How Do You Spell the Future of Net Metering? Maybe like this: LMP+D

Posted by Ryan Katofsky on May 13, 2016 7:26:41 AM


There are lot of hot topics in energy these days, but perhaps none more so than net energy metering (NEM). This simple rate design allows customers with onsite generation (usually rooftop solar, but also other technologies, like fuel cells and small wind systems) to send excess electricity onto the grid and spin their meters backwards. At the end of the month, the customer receives either a bill or a credit, depending on whether there was net excess generation in that month. This makes owners of distributed generation happy - and makes utilities nervous.

Although NEM clearly sets out what distributed generation (DG) customers get paid for their electricity, it does not fully answer the question of what that DG is worth, not only to that customer but to all the other customers who depend on the grid. That’s exactly what New York’s Public Service Commission asked for comment on in the latest round of filings under its “Reforming the Energy Vision” proceeding. In response, AEE Institute, and its state and regional partners engaged in that proceeding, submitted a proposal for setting the balance between deploying distributed energy resources (DER) and maintaining the grid for all. What’s the not-so-secret formula? LMP+D. For what that means, read on.  

First, let’s set the stage for efforts in New York, and elsewhere, to move beyond NEM.

As a way of compensating DG owners for the electricity they produce, NEM is simple and understandable but also, arguably, a blunt instrument. So are the rates it is built upon. In standard rates, the costs to generate and deliver electricity are averaged out over time and location, even though these costs can vary a lot. This is generally accepted as good ratemaking practice - customers with similar characteristics are charged the same rate per kWh of electricity, and thus the costs of the system are shared among them.

But as DER penetration rises, NEM shifts some of the revenue that utilities collect from rooftop solar customers to those who don’t have onsite generation, making utilities nervous about the impact on non-NEM consumers. Also, under NEM, which provides the same rate benefit to every distributed energy customer, grid operators may find themselves with too much DER where it is not particularly helpful (which can impose new costs on the grid) and not enough where it may be really useful (e.g., on a constrained circuit).

For these reasons, utilities generally don’t like NEM. But as a policy tool for encouraging customers to invest in DER, NEM works. It’s simple to implement and easy for customers to understand. Companies that install and finance distributed generation projects can build business models around it, and in so doing, give customers new options for meeting their energy needs, while helping to meet state energy, environmental, and economic development policy goals.

Most utility attempts to deal with NEM have focused on changing rates in ways that would make DER less attractive to customers, by imposing higher fixed charges or cutting compensation rates for net excess generation. What if, instead, rates were changed to give customers more accurate price signals, so that DER could be installed where it was most valuable, and operated (dispatched) in a manner that generated power when it was most needed? This would allow DER to reduce system costs and provide benefits to the entire system.

This is the idea behind the Reforming the Energy Vision (REV) proceeding in New York State, in which the PSC recently opened a separate case (PowerSuite users can follow it here) to develop and implement a successor tariff to NEM. This successor is intended to be one that more fully and accurately values DER, based on an obscure but technically accurate formula known as “LMP+D,” where LMP (locational marginal price) represents wholesale market value and D represents all other values, including distribution system benefits and environmental externalities (which are not fully captured in market prices). AEE Institute, in conjunction with our state and regional partners ACE NY and NECEC, recently filed a detailed proposal in that proceeding, which we hope will move the NEM conversation in the right direction, in New York and elsewhere.

One objective of our proposal was to create a rate that works for all DER technologies, whether generation or load reduction, whether dispatchable or non-dispatchable, and whether behind-the-meter, a shared community resource, or connected on the utility side of the meter. For example, value-of-solar tariffs, which have been studied in many jurisdictions and implemented in a few, only work for… solar. On the flip side, critical peak pricing or peak time rebate programs are geared mainly towards load management, and can only be effective with advanced metering infrastructure (AMI). We wanted a rate that would work for both distributed generation and demand management with existing metering technology, because utilities in New York have yet to deploy AMI.

To meet these needs, we proposed an hourly rate that would vary based on time and location. All components of this “LMP+D rate” would be converted into $/kWh charges. This includes converting wholesale capacity and distribution costs into $/kWh. The rate would apply to the customer’s entire bill - the value paid for a kWh generated in a given hour would be equal to the rate charged for a kWh consumed in that hour. Similarly, a kWh saved would be worth the same as a kWh generated. Much like NEM, this would keep things relatively simple, once the prices were known. Interval meters would log hourly net consumption or production and bills would be calculated by applying the hourly rate. Customers would receive a bill or a credit, just like with traditional NEM. There would be no need for real-time communication - just a monthly meter reading, albeit with more data to read.

Compared to existing time-of-use rates (mostly applied to larger commercial customers, but also some residential consumers), which have multi-hour blocks of peak and off-peak pricing, our proposed rate would have shorter, sharper peaks corresponding to the actual hours of highest pricing. Also, there would be no need for a separate demand charge, which imposes a fee based on peak usage, as all costs would be built into the hourly price. For customers who installed dispatchable DER, like energy storage or fuel cells, this means they could schedule their DER, based on a published price forecast, to operate during those hours where it is most valuable to the system, as expressed by price. Similarly, customers given advance notice (based on the price forecast) could pre-cool buildings ahead of times when prices were expected to be high. For customers with non-dispatchable DER, like solar, the values paid would likely be similar to those calculated under value-of-solar tariffs, with no benefit - or penalty - based on time of production.

Our proposal represents a more significant departure from NEM than some others. To help manage the transition, our proposal does four things.

First, it grandfathers existing NEM customers so that they can continue to operate under rate structures that are the same as when they made financial commitments to install DER. (This varies, in some ways, from the proposal submitted by the Solar Progress Partnership, which AEE Institute helped facilitate, but that breakthrough joint filing by utilities and major solar developers may provide a framework that moves the process forward.)

Second, for customers who install distributed generation that remain net importers on an annual basis, our proposal retains traditional NEM as the default option. In other words, if you are not generating more electricity than you are using, you get the full-retail NEM credit.

Third, it phases in the new rate gradually - it would be opt-in for most customers and become the default rate only for customers that are net exporters (those producing more than 120% of their annual usage), including remote net metering and community DG projects.

Fourth, we proposed several options for increasing the price stability/predictability of the rate so that DER providers and customers can have confidence in the expected revenue streams. This will allow DER providers to raise needed capital and offer customers a firm deal for their DER installation.

The structure of this proposal is fairly simple, but executing it will be more complex.

Utilities will need to make available to customers and DER providers more data on their costs, both current and future (and past so that it is possible to see what the rate would have been if it had been in place over the prior three years). New tools and price forecasts will have to be developed so that customers can decide to (a) invest in DER and go onto the hourly rate, and (b) determine how to dispatch their DER assets for greatest benefit. This plan is also predicated on utilities making changes to their planning processes as well as ongoing investments in their networks to accommodate, and take advantage of, the growth of DER.

No one is saying it will be easy. But if these pieces can be brought together, we envision a future where DER providers and customers will be investing in DER where it has the most value and then operating these resources in a way that maximizes value to themselves and the system that serves everyone. This will lower costs for all customers over time, by driving down wholesale energy and capacity prices, and by stimulating private investment in new DER capacity that is aligned with system needs. At the same time, customers who want to invest in DER of any kind will continue to be able to do so, even if they aren’t located in areas with high LMP+D rates.

Transitioning from NEM may be complicated, but done the right way, DER and the grid can coexist not only peacefully but happily. Here’s hoping that New York will show the way.

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Topics: State Policy, 21st Century Electricity System



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