A wide range of power industry participants, including Paul Zummo, the American Public Power Association’s director of policy research and analysis and Christopher Norton, director of market regulatory affairs at American Municipal Power, recently weighed in on questions tied to the aggregation of distributed energy resources at a two-day technical conference convened by staff at the Federal Energy Regulatory Commission.
Representatives from regional transmission organizations and independent system operators, state utility regulators and utilities participated in panels that took place at FERC headquarters in Washington, D.C., on April 10-11. Other panel participants included officials from the Electric Power Research Institute, the North American Electric Reliability Corporation and the Electric Power Research Institute.
Conference stems from reforms proposed in NOPR
FERC on Feb. 15 voted to remove barriers to the participation of electric storage resources in the capacity, energy and ancillary services markets operated by regional transmission organizations and independent system operators. At the same time, the commission said it would convene a technical conference that would be used to gather additional information to help determine what action to take on distributed energy resource aggregation reforms proposed in a Notice of Proposed Rulemaking issued in late 2016, as well as discuss other technical considerations for the bulk power system related to DERs (Docket No. RM18-9).
On April 10, two panels focused on DER participation and compensation in the RTO and ISO markets, including specific NOPR proposals related to such participation. A third panel provided a forum for FERC Commissioners to discuss DER aggregation with a panel of state and local regulators. On April 11, operational issues associated with DER data needs, modeling, and coordination were examined.
Integration of DER aggregations
The first panel on day one of the conference was asked to discuss the integration of DER aggregations into the modeling, clearing, dispatch, and settlement mechanisms of RTOs and ISOs as considered in the NOPR.
The NOPR proposed to require each RTO/ISO to revise its tariff to remove barriers to the participation of DER aggregations in its markets by, among other steps, establishing locational requirements for DER aggregations that are as geographically broad as technically feasible. The NOPR also addressed the use of distribution factors and bidding parameters for DER aggregations.
Participants in this panel were representatives from the California Independent System Operator, the Midcontinent Independent System Operator, the New York Independent System Operator, ISO New England, PJM Interconnection, and Monitoring Analytics, the PJM market monitor.
Panelists were asked to discuss what approaches are available to ensure that the dispatch of multi-node DER aggregations do not exacerbate transmission constraints. A FERC staff member noted that CAISO, as well as certain other grid operators, already allow DER aggregations across multiple pricing nodes.
John Goodin, manager for infrastructure and regulatory policy at CAISO, said that “on this particular issue, I think that it’s important that if you’re going to establish DER aggregations, that you impose both size and boundary constraints,” which is something that CAISO has done. He also later pointed out that while the CIASO established DER aggregation rules in 2016, they have five contracts signed but no participants.
“We’ve borrowed a lot of our distributed energy resource aggregation model from functionality that we established previously for demand resources,” he noted.
Jeff Bladen, executive director for market services at MISO, said that the discussion should not just be about the application of security constrained economic dispatch to distribution resources, but to “do no harm” to the distribution system and to develop best practices. He also stated that “we generally agree that you can accommodate aggregations within areas that tend to be both topologically and price consistent.”
But he said that there is a broader set of issues and challenges that need to be considered. Bladen said that “as we think about aggregations, as we think about building aggregation groups, it needs to be more than just how do we security constrain those aggregations for the transmission system, but how are we going to manage the potential constraints that might occur at the distribution level.”
The MISO official said, “what I would suggest is that, as we begin down this road, that we recognize that we don’t yet as an industry know what best practices look like in this regard. That there is an opportunity – and FERC has done this repeatedly over the years – to use RTOs as laboratories of innovation in a sense, allow some different approaches to be developed and to let those different approaches then inform best practices over time.”
He said that once best practices can be identified, something closer to a one-size-fits-all approach could be brought forward.
Joe Bowring, the market monitor for PJM, said that “we need to think not about what some individual RTO is doing at the moment,” but rather what the sustainable model would be for a significant expansion of DER-type resources, “which I think we will see.”
It is critical to think about how that works in a nodal system, Bowring said. “It’s not possible to predict congestion, it’s not possible to pre-define constraints that exist or don’t exist. A zone is way too big for aggregation.”
He said that there is “lots of aggregation that can occur behind nodes. There’s aggregation that can occur for settlements.” However, for purposes of injection into the grid, anything larger than a node would be problematic and create issues, “which are non-resolvable.”
Andrew Levitt, senior market strategist at PJM, stated that he shared Dr. Bowring’s concerns about dispatch across multiple nodes, but sees benefits from aggregation. He noted that PJM’s congestion is often unpredictable, and described the RTO’s proposed approach as to gather detailed data about individual units and avoid dispatch if doing so at a node would increase congestion.
In New York, the ISO released a DER roadmap in early 2017, noted Michael DeSocio, senior manager for market design at NYISO.
“The path that New York has been taking has been focused on a single node aggregation,” he said at the FERC conference. “There’s been a lot of discussion with our stakeholders on a multi-node possibility, but when we think about that in New York we get worried about how we’re going to deal with managing multiple transmission constraints at the same time and in New York that happens on a minute-by-minute, hour-by-hour basis – New York is highly transmission constrained.”
DeSocio said that “when we think about where we expect DERs to locate, first and foremost, we expect to see DER really come into New York in the load centers where we have a lot of transmission constraints.”
He said that in thinking about how best to integrate these resources into the system and the fact that “these are going to be resources that are injecting onto the grid, we wanted to make sure that we provided as much visibility and operational control as we could because we expect that as DER begins and starts to proliferate the system, it’s going to come really fast.”
Henry Yoshimura, director for demand resource strategy at ISO-NE, said that “when I think about the question of aggregation I think of this as being a method or a means toward another end. Aggregation – as I read the NOPR – talks about using that to facilitate the participation of small resources in the wholesale market,” as well as to ensure that the dispatch of these resources contributes to a secure and efficient market.
He said that the new resources coming into the New England system are primarily solar PV and energy efficiency, noting that these are non-dispatchable resources.
Yoshimura argued that implementing the NOPR “won’t really facilitate their participation in the market because these are things that can’t be dispatched anyway, so aggregating them to facilitate their dispatch in the wholesale market doesn’t really contribute to the ends towards which aggregation was designed.”
“The ISO does not see a need for an additional DER participation model for New England at this time,” Yoshimura said in written remarks submitted for the conference. “Implementing the DER participation model envisioned under the DER NOPR would be costly and disruptive, and will not bring any additional value to New England. We believe that there would be little to no interest in participating in that new model if implemented in parallel with the current approach. And if the new model replaces the existing approach, DERs will likely exit the wholesale market.”
LaFleur raises coordination process question
FERC Commissioner Cheryl LaFleur raised the question of why there should be process differences “and how we figure this out or address this among the different regions.” She said, “shouldn’t we try to solve the coordination process once and then sort of spread that, as opposed to developing six different ways to do it?” Putting aside political and regulatory reasons, she asked panelists to address the technical reasons “in your rates or your market design that I don’t understand why it has to be different.”
ISO-NE’s Yoshimura said that there “really isn’t consensus in the industry as to how distributed energy resources ought to be operated, if at all. The struggle that any ISO would have is, whereas we model transmission constraints, I don’t think any of us model distribution constraints.”
But then the question becomes, who is going to do that? “Who should be operating these resources? We don’t have consensus about that,” he said.
“I don’t think we have consensus in the industry, let alone in a single state or within a region…what the architecture of this industry is with a greater penetration of distributed resources. Once we have that nailed down, I think” it becomes easier. “At least we know what we’re aiming for. Right now, I think we’re kind of struggling with some of these basic questions as to who’s going to operate these things and then” how would, for example, a distribution system operator communicate with a grid operator?
“I think what’s important to understand when we think about the opportunity for identifying best practices through innovation that can occur in different places in different ways, is that we’re all facing different challenges,” said MISO’s Bladen.
“To the extent that we could imagine everybody’s grid is going to look identical – is going to have identical technologies, identical investments in distribution automation -- then maybe today we could say, absolutely, we could solve this challenge. I think where we are right now is we don’t know what best practices are going to look like, we don’t know yet what the dominant DER technologies are going to be.”
At same time, “what you have in front of you is a number of companies that are invested in identifying best practices,” some of which are beginning to emerge, but “we still need to figure out how do we get them to the point where we could actually translate them to other places.”
PJM’s Bowring said that “we should have the same rules and the fact that there are all these complexities it doesn’t mean we shouldn’t have the same set of rules. The same set of rules will evolve, but we need to start in the same place where everyone’s facing the same issues.”
Duplication of service
DERs can both sell services into the RTO/ISO markets and participate in retail compensation programs.
To ensure that that there is no duplication of compensation for the same service, in the NOPR the Commission proposed that individual DERs participating in one or more retail compensation programs, such as net metering or another RTO/ISO market participation program, will not be eligible to participate in the RTO/ISO markets as part of a DER aggregation.
A panel on April 10 explored potential solutions to challenges associated with DER aggregations that provide multiple services, including ways to avoid duplication of compensation for their services in the RTO/ISO markets, potential ways for the RTOs/ISOs to place appropriate restrictions on the services they can provide, and procedures to ensure that DERs are not accounted for in ways that affect efficient outcomes in the RTO/ISO markets.
Panelists were asked by a FERC staff member to comment on whether it is possible to universally characterize a set of wholesale and retail services as the “same service” and, if so, how FERC could prohibit a DER from providing the same service to the wholesale market as it provides in a retail compensation program.
“Yes, it is possible to establish a way to determine whether retail and wholesale programs should be considered the same service,” said Katie Guerry, Vice President, Regulatory Affairs, EnerNOC.
She said a key element of determining what a same service is relates to what the dispatch trigger is. “So more specifically, what is the time of required performance? Is it the same? If it is, then you have a same service,” Guerry said. Later, she added that a resource should not get payments for same energy, but can receive dual capacity payments in different markets.
The question is not whether or not “we can avoid classifying something as wholesale or retail. It’s whether or not we should classify an entity or an entity should be able to be retail and wholesale at the same time, or kind of mix and match,” Zummo said.
He said he agreed with sentiments voiced at the conference that states should make the determination whether or not there is the ability to mix and match.
While states may be able to make such a determination and, more specifically, from a technology point of view, “I think we need to figure it out first before we set the rules because I think there are a number of questions we need to ask,” Zummo said.
Zummo said that “if we’re going to have entities that are kind of going back and forth between the retail and wholesale markets,” it necessitates going beyond AMI, as we will need metering with enhanced communication channels to distinguish when an entity or resource is acting in a retail capacity or a wholesale capacity, he said.
Moreover, “if we are going to have new technologies, we’re going to have to create new resources to be able to mix and match,” the Association official told the FERC conference. But this “creates a burden” for small and medium-sized utilities, Zummo pointed out.
“We are entering a new paradigm where utilities are really looking at new types of rate design – time of use rates, demand charges for residential, and then some rate design in the context of distributed energy resources like value of solar, net billing, by all/sell all,” he said.
As utilities do these rate designs, “whether or not it’s in the context of DER or not DER, especially for medium-sized, small municipal electric utilities, their margins for error when they’re doing load analysis, when they’re doing the cost of service analysis that set these rates, there’s a very small margin for error,” Zummo said.
“So I think the question that we have to answer before we proceed is really how is that going to affect these retail rate designs? How is this going to impact cost recovery for these utilities” in an environment where there are entities or resources that can toggle back and forth between retail and wholesale markets.
“I think that creates a real issue for cost recovery and I think that’s something we have to consider before we go forward,” Zummo said.
Panelists were also asked to discuss what other options besides the NOPR’s proposed limits on dual participation exist to address issues associated with the participation of DERs or DER aggregations in one or more retail compensation programs or another wholesale market participation program at the same time as it participates in a wholesale DER aggregation.
Zummo said “I think our organization’s stance is that we largely agree with the NOPR’s prohibition, but if we were to move past it – if some of the operational concerns that I expressed initially were addressed and we moved to a different compensation and we allowed some back and forth – I think I’d just have some general principles that should be kept in mind.”
For example, he said that predictability is very important. “I think we have to set clear rules and distinguish between services and compensation for those services,” he said.
In addition, “anything we do has to be fairly automated,” noting that with small and medium utilities there is limited staffing, so “the mechanisms have to be fairly automatic to not strain those already limited resources.”
Also, “we have to respect that local utilities have their own unique programs meant to encourage DERs and energy efficiency, and I think the market rules have to respect those unique programs.”
State/local utility regulators
A third panel on April 10 offered a forum for FERC commissioners to discuss the NOPR’s DER aggregation proposals with state and local utility regulators.
FERC Chairman Kevin McIntyre said that his principle concern is that as DERs are brought onto the grid, “we avoid messing anything up.”
He asked the regulators to discuss the potential negative impacts that DER participation in the wholesale markets could have on distribution systems in their states.
AMP’s Norton noted that most of AMP’s members are not subject to state jurisdiction, so city councils “are the regulator.”
The operational concern “there is that there has to be coordination, they have to know what is going on. Their utilities need to know what DER is being registered and they have to have the time to be able to look at it and make sure you’re not jeopardizing facilities.” For example, if the utility needs to conduct maintenance on a line, the DER will need to make itself unavailable such that there is no risk of electrocution.
Norton said that there are “a whole host of issues and it all has to happen through coordination and it’s not that it can’t happen. There just needs to be a good, tight coordination between the market operator and those individual municipalities and the state utilities.”
Michael Picker, president of the California Public Utilities Commission, said that there are operational issues. “I worry far more about congestion in the distribution system as a result of the growth of DERs in California,” he said. Why? Because the state has a grid system “that was never designed for two-way flows.”
Ted Thomas, chairman of the Arkansas Public Service Commission and president of the Organization of MISO States, argued that “the distribution operations have to be managed by some entity in a different way than we’ve had to do in the past.”
Thomas said that for “both safety, for curtailment, somebody has to have the authority when there’s a system problem to turn things off. The systems to do that don’t yet exist,” Thomas said. He also recommended that at least in the beginning, the states that should be permitted to choose whether resources may participate in both wholesale and retail markets, or be prohibited from doing so.
“Are there operational concerns? Yes,” said Asim Haque, chairman of the Public Utilities Commission of Ohio. “Can they be overcome? We think also yes.”
He noted that the PUCO recently completed a grid modernization proceeding called Power Forward.
“Like you, we are trying to figure out how to harness the benefits of distributed energy resources,” Haque said.
What the PUCO learned in part from the Power Forward proceeding is that the distribution utility role “and their set of competencies are going to have to expand as are state commissions’ role and competencies going to have to expand.”
He said that as DERs proliferate “there will have to be impact analyses, hosting capacity analyses, all of these engineering things that from a state regulatory standpoint are items that we don’t typically see at the agency.”
California regulator highlights SMUD’s efforts
At a later point, in response to questions from LaFleur, Picker said that “there are distribution system operators who actually have pretty good management tools to operate the system with a high penetration of DERs.”
He cited California public power utility SMUD as an example. “They actually have visualization of large parts of their grid. The know exactly what is where. That came about as a result of their investments in advanced metering infrastructure and a lot of fiber for other purposes. They wanted to get a time of use rate structure in place.”
SMUD “started to see some of these other DER resources showing up and they wanted to be able to visualize it and see the impacts, so they started that grid mapping process.”
Also, the utility “developed in concert with some software companies tools that actually let them see that and then they actually began to coordinate that with their weather maps” in order to ultimately “get very real-time impacts of generation from rooftop arrays behind the meter.”
Panels at day two of the conference examined the collection and availability of data on DER installations, incorporating DERs in modeling, planning and operational studies, coordination of DER aggregations participating in RTO/ISO markets and ongoing operational coordination issues. Many of the panelists discussed the difficulties of modeling the distribution system.
The second panel on day two included discussions of the role of the distribution utility. Audrey Lee, Vice President, Energy Services, Sunrun, stated that the utilities should not be the gatekeeper for distributed resource participation in the wholesale markets, but instead serve as a “facilitator.” David K. Owens, retired Executive Vice President, Edison Electric Institute stated that the utility must have a list of all DERs, their attributes and how they impact the system. The utility should then be able to take needed action to protect reliability, if a distributed energy resource is disruptive to the system.
Daniel Hall, Chairman, Missouri Public Service Commission and Vice-President, Organization of MISO States similarly stated that the utility needs to ensure that the DER is not going to harm the reliability and safety of the system.