OVERVIEWThe United States has produced clean, renewable electricity from hydropower for more than 100 years. Today there are approximately 2,500 domestic dams and pumped-storage facilities that provide roughly 100 gigawatts (“GW”) of electricity. In addition, there are more than 80,000 non-powered dams, i.e., existing structures that could produce power, with the potential capacity of 12 GW. New England’s non-powered dams potential capacity is 243 mega watts (“MW”). Many of the 80,000 non-powered dams could be converted to produce hydropower at relatively low cost and within a relatively short timeframe. See U.S. Department of Energy, An Assessment of Energy Potential at Non-Powered Dams in the United States (2012).
The energy storage rule, Order No. 841, issued on February 15, 2018 by the Federal Energy Regulatory Commission (“FERC”), creates new opportunities for hydropower facilities to participate in the wholesale power market, and thus incentivizes the conversion of non-powered dams to hydropower and the addition of storage to existing hydropower facilities. This article explores the opportunities presented by the new energy storage rule, particularly with respect to small, low-head non-powered dams where the installation of energy generation capacity can be achieved with lower installed costs, lower levelized cost of energy, fewer barriers to development, less technological and business risk, and in a shorter time frame than development requiring new dam construction. Moreover, energy from low-head hydropower installations can be aggregated for coordinated dispatch into a regional transmission organization (“RTO”), thereby leveraging its ability to be a peak shaving resource, which is an area FERC has determined is important for removing barriers, but has concluded should be the subject of a separate proceeding in order to permit the Commission to gather more information.
UNDERSTANDING ENERGY STORAGE
An “energy storage resource” is a commercially available technology that is capable of absorbing energy, storing it for a period of time, and thereafter dispatching the stored energy to the wholesale or retail electricity market. Existing technologies include (1) batteries (lead acid, lithium ion, sodium sulfur, flow, dry cell); (2) fly wheels (mechanical devices that harness rotational energy to deliver instantaneous electricity); (3) compressed air storage that uses electricity to compress air and store it, which is then expanded through a turbine to generate electricity later; (4) electrochemical capacitors that store electricity in an electrostatic charge; (5) thermal energy storage that uses either heat sinks like molten salts to store heat energy which can be used to either generate electricity or provide heating later; or electricity to freeze water into ice that can be used to provide air conditioning later and (6) pumped hydro power. New developing battery technologies include, for example, sodium-ion and solid magnesium electrolyte.
Energy storage technologies are viewed favorably by most regulatory bodies for many reasons that conform to smart energy policy. They can reduce the emission of greenhouse gases, reduce demand for peak electrical generation, defer or substitute for an investment in generation, transmission or distribution assets, improve the reliable and stable operation of the electrical transmission or distribution grid and reduce or eliminate variability and flicker that accompany some renewable energy sources. These storage technologies are seen as essential to the continued expansion and value of renewable energy, and as key to balancing energy generation and consumption and to maintaining grid stability.
Prior to issuance of the current rule, FERC regulated U.S. interstate wholesale electrical energy markets by participant categories – generators, transmitters and distributors, with different rules for different categories. While generators were authorized to sell into the wholesale market at market-based rates, transmission remained largely subject to cost-of-service ratemaking and required strict adherence to open-access transmission tariffs and non-discriminatory service to customers.
Because energy storage technologies can both inject electricity into as well as withdraw (i.e., be charged by) electricity from the grid, they transcend the Commission’s traditional “siloed” regulatory framework for generation, transmission and distribution resources. Understandably, therefore, FERC’s rules on how to connect energy storage to the electricity grid were inadequately defined and were designed to accommodate traditional technologies that are markedly different from energy storage. See Massachusetts Clean Energy Council and Massachusetts Department of Energy Resources, State of Charge: Massachusetts Energy Storage Initiative (2016).
FERC’S ENERGY STORAGE RULE
In November 2016, FERC proposed amendments to its regulations to remove barriers that discouraged energy storage resources and distributed energy resources aggregators from participating in the capacity, energy and ancillary services markets operated by the six regional transmission organizations (“RTOs”) and independent system operators (“ISOs”) subject to FERC jurisdiction. Pending public comment on the proposed rule, in January 2017 FERC issued a policy statement clarifying that an energy storage resource may provide services at both cost-based (e.g., transmission, which is regulated) and market-based (generation, which may be non-regulated or market-based) rates at the same time so long as (1) there is no double recovery of costs to the detriment of cost-based ratepayers, (2) the potential for cost recovery through cost-based rates does not inappropriately suppress competitive prices in wholesale electric markets to the detriment of other competitors who do not receive such cost-based rate recovery, and (3) the level of control in the operations of the electric storage resource by an RTO/ISO does not jeopardize its independence from market participants.
The February 2018 final rule adopted the conceptual approach set forth in the 2016 proposed rule and 2017 policy statement. That approach opened and leveled the playing field for energy storage resources by making the resources eligible to participate in the wholesale capacity, energy, and ancillary services markets. FERC deferred regulatory action with respect to distributed energy resources aggregators until a later date. The final rule provides regulatory flexibility to effectively deploy energy storage technologies in an array of applications that include improving (i) utility energy efficiency as well as grid stability and security; (ii) grid modernization; (iii) emergency back-up power; (iv) effectuating full use of variable renewable clean energy production facilities such as solar and wind; and (v) lowering annual energy costs. Each of these applications will contribute to expand state renewable portfolio standards goals and replace fossil fuel and nuclear generating plants.
APPLICATION TO HYDROPOWER
Energy storage resources that are deployed in conjunction with, and charged by small, low-head hydropower projects, can function as an independent energy source that provides: (1) reliable energy for a predictable time period, (2) peak power shaving at a substantially lower cost of electricity than the cost of peak power from conventional fossil-fueled sources, (3) reduced variability and flicker that have accompanied renewable energy sources, and (4) reduced greenhouse gas emissions by displacing demand for more natural gas powered electric power generating plants and natural gas pipelines that have heretofore been relied on to satisfy peak demand. In addition, the Senate Energy and Natural Resources Committee will shortly take up consideration of H.R. 2786, an amendment to the Federal Power Act to incent small-conduit hydropower. The bill passed the House last year 420-2.
Pursuant to Section 203 of the Federal Power Act (“FPA”), a hydropower facility must be licensed by FERC, receive an order from FERC indicating that it is non-jurisdictional to FERC, or obtain a determination from FERC that it is a “qualifying conduit hydropower facility.” FERC requires federal licensing when a hydropower project ties into the grid because interstate commerce is affected.
A non-federal hydroelectric project must also be licensed if it is located on a navigable water of the United States. The complicated issue regarding which waters are deemed “navigable” for purposes of federal jurisdiction is currently being litigated, and the current EPA is seeking to rescind and revise the navigability rules promulgated during the Obama Administration. Non-federal hydroelectric projects are also subject to federal jurisdiction if they (1) occupy lands owned by the United States; (2) use surplus water or water power from a government dam; or (3) are located on a body of water over which Congress has Commerce Clause jurisdiction, project construction occurred on or after August 25, 1935, and the project affects the interests of interstate or foreign commerce. See GZA GeoEnvironmental, Inc., Report on Permitting Small and Low Impact Hydropower Projects in Massachusetts (2016).
Even small hydroelectric projects that are connected to the interstate grid are deemed to affect interstate commerce by displacing power from the grid, and if the cumulative effect of the national class of these small projects is deemed significant for purposes of FPA section 23(b)(1). However, FERC does not require federal licensing if the hydro project is not tied into the grid, but its power is simply used on site.
Battery storage currently is a preferred technology for shaving peak energy demand and eliminating variability and flicker in renewable, clean energy resources, whether solar, wind or low-head hydropower. Especially important is the fact that battery storage generally can be deployed more quickly and flexibly than other storage technologies to meet peak demand, and at a cost that is expected to continue its significant rate of decline. Hydropower also runs twenty four hours a day seven days a week, subject to water level and environmental requirements. Further, according to the Low Impact Hydropower Institute (“LIHI”), the average capacity factor for LIHI Certified Hydropower is 54.4%. A “capacity factor” describes how intensively a fleet of generators is run. A capacity factor near 100% means operation is continuous close to 100% of the time. In comparison to low-head hydro, the 2017 capacity factor for nuclear was 92.2%, natural gas fired combined cycle – 54.8%, coal - 53.5%, wind - 36.7%, and solar photovoltaic – 27.0%.
A significant opportunity is presented by the potential development of hydro-charged battery storage for peaking facilities at currently existing small to midsize hydro sites. Peaking facilities can be deployed quickly, although installation may require upgraded and smarter transmission and grid infrastructure as well as new grid interconnection construction. Smart siting and distributed grid integration of battery stored power through hydroelectric generation can significantly reduce the pressure to build more natural gas pipelines to meet peak demand, and cut costs if available when natural gas prices for electricity generators peak. Other benefits would include enhanced grid reliability, and relatively more stable and predictable electricity prices since these hydroelectric peaking facilities would have small marginal operating costs.
Advanced energy storage resources are capable of dispatching electricity within seconds without producing direct air emissions. Therefore, significant modifications would not have to meet air quality standards.
In addition, the permitting process for advanced energy storage projects is simpler than for more complex infrastructure projects, and construction timelines are considerably reduced. The modular design of many energy storage systems allow components to operate and interconnect the storage resource using simple containerized structures. Such projects require a much smaller footprint than conventional power plants and easily can be added in local areas to provide grid stability, thus eliminating the need for new gas-fired generation or new transmission facilities to solve local reliability needs.