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.

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.

Funded by the Bipartisan Infrastructure Law and with consideration of facilities located in communities with inadequate electric service, the incentive payments provide funding for electricity generated and sold from dams and other water infrastructure that add or expand hydroelectric power generating capabilities. These payments represent DOE’s largest investment in hydroelectric facilities to date, according to a release.

“Hydropower is one of the nation’s original sources of renewable energy and President Biden’s Investing in America agenda is providing transformative funding to help protect this existing clean energy infrastructure,” said U.S. Secretary of Energy Jennifer M. Granholm. “Today’s announcement supports waterpower’s continued growth while maintaining and expanding good-paying jobs and increasing access to affordable, clean power where it is needed most.” 

Hydropower accounts for 28.7% of renewable electricity generation in the U.S., as well as 93% of all utility-scale energy storage capacity. However, fewer than 3% of the nation’s more than 90,000 dams produce power. Adding generation equipment to these sites could add up to 12 GW of new hydropower capacity to the U.S. electric system.

The Hydroelectric Production Incentives, administered by DOE’s Grid Deployment Office, are part of a comprehensive program funded by a $750 million investment from the Bipartisan Infrastructure Law to support the continued operation of the U.S. hydropower fleet and ensure a more reliable and resilient electric grid system. Other program offerings are the Hydroelectric Efficiency Improvement Incentives and Maintaining & Enhancing Hydroelectricity Incentives. Since 2014, hydropower incentives have been used to support operations and maintenance, fees and service debts, exploration of new small hydropower opportunities, and salary and benefits for the hydropower workforce.

Click here for a complete list of selected applicants.

Additionally, DOE released the reimagined Hydropower Vision Roadmap, led by the Water Power Technologies Office. With the release of the Hydropower Vision report in 2016, DOE made a commitment to the hydropower community to make the Vision a living document. The original Hydropower Vision report was released at HYDROVISION International 2016.

To uphold that commitment, WPTO and the Pacific Northwest National Laboratory reimagined the Vision’s roadmap with the support of the hydropower community. The Vision stated that with continued technology advancements, innovative market mechanisms, and a focus on environmental sustainability, U.S. hydropower could grow from its current 101 GW to nearly 150 GW of combined electricity generating and storage capacity by 2050. The roadmap lays out the specific activities identified by the hydropower community to achieve those goals by 2050

About half of the country’s hydropower is generated in the Pacific Northwest. Precipitation that accumulated in the Northwest over last fall and winter provided the region with a plentiful water supply outlook for the summer months, with near- to above-average levels by the beginning of April. However, above-normal temperatures in May in the Northwest melted snow rapidly, resulting in a significant loss of water supply, measured as snow water equivalent in higher elevations. With less water available, the region generated 24% less hydropower in the first half of this year than during the same period in 2022. This year, EIA said it expects 19% less hydropower generation in the Northwest than in 2022.

However, the impact of decreased hydropower generation in the Northwest is offset by higher-than-expected generation in California, where record-breaking winter precipitation filled reservoirs and left a deep snowpack across the Sierra Nevada mountains. California had 94% more hydropower generation in the first six months of this year compared with the first half of last year. EIA forecasts 99% more hydropower generation in California this year compared with 2022.

Drought — which includes below-normal precipitation and snowpack accumulation, very dry soil, and higher-than-normal temperatures — directly affects water supply. In most western regions, particularly California, drought conditions have significantly improved compared with a year ago, according to data from Drought Monitor. However, parts of the Northwest, particularly around the Columbia River Basin, have had increasingly severe drought conditions since June 2023. These conditions will limit water supply, which could limit hydropower generation in the future.

The National Oceanic and Atmospheric Administration’s Climate Prediction Center issued an El Niño advisory in June 2023. The El Niño conditions are present and expected to gradually strengthen into the winter. El Niño is associated with wetter-than-average conditions in the southwest U.S., including parts of California, and warmer-than-average temperatures in the Northwest. Water supply for the new water year, which starts on Oct. 1, will be influenced by the El Niño conditions, which are likely to affect hydropower generation for the remainder of 2023.

In addition, FirstLight will add Hydroméga’s clean energy development pipeline that includes over 2 GW of wind, solar, storage and hydroelectric projects, doubling FirstLight’s development pipeline to about 4 GW in the U.S. and Canada. The transaction is expected to close in Q4 2023 and is subject to customary closing conditions.

After the recent integration of H2O Power, the addition of Hydroméga’s assets will give FirstLight a combined operating capacity of over 200 MW in Québec and Ontario. Hydroméga’s operating projects include ownership participation by four First Nations. By expanding its presence in the Canadian market, FirstLight is well-positioned to further accelerate its growth across North America by advancing Hydroméga’s renewable energy development pipeline, including over 1 GW of wind projects in Québec and over 1 GW of battery storage projects in Ontario, according to a release. FirstLight will also welcome Hydroméga’s employees into its team.

“The strategic acquisition of the Hydroméga platform continues an exciting and transformational period for FirstLight,” said Alicia Barton, president and chief executive officer of FirstLight. “By adding Hydroméga’s development capabilities and operational assets to FirstLight’s existing diversified renewables and energy storage portfolio, we will position ourselves for even greater growth in the years ahead as we pursue our mission to accelerate the decarbonization of the electric grid by building, operating, and integrating renewable energy and storage to meet the world’s growing clean energy needs.”

Hydroméga has been originating, developing, implementing and operating clean electricity production facilities in Québec for over 36 years and in Ontario for 20 years. In 1987, the company was the first independent power producer to operate hydroelectric facilities in Québec and was also one of the first wind developers in the province.

“As an early leader in Canada’s renewable energy sector, we are proud to join forces with FirstLight to accelerate the development of our diversified clean energy portfolio to fight climate change and increase access to renewable power in our current target markets, Québec, Ontario and beyond,” said Stéphane Boyer, CEO of Hydroméga. “We have always strived to build partnerships with local communities and organizations committed to the development of their region’s renewable power potential, and we are proud of the meaningful partnerships that have been established with local governments for over two decades. Given its track record of managing clean energy assets and natural resources in harmony with the environment, it is clear that FirstLight shares our values, so joining forces with them makes sense on many levels.”

The announcement follows several growth-related initiatives and strategic moves by FirstLight. In addition to the recent integration of H2O Power, FirstLight was part of an investment consortium that secured a lease in the NY Bight Offshore Wind auction. The company also acquired two hydroelectric facilities in western Pennsylvania that expanded the company’s footprint into the PJM and New York electricity market. In addition, FirstLight announced a new partnership in Connecticut to advance hybrid renewable energy projects at the company’s existing Connecticut properties. FirstLight also announced a strategic partnership with New Leaf Energy (formerly Borrego) to develop new solar and storage generation at existing hydropower facilities in Massachusetts and Connecticut.

TD Securities is acting as financial advisor to Hydroméga in connection with the transaction; Davies Ward Phillips & Vineberg LLP is Hydroméga’s legal counsel and KPMG represents Hydroméga as its tax advisor. Blakes, Cassels & Graydon LLP is FirstLight’s legal counsel.

FirstLight has a diversified portfolio that includes over 1,650 MW of operating renewable energy and energy storage technologies and a development pipeline with 2,000+ MW of solar, battery, and offshore wind projects. FirstLight specializes in hybrid solutions that pair hydroelectric, pumped hydro storage, utility-scale solar, large-scale battery and offshore wind assets.

Alaska is warming faster than any other U.S. state, per the U.S. Department of Agriculture. The result is coastal erosion, increased storm effects, sea ice retreat and permafrost melt, among other impacts.

The state’s massive size and diverse landscape have created unique energy needs and challenges. Alaska is not connected to a large interstate energy grid. It consists of two larger transmission systems and more than 150 small, isolated systems serving remote communities.

Alaska is primarily powered by fossil fuel-based power that emits the carbon dioxide that drives climate change, according to Argonne. The state gets roughly 30% of its power from renewable energy, including wind, solar and water. To integrate those zero-carbon energy sources into the electric grid on a larger scale, scientists are seeking cost-effective ways to store energy to provide constant power when solar and wind are scarce. In Alaska, the sun might shine 24 hours on some summer days and barely at all in the winter.

Scientists at Argonne led a study to determine the potential of pumped storage hydropower as an efficient way to store large amounts of energy and improve grid resiliency throughout Alaska. Argonne partnered with NREL for the project funded by the U.S. Department of Energy’s Water Power Technologies Office.

Scientists collaborated on mapping and geospatial analysis to identify Alaska locations feasible for pumped storage hydropower. The result: About 1,800 sites are suitable for the development of closed-loop pumped storage and many more are suitable for open loop pumped storage.

Argonne researchers evaluated pumped storage hydropower potential in Alaska’s integrated Railbelt system. The transmission grid comprises five regulated public utilities that extend from the cities of Fairbanks to Anchorage and the Kenai Peninsula. About 80% of the Railbelt’s electricity comes from natural gas.

Argonne scientists created detailed models using A-LEAF (Argonne Low-Carbon Electricity Analysis Framework), an integrated national-scale simulation framework for power system operations and planning. Argonne scientists studied past and present energy transmission trends. They analyzed overall growth in electricity demand expected in the next 25 years. A-LEAF also considered retiring existing generators as they reach their economic lifetime.

“One of the key findings of the A-LEAF modeling is that the Railbelt system will need both short- and long-duration energy storage in the future. That storage will balance the operational variability of wind and solar generation and provide reliability and backup capacity for longer periods,” said Vladimir Koritarov, director of the Center for Energy, Environmental and Economic Systems Analysis (CEEESA) in Argonne’s Energy Systems and Infrastructure Analysis division.

Pumped storage hydropower provides roughly 10 or more hours of energy storage. The study showed that lithium-ion batteries were feasible for short-term (four-hour) energy storage in the Railbelt system.

NREL scientists evaluated Alaska’s remote areas that are powered by small isolated electrical grids, or ​microgrids. Using the HOMER (Hybrid Optimization Model for Electric Renewables) model, researchers analyzed the viability of small-pumped storage projects in rural communities with at least 250 or more residents. The team identified 18 remote communities with potential for smaller pumped storage projects. Scientists determined that in most cases, pumped storage hydropower may not be economically feasible for remote areas due to the high investment cost of small-size projects. Lithium-ion battery storage may be more economically beneficial in rural areas seeking to lower electricity costs but will not provide longer duration storage economically.

“In addition to identifying remote communities with optimal pumped storage hydropower resources and characteristics, the study included a sensitivity analysis of pumped storage hydropower capital costs and the price of diesel fuel,” said Rebecca Meadows, an NREL senior engineer. “The goal was to determine at what point distributed scale-pumped storage hydropower projects could become economically viable. For larger remote communities with higher diesel costs, … pumped storage hydropower could be a cost-effective option depending on site-specific considerations such as renewable resources and constructability.”

Along with validating the use of pumped storage hydropower as a viable technology for reducing carbon emissions, the Argonne-NREL study offers guidance on developing clean energy policies and regulations and making investment decisions. Such projects can also pump dollars into the Alaskan economy.

The Argonne-NREL research was conducted under DOE’s HydroWIRES (Water Innovation for a Resilient Electricity System) initiative to understand, enable and improve hydropower and pumped storage hydropower’s contributions to reliability, resilience and integration in the rapidly evolving U.S. electricity system.