On Tuesday, 2012 November 27, I attended the Heritage Foundation’s discussion of Jonathan Lesser’s 2012 October paper “Let Wind Compete: End the Production Tax Credit.” The only philosophical statement on which there seemed to be agreement was that improved storage systems could improve the market for wind.
But who would own the storage systems necessary to make wind even more viable? Unless the ownership is in common with the wind systems, how would these storage systems be compensated?
- And, can we expect entrepreneurs to build these storage systems and then expect FERC to set an appropriate price? Beacon Power produced a flywheel storage system but couldn’t get FERC approval of a tariff before it ran out of operating cash and is now bankrupt.
- Or should FERC put into place a pricing mechanism that could compensate storage systems when they arrived on the scene? I look at this as the Field of Dreams mantra of “If you build it (a competitive market appropriate for storage systems), they (storage systems) will come.”
Truly, a chicken and egg issue.
Wind has been accused of having two failings. Wind often provides a lot of power at night, when electricity is not highly needed. Wind provides less power on the hot mid-summer afternoon, when electricity is needed the most. This is an intra-day issue for storage to handle. Wind power also follows the wind speed. A wind gust can push power production up to great heights. A wind lull can suddenly drop power production. Storage could be useful for handling this intra-hour issue.
Not all storage can handle both the intra-day and the intra-hour issues well. For example, the storage part of the Heritage Foundation discussion mentioned only pumped storage hydro as a representative storage technology to help wind. Pumped storage hydro has been used for decades to transfer power from the nighttime and weekends to the midweek daytime periods. That is, pumped storage is known as a way to handle the intra-day issue. I like pumped storage. My first job after getting a Masters from MIT’s Sloan School was with American Electric Power which owned a pumped storage plant. This perhaps accounts for some of my bias of liking pumped storage hydro. (Actually I like to have a variety of generation options available, not just pumped storage.) Pumped storage hydro is excellent for intra-day transfers of power.
I have never seen anyone use pumped storage hydro for intra-hour transfers of power, or even propose it for such purposes. The absence of a historical use of pumped storage to provide intra-hour storage doesn’t mean that pumped storage could not be used for that purpose. After all, many people tout pumped storage for its ability to respond in seconds to changes in the need for electricity.
Pumped storage is often touted as being about 75% efficient. For every 100 MWH used for pumping, 75 MWH can be subsequently generated. We can model the effect of shorter duty cycles by beginning with the assumption that 0.5 hours in the pumping mode is ineffective. Under this modeling assumption, for 13 hours of pumping, there is the equivalent storage of 12.5 hours. With the 75% efficiency assumption, the system can generate for 9.375 hours, for a revised efficiency of 72% (9.375/13). Reduce the pumping time to 5 hours will reduce the generating time to 3.375 hours and the revised efficiency to 67%. Reduce the pumping time to 1 hour will reduce the generating time to 0.375 hours and the efficiency to 37%. This is not a very good efficiency ratio but we normally don’t think of running pumped storage on an intra-hour basis. I don’t know that pumped storage can run with just one hour of pumping, just that trying to do so will be costly, indeed very costly.
The intra-hour situation has been handled by batteries, flywheels, magnetic storage devices, and theft of service. Theft of service is a harsh term. When an electric utility faces the intra-hour problem associated with rapid changes between wind gusts and wind lulls, the physics of the electric system results in inadvertent interchange, electricity moving into and out of the utility. With the inadvertent interchange going both ways, which utility is providing a service to the other utility?
If the wind gust occurs first, the power is stored on a neighboring utility system. If the lull occurs first, the utility is borrowing electricity and then gives it back. There is no systematic payment mechanism associated with this storage or borrowing of electricity. It is a free service as I described over two decades ago in “Tie Riding Freeloaders–The True Impediment to Transmission Access,” Public Utilities Fortnightly, 1989 December 21.
Most of the currently operating pumped storage systems were put into place by vertically integrated utilities. AEP often looked at its coal fired generating system as providing cheap, efficient capacity, allowing AEP to make large sales to its neighboring utilities. But the pumped storage system also helped AEP with its minimum load issues. The large AEP generating units were very efficient. The investments made to achieve these efficiencies hampered the ability of generators to cycle down at night, during minimum load conditions. Pumped storage systems helped AEP with that situation. Now many pumped storage systems operate in advanced markets operated by ISOs/RTOs, where their value can be assessed based on their interaction with the advanced market.
The thought process of testing how a pumped storage system would operate on an intra-hour basis also provides some information about profitability issues. For 13 hours of pumping and 9.375 hours of generation requires the off-peak price to be less than 72% of the on-peak price to achieve breakeven revenues, that is revenue from the sales to be equal or exceed the payments for pumping energy. The off-peak price has to be even less for the pumped storage system to have book income, that is the ability to cover its investment and other operating costs. The shorter the operating period, the smaller the break-even off-peak price relative to the on-peak price. A competitive market for storage systems needs to have very low “off-peak” price relative to its “on-peak” prices. In this context, off-peak price and on-peak prices could be better described as storage prices versus discharge prices.
The advanced markets have hourly pricing periods that are consistent with the dispatch periods of pumped storage. But for rapid response storage, hourly energy prices do not provide any incentives for the storage system to operate on an intra-hourly basis. Indeed, if storage systems are to operate on an intra-minute period, then prices need to be differentiated on an intra-minute basis, not just on an intra-hour basis. Area Control Error (ACE) is an intra-minute utility metric that can be used to set an intra-minute price for storage systems that are expected to be operated on an intra-minute basis. India has developed a very simplified pricing vector that uses ACE to set the price for Unscheduled Interchange on an intra-dispatch period basis.
In India, the regional system operators set hourly schedules for the utilities and for non-utility owned generators. Though the schedules are hourly, the utilities and non-utility owned generators are nominally required to achieve an energy balance every 15 minutes. Each 15 minute energy imbalance is cashed out using a pricing vector that indexes the price for all imbalances against system frequency. In India, system frequency is the equivalent of ACE.
There are ongoing discussions in India about modifying the pricing vector to reflect the hourly settlement price, to expand the pricing vector for more extreme values of ACE, to geographically differentiate the price, etc. Though there are discussions about revamping the pricing vector, the pricing vector concept has greatly improved the competitive system against which the utilities and non-utility owned generators have be operating. The pricing vector concept could be used to price intra-dispatch period storage to provide the competitive market from which the storage systems could draw power and into which the storage systems could discharge power.
Utilities, including ISOs/RTOs, use ACE to determine dispatch signals for their generators. ACE is calculated every three or four seconds using the frequency error on the network and the interchange being delivered inadvertently to other utilities on the network. Generally, the convention is that a positive ACE means that the utility has a surplus, while a negative ACE means that the utility has a shortage.
- A surplus means that the utility is giving away energy, not getting any money for the surplus energy. Under the situation of a positive ACE, the utility will want its generators to reduce their generating levels and would want storage systems to store energy. As demonstrated by the earlier thought experiment, the market price for unscheduled energy into the storage system would have to be low for the storage system to absorb the energy economically. When the utility is giving the energy away and not getting any money for the giveaway then any price, even a low price, for the energy going into storage can be appropriate.
- A shortage means that the utility is taking energy from its neighboring unities, without paying for the shortage. This is one form of the theft of service I mentioned facetiously above. Under the situation of a negative ACE, the utility will want its generators to increase their generating levels and would want storage systems to produce energy. As demonstrated by the earlier thought experiment, the market price for unscheduled energy coming out of the storage system would have to be very high for the storage system to produce the energy economically. When the utility is stealing energy, then any price, even a very high price, for the energy coming out of storage can be appropriate.
For an explanation of the Indian mechanism for pricing Unscheduled Interchange, I recommend “ABT – Availability Based Tarrif”, a completion of postings on InPowerG, the Indian equivalent of IEEE’s PowerGlobe and “ABC of ABT: A Primer On Availability Tariff,” written by Bhanu Bhushan, the developer of the Indian pricing vector concept. For a discussion of advanced pricing vectors that could be used for pricing storage, see the papers on my web site, especially those filed recently with FERC.
The advanced markets have prices for generators that respond to the dispatch programs in a rectangular manner. For instance, consider a 5 minute dispatch period. The price does not differentiate between those generators that are ramping versus those that are constant or those that move up and down to counteract ACE excursions. An intra-dispatch period price for generation excursions would reward those generators (and loads) that help with ACE excursions and charge those generators (and loads) that cause the ACE excursions. A pricing plan that achieves such a concept would be worthwhile even before fast acting storage systems came on line.