An unprecedented collaboration between California’s grid operator, its investor-owned utilities, and third-party distributed resource providers could streamline electric system communications in preparation for higher distributed energy resource penetration.
The groundbreaking work maps out plans to interconnect the bulk transmission system to distributed energy resources (DERs) through utility-operated distribution systems, achieving a new level of communication between the transmission system operator, the distribution system operator, and the DER provider.
Technology advances and customer demand are transforming the electric power, according to a newly-released report from the California Independent System Operator (CAISO), Pacific Gas and Electric (PG&E), Southern California Edison (SCE) and San Diego Gas & Electric (SDG&E).
DERs are beginning to reach significant penetration levels on the emerging “decentralized system,” and are on their way to becoming key resources, the paper noted. A working group led by think tank More Than Smart (MTS), which included the IOUs, CAISO, and DER providers, released the paper at the end of the first year of a multi-year effort.
The group’s objective is to resolve operational challenges preventing transmission operators and distribution operators from working with private sector developers to meet consumer demand for DER, said MTS President Tony Brunello.
Jeffrey Nelson, SCE Director of FERC Rates and Market Integration, said that DER demand is driving a “transformation in the way we operate the grid.” The utility, Nelson said, wants to be involved “in shaping that transformation.”
It has never been necessary before for transmission and distribution operators to coordinate, added Lorenzo Kristov, a market and infrastructure policy principal for CAISO. But as DERs proliferate, efficient dispatch of those resources in wholesale power markets will require communication between DER providers, distribution operators and the transmission operators.
Power sector experts agree proactive information exchanges will be necessary on tomorrow’s grid. This working group, which is endorsed by all three stakeholder groups, is the leading effort to build that coordination framework, Krisotov said.
What’s happening at the transmission-distribution interface
The transmission and distribution systems are interconnected, but are distinct and have “different structures, characteristics, functions and operating principles,” the MTS white paper noted. Because of that, crafting communications to bridge the different systems and DER providers is key to handling higher DER penetration.
The transmission system delivers central-station generated electricity to utility-operated distribution systems via transmission-distribution substation “interfaces.”
Transmission operators have “little to no visibility” into the distribution system, the white paper noted. But with only central station generation flowing one way through transmission -distribution interfaces, there has been no need for visibility.
DERs are defined as resources connected to the distribution side of the transmission-distribution interface, according to the paper. In California, across the U.S., and around the world, policies and incentives are driving down the cost of DERs and spurring customer demand, MTS reports. In California, DERs make up 10% of peak demand, and some forecasts predict an installed capacity doubling before 2030.
Private providers see new value propositions in delivering aggregated DERs to wholesale markets while also serving retail customers, MTS reported. CAISO and the California Public Utilities Commission (CPUC) are working to lower barriers.
But growth introduces new operational complexities because of the lack of visibility of transmission operators into distribution system-interconnected DER described by the white paper.
“This lack of visibility may result in the ISO issuing dispatch instructions to DERs that the [resources] are unable to comply with due to distribution system constraints,” MTS reports. It may also create operational complications for [distributed operators], making streamlined coordination and communication at the transmission-distribution interface “even more important.”
The paper evaluates two timeframes: a near-term outlook to 2018 and a mid-term outlook into the early 2020s. In the near term, a relatively low DER penetration will make aggregated DERs only a small factor in the wholesale market.
Towards the mid-term, wholesale markets are likely to see “much higher volumes and diversity of DERs and DER aggregations.”
The paper considers three DER use cases in those timeframes: In one, DERs provide services only to the wholesale market. In another, those resources provide services to the distributed operators or end-use customers but not to the wholesale market. In the third, DERs provide wholesale market and end-use customer services, as well as services for distributed operators.
As these scenarios move from the near term to the mid-term, increased coordination and communication across the transmission-distribution interface will become critical.
“DER providers have to be informed of current distribution system changes that will affect their operation,” Kristov said. And the transmission operator’s' dispatch instructions to DER “need to be communicated to the distribution operators.”
The paper recommends steps to achieve the needed coordination and communication.
For 2017,CAISO and the distribution operators, supported by DER providers, should “initiate, pilot, and test” ways to move beyond manual procedures, the paper proposes. To allow providers to modify market bids when necessary, “[Distributed operators] should pilot processes to communicate advisory information on current system conditions to DER providers.”
CAISO needs to develop ways to provide day-ahead DER dispatch schedules to the distribution operators so they can anticipate potential “reliability or performance problems,” MTS adds. This type of communication could be incorporated into DER Management Systems (DERMS).
DER providers need to be able to communicate constraints on their resources to CAISO, MTS reports, which could be modified market bids or outage notifications.
Finally, the distribution operator and the DER provider should have a formal “integration agreement” for aggregated DERs, similar to an interconnection agreement while delineating responsibilities in the event of disruptions.
For the mid-term scenario, the paper recommends exploring new utility business models that call for today’s utilities to act as distribution system platform operators (DSOs).
Participants should also “develop and pilot” methods of forecasting DER “activity and impacts at T-D interfaces,” MTS recommends. And stakeholders need to expand understanding of how high DER penetrations may impact distribution system safety and reliability and identify ways to mitigate threats.
Matthew Tisdale, the executive director of MTS,said overall, the DER transformation remains too hazy prescribe more precise solutions. But the working group allows CAISO and distributed operators to work proactively on more precise planning with DER providers who are “disrupting the way the grid has been run.”
Why the utilities are in
Some utility officials agree the foremost objective of participating in the workshop was to ensure the utility transformation protects distribution system safety and reliability.
“A lot more can happen on a distributed system,” said Mark Esguerra, PG&E’s director of integrated grid planning, said. “Being able to provide advisory information on events to providers will be key to them knowing if their market participation will be impacted.”
The current low penetrations of DERs can be served manually with existing tools, but future penetrations will likely require a “a website or server that DER providers log into,” Esguerra expected. “It will certainly require utility investment in software capabilities and automation.”
PG&E also anticipates the need for pilot programs to test software capabilities, he added.
Esquerra sees two takeaways in the MTS work so far. One is that the distributed operators “don’t have the same level of visibility, control, and situational awareness on DER that CAISO has on transmission-connected generation.”
The other is that the transmission operator, the distributed operator, and DER providers “all stand to benefit” from improved communication and coordination across the T-D interface.
SCE’s Nelson said it is noteworthy that the paper acknowledged the complexity of developing greater coordination between the three system participants. “A much more sophisticated coordination than what is in place needs to be envisioned.”
Each of the three participants has part of the system information needed “to know if market transactions are feasible,” Nelson said. “But none has enough information.”
He endorsed the paper’s near term and mid-term scenarios. “It offers no specific remedies but reports that monitoring, visibility, and control of the distribution system needs to be synchronized with the complexity it has to deal with.”
The MTS working group is “about getting out ahead of the coming transformation,” Nelson added. “If that does not happen, the electric power sector will not be ready to provide customers with the choice they are demanding and to use DER to help meet the state’s goals.”
SDG&E’s director of electric transmission and distribution engineering Will Speer said that even beyond specific takeaways, “the best thing that happened was us sitting around the table and discussing what the future will look like.”
They did not engage in controversial questions about rate design or the costs and benefits of DER, he added. They focused “purely on operational issues.”
A framework on which to build coordination and communication is not urgently needed at present but “we need to establish a process,” Speer said. “A DERMS or some other kind of platform or control system will eventually be necessary but we are not there yet.”
To determine the exact hardware or software infrastructure needed to streamline coordination and communication, “there has to be a bigger DER sample size,” Speer said.
Once such an infrastructure is built, “we will be able to operate in a high DER future with the resources participating in wholesale markets,” Speer said. “That would reduce cost for all our customers.”
Modernizing the system will include a DERMS-like platform that provides automated monitoring and control systems, Speer agreed. That will provide distributed operators with the kind of distribution system visibility CAISO has at the bulk system level. It will also give DER providers the system status signals they need and keep the distribution operators in the loop.
The providers’ perspective
On the third-party side, Advanced Microgrid Solutions (AMS) and Green Charge Networks described the communications proposed by the paper as a “connective tissue” to allow cost-effective management of the grid.
It’s crucial because “visibility and control don’t talk to each other and can’t be managed without communication,” said AMS CEO Susan Kennedy, also an MTS board member.
Solutions for communications at the T-D interface “are the key technical and regulatory issues in distribution system operations and will be the foundation for integrating DER,” Kennedy said.
Michael Grabstein, AMS' working group representative and grid sercices project manager, said the paper’s communications proposals are essential to the limited-scale DER aggregation now being done by AMS. “To provide a capacity resource for the ISO, we have to ensure the [distribution operator] does not constrain us.”
AMS' vice president of markets and policy Manal Yamout said AMS’s newest project will deliver a 90 MWh fleet of resources to SCE. “Without communications, that could cause havoc on the distribution grid instead of displacing the need for transmission and distribution upgrades and providing services to the customer.”
The paper’s communications proposals will make aggregated DER, and especially distributed energy storage, dispatchable grid resources, Yamount added. “The key to storage economics is enabling multiple uses of a single asset and that can only happen if everyone who wants to use that asset always knows what’s going on in real time.”
GCN’s vice president of policy Walker Wright said working group participation is crucial for DER providers. “Regulatory intelligence and business development go hand in hand,” he said. “Providers need to be at the table to hear the perspectives of utilities, regulators, and other stakeholders as they build a framework for new DER markets.”
While the working group strives to develop cooperation on the complicated interactions between the three interdependent parties interacting at the transmission-distribution interface, Wright noted ultimately all parties want the same outcome.
“Utilities and DER developers want the same thing, which is to satisfy their customers,” he said. “Consumer demand is the force building the grid of the future and it is important to go back to the kitchen table and ask the question high level regulatory conversations can miss: What is driving consumers?”
