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.

Continue Reading DERs and Double Payment Streams

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.

Continue Reading DER Aggregation Comments – Takeaways from Other Commenters

  • 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.

Continue Reading DER Aggregation Comments – Five Takeaways from the Distribution Owners (DOs)

  • 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.

Continue Reading DER Aggregation Comments – Five Takeaways from DER Aggregators/DERs

The takeaways from the individual state commissions and commissioner who commented must be viewed in light of the fact that four of the five sets of comments from individual states (NJBPU; CPUC; NYPSC; PA PUC Comm’r Place) are from states that have supported the integration of DERs, already have fairly high DER penetrations levels, and are located in the three ISOs that are arguably the furthest along in adopting DER aggregation policies (CAISO, PJM, and NYISO). Most of the state comments were more focused on DERs generally and not the aggregation of DERs.

  • State Commissions Should Be Participation Gatekeepers. Although the majority of state commissions that filed comments fully support DER participation in wholesale markets, when the totality of comments are considered (Indiana URC; NARUC; MISO States), the states, as a whole, generally do support an opt-in, opt-out approach to both DER aggregation and in some cases the participation of DERs directly in wholesale markets. Even some of those states that support full DER participation caveat such support: for example, the NJBPU proposes that distribution owners (DOs) review and determine participation eligibility as to reliability issues and does not support an RTO/ISO being able to override such decision. A majority of the states insist that they retain a coordination role in any DERs participation in an aggregation. As to those supporting a complete opt-out option (MISO States; NARUC; Indiana RUC), they cite to legal precedent that they believe leaves the participation decision to the states and also express concern as to entities seeking compensation from both retail and wholesale programs.

Continue Reading DER Aggregation Comments – Five Takeaways from State Commissions

  • Slow Down/Permit Flexibility on Timing. Several of the RTOs/ISOs provide FERC reasons why it needs to slow down its desire to have DER aggregation processes in place. The reasons range from the mere time it will take to implement such processes in a well-thought out manner with the right technology (which technology may not be readily available today) (NYISO, MISO, ISO-NE) to the fact that the demand for participation through aggregation is just not there (MISO, ISO-NE). Although the CAISO already has an aggregation process in place, it is not being used, and while blame for that is debatable, this fact supports the general theme that time is not of the essence. PJM’s comments indicate that it is fairly well-prepared for DER aggregation in light of existing DER participation, but also indicate that many questions need to be answered before it and its stakeholders can implement a workable program. ISO-NE does not believe adequate tools exist yet for implementation. MISO believes DER integration and aggregation needs to be accomplished over a time period that is consistent with other reform efforts that may have a higher priority.

Continue Reading DER Aggregation Comments – Five Takeaways from the RTOs/ISOs

Blockchain technology unquestionably will impact the electric utility industry in various ways. (For background on blockchain – which is distributed ledger technology (DLT) that offers a consensus validation mechanism through a network of computers that facilitates peer-to-peer transactions without the need for an intermediary or a centralized authority to update and maintain the information generated by the transactions – click here.) It is difficult to predict the impacts of blockchain technology on the utility business at this nascent stage. Although there are myriad ways in which utilities can use blockchain technology to their benefit, some view it is a threat to the entire utility model. There are many potential uses of blockchain technology relevant to DERs (including electric vehicles) and optimizing the distribution system. One blockchain impact relevant to this blog is that the technology can be used by DERs to allow them to more seamlessly provide energy to other consumers if state law so permits. Continue Reading DERs and Blockchain

After holding its two-day Technical Conference on DERs, FERC issued two Requests for Comments on April 27, 2019 in existing Docket No. RM18-9 and new Docket No. AD18-10.  FERC divided the existing rulemaking docket into two parts, separating the topic of DER Aggregation in ISOs and RTOs from the topic of DER Technical Considerations for the Bulk Power System.  Also, FERC added “new” questions to the seven existing sets of questions asked before the conference.  The docket split and new questions provide some new insights that should be considered in drafting comments, which are due June 26, 2018.  Specifically:

  • We can discern from the opening of an AD docket that is not limited to ISOs/RTOs that FERC is interested in ensuring DERs are taken into account by all Transmission Providers in modeling, planning, supporting, and operating the bulk power system.
  • We can discern from new questions on planning and models that FERC may be seeking to assert some sort jurisdiction over distribution system planning on the grounds that DERs impact bulk power systems and that transmission planning must be (somewhat) integrated with distribution planning.
  • We can discern from new questions about the need for DER data that more information about the importance of 1) individual DER size and 2) overall DER penetration levels should be provided to FERC.
  • We can discern from the new questions about aggregating behind single versus multiple nodes that pricing issues may be difficult to resolve and may need to vary by ISO/RTO.
  • We can discern from the new questions about utility distribution companies (UDC) that the myriad issues they face as relates to DERs, including ensuring distribution system safety and reliability, ensuring retail ratepayers are not adversely financially impacted, and dealing with state retail customer privacy laws, need to be identified and addressed in an appropriate fashion. The UDCs will need to identify those issues of concern, given their own particular situations.
  • We can discern from the new question about participation in the CAISO DER program, that FERC needs more information on the relationship between each UDC/state retail net metering program and the impacts of such programs on the likelihood and type of DER participation in wholesale markets.

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.

  • Identify where/whether need exists. The need for ISO/RTO rules for DER aggregations or DER participation in wholesale markets may vary widely, especially as a preference for participation in “the retail market” (e.g., net metering; distribution system support; distribution facility deferral) may result in very little DER participation in wholesale markets, even where market penetration of DERs is significant.
  • The UDC rules this domain. The role of the Utility Distribution Company (UDC) in wholesale market participation will be significant. The notion that a DER aggregator would interface only with the ISO/RTO, although supported by DER aggregators at the conference, appeared to be a non-starter for UDCs and ISOs/RTOs. The message that the UDC or a Distribution System Operator ultimately had to have operational control over the distribution system was clear.
  • Plug and play is not here today. The readiness for significant DER penetration varies widely from UDC to UDC and any FERC rule must take this into account, particularly as state commissions are the entities ultimately authorizing UDC “spend” on distribution system modernization.
  • Jurisdictional, regulatory, and legal issues must be resolved first, not as an afterthought. Technical/operational issues cannot be fully divorced from jurisdictional, regulatory, and legal issues. Establishing rules and policies should precede any discussion of technical implementation, but have been largely ignored to date (and purposefully omitted from the Technical Conference). Examples: 1) is it practical for DERs that do not have or cannot obtain qualifying facility (QF) status to sell into wholesale markets (whether directly or through a DER aggregator) under the existing regulatory system (requiring quarterly EQR filings and maintaining market-based rate eTariffs)?; 2) Currently, QFs selling to the market must take FERC-jurisdictional interconnection service under existing FERC policy; if aggregators are considering aggregating entire neighborhoods of PV owners (which are QFs as a matter of law if under 1 MW), is this approach to interconnection practical? When and how are such issues going to be addressed?
  • Multi-use applications will take time to address. Compensation and cost recovery relating to DERs offering both FERC- and state-jurisdictional services and/or taking FERC- and state-jurisdictional services raise implementation issues that are very complex. Although they are solvable issues, significant time and effort is required to solve them, particularly at the state commission level.