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. Continue Reading Virtual Net Metering –Vulnerabilities of Free Delivery Service to Legal Challenges
Supplemental Comments in Docket No. AD 16-16
In testimony before the Senate Energy and Natural Resources subcommittee as well as other venues, FERC Chairman McIntyre has made clear his desire to update PURPA, which has led to several entities submitting supplemental comments to FERC in Docket No. AD16-16. Supplemental comments have been filed by ELCON, et al., North American BioFuels LLC (BioFuels), EEI, and NARUC. Largely, these comments reiterate prior positions taken by these parties. EEI and NARUC continue to be focused on, among other issues, several areas of reform that would accrue to the benefit of utility purchasers (and presumably their ratepayers) such as competitively-determined avoided cost, the one-mile rule and other economy-of-scale issues, lowering the MW threshold for eliminating the must-purchase obligation. ELCON reinforced its position on standard contracts, FERC’s inappropriate focus on QF size, and the need for more public documentation on avoided cost.
Although the focus of these trade associations on a limited number of big picture issues is understandable, the reality is that FERC’s PURPA regulations could use an even more comprehensive overhaul. For example, a good start would be for the Commission’s PURPA regulations to assume that open access exists, to reconcile (or reconsider) the Commission’s “better than firm” transmission policy for QFs with the reality of the terms of open access tariffs, and to codify the FP&L policy on interconnection jurisdiction. If fast action is desired, two separate rulemakings could be opened: 1) a narrow rulemaking to deal with more pressing issues; and 2) a rulemaking that is broader in scope and focuses on eliminating the vestiges of the 1970s vintage FERC PURPA regulations and case precedent set in the 1980s.
In contrast to the trade associations discussed above, BioFuels, is seeking to solve a particular problem that arose when FERC issued Order No. 671 and Order No. 732 which together require QFs over 1 MW to file self-certifications through Form 556. In its most recent set of supplemental comments, BioFuels is asking FERC to: 1) provide an amnesty period for QF-eligible entities that do not have a Form 556 on file in order to allow them to get into compliance; 2) require that a purchasing utility has received a Form 556 or the equivalent before a power purchase agreement (PPA) becomes effective or a purchase is initiated; 3) require that a purchasing utility not purchase energy from a QF without having received Form 556 or the equivalent; 4) place an obligation on the purchasing utility to provide FERC a copy of any PPA with a QF (whether or not the PPA is entered into pursuant to PURPA) and documentation that the purchase is from a QF; 5) impose possible penalties (albeit under 15 U.S.C. § 797, rather than the Federal Power Act) on purchasing utilities for violation of this last regulations; and/or 6) simplify Form 556 by creating a small power production-specific form. Continue Reading PURPA – Update on Docket No. AD16-16 and Other FERC PURPA Developments
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.
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.
- 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.
- 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.
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.
- 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.
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