Energy & Technology
A recent story on NPR’s Morning Edition about plug-in electric vehicles (PEVs) misses the mark. At C2ES, we don’t believe PEVs are the single answer to our transportation energy security and environmental problems, but we think they could make a contribution if they’re given a fair shot. That’s why we started an initiative on PEVs almost a year ago to take a practical look at the challenges and opportunities of PEV technology.
First, the story mentions plug-in hybrid electric vehicles (PHEVs) like the Chevrolet Volt at the outset, but then ignores how that vehicle type overcomes the problem at the heart of the story – range anxiety. The fear of being stranded due to inadequate driving range and deficient charging infrastructure is a legitimate critique of battery electric vehicles (BEVs). BEvs are battery-only vehicles, i.e. they cannot run on gasoline. But, the Volt and soon-to-be-released Toyota Prius Plug-in Hybrid can run on gasoline or electricity and have the same range as a conventional car. You can travel 25 to 50 miles in a Volt or up to 15 miles in a plug-in Prius without using gasoline and then rely on gasoline to fuel the rest of your trip. It’s difficult to estimate how many trips these electric-only ranges will accommodate, but a plug-in hybrid overcomes the need for a consumer to make that determination. In case you’re wondering, the average car trip length is 9.34 miles according to the National Household Transportation Survey.
November 16, 2011
On E&E TV's OnPoint, Eileen Claussen discusses goals of the newly-launched Center for Climate and Energy Solutions (C2ES) and assesses the current state of energy policy talks in Washington. Claussen also gives her views on the Obama administration's handling of energy policy. Click here to watch the interview.
Click here for additional details on C2ES.
For those of you who came to our website today expecting to find information and resources from the Pew Center on Global Climate Change, please don’t click away. Today we announced an exciting transition. We are now C2ES — the Center for Climate and Energy Solutions. In addition to changing our name, we’ve refreshed our mission and strategic approach, updated our website, and made other changes to ensure that we can continue to craft real solutions to the energy and climate challenges we face today.
Yes, a great deal has changed in the last 24 hours. But what hasn’t changed is the need for straight talk, common sense and common ground. Today’s climate and energy issues present us with real challenges — and real opportunities as well. This is about protecting the environment, our communities and our economy. And it is about building the foundation for a prosperous and sustainable future.
Over the past few weeks, college students have been shedding light on the future of solar energy on the National Mall in Washington, D.C. Out of 19 teams from around the globe and 10 energy performance and livability contests, one overall winner emerged at the recently held U.S. Department of Energy 2011 Solar Decathlon. The winning WaterShed home design, built by students from the University of Maryland, was inspired by the Chesapeake Bay ecosystem. The house included a 9.2 kilowatt rooftop solar array and prominently featured storm water management and recycling components, such as a butterfly roof and pollution filtration.
This Q&A orginally appeared on Singapore International Energy Week's website.
Q1. The Kyoto Protocol expires in 2012. Do you see an agreement on its successor during negotiations at Durban later this year? Or is an extension of the Kyoto Protocol or a move to a transitional framework a more likely outcome?
Eileen Claussen: The Kyoto Protocol has played an important role in advancing climate change efforts in some parts of the world. Most notably, the European Union established its successful Emissions Trading System and other policies in order to fulfil its obligations under the Kyoto Protocol. However, because developing countries are exempt from Kyoto's emission targets and because the United States has chosen not to join, the Protocol covers just one-third of global greenhouse gas emissions. Japan, Canada and Russia have made clear that they will not take on new binding targets post-2012 without commensurate obligations by the United States and the major developing countries, which are not prepared for binding commitments. Hence, there appears very little prospect of new Kyoto commitments being adopted in Durban.
While our ultimate aim should be a comprehensive and binding international climate framework, we must accept that getting to binding commitments will take time. The Cancún Agreements made important progress in strengthening the existing frameworks in the areas of finance, transparency, adaptation and technology. Further incremental progress in these areas will promote near-term action and will strengthen parties' confidence in one another and in the regime, thereby building a stronger foundation for a later binding agreement. At the same time, countries must continue strengthening political will and policies domestically. In Durban, parties should make concrete progress in implementing the Cancún Agreements--for instance, by establishing the Green Climate Fund and agreeing on stronger transparency measures--while affirming their intent to work toward binding outcomes.
Q2. Global GHG emissions increased by a record amount last year. Is the goal of preventing a temperature rise of more than 2 degree Celsius just a "nice Utopia" as IEA's Dr Fatih Birol put it?
EC: Long-term goals are tricky. On the one hand, they provide a rallying point to help focus attention and orient action, and a yardstick for measuring progress. On the other hand, they are meaningful only if they can be operationalized, and if interim efforts don't appear to be on track, people may be discouraged as a result and the will to act may actually weaken. In the case of climate, a temperature goal is appealing because it is easily related in the public mind to the core issue--global warming. But as a metric, it is several steps removed from the action that is needed: Reducing emissions. From a practical standpoint, a global emissions goal might be more helpful.
Countries' pledges to date clearly do not put us on the path to meeting the 2 degree goal. While achieving the goal is not yet out of the question, it would require a dramatic acceleration of efforts around the globe. The bottom line is that we know what direction we must go. Whatever our long-term goal--indeed, whether or not we have a long-term goal--the immediate challenge is the same: Ramping up our efforts as quickly as possible.
Q3. How much of an impact will the recent nuclear power crisis in Japan have on GHG emissions reduction?
EC: It is still too early to know what impact the Fukushima disaster will have on energy choices and greenhouse gas emissions around the world. The most dramatic example is the recent decision by Germany to completely phase out nuclear power. While many in Germany believe that the gap can be filled by renewable energy and improved energy efficiency, others are deeply concerned that the country will deepen its reliance on coal, making it impossible to achieve its ambitious greenhouse gas reduction goals.
Other countries must assess for themselves the implications of Fukushima for their energy futures. For those countries choosing to continue or deepen their reliance on nuclear power, the tragedy clearly offers lessons for improving safety. Given the continued growth in energy demand projected in the future, particularly in developing countries, it is difficult to imagine that we will be able to meet the world's energies needs and simultaneously meet the climate challenge without continued reliance on nuclear power. It is therefore imperative that we continue striving to enhance safety and solve the issue of long-term waste disposal.
Q4. Technology is seen as a key enabler to achieve low emissions growth. In your opinion, what are the top three technologies available today that can make the biggest impact?
EC: There are thousands of technologies available today that could make a huge impact with the right policy support, such as a price on carbon. But the problem, at least in the US today, is that it is unclear when such policy support will be forthcoming. So I will pick my top three based on the ones that need the least additional policy support to make a contribution, either because they yield multiple economic benefits beyond climate, or because they benefit from existing policy drivers.
a. Batteries in cars. Batteries can be used in vehicles in a variety of ways. While a battery-only vehicle may only be able to fill a niche market, hybrid vehicles that run on either gasoline or electricity will likely have broader appeal, and start-stop batteries, which turn off the gasoline engine while a vehicle idles, can be applied to just about any vehicle, achieving modest per-vehicle reductions that add up to significant reductions fleet wide. The combination of new US standards for fuel economy and GHG emissions and electric utility interest in selling electricity can drive battery costs down. The potential emission reductions are enormous, but they depend on cleaning up the electricity grid.
b. Information technology. IT can enable dramatic GHG reductions, for example through energy efficiency (e.g. smart buildings that turn on lights and HVAC when they're needed and turn them off when they're not), substituting videoconferencing for travel, and using wireless communication to optimize transportation routing for people and goods. Convenience and time savings are such powerful drivers of IT that it needs little incremental policy support.
c. Carbon capture and storage (CCS) for enhanced oil recovery (EOR) using CO2. CCS is technically available, and potentially a game changer, enabling us to continue to use fossil fuels but with very low CO2 emissions. CO2-EOR is already economic using naturally occurring CO2, and is close to economic using captured CO2. With very little policy support, EOR using captured CO2 could yield some near-term emission reductions while driving CCS costs down, thereby enabling enormous emission reductions in the future.
Q5. Energy efficiency has long been touted as the lowest hanging fruit to address the energy and climate change challenges. Many Asian countries have announced ambitious targets to cut their energy and carbon intensities. For example, as part of its 12th Five-Year Plan, China has indicated that it aims to cut energy intensity by 16 percent and carbon intensity by 17 percent in the next five years. Do you think Asian countries are doing enough? What more can they undertake to help combat climate change?
EC: Efficiency improvements that generate more economic output with less energy input are important for a variety of reasons, including energy supply security, pollution and greenhouse gas (GHG) emission reduction, and improvement of livelihoods. Countries such as Korea, China and India have taken significant measures to improve efficiency, with the result that the energy intensity of their economies has been lowering over the past decade.
Many energy efficiency measures are classified as "low hanging fruit," meaning the energy savings and other benefits they produce far outweigh the cost of investing in them. Asian countries are currently focusing on exploiting these low hanging fruit, notably in the industrial and power sectors, as well as in appliances and equipment, and large commercial and public buildings. Eventually, achieving additional energy savings will require more expensive investments, and targeting more difficult sectors, such as small and medium enterprises and households.
Asian governments will need to adjust policy tools to meet these new challenges. Policy certainty and appropriate price signals are important to ensure the efficiency improvement potentials of current investments are maximised. One way of providing these is through cap-and-trade type systems, such as those being considered or developed in China, India and Korea. This will also require the phase-out of subsidies that artificially decrease energy prices and encourage consumption rather than conservation. Though progress is slow, several Asian countries have taken or are taking steps in this direction as well.
Limiting the growth of or reducing energy consumption is, of course, essential. However, shifting to less carbon-intensive sources of energy is equally important in the medium to long term. As such, many Asian countries should also be commended for investing in developing less GHG-intensive energy sources.
The Pew Center's September 2011 newsletter highlights a new intiative focused on expanding carbon dioxide enhanced oil recovery, a new brief on international climate assistance, the lessons we can learn from Hurrican Irene, and more.
- Hydropower is a renewable, efficient, and reliable source of energy that does not directly emit greenhouse gases or other air pollutants, and that can be scheduled to produce power as needed, depending on water availability.
- There are about 78,000 megawatts of hydropower generation capacity in the United States.
- Over the last decade, depending on water availability, hydroelectricity provided 5.8 to 7.2 percent of the electricity generated in the United States and averaged more than 70 percent of the electricity generated annually from all renewable sources, although this share is falling as the renewable capacity from other sources grows.
- More than half of the total U.S. hydroelectric capacity for electricity generation is concentrated in three western states--Washington, California and Oregon--with approximately 26 percent in Washington alone. Canada is a major electricity supplier to New York, New England, the Upper Midwest, the Pacific Northwest, and California.
- Hydropower could offer at least 80,000 megawatts of additional generation capacity. Small, micro, and low hydropower are developing hydro technologies, while the efficiency and capacity of existing hydroelectric generators can be improved. Only about 3 percent of the roughly 80,000 dams in the United States have hydropower plants and can generate electricity.
- Existing hydropower is very inexpensive to operate (generation costs 2 to 4 cents per kilowatt-hour). The levelized cost of electricity of new hydropower projects, of less than 50 megawatts, (6 to 14 cents per kilowatt-hour) and incremental hydropower projects (adding generating capacity to existing dams; 1 to 10 cents per kilowatt-hour) puts them among the least expensive forms of low-carbon electricity.
- The effects of climate change on water availability are expected to affect hydropower generation.
Hydropower, or hydroelectricity, is electricity generated by the force of moving water in the penstock of a hydropower unit. Turbines are used to capture the kinetic energy of water by converting it to electricity as the falling water spins the turbine. Hydropower plants may be located below reservoirs or built in rivers (called “run-of-the-river” units) with no water storage capacity. Hydropower is considered a renewable source of energy, as it relies on water which is continuously renewed through the natural water cycle.
Hydroelectricity’s low cost, near-zero emissions, and ability to be dispatched quickly to meet peak electricity demand have made it one of the most valuable renewable energy sources worldwide. Hydropower accounts for about 17 percent of the world’s total electricity generation.
Depending on water availability and annual precipitation, hydroelectricity has provided 5.8 to 7.8 percent of the electricity used in the United States in the last dozen years and is the largest renewable source of electricity in the United States.,U.S. hydropower accounted for 8.5 percent of global hydropower capacity and 7.6 percent of global hydropower generation in 2010 (1.29 percent of global electricity generation from all sources).
The amount of electricity generated by a hydropower facility depends on three factors: 1) the turbine generating capacity; 2) the turbine discharge flow (the volume of water passing through the turbine in a given amount of time), and 3) the site head (the height of the water source or vertical distance between the highest point of water source and the turbine). The higher the head, the more gravitational energy the water has as it passes through the turbine. Most existing hydropower facilities in the United States can convert about 90 percent of the energy of falling water into electricity, which makes hydropower a technically efficient source of energy.
U.S. hydropower plants are very diverse. They might be located at dams with various storage capacities or be run-of-the-river facilities with no water storage capacity. Their elevation also varies. Only 3 percent of the dams in the United States have hydropower plants and can generate electricity.
Generally, based on the head and storage capacity availability, hydropower plants are categorized as follows:
- Low-Head High-Storage Hydropower Plants
These facilities are usually located behind multi-purpose (water supply, flood control, etc.) dams which have hydropower generation as an ancillary benefit. The reservoirs associated with these units are large (high storage capacity) while the head is relatively low at these facilities.
- High-Head Low-Storage Hydropower Plants
These facilities are often located behind reservoirs which have hydropower generation as their single objective. The reservoirs associated with these units are small (low storage capacity) while the head is relatively high. These units are usually located at higher elevations.
- Run-of-the-River Hydropower Plants
These facilities are usually built on rivers with steady natural flows or regulated flows discharged from upstream reservoirs. These units have little or no storage capacity, and hydropower is generated using the river flow and water head. Run-of-the-river hydropower plants are less appropriate for rivers with large seasonal fluctuations.
- Pumped-Storage Hydropower Plants
At these facilities water is stored in a lower reservoir after it is released from an upper reservoir to drive the turbine and generate power. Later, water is pumped back to the upper reservoir for reuse. Pumping water back to the upper pool requires energy (electricity). Pumped-storage systems are considered as flexible sources of electricity generation. These units generate electricity when demand and price are higher (during peak hours) and pump water back to the upper pools when electricity demand and price are lower. Pumped-storage plants are not net energy producers; rather, they provide energy storage and electricity at its peak demand times (see Climate Techbook: Energy Storage).
Hydropower plants can also be categorized based on their capacities:
- Large Conventional Hydropower plants
These facilities have a generation capacity of more than 30 megawatts. The installed large hydropower capacity in the U.S. is approximately 66,500 megawatts.
- Small Conventional Hydropower plants
These facilities have a generation capacity of 1 to 30 megawatts. The installed small hydropower capacity in the U.S. is approximately 8,000 megawatts.
- Low Power Hydropower Plants
These facilities have a generation capacity of 100 kilowatts to 1 megawatt. The installed low power hydropower capacity in the U.S. is approximately 350 megawatts.
- Micro Hydropower Plants
These facilities have a generation capacity of less than 100 kilowatts.
Electricity demand fluctuates during the day and between months depending on different factors, most importantly the hour of the day and temperature. One of the advantages of hydropower over other sources of electricity (e.g., variable wind and solar power or baseload coal and nuclear plants) is its generation flexibility. Such flexibility enables hydropower to meet sudden fluctuations in demand or help to compensate for the loss of power from other sources. Hydropower can be used for both baseload and peak generation.
Environmental Benefit/Emission Reduction Potential
Hydropower is a clean source of energy, as it burns no fuel and does not produce greenhouse gas (GHG) emissions, other pollutants, or wastes associated with fossil fuels or nuclear power. However, hydropower does cause indirect GHG emissions, mainly during the construction and flooding of the reservoirs. This may be due to decomposition of a fraction of the flooded biomass (forests, peatlands, and other soil types) and an increase in the aquatic wildlife and vegetation in the reservoir. Hydropower’s GHG emissions factor (4 to 18 grams CO2 equivalent per kilowatt-hour, , , ) is 36 to 167 times lower than the emissions produced by electricity generation from fossil fuels., Compared to other renewables, on a lifecycle basis hydropower releases fewer GHG emissions than electricity generation from biomass and solar and about the same as emissions from wind, nuclear, and geothermal plants.
Hydropower is mainly criticized for its negative environmental impacts on local ecosystems and habitats. Damming a river alters its natural flow regime and temperature, which in turn changes the aquatic habitat. Such a change disturbs the river’s natural flora and fauna. Fish are very sensitive to hydropower operations, and fish species (especially migratory species) have been significantly affected by hydropower dams across the United States. Small, low and micro hydropower facilities have much smaller negative environmental impacts than large hydropower facilities, but even they can engender public concern.,
Studies have estimated significant potential for increased deployment of hydropower in the United States, with additional generation capacity of at least 80,000 megawatts, mostly provided through the development of new small and micro hydroelectric plants (accounting for nearly 59,000 megawatts), development of new hydroelectric capacity at existing dams without hydropower facilities (17,000 megawatts), and generation efficiency improvements at existing facilities (4,000 megawatts). Fully realizing the aforementioned low or high estimates of new hydropower potential might reduce or avoid CO2 emissions from electricity generation equal to roughly 8.5 percent of total 2003 U.S. CO2 emissions from electricity generation.In its reference case scenario, the Energy Information Administration (EIA) predicts that between 2009 and 2035, conventional hydropower capacity will average 0.1 percent growth and hydropower generation will average 0.5 percent growth. Its overall share of renewable electricity capacity will fall as other renewable energy sources are deployed.
A 2010 report from the International Energy Agency (IEA) projected that global hydropower production might grow by nearly 75 percent from 2007 to 2050 under business-as-usual but that it could grow by roughly 85 percent over the same period in a scenario with aggressive action to reduce GHG emissions. However, even under this latter scenario, increased hydropower generation is projected to provide only about 2 percent of the total GHG emission reductions from the global electric power sector compared to business-as-usual by 2050 (with all renewable technologies nonetheless providing nearly 33.5 percent of GHG abatement from the power sector). According to IEA, a realistic potential for global hydropower is 2 to 3 times higher than the current production, with most remaining development potential in Africa, Asia, and Latin America. IEA also notes that, while small hydropower plants could provide as much as 150 to 200 GW of new generating capacity worldwide, only 5 percent of the world’s small-scale (i.e. small, low, and hydro) hydropower potential has yet been exploited.
Existing hydropower is one of the least expensive sources of power since the cost of hydropower is dominated by the initial capital cost of building the facility while the ongoing operating and maintenance (variable) costs are low. Moreover, since hydropower generation does not require burning fuels, operations costs are not vulnerable to fuel price fluctuations. Existing hydropower facilities are very cheap to operate and they can operate for 50 years or more without major replacement. The cost of hydropower is highly site-specific and depends on different factors, including hydrologic characteristics, site accessibility, and distance from transmission. A 2008 study of the cost of new renewable electricity generation in the western United States (where much of the potential for new U.S. hydropower is located) estimated the levelized cost of incremental hydropower at existing dams to be $0.01 to $0.10 per kilowatt-hour (kWh) and the levelized cost of new small and micro hydropower to be between $0.06 and $0.14 per kWh, making incremental hydropower the least expensive option for new renewable generation and new hydropower roughly on par with new wind and biopower.
Current Status of Hydropower
At present, there are about 78,000 megawatts of hydropower generating capacity in the United States, enough to supply 28 million households with electricity, or replace 500 million barrels of oil. Pumped-storage facilities offer an additional to 22,000 megawatts of capacity to that amount. More than half of the total U.S. hydroelectric capacity for electricity generation is concentrated in three western states-- Washington, California and Oregon--with approximately 27 percent in Washington alone. There are nearly 2,400 hydropower facilities in the United States, although the United States has roughly 80,000 dams., In the past 10 years, hydropower has provided between 5.8 and 7.2 percent of total U.S. electricity, and, in 2010, hydropower accounted for nearly 60 percent of all renewable electricity generated in the United States. The United States has constructed very few new large dams since the early 1980s owing to concerns over their negative impacts on rivers, and the construction of new large hydropower dams is not considered a practical option for increasing hydropower generation due to the environmental impacts and unavailability of proper sites to develop for large-scale hydropower generation.
The U.S. Army Corps of Engineers is the largest hydropower operator in the country, running 75 plants with a total installed capacity of 20,474 megawatts (26 percent of nationwide capacity). These federal plants produce about 100 billion kilowatt-hours a year, nearly a third of the nation’s total hydropower output, or enough to serve about ten million households. The privately owned dams in the United States which generate hydroelectric power are under the regulatory authority of the Federal Energy Regulatory Commission (FERC). FERC issues licenses for legal operation of hydropower dams to permit the dam owner to use public waters for hydropower generation. FERC licenses are renewed every 30 to 50 years. License renewal is an opportunity to balance the hydropower benefits against the negative effects of hydropower generation on the health of aquatic and riparian ecosystems.
Currently, 1,010 gigawatts of hydropower generation capacity are in operation globally, and in 2010, 30 gigawatts of new capacity was added. Hydropower accounts for about 16 percent of global total electricity generation and nearly 85 percent of renewable electricity generation (in 2008).As regions, Central and South America generate nearly 64 percent of their electricity from hydropower, and many countries, including several large countries such as Canada and Brazil, rely on hydropower for more than half of their electricity., China currently obtains about 16 percent of its electricity from hydropower; from 2005 to 2010, China added almost 100 gigawatts of hydropower capacity, increasing generation by almost 40 percent between 2005 and 2009 (global hydroelectric generation averaged slightly negative annual growth between 2005 and 2008).
Obstacles to Further Development or Deployment of Hydropower
- Unavailability of Proper Sites for New Large Hydro Facilities
The best sites for large hydropower generation in the United States have already been developed, and developing new sites for hydropower generation without negative ecological and recreational impacts is challenging. Storage and generation capacity expansions at existing hydropower sites or adding hydropower generation to reservoirs with existing dams that currently lack hydroelectricity generation is more likely.
- Regulatory Hurdles
Hydropower is the most heavily regulated electricity generating technology after nuclear power, with regulatory requirements that may be time-consuming, expensive, and redundant as well as tailored to past experience with large hydropower projects, despite the likelihood that small-scale and incremental hydropower will be most important for future U.S. hydropower growth.
- Environmental Tradeoffs
There is a tradeoff between the GHG avoidance or reduction benefits of hydropower and other environmental impacts. Increasing hydropower generation can have negative ecological and recreational impacts. For example, FERC, in an effort to protect riverine ecosystems, has often mandated reduced hydropower production levels under hydropower licenses.
- Climate Change
Climate change and the alteration of rainfall and temperature regimes can affect hydropower generation. Hydropower systems with less storage capacities are more vulnerable to climate change, as storage capacity provides more flexibility in operations. Although hydropower systems may benefit from more storage and generation capacity, expansion of such capacities may not be economically and environmentally justified.
Policy Options to Help Promote Hydropower
- Price on Carbon
A price on carbon would raise the cost of electricity produced from fossil fuels relative to the cost of electricity from renewable sources, such as hydropower, and other low carbon technologies.
- Renewable Electricity Standards
Renewable electricity standards (renewable portfolio standards) require electricity providers to gradually increase the amount of renewable energy resources—such as wind, solar, bioenergy, and geothermal—in their electricity supplies, until they reach a specified target by a specified date. The hydropower production growth under these standards is mostly provided through development of small-scale hydropower and this growth is considerably slower than increase in electricity generation from other renewable sources.
- Economic Incentives
Different financial incentives (e.g. tax credit bonds, production tax credit, incentive payments) are provided to encourage the growth of hydropower generation, improving efficiency at existing projects, and more reliance on renewable electricity sources in the United States.
- R&D Efforts
R&D efforts are required to improve efficiencies, reduce costs and negative environmental impacts, and improve reliability and durability of hydropower technologies. Integration of hydropower systems with other renewable sources (developing hybrid systems) of electricity generation are recommended. There is a need for further R&D to improve equipment designs, investigate different materials, improve control systems, and optimize generation as part of integrated water-management systems.
Hydropower generation is an ancillary benefit of most dams that currently have it. Absence of reliable hydrological forecasts may result in needlessly foregone hydropower. For instance, a reservoir may be emptied to minimize the flood risks and ensure that flooding does not occur. In that case minimizing flood risks results in loss of hydropower benefits. R&D efforts are required for improving the meteorological and hydrological forecasting abilities for better performance of hydropower systems.
- Adaptive FERC Licenses
FERC licenses are issued for periods of 30 to 50 years. Hydrological and ecological changes of hydropower systems during this period may require changes in the license requirements to increase the hydropower and environmental benefits. Adaptive FERC licenses may help to avoid the need to change license requirements and improve the performance of hydropower systems.
Related Business Environmental Leadership Council (BELC) Company Activities
Related C2ES Resources
Further Reading / Additional Resources
Aspen Environmental Group and M. Cubed (2005); “Potential changes in hydropower production from global climate change in California and the western United States”; California Climate Change Center, CEC-700-2005-010, June 2005 (http://www.energy.ca.gov/2005publications/CEC-700-2005-010/CEC-700-2005-010.PDF).
Casola, J. H., Kay J. E., Snover A. K., Norheim R.A., Whitely Binder L. C., the Climate Impacts Group (2005), “Climate Impacts on Washington’s Hydropower, Water Supply, Forests, Fish, and Agriculture”, Center for Science in the Earth System, Joint Institute for the Study of the Atmosphere and Ocean, University of Washington, Seattle (http://cses.washington.edu/db/pdf/kc05whitepaper459.pdf).
Electric Power Research Institute (EPRI) (2007), Assessment of Waterpower Potential and Development Needs (http://www.aaas.org/spp/cstc/docs/07_06_1ERPI_report.pdf).
Energy Information Administration, International Energy Statistics (Official Energy Statistics from the U.S. Government) (http://www.eia.gov/cfapps/ipdbproject/IEDIndex3.cfm).
Hall D. G. and K. Reeves (2006) A Study of United States Hydroelectric Plant Ownership, Report prepared for the National Renewable Energy Laboratory, Idaho National Laboratory, INL/EXT-06-11519.
Idaho National Laboratory, Hydropower Program (http://hydropower.inl.gov/index.shtml).
IEA (2010) Energy Technology Perspectives, Scenarios and Strategies to 2050, In support of the G8 Plan of Action,
Kosnik L. (2008), “The Potential of Water Power in the Fight against Global Warming in the US”, Energy Policy (36): 3252-3265.
Madani K., Lund J. R. “High-Elevation Hydropower and Climate Warming In California.” http://www.ltrr.arizona.edu/~katie/kt/FLOODS-USGS/NSF-AHIS/World-Env-Water-Res-Congress-Proc-2007/40927-3342.pdf
National Energy Education and Development Project (2008) Hydropower, Secondary Info Book, pp. 24-27 (http://www.need.org/needpdf/infobook_activities/SecInfo/HydroS.pdf).
U.S. Army Corps of Engineers (2009) Hydropower; Value to the Nation (http://www.vtn.iwr.usace.army.mil/docs/VTNHydropowerBro_loresprd.pdf).
U.S. Department of Energy, Wind and Hydropower Technologies Program Website, Hydropower (http://www1.eere.energy.gov/windandhydro/hydro_technologies.html).
Wilbanks T. J., T. Bhatt, D. E. Bilello, S. R. Bull, J. Ekmann, W. C. Horak, Y. J. Huang, M. D. Levine, M. J. Sale, D. K. Schmalzer, and M. J. Scott (2008) Effects of Climate Change on Energy Production and Use in the United States, Synthesis and Assessment Product 4.5, Report by the U.S. Climate Change Science Program and the Subcommittee on Global Change Research, February 2008.
World Bank Group (2009), Directions in Hydropower
 U.S. Energy Information Administration (EIA) (2009) “Existing Capacity by Energy Source,” 2010. http://www.eia.gov/cneaf/electricity/epa/epat1p2.html
 U.S. Energy Information Administration (EIA) (2011) “Net Generation by Energy Source: Total All Sectors.” 2011. http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_5.pdf
 U.S. Energy Information Administration (EIA) (2010) “Net Generation from Hydroelectric (Conventional) Power by State by Sector, Year-to-Date through December 2010 and 2009.” 2011.
 Kosnik, L-R (2008a), “The Potential of Water Power in the Fight against Global Warming in the U.S.,” Energy Policy (36): 3252-3265. Accessed 1 August 2011. http://www.umsl.edu/~kosnikl/Saved%20Emissions.pdf
 National Hydropower Association. “Hydro Works for America.” Accessed 25 July 2011.
 Idaho National Laboratory. “Hydropower Plant Costs and Production Expenses.” Accessed 25 July 2011.
 California Institute for Energy and the Environment (CIEE), Renewable Energy Transmission Initiative (RETI): Phase IA. Final Report prepared by Black & Veatch. April 2008. http://www.energy.ca.gov/2008publications/RETI-1000-2008-002/RETI-1000-2008-002-F.PDF
 A penstock is an intake structure or enclosed pipe that that delivers water to turbines.
 U.S. Energy Information Administration (EIA) (2008) “International Energy Statistics – Electricity Generation” Accessed 29 July 2009. http://www.eia.gov/cfapps/ipdbproject/iedindex3.cfm?tid=2&pid=33&aid=12&cid=ww,&syid=2005&eyid=2009&unit=BKWH
 U.S. Energy Information Administration (EIA) (2011) “Net Generation by Energy Source: Total All Sectors.” http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_5.pdf
 EIA (2014) “International Energy Statistics.” Accessed 18 February 2014. http://www.eia.gov/cfapps/ipdbproject/IEDIndex3.cfm
 Electric Power Research Institute (EPRI) (2007), Assessment of Waterpower Potential and Development Needs (http://www.aaas.org/spp/cstc/docs/07_06_1ERPI_report.pdf).
 Hydro Quebec (2009) Greenhouse Gas Emissions and Hydroelectric Reservoirs (http://www.hydroquebec.com/sustainable-development/documentation/ges.html).
 Tremblay A., Varfalvy L., Roehm C. and Garneau M., The Issue of Greenhouse Gases from Hydroelectric Reservoirs: From Boreal to Tropical Regions, Table 1, p. 3 (http://www.un.org/esa/sustdev/sdissues/energy/op/hydro_tremblaypaper.pdf).
 Meier P. J. (2002) Life-Cycle Assessment of Electricity Generation Systems and Applications for Climate Change Policy Analysis, Ph.D. Dissertation, University of Wisconsin, Madison (http://fti.neep.wisc.edu/pdf/fdm1181.pdf).
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 Tremblay et al. GHG emissions from reservoir flooding are higher in tropical areas, and in other regions reservoirs older than 10 years produce GHG emissions similar to natural lakes.
 Van de Vate, 2002. Run-of-the-river systems produce less GHG emissions (5 to 10 g CO2 equivalent per kilowatt-hour) due to absence of reservoirs.
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- Hydrokinetic technologies use the power of moving water – ocean waves or currents in canals, rivers, and tidal channels - to produce electricity.
- New hydrokinetic generation technologies are primarily in the development, demonstration, and pilot phases of deployment and have not yet been commercialized.
- In 2011, the United States had less than 1 megawatt (MW) of installed hydrokinetic, as compared to more than 77,000 MW of conventional hydroelectric generation capacity.,
- Many hydrokinetic development projects are underway in the United States - as of 2011, the Federal Energy Regulatory Commission (FERC) has issued 70 preliminary permits for hydrokinetic projects.
- Some experts predict that hydrokinetic energy could provide 13,000 MW of new generation capacity to the United States by 2025.
- Like some other renewable energy sources, ocean wave power is variable, with actual generation changing with fluctuations in wave height and/or period. Unlike wind and solar power, however, this variability is highly predictable (for days ahead) facilitating the integration of ocean wave power into electricial grid operations. Tidal current flows can be nearly constant throughout the year, so these hydrokinetic power sources can supply baseload generating capacity. River currents typically fluctuate seasonally and with precipitation events.
The power of tidal, river, and ocean currents and ocean waves is tremendous, and the basic concept behind hydrokinetic power is not new. For centuries people have harnessed the power of river currents by installing water wheels of various sorts to turn shafts or belts.
Modern ocean wave energy conversion machines use new technology that is designed to operate in high amplitude waves, and modern tidal/river/ocean current hydrokinetic machines use new technology that is designed to operate in fast currents. Both of these emerging technologies have the potential to provide significant amounts of affordable electricity with low environmental impact given proper care in siting, deployment, and operation.
Tidal/river/ocean current energy and wave energy converters are sometimes categorized separately, but this factsheet covers both types of technology under the general term “hydrokinetic power.” Another marine energy technology, ocean thermal energy conversion, is not covered in this factsheet because it is not applicable to the continental United States but rather to tropical areas.
Wave energy converters take many forms. The simplest are tethered floating buoys that convert the energy in the rise and fall of the passing waves into electricity (often via hydraulics). Other machines have chambers that, when filled and emptied by rising and falling wave water, compress and decompress air to drive an electric generator. Yet another type of machine looks like a giant sea snake with floating pontoons that heave and sway on the ocean surface, driving hydraulic pumps to power an electric generator (see Figure 1 and Figure 2). All of these machines are anchored to the seabed and must withstand marine environments. Waves powerful enough to drive these generators are often found off coasts with large oceans to their west (providing long wind fetch) and strong prevailing winds such as the west coasts of the United States, Chile, and Australia and in the North Sea, amongst many other places.
Figure 1: The 750 kilowatt (kW) Pelamis sea “snake” converting wave energy to electricity during sea trials in Aguçadoura, Portugal.
Source: Pelamis Wave Power, August 2009.
Figure 2: Illustration of the sea snake’s operation.
Source: Pelamis Wave Power, August 2009
Rotating devices take a variety of forms but in general capture energy from water flowing through or across a rotor. Some of these devices are shaped like propellers and can swing, or yaw, to face changing tidal currents. Other rotating devices are shaped like a jet engine, having many vanes turning within a fixed outer ring (seeFigure 3). Fast currents, like those in the Missouri and Mississippi Rivers, in tidal channels such as the Puget Sound, or in ocean currents such as the Gulf Stream off Florida, have enough power to turn large rotating devices. The power from a hydrokinetic machine is proportional to the cube of the current velocity. Faster currents are better, and sites with current velocities reaching 3 meters per second (m/s) are desirable. Tidal barrage technology takes advantage of predictable ocean tides. A barrage, or dam across an estuary or tidal channel, traps tidal flows and then releases them through turbines as tides fall.
Figure 3: An ocean view of OpenHydro’s tidal current turbine installed near the Orkney Islands at the European Marine Energy Consortium (EMEC) test site.
Source: European Marine Energy Consortium (Image: Mike Brookes-Roper)
Environmental Benefit/Emission Reduction Potential
Deploying hydrokinetic power generation instead of relying on fossil fuels for electricity generation avoids greenhouse gas (GHG) emissions and other air pollution associated with fossil fuel use. It has been estimated that 13,000 megawatts of hydrokinetic capacity could be developed by 2025. At full potential, hydrokinetic sources could generate 400 terawatt-hours (TWh) per year, or around 10 percent of U.S. demand in 2007. Assuming hydrokinetic generation displaces generation from the current mix of U.S. fossil fuel power plants, this level of hydrokinetic power generation would avoid over 250 million metric tons of carbon dioxide (CO2) emissions per year, equal to 4 percent of total U.S. CO2 emissions in 2007.,
Unlike conventional hydroelectric generation, hydrokinetic power does not require a dam or diversion, thus avoiding the negative environmental impacts associated with dams.
Because no commercial hydrokinetic power projects are currently licensed and operating in the United States, it is difficult to estimate the cost of hydrokinetic power production. A 2005 report by the Electric Power Research Institute (EPRI) estimated that some U.S. utility-scale wave power projects could produce electricity for about 10 cents per kilowatt-hour (kWh) once the technology has matured. The present state of technology makes hydrokinetics a long-term investment opportunity with potentially significant but highly uncertain returns. In the meantime, the early stage of the technology and high regulatory costs associated with lengthy permitting requirements and licensing uncertainties are likely to continue presenting major economic hurdles to commercialization of the technology.
Current Status of Hydrokinetic Electric Power
A number of hydrokinetic generation technologies are moving beyond pilot or demonstration stages in the United States and globally, and several U.S. commercial wave and tidal energy projects are likely to apply for federal operating licenses in the near future. Areas in the United States with good wave energy potential include most of the continental U.S. west coast, Hawaii, and Alaska. For tidal energy, good sites exist in the Puget Sound, San Francisco, a variety of east coast tidal channels, and in Alaska. For river hydrokinetic energy, large inland rivers such as the Mississippi, Missouri, and Yukon have promising potential power.
As of June 2011, the Federal Energy Regulatory Commission (FERC) had issued 70 preliminary permits for hydrokinetic projects (27 tidal, 8 wave, and 35 inland) with 9,306 megawatts (MW) of generation capacity (see Figure 4). Preliminary permits are pending for an additional 147 projects with 17,353 MW of capacity. These preliminary permits allow feasibility studies but no permanent or large-scale installations. In 2010, a utility-scale wave power project in Reedsport, Oregon, capable of supplying electricity to 1,000 homes, received the first-ever Settlement Agreement with FERC and is expected to apply for a commercial license in the next couple of years. In addition, the Department of Energy awarded $34 million to hydrokinetic research and development (R&D) projects in the FY2010 budget.
On a global scale, at least 25 countries have initiated hydrokinetic R&D activities. Only tidal barrage technology has achieved commercial scale, and it accounts for 262 MW of the nearly 270 MW of hydrokinetic installed capacity. Approximately 2 MW of wave power and 4 MW of tidal power have been installed, but mostly as short-run tests or prototypes. As in the United States, the development of hydrokinetic projects is also reaching the early commercial stage in other countries, including the under-development 254 MW Sihwa tidal barrage power project in South Korea and the proposed 50 MW tidal current power project off the coast of Gujarat, India.
Figure 4: Map of FERC preliminary permits issued for hydrokinetic projects, June 2011.
Source: Federal Energy Regulatory Commission, June 2011.
Facilities for testing and demonstrating new hydrokinetic technologies are also being established. Prominent R&D centers for each technology include:
- Wave Energy - the European Marine Energy Consortium (EMEC) in Scotland, Wave Hub in Cornwall England, The Danish Wave Energy Center in Hanstholm, the New England Marine Renewable Energy Center (MREC) at the University of Massachusetts Dartmouth, the Northwest National Marine Renewable Energy Center (NNMREC) at Oregon State University, Hawaii’s National Marine Renewable Energy Center (HNMREC), and the Southeast National Marine Renewable Energy Center at Florida Altantic University. Other notable facilities are found in Galway Bay in Ireland and the Azores in Portugal.
- Tidal Energy - the European Marine Energy Consortium (EMEC) in Scotland, the New England Marine Renewable Energy Center (MREC) at the University of Massachusetts Dartmouth, the Northwest National Marine Renewable Energy Center (NNMREC) at the University of Washington, and the Southeast National Marine Renewable Energy Center at Florida Altantic University. Another notable facilities are found in the Minas Passge in the Bay of Fundy in Canada.
There are a number of hydrokinetic devices that have had successful trials and remained in operation after many years of service. For tidal current power, notable examples include: the Irish Open Hydro 1-MW turbine, the first commercial-scale turbine deployed in North America; the 250 kW TREK turbine; Verdant Power’s horizontal axis turbines in the St. Lawrence River, developed following Verdant’s 2006-2008 RITE project in New York City’s East River; the 1.2 MW SeaGen turbine operating in Northern Ireland since 2008; and the 1.5 MW Morild II floating horizontal-axis prototype in Norway. For wave power, notable examples include next generation .75 GW Pelamis Wave Power devices; Aquamarine’s Oyster 1 device operating at EMEC since 2009; and Ocean Power Technologies’ 150 kilowatt PB150 PowerBuoy in Oregon.
Obstacles to Further Development or Deployment
Although equipment costs are likely to fall as technology matures, installation costs could remain high due to extreme marine environments and the specialized engineering required for large marine infrastructure projects. Operation and maintenance (O&M) costs could remain high due to difficult access and working conditions unless machines are developed that can be unattended for long periods of time.
The technology required for hydrokinetic generation - turbines, generators, structural components, and transmission lines – must withstand extreme marine and river environments. Although the technical issues are challenging, they are not insurmountable. A wide variety of propeller designs and wave energy devices are being tested, and much remains to be learned. Wave energy converters must be designed to withstand very harsh marine conditions for long periods of time. Some of the pilot projects have suffered very rapid failures for this reason.
- Permitting Requirements
Developers of hydrokinetic generation projects in the United States face considerable hurdles as regulatory agencies, such as FERC and the Minerals Management Service (MMS), adapt permitting policies to new technologies. Resource agencies, such as the Fish and Wildlife Service, will also require time to learn about the environmental effects of the new technologies. The permitting process for conventional hydroelectric projects is lengthy, taking as much as seven years to obtain an initial FERC operating license, due to a comprehensive review process and environmental study requirements. Hydrokinetic projects must go through a similar review process, and the environmental study requirements are, at this point, even lengthier because so much is unknown about environmental impacts of the new technologies. In 2007, the FERC adopted the Hydrokinetic Pilot Project Licensing Process, which streamlines the issuance of construction and operation licenses for pilot demonstration projects with rated capacities of less than 5 MW, with periods of operation of less than 5 years, and whose purpose is experimental in nature.
- Environmental Impacts
Becausehydrokinetic power does not require the construction of a dam, it should have less impact on the environment than a conventional hydroelectric project. However, there is still considerable uncertainty about environmental impacts and recognition that impacts will vary with technology and site characteristics. The pilot demonstration projects currently in operation are providing valuable data that regulators and resource agencies need to understand environmental impacts. Attention is focused on the questions of harm to fish and other marine life, detrimental changes to currents and sediment transfer, site impacts from installation and decommissioning, conflicts with other uses of the water body, and intrusive visual appearance. In 2009, the U.S. Department of Energy (DOE) delivered a comprehensive report on environmental impacts of hydrokinetic power generation to Congress. The report stated there is no conclusive evidence that hydrokinetic technologies will cause significant environmental impacts on acquatic environments, fish and fish habitats, ecological relationships, and other marine and freshwater resources.
Policy Options to Help Promote Hydrokinetic Power Generation
- Price on Carbon
A price on carbon, such as that which would exist under a GHG cap-and-trade program, would raise the cost of electricity produced from fossil fuels relative to the cost of electricity from renewable sources, such as hydrokinetic power, and other lower-carbon technologies. A price on carbon would increase both deployment of mature low-carbon technologies and R&D investments in less mature technologies.
- Research, Development, and Demonstration (RD&D)
Increased government funding for technology development and testing can help accelerate the commercialization of hydrokinetic technologies.Establishing test sites with existing permits and licenses for testing of wave energy conversion devices and hydrokinetic turbines and generators under standardized conditions could also speed technology development.
- Addressing Environmental Impacts
Government-funded test programs with resource agency participation could determine environmental impacts of hydrokinetic power generation with more certainty and inform guidelines and regulations for mitigating such impacts.
- Streamlining Licensing and Permitting
Continued efforts to simplify and accelerate project licensing and permitting would enable pilot and commercial-scale projects to be deployed more rapidly and inexpensively.
- Renewable Portfolio Standards
A renewable portfolio standard (RPS, sometimes also called a renewable or alternative energy standard, RES/AES) requires that a certain amount or percentage of a utility’s power plant capacity or electricity sales come from renewable sources by a given date. Power generators or utilities receive credits for qualified renewable generation and must have sufficient credits to meet the states’ targets. At present, 31 U.S. states and the District of Columbia have adopted RPSs (8 U.S. states have renewable energy goals). In addition, Congress has several times considered a federal RPS. State RPSs or a federal RPS could promote hydrokinetic power technologies by making them qualifying renewable technologies whose generation counts towards compliance with the RPS. In addition, RPS policies or proposals often have carve-outs for specific renewable technologies or provide extra credits for generation from certain technologies, generally in order to promote less commercially mature technologies.
Related Business Environmental Leadership Council (BELC) Company Activities
Related C2ES Resources
Further Reading/Additional Resources
Cada, Glenn et al., “Potential Impacts of Hydrokinetic and Wave Energy Conversion Technologies on Aquatic Environments,” Fisheries, April 2007.
U.S. Department of Energy (DOE)
- Marine and Hydrokinetic Technology Database
- Report to Congress on the Potential Environmental Effects of Marine and Hydrokinetic Energy Technologies
- National Renewable Energy Laboratory, Ocean Energy Technology Overview
Electric Power Research Institute (EPRI)
- Assessment of Waterpower Potential and Development Needs, EPRI Report 1014762, Palo Alto, CA March, 2007.
- Ocean Energy Program
- Ocean Tidal and Wave Energy: Renewable Energy Technical Assessment Guide—TAG-RE: 2005, EPRI Report # 1010489, Palo Alto, CA, December 2005.
- Primer: Power from Ocean Waves and Tides, Palo Alto, CA, June 2007.
Federal Energy Regulatory Commission (FERC)
- Hydrokinentic Pilot Project Licensing Project
- Joint guidance issued with Minerals Management Service (MMS) for licensing offshore hydrokinetic projects
- Hydrokinetic project licensing website, including maps of existing projects
Hagerman, George, Energy from Tidal, River, and Ocean Currents and from Ocean Waves, Presentation, 8 June 2007, Washington, DC.
International Energy Agency Implementing Agreement on Ocean Energy Systems (IEA-OES)
 U.S. Department of Energy (DOE), Energy Efficiency and Renewable Energy (EERE), “Marine and Hydrokinetic Technology Database.” Accessed 17 August 2011. http://www1.eere.energy.gov/windandhydro/hydrokinetic/default.aspx
Federal Energy Regulatory Commission (FERC), “Hydrokinetic Projects.” 9 June 2011. http://www.ferc.gov/industries/hydropower/indus-act/hydrokinetics/hydrokinetics-projects.pdf
 Electric Power Research Institute (EPRI), Assessment of Waterpower Potential and Development Needs, EPRI Report 1014762, Palo Alto, CA, March 2007.
 For example, in the American colonies, undershot waterwheels, built so that only the bottom of the wheel was in the river, drove flour and lumber mills. Dams and diversions, which are required for conventional hydroelectric (which uses the hydro potential energy) but not for hydrokinetic power, were built across rivers in the United States to power mills and factories throughout the 19th and 20th centuries. And over a century ago, ocean waves were used to pump seawater up to a tank on the cliffs in Santa Cruz, California, for spraying on dirt roads and dust control.
 Schwartz, SS, editor, Proceedings of the Hydrokinetic and Wave Energy Technologies Technical and Environmental Issues Workshop, Washington, DC, October 2005, prepared by RESOLVE, Inc., March 2006.
 Wind fetch refers to the unobstructed distance over which wind can travel across a body of water in a constant direction. Wind fetch is important because longer fetch can result in larger wind-generated waves.
 EPRI. “The Future of Waterpower: 23,000 MW+ by 2025” EESI Briefing, June 8, 2007. Accessed 4 August 2011.
 Bedard, et al. North American Ocean Energy Status – March 2007. Accessed 4 August 2011. http://oceanenergy.epri.com/attachments/ocean/reports/7th_EWTEC_Paper_FINAL_071707.pdf
 U.S. Environmental Protection Agency (EPA), Greenhouse Gas Equivalencies Calculator based on eGRID2007 Version 1.1.
 EPRI, Ocean Tidal and Wave Energy: Renewable Energy Technical Assessment Guide—TAG-RE: 2005, EPRI Report # 1010489, Palo Alto, CA, December 2005.
 Federal Energy Regulatory Commission (FERC), “Hydrokinetic Projects.” 9 June 2011. http://www.ferc.gov/industries/hydropower/indus-act/hydrokinetics/hydrokinetics-projects.pdf
 IEA Energy Technology Network. Annual Report Implementing Agreement on Ocean Energy Systems. 2010. http://www.iea-oceans.org/_fich/6/2010_Annual_Report.pdf
 Ocean Renewable Energy Coalition. “MHK Talking Points.” 2011. Accessed 5 August 2011. http://www.oceanrenewable.com/wp-content/uploads/2011/03/mhk-talking-points.pdf
 REN21. Global Status Report (GSR) 2011. 2011. http://www.ren21.net/Portals/97/documents/GSR/REN21_GSR2011.pdf
 IEA 2010.
 REN21 GSR 2011.
 Federal Energy Regulatory Commission (FERC). “Issued Hydrokinetic Preliminary Permits.” August 2011. http://www.ferc.gov/industries/hydropower/gen-info/licensing/hydrokinetics/issued-hydrokinetic-permits-map.pdf
 IEA 2010.
 Federal Energy Regulatory Commission (FERC). “Licensing Hydrokinetic Pilot Projects.” April 14, 2008. http://www.ferc.gov/industries/hydropower/indus-act/hydrokinetics/pdf/white_paper.pdf
 U.S. Department of Energy (DOE), Energy Efficiency and Renewable Energy (EERE), Report to Congress on the Potential Environmental Effects of Marine and Hydrokinetic Energy Technologies. December 2009. http://www1.eere.energy.gov/windandhydro/pdfs/doe_eisa_633b.pdf
- Electric energy storage (EES) uses forms of energy such as chemical, kinetic, or potential energy to store energy that will later be converted to electricity. Such storage can provide three basic services: supplying peak electricity demand by using electricity stored during periods of lower demand, balancing electricity supply and demand fluctuations over a period of seconds and minutes, and deferring expansions of electrical grid capacity.
- Global EES capacity in 2010 was 127 gigawatts (GW), which is only 2.6 percent of electric power production capacity due to the high capital cost of EES compared to natural gas power plants, which can provide similar services, and regulatory barriers to entry in the electricity market. Of that global capacity, 22 GW of EES is in the United States (2.4 percent of U.S. power capacity).
- EES can potentially smooth the variability in power flow from renewable generation and store renewable energy so that its generation can be scheduled to provide specific amounts of power, which can decrease the cost of integrating renewable power with the electrical grid, increase market penetration of renewable energy, and lead to greenhouse gas (GHG) emissions reductions.
Electric energy storage (EES) technology has the potential to facilitate the large-scale deployment of variable renewable electricity generation, such as wind and solar power, which is an important option for reducing greenhouse gas (GHG) emissions from the electric power sector. Wind and solar power emit no carbon dioxide (CO2) during electricity generation but are also variable or intermittent electricity sources. Wind power only produces electricity when the wind is blowing, and solar power only when the sun is shining, thus the output of these sources varies with wind speeds and sunshine intensity. Since operators of the electrical grid must constantly match electricity supply and demand, this makes variable renewable resources more challenging to incorporate into the electrical grid than traditional baseload (e.g., coal and nuclear) and dispatchable (e.g., natural gas) generation technologies, which can be scheduled to produce power in specific amounts at specific times. Electrical grid operators have several options for managing the variability of electricity supply introduced by large amounts of renewable generation, one of which is EES.
EES promises other benefits unrelated to renewable energy, such as improved grid reliability and stability, deferral of new generation and transmission investments, and other grid benefits.
EES technologies vary by method of storage, the amount of energy they can store, and how quickly and for how long they can release stored energy. Some EES technologies are more appropriate for providing short bursts of electricity for power quality applications, such as smoothing the output of variable renewable technologies from hour to hour (and to a lesser extent within a time scale of seconds and minutes). Other EES technologies are useful for storing and releasing large amounts of electricity over longer time periods (this is referred to as peak-shaving, load-leveling, or energy arbitrage). These EES technologies could be used to store variable renewable electricity output during periods of low demand and release this stored power during periods of higher demand. For example, wind farms often generate more power at night when winds speeds are high but demand for electricity is low; EES could be used to shift this output to periods of high demand.
The major technology options for EES include the following:
- Pumped Hydro
Pumped hydro storage uses low-cost electricity generated during periods of low demand to pump water from a lower-level reservoir (e.g., a lake) to a higher-elevation reservoir. During periods of high electricity demand (and higher prices), the water is released to flow back down to the lower reservoir while turning turbines to generate electricity, similar to conventional hydropower plants. Pumped hydro storage is appropriate for load leveling because it can be constructed at large capacities of 100-1000s of megawatts (MW) and discharged over long periods of time (6 to 10 hours).
- Compressed Air
Compressed air energy storage (CAES) is a hybrid generation/storage technology in which electricity is used to inject air at high pressure into underground geologic formations. When demand for electricity is high, the high pressure air is released from underground and used to help power natural gas-fired turbines. The pressurized air allows the turbines to generate electricity using significantly less natural gas. CAES is also appropriate for load leveling because it can be constructed in capacities of a few hundred MW and can be discharged over long (8-20 hours) periods.
- Rechargeable Batteries
Several different types of large-scale rechargeable batteries can be used for EES including sodium sulfur (NaS), lithium ion, and flow batteries. Batteries could be used for both power quality and load-leveling applications. In addition, if plug-in hybrid electric vehicles (PHEVs) become widespread, their onboard batteries could be used for EES, by providing some of the supporting or “ancillary” services in the electricity market such as providing capacity, spinning reserve, or regulation services, or in some cases, by providing load-leveling or energy arbitrage services by recharging when demand is low to provide electricity during peak demand.
- Thermal Energy Storage
There are two very different types of thermal energy storage (TES): TES applicable to solar thermal power plants and end-use TES. TES for solar thermal power plants consists of a synthetic oil or molten salt that stores solar energy in the form of heat collected by solar thermal power plants to enable smooth power output during daytime cloudy periods and to extend power production for 1-10 hours past sunset. End-use TES stores electricity from off-peak periods through the use of hot or cold storage in underground aquifers, water or ice tanks, or other storage materials and uses this stored energy to reduce the electricity consumption of building heating or air conditioning systems during times of peak demand.
Hydrogen storage could be used for load-leveling or power quality applications. Hydrogen storage involves using electricity to split water into hydrogen and oxygen through a process called electrolysis. When electricity is needed the hydrogen can be used to generate electricity via a hydrogen-powered combustion engine or a fuel cell.
Flywheels can be used for power quality applications since they can charge and discharge quickly and frequently. In a flywheel, energy is stored by using electricity to accelerate a rotating disc. To retrieve stored energy from the flywheel, the process is reversed with the motor acting as a generator powered by the braking of the rotating disc.
Ultracapacitors are electrical devices that consist of two oppositely charged metal plates separated by an insulator. The ultracapacitor stores energy by increasing the electric charge accumulation on the metal plates and discharges energy when the electric charges are released by the metal plates. Ultracapacitors could be used to improve power quality because they can rapidly provide short bursts of energy (in under a second) and store energy for a few minutes.
- Superconducting Magnetic Energy Storage (SMES)
Superconducting magnetic energy storage (SMES) consists of a coil with many windings of superconducting wire that stores and releases energy with increases or decreases in the current flowing through the wire. Although the SMES device itself is highly efficient and has no moving parts, it must be refrigerated to maintain the superconducting properties of the wire materials, and thus incurs energy and maintenance costs. SMES are used to improve power quality because they provide short bursts of energy (in less than a second).
Environmental Benefit / Emission Reduction Potential
The use of EES can potentially enable very large penetration of variable renewable generation in the longer term by lowering the cost of connecting these resources with the transmission grid and of managing the increased variability of generation. For example, a modeling analysis conducted in 2008 by the National Renewable Energy Laboratory (NREL) examined the effect of EES on wind power. In a “business-as-usual” case, NREL’s model projected that building about 30 GW of EES could allow for the installation of an additional 50 GW of wind generation capacity by 2050 (a 17 percent increase compared to a scenario with no EES).NREL also modeled a scenario that required 20 percent of electricity to come from wind power by 2030. In this case, NREL found that investments in EES (in the form of CAES) became economic once wind penetration reached 15 percent of generation and that EES would lower the cost of electricity in the case of high wind penetration by 3 percent (about $3/MWh) in 2050.
EES enables GHG emission reductions by two main mechanisms:
- EES can be used instead of natural gas generators to smooth out the variable output of renewable resources such as wind or solar power over long periods, and allow these resources to be scheduled according to daily fluctuations of electricity demand. For example, the use of CAES to smooth wind power generation would result in a 56 percent reduction in CO2 emissions per kilowatt-hour of electricity, compared to smoothing variable wind power with generation from a gas turbine, and would enable a greater penetration of wind power. Another study estimated that over the span of 20 years, a 20 MW flywheel facility could reduce CO2 emissions from coal power plants by 67-89 percent, depending on the regional regulations and intended use of the coal power plant (whether it is for peak or base power generation). The flywheel plant would remove the need to have a coal power plant that could produce 20 MW of power to the grid, resulting in CO2 emissions reduction.
- EES charged with electricity from low-carbon sources can also be used to displace fossil fuel generation to provide regulation services by smoothing out the fluctuations between supply and demand over short periods of less than 15 minutes. This use of EES could reduce the amount of fossil fuels burned by generators, leading to GHG and conventional emission reductions.
However, EES can also increase GHG emissions if recharged with cheap electricity from high-carbon baseload coal power plants to displace more expensive peaking power from lower-carbon natural gas generators. The GHG emission reduction potential from EES depends on its use with renewable or low-carbon (i.e. nuclear or coal with carbon capture and storage (CCS)) resources.
The up-front capital costs of EES vary by technology and capacity. Total capital costs per unit of power capacity for most EES technologies are high compared to a $800-1100/kW natural gas power plant, varying from $500/kW for ultracapacitors, $1000-$1250/kW for underground CAES, $950-$1590/kW for batteries, $434-$3000/kW for hydrogen fuel cells, $758-$1,044/kW for hydrogen fueled gas turbine, $1500-$4300/kW for pumped hydro, and $1950-$2200/kW for flywheels. These costs are highly uncertain and complicated by the fact that the cheaper technologies, such as SMES, ultracapacitors, and some batteries, are only available with small (a few kilowatt to MW) power capacities. Integrating many small units of these cheaper storage technologies into a 100+ MW-scale utility application would lead to additional cost and complexity.
The cost premium for stored electricity, which depends on the lifetime of the EES technology and its useable energy storage capacity, are not well understood for most EES technologies. One study calculated a cost premium of $0.05-0.12/kWh for pumped hydro storage, $0.07-0.86/kWh for batteries, and $0.07-0.64/kWh for flywheels. EES technologies at the low cost ranges seem promising in a few applications when competing against average U.S. peak electricity prices of $0.18/kWh.
TES for solar thermal power plant and end-use applications are also commercially promising. A study by the Electric Power Research Institute (EPRI) of a 125 MW solar thermal power plant in New Mexico estimated that a parabolic troughdesign solar thermal power plant with TES has almost a 10 percent lower levelized cost of electricity compared to one without storage, and up to 30 percent cost savings with a central receiver design., EPRI has also found that the use of end-use TES systems can save between 2-7 percent of annual heating/cooling energy costs, if well-designed.
Current Status of Electric Energy Storage
The current use of EES technologies is limited compared to the rates of storage in other energy markets such as the natural gas or petroleum markets. EES capacity, most of which is pumped hydro, is only 2.3 percent of U.S. electric power capacity. However, demonstration projects of various EES technologies are underway in the U.S. and internationally.
- Pumped Hydro
The majority of EES in operation today consists of pumped hydro facilities. The U.S. has 40 pumped hydro facilities in operation that provide up to 22 GW of power. As of August 2011, The Federal Energy Regulatory Commission (FERC) has issued 25 preliminary permits since the start of 2010 for pumped hydro energy storage projects, totaling 16.7 GW of capacity.These preliminary permits allow feasibility studies but no permanent or large-scale installations. The potential use of this technology is limited by the availability of suitable geographic locations for pumped hydro facilities near demand centers or generation.
- Compressed Air Energy Storage (CAES)
Two CAES facilities are in operation today: a 290 MW facility in Huntorf, Germany, which is used to level variable power from wind turbines, and a 110 MW facility in McIntosh, Alabama, which is used to provide a variety of power quality functions. Several improved second-generation CAES systems are being designed that have potential for lower installed costs, higher efficiency, and faster construction time than first-generation systems. The American Recovery and Reinvestment Act (ARRA) is providing funds for two CAES demonstration projects in New York and California. Some studies forecast that CAES will provide the bulk of EES services by 2050 because of its lower capital and operating costs.
As of 2010, sodium sulfide (NaS) batteries have been used by utilities worldwide in 221 projects with a total capacity of 316 MW. EPRI estimates that with current efforts the installed capacity of NaS batteries will increase to 606 MW by 2012. Globally, there are 16 MW in commercial service with numerous demonstration projects in the kW range. Several flow batteries are being field-tested around the world, and a 4 MW commercial unit is already operating in Japan. ARRA has provided funding for several large-scale demonstration projects for flow, battery chemistries newer than NaS like lithium ion, and other battery technologies.
- Thermal Energy Storage (TES)
There are several operational commercial solar thermal power plants with integrated TES as of August 2011. They include:
o AndaSol One in Andalusia, Spain;
o Solar Tower in Seville, Spain;
o La Florida Solar Power Plant in Alvarado, Spain;
o Extresol-1 and Extresol-2 in Torre de Miguel Sesmero, Spain;
o La Dehesa in La Garrovilla, Spain;
o Manchasol in Alcazar de San Juan, Spain;
o Archimedes Solar Power Plant in Priolo Gargallo, Italy;
o Holaniku in Keahole Point, Hawaii, U.S.A;
o Nevada Solar One in Boulder City, Nevada, U.S.A;
The majority of the concentrated solar power (CSP) plants use molten salt as the energy storage medium. The planned Hualapai Valley Solar Project in Arizona is a 340 MW thermal solar power plant using molten salt for energy storage and will be completed in 2014. Demonstrations of end-use TES technologies have occurred in the United States, United Kingdom, Germany, and Scandinavia. For example, about 8 percent of residential water heaters in the United Kingdom use a specific TES material that is heated at night in order to heat water throughout the day and reduce peak electricity consumption.
There are some demonstrations of EES using hydrogen and fuel cells for utility applications. However, hydrogen storage requires significant cost reductions prior to large-scale deployment since electrolysis is about 62-87 percent efficient while fuel cells are about 47-58 percent efficient, resulting in lower efficiency to provide electricity to the grid compared to the 60-94 percent efficiencies of other EES technologies. A combustion turbine using hydrogen as fuel instead of natural gas results in 42-70 percent efficiency.
Several installations of flywheels to provide power quality services have taken place across the United States. Flywheel modules can be connected together to increase the storage capacity. In July 2011, a 20 MW flywheel energy storage facility, built using two hundred 100 kW flywheels, in Stephentown, New York became operational. Flywheels have a high cycle life of 100,000 to 2,000,000 cycles, long operating life of about 20 years, rapid response time of 4 milliseconds or less, and fast charging and discharging times of a few seconds to 15 minutes. More research needs to be conducted to improve the energy densities of this storage technology.
ARRA is currently funding a grid-scale ultracapacitor demonstration project with a 3 MW capacity. The Advanced Research Projects Agency-Energy (APRA-E) is funding research and development of ultracapacitors with greater energy density.
- Superconducting Magnetic Energy Storage (SMES)
Several MW-capacity SMES demonstration projects are in operation around the United States and the world to provide power quality services, especially at manufacturing plants requiring ultra-reliable electricity such as microchip fabrication facilities. SMES requires further research to lower capital costs and improve energy densities.
Obstacles to Further Development or Deployment to Electric Energy Storage
- High Capital Costs
The capital costs of current EES technologies are high compared to natural gas generators that provide similar services.
- Need for Large-Scale Demonstration Projects
EES technologies such as CAES require a few large-scale demonstration projects before utility managers will have the confidence to invest in these technologies. ARRA is supporting two utilities in New York and California with funding to build large-scale CAES plants that will demonstrate technological maturity and economic feasibility, but other technologies such as SMES will also require large-scale demonstrations before wider adoption can take place.
- Transmission Planning Processes
Transmission planning only takes into account the location of demand centers and generation facilities. As a result, geographically remote EES facilities such as pumped hydro or CAES have limited access to the transmission grid.
- Regulatory Barriers
Federal and state regulations treat EES as a type of electricity generation technology rather than as an investment in transmission capacity. Thus transmission and distribution companies are barred from owning EES. In addition, most renewable portfolio standards or government investment or production incentives are written for renewable generation only and exclude EES, despite the fact that EES can enable higher penetration of renewable energy., 
- Conservative Industry Culture With Respect to Technology Risks
Regulated utilities are risk averse and reluctant to invest in new technologies, such as EES, due to the capital-intensive nature of electric generation and the lack of competition in the market. Deregulation of the electricity industry in parts of the U.S. created a competitive market for generation, but generator owners are unsure whether they will be able to recover their capital costs and are also reluctant to invest in new technologies. In general, the energy industry invests a tiny fraction of profits in research and development compared to other industries, which limits the pace of improvements in technologies such as EES.
- Incomplete Electricity Markets
Most regions of the United States have not yet fully developed markets and transparent prices for all the types of ancillary services that EES (and generation) technologies provide besides providing electricity, such as regulation, spinning reserve, load-following, and other services.
Policy Options to Help Promote Electric Energy Storage
- Carbon Price
A price on carbon, such as that which would exist under a greenhouse gas cap-and-trade program (see Climate Change 101: Cap and Trade), would raise the cost of electricity produced from fossil fuels relative to the cost of electricity from variable renewable sources, such as wind and solar power, and from low carbon sources, such as nuclear and coal power with CCS. This would, in turn, increase the value of the services provided by EES in situations where EES could store relatively inexpensive low-carbon electricity to displace carbon-intensive power.
- Real-Time Electricity Pricing
The cost of producing and delivering electricity to consumers varies throughout the day, since cheaper baseload coal or nuclear power plants generate more of the electricity at night when demand is low, and more expensive peaking power plants must be activated during the day when demand is high. However, most residential consumers are charged a flat price for electricity, and commercial and industrial consumers face demand charges for high power consumption and higher peak electricity rates that are not set according to the daily hour-by-hour variations of electricity production costs. If consumers were charged a real-time price for electricity, the high cost of peak electricity would be transparent and investments in EES to reduce peak load would have greater value. A national smart grid would facilitate real-time electricity pricing. (See Climate Techbook: Smart Grid.)
- Markets for Ancillary Electric Services
EES technologies would benefit from receiving prices set by competitive markets for ancillary electric services such as regulation, spinning reserve, and load-following, which would increase the overall value of EES.
- Relaxation of Ownership Restrictions
EES can serve both generation and transmission functions, but existing deregulated electricity markets place limits on who can own such facilities. Removing restrictions on the ownership of EES facilities by end-use customers, transmission owners, or distribution companies could enable greater market penetration of EES.
- Integration of EES in Transmission Planning
Decisions regarding new transmission lines could factor in the location of large-scale EES sites, as well as demand centers and generation facilities. Investments in EES are often less costly than building new transmission lines. The Federal Energy Regulatory Commission could modify rules so that EES is subject to transmission pricing incentives and a part of the transmission planning process.
- Matching Grants for Large-Scale EES Demonstration Projects
Matching grants can lower the cost of large-scale technology demonstration projects and accelerate commercialization. For instance, the ARRA is providing $185 million in federal matching funds to support energy storage project with a total value of $772 million. The projects would add 537.3 MW of energy storage capacity to the grid.
- Basic and Applied Research and Development
Low charge/discharge efficiencies, low cycle lives, and high capital costs make most EES technologies less economically competitive for smoothing out renewable energy or providing power quality services compared to power plants that provide similar services. Federal or state investments and incentives for private investment in basic and applied research and development would help to improve the performance of existing technologies and support the discovery of fundamental breakthroughs for the next generation of EES technologies. Department of Energy’s ARPA-E program is supporting advanced research in energy storage technologies with $55 million in funds for fiscal year (FY) 2011 and FY 2012.
Related Business Environmental Leadership Council (BELC) Company Activities
Related C2ES Resources
Komor, Paul. 2009. Wind and Solar Electricity: Challenges and Opportunities.
Morgan, Granger, Jay Apt, and Lester Lave. 2005. The U.S. Electric Power Sector and Climate Change Mitigation.
American Physical Society (APS). 2007. Challenges of Electricity Storage Technologies. See http://www.aps.org/policy/reports/popa-reports/upload/Energy-2007-Report-ElectricityStorageReport.pdf.
California Independent System Operator (CAISO). 2007. Integration of Renewable Resources: Transmission and Operating Issues and Recommendations for Integrating Renewable Resources on the California ISO-Controlled Grid. See Chapter 7, “Storage Technology,” available at http://www.uwig.org/CAISOIntRenewablesNov2007.pdf.
Electricity Advisory Committee. “Energy Storage Activities in the United States Electricity Grid.” May 2011. See http://www.doe.gov/sites/prod/files/oeprod/DocumentsandMedia/FINAL_DOE_Report-Storage_Activities_5-1-11.pdf
Denholm, Paul. 2008. The Role of Energy Storage in the Modern Low-Carbon Grid. National Renewable Energy Laboratory. See http://tinyurl.com/d4t4pu.
International Energy Agency (IEA). 2008. Empowering Variable Renewables: Options for Flexible Electricity Systems. See http://www.iea.org/g8/2008/Empowering_Variable_Renewables.pdf.
Lee, Bernard and David Gushee. 2008. Massive Electricity Storage. American Institute of Chemical Engineers. See http://tinyurl.com/3z94h2.
National Renewable Energy Laboratory (NREL). “Energy Storage Basics.” See http://www.nrel.gov/learning/eds_energy_storage.html.
Peters, Roger and Lynda O’Malley. 2008. Storing Renewable Power. Pembina Institute. See http://pubs.pembina.org/reports/StoringRenewablePower-jun17.pdf.
Rastler, Dan. "Electricity Energy Storage Technology Options." Electric Power Research Institute. 1020676. 2010. See http://www.electricitystorage.org/images/uploads/static_content/technology/resources/ESA_TR_5_11_EPRIStorageReport_Rastler.pdf
Yan, Chi-Jen and Eric Williams (Nicholas Institute). 2009. Energy Storage for Low-carbon Electricity. Duke University Climate Change Policy Partnership. See http://www.nicholas.duke.edu/ccpp/ccpp_pdfs/energy.storage.pdf.
 “Energy Storage Activities in the United States Electricity Grid”. Electricity Advisory Committee. May 2011.
 Other approaches for managing the variability of renewable generation include increasing the interconnectedness of electric grids, developing more flexible generation technologies capable of increasing or decreasing output at faster rates (called ramping rates), demand response programs which create flexibility in demand, and market mechanisms, such as different pricing structures for variable renewable resources. For more information, see the resources under Further Reading, especially the Center’s report on wind and solar power and the reports from IEA and CalISO.
 Jewell, Ward et al. 2004. Evaluation of Distributed Electric Energy Storage and Generation. Power Systems Engineering Research Center. See http://www.pserc.wisc.edu/documents/publications/reports/2004_reports/je... .
Power quality is defined as the provision of power with specified voltage and frequency characteristics to the customer. Small imbalances in the sub-minute time frame between electricity supply and demand, and the physical properties of electricity generators, electricity-consuming devices, and the transmission grid lead to small deviations (1 to 5 percent) between the expected and actual voltage and frequency of power delivered, which can cause highly sensitive equipment such as computers to fail. When electricity supply and demand are in balance, these deviations in voltage and frequency are eliminated.
 Load leveling or peak shaving refers to the use of electricity stored during times of low demand to supply peak electricity demand, which reduces the need for electricity generation from peaking power plants. The use of EES for load leveling is also known as “energy arbitrage” since it may be possible to earn a profit by charging EES with cheap electricity when demand is low and selling discharged electricity at a higher price when demand is high. Load leveling can also be achieved through demand-side measures such as using higher peak prices to induce a reduction in peak demand through demand charges, real-time pricing, or other market measures.
 Rastler, 2010
 Unlike traditional batteries, flow batteries use fuel that is external to the battery that flow in and out to generate electricity through an electro-chemical process.
 Generators (and potentially EES) provide energy and ancillary services to electricity markets. Energy services are defined as providing electric generation to meet demand, usually scheduled on a day-ahead basis. The term, “ancillary services” includes a variety of services related to power quality. For example, in some electricity markets, generators (and potentially EES) are paid for the capacity of power they can produce, whether or not they are actually generating, in order to ensure that the market has sufficient capacity to meet peak demand.
 Spinning reserve is an ancillary service in the electricity market defined as the ability of (usually a generator) to remain on and ready to start generating given notice over a short period of time (15 minutes to an hour).
 Regulation refers to an ancillary electric service (usually provided by electric generators) to maintain power quality by following unpredicted minute-by-minute fluctuations in electric demand.
“SolarReserve Gets Green Light On Nevada Solar Thermal Project” July 28, 2010.
 End-use thermal energy storage could also be considered a type of demand response as it reduces the electricity use of heating or air conditioning systems during times of peak demand. By pre-cooling or heating the building during off-peak times and using a few hours of hot or cold storage in the form of aquifers, water/ice tanks, or heat storage materials, the heating, air-conditioning, and refrigeration loads of the building can be shifted to off-peak hours. For more information, see International Energy Agency. Energy Conservation through Energy Storage website. http://www.iea-eces.org/
 Schoenung, S. M. Hydrogen Energy Storage Comparison. Department of Energy. See http://www.osti.gov/bridge/servlets/purl/763084-JtAYM6/webviewable/76308...
 American Physical Society (APS). 2007. Challenges of Electricity Storage Technologies. See http://www.aps.org/policy/reports/popa-reports/upload/Energy-2007-Report-ElectricityStorageReport.pdf.
 Sullivan,P., Short, W., and Blair, N. 2008. “Modeling the Benefits of Storage Technologies to Wind Power.” American Wind Energy Association (AWEA) WindPower 2008 Conference. Conference Paper NREL/CP-670-43510.
 Greenblatt, J. B., Succar, A., Denkenberger, D. C., Williams, R. H., and Socolow, R. H. 2007. “Baseload wind energy: modeling the competition between gas turbines and compressed air energy storage for supplemental generation.” Energy Policy. 35: 1474–1492.
 Emissions Comparison for a 20 MW Flywheel-based Frequency Regulation Power Plant. Beacon Power Corporation. January 8, 2007.
 California Public Utility Commission.Greenhouse Gas Modeling. “New Combined Cycle Gas Turbine (CCGT) Generation Resource, Cost, and Performance Assumptions.” www.ethree.com/GHG/21%20Gas%20CCGT%20 Assumptions%20v4.doc. Development and construction capital costs from 2002 escalated by 3% per year to 2009 from Northwest Council. “Natural Gas Simple-Cycle Gas Turbine Power Plants.” http://www.nwcouncil.org/energy /powerplan/grac/052202/gassimple.htm.
 Rastler, 2010.
 Steward, Darlene M. “Analysis of Hydrogen and Competing Technologies for Utility-Scale Energy Storage” National Renewable Energy Labatory. February 2010.
 Rastler, 2010..
 The cost premium is the difference between the cost of electricity discharged from an EES facility and the cost of the electricity used to charge the EES facility.
 Poonpun, P., and Jewell, W. T. 2008. “Analysis of the Cost per Kilowatt Hour to Store Electricity.” IEEE Transactions on Energy Conversion. Vol 23. No 2. June.
 Levelized cost of electricity (LCOE) is defined as the ratio of the sum of the plant operation and maintenance costs and amortized capital costs to the annual plant generation.
 Electric Power Research Institute. “Program on Technology Innovation: Evaluation of Concentrating Solar Thermal Energy Storage Systems.” 1018464. 2009.
 While TES increases the capital costs of a solar thermal power plant, it also increases the total electricity output from the power plant by using a larger solar collector to heat the molten salt-based TES material and allowing the plant to operate during sundown. The increase in power output is greater than the increase in capital costs for the TES material and additional solar collector area.
 Electric Power Research Institute. “Thermal Energy Storage Systems Operation and Control Strategies Under Real-Time Pricing.” Palo Alto, CA: 2004. 1007401.
 Electric Advisory Committee, 2011.
 Rastler, 2010.
 Rastler, 2010.
 Ibid, page 4-4.
 EAC 2011
 Sullivan, et. al., 2008.
 Rastler, 2010, page 4-10
 Ibid, page 4-18.
 Ibid, page 4-13.
 EAC 2011.
 Andasol Solar Power Station, Spain. Power-technology.com. Accessed August 9, 2011. See http://www.power-technology.com/projects/andasolsolarpower/
 Solar Tower, Seville, Spain. Power-technology.com. Accessed August 9, 2011. See http://www.power-technology.com/projects/Seville-Solar-Tower/
 La Florida Solar Power Plant, Spain. Power-technology.com. Accessed August 9, 2011. See http://www.power-technology.com/projects/lafloridasolarpowerp/
 Concentrating Solar Power Projects: Holaniku at Keahole Point. National Renewable Energy Laboratory. December 3, 2010. Accessed August 12, 2011.
 Concentrating Solar Power Projects: Nevada Solar One. National Renewable Energy Laboratory. June 1, 2007. Accessed August 12, 2011.
 Hualapai Valley Solar Project, Arizona, USA. Power-technology.com See http://www.power-technology.com/projects/hualapaivelleysolarp/
 Baker, J. 2008. “New Technology and Possible Advances in Energy Storage.” Energy Policy. Vol. 36, p 4368–4373.
 Steward, D., Saur, G., Penev, M., Ramsden, T. “Lifecycle Cost Analysis of Hydrogen Versus Other Technologies for Electrical Energy Storage.” National Renewable Energy Laboratory. NREL/TP-560-46719. 2009.
 Rastler, 2010. Pages xxiii-xxiv
 Beacon Power Inaugurates 20 MW Flywheel Plant in New York. July 21, 2011.
 Cycle life is defined as the number of times an EES technology can be charged and discharged up to its maximum charging capacity during its lifetime.
 Walawalkar, Rahul, and Jay Apt. 2008. Market Analysis of Emerging Electric Energy Storage Systems. National Energy Technology Laboratory. See http://www.netl.doe.gov/energy-analyses/pubs/Final%20Report-Market%20Analysis%20of%20Emerging%20Electric%20Energy%20Sto.pdf.
 Rastler, 2010.
 Energy density is defined as the ratio of the energy storage capacity in kWh to the physical footprint required for the technology, often in expressed in units of square meters. Energy density is most important for vehicular applications.
 EAC 2011.
 APS, 2007.
 Yan, Chi-Jen and Eric Williams (Nicholas Institute). 2009. Energy Storage for Low-carbon Electricity. Duke University Climate Change Policy Partnership. See http://www.nicholas.duke.edu/ccpp/ccpp_pdfs/energy.storage.pdf.
 The Energy Independence and Security Act of 2007 (EISA 2007) is an exception, as it provides $50 million in basic research funding, $80 million in applied research funding for automotive and utility energy storage, and defines “deployment and integration of advanced electricity storage and peak-shaving technologies, including plug-in electric and hybrid electric vehicles, and thermal-storage air conditioning” as a “Smart Grid” characteristic” and eligible for matching grants and other incentives for Smart Grid technologies found in the law. Source: Peters, Roger and Lynda O’Malley. 2008. Storing Renewable Power. Pembina Institute. See http://pubs.pembina.org/reports/StoringRenewablePower-jun17.pdf.
 Margolis, R. M., and Kammen, D. M. 1999. “Underinvestment: The Energy Technology and R&D Policy Challenge.” Science. Vol. 285. no. 5428, pp. 690 – 692.
 Load-following is an ancillary service is the electricity market defined as the ability of (usually a generator) to increase or decrease electricity output over a short period of time (15 minutes to an hour) according to the predicted change in electric demand throughout a day.
 Nicholas Institute, 2009.
 EAC 2011.
- The smart grid refers to the application of digital technology to the electric power sector to improve reliability, reduce cost, increase efficiency, and enable new components and applications.
- Compared to the existing electrical grid, the smart grid promises improvements in reliability, power quality, efficiency, information flow, and improved support for renewable and other technologies.
- Smart grid technologies, including communication networks, advanced sensors, and monitoring devices, form the foundation of new ways for utilities to generate and deliver power and for consumers to understand and control their electricity consumption.
- Some of the largest utilities in the country, including Florida Power and Light, Xcel Energy, Pacific Gas and Electric, and American Electric Power, have undertaken initiatives to deploy smart grid technologies.
- Smart grid technologies could contribute to greenhouse gas emission reductions by increasing efficiency and conservation, facilitating renewable energy integration, and enabling plug-in electric vehicles.
The Smart Grid and Its Potential Benefits
The smart grid is a concept referring to the application of digital technology to the electric power sector. It is not one specific technology. Rather, the smart grid consists of a suite of technologies expected to improve the performance, reliability, and controllability of the electrical grid. Many of these technologies have been employed in other sectors of the economy, such as the telecommunications and manufacturing sectors.
Smart grid technologies offer several potential economic and environmental benefits:
- Improved reliability
- Higher asset utilization
- Better integration of plug-in electric vehicles (PEVs) and renewable energy
- Reduced operating costs for utilities
- Reduced expenditures on electricity by households and businesses
- Increased efficiency and conservation
- Support for new components and applications
- Lower greenhouse gas (GHG) and other emissions
Digital technologies have been integral to the modernization of many sectors of the economy and have resulted in efficiency gains, new opportunities, and greater productivity. The electric power sector, however, has lagged behind. Many utilities still use the same designs as they did when most of the grid was built in the 1960s and 1970s.
Issues with the Existing Grid
The U.S. electrical grid is an enormous and extremely complex system consisting of centralized power plants, transmission lines, and distribution networks. It is capable of carrying over 850 gigawatts (GW) of power and continuously balancing supply with fluctuating demand. It does so with remarkable reliability, providing 99.97 percent uptime (when the grid is operational), or about 160 minutes of downtime a year.,
However, the traditional electric power grid was designed neither with the latest technology nor with the goal of supporting a high-tech economy and enabling low-carbon technologies, energy efficiency, and conservation. Some of the grid issues described below are addressed by smart grid technologies but do not relate directly to GHG emission reductions.
The power still goes out for customers at an average of 2.5 hours per year, which leads to sizeable economic losses. Power quality disruptions for ordinary consumers may be no more than lights flickering or dimming, but for high-tech manufacturing and critical infrastructure that rely on high quality power (such as communications networks and pipelines), these events can disrupt operations and collectively can cost millions.
- The grid is inefficient at managing peak load.
Peak load is the short period when electricity demand is at its highest within a day, season, or year. Electricity demand is cyclical and variable, and the cost of meeting that demand varies, but because utilities have limited tools for managing demand, supply must be adjusted continuously to track demand. In addition, the power grid must constantly maintain a buffer of excess supply, which is primarily fossil fuel based, resulting in lower efficiency, higher emissions, and higher costs.
- The grid does not support robust information flow.
For example, utilities often do not find out about blackouts until consumers call to notify them. Moreover, consumers have very little knowledge about how their electricity is priced or how much energy they are using at any given time. This limits the incentives for efficiency, conservation, and demand response.
The electricity generation from certain important renewable technologies fluctuates based on the availability of variable resources (e.g., the wind and sunlight). The ability of the existing grid to support high levels of variable renewable generation is uncertain. Efforts are currently underway to better understand the impact of high levels of renewable energy in the electricity grid, and will become more important as renewable energy increases. For instance, California aims to incorporate 33 percent renewable energy by 2020.
Because the grid was designed for a one-way power flow from centralized power stations to end users, it has to be upgraded to allow a two-way power flow that supports small distributed generators. Adding variable generators such as rooftop solar or micro wind (small wind turbines able to be mounted on a residential rooftop) makes managing distributed generation even more difficult for the existing grid.
- The grid would be strained by high PEV deployments.
A significant deployment of PEVs over the next few decades would represent a major strain on the electric power system. Due to the nature of the charging cycles of PEVs, it will be both expensive and technically difficult to manage the fleet’s demands through the existing grid.
Characteristics of smart grid technologies enable many functions beyond what the existing grid does. A smart grid:
- Gives the utility actionable information
Instead of estimating network activity or having to send out physical readers to many locations, utilities receive a constant flow of information about their network, their customers, and their options for managing their operations.
- Gives the consumer actionable information
Customers can be provided with information about their electricity usage patterns and costs. They can use this information to reduce their energy costs and their environmental impact.
- Automates and decentralizes decisions
Instead of forcing centralized system operators and planners to make decisions, a smart grid automates easy decisions and empowers consumers to take informed actions.
- Supports and enhances new technologies
A smart grid provides support for new applications and components, such as smart appliances, PEVs, distributed generation, and renewable energy by allowing for better management of their interaction with the grid.
The technologies that comprise a smart grid address the existing grid’s shortcomings by providing actionable intelligence and enhanced management capabilities that can improve operational efficiency and performance. These technologies are available now, and some of the largest utilities in the country, including Xcel Energy, Pacific Gas and Electric (PG&E), and American Electric Power (AEP), have begun large-scale deployment of these technologies to their customers.
According to the Smart Grid Information Clearinghouse (SGIC) the smart grid consists of five key technology areas:
- Integrated Communications
High-speed, standardized, two-way communication allows for real-time information flows and decision-making among all grid components. Several existing technologies, including wide-area wireless internet and cellular networks, could provide the communications infrastructure needed.
- Sensing and Measurement
Sensing and measurement allow utilities and consumers to understand and react to the state of the electrical grid in real-time. For example, households could monitor their energy demand and the current price of electricity through smart meters, which communicate with home networks that link smart appliances and display devices.
- Advanced Components
Advanced components such as GPS systems, current-limiting conductors, advanced energy storage, and power electronics will improve generation, transmission, and distribution capacity and operational intelligence for utilities.
- Advanced Control Methods
As more information is available to grid controllers and faster response times are required, the task of managing an electrical grid is becoming more complex. Advanced control systems find and process important information quickly, streamlining operations and providing clarity to human operators.
- Improved Interfaces and Decision Support
New tools, such as software to visualize networks at any scale (from an individual neighborhood to the entire national grid), provide system operators with greater situational awareness and diagnostics and allow planners, operators, and policymakers to make informed decisions.
The smart grid technologies that form the foundation of a new grid enable new smart grid applications, including:
AMR allows utilities to read electricity, water, and gas meters electronically; as opposed to sending a meter-reader to each house every month. AMI goes the next step, adding 2-way communications that allow the utility to act on information coming back from meters, adjusting prices and responding to outages or power quality events in real-time.
- Real-Time Pricing (RTP)
RTP charges electricity prices dynamically to reflect the realities of the electricity market. Successful RTP depends on a price-elastic demand for electricity, allowing markets to determine prices quickly and keeping prices in a reasonable range for consumers. A smart grid lets consumers prioritize and monitor their electricity use, resulting in cost savings and a more economically efficient electricity market.
DR allows utilities to reduce demand during periods of peak load and thus avoid dispatching high-cost generating units which are often among the least efficient and dirtiest. DR can distinguish between valuable and low-priority electricity uses – for example, dimming lights and adjusting air conditioners without disrupting vital services.
- Smart Charging / Vehicle-to-Grid (V2G)
PEVs will greatly increase the load on the grid. A single PEV can draw more power than a typical household. Smart Charging devices allow PEVs to communicate with the utility, timing the charging to coincide with low prices, low grid impact, and potentially low emissions periods (e.g., when renewable energy sources are available). V2G takes this concept one step further by allowing PEVs to feed their power back into the grid to help stabilize voltage and frequency, reducing the need for spinning reserves and regulation services and thus avoiding emissions from electricity generating units that would otherwise need to provide these services.
- Distribution Automation
Distribution automation allows distribution systems to reconfigure themselves when a fault occurs, restricting the problem to a smaller area. This reduces the amount of time that backup generators (usually diesel-based) operate and cuts total outage time.
- Distributed Generation Integration
By providing greater fault tolerance and islanding detection, a smart grid allows for safer and more reliable connections of distributed generation units such as rooftop solar installations, small natural gas turbines used for heat and electricity in commercial buildings, and building integrated wind systems.
Environmental Benefits/Emissions Reduction Potential
Smart grid technologies reduce GHG emissions in a number of ways. This Climate Techbook entry focuses on three:
- Increasing efficiency and conservation
- Enabling renewable energy integration
- Enabling PEV integration
The Electric Power Research Institute (EPRI) calculates that a national smart grid could reduce annual GHG emissions by 60-211 million metric tons of carbon dioxide equivalent (MMT CO2e) compared to “business-as-usual” by 2030, an amount equal to 2.7-9.6 percent of GHG emissions from electricity generation in 2009.,
- Increasing Efficiency and Conservation
More than half of this potential reduction in GHG emissions would be achieved through energy efficiency and conservation measures enabled by the smart grid, such as:
o Reducing transmission losses through better management of distribution systems.
o By having a better understanding of equipment conditions through real-time equipment monitoring, utilities can keep vital components operating at high efficiency.
o Managing peak-load through demand response instead of spinning reserves.
o Increasing transparency in electricity prices, helping customers understand the true cost of electricity. The simple act of giving consumers continuous direct feedback on electricity use could reduce annual CO2 emissions by 31-114 MMT CO2e/year in 2030 as consumers adjust their usage in response to pricing and consumption information.
- Enabling Renewable Energy Integration
EPRI estimated that the increased renewable generation enabled by a smart grid could reduce GHG emissions by 19-37 MMT CO2e /year in 2030. There are two separate components to better renewable integration:
Support for distributed generation
o Control technologies enable safer and more reliable integration of distributed renewable generation (e.g., rooftop solar)
o More accurate accounting for distributed generation with advanced meters makes net metering more attractive
Network-wide resilience to variable renewable supply
o Demand response resources buffer variability in supply
o PEV integration offers distributed energy storage and ancillary services
o Better pricing mechanisms and demand side management can reduce transmission congestion, allowing more utility-scale renewable projects to connect to the grid
- Enabling Plug-in Electric Vehicles
A large source of GHG emissions in the United States is the auto fleet. PEVs can have lower emissions than traditional automobiles with gasoline internal combustion engines. EPRI estimated that the incremental adoption of plug-in hybrid electric vehicles (PHEVs) enabled by a smart grid could result in GHG emission reductions of 10-60 MMT CO2e/year by 2030. A smart grid is needed to integrate PHEVs, and PEVs more generally, without putting intense strain on grid resources.
With real-time pricing and system-wide price signals, PEV charging can be done primarily during off-peak periods, avoiding reliance on costlier and often more polluting “peaker” plants.
PEVs can be used to provide regulation services for the grid instead of relying on fossil fuel generation such as diesel or natural gas generators.
The business case for a smart grid can be separated into costs and benefits for three major stakeholders: utilities, consumers, and society. Unlike some technologies whose primary benefit is direct avoidance of GHG emissions, the smart grid provides a wide array of benefits beyond helping combat climate change, and also indirectly reduces GHG emissions to a large degree by enabling other low-carbon technologies. Moreover, the benefit-cost rationale for smart grid investments is not dominated by GHG emission reductions.
Smart grid projects represent large capital expenditures for utilities. For example, an AMI deployment is estimated to have a cost about $70 to $140/meter for residential users and $7 to $15/meter installation cost. As metering components and communications systems become more standardized costs may come down. EPRI estimates that a national smart grid could cost $338 to $476 billion over 20 years, but resulting in $1,294 to $2,028 billion in benefits over the same period. As of May 2011, California’s Pacific Gas and Electric (PG&E) company installed 7.9 million meters at a cost of $2.095 billion. PG&E reports that it has already accumulated $111.3 million in benefits since the start of the transition to smart meters that began in 2007.
Consumers undoubtedly bear much of the cost of smart grid projects through rate increases. At the same time, consumers who are active in managing their electricity consumption will benefit in the long-run from decreased peak electricity consumption and a lower total cost of energy. A Department of Energy (DOE) smart grid demonstration project in Olympic Peninsula, Washington found that consumers save 10 percent on their utility bills. Consumers also stand to benefit from improved power quality and fewer outages. For example, estimated incremental monthly costs for consumers of providing advanced meters for every household and business vary from $9 to $12 per residential and $60 to $84 per commercial customer, but consumers can benefit from monthly rate savings from greater control over electricity usage. A benefit to utilities can in turn benefit consumers through rate reductions or reduced rate increases.
Society stands to benefit from the environmental benefits, increase in reliability, and other benefits of a smart grid. For example, EPRI estimates that $102 to $390 billion benefits to the environment in terms of lower carbon dioxide emissions from greater electricity system efficiency, and $281 to $444 billion in benefits to society from improved grid reliability.
According to National Energy Technology Laboratory (NETL), most of the needed smart grid technologies are commercially available now or are actively being developed. This availability of technology is reflected by the hundreds of AMI projects currently underway across the country. At least 10 different coalitions exist to promote smart grid technologies, conduct R&D, and organize standards and interoperability. The market penetration for advanced meters has also increased, jumping from 1 percent of households and businesses in 2005 to 8.7 percent in 2009. Certain states, such as Arizona, Oregon and Idaho, have reached about 25 percent smart meter penetration. Examples of recent projects include:
- Southern California Edison, through its SmartConnect program, is planning to install advanced meters for all its household and small business customers (approximately 5.3 million meters) by 2012 and initiate dynamic pricing and demand reduction practices; the efforts are expected to avoid as much as 1 GW of capacity additions and to lower electricity bills for consumers, while reducing GHGs per year by 365,000 metric tons. As of July 2011, it has installed more than 2.7 million smart meters.
- Florida Power and Light has partnered with General Electric (GE), Cisco Systems, and Silver Spring Networks in a $200 million overhaul of 1 million homes and businesses with open-standards, internet-based smart grid system. The system is expected to save customers 10-20 percent on their power bills, with half the cost of the smart grid investments paid by the utility and half by the American Recovery and Reinvestment Act of 2009 (ARRA).,
- PG&E has installed more than 7.9 million meters and reported $111.3 million in benefits since the first smart meter became active in 2007.
Obstacles to Further Development or Deployment
Several obstacles prevent the implementation of a nationwide smart grid:
- Upfront Consumer Expenses
In the responses of 200 utility managers to a 2009 survey, 42 percent cited “upfront consumer expenses” as a major obstacle to the smart grid.These concerns were confirmed by consumer responses in which 95 percent of respondents indicated they are interested in receiving detailed information on their energy use; however, only 1 in 5 were willing to pay an upfront fee to receive that information. Regulatory approval for rate increases needed to pay for smart grid investments is always difficult, and the receptiveness of regulators varies from state to state.
- Lack of Standardization
30 percent of utility managers cited “lack of technology standards” as a major obstacle to smart grid deployment. Uncertainty about interoperability and technology standards present the greatest risk to utilities, who do not want to purchase components that will not work with new innovations down the road.
Many of the obstacles to a smart grid are regulatory issues. Electric power is traditionally the regulatory domain of states. The patchwork of regulatory structures and jurisdictions is only loosely coordinated, and final authority on many decisions can be unclear, as projects are subject to multiple levels of review. Local (municipal, county), state-level, and federal jurisdictions overlap, and conflicting decisions can result in regulatory lead times of several years. Some regulatory decisions can also be challenged in court, resulting in more potential delays at each level. This series of delays adds significantly to the cost and regulatory risk of pursuing a smart grid project.
- Lack of Widespread Understanding
Because smart grid is still a new concept and the technologies that enable it are rapidly evolving, there is misunderstanding amongst consumers, regulators, policymakers, and businesses about what its costs and benefits are. Stakeholders that are generally aligned may reach different conclusions based on a different understanding of the smart grid. As an example of the mistrust of new smart meter technologies, some customers have complained about rate increases after receiving a smart meter, which resulted in a lawsuit against California’s PG&E. The suit has damaged consumer confidence with new technology and prompted California’s PG&E to slow smart meter deployment. Ultimately, the suit was dismissed based on California Public Utilities Commission’s findings that the smart meters are accurate and functioning properly.
Policy Options to Help Promote a Smart Grid
- Develop National Standards
The 2007 Energy Security Act tasked the National Institute of Standards and Technology (NIST) with developing nationwide standards for smart grid technology in consultation with industry groups, such as the GridWise Alliance, and other standards bodies, such as the Institute of Electrical and Electronics Engineers (IEEE). Because technology risk from changing standards represents the largest risk to utilities, developing and institutionalizing national standards that are available to all players will greatly accelerate development. Standards would cover such technical areas as communication among smart grid devices and security.
- Provide Federal Funding for Smart Grid
The Energy Independence and Security Act of 2007 (EISA) and the economic stimulus bills of 2008 and 2009 all authorized federal funding for smart grid projects and R&D. The American Recovery and Reinvestment Act of 2009 (ARRA) directs $4.5 billion to modernize the electrical grid. Over 150 smart grid projects have been funded through ARRA as of July 2011. The projects include replacing traditional meters with smart meters, adding monitoring and controlling software to existing electric power infrastructure to enable smart grid features and to conduct consumer behavior surveys to see how consumers react to time-based electricity pricing. In addition, the federal government could provide a direct incentive to utilities in the form of tax credits to accelerate smart grid deployment.
- Require Greater Reliability
The current grid is 99.97 percent reliable on average, however this varies amongst utilities. Increasing the requirement for grid reliability or establishing performance-based rates that would allow utilities to charge a higher rate for better reliability, would incentivize utilities to invest in new technologies.
Many utilities engaged in smart grid projects find that they are spending significant portions of their project costs on communications and IT infrastructure rather than physical smart grid components. Creating a nationwide broadband infrastructure and allowing the smart grid to leverage it could have benefits for both the communications and electric power sectors.
- Provide for Utility Cost Recovery
Because states bear the primary responsibility for approving smart grid projects and cost recovery for utilities, there is significant disparity in smart grid deployment levels among states. Coupling federal incentives for smart grid with prudent cost recovery at the state level can help to accelerate deployment.
- Increase Consumer Awareness
Greater educational efforts could be made to inform consumers about smart grid and the environmental impacts of energy use.
Business Environmental Leadership Council (BELC) Company Activities
- Dow Chemicals
- DTE Energy
- Duke Energy
- Johnson Controls
- NRG Energy
- PNM Resources
Related C2ES Resources
Further Reading / Additional Resources
SMART 2020: Enabling the Low Carbon Economy in the Information Age, The Climate Group, Prepared for the Global eSustainability Initiative (GeSI), 2008
Electric Power Research Institute (EPRI), The Green Grid: Energy Savings and Carbon Emissions Reduction Enabled by a Smart Grid, 2008
U.S. Energy Information Administration (EIA), Energy in Brief: What Is the Electric Power Grid, and What Are Some Challenges It Faces?
The Electricity Advisory Committee, Smart Grid: Enabler of the New Energy Economy, 2008
National Energy Technology Lab (NETL), “The NETL Smart Grid Implementation Strategy”
 PEVs include plug-in hybrid electric vehicles and battery-electric vehicles.
 For a useful overview of the electricity grid, see the U.S. Energy Information Administration (EIA), Energy in Brief: What Is the Electric Power Grid, and What Are Some Challenges It Faces?
 Power quality is defined as the provision of power with specified voltage and frequency characteristics to the customer. Small imbalances in the sub-minute time frame between electric power supply and demand, and the physical properties of electric power generators, electricity-consuming devices, and the transmission grid itself lead to small deviations (1 to 5 percent) between the expected and actual voltage and frequency of power delivered, which can cause highly sensitive equipment such as computers to fail. When electric power supply and demand are in balance, these deviations in voltage and frequency are eliminated.
 Tuophy, A. “Integrating Wind Generation in the Bulk Electricity System”. EPRI. 2011.
 Kintner-Meyer, M. et. al. “Energy Storage for Variable Renewable Energy Resource Integration – A Regional Assessment for the Northwest Power Pool (NWPP)” Pacific Northwest National Laboratory. 2010.
 California Governor Issues Executive Order Increasing State RPS. Center for Climate and Energy Solutions. September 2009.
 U.S. Department of Energy National Energy Technology Laboratory. “Smart Grid Principal Characteristics: Enables Active Participation by Consumers”. September 2009.
 U.S. Department of Energy National Energy Technology Laboratory. “A Systems View of the Modern Grid – Appendix A1: Self-Heals v2.0” 2007.
 Software that monitors the smart grid could automatically sense power fluctuation that could interrupt service and make adjustments without operator intervention. See Smart Grid Information Clearinghouse: distributed intelligent control systems.
 U.S. Department of Energy National Energy Technology Laboratory. “Smart Grid Principal Characteristics: Enables New Products, Services, and Markets” February 4, 2010.
 Electric Power Research Institute. “Advanced Metering Infrastructure (AMI) Factsheet” February 2007.
 Department of Energy National Energy Technology Laboratory. “Advanced Metering Infrastructure: Powering our 21st-Century Economy.” February 2008.
 University of Delaware. “The Grid-Integrated Vehicle with Vehicle to Grid Technology.” Accessed August 5, 2011.
 Spinning reserve is an ancillary service in the electricity market defined as the ability of (usually a generator) to remain on and ready to start generating given notice over a short period of time (15 minutes to an hour). Regulation refers to an ancillary service (usually provided by electricity generators) to maintain power quality by ramping generation up and down to follow unpredicted minute-by-minute fluctuations in electricity demand.
 Distribution automation is the use of intelligence to create automated operational decisions in electric power distribution infrastructure for the purpose of maintaining or restoring power.
 Reitenbach, G. “The Smart Grid and Distributed Generation: Better Together.” POWER. April 1, 2011. Accessed August 5, 2011.
 Fault tolerance allows distributed generation to “ride through” fault events on the distribution system that would otherwise force it to disconnect and stop producing power. This allows the distributed generation to be connected for a larger amount of time and provide a better return on investment for the investor. Islanding detection refers to the ability of utilities to detect unintentional islanding (or parallel operation) of distributed generation systems, which can result in poor power quality, be harmful to equipment and dangerous for electricians. Island operation occurs if one or more distributed generators continue to energize a part of the grid after the connection to the rest of the system has been lost, this can be dangerous to utility workers, the generation equipment itself, and other equipment connected to the grid.
 The Green Grid - Energy Savings and Carbon Emissions Reduction Enabled by a Smart Grid, Technical Update (Electric Power Research Institute (EPRI), June 2008), 1016905.
 Environmental Protection Agency, 2011, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009. Table 2-13.
 Greater information availability about distribution systems will allow utilities to make better decisions about maintenance and operations. The information allows utilities to make informed decisions about field equipment.
 The Green Grid, EPRI 2008.
 The Green Grid, EPRI 2008.
 Wind and solar power are both variable electricity generation technologies insofar as they only generation power when the wind is blowing or the sun is shining, respectively.
 The Green Grid, EPRI 2008.
 Estimating the Costs and Benefits of the Smart Grid: A Preliminary Estimate of the Investment Requirements and the Resultant Benefits of a Fully Functioning Smart Grid. EPRI. March 29, 2011. 1022519.
 EPRI 2011.
 FERC 2011.
 Amy Abel, “Smart Grid Provisions in H.R. 6, 110th Congress”, Congressional Research Service, Dec 2007
 Edison SmartConnectTM: About Edison SmartConnectTM. Southern California Edison. Accessed July 28, 2011.
 “Get Smart: GE, FPL Announce ‘Biggest’ Smart Grid Deal in Miami.” WSJ Blogs. Keith Johnson. April 2009.
 Open standards, as opposed to proprietary standards, allow any firm to develop devices or applications that interface with a system rather than limiting a system, such as the smart grid or a component thereof, to devices and applications from a single or limited set of firms. Open standards are thought by many to be more conducive to innovation and flexibility.
 SmartMeterTM Steering Committee Update. PG&E 2011.
 Oracle 2009.
 Oracle 2009.
 PG&E Sued Over Smart Meters, Slows Down Bakersfield Deployment. Greentech Grid. November 11, 2009. Accessed July 28, 2011.
 SmartMeterTM Updates: Lawsuit Dismissed; Final CCST Report Issued. PG&E Currents. April 18, 2011. Accessed July 28, 2011.
 The stimulus bills are the Economic Stimulus Act of 2008 and the American Recovery and Reinvestment Act of 2009.
 Smart Grid Investment Grant (SGIG) Program Asset Investment. U.S. Department of Energy. June 10, 2011. Accessed July 28, 2011.
In addition to raising the reliability standard from 99.97 percent, the minimum outage duration counted against reliability could be lowered. Currently, reliability standards ignore outages of less than 5 minutes.
 Policy Framework for a Consumer-Driven Electric Power System. Perfecting Power. Galvin Electricity Initiative. January 2010.