Jennifer Key

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When considering a federal agency’s jurisdiction, we tend to think that jurisdiction is a legal issue, not a policy issue. Certainly, a federal agency can expand or narrow its jurisdiction through a new interpretation of a Congressional mandate, but FERC of late has taken actions that indicate that it views jurisdiction, as a matter of policy untethered to FPA. As already discussed in a blog article on Order No. 2222-A, FERC waved away thirty years of legal precedent on interconnection jurisdiction over distributed QFs selling power at wholesale, to third parties providing no legal basis for its decision to decline interconnection jurisdiction as to distributed QFs selling wholesale power to DER aggregators. FERC indicated that “state and local authorities, which have traditionally regulated distributed energy resource interconnections, have the requisite experience, interest, and capacity to oversee these distribution-level interconnections.” This decision was all the more profound because an aggregation of one was permitted.

In Order No. 2222, FERC already had decided to “decline” jurisdiction over second-use DER interconnections, without any discussion of its legal authority to decline jurisdiction given to it by Congress, particularly while reserving its right to reassert jurisdiction. Remarkably, FERC even stated that jurisdiction was matter of policy, not law, noting that “the Commission may revisit this policy decision in the future.” In the same decision, FERC implicitly declined to assert jurisdiction over sales of wholesale power in interstate commerce by DERs to aggregators, once again refusing to provide the basis for its authority to decline jurisdiction or, at the very least, deregulate such sales.

The August 26, 2022 ISO New England Inc. order, however, is perhaps even more stunning in its approach to jurisdiction. FERC ruled there that an RTO and its transmission owners could determine the bounds of FERC jurisdiction under the “independent entity variation” standard.
Continue Reading FERC Jurisdiction – A Matter of Policy?

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…

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…

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

Topic 6: Locational Requirements

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

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

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

Distribution Factors and Bidding Parameters

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

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

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

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

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

Participation Model

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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