A fight over the future of net energy metering (NEM) in California was resolved by a  California Public Utilities Commission (CPUC) May 24 decision on the arcane question of how to define the NEM cap. The definition of the cap had become a battleground over NEM pitting Investor Owned Utilities (IOUs) against renewables advocates.

Following speeches in which they noted the many economic benefits to California from renewables, the commissioners voted unanimously against the IOUs and in favor of a definition of the NEM cap that will allow for much more distributed generation (DG) going forward.

“This is a big, big win,” said Mainstream Energy Director of Government Affairs Ben Higgins.

Like 43 other states, California has a NEM program that allows owners of DG systems of up to one megawatt in capacity, like small wind turbines, combined heat and power systems and rooftop solar systems, to reduce their electricity bills.

For the kilowatt-hours they send to the grid, system owners’ meters turn backwards as they are credited at the same retail rate they pay for the kilowatt-hours they consume.

When California established its NEM program in 1995, it imposed a 0.1 percent cap but used the ambiguous language of “aggregate customer peak demand” to define what the total megawatts of net metered systems should be divided by to calculate the cap percentage. And that calculation remained undefined, even as the CPUC expanded the cap to today’s five percent.

The differing methods used by the IOUs to calculate the bottom term of the cap equation, and the differing percentages thereby obtained, were recently observed by the Interstate Renewable Energy Council (IREC) which, among its other activities, acts as a watchdog group on U.S. net metering programs. IREC filed a motion asking the CPUC for clarity. Commission President Michael Peevey issued a proposed decision April 5.

He pointed out several differences in how the IOUs calculate the percentage of their NEM but noted one key commonality: Pacific Gas and Electric (PG&E), Southern California Edison (SCE) and San Diego Gas and Electric (SDG&E) all use “coincident” peak demand. Renewables advocates argue that “non-coincident” peak demand should be used.

Coincident peak demand is the designated period when all sectors (residential, commercial and industrial) reach their maximum electricity consumption and the state’s consumption peaks.

Non-coincident peak demand is the sum of the individual peaking demands of all customers in the three sectors. Residential peak is typically late afternoon, commercial peak is early midafternoon, and industrial peak can be at night. That sum of all peaks is greater than the total peak demand at any one time of the day.

When the installed DG capacity eligible for NEM divided by the peak demand gets to five percent, the utilities are off the hook. So they want that bottom number to be smaller. Renewables advocates want just the opposite because the larger number keeps what one solar advocate called their “backbone” incentive in place.

Peevey concluded that the legislature “did not intend ‘aggregate customer peak demand’ to mean coincident peak demand…[and] SCE, SDG&E, and PG&E should use the aggregation of customers’ non-coincident peak demands to calculate their caps on NEM participation…” The commission voted 5-0 to validate Peevey's decision.

In comments filed by their attorneys, the IOUs disputed Peevey’s conclusions. PG&E’s filing complicated the basic dispute by suggesting a change in the way both numbers would be calculated and concluded, “PG&E recognizes that this means more net metering. However…[it] is the better measure of the impact on the grid…”

By raising the issue of the impact of renewables on the grid, PG&E exposed the heart of the real debate between renewables advocates and the IOUs.

The utilities pointed out that of the three parts of the standard electricity bill, only one covers the price of electricity generated. The other charges cover the costs of delivering electricity through the transmission and distribution infrastructure. When NEM customers’ bills are reduced by the retail rate, they escape paying their fair share of costs for infrastructure they use as much as non-NEM customers. And, the utilities argued, it shifts costs to other ratepayers.

But the difference between the generation cost and the full retail cost of electricity is not necessarily a subsidy if the cost shifted to other ratepayers pays for benefits to them as well.

Consulting firm Crossborder Energy principal Tom Beach did a thorough cost-benefit analysis that was based on PG&E data and included a review of two previous cost-benefit analyses. It showed that if the higher value of the power not consumed due to the use of DG is considered, the benefits to the utility are greater and the costs to the other ratepayers are offset.

The biggest component of the benefit, Beach said, is the savings on power plant use and fossil fuel use. Such energy and capacity savings, Beach said, comprise 60 to 70 percent of the benefit to all ratepayers from the rooftop solar facilitated by NEM. And, Beach added, transmission and distribution system savings avoid the costs of line losses and the need for new transmission that provide another ten percent to twenty percent of the benefits from NEM.

Beach’s calculations came to a net benefit from NEM of two cents per kilowatt-hour for commercial and industrial systems, a cost of two cents per kilowatt-hour for residential systems, and, in sum, no cost extra cost of any significance to ratepayers.