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The Maryland PSC has initiated a docket and issued a notice for comment concerning “retail grid services” including, but not limited to, implementation of virtual power plants (VPPs).

Excerpts from Workgroup Recommendations: 

{***} “In summary and on behalf of the Workgroup, I respectfully recommend that the Commission: 1. Expand the workgroup’s charge to also include VPP and V2G grid services implementation to facilitate achieving FERC Order No. 2222 and the DRIVE Act goals. 2. Establish a new docket for filings related to Workgroup activities. 3. Issue a notice requesting stakeholder comments on the foundational nonconsensus issues identified in this filing and on any other items the Commission should consider related to FERC Order No. 2222 implementation. 4. Provide direction to the workgroup on issues raised in these comments at a later date in 2025.

Foundational Non-Consensus Issues Within the Workgroup5 To date, the Workgroup has developed a set of draft regulations but is in need of Commission direction on several foundational non-consensus items before we can finalize a regulation proposal. Therefore, the Workgroup requests Commission direction on the following foundational issues: 

Scope of Maryland’s Initial VPP Implementation – PJM’s FERC Order 2222 implementation encompasses VPPs that participate in wholesale markets. The Workgroup is also pursuing regulations for VPPs that are harmonized with PJM requirements to the extent practical, that can participate in retail tariffs once they are developed. Workgroup stakeholders are not in agreement that a broader implementation of VPP regulations for retail grid services tariffs needs to be implemented at this time pending the implementation and evaluation of VPP pilot programs and tariffs required by the DRIVE Act. 

Proponents of a broader implementation of VPP regulations argue that FERC Order 2222 already addresses a future where the same VPPs can provide both wholesale and retail grid services, as long as there is no double-counting. In addition, these proponents also advocate that VPPs should be part of non-wires solutions to grid needs in the immediate future, as opposed to waiting until after the evaluation of DRIVE Act pilot programs to expand VPP implementation more broadly. 

DER Registration – Proponents of a common DER Registry in Maryland argue that there needs to be a single system that enables the appropriate stakeholders, including regulators, to have visibility into the appropriate set of information to know where DERs are, what they are, what they can do, or who owns them so that there is a “single point of truth” for a DER. Furthermore, these proponents argue that the electric industry is fractured by creating ‘silos’ of information and that we must have more effective collaboration on DER information in our industry to effectively integrate DERs more rapidly into the grid and markets as well as lower the cost of this significant effort for the entire industry. With the implementation of VPPs, these proponents advocate that there is a need to develop a platform to handle DER registration and data exchange. As an example, PJM is expanding its existing Demand Response Hub (DR Hub) to handle DER registration for implementation of FERC Order 2222, but there is no existing method for DER registration for future retail tariffs. Due to operational and data sharing concerns, electric companies prefer to maintain their own customized solutions and support PJM’s DR Hub requirements as needed. Proponents argue that customized solutions involving PJM’s DR Hub is problematic in that these same VPPs can potentially participate in both wholesale markets and retail tariffs, but this PJM DR Hub data is only available to electric companies. These proponents also argue that creating a common DER registry in Maryland will rapidly enable DERs, rapidly enable all competitive DER offerings where available, and speed the effective integration of DERs into our grid and market systems for all electric companies, regardless of market structure. Some other stakeholders advocate that these same benefits of a common DER registry can also be achieved by creating regulations that require that utilities capture common DER information framework and use the International Electrotechnical Commission (IEC) 61970/61968 Common Information Model (CIM) design to facilitate less costly and more efficient data transfer between applications where it is needed. While agreeing that we need a “single point of truth” for DER data to facilitate DER registration and settlements, other stakeholders feel that initiating a common DER registry will take a great deal of time and resources since this DER registry doesn’t exist today. These stakeholders instead advocate for using existing systems such as Green Button Connect to provide bulk API6 access between utilities, aggregators and the PJM DER Hub data so that all parties are getting the same data at the same time. 

Communications Protocols – Maryland has implemented an IEEE 1547-2018 smart inverter requirement effective January 1, 2024. IEEE 1547-2018 currently specifies three compatible DER communications protocols, IEEE 2030.5, DNP3 and Modbus. The California Rule 21 specifies IEEE 2030.5 for some communications with utilities, with certain exceptions. The Workgroup has started to explore IEEE 2030.5 internet alternatives for DERs and VPPs as the high cost of utility proprietary solutions is cited by some stakeholders as an interconnection obstacle. These Workgroup stakeholders believe that DERs and VPPs should not be unreasonably denied the ability to utilize less costly internet communications using IEEE 2030.5 as the default protocol and unless clear direction is given by the Commission, utilities will not start to move in this direction by developing and submitting implementation plans for Commission approval. IEEE 2030.5 is an application layer protocol for smart energy communications for the management of distributed generation, electric vehicles, etc. However, citing the lack of IEEE 2030.5 internet capable gateways, utilities plan to leverage secured private connections for DER and VPP interconnections, utilizing available protocols, including DNP3 or Modbus. Utilities have also expressed other concerns, including the need to build the necessary infrastructure to securely receive IEEE 2030.5 connections via the internet. 

Device-Level Submetering – Some Workgroup stakeholders have argued that there is a need to establish device-level metering, or submetering, for dispatchable resources that can be easily separated from other net energy metered resources located on the same premise. This will allow these devices to be separately compensated for providing grid services without requiring separate utility metered accounts. Recent technology advances have made a number of non-traditional metering solutions viable as submeters, as long as the submetering meets ANSI C12.1 accuracy provisions. For instance, electric vehicle charger submetering that is compliant with the National Institute of Standards and Technology Handbook 44 – 2023 Section 3.40. for Electric Vehicle Fueling Systems, inverter metering data or battery management system metering are all new viable methods of submetering dispatchable resources. PJM requires submetering to provide ancillary services with device-level submetering. 

Some Workgroup stakeholders advocate for a slower approach until various retail use cases for grid services are developed where submetering can be a benefit. In addition, the FERC rejected Tesla’s arguments to expand PJM submetering for wholesale markets in a July 25, 2024, order on PJM’s FERC Order No. 2222 compliance filing. Similar to communications protocols, utilities have expressed concerns about the need to build necessary infrastructure to securely receive submeter data and incorporate it into reporting and billing mechanisms.

Level of Customer Information Sharing with Aggregators – Aggregators have maintained that they need access to utility customer data in order to market and effectively provide VPP services. These aggregators would like to have access to this data in a timeframe necessary to meet any applicable PJM tariff requirements and also to support any applicable future retail tariff requirements. Furthermore, these aggregators desire that an electric company provide this information access using automated on-line tools and forms while ensuring data privacy through non-disclosure agreements while also meeting any applicable electric company cybersecurity requirements. Electric companies have generally opposed broad information sharing of utility customer data except for certain use cases, and with customer consent. Due to the legal and regulatory requirements regarding sharing of customer information, electric companies also have not agreed with providing automated on-line tools and forms to facilitate information sharing.” {***}

Non-Consensus Items include:

• Excluding a utility’s interconnection from the application process if it is “operated solely for the purpose of providing safe and reliable electric distribution service”; 
• Adding new definitions for “inadvertent export”; “net system capacity” (initially referred to as “net nameplate capacity”) and “proposed use”; 
• Removing listed fee amounts from the regulation (instead instructing them to be included in a tariff); • Raising the size of the smallest interconnection review category (i.e. Level 1) from 10 kW to 25 kW; and 
• Removing the prohibition of charging a fee to customers applying for a Level 1 interconnection.

Near-Consensus Items include: 

• Removing the current regulation’s jurisdictional restriction of projects over 10 MW, to fix a gap in the current regulation; 
• Adding a definition of “energy storage device” and including it throughout the regulations; • Modifying the “pre-application report” process; 
• Requiring utilities to publicly post information regarding the general characteristics and grid location of pending and recently approved interconnections; 
• Removing applications from the interconnection queue after a period of inaction; and 
• Updating data reporting requirements.

Consensus Items include: 

• Including updated standards from the Institute for Electrical and Electronics Engineers (IEEE); 
• Eliminating the requirement for formal Commission approval of utility interconnection forms (while including specific requirements), which will allow utilities to be more flexible in adapting forms for electronic completion; 
• Allowing an applicant’s designee to perform tasks electronically; 
• Allowing electronic signatures and tracking of applications online; 
• Defining the term “minor system modification” so that an applicant’s interconnection project can be reviewed as efficiently and cost-effectively as possible; 
• Removing the prohibition on utility monitoring and control of an interconnection system smaller than 2 MW, instead allowing monitoring or control either through customer consent or a holistic Commission-approved plan;
• Including a utility reporting requirement if actual costs for interconnection upgrades significantly exceed the cost estimate; and 
• Several minor language changes to modernize and clarify the text.

Notice Initiating A New Docket And Request For Comments (02/04/2025)
9778
(Interconnection Workgroup and the Implementation of FERC Order No. 2222 and Retail Grid Services in Maryland)
See also PC44
(In the Matter of Transforming Maryland’s Electric Distribution Systems to Ensure that Electric Service is Customer-Centered, Affordable, Reliable and Environmentally Sustainable in Maryland.)