FERC has issued its third and fourth orders on initial compliance attempts with Order No. 2222, covering PJM and ISO-NE. Many of the holdings reflected compliance policies similar to those adopted in the prior NYISO and CAISO orders (summarized previously Part 1, Part 2, Part 3, Part 4). This analysis thus will focus on unique findings, new precedent, and otherwise noteworthy matters.

PJM Compliance Filing Order

Double-Counting. It is remarkable that FERC made two unremarkable findings with regard to net energy metering (NEM) programs under which DER owners are compensated at the full retail rate. First, FERC found that such DERs cannot participate in PJM’s capacity market (largely due to the must-offer energy requirement, but perhaps also recognizing that they would be compensated twice for capacity under such a full retail NEM program). Second, FERC acknowledged that DER owners in full retail NEM programs actually are compensated for ancillary services that they do not even provide and that paying them for ancillary services, assuming they could provide them, would be double counting. The point that DER owners in full retail NEM programs could not possibly earn wholesale compensation in energy, capacity, or ancillary services markets that was not double compensation is a point electric distribution companies (EDCs) have made for years, but this is the first time that FERC has expressed a clear understanding that NEM participants already may be compensated for a large range of products, let alone acknowledged that participants are compensated regardless of whether or not they actually provide such services. Although further clarity will result on compliance, the decision reflects a breakthrough of sorts, as previously FERC refused to explicitly acknowledge that NEM customers in California might be receiving compensation for ancillary services. The fact that the Pennsylvania PUC expressed concern over double counting as to ancillary services in particular perhaps swayed FERC into recognizing the level of compensation offered by some NEM programs. (Of course, it is this level of NEM compensation that largely renders Order No. 2222 meaningless as to some DERs.)

EDC Review. The PJM decision also was notable as to the ferocity with which FERC rejected the notion of giving EDCs more than 60 days to review DER Aggregations, unless the RTO/ISO itself indicates exceptions may be necessary. Although PJM’s pre-registration process was not rejected, the role of the EDC in that process must be reformed and its clear that such process cannot include any EDC review, given PJM’s 60-day EDC review period that is part of the registration process.

Locational Requirements. FERC appeared disbelieving of PJM’s justifications for a single node approach for energy market participation and has sought a change or a better explanation. Given that several other RTOs/ISOs are seeking only single node aggregation, this issue likely will get more attention.

ISO-NE Compliance Filing Order

BTM DERs Metering and Double Counting. The proposed treatment of behind-the-meter (BTM) DERs drew quite a bit of attention from FERC, which found that ISO-NE’s proposal to require measurement of BTM DERs at the retail delivery point, unless the Assigned Meter Reader can accommodate submetering or parallel metering of the DER was not just and reasonable, as it created barriers to entry. Protesters had asserted that measurement at the RDP is a barrier to participation for BTM DERs because it obfuscates actual DER performance for purposes of wholesale market participation and that parallel metering is impractical and costly. ISO-NE argued that metering at the RDP, parallel metering, or submetering combined with reconstitution comprise the universe of metering options of which ISO-NE is currently aware that address double counting. In her concurrence, Commissioner Clements observed that “one comes away with the impression that developing a workable participation framework for behind-the-meter DER is nearly impossible.”

A closer examination of the issue, as relates to customers with on-site BTM DERs and retail load that are not participating in a demand response-only DER Aggregation, reveals that the ISO-NE is assuming that a BTM DER is participating in the wholesale market with its gross, rather than net, production. For example, in its pleadings, the ISO-NE made the point that paying behind-the-meter generator based on its directly submetered output while also billing the customer based on its lower RDP (i.e., retail) meter reading would result in double counting. This fact was the main reason behind ISO-NE’s metering proposal. But there is no double counting at all, if the BTM DER serves its on-site retail load first, and then sells its net output to the DER Aggregator. And, the BTM DER owner likely would ensure that the DER Aggregator can only dispatch the BTM DER to sell its net output. The ISO-NE instead assumes a BTM DER would choose to not serve its on-site retail load before selling any power to the wholesale market, an economically irrational decision unless wholesale market prices reach up the $100s/MWh. That is, BTM DERs are typically installed to reduce on-site load, with net energy (or other services) being sold at wholesale. The notion of a BTM DER selling its gross energy is illogical in nearly every hour of the year. (A BTM DER could be connected to an EDC that mandates a “buy-all, sell-all” structure (an unusual, but not unheard of approach that disallows all netting), but in that case, the proper metering would already exist.)

One question raised by FERC is why did other RTOs/ISOs seem not to have the same issue? There is no evidence that the issue of a BTM DER choosing to sell its gross production would not be a major problem in every other ISO/RTO (again, ignoring demand response BTM DERs). Rather, no other ISO/RTO has assumed the BTM DER is selling gross output, so the issue has not arisen. No one has needed to develop a framework for gross sales because presumably no one would take the economically illogical step of turning over control of their gross energy production to a DER Aggregator, if in nearly all hours, the retail price of electricity exceeds the wholesale price of any market service. Indeed, CAISO has had DER Aggregation for years, but due to net metering, where BTM DERs of all sizes may net, the DER Aggregation program is basically uneconomical for BTM DERs. In NYISO, BTM DERs would presumably sell their net output to the DER Aggregator, avoiding this issue. (And, there is evidence that the New York EDCs expect BTM DERs to choose this net option.)

In sum, the ISO-NE should be able to accommodate BTM DERs that own generators selling only net production, as is typical. If a BTM DER truly intended to sell on a gross basis, the ISO-NE is correct that the metering, billing, and accounting are all quite difficult absent an EDC that already prohibits all netting and meters accordingly. Of particular concern, if FERC believes that BTM DER owners should be able to switch between selling net production at wholesale to selling gross production at wholesale (i.e., selling gross when wholesale prices rise to the $100s-$1000s/MWh), such an approach inevitably would require either resource-intensive manual workarounds and/or expensive (and yet-to-be-developed) metering. Only if the BTM DER bore all such costs, would such approach be equitable to other retail customers. Perhaps ISO-NE explaining to FERC that BTM DERs that are netting on-site retail load can be accommodated could largely solve the perceived problem.

Although the above discussion does not apply to BTM DERs in the form of demand response, Order No. 745 seemingly already addressed the relevant issue. Under Order No. 745, in circumstances in which the net benefits test is satisfied, paying the LMP to BTM DERs participating as demand response resources, without reflecting the savings load realized from not having to purchase electricity, does not reflect a double payment, according to FERC. In contrast, under Order No. 2222, If the BTM DER resource participates as another type of DER (i.e., not as a demand response DER in an aggregation of only demand response DERs), the requirements in Order No. 745 would not apply. In the case of a heterogeneous aggregation, the same problem discussed above admittedly exists because the load served is not entitled to a highly significant benefit of Order No. 745. But, that fact merely raises the issue of why would a demand response DER participate in a heterogeneous DER Aggregation when far more favorable compensation is available through a homogeneous demand response DER Aggregation?

Clements’ Concurrence (ISO-NE)

Clements’ view is that participation of BTM DERs in ISO-NE markets is being completely stymied and reliability is threatened by the issue discussed above – an issue that may very well be non-existent. She mentions Massachusetts and other New England states having aggressive DER goals. One question raised by her dissent is whether Order No. 2222 is actually needed to meet these goals or whether these goals already are being met outside of Order No. 2222. According to the EPA’s State Energy and Environment Guide to Action: Interconnection and Net Metering, issued in 2022, Massachusetts “is a national leader in net metering policy and in the amount of total net metered energy sold back to the utility, which in 2020 was 717 GWh.” According to the EPA, this was “approximately 28 percent of all net metered energy sold back in the United States (EIA 2020).” Moreover, the ISO-NE adopted a new policy allowing small generators to serve as wholesale load reducers by not participating in the wholesale market. Commissioner Clements’ dissent ignores that Order No. 2222 is not the only way to encourage DERs. Indeed, many BTM DERs have state-mandated options that both provide more compensation and eliminate any middleman, and thus are more encouraging of BTM DERs than Order No. 2222. For now.

Christie’s Dissents

Commissioner Christie voted against both orders, despite voting for the CAISO and NYISO compliance orders. (One possible reason that he failed to dissent earlier is that CAISO and NYISO had adopted DER Aggregation voluntarily prior to Order No. 2222 being issued.) Commissioner Christie pointed out in his dissents that the problems and complexities of complying with Order No. 2222 are extreme and the costs enormous. His conclusion in the PJM order is that Order No. 2222 will haunt the RTOs and RERRAs, the reliability of the grid, and the pocketbooks of consumers for a very long time. Although legal/regulatory implementation costs are high, if states continue to use NEM, PURPA programs that ask EDCs to voluntarily pay above avoided cost rates, and other programs that provide more value to energy-producing DERs than the wholesale market, Order No. 2222 will be largely irrelevant. Costs may not be as high as feared if participation is largely non-existent. That said, there is a limit to the degree to which states can use such types of programs before cost shifting renders them unworkable and they are reformed so that DER owners are relegated to earning compensation that more accurately values the services they provide. (As noted, the Pennsylvania PUC quite unabashedly admitted that it pays DERs not only for energy, but for the transmission, capacity, ancillary services and distribution components of retail rates as compensation for the energy produced.) Once state-mandated DER compensation is more accurate, participation in the wholesale market through DER aggregation may become more appealing. But even smaller state subsidies, such as compensating NEM customers for excess energy under a value of solar program, may continue to pay well more than the wholesale market price, less a cut for a DER Aggregator.

One leaves the newest compliance orders with the impression that a fulsome understanding of the direct connections between state DER programs (including NEM), Order No. 745 demand response aggregation programs, and Order No. 2222 aggregations and how, whether, or why a DER may choose among such options does not yet exist. Given that there may be as many different such connections as there are states with at least one ISO/RTO member, renders obtaining such an understanding difficult. Such direct connection also may result in retail customers paying Order No. 2222 implementation costs when Order No. 2222 DER Aggregations will not be an option that is economically logical for DER owners.

Recently, the D.C. Circuit upheld FERC’s decision granting Broadview Solar’s application to become a QF in SEIA v. FERC. In doing so, the appeals court solidified FERC’s “send-out” capacity approach for determining QF status. The underlying case, Broadview, has been the subject of several prior blog posts, as the underlying FERC decisions reflect just how deeply political PURPA, and its application, have become. The decision in this case was quite likely to turn, in the first instance, on three jurists’ views on agency deference under Chevron, a judicial doctrine that has become highly politicized because of varying views of the role of the administrative state. The panel consisted of Circuit Judges Sentelle (a Reagan appointee, extraordinarily well versed in FERC, who has drafted or signed onto many important orders upholding FERC opinions based on Chevron deference, but who will rein in FERC when the agency exceeds its statutory bounds), Pillard (an Obama appointee), and Walker (a Trump appointee whose disdain for Chevron deference was on full display here). Walker’s claim that “[o]n the D.C. Circuit, Chevron maximalism is alive and well,” historically has been accurate, and only a rehearing en banc would indicate whether that tide has turned. There is no question the tide has turned at the United States Supreme Court. As discussed herein, it actually is shameful that this proceeding could result in a significant decision on Chevron deference, as it is Congress’ responsibility to address the many issues presented by PURPA, such as what is meant by “power production capacity,” before the law turns forty-five later this year.

The primary issue on appeal was whether the measure of relevant capacity under the statutory definition of small power production facility (limiting such QFs to 80 MW of power production capacity) should be based on how much power could be sent to the transmission system.  In finding that Broadview merited QF status, FERC took into account all of its components working together, not just the maximum capacity of one subcomponent, focusing on grid-usable AC power. Using the Chevron framework, the D.C. Circuit (1) agreed with FERC that the measure of “power production capacity” is ambiguous under PURPA Section 210; and (2) determined that FERC’s focus on grid-usable AC power was reasonable because it aligned with PURPA’s structure and purpose. The opinion explained that focusing on net output (rather than denying facilities QF status because a subcomponent exceeds 80 MW) advanced PURPA’s goal of promoting small power production facilities and the use of alternative energy sources. Finally, the court concluded that FERC’s interpretation aligned with legislative history regarding the meaning of power production capacity.

This opinion would have been wholly unremarkable, but for the first Broadview FERC order, which rejected forty years of FERC precedent and reflected a more textualist view of the statute. In his dissent, Circuit Judge Walker reached the same substantive outcome as was adopted in the first FERC order, that Broadview was too large to be a QF. He explained that PURPA Section 210’s mandatory purchase requirement is an extraordinary measure, which can force utilities to purchase above-market or unnecessary power and pass on costs to consumers. He noted that the broader the definition, “the greater the number of power plants that get special regulatory treatment.” Next, Judge Walker focused on how narrowly Chevron deference should be applied, explaining that courts must try every tool of statutory construction before declaring the text ambiguous and proceeding to agency deference. He agreed with Justice Kavanaugh that the court will almost always reach a conclusion about the best interpretation of the statute, resolving any ambiguity. Walker then focused on the fact that Broadview’s facility can produce 80 MW for its inverters (to sell), while it simultaneously produces 50 MW for its battery to store, such that it is too large to be a small power production facility.

This case can be appealed, or a rehearing en banc may be requested, and thus its ultimate conclusion is unknown. Moreover, theD.C. Circuit is unlikely to be the last word on power production capacity because the D.C. Circuit likely will not be the first choice of another utility aggrieved by identical facts. Putting aside the threshold question of whether PURPA is ambiguous and Chevron has relevance to any judicial analysis of the issue, Congress can and should dictate the future of PURPA policy. The mere existence of this the case reflects a failure by Congress to reconsider innumerable aspects of PURPA, but for one significant change in the Energy Policy Act of 2005. Indeed, the majority’s focus on Congressional intent and encouraging renewables up to 80 MW in size is rather ironic given that in 2005 Congress passed a law such that for a huge swath of the country, small power production QFs now must be under 20 MW or 5 MW to obtain a PURPA contract from a utility. And, the relevant industry changes that have occurred between 2005 and 2023 arguably dwarf the industry changes that occurred between 1978 and 2005. In the nearly two decades since the Energy Policy Act of 2005 somewhat limited PURPA’s reach, profound changes have occurred in the electric industry with regard to renewables. Such changes include reductions in the cost of renewable power, technological advances in storage, and the widespread adoption of mandatory and voluntary renewable mandates.

It is actually astounding that a law driven by an industry largely fueled by oil and coal, drafted in an era when renewable energy was in a larval stage and the storage industry, i.e., renting large lockers to store furniture, cars, etc., was just starting to hit its stride, oops!, i.e., storing energy for later use as a substitute for generating plants did not even exist, is now causing judicial posturing over an issue that Congress could readily address with very minor legislative tweaks. Resolution of this issue is best performed by Congress.

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