By Tom Kleckner, Michael Kuser, Amanda Durish Cook, Michael Brooks and Rich Heidorn Jr.
Solar power and storage providers differed sharply with local distribution companies and state officials in comments filed this week in FERC’s rulemaking on distributed energy resources.
More than 50 commenters submitted answers to questions FERC posed, differing on whether aggregation should be limited to single nodes and on the roles of RTOs, state regulators and LDCs (RM18-9, AD18-10).
The commission initiated the rulemaking in February, deciding to separate DER issues from its Order 841 on energy storage. The comments supplement testimony from a technical conference in April. (See Gatekeeper or Facilitator? FERC Panels Debate EDCs’ DER Role and RTOs, Regulators Set Course for DER Market Participation.)
Below is a summary of the major issues and the range of recommendations FERC received, based on RTO Insider’s review of 40 comments.
How prescriptive should FERC be in its rulemaking?
Most RTOs and ISOs submitted comments, with PJM, NYISO and CAISO urging FERC to move forward while affording RTOs flexibility. “Distributed energy resources can, and do, participate in wholesale markets, and are contributing to grid reliability and resilience in new and important ways,” CAISO said. “The commission should not foreclose options for these resources.”
MISO and ISO-NE, however, urged caution.
MISO said FERC should postpone issuing a final rule on DER market integration, calling it “premature.” The RTO said its footprint does not have a high volume of DER installation and said it’s not predicting significant penetration levels, or a need for DER aggregation, anytime soon.
Part of MISO’s concern is that its aging market system platform cannot handle the added intricacy. (See “Limited Improvements for Old Platform,” MISO Platform Replacement Risks Delay, Budget Overrun.)
“Commission directives requiring major additions to MISO’s existing market platform would yield almost no benefits given the lack of capability of MISO’s legacy technology system and low regional DER penetration. Prescriptive action would incur very high costs associated with retrofitting MISO’s soon to be retired platform … likely delaying the transition to a far more capable system,” the RTO said.
ISO-NE also pleaded for flexibility, saying its current market rules and the new approach to integrating storage under Order 841 indicate no need for a DER participation model in New England. “The DER participation model envisioned in the DER [Notice of Proposed Rulemaking] would be costly and disruptive, and would produce no additional value for New England,” the RTO said.
The Advanced Energy Management Alliance called on FERC to create a “participation model” with a checklist for RTOs to demonstrate compliance with minimum requirements, like the one it included in Order 841 on energy storage. (See FERC Rules to Boost Storage Role in Markets.) It said the model should cover issues including market access, measurement and verification, and coordination with LDCs.
The Edison Electric Institute said FERC should “carefully consider the far-reaching impacts” of allowing DER aggregations to participate in the wholesale markets and defer to the grid operators and states on details.
“The proposal has significant implications for the reliability of the distribution system and additional time is needed to install infrastructure and to develop coordination agreements to ensure that the reliability of the distribution system and the [bulk power system] is maintained,” EEI said.
Public interest groups, including the Environmental Defense Fund, Sustainable FERC Project and Union of Concerned Scientists, said it would be premature for FERC to mandate best practices for transmission-distribution coordination. But it said the commission should finalize the DER aggregator participation model it proposed in November 2016. (See FERC Rule Would Boost Energy Storage, DER.)
“Relying on ISO/RTO stakeholder processes alone to eliminate barriers to market participation by non-incumbent storage and DER participation without commission involvement (as EEI suggested) would not likely yield results consistent with efficient functioning of the market or a fair outcome for these resources,” the groups said. “As noted by many commenters, the ISO/RTO stakeholder processes generally favor incumbent stakeholder members and underrepresent emerging technologies and the public interest.
“There is no need to further delay finalizing the proposed rule. Understanding that there might be legitimate reasons for RERRAs [relevant electric retail regulatory authorities] to delay implementation of the rule in their own regions, that may be done by granting a longer implementation timeline for that RERRA or a limited waiver,” the groups said.
The American Public Power Association said FERC must distinguish between “undue barriers to DER participation in wholesale markets and factors that, although they might have the effect of limiting DER participation in those markets, are grounded in legitimate operational, reliability and regulatory considerations.”
The Electric Power Supply Association said “any initiatives or rules to facilitate participation of [DER] must first and foremost be designed to serve reliability and efficiency objectives, not simply to facilitate DERs business model objectives.”
Should FERC permit aggregation of DER beyond a single node?
AEMA and the Solar Energy Industries Association said the commission should allow multi-nodal aggregation. “Aggregation at a node is not aggregation,” said AEMA, calling for aggregation across an area as “geographically broad as technically feasible.”
SEIA said it supports the commission’s proposed 100-kW minimum size requirement. “Even with [a] 100-kW minimum size requirement, however, there is no guarantee that each of the many thousands of nodes across the RTO/ISOs would be of a sufficient size to sustain aggregations and to foster market competition among multiple aggregators. Aggregators should have the ability to compete across a load zone, and allowing multi-node aggregation should reduce the price of delivered power by reducing congestion and alleviating system constraints.”
Limiting aggregations to a single node would hurt the economics of DERs and their value to system operators, “restricting their ability to deploy these resources economically and in response to reliability needs,” said Advanced Energy Economy, which represents more than 100 companies and organizations in energy efficiency, demand response, natural gas, renewables and storage.
PJM said multi-nodal aggregation would be challenging but that its experience modeling DR across multiple nodes shows it can be done. “PJM does not anticipate any significant modifications to modeling and dispatch software, communications platforms or automation tools to implement multi-node DER aggregations,” the RTO told the commission.
But opponents, including Calpine and EPSA, cited the technical conference comments of PJM Independent Market Monitor Joe Bowring and NYISO Manager of Market Design Michael DeSocio, who expressed concern at the technical conference over aggregation over multiple nodes.
“DER aggregation across multiple nodes is inconsistent with the design of the organized wholesale markets, will distort market outcomes and reduce efficiency, and should therefore not be mandated,” Calpine said.
“If the precedent is established now that DER, alone among generation resources, does not need to be nodal, it will be difficult or impossible to reverse that precedent as DER grows based on that approach,” the Monitor said in its filing. “The fact that aggregation may provide some short-term business benefits to the providers of DER is not relevant to defining the correct market design to facilitate the long-term, effective participation by DER.”
The Monitor said DERs can be priced and dispatched at individual nodes and still be aggregated across multiple nodes for settlement purposes.
How much control should local distribution utilities have over DER?
EEI said electric distribution companies “must have transparency and ultimate control over the resources connected to the distribution system” and that regulators must address cost allocation issues associated with distribution system investments needed to facilitate DERs.
“Generally, DER aggregations will increase, not decrease, volatility on the distribution system given its radial design, and because there may be significant changes in power flows that will have to be mitigated to ensure that load can be served under all circumstances,” EEI said.
The Transmission Access Policy Study Group, which represents transmission-dependent utilities, said “DER aggregations can adversely affect distribution systems.” FERC should “defer decisions to those with the best understanding of the relevant distribution systems, including an ‘opt-in/opt-out’ mechanism modeled on Order No. 719-A or, at minimum, an express opt-in requirement for small distribution utilities.”
The National Rural Electric Cooperative Association said FERC’s proposal to allow third-party DER aggregators to participate directly in RTO markets will present bigger challenges for its members than the deployment of DERs on cooperatives’ systems, requiring them to invest in new equipment and software.
“Third-party DER aggregators participating in the RTO/ISO markets will have incentives to operate the DER in response to wholesale market signals, which can pose operational, reliability and safety issues for local distribution cooperatives,” NRECA said.
NRECA also said third-party aggregators may engage in “cherry picking,” potentially preventing cooperatives from using their own or their members’ DER, which “may be a significant part of many cooperatives’ integrated resource portfolios. If those DER resources are available to third-party aggregators, this could severely undermine the cooperative’s ability to manage cost and risks for its consumer-members.”
“These factors were an integral part of the commission’s decision to permit RERRAs to decide whether to allow aggregators to bypass utility demand response programs and bid retail demand response directly into the wholesale markets in Order No. 719,” NRECA said.
Several commenters said they opposed giving LDCs veto power.
AEE said it supports reasonable mechanisms to ensure LDCs, aggregators and RTOs have sufficient operational coordination and situational awareness. “However, distribution utilities should not be given discretion to reject DER registrations in an aggregation for reasons beyond operational coordination and reliability,” the group said. “Allowing distribution utilities a broad veto, even in instances when a DER has an interconnection agreement in place, will restrict DER participation in wholesale markets, erode competition and potentially result in undue discrimination. The interconnection process determines what a DER needs to do to operate in a safe and reliable manner.”
EPSA said FERC should ensure LDCs don’t use their knowledge of their systems and needs for a competitive advantage in developing DERs. “If utilities are allowed to exploit their asymmetric access to information to the detriment of their competitors, even for the short term to speed the deployment of DERs, it will serve to chill merchant investment in this space, which may ultimately slow DERs deployment.”
SEIA also raised market power concerns. “Facing true competition from DERs, certain distribution utilities may have incentives to engage in conduct … to protect their current market positions,” it said.
Should state and local regulators have opt-out rights over DER?
AEMA and the Energy Storage Association said states should not be able to prevent consumers from participating in wholesale markets.
Instead, AEMA said FERC should clarify that states have the right to implement retail tariffs that prohibit participants from direct participation in wholesale markets. “In that instance, customers would choose whether they preferred to participate in a retail tariff or … via an aggregator in the wholesale market. The retail tariff could facilitate wholesale services and enable states to preserve their jurisdiction over retail customers, programs, and activities without impinging on customers’ ability to access wholesale markets,” AEMA said, citing Indiana and Michigan Power’s DR service rider.
But NRECA said FERC should defer to RERRAs’ timetables for implementation because the industry “is not uniformly ready for third-party DER aggregations.”
The National Association of Regulatory Utility Commissioners said it opposed a limited opt-out provision that would allow states to require DERs to choose participation in either the wholesale markets or retail programs, but not both.
“The limited opt-out provision provides no additional benefits or options to state commissions,” NARUC said. “States already have the authority to prevent an asset from participating in a retail compensation program [under the Federal Power Act]. … No FERC FPA-based regulation can require states to allow aggregated DER assets to participate in both RTO/ISO markets and retail compensation programs.”
Xcel Energy asked FERC to suspend the rulemaking pending further technology improvements, saying technology does not exist “to effectively and fairly integrate DERs” into wholesale markets. “In the meantime, states and other stakeholders can serve as the laboratory for policy initiatives in this arena as they move forward with incremental and evolutionary programs involving DER integration.”
How should concern over double payments be addressed?
AEE said “there is little to no risk that customers will ‘pay twice’ for the same service.”
The commission’s proposed blanket prohibition on wholesale market participation by aggregated DERs that participate in retail programs would “arbitrarily exclude many, if not most, existing DERs from the wholesale market, and limit the benefits that the wholesale grid can capture from these resources,” AEE said.
“Dual participation does not equal double compensation,” ESA said.
“Rather than limiting an entire function of DER assets by forcing the asset to participate exclusively in one market, ESA suggests that states examine specific services on a case-by-case basis, with sufficient evidence to demonstrate a justification for the exclusion, to limit a specific combination of two services by the same DER asset.”
ESA cited resources participating in both NYISO and Consolidated Edison’s DR program. “These assets are providing value for both the retail and wholesale markets and should be compensated accordingly — they provide demand savings for consumers and export power onto the grid for system support.”
Calpine said the commission must prevent DERs that receive out-of-market compensation from skewing RTO markets and price formation. “In particular, DERs that are compensated for participating in retail programs will not have to submit offers in the RTO/ISO markets that reflect their actual costs, and would therefore have a competitive advantage over resources that do rely on RTO/ISO market revenues,” it said. “Put simply, DERs should have to choose whether they want to participate in the retail market or an RTO/ISO market, and stick with that decision for a defined period (e.g., for five years, similar to the fixed resource requirement process in PJM).”
Vehicle and battery manufacturer Tesla said RTOs should require proof before allowing restrictions. “RTOs/ISOs should be required to articulate a specific scenario in which a resource would receive more than one revenue stream for only one distinct value.”
SEIA said the most effective solution “is to ensure that wholesale and retail services are clearly defined. Whether two markets compensate the ‘same service’ or ‘distinct values’ is a question that should be addressed on a fact-specific basis.”
