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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Some states permit end-users to “obtain” energy generated at a remote location, without requiring such end-users to pay the utility to which they and the generator are interconnected for the delivery and ancillary services required to move the energy to the end-user’s load. Such “virtual net metering” is a key element of some community (or shared) solar programs. Examples of end-users that pay no delivery charges for energy delivered from “off-site” or “remote” generation are reflected in an Oregon commission’s recent May 23, 2018 order and in Minnesota, where the local utility continues to credit customers of community solar gardens at the full retail rate. In contrast, (most) other end-users must pay delivery charges when consuming energy delivered over the utility’s wires, whether the energy they consume is largely produced a block away or hundreds of miles away. (On-site net-metering programs also may result in free delivery service for end-users, but that issue is not the focus of this post.) The focus of this post is whether a state or state utility commission may lawfully mandate that energy produced at one location can be deemed to have been consumed by an end-user at another location without that end-user having to pay for delivery service if the utility’s wires are used for such delivery. As discussed below, there are a variety of legal grounds on which virtual net-metering laws, regulations, or tariffs could be challenged by utilities, customers to whom delivery costs may be shifted, and competing generators as relates to the free (or reduced cost) delivery service aspect of virtual net metering.
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Based on the two-day FERC Technical Conference on DERs, where varying opinions were presented on a variety of technical and operational issues relating to DERs and DER aggregation, the following are overarching takeaways that the Commission and its Staff should consider before taking the next step on DERs’ and/or DER aggregations’ participation in wholesale markets.

Those persons that believe that the Federal Power Act left exclusive jurisdiction over local distribution facilities (and everything that occurs on such facilities) to the states have been told that they are wrong. The courts have told them they are wrong. FERC has told them they are wrong. Yet, whenever FERC mentions the distribution system, state regulators and others object vociferously that FERC is intruding into state-jurisdictional matters. Indeed, the Commission’s Final Rule on Storage, which assumes that many if not most storage devices will be connected to distribution, actually raises no meaningful jurisdictional issues that have not already been addressed by the courts. Nonetheless, several rehearings raising jurisdictional issues related to storage devices located on the distribution system were filed in response.

Successful appeals are unlikely on jurisdictional grounds, assuming FERC does not appease the states as it has on other occasions, such as with regards to non-QF interconnections to distribution. NARUC and some utilities have objected to certain aspects of the Final Rule that permit participation by storage resources interconnected to distribution in wholesale markets. FERC jurisdiction over all wholesale sales in interstate commerce is well-established. And, FERC jurisdiction over the usage of a distribution system to engage in wholesale market transactions rests on FERC precedent more than two decades old. FERC jurisdiction over wholesale distribution service was affirmed in New York v. FERC, and Detroit Edison Co. v. FERC.
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