FERC Order 2222 – What Does it Mean for DERs?
Written by Swochchhanda Shrestha, Rabab Haider, and Anuradha M. Annaswamy
Technological advancement has been central to the deployment of small-scale Distributed Energy Resources (DERs) into the US grid. Installed capacity of DERs in the US is expected to grow to 387GW by 2025 , with an estimated 13% of US homes equipped with solar by 2030 . While such forecasts boast high DER penetration, improved efficiency, and lower technology costs, with the US rejoining the Paris Agreement and setting ambitious goals for a carbon pollution-free power sector by 2035 during April’s Leaders Summit on Climate , technological advancement alone cannot solve the climate crisis. Regulatory reform and policy support for resource deployment and integration are vital to achieving carbon neutrality. Even more, innovation in the space of electricity markets is a linchpin to achieving grid flexibility, maintaining grid reliability, and enhancing grid resiliency. The successful integration of small scale Distributed Energy Resources (DERs) into the grid requires, at minimum, adjustments to market design, and more radically, market redesign and reform. FERC Order 2222 is a quintessential example of the latter.
The idea that electricity markets need updating is not new. Since inception, US electricity markets have undergone many changes1. Most notably, the Federal Power Act of 1935 established the Federal Energy Regulatory Commission (FERC) as an oversight body, the Public Utility Regulatory Policy Act (PURPA) of 1978 and 2005 opened market participation to non-utility generators, the National Energy Policy Act of 1992 paved the road for electricity deregulation, the 2005 Energy Policy Act expanded the authority of FERC, and various FERC Orders over the years have been issued to reduce regulatory barriers to entry at the wholesale level. Notably, FERC Orders 719, 745, 783, and 841 have supported the interconnection and/or market participation of small generators (< 20 MW), demand response, and storage resources. Despite these changes, market participation for DERs continues to be limited. Some DERs are as small as a single household’s flexible demand, an electric vehicle (EV), or a set of rooftop photovoltaics, and so are much smaller than the conventional generators which dominate today’s electricity markets. As such, DERs participating in energy markets individually are often unable to effectively bid into markets and influence prices.
Naturally, this leads us to FERC Order 2222: passed in September 2020, which is lauded as a historic final rule on DERs [5, 6]. Order 2222 mandates that DER aggregators be allowed to participate in all regional organized wholesale energy markets. Grid operators who currently have rules excluding aggregators in various capacities will have to revise their tariffs to allow aggregators to participate by mid-2021. DER aggregators are third-party entities that represent multiple DERs at a scale comparable to conventional generators, thereby allowing aggregators to actively bid into markets and influence prices. Typically, individual DERs provide their aggregator with deployment schedules that have information about how much energy that DER can provide or reduce at given times. Aggregators can then aggregate the schedules of all their individual DERs to bid the total amount of energy present in the aggregators’ individual DERs into energy markets. Compensation for this energy is passed along to the aggregators, which often take a portion before passing along the remainder of the savings to individual DER owners.
In the United States, the presence of aggregators in a given energy market varies greatly depending upon the regional operator that runs the market. For example, in the California Independent System Operator (CAISO) market, the presence of aggregators is actively encouraged by the ISO and multiple large aggregators contribute significantly in the market . Conversely, in the case of the New England Independent System Operator (ISO-NE) market, aggregators beyond a total load of 5 MW have historically not been permitted  and many DERs choose a participation model in which they are explicitly price-takers, rather than actively bidding into an energy market. Order 2222 is heavily influenced by the CAISO Distributed Energy Resource Provider (DERP) model, which was established in 2015. Prior to releasing its Notice of Proposed Rulemaking (NOPR) on aggregators in November 20162, FERC held discussions with ISO/RTOs, and garnered much support from CAISO , but drew much criticism from ISO-NE which looked for more flexibility in determining market participation for DERs [12,13].
When evaluating the potential impact of FERC Order 2222 as a whole, it is important to evaluate the effect of aggregators in general. Clearly, FERC sees aggregators as a net positive with many advantages for not only individual DERs, but also the average ratepayer. However, we must also consider where aggregators may fall short and what alternative options exist to tackle those shortcomings. The first concern is the question of how much aggregator participation costs an individual DER. Some aggregators may have recurring subscription costs that DERs need to pay at given time intervals. And aggregators will commonly take a percentage of the total savings/compensation generated by DER deployment. One large aggregator in the CAISO market previously made public claims that they aim for an 80/20 split annually; that is, the aggregator keeps one fifth of the total compensation. This is a significant amount and very important in evaluating the value of aggregators for DERs. However, it is worth noting that this aggregator no longer claims to aim for this 80/20 split and instead claims that they have made changes over time in their compensation scheme, to reflect their current revenue model. Quantifying the profit split between aggregators and DERs can often also be difficult if the rewards earned by a DER are not strictly in the form of direct cash; for example, the same aggregator now also offers rewards in the forms of lottery drawings for big prizes for their customers. Once an average monetary split can be determined for current aggregator participation models, other methods of participation that have a more favorable split for DERs should be seen as improvements in this regard.
Another concern of aggregator participation models is that aggregators are still bidding into wholesale markets. Although the inclusion of aggregators does allow the overall presence of DERs to be influential in these markets, the markets are still settled at the level of the regional operator, which can span across multiple states. Despite using locational marginal pricing (LMPs), these wholesale prices settled at a large scale are not fully representative of the local grid conditions within which the DERs operate. More importantly, DERs residing in the distribution feeder are now being used to meet transmission level objectives; this phenomenon, known as tier bypassing, sees DER utilization at the wholesale level, possibly at the expense of local grid physics (such as voltage levels, line losses, or congestion in the low voltage distribution grid) leading to a potential violation of distribution-level constraints . Further, without assessing the impact that DERs have at their point of interconnection, services such as reactive power or voltage support are overlooked, and DERs are unable to contribute to supporting local grid reliability and resiliency. Finally, although aggregator models like CAISO’s DERP permit DER participation, they retain, by and large, features of legacy wholesale participation designed around large-scale, centralized, and controllable generators. For example, requiring all-year and 24/7 participation prohibits DERs from stepping out of the market when needed3. This is especially limiting for behind-the-meter resources which serve on-site load: a storage device discharging locally (i.e. not injecting power to the grid) when the LMP is negative must make payments to the wholesale market, rather than stepping out of the market . From a market standpoint, the wholesale prices with which DERs are compensated in the aggregator model do not account for the operational flexibility and range of services possible from DERs, nor are they truly representative of the impact the DERs have locally in the grid.
It cannot be denied that aggregators do present many benefits for DERs. The obvious one is size. Aggregation helps to effectively bid into wholesale energy markets and thus ensure that compensation prices are more fair and accurate for a given time and location. Furthermore, because aggregators tend to handle this bidding process without much input from individual DERs aside from their deployment schedule, with the entire process of deployment and compensation remaining simple for the participating DERs. In addition, often aggregators will also help to guide a DER owner through the process of registration and regulation with grid operators. Often times, this may also involve the aggregator paying upfront costs for things like metering technology that are needed for a DER to participate and be properly compensated by a grid operator . When aggregators are able to handle capital costs and occasionally also cover any penalties that a DER may accrue due to being unable to deploy at a committed time, market participation can be a risk-free process for the DER owner.
Clearly, while aggregators certainly have their merits and are among the best existing options for DER participation, they also have their weaknesses that can be addressed with novel participation models. In 2019, researchers at MIT proposed a retail market model that would be operated and cleared at the distribution level, where individual DERs exist, rather than the transmission level, as the wholesale market does [4,18]. A Distribution System Operator (DSO) will be able to coordinate transactions at the local level between individual agents, including DERs, to supply and purchase energy at prices that reflect local conditions. In addition, by operating at a much smaller scale, the retail market accounts for local grid physics, and through distribution-level LMPs (d-LMPs), prices the fine-grain temporal and spatial services offered by DERs. In this way, a distribution-level retail market may overcome the phenomenon of tier bypassing that is present in aggregator participation at the wholesale level.
It remains to be seen how FERC 2222 fares with respect to effective DER participation in the years to come, especially as we move towards the aggressive 2035 targets set by the Biden administration .
- See  for a global snapshot
- FERC NOPR, Docket Nos. RM16-23-000 and AD16-20-000, released November 17, 2016 . Subsequent technical conference held by FERC to address participation of DER aggregators in wholesale markets was held in April 2018, Docket Nos. RM18-9-000 and AD18-10-000 .
- ISO-NE does have participation models for seasonal resources (i.e. summer-only or winter-only), but only in capacity markets. Settlement Only Generators (SOGs) are one such class for DERs connected at the distribution level, but must be a minimum of 100kW and up to a maximum of 5MW, to participate in the capacity market. 
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This article edited by Cesar Duarte