Net metering debate continues

March 22nd, 2016, Published in Articles: EE Publishers, Articles: Energize


The price of solar panels has dropped to the point where many customers find it cost effective to install them on their roofs, reducing their monthly electric bills in the process. The value proposition is greatly enhanced if the distribution company offers a credit for any net or excess generation fed into the grid.

This explains why solar PV installers are active, and profitable, in states with generous net energy metering (NEM) laws, such as California, and why they no longer do business in Nevada following the recent changes in the NEM laws that pays something close to the wholesale, rather than retail price for the excess generation.

Fig 1 Grid parity Solar panels getting cheaper while retail prices continue to rise

Fig. 1: Grid parity: solar panels get cheaper as retail tariffs increase. 


Needless to say, the future growth of distributed solar is closely tied to the future of NEM laws, or similar schemes, where they exist. Remove or reduce the credit received for excess solar generation and the payback period for investments become longer and the value proposition shrinks.

For example, GTM Research’s latest report claims that 20 US states are currently at grid parity, with 42 expected to reach that milestone by 2020 assuming current NEM laws remain unchanged. That, of course, is highly unlikely as a number of state regulators are expected to tinker with the existing NEM laws, with the expectation that, in most cases, they will modify the schemes in ways that reduces their attractiveness to solar customers.

Regulators, of course, are not anti-solar per se; they are merely trying to protect the non-solar customers from the cost-shifting that takes place when solar customers reduce their contribution to the upkeep of the network’s mostly fixed costs. At least that is the argument many want you to believe.

As extensively reported in previous issues of this newsletter, there is general consensus that, as Severin Borenstein wrote in a blog, much of the blame for the cost-shifting that takes place when customers go solar can be placed on “sloppy rate design” – basically tariffs that are not cost-reflective.

This explains why customers in high retail tariff states massively oversize their PV installations. Not only do they reduce or eliminate their annual electric bills, but in some cases they actually receive a refund from the utility at the end of the year for the net annual export to the network. It must feel good. But in a zero-sum game, as in the regulated utility network business, one customer’s gain means higher bills for everyone else – all else being equal.

And the amounts in question are apparently non-trivial. In a recent filing to the Arizona Corporation Commission (ACC), Arizona Public Service Company (APS), claims that net metering customers pay for roughly 36% of the true cost of service under existing tariffs and prevailing NEM laws (Fig. 2).

Fig 2 APS Solar customers not paying fair share of costs

Fig. 2: Solar customers not paying their share of costs.


As illustrated, APS’ retail tariffs are designed to cover the costs of providing service in aggregate – the 99% bar labeled “total company” on extreme left. Some customer classes pay a bit less than their fair share, which is made up by others, leaving the company “whole.”

Solar customers, according to APS, pay only 36% of the costs (the red bar on extreme right). Elsewhere in its regulatory filing, APS claims that, on average, it incurs US$67 each month in costs from each solar customer that customers without solar must cover. With 40 000 current solar customers, the revenue shortfall borne by non-solar customers is $32-million. It is a negligible amount compared to neighbouring California, where the cost shift is far bigger and rapidly growing.

Many, Prof. Borenstein included, have been advocating alternative tariffs that would get around or reduce the inequities in existing tariffs. In a recent report by the R Street Institute, a non-profit public policy research organisation, Lynne Kiesling, a professor at Northwestern University says as more consumers adopt photovoltaic solar and other forms of distributed energy resources (DER), policymakers will need to scrap outdated rules for electricity rates in favor of an open retail market platform with open interconnection standards and transparent two-part grid services charges. Regulatory policy has been cost-based in electricity for more than a century, Kiesling says, adding that in a period of rich technological change and new value creation, too much focus on cost recovery and not enough on reducing barriers to value creation is unlikely to make consumers better off and unlikely to serve the public interest.

There are no shortages of ideas on how the outdated rules and rates are to be changed. Many experts have proposed including more fixed costs, capacity charges, connections fees, minimum fees, etc., with the aim of recovering a higher component of the cost of service through fixed components and/or through a maximum demand charge. There is, for example, broad agreement that customers must pay for the maximum costs that they exert on the network, regardless of the direction of the flow.

As it turns out, this is not easy to do. As noted by Bob Passey and Navid Haghdadi, two researchers at the Centre for Electricity and Environmental Markets (CEEM) at the University of NSW in Sydney, Australia, the majority of the distribution network operators develop what they call ‘cost-reflective’ tariffs that charge customers based on their monthly peak demand, but it can readily be shown that this isn’t what causes the annual network peak. The annual network peak is important because it determines the possible need for network augmentation, and so determines the capital costs faced by the network.

Based on analysis of actual load data, they found that about half of the customers actually peak in winter, with only 31% peaking in summer as illustrated in Fig. 3.

Fig 3 Peak demand by season

Fig. 3: Peak demand by season.


Moreover, they found a rather poor correlation between an individual customer’s annual peak demand and the actual annual peak demand on the network that serves them.

This means that charging a household based on their annual demand peak would not only result in them being charged too much, but would also mean they are charged for network augmentation at times when their demand is not affecting the cost of augmentation.

The authors highlight several important implications of their findings. Firstly, because the demand charge is applied through the whole year, households have a stronger incentive to install load control devices such as batteries. However, batteries will be programmed to shave a household’s peaks, not minimise demand at the time of the network peak, which will make them less effective at reducing the network peak. Similarly, suggestions of a “pipe approach”, where a household’s grid connection capacity is capped at a certain level, will be ineffective.

Having larger networks increases the size of the network operators’ regulated asset base, and under revenue cap regulation they are able to increase their tariffs to maintain their revenue.

What is one to make of these findings? Passey and Haghdadi suggest that a more rigorous approach to cost-reflective tariff design is required. There is also a need to allocate the sunk (residual) costs fairly, as well as design tariffs that households will wish to take up.


This article was published in EEnergy Informer, April 2016, and is republished here with permission.

Contact Fereidoon P. Sioshansi, EEnergy Informer,




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