• 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

With comments having been filed in response to two dockets focused on DERs, this blog will examine comments filed in the rulemaking docket (Participation of Distributed Energy Resource Aggregation in Markets Operated by Regional Transmission Organizations and Independent System Operators), Dkt. No. RM18-9 and (1) identify the key takeaways from differing sets of stakeholders (including their trade associations); and (2) provide some limited commentary. The question that remains, in light of the comments, is whether FERC will issue a revised NOPR, will proceed to a Final Rule, or will shelve the rulemaking and focus on other priorities while various RTOs/ISOs adopt their own DER aggregation approaches, if they consider one is needed.

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

In a recent article, the well-respected Ari Peskoe, director of the Electricity Law Initiative at the Harvard Law School Environmental and Energy Law Program, was quoted as saying that FERC does not have the authority to rewrite the goal of encouraging the development of qualifying facilities (QFs) because “[t]hat goal is embedded in the law.” PURPA Section 210(a) requires FERC to set rules “as it determines necessary” to encourage QFs. In other words, FERC, led by Chairman Kevin McIntyre, has significant discretion to determine what rules are necessary to encourage QFs beyond the basic purchase/sale obligation, as modified by the Energy Policy Act of 2005. QFs may be sufficiently encouraged by policies such as state renewable portfolio standards, state greenhouse gas reduction targets, net energy metering programs, community solar, and the like, such that FERC could find certain existing regulations and policies are no longer necessary or that new policies and regulations are merited.

A comparison of whether FERC could adopt all of the reforms that Senators Barrasso and Risch are proposing in their UPDATE PURPA Act (S. 2776) demonstrates the breadth of the power of FERC’s authority. Of course, changes to FERC PURPA regulations and policies can readily be “undone” by a new Commission, but legislative reform also can be reversed by a new Congress, and may be harder to achieve in the first place.  Continue Reading The UPDATE PURPA Act: What Could Kevin (McIntyre) Do?

A PURPA complaint before the Michigan PSC, accessible through the article Michigan Utility Under Fire For Alleged PURPA Violations, teaches a good lesson about words. The QF complainant (Greenwood Solar) stated that a utility (DTE): 1) has an obligation to buy capacity even if unneeded; and 2) needs to obtain a waiver from FERC in order to be absolved of the requirement to buy capacity. Indeed, in a fairly recent case cited by Greenwood Solar, FERC reiterated its regulation that specifically requires that a utility purchase any energy and capacity made available by a QF. PURPA regulations state that energy and capacity purchases are mandatory, but for the exemption for purchases from over 20 MW QFs that most utilities in organized markets have obtained. The complaint alleges that respondent DTE insisted that it had no obligation to purchase unneeded capacity from a QF. A close reading of FERC’s exact words on the topic supports Greenwood Solar’s contention that an obligation to purchase capacity exists, despite any need. Although this policy appears counterintuitive, the policy is logical when coupled with other words issued by FERC – that a utility that lacks a need for capacity may lawfully fulfill its purchase obligation by offering a QF a price for capacity of $0.00/MW. Continue Reading Words with Enemies – PURPA and the Capacity Purchase Obligation

In our series of posts on the need for PURPA reform targeted at the Allco decision, we identified Congress as one avenue of reform. Although the Congressional path to success may be arduous, the journey has begun. On May 3, 2018, Senators John Barrasso (R-WY) and James Risch (R-ID) introduced the “Updating Purchase Obligations to Deploy Affordable Resources to Energy Markets Under PURPA Act” (“UPDATE PURPA Act”). Although the UPDATE PURPA Act is quite broad in scope and will undoubtedly prove controversial, unlike Rep. Walberg’s (R-MI) PURPA Modernization Act of 2017, the new bill directly addresses 18 C.F.R. Section 292.304(d)(2)(ii) (as to renewable (small power production) qualifying facilities (QFs)) by requiring that Section 292.304(d)(2) be amended to provide that “a legally enforceable obligation for the delivery of electric energy or capacity from a qualifying small power production facility shall not require any electric utility to purchase energy or capacity from a qualifying small power production facility at a rate that exceeds the incremental cost of the electric utility of alternative electric energy or capacity, as calculated at the time of delivery.” In short, the bill effectively eliminates the requirement for a utility to pay for energy and capacity at a price other than the price at the time of delivery, eliminating the price risk for both buyers and sellers alike inherent in long-term contracts.

Given that the more modest reforms of the PURPA Modernization Act of 2017 have not been enacted (well over a year after introduction), FERC could speed the journey to “fix” Allco, by introducing a rulemaking that clarifies that rates set at the time of a legally-enforceable obligation can be formula rates. Even if such relief is later superseded by more comprehensive PURPA reform, this reform should be adopted sooner rather than later to stem litigation. Certainly, broader reform by FERC would be welcome by the utility industry, but reform of 18 C.F.R. Section 292.304(d)(2)(ii) is a priority reform. Continue Reading Some in Congress Are Ready to Address Allco – Are the FERC Commissioners Willing to Join Them?

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.