A pair of bills signed by President Barack Obama to streamline the approval process for small hydropower facilities has led to an increase in project investment and calls by proponents for more legislative fixes.
But a conservation group has warned the industry against assuming the new laws indicate broad public support for all new hydropower, regardless of impacts.
The small-hydropower laws are “a step in the right direction but not the final step,” Kevin Frank, president and chief executive officer of Voith Hydro, a major manufacturer of hydropower equipment, told Bloomberg BNA.
A second step would be to further streamline the approval process for hydropower, which now accounts for 7 percent of the electrical generating capacity in the U.S. Given the potential of the U.S.'s 80,000 dams that lack power facilities, the laws are expected to spur activity, he said.
The Hydropower Regulatory Efficiency Act (P. L. 113-23) and the Bureau of Reclamation Small Conduit Hydropower Development and Rural Jobs Act (P. L. 113-24) will speed up the approval process for small hydropower projects, which typically can involve dozens of state and federal agencies and take up to five years, Matt Nocella, assistant manager of strategic communication for the National Hydropower Association, said in an email.
Reducing the regulatory burden and “capital intensive” up-front costs would remove the final barriers to rapid growth in the industry, he said.
In addition to Voith, other major hydropower manufacturers include Alstom, Andritz and Weir American Hydro. Smaller manufacturers operating in the U.S. include Canyon Hydro and Mavel Americas.
Developers include investor-owned utilities such as American Electric Power, independent power producers such as PPL Holtwood and municipalities and nonprofit public power corporations such as American Municipal Power.
Congress overwhelming supported the hydropower bills, with the Senate voting 100-0 on both. In the House, P. L. 113-23 also won unanimous consent, and only seven House members voted against P. L. 113-24. Obama signed the laws Aug. 8.
During a September congressional hearing on hydropower, Rep. Scott Tipton (R-Colo.), who sponsored P. L. 113-24, said: “Large-scale federal and non-federal projects are hindered by excess litigation, regulation and arbitrary requirements. Bureaucracy is exactly what we did away with in my hydropower legislation. We need to apply similar thinking to larger projects as well.”
Rupak Thapaliya, national coordinator for the Hydropower Reform Coalition, a conservation group seeking to improve the condition of dammed rivers, called the two laws signed by Obama “a very good approach to hydropower development.”
He said that if done right, hydropower has a place in the nation's energy portfolio. “However, pristine rivers should not be a way to build energy projects,” Thapaliya told Bloomberg BNA.
Rich Bowers, the coalition's Northwest coordinator, said that while both laws refrain from encouraging development of new dams, a minority of private developers and utilities may be creating a “slippery slope” by arguing that the success of the legislation demonstrates broad support for all new hydropower, regardless of impact. “That's just not true,” he said.
P. L. 113-23 increases the rated capacity of small hydropower projects eligible for a Federal Energy Regulatory Commission licensing exemption from five megawatts to 10 MW. To qualify, a project must be located at an existing dam that doesn't require construction or enlargement of an impoundment or it must use the hydropower potential of a natural water feature, such as a waterfall.
Also, developers must address fish and wildlife protection as well as other environmental concerns.
According to the Energy Department, non-powered dams were constructed for one or more non-energy benefits, including flood control, water supply, navigation or recreation. Non-powered dams range in size from small berms impounding farm ponds to large Ohio River and Mississippi River dams that pool water to maintain navigation depths during low-flow periods.
The majority of the hydropower
projects FERC regulates are small projects, with about 70 percent having an
installed capacity of five MW or less.
Frank of Voith Hydro told Bloomberg BNA that while expanding the FERC licensing exemption from five megawatts to 10 MW in P. L. 113-23 is small, such projects are “still fairly significant” in terms of size and costs.
By waiving the licensing requirement, the law is expected to provide investors with more regulatory certainty and lower up-front costs, Nocella said.
Other Qualifying Projects
The law also seeks to promote hydropower projects at artificial aqueducts, canals, tunnels, pipelines or other water conveyances, referred to as conduits. To be eligible for an exemption from FERC licensing requirements, the conduit project must primarily distribute water, as opposed to generating electricity, for consumption by farms, industry or municipalities.
The law also expands the scope of the
FERC licensing exemption for hydropower conduit facilities with an installed
capacity limit of 15 MW to a limit of 40 MW.
Previously, a 40 MW exemption was available only to state or local government facilities used solely for municipal water supply purposes.
Conduit facilities of up to 40 MW remain subject to federal and state fish and wildlife agency review. However, developers of smaller conduit projects of up to five MW aren't subject to fish and wildlife review and only need to file a notice of intent with FERC, which must provide a 45-day public comment period.
To further promote hydropower, the law allows FERC to extend preliminary permits for any project for up to two years, for a total of five years.
Also, the commission must, if deemed practicable, initiate a two-year licensing pilot program for hydropower projects at non-powered dams and closed-loop pumped storage projects.
According to FERC spokeswoman Celeste Miller, the commission is moving forward with the pilot project for which criteria, such as cutoff size for projects, have yet to be determined. The pilot program, if deemed practicable, is expected to begin Feb. 5.
Sharing Lessons Learned
A two-year licensing
program is bound to carry “lessons learned” that may be applicable to other
hydropower projects across the U.S., Nocella said.
Finally, the law requires the Energy Department to study the “range of opportunities” for U.S. hydropower from conduits and the potential for new and existing pumped storage facilities to support intermittent renewable energy generation and provide grid reliability.
Meanwhile, P. L. 113-24 seeks to promote hydropower generation at 373 conduits owned by the Interior Department's Bureau of Reclamation by allowing companies to develop small projects of five MW or less to generate and sell power. The conduits are located in Arizona, California, Colorado, Idaho, Montana, Nebraska, New Mexico, Nevada, Oregon, South Dakota, Utah, Washington and Wyoming.
Developers may seek approval for a small hydropower project as long as the conduit remains a supply of water for irrigation districts. Municipalities that operate or receive water from the conduit have a right of first refusal to develop their own hydropower projects.
Also, the law stipulates that the Bureau of
Reclamation is the sole agency in charge, whereas previously FERC could have
been deemed the lead agency.
Environmental assessments and impact statements typically required under the National Environmental Policy Act are unnecessary under the law's provisions for “categorical exclusions,” as long as the Bureau of Reclamation finds no “extraordinary circumstances.”
These would be deemed to exist if the project would significantly impact public health or safety, natural resources, wildlife or the environment. If the bureau determines “extraordinary circumstances” exist, a higher degree of evaluation under NEPA would be required. The exemption doesn't apply to the siting of associated transmission facilities on federal lands.
Other provisions in the law clarify that the Bonneville, Southwestern and Western Area power administrations aren't required to purchase or market energy generated by small hydropower conduit projects and costs aren't to be included in their power rates.
To date, several developers across the U.S. have been granted exemptions under the two hydropower laws' new provisions. In November, the 11-kilowatt Silverton Mayflower Mill Hydro Project in Colorado became one of the first conduit projects exempted under the P. L. 113-23, according to Nocella.
Since Dec. 12, another three conduit projects in Colorado and three in California, which total nearly six MW of capacity, have been approved as qualifying for the exemption, Nocella said. Another eight conduit projects in Illinois, Idaho, Massachusetts, Oregon, Pennsylvania, Vermont and Utah are awaiting approval.
Larger Projects Sought
Obama also included the expansion of larger-capacity hydropower on existing dams in his Climate Change Action Plan unveiled June 25.
While the climate plan doesn't affect the small hydropower laws, all share the goal of expanding hydroelectric capacity.
For example, Obama's plan highlights the Red Rock Hydroelectric Plant on the Des Moines River in Iowa, expected to have a capacity of 36.4 MW, with a peak of up to 55 MW. It was placed on the so-called Federal Infrastructure Projects Permitting Dashboard, which is intended to develop and demonstrate an improved permitting process for such federal projects.
The dashboard is an outgrowth of Obama's Executive Order 13,604 of March 2012 on improving federal permitting for infrastructure projects.
Construction of the Red Rock hydroelectric project on the existing Red Rock Dam, which is owned by the U.S. Army Corps of Engineers, is expected to begin in early 2014. The plant is expected to be operational by early 2016.
Corps' Primary Function
The corps' primary function for the project is to review and comment on documents prepared by the Western Minnesota Municipal Power Administration, the developer of the dam, Roger Less, chief of design for the corps' Rock Island District, told Bloomberg BNA.
The 50-year structure was built for
flood control and is a high-risk dam, Less said. While the project has been
progressing on schedule, it's a “highly complex project,” he said.
Any failure of the dam would place thousands of people at risk downstream, Less said. So in addition to NEPA Act requirements, the corps is looking at potential flood conditions while the dam is under construction.
“The takeaway for developers,” he said, is that the corps' review of hydropower projects looks not only at the end product but also at conditions that may exist during construction. Also, the corps' existing operation of the dam must remain unchanged.
According to the National Hydropower Association, hydropower provided the majority of the nation's renewable electricity in 2012, with 100,000 MW of installed capacity, employing about 300,000 workers.
A study conducted by Navigant Consulting in September 2009 for the association determined that by 2025, the U.S. hydropower industry could install up to 60,000 MW of new capacity, adding as many as 1.4 million jobs. The estimates are based on the “right policies,” such as Congress passing a 25 percent national renewable electricity standard (RES).
Under a business-as-usual scenario, the study found that under a 10 percent RES, hydropower would still add 23,300 MW of capacity, creating up to 480,000 jobs.
While Congress has yet to enact a national RES, 37 states and Washington, D.C., have such policies—also known as renewable portfolio standards—and all include hydropower of some kind, Nocella said. The level of recognition varies from state to state. For example, some include only hydropower facilities of a certain size, while some recognize hydropower built after a certain date.
States in New England and the Pacific Northwest have been reassessing hydropower's role in their renewable portfolio standards and have been considering either expanding the eligibility for existing hydropower or including large hydro facilities, according to an April report by the Clean Energy States Alliance, “Environmental Rules for Hydropower in State Renewable Portfolio Standards.”
“As states increase their renewable energy targets, several have questioned what types of hydropower should count towards RPS targets,” the report said.
To better characterize U.S. hydropower potential, the Energy Department released a report in April 2012, “An Assessment of Energy Potential at Non-Powered Dams in the United States.” Prepared by Oak Ridge National Laboratories for DOE's Wind and Water Power Program, the report identified the “top 100” non-powered dams with hydropower potential.
The report said the assessment could be used by developers to focus on more detailed analysis of promising sites. The estimated potential capacity of the 100 dams ranged from 20 MW to 496 MW for a total of about eight gigawatts.
Other Potential Resources
In addition to non-powered dams targeted by the laws, the National Hydropower Association pointed in a statement to other potential resources, including pumped storage from reservoirs, new ocean and tidal technologies and modernized existing facilities.
Furthermore, the industry group said small hydropower projects could be developed within commercial buildings and wastewater treatment facilities. However, more analysis and studies are needed to determine the extent to which they can be harnessed for hydropower generation, the group said.
While hydropower is considered one of the least expensive sources of power, according to the Center for Climate and Energy Solutions (C2ES), the cost is dominated by initial capital costs of building the facility.
However, ongoing operating and maintenance costs tend to be low, according to a C2ES fact sheet. “Levelized cost,” which is the net cost to install a hydropower project divided by its expected lifetime energy output, makes hydropower the least expensive option for new renewable energy generation on par roughly with new wind and biopower, according to C2ES.
Meanwhile, a three-year study by the DOE and the Electric Power Research Institute, “Quantifying the Value of Hydropower in the Electric Grid,”released in February, said, “The value of hydropower in the electricity grid is very application- and case-specific.”
Also, the value in the future will be sensitive to fluctuations in energy scenarios, including commodity prices, such as the cost of coal, natural gas and carbon dioxide emission credits. The report found that potential improvements to existing hydropower plants would be cost-effective and construction of new pumped storage “continues to be in active discussion.”
While the report concluded that more studies need to be done to quantify the full value stream of hydropower resources, the “study confirmed that hydropower resources across the United States contribute significantly to operation of the grid in terms of energy, capacity and ancillary services.”
Furthermore, hydropower equipment lasts for about 50 years and eventually will need to be rehabilitated, according to Frank of Voith Hydro. “The fleet in the rehab market will upgrade equipment with higher efficiencies, and that will be a good investment for owners,” he said.
In addition, new technology can address concerns about low dissolved oxygen concentration, and improved fish passage technology is available, Frank said, adding that the industry works with nongovernmental organizations to address environmental protection issues.
States Offer Incentives
Several states also have been seeking to expand hydropower facilities. For example, the Colorado Department of Agriculture announced plans to complete a small hydropower road map in early 2014 for the state's agriculture industry, which has enough irrigation ditches to make small hydropower projects viable.
The Colorado Agricultural Value-Added Development Board administers the Advancing Colorado's Renewable Energy (ACRE) Program, which provides funding to promote energy-related projects beneficial to the agriculture industry. The small hydropower road map will include data on the costs, benefits and barriers to the development of small hydropower.
In addition, the Colorado Energy Office published a “Small Hydro Handbook” to help developers, ranchers, municipal water operations, irrigation districts, agricultural producers, resource agencies, environmental groups, utilities and others understand the licensing process and technology needed to develop projects.
Meanwhile, Connecticut Gov. Dannel P. Malloy (D) signed legislation in June that, among other things, modifies the state's renewable portfolio standard to allow for more use of hydropower by increasing the size of qualifying facilities from five MW to 30 MW and eliminating the requirement that the facility not cause an appreciable change in riverflow.
New England States
In addition, Connecticut, Maine, Massachusetts, Rhode Island and Vermont announced an initiative in June that aims to expand imports of hydropower in the region to provide “cleaner and cheaper energy.”
The states said the benefits of clean hydropower include reducing and stabilizing power prices, enhancing fuel diversity, increasing electric grid reliability, reducing environmental impacts from the energy sector and encouraging an energy future that utilizes resources from within the region and nearby border areas.
The governors said the regional approach will seek to utilize economies of scale to unlock imports from the significant resources in Canada, including Quebec and the Maritime provinces.
Also on the East Coast, New York, which is the largest hydropower producer east of the Rocky Mountains, obtains more than 17 percent of its electricity from hydropower. According to the state's Department of Environmental Conservation website, the state expects hydropower to grow incrementally as a mainstay of renewable power generation and supports both new and old projects, including through its RPS.
Process Poses Hurdles
At least one developer probably could have benefited from P. L. 113-23 if it had been enacted years ago. The developer, the Okanogan Public Utility District in Washington state, has been bogged down in the approval process for a nine MW project for eight-and-a-half years, known as the Enloe Dam, said John Grubich, the PUD's general manager.
He testified in September before the House Natural Resources Subcommittee on Water and Power about the high cost and regulatory delays of trying to reconstruct an existing hydropower facility that has been inactive since 1958: the Enloe Hydroelectric Project on the Similkameen River.
Even though FERC granted the district a 50-year license in July, conservation groups have until Jan. 20 to file an appeal with the U.S. Court of Appeals for the District of Columbia Circuit or the U.S. Court of Appeals for the Ninth Circuit regarding a Nov. 21 FERC order denying their request for a rehearing over the license.
The groups claim FERC failed to consider the environmental and economic impacts of the minimum required flow of a waterfall that would be used to generate hydropower when it issued the license.
Initially, licensing and other permitting costs were estimated to be between $500,000 and $1 million and construction to take up to two years, Grubich said. To date, the district has spent $10 million for the licensing process, “and we're still counting.” The cost for the hydropower project is estimated at $35 million, he said.
Another factor in the delay of the Enloe Dam project is a push by nonprofit special interest groups to remove dams, Grubich said. “My troubling concern is that we also have governmental entities or organizations that mirror that rhetoric, and they're saying that if we're not going to use the dam, that it should be removed. Yet it's taken so long to develop this project that we face economic uncertainty, and we may not be able to finish this project unless things get moving quickly.”
Onus on Developers
In written testimony for an April hearing on the bills, Jeff C. Wright, director of FERC's Office of Energy Projects, told Congress “it is extremely important” for project developers and other stakeholders to understand that they play the leading role in determining a project's success.
A key issue, Wright said, is the site selection process. For example, projects that involve lands and facilities owned by the developer and where hydropower facilities don't currently exist are likely to be more successful than others.
Also, the review process will be expedited if the project would result in little change to water flow, would probably not threaten endangered species and would probably not require fish passage facilities. To the extent that a proposed project, even one of small size, raises concerns about water use and other environmental issues, “it may be difficult for the commission to quickly process an application,” Wright said.
“Another, and related, factor is the extent to which project developers reach out to affected stakeholders,” he said. “If a developer contacts concerned citizens; local, state, and federal agencies; Indian tribes; and environmental organizations and works with them to develop consensus as to what information is needed to understand the impacts of a project and what environmental measures may be appropriate, and to develop support for the project, the application and review process is likely to be simpler and quicker.”
To help developers, the Low Impact Hydropower Institute, a nonprofit group, created a voluntary Hydropower Certification Program to identify and reward dams that minimize their environmental footprint, Michael J. Sale, executive director for the institute, testified at the September hearing.
To be certified, hydropower facilities must meet criteria for river flows, water quality, fish passage and protection, watershed protection, threatened and endangered species protection, cultural and resource protection and recreation.
Sale said the institute was established in 2000 by a group of river conservation organizations and renewable energy marketers in anticipation of the need to identify acceptable hydropower sources in green energy markets.
A hydropower facility that meets the requirements can use the certification when marketing green power to consumers, he said. As of September, 109 facilities at 165 dams had received the certification, he said.
Hydropower facilities, along with water supply and irrigation systems, have been identified by a federal-state-local partnership as being at risk from wildfires that are expected to become more prevalent, especially in the West, because of climate change.
The goal of the Western Watershed Enhancement Partnership, unveiled in July in response to the Obama administration's Climate Action Plan, will be to “proactively plan for post-wildfire response to protect agricultural and municipal water supplies and hydropower generation,” the Agriculture Department and the Interior Department said in announcing the partnership.
The effects of climate change also are being addressed in the “National Climate Assessment.” According to a draft assessment released in January 2013, climate change is expected to affect hydropower directly though changes in runoff and indirectly through increased competition with other water uses.
Based on runoff projections included in the draft, hydropower is expected to decline in the Southwest and increase in the Northeast and Midwest, though actual gains or losses will depend on facility size and changes in runoff volume and timing.
“One quarter of all hydropower facilities nationwide, especially in the Southeast, Southwest and the Great Plains, are expected to face water availability constraints, and challenges will rise as aging hydropower infrastructure needs to be replaced,” said the draft assessment, which is expected to be released in March. In the West, hydropower plants, which depend on the seasonal cycle of snowmelt to provide steady output throughout the year, will likely experience reduced production in areas where decreased snowpack is likely to occur.
DOE also released a report in August to Congress, “Effects of Climate Change on Federal Hydropower.” Federal hydropower makes up about half the nation's hydropower capacity.
The report concluded that over the next 30 years, “at the national level, the median decrease in annual generation at federal projects is projected to be less than 2 billion KWh (2 percent of total) with a relatively high climate-model uncertainty.”
“While challenges to federal hydropower that are associated with climate change appear to be manageable on a national scale over the next few decades, challenges within specific regions and seasons may be more difficult to manage, and those challenges will likely increase in the second half of the 21st century,” the report said.
In another report released Dec. 13, the Government Accountability Office said the Army Corps of Engineers and the Bureau of Reclamation are working together to provide data and tools to address water resources and the vulnerability of infrastructure, including hydropower, to the impacts of climate change.
“Climate change is having a variety of impacts on natural resources in the U.S., ranging from more severe drought to increased flooding, and is altering assumptions that have been central to water resource planning and management,” GAO said in the report, “Federal Efforts Under Way to Assess Water Infrastructure Vulnerabilities and Address Adaptation Challenges.”
More Efficient Turbines
Kerry McCalman, senior adviser for the Bureau of Reclamation's Hydropower and Electric Reliability Compliance Office, said at the September congressional hearing that to address climate change at existing facilities, the bureau is installing more efficient turbines that can operate at lower water levels. Also, new conduit hydropower and hydrokinetic energy technologies are being tested to find ways other than using rivers to harness hydropower, he said.
If FERC's response to potential climate change impacts on a proposed 735-foot dam on Alaska's Sustina River is any indication, climate change may not be a central issue to siting new hydropower, at least for now.
While the National Oceanic and Atmospheric Administration's National Marine Fisheries Services told FERC that an assessment of the impact of climate change on the basin should be conducted to evaluate the project's effects on aquatic and riparian species, the commission disagreed. FERC concluded that a such a climate change study wasn't likely to yield reliable data and the cost—estimated at $1 million—was not justified. The 600 MW, $5.1 billion project is expected to be operational in 2024.
FERC said such detailed climate change analyses may be required in the future. Nonetheless, FERC said the Alaska Energy Authority must review existing information on changes to glaciers that could affect the project, which developers say is key to Alaska meeting its goal of deriving 50 percent of its energy needs from renewable sources by 2025.
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