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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?

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

Who Needs to Submit a Baseline: As November 2, 2021 looms (and is far scarier than Halloween), owners of QFs and DERs may be thinking, “what me worry?” But the looming due date for Order No. 860 baseline submissions can impact some QFs and some DERs. Although it is perhaps almost too late for those subject to, but unaware of their obligations to, make timely Order No. 860 submissions, steps can be taken now by those QFs and DERs with market based-rate (MBR) authority.

For a variety of reasons, some QFs have MBR authority: they may no longer sell under PURPA and are too large to be exempt from FPA Section 205 regulation; they may have MBR authority as a safety measure in case they fall out of QF compliance; they may be concerned about losing QF status due to changes in the 1-mile rule; among other reasons. As to DERs, while many DERs are renewables and sized to be exempt from FPA Section 205 regulation and thus Order No. 860, some DERs, such as in front of the meter, stand-alone storage, will be “Sellers” with Order No. 860 obligations. Determining if a QF or DER has an Order No. 860 obligation is simple, does the entity that owns/controls the asset have an MBR Tariff on file? If yes, an Order No. 860 baseline obligation exists, even if the entity has never made a sale subject to FPA Section 205 regulation. FERC keeps a list of entities with MBR on this page (look at right side of page for link to “Electric Utilities With Approved Market-Based Rate Authority (Includes Contact Information)”).

For those QFs/DERs who belatedly realize that they have an Order No. 860 obligation, if they cannot gather the data required by Order No. 860 and learn how to submit it in a matter of two weeks, an extension request may be an option. Some QFs, particularly those whose sales are all exempt under 18 C.F.R. Section 292.601, may want to reconsider whether they need MBR authority at all and seek to cancel their MBR Tariffs effective on or before November 1, 2021. Although, such Seller may be technically out of compliance with Order No. 860, as long as the Commission grants the cancellation date, FERC may choose not to demand compliance between November 2nd and the effective date of the cancellation. (This option applies to anyone with an unnecessary or unused MBR Tariff.) Other Order No. 860 issues relating to QFs and DERs are discussed below.
Continue Reading Order No. 860: QFs and Distributed Energy Resources

In Order No. 2003, FERC adopted a very clear policy – that if a vertically-integrated transmission provider charged its OATT customers for reactive power from its own generating fleet under OATT Schedule 2, it had to allow other generators in its BAA (f/k/a control area) to be compensated for reactive power as well. This meant merchant and public power (non-jurisdictional) generators could file seek reactive compensation, regardless of the transmission provider’s need for additional reactive power. Implementation of the policy was not quite so simple because not all transmission providers were vertically-integrated. RTOs/ISOs had to make their own decisions as to whether generators would be compensated for reactive power. Some RTOs/ISOs decided any generator could obtain compensation (e.g., PJM); some decided no generator could (e.g., CAISO). In any case, the question arises what does eligibility for reactive power compensation have to do with a PURPA and DER blog? The subject is relevant because FERC has yet to provide clear answers in all cases as to QF and DER eligibility for reactive compensation.
Continue Reading Reactive Power Sales: QFs and Distributed Energy Resources