By RTO Insider Staff

CAISO, ISO-NE and NYISO look to be the pacesetters in opening the country’s organized electricity markets to greater participation by distributed energy resources, according to filings submitted to FERC on Monday.

The filings came in response to the commission’s request for information on how RTO/ISO interconnection processes accommodate aggregated DERs. (See FERC Sends DER Data Request to RTOs.)

In its Sept. 5 letter, which included 11 questions, FERC said it was seeking information in particular on distribution-connected DERs aggregated to participate in wholesale markets. The submissions provided a flavor of how disparate the treatment of DER aggregations across the markets is, an issue FERC will likely attempt to tackle in its rulemaking (RM18-9):

• CAISO, PJM, MISO and SPP said their interconnection processes do not differ based on whether the DER is a qualifying facility under the Public Utility Regulatory Policies Act. NYISO said QFs connecting to distribution facilities to participate in ISO markets are subject to the ISO’s interconnection procedures, regardless of whether the distribution facility is subject to a FERC-jurisdictional open access transmission tariff. ISO-NE said QFs selling all their output to the host utility follow state interconnection processes rather than the RTO’s rules.
• All the grid operators said their interconnection processes are the same for DERs seeking to participate in wholesale markets regardless of whether they are interconnecting behind a retail customer meter. CAISO said that DERs, by definition, must have points of interconnection on the distribution grid. ISO-NE said DERs seeking to inject power into the system are subject to its Tariff if the interconnection is to an OATT distribution facility and to the state interconnection process if connected to a non-OATT distribution facility. NYISO said behind-the-meter resources that only reduce consumption and are not injecting power are not subject to the ISO’s interconnection procedures.
• ISO-NE, NYISO, PJM and SPP said their interconnection process allowed studies for bidirectional service, although all but ISO-NE limited them to storage facilities. CAISO and MISO said they defer to the practices of the host distribution providers.
• None of the grid operators was able to provide definitive data in response to the commission’s request for the number of DERs in each footprint that directly participate in wholesale markets versus the DERs that don’t participate. All but PJM offered up some data, however:

1. • CAISO referred to state data showing that California leads the nation in distributed generation. Its more than 1 million solar projects had a combined nameplate capacity of 8,431 MW as of July 31.
   • ISO-NE said DERs participating in its wholesale markets consist of 1,649 MW of “settlement only” resources (generation assets of less than 5 MW that are often connected to the distribution system) and 3,813 MW of demand resources (price-responsive demand, energy efficiency, load management, BTM generation and storage that reduce end-use demand). Although it said it lacked “visibility” on DERs outside its markets, it estimated there are 1,975 MW of solar PV generation not participating. It said it lacked similar estimates for combined heat and power facilities and batteries.
   • NYISO said it had 3,678 facilities providing 1,431 MW of demand response capability and one BTM net generation resource as of July 31, 2018. For non-ISO resources, it cited data from the New York State Energy Research and Development Authority estimating there are about 90,000 BTM solar PV installations in the state with a capability of 1,479 MW. NYSERDA also has estimated there are 300 to 400 non-solar distributed generation facilities, primarily combined heat and power facilities and energy storage, totaling 200 MW.
   • MISO said the resources participating in its markets include DR resources (28 resources with a combined target demand reduction of 672.6 MW), load-modifying resources (7,326.5 MW) and emergency DR resources (66 resources totaling 2,163.3 MW). It said it had no data on what share of those resources are connected on the distribution versus the transmission system. (It noted that its LMR data includes transmission-connected generators beyond the scope of FERC’s queries). MISO cited the Organization of MISO States’ recent survey of utilities, which estimated almost 195,000 installations totaling 4,698 MW of DERs are not participating in the MISO market. (See OMS: 4.5 GW of Unregistered DERs in MISO.)
   • SPP said it has no DERs directly participating in its Integrated Marketplace, adding that it does not consider cogeneration facilities as DERs. It said it did not know how many DERs in its region are “part of the regulated retail environment.”

• None of the RTOs was able to provide data on what share of the distribution facilities within their footprints were subject to a FERC-jurisdictional OATT. MISO, however, said it will begin tracking facilities that provide wholesale distribution service “in anticipation of DERs.”
• All the grid operators said they were engaged with state or local authorities regarding the interconnection process for DERs or had done so in the past.

Below are individual summaries of the grid operators’ responses.

CAISO’s ‘Great Lengths’

CAISO offered a robust response in keeping with its status as one of the most advanced incorporators of solar and other renewable resources.

“CAISO and its participating transmission owners have gone to great lengths to ensure that distributed energy resources can easily access and participate in the CAISO’s wholesale markets for energy and ancillary services,” it said. “The CAISO Tariff allows distributed energy resources to access the wholesale markets quickly. The CAISO allows DERs to participate as standalone resources, aggregations and DR resources. The CAISO continually works to ensure that its Tariff keeps pace with emerging technologies and grid trends.”

The ISO has been conducting a stakeholder process since 2015 on energy storage and DERs (ESDER), which has generated three sets of Tariff changes. It is now in its fourth phase of ESDER development.

In 2016, FERC approved what the ISO called its “first-of-its kind” process that allows DERs too small to meet the ISO’s minimum capacity requirements — 100 kW for storage resources and 500 kW for conventional generators — to pool their resources and participate jointly in the CAISO market. The smaller resources can sell energy and ancillary services in CAISO as a distributed energy resource provider (DERP).

“Moreover, each CAISO transmission owner that is FERC jurisdictional and operates distribution facilities has a wholesale distribution access tariff (WDAT) with the express purpose of enabling DERs to interconnect to the distribution grid and still participate in the CAISO wholesale markets,” the ISO said. “These transmission owners actively participate in CAISO stakeholder processes and update their WDATs to remain consistent with the CAISO Tariff.”

A DER planning to participate in CAISO submits its interconnection request to its utility distribution company (UDC), with the applicable process set forth in the UDC’s tariff, the ISO told FERC.

“The UDC performs all of the interconnection studies and administers the interconnection process, including the construction of network upgrades to mitigate any impact on the distribution or transmission grids. If the DER seeks a deliverability capacity allocation to be eligible to provide resource adequacy capacity, the CAISO performs the deliverability studies and informs the UDC of the results.”

Before the DER goes live, it must complete CAISO’s new resource implementation process to analyze the resource in the ISO’s network model, register its scheduling coordinator and execute a participating generator agreement.

The process doesn’t change if the DER is a QF or if it connects behind a retail customer meter, CAISO said. Whether participating individually or through an aggregation, all DERs interconnect to the distribution system under the applicable tariff of the UDC.

The California Public Utilities Commission’s Rule 21 establishes the interconnection rules for state-jurisdictional utilities, requiring WDATs and DERs to mitigate any reliability impact on the CAISO grid.

CAISO said it doesn’t keep data on the number or capacity of DERs in its market.

“DERs execute the same participating generator agreement that transmission-connected resources execute, and the CAISO’s Master File and network models consider the voltage level of the point of interconnection, not whether that interconnection is considered transmission or distribution,” the ISO said. “Determining whether each participating generator is interconnected to the transmission or distribution grid would require significant time and resources.”

The ISO said “DERs’ ability to participate in the CAISO markets has been a settled issue in California for many years. Recent regulatory coordination efforts have focused on modern, complex issues like [distributed energy resources aggregation], multiple-use applications and accounting for net energy metering resources.

“In addition, the CAISO continues to pursue discussion with transmission owners, UDCs and local regulatory authorities on managing the transmission-distribution interface with a high volume of DERs.”

ISO-NE: DERs 19% and Growing

ISO-NE prefaced its response with a summary of DER participation in its markets, noting that its 7,437 MW of DERs account for about 19% of the region’s total electrical capacity, most of it solar PV and energy efficiency. The RTO projects that by the end of 2028, installed PV nameplate capacity will exceed 6,700 MW and energy efficiency resources will reduce summer peak load by about 5,400 MW.

The RTO urged the commission to “afford regional flexibility” in any final order.

Schedule 23 of the ISO-NE OATT governs interconnections of small generating facilities (20 MW or less).

ISO-NE said it coordinates with the relevant TO regarding the status of the distribution facility in order to direct the DER developer to the applicable interconnection process. New or increased generation interconnections of 5 MW or greater require a “proposed plan application.” Interconnections greater than 1 MW, but less than 5 MW, require a notification, unless the RTO determines the proposed plan will have a cumulative impact on facilities used for the provision of regional transmission service, in which case, an application is required.

The RTO requires an interconnection agreement for each POI, although each interconnection may include multiple units or devices. Two or more interconnection requests may be studied in a cluster if the conditions for clustering are triggered. Clustering is available when there is an interconnection queue backlog of two or more requests in the same part of the RTO’s transmission system and none of the requests will be able to interconnect without significant transmission upgrades.

ISO-NE does not allow a single interconnection request for multiple generating facilities. However, it permits aggregation of multiple points of interconnection and multiple units behind a single POI for DR resources and alternative technology regulation resources.

The entity responsible for processing the interconnection request is determined by the status of the facility to which the DER generating facility plans to interconnect. Facilities that are part of the administered transmission system — existing pool transmission facilities (PTF), non-PTF and distribution facilities governed by the OATT — are subject to the RTO’s interconnection procedures.

The interconnection studies assess the impact of the small generating facility’s interconnection on both the transmission and distribution systems of the interconnecting TO.

MISO: DER Interconnections ‘Untested’

MISO told FERC it doesn’t keep track of resources at the distribution level and couldn’t tell the commission the number or megawatt volume of DERs in its footprint.

The RTO said that, save for DR resources, it’s not home to many DER installations and that it “does not anticipate significant penetration levels in the near future.”

It said its existing interconnection rules only apply to DERs seeking to connect to distribution facilities that provide wholesale distribution service — which it deems as part of its transmission system for interconnection purposes. It noted that DERs must follow interconnection queue rules to participate in its capacity auctions.

“To date, however, MISO has not received nor processed a request from a DER to interconnect to such a facility. … The application of current rules to DERs remains untested in practice, and MISO’s responses consequently are to some degree hypothetical,” the RTO told FERC.

A connection to facilities that are not providing wholesale distribution service doesn’t require a trip through MISO’s interconnection queue. DERs would instead seek interconnection permission from distribution owners. In MISO, it’s left to distribution owners to determine and alert MISO as to whether an interconnecting DER would impact the transmission system.

MISO also said it has yet to receive any requests to interconnect aggregated DERs, nor does it yet have rules in place as to how it would study aggregations for interconnection.

The RTO noted it’s beginning work on a DER participation model with stakeholders and OMS and said its interconnection rules will likely require “carefully considered adjustments.”

“As MISO continues developing its DER aggregator participation model, MISO may reexamine the scope and applicability of MISO’s interconnection process under various scenarios,” the RTO added.

New Rules Pending for NYISO

NYISO prefaced its response by referring to its June 27 filing of proposed Tariff revisions to establish a new model allowing individual generating facilities located at the same bus to aggregate as a single resource to participate in the ISO markets (ER19-2276). (See NYISO Management Committee Briefs: April 24, 2019.)

Under the proposal, which is pending before FERC, an aggregation could consist of two or more generation, DR or DER resources with a maximum injection of 20 MW.

The proposal would expand the definition of “small generating facility” to include injections into the grid from generating units and energy storage of the same or different technologies located behind a single meter.

NYISO noted that DERs do not participate much in its markets currently except through DR programs that reduce the amount of energy that LSEs must obtain in the markets.

The ISO said it coordinates with TOs on a case-by-case basis to determine whether a proposed interconnection is to a distribution facility subject to the Tariff.

“The voltage of the facilities is not the sole criteria for making this determination,” it said. “While generally facilities 45 kV and above are considered transmission, and facilities below 45 kV are considered distribution facilities, this is not always the case.” How the TO operates its distribution system — whether radial or networked — is also important in this determination.

The proposed rules would also stipulate that generating facilities located at separate points of the grid may participate in an aggregation so long as all the facilities are electrically located at or downstream from the same transmission node.

The ISO said it will not perform additional studies based on an existing facility’s determination to participate in an aggregation, regardless of whether they were subject to the small generator interconnection procedures (SGIP), standardized interconnection requirements (SIR) or utility interconnection procedures.

NYISO said it anticipates a substantial increase in the number of existing and new distribution-connected generating facilities that will seek to participate in its wholesale markets.

“Once such generating facilities begin to enter into service and start making wholesale sales, they will trigger the distribution facility to which they are interconnected as subject to the commission’s interconnection jurisdiction going forward, which will increase the distribution facilities in New York subject to the commission’s jurisdiction for interconnections for purposes of making wholesale sales,” it said.

PJM: No Specific Aggregation Processes

PJM’s Tariff does not outline specific aggregation processes, so each FERC-jurisdictional DER would require its own interconnection service agreement. Those outside the commission’s authority require a wholesale market participation agreement. Tariff revisions would be required to accommodate aggregations of new and existing DERs at multiple points of interconnection, the RTO said.

The process for DERs interconnecting to both types is the same, PJM said, except that those seeking connection to non-jurisdictional facilities must execute any additional steps required by state regulators.

PJM said it has engaged in conversations with authorities in D.C. and several states — including Ohio, Pennsylvania and Michigan — regarding DER ride-through capability. The RTO produced a report comparing state interconnection procedures, including how they might apply to wholesale DER, with the help of state commissions. It also participated in Maryland’s PC-44 grid transformation proceeding, which “examined the applicability of Maryland jurisdiction to the interconnection of wholesale DER.”

Bidirectional service studies are only conducted for energy storage devices capable of charging from the grid. PJM also does not consider BTM generation as eligible for wholesale participation.

The RTO doesn’t keep track of how many DERs currently exist within the region, nor does it maintain data or estimates on which distribution facilities are subject to FERC jurisdiction versus those that are not.

DERs not Participants in SPP Markets

No DERs directly participate in SPP’s market, the grid operator said in its filing. The RTO said it would consult with the interconnecting utility and the appropriate TO to determine whether an aggregate or individual affected-system study would be appropriate.

“The affected-system study is strictly for the purpose of determining impacts to the SPP transmission system,” SPP said. It said it considers each interconnection point as a separate request, to be studied individually.

SPP said its Tariff allows individual DERs looking to join an aggregation to be studied under a cluster study, if the customer requests it.

“The DER’s decision to participate in an aggregation would not trigger the RTO/ISO interconnection process,” the grid operator said. “To the extent that the interconnecting utility determines that the aggregation would create the possibility that the DER could impact the SPP transmission system, the utility would have an obligation to inform SPP and to determine whether additional studies would be needed.”

The grid operator said distribution utilities would be responsible for determining whether proposed DER facilities are under SPP’s functional control and, if so, they would direct the customer to submit an interconnection request to the RTO. If the facilities are not under SPP control, the utility would determine whether there is a potential impact to the transmission system and notify SPP of the request. The RTO and interconnecting utility would jointly determine whether a study is necessary and which entity would conduct it.

If upgrades are required, SPP would tender an agreement to the customer for construction. The three-party construction agreement would be between SPP, the customer and the TO, which would own the upgrade. SPP would not be a party to any interconnection agreement.

Responding to FERC’s question on how it defines the physical boundaries of a distribution facility when determining whether it is already subject to SPP’s OATT for making wholesale sales, the RTO said its interconnection procedures only apply to facilities under its functional control.

“Any resource, regardless of whether it interconnects to the SPP transmission system or not, may make wholesale sales … as long as it meets the other requirements under the Tariff for market registration and transmission service reservations, as applicable,” it said.

The RTO said that whether energy storage resources are required to support charging activities would be determined by its interconnection study process, unless the customer indicates that it will not charge from the system.

If the facility is not an energy storage resource, the study process would only evaluate the effect of energy’s injection into the system. If the facility includes network load, it may be subject to the Tariff’s provisions for block-load additions, which is separate from the interconnection study process.

Asked how it would address individual DERs in an aggregation trying to interconnect to distribution facilities, some of which are subject to the Tariff, the RTO reiterated that only facilities under its functional control would be subject to its procedures.

Amanda Durish Cook, Rich Heidorn Jr., Tom Kleckner, Michael Kuser, Robert Mullin, Hudson Sangree and Christen Smith contributed to this report.