Community choice aggregators (CCAs) are growing in popularity as an alternative electricity provider for communities that want more local control over their energy mix. And so, financiers, CCAs and other business leaders must assess what this growth means for the electric grid, utility business models and project finance. While there’s a primary focus on California, increasing energy loads being served by CCAs and other non-utility suppliers have been trending across the country.

The recent American Council on Renewable Energy (ACORE) Forum united dealmakers, policymakers and systems experts to confront the business opportunities, policy and regulatory issues, and technology challenges associated with integrating high-penetration renewable electricity on the grid. The goal of ACORE’s 2019 forum was to advance efforts for a modernized grid that values flexibility, reliability and resilience. One important session was Community Choice Aggregation: Impacts on Project Finance and Grid Management, which was moderated by Ed Zaelke of McDermott Will & Emery and included panelists Nick Chaset of East Bay Community Energy, Daniela Shapiro of ENGIE, N.A. and Britta von Oesen of CohnReznick Capital.

A Brief History

The first CCA formed in 2010 in Marin County, CA, and since then, the CCA movement has grown very quickly to 19 agencies (19 of California’s 58 counties). Notably, CCAs serve over 10 million Californians today. Helping local governments accelerate climate action is foundational to CCAs, with many seeing CCAs as a positive catalyst in promoting climate action, cleaner energy and finding ways to make the necessary energy investments to actuate transportation electrification and building electrification.

In a nutshell? They want to offer lower-cost energy that is cleaner and find ways to invest in local communities.
Continue Reading

On September 28, 2017, the US Department of Energy (DOE) submitted a proposed rule to the Federal Energy Regulatory Commission (FERC) that, if implemented, could reshape organized wholesale electricity markets. Citing electric grid reliability and resiliency issues like the 2014 Polar Vortex and recent hurricanes, DOE asked FERC to enact a new compensation system for coal and nuclear power plants—dubbed “fuel-secure resources” by DOE. Coal and nuclear plants have been retiring prematurely and, according to DOE, the retirements are “threatening the resilience of the Nation’s electricity system.”

In order to stem the tide of retirements, DOE submitted to FERC a proposed rule requiring organized wholesale electricity markets run by independent system operators (ISOs) or regional transmission organizations (RTOs) to develop and implement market rules that “accurately price generation resources necessary to maintain the reliability and resiliency” of the bulk power system. The proposed rule would require ISOs and RTOs to provide “a just and reasonable rate” for the purchase of electricity from a fuel-secure resource and “recovery of costs and a return on equity for such resource.” Eligible resources must (i) be located within an ISO or RTO, (ii) be able to provide energy and ancillary services, (iii) have a 90-day fuel supply on site, (iv) be compliant with all environmental laws, and (v) not be subject to cost-of-service rate regulation at the state or local level. Practically, these requirements limit participation to coal and nuclear plants.
Continue Reading