California ISO (CAISO) and the New York ISO (NYISO) have both recently secured approval from FERC to allow increased participation of distributed energy resources (DERs) in wholesale markets. DERs have typically focused on delivering energy savings, resiliency, and other benefits to host buildings, often behind the meter. These recent ISO tariff changes reflect increased customer demand for the greater energy control and options that DER solutions can provide. In petitions to FERC, CAISO (docket ER16-1085) and NYISO (docket ER16-1213) cited increased “participation,” “competition,” “resiliency,” and “flexibility” as reasons for expanding DER access to wholesale electricity markets.
While CAISO previously allowed DERs to participate in wholesale markets, small generators were excluded, due to minimum size requirements (0.5 MW). FERC’s recent approval (June 6) of CAIOS’s proposal allows aggregation of small DERs to satisfy the minimum capacity requirements, thus treating aggregated DERs as participants in wholesale energy and ancillary service markets.
FERC’s approval (May 17) of NYISO’s proposed revisions opens wholesale market participation to behind-the-meter (BTM) net generators. BTM generators must first supply their host loads, before being allowed to play in the wholesale energy and capacity markets. Minimum size requirements will exclude smaller BTM assets, as net generators must be at least 2 MW in size and be able to export 1 MW into the transmission or distribution system after satisfying the host load. Intermittent resources and emergency-only generation are not permitted to participate. In addition, BTM resources cannot participate in both the wholesale market and as either an active player in demand response or in generation buy-back programs.
Both ISO tariff expansions move one step closer to an increasingly “DER friendly” electric grid. They do so by creating market opportunities for the use of excess DER capacity, to support the grid and improve efficiencies in the wholesale market. The NYISO estimates that these rule changes could open 100 MW of capacity to wholesale markets.
It remains to be seen how many non-emergency BTM generators will satisfy the physical and regulatory requirements to participation. Existing continuous duty BTM generators, such as those used in CHP applications, may not be physically configured for export due to safety concerns over utility backfeed or network protection. In addition, existing BTM generation systems may never have been sized to offer 1+ MW of excess capacity, especially during peak times.
New or existing BTM net generating assets that do have 1+ MW excess capacity will need to consider the optimal financial play between participation in wholesale markets, or demand response and buy-back programs. CHP systems that may be eligible are also likely to be subject to efficiency requirements; running excess electric capacity will introduce excess waste heat that the host thermal off-taker may not be able to use. It may only makes sense to run 1+ MW of excess CHP electric generation at specific times. Weighing efficiency implications against ISO and local utility energy and demand pricing will require intricate ongoing knowledge of the tariffs. It is also likely to require the introduction of sophisticated interactive (often expensive) controls and automation, if systems are to respond economically to day-ahead or real-time market and tariff signals.
There is no doubt that the technical and regulatory details around controlling and optimizing DERs will continue to be expanded and refined. However, the recent recognition by CAISO and NYISO that DERs have a greater role to play in electricity markets – beyond the constraints of their host building – is a significant step towards a more dynamic, resilient, and efficient grid.
By Tim Banach, GI Energy Director of Analytics