2014 Hydropower Market Report
Uría-Martínez, O’Connor, et. al., April 2015 (Oak Ridge National Laboratory)
The U.S. hydropower fleet has been providing clean, reliable power for more than a hundred years. However, no systematic documentation exists of the U.S. fleet and the trends influencing it in recent years. This first-ever Hydropower Market Report seeks to fill this gap and provide industry and policy makers with a quantitative baseline on the distribution, capabilities, and status of hydropower in the United States.
Overall, the size of the U.S. hydropower fleet has continued to grow over the last decade as owners optimize and upgrade existing assets. Despite some retirements, U.S. hydropower capacity increased by nearly one and a half gigawatts (GW) from 2005 to 2013. For those new projects that have been constructed during that time, only four—out of more than a hundred—were not associated with existing water infrastructure. Instead, the industry has focused on opportunities to develop hydropower on existing pieces of water infrastructure at non-powered dams (NPDs) and conduits. These types of projects, along with dozens of new large-scale pumped storage hydropower (PSH) projects that are being pursued, dominate the current development pipeline and face at least two differences relative to projects completed since 2000. The permitting and licensing process for many smaller hydropower projects has changed in recent years, which could result in less cost and time spent in federal permitting. Also, the extensive bond, tax credit, and grant programs that helped fuel development in recent years are no longer available, and hydropower projects might have to rely on alternative sources of funding and revenue, which could complicate or slow future developments.
Key findings from this report include the following:
Section 1—Description of Existing U.S. Hydropower Fleet
• The U.S. hydropower fleet contains 2,198 active plants with a total capacity of 79.64 GW (approximately 7% of all U.S. generating capacity). Half of the installed capacity is located in three states (Washington, California, and Oregon). The Northwest has the largest amount of installed capacity, but the Northeast ranks first in number of facilities. Despite slow recent growth, in 2013 hydropower remained the largest renewable energy source in the United States.
• Hydropower projects support more than just the power system—most installed hydropower capacity, particularly in large projects, is connected to reservoirs that also provide recreation, flood control, irrigation, navigation, and/or water supply. At least 84% of the fleet (by capacity) provides one or more of these additional benefits, with recreation being the most common. The multipurpose nature of these projects influences their design, operations, and life cycle costs and benefits.
• Most of the installed capacity is located at large projects built between 1930 and 1970. On the other hand, the most active decade in number of projects built was the 1980s. But most of those projects were small or medium size and did not represent a large capacity increase compared with previous decades.
• Federal agencies (U.S. Army Corps of Engineers, Bureau of Reclamation, and the Tennessee Valley Authority) own nearly half of the installed hydropower capacity. The 176 plants they own account for 49% of the capacity but only 8% of the plants. Publicly owned utilities, state agencies, and electric cooperatives own an additional 24% of capacity. The remaining quarter—which corresponds to 62% of the plants—belongs to private owners
Section 2—Trends in Hydropower Development Activity
• Although the expansion of the U.S. fleet has slowed, growth is still occurring from three different kinds of projects: (1) unit additions and upgrades at existing facilities; (2) NPD and conduit projects to which hydropower generating equipment is added; and (3) low-impact, new stream-reach developments (NSDs).
• Installed capacity in the United States experienced a net increase of 1.48 GW from 2005 to 2013. Capacity additions to existing projects accounted for 86% of the increases. The net capacity change was positive in every region but was largest in the Northwest (586.75 megawatts [MW]). A total of 432 MW were lost to either downrates (61%) or retirements (39%). In a few cases, retirements involved full decommissioning of the plant (including dam removal).
• Significant capital investment toward modernizing and upgrading the existing fleet is consistently taking place. Since 2005, the industry has invested at least $6 billion in refurbishments, replacements, and upgrades to hydropower plants. Nonfederal owners have spent more per installed kilowatt than federal owners. Funding mechanisms play an important role in explaining differences in spending within the federal fleet.
• The length of the development process varies widely across hydropower projects that require a Federal Energy Regulatory Commission (FERC) license depending, among other factors, on size, location, and environmental effects. For new projects requiring a FERC license that came online in the last decade, postlicensing activities required before the start of construction (e.g., additional permitting, financing, and interconnection and power purchase agreement negotiations) typically took longer than obtaining the license.
• The number of hydropower projects in the FERC or Lease of Power Privilege development pipeline is 331, amounting to a capacity of 4.37 GW. Of that capacity, 407 MW are currently under construction, and an additional 315 MW have received authorization by FERC or the Bureau of Reclamation. More than 60% of proposed capacity in the FERC pipeline corresponds to developers holding (or having solicited) preliminary permits—which grant the developer exclusive rights to study and file a license application at a specific site during a three-year period. The attrition rate between the preliminary permit and license application stages has traditionally been high.
• Regardless of modality (NPD, conduit, or NSD), the median project size in the development pipeline is small (<=10 MW). NSD is the least common category and is highly concentrated in the Northwest. Of NSD projects, 66% are in a single state: Alaska. NPD projects dominate the pipeline, accounting for 233 projects and 58% of capacity.
• New NPD and conduit projects will typically have to operate within parameters that do not harm the originally intended function of the dam or conduit. Consequently, these projects will normally have limited flexibility in their mode of operation but also might have limited additional environmental impact because of their use of existing infrastructure.
Section 3—Hydropower Performance Metrics
• Generation from the hydropower fleet has averaged 288 terawatt-hours from 2011 to 2013, accounting for 7.1% of U.S. electricity generation during that period. Even though the total generation changes significantly from year to year based on water availability, its geographical and seasonal distribution is relatively stable.
• The capacity factor for the entire fleet was 39% in 2013, 40% in 2012, and 46% in 2011. Capacity factors vary from year to year because of hydrologic conditions, water demands for competing uses, environmental and regulatory restrictions, and factors such as plant outages that affect available capacity.
• There is also significant plant-to-plant variability in capacity factor. In 2012, one quarter of active projects had capacity factors below 30% while projects in the top quartile had capacity factors above 55%. The two most common operational modes for facilities in the top quartile were run-of-river and conduit.
• For a representative set of plants installed before 1970, a long-term decreasing trend in capacity factor is visible. Likely contributors to this trend include equipment aging—combined with different funding availability for refurbishments and upgrades—operational changes from environmental regulations, climate change, and realignments of the relative priority given to different water uses in multipurpose projects.
• For the set of turbine-generator units that report performance data to the North American Electric Reliability Corporation during the 2000–2013 period, there is a visible decreasing trend in availability factor. The trend is most pronounced for smaller (<=10 MW) units and suggests a trade-off between planned and forced outages. However, availability factor changes by season and has been on average 5 to 10 percentage points larger in the summer—when electricity demands are generally the greatest—compared with fall.
• The operational mode of the hydropower fleet displays a broad spectrum of flexibilities. For the portion of the fleet for which operational mode information was available, more than 39 GW have operational modes with high flexibility potential. That portion of the fleet will be the most valuable for following the shape of the daily load curves primarily influenced by demand fluctuations and variable renewable generation.
Section 4—Pumped Storage Hydropower
• PSH plants account for the bulk of utility-scale electrical energy storage in the United States (and worldwide). With their ability to provide a wide range of ancillary services, PSH plants play an important role in ensuring grid reliability. In the United States, many new PSH projects are under consideration but—in contrast with other countries—none is currently under construction.
• PSH plants can consist of only reversible turbine-generator units (dedicated PSH plants) or a combination of conventional and reversible turbine-generator units (hybrid PSH plants). Median size, ownership, and patterns of operation are significantly different for the two kinds of plants.
• The PSH fleet comprises 42 plants with a capacity of 21.6 GW. The Southeast has the most PSH capacity (9.06 GW). Three-quarters of the installed capacity is located at very large (>500 MW) plants indicating that economies of scale have proved to be very strong for this type of project.
• The majority of PSH construction took place between 1960 and 1990. PSH complemented nuclear and thermal base load plants that provided cheap power for pumping and that were not well suited to follow demand peaks. Since 1995, except for a 40-MW plant that went into service on 2011 (Olivenhain Hodges, located in California), all additional PSH capacity has come from modernization and upgrades to the existing fleet.
• Given current electricity prices in many areas of the United States, analyses have shown that the old model of peak, off-peak energy arbitrage might no longer be sufficient to justify additional PSH development. A new wave of interest in PSH development has been spurred by (1) regulatory changes in electricity markets, allowing the participation of storage in ancillary service and capacity markets; and (2) policies, mostly at the state level, requiring increased penetration of renewable generation. Due to its flexibility, PSH is capable of providing a range of ancillary services to support the integration of variable renewables into the grid.
• There are 51 PSH projects in the FERC development pipeline with a capacity of 39 GW. However, the developers had pursued a license application for only three of these projects as of the end of 2014. The rest have been issued (or are waiting for) preliminary permits to conduct feasibility studies. Most of the projects are pursued by private developers.
• In 2014, FERC authorized the first original license for PSH in more than 15 years (Eagle Mountain) and a second PSH facility (Iowa Hill) as part of the relicensing of an existing hydropower project—the Upper American River Project in California. Eagle Mountain and Iowa Hill differ substantially in configuration (closed-loop versus open-loop), size (1,300 versus 400 MW), and ownership (private versus public). They are both in California, an attractive market because of the high wind and solar penetration and a state renewable portfolio standard with a target of 33% by 2020.
• The key performance metric for PSH is its availability factor. For units reporting performance data to the North American Electric Reliability Corporation, the availability factor has decreased slightly over the 2000–2014 period. The effect of seasonality is more acute and noticeable than for hydropower plants. On average, availability factors stayed above 90% every summer but fell as low as 75% in some fall and spring seasons.
Section 5—Trends in U.S. Hydropower Supply Chain
• Since 1996, Voith has led the United States in terms of market share of installed turbine capacity. Of the 9,455 MW capacity installed identified—either at new facilities or as upgrades/retrofits—from 1996 to 2011, Voith manufactured 5,389 MW, including 2,683 MW for 62 turbine replacements/upgrades at federal facilities. Alstom held the second largest share of the United States market with 1,991 MW.
• At least 172 companies, spread across 35 states, have manufacturing facilities in the United States to produce one or more of six major hydropower components (turbines, generators, transformers, penstocks, gates, and valves). The facilities typically are located close to substantial installed hydropower capacity and/or access to waterways to facilitate shipping of their end products.
• Turbines are the only hydropower plant component for which trade data—excluding turbinegenerator sets—are publicly available. Most of the U.S. hydraulic turbine trade involves turbine parts.
• The direction and magnitude of U.S. hydraulic turbine trade with various countries has changed during the last 15 years. More than 50% of the value of U.S. hydraulic turbine trade during the last three years has corresponded to imports and exports within North America—a significantly larger percentage than in the late 1990s. From 1996 to 2014, China and other Asian countries have gone from net importers of U.S. manufactured turbines to net exporters of turbines—and turbine parts—to the United States.
Section 6—Policy and Market Drivers
• Broadly supported federal regulatory reforms have altered the permitting and licensing process for some (typically smaller) projects. Federal legislation passed unanimously in 2013 aims to lower the cost and time necessary for small NPDs and conduits to obtain federal permits. FERC is also investigating the potential for a two-year licensing process for NPDs.
• Access to incentives has supported nearly all recent capacity additions and new projects. Although public and private owners have access to different funding and incentive resources, both have been able to leverage incentives provided by the American Reinvestment and Recovery Act to support project development efforts. This substantially benefitted project economics. The1603 grant program supported more than $1.6 billion of hydropower development activity by private owners, and Clean Renewable Energy Bonds and Build America Bonds supported billions more by public power entities. In addition, several states have provided financing for smaller projects.
• Hydropower is treated very differently across state-level renewable portfolio standards, which have been major drivers of growth in other renewables. Each of the 29 states that include hydropower as a primary-tier renewable defines hydropower eligibility in a unique way. Common restrictions on eligibility are inconsistent and include project size, type, age, and a variety of implicit and explicit environmental sustainability criteria. The way in which hydropower is classified as “renewable” for purposes of renewable portfolio standard compliance or future carbon policies could weigh heavily on project development prospects.