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.

In that article, I didn’t really provide an answer to the question. I did list the three projects I saw as the front runners, based on them having operating licenses from the Federal Energy Regulatory Commission: 1,300 Eagle Mountain in California, 400 MW Gordon Butte in Montana and 393 MW Swan Lake in Oregon. And I included the 1,200 MW Goldendale project in Washington in the honorable mention position.

Instead, I asked readers to share their predictions and insights on this subject. And they did not disappoint. Below I will first give an update on the status of the four projects above, and then I will share some of the input I received. I hope we can keep this conversation going, so this is an open invitation to email me your opinions at any time.

Update on the four projects

As you might have imagined, there has been little forward progress by these projects, but there are some updates:

Eagle Mountain Hydroelectric Pumped Storage Project (P-13123)

A search of FERC activity for the past three months revealed that in mid-June, Eagle Crest Energy Company received an order from FERC granting a stay of the commencement and completion of construction deadlines. Eagle Crest now has until June 19, 2028, to commence construction and June 19, 2031, to complete construction.

In August 2023, experts from Oak Ridge National Laboratory published an article on Hydro Review discussing development of pumped storage hydropower on mine land in the U.S. They said the U.S. Department of Energy’s Office of Clean Energy Demonstrations aims to accelerate development by demonstrating use of pumped storage hydropower and other clean energy technologies on mine land. They cited the Eagle Mountain project as an example, given its FERC license.

A 2012 Environmental Protection Agency report said the project will generate 4,308 GWh annually.

Gordon Butte Pumped Storage Project (P-13642)

A search of FERC activity for the past three months yielded no results. The webpages for the project and developer Absaroka Energy contained no updates on project status or progress.

The project website estimated annual generation of 1,300 GWh.

Swan Lake Energy Storage project (P-13318)

A search of FERC activity for the past three months showed that earlier this month, Rye Development submitted a response to a request by FERC for additional information related to the updated Exhibit G drawings for the project. And in early July, Rye Development submitted a response to comments from FERC’s Board of Consultants Meeting No. 1.

The timeline published on the project website indicates construction is to begin in 2023, with commercial operation in 2026.

In 2019, Hydro Review reported expected annual generation of 1,187 GWh.

Goldendale Energy Storage Project (P-14861)

In March 2023, Hydro Review reported that FERC staff had prepared a draft environmental impact statement for licensing of this project. In the draft EIS, FERC staff recommended the staff alternative, which consists of issuing a license that includes the measures proposed by the applicant, as well as certain recommendations made by state and federal agencies and non-governmental organizations and some staff-recommended modifications.

A search of FERC activity for the past three months revealed that in mid-August, Rye Development submitted a response to the draft EIS.

In addition, the project website said the Washington Department of Ecology issued a Section 401 Water Quality Certification under the Clean Water Act for the Goldendale project in May 2023.

Expected annual generation from this project is 3,561 GWh, per multiple sources.

Industry feedback

And now, to the most interesting context on this subject: insights from the industry.

First, a reader pointed out that the previous article did not contain information on actual generation from the above projects, so I have added that information in this article.

Andrew Blakers, a professor in the School of Engineering, College of Engineering and Computer Science, Australian National University, pointed out that the U.S. has “vast numbers of excellent closed loop (off-river) pumped hydro sites,” with 35,000 good sites with no new dams needed on rivers and no flood control costs. Despite this, he said, “I wonder whether energy planners have realized just how good the off-river U.S. pumped hydro resource is.”

Another reader commented on the importance of ensuring that pumped storage facilities use electricity from wind and solar plants to pump the water uphill, as opposed to the current situation of pulling electricity from the grid, which may come from fossil fuels. He also suggested using green hydrogen to power the pumps as a backup to wind and solar, potentially making this hydrogen from solar and wind projects. He said my article asks the wrong question and instead should ask: “Who will be the first to pump water back up the hill with renewables.”

Another perspective received pointed to the value of seawater-based pumped storage and discussed a particular technology.

Nobody, unfortunately, provided an answer to the question in the article.

What now?

Is the U.S. industry any further along in its quest to build new pumped storage than it was a year ago? The short answer: Yes, but progress continues to be slow. And setbacks seem to continue.

In general, the news around this technology in the U.S. is a bit … lackluster.

Good news: Hydro Review reported earlier this month that the U.S. Department of Energy announced more than $13 million in funding for expansion of pumped storage hydropower and generating power at non-powered dams. Bad news: However, a month earlier in August, Alabama Power announced its intent to voluntarily surrender the preliminary permit for its proposed 1.6 GW Chandler Mountain Pumped Storage project.

Good news: The National Renewable Energy Laboratory said closed-loop pumped storage hydropower systems have the lowest potential to add to the problem of global warming for energy storage when accounting for the full impacts of materials and construction. Other good news: NREL and Argonne National Laboratory found about 1,800 sites in Alaska that are suitable for the development of closed-loop pumped storage and many more that are suitable for open-loop pumped storage. Bad news: In May, MidAmerican Energy and Missouri River Energy Services announced they discontinued development work on the 1.8 GW Gregory County Pumped Storage Project.

I’m confident that on the average the good news will outweigh the bad and the industry will continue to move forward, but the pace will be more marathon than sprint. What’s your prediction?

These findings, reported in the journal Environmental Science and Technology, provide insight into how closed-loop pumped storage hydropower — which is not connected to an outside body of water — compares to other grid-scale storage technologies.

The paper, “Life Cycle Assessment of Closed-Loop Pumped Storage Hydropower in the United States,” was written by Daniel Inman, Gregory Avery, Rebecca Hanes, Dylan Hettinger and Garvin Heath, all of whom are with NREL’s Strategic Energy Analysis Center.

The researchers analyzed the global warming potential (GWP) of energy storage technologies, which stand as a bottleneck that inhibits the end use of renewable electricity generation. Storage can help increase the grid’s ability to accommodate renewables such as wind and solar. Pumped storage hydropower is an established technology, but limited information is available about GHG emissions associated with its use. The NREL study provides a life cycle assessment of new closed-loop pump storage hydropower in the U.S. and assesses its GWP.

Pumped storage hydropower is compared against four other technologies: compressed-air energy storage (CAES), utility-scale lithium-ion batteries (LIBs), utility-scale lead-acid (PbAc) batteries and vanadium redox flow batteries (VRFBs). Pumped-storage hydropower and CAES are designed for long-duration storage, while batteries are intended to be used for a shorter time frame.

“Closed-loop pumped storage hydropower is shown to be the smallest emitter of greenhouse gases,” Inman said. “Not all energy storage technologies provide the same services. We looked at compressed-air energy storage, which allows for grid-scale energy storage and provides services like grid inertia and resilience. But pumped storage hydropower is about a quarter of the greenhouse gas emissions compared to compressed air.”

In examining pumped storage hydropower, the researchers modeled their findings based on 39 preliminary designs from 35 proposed sites in the contiguous U.S. The average closed-loop pump storage hydropower facility was assumed to have storage capacity of 835 MW and an average estimated 2,060 GWh of stored energy delivered annually. The base scenario also assumed the electricity mix would entirely come from renewable technologies.

The researchers calculated the GWP attributed to 1 kWh of stored electricity delivered to the nearest grid substation connection point. They estimated the GWP for pumped storage hydropower ranges from the equivalent of 58 to 502 grams of carbon dioxide per kWh. Hydropower offered the lowest GWP on a functional unit basis, followed by LIB, VRFB, CAES, and PbAc. They also determined certain decisions can have a substantive impact. For example, building on a brownfield rather than a greenfield site can reduce the GWP by 20%.

DOE’s Water Power Technologies Office funded the research. NREL is DOE’s primary national laboratory for renewable energy and energy-efficiency research and development. NREL is operated for DOE by the Alliance for Sustainable Energy LLC.

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.

These environmental reviews are the first steps in considering potential environmental impacts of projects that would support a cleaner energy future, while maintaining affordability, reliability and resiliency.

First, TVA said it is studying various technologies to store energy, including pumped storage hydroelectricity. TVA will need long-duration energy storage to meet energy demand as more intermittent renewable energy sources are added to the grid.

TVA is developing a Programmatic Environmental Impact Statement (PEIS) to increase pumped storage hydropower capacity within its power service area. The PEIS will evaluate the potential environmental and economic impacts of several options, which include expanding the existing 1,652 MW pumped storage facility at Raccoon Mountain or constructing a new pumped storage facility at one of two locations in Jackson County, Ala.

Public comment is invited concerning the scope of the PEIS, alternatives being considered, and environmental issues that should be addressed as a part of this PEIS. Comments must be received by July 5.

The other two projects for which TVA is seeking input are a solar and battery storage project and a natural gas combustion turbine and battery energy storage system.

TVA has a strategic goal to add 10,000 MW of solar by 2035. To facilitate that goal, TVA is developing new guidance to help review solar energy and battery storage projects that could be built on private and TVA-owned land in its service area. TVA is preparing a PEIS to help develop new guidance and a bounding analysis, including recommended environmental practices and mitigation measures, that would be part of the decision-making processes.

And TVA is considering the construction of a new natural gas combustion turbine plant and battery energy storage system in Cheatham County, Tenn. TVA intends to prepare an EIS to evaluate the potential environmental impacts associated with the proposed construction and operation of the energy complex on 286 acres of TVA-owned land northwest of Nashville, Tenn. The Cheatham County Generation Site would generate about 900 MW and replace generation capacity for a portion of the Cumberland Fossil Plant second unit retirement planned by the end of 2028. The addition of the proposed 400-MW battery storage system could also help TVA maintain grid stability and reliability as intermittent renewable generation is added to the system.

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.

FERC will now begin the environmental review and licensing process for White Pine Pumped Storage with local, state and federal agencies. Construction could start as early as 2025.

The proposed White Pine Pumped Storage project is expected to provide eight hours of energy storage at its full capacity of 1,000 MW, which is equivalent to about an eighth of Nevada’s peak power demand on a hot summer day, rPlus Hydro said. The project represents more than a $2.5 billion investment in Nevada’s energy infrastructure and will support Nevada’s move toward the clean energy goals adopted by its legislators and approved by its voters, according to a release.

“White Pine is located at an important crossroads of existing, planned and proposed electric transmission in Nevada,” states Matthew Shapiro, rPlus Hydro chief executive officer. “From this location, the project would help the state meet peak power needs in its northern and southern load areas and help stabilize the grid, while making the most effective use of renewable energy sources. With planned third-party transmission build-outs, the White Pine project will sit at the intersection of regional energy markets. It’s hard to imagine a more strategic location for this project.”

The project’s construction phase will create up to 500 construction jobs. Once operational, the plant will bring more than 35 new full-time, skilled positions to the area and provide an estimated $12 million in additional annual tax revenue for state and local governments.

In January 2023, rPlus Hydro submitted the final license application for the 900 MW Seminoe Pumped Storage project in Carbon County, Wyo.

rPlus Hydro, based in Utah, is a subsidiary of rPlus Energies and is focused on developing, designing and constructing large-scale pumped hydroelectric energy storage projects in the U.S. Black Canyon Hydro LLC, an Idaho-based company that is the license applicant for the Seminoe Pumped Storage project, is a subsidiary of rPlus Hydro. rPlus Energies develops modern power plants to contribute to rebuilding America’s energy infrastructure. rPlus Energies has over 30 projects across 15 market areas in the U.S. in active development, including solar, wind, pumped storage hydro, and solar plus battery. rPlus Energies is a subsidiary of the Gardner Group.

The funding is part of the ARPA-E Seeding Critical Advances for Leading Energy technologies with Untapped Potential (SCALEUP) program, which provides further funding to previous ARPA-E teams that have been determined to be feasible for widespread deployment and commercialization domestically. SCALEUP selectees demonstrate a viable path to commercial deployment and the ability to attract private sector investments.

Quidnet Energy was launched to build energy technology to accelerate the energy transition. Quidnet Energy’s Geomechanical Pumped Storage (GPS) technology uses existing natural resources to store renewable energy over long durations and in large quantities. The company uses existing drilling and hydropower machinery supply chains, according to a release.

The main idea is to use excess renewable energy to pump water into the ground, between rock layers where the water would be kept under pressure. The natural elasticity of certain rock formations act like a spring and keep the water under pressure. When renewable energy is not available, the valve is opened and the water is released through a hydroelectric turbine to generate electricity. Quidnet said its technology is an adaptation of centuries-old gravity-powered pumped storage, but without the massive land requirements and reliance on elevated terrain.

The ARPA-E funding will support Quidnet Energy’s project with San Antonio-based CPS Energy. Quidnet Energy will scale its GPS to a 1 MW/10 MWh commercial system that will provide CPS Energy with 10-plus-hour long-duration energy storage. The project will support CPS Energy’s “Flexible Path” Resource Plan to reduce net emissions by 80% by 2040 while allowing Quidnet Energy to advance GPS from its current pilot scale to MW-scale commercial systems.

“We’re honored that ARPA-E has selected Quidnet Energy as an awardee of the SCALEUP program,” said Joe Zhou, chief executive officer of Quidnet Energy. “This funding will support continued work on our GPS project with CPS Energy, which will demonstrate the benefits of using proven pumped hydro technology to create a long-duration energy storage resource that doesn’t require mountainous terrain.”

Duke Energy published its latest climate report Oct. 4, highlighting planned investments to the company’s generating fleet.

The company said it plans to increase capital investment for its seven regulated utilities to $145 billion over the next decade. $40 billion of that total would be for investments in zero-carbon generation sources, such as renewables, battery storage resources and hydrogen-powered natural gas technologies. It would also include extending the life of its nuclear fleet.

Duke Energy’s goal is to reach net-zero emissions by 2050. In its climate report, the company noted it also has an interim target of 80% emission reductions from 2005 levels by 2040. Duke Energy said it has already reduced emissions from its generating fleet by 44% through the end of 2021.

See the climate report here

Hydrogen

In its climate report, Duke Energy said it is implementing a solar to 100% green hydrogen-capable combustion turbine in Florida, with the goal to be operational by 2024. The company did not provide more details on the project, so we have reached out to get more details.

Duke Energy is also partnering with Clemson University and Siemens Energy to potentially produce, store and co-fire hydrogen at the utility’s CHP plant on Clemson’s campus.

The company is also partnering with Wabash Valley Resources on a DOE -funded front-end engineering design study of biomass to-net-zero-hydrogen production in Indiana.

Renewables

By 2035, Duke Energy said it expects to have 30,000 MW of renewables on its system. In September the utility completed a 700 MW solar project portfolio in Florida, one of its fastest growing states for solar power.

Completion of the 74.9 MW Charlie Creek Solar Power Plant in Hardee County marked the last of 10 solar projects to be brought online from 2018 through 2022.

By 2024, the company believes its solar portfolio in Florida will include 25 solar plants, which would provide about 1,500 MW of capacity.

Duke Energy also recently became one of two offshore wind lessees for the Carolina Long Bay area east of Wilmington, North Carolina. The lease could support the development of up to 1.6 GW of offshore wind.

New nuclear

In its climate report, Duke Energy said continuing to operate existing nuclear generation and adding new small modular reactors (SMR) are essential to maintaining emission reduction progress and achieving net-zero goals.  

The company serves an advisory role on the TerraPower-led team that is working to demonstrate GE Hitachi’s Natrium fast sodium reactor with molten salt storage. The project received one of two U.S. Department of Energy (DOE) awards through the Advanced Reactor Demonstration Program (ARDP) in 2020.

Duke Energy is also an advisory board member for NuScale, which is working toward a six-unit pilot SMR in Idaho by 2030. NuScale is the first SMR design to receive certification by the Nuclear Regulatory Commission (NRC), but it has not yet received its operating license.

In Indiana, Duke Energy is working with Purdue University on an SMR feasibility study to determine how to best meet the energy needs of the university and the state using nuclear.

Finally, Duke Energy is a member of the Market Development Advisory Committee for General Fusion, a Canadian company developing a fusion power plant technology.

Long-duration energy storage

Duke Energy is evaluating the potential for increased pumped-storage capacity to support renewables integration in the Western Carolinas. The utility has owned and operated pumped-storage hydro stations in the region since the 1970s.

The utility also said it is piloting multiple technologies, including a vanadium flow battery with the University of Central Florida; Honeywell’s new nonflammable flow battery and EOS’s Znyth Gen 3.0 zinc bromine battery at Duke Energy’s Emerging Technology Innovation Center in Mount Holly, North Carolina; and EnerVenue’s nickel-hydrogen battery at our McAlpine Creek Substation in Charlotte, North Carolina.

Duke Energy is also partnering with the Electric Power Research Institute (EPRI) to study the cost and performance of deploying Hydrostor’s advanced compressed air energy storage technology at an existing coal site in North Carolina.

How new laws help

Duke Energy believes the Inflation Reduction Act (IRA) will help drive advancements in hydrogen and storage technologies, as well as strengthen the supply chain for clean energy resources such as hydrogen, new nuclear and advanced energy storage.

Duke Energy says its preliminary modeling indicates that the IRA will reduce the cost of its energy transition through the 2030s, bringing down costs with the legislation’s tax credits for solar, wind, hydrogen, storage and new and existing nuclear.

The utility also expects to benefit from the IIJA, also known as the bipartisan infrastructure bill. Enacted in late 2021, the IIJA provides more than $60 billion for clean energy technology development and grid modernization.

rPlus Hydro is seeking approval to develop a 900 MW pumped storage project to address energy storage needs in the western U.S.

The Seminoe Pumped Storage Project would about 30 miles outside Rawlins, Wyoming. It would be the state’s first pumped hydro storage project. Construction costs are estimated at $2.5 billion.

rPlus Hydro submitted a license application to state and federal authorities, it said June 6. The application opens a multi-year study and approval process which includes engineering designs, environmental assessments and community engagement.

After a 90-day review, rPlus Hydro would then submit a final license application to the Federal Energy Regulatory Commission (FERC). That submission would include additional data collection, impact analysis and opportunities for public input.

The proposed project could include one new reservoir, underground tunnels and underground powerhouse, an intake-outlet structure in the Seminoe Reservoir, and a new transmission line. The reservoir will be located some 1,000 feet above the Seminoe Reservoir, and around two miles east of the Seminoe Dam.

Energy for pumping, and power generated by the project, would be delivered through a 30-mile transmission line connecting with PacifiCorp’s existing Aeolus Substation near Medicine Bow. 

Construction could be underway as early as 2025, pending FERC and other approvals, and would take approximately four years. 

In October 2021 our partner publication Hydro Review reported that rPlus Hydro chose the engineering firm Stantec to conduct a detailed feasibility study for the Seminoe project.

Stantec would identify and analyze the alternative intake and outlet structure types and identify the location and type of upper reservoir to complete the pumped storage scheme.

Additionally, the firm would plan and perform a geotechnical investigation to support the feasibility design of the underground facilities, identify pump-generating equipment, identify routing for a transmission line to a nearby grid interconnection, evaluate project constructability, and provide an opinion on probable construction cost.

Pumped storage is currently the largest form of energy storage on the U.S. grid today, accounting for about 95% of the country’s utility-scale energy storage capacity.

The technology is based on conventional drilling technology used in the oil and gas industry as well as off-the-shelf hydropower equipment. When low-cost electricity is available, water in a storage reservoir is pumped down a well and into a body of rock. The energy-storing rock bodies are non-hydrocarbon bearing and found in many locations, including near electricity transmission and distribution hubs.

When electricity is needed, the well is opened to let the pressurized water pass through a turbine to generate electricity, and return to the pond for the next cycle.

The approach makes use of approaches and supply chains used in the oil and gas industry, Houston-based Quidnet said, and provides a possible “pathway into the green economy” for oil patch workers.

(Read “What makes a great plant manager? CPS Energy’s James Richardson got hooked early.”)

Quidnet has developed energy storage test sites in Medina and San Saba counties in Texas. It said it is working on pilot projects in Ohio, New York, and Alberta, Canada. The company is backed by Breakthrough Energy Ventures, Evok Innovations, Trafigura, and other investors and has received support from the U.S. Department of Energy, the New York State Energy Research and Development Authority, and Emissions Reduction Alberta.

The company said that each 10 MWh system would cycle water equivalent to approximately five olympic swimming pools, or around 3.3 million gallons.

CPS Energy adopted its Flexible Path Resource Plan to close coal plants, and adopt technologies like energy storage and electric vehicles, expand renewable resources, and add more programs and services such as energy efficiency and demand response. By 2040, the utility plans to increase renewables by 127% while decreasing gas- and coal-fired generation by 72% and 61%, respectively.

EPIcenter’s Innovation Management program was engaged to support CPS Energy’s decision-making process for this novel form of energy storage. The program facilitates the process alongside a team of CPS Energy leadership to vet and implement emerging technologies. The nonprofit organization, established in 2015, is intended to speed innovation to make the production and consumption of energy smarter, cleaner, more resilient and more efficient. 

EPICenter is taking part in DISTRIBUTECH / POWERGEN 2022 with the session Energy Innovation: Move the Needle for Real on May 25.