower to account for 29% of the northwest and Rockies region’s electricity generation this year, and the increased output from hydropower resources and non-hydro renewables will reduce generation from natural gas and coal.

Southeast

The largest regional increase in hydropower this year comes from the southeast region, defined as the SERC Reliability Corporation. EIA expects hydropower generation in the southeast to increase by 4 billion kWh this year compared with last year. This region includes Alabama, Tennessee and North Carolina, which combined account for about 10% of total hydropower generating capacity in the U.S.

EIA expects hydropower to account for 5% of electricity generation in the southeast in 2024. Natural gas and nuclear are the two largest sources of electricity generation in the southeast, and EIA expects both to increase in 2024. In particular, nuclear generation will increase after the Vogtle Unit 4 generator in Georgia starts providing power to the grid during the second quarter of 2024. EIA expects these increases in natural gas, nuclear and hydropower to reduce the use of coal for electricity generation in the region.

California

California’s water supply is susceptible to drought. After a very wet year last year, annual hydropower generation increased by more than 80%, from 17 billion kWh in 2022 to 31 billion kWh in 2023. EIA expects similar hydropower generation in California this year.

The California-Nevada River Forecast Center expects California to have a near-to-above normal water supply. Water reservoirs in California are also mostly above their historical averages for this time of year. In addition, snowstorms between the end of January and end of March increased snowpack across the Sierra Nevada mountain range.

Non-hydro renewables, mainly solar and wind, are the most significant component of change in California’s electricity generation mix. EIA expects California’s non-hydro renewables to increase by 5 billion kWh in 2024.

Rest of the U.S.

EIA expects hydropower to increase in nearly every region, with notable increases in New York and the central region (Southwest Power Pool or SPP). About 6% of U.S. hydropower capacity is located in New York, and EIA expects the state’s hydropower output to increase slightly, to 29 billion kWh.

The SPP region includes many of the states just east of the Rocky Mountains. In 2023, SPP’s hydropower output fell to 11 billion kWh, the least in at least a decade. EIA expects SPP’s hydropower will increase to 14 billion kWh in 2024.

OPG’s hydroelectric stations in Niagara Falls have generated clean, reliable and affordable electricity for Ontario for more than a century, powering the province’s growth and helping establish the low-carbon electricity system we enjoy today.

OPG’s Niagara Operations encompass five hydro generating facilities, including the Sir Adam Beck I and II GS, Sir Adam Beck Pump GS, and DeCew I and II GS. Each year, these plants meet about 9% of Ontario’s energy needs.

Now, this fleet of stations is set to undergo a multi-year refurbishment to keep producing reliable power for Ontario’s electrification and future growth, while supporting OPG’s net-zero goals.

In April, OPG announced it is partnering with General Electric Vernova to complete the first phase of the $1 billion refurbishment project. Starting in 2025 and lasting over 15 years, GE will refurbish up to 25 units at the Sir Adam Beck I and II stations, increasing these plants’ capacity by up to 50 MW.

This work will build on OPG’s long relationship with GE, which manufactured the original generating units still in operation at some of OPG’s sites in Niagara. It will also create more than 200 highly skilled jobs in the Niagara region.

OPG is also developing refurbishment plans for its DeCew I and II stations.

“Upgrading and optimizing OPG’s renewable generation workhorses like the Sir Adam Beck complex is crucial to support the growing demands of electrification and a thriving economy,” said Ken Hartwick, OPG’s president and chief executive officer. “Through this refurbishment, these hydropower stations will build on their remarkable legacy and continue to produce the low-cost, reliable electricity Ontarians need for decades to come.”

The initiative is part of OPG’s commitment to invest in updating and upgrading its hydroelectric fleet. This wider turbine-generator refurbishment program will result in the renewal of 48 OPG hydro stations to extend station life, while also increasing efficiency and, in some cases, generating output.

At Niagara, the refurbishment of older generating units will involve removing some key components, including the turbine runners. These parts will be replaced with newer, more efficient designs that will require less water to generate power.

OPG’s Sir Adam Beck I GS went into service in 1922 and was considered the largest hydro plant in the world at the time. In 1954, its sister station, the 16-unit Sir Adam Beck II GS, went into service and remains Ontario’s largest hydro station by generating capacity.

“Currently, the Dniprovska HPP is not working. Today, we cannot disassemble all the rubble, as both the floor and the walls with the crane beams leaned towards the engine room. It is necessary to dismantle the upper part of the mashzal [turbine hall] in order to get to the lower part.

“On Saturday, March 23, we held a meeting with the head of Zaporizhzhya OVA, so that emergency services specialists with equipment for dismantling the ceiling could join the liquidation of the consequences.

“Together with the relevant services, we will try to restore the bridge crossing as soon as possible.

“The situation at the Dnipro HPP dam itself is under control. There is no threat of a breakthrough. The extent of damage requires a thorough examination. However, it is already known for certain that the restoration of the station will require a lot of money and a long time.”

Per Ukrhydroenergo, on the morning of March 22, from 04:10 to 07:00, Russian rockets attacked the Dnipro hydroelectric plant in the city of Zaporizhia. Emergency services and emergency services quickly arrived at the station. The fire at the facility was contained around 8:00.

As a result of several missile strikes at the Dniprovskaya HPP, electrical equipment and hydraulic units were damaged, and a significant number of construction structures were damaged. The station is not working.

There are no victims among DniproHES employees.

Ukrhydroenergo said it was implementing all possible measures to pass water downstream of the Dnipro plant.

Hydropower plays a key role in regulating peak loads. Ukraine has lost more than 1,000 MW of regulating capacity in terms of the operation of the energy system. Compensating mechanisms will be found for energy supply to consumers. However, for the energy system today, in the situation of constant terrorist attacks on energy facilities, these are serious losses, Ukrhydroenergo said.

Discussions are under way with international partners and financial institutions to attract assistance in the restoration of Dnipro HPP.

“Ukrhydroenergo draws the attention of the international community to the need for quick decisions and decisive actions. The destruction of the Kakhovskaya HPP and the terrorist attack on the Dnipro HPP require the Russian side to be held accountable for targeted attacks on Ukrainian infrastructure,” according to a release.

Just last week, Hydro Review reported that Dnipro was one of three Ukrhydroenergo hydroelectric projects to be rehabilitated under a memorandum of understanding with the European Investment Bank.

This is the key message of a new report, Hydropower Investment Landscape, developed by the National Renewable Energy Laboratory with support from Deloitte.

Globally, hydropower is the third largest source of electricity after coal and natural gas. As the world continues to transition away from fossil fuels, low-carbon sources of firm power will be increasingly critical to maintain the electric grid’s reliability. Hydropower already serves as a force multiplier for other renewable energy sources, and the value of this reliability and flexibility will continue to increase.

With the Bipartisan Infrastructure Law and Inflation Reduction Act offering financial support for clean energy projects, new hydropower and pumped storage projects could offer increasingly attractive investment opportunities.

The new report provides a comprehensive analysis of the risks and opportunities for investing in small- to medium-sized hydropower and pumped storage projects. Key findings from the study, which was funded by the U.S. Department of Energy’s (DOE’s) Water Power Technologies Office (WPTO), include:

Medium-sized projects offer significant opportunities for low-impact hydropower development. The medium-sized project pipeline includes projects that would constitute a total capacity of more than 1 GW and involves capacity additions, non-powered dam retrofits, hydropower generation in conduits, pumped storage, new stream-reach development and hybrid projects that combine multiple renewable technologies.

New technology innovations and the variety of sites at which hydropower could be developed present potential opportunities for future investment. Top areas of interest include modular conduit hydropower, non-powered dam resources, hybrid plant confirmation and closed-loop pumped storage innovation.

In the past decade, developers have begun designing and deploying small modular conduit systems, which can be manufactured offsite and assembled onsite. This approach can decrease construction costs, reduce project timelines and increase flexibility to expand the size of a hydropower system in the future. One example highlighted in the report of a company pursuing modular conduit hydropower is Emrgy, which raised several million dollars in private investment.

Because about 97% of U.S. dams do not have power-generating infrastructure, non-powered dams represent an attractive development opportunity with a potential capacity of 2 GW or more within the medium-sized range.

Using hydropower in a hybrid configuration with other renewables and battery storage can unlock new revenue streams by providing power during peak demand or ancillary services, such as the ability to adjust quickly to ensure grid reliability.

Closed-loop pumped storage systems feature two reservoirs that are not connected to a naturally flowing water feature like a river. These projects, which can offer siting flexibility, account for the majority of pumped storage projects in the pipeline. These projects would be the first closed-loop facilities in the U.S.

Investors surveyed for this study generally expressed the greatest level of interest in supporting capacity additions at existing facilities. With a connection to the grid already established, these facilities offer critical opportunities to increase clean energy production.

Overall, innovations in hydropower are driving the industry toward smaller, more modular and flexible solutions that can be more easily scaled and replicated.

Of course, there are challenges associated with hydropower projects, which are generally well known in the industry. Risks like financing for early-stage development, long permitting and licensing timelines, supply chain constraints, and more are important considerations but can also be addressed. The report includes several suggestions for addressing challenges in the industry to help increase investment. They are:

• Provide financing, funding and support for early-stage development
• Support improved market-based incentive signals for hydropower and pumped storage
• Support transparent and efficient permitting and licensing processes
• Support new, innovative research on reducing deployment time and costs
• Clarify new legislation and regulations and conduct outreach with developers and industry
• Increase awareness of new opportunities in hydropower and pumped storage

Published on Hydro Review.