New, smart DER can go beyond customer benefits to help stabilize utility systems.
Proof is emerging that distributed energy resources (DER) can deliver services to the power system in addition to the customers who buy and install them.
DER advocates say the resources can respond quickly to the grid’s need to ramp generation up or down, store over-generation and control system frequency changes and local voltage fluctuations. Pilots are in place across the country to prove DER can fulfill these promises, and interest from utilities and system operators, driven by market factors and policy mandates, is growing fast.
“DER is not just rooftop solar anymore, it’s also storage, demand response and smart inverters, and it is smarter and costs less. This is not your grandma’s DER,” said Ric O’Connell, executive director of GridLab and co-author of a new paper on how DER can be used to meet grid needs.
According to the paper from GridLab and GridWorks, one word explains the rising interest in DER as grid services: flexibility.
The uses of flexibility
The evolving system’s variable demand and supply, and two-way power flows create an unprecedented need for the fast on-off flexibility that DER, and especially battery energy storage, offer.
“Storage is changing the DER landscape,” the paper reports. Commercial-industrial customers are using it to shift their usage, cut demand charges or participate in demand response (DR) programs. Residential customers are pairing storage with solar to reduce their usage when rates make electricity more expensive.
The grid’s use of DER falls into three broad categories, according to Tanuj Deora, chief technology officer for the Smart Electric Power Alliance (SEPA). First, DER can be a non-wires solution (NWS) that replaces a more costly build or upgrade of transmission and distribution (T&D) system infrastructure to meet reliability needs at a local site.
Second, customer-sited DER across a distribution system can meet system-wide frequency or ramping needs, Deora said. The DER could be solar-plus-storage, electric vehicle (EV) fleets or customer-owned hot water heaters.
Third, distributed generation (DG) of any kind can be paired with storage to maintain a normal production curve on systems with high renewables penetrations, despite disruptions like clouds and demand spikes.
“Economies of scale give large-scale renewables and grid infrastructure the advantage for the majority of applications,” Deora said. DER can be deployed at a small scale, and then scaled when proven, “a slightly more expensive, but less risky, approach.”
The potential for DER depends on “finding the right locations where DER can provide a benefit to an established system need,” Kevin Hernandez, a director with business consultant ScottMadden emailed Utility Dive. “We are just at the tip of the iceberg of understanding the value DER can provide to the grid.”
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Residential deployment of battery storage grew by 202% in MW and 317% in MWh in 2017, according to SEPA’s latest energy storage market report. SEPA’s survey of 137 utilities found 10.6% have implemented an NWS, 17.6% are planning them and 54.1% are interested in learning more about NWS.
Of the 155 utilities surveyed in SEPA’s most recent DR market report, only 5.7% have paired solar, storage and other DER in DR programs to meet reliability needs. But 18.7% are planning to do so and 53.7% are interested in doing so.
NWSs have been implemented to meet grid needs and avoid T&D upgrade expenditures by only 4.9% of surveyed utilities, SEPA found. But 20.3% are planning deployments and 49.6% are interested in NWSs. Over a quarter or utilities, however, still have no interest.
Use of aggregated DER is expected to grow after work is completed by system operators to implement Order 841, issued by the Federal Energy Regulatory Commission in early 2018. Grid operators were directed to prepare market rules allowing dispatchable aggregated storage to sell into capacity, energy and ancillary services wholesale markets.
But it is not yet clear how DER may avoid the costs of incumbent technologies “or where DER may add costs,” ScottMadden’s Hernandez cautioned.
The role of DER
DER demand comes from customers who want to choose where their energy comes from and manage that use, but for now, integrating utility-scale variable renewables into the power system “is the central challenge” of the utility industry, the GridLab/GridWorks paper reports.
However, DER provides utilities and grid operators with “new flexibility” to integrate those renewables, it adds.
“Regulators, utilities and system operators tend to look at DER as a problem because they exacerbate over-generation and are not visible or controllable,” O’Connell said. “But new smart technologies have changed that.”
Customer-sited resources reduce the utility’s need both for new utility-owned generation and for T&D infrastructure, the paper reports. They also tend to keep customers connected to the grid, both to be able to supplement their own generation with grid-supplied power and to be able to take advantage of compensation for excess power exported to the grid.
Battery energy storage can make DG a dispatchable resource because charge and discharge can be controlled which shifts usage away from high-priced electricity times, but also flattens peak demand and creates potential for customer-friendly time-of-use (TOU) rates.
Both O’Connell and ScottMadden’s Hernandez stressed that rate design will be key to the integration of DER into power systems in a way that allows them to deliver grid services. But SEPA’s Deora cautioned that new rate designs that encourage DER use must not “overcompensate and enable gaming the market.”
Batteries paired with smart inverters can serve the system by responding almost instantaneously to stabilize voltage and frequency shifts, the paper reports. The tools’ intelligence allows system operators to see and limit impacts of distribution grid disruptions.
EE reduces utility kWh sales. But if incentives increase EE when or where a distribution system upgrade cost would be greater than the combined costs of the incentives and the lost sales, the utility profits.
DR can shape and shift load to meet many of the same grid needs as other DER. But its impacts are subject to the control of the system operator, which allows pre-planned, time- and place-specific impacts that increase system flexibility even more.
Consumers don’t buy EVs to provide grid services, the paper acknowledges. But utilities that manage charging smartly can grow their kWh sales without adding significantly to system costs. TOU rates have been designed to move charging toward when the system’s renewables penetration is highest and away from the system’s peak periods.
DER can be combined to maximize their value to the grid and the customer while also adding to system resilience, the paper reports. A customer with a smart inverter-controlled solar-plus-storage system and an EV owns both dispatchable generation and on-site-powered transportation. But that DER can also respond to a grid operator’s need for supplementary generation or system stabilization.
Utilities can aggregate system-wide EE, DR, EVs and solar-plus-storage systems while “engaging a range of residential, commercial, and industrial customers,” it concluded. “[T]he technologies and customers can contribute to a whole which is greater than the sum of the parts.”
From the front lines
There are relatively few examples of DER successes in providing grid services because “this is new territory,” O’Connell said.
The flagship use of aggregated DER as an NWS is the Brooklyn Queens Demand Management (BQDM) project. New York City’s Consolidated Edison deferred a $1.2 billion substation upgrade with $200 million in contracts for 69 MW of DER and DR.
The BQDM project teaches two key lessons, the paper reports. One is that a utility can do a successful NWS through a “traditional distribution planning process.” The other is that aggregated DER “spread across diverse customers” can “address big grid needs.”
In terms of other examples, in upstate New York, Central Hudson Gas and Electric has been operating Peak Perks since 2016. It has now aggregated 8.8 MW of DER involving 2,968 participants and has “not experienced system issues as a result of the program,” according to spokesperson John Maserjian.
In March, California regulators approved the Oakland Clean Energy Initiative, a joint undertaking of Pacific Gas and Electric and East Bay Clean Energy (EBCE), which will use up to 45 MW of DER to replace an outdated fossil fuel peaker plant. This “landmark example of DER serving transmission reliability needs” will cost $102 million instead of the $537 million in transmission infrastructure that would have been needed, the paper reports.
Since 2013, Southern California Edison has been working on what may be the most significant portfolio of DER yet in use. It has now deployed 112 MW of DER, including EE, DR, DG and energy storage and, by 2022, its portfolio “will consist of 265 MW of DER,” Sergio Islas, a senior advisor to the SCE program, told Utility Dive.
In Hawaii, DER penetration was causing stability-threatening “overvoltage” and “frequency disruptions” for the Hawaiian Electric Companies (HECO) grid as early as 2015. However, continued growth of DER has been made possible in the state through “advanced inverter requirements on new solar installations and a suite of tariffs,” according to the paper.
A new DR program will supplement these regulatory actions with “capacity, fast frequency response, regulating reserve, and replacement reserve” obtained from customer-sited DER.
The utility is convinced that customer-sited DER and smart technologies “can solve bulk system needs” and DER penetration could “realistically grow” to 20% or 30% of peak system capacity, HECO Director for Demand Response Richard Barone emailed Utility Dive.
As these early projects prove the value of DER, policymakers can begin to think of it “as a way to help the grid transition, rather than a frustration,” O’Connell said.