Microgrid system sizing and aggregation of distributed energy resources for wholesale market participation

Electricity billing is broadly divided into two categories—retail rates and wholesale rates. This separation is evolving in the United States with the introduction of Federal Energy Regulatory Commission (FERC) Order 2222 and aggregation approaches that could employ hybrid rate structures with aspects of both retail and wholesale billing. Yet to date, the public dialogue and discourse of aggregation has outpaced research literature. This study compares potential contractual models for aggregation and evaluates the associated financial and technical implications to customers. The resulting data and insights provide guidance for policy development, business models, and technology needs for aggregation. Comparative case studies are provided for two different microgrid customers (hospital, school) for three urban areas (Chicago, Duluth, Los Angeles) serviced by utilities within an Independent System Operator (ISO) or Regional Transmission Operator (RTO). Each microgrid includes options for solar PV, energy storage, and a backup generator. A Mixed-Integer Linear Programming (MILP) approach is used to find the cost-optimal size of microgrid assets and determine dispatch. Four policy scenarios were modeled with different financial implications for microgrid assets including no export, net metering, wholesale buy-back, and committed buy-back. Approaches which allow a customer to offset their own energy expenditures (wholesale buy-back) perform nearly the same or better than net metering approaches. However, prohibiting self-generation from offsetting utility expenditures (committed buy-back) generally results in poorer performance in all scenarios because selling all generation at the wholesale price of electricity is financially less attractive than using generation to offset utility purchases at a higher retail price. For purely retail policy scenarios, net metering was financially more attractive to customers than a policy that prevented all exports. However, the benefit of net metering was less when electricity tariffs included demand charges. The cost-optimal sizing of solar photovoltaic (PV) was largest under net metering or wholesale buy-back scenarios, with energy storage sizing was largest under the no export or wholesale buy-back scenario. The committed buy-back scenario had an average of 47 % and 88 % less capacity in energy storage and solar PV, respectively, and thus often included larger diesel generators to meet the resilience requirement for backup power. These findings suggest potential schemes for utilities, customers, and microgrid developers to consider as the U.S. electric sector continues to evolve for retail markets, wholesale markets, and hybrid approaches as evaluated here.