By Larry Eisenstat and George Johnson
The reliable matching of power supply and load is the cornerstone of electric grid operations: the electricity supplied must match the amount withdrawn. The problem, though, is that by their nature, the variable energy resources (VER) that are increasingly being added to the grid—principally wind and solar projects—are not subject to direct control. Therefore, their addition raises operational issues (albeit ones that can be solved) about how best to match or balance these relatively new sources of supply with load.
This was the question posed by the Federal Energy Regulatory Commission (FERC) in its January 21st, 2010 Notice of Inquiry on Integration of Variable Energy Resources, and it’s one that can be answered in several ways. But one answer is to facilitate the widespread deployment of energy storage technologies and, specifically, utility scale Distributed Energy Storage (DES). Last century, it was a fundamental precept that electricity could not economically be stored to any material degree, but this is no longer the case. Today, if the energy anticipated to come from a variable resource turns out not to be available in real time (because the wind isn’t blowing or the sun isn’t shining), stored energy can be substituted. Simply put, we have at our disposal storage devices that draw electric power from the grid during off-peak periods and, then later when the power is needed, are discharged to provide back-up energy typically at a lower cost than the energy that otherwise would have been withdrawn to backup the VER—assuming this energy was even available during the times of peak demand. These same devices, when operating in charging mode, can also provide ancillary services by reducing the level of demand during periods of the day when VER and load are ramping up or down.
Utility scale DES consists of hundreds, thousands, or hundreds of thousands of energy storage devices located at residential, commercial, governmental, and/or industrial sites. What makes “utility” scale DES possible is that it can be electrically aggregated in the form of thousands of individually sited, small storage devices, and then linked through the Internet, or other electronic means, to the System Control and Data Acquisition (SCADA) systems used by the electric grid operators. An operator can then control and dispatch the aggregated storage devices as though they were actually a single 50 or 100 megawatt (MW) generator or load that could be shed.
In short, utility scale DES would not only allow large amounts of load to be seamlessly shifted from high-cost peak hours to low-cost non-peak hours, but would also provide a way to store the power from VER that otherwise might need to be curtailed. The DES devices, by reducing their demand, can also provide balancing service when needed to fill in at such times as the VER might fluctuate beyond grid tolerances, be this over the course of a few seconds or minutes, or from hour to hour, or over the course of a day. In so doing, the DES would make the VER considerably more valuable and more plentiful.
But, is this really true? Isn’t meaningful energy storage via electric and hybrid electric vehicles years away? Yes, but flywheel systems that provide rapid ramping for regulation service are already deployed in the PJM Interconnection and in the New York ISO, and are under development elsewhere. Plus, utility scale DES in the form of aggregated and centrally controlled ice storage air conditioning is now a reality. In January, the Southern California Public Power Authority (SCPPA), a group of 11 southern California municipal utilities, announced it had entered into a long-term agreement with Ice Energy, Inc., a Colorado-based firm, to purchase and deploy thousands of Ice Energy’s storage devices at small- and medium-sized commercial and government buildings in the SCPPA utilities’ service territories. The devices, which are installed next to five- to 20-ton air conditioners, make ice at night and at other non-peak hours, usually when wind power both is plentiful and cheap. During daytime peak load hours, the ice is used to cool the refrigerant and to air condition the buildings. Collectively, the devices, which will be “cycled,” will be aggregated and centrally controlled by the member utilities, be used to shift 53 MW of peak-load to off-peak hours, and be available to provide ramping services during the early morning and evening transition periods when load, net of wind (referred to as “net load”), is ramping up or down.
From the perspective of wind power producers, DES, particularly on the scale available from DES suppliers such as Ice Energy, provides numerous types of “partnering” opportunities to firm or backup the capacity of wind and other VER generators, particularly through the energy, ancillary services, and capacity markets administered in RTO and ISO markets—where, coincidentally, most of this power is being developed. However, because the current markets were developed primarily to accommodate the operating characteristics of large, central station plants rather than VER and utility scale DES, certain adjustments to these markets would be needed to make these partnering opportunities a reality. In its Notice of Intent, FERC recognized that certain of the market rules might not be flexible enough and, therefore, might need to be modified to level the playing field for VER and those new technologies that would aid VER integration. In particular, FERC suggested the expected large increases in VER will require increases in the amount of reserves and it sought ways to reduce the need for, and cost of, such reserves.
Here are several suggested market rule changes that would facilitate DES’s ability to firm up VER when necessary, and to increase the value of both:
1. Provide a market revenue stream for the system efficiency value and other benefits resulting from peak load shifting such as lower peak-hour prices, increases in capacity factors, and reductions in curtailments, transmission congestion, and line losses.
2. Create a new category of Load Following Reserves. Obviously, load following service would be more available if its providers were compensated. Utility scale DES could be dispatched for load following if limited offers and operation were permitted.
3. Allow combined, partial day, Day-Ahead Market offers or, alternatively, create an intra-day Real-Time Market. DES participation in the day-ahead markets is constrained because it can’t be offered in all hours. Allowing partial day DES and VER offers to be combined would eliminate real-time deviations and increase supply source participation.
4. Allow combined Forward Capacity Market offers from VER and DES resources. VER participation in forward capacity markets is limited to the capacity available during peak load hours. Although current markets allow summer and winter seasonal resources to be combined, it is not permissible for different resources to be combined during the same season. Allowing combined VER and DES offers would allow VER capacity to be “firmed.”
In sum, there is no one or two silver bullets here. But, given its obvious potential, system operators should take all economically justified steps to fully integrate VER and technologies like DES into the power markets.
Larry Eisenstat is a partner at Dickstein Shapiro LLP and head of its Energy Practice. He has experience handling regulatory and transactional matters, as well as litigation, antitrust, compliance, and enforcement matters on behalf of energy and non-energy companies.
George Johnson is senior counsel in Dickstein Shapiro’s Energy Practice. He has been engaged in administrative regulatory practice in the energy, environmental, and telecommunications areas for more than 25 years.
Dickstein Shapiro LLP