How California's biggest utilities plan to integrate distributed resources
New plans filed with state regulators show where DERs should go and how much they are worth to utilities
California’s big utilities just took a leap into the future.
In recent filings with the California Public Utilities Commission (CPUC) on how to get the best from distribution system resources, Southern California Edison, Pacific Gas & Electric, and the state's other investor-owned utilities take a clear-eyed look at the future of electricity delivery.
Their plans and the research that went into them could shed new light on how best to site, integrate and value energy resources on the distribution grid, tasks that utilities across the nation have struggled to perfect. In the process, the companies will further define their roles and business opportunities on the distribution grid, likely setting precedents for regulators and power companies across the country.
What is in the California Distribution Resource Plans? Utility Dive spoke to officials from Southern California Edison and Pacific Gas & Electric to find out. Plans were also filed by San Diego Gas and Electric, Liberty Utilities, PacifiCorp, and Bear Valley Electric Service. They will be profiled by Utility Dive in the coming weeks.
The distribution resource planning process
“Distribution planning should start with a comprehensive, scenario driven, multi stakeholder planning process that standardizes data and methodologies to address locational benefits and costs of distributed resources,” read the first of four key principles informing the CPUC’s Order Instituting Rulemaking.
The principles were intended to guide each utility in meeting the obligation under AB 327 to file, by July 1, a distributed resource plan (DRP) to “identify optimal locations for the deployment” of distributed energy resources (DERs).
The law defines DERs as “distributed renewable generation resources, energy efficiency, energy storage, electric vehicles, and demand response technologies.”
“From a distribution planning perspective, it most definitely allowed for thinking with tools we haven’t normally used,” Pacific Gas and Electric (PG&E) Principal Engineer and DRP filing lead Mark Esguerra said. “Instead of looking strictly at wires solutions, we started looking at DERs as non-wires solutions and at what the most cost-effective way of using them is to meet our reliability, safety, and affordability standards.”
The process forced IOUs to ask new questions, Esguerra said. “How do you better leverage distributed solar, storage, energy efficiency, demand response? Can we target locations where the profiles of those DERs could be effective at mitigating issues utilities see? How can you optimize your grid to integrate DERs into the facilities you have?”
“The filing is part of our vision of grid modernization,” said Southern California Edison (SCE) Director of Electrical System Planning Erik Takayesu. “This identifies a roadmap for what needs to be done on the distribution system from a technology perspective, what needs to be done to make the grid more robust, and what needs to change in the planning process to prepare the distribution system for higher penetrations of DERs.”
The public filing is in keeping with the second guiding principle of the DRP work, that “distribution system planning, design and investments should move towards an open, flexible, and node-friendly network system (rather than a centralized, linear, closed one) that enables seamless DER integration.”
Appended to the CPUC order was a white paper by Newport and CalTech Consultant Paul DeMartini. The paper, entitled "More Than Smart: A Framework to Make the Distribution Grid More Open, Efficient and Resilient" outlines the purpose, direction, and requirements of the DRP filing.
DeMartini's work came out of a collaboration between Caltech’s Resnick Institute, the Greentech Leadership Group, and the Governor’s Office of Planning and Research. Current CPUC President Michael Picker was among the participants in that collaboration. Its purpose was to define the changes necessary for a DER-ready grid. He is now the DRP “Assigned Commissioner.”
One of the guiding principles laid out by the white paper raises a critical question being asked across the U.S. as grid operators face rising penetrations of DERs. It asks the IOUs how a distribution system operator (DSO) can avoid conflicts of interest while sharing system operations with the California Independent System Operator acting "as a technology neutral marketplace coordinator.”
The last guiding principle assumes the value of DER to the grid as flexible capacity and asks the IOUs how it can be used to “optimize markets, grid operations and investments.”
“A lot of new distribution system planning methodologies for DERs were developed,” Esguerra said. “How do you integrate DERs in the most cost-effective way for serving the needs of the grid? They don’t really replace the wires. They optimize investments in the system.”
Three big asks
The three overarching practical exercises requested of each utility by the CPUC were to,
- Identify the full value of DERs to the utility,
- Specify where on the utility's distribution system DERs best provide value,
- Propose demonstration projects to prove their conclusions about value and location.
In addition, the CPUC asked each utility to identify three scenarios for DER growth, one based on its current trajectory, another based on a “high growth” of DERs, and a third based on very high growth.
All of these exercises required the utilities to develop quantitative methodologies.
“The intent is to create a set of mutually supportive tools,” the CPUC guidance document explained, “that detail how much DER can be deployed under a business as usual grid investment trajectory, and build the capabilities to compare portfolios of DERs as alternatives to traditional grid infrastructure.”
The guidance also asked for a wide range of proposals on how best to support future utility planning. They cover things like the handling of data, grid management, customer issues, barriers to deployment, and regulatory proceedings.
Integration capacity analysis
Each utility was required to provide an Integration Capacity Analysis to “specify how much DER hosting capacity may be available on the distribution network.” This must be a granular analysis and documented “down to the line section or node level” or “on a select set of representative circuits, including all related line sections.”
The CPUC’s intention was to streamline the utilities’ grid interconnection processes.
PG&E did the detailed analysis of its entire system. SCE chose the option of using 30 representative circuits which, the guidance stipulated, “must not be construed as a substitute for the ultimate goal of fully analyzing all distribution circuits” in a later phase of the DRP proceeding.
“A representative feeder has characteristics similar to other distribution circuits in factors like resistance, voltage, load, and whether it is overhead or underground,” said Takayesu. “It is a way to model an entire system without modeling every single circuit.”
Going forward, SCE will have an online tool that will, using the results of the study of the representative feeders, extrapolate the capabilities of the other 4,600-plus circuits in SCE's service territory, he explained.
“In the next DRP, using automated analytical processes, we intend to perform this analysis across all our distribution circuits," Takayesu said.
“PG&E was able to conduct dynamic analyses for all relevant distribution feeders down to the line section level,” its filing reports. It “analyzed more than 500,000 nodes and 102,000 line sections across 3,000+ feeders to provide the locational capacity for multiple DERs.”
By modleing its distribution feeders, PG&E was "able to assess what the current loading profile on each of them is on an hour-by-hour basis," Esguerra said.
"We can layer in the various DER profiles and see how the feeders perform and how the DERs perform to determine how much capacity for DERs to be interconnected is available for different sections of our line," he continued. "We learned a lot about our distribution system.”
In keeping with the open access principle, publication of the analyses was required “via online maps maintained by each utility and available to the public.”
The guidance also required the analyses to include both current system capability and planned investments and the utilities were asked to profile “the state of DER deployment and DER deployment projections.”
Finally, the CPUC asked the utilities to make recommendations for incorporating its ongoing distributed generation and electric vehicle initiatives into the DRP process.
Optimal location benefit analysis
The Optimal Location Benefit Analysis asked the utilities to calculate the value of DERs to their systems at specific locations. It was based on a CPUC-approved Distributed Energy Resource Avoided Cost (DERAC) Calculator developed by Energy+Environmental Economics but enhanced to include a comprehensive list of location-specific benefits and avoided costs.
The guidance also asked the utilities to define the unique value components they added in, detail their methodologies, explain how system updates can be managed, and describe how their methodologies could be used by the state’s grid operator and generation planning agencies.
“SCE has proposed methods to replace the DERAC’s system-level calculations with location-specific values,” its filing reports. The utility also added value components. “It should be noted that while some of the components may result in net benefits, others may result in net costs,” the filing adds.
SCE’s filing includes a projection of a $347 million to $560 million cost through 2017 for the proposals described in its filing. From 2018 to 2020, the projected cost grows to between $1.4 billion and $2.6 billion.
This is not in contradiction to the CPUC’s guidance to find ways to use DERs on the distribution system to avoid expenditures, Takayesu said. The costs detailed are for upgrades that will allow the system to bring on more DERs.
“The upgrades the CPUC wanted to have deferred by the use of DERs are related to meeting load growth,” he explained. “DERs will offset new load if coordinated the right way. The different technologies could potentially satisfy what a wires upgrade would have done to meet the same amount of demand growth.”
The three CPUC-requested DER Growth Scenarios were intended to speculate across a ten year horizon. The first scenario, based on the California Energy Commission (CEC) Independent Energy Policy Report (IEPR), was required to detail each line section at the feeder level.
Utilities were asked to use the CEC IEPR’s “High Growth” case for the second scenario but to include information from Load Serving Entities, 3rd party DER owners, and DER vendors.
A third “very high” growth scenario assumed the use of DERs to meet transmission system needs, resource adequacy, distribution reliability, resiliency, and long-term greenhouse gas (GHG) reductions. In this third scenario, utilities were also asked to take into consideration the impact of state policies and system operations on DER growth.
The demonstration projects
The CPUC asked the utilities to show their DRPs to be practical by proposing demonstration projects. The projects were to be identified by the methodologies developed for the integration capacity and optimal location benefit analyses.
In addition, they must dovetail with smart grid deployment plans and meet minimum cost and cost effectiveness criteria. They must be ready to be implemented within a year of CPUC approval and have Load Serving Entities, third-party DER providers, and DER technology vendors on board.
Finally, the demonstration projects must meet very strict technical requirements like preventing the backflow of power beyond the substation busbar, allowing for grid integration even with high DER penetrations, and adding to system load serving and reliability capabilities.
SCE is proposing two field demonstration projects, Takayesu said. One demonstrates how an optimal location benefit analysis can facilitate use of multiple DERs at a minimum cost to satisfy area needs. The second demonstrates effective operations at higher DER penetrations. It installs a dedicated control system to manage five circuits at the distribution system level to optimize dispatch of the DERs.
The first is in a region “directly affected by the closure of the San Onofre Nuclear Generating Station (SONGS) and will also be affected should the nearby ocean-cooled power plants close in 2020 as part of California’s once-through cooling policy,” the filing explains.
For it, “SCE has designed a portfolio of preferred resources (i.e., mix of energy efficiency, demand response, renewable distributed generation, and energy storage)…[and is] developing a framework and process to measure the performance capabilities of preferred resources in offsetting the impact of the local electrical load growth,” it adds.
The utility has already issued a request for offers to attract renewables developers and is studying the need for system upgrades to support the demonstration.
The second pilot will demonstrate how multiple third party and utility-owned DERs can be dispatched “in a coordinated manner using one or more dedicated control systems to maintain grid reliability and optimize operations,” the filing reports. It will also “define operational functionalities necessary to support situational awareness, coordination of DERs, and reliability services.”
PG&E’s micro-grid pilot project for Angel Island State Park really jumps out from the filing, Esguerra said, because it offers a genuine alternative to the costly replacement of an undersea cable.
The micro-grid “is intended to operate an optimal DER portfolio that will run 24 × 7 and 365 days to maximize the benefits of the DER and reduce the dependency on the cable,” the filing explains. “Electrical loads include lighting, baseboard electric heat, minor concession operations, waste lift pumps, work vehicle charging, and boat dock hook-ups.”
“We are looking at whether we could do it more cost-effectively and reliably with a micro-grid,” Esguerra said. The island has a 100 kW load that could grow to 500 kW. By using solar, storage, energy efficiency, demand response, and possibly wind, he explained, “we are looking to make the island 100% renewables.”