Net Metering–Morphing Customers Who Self Generate

The U.S. Public Utilities Regulatory Policy Act of 1978 started a flood of non-utility generation, initially a few very large cogeneration plants and recently a large number of small roof top solar generation.[1]  The rapid growth in the number of small roof top solar generators requires the electric industry to develop a pricing plan that is fair to traditional customers as well as to the hybrid customers, those still connected to the grid but with some self generation.

Electric utilities support their pricing decisions with class cost of service studies  (CCOSS).  The CCOSS allocates the utility’s revenue requirement[2] to groups of customers, called classes.  Classes of customers are claimed to be homogeneous, such as being of a similar size, but more often as having similar load patterns.

Some costs in a CCOSS are allocated based on the number of customers, perhaps weighted by the cost of meters and services.  Fuel costs are allocated based on energy through the meter, though often weighted by the losses incurred to reach the  meter.  A large portion of the costs are allocated based on demand, the amount of energy used by the class during the times of maximum stress on the utility, or at times of maximum stress upon portions of the utility, such as on the generation, the transmission, distribution.  Utilities are concerned about recovering these demand related costs as customers morph from being a full requirements customer to being hybrid customers.

Electric utilities have long alleged that the homogeneity of residential load patterns allowed the utility to use energy meters, often called watt-hour meters, to determine how much each residential customer should pay each month.  The logic is that the allocation process brought costs into the rate class based on the customer’s demand.  Further, homogeneity means that the amount of energy through the meter is proportional to the customer’s demand.  The utility could collect roughly the right amount of money from each residential customer by charging residential customers based on their energy consumption[3] instead of charging residential customers based on the demand.

Charging customers based on energy allowed utilities to reduce substantially the cost of owning and reading meters without significantly distorting how the revenue to cost ratio from each customer.  At least until roof top solar substantially reduced the amount of energy that goes through the meter without necessarily reducing the customer demand.  Thus, with roof top solar, the revenue collected from the customer goes down greatly while the costs brought in by the customer demand goes down only slightly.

The growth in roof top solar coincides with the growth of Advanced Metering Infrastructure (AMI).  AMI often includes automatic meter reading and interval metering .  Automatic meter reading generally means replacing the person walking door to door with equipment.  The carrying cost of the equipment is often less than the cost of the human meter reader, allowing AMI to pay for itself.  Interval metering means collecting the amount of energy delivered during small time intervals, generally one hour (24×7), though sometimes on an intra-hour basis.  These interval readings are the demands in the CCOSS.

The intra-hour meter readings made possible by AMI would allow electric utilities to charge all residential customers based on their maximum demands, the determinant used in CCOSS to allocate costs to customer classes.  No longer would the utility have to rely on homogeneity assumptions in regard to residential customers.  The demand charge permitted by AMI would reduce the disparity between the lower revenue to cost ratio for residential customers with roof top solar relative to the revenue to cost ratio of standard residential customers.



[1] See

[2] the amount of money the utility needs to collect each year to continue functioning

[3] with a very inexpensive watt-hour meter

Net Metering–Reducing the Cross Subsidies

The U.S. Public Utilities Regulatory Policy Act of 1978 started a flood of non-utility generation, initially a few very large cogeneration plants and recently a large number of small roof top solar generation.  The large cogeneration plants sold power to utilities under individual contracts, such as those using the Ernst & Whinney Committed Unit Basis which I designed in 1984 for the Texas Study Group for Cogeneration and which was adopted that year by name by the Texas Public Utilities Commission.  The concept was adopted in other jurisdictions though generally without the explicit reference used by the Texas PUC.

The large number of roof top solar projects required a generic approach to pricing the output of non-utility generation.  A simple expedient has been net metering.  When there is a single meter on a customer premise, the meter can only measure the net amount into the premise.  Any generation just reduces the amount of electricity that the customer takes from the utility.  At some times, the generation will exceed the customer consumption resulting in an export of electricity to the utility.  Some jurisdictions extend the net metering concept to allow the exported energy to be offset against energy draws during other periods.

A problem with net metering is that the value of electricity changes rapidly, perhaps by a factor of 100 in the span of a few seconds.  Further, the change in value can be between positive and negative, as utilities are increasingly stressed by surpluses, especially at night and during periods of rapidly changing meteorological conditions.  This confounding situation makes net metering less and less applicable to the energy meter that has been a standard for measuring domestic consumption.  The advent of the smart grid and an automatic metering infrastructure may alleviate some of this issue, at least once the utility industry adopts real time pricing for retail consumption.

I mentioned the time span of a few seconds previously.  Independent System Operators create new economic dispatch order every 5 minutes, in that ISOs re-evaluate the relative merits of the available generation based on their relative fuel costs, as well as transmission constraints that can occur in less than a second, such as with a bolt of lightning.  The rapid change in the transmission system also occurs on the distribution system, which should similarly impact the price charged to retail consumers.  Decreasing the time span for pricing mixed deliveries of electricity should reduce the subsidies that can occur with net metering.