Feature

A lot of dam potential: Renewables growth could drive massive hydro buildout

With pumped storage, hydropower can grow 50% by 2050 - if developers can get over the hurdles

U.S. hydroelectric power, the nation’s oldest and biggest renewable, could see striking growth through 2050 – if developers work around its potential harms to river ecosystems and take advantage of expected growth in wind and solar.

Hydropower provided 6.2% of the nation’s electricity, 48% of all renewable electricity, and 97% of all energy storage in 2015, according to a new report, "Hydropower Vision: A New Chapter for America’s First Renewable Electricity Source," from the U.S. Department of Energy (DOE).

That almost 101 GW of combined hydropower generating and storage installed capacity in 2015 could explode to nearly 150 GW in 2050, the report’s rigorous modeling found. But that will require technology innovations to drive the cost of project development and financing down and to solve environmental challenges.

“The growth potential for hydropower is real,” Jose Zayas, DOE’s Wind and Water Technologies Office Director, told Utility Dive.

The key word there may be “potential.” Other studies have highlighted hydropower's room for growth in the U.S., but the power sector has largely opted for wind, solar and natural gas for capacity additions.

Today's 101 GW of hydro includes 79.6 GW of generating capacity and 21.6 GW of pumped storage hydro (PSH). Investor-owned utilities, independent power producers, and private industry own 27% of it. Another 24% is owned by public utility districts, irrigation districts, states, and rural cooperatives.

Federal agencies, including the U.S. Army Corps of Engineers, the U.S. Bureau of Reclamation, and the Tennessee Valley Authority (TVA), own the remaining 49% of capacity. 

Through 2030, the DOE study reports, growth will come mainly from “optimizing and upgrading the existing fleet, and powering non-powered dams.” But between 2030 and 2050, the study foresees solar and wind rising to a 45% U.S. grid penetration, driving the development of a remarkable 35.5 GW of new PSH to balance the variable generation. 

In the models used for the study, “solar and wind increase drastically and as they enter markets, the variability on the system grows,” Zayas said. “They need a partner that is very flexible and cost-effective and pumped storage hydro (PSH) is that partner.”

Its ability to provide flexibility and other important grid services “is certainly a reason for the increased interest in hydro,” Zayas said. But many who build PSH have found it challenging to overcome cost and environmental hurdles to add new systems or upgrade existing ones. 

Hydro capacity is concentrated in the Northwest and Southeast, while Northeastern states also import a sizable amount from Canada. 
 

Making old dams new

Hydro growth will initially come in “upgrades to the existing fleet of dams already generating power or from transforming dams that do not currently have generation but are used for water storage or flood control,” Zayas said.

“As new technologies become available, there will be some new generating capacity in undeveloped waterways that are like greenfield sites," he added.

Of over 87,000 U.S. dams, less than 2,200, or 3%, both generate electricity and serve non-generating needs like flood control, irrigation, recreation, navigation, and drinking water supply, the study reports.

Development of 4.8 GW of generating potential from these non-power dams (NPD) might face significant objections from “multiple and varied interests and stakeholders,” the study warns. But as demand for electricity from renewable sources grows, objections may fade if technologies offer adequate protections to environmental, recreational, and other concerns.

“Right now, the most cost-effective option is the 6.3 GW possible from upgrades to existing generation facilities,” Zayas said. “The assets and the infrastructure are there and new designs and technologies can optimize energy conversion of even 100-year-old turbines that make the payback period as short as two years or less."

Both Duke Energy and TVA verified Zayas' point. TVA gets 10% to 12% of its electricity from hydro and it is the “cheapest form of generation and one of our foundations,” Spokesperson Scott Brooks told Utility Dive. Yet TVA “has no plans for additional hydro.”

The nation’s biggest public power provider does, however, “expect to continue to get minor uprates from our existing units as we modernize our equipment,” Brooks said.

Duke Energy had an installed hydropower capacity of 3,536 MW and obtained 6.75% of its generation from hydro in 2015, according to Spokesperson Kim Crawford. Like TVA, hydro is "important" to Duke, Crawford said, but “we do not have plans to build new hydropower."

The utility is “looking at potential hydropower upgrades” but also intends to “continue to invest in diverse generation, such as natural gas, nuclear and renewables,” she said.

In the Pacific Northwest, Bonneville Power Administration (BPA) gets 83.6% of its generation from the 31 federal dams on the Federal Columbia River Power System. It's “the largest carbon-free energy system in the nation,” according to Spokesperson Joel Scruggs.

Echoing TVA and Duke, BPA's “asset investment strategy prioritizes upgrades and operation and maintenance at the system’s facilities over the next 50-plus years to ensure BPA’s limited capital dollars are going to the right areas at the right time,” Scruggs said.

 

Non-power dams and new development 

Upgrading non-power dams is “the next most cost-effective opportunity," beyond upgrading existing generating faciilities, Zayas said. "Most of the civil infrastructure is there and the environmental elements have been addressed and that makes up 50% to 60% of the total cost of a new hydro plant." 

NPD development presently has an average capital cost of $4,200/kW to $5,800/kW, according to the study. The capital cost for new stream reach development (NSD), which is installation of new generating dams, is $6,000/kW to $7,000/kW. 

Portland General Electric owns and operates 191 MW of hydropower capacity in Western Oregon and a 67%, or 300 MW, share of another project in Central Oregon, Spokesperson Steve Corson told Utility Dive.

It is currently adding micro-turbines that will add 4 MW of nameplate capacity at sites on its century-old system along the Clackamas and Willamette River “to take advantage of downhill flow that wasn’t previously being used for power generation,” Corson said.

NSD “is the longer play and by far the biggest resource,” Zayas said. But it is expected to provide only 1.75 GW of 2050 capacity because, “like any greenfield development, it includes costs for infrastructure and environmental permitting.”

Of the three ways to do new stream development, building a new dam with turbines has the most significant environmental impacts, according to Zayas. One alternative is to divert part of a river’s flow through a turbine and restore the flow on the other side of the generator. The other is to place marine hydrokinetic generators into the river’s flow.

“The last two sacrifice the higher capacity factor of capturing the flow behind a dam in order to be more environmentally safe,” Zayas said.

PGE, Oregon's biggest electricity provider, is watching technology developments and looking for potential at existing dams that don’t currently have turbines, Corson said, because “new hydro development opportunities tend to be small and very challenging to permit.”

Much of the permitting challenge for NSD is in environmental regulations. Both American Rivers, an environmental group chartered to remove dams and restore waterways, and the Nature Conservancy, a nationally recognized environmental advocate, reviewed the DOE study. But both also have qualifications. 

“Hydropower – done right – is an important part of our nation’s energy mix. But the key lies in getting it right,” according to American Rivers, which has worked for almost four decades to protect U.S. waterways.

Hydropower “must be sited, operated, and mitigated responsibly,” it says. But new environmental laws and values and effective oversight by the Federal Energy Regulatory Commission (FERC) make it possible to think about NSD as a tool in the much bigger fight against climate change, it adds.

Hydropower has done harm to waterways in the past but its emissions-free, baseload capacity and potential to provide storage capacity and flood control can’t be ignored, according to The Nature Conservancy.

DOE is working on advances that can bring the potential of NSD to market in more cost-effective and environmentally friendly ways by more efficiently managing the regulatory challenges, Zayas said.

 

New tech could grow "dispatchable" hydro

Largely because of regulatory hurdles, little new pumped storage hydro has been built in recent years, Zayas acknowledged. But as variable renewables grow, there will be demand for the services it can provide, he argued.

Brookfield Renewable Partners currently owns and operates over 8,400 MW of hydropower globally, over 4,800 MW in North America, and a 600 MW PSH site in Massachusetts, Communications Manager Angela Fentiman said.

Brookfield's effort to develop a new 280 MW PSH project in California is part of its current focus on opportunities to pair dispatchable hydro resources with new wind or solar development, she said. The recent Massachusetts energy bill that recognized such blended offerings “adds to our optimism about the future of hydro.”

New PSH systems, which will be developed most in the Southwest for solar and in the Midwest for wind, will be very different than existing ones, according to the study.

Advanced technologies will have “improved capabilities such as adjustable speed, closed loop, and modular designs,” it adds.

Current open loop PSH was designed to support nuclear plants that consume massive amounts of water and there was no point in being concerned about water use. But newer designs are more efficient. 

“The two large pools of a closed loop pumped storage hydro system are co-managed," Zayas said, "so water is lost only to evaporation, making it more acceptable to environmental advocates."

A new adjustable speed capability will more efficiently provide the “flexibility, reserve capacity, and system inertia” the grid will need to integrate higher levels of variable renewables.

But even with these new capabilities, it can be difficult or PSH systems to pencil in today's interstate energy markets. The DOE study recommends new policy efforts to define the right market mechanisms to accurately compensate PSH for this full range of grid services it can provide. Recent regulatory work in California echoes the point. 

“Justifying investments to upgrade existing facilities or build new pumped storage projects remains very challenging under current regulatory structures and electricity market economics," agreed a recent California Public Utilities Commission (CPUC) workshop white paper. “To rectify this, regulators should do the necessary work to quantify the value of PSH as generation and grid services."

California has seven PSH facilities with a total capacity of 3,967 MW, according to the white paper. As a “peak-loading technology, [PSH] generally competes with natural gas peaking power plants, meaning that the viability of pumped hydro depends on the price of natural gas.”

Pacific Gas and Electric and the Los Angeles Department of Water and Power are already using PSH capacity to manage solar over-generation, according to the white paper. Operators of several of California’s existing pumped storage projects "are changing their operational profiles as renewable energy production increases,” it adds.

In this way, PSH and battery energy storage are complementary because “even the smaller, more modular PSH systems proposed in the study are to support the bulk transmission system,” Zayas said. “Batteries are more for the distribution system. Innovation may affect that complementary relationship over time but in the near term, PSH will remain over 95% of U.S. utility-scale storage.”

First pumped storage in 30 years nearing construction 

One California project illustrates many of the issues in building new pumped hydro facilities.

After a protracted permitting effort, the Eagle Mountain Pumped Storage Project is expected to begin construction by 2019 and be online by 2023, providing 12 hours to 18 hours of storage, according to the CPUC white paper. It will be able to ramp up at 20 MW per second in either energy generation or energy storage mode.

Its long development “exemplifies the urgency needed to start new projects; anything that is begun today can take a decade or more to come online,” the white paper notes.

After a five year process, Eagle Crest Energy (ECE) got a 50-year Federal Energy Regulatory Commission (FERC) license in 2014 for a former mining site, according to Spokesperson Steve Lowe. It was the first large PSH site licensed in three decades. Final Bureau of Land Management environmental reviews are expected by the end of this year.

PSH is likely to become increasingly important as the California Independent System Operator (CAISO) works to accommodate major changes on its system, Lowe said.

CAISO faces the closures of the San Onofre and Diablo Canyon nuclear facilities and the shuttering of multiple large natural gas plants because of water use regulations. It also must cope with a 50% by 2030 renewables mandate and a rapidly increasing penetration of distributed energy resources.

“Large bulk energy storage projects like Eagle Mountain will provide a cost effective way to store the excess renewable energy produced and then deliver electricity to households during peak demand periods, solving intermittency issues and maintaining the current high levels of grid reliability,” Lowe said.

Future PSH development faces hurdles that Eagle Mountain’s unique site allowed it to get over, Lowe said. “Unlike other projects, ECE will utilize already massively disturbed private land.”

Repurposing a barren former mining site meant minimal environmental challenges, he explained. The mine’s existing pits reduced reservoir construction costs and its groundwater supply eliminated any negative impacts to aquatic ecosystems that often result with hydropower.

Finally, the site’s proximity to several solar power plants and the existing regional transmission line similarly eliminated costs and increased the project's value.

While sites like Eagle Mountain may attract consensus between the power sector and environmentalists, not all hydro growth will come with so few ecological tradeoffs. In a recent blog post, Giulio Boccaletti, Managing Director of The Nature Conservancy, summed up the central question on the future of hydropower in the U.S.

“The most important question may not be whether to build,” he observed, “but rather about where and how hydropower is built.”

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