The Goldilocks Dilemma

An old posting about why intermittency is not a big deal came to my attention today.  I re-read some of what had been said, especially when I had just sent out a paper on the topic yesterday.

I believe that the value of electric “energy” is often overstated.  The author of the old posting, Chris Varrone, inadvertently acknowledges this when he wrote

However, the energy in wind is worth 100% of the energy in nuclear (or anything else) in the spot market; wind energy in the day-ahead market may be worth a little less, but this can be “firmed” using energy trading desks or by using other assets in the operator’s fleet.

If the day to day differential can be handled by firming with other assets, then the value of the electricity is not just energy.  It is not worth debating what to call this other value, but a substantial part of the value in the spot market is something other than energy.

As to The Goldilocks Dilemma, the paper I sent out yesterday, I began by asking

Is the price paid to dispatchable generation too high, too low, or just right for intermittent generation?

I then answer

Though intermittent generators often argue that they should receive the same price as dispatchable generation and some utilities argue that they should pay less to intermittent generators, sometimes intermittent generators should face a higher price than dispatchable generators, such as when intermittent generation is part of the market during instances of extreme shortage.

The entire paper is available on my web site, the companion to this blog site.  Look for the hot link to the library near the bottom of the first page.  A hot link for the article is near the bottom of library index in the section called drafts.

Storage/Pricing — Chicken/Egg

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”,[1] a completion of postings on InPowerG, the Indian equivalent of IEEE’s PowerGlobe and “ABC of ABT: A Primer On Availability Tariff,”[2] 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,[3] 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.




Electricity Pricing—Fair Trade vs. Free Trade—Which is High/Lower

When I got married in 2004, my wife introduced me to the term “Fair Trade” as in fair trade coffee, where coffee growers are paid a price that allows a “living wage” to be paid to the workers on the coffee plantation where the coffee beans were grown.  I quickly realized that Fair Trade could be used to describe the standard regulated electricity market, including a fair rate of return to the investors.  In contrast, the term Free Trade could be used to describe a competitive market, such as the ones then being developed by Independent System Operators (ISOs).  Free Trade could also be used to describe the bulk power markets between large vertically integrated electric utilities, such as when my former employer American Electric Power (AEP) sold electricity to other utilities, whether Commonwealth Edison to its northwest or TVA to its south.  However, both these Free Trade examples have some aspects of Fair Trade, as has been shown by regulators intervening in the Free Trade markets when prices have appeared to be excessive, such as the imposition of caps on the ISO markets.


In 1978, the Federal government implemented a mixed form of Fair Trade/Free Trade for Qualifying Facilities, requiring many utilities to buy electricity at Avoided Cost under the Public Utilities Regulatory Policy Act (PURPA).  In 1984, Ernst & Whinney, my employer at the time, won a contract with the Texas Study Group on Cogeneration to investigate the way Houston Lighting & Power (HL&P) was paying (or not paying) cogenerators for the electricity that was being produced.  I invented the Committed Unit Basis[1] (CUB) for evaluating long term contracts under which utilities bought power from cogenerators.  CUB was adopted by name by the Texas Public Utilities Commission in its regulations and was used to determine the reasonableness of three large cogeneration contracts that HL&P signed over the next year.


CUB develops an inflation adjusted annual revenue requirement for the next generating unit that the utility would build were it not for the presence of the cogeneration plant.  The inflation adjustment results in economic depreciation rates, which could be negative in the first few years of the model.  Thus, not only did CUB reduce the first year payment to a levelized rate below the standard utility model for the revenue requirement, but the first year payment was below even that levelized rate.  The payment escalated with inflation over the life of the contract.


I saw HL&P sign three major contracts in 1984/5 based on CUB.  My analysis suggested that the second and third contracts were for rates that were successively lower than the first contract.  Some suggested that the lower rates reflected the loosening of the market for electricity.  The first contract reflected the full value identified by CUB, while the subsequent markets reflected competition, effectively going from a Fair Trade price to a Free Trade price.  When I subsequently addressed the concept of a competitive market for unscheduled flows of electricity, I concluded that sometimes the Free Trade price needed to be above the Fair Trade price, not always below the Fair Trade price.  This concern was included in the name of my model for a competitive market for electricity, WOLF, or Wide Open Load Following.


The Free Trade/Fair Trade issue comes up most starkly in the discussion of dispatchability, an issue that dramatically affects wind and solar generation.  They are not dispatchable and many argue that they should be paid a price that is lower than the price paid to dispatchable generators, such as gas turbines.  This lower price would be paid to any “as available” wind and solar (as well as many other forms of QF power, such as surplus cogeneration).  But sometimes, the “as available” power happens to occur when it is needed.  Should “as available, as needed” power always be paid a lower price than dispatchable power?  Should there be a way for “as available, as needed” power be made whole relative to the lower prices that they are paid during many of the hours when dispatchability is important?  How can that be done?


WOLF provides a price adjustment to reflect the concurrent need for power.  When load outstrips supply, the price follows the load upward above the standard price for scheduled power.  Conversely, when load is much below supply, the price follows the load downward below the standard price for scheduled power.  For electricity, the standard measure for whether load and supply are in balance on a utility is Area Control Error.  When the utility is synonymous with the entire grid, the standard measure for whether the load and supply are in balancer is frequency error.  Since both ACE and frequency error can be positive or negative, the price adjustment can serve to raise or to lower the settlement price relative to the standard price.


There are times when dispatchable generators fail to meet their obligations and the utility is able to meet its load because of the availability of non-dispatchable generators.  During such times, the value of the non-dispatchable generation is equal to the value of the dispatchable generators, perhaps even more valuable.  WOLF provides a way to set a price based on the value of “as available, as needed” generation.  When there is a shortage, the Free Trade price for “as available, as needed” generation should even exceed the Fair Trade price for dispatchable generation.

[1] Recently I googled “Committed Unit Basis” and had ten hits, including a paper written in Portuguese by Brazilian authors, but I had include the quotation marks to reduce the hits down to ten.