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 Smart Grid Needs Real Time Pricing of the Distribution Grid

When I read the January-February edition of IEEE Power & Energy Magazine earlier this week, I got hung up on figure 1 on page 53, “The price of energy in the PJM market.”  Figure 1 shows 6 hours of prices every 5 minutes.  There appears to be five prices for each time point which would represent 5 locations on the PJM system.  There is the obligatory price spike to $210/MWH and a price suppression to minus $40/MWH.

Curiously, the prices for the 5 locations seem always to fall almost on top of each other, even during the price spike.  Except during the price suppression period.  There, two of the prices actually went up slightly and were not suppressed, one dropped to the previously stated minus $40/MWH and the other two dropped significantly though not to minus $40/MWH, though one did go slightly negative.

My analysis is that the price spike was a generation related issue while the price suppression was a transmission related issue.

This edition of IEEE Power & Energy Magazine focuses exclusively on the smart grid.  Since the related article was about demand response in Chicago, I thought that there should be more about using demand response to handle constraints on the distribution grid, the section of the wires that most people discuss in regard to the smart grid.  Thus, the geographic price differentials should be on the distribution grid, which would be a issue for Exelon’s Commonwealth Edison instead of a transmission issue for PJM.

Using demand response to address generation issues is old hat, the load management programs of a few decades ago.  And though figure 1 shows some geographic dispersion of prices and thus, perhaps, demand response being worthwhile for the transmission portion of the wires associated with the smart grid concept, my experience with PJM suggests that the price suppression was probably most severe in the Chicago area, suggesting that there was too little load in that area instead of the need for demand response.

I believe we need more demand response, not just to handle the G&T issues associated with figure 1, but more especially to handle overloads on the distribution grid.  Electric vehicles (according to EPRI) will overload the majority of the transformers that EPRI studied. 

  • The presence of figure 1 in the IEEE P&E Magazine suggests that many people believe that we can use real time prices to get more demand response.
  • The EPRI study tells me we need demand response to handle distribution issues. 

Putting it together, we need a way to price the use of the distribution grid on a real time basis, just as PJM has put into place a way to price the G&T on a real time basis.

I came to this distribution pricing conclusion last January while speaking at the IEEE/NIST smart grid conference.  My paper on the subject is “Dynamic Pricing: Using Smart Meters to Solve Electric Vehicles Related Distribution Overloads,” Metering International, Issue 3, 2010, which came out last Fall.

Getting the Smart Grid to Make Sense

For the smart grid to make economic sense, we need a way to pay for it by reducing the cost of generation, as well as the cost of wires, not just increase the cost of wires by the investment in the smart grid. There has to be some cost offsets. To accomplish those cost offsets, we need to change the load profile of the customers behind the meter, the cash register of the electric system. To change that load profile means we must give the customers economic incentives, which means changing the prices that are being charged to the customer. Yes, that means higher prices when things are going bad, but also lower prices at other times, including some times when things are going so well that they are going bad.

How can there be too much of a good thing such that “things are going so well that they are going bad?” I wrote of that in “Renewable Electric Power—Too Much of a Good Thing: Looking At ERCOT,” Dialogue, United States Association for Energy Economics, 2009 August. Prices for electric generation in the “wind patch” of West Texas were negative for about 25% of the month of April 2009. Things got so good, with so much wind, that things got bad, with prices that seem so unusual. And it need not just be the “wind patch” of West Texas where there is too much power. If my neighbor puts in a 1 MW wind mill in my residential neighborhood, that will overload the wires and cause too much of a good thing, as I wrote in “Microgrids And Financial Affairs,” Industrial Fuels and Power, January 2008.

The same concept applies to charging electric vehicles, as I wrote in “Dynamic Pricing: Using Smart Meters to Solve Electric Vehicles Related Distribution Overloads,” Metering International, Issue 3, 2010. This article was my response to a pro-EV group which wrote

In a study conducted by EPRI, plugging in just one plug-in hybrid electric vehicle (PHEV) to charge at 220 V overloaded 36 of 53 transformers examined during peak hours and five of 53 transformers during off-peak hours. It is, therefore, important to identify where GEVs are parked and charged so that utilities can make the upgrades necessary to maintain reliable service. (Electrification Roadmap, November 2009, p. 102, emphasis added)

Integrating Wind and Electric Vehicles

I see two issues in regard to integrating renewable resources and electric vehicles, one physical and one financial.

Renewable resources and electric vehicles are both intermittent, requiring some sort of storage to get them to interact with the “normal” part of the grid.  There are many types of storage, including batteries, pumped storage, and load management.  I call load management storage because I can use the electricity now to heat water or I can store the hot water by having heated the water last night.  Perhaps one of the oldest forms of storage is the flywheel.  Think how essential the potter’s wheel is as part of the infrastructure used by a potter.  In essence, flywheels keep the electric system running in that the rotating mass of the generators and the motors are flywheels. When there is a shortage, energy is extracted from the flywheels/rotating equipment and system frequency declines. When there is a surplus, energy is stored in the flywheels/rotating equipment and system frequency increases.

We need more storage devices, such as flywheels built just to be flywheels instead of as part of a motor or of a generator. And we need to pay the owners of these storage devices for their use. Their use should be similar to the use of the flywheel aspects of the grid. When system frequency is increasing or is high, we want storage devices to be absorbing energy. When system frequency is decreasing or is low, we want storage devices to be discharging energy. The incentives for the storage devices to act like this should be low prices (or even negative prices) when the frequency is high and high prices when the frequency is low.

I wrote “Renewable Electric Power—Too Much of a Good Thing: Looking At ERCOT,” Dialogue, United States Association for Energy Economics, 2009 August, to report on the negative prices experienced by the wind farms in Texas, about ¼ of the month of April 2009. And electric vehicles have the additional potential issue of overloading distribution transformers, at least if they are allowed to charge on an unfettered basis. My “Dynamic Pricing: Using Smart Meters to Solve Electric Vehicles Related Distribution Overloads,” Metering International, Issue 3, 2010 deals with that issue.