Advanced Energy Perspectives

This post was originally published on SmartGridNews. Read it in full by clicking here.

The rise in customer-sited distributed generation (DG) and the success of energy efficiency (EE) programs in reducing load growth have brought rate design to the fore as utilities look for ways to ensure cost recovery and reduce risk. The large uptick in fixed charge proposals has continued as a result, but now a new trend toward a more sophisticated rate design has emerged - demand charges. Demand charges, the argument goes, are intended to better align revenue collection with cost and provide a strong incentive for customers to reduce their peak consumption. But do they really make sense for residential customers?

Rapid improvements in advanced energy technologies, increased customer adoption of distributed energy resources (DER), and changing public policy goals are driving change in our electric grid. Utilities historically have not taken DER - such as solar PV, demand response, energy efficiency, energy storage, or electric vehicles (EVs) - into consideration in their resource planning. The result is a business-as-usual resource plan, as if no DER were deployed. Cost savings in utility distribution system spending may be going unrealized because of excess capacity or because of investments in equipment for grid services that could be provided by DER at a lower cost. Getting utilities to consider DER in competition with traditional investments can lead to a more flexible, reliable, resilient, and clean grid, all while saving money for customers. The question is: how to do it?

In recent months, Nevada has been the epicenter of the net metering debate nationally. The dispute came to a head on December 23, when the Public Utilities Commission of Nevada (PUCN) approved a new two-part net metering tariff that slashed the existing retail rate and tacked on a higher fixed charge, phased in over four years. The new net metering rules applied not only to new solar customers but existing ones as well. On February 12, the PUCN revised the order, extending the rate phase-in period from four to 12 years, but again without grandfathering existing solar owners. It seemed a watershed moment in the growing conflict over distributed generation connected to the grid - and for the rooftop solar industry that supplies it. But it is far from the last word.

In this post, we look at 10 key issues before state public utility commissions (PUCs) this year, from comprehensive energy storage to rate design and utility mergers. For access to PUC dockets referenced in this column in all 50 states, along with state legislative activity, sign up for a free trial of AEE’s PowerSuite. The trial includes a free subscription to DocketDigest, our bi-weekly newsletter focused on the latest PUC advanced energy dockets.

California is currently immersed in a variety of proceedings focused on topics ranging from distribution planning to rate design to energy storage. Arguably the two most consequential proceedings are on Distribution Resource Plan (DRP) - focused on how utilities can value distributed energy resources (DER) - and Integrated Demand-Side Resource (IDER) - focused on how best to source DER needed by utilities and to consider the issue of localized incentives.

Image courtesy of Clean Energy Resource Teams, from a workshop and tour on community solar gardens at Lake Region Electric Cooperative in Minnesota.

More and more, across the U.S., consumers want access to solar energy. However, according to a new GTM market report, only an estimated 13.5% of U.S. households have rooftops suitable for solar. In what many are hailing as the solution - community solar - the remaining 86.5% of households could benefit from solar power as if the panels were installed on their homes. Community solar makes solar an option for everyone: renters, apartment dwellers, owners with shaded rooftops, consumers with sub-optimal credit, people living in historic districts, and those hampered by unfavorable building codes or zoning ordinances.