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.

This funding — made possible by the Bipartisan Infrastructure Law — will support community-driven energy projects in rural and remote regions, such as building microgrids for health centers or constructing a new hydroelectric facility on Tribal lands. The announcement underscores the Biden-Harris Administration’s commitment to building an inclusive and equitable clean energy future that creates safer, more resilient communities, enhances Tribal energy sovereignty, strengthens energy security, and delivers new economic opportunities, according to a release.

“President Biden firmly believes that every community should benefit from the nation’s historic transition to a clean energy future, especially those in rural and remote areas,” said U.S. Secretary of Energy Jennifer M. Granholm. “DOE is helping revitalize communities across America — ensuring thriving businesses, reliable access to clean energy, and exciting new economic opportunities, now and for generations to come.”

In line with President Biden’s Justice40 Initiative to advance energy and environmental justice, all 17 projects are located in or adjacent to disadvantaged communities that are disproportionally overburdened by pollution and historically underserved. The projects are part of DOE’s Energy Improvements in Rural or Remote Areas (ERA) program, which is managed by the Office of Clean Energy Demonstrations (OCED). The ERA program leverages DOE’s expertise in resilient energy solutions while recognizing the unique environmental, cultural and economic landscapes of rural and remote communities. At least 12 projects will support Tribal communities.

Each ERA selectee is required to develop and implement a comprehensive Community Benefits Plan (CBP) — which will be informed by early and meaningful community engagements in each region. As part of the department’s commitment to transparency, OCED will hold a series of national and regional virtual briefings to provide information on the selected projects, OCED’s approach to clean energy demonstrations, and opportunities for community engagement.

Before funding is issued, DOE and the selectees will undergo a negotiation process, and DOE may cancel negotiations and rescind the selection for any reason during that time. Lead applicants also may change during the award negotiations process. If awarded, OCED will evaluate these projects through a phased approach to project management that includes “go/no-go” decision points between each phase.    

Below are details on the four hydroelectric projects chosen:

Chignik Hydroelectric Dam and Water Source Project in Chignik Bay, Alaska, will receive a federal cost share of $7,270,000. The lead applicant is The Lake and Peninsula Borough. This project involves constructing a new run-of-the-river hydroelectric facility, replacing a 70+ year-old wooden dam that is at risk of failure. It aims to improve energy and water security as the current dam leaks frequently, also jeopardizing the community’s only stable source of clean water. The proposed 2.1 MWh hydroelectric facility aims to replace 100% of the community’s diesel consumption. It also plans to provide excess power for heating, electric vehicle charging, and expansion of local economic activities like tourism and fish processing. The Chignik Bay Tribal Council will own the facility and plans to sell power to local utilities for 80% of the avoided cost of fuel, reducing total electricity rates by an estimated 7%.

Old Harbor Hydroelectric Project in Old Harbor, Alaska, will receive a federal cost share of $10,000,000. The lead applicant is the Alutiiq Tribe of Old Harbor. This project plans to construct a run-of-river hydroelectric facility with a diversion structure, pipeline, powerhouse and electric transmission line. It is anticipated that the project will be capable of generating about 3,470 MWh of energy annually and offset diesel fuel use at the local power plant by 95%. Old Harbor is a remote Alutiiq Tribal village on Kodiak Island, about 50 air miles from the nearest social services in the City of Kodiak. There are nearly 200 residents and 83% are Native Alaskans who rely on a subsistence diet. According to the Denali Commission, 88% of residents live below the federal poverty line, with a median household income of $13,181, and experience disproportionally higher cost energy bills.

Thayer Creek Hydroelectric Project in Angoon, Alaska, will receive a federal cost share of $26,920,000. The lead applicant is Kootznoowoo Inc. (KI). This project encompasses an 850-kW, run-of-river hydroelectric project that has the potential to supply three times the community’s electricity needs, providing additional power for heating, fish processing, electric vehicle charging and tourism. KI is the Alaska Native Village Corporation for the community of Angoon, the ancient home of the Tlingit Xóotsnoowe’di people, with a population of 357. In 1980, as part of the Alaska National Interest Lands Conservation Act (P.L. 96-487), KI and Angoon gave up rights to their ancestral land to establish the Admiralty Island National Monument. As compensation, KI was granted the right to develop Thayer Creek Hydroelectric. However, the initial agreement did not include funding, and the Tlingit people are still entirely reliant on imported diesel, which leads to energy costs that are 4.5 times the national average. This project aims to provide an avenue to address historical oversight and support access to reliable and affordable energy for the Tlingit people.

Yakama Tribal Solar Canal & Hydro Project on the Yakama Indian Reservation, Wash., will receive federal cost share of $32,000,000. The lead applicant is The Confederated Tribes and Bands of the Yakama Nation. This project aims to convert inefficient, open-water irrigation canals into a solar and micro-hydropower irrigation system. This system could conserve up to 20% more water and help energy-burdened residents save up to 15% on their utility bills. Additionally, the project team plans to build solar panels on land the Tribe knows does not risk disturbing cultural resources. It is anticipated that deploying solar technologies will increase the Yakama Nation’s renewable power supply, while improving its energy resilience and reliability. Improvements in irrigation efficiency could also benefit grazing and irrigated agriculture, the area’s key economic drivers.

The Hydroelectric Efficiency Improvement Incentive payments are administered by the Grid Deployment Office and funded by the Bipartisan Infrastructure Law.

“Hydropower is the nation’s prototype of renewable power playing an important role in deploying affordable and reliable electricity across the country,” said U.S. Secretary of Energy Jennifer M. Granholm. “Thanks to the President’s Investing in America agenda we are maintaining and expanding our hydropower fleets, helping reduce costs of operation and ensuring American workers continue to drive the nation’s clean energy transition.”

This incentive program received robust industry interest, DOE said, with applications requesting a total of $192 million in federal support. Using all available funding directed to the incentive, the selected improvements are anticipated to generate $468 million in combined federal and private investment. With an average selectee facility age of 75 years, these upgrades will contribute to the continued operation and longevity of hydroelectric assets. 

Hydropower accounts for 27% of renewable electricity generation in the U.S., as well as 93% of all utility-scale energy storage capacity. In addition, the U.S. hydroelectric fleet and their associated reservoirs play an important role with respect to water supply, flood control and recreation. More efficient use of water for electric generation can only enhance the fleets’ ability to more effectively manage the nation’s waters.

Investments under the Hydroelectric Efficiency Improvement Incentives will support the continued operation of the U.S. hydropower fleet and ensure a more reliable and resilient electric grid system. The owners or operators of hydroelectric facilities, including pumped storage hydropower, receiving the efficiency incentives announced will make capital improvements that improve their facility’s efficiency by an average of 14% with a statutory minimum of 3% improvement per facility. Investments include upgrades to facility turbines and generators, as well as improvements to water conveyance structures, to increase efficiency. 

The 46 selected projects are in California, Colorado, Connecticut, Georgia, Idaho, Maine, Massachusetts, New Hampshire, New York, North Carolina, Oklahoma, Oregon, Pennsylvania, Rhode Island, Tennessee, Vermont, Virginia, Washington and West Virginia.

The Hydroelectric Efficiency Improvement Incentives are one of three incentive offerings funded by the Bipartisan Infrastructure Law to maintain and enhance existing hydroelectric facilities and ensure generators continue to provide clean, renewable electricity, while improving dam safety and reducing environmental impacts. Other program offerings include Hydroelectric Production Incentives provided to qualified hydroelectric facilities for electricity generated and sold and Maintaining and Enhancing Hydroelectricity Incentives provided to existing hydroelectric facilities for capital improvements directly related to grid resiliency, dam safety and environmental improvements.

“Hydroelectric power generated by the Columbia River System is the foundation of the electric grid in the Northwest,” Matheson told the House Energy and Commerce Subcommittee on Energy, Climate and Grid Security. “It is the key to electric reliability, economic prosperity and public safety. Put simply, hydropower is the reason why the lights stay on in the Pacific Northwest. Breaching or chipping away at the lower Snake River dams pulls a critical, dispatchable, carbon-free renewable resource out of the mix at a time when electric demand continues to grow.”

The U.S. Army Corps of Engineers operates four run-of-river dams and locks on the lower Snake River in Washington that together provide 1,000 average MW of capacity and up to 3,033 MW of capacity at their peak. The dams, constructed between 1955 and 1961, are Ice Harbor, Lower Monumental, Little Goose and Lower Granite. Construction and operation of the dams altered the physical, chemical, hydrological and biological processes in the river, and all species of salmon that use the Snake River are listed as threatened or endangered under the Endangered Species Act. With salmon being “central to culture and wellbeing in tribal nations throughout the Pacific Northwest,” there have been discussions about breaching the dams.

Matheson testified before the panel about a legal settlement reached by the Biden administration, environmental groups, and tribal and state governments over the federal government’s operation of the lower Snake River dams. Those dams supply hydropower to 55 coops in eight western states served by the Bonneville Power Administration.

In a 2021 lawsuit, plaintiffs charged that the dams are threatening the survival of endangered salmon. The settlement supports breaching the dams and replacing them with other types of renewable energy.

Although it would take an act of Congress to breach the dams, the settlement agreement undermines their operation, Matheson said. “While the dams are not physically breached by the agreement, the mandated spill and flow requirements chip away at the economic viability of the dams with the goal of making them uneconomical to operate,” he said.

It won’t just be electric power providers who will be hurt, Matheson added. “It will adversely impact agricultural producers, the transportation sector and economically disadvantaged rural communities.”

For decades, the hydropower provided by the Columbia River System has fueled economic growth in the region, Matheson said. “The region’s hydropower is a major attraction for economic investment in the Northwest. Companies locate their operations in the Northwest to take advantage of the reliable, affordable and carbon-free hydropower. Small family-owned businesses, electric vehicle manufacturers, agricultural producers and tech giants have all based operations in the Northwest because of hydropower.”

Although power generation within the BPA system includes wind, solar and biomass, those sources are dwarfed by hydropower, which makes up nearly 80% of capacity, Matheson said.

The settlement envisions replacing lower Snake River dam hydropower with other renewables. Matheson noted that “hydropower is not interchangeable with wind or solar. Hydropower is a dispatchable resource, meaning it can be adjusted to meet demand and is ever-ready as a source of baseload power. Wind and solar, on the other hand, are unpredictable.”

He also denounced the exclusion of co-ops and other electric utilities in the settlement talks. “No one from the electric consumer sector was included in the final closed-door negotiations that led to this settlement,” Matheson said. “The people that keep the lights on were purposefully kept in the dark…This settlement process sets a dangerous precedent of exclusion.”

Originally published in Hydro Review.

Why? “What got us to where we are is not going to get us where we need to be,” said Brian Roth, vice president O&M with PROENERGY. The company is a third-party solutions provider for the energy industry.

How does this connect to remote power plant operations? Divergent thinking, which is a process used to create ideas by exploring many possible solutions, is needed to help address challenges the industry is facing now and will be facing in the future. And yet convergent thinking, which focuses on reaching a single well-defined solution to a problem, often causes us to shut down potential solutions. Roth encouraged a focus on separating convergent thinking from divergent thinking within organizations. Thinking about a challenge without taking into account constraints encourages divergent thinking.

With this encouragement setting the stage, Roth discussed the difference between remote dispatch, which is a subset of remote operations that focuses on start/stop energy monitoring, remote operations (physically controlling a unit) and remote monitoring (and diagnostics) or RM&D. The latter involves looking at data trending, setting more narrow bands to get alarms earlier than the control system and enabling plant personnel to take action.

He was frank when sharing the value of remote operations centers (ROC), including pros and cons. The pros list is substantive: better coordination and resource allocation, safety enhancements, and improved reliability and sustainability. But the cons must also be acknowledged, with Roth highlighting two in particular: technology differences make it more challenging, and the importance of communication without the ability to meet face-to-face can’t be overlooked. In addition, it is easy to overload ROC operators with information.

Roth pointed out that tools don’t solve problems. With RM&D, the aspiration is to detect small anomalies and then do something with that information before there’s a problem. RM&D can empower a utility to reach peak efficiency using predictive technology. RM&D systems can deliver prescriptive alerts to operator, which Roth called alarms with recommendations.

Now, coming back to the concept of divergent thinking: Early in the session, Roth asked attendees: “Can a single operator run 100 units?” The knee-jerk answer to that question might be no, and in that case you would be thinking convergently, not divergently. Putting aside current technology and personnel constraints, your answer should change. Roth said at this time, the company has an ROC where a single operator runs 32 units, so taking today’s constraints out of the equation could perhaps see the aspirational goal of 100 units reached.

To start identifying recommendations for accomplishing this vital task, the Accelerating the Energy Workforce Development Workshop was held Monday at POWERGEN International 2024. Outcomes from the workshop, facilitated by the nonprofit U.S. Women in Nuclear organization, will help in the creation of a report offering recommendations on developing a diverse, equitable, and inclusive workforce as energy industries gear up for rapid expansion.

What is exactly the size and scope of this challenge? Representatives of Idaho National Laboratory, who moderated the workshop, set the stage for what the industry faces.

It is well-known that diverse perspectives allow companies to craft more effective solutions. Despite this, and even though half of the global energy workforce is in clean energy, only 26% of the energy workforce is female and 24% minorities. One major challenge identified when it comes to staffing for nuclear energy is a small applicant pool, with many of those applicants not having the technical skills needed. In addition, the need for jobs in nuclear energy is quite diverse, encompassing regulatory, construction, manufacturing/supply chain, wholesale trade, professional and business services, and more.

The goal of this small and very interactive roundtable discussion was to help attendees identify ways to develop a diverse pipeline and ensure gender equity and a growth plan for the industry.

Four expert panelists addressed the situation from three key angles: readiness, recruitment, and retention.

Concerning readiness, Kimberly Cook-Nelson, executive vice president of nuclear operations and chief nuclear officer with Entergy, said her company employs a variety of initiatives, starting with working as early as the elementary school level in the communities it serves, to reach the potential future energy workforce. As stated above, employees needed for the industry include accountants, human resources, electricians, and more as well as engineers. At the university level, Entergy’s efforts include providing $7 million in grants and scholarships to historically black colleges and universities and working on a radiation protection program at a Mississippi university that has translated to 19 employees for the company.

On the topic of recruitment, Erin Hultman, vice president of member and corporate services and chief financial officer with the Nuclear Energy Institute, said it is important to understand the size and scale of the challenge. Among NEI members alone, which represent just over half of all nuclear production in the U.S., it is anticipated nuclear production will more than double over the next 10 to 15 years, based on plans (not aspirations). In addition, about 300 small modular reactors may be installed, with “everything that goes along with that,” Hultman said.

Finally, regarding retention, Nicole Hughes, director, North America Nuclear at Thomas Thor, pointed out that while developing a career path for employees is nice, one caveat is it’s not an approach that works for everyone. Kara Temple, MBA, member of the board of directors at Allied Power, shared her own experience with regard to retention in the industry. She recalled working at a company where she took the initiative to set up three rotation opportunities for herself with office directors, only to have her boss deny her request to cross-train, three times. Temple said it’s important to create a holistic experience so employees can try different things, even potentially offering them the opportunity to move to different locations within the company so they can find their best fit.

Hughes left attendees with a memorable impression of the challenges, and how changing the way they’re viewed can yield results: “The rainbow-colored unicorn you’re looking for might not be available. Maybe a zebra might be a better fit for you,” she said.

Further, TC Energy and prospective partner Saugeen Ojibway Nation will assist with the ministry’s evaluation of the project’s broader societal and economic benefits.

This decision comes after direction from the minister to the Independent Electricity System Operator (IESO) outlining next steps related to the project, including a cost recovery agreement. Subject to an agreement with the IESO, this direction from the minister will facilitate the continued development of the project.

The Ontario Pumped Storage project is proposed for construction on the Department of National Defence’s 4th Canadian Division Training Centre in Meaford, in the territory of the Saugeen Ojibway Nation. The project would store enough clean electricity to power 1 million homes for 11 hours. It would generate about $12.1 billion in energy system cost benefits while creating more than 1,000 direct jobs regionally and in Ontario. The project represents a made-in-Ontario solution – it will be designed, engineered and built by a domestic supply chain, TC Energy said. Over 75% of the total materials and supplies will be provided by Ontario-based companies. Once operational, the project would pay about $8.5 million annually in income to workers employed at the facility, off-site employees and direct contract workers.

“The Minister’s direction to advance this project is a strong signal that the work TC Energy and Saugeen Ojibway Nation are doing is important. It recognizes the critical role that pumped hydro storage will have in enhancing the diversity of Ontario’s supply mix and achieving a net-zero electricity grid,” said Annesley Wallace, executive vice president, Strategy and Corporate Development and president, Power and Energy Solutions, TC Energy.

TC Energy said it will begin immediate work with the ministry and the OEB to establish a potential long-term revenue framework for the project, culminating in a report to the minister by July 31, 2024. Further, TC Energy will provide a report to the ministry with a breakdown of estimated development costs and schedule. After submission of these items, the ministry will provide a recommendation to proceed with pre-development work within 45 days.

Following this, TC Energy would begin negotiation of a cost recovery agreement with IESO to recover eligible, prudently incurred expenses associated with pre-development work. A follow-up report is to be provided to the ministry by the IESO within 60 days of submission of the estimates.

The project remains subject to the approval of TC Energy’s board of directors and Saugeen Ojibway Nation. It is expected that construction would begin in the latter part of this decade, with the project entering service in the early 2030s, subject to receipt of regulatory and corporate approvals. Further, any future capital allocation decisions will align with TC Energy’s net capital expenditure limit of $6 billion to $7 billion post-2024.

D&Z will also perform scaffolding, coatings, insulation, asbestos abatement and lead abatement work. The $985 million contract spans five years, with the option to renew for an additional five years.

D&Z has more than 25 years of experience working with TVA, according to John McCormick, president of D&Z’s maintenance and construction division. In April 2022, TVA named D&Z its 2022 Prime Supplier of the Year through TVA’s Diversity Alliance Program.

TVA is a corporate agency of the U.S. that provides electricity for business customers and local power companies, serving nearly 10 million people in parts of seven southeastern states. In addition to operating and investing its revenues in its electric system, TVA provides flood control, navigation and land management for the Tennessee River system and assists local power companies and state and local governments with economic development and job creation.

The electricity TVA delivers is nearly 60% carbon-free through its 29 hydroelectric projects, TVA’s nuclear fleet and other renewables such as solar. TVA owns four fossil plants, three nuclear plants, 29 hydro plants, one pumped storage hydroelectric plant, nine natural gas combustion turbine gas plants, eight natural gas combined cycle gas plants, one diesel generator site and 13 solar energy sites.

TVA is reducing its reliance on coal and plans to expand its natural gas fleet to provide the ongoing flexibility needed to reliably integrate more renewables.

Hydropower accounts for 28.7% of total U.S. renewable electricity generation and about 6.2% of total U.S. electricity generation. It can supply electricity immediately or store it to meet real-time demand. By enhancing these abilities, this investment helps strengthen hydropower’s ability to support an electric grid with an increasing amount of variable renewable energy resources as the U.S. works to meet its clean energy goals.

The opportunity will fund projects in three topic areas:

• Up to $4 million for projects that demonstrate hydropower hybrid configurations, such as a hydropower facility paired with another type of generation or with an energy storage resource.
• Up to $4 million for projects that advance technology innovations to improve the flexible capabilities of the U.S. hydropower fleet.
• Up to $1.5 million for projects that quantify the flexible capabilities of hydropower and advance operational strategies to increase such flexibility to better serve an evolving electric grid. 

Between four and seven awards are anticipated under the Strategies to Increase Hydropower Flexibility funding opportunity. Individual awards may vary between $750,000 and $4 million.

Topic Area 1, Hydropower Hybrids Demonstration, will support demonstrations of hybridized hydropower operations in which hydropower is co-located and co-operated with at least one other non-hydropower generation or storage resource. This topic is motivated by industry insights and previous research suggesting that synergies between hydropower and other resource characteristics can expand capabilities to provide enhanced grid services, reduce machine wear-and-tear, and mitigate environmental impacts.

Topic Area 2, Technologies to Increase Flexibility, will support testing of advanced hydropower components, which will tackle component-level constraints to a hydropower facility’s flexibility. Motivated by industry discussions and targeted technical workshops with manufacturers, this topic builds on previous research to de-risk promising new technologies so they can progress toward widespread deployment.

Topic Area 3, Operational Flexibility, supports development of operational strategies, model enhancements and related tools that can allow individual plants or coordinated sets of plants (e.g., in cascading river systems) to increase their net flexibility. Informed by previous research by academics, national laboratories and other research organizations, this topic will target projects that advance the state of the art while pursuing incorporation of these advancements into actual operational practice in the industry.

Concept papers are due by 5 p.m. ET on Jan. 18, 2024, to be eligible to submit a full application. The expected submission deadline for replies to reviewer comments is May 23, 2024. The expected date for DOE selection notifications is August 2024 and the expected timeframe for award negotiations is August to November 2024.

Construction of the Romaine complex stretched from 2009 to 2023, with a total cost of $7.4 billion, or 14% less than the initial estimate. The complex has annual energy output of 8 TWh.

Construction of the Romaine-2 development began in 2009, and it was commissioned in 2014. The Romaine-1 development was commissioned in 2015 and Romaine-3 in 2017. The Romaine-4 development is now operational.

The resale price of 6.4 cents/kWh is also highly advantageous, especially given that the Romaine provides both energy and capacity—making it possible to balance variable generation from other renewable sources, such as wind and sun. 

The project generated economic spinoffs of $5.5 billion for Québec, including $1.4 billion for the region. It created an average of 975 jobs each year while the project was being carried out. Mitigation measures were implemented, including the creation of 60 hectares of new wetlands and the seeding of Atlantic salmon, lake trout and landlocked salmon. Environmental follow-ups will continue through to 2040 in collaboration with local partners, according to a release.

The Romaine project was unfortunately marked by the death of four workers, Hydro-Québec said. These accidents led the utility to thoroughly review and strengthen its health and safety practices. The completion of the Romaine complex would not have been possible without the contribution of all the men and women who worked there, Hydro-Québec said. In addition, the close collaboration of the Innu and Minganois communities enabled the company to adapt its practices to the realities of this vast territory.

“I am very proud to inaugurate the Romaine facilities, the largest hydropower complex since Baie-James, and a monument to Québec engineering,” said François Legault, Premier of Québec. “This project is essential for our energy future, allowing us to meet Québec’s industrial needs for the next 100 years! I am especially proud that this project was carried out in partnership with the Innu nation, two great forces working together. Thanks to visionaries Jean Lesage, René Lévesque and Robert Bourassa, Québec chose hydroelectricity, clean energy that puts us way out in front for the energy transition. We need to capitalize on this strength to create more wealth while emitting less GHGs.”

Hydro-Québec generates, transports and distributes electricity. It is Canada’s largest electricity producer and one of the largest hydroelectric producers in the world. Its sole shareholder is the Quebec government.