Hydropower ’s future, when viewed from the perspective of past and current regulatory environments, suggests that the industry is at a crossroads. The response to existing challenges will, to a large extent, determine the significance of hydropower as a meaningful component of U.S. renewable energy capacity.
By Stephen D. Padula
U.S. energy policy is at a crossroads. There is a resurgence in interest and incentives to add hydropower generation to the domestic energy mix using both conventional and unconventional technologies. The regulatory environment to which this generation development will be subject could be a critical factor in ultimately determining how much new hydropower generation is brought on line in the U.S.
This article provides a perspective on past, current, and likely future trends affecting the licensing and development of non-federal hydropower in the United States.
Non-federal hydro regulation: Where have we been?
Comprehensive federal oversight of non-federal hydropower projects began with the passage of the Federal Water Power Act in 1920, which created the Federal Power Commission (FPC). The act, amended in the 1930s, required the FPC to issue licenses only to projects that were “best adapted ” to improving or developing a waterway for navigation, interstate commerce, and recreational purposes. Licenses could be issued for periods of up to 50 years, and conditions could be added to the licenses to ensure that projects met the ”best adapted ” standard. Because rivers were considered a resource to be utilized to support the development and growth of the country, the FPC ’s major focus was on engineering aspects of projects, to ensure dam safety and efficient use of water for power generation. The emphasis on new hydropower development and efficient resource use continued through the 1940s to 1960s, when the FPC licensed many new projects, along with existing projects identified through jurisdictional reviews. Roughly 500 project licenses were issued by the FPC through the 1960s, representing about half of the total number of projects currently under license.
With the onset of the environmental movement, federal legislation was enacted that would transform hydropower licensing. Legislation included: the National Environmental Policy Act (NEPA), 1969; the Clean Water Act (CWA), 1970; and the Endangered Species Act (ESA), 1973. Also, in 1977, Congress abolished the FPC and created the Federal Energy Regulatory Commission (FERC) in its place as part of the larger consolidation of energy-related programs into a new U.S. Department of Energy.
Under NEPA, FERC as a federal agency was required to consider the environmental effects of its licensing decisions – through preparation of an environmental impact statement (EIS) or environmental assessment (EA) – along with the cumulative effects of its actions. Under ESA, FERC began to assess whether its licensing decisions would jeopardize endangered or threatened species or result in adverse consequences to their critical habitat. The Clean Water Act, in particular Section 401, gave states a means for ensuring that federal licensing decisions would be consistent with initiatives to bring rivers into compliance with state water quality standards.
In 1978, the Public Utility Regulatory Policies Act (PURPA) was enacted to promote development of efficient, environmentally friendly energy production. PURPA gave independent power producers incentives to develop hydropower by requiring utilities to buy power directly from hydropower developers at “avoided cost. ” The resulting viability of development at many sites led to more than 6,000 proposals for new development between 1978 and 1985. Many of these were small projects (less than 5 MW) located on small streams or at existing dams or mill works. FERC ultimately issued approximately 350 licenses and 420 exemptions for “small ” projects, averaging 4 MW in size during this time frame.
The resurgence in hydropower licensing brought on by PURPA raised new concerns about the environmental effects of hydropower, particularly on instream flows in bypass reaches and the cumulative effects of multiple hydro developments in a river basin. It also led FERC to create the three-stage consultation requirements, which remain the foundation of all of FERC ’s licensing procedures today.
Environmental concerns with hydropower development gained even greater prominence with the passage of the Electric Consumers Protection Act (ECPA) in 1986. This act required FERC to give “equal consideration ” to power development and protection of environmental, recreational, and cultural resources, and to give substantial deference to “Section 10(j) ” recommendations of state and federal fish and wildlife agencies.
In 1991, as a result of jurisdictional determinations made in the 1940s, FERC faced the simultaneous filing of over 160 new license (relicensing) applications for existing projects with licenses expiring at the end of 1993, the so-called “Class of ‘93. ” The regulatory environment for the processing of these projects began in the mid-1980s under the three-stage or traditional licensing process (TLP).
The processing of these applications marked a fundamental change in the development and processing of hydropower license applications. The focus of FERC, other agencies, and non-governmental organizations (NGOs) changed from one of primarily new development to one of considering the relicensing of existing projects. From that time onward, the FERC licensing process has been largely geared toward determining what conditions should be established for new licenses for existing projects.
Hallmarks in the processing of these license applications were:
– The new empowerment of agencies through the “equal consideration ” provision of ECPA;
– More aggressive use of fish and wildlife provisions in the FPA ’s Section 10(j), fishway prescriptions under Section 18, and land managing agencies ’ Section 4(e) authority; and
– Expansion in the interpretation of what elements of hydropower development could be regulated through the CWA ’s Section 401 water quality certification process.
This resulted in an increase in the amount and quality of information needed to evaluate “project effects ” and an increase in the time needed to develop and process applications and make license decisions. It also ushered in the era when many key licensing decisions were driven primarily by agencies with mandatory conditioning and prescriptive authority and not by FERC.
Frustration with the Class of ’93, including the increase in study costs, unresolved issues, and outright disagreements among applicants, agencies, and NGOs, and the inability to complete the processing of applications within a timely fashion led the industry and FERC to explore other process alternatives. One innovation was the use of negotiated settlement agreements. Initially, a few licensees were able to reach settlements for licenses that otherwise would have led to controversial proceedings at FERC. FERC worked with the licensees on these early settlements, and, based on their success, encouraged others to consider settlement negotiations as a means for resolving disputes prior to filing license applications.
Industry also saw the need to streamline the relicensing process, resulting in the National Hydropower Association ’s reform efforts that led to the alternative licensing process (ALP) in the mid-1990s. While the ALP was considered an improvement over the traditional licensing process, there was continued frustration with the length of the process and the continuing expansion in the scope of licensing studies. In response, industry continued working with agencies, environmental groups, and FERC to establish a five-year process that held all parties to a rigorous schedule of existing information development, consultation, study criteria and time frames, and environmental assessment. The resulting integrated licensing process (ILP) was adopted by FERC in 2003.
Throughout the legislative and regulatory changes of the past 20 years, most licensing activity has involved existing projects, with “new ” hydro development applications accounting for only a small proportion of the licensing workload at FERC. The focus on relicensing existing projects has influenced the perspectives of all involved parties. The resulting practices, attitudes, and mindsets could have significant ramifications for the future of hydropower in the U.S.
Current regulatory developments
Hydropower regulation continues to change. Four recent developments are expected to have significant implications for hydro licensing.
Trial-type hearings established under the Energy Policy Act
Section 241 of the Energy Policy Act (EPAct) of 2005 allows a party in a licensing process to propose energy- or cost-saving alternatives to agencies ’ mandatory conditions and prescriptions and affords the party a 90-day expedited trial-type hearing on disputed issues of material fact relating to the conditions and prescriptions. The affected mandatory conditioning agency must accept the alternative, if the proposed alternative provides satisfactory environmental and resource protection along with cost or power savings. Utilization of this new provision bears close watching for implications on the use of mandatory conditioning authority in the future.
Water quality certifications
The U.S. Supreme Court issued a decision in S.D. Warren Co. v. Maine Board of Environmental Protection upholding the state of Maine ’s policy of requiring water quality certifications for FERC-licensed hydro projects in Maine. The S.D. Warren Company had argued that a Section 401 certificate was not needed for its small run-of-river projects because they did not introduce pollutants into the water. The Supreme Court concluded that Section 401 certification is necessitated simply by the fact that water is passed through a dam. Based on this decision, it appears that water quality certification conditioning will remain a major factor in future licensing proceedings.
Limits on FERC authority
The U.S. Court of Appeals for the D.C. Circuit issued a decision in City of Tacoma, Washington v. FERC, upholding FERC ’s relicensing of the city of Tacoma ’s Cushman project. This decision addressed several issues that may affect hydropower relicensing. The court held that the relevant secretary is authorized under Section 4(e) to impose any conditions that will protect a tribal reservation, as long as any project works are located on it, and that FERC has no discretion to reject or modify the secretary ’s conditions. The court also found that FERC does not have the authority to enforce time restrictions on federal agencies, which raises questions about validity of deadlines aimed at conditioning agencies found in FERC ’s licensing and EPAct provisions. With no ability to forecast when an agency might submit terms and conditions, conducting a timely and efficient closure to a licensing proceeding seems to be severely handicapped.
FERC ’s policy on settlement agreements
To address industry, agency, and stakeholder concerns related to the issuance of license orders that reject or are inconsistent with provisions of negotiated settlement agreements, FERC in 2006 drafted its “Policy Statement on Hydropower Licensing Settlements. ” The policy statement explains that FERC will reject or modify settlement provisions that do not meet the FPA comprehensive development and equal consideration standards or are beyond FERC ’s enforcement authority. While this document describes approaches taken by FERC historically to address specific situations involving settlement provisions, FERC ’s policy will undoubtedly continue to evolve to address new or unique circumstances.
All of these recent actions are likely to have continuing effects on hydro licensing practice in the future. Of particular relevance to the future of new development is that all four of these recent actions primarily address issues related to licensing existing projects.
Future hydropower licensing
Many existing, conventional hydropower projects will undergo relicensing in the near future. During the next ten years, 150 projects will begin the relicensing process (49 of those begin the process within five years). Between now and 2027, almost 45 percent of all FERC-licensed projects will have begun relicensing. Many of these projects were last licensed after ECPA, and well after the enactment of the major environmental laws discussed above.
Because projects that were licensed post-ECPA have significantly more existing environmental information, future relicensings could be more streamlined than those of recent years. Whether this information will lead to some abatement in the need for extensive new studies to support the next round of relicensing decisions is unclear. If it does, completion of relicensing proceedings within five years may finally start to occur on a regular basis, potentially obviating the need for continuing relicensing process changes that have become the hallmark of the past ten years. Some minor adjustments will undoubtedly be needed, particularly based on experience being gained with the ILP, but wholesale regulatory changes should hopefully become a thing of the past with regard to licensing existing projects.
Outlook for new development
While the amount of relicensing activity will remain significant in the future, it is less clear whether new hydropower generating capacity will be developed to any significant extent. Over the past 20 years, most new hydropower capacity at non-federal projects has been added through upgrades of existing units or addition of new units at existing projects. Over the same period, new project proposals have become less common than at any other point in the industry ’s history. A closer look forward at the potential for new development, using both conventional and non-conventional approaches, follows.
Despite the lack of new hydroelectric projects being licensed and developed in the recent past, hydropower still generates about 10 percent of the electricity in the U.S. and is the largest renewable energy source in the nation, with installed capacity close to 80,000 MW.1 Opportunities exist for expanding conventional hydropower ’s contribution to the country ’s energy capacity. Based on a recent assessment of power potential associated with natural streams in the U.S., the U.S. Department of Energy concluded that about 10 percent of this potential has been developed. Of the undeveloped resources, DOE estimates that nearly 100,000 average MW of gross power potential, from nearly 130,000 potential low-power (,1 MW) and small (.1 MW and ,30 MW) hydro projects, could feasibly be developed.2
Much of this potential could be harnessed through incremental hydropower (i.e., without new dams). Increased efficiency and equipment upgrades could create an additional 4,300 MW of capacity.3 An estimated 16,700 MW of capacity could be created by adding powerhouses to existing non-hydropower dams.2
Despite these undeveloped resources, the U.S. Department of Energy projects that only 560 MW of new conventional hydropower capacity will be developed by 2025. By this time, hydropower ’s share of the U.S. ’s energy generation is forecast to decline to about 6 percent.1
Although current trends (such as the rising cost of fossil fuels, energy security considerations, carbon credits, and federal incentives) suggest that projects not economically viable until now could become so in the near future, achieving significant amounts of new conventional hydropower remains questionable. Potential sites are limited because existing water users, resource agencies, and interest groups assert strong resistance to changes in the existing uses of free-flowing waters. Also, new hydropower development is hindered by the cost and duration of the federal licensing process, along with high capital costs for construction and mitigation. Realizing substantial increases in hydropower capacity through new conventional projects would require a fundamental reexamination of how conventional hydropower is perceived, regulated, and managed.
Multiple factors will affect how much hydropower potential is developed, including financial incentives and continued development of new low-impact technologies. For its part, FERC should ex- amine whether the available regulatory processes (TLP, ALP, ILP) are designed to efficiently handle the licensing of new conventional development, and explore ways to encourage environmentally compatible energy development. With most of the potential likely to come from small or incremental development, the three available regulatory models for relicensing existing projects may simply be too cumbersome. Treating all conventional hydropower in the same way – for example, treating the licensing of incremental new hydro in the same fashion as relicensing large existing projects – could inadvertently dampen new conventional development. At a minimum, it would seem a good investment for the country for FERC to ensure that its regulatory processes are not a barrier to new conventional development.
A survey of the 116 preliminary permits issued by FERC since 2004 demonstrates that new hydropower capacity is increasingly being sought through alternative approaches, most significantly through the development of new technologies. These technologies include hydrokinetic (generating power from water moving through artificial channels), in-stream (generating water power without an impoundment), and ocean/marine (generating power from wave and tidal energy).4 EPAct recognized the potential for unconventional hydropower by including a research and development program for technologies that do not require new dams and extending the existing production tax credit (PTC) and clean renewable energy bonds (CREBs) to new hydropower technologies.
Despite incentives and policies intended to promote alternative hydropower, these fledgling technologies face significant challenges. In contrast to the conventional hydropower sector, alternative hydropower developers are typically start-up companies looking for venture capital or other equity sources. To be successful in attracting capital on a commercial scale, these firms need to demonstrate that their deployment path has manageable risks and uncertainties and can be accomplished in a reasonable time frame.
Most industry observers assume that the economics of alternative technologies will eventually compare favorably to wind power at equal production levels, especially if the PTC and CREBs are continued.5 This leaves regulatory uncertainty as the most significant obstacle to deployment of new technologies. This uncertainty is derived from concern about the time and resources required to address licensing (and leasing of development rights where applicable) and the potential for onerous requirements imposed by mandatory conditioning agencies. Alternative technologies, particularly those that are to be deployed in ocean and tidal environments, face layers of regulatory uncertainty beyond those faced by conventional hydropower. For examples, see the box on page 12.
The view of hydropower ’s future from the perspective of past and current regulatory environments suggests that we are at a crossroads. The response to existing challenges and changing realities will, to a large extent, determine the significance of hydropower as a meaningful component of U.S. renewable energy capacity in the future. Current approaches for licensing existing projects appear to be providing desired flexibility, with the possibility of improved efficiencies due to the higher quality of information available for projects with significant post-ECPA operations. However, the dearth of proposals for new small and incremental conventional hydropower capacity additions should be a red flag that significant financial and regulatory barriers are impeding development of new generation; projections of only developing less than 3 percent (560 MW out of 21,000 MW) of the available small conventional hydropower capacity not requiring the construction of new dams should not sit well with policy-makers. A review of existing policies and procedures to ensure they are not creating unnecessary barriers to developing this available capacity would be prudent.
To avoid some of the pitfalls that hamper new conventional development, FERC and the U.S. Department of the Interior ’s Minerals Management Service (MMS) – as well as local, state, and federal agencies – will need to develop regulatory schemes that effectively address environmental protection and stakeholder participation, while paying heed to the unique characteristics of these new resources. If regulatory approaches carry with them the cost, time, and uncertainty associated with the licensing/relicensing of traditional hydropower, nascent technologies may not survive, leaving significant alternative sources of renewable energy untapped.
To promote these alternative technologies, FERC, MMS, and others should consider regulatory approaches that take advantage of these technologies ’ key elements. Some of these approaches are listed in the box on page 14.
Clearly, exciting opportunities exist for development of new hydropower to enhance the U.S. ’s supply of clean, secure, renewable energy – ranging from increased efficiencies and capacity at existing facilities, to additional small conventional hydroelectric projects, to employment of promising alternative technologies. Realizing this potential, however, will require a number of systemic changes, especially in the regulatory arena.
The successful approach will ensure legitimate involvement of all interested parties. It also will utilize, where possible, a strategy of allowing phased development to actually assist in the collection of meaningful information to guide decision-making and protection of natural resources. What seems most apparent is that a one-size-fits-all regulatory approach – including processes, mindsets, and attitudes – developed over many years focused on relicensing existing projects is unlikely to function well for promoting new small conventional and emerging non-conventional technologies of the future.
Mr. Padula may be reached at Long View Associates, Inc., 2705 North East 163rd Street, Ridgefield, WA 98642; (1) 360-576-3579; E-mail: [email protected]
- U.S. Department of Energy Biennial Report 2005–2006, July 2006.
- Feasibility Assessment of the Water Energy Resources of the United States for New Low Power and Small Hydro Classes of Hydro Plants, U.S. Department of Energy, January 2006.
- “As President Looks For Domestic, Affordable Energy: More Hydropower Is Obtainable ” News Release, National Hydropower Association, February 2006.
- Verville, Sarah, “Achieving Energy Supply Security With Sustainable Resources, ” presented at 9th Annual Renewable Energy and Energy Efficiency Expo, Washington, D.C., 2006.
- System Level Design, Performance, and Costs; Oregon State Offshore Wave Power Plant, EPRI, E2I EPRI Global-WP-006-OR-Rev 1, 2004.
Steve Padula is principal of Long View Associates, Inc., a consulting firm with expertise in Federal Energy Regulatory Commission (FERC) hydropower licensing, relicensing, and compliance. Mr. Padula has worked as a FERC licensing consultant since 1993. He also has worked for Central Maine Power Company, FERC, the U.S. Department of the Interior, and Shell Oil Company.
Potential Regulatory Challenges for Projects using Alternative Technologies
Alternative technologies, particularly those that are to be deployed in ocean and tidal environments, may face layers of regulatory uncertainty beyond those faced by conventional hydropower.
Conventional hydropower operates in an environment where property ownership is clear, but the ocean is a common property resource. Submerged lands are typically owned by either the state (inside 3 miles) or federal government (outer continental shelf lands). The water above these lands has a long history of use by multiple parties. Commercial fishermen and other marine resource interests and the communities they support will expect to play a significant role in regulatory proceedings.
Section 388 of the 2005 Energy Policy Act (EPAct) authorizes the U.S. Department of the Interior, through the Minerals Management Service (MMS), to grant leases, easements, or rights-of-way on the U.S. outer continental shelf (OCS) for development of renewable energy and to allow for alternative uses of existing facilities on the OCS. The MMS is currently establishing a program to oversee new operations on the OCS. While EPAct does not extend MMS authority to state waters, it is unclear how EPAct meshes with Federal Energy Regulatory Commission (FERC) authority on OCS lands. This raises the prospect that new hydro development on the OCS will be subject to two major overlapping federal regulatory processes.
Newcomers to FERC proceedings
A FERC process applied in ocean and tidal locales will need to engage local, state, and federal stakeholders who have little or no relevant experience with FERC. County governments, fishing organizations, and public interest groups will need to be informed about regulatory processes to ensure their effective early involvement. Failure to identify and involve these groups early could lead to significant delays later. Even state and federal agencies that have experience with FERC will find that involvement with ocean and tidal technologies requires new thinking – and in many cases, different personnel than have been involved in conventional hydro licensing.
The FERC process
Available FERC licensing processes may not be well suited to the deployment of new technologies, particularly during the early years of research and development, pilot projects, and the first stages of commercial development. It would seem appropriate for FERC and other key regulators to first consider what is being regulated before concluding that these new technologies can be efficiently regulated through processes developed and refined primarily for existing conventional hydropower.
Regulatory Approaches for Alternative Technologies
To promote alternative technologies, the following regulatory approaches are key.
Unlike conventional hydropower, most new technologies can be deployed incrementally as regulators and developers use pilot installations to gain knowledge of possible effects and operational or performance challenges. Beyond the preliminary permitting stages, some developers are exploring phased installation of commercial projects, which may provide agencies the flexibility to forego exhaustive studies at the outset of a commercial license in lieu of focused monitoring and evaluation efforts to gain insights through “in-the-water ” experience.
Such flexibility would enable projects to begin to generate revenue at early phases of development, with a portion of this cash flow being applied to meaningful focused studies on project effects and performance monitoring. As the first projects develop, it will become clearer where adjustments may be needed to Federal Energy Regulatory Commission (FERC) licensing procedures, and whatever process may be implemented by the Minerals Management Service (MMS), to encourage this phased approach.
Coordination of regulatory systems
FERC ’s role will need to be melded with the authorities associated with state waters and OCS lands – e.g., Coastal Zone Management Act, MMS leasing/permitting, and federal fisheries management as authorized by the Magnuson-Stevens Fishery Conservation and Management Act.
Given MMS ’s history with exploration and planning for oil and gas leases, baseline information gathering and consultation under the MMS program could differ significantly from FERC ’s developer sponsored, study-oriented approach to licensing, leading to challenges for projects that span state and federal waters.
Coordination of the two agencies ’ institutional approaches will be critical to the development of renewable resources on OCS lands and lands located at the state/federal interface.
Development of comprehensive plans
Development of comprehensive plans for wave or tidal energy could provide an opportunity for historical users of the resources and regulatory agencies to engage around basic planning principles to avoid future conflict. If executed in collaboration with federal and state regulators, such plans also could create opportunities to develop “programmatic ” environmental assessments that provide developers and regulators with critical information about likely issues and effects of concern before expensive investments are made.
The MMS, in regional stakeholder meetings, has signaled its interest in conducting a “regional planning ” exercise following completion of its final rule in the fall of 2007; there may be opportunities here to propose planning principles for both state and federal waters.
Streamline existing regulations
An inherent aspect of the development of emerging alternative technologies should be FERC and other federal and state regulators looking for opportunities to design regulatory and permitting processes to shorten review times and lower costs for technologies and developments meeting specific criteria.