For utilities and system operators who find that coping with all the new distributed resources on the grid is like holding an armful of marbles, you may have a new — and rather unexpected — best friend: SolarCity.
The leading U.S. solar installer’s new white paper, "Integrated Distribution Planning," aims to get all the new grid resources and their uses organized so they can be put to the best use by power companies and system operators.
“It starts with the assets themselves,” explained SolarCity Senior Director of Grid Engineering Solutions and white paper author Ryan Hanley.
The assets are distributed energy resources (DERs), which include distributed renewables like rooftop solar as well as advanced inverters, stationary energy storage, electric vehicles, and technologies that allow for demand flexibility — the ability of utility customers to control their electricity use and participate in energy efficiency and demand response programs.
Programs for individual DERs at utilities “have been successful and pushed engagement,” Hanley said. “But that approach limits the true capability of these assets. As an aggregate portfolio of multiple assets, these diverse assets accommodate for their individual weaknesses and become more powerful.”
By modernizing utility interconnection, planning, procurement, and data sharing processes, utilities and distribution system operators can capture the benefits of DERs in bundles to both meet distribution needs and expand customer choice, the white paper explains.
The idea to aggregate was put forward some months ago by former Texas utility executive and utility commissioner Karl Rabago.
“The time has come to complete the transformation of the electric utility sector,” he wrote in a blog post in February. “A deliberate and sustained effort to establish robust markets for distributed energy services is the major remaining step in that process.”
“It is imperative to transition to a grid that actively leverages the wave of renewable distributed energy resources,” Hanley’s paper explains, because it is a way of “engaging customers in energy management, increasing the use of clean renewable energy, improving grid resiliency, and making the grid more affordable by reducing system costs.”
How the new responsive grid would work
Under the paradigm of distribution system planning that Hanley and his colleagues are pushing, utilities could meet system needs with aggregations of distributed resources, put together by companies like SolarCity.
“Today, a utility thinks of control as a fiber line going directly to a generator,” Hanley said. “In the future, a utility controls our assets through an interface at a substation.”
Under that system, the utility communicates its need through the interface in grid terms, asking for capacity or reactive power or another ancillary service. SolarCity or another supplier commits to meet the need and then uses aggregated DERs in the region served by the substation to meet the utility's demands.
“We don’t tell the utility how we will do it because every day it will probably be a little different,” Hanley said.
SolarCity would look for the most economic portfolio of assets to meet any given utility need. One day it might be part pre-contracted reduced customer consumption, part reimbursed customer consumption cuts, and part purchased energy from batteries. Another day it might include solar from roofs where customers are not home, or power from parked electric vehicles as well as reduced consumption.
“The utility gets what it needs every single time because we have a firm contract to deliver,” Hanley said. “The way we make money is getting good at optimization, at making sure our assets are available.”
Utilities would need to be no more concerned about SolarCity fulfilling its “contract to deliver” than they now are about central station power plants meeting their obligations, Hanley said. “The key is to make the financial disincentive so punitive that people show up. We are ready for that.”
DERs can support the grid, and in many ways do it better than the assets now available, he added.
“The premature retirement of the San Onofre Nuclear Generating Station cost Southern California ratepayers over $3 billion," Hanley said. "With distributed resources, there is never one big asset that fails. There will be small ones that fail, but having a stranded cost of over $3 billion would not happen.”
Rabago applauded SolarCity’s attention to DERs and the distribution system because it meets the “glaring absence of adequate, comprehensive, integrated distribution planning.” But, he reminded, “you still have to plan for the rest of the system.”
The Distribution Loading Order
To modernize procurement for the distribution system, the white paper offers its biggest innovation.
System needs are today met through procurement of “utility-owned distribution equipment such as transformers, capacitor banks, reconductored wires, and other capital equipment,” it says.
“To fill the need they don’t procure, they install equipment,” Hanley explained.
In a high DER penetration future, “distribution planners must be willing and able to consider the full range of solutions,” the paper says. To lead planners there, the paper proposes a new distribution-level policy concept to encourage utilities to use DERs instead of traditional energy solutions when they are cost effective. It's called the Distribution Loading Order.
Some states have a system level loading order. California, Hanley noted, requires its regulated utilities to consider energy efficiency first, followed by demand response, and then renewables and distributed generation, before the grid operator can look to traditional generation.
“This procurement loading order puts the traditional ‘least cost, best fit’ solution in the ground,” Hanley said. Efficiency, demand response, and renewables are bypassed if they are not price competitive. “If fossil fuels are the cheapest, they get picked.”
Similarly, SolarCity’s loading order “prioritizes the utilization of individual DERs or portfolios of DERs over traditional utility infrastructure, when such portfolios are cost-effective and able to meet grid needs,” the paper reports.
The idea is to “use DERs before traditional capital grid investment if DERs are cheaper than or the same price as doing a substation upgrade,” Hanley said. “If DERs are not cheaper, pick the upgrade.”
Utilities and distribution system operators should consider two DER opportunities before turning to hardware, according to the paper. First, are “DER portfolios that voluntarily respond to price signals sent from the utility that incent the desired behavior to meet grid needs.”
SolarCity customers with solar-plus-storage, smart thermostats and meters could readily respond to price signals to alter their usage when system demand peaks, Hanley said. “If utilities do substation upgrades, they won’t use these low marginal cost resources.”
If those DERs do not meet the “least cost, best fit” standard, procurers should turn to “DER portfolios that are contractually obligated to deliver grid services based on contracted prices.”
Only if planners conclude these options cannot meet system needs should they turn to hardware upgrades, Hanley said. “This extends the tool kit utilities have to meet their distribution system needs, and if they follow the economic principle of ‘least cost, best fit’ it also guarantees that ratepayers are getting the best solutions available.”
The distribution loading order concept impressed Rabago.
"We have long claimed to use 'economic dispatch' as the protocol,” he observed. “But best buys don’t actually go first. Rather, the system loads baseload to recover capacity costs, then continues to dispatch from least to most dispatchable.”
SolarCity’s loading order could be the needed protocol, he thought. But also needed at the system level is a “‘load management utility’ with performance standards rewarding maximum reliance on DER first, and then using large-scale resources only as necessary.”
The paper’s discussion on interconnection modernization comes down to a relatively simple idea that covers a lot of ground: “Streamline the DER interconnection process, eliminate unwarranted costs, and expand allowable interconnection approvals.”
The paper offers an array of granular improvements on ideas presented elsewhere, Hanley said, because, as the paper notes, “the pace of change is measured…[and] a more comprehensive set of enhancements is needed.”
A key improvement, it says, would be utilities incorporating “automated DER Hosting Capacity analyses into the interconnection review process to increase allowable interconnections while decreasing the application review timeline.”
“The extensive detail on interconnection will benefit all DER, and is long overdue,” Rabago said. “SolarCity has the national reach and visibility to add value to this discussion.”
The planning modernization section covers much of the same ground as the California Public Utilities Commission (CPUC) Distribution Resource Planning (DRP) proceeding but “we try to push that ahead,” Hanley said.
“The goal is to identify locational needs across the [distribution] grid, just like they do on the transmission grid," he said.
As the presence of DERs increases, customer choice must also be accommodated into grid needs, the paper reads.
“Utilities will need to become much more proficient at forecasting customer DER growth than they are today.” With a more detailed understanding of what is coming, it adds, planners will be able to find DER alternatives to procured investments “at low or no cost.”
The analysis should not be limited to technical capacity but should “be informed by economics,” Rabago said. “We need value-based analysis of DER so that best buys can go first…[and not] resources that offer suboptimal value.”
DER providers need operational and planning data to achieve optimization and drive innovation, but utilities make little of it available, the paper asserts. “Solely publishing outcomes of utility analyses rather than sharing the underlying data does not enable sufficient industry stakeholder engagement,” it reports.
There are five categories of data that utilities must commit to sharing, SolarCity believes:
- Locations where DERs would be of most value to the system
- The circuit by circuit capacity of the system
- Locations of planned investments in the system for which DERs may reduce the need
- Real-time and historical operational data that points to how DER portfolios can meet grid needs
- Pricing data and event statistics that would support transactive markets
To allow DER providers to serve the system, the paper says, utilities must make the data accessible online and downloadable. System maps made available by Southern California Edison and Pacific Gas & Electric in the CPUC’s Renewable Auction Mechanism program and the DRP proceeding are examples of data sharing that, while not perfect, are innovative, Hanley said.
The practice of utilities holding data unavailable to the market is part of an outdated business model, Hanley said.
“Companies that can crunch more data than the utilities have ever seen are on the sideline because they can’t get access,” he explained. “But it has been shown time after time that if you share data, innovation will accelerate and it is good for consumers.”
In the role of system support, SolarCity could send sales teams to circuits where there will be upgrades and avoid circuits without capacity.
“Utilities will say they can tell us where to install or the hosting capacity on a circuit and you don’t need the underlying data,” Hanley said. “But there will be new questions tomorrow that can only be answered by having the data.”
Rabago applauded the paper’s data and transparency discussion.
“This adds important detail to a discussion that is too often very generalized," he said. "It will also be a huge battleground.”
What the paper proposes “is a new paradigm and it will take time,” Hanley said. But utility engineers think about DERs like any technology and are becoming more comfortable with them every month.
"As DERs become cheaper, [utilities] will use more of the products," he said. "It is already reaching a tipping point.”