Net metering simply refers to the ability of a meter to “spin backwards” when a customer with an on-site fuel cell or solar PV system is generating power and putting it into the electricity grid. When they draw power from the grid, the meter goes forward again – in this way, the customer is charged only for the “net” power they take from their utility, over and above the amount they deliver to the grid.
Most states have adopted some form of net metering, but, the structure of each varies widely. Most states place certain limits on net metering in the form of “caps” on either capacity (i.e., systems over 2MW may be excluded from net metering) or a percentage (systems may not be net metered if they produce more than 120% of the customer demand). Similarly, many states will have a system wide cap – once they achieve a certain percentage of peak power, the utility no longer must net meter new generation systems, for example.
In the early days, net metering looked more like “net billing” – a customer would be credited at a lower rate (often avoided cost – or wholesale power rate) for power produced and charged a higher rate (retail) for power consumed. While this fit with the utility model of purchasing power at one rate and selling at another, it didn’t fit well with owners of on-site generation systems, who found themselves selling their power at a price lower than the electricity they bought. Increasingly, however, net metering has become a one-for-one swap – where kilowatt-hours (kWh) put into the grid are valued the same as the kWh consumed from the grid, greatly improving the owner’s economics.
Another issue that challenges net metering objectives around the country is the differing methods of carrying forward excess generation credit, that is generation beyond the amount consumed over a month, and if and how that credit is compensated. Some utilities do not provide credit, while others have insisted on a monthly “true-up” which compensates the owner for excess power on a monthly basis. A better way (and much more common today) is an annual true-up, where credit can be carried forward month to month until the end of the year when the owner is paid for net generation. The best method is a continuous carry-forward. In this case, the customer can carry credits for excess production indefinitely. Customers prefer this method because, depending on when the annual true-up occurs within the year, they may not get the full benefit of their excess production.
Apart from these technicalities, net metering laws face a new set of challenges today. Because a portion of utility rate revenues pay for distribution infrastructure, utilities sometimes describe net metering as representing a cost shift to other customers. Proponents counter that distributed generation delivers a quantifiable benefit to the system as well – delivering power coincident with peak demand and minimizing the need for additional transmission infrastructure.
But utilities argue that, as distributed generation becomes more widely adopted, the cost shift becomes more pronounced. In response, a number of utilities have proposed to their regulatory commissions that a new “distributed generation surcharge” be levied to replace the lost revenue for infrastructure costs.
As states consider such net metering surcharges, they can learn from the experiences of Arizona and Colorado, where commissions have ordered a full cost-benefit study be conducted prior to any potential assessment. In Colorado, a study conducted by the utility found no net benefit to the system from net metering. But in Arizona, a neutral third party (Keyes & Fox) conducted the cost-benefit study and found a benefit to the system of 14¢/kWh, while the cost to the system was 7¢/kWh.
While net metering has been considered a core principal of distributed advanced energy projects, a new generation of standards may be evolving that reflect greater penetration of these technologies into the market, as they move from early adopters and into the mainstream.
