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FERC Order 2222 - Opening Wholesale Energy Markets to Distributed Energy Resources

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JC Culberson's picture
JC Culberson 630
Manager of Operations, Certrec Corporation

A proven industry leader in energy system operations, planning, compliance, and wholesale energy market structure, I have developed NERC compliance programs for entities ranging from ISO/RTO...

  • Member since 2020
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  • Nov 5, 2020
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FERC Order 2222

 

In keeping with the recent past’s trend of addressing emerging technologies and their impact(s) on the Bulk Electric System and wholesale energy markets, FERC has defined Distributed Energy Resources (DER) and the opportunity for DER services to participate in energy markets, to a larger degree than they are currently allowed.

So, what does FERC Order 2222 do? It determines the aggregate kW threshold (100kW) for DER resources to participate in energy markets. While the facilitators and operators of the wholesale energy markets are to allow DER to participate alongside conventional generation resources, as stated above, it does leave a lot of the “how” decisions to ISOs and RTOs, which must complete compliance filings and revise their tariffs within 270 days of the Order taking effect (60 days after the Order’s publication). This means, with the exception of legal appeal, this decision is going to move forward, potentially allowing for a plethora of DER aggregators, representing substantially more GW of energy to participate in energy markets as early as next year. Presently, it is estimated that 50-100 GW of DER services in use, but we anticipate a much broader increase in DER services once this order opens the markets to allow for a more robust participation factor. What doesn’t FERC Order 2222 do? Well, it doesn’t allow for the current market oversight entities to broadly deny DER services in their wholesale energy market structures. This further solidifies the statement in the paragraph above that DERs are going to experience a new presence in energy markets, moving forward.

It is expected that new rule changes will be contemplated by the various sates’ Public Services Commissions, Public Utility Commissions, ISOs and RTOs that operate and manage wholesale energy markets. It will be important to monitor how the stakeholder groups and committees at the ISO/RTO levels address DERs and their participation factor(s) in these markets. This rule is intended to result in lower energy costs for ratepayers, increase reliability and resiliency on the grid, as well as fostering a more innovative approach to addressing generation resources in wholesale energy markets. Overall, this is an impactful filing and it poses a great opportunity for DER owners and aggregators.

Discussions
Matt Chester's picture
Matt Chester on Nov 5, 2020

It will be important to monitor how the stakeholder groups and committees at the ISO/RTO levels address DERs and their participation factor(s) in these markets.

Should we expect these developments to take place pretty quickly, or will the timing vary region to region? 

JC Culberson's picture
JC Culberson on Nov 5, 2020

Thank you for your question, Matt! The ISO/RTOs have 270 days to complete their tariff and compliance filings (past the initial 60 day period), so I think we can expect some market changes to be discussed in stakeholder groups, as well as NERC and Regional Entity committees, very soon. There is already chatter from NERC regarding DERs and the role they play in the reliable operation and planning of the Bulk Electric System. I believe we will see some impactful movement soon, barring any legal filings to appeal the ruling.

JC Culberson's picture
JC Culberson on Nov 11, 2020

NERC has a DER modeling data guidance document in the commenting period now through the middle of December. Additionally, FERC allowed 270 days past the order's posting for compliance filings by the grid/market operators. I think we can expect DERs to become more prevalent in the coming year.

Richard Brooks's picture
Richard Brooks on Nov 5, 2020

Matt, it sure would be nice if all of the ISO/RTO's could agree to a  common set of standards so that DER Aggregators can participate in all markets without having to tweak their systems to address regional differences.

JC Culberson's picture
JC Culberson on Nov 5, 2020

I agree with you, Richard. Unfortunately, I believe we will probably expect each region and ISO to apply the services differently. I think we will see as much diversity in the rules as we currently see in the markets, as applicable to ancillary services, Demand Response, etc. The market rules PJM will use to manage a service is going to be slightly different than the rules and application of similar services in ERCOT.

Richard Brooks's picture
Richard Brooks on Nov 5, 2020

Thanks for your comments JC. I would hope that all ISO/RTO would be willing to cooperate in defining a standard definition and set of available grid services which a DER may offer for sale in whoelsale markets, which they can all refer to in their tariff filings, due 12/17/2021.REBA called out this conncern regarding differences across markets " different policy and market structures constrain options available to C&I customers to buy the renewable energy they want across markets in the
U.S. Large energy buyers of many types – from businesses, to cities, to higher-ed – are increasing their commitments to renewable energy, and at times are
making decisions about expanding or siting facilities based on access to renewable energy" I know that Hawaii has taken steps to define a set of services and their unique characteristics: https://www.hawaiianelectric.com/products-and-services/demand-response/rfp-for-grid-services-from-customer-sited-distributed-energy-resources

JC Culberson's picture
JC Culberson on Nov 5, 2020

Yet another reason to go to Hawaii!

Richard Brooks's picture
Richard Brooks on Nov 5, 2020

Amen to that JC.

Gary Hilberg's picture
Gary Hilberg on Nov 9, 2020

Standardization across ISO's will be difficult due to state regulations.  Just the different end use pricing drives dramatically different economics - retail pricing in Hawaii at 28 cents vs. 8-10 cents in the middle of the US.  Also the difference in vertically integrated utilities (Fl, GA, etc..) vs. deregulated in ERCOT and PJM.  Then the differences in de-regulated market structures - energy only ERCOT vs. capacity/energy PJM.    Here in ERCOT we are seeing dramatic short term energy price swings all year long now, Wind drops off line while fossil units are in outage and bulk energy prices swing from 1-2 cents/KWH to over $1.5/KWH.  More DER should dampen these swings but the rules will probably need to be different here vs. Hawaii, PJM, etc..

JC Culberson's picture
JC Culberson on Nov 10, 2020

I couldn't agree more, Gary.

Michael Wolf's picture
Michael Wolf on Nov 9, 2020

JC, you say that "the rule is intended to result in lower energy costs for taxpayers, increase reliability and resiliency of the grid ...". I can agree with the first part, that adding players to the wholesale market will naturally lower prices. I don't understand how this will increase reliability and resiliency, as those aspects have nothing to do with the wholesale market, but with other technical aspects of the grid, such as inertia, frequency regulations and voltage regulations. Do you believe this is the first step to opening the ancillary services market to other services, such as inertia?

JC Culberson's picture
JC Culberson on Nov 10, 2020

The procurement of energy from market mechanisms is how ISOs and RTOs ensure there is enough generation to serve load. In this respect, market functions are an integral part of the reliability and resiliency of the BES. By introducing MW from DERs is another way of supplying load with MW that have been bid into the market. To answer your last question, I have no insight as to whether inertia will play any part in future market offerings or services, ancillary or primary; I just haven't heard anything about this.

Richard Brooks's picture
Richard Brooks on Nov 12, 2020

Inertia is a "ride through" capability tied to a disturbance event. Newer DER standards, such as IEEE 1547-2018, are defining the need for DER ride through requirements. PJM now refers to "synchronized reserve", which appears to be an alternative, but equal, capability to spinning reserves.

JC Culberson's picture
JC Culberson on Nov 13, 2020

I realize what inertia is, I just haven't heard of inertia as a market service. Spinning reserves and non-spin reserves are common in most, if not all markets. Ride through requirements will likely be tied to a disturbance, as you stated, and will apply to voltage and frequency. Both are addressed in NERC standard PRC-024, which calls out the "no-trip zone" for generation resources. Voltage ride through and frequency ride through parameters will likely be required for DERs, as well as all other generation types. 

Richard Brooks's picture
Richard Brooks on Nov 14, 2020

JC, Hawaiian Electric lists inertia as a grid service on their grid services framework:

Inertia

Contribution to the capability of the power system to resist changes in frequency by means of an inertial response from a generating unit, network element or other equipment that is electromagnetically coupled with the power system and synchronized to the frequency of the power system.

The industry is moving away from "spinning reserves" to "synchronized reserves", from the materials I've read recently "the Commission has approved a single, consolidated product for
synchronized (or spinning) reserve in every other jurisdictional RTO/ISO in the United States"; FERC PJM filing

Michael Wolf's picture
Michael Wolf on Nov 15, 2020

Thank you for your responses. Adding additional generation assets will allow a RTO/ISO the flexibility to manage their generation vs. demand, and thereby maintain their frequency regulations. I am specifically referring to the decline in synchronous reserves (rotating mass) and increase in non-synchronous sources (solar and wind). Even IEEE 1547:2018 doesn't resolve this issue, and only has a small clause regarding inertial response which is voluntary. The lack of inertia on the grid will be a big issue in the future. The UK and Australia are already taking steps to try and prepare for this by buying inertia reserves. Is there any talk about this in the US, at any level from the FERC down?

Howard Smith's picture
Howard Smith on Nov 16, 2020

An issue that will need to be address is who will be responsible for the communication equipment and control of these resources.  Will the RTO/ISO have this control or the local distribution system or the aggregator/customer?  In addition, will the state commissions have oversite for resources that may be included in state programs for DERs?  Also, their will need to be provisions for physical and cybersecurity for these DER resources.  Another potential concern is - will any of these resources fall under the CIP requirements.  Former FERC Commissioner has noted that under certain curcumstances DERs that replace transmission projects that were CIP requirements would fall to the DERs and their owners.  If this occurs, this could represent significant costs and reporting requirements.   I look forward to seeing how these issues are addressed.

Richard Brooks's picture
Richard Brooks on Nov 16, 2020

I agree Howard, there are a lot of dragons to slay before we reach a stable state in the energy transition. But, there is no place else I would rather be putting my energies and contributions. This is an historical time for the industry; a new epic is emerging.

JC Culberson's picture
Thank JC for the Post!
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