The DERs Aggregation rulemaking (now FERC Docket No. RM18-9) was initiated back in 2016 and was the subject of a 2018 Technical Conference. Now, FERC has posed to the six ISOs/RTOs an identical set of data requests regarding DERs that focus primarily on how interconnection service and distribution service would be provided to DERs. The data requests illustrate an issue discussed in a recent blog post about Order No. 2003 and FERC’s decision there to: 1) eliminate the bright line between its jurisdiction and state jurisdiction over interconnection service and replace it with a blurrier jurisdictional line that is referred to as the “first-use test” or “already subject to an OATT test”; and 2) retain the bright line between its jurisdiction and state jurisdiction over interconnection service when the seller is a qualifying facility (QF) that can sell to third parties. FERC’s questions reflect how complicated this policy is to implement (particularly as a non-QF may become a QF, thus shifting jurisdiction). The questions also indicate how difficult to even determine the role, if any, ISOs and RTOs take in DER interconnections by reviewing their filed tariffs. Taking FERC’s jurisdictional policies and ISO/RTO policies on whether to participate in the DERs interconnection process and applying them to an aggregation that may be comprised of QFs, non-QFs, demand response participants, and storage DERs raises a host of questions that many ISOs, RTOs, and Distribution Owners likely have not even considered. These questions may get those conversations started.

The answers to the questions will probably reveal several interesting things about how much, or how little, any particular ISO or RTO knows about interconnection processes for DERs. Some predictions of what FERC may learn from some of its questions are made below. These are only predictions. For brevity, the data requests are not repeated here.
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The jurisdictional discussion in Order No. 841-A was lengthy. It could have been very short.

This blog today takes a personal turn as I relate the tale of FERC’s jurisdiction over energy storage resources (ESRs) connecting to a public utility’s distribution system to sell wholesale power. There is only reason that the tale is long


Yesterday, FERC issued an order on a Petition for Declaratory order from Sunrun, asking that FERC waive the QF certification filing requirements for separately-interconnected, individual residential rooftop solar PV systems and related equipment with maximum net power production of 20 kW or less that Sunrun provides financing for but which the homeowner has an option to purchase, where such 20 kW or less systems may aggregate to over 1 MW within a one-mile radius; and that in a Form No. 556 submitted for a cluster of rooftop PV systems that exceeds 20 kW, the Commission waive the requirement in Item 8a of Form No. 556 to include information regarding the facilities covered by the first requested waiver (i.e., 20 kW or less facilities), even if they are within one mile of the cluster that exceeds 20 kW that is being certified).

Although the Petition garnered minimal opposition, largely in the form of requests to delay action until (anticipated) PURPA reform occurred, FERC chose to act. FERC granted both waivers, agreeing with prior statements that solar generation facilities installed at residences or other relatively small electric consumers such as retail stores, hospitals, or schools do not present a compelling need for QF registration. The burden of such filings was considered to be too great in light of the lack of benefits. The second waiver was granted for similar reasons, as the fact that new client homeowners are added frequently and existing client homeowners may at any time exercise their option to purchase their 20-or-less kW PV systems would create a major burden on entities with business models such as Sunrun.
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On April 1, 2019, FERC issued deficiency letters to all the ISOs/RTOs that submitted Order No. 841 (Storage Rule) compliance filings: CAISO, ISO-NE, MISO, NYISO, and PJM. Generally such letters ask the RTOs and ISOs to explain in much greater detail how their tariff provisions permit energy storage resources (ESRs) to participate in their markets. It appears that FERC wants each requirement imposed by Order No. 841 to be discussed in the specific context of ESRs, such that if a tariff provision does not specify that ESRs are covered or subject to a provision, the ISO or RTO must explain why the provision nonetheless applies to ESRs. There are only a handful of Order No. 841 compliance deficiency letter issues relevant to distribution-connected ESRs (i.e., a form of DER). The most interesting question actually arguably is relevant to both distributed ESRs and transmission-connected ESRs, although in one deficiency letter (MISO) the question was asked only as to distributed-ESRs. That question is: How is the ISO/RTO is going to prevent ESRs from paying twice for “charging for later discharge” energy? It will be interesting to see what “prevention methods” FERC finds adequate.

Under Order No. 841, FERC found that an ESR should pay the wholesale market price (the nodal LMP in particular) for charging energy used for later discharge in the wholesale market. FERC was not “persuaded by commenters who argue that developing metering practices that distinguish between wholesale and retail activity is impractically complex.” Even though FERC expects that wholesale and retail loads typically can be distinguished, it did recognize that, particularly for distributed DERs with retail load, the task may be too complex. In Paragraph 321 of Order No. 841, FERC stated: “we require each RTO/ISO to prevent resources using the participation model for electric storage resources from paying twice for the same charging energy. To the extent that the host distribution utility is unable – due to a lack of the necessary metering infrastructure and accounting practices – or unwilling to net out any energy purchases associated with a resource using the participation model for electric storage resources’ wholesale charging activities from the host customer’s retail bill, the RTO/ISO would be prevented from charging that resource using the participation model for electric storage resources electric wholesale rates for the charging energy for which it is already paying retail rates.”

This paragraph gives ISOs and RTOs an “out” if a distributed ESR is located within a distribution utility that will not net out wholesale purchases from the retail bill. In such cases, the RTO/ISO should not bill the ESR at wholesale for its charging energy. Indeed, where load is not distinguished, answering FERC’s deficiency letter question may be quite simple. Several ISOs/RTOs explained on compliance that they would not assess a wholesale charge unless the retail and wholesale loads could be distinguished:

  • MISO Tariff Attachment HHH, Section 6 states “To the extent the [ESR] is paying retail rates for energy associated with wholesale charging activities, the [ESR] shall complete Appendix 3 to this agreement in order for MISO to exclude settlement at wholesale prices for the same charging energy.”
  • The CAISO provided ESRs several options, including one where the CAISO does not charge such ESRs for their charging because the distribution utility already has done so at a retail rate.

The difficult and interesting question is what happens if the ISO/RTO has a method for distinguishing wholesale and retail load.
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On February 7, 2019, comments were submitted to FERC on the six RTO/ISO Order No. 841 (storage) compliance filings. FERC will need to address several issues regarding energy storage resources (ESRs), which are also distributed energy resources (DERs). This summary does not address issues that apply to all ESRs, such as limits on qualifying for capacity payments, transmission charges being properly excluded, PJM’s 10-hour rule, etc. Rather, it focuses on comments relating to ESRs that are also DERs or are quite likely to be DERs. For example, if an issue raised assumes that the ESR is co-located with retail load, that issue is likely to involve DER ESRs.

Overarching DER ESR Concerns

The comments relating to DER ESRs reflect many similar concerns – namely that the ISO/RTO is not including in its tariff sufficient information about matters relating to the state-federal jurisdictional overlap. Such alleged “omissions,” however, may reflect a lack of knowledge of the degree to which similar issues have been resolved in the non-ESR DERs context. Moreover, distribution owners (DO) (not the ISO/RTO) should be setting terms and conditions for DER ESRs’ usage of DO systems, in the first instance, subject to state commission or FERC oversight, if the DO is regulated.

Advanced Energy Economy, Tesla, and EDF Renewables all raise similar concerns that the ISOs and RTOs has not explained how DER and behind-the-meter (BTM) ESRs will access wholesale markets. This claim is somewhat odd in that DERs and BTM DERs have been accessing wholesale markets for decades in many states. Presumably, DER ESRs (whether BTM or in front-of the meter (IFOM)) will use the same processes and tools to interconnect and obtain service from their local utility to participate in the wholesale market as DERs use today. If such tools do not exist because of a lack of DERs, there are numerous states and DOs that can serve as models. There is nothing special or unusual about DERs participating in wholesale markets other than they (1) typically need to interconnect by asking their DO, rather than their ISO/RTO for interconnection service, (2) need to obtain wholesale distribution service (WDS) to sell some FERC-jurisdictional products to the market, and (3) DER ESRs will need WDS for charging purposes (when charging to resell). Only item (3) is unique to ESRs.

Comments such as those submitted by DTE Electric Company (DTE) indicate that some DOs evidently have not had to address market DER participation and are not yet prepared for such participation. For example, DTE is concerned with MISO providing dispatch instructions to DER ESRs due to a lack of visibility. DTE also is concerned with conflicting directions being issued by the DO and MISO. Yet, these are all issues any DER participating in MISO’s wholesale markets today would have to deal with, regardless of Order No. 841. Where a DO is providing a state-jurisdictional service, it can turn to its state commission (or if unregulated, to itself) to propose appropriate rules and protections; where a DO is providing a FERC-jurisdictional WDS, it has the right to set the terms and conditions for such service in the first instance. FERC-jurisdictional interconnection service for DER ESRs, largely will have to abide by the pro forma SGIA, as perhaps modified to reflect the ISO/RTO’s existence.

Advanced Energy Economy also raises in all dockets a concern about an ESRs’ opportunity costs where the ESR is co-located with retail load. Advanced Energy Economy argues that “opportunity costs are a key component of an ESR’s reference level” and that certain ESRs are used to ensure that a given [retail] customer’s demand does not exceed a certain threshold level. FERC, however, in developing market mitigation for ESRs should not consider an ESR’s role regarding managing the retail demand charge assessed a co-located retail customer. Wholesale and retail market considerations should be separated. FERC’s concern is wholesale markets, an ESR should not be permitted to set its wholesale opportunity cost based on retail rates.

Some of the more specific concerns of DERs and DOs are discussed below.
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FERC, not surprisingly, has asserted jurisdiction over the “inbound” wholesale distribution service (WDS) required by distributed storage resources that participate in FERC-jurisdictional energy and ancillary service markets (Wholesale Storage DERs). Although FERC has long asserted jurisdiction over WDS, it addressed charging Wholesale Storage DERs several years ago in a case involving Commonwealth Edison and Energy Vault.  There, FERC explained that ComEd may recover the costs of the use of its distribution system by Energy Vault, provided such recovery is just and reasonable.  That said, as Wholesale Storage DERs increase their market penetration, issues arise as to how distribution owners (DOs) should set rates for WDS and differentiate between wholesale and retail energy delivered to Wholesale Storage DERs and co-located retail load.  There are two primary challenges relating to developing and assessing WDS rates for Wholesale Storage DERs – 1) FERC’s general policy preferring that WDS rates be direct-assignment rates rather than rolled-in rates; and 2) separating energy delivered to co-located retail load (including station power load) from the energy delivered that will be resold into the wholesale market.  (“Outbound” WDS is a different issue as several DOs have made the decision not to charge for such service at all, outside of interconnection-related upgrades.)

FERC generally prefers that rates for WDS be customer-specific, reflecting the costs of the actual facilities used by DERs or other wholesale load. That is, rates for WDS are supposed to be determined on a direct assignment basis; the ComEd/Energy Vault case also reflects this policy.  At some point, however, Wholesale Storage DERs’ penetration may increase to a level where the ratemaking task becomes overwhelming and non-customer-specific rates for charging Wholesale Storage DERs will be necessary to relieve that ratemaking and regulatory burden.  FERC has permitted rolled-in pricing for WDS rates, but the (relatively small) utility in that case, argued that its wholesale distribution facilities operate as a single, integrated system consisting of mostly networked and looped facilities rather than a collection of radial segments off the transmission system, for which the specific costs can not be easily assigned to particular customers.  There is some likelihood FERC will allow additional utilities to adopt rolled-in pricing approaches.  One option for DOs is to ask FERC to use the state-approved retail distribution rate, but this approach is difficult to implement if a DO is located in a state that has not fully unbundled its retail rates, such that charges for other services are embedded in their retail distribution rates.  It does not appear that many DOs have had to deal with a level of Wholesale Storage DERs penetration yet.  That said, direct assignment rates likely will become unwieldy for some DOs in the relatively near future.

The second challenge facing DOs is the fact that Wholesale Storage DERs may be located behind the same retail meter as retail load unrelated to the Wholesale Storage DER or a Wholesale Storage DER will likely have (retail) station power load. Options such as mandating dual metering to separate the wholesale and retail load is one solution, but can prove expensive and may not be acceptable to retail regulators seeking to encourage distributed storage.  FERC recognized this issue in Order No. 841 and has indicated dual meters may be required for transmission-connected storage facilities, but it did not indicate whether this dual-meter solution could be mandated for Wholesale Storage DERs, where it may lack jurisdiction over the metering requirements, i.e., particularly where the interconnection of the Wholesale Storage DER is state-jurisdictional under the “first-use” test. 
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As noted in the DERs Rulemaking Comments of various entities, the issue of double compensation was a considerable concern for some, while the issue generally dismissed by the DER industry generally. For example, the New York Transmission Owners (NYTOs) explained to FERC that they support the participation of DERs in wholesale markets, but suggested that “a review of each retail-level program by the relevant RTO/ISO is required so that the compensation at the retail and wholesale level is for distinct services and not the same service.” Speaking specifically to Value of DER (“VDER”) tariffs, the NYTOs suggested that rules should allow a DER to receive wholesale compensation from NYISO, but that the resource should not receive overlapping compensation as part of the Value Stack under the VDER tariff. In contrast, Sunrun stated: “the Commission should rebuttably presume that state programs aim to compensate a value that is different than what the DER provides to the wholesale market. A rebuttable presumption along these lines is justified because states have no incentive to create retail programs that waste their ratepayers’ money by duplicating services procured in wholesale markets.” The complexity surrounding determining whether dual compensation is occurring recently was highlighted when a group of large industrial, commercial, and institutional energy consumers and an association of independent power producers recently petitioned the New York State Public Service Commission for expedited prospective relief from double payments that may occur if carbon pricing is implemented in the NYISO.

The petition relates to the NYISO’s recent Carbon Pricing Straw Proposal (Straw Proposal) to incorporate the cost of carbon dioxide emissions into the NYISO-administered wholesale markets. Because existing programs compensate certain resources for their low-carbon attributes, the Petitioners are concerned that if implemented, carbon pricing (i.e., the Straw Proposal) would result in double-payments for the same attribute to resources that already receive compensation under existing programs. More recently, Nucor Steel Auburn, Inc. submitted a statement in support of the petition.


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Some of the more salient points raised by DER commenters that do not fall neatly into the categories of comments already summarized by this blog are identified below. Many such commenters are quite supportive of DER aggregations and thus their comments reflect similar views of the DERs/DER Aggregator comments. (E.g., Advanced Energy Buyers Group; Microsoft; Lorenzo Kristov; Public Interest Organizations). Others, however, such as the Energy Power Supply Association (EPSA) have some concerns, such as that DERs’ contributions must be valued correctly.

  • EPRI: EPRI’s comments focus heavily on the multi-nodal issue, which it thinks can be addressed with the appropriate use of distribution factors. It believes that Distribution Owners (DOs) may require greater capability to limit DER injections. EPRI supports the concept of a DER Management System, which will provide greater grid visibility. More generally, EPRI supports more research and development efforts to find operational solutions.
  • EPSA: EPSA supports FERC starting with single node aggregation because this approach is consistent with existing security constrained economic dispatch models. Market signals could become highly distorted without such a limitation in its view. Adequate metering of DERs is another EPSA concern both for reliability and accountability reasons. To the extent DERs participate in wholesale capacity markets, accountability is crucial. EPSA also is concerned with market power and subsidization issues that could arise if DOs own and operate DERs.


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  • The Opt-Out a Must-Have for Small (Largely Non-FERC and Non-State –Jurisdictional) DOs. The DOs with the greatest concerns about the NOPR are small, typically self-regulating utilities, as reflected in the comments of the American Public Power Association (APPA), the National Rural Electric Cooperative Association (NRECA), and the Transmission Access Policy Study Group (TAPS). All three entities support, at the very least, an opt out option for smaller DOs, if the opt-out is not granted to all state and local regulatory authorities. Some FERC-/state-jurisdictional utilities prefer an opt out (e.g., Southern Company (Southern), Xcel, and/or the small group of DOs that filed as the PJM Utilities Coalition). The concerns of the DOs seeking an opt out are many and include: rate design challenge; load forecast accuracy; operational technological and administrative challenges; incremental costs; lack of coordination with RTOs/ISOs; dispatches that would harm distribution reliability; issues with override and protection settings; and the timetable for implementing necessary controls. Many individual DOs who commented do not see a need for an opt out (e.g., Indicated NY TOs; Southern California Edison Company (SCE), Pacific Gas and Electric Company (PG&E), and San Diego Gas & Electric Company (SDG&E)). Those DOs who do not propose an opt out are located in states that are supportive of aggregation.
  • The DOs Must Be Able to Override Dispatch Directions from the RTOs/ISOs. An issue addressed by almost all DOs is which entity should ultimately determine whether a DER in an aggregation may operate – the DO or the RTO/ISO. Uniformly, DO commenters weighing in on this subject indicated that the DOs must have this authority. The Indicated NY TOs explained that if a DO has a known constraint, it must be permitted to require a DER to come offline to preserve safety and reliability. The APPA insists that DOs must have the ability to manage the reliable operation of their systems and that a transmission system can readily deal with an override of a distribution-level dispatch. NRECA explains that coordination agreements must give the DO an override authority. TAPS notes that DOs must be able to override dispatch decisions of RTOs/ISOs or require the disconnection of DERs if their dispatch would undermine local distribution reliability. EEI, Eversource, and Duquesne Light Company (Duquesne) support DO control over resources connected to their systems. Several commenters also indicate that such override authority must not result in liability to the DO.


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  • Framework and Roadmap Needed Soon. Most DER commenters see no valid reasons for any significant delay in implementing DER participation through aggregation (e.g., Advanced Energy Economy (AEE), Advanced Energy Management Alliance (AEMA), Direct Energy, Energy Storage Association (ESA), NRG, Solar Energy Industries Association (SEIA), Stem, Sunrun, Tesla). Many want a framework or roadmap laid out quickly. Generally, issues they favor to be included in such guidance would include the limited need for telemetry (AEE, AEMA) and for FERC to permit multi-nodal aggregations. (Sunrun, AEE, AEMA, NRG) Microgrid Resources Coalition (MRC), however, does see a need for substantial gird architecture changes and a new control architecture.
  • There Are Legitimate Questions About State/Distribution Owner (DO) Reliability-Impact Claims. One key argument from the DER commenters is that there already are plenty of DERs operating today (e.g., under net metering, aggregated demand response) without adverse distribution system impacts and without the distribution grid knowing whether kilowatts are sold at wholesale (AEMA). Sunrun points out that many DERs are being built today without the expectation of wholesale market revenues and distribution system impacts will occur regardless of wholesale participation. Although some DER commenters acknowledge that DERs acting in an aggregated manner may have some differing impact, several express sincere doubts that reliability review is required beyond the initial interconnection (AEE). ICETEC Energy Services (ICETEC), Tesla and NRG, for example, seek to limit the ability of the DO or RTO/ISO to study or re-study DERs once interconnected simply because they are later aggregated. Stem asks, where reliability claims are made, that they be supported by factual evidence and points out that aggregations can have the same impacts on a distribution system as instructions issued to multiple resources under retail programs.


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