Often overlooked in the dash toward wind and solar, hydropower remains a major player in renewable generation. But recent trends suggest a shift toward pumped storage and retrofitted generation may be in the works.
Can hydropower get some love?
Even fans of renewable energy can be forgiven for having forgotten about a resource that—up to now—has produced more electricity than wind, solar, biomass, and all other renewable sources combined. Energy sector news is dominated by reports about the latest big solar plant coming online, ever-larger wind turbine models coming on the market, and seemingly never-ending battles over subsidies and credits.
The limited public interest in hydropower is understandable to some extent. Hydro is a mostly low-tech, mostly familiar resource that generally makes waves only of the watery sort. The giant hydroelectric projects of the 20th Century have become part of the landscape in North America, and relatively few more of those are likely to ever get built. Wind and solar have seized not just the headlines but also the generation momentum: The U.S. Energy Information Administration predicted in this year’s Annual Energy Outlook that 2014 will be the first year ever in which total non-hydro renewable generation will exceed total hydropower generation.
That’s a crown that hydro may struggle to get back. Total U.S. hydroelectric capacity (including pumped storage) increased about 1.3% between 2002 and 2012, a period in which wind capacity increased more than 1,300% and solar increased nearly 800%.
Hydro has also missed out on a lot of the support given to wind and solar. Focused as many renewable subsidies are on fostering new capacity, many incentives specifically exclude existing hydroelectric generation. The Environmental Protection Agency’s (EPA’s) proposed carbon emissions standards barely mention hydro, leaving several hydro-heavy states feeling left out. Nuclear generation gets a credit to help keep existing plants operational in the face of competition, but existing hydro appears to get nothing. In fact, the EPA didn’t consider hydro at all in calculating several states’ baselines for renewable generation (on the rationale that doing so would disadvantage states with no or limited hydro potential).
Forgotten But Not Gone
But counting hydro out would be a big mistake.
A common misconception is that hydro is “built out” in North America—especially in the U.S.— with nearly all large potential sites already harnessed. In fact, in the U.S. alone there is substantial undeveloped hydroelectric potential, almost as much as is currently used for generation. A study by the Oak Ridge National Laboratory (ORNL) released in April 2014 found that there was more than 84 GW of untapped potential nationwide, though this included areas where hydro development is prohibited. When excluding areas that are within or close to National Parks, Wild and Scenic Rivers, and Wilderness Areas, the study found that there was still more than 65 GW of potential capacity that could generate almost 350 TWh annually.
The potential capacity goes beyond greenfield projects. An earlier ORNL report from 2012 found that the more than 54,000 unpowered dams across the U.S. represented substantial opportunities for retrofitting generation at a fraction of the cost—and hassle—of new dams. Though most of these dams are too small or poorly configured, the 600 or so most favorable sites could be retrofitted with a total of around 10 GW of capacity.
The highest potential was found in the Ohio, Upper Mississippi, and Arkansas-White-Red river basins, where many U.S. Army Corps of Engineers (USACE) navigational locks could be fitted with generation (Figure 1). The study identified 87 such sites with a total 6.9 GW potential. Not surprisingly, most of the untapped generation resources were found in the Midwest and Northeast; relatively little was located in the West.
These numbers are no news to hydropower industry people in the U.S., many of whom are focusing their development efforts on smaller retrofits. “There’s a recognition recently that there is a lot of existing infrastructure out there that we can take advantage of,” Mario Finis, North America energy and industry director and former global director for hydropower and dams for MWH told POWER in an interview.
The biggest attraction, naturally, is the reduced cost of development: With the dam already in place, most of the costs of a comparable greenfield project have already been incurred. Another bonus of these smaller projects is that they can provide relatively inexpensive support for intermittent renewables (see “Small Hydro, Big Opportunity” in the May 2013 issue).
“There are some interesting interactions between wind and solar that are helping drive the need for hydro in terms of some of the ancillary services that hydropower generation can provide.” In this, Finis said, direct policy support for wind and solar is creating indirect support for dispatchable generation like hydro. “Investors and utilities that are taking a more long-term view in terms of generation resources are looking at hydro as a way to help balance” wind and solar generation.
Furthermore, while big hydro has gotten the cold shoulder from state renewable energy portfolios, smaller projects in the neighborhood of 30 MW can often qualify, Finis said. “There’s also a sort of renewed sensitivity to the smaller projects having less overall impact on the environment.”
A Promising Niche
One of those smaller retrofit projects is taking shape at the Red Rock Dam on the Des Moines River in Iowa (Figure 2). The 36.4-MW-rated project, with a peak output of 55 MW, is being built by Missouri River Energy Services (MRES) for the Western Minnesota Municipal Power Agency (WMMPA). MWH is supplying engineering and consulting services, and Voith Hydro is supplying the generators and turbines. Ground was broken on the Red Rock Hydroelectric Project (RRHP) in August, with completion scheduled for 2018. The $379 million facility will be operated by MRES and financed and owned by WMMPA.
|2. Red Rock retrofit. Missouri River Energy Services is in the process of adding 36.4 MW of hydro generation to the Red Rock Dam in Iowa. The powerhouse will be located on the near bank below the dam. Courtesy: MWH|
While there are avoided costs involved with a retrofit as compared to a new project, there are also some new challenges. As Ralph Watt, MWH’s project manager for RRHP explained to POWER, the Red Rock Dam was built primarily for flood control, with recreation as an additional benefit. “One of the major challenges was to construct the facility without having any impact on the existing operation,” he said. Because of the demands of flood control operations, the water level at Red Rock can fluctuate up to 40 feet through the course of the year, meaning the construction site is sometimes completely dry and sometimes flooded. “It changes all the ways you would approach building the project.”
Like many other potential projects, RRHP is being built at a USACE dam. “That adds another level of regulatory scrutiny,” Watt said. “In design and construction of these facilities, we had to make sure that we satisfied the Corps of Engineers concerns and requirements when it comes to any impact we might have had on their structures.”
Those concerns may be getting some revision. In July, the USACE updated its policy guidance on requests to modify USACE-owned facilities under Section 408. In it, the USACE says that “USACE and [the Federal Energy Regulatory Commission (FERC)] have agreed to work with each other and with other participating agencies or entities, as appropriate to ensure that timely decisions are made and that the responsibilities of each agency are met.” The updated guidance extends not just to conventional hydropower projects but also to “non-conventional” facilities such as hydrokinetic generation (which relies on natural flow rather than a hydraulic head) that could be added to jetties, levees, and navigational channels.
Other policy support may be on the way was well. In 2011, the Obama Administration launched the Federal Infrastructure Permitting Dashboard, which is designed to expedite the licensing process for critical infrastructure projects “that will create a significant number of jobs, have already identified necessary funding, and where the significant steps remaining before construction are within the control and jurisdiction of the federal government and can be completed within 18 months.” While the list includes several wind and solar generating facilities, RRHP is so far the only hydropower project to receive such expedited review. Hydropower backers are hoping the success of RRHP will lead to others.
Hydro Is Still Big
None of this is to suggest that the days of Big Hydro are over, even in North America.
Quebec, which gets a whopping 96% of its electricity from hydropower, is still looking to add capacity. Hydro-Québec’s four-unit, 1,550-MW Romaine project is partway through full commissioning, with Unit 2 scheduled for service this year, and the remaining units expected to be complete by 2020. Equipment for the two largest units, 2 and 3, is being supplied by Alstom. Upgrade projects to add capacity at several older facilities are also under way.
The Romaine project has been controversial in part because it may prove to be a money loser. Hydro-Québec earns substantial income from exporting electricity to customers in the northeastern U.S., but with the shale gas boom having depressed wholesale power prices across the region, it is not clear if Romaine will ever earn enough money to pay for itself.
Out west, BC Hydro is still pushing forward with the Site C project on the Peace River in northeast British Columbia. The proposal, which has been in the works for more than 30 years, is projected to generate 1,100 MW. The plan is still in the permitting process, but BC Hydro hopes to have it online by 2024. This project as well is facing stiff opposition, much of it from First Nations groups concerned about lost farmland and fishing grounds.
Perhaps the biggest growth area for North American hydro is pumped storage, Finis said. “One of the great drivers for these projects is going to be the integration of renewable energy resources.”
In terms of storage options, pumped storage hydropower reigns supreme in terms of how much capacity it can add to the grid with existing technology. That means big potential in areas with a lot of renewable capacity being added.
“We are seeing quite an interest in development of storage projects right now in the U.S.,” Finis said.
One of those projects is taking shape in Northern California. The Sacramento Municipal Utility District (SMUD) is conducting feasibility testing for a 400-MW pumped storage facility that would be added to its existing Upper American River Project near Lake Tahoe. The Iowa Hill plant would add a storage pond 1,200 feet above a bend in the existing Slab Creek reservoir. The $800 million project could begin construction as soon as 2018 if SMUD decides to proceed.
An even larger pumped storage project is planned for Southern California, on the site of an old iron mine near Joshua Tree National Park. The 1,300-MW closed-loop facility would convert the old mining pits into storage reservoirs. GEI Consultants is leading the project for Eagle Crest Energy Co. FERC gave the project a license to proceed in July after state water quality officials approved the plan in 2013, but roadblocks remain. In particular, the effect on area water resources from filling the over 17,000-acre-feet project—the plan is to use groundwater drawn from nearby wells—is sure to be controversial in the midst of one of the worst droughts in California’s history. If completed, it would be the fifth-largest pumped storage facility in the U.S.
No Silver Bullet
Despite the advantages, getting backers for hydropower projects in the current environment can be tricky, Finis acknowledged. “Hydro is still facing some challenges when it comes to financing.”
There are a couple of factors behind this, he explained. One is the longer period for FERC licensing for hydro generation, which can take three to five years. However, changes in the law in 2011 are intended to expedite development at unpowered dams like Red Rock. FERC has now been directed to consider a shortened two-year licensing process for such facilities.
The long licensing period stands in stark contrast to how long it actually takes to build small retrofits. In especially favorable sites, the plant can be up and running in less than a year. The 6-MW Mahoning Creek Hydroelectric Project at Mahoning Creek in Armstrong County, Pennsylvania, began construction in March 2013 and was online by December. The project, retrofitted to a flood control dam built in 1941, was developed by Enduring Hydro, an investment and development firm that specializes in small hydropower.
Another roadblock is the larger upfront costs compared to equivalent natural gas generation. “To develop hydro, you really have to have more of a long-term outlook,” Finis said, and focus on the lower levelized cost of energy over the project lifetime. “You’ll have more cost on the O&M side, replacement side, and fuel side with other technologies that you don’t necessarily have with hydro.”
This is an important advantage when you consider the much longer lifespan for a hydro plant compared to a gas plant: Some hydro projects in the U.S. have been reliably generating electricity for more than 100 years.
The look of the hydro sector may be evolving, but all signs are that its legacy will continue. ■
— Thomas W. Overton, JD is a POWER associate editor (@POWERmagazine, @thomas_overton).