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).