California regulators on Dec. 15 approved a controversial decision to reform the state’s net energy metering solar tariff, which compensates customers who generate their own electricity and export some of that back to the grid.

The new tariff adopted by the California Public Utilities Commission includes a retail export compensation rate that is based on the value that behind-the-meter generation provides to the grid, and import rates that are designed to incentivize electrification as well as solar systems paired with storage, according to the decision

Revamping the net energy metering framework has been a challenging process, in part because the agency had to balance competing priorities, CPUC Commissioner Clifford Rechtschaffen said at the meeting. “We want to make sure that distributed generation grows in a sustainable manner … we need to make sure that the benefits to all customers and the grid are approximately equal to the costs. We want to make sure that whatever growth occurs doesn’t unduly burden ratepayers, and that we also expand the access of low-income customers to rooftop solar…” he said.

California’s NEM tariffs have allowed around 1.5 million customers to set up over 12 GW of renewable generation. However, the overall portfolio mix of the modern grid is very different than it was when the framework was first put in place, according to CPUC President Alice Reynolds.

“[T]he electric grid is now powered largely by renewable systems, both large and small, and there are even moments when we need to curtail, meaning shut down, clean renewable generation because we have too much on the grid at once,” Reynolds said.

At the same time, the state still needs to fire up natural gas and other carbon-emitting resources to meet demand during the evening hours, when solar energy has waned.

“Rooftop solar is not displacing dirty power in California in the same way that it might in other states,” Reynolds said. 

The CPUC released the first version of its proposal to reform the NEM framework last December, but eventually shelved it following heavy criticism from multiple parties, including the solar industry. The new proposal was released last month, but also drew criticism from the solar industry. One analysis from the California Solar & Storage Association indicated that the proposal could cut the average export rate in California from 30 cents/kW to 8 cents/kW starting in April. 

The decision approved Dec. 15 adopts export rates based on the value distributed generation provides to the grid and electrification retail import rates that have high differentials between winter off-peak and summer on-peak rates. Regulators hope that this will encourage customers to install storage paired with solar systems to draw more energy during the middle of the day, and export energy back to the grid in the evening. 

Under the new structure, the average residential customer installing solar is expected to save $100 a month on their electricity bills, while those who install solar paired with battery storage will save at least $136 dollars a month, according to the commission. The CPUC estimates that new NEM customers will be able to fully pay off their solar systems with these savings in nine years, or less, since the amount saved will likely increase every year as utility bills increase over time, Reynolds said at the meeting. 

The solar industry, however, remains concerned about the impact of the new decision on rooftop solar installations in the state. CALSSA said in a statement that the decision would slash the value of solar energy put back on the grid by 75%, leading to “an expected cliff in the growth of new solar installations.”

In addition, the group said the decision does not do enough to advance energy storage in California, as it extends the payback periods for these combined systems beyond what they currently are.

“For the solar industry, it will result in business closures and the loss of green jobs. For middle class and working class neighborhoods where solar is growing fastest, it puts clean energy further out of reach,” CALSSA Executive Director Bernadette Del Chiaro said in a statement. 

“Rooftop solar is a critical part of our clean energy transition, and we need to accelerate deployment. Governor Newsom and the CPUC should be making clean energy more accessible and affordable so that rooftops across the state can catch the sun to power our lives,” Laura Deehan, state director of Environment California, said in a statement. 

Rechstchaffen, however, pushed back on the notion that the decision will lead to a drop in bill savings of 75%, stating that the number is a contested fact. Moreover, compensation for electricity exported back to the grid is only one part of the customer savings equation, he said, and a much larger portion of savings from rooftop solar comes from customers powering their electricity needs with their own solar energy. 

Matt Baker, director of the CPUC’s Public Advocates Office, said in a statement that the NEM update is “a win for all parties.”

“We need solar. It has helped turn California into a clean energy world leader. But we need to do more. Clean energy use during the day must be extended into the evening. Solar with batteries does exactly that,” Baker said. 

The clean energy transition makes the question of how distributed energy resources, or DERs, fit in the future energy mix particularly urgent, utilities and DER advocates agree.

The technical potential of DER like rooftop solar, batteries, electric vehicles, and flexible industrial and building loads like smart water heaters and heat pumps could “play a significant role” in a 100% clean energy mix, an August Department of Energy study found.

With adequate “distribution system visibility and control” of DERs, they can “help protect system reliability and resiliency,” agreed Xcel Energy Colorado President Robert Kenney. But “the cost of new technologies to manage those resources threatens rate affordability and slows deployment because regulators and utilities face the responsibility to balance stakeholder concerns,” he added.

Integrating high DER penetrations into power system operations will ultimately require significant investments in technologies like Advanced Distribution Management Systems, or ADMS, and Distributed Energy Resource Management Systems, or DERMS, utility representatives and DER advocates acknowledged. The question is how and when those investments are made.

Transportation and building electrification, constraints on bulk system resource delivery, and consumer demand “require addressing DER growth,” Generac VP, Markets and Programs, Josh Keeling, a former Portland General Electric executive, said. But a staged deployment of technologies to manage them “can reduce their costs and burdens and benefit customers and power systems over the long term,” he said.

A “national initiative” and stakeholder dialogue can build a framework for that staged DER integration to protect affordability and reliability for customers, according to recent papers from a group of DER advocates. But advocates underestimate the urgency of investments in distribution system situational awareness for managing DER and limitations of the nation’s divided regulatory jurisdictions to approve them, utilities said.

A DER framework

A “broadly inclusive” national initiative could engage federal and state regulators, investor-owned, municipal and cooperative utilities, DER advocates, and their national associations, according to January and August 2022 papers from the Energy Systems Integration Group, or ESIG, DER Task Force, a committee of the non-profit organization focused on independent analysis of the power system’s future.

The initiative’s objectives are “a common vocabulary, framework, and vision,” for stakeholders that leads to near-term, “least-regrets strategies” and a “structured dialogue” on longer-term challenges of integrating customer-owned resources into the utility-controlled distribution system, ESIG said.

The proposed work could build on DOE’s 2019 distribution system studies, Federal Energy Regulatory Commission Order 2222 work on integrating DER into wholesale markets, and the NARUC-NASEO task force effort to make DER more useful and safer for distribution system operators, ESIG added.

DER penetrations, regulation, and goals vary by regulatory regimes, localities, and technology types but DER are transforming the meaning of reliability everywhere, ESIG said. A national initiative to safely and cost-effectively integrate DER can recognize jurisdictional autonomy and enable new stakeholder opportunities by identifying commonalities in current “disparate standards, terminology, and approaches,” the group added.

A first track would start with “relatively minor changes” to existing DER integration practices, it said. A second track would be about using current best practices to develop new national standards for integrating DER with “fundamental changes” to federal and state regulation, markets, and system planning, ESIG said.

A long-term third track could lead to new utility regulation and business models, ESIG added. The power sector is “too diverse and complex” for one solution, but a key decision point in each jurisdiction will be whether DER aggregators, load-serving entities or distribution system operators manage and coordinate DER with bulk markets and systems, ESIG said.

The initiative can “start stakeholder conversations on complicated questions like planning, ownership and operation of DER,” said GridLab Program Director and project lead author Priya Sreedharan. When each jurisdiction’s choices from the initiative’s “suite of solutions” are selected, “the hard work begins for regulators to implement stakeholders’ choices based on that jurisdiction’s parameters,” she said.

DER is “a fraction of power system resources in most large states’ economies, but Hawaii and California are demonstrating what can happen nationally” when penetrations rise, said Independent Consultant and ESIG papers co-author Fredrich Kahrl. The ESIG initiative can allow regulators, utilities and stakeholders “to coordinate bulk and distribution system operations,” he said.

In the near term, interconnection practices, DER curtailment rules, and communications from utilities to aggregators about outages “can be improved with existing software and hardware tools,” GridLab’s Sreedharan said. “That is a least-regrets strategy because it leaves decisions about major technology investments until higher penetrations of DER emerge,” she added.

Though utilities widely agreed with DER advocates about the potential value, they do not agree with ESIG’s proposals on facilitating DER integration to realize that value.

What utilities want

Postponing investments in grid modernization technologies needed to integrate the rising DER penetrations until they reach undefined higher levels “has only led to DER growth and not to more system value,” Edison Electric Institute General Counsel, Corporate Secretary, and Senior Vice President, Clean Energy, Emily Fisher said, echoing Xcel Colorado’s Kenney call for technology investment.

Utilities will need “much greater situational awareness of DER performance” to obtain system and customer benefits, agreed David Castle, senior manager of grid modernization policy, with Southern California Edison, a national DER penetration leader that has debated with regulators and stakeholders about spending on new technologies to support DER integration for several years. 

Instead of identifying the DER penetration at which new technologies will be needed, “proponents kick questions about those investments down the road,” Fisher said. “That is not a useful way of addressing any issue, especially when it is clear investments to protect reliability are important.”

“ESIG intentionally did not define a penetration at which more distribution system visibility, monitoring, and control capabilities will be needed,” responded ESIG co-author Kahrl. It will depend on specifics that are left to each jurisdiction like whether DER aggregators, load-serving entities, or distribution system operators manage and coordinate DER, he said.

Utilities want the best technologies to meet their responsibility for reliability, acknowledged Generac’s Keeling. But “the ESIG initiative would first reach functional definitions of visibility and control, which can change stakeholders’ understanding of how existing technologies can be leveraged and when new investments are needed,” he said.

Power providers supplied by Guzman Energy “have found they already have sufficient visibility and control of DER to protect reliability,” said Steve Beuning, senior advisor, market design and integration, for Guzman, which supplies Holy Cross Energy and other Western cooperatives. “A sufficient level does not have to be a perfect and complicated level that prevents reducing customer costs,” he added.

New operations and technologies may not be needed immediately, but “investments are needed now so utilities can be ready when DER penetrations require it,” EEI’s Fisher responded. And “the real challenge is that DER growth will be customer-driven and not in any way orderly,” she said.

“Those DERs might be valuable to individual customers, but they will have very different system reliability benefits at different locations,” she said. “Proponents’ contention that DER have system value is undercut if they do not support investments in technologies to obtain that locationally-specific value,” she added.

Utilities need situational awareness of DER on their systems and that need will grow as federal funding accelerates deployment, acknowledged Plugged In Strategies President Chris Villarreal, a former staffer at the California and Minnesota utility commissions. But the ESIG national initiative would “identify the most efficient ways to use utility investments,” he said.

A DER integration framework “which identifies the best locations for specific DER may be theoretically possible,” Fisher responded. But “the current customer-centric regulatory approach is to accommodate customer DER additions wherever they are located, whether or not they add system value,” she said.

Current U.S. power sector regulation was designed for a centralized system, and it needs to evolve to help utilities and other stakeholders address DER integration and more decentralized solutions, Xcel Colorado’s Kenney agreed.

Utilities “understand DER integration is part of the future, and their job is to integrate and maximize the value of customers’ assets,” Fisher added. “But that will increase distribution system complexity by orders of magnitude, while high electricity rates from inflation and natural gas prices keep regulators from approving expenditures for technologies to manage it,” she said.

But a threat may await regulators and utilities that do not take on that distribution system complexity, DER advocates said.

Preparation vs. defection

A "DER integration framework is required” for a “higher performing, lower cost electric system” that meets customer needs, acknowledged SCE Principal Manager of Grid Strategy Devin Rauss.

And impeding DER ignores “customer desires” and “cost-effectiveness trends” and creates incentives for “financially capable customers to defect from the grid,” added electric policy and market design consultant Lorenzo Kristov, who previously worked at the California Energy Commission and California Independent System Operator, in recent Xcel Minnesota rate case testimony.

If customers use DER to supply their own electricity, rates will go up and DER costs will fall, making grid defection more affordable and accelerating it, Kristov wrote. But DER can provide the system with flexibility, voltage control, congestion management, frequency control, energy, capacity, and net load flattening, he added.

“Widespread grid defection would be detrimental to society” because it reduces the system benefits of customer-owned DER, he wrote. It would also “worsen energy injustice” because DER is largely accessible “to customers with financial resources,” leaving less affluent customers to pay for system costs, Kristov added.

DER integration can, though, also lead to a “partnership” between the bulk and distribution systems, leading to “estimated savings on the order of $500 billion” through 2050, Kristov testified in the Minnesota case, citing 2021 Vibrant Clean Energy modeling.

Demand for Generac’s off-grid solutions has grown with recent rising electricity rates, Generac’s Keeling said. And it is causing the cost shift Kristov described, “because installations are done by the more affluent” and because “inefficient operation of batteries” is offsetting those customers’ usage instead of flattening system peaks, he added.

The higher rates may also “slow electrification,” or cause “some customers to switch to lower cost fossil fuel generators,” which would impede societal goals to reduce greenhouse gas emissions, Keeling said. 

ESIG’s national initiative is to provide “a framework built on existing best practices” that allows each jurisdiction “to develop DER integration that is good for their system, customers, and utilities,” he added.

In many jurisdictions, regulators and utilities are doing only the minimum to leverage and optimize existing assets, said Plugged In Strategies’ Villarreal. But now is the time “to develop policies, goals, objectives and a vision for what they want their distribution utilities to become,” he said.

Many may not realize the importance of distribution system planning initiatives, Villarreal added. “But distribution assets are aging even as demands on the system’s capability to leverage DER are evolving,” he said.

ESIG’s proposal recognizes “consumers will buy EVs and rooftop solar if it is cost-effective for them, whether it benefits the system or not,” Villarreal said. “Utilities can try to slow that or create market opportunities for consumers to partner with them in ways that postpone or reduce technology investments because market signals provide the system visibility they need,” Villarreal said.

It happens fast

The main question regulators face is “whether to approve technology investments in expectation of DER growth or to approve them only as DER penetrations rise,” ESIG’s Kahrl said.

Most utilities are planning “the foundational grid modernization investments in ADMS, DERMS, and advanced meters and communication platforms to enable greater DER penetrations,” Xcel Colorado’s Kenney said. “But technology continues to evolve, and there could potentially be technologies that emerge that will also be important,” he recognized.

“Utilities do need the best distribution system technologies, but they cannot design the future, they can only enable it,” which is why ESIG proposed “an evolutionary process,” said Generac’s Keeling, who worked on distribution system development at Portland General Electric. “Trying to solve all problems at once often leads to a longer process that is out of date before it is completed,” he added.

But “utilities without a long-term vision for DER integration don’t realize their peril,” Kahrl added. “Some utilities have learned over the past decade that when DER penetrations rise, it happens really fast.”

Sponsored content

By Peak Load Management Alliance

Where do today's load management activities - including demand response, energy efficiency, and renewable energy programs - fit in a distributed energy resource (DER) future of non-wires alternatives, storage and more? A recent publication titled “The Future of Distributed Energy Resources: A PLMA Practitioner Perspectives^TM Compendium” details eight industry initiatives where leading utilities are partnering with their customers and allies to demonstrate the path to a more integrated approach to DERs.

Peak Load Management Alliance (PLMA) members, utility companies, consultants, and vendors have deep experience in delivering practical solutions to the operational requirement to balance resources and loads. And while the first 100 years of the energy industry was focused on matching resources (generation) to loads, the next several decades will be focused on flexible loads efficiently meeting generation output at both the Transmission system and Distribution feeder level, incorporating renewable, distributed and intermittent resources. We are moving into the realm of dynamic management of the system every day. The last decade has seen a rapid increase in behind-the-meter solar installations; recent advances in battery and thermal storage, electric vehicle (EV) charging, and load flexibility resources are also indicators of the growing importance of distributed energy resources (DERs).

The PLMA community has a history of sharing experiences that enable others in the industry to understand, learn, and embrace industry change. In keeping with this mission, PLMA asked its membership to share case studies about current DER activities and projects. The initiatives detailed in the Compendium are:

• Planning/Foundational Category – Defined as those utilities taking bold steps to leapfrog pilots/technology straight to integrative planning and procuring, and change management.
  • Hawaiian Electric's Integrated Grid Planning, Hawaiian Electric Company
  • Distributed Resource & Flexible Load Study, Portland General Electric and Navigant
  • Integrating DER Planning, Research and Program Development, Tacoma Power
• “DR Plus” Category – Defined as customer-sited assets (with or without the involvement of an aggregator) to monetize DER operations for utility/grid benefits to a growing spectrum of network problems.
  • Deriving New Wholesale Market Revenue Opportunities and Maximizing Customer Utility Savings with Behind-the-Meter Distributed Energy Resources, Center for Sustainable Energy, Tesla, Conectric Networks, and Olivine
  • Expanding National Grid’s ConnectedSolutions Program to Include Energy Storage, Sunrun, EnergyHub, and National Grid
• Microgrids Category – Defined as customer-sited assets that have great degrees of flexibility and opportunity for monetization.
  • Microgrid Enables Military Facility to Participate in Utility Services, Eaton
  • Energy Storage and Microgrid Performance in Non-Wires Solutions and Other Demand Management Programs, Enel X
• International Category
  • First Movers in DER in Colombia, U.S. Energy Association

If management is asking "where do today's load management activities (including DR, EE, and renewable energy programs) fit in a distributed energy resource (DER) future?" the eight case studies in the Compendium offer a glimpse into the future that is unfolding today. If imitation is the sincerest form of flattery, then now is the time to embrace progress through plagiarism. Here, PLMA members provide the blueprints for utilities, regulators and service providers to follow. Read the Compendium at www.peakload.org/plma-publishes-future-of-der-compendium.

Distributed energy resources, or DERs, “pose emerging cybersecurity challenges to the electric grid” and they should be designed with security as a “core component,” the U.S. Department of Energy concluded in an Oct. 6 report.

An attack on distributed solar or battery storage resources would have “negligible impact” on grid reliability today, DOE said, but the capacity of DERs on the electric system is expected to quadruple by 2025 and the agency warned that each of those systems could be hacked.

The Federal Energy Regulatory Commission has been considering developing new cybersecurity rules for DERs on the bulk electric system, but experts say safeguarding the grid will require exceeding any baseline standards.  

DOE officials say designing security into the growing fleet of DERs is a “strategic opportunity like we’ve never had before.”

“We can address both climate risks by deploying clean energy solutions and integrate cybersecurity into those systems from the ground-up,” Puesh Kumar, director of DOE’s Office of Cybersecurity, Energy Security, and Emergency Response, said in a statement.

DOE’s report is meant to start “critical conversations” between the clean energy sector and the cybersecurity community, Kumar said.

The report concludes future DER systems “must be designed, built and operated in an enforced zero-trust model where data are validated using cryptographically secure mechanisms informed by standards, testing, and vulnerability assessments.”

It also says broad industry involvement “is key to the development, approval, and implementation of robust DER cybersecurity standards, trust models and best practices that would raise the bar for foundational DER defenses.”

Whether and how critical infrastructure protection standards managed by the North American Electric Reliability Corp. could be modified to better protect DERs is an open question. FERC Chariman Richard Glick has said NERC’s prescriptive standards for broad categorizations of low-, medium- and high-impact facilities may not be the right approach.

The utility sector has been skeptical of the need for new or stronger CIP standards, while security vendors have favored stricter rules. Regardless, there is broad agreement that going beyond baseline energy security requirements is necessary to protect the grid.

”A cyberattack targeting distributed energy resources systems could have a massive impact,” Vaultree co-founder and Chief Operating Officer Tilo Weigandt said in an email. “Becoming proactive instead of reactive and exceeding current security standards is the key.”

While the grid reliability threat posed by DER vulnerabilities is low for now, DOE warned aggregated resources could scale up the threat.

“Depending on systems conditions, a fleet of DER aggregated to significant size could pose a reliability challenge if under the control of an advanced, capable attacker, and if cybersecurity considerations and threat mitigation strategies are ignored,” the agency said in a statement.

FERC issued Order 2222 in September 2020, ordering regional grid operators to enable DER aggregators to compete in wholesale markets. The commission is currently reviewing grid operator implementation plans.

The DER industry must partner with the energy sector and government over the next decade to address cybersecurity challenges, DOE concluded in its report.

“This means ensuring that new controls and software interfaces for these smart devices are cybersecure and standardized to mitigate emerging cyber risks,” the report said. “Securing DER also will require addressing the varying ways that DER operate, including their different controls and the fact that owner/operator entities do not have a defined role in securing the grid.”

General Motors will expand its commitment to electric vehicles with the creation of a new business unit called GM Energy, which will offer vehicle-to-home and vehicle-to-grid charging, stationary battery storage, solar products, software applications and cloud management tools for retail and commercial customers, the company announced Oct. 11.

“We are not just focused on the vehicle,” said Mark Bole, vice president and head of V2X battery solutions at GM. “We're focused on energy, on the infrastructure, on the entire ecosystem because we know we really need to enable it for EV adoption.”

Three product and service offerings constitute GM Energy. Currently, Ultium Charge 360 connects GM vehicle mobile apps with seven major charging networks for consumers. Through GM’s Dealer Community Charging Program, its dealers get 10 Level 2 chargers  they can place anywhere in their community, not including the dealer store itself. Ultium Home and Ultium Commercial, which are new additions, will focus on services to those markets.

The company said in a press release that it aims to “provide customers with more seamless and integrated energy management and help improve grid resiliency.” Properly equipped electric vehicles and stationary storage batteries will be able to send energy back to utilities during peak, high energy consumption periods. 

The automaker is already working with Pacific Gas & Electric in California on a pilot program for bidirectional charging for use as backup power for the home. GM said in the press release that following initial lab tests, the two companies expect to expand the program to a subset of residential customers within PG&E’s service area in 2023.

Bole said GM is also talking with major utility companies in California, Florida, Michigan, New York and Texas. The goal for these discussions is to ensure a smooth electrification rollout nationwide, he explained. 

GM also entered into an agreement with SunPower, a residential solar power and energy storage company. The two companies will develop a solar home energy and storage system that will allow car owners to send power from the battery in their compatible electric vehicle to their homes.

The 2024 Chevrolet Silverado EV, expected to be available in late 2023, will be the first GM production vehicle capable of bidirectional charging. “We want to go big in this area,” Bole said. “We are working hard on how we can bring bidirectionality to our broad spectrum of [electric vehicles] of the future.” 

GM Energy’s partnerships and products will also serve its fleet customers. “We are talking to some of our large fleet customers today about their electrification needs,” said Bole, adding that fleets want help managing charging infrastructure and energy costs.

Last month, Hertz said it plans to order up to 175,000 GM vehicles to expand its fleet of electric vehicles. The first deliveries of Chevrolet Bolt EVs are expected in the first quarter of 2023. 

GM’s Energy Services Cloud will connect customers with retail, fleet and commercial energy assets through cloud-based software applications. Bole explained that it will be open to third-party applications and will work with non-GM vehicles and with power utilities. “Through the telematics we can actually instruct the car to stop charging [or] start charging,” Bole said.

General Motors expects to sell 1 million EVs per year in North America and China by 2025 and has committed to investing $35 billion in electric and autonomous vehicles by mid-decade. In comparison, Tesla has delivered more than 900,000 vehicles through the first three quarters of this year. Ford expects to reach a rate of 600,000 annual EV sales in late 2023 and two million annually by late 2026.

To prepare California for a “high DER future” that could overstress the state’s distribution system, a series of regulatory workshops opened May 3.

Distribution system reform is needed as California moves from “firm dispatchable one-way generation to variable two-way generation” that will accelerate the impacts of distributed energy resources, a white paper introducing the California Public Utilities Commission stakeholder-led workshops reported. The paper offered potential distribution system operator, or DSO, models that could meet coming needs.  

“By DSO or another name, a different model of the distribution utility is needed, because in the future every electricity user can have DER and participate in an open access distribution network,” Lorenzo Kristov, consultant for electric system policy, structure, and market design to climate and energy policy advocates, The Climate Center, told Utility Dive. But "right now, the need for a DSO is more concrete than the DSO concept," he added.

The workshops will develop “alternative roles and responsibilities of the distribution utility,” said Gridworks Executive Director Matthew Tisdale, who is leading the series of CPUC workshops. But those roles and responsibilities “are enormously financially and politically complicated” and “probably the most fundamental, contentious, and difficult issue in energy policy.”

Two insights about California’s distribution system work emerged from the May 3 workshop, though neither identified the state’s eventual DSO model. First, it was clear there is strong contention between some power system incumbents and community representatives on critical proceeding points, including who can participate and how to define a DSO. And second, it appears major regulatory reforms that could impact utilities' earnings, like performance-based regulation, are part of the discussion. 

The numbers and the need

DERs are “distributed renewable generation resources, energy efficiency, energy storage, electric vehicles, and demand response technologies,” according to the California Public Utilities Code.

Though rooftop solar is currently threatened by a Commerce Department inquiry and California's net metering reconsideration, the state's DER growth will accelerate, workshop participants agreed. Customer demand, the state's zero emissions by 2045 goal, evolving technology, and falling prices will be key drivers, the white paper added.

California installed distributed solar photovoltaic capacity is expected to increase from 2022’s 14,048 MW to 24,721 MW in 2030, according to California Energy Commission spokesperson Michael Ward’s review of the commission’s 2021 Integrated Energy Policy Report. Distributed energy storage capacity is projected to increase from 2022’s 740 MW to 2,587 MW in 2030, he added.

California’s estimated 839,000 zero-emission vehicles at the end of 2021 are projected to reach 5.7 million light-duty passenger and medium- and heavy-duty vehicles by 2030, Ward added, citing CEC data. And an estimated 1.5 million households had smart thermostats in 2018, according to the commission’s 2019 Residential Appliance Saturation Study, though they were too few to count in its 2009 study.

Gov. Gavin Newsom’s, D, Executive Order N-79-20 targeting 100% zero-emission new passenger vehicle sales by 2035 is expected to drive exponential growth, the CPUC white paper said. Assembly Bill 327, a 2013 provision that protects customer-owned resources, programs supporting battery storage and heat pumps, and utility and private sector policy-led rebates and initiatives, will all add to accelerating DER growth, it added.

As DER penetration increases, the management of its integration into the distribution system is becoming increasingly important.

A DSO may be an entity responsible for planning and operations on a distribution system or one that operates and develops multi-faceted “networks,” the white paper said. Or it could be “a neutral facilitator of an open and accessible market” for DER, the paper added. Or it might be “the existing utility,” according to a 2015 paper co-authored by workshop participant Kristov.

Identifying distribution system reforms is essential to meeting the commission’s 2021 High DER Future Proceeding (R.21-06-017) order, CPUC Energy Division Senior Energy Analyst Rob Peterson told the May 3 workshop. The objective is to “guide public and private sector investment for a high DER future” while “integrating equity and access considerations," he said.

Reports on the May 3 and other workshops will go to the CPUC “as record evidence” in 2022 and 2023, with a final proposed commission decision on distribution system management scheduled in 2024, Gridworks' Tisdale reported. It also outlined key questions for participants and four “conceptual” new distribution system models.

In one model, “DER provide distribution services” to a wholesale market, the paper reported. In another, IOUs remain responsible for "overseeing” DER-provided services in a separate new distribution market, the paper said.

In the paper's third model, a new independent DSO provides grid services from DERs to “layered wholesale and distribution service markets,” and coordinates with the bulk system. A fourth “hybrid” option would have features of the other models, the paper said. A missing option is automated transactions independent of utility or DSO control, some workshop participants added.

Participants at future workshops will be asked to identify “legal, regulatory, procedural, technical and financial barriers” to proposals and regulatory or policy solutions for overcoming them, the paper said.

The commission ordered the workshops to “leverage the insights gained from Australia, the U.K. and New York, while creating the process and new ideas California needs,” the white paper said.

Experiences to learn from

Australia's 2017 "Roadmap" detailed goals, milestones and actions for a distribution system “transformation” through 2027, Mark Paterson, Australia-Pacific Managing Director for consultant Strategen, told the workshop. California should expect “TUNA” — a "Turbulent," "Uncertain," "Novel, Non-linear," and "Ambiguous" process of “ten solid years of transformation,” he warned.

The United Kingdom’s five-year “step-by-important-step” process had the advantage of utilities familiar with performance-based regulatory innovation, British consultant Jason Brogden told the workshop. From five scenarios, U.K. leaders selected coordinated procurement and dispatch between a new DSO and the bulk system operator. “Invest in stakeholder engagement” or risk losing “buy-in,” Brogden cautioned. 

New York's incomplete efforts to create an independent distribution system operator, or IDSO, may be more instructive for California.

The Distributed System Platform, or DSP, proposed in New York's Reforming the Energy Vision proceeding is now part of the state’s Distributed System Implementation Planning, or DSIP, New York Department of Public Service spokesperson James Denn told Utility Dive. DSIP proceeding filings show the IOUs are implementing DSP functions described in REV, he said.

But the development of the DSP as a fully functioning IDSO remains incomplete.

New York’s DSIP effort has completed only limited distribution system reform and is still working on whether and how to separate operations and market functions, the white paper reported. The paper also asked what the lesson to be learned might be from the fact that Hawaii and California have higher DER penetrations without a reformed distribution system?

New York stakeholders found the most practical approach to distribution system management was to make IOUs responsible for their own operations and DER market services, Consolidated Edison Utility of the Future Group General Manager Steve Wemple emailed Utility Dive. That has allowed time to develop the DSP concept, though at high DER levels “it will need to be more robust and interactive,” he acknowledged.

REV’s original intent was a platform compensating utilities as DSP service providers for managing transactions, Regulatory Assistance Project President and CEO Richard Sedano recalled. “They would control less and earn revenues for enabling the DER marketplace.”

But other REV initiatives took priority, the platform was set aside, and the utilities “maintained control over the system while working through the DSIP process,” Sedano said. Through it, however, “the utilities have built non-wires solutions, community solar, and distribution technologies.” DER demand from California’s community choice aggregations may make it more “market-ready” for an IDSO to integrate DERs than New York was, he added.

New York’s distribution utilities leveraged their political control to take over REV’s DSP concept, but a DSO’s benefits for California will be “analogous to those from a regional wholesale market,” former FERC Chair Jon Wellinghoff, a longtime independent DSO advocate, told Utility Dive. “Competition at the distribution level can drive multiple layers of direct and transactional efficiencies with new market products and resources,” he said.

Complicating considerations

California likely faces a long conversation about distribution system reform because “difficult barriers and California’s typical incremental approach" may not satisfy all stakeholders, former CPUC President and longtime DER advocate Michael Picker said.

“We are moving to a future of two-way power flows and inverter-driven resources that will require investment in new distribution services,” Picker said. But New York found that only the utilities were willing take on managing the undefined distribution system infrastructure, operations, and market costs and responsibilities, he said.

A workshop report from distribution circuit technology provider Utilidata found significant spending will be necessary for hardware and software to manage and integrate high penetrations of DER, added Utilidata VP of State Policy and Regulatory Lauren Randall.

A different consideration that could impede progress toward a DSO is California’s inverse condemnation law, which holds IOUs responsible for any infrastructure involvement in wildfires, Picker said. Though workshop stakeholders may offer solutions to such barriers, a distribution operator could, like California’s utilities, be held responsible for distribution infrastructure involved in a wildfire, he said.

California utilities are rapidly investing in grid modernization to support reliability, customer needs, state policy and DER growth, Southern California Edison Senior Manager, Grid Modernization Policy, David Castle told the workshop. But a DSO facing the “inherent complexity of reconfiguring the distribution system” should face “upfront criteria and metrics” and a “detailed benefit-cost analysis” of effectiveness, he said.

The workshop had a “built-in bias” against an independent DSO, but the right market design can offer an alternative, transactive energy services provider TeMix CEO Edward Cazalet told the workshop. Small scale TeMix pilots have demonstrated “the technical feasibility” of a transactive market approach and two larger CPUC-initiated pilots are underway, he told Utility Dive.

The New York IOUs are demonstrating the DSO model that “will ultimately win" because "the utilities have the market power,” Kay Aikin, founder and chief product officer of microgrid developer Dynamic Grid, told Utility Dive. “There may not be enough money in the distribution system to support an independent DSO, utilities, and customers,” she said.

But the participation of local community leaders who see DERs as the solution instead of the problem is vital “because the future of the power system is through the customer,” Aikin added. In the near term, California’s cost of service regulation may impede distribution system reform, but “a new performance-based paradigm can eventually allow utilities to make money by saving money,” she said.

A legal consideration was raised by Coalition of California Utility Employees Attorney Rachael Koss. The California Public Utilities Code Section protects the utilities’ operation of their distribution systems, she told the workshop. Any proposal “that goes beyond the legal guardrails will have to convince the legislature,” she added, suggesting a new DSO model that compromises utility control would face challenges.

The important proceeding proposals began with “societal goals common to all communities” and worked backwards to distribution system reform that achieved those goals, Synergistic Solutions Principal Analyst Robert Perry told the workshop. The best was a “rethinking” of distribution system reform by The Climate Center’s Kristov, he said.

The community-based rethink

The existing distribution system model "is not adequate to a high DER future" and the utility revenue model that favors capital investments over DER integration "requires rethinking,” said Kristov, who helped design features of California's transmission system. The incumbent utilities, regulatory agencies and system operator have key roles in creating an interactive open access network “but their approach requires reshaping," he said.

“The conversation must shift from DER as a problem to DER as the key to the future,” Kristov added. “The heart of the issue is the utility’s incentive to overbuild infrastructure,” because DER can be “a reduced cost-alternative,” he said.

With regulation that compensates utilities for system services, their wires services can interconnect community-serving resources built by DER providers, he added.

Another key factor that requires rethinking is the commission's attitude toward many who could potentially be affected by decisions on distribution system management, advocates for customers and customer-owned resources said.

A too-technical approach to the workshops could limit stakeholder engagement, prevent “a stakeholder-informed record,” and “meet only the needs of incumbent utilities,” California Alliance for Community Energy Operations Director Erika Morgan warned the workshop on behalf of multiple community and environmental groups.

“The utilities, the distribution system, and its rules should serve the needs of the community, not the other way around,” California Alliance for Community Energy Coordinator Al Weinrub added. A community-led process would identify distribution reform objectives before picking a DSO model, he said.

DSO models, utility incentives and customer engagement are key parts of rethinking the distribution system, Kristov agreed. "After the objectives for the 2030 power system are clear, the DSO model to deliver them can be designed, and a new regulatory framework can make that DSO the centerpiece of a renewed, networked power system.”

Pushing back against state utility regulators and others, the Midcontinent Independent System Operator told federal regulators July 8 its plan to wait until 2030 to allow aggregated distributed energy resources to participate in its power markets is “reasonable and appropriately tailored for the MISO region.”

Also, MISO said there are various pathways for resource owners to participate in existing retail programs as well as in its wholesale markets via existing load-serving entity programs and through aggregation programs established by state utility commissions and other “relevant electric retail regulatory authorities,” called RERRAs.

“The time between now and 2029 will be best used to work on other market and underlying system enhancements that it believes will make the full DER implementation process seamless and able to provide the most value to the MISO region,” the grid operator said.

In a landmark decision, FERC in September 2020 ordered regional transmission organizations and independent system operators to remove barriers keeping DER aggregations from participating in wholesale markets. The aggregations could include resources like rooftop solar, energy storage and electric vehicle chargers.

FERC is now reviewing grid operators’ plans to meet the requirements the commission laid out in its Order 2222, such as PJM Interconnection’s proposal, which has a 2026 start date.

After conducting a stakeholder process, MISO in mid-April filed its plan at FERC, saying that before letting groups of DERs into its markets it needed to finish a major market software overhaul that is set to be in place by 2025. Then, MISO wants to work on its Multiple Configuration Resources initiative, which the grid operator said would help it manage its growing fleet of wind and solar resources.

In comments filed last month, the Organization of MISO States, which represents state utility regulators, and the Solar Energy Industries Association and Advanced Energy Economy raised concerns about MISO’s proposal, including its implementation schedule. Utilities like DTE Electric, Northern States Power and Consumers Energy generally supported MISO’s plan.

Besides defending its timeline for allowing DER aggregations under Order 2222, MISO told the commission its proposal to limit aggregations to a single “elemental pricing node” is the broadest and most technologically feasible approach possible.

Some groups contend the single-node limit will effectively bar some resources, such as residential resources, from taking part in DER aggregations. They want MISO to adopt a multi-nodal approach.

However, a multi-nodal approach could lead to inaccurate modeling of what is happening on its system, threatening grid reliability, MISO said.

“Failure to accurately model the location of energy can lead to avoidable transmission constraints, broad oscillation of energy dispatch from interval to interval, and other reliability concerns,” MISO said, noting in 2020 it studied approaches to managing multi-node aggregations.

MISO said its proposal is appropriately tailored to prevent DER aggregations from being double-counted in retail and wholesale markets.

To address some utility concerns, in its reply comments, MISO proposed language that aims to prevent market participants from trying to avoid reviews by the grid operator’s market monitor by keeping their aggregations under a 10-MW threshold that triggers a review.

Under the proposed change, aggregated resources that are near each other and controlled by the same market participant would be treated as a single resource to see if they pass the 10-MW threshold.

Republican Gov. Ron DeSantis vetoed a bill April 27 that would have authorized public utilities to impose additional charges on customers to recover lost revenue from residential solar generation.

Passed at the end of March, the bill was part of a larger effort that has investor-owned utility support. DeSantis cited the potential cost increases in his rejection.

The bill was heavily opposed by the state's solar developers, who said it would have increased utility bills and ruined the cost proposition for distributed generation. A week after the state Senate passed the bill, a Sachs Media poll found that only 3% of Florida voters supported the legislation, while 86% wanted to see the measure vetoed.

Since the two chambers of the Florida legislature passed H.B 741/S.B. 1024, Solar United Neighbors confirmed more than 15,000 outreach attempts from Florida residents to the governor's office in opposition to the bill, according to Heaven Campbell, the group's Florida program director.

"His decision to veto this bill will allow our industry to continue growing and give more homeowners in our state the chance to lower their electric bills with solar," Justin Vandenbroeck, president of the Florida Solar Energy Industries Association, said in a statement.

In his rejection, DeSantis wrote that "the state of Florida should not contribute to the financial crunch that our citizens are experiencing," referencing nationwide inflation that includes a rise in gas and grocery prices.

"We are thrilled and encouraged and heartened and ecstatic and validated," said Katie Chiles Ottenweller, Southeast director of solar advocacy group Vote Solar. 

"This has been a long, bitter fight to try to protect solar rights in Florida... I feel like Floridians have spoken. Credit really goes to the public for speaking out," Chiles Ottenweller said.

The bill included language that prevented it from becoming a precedent for other similar measures, stating that "the Legislature provides the limited, extraordinary relief set forth ... to address the potential impact on a public utility of a previously unanticipated surge, unaccounted for in the utility's last rate case, in the installation of customer-owned or leased renewable generation over the period specified in this subsection." It specifically "makes no findings as to whether the recovery of lost revenues by a public utility is appropriate for any other purpose."

"The wonky bill readers, and us energy nerds, see that this as legislators saying this is a lot to take in," Campbell said. "It's like they're saying, 'This is the worst clause we've ever put into a statute. Please don't ever use this again.'"

The bill had the support of the state's utilities, including Florida Power & Light (FPL) and Duke Energy Florida, and the local chambers of commerce.

"We remain committed to finding a more equitable net metering solution for all Floridians," Chris McGrath, FPL spokesperson, said in an email. "FPL is leading the nation’s largest solar expansion and we will continue to advance solar that is cost-effective for all our customers."

"Duke Energy Florida will review the Governor’s veto message and continue our commitment to our customers to provide clean, reliable and affordable energy," Ana Gibbs, utility spokesperson, said in an email.

Duke’s Florida subsidiary says it leads the state in customer-sited renewable generation.

The Public Utilities Commission of Texas is requesting information on how distributed energy resources can boost reliability, and what grid upgrades would be required to facilitate their integration. 

DERs are a "holy grail issue" for the electric grid, Commissioner Will McAdams said at the PUCT's open meeting on April 21. The questions involved may be considered alongside efforts to standardize the distribution system interconnection process, he said.

Commissioners also discussed development of a new Firm Fuel Supply Service (FFSS) that would incentivize gas generation units with firm storage to be available in the 2022-23 winter. Looking further ahead, commissioners said they will also consider encouraging generators to purchase more coal for on-site storage.

The PUCT on April 21 continued its work to overhaul the state's wholesale markets in the wake of Winter Storm Uri and widespread blackouts last year. Commissioners are rushing to hammer out details that will inform an Aug. 1 FFSS request for proposals to be issued by the state's grid operator.

An April 20 memo by Commissioner Lori Cobos sketched out what resources could be eligible in the Electric Reliability Council of Texas' first FFSS procurement. Commissioners agreed those would be limited to dual-fuel capable generation units with on-site alternative fuel storage, and generators that own and control the pipeline to a storage facility.

That limits the first tranche of FFSS resources to certain gas units, but commissioners discussed expanding the product for the 2023-24 winter and beyond.

"Coal piles provide firm fuel," Commissioner Jimmy Glotfelty said. "I would be interested in looking, in perhaps a second phase, if additional coal stocks beyond what is normally contracted for during winter months, or times of need, would be considered."

Coal is "very firm," Chairman Peter Lake agreed. "I think it's worthwhile to include consideration of coal for phase two." 

More gas units could be eligible for an expanded FFSS product, as well. Commissioners discussed allowing units with fuel supply arrangements consisting of off-site storage with firm transportation contracts to participate in future years.

Cobos did raise some concerns regarding additional coal purchases. 

"I've been reading that coal prices are going up. I've also been reading that the [U.S. Environmental Protection Agency] is coming out with regulations that impact coal," she said, referring to cross-state air rules. "What are we ultimately going to have to pay for, a pile of coal? Or are we going to be asked to pay for a scrubber?"

PUCT wants help with DER integration 

Commission discussion of how distributed resources can boost Texas reliability was based around an April 20 memo filed by McAdams. There are nearly 3 GW of distributed generation resources on the ERCOT grid, and about a quarter of that was added in 2021, according to the memo.

"This is a dynamic and evolving area of the energy industry," McAdams said. "It is growing leaps and bounds by the day and it's only accelerated after Winter Storm Uri because everybody is looking at trying to have some type of backup power source on their house."

PUCT staff is developing a formal filing, based on the memo, to request one round of industry comments. Questions revolve around issues of distribution planning and control, costs, grid upgrades and the need for more data on distributed resources.

Questions include:

• What level of remote, granular controllability is possible?
• Presently, how are existing DERs utilized on distribution networks? 
• What equipment, processes, and standards need to be implemented to allow for further DER participation? 

As more Texans install backup generation following blackouts last winter, the request for comments on how to muster that resource is "a cry for help," McAdams said.

"If we can ever crack the code on [DERs], then the grid has unlimited potential in terms of resiliency capabilities and resource adequacy," McAdams said. "All the other grids are tackling this, and [the Federal Energy Regulatory Commission] is keenly interested in it."

The PJM Interconnection’s plan to open its markets to distributed energy resource (DER) aggregations is a "good first step," but it includes provisions that may prevent them from full market participation, Advanced Energy Economy (AEE) and Advanced Energy Management Alliance (AEMA) said Feb. 2.

PJM, the largest U.S. grid operator, filed a plan Feb. 1 at the Federal Energy Regulatory Commission establishing a framework for aggregated DERs like rooftop solar, energy storage and electric vehicle chargers to take part in the grid operator's energy, capacity and ancillary services markets starting in 2026.

PJM said it will continue to work on various issues that emerged during stakeholder discussions, such as cybersecurity and making sure the DER aggregation model keeps up with evolving state policy and grid modernization efforts.

In a landmark decision, FERC in September 2020 ordered regional transmission organizations and independent system operators to remove barriers keeping DER aggregations from participating in wholesale markets.

Since then, grid operators have been developing plans to meet the requirements FERC laid out in its Order 2222.

FERC’s decision coincided with rapid growth in DERs in response to declining consumer costs, increased consumer interest and state policy, according to Jeff Dennis, AEE managing director and general counsel.

"We're going to have this big set of resources out there that, when aggregated together, can provide valuable services to the wholesale market, and in capturing that value can help make the markets more efficient, and can provide a new, resilient and reliable set of resources for the RTOs," Dennis said Feb. 2. "And it's really one of the first steps toward unlocking flexibility on the demand side of the market."

The compliance plan aims to strike a balance between giving aggregated DERs access to the wholesale markets while allowing distribution utilities and "relevant electric retail regulatory authorities" to make sure the electric distribution system is safe and reliable, according to PJM, which operates the grid in 13 Mid-Atlantic and Midwest states and the District of Columbia. 

PJM said its DER aggregator participation model accommodates the physical and operational characteristics of an aggregation without placing restrictions on resource or technology types for market participation, and allows both single-type and mixed DER aggregations to participate in all markets where they can provide services. A mixed aggregation could combine different resources such as residential rooftop solar, energy storage and larger, off-site solar, for example.

The proposal defines a DER aggregator as having at least one DER component. The aggregation must be able to provide at least an energy and/or ancillary services market offer of 100 kW, and individual DER components may not exceed 5 MW, according to the filing.

PJM’s "balanced treatment" of various resource types and innovation on metering, submetering and settlement data will help facilitate DER participation in the grid operator’s markets, AEMA said in a statement.

Even so, the alliance and others see areas in the proposal they say may limit DER aggregations.

PJM’s proposal restricts DER aggregation participation in the energy market to a single pricing node on the grid. PJM said allowing aggregations to use multiple nodes would make it hard to meet reliability standards. The grid operator proposed allowing multi-nodal aggregations of up to 5 MW for its capacity and ancillary services markets.

The limit to a single node makes it challenging to create DER aggregations and could strand potential resources, according to Greg Geller, head of regulatory affairs for Enel North America. Ideally, an aggregation is as large as possible, which may require covering a wide area, he said Feb. 2.

Enel manages aggregations of electric vehicle chargers in markets run by the California Independent System Operator (CAISO) and is interested in bringing them to other markets, Geller said.

PJM has thousands of nodes so meeting a 100-kW minimum size for an aggregation may be difficult, according to AEMA. "By comparison, California, New England, and New York all found ways to allow for these smaller resources to participate by allowing aggregation over large subsets of pricing nodes," the trade group said in a statement.

AEE is also concerned about PJM's proposed registration process for aggregations. Under the plan, DER aggregations must coordinate with their distribution utility before registering with PJM. The registration process includes a 60-day period for distribution utilities to review the proposed aggregation. After getting the utility’s recommendation, PJM has 15 days to approve or reject the registration.

The proposed registration process could effectively give distribution utilities veto power over planned aggregations, according to Prusha Hasan, AEE policy principal.

The trade group is also concerned about limits on participation by net energy metered resources in energy and capacity markets, which would leave a "swath" of resources unable to be a part of PJM’s markets, Hasan said.

While AEE would like to see some changes to PJM’s proposal, it appears to meet the needs of potential DER aggregators better than other grid operator plans, including ISO New England’s proposal filed Feb. 2, according to Dennis.

"Our members were happier with PJM's proposal than some of the other ones we've seen," Dennis said. "Like in New England, we don't think New England's proposal will unlock really anything."

FERC is reviewing Order 2222 compliance filings from CAISO and the New York Independent System Operator. The Midcontinent Independent System Operator and the Southwest Power Pool are preparing to file their proposals this spring.