With ‘Twosday’ upon us (2-2-22), we anticipate a social media frenzy over the novelty of palindrome dates, as well as the next pair of (cleverly-selected) filing deadlines for regional grid operators’ plans for compliance with FERC Order No. 2222 (O. 2222). Here, we use Twosday to refer not only to February 2, but also – more broadly – to a time (likely, years from now) when the concept of O. 2222 is actualized and when its intentions are realized.
FERC Order No. 2222- Where Are We Now
FERC Order No. 2222, issued in September 2020, aims to facilitate distributed energy resources (DERs) participation in regional wholesale markets. The order requires regional grid operators to revise their tariffs, allowing qualified market participants to aggregate DERs and offer their capacity, energy, and ancillary services through participation models that accommodate their unique characteristics. DERs, including electric storage, distributed generation, and demand response, can enhance grid flexibility, resilience, and decarbonization.
To achieve these goals while accounting for DERs’ unique characteristics, FERC directed regional grid operators (shown below*) to revise their tariffs which govern participation in these competitive wholesale markets. Specifically, the operators must enable qualified market participants to aggregate (or bundle) these smaller DERs and offer their capacity, energy, and ancillary services into wholesale markets through ‘participation models’ that accommodate their unique physical and operational characteristics. A ‘participation model’ refers to a set of rules and procedures that provide a path for a given market participant to offer their resources’ services in the market. Presently, many distributed resources including flexible/dispatchable loads, energy storage, and distributed generation, are able to participate in certain wholesale markets, primarily through demand response participation models, which do not adequately account for the range of services that these DERs are technically capable of providing (including, in some cases, injecting energy onto the grid). O.2222 is meant to ensure that market rules enable DERs to provide all services that they are technically capable of providing through aggregation.
*Note: These grid operators are referred to as independent system operators (ISOs) or regional transmission organizations (RTOs). Only FERC-jurisdictional ISOs/RTOs are subject to O. 2222 (this excludes the Canadian territories and ERCOT in Texas).
Originally, RTO/ISOs’ compliance plans (including proposed tariff revisions) were to be filed with FERC by July 19, 2021. CAISO and NYISO – the two ISOs which, at the time of O. 2222’s issuance, already had FERC-approved participation models for DER aggregations – filed timely compliance plans, which are working their way through regulatory review processes (CAISO (Docket No. ER21-2455-000), NYISO (Docket No. ER21-2460-000)). The four remaining RTOs whose market rules require a greater overhaul to reach compliance requested and have been granted extensions to the original deadline through the Spring of 2022. Details on their progress to date can be found in their stakeholder groups here: PJM, ISO-NE, MISO, SPP. Compliance plans for PJM and ISO-NE are expected to be filed Tuesday, February 1st and Twosday (really, Wednesday) February 2nd (2-2-22), respectively.
To prepare for Twosday today, we need to revisit the idea of value stacking that lies at the core of O. 2222’s expected impacts and understand what electric utilities and other industry actors can do now to promote a smooth and informed transition to compliance.
DERs can be capable of providing various services to their owners and operators, as well as to other market participants and to the grid as a whole. Today, while it is common for resources’ behind-the-meter (BTM) and retail services to be valued in those markets, wholesale market compensation is less accessible, resulting in the under-utilization of services that DERs do or could perform for the bulk power system. Some of these additional services can be extracted from existing resources, maximizing the benefits from investments made to date; in other cases, the prospect of new revenue streams may change the business case dynamics and motivate investment in additional DERs.
Take, for example, my Ecobee smart thermostat. I admit that the primary value of this technology to me is the convenience of adjusting the temperature of my home from the comfort of my own bed by using the Ecobee app on my smart phone. However, this thermostat provides a secondary value to me in managing my retail energy bills. The scheduling and setback functionalities that optimize the operation of my home’s HVAC system save me roughly 10% on my heating and cooling costs each year.
In St. Louis, Missouri, the value stack does not end there. The local electric utility, Ameren Missouri, aggregates these thermostats from thousands of other residential customers, and operates them as a DR resource to reduce load when energy costs are high (putting downward pressure on rates for all of their customers). In exchange for the ability to operate my home’s HVAC system as a DR resource, Ameren Missouri provides me with a one-time payment for enrollment in their retail DR program, as well as an annual performance bonus. While these payments are less substantial than my annual bill savings, they make the economic case for purchasing a smart thermostat even more attractive for residents in my area (Note: There are other opportunities for me to capture value in the retail market, including an optional time-of-use rate, but we’ll set those aside for the sake of this example).
Presently, Ameren Missouri calls on my device for DR events a handful of times per year by increasing my thermostat setpoint by a few degrees for short periods of time. Depending on the compensation they may offer, I might be willing to allow more frequent and/or more significant adjustments, which could benefit the grid (and myself) while continuing to drive down costs for other ratepayers.
Under O. 2222 (depending on yet-to-be finalized compliance plans), distribution utilities like Ameren Missouri as well as possible third-party aggregators could design a program to offer the aggregated capabilities of residential smart thermostats into wholesale energy, capacity, or ancillary services markets, and pass along a portion of the revenue from these bulk system services back to DER owners like me – adding to the value stack for this technology, maximizing the grid benefits derived from existing resources, and strengthening the case for investments in additional DERs.
The Utility POV
This smart thermostat example may have raised red flags for those thinking from the perspective of an electric distribution utility. These utilities are required to maintain distribution grid reliability and make informed, cost-effective plans about necessary system investments. How can this be done effectively when third parties are able to enroll BTM or distribution system-connected resources and operate them at the direction of bulk power system operators, according to wholesale market signals, which may conflict with local system needs?
For certain utilities (both traditionally integrated monopoly utilities and in deregulated jurisdictions, utilities that serve as providers of last resort), there is an additional layer of complication with O.2222. Again, if third parties bring BTM resources directly to wholesale markets (outside of utility retail programs), how can the utilities ensure that this does not create “missing load” in their load forecasts and system-level generation plans, jeopardizing their abilities to ensure all customers can be reliably served?
These are the strongest concerns that we have heard TRC clients express, in response to O. 2222.
Fortunately, we have time to prepare.
First, we need pilots – new ones and syntheses of the findings of projects conducted to date. Surely, the pilots solicited to inform NYISO’s DER Roadmap will have useful lessons to offer to other jurisdictions currently considering topics like the effectiveness of certain metering and telemetry technologies and baseline methodologies for accurately capturing aggregated resource performance. In terms of innovative program designs, the Michigan Public Service Commission has called on the states’ investor-owned utilities to propose tariffs that provide retail and pass-through wholesale values to participants for energy storage resources (Note: this recommendation was made more directly in response to FERC Order No. 841 than O. 2222). The pursuit of attractive program designs like this one will be an important strategy for utilities seeking to retain maximum control of the resources on their distribution grids, at a time when states’ restrictions on the activity of unaffiliated third-party aggregators are in question.
Secondly, as expectations, rules, and requirements guiding market operations evolve in different regions, it will be important to stay on top of the details, including:
- Opt-in provisions for small utilities, and opt-out rights for states to restrict the participation of DR aggregators in those jurisdictions;
- Criteria and processes for utility review of DER interconnection/enrollment and for utility override of ISO/RTO dispatch of distribution system-connected resources;
- Processes for defining and mitigating double counting of services (identifying overlap between retail programs and wholesale market services);
- Expectations for data sharing between aggregators, utilities, and ISO/RTOs for settlement;
- And more.