Last week was the close of public comments on the final draft of the NextGrid Illinois Utility of the Future Study (PDF), a report that — while not an official roadmap for modernizing Illinois’ power grid and energy regulatory framework — represents the state’s biggest effort on that front.
The 256-page document is the result of 18 months of study and collaboration between the University of Illinois Urbana-Champaign, the Illinois Commerce Commission (ICC), utilities ComEd and Ameren, grid operators PJM and MISO, and scores of advocacy groups, researchers, government agencies and companies. Other participating parties include Citizens Utility Board, the Union of Concerned Scientists, the Illinois Attorney General’s Office and Tesla.
The scope of the report is massive, ranging from deployment and integration of grid edge technologies such as solar PV, energy storage, electric vehicles and community microgrids, to big-picture questions about overhauling the state’s utility regulatory structure to better cope with a more distributed and customer-centric energy future.
NextGrid’s facilitators didn’t try to encourage participants to reach consensus on any of these issues in the 12 months of working groups that informed the report — that wasn’t part of its mandate. Instead, its goals are to “explore legal, policy, market-based and technological options for further grid modernization efforts,” create a “common knowledge base about grid modernization” to inform that discussion, and “focus on how potential changes may impact customers, markets, communities, and the utilities [that] serve them.”
The NextGrid report adopts the following working definition of the term grid "modernization": “all investments, technology adoption, necessary grid modifications and policy initiatives via legislative and regulatory actions to realize the envisioned capabilities and attributes of future grids.” But it doesn’t include any “investigation of the projected costs and benefits of grid modernization investment strategies,” although it presents plenty of stakeholder viewpoints on the subject.
The study is not an official ICC proceeding that could deliver an order directing utilities to start following any new policies. It hasn’t had the hearings, testimony or cross-examination that any such ICC proceeding would face. This fact has already led the NextGrid effort into its first legal challenge this week, when a state court issued an injunction against releasing the final version of the report until a lawsuit against the ICC is resolved.
Consumer advocacy group Illinois Public Interest Research Group Education Fund and battery storage developer GlidePath have accused the ICC of blocking their participation in several report-related working groups that weren’t open to the public, arguing that ComEd and Ameren have been able to influence the study by funding project facilitators and reviewing drafts before they’re released.
Even so, the NextGrid effort is likely to lay the groundwork for how regulators and utilities define the terms of what is to come next in the state’s grid modernization push, which makes it worth getting into. Here are the highlights from the sprawling document, from its grounding in the state’s energy history, to how stakeholders see its future coming into focus.
The fundamentals of Illinois’ energy landscape
The Illinois NextGrid report starts with the basics, such as data on the two utilities, ComEd and Ameren Illinois, that serve 90 percent of electricity customers in the state. It also looks at the fact that each utility is a member of a different interstate grid operator — ComEd with PJM and Ameren with the Midcontinent Independent System Operator (MISO) — which complicates the interaction of state-level policies with federally regulated energy markets.
Illinois partly deregulated its vertically integrated utility regime with the Electric Service Customer Choice and Rate Relief Law of 1997, creating the competitive retail markets of today. ComEd and Ameren still serve most customers by default, however, and third-party retailers have been embroiled in controversy for overcharging customers relative to utility rates. Illinois also has the largest fleet of nuclear power plants in the nation, totaling nearly 12,000 megawatts — one-eighth of the nation's nuclear capacity, and about half of the power generated in the state.
Illinois currently ranks second in the U.S. behind California for grid modernization, according to the GridWise Alliance’s 2018 Grid Modernization Index, a ranking helped along by the massive investments in smart meters, distribution automation, volt/VAR optimization, and other grid modernization starting early this decade. The Energy Infrastructure Modernization Act, passed in 2011, authorized up to $3.3 billion in investment ($2.6 billion by ComEd and $715 million by Ameren Illinois) largely spent to bring smart meters to all of ComEd’s 4 million customers as of 2018, and all of Ameren’s 1.25 million customers by the year’s end.
To hold ComEd and Ameren accountable for this spending, Illinois lawmakers required both utilities to meet certain performance metrics or face financial penalties, with targets such as reducing outages by 20 percent, cutting energy theft by 50 percent and reducing the number of inactive meters, or those delivering power to unoccupied homes, by 90 percent. ComEd has claimed a variety of improvements since it rolled out advanced metering infrastructure to its customers, as illustrated by this chart from the NextGrid report.
In 2016, the Future Energy Jobs Act (FEJA) increased the state’s investment in energy efficiency, along with incentives to allow utilities a return on these investments if they’re successful; it also launched the state’s community solar program.
The law requires the Illinois Power Authority, which oversees electricity procurement plans for the state’s investor-owned utilities, to create a Long-Term Renewable Resources Procurement Plan for the acquisition of solar and wind power renewable energy credits, in compliance with the Illinois renewable portfolio standard. FEJA also includes the Zero Emission Standard Procurement Plan, part of the state’s plan to offer zero-emission credits to nuclear facilities to help support financially struggling nuclear power plants in the state owned by ComEd parent company Exelon.
New technology and grid integration
The bulk of the NextGrid report is broken into seven chapters, with each dealing with one of NextGrid’s seven working groups. The first, new technology deployment and grid integration, starts with the premise of a grid with lots of bidirectional power flows from DERs at the distribution and bulk power system levels, along with the digital sensors and information, communication and control technologies to “facilitate transactions among energy market participants and enable integration of DERs.”
Illinois currently has a relatively small share of DERs, compared to vanguard states like Hawaii and New York. As of the end of 2016, ComEd reported 824 solar installations with a total capacity of 9.7 gigawatts, and Ameren Illinois reported 699 solar installations, with installed capacity of 5.4 megawatts.
But the community solar provision and adjustable block program (ABP) for solar installations less than 2 megawatts in size are expected to spur “significant growth in community and distributed solar, from a few thousand installations and about 60 megawatts capacity today to tens of thousands of installations and hundreds of megawatts in the next few years.” This will help reach the state’s goal to hit 25 percent renewables by 2025, the report notes.
The ABP has its faults, though. Greentech Media recently covered the problems with Illinois’ ABP, including delays in implementation and confusion over its lottery system that determines which projects move forward.
Increasing DERs will bring big changes to distribution-system engineering and operations, the NextGrid report notes, requiring more visibility and control into distribution grids or even behind-the-meter assets, more distribution automation, circuit configuration options and fault location isolation and service restoration capabilities. And beyond that, utilities will want “the ability to control DER power and VAR output for grid support,” as in with solar or battery smart inverters, and “planning for DER outages or failure to perform” if they’re serving as non-wires alternatives (i.e., as replacements for upgrades to traditional poles, wires and transformers).
The NextGrid report runs through the typical lists of what utilities will need to enable this transition, such as “communication among all grid components” that’s protected from cyber-intrusions, and able to quickly recover from disturbances and to use the data that it receives.” The NextGrid study doesn’t cover the transmission system, but notes that “some stakeholders believe that its modernization should be a concern of state regulators,” with estimates that more advanced dynamic line-rating techniques could increase throughput by 10 to 40 percent.
But the NextGrid study also puts an emphasis on the Illinois-specific concept of a community microgrid to serve as a foundation of its DER integration efforts. That’s not surprising, given that both ComEd and Ameren have put microgrids at the center of their plans for DER management. State legislation introduced in 2016 initially called for as much as $250 million for ComEd and $60 million for utility Ameren for a series of microgrids in the state, but much of that funding was stripped from the bill in late 2016, leaving only $25 million for ComEd’s Bronzeville microgrid project, which was approved by the ICC in March.
Parties including the Environmental Defense Fund and the Citizens Utility Board were able to get some significant alterations into ConEd’s original plans for Bronzeville to open competitive bids for distributed energy resources to serve its generation needs, and rely as much as possible on solar, energy storage and other alternatives to standby diesel-fueled generators. The ICC’s decision also started a process to design a “microgrid services tariff” that will allow third parties to structure “microgrids-as-a-service,” with customers and third parties collecting behind-the-meter resources to be controlled by a platform being developed via DOE grants by Argonne National Laboratory, S&C Electric, OSIsoft, Quanta Technology, Alstom and others.
One critical section of 2017’s Future Energy Jobs Act also starts Illinois down a road similar to that taken by California, Hawaii, New York, Nevada, Arizona, Minnesota and a growing number of states to value DERs like solar, batteries, EVs, smart thermostats and appliances, and other grid-responsive loads as part of the distribution grid. Specifically, “FEJA requires that the rebate formula in Illinois ultimately approved by the Commission ‘reflect the value of the DG to the distribution system at the location at which it is interconnected, taking into account the geographic, time-based and performance-based benefits, as well as technological capabilities and present and future grid needs,’” the NextGrid report notes.
“What to include when determining DER worth and how to calculate it are the subjects of ICC workshops (jointly conducted with the Pacific Northwest National Laboratory) in anticipation of future regulatory proceedings mandated under FEJA," it continues.
Metering, data and communications
The biggest takeaways from this chapter are the challenges that ComEd and Ameren face in bringing communications up to speed to manage the real-time transactive grid envisioned in the report. Neither utility’s advanced metering infrastructure systems can support a full-on DER management system. “Existing AMI networks can only support this level of data for a small number of devices and would require modifications to the communications architecture to support this level of data gathering across the board," the report states.
What about the internet? The report notes that DERs are using the internet for connectivity, and that this trend is likely to continue. But there are three big problems with this approach, it states. “First, grid reliability cannot depend on the internet, because it does not offer guaranteed availability and time to repair,” it states. “Second, not all customers have internet access and the utility has to offer its rates to all customers,” and “third, security of an open-internet connection is a concern.”
The report also brings up the ongoing dispute in the utility world about using public cellular or building their own communications networks for critical infrastructure. “Key unanswered questions from the [working group] sessions largely focused on the development of a resilient communications network capable of integrating and managing potentially millions of devices that have sufficient bandwidth to collect and relay data as needed to meet market and operational demands," according to the report. "While most of these questions are largely addressed through identified cross-cutting issues, a key question regarding who should own the network infrastructure remained.”
In a pitch for removing the utility incentive to seek out privately owned, rate-based communications over public carrier alternatives, the report suggest that “clarifying the leasing requirements for which a utility can get recovery may, in some cases, incentivize them to lease rather than build capital assets.”
This chapter also lays out just what a bust the ZigBee-enabled home area network (HAN) has been for communications. While Illinois has pushed its utilities to allow customers to access data in close to real time through HAN devices, “there are only approximately 30 HAN devices authorized to communicate to meters,” the report notes — a tiny figure that’s pretty much in line with HAN uptake in other markets. Its Green Button Connect-enabled customer portals don't get much traffic either, with only about 20,000 customers accessing billing history each month, and about 1,000 customers downloading their data each month.
That’s too bad, the report notes, because “ComEd has become one of the nation’s first utilities to provide access to internet-of-things applets that enable automatic response of smart appliances to real-time conditions, such as changing the temperature on a smart thermostat when time-varying prices fluctuate or precooling in advance of an expected curtailment event."
Customers, communities and transactive energy
Chapter 4 of the report tackles all of the “changes underway in the ways that customers and communities participate in an electricity system characterized by a proliferation of 'behind-the-meter' energy resources, availability of finer-granularity consumption data, automated demand response, increasing electrification of transportation and other industrial sector loads, continuing technological innovation and a growing array of energy product and service options for customers of all sizes.”
As may be expected, “within the limited available time to take up a broad set of complex topics, there was no attempt to forge consensus regarding the many issues about which stakeholders have divergent views, opinions and expectations” on these subjects, the report notes.
Still, the chapter does contain a useful list of areas where new policies might be required to make behind-the-meter DER interconnection more simple and timely, ensure accurate and effective price signals to customers, allow customers to be compensated for the value they provide to the grid, make certain that the benefits of utility investment in new technologies flow to all customers and communities, and determine how to “effectively and securely improve data sharing capabilities with third parties as utility usage data becomes more granular.”
Chapter 5 picks up on one of the more future-forward ideas for managing this customer-community energy interaction — the “possibility to establish transactive electricity markets at the distribution level nodes to allow the trade of electricity on a regional basis.” But this section is lacking on details, given the fact that the concepts under discussion are beyond the technological capabilities of utilities or customers at present.
Building the regulatory structure for the future grid
Chapters 7 lays out the findings of the working group exploring different rate structures that could work in a world with high levels of DERs, digital technology and customer choice.
“Concerns have been raised by utilities, stakeholders, and analysts about the ability of current ratemaking practices to support or adapt to the industry’s ongoing transformations,” the report notes. These include the threat of DERs hurting utility revenues, pushing costs onto customers without DERs, and paying out incentives that are “higher than the resulting system benefits,” as well as the possibility that DERs will receive excessively low prices for their surplus power or receive insufficient compensation for their grid values.
The report lays out the debate over the formula ratemaking available to ComEd and Ameren since the passage of the Energy Infrastructure Modernization Act in 2011, as well as the performance-based ratemaking concepts introduced by that law’s linking of return on equity to the utility’s performance on resiliency and customer metrics. But 2017’s FEJA goes further, by including “symmetrical return on equity incentive/penalties” for performance of its energy efficiency programs. That led some stakeholders to state that “this is already, in essence, a provision that established performance-based rates in Illinois.”
Whether performance-based ratemaking will see an expansion in Illinois is an open question. Performance-based ratemaking is allowed in Illinois under Section 9-244 of the Public Utilities Act. "However, it has not been used much, if at all, particularly since the enactment of [the Energy Infrastructure Modernization Act],” the report states.
