There is a lot of potential for pumped-storage development in the U.S. What will it take to get construction of this valuable generating resource moving forward again?
By Elizabeth Ingram
There’s no doubt that pumped-storage hydropower is a valuable resource in the U.S. These facilities are ideal to store energy from and balance intermittent renewables, such as wind and solar, providing stability and flexibility to the transmission grid. In fact, in 2012, data from EPRI indicates pumped-storage hydropower accounted for more than 99% of bulk storage capacity worldwide, about 127,000 MW.
However, it’s also an undeniable fact that there has been little new development in this field in the U.S. in the past two decades, which seems to indicate the atmosphere is not favorable for encouraging construction of pumped-storage facilities. But this may be about to change. There has been a stirring of movement lately, primarily on the regulatory side, with regard to pumped-storage hydro in the U.S.
This article analyzes the activity to date and provides some insight into the (potentially) bright future of this valuable generating resource.
Background on pumped storage
My research indicates the first use of pumped-storage units in the U.S. was in 1930 by Connecticut Electric and Power Co., pumping water from the Houstatonic River. This technology actually dates to much earlier outside the U.S., with pumped storage first being installed in the 1890s in Italy and Switzerland, according to EPRI.
The heyday of this technology in the U.S. appears to be the 1960s and 1970s, with facilities going on line in California, Colorado, Massachusetts, Michigan, Missouri, New York, Oklahoma, Pennsylvania, South Carolina, Tennessee and Virginia. The 3,003-MW Bath County facility, which was completed in 1985 in Virginia, is the largest pumped-storage plant in terms of generating capacity in the world.
It seems that the most recently completed pumped-storage project in the U.S. is the 40-MW Lake Hodges plant, built by the San Diego County Water Authority (SDCWA) at the existing Olivenhain Reservoir and completed in September 2012. (For more on this project, see the sidebar on page 14.) However, before that it had been more than 15 years since such a project was completed, that one being the 1,035-MW Rocky Mountain facility in Georgia, owned by Oglethorpe Power Corp., which began operating in 1995.
According to the Federal Energy Regulatory Commission (FERC), there are a 24 operating pumped-storage projects under its jurisdiction, with a total installed capacity of about 16,500 MW. Only one of these projects was authorized in the past 30 years.
The Energy Storage Association reports that the 40 total pumped-storage facilities operating in the U.S. provide more than 20,000 GW of capacity, or nearly 2% of the country’s electrical supply system. While these numbers may sound good, compare the shares in Europe (nearly 5%) and Japan (about 10%). It is clear we have a long way to go in the U.S.
However, the number of pumped-storage projects in the U.S. looks set to jump considerably. FERC says there are about 50 active preliminary permits for these projects, representing more than 37,000 MW of capacity. And while only a third of the operating projects under FERC’s jurisdiction are located west of the Mississippi River, more than 80% of the preliminary permits are located west of the Mississippi, where the majority of existing and proposed solar and wind generation is located.
The majority of the recently proposed pumped-storage projects would employ a closed-loop system, FERC says. These projects are not continuously connected to a naturally flowing water feature. (At this time, only one of the constructed projects under FERC jurisdiction is closed loop.) In addition, many of the proposed projects would use variable-speed pump-turbines that would allow for more flexible operation than the current fleet.
What is behind the resurgent interest in pumped storage in the U.S.? According to Debbie Mursch, chair of NHA’s Pumped Storage Development Council, “Policy makers are finally realizing that we can’t continue to increase the amount of intermittent generation while at the same time removing baseload nuclear and coal plants and not consider the need for grid-scale storage.” The council was established to provide a platform for the industry to keep abreast of the latest developments in pumped storage, be it legislative, new technology, policy or global trends. The council also aims to educate policy-makers and the public on the benefits of pumped storage.
|The two pump-turbines in the powerhouse of the 40-MW Lake Hodges pumped-storage project began operating in 2012. (Courtesy San Diego County Water Authority)|
Perhaps the greatest quality of pumped storage is that it is the only commercially proven technology available for both grid-scale energy storage and power generation, Mursch says. Developing additional pumped storage, particularly in areas with recently increased wind and solar capacity, would significantly improve grid reliability while reducing the need for construction of additional fossil-fueled generation. Grid-scale storage also could reduce the amount of new transmission required to support many states’ RPS goals, Mursch says.
Utilizing pumped-storage projects also allows utilities to follow load and respond to rapid changes in demand for power on the grid using a non-emitting resources, as opposed to fossil-fuel-fired units, Mursch says. This allows the utilities to run their fossil units more efficiently and reduces carbon emissions output from these plants.
New development in the offing
There has been much recent activity through FERC with regard to proposed new pumped-storage facilities.
For example, FERC authorized construction of the 400-MW Iowa Hill pumped-storage development as part of its August relicensing of the 637.3-MW Upper American River project in California. Iowa Hill is to be an off-stream plant that pumps water from the existing Slab Creek Reservoir into the new Iowa Hill Reservoir. The powerhouse will contain three 133-MW pump-turbine units.
Many companies are involved in development of this project, including AF-Consult of Switzerland; AMEC in London; Ascent Environmental in Sacramento, Calif.; Carlton Engineering in Folsom, Calif.; Crux Subsurface in Henderson, Nev.; Foxfire Constructors in San Clemente, Calif.; GEI Consultants in Woburn, Mass.; HDR Engineering in Omaha, IEC Corporation in Sacramento; Jacobs Associates in San Francisco, Calif.; Northwest Hydraulic Consultants in Vancouver, British Columbia, Canada, and Stillwater Sciences in Berkeley, Calif.
In addition, FERC issued a license to the 1,300-MW Eagle Mountain pumped-storage project in June, authorizing Eagle Crest Energy to build the project at the site of an inactive iron mine in Riverside County, Calif. There will be a head of 1,400 feet between the reservoirs, created by adding saddle dams and liners to two abandoned mining pits. GEI Consultants, a developing partner in the project, says Eagle Mountain will be an “integral component of California’s renewable energy policies and its goals for reduction of greenhouse gas emissions.”
The primary environmental issues associated with the project are effects of its construction and operation on groundwater, water quality and terrestrial species (including several sensitive bat species, the desert bighorn sheep and threatened desert tortoise). Groundwater will be pumped from a series of proposed wells in the Chuckwalla Basin to fill the reservoirs and replace water lost to evaporation.
With California seemingly at the epicenter of the interest in pumped-storage development, it’s not surprising I am reporting on interest in developing a third project in the state. SDCWA is looking into adding a 500-MW pumped-storage plant near its San Vicente Dam following the closure of the 2,200-MW San Onofre nuclear power plant. SDCWA recently raised the dam, adding 152,000 acre-feet of water storage capacity to the reservoir.
Another state where we’re seeing interest in pumped storage is Hawaii. In August, Paniolo Power Co. LLC announced it planned to issue a request for qualifications seeking an engineering-procurement-construction contractor to develop a pumped-storage project on Parker Ranch. Capacity of this project could range from 10 MW to as much as 200 MW. The energy developer said pumped storage would allow wind and solar energy that otherwise would be curtailed to be used to pump water that would then be released in the evening to meet peak loads being served by expensive oil-fired generation.
Also in Hawaii, the Kauai Island Utility Cooperative is pursuing a pumped-storage project to be located on state land on Kauai’s west site. The co-op has obtained access to two potential sites that will allow it to conduct technical studies.
Moving this development forward
FERC says good siting and consultation, as well as filing of a complete application that addresses stakeholder concerns, are key to expediting the licensing process. On its website, the commission has state-specific lists of potential stakeholders to consult as a starting point. Developers should also consult with other site-specific interested entities, FERC says. Early consultation with key stakeholders on potential environmental impacts and other concerns, in addition to technical site evaluation, will facilitate optimal site selection. Continued consultation on study needs and conduct of needed studies is essential, FERC adds. Should a developer not agree on a study after earnest negotiations with stakeholders, the pre-filing dispute resolution process should be used, rather than taking the chance on an inadequate application, which can delay the post-filing application process.
FERC also encourages developers to contact commission staff before filing a notice of intent to file an application and a preliminary application document to discuss process selection and FERC resources that may be helpful to them.
The Pumped Storage Development Council issued a whitepaper on Challenges and Opportunities for New Pumped Storage Development. This whitepaper cites the need for grid reliability in the U.S., provided by reliable, affordable and grid-scale energy storage: hydropower pumped storage. With the tremendous growth of wind and solar generation in the past decade, the grid is affected by the variability of this supply. The whitepaper also says that “current market structures and regulatory frameworks do not present an effective means of achieving this goal.” NHA’s key policy recommendations are:
- Create market products that allow flexible resources to provide services that help meet electric grid requirements, including fast-responding systems that provide critical capacity during key energy need periods;
- Level the policy playing field for pumped storage hydropower with other storage technologies to encourage the development and deployment of all energy storage technologies;
- Recognize the regional differences within the U.S. generation portfolio and the unique roles energy storage technologies play in different regions;
- Recognize the energy security role pumped storage hydropower plays in the domestic electric grid;
- Establish an alternative, streamlined licensing process for low-impact pumped storage hydropower, such as off-channel or closed-loop projects;
- Improve integration of federal and state agencies into the early stage licensing processes for pumped storage hydro; and
- Facilitate an energy market structure where transmission providers benefit from long-term agreements with energy storage facility developers.
NHA says the barriers that prevent new pumped storage from being developed are slowly being recognized and reduced and/or removed. For example, Mursch says, there is a lack of markets to fairly compensate pumped storage for the many electrical benefits it brings to the grid. The U.S. Department of Energy recently provided funding to Argonne National Laboratory to model/quantify these benefits. Argonne is leading a team that is seeking to provide a comprehensive study of the technical and market operations, economics and value of conventional hydro and pumped-storage plants for power system operation, including their role in accommodating a larger share of variable renewable energy sources.
Another example is the time it takes to get a project licensed as compared with other technologies. NHA says gas plants can be licensed in fewer than two years, while pumped storage may take five to six years. Many developers today are considering closed-loop systems because they are more environmentally benign and FERC is looking to reduce licensing time for these facilities to two years, as mandated in the Hydropower Regulatory Efficiency Act of 2013.
“I believe the time is now or never that new pumped-storage plants will be built,” Mursch says. With the need for grid-scale storage being greater than ever and barriers to development slowly being removed, pumped storage’s time has finally come in the U.S., she says.
Even the U.S. Department of Energy is getting in on the act with its Hydropower Vision plan. As part of this plan, DOE will issue a report that seeks to answer a number of questions regarding the current state and future of hydroelectric power in the U.S., among these how pumped-storage projects factor into America’s energy mix.
Pumped storage in Canada
The landscape for pumped-storage development in Canada is different from that in the U.S. because Canada still has significant untapped potential for conventional hydro development.
But, there has been some recent interest in bringing pumped storage to Canada. For example, Northland Power, based in Toronto, proposes a 00 million project, called Marmora, that would use an abandoned open-pit mine to provide a capacity of 400 MW. The company would build a new upper reservoir for this facility, and the powerhouse would be equipped with Francis pump-turbine units.
A story of modern-day development
Development of the 40-MW Lake Hodges pumped-storage project was accomplished at a time when new projects of this type simply were not being brought on line in the U.S. So development of this facility was both a challenge and an achievement for the San Diego County Water Authority in California, says Frank Belock, deputy general manager.
Olivenhain Reservoir was impounded in 2003 as part of SDCWA’s Emergency Storage Project to protect the region from severe water supply shortages. Lake Hodges sits 770 feet lower in elevation, leading SDCWA to decide in 2002 to add generating capability to the pumping station that was already being designed. From the time the pumped-storage component was included in the scope of work until the generating station was completed, 10 years elapsed, Belock says.
The bottom line benefit in adding this pumped-storage component was estimated to be $2 million to $3 million in annual revenue from power generation that could be used to offset the cost of water supply and delivery. Belock says the 0 million pumped-storage plant was cash financed.
Thanks to the success of this project, SDCWA announced in July 2013 that it was preparing to assess the potential to develop a larger pumped-storage facility (up to 500 MW) at its San Vicente Reservoir. Construction of this facility is anticipated to take at least five years.
Elizabeth Ingram is managing editor of Hydro Review.
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