Who will be paying for the impacts of on both distribution and transmission systems of widespread DER penetration, whether it is in the form of DER Aggregations under Order No. 2222, state-jurisdictional net energy metering (NEM), or stand-alone DERs (often PURPA facilities)? And, who will decide who bears such costs – FERC or state commissions? These are questions that need to be answered over the coming years. Likely, the answers to these questions will be inconsistent across the states and disputes regarding cost allocation as well as jurisdictional could occur. Although the cost allocation disputes over NEM have been increasing in number and intensity, they have remained largely within individual states. With DER Aggregations, non-NEM DER participations, and Reliability Standards involving invertor-based DERs, such disputes should involve more, and more complex, issues.

The fact FERC and the states share some jurisdiction over distribution service, as well as jurisdiction over DER programs varying based on the programs’ characteristics, both create a bit of a jurisdictional quagmire as to who determines how costs imposed on utility distribution companies (UDCs) and transmissin owners/providers will be allocated. Although some utilities are taking matters into their own hands, seeking to recover significant distribution system modernization costs in retail rate cases, how and whether DERs participating in FERC-jurisdictional programs, such as DER Aggregation or FERC-jurisdictional sales, will contribute to the recovery of costs that their market participation causes remains unclear. Similarly, whether and how IBR-DERs, and most DERs are IBR-DERs, will bear costs of transmission system impacts of their aggregate adoption is likewise murky.

FERC has been largely silent on who even has jurisdiction over the cost of analyzing the reliability impacts of DER Aggregations under Order No. 2222 on the distribution system of a UDC. Impacts of DER Aggregations on transmission systems may be rare, but raise similar questions. One of FERC’s most recent NOPRs, Invertor-Based DERs and Transmission System Reliability, implicates cost questions, but never answers them. For example, will all transmission customers, or all distribution customers, bear the costs of NERC compliance associated with IBR-DERs, or will it depend on who is incurring such costs – UDCs or transmission owner/providers?

This article explores a few of the areas where many answers surrounding cost and jurisdiction seem lacking.

Order No. 2222 and Distribution System Reliability Costs

In Order No. 2222, FERC shifted jurisdiction over all interconnection of DERs in Aggregations (other than those DERs who were interconnected under FERC jurisdiction and decided to stay that way) to the states. Thus, the interconnection of individual DERs would be subject to either existing, new, or modified UDC interconnection procedures, some of which procedures are state-regulated. A sampling of such state-regulated procedures, often first drafted in the context of PURPA implementation, indicate that it is typical to allow the utility to charge for needed studies and analysis, as well as interconnection costs, with some variation, depending on the nature and size of the DER and the DER’s business plans.

But, Order No. 2222 also permits “incremental” analysis of DERs that are aggregating. Under Order No. 2222, RTOs/ISOs must coordinate with UDCs to develop a distribution utility review process that includes criteria by which the UDCs would determine whether the participation of each proposed DER in an Aggregation will pose significant risks to the reliable and safe operation of the distribution system. Despite this mandate, FERC has now found in several Order No. 2222 compliance orders in which UDCs must develop such criteria for DER Aggregations, it is unclear who has jurisdiction over this “second” reliability analysis and the costs associated with applying it to DER Aggregations where the UDC is FERC-jurisdictional. (One of Order No. 2222’s very few mentions of how costs imposed by DER Aggregations should be allocated related to a finding that it may also be appropriate, on a case-by-case basis, for UDCs to assess a wholesale distribution charge on DER Aggregators and this process could be a FERC-jurisdictional vehicle for the analysis.) But, it remains somewhat unclear who has jurisdiction over the costs associated with DER Aggregation reliability analysis and any costs to upgrade distribution systems due to DER Aggregations.

Since DER Aggregation already was permissible in CAISO and NYISO prior to Order No. 2222, UDCs there might provide answers, but if any UDC DER Aggregation reliability review processes have been established by such utilities, they are not readily locatable. Most state commissions have not even started to consider the issue of studying or analyzing DER Aggregations, whether inside the state interconnection process context or in a broader context. A few states – Missouri, California, and Indiana – have opened rulemakings or passed laws that will examine Order No. 2222 potential impacts, but progress is slow. Indeed, some state commissions have remained focused on other DER issues. For example, in September 2021, the Massachusetts commission decided to not investigate investments driven primarily by future compliance with FERC Order 2222 in a proceeding involving UDC Grid Modernization Plans. 

Here are just a few cost allocation/recovery issues that could arise:

  • Does a FERC-jurisdictional UDC need FERC permission to collect fees for a FERC Aggregation reliability analysis, if the analysis is outside the state interconnection context?
  • Who will bear the costs UDCs may incur to modernize or enhance their distribution grids to accommodate Order No. 2222, if Order No. 2222, as opposed to state NEM programs, is the cause of modernization need?
  • If states allocate grid modernization costs to DER-owners selling at wholesale and DER Aggregators, how and who will perform such allocation?

One interesting note on this topic, the Kentucky PSC actually found recently in a NEM proceeding that participation in wholesale power markets by DERAs is likely to increase the cost to serve customer-generators and that NEM rules may need to discourage participation in DER Aggregations.

Order No. 2222 and RTO/ISO Transmission Reliability Costs

In Order No. 2222, FERC says very little about the DER Aggregation application process, other than the fact it would involve coordination with the relevant UDC and coordination with the retail regulatory authority (RRERA). The RTO/ISO was tasked with certain activities regarding reliability, although the issue of the impact of DER Aggregations on transmission system reliability was largely overlooked. FERC found that coordination between RTOs/ISOs and UDCs should ensure that RTOs/ISOs have the information that they need to study the impact of DER Aggregations on the transmission system. There were no specific processes mandated with regard to how or whether an RTO/ISO should study or review the impacts of a DER aggregation on its transmission system for reliability purposes.

The Order No. 2222 compliance filings generally include application processes and procedures, but with little focus on any ISO/RTO reliability analysis or payments for the same by a DER Aggregator (DERA). RTOs/ISO seemingly have imposed no fees associated with DERA registration (beyond existing registration fees for market participants), or explained what would happen if a UDC identified a transmission system reliability issue that would cause the need for an upgrade.

Perhaps DER Aggregations, in states where they do form, will rarely if ever cause transmission system costs, such that this question will rarely arise. But if an aggregation does have transmission cost implications, who should seek cost recovery and through which regulator, remains unclear, particularly if the impact is found by the UDC. It is possible that any transmission system cost impacts will be identified in the state-jurisdictional interconnection process, rendering the ISO/RTO an “Affected System.” State interconnection processes thus should address the need for Affected System upgrades on the interconnected transmission system.

Invertor-Based DERs and Transmission System Reliability Costs

FERC has issued a NOPR on gaps in NERC’s Reliability Standards relating to IBRs, which NOPR is focused, in part, on IBRs connected at the distribution level. FERC preliminarily found that the existing NERC Reliability Standards may not provide Bulk-Power System planners or operators with the tools necessary to plan because IBR-DERs, when acting in the aggregate, can have a material impact on the reliable operation of the Bulk-Power System. According to FERC, the Reliability Standards should ensure that validated planning and operational studies assess the reliability impacts on Bulk-Power System performance by IBR-DERs in the aggregate. FERC expresses concern in the NOPR about modeling, such as whether UDCs are communicating to planners and operators concerning IBR-DERs in the aggregate for modeling purposes, including settings, configurations, and ratings. FERC notes that the existing Reliability Standards do not require the provision of data that represents IBR-DERs in the aggregate, at a sufficient level of fidelity for planners and operators to accurately plan, operate, and analyze disturbances on the Bulk-Power System. 

Proposed solutions impose new requirements on UDCs such as providing validated models of IBR-DERs in the aggregate to planning coordinators for interconnection-wide planning and operational models. Another proposal is to require UDCs that have IBR-DERs to provide to planning coordinators, transmission planners, reliability coordinators, transmission operators, and balancing authorities models accurately represent the dynamic performance of IBR-DER facilities in the aggregate, including momentary cessation and/or tripping, including all ride-through behavior (e.g., IBR-DERs in aggregate modeled by interconnection requirements performance to represent different steady-state and dynamic behavior).

What is missing from the NOPR is any discussion of costs, cost allocation, and jurisdiction. In fact, the words “cost” and “expense” are not mentioned at all. For example, what if the UDC is not affiliated with any Transmission Owner (e.g., Consumers Energy, DTE, etc.) and it is incurring costs under the new standards, is such a UDC allocating compliance costs only to distribution customers, largely under state jurisdictional rates? If the Transmission Owner in such a scenario is having to expend money to address an unaffiliated UDC’s IBR-DERs transmission-system impacts, it would seem FERC has jurisdiction over who pays those costs in the first instance – but, that does not answer the question of who should pay such costs. Another important question is what if NEM tariffs prevent allocation of costs to the very IBR-DERs owners causing the need to collect and model data; is it fair to require non-participating retail customers to bear such costs? Can IBR-DERs in NEM programs and other IBR-DERs be treated differently as to cost allocation? Questions abound.

The scope of IBR-DERs with which FERC is concerned also is not mentioned in the NOPR, which scope could have a significant impact on cost allocation. Most importantly, an IBR connected to the distribution system, i.e., an IBR-DER, could include behind-the-retail-meter (BTM) IBR-DERs, which has profound consequences for cost allocation, particularly where those customers with BTM IBR-DERs are largely NEM residential customers. If FERC adopts Reliability Standards that requires UDCs to expend millions of dollars to implement the NOPR and to address the existence of IBR-DERs, it is rather important to understand which IBR-DERs’ data must be aggregated, if a UDC and Transmission Owner are going to allocate costs on a causation basis, rather than simply roll in the costs of such expenses to all customers. For example, a cost-allocation line could be drawn between IBR-DERs that do and no not participate in wholesale markets. Such a cost allocation line would be appropriate if FERC is only asking for data in the NOPR on IBR-DERs that participate in wholesale markets. That said, such a set of data may be meaningless from a reliability standpoint if the overwhelming majority of impacts on the Bulk Power System are actually related to NEM customers with IBR-DERs. If IBR-DERs are selling under PURPA, that law presents another complex jurisdictional situation regarding to whom and by whom costs could be allocated. If FERC simply expects all customers that pay for distribution or transmission service to bear IBR-DER-related Reliability Standard compliance costs – which is a possibility – the link to cost causation is broken.

In sum, clarity does not exist at this time as to many interesting and complex questions involving various DER programs.

Fifth and final post on the Order No. 2222 compliance filings issued on June 17, 2022: “CAISO 2222 Order” and the “NYISO 2222 Order.” The post covers the topics: Modifications to List of Resources in Aggregation; Market Participation Agreements; and Effective Date.

Topic 10: Modifications to List of DERs in Aggregation

In Order No. 2222, FERC required each RTO/ISO to establish market rules that address modifications to the list of DERs in a DER Aggregation. The Commission ruled that any modification re-triggers the Distribution Utility (DU) review process, although that review could be abbreviated. FERC urged abbreviated procedures especially for an exiting DER.

This issue was not discussed as to the CAISO.

The NYISO was ordered to correct wording that allowed DU review of only incremental modifications to an Aggregation, rather than to review any modification; this correction may just be a matter of semantics.

Topic 11: Market Participation Agreements

Each RTO/ISO must establish market rules that address market participation agreements for DER Aggregators that defines the DER Aggregator’s role and responsibilities and its relationship with the RTO/ISO. The Commission stated that this market participation agreement must include an attestation that the DER Aggregation is compliant with the tariffs and operating procedures of the DU and the rules and regulations of any retail regulator (RERRA). The market participation agreements could not limit the business models under which DER Aggregators can operate.

This issue was not discussed as to the CAISO.

The NYISO’s use of its existing Service Agreement under the Services Tariff was accepted with a fix to the attestation. NYISO’s proposed attestation required the Aggregator to attest that the DU and RERRA have authorized the individual facilities and Aggregation to participate in the wholesale markets. FERC found that the attestation should instead address compliance with the tariffs and operating procedures of the DU and rules and regulations of any RERRA.

Topic 12: Effective Date

FERC required each RTO/ISO to propose a reasonable implementation date, together with adequate support explaining how the proposal is appropriately tailored for its region and implements Order No. 2222 in a timely manner.

CAISO requested an effective date no later than November 1, 2022 for the proposed Tariff sections that pertain to heterogeneous DER Aggregations, and for all other proposed Tariff revisions, CAISO requested an effective date contemporaneous with the Commission’s approval of its Tariff revisions. FERC accepted this proposal.

The NYISO’s proposed implementation timeline in the fourth quarter of 2022 also complied with Order No. 2222. NYISO also had to file a proposed effective date by which it will allow DERs in heterogeneous Aggregations to provide all of the ancillary services that they are technically capable of providing through aggregation. This proposal was accepted

The effective date issue was not at all controversial as to these ISOs because they were immediate/relatively soon, which was expected given their existing Aggregation programs. Other RTO/ISO proposed effective dates, i.e., MISO in particular, already have proven far more controversial.

Fourth post on the Order No. 2222 compliance filings issued on June 17, 2022: “CAISO 2222 Order” and the “NYISO 2222 Order.” The post covers the topic: Coordination between the RTO/ISO, Aggregator, and Distribution Utility.

Topic 9: Coordination between the RTO/ISO, Aggregator, and Distribution Utility (DU)

Role of Distribution Utilities

Under Order No. 2222, RTOs/ISOs must establish market rules that address coordination between the RTO/ISO, the DER Aggregator, the DU, and the retail regulator (RERRA) that should not create undue barriers to entry for Aggregations but must consider the substantial role of DUs and RERRAs. The rules have to include a comprehensive and non-discriminatory process for timely review by a DU of the DER Aggregation, triggered by initial registration of the DER Aggregation or changes to a DER Aggregation already participating in the markets. RTOs/ISOs have to coordinate with DUs to develop a DU review process that includes criteria by which the DUs would determine whether: (1) each proposed DER is capable of participation in a DER Aggregation; and (2) the participation of each proposed DER in a DER Aggregation will not pose significant risks to the reliable and safe operation of the DU’s distribution system.

FERC expected RTOs/ISOs to include potential impacts on distribution system reliability as a criterion in the DU review process, referring specifically to any incremental impacts from a DER’s participation in a DER Aggregation that were not previously considered by the DU during the interconnection study process for that DER (if any). To the extent a DU recommends the removal of a DER from an Aggregation due to a reliability concern, an RTO/ISO should not remove the DER without a demonstration by the DU that the DER’s market participation presents a threat to distribution system reliability. Dispute resolution provisions also had to be included in compliance filings.

These requirements have proven somewhat divisive and difficult to implement, due to jurisdictional issues and RTO’s/ISO’s lack of experience with distribution system operations.

The CAISO largely complied with the many requirements imposed, but flaws were found (one “flaw” regarding dual NEM and DER Aggregation participation was addressed by a prior posting). More generally, FERC found that the CAISO did not have the expertise and jurisdiction to set DU safety and reliability criteria but encouraged the CAISO to coordinate with stakeholders to develop guidance documents that list relevant criteria and operating parameters. The CAISO also needed to clarify that the scope of DU review of an Aggregation is limited to any incremental impacts that the DU has not previously considered in interconnection analysis.

The CAISO also was required to share with each DER Aggregator any information regarding a DER that is provided by a DU to the CAISO as part of the DU review process. Likewise, each RTO/ISO must share any necessary information and data on each DER with the DU.

Lastly, the CAISO’s deferral of disputes to the DU and RERRA was rejected because it did not provide a formal mechanism for interested parties to attempt to resolve any issues related to the DU review process with the CAISO. That said, FERC recognized that the CAISO cannot resolve issues that are beyond its authority.

NYISO was ordered to clean up some minor wording issues and several other flaws were identified with its DU review process. NYISO did not address the requirement that the results of a DU’s review be incorporated into the DER Aggregation registration process. NYISO did not include in its tariff the capability criteria by which DUs will determine whether each proposed DER is capable of participating in a DER Aggregation. Also lacking were criteria by which the DUs will determine whether the participation of each proposed DER in a DER Aggregation will not pose significant risks to the reliable and safe operation of the distribution system, but FERC found that NYISO is not in a position to dictate the specific evaluation criteria to be considered by the DU because NYISO lacks the expertise and authority to do so. FERC encouraged NYISO to develop guidance documents that could include a set of illustrative review criteria. Like CAISO, NYISO had to ensure DU review criteria focused on incremental impacts that the DU had not previously considered in any interconnection studies.

NYISO failed to propose to require that the DU provide a showing that explains any reliability findings. FERC also clarified that a DU could not indefinitely toll expiration of the 60-day review period by being non-responsive. The NYISO data sharing process also had to be clarified. FERC indicated that as to disputes over the substantive determinations that a DU makes about reliability and safety on the distribution system, parties must resolve such specific disputes before RERRA, not before NYISO, a ruling that seems somewhat at odds with the ruling on dispute resolution in the CAISO 2222 Order.

Ongoing Operational Coordination

Order No. 2222 required each RTO/ISO to revise its tariff to: (1) establish a process for ongoing coordination, including operational coordination; and (2) require the DER Aggregator to report to the RTO/ISO any changes to its offered quantity and related distribution factors that result from distribution line faults or outages. It also required each RTO/ISO to revise its tariff to include coordination protocols and processes for the operating day that allow DUs to override RTO/ISO dispatch of a DER Aggregation in circumstances where such override is needed to maintain the reliable and safe operation of the distribution system. The order required each RTO/ISO to revise its tariff to apply any existing resource non-performance penalties to a DER Aggregation when the Aggregation does not perform because a DU overrides the RTO’s/ISO’s dispatch.

The CAISO did not sufficiently address data flows and communication between the DER Aggregator and the DU. This finding was a bit confusing because the CAISO had explained that communication would be between the DU and the Scheduling Coordinator for the DER Aggregation. FERC also found it unclear whether CAISO’s reference to DUs’ limitations or operating orders only include planned or forced outages, or a broader range of potential actions such as limiting injections into the grid for a particular time.

As to the NYISO, it neglected to specify the existing non-performance penalties that would apply to an Aggregation when a DU overrode NYISO’s dispatch. The NYISO, like the CAISO, did not sufficiently address data flows and communication between NYISO, the Aggregator, and the DU.

Given the often real-time nature of operational issues, some of FERC’s requirements appear unimplementable as drafted, an issue not really addressed by the filings or orders.

Role of Relevant Electric Retail Regulatory Authorities

Through Order No. 2222, FERC required each RTO/ISO to specify in its tariff how each RTO/ISO will accommodate and incorporate voluntary RERRA involvement in coordinating the participation of aggregated DERs. Possible roles and responsibilities of RERRAs in coordinating the participation of DER Aggregations in RTO/ISO markets could include: developing interconnection agreements and rules; developing local rules to ensure distribution system safety and reliability, data sharing, and/or metering and telemetry requirements; overseeing DU review of DER participation in Aggregations; establishing rules for multi-use applications; and resolving disputes between DER Aggregators and DUs over issues such as access to individual DER data. To the extent that metering and telemetry data comes from or flows through DUs, the Commission required that RTOs/ISOs coordinate with DUs and the RERRAs to establish protocols for sharing metering and telemetry data that minimize costs and other burdens and address concerns raised with respect to customer privacy and cybersecurity.

As to the CAISO, FERC found that that requiring DER Aggregations to comply with RERRA rules and regulations as the sole means for fulfilling the voluntary participation in coordination requirement was sufficient for compliance.

NYISO also requires each Aggregator to ensure that its Aggregation and the individual DERs within the Aggregation comply with all applicable rules and regulations promulgated by the RERRA. NYISO, however, was also directed to ensure that any information provided by the RERRA to NYISO about a specific DER Aggregation must be shared with the Aggregator.

Third post on the Order No. 2222 compliance filings issued on June 17, 2022: “CAISO 2222 Order” and the “NYISO 2222 Order.” This post covers the topics: Locational Requirements; Information and Data Requirements Metering; and Telemetry System Requirements.

Topic 6: Locational Requirements

Order No. 2222 requires each RTO/ISO to establish locational requirements for DER Aggregations that are as geographically broad as technically feasible. Each RTO/ISO must provide a detailed, technical explanation for its proposed geographical scope. This issue has become quite controversial, as many RTOs/ISOs have proposed only single node Aggregation.

Given that the CAISO is one of very few RTOs/ISOs proposing multi-nodal Aggregation, this issue was not discussed.

NYISO proposed that along with its Transmission Owners (NYTOs), on an annual basis, it will identify Transmission Nodes and associated distribution feeder lines to which individual facilities may aggregate and try to maximize the area of the distribution system covered while minimizing bulk power system reliability concerns. FERC generally accepted this proposal but found it lacking in detail. FERC found the NYISO Tariff insufficiently clear regarding how NYISO will identify or change its Transmission Nodes, as it did not include the criteria that it will use to establish Transmission Nodes or update them. FERC declined a request for a formal stakeholder process to map NYISO Transmission Nodes.

Distribution Factors and Bidding Parameters

FERC requires RTOs/ISOs to establish market rules that address distribution factors and bidding parameters for DER Aggregations, if multi-node Aggregations are allowed, in order to: (1) require that DER Aggregators give to the RTO/ISO the total DER Aggregation response that would be provided from each pricing node, where applicable, when they initially register their Aggregation, and to update these distribution factors if they change; and (2) incorporate appropriate bidding parameters into its participation models as necessary to account for the physical and operational characteristics of DER Aggregations. In addition each RTO/ISO with multi-node Aggregations must either: (1) incorporate appropriate bidding parameters that account for the physical and operational characteristics of DER Aggregations; and/or (2) adjust the bidding parameters of the existing participation models to account for the physical and operational characteristics of DER Aggregations. Given that only CAISO has proposed multi-nodal Aggregation, this issue was only relevant to it.

FERC found CAISO’s approach satisfactory in that Aggregators provide to CAISO distribution factors with each bid reflecting the total Aggregation response that would be provided from each pricing node and register default distribution factors in CAISO’s master file. And, Aggregators must submit the common bid components for supply resources, and bid components specifically needed for Aggregations, including the distribution factor, ramp rate, minimum and maximum operating limits, energy limit, and contingency flag. The CAISO submitted clear protocols for its requirements.

In short, the CAISO has presented a model as to how the FERC requirements for multi-nodal Aggregations should work, but it remains to be seen how common multi-nodal Aggregations will be in the other RTOs/ISOs. Continue Reading The First Order No. 2222 Compliance Orders (CAISO and NYISO):Part 3 – Topics 6-8 (Locational Requirements; Information and Data Requirements Metering and Telemetry System Requirements)

Second post on the Order No. 2222 compliance filings issued on June 17, 2022: “CAISO 2222 Order” and the “NYISO 2222 Order.” The post covers the topic Eligibility to Participate in RTO/ISO Markets through a Distributed Energy Resource (DER) Aggregator, which the Commission subdivided into several subtopics.

Topic 5: Eligibility to Participate in RTO/ISO Markets through a Distributed Energy Resource Aggregator

Participation Model

Order No. 2222 requires each RTO/ISO to establish DER Aggregators as a type of market participant and to allow them to register DERs under one or more participation models in the RTO’s/ISO’s tariff that accommodates the physical and operational characteristics of the DER Aggregation.

As to the CAISO, FERC largely accepted the CAISO’s use of its existing participation models, but took issue with its attempt to use its two existing DER Aggregation models for homogeneous demand response, as they were currently drafted. The flaws FERC found with the existing demand response Aggregation models were fairly minor. For example, one model had maintained a 500 kW minimum size threshold rather than the 100 kW threshold required by Order No. 2222. The other flaw was in the Distribution Utility (DU) review process, which was not Order No. 2222-compliant in the existing model. FERC indicated that it would allow the CAISO to tweak its existing demand response models to comply with Order No. 2222. The issues appear easily fixable. Because the CAISO does not run a capacity market and resource adequacy is controlled by the state, FERC rejected requests to enable DER Aggregations to provide resource adequacy as outside the scope of Order No. 2222.

NYISO proposed using its existing participation models, which FERC largely accepted. A point of contention was that NYISO’s proposal limited the ancillary services (i.e., regulation service and operating reserves) that a heterogeneous Aggregation can provide in scenarios where one or more DERs within that Aggregation is not capable of providing an ancillary service. FERC that held so long as some of the DERs in an Aggregation can satisfy the relevant requirements to provide certain ancillary services, the Aggregation as a whole should be able to provide the service. FERC afforded NYISO time to develop such a proposal to address NYISO’s reliability and visibility concerns. FERC also found protesters’ argument that DERs with the capability to inject energy should not be subject to buyer-side market power mitigation outside the scope of the proceeding.

In sum, FERC applied practical solutions to rather minor deficiencies in the existing DER Aggregation models already in use. Continue Reading The First Order No. 2222 Compliance Orders (CAISO and NYISO): Part 2 – Topic 5 (Eligibility to Participate in RTO/ISO Markets through a Distributed Energy Resource Aggregator)

On June 17, 2022, FERC issued its first two orders on Order No. 2222 compliance filings, the “CAISO 2222 Order” and the “NYISO 2222 Order.” Both ISOs had FERC-approved, pre-existing DER Aggregation programs (i.e., aggregation programs beyond Order No. 719’s demand response aggregation) in place prior to making their July 2021 compliance filings.  Given the length of the orders, blog postings in coming days will only cover several topics each; twelve overarching topics were identified and discussed in the NYISO 2222 Order, and seven of these same topics were discussed in the CAISO 2222 Order. The twelve topics, some of which have many several subtopics, as well as the section of Order No. 2222 in which they were addressed, are as follows:  1) Stakeholder Process (N/A); 2) Small Utility Opt-In (Order No. 2222 § IV.A.2); 3) Interconnection (§ IV.A.3); 4) Definitions of Distributed Energy Resource and Distributed Energy Resource Aggregator (§ IV.B); 5) Eligibility to Participate in RTO/ISO Markets through a Distributed Energy Resource Aggregator (§ IV.C); 6) Locational Requirements (§ IV.D); 7) Information and Data Requirements (§ IV.F); 8) Metering and Telemetry System Requirements (§ IV.G); 9) Coordination between the RTO/ISO, Aggregator, and Distribution Utility (§ IV.H); 10) Modifications to List of Resources in Aggregation (§ IV.I); 11) Market Participation Agreements (§ IV.J); and 12) Effective Date (N/A).

Overview.  Despite the fact that the two orders were addressing ISOs with pre-existing DER Aggregation programs, FERC found a fair amount of deficiencies in each compliance filing. That said, the vast majority of each of their proposals was accepted, i.e., the Applicants did far better than the protesters. Largely, most DER/DER Aggregator industry requests to do more, go further, add more optionality, and apply fewer tariff obligations/rules than are applied to other resources, were rejected. Requests for more explanation or detail, however, were often granted.

Likely due to the pre-existing aggregation programs, the investor-owned distribution utilities (DUs), who have no opt-out options due to state policies, largely only sought clarifications, which often were granted. The NYPSC and CPUC played little role in shaping these orders, a situation that may differ in some other regions, as the CPUC and NYPSC are highly supportive of Order No. 2222’s goals. In California, the large public power utilities are not part of CAISO, such that most public power entities can opt out and they remained fairly silent. In New York, NYPA and LIPA will be subject to Order No. 2222, and aligned with the investor-owned DUs. In contrast to California, NYAPP (i.e., small public power) was active in the compliance proceeding.

Both orders reflect that there is significant more work to do (particularly as to new business practices and manual updates) even for these entities who had existing DER Aggregation programs; the coordination and work required for a fully-compliant DER Aggregation program will take some time.

The most surprising impression was the degree to which FERC recognized, conceded even, that it had, in several cases, assigned tasks to RTOs/ISOs that they simply could not fulfill given their knowledge of distribution systems. The orders also reflect the clear jurisdictional tensions in Order No. 2222 and the problem with implementing the entire DER Aggregation program through only an ISO Tariff. There were a few issues here and there ripe for successful clarifications or rehearings (i.e., FERC not recognizing that the CPUC’s NEM program participants are compensated for ancillary services). Generally, FERC did not overstep its jurisdictional bounds and where it may have arguably overstepped them in Order No. 2222, FERC actually stepped back a bit (by relieving the ISOs of certain tasks). FERC still failed to solve the riddle of why Order No. 2222 does not explain FERC’s regulatory approach to DERs selling energy for resale in interstate commerce to DER Aggregators, particularly where the DER is not a QF eligible for an FPA regulatory exemption.

A discussion of the first four topics addressed in the orders follows: Continue Reading The First Order No. 2222 Compliance Orders (CAISO and NYISO): Overview and Topics 1-4 (Stakeholder Process; Small Utility Opt-In; Interconnection; Definitions of Distributed Energy Resource and Distributed Energy Resource Aggregator)

In May 2022, with some, but relatively little, acknowledgment in the trade press, the North American Energy Standards Board (NAESB), at the behest of the Department of Energy (DOE), Lawrence Berkeley National Laboratory (LBNL), and Pacific Northwest National Laboratory (PNNL), announced its intention to “create standardized, technology-neutral grid service definitions that can benefit both wholesale and retail electric market interactions” for DERs. According to a NAESB press release, “the NAESB standards development effort will promote more efficient wholesale and retail electric market operations while also advancing market utilization of distributed energy resources  The request proposes to build upon existing wholesale market structures by standardizing common grid service names, definitions, and performance characteristics that align with the market product taxonomies and definitions identified in the Federal Energy Regulatory Commission (FERC) Electric Quarterly Reports.” Purportedly, “the NAESB standard[s] will enable wholesale market operators to associate or classify existing market products with common grid services and support more efficient communications between market operators and market participants, such as generators, distribution system operators, and distributed energy resource aggregators.”

The NAESB press release raises some questions. The first rather obvious question is, given that FERC is housed within the DOE, why didn’t FERC join the referenced request to NAESB? Does FERC support the request? Is FERC going to order the six complying RTOs/ISOs to adopt any new taxonomy developed? Is NAESB going to incorporate its new taxonomy into its Business Practice Standards that FERC may later mandate the ISOs/RTOs adopt? Continue Reading NAESB Role in DERs and DER Aggregation: What Do FERC and the States Think?

On May 18, 2022, 235 self-described “consumer, anti-monopoly advocates, public interest and environmental organizations, and rooftop solar companies” (Petitioners), petitioned the FTC to exercise its authority under Section 6(b) of the FTC Act to study electric utility industry practices that they claim impede renewable energy competition and harm consumers (the FTC Petition) (link and press release).

Why did they make this filing? It appears that they did so to stave off actions by certain states to reduce compensation for energy produced by DERs under net energy metering (NEM) laws and policies.

The participants in the rooftop solar industry are on the verge of possible defeat, or a partial defeat, in their most important state, California. Even though NEM reform battles may eventually occur in most every state with NEM (it ended in a loss in Hawaii years ago), California matters most. And California’s regulators preliminarily have determined that the subsidies to NEM participants are too high. So, Petitioners hope that the can persuade three FTC Commissioners to assist them in quashing all efforts to reform “full NEM,” whether in California or elsewhere.

The concept of full NEM is simple. A retail customer produces energy from a DER (typically, but not always with on-site, rooftop solar panels) and the energy not consumed on site in real time is credited to the customer at the full retail rate. Thus, this means that the customer producing energy from rooftop solar that is not in excess of its total needs during the billing period gets paid a rate equal to the utility’s cost of energy plus the utility’s costs of transmission, distribution, back-up power, and much more. This compensation is many times higher than the amount paid for energy and capacity sold by solar and wind power developers selling to the market or bilaterally. (Note that no actual wind or solar power companies or their trade associations signed onto the Petition.) This over payment to NEM participants results in the costs of the utilities’ transmission and distribution system (as well as many other costs) being shifted from the NEM participants to other customers, generally from wealthier people with larger houses on which to put solar panels to power customers without. Currently, California has a closed (but ongoing) NEM 1.0 program (full NEM) and an open NEM 2.0 program (best characterized as “almost full” NEM). Continue Reading The FTC Petition – A Thinly-Veiled Attempt to Protect Full Net Energy Metering for DERs

In Order No. 872, FERC provided PURPA purchasers and other interested parties the opportunity to protest QF re-certifications if a “substantive change” was being made, although the Final Rule was less than perfectly clear as to what constituted a substantive change. FERC stated in Order No. 872-A that substantive changes that may be subject to a protest could include “a change in electrical generating equipment that increases power production capacity by the greater of 1 MW or five percent of the previously certified capacity of the QF or a change in ownership in which an owner increases its equity interest by at least 10% from the equity interest previously reported.” In response to a concern that the “substantive change” standard was vague, FERC responded that it intended to make a case-by-case determinations on what changes are substantive.

In Dalreed Solar, FERC declined an opportunity to expand its identification of examples of substantive changes. In the re-certification at issue, Dalreed Solar changed its net power production capacity from 20 MW to 40 MW, an obvious slam dunk of “substance,” although due to an earlier re-certification of its original proposed project from 40 MW to 20 MW, Dalreed Solar had a non-frivolous claim that the change was not substantive. FERC readily dismissed this argument and indicated that the proper comparison was between the last re-certification and the current one. Given that it ruled on this MW change as sufficient, FERC then declined to rule on whether other changes were substantive. Continue Reading Dalreed Solar – FERC Declines to Provide Additional Clarity as to QF Re-Certification “Substantive Changes” that Trigger Protest Rights, But Engages in a Same-Site Analysis

In its PURPA Reform Final Rule (Order No. 872), FERC mentioned the fact that the Idaho PUC had reduced the term of PURPA PPAs to two years (albeit there would be a perpetual new contractual obligation to purchase every two years). The Idaho PUC did so “based on its concern about fixed QF rates, and that the ability to require variable energy rates could lead to longer contract terms.” In fact, FERC mentioned this fact several times in Order No. 872, seemingly hoping that the PURPA reforms adopted would convince the Idaho PUC to permit longer terms for PURPA PPAs. FERC, however, never commenced an enforcement action against the Idaho PUC or opined in dicta that its two-year PPA term maximum was illegal. These facts render the recent dicta adopted in Magnolia Solar, LLC v. South Carolina Public Service Authority largely inscrutable.

There, Magnolia filed a petition for enforcement against Santee Cooper claiming that Santee Cooper was violating FERC’s PURPA regulations regarding a QF’s ability to form a legally enforceable obligation (LEO). Although FERC declined to initiate an enforcement action, FERC found that a LEO had been formed based on the facts: (1) Magnolia informed Santee Cooper that it was ready to “initiate next steps … for offtake/power sales” and Santee Cooper responded with a shell PPA; (2) the parties had discussions on numerous contractual terms and Magnolia moved forward on many critical steps for the project (i.e., lease agreements, zoning, required reports and studies, interconnection request, Form No. 556, obtaining financing); and (3) Santee Cooper provided a five-year avoided cost rate in a draft PPA and then Magnolia revised the draft for a 20-year avoided cost rate and submitted it to Santee Cooper.

The record was clear, however, that Santee Cooper would not negotiate PPA with a term of any greater length than five years. It had argued that there was no LEO because Magnolia refused to commit to any PPA with a term of only five years. Certainly, if the Idaho PUC can limit a PURPA PPA term to two years and face no FERC action in federal court, Santee Cooper, in its regulatory role, also should be allowed to limit PURPA PPAs to five years without any concern FERC would bring an enforcement action. Otherwise, FERC arguably would be acting discriminatorily. Thus, the import of the dicta in Magnolia Solar regarding the LEO seems somewhat meaningless. Continue Reading Magnolia Solar, LLC – What Does it Mean to Have a LEO, If a Self-Regulating Purchaser Is Permitted to Limit the Term Length of a PURPA PPA?