Market forces and government policy are driving clean energy deployment across the U.S. at a level that could impact reliability if not carefully implemented. State regulators, independent system operators (ISOs), and the Federal Energy Regulatory Commission (FERC) are therefore increasingly considering changes in how to plan for reliability and maintain it in real-time.
One set of efforts focuses on better understanding and managing the reliability contributions of utility-scale resources within existing regulatory and market frameworks. Multiple ISOs have turned to sophisticated Effective Load Carrying Capability (ELCC) analyses to better capture the reliability attributes of intermittent renewable or limited-duration resources across all 8,760 hours of the year. The Midcontinent ISO, California ISO, and Southwest Power Pool all apply ELCC modeling for intermittent resources; New York ISO uses an ELCC calculation for energy storage; and PJM is currently seeking FERC approval of a new ELCC regime for sporadic and limited-duration resources.
In a more proactive approach to resource adequacy, several western U.S. jurisdictions came together in 2014 to form a Western Energy Imbalance Market, facilitating energy exchanges between regions to lower costs and better integrate variable renewable resources. A group of utilities in the Southeast has submitted a Southeast Energy Exchange Market agreement for FERC review under section 205 of the Federal Power Act, with similar goals. However, that proposal is facing critiques regarding both market design and governance concerns.
Another category of proceedings considers establishment of new regulatory regimes and market rules to better leverage distributed energy resources (DERs) to meet reliability needs. These undertakings explore a new approach to reliability that focuses less exclusively on generation and opens the door for flexible load to play a more substantial role.
Unsurprisingly, given its significant DER penetration levels and renewable integration needs, California is at the forefront with overlapping efforts between the California Energy Commission (CEC) and California Public Utilities Commission (CPUC). The CEC is updating its long-dormant load management standards, with a staff proposal under consideration that would establish a statewide system of time-varying rates that can be utilized through automated load management technologies to provide real-time demand flexibility. This rulemaking is being conducted in parallel with another CEC proceeding to set standards for appliances that can automatically provide flexible demand. The CPUC has meanwhile initiated a new rulemaking that raises a suite of questions regarding how “to modernize the electric grid for a high distributed energy resources future”—including how DERs can contribute to reliability at the distribution grid level.
California is not alone; Arizona Public Service issued a request for proposals in June 2021, in response to a directive from the state utility regulator, seeking portfolios of distributed demand-side resources to meet system needs. Other states are taking similar steps, as with New York’s long-running Reforming the Energy Vision initiative.
No discussion of DERs would be complete without a nod to FERC Order 2222, which has set the stage for such resources to achieve “a level playing field in the organized capacity, energy, and ancillary services markets run by regional grid operators.” Although it will likely take years to bring this vision to life, FERC’s order has set off a flurry of important discussions, including how existing wholesale market rules, tariffs, and manuals should change to recognize and appropriately compensate the potential contribution of DER aggregations to system reliability. The following are some some key considerations going forward.
Both Generation and Load Are Becoming More Dynamic and Regulatory Frameworks Are Just Starting to Catch Up. As demonstrated by grid emergencies in California in 2020 and Texas in 2021, reliability is a moving target. Traditional approaches to grid management must adapt, whether to guard against reliability problems in the face of more unpredictable generation and load dynamics, or to utilize new DERs and automated load management technologies to reduce the costs of integrating renewable resources.
DERs Are Underutilized. Based on sheer numbers, the potential reliability and resilience value of DERs is hard to ignore. An expert analysis by The Brattle Group has projected that the U.S. could have nearly 200 GW of cost-effective load flexibility by 2030. But only a few proceedings are addressing how to realize that value at scale, whether through load-shifting during grid emergencies or as a regular component of grid management. Actual reliance on DERs as grid resources in the field remains the exception rather than the rule. As California is discovering, there is much left to do to take advantage of newer automation technologies like smart thermostats, and increasingly more common flexible load resources like electric vehicles, on a widespread basis.
There Is More to Come. On the generation side, ongoing implementation of ELCC models and energy imbalance markets will likely produce lessons learned that will spur additional adaptations to handle a diverse and complex generation mix. As for DERs, although FERC Order 2222 aims to enable direct DER participation in wholesale markets, there may be a range of distribution-level and other use cases outside that venue. It will be important for regulators to establish workable rules that allow all types of resources to play their part in this brave new world of reliability.
—Madeline Fleisher is of counsel with Dickinson Wright PLLC.