Billing Tweaks Don’t Make Net Metering Good Policy

Severin Borenstein published a blog on 2016 January 4 with the title of “Billing Tweaks Don’t Make Net Metering Good Policy.”  The entry reminded me of a presentation I had made in October at Oklahoma State, so I added the following comment to Severin’s Haas Blog.

Net Metering can be Good Policy for the recovery of some costs incurred by a utility in serving its customers, such as the cost billed to it by its ISO supplier.  But for the rest of the costs incurred by the utility, such as the cost of wires and meters, a demand charge and a monthly customer charge are more appropriate.

For the cost billed by the ISO supplier, the metering periods need to be aligned, an issue that is current before FERC in Settlement Intervals and Shortage Pricing in Markets Operated by Regional Transmission Organizations and Independent System Operators, FERC Docket No. RM15-24-000.  If the ISO is billing the utility based on fifteen minute intervals, it might be good policy for the utility to bill the retail consumer for those ISO costs on fifteen minute intervals using net metered amounts during those fifteen minute intervals.

This net metering paradigm seems to be only appropriate for the charges coming to the utility from the ISO, as I discussed in “Fairly Pricing Net Intervals While Keeping The Utility Financially Healthy,” 48th Annual Frontiers of Power Conference, cosponsored by The Engineering Energy Laboratory and The School of Electrical and Computer Engineering, Oklahoma State University, Stillwater, Oklahoma, 2015 October 26-27.  A shorter version of this paper was published in Dialogue, United States Association for Energy Economics, 2015 September 1.  The full paper is on my web site  in the library under Conference Papers.

The majority of the cost incurred by an increasing number of utilities are incurred for wires.  A much better way to recover the cost of wires is a demand charge.  When the customer wants to have access to a specific amount of power, the customer can contract for wires access in that amount, which would be billed monthly based on contract demand.  Customers with poorer information about their power requirements can rely on a demand charge based on the interval with the highest net metered amount, generally fifteen minutes or an hour, though I have seen the interval being an entire summer month.  Customers who exceed their contract demand would pay for the excess demand through a multiple of the demand charge.

There are a few appropriate demand metrics, such as the customer maximum demand or more exotic demands such as the contribution to the distribution system peak or the peak on a subsection of the distribution system, all as discussed in the above paper.  We are still several years away from real time pricing of the distribution system, as I discussed in “Dynamic Pricing: Using Smart Meters to Solve Electric Vehicles Related Distribution Overloads,” Metering International, Issue 3, 2010.

The Electric Transmission Grid and Economics

Tuesday, 2013 October 8, I went to the MIT Club of Washington Seminar Series dinner with Anjan Bose of Washington State University talking about Intelligent Control of the Grid.  Anjan began with giving two reasons for the transmission grid but then seemed to ignore the predicate in explaining what the government has been doing in regard to the grid.

The first slide identified two reasons for the electric transmission system.  The first was to move electricity from low cost areas (such as hydro-electric dams) to higher cost areas.  This is an obvious reference to economics.  The second was to improve reliability.  Anjan did not get into the discussion of how that is an economics issue, but it is.  Reliability is greatly improved by increasing the number of shafts connected to the grid.  We can produce the same amount of electricity with five 100 MW generator or one 500 MW generator.  The five units provide greater reliability but also higher costs.  The higher costs are associated  with various economies of scale, including higher installed cost per MW, less efficient conversion of the fuel into electricity, and the need for five sets of round the clock staffs.  A transmission system allows dozens of 500 MW units to be connected at geographically dispersed locations, achieving the reliability of many shafts and the lower cost of larger generators.

But, the presentation had little to do with the economics of the power grid, and the investigations into those economics.  I noticed that much of the discussion during the question and answer period did talk about the cost of operating the grid, so people were indeed interested in money.

Anjan said that the financial people used different models than did the engineers who operate the system.  I have long said that we need to price the flows of electricity in accord with the physics of the system, by pricing the unscheduled flows.  The engineers and operators may plan to operate the system in a prescribed way, but the flows of electricity follow the laws of physics, not necessarily the same was the way some people have planned.

Anjan said that deregulation[1] has caused a dramatic decline in new transmission lines, especially between regions such as into and out of Florida.  My feeling is that new transmission lines would be added more willingly if the owners of the new transmission lines would be paid for the flows that occur on the transmission lines.  For instance, twenty years ago a new high voltage transmission line in New Mexico began to carry much of the energy that had been flowing over the lower voltage transmission lines of another group of utilities.  The group of utilities called the service being provided “vampire wheeling” and refused to make any payment to the owner of the new transmission line.  The new line provided value in the reduced electrical line losses and perhaps allowed a greater movement of low cost power in New Mexico, but that value was not allowed to be monetized and charged.

I note that a pricing mechanism for the unscheduled flows of electricity would have provided a different mechanism to handle the 2011 blackout in Southern California, which began with a switching operating in Arizona.  Engineers swarmed to the area to find data to assess the root causes but were initially blocked by San Diego Gas & Electric’s attorneys who feared that any data could be used by FERC to levy fines pursuant to the 2005 electricity act.  I remember a discussion at the IEEE Energy Policy Committee on that proposed aspect of the bill.  The IEEE EPC voted to suggest creating mandatory reliability standards.  I was the sole dissenting vote, arguing that the better way was to set prices for the unscheduled flows of electricity.  Thus, SDG&E and the Arizona utilities would have been punished by the market instead of risking a FERC imposed fine.



[1] I prefer to use the more accurate term restructuring, since the entire industry is still regulated, even though generation is often subject to “light handed regulation” by FERC, which approves concepts instead of specific prices.

NCAC-USAEE Overnight Field Trip of 2013 October 4-5

Friday and Saturday I went on a overnight bus trip with NCAC-USAEE to visit energy facilities in Western Pennsylvania and Maryland.  The trip included a visit to the Conemaugh coal fired generating plant near Johnstown, PA, the EDF Renewable Energy Chestnut Flats wind farm near Altoona, PA, and a family owned open pit coal mine near Frostburg, MD.  It was wonderful to visit these different technologies, seeing how they work, and getting some quality time with other people interested in the topic of energy economics.

The National Capital Area Chapter (NCAC)of the US Association for Energy Economics (USAEE) is one of the largest chapters of USAEE.  USAEE is in turn one of the largest members of the International Association for Energy Economics (IAEE).  I started attending NCAC meetings in January 2001, was on the NCAC council for 2003-4, treasurer 2005-2011, secretary 2011-2012, vice president 2012-2013, and am now president for 2013-2014.  As president I receive great support from the other council members.  This trip was the result of that support.

Jim McDonnell of Avalon Energy Services has been an NCAC member for about 5 years.  Late this summer he called to tell of a visit he had made to an open pit coal mine in Western Maryland, suggesting it might be a good place for an NCAC field trip.  Rodica Donaldson, NCAC secretary, of EDF Renewable Energy had mentioned during the July NCAC council meeting the possibility of a field trip to a wind farm.  I introduced Jim and Rodica and the next thing I knew they had plans to combine those two field trips with a field trip to a coal fired power plant and we were off for an overnighter.

During the bus ride Friday morning to Conemaugh, the 20 people on the tour introduced ourselves.  We included two current officers of NCAC, two past presidents of NCAC, and a vice president of IAEE, who currently lives and works in the DC area.  Sarah McKinley, an NCAC past president, of the Federal Energy Regulatory Commission was one of the last people to introduce herself.  She told of the open meetings at FERC that facilitated discussions, including the meeting of the Asian Pacific Electricity Regulators (APER) forum 2012 August 1-2.  She told the group that I had attended the APER conference as a member of the public.  Sarah and I talked the rest of the ride to Conemaugh.

My memory of the APER forum included having lunch with two members of India’s Central Electricity Regulatory Commission (CERC), including its chairman.  During the two days prior to the conference, on July 30-31, the Indian electric grid had suffered two huge blackouts, which were highly publicized.  Sarah remembered the two CERC commissioners being interviewed by the press about the blackouts.  My view of the blackout was that India had an overly constrained market mechanism for unscheduled flows of electricity.  A less constrained market would have provided larger incentives for actions that might have prevented the blackout.  I had even written a blog entry on that issue.[1]

In 1998, I became a pen pal through IEEE’s PowerGlobe with Bhanu Bhushan, the principal architect of the Availability Based Tariff (ABT) which in 2002 began to govern wholesale transactions in India.  Bhanu and I visited over dinner in both 1999 and 2001 when he came to Washington, D.C.  He gave me his papers supporting the ABT concept including its provision for pricing Unscheduled Interchange (UI).  A pricing vector sets the UI price every 15 minutes based on the average frequency variation experienced during that 15 minute period.  The UI pricing concept was quite similar to my Wide Open Load Following (WOLF) concept, in that WOLF also sets a price for unscheduled flows of electricity based on concurrent frequency variation.  Just as he shared his private papers on UI pricing, I gave Bhanu some papers I had published on WOLF.  As suggested by the full name of Wide Open Load Following and by the WOLF acronym, the UI pricing mechanism is very constrained relative to the prices that WOLF can produce.

In 2003 January, after UI pricing became active, Bhanu introduced me to InPowerG, an Internet e-mail group of electric power engineering professionals, generally from Indian industry and academia. The group is currently administered by the Power Electronics and Power System group, Electrical Engineering Department, IIT-Bombay and has more than 500 subscribers.  Bhanu’s introduction of me to InPowerG was in regard to an extended discussion of UI pricing, with some people strongly opposed to the concept.  I ended up adding comments providing theoretical support of UI pricing.[2] Though I fault UI pricing as being overly constrained, especially in comparison to my WOLF, I note that the US has no mechanism for pricing the unscheduled flows that brought down the US grid in 2003.[3]

Conemaugh is an 1800 MW power plant near Johnstown, PA, with two 900 MW units.  Conemaugh’s low cost has generally resulted in it being operate 24×7 at full load.  The expanded PJM market place has changed sufficiently to provide incentives for Conemaugh to cycle down at night.  Its operators have made major modifications to allow each unit to have a minimum load of about 380 MW.  I was impressed that the ball mills used to crush limestone for the scrubbers are generally operated off-peak.  The plant has sufficient storage for crushed limestone that the operators shut down this major parasitic load during the day, moving the parasitic load to the night.

One of our tour members subsequently ascribed the need for cycling to the growth of wind during the night.  I question attributing the need for cycling solely to wind since PJM has also experienced a huge shift in load patterns, with many fewer major loads, such as steel mills, that used to operate 24×7.  For instance, the river passing Conemaugh used to be reddish orange from the run-off at Johnstown Steel a few miles upstream.  Now the steel mill is gone.  I imagine that the shift in load shape could be having as big of an effect as the growth in wind.  Accordingly, I say that the jury is still out on the cause of the need for increased cycling of coal fired power plants.  I prefer to think that the cause of increased cycling is the increased transparency of the diurnal price of electricity, independent of the cause of that diurnal aspect of prices.

Another tour participant commented on the very large investment being made at Conemaugh to handle new environmental concerns, both NOX’s and mercury.  His analysis was that the investment is in excess of the original cost of the plant, at least according to his estimates.

EDF Renewable Energy’s Chestnut Flats wind farm is near Altoona, PA.  Seeing the wind mills operate up close, I could image Don Quixote tilting at wind mills in the 1605/1615 classic or the attack of the Martian machines in H.G. Wells “War of the Worlds” radio broadcast of 1938.  I have a blog entry combining Don Quixote and Robin Hood in regard to a proposal last year to mandate Maryland customers paying for off shore wind, which is an expansion of my “Letter to the Editor” published by The Washington Post.[4]

The output of Chestnut Flats is sold to Delmarva Power at a flat energy price.  There is no seasonality nor diurnal incentives, just that maintenance could not be planned during the summer.  After all, the summer is the high price period for PJM.  The SCADA system is operated in Spain, home to the company that provided much of the equipment and has the contract to provide operations and maintenance.  The Spanish company normally has three workers on site.  EDF Renewable Energy’s field manager at Chestnut Flats does have access to the SCADA information.  The SCADA system includes the ability to feather the blades after 6 seconds of continuous excessive wind speeds.

Our bus parked in the wind shadow of one of the wind mills.  Most of the time that we stood there I did not notice the noise created by the wind mills.  But when I thought about it, I could pick out a sound that I realized was the action of the blades.  The local township has zoned Chestnut Flats as residential, though the closest house is about 1200 feet from a tower.  A result of the residential zoning is that rain runoff ponds must be encircled by fences to protect children from drowning hazards.  But with the nearest house being 1200 feet from one of the towers and the land being fenced and at the top of a ridge, the zoning requirements seem excessive.  EDF Renewable Energy’s field manager very much accepted the regulations, providing very matter of fact responses to our questions, much like the old Dragnet line, “Just the facts, Ma’am, just the facts.”

The field manager had no impression that the wind was stronger during the night versus during the day.  His experience was that there was no significant difference.   Again, “just the facts” as he saw the facts and his personal observation of the movement of the wind mills.

On Friday morning we visited a family owned open pit coal mine near Frostburg, MD.  The owner described buying about 180 acres for his home so he could be away from everyone and then deciding to dig up coal from the abandoned drift mine about 100 feet under his property.  The entrance to the drift mine was about one mile away from the pit into which we walked.  Thus, the old underground miners eventually had to walk a mile into a hill side to get to the coal.  Initially the underground miners would have chipped at the coal at the hill side and then went deeper into the hill side to get to the remaining coal.  At the greatest extent, the walk was about a mile into the hill, at least for the underground mine.  Now, the mine was a pit 100 feet deep.

The owner had preserved, perhaps only temporarily, an area that included two wooden rails that had been used about 200 years ago to move coal cars into and out of the mine.  In the early 1800’s, miners would pull wagons into the mine, at an upward slope, through the coal seam to the face at which they were working.  The loaded wagons could almost drift down the rails to the exit.  Thus, empty coal cars were pulled up hill into the mine and loaded coal cars were pulled down hill out of the mine.  Jim McDonnell had given another explanation for working at an upward slope.  Water could not run upslope to fill the mine and did not need to be pumped out.  Both explanations work for me.

One of the mine workers seemed to express surprise that our group from Washington was “pro” coal, making the comment to Andy Knox, the other NCAC past president on the field trip, who works on energy projects for the Navy.  I didn’t hear Andy’s response but the worker’s comment led me to think that I am not “pro” coal, since that would imply that I am “anti” some other source of electricity.  Rather, I am “pro” keeping the lights on at the lowest reasonable cost to consumers.  As an engineer, I have learned that diversity of supply is generally good.  Having all wind, all nuclear, all gas, or all coal would make the electric system subject to great stress during political or environmental upheavals, such as has occurred in regard to nuclear, wind, coal, and gas.  Thus, I personally am “pro” diversity.  If NCAC is “pro” anything, NCAC is “pro” an open discussion of the issues.

The trip back to Washington, DC, on Saturday from Frostburg included a stop at Sideling Hill, where I-68 goes through a manmade notch in a ridge.  Jim McDonnell is a geologist and had provided material on synclines (which look like a bowl) and anticlines (which look like an inverted bowl) that resulted in the folding of the earth’s crusts millions of years ago.  Sideling Hill is at a sharp syncline, showing dozens of strata in the manmade notch.  The upward slope of the strata in the syncline suddenly stopping on both sides of Sideling Hill, which is only obvious because of the manmade notch, is quite impressive.  That Sideling Hill is at such a sharp syncline shows the impressive results of erosion, in that the notch is several hundred feet about the base of the mountain.  The implication is that huge amounts of the upper portion of the syncline bowl had been washed away.  What was left, as revealed in the manmade notch, was a narrow bottomed bowl that had layers of different types of rocks stacked in its center.

For me, an important part of the field trip was the interaction with the other participants.  Some of that is described above in regard to my discussion with Sarah McKinley and hearing the questions asked by various parties, including the mine worker’s comment.  Andy Knox also talked about his personal experience of becoming a net zero energy household.  He has installed enough solar cells that he often has a surplus and exports electricity to the grid.  He believes he has enough solar power to offset not only the energy he takes when solar production is low but also to compensate for the gas he burns in his range.  Recently, the gross generation from the solar cells has become enough that he was able to sell a REC, or a Renewable Energy Credit, for the 1 MWH he has generated to date.  I believe that Andy has an impressive story to tell.

Pictures from the field trip are being posted to the NCAC web site.[5]  Jim McDonnell has already submitted his photos and I saw many other people with cameras.  We expect to have an article published in the next issue of USAEE’s Dialogue.  I hope that some of the other participants on field trip will add comments to this blog or that I can include their comments in the Dialoguearticle.  There is enthusiasm for another field trip, which NCAC had already been planning for the spring in the Philadelphia direction.  One participant expressed interest in a field trip dealing with the use of electricity, such as at a steel mill or an aluminum plant, which the Philadelphia trip would do only partially.  Another participant said he had contacts in the steel and aluminum industry and might be able to arrange such a trip.  Maybe more later.



[1] Economic Failures Contribute to Indian Grid Blackouts, Posted on 2012 Aug 06 by Mark Lively, http://www.livelyutility.com/blog/?m=201208

 

[2] ABT – Availability Based Tariff, http://abt-india.blogspot.com/2007/10/windpower-discussion-on-inpowerg.html

[3] Power Crisis: Revenue Accounting Needed, http://www.energycentral.com/utilitybusiness/businesscorporate/articles/521/Power-Crisis-Revenue-Accounting-Needed

[4] Wind Boondoggles, Posted on 2012 Feb 28 by Mark Lively, http://www.livelyutility.com/blog/?m=201202

[5] NCAC-USAEE.org

FERC, Barclays, and Formulary Arbitrage

On 2013 July 16, FERC ordered Barclays bank to pay a half billion dollars for market manipulation.[1]  The next day Barclays responded by suing FERC in federal district court, forcing FERC to prove the allegations in a venue that Barclays feels would be a level playing field.  On July 22, a New York reporter called a friend of mine who is normally well versed in utility legal matters, having been a regulator and a utility executive, seeking to understand what Barclays did to get FERC upset, asking for a simplified explanation.  My friend suggested another industry expert and also called me.  I got back to my friend on July 23, heard the request, and wrote a message to him explaining what I understood Barclays to have done on a generic basis, without having read much more than articles in The Washington Post.  It is that message of yesterday that I am copying here.

Thanks for the call on Monday in response to a NYC reporter who was asking you for background or information about the Barclays spat with FERC.  I have not followed the details of the spat, but the way I find it easiest to describe is as a thinly traded formulary arbitrage.

An arbitrage is buying and selling related securities with the hope of making a profit on the difference.  For instance, one might buy oil for $90/bbl and sell at $100/bbl and make $10/bbl on the paired transactions.  If the transactions are for oil delivered in different locations, one might also have a transportation cost of $1/bbl, reducing the profit to $9/bbl.  There may be some insurance and other handling costs, but if they are minor, one makes a profit so long as the differential is greater than the cost of transportation.  The transactions can be for the same location but different times.  One might buy a May futures contract for $90/bbl and sell a June futures contract for $100/bbl and make $10/bbl on the paired transactions.  But one has to store the oil, which might again cost $1/bbl for going into and out of storage and for one month in storage.

My understanding is that futures contracts settle at the end of the month before at the average spot price of oil on the last few days of the month.  So, a May futures contract would be settled at the end of April based on the spot price on April 30, or some sort of average.  I call this a formulary settlement.

If one has bought a lot of May futures contracts, one would like to see them settle at a very high price.  So, one might buy lots of spot oil on April 30 to push up the price at which the May futures contracts would settle.  This would be a formulary arbitrage.

But considering that the spot market is very large, it is difficult to budge by buying a lot of spot oil on April 30.  One might need to buy enough oil to supply ExxonMobil.  That would be a thickly traded formulary arbitrage.

Some commodity exchanges offer electricity forwards markets which settle based on the actual spot price of electricity on some of the ISOs.  The ISO spot prices might be thinly traded.  A paired transaction on the electricity forwards market and the ISO market may be a thinly traded formulary arbitrage.  At least that is what I would have told the reporter had you directed him to me.

Hope this helps for the next time.



[1] The Federal Energy Regulatory Commission (FERC) today ordered Barclays Bank PLC and four of its traders to pay $453 million in civil penalties for manipulating electric energy prices in California and other western markets between November 2006 and December 2008. FERC also ordered Barclays to disgorge $34.9 million, plus interest, in unjust profits to the Low-Income Home Energy Assistance Programs of Arizona, California, Oregon, and Washington. FERC News Release https://www.ferc.gov/enforcement/market-manipulation.asp

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.



[1] http://abt-india.blogspot.com/2007/10/windpower-discussion-on-inpowerg.html

[2] http://www.nldc.in/docs/abc_abt.pdf

[3] http://livelyutility.com/library.php