Utility rate design is critical to the future of the electric utility industry. Rate design dictates utility financial viability and the role that individual utilities will serve in the future.

By: Paul Augustine

There are two main components of retail rate design that have to be reexamined: (1) rates for electricity consumed and (2) rates for electricity sent back onto the grid (i.e., from distributed energy resources or DERs). Here we focus on the latter component, though the two are related. 

Typically in the past, electric utilities have charged customers a combination of fixed fees plus a volumetric charge for electricity consumed. This ensured that the utilities received fair compensation for the reliable service they provided. With the growing penetration of DERs, the equation has changed. Utility customers are no longer simply energy consumers; they are also energy producers and act as energy managers. Net Energy Metering (NEM) has been the most widespread, though imperfect, tool for crediting customer-produced energy that is fed back to the grid. In its most basic form, NEM is a mechanism of compensating owners of residential and small commercial DERs at the retail rate for every kilowatt-hour of electricity that those DER systems put back on the grid. Whereas in the past it was a conveniently simple way to aid the development of customer-sited DERs, now with rapidly increasing DER adoption, utilities have to balance supporting customer-sited DER with the costs of maintaining the grid and infrastructure. 

Not only is this conversation important for utilities; it is also important for all of their customers. At the end of last year, the state of Nevada dramatically altered its NEM rules, and customers (even those who had already installed DER systems under the NEM laws) were no longer eligible for NEM at the retail rate. Customers who made investment decisions largely based on NEM found themselves in a disadvantageous position. Situations like that in Nevada are bad for all major stakeholders—utilities, DER owners, and non-DER owning utility customers alike.  

When NEM policies originally went into effect, unit costs of DERs—even with NEM and many incentives that were in the books—were uneconomic, so penetration of DERs was low. Heading into this year, costs of DERs were dropping rapidly, but incentives, in particular the Investment Tax Credit or ITC, were set to be significantly reduced at the end of 2016. The falling ITC meant a readjustment in the economics of DERs. And then, against most industry expectations, the U.S. Congress passed a law last December extending the ITC. Now solar costs are low and dropping, energy storage costs are also dropping, and there are strong federal and, in some states, state incentives to accelerate the deployment of DER.

Crediting DER customers at retail rates through NEM is not sustainable for utilities. Ideally, the actual value of each DER system would be assessed and captured in the rate at which a utility credits customers for providing energy to the grid. Unfortunately, the quantification of the value of DER systems is difficult; it is challenging to assess the locational and temporal value of distributed energy at various nodal points, and many of the benefits are intangible. For example, in order to quantify the value of electricity generated from a specific solar photovoltaic array there are several questions that would have to be answered, including: 

  • What investments can the utility actually defer as a result of the DER system being tied to the grid? 
  • What savings will accrue from a distribution standpoint? 
  • What back-up generation is required to address the intermittency of the solar array and what are its associated costs and emissions? 
  • What is the dollar-value of avoided emissions? 
While the complexity involved drove policymakers to a simplistic policy response, the time for an open discussion on this issue, delving into the details in a constructive and inclusive way is upon us. From a utility perspective, failing to do so could accelerate a death spiral (as more customers shift to DERs, more fixed costs are placed on remaining customers who then are drawn to DERs); from a DER-advocacy standpoint—failing to do so could result in another state pulling the plug or adding restrictive caps to NEM policies. In states with low penetration of DER, there is a great opportunity right now to dive into data, analysis, and dialogue about rate redesign. In states with high penetration of DERs, interim decisions will have to be made on net energy metering.  

The energy landscape is changing too rapidly to revert to entrenched positions. Constructive dialogue among stakeholders with the backing of sound data, analysis, and modeling, is the only way to develop a sustainable rate design successor to NEM. At the end of June, a group of over 30 organizations sent a letter to the National Association of Regulatory Utility Commissions (NARUC) recommending rate design process principles. Key among these principles were transparency, the use of good data and credible modeling, and appropriate timing. 

At West Monroe, we are helping utilities throughout the nation to investigate alternative rate designs and to develop win-win solutions that adequately compensate utilities while not disadvantaging DER development. Our work has highlighted the importance of early and comprehensive data collection and modeling to fully understand the implications of proposed rate design. Please reach out if we can assist you as you explore new rate strategies and the opportunities and challenges presented by DERs. 

Paul Augustine is a manager in the West Monroe’s Energy & Utilities Practice. Paul's work focuses on strategic priorities for utility clients. Paul may be contacted at paugustine@westmonroepartners.com