Improving Grid Reliability with Distributed Generation Policy Reforms

California has built the largest aggregation of residential batteries in the world — over 720 megawatts enrolled in its Demand Side Grid Support program. What California hasn't done is make that capacity routine. DSGS and the Emergency Load Reduction Program activate only when CAISO declares a grid stress event, meaning the enrolled fleet its mandated for all new solar customers but not integrated into the way that California Utilities operate their grid. I get it, CAISO is one of the most complex wholesale markets in the world. But the fragmented result — NEM 3.0, DSGS, ELRP, and Rate tariff arbitrage running in parallel with different enrollment requirements — is the point. California built programs to satisfy policy mandates and forgot to integrate these resources to help acheive speed to power for data centers and load growth. Rocky Mountain Power's Wattsmart in Utah represents the opposite philosophy. Built as a direct operational tool from day one, the program ran more than 130 response events in 2024 — not emergencies, but routine grid balancing. The DOE called it among the most advanced VPPs in the country for its integration into system operations. Batteries dispatch in under 250 milliseconds, enabling frequency regulation that California's programs don't attempt. That control is what makes the resource reliable enough to count in capacity planning. ConnectedSolutions in the Northeast sits ahead of California on reliability. Its pay-for-performance model — locking incentive rates for five years, paying based on actual energy delivered — has 95–99% event response rates. Narrower in scope than Wattsmart, operating only in summer, but what it does it does consistently. Texas is the most structurally ambitious experiment. ERCOT's Aggregated Distributed Energy Resource pilot — born from the trauma of Winter Storm Uri — aims to let distributed batteries participate directly in wholesale energy and ancillary services markets, not just demand response. Now in Phase 3, the program has doubled its capacity cap to 160 megawatts and expanded into contingency reserve services. Seven commercial ADERs were participating as of late 2025, small in scale but sophisticated in architecture. Texas is attempting to give a home battery the same market standing as a conventional power plant. Importantly, sophisticated business models are already unlocked for home batteries through the wholesale market. The pattern is consistent: operational integration requires either a vertically integrated utility with direct dispatch authority, like Rocky Mountain Power, or a wholesale market genuinely built for small resources, like ERCOT is constructing. California has neither cleanly. The gap between its enrolled megawatts and its operational reliability is frustrating for those of us who think that California should lead on distributed energy.

Some of us keep talking about DERs and better grid utilization to help solve the power demand problem. Excited to see things are starting to move in that direction. For years, when utilities needed to meet peak demand, the answer was almost automatic: build a gas peaker plant. That assumption is starting to crack. Not because of ideology—but because the math is changing. Take Consolidated Edison’s Brooklyn-Queens Demand Management program. Instead of building a new gas peaker and substation upgrade, they deployed a portfolio of distributed energy resources—efficiency, rooftop solar, and behind-the-meter batteries. It delivered the same reliability outcome at a fraction of the cost. Or look at what’s happening more broadly with virtual power plants—aggregations of home batteries, smart thermostats, EVs, and flexible loads. In places like California and Texas, these systems are now being treated as real capacity resources—able to shave peaks and reduce the need for fossil peakers. What’s emerging is not a one-off workaround. It’s a pattern. Distributed energy resources are increasingly taking over the role that gas peakers used to play: meeting short-duration spikes in demand, cheaply and quickly. And now there’s a new twist: Large loads—especially data centers—are beginning to join that stack. Through demand flexibility and workload shifting, they can act less like passive demand and more like dispatchable capacity. If this continues, the implications are significant: • Less need to build new gas peakers • Lower system costs (because DERs are modular and faster to deploy) • A grid that’s more flexible—and more participatory To be clear: DERs aren’t replacing all firm capacity. We still need solutions for multi-day reliability and extreme events. But they don’t have to. If DERs can cover even 10–20% of peak demand by 2030—as several analyses suggest—that’s enough to avoid a large share of new peaker builds. The “default” is shifting from one big plant solving the problem to a portfolio of smaller, smarter resources working together. That’s not just a technology story. It’s a different way of thinking about the grid. Keep watching this trend ….

Good News Thursday! Michigan is trying to fix its grid in new, distributed ways. The Michigan Senate Energy and Environment Committee just advanced SB 731 and SB 732, two bills that would create a statewide virtual power plant (VPP) program. Right now, Michigan doesn’t really have one. There are small pilot programs, but no clear rules, no consistent payments, and no requirement for utilities to use them, making it hard for the private sector to get involved. These bills aim to change that. Here’s what each one does: 1. SB 731 This bill sets the legal groundwork. It defines how virtual power plants work under Michigan law and allows distributed energy resources (like rooftop solar, home batteries, EV chargers, and smart devices) to be treated as a real grid asset. Without this, everything stays in scattered pilot programs, each working in isolation, with no common rules and no way for those systems to talk to one another. 2. SB 732 This bill moves it into action. It requires the Michigan Public Service Commission to: • create a statewide VPP program • require utilities to include VPPs in their grid planning for distribution and transmission • set compensation for households and aggregators who provide grid services In simple terms, it turns distributed resources into something utilities are actually required to use. The state has faced growing reliability concerns in recent years. Storm-related outages have left hundreds of thousands of customers without power at times. At the same time, demand is rising, and the grid is aging. The traditional solution is to build more infrastructure. But that takes time and costs money. VPPs offer another option. California, Texas, and New York have all expanded VPP programs: • California has used solar + battery VPPs during heat waves to cut peak load, reduce stress on the grid, and avoid emergency measures. • Texas has scaled residential battery VPPs that pay battery owners to respond to price signals and support grid-constrained areas during summer peaks. • New York is expanding utility-run programs that pay households with batteries to provide grid support during high-demand periods. The result in many cases has been: • lower peak demand • fewer last-minute emergency measures • better use of existing transmission and distribution infrastructure Instead of relying only on large power plants, the grid starts using what people already have installed that can reduce pressure during peak demand, lower system costs over time, and improve reliability during extreme weather. Both bills now move forward in the legislative process. If passed, Michigan would move from scattered pilots to a structured, statewide VPP program that actually integrates distributed resources into how the grid is planned and run.

Two Recent Policy Actions in CA and MD Suggest an Evolving Future for DERs. 1) On March 21, 2024, the California PUC issued ruling permitting distributed renewables to be interconnected to the grid through an energy export schedule (called a Limited Generation Profile). The ruling requires utilities to furnish hourly hosting capacity information for each circuit, allowing asset developers to design projects that stay within pre-defined limits - export levels can vary 24 times per year - instead of paying for upgrades such as new transformers. This provides a more realistic and cost-effective approach to integrating renewable exports into the grid. 2) On April 4, 2024, the Maryland legislature passed the Distributed Renewable Integration and Vehicle Electrification Act, or DRIVE (it now goes to the governor for signature). DRIVE requires utilities to compensate customers for providing grid services through virtual power plants (VPPs), while specifically calling for utilities to accelerate vehicle to grid (V2G) bidirectional charging systems. Utilities must submit V2G plans by next April and VPP plans 3 months later. These actions matter. Today’s grid runs at around a 41% average annual capacity factor and it’s getting peakier. However, if we could cut demand by just 1%, we could reduce capital costs by roughly 8%. If we could cut peak demand by 10%, we’d reduce total expenditures by roughly a quarter. With a growing population of rooftop solar, home batteries, and EVs, we may soon have the tools to address this opportunity. California’s first-of-its-kind approach helps avoid unnecessary grid upgrades, while Maryland’s future virtual power plants and bi-directional EVs will add flexibility while increasing capacity utilization factors – reducing costs per kilowatthour delivered.  Charging EVs at the right times, combined with solar assets, rooftop batteries, and optimized bi-directional flows could deliver more clean power to the right locations, when we need it and help flatten those costly demand curves. If the two models were combined, then we’d really have something. Utilities elsewhere should be paying attention. Links: https://lnkd.in/enqATa_R https://lnkd.in/ekyaEnHA #VPPs #virtualpowerplants #DERs #distributedenergyresources #vehicletogrid #V2G #vehicletoeverything

The grid is moving away from a 100-year old paradigm where controllable centralised supply is adjusted to meet uncontrollable demand, to one where controllable demand is adjusted to meet increasingly uncontrollable and decentralised supply. Data centres have huge UPS and backup generators. The issue is whether they can avail of these for interruptible load/demand response, bearing in mind their very stringent operational requirements. The grid is the backbone of decarbonisation. There is no transition without transmission. "Singapore's demand for electricity is also expected to grow with the increase in businesses and facilities that rely on large and steady supplies of electricity, such as data centres and EVs. "Grid management will become more complex with these new load profiles", he added. To address this, EMA will explore a demand-side flexibility roadmap aimed at allowing the grid to tap "underutilised" distributed energy resources such as battery energy storage systems and backup generators. This means that such resources, which keep energy on standby when they are not being used, could be relied on for Singapore's power needs on a "near-continuous basis". The authority said in a statement: "These resources are typically maintained on standby, placing them in a state of readiness that enables activation with short notice. "Their capability to sustain load curtailment over extended periods suggests they could be well-positioned to provide ancillary services alongside their primary operational role." Together, distributed energy resources and electricity users or facilities that require a continuous and high load of power can be a "potentially dependable and scalable means of contributing to system reserves", EMA said. EMA will be publishing a tender to explore the feasibility and design of a programme that can incentivise relevant parties to contribute to power grid reliability continuously, it said. As part of this roadmap, EMA will also enhance its interruptible load programme, which is targeted at business consumers. The scheme allows eligible participants to be compensated for being on standby and to reduce their electricity demand when the grid faces tight supply constraints. The authority plans to provide greater certainty to these participants during contingencies by reducing interruptible load activation period to 30 minutes. Implementation details have yet to be finalised." EMA said the current pool of interruptible load resources was "opportunistic", as participants only reduce their load when schedules allow. These participants, who are mainly factories or production lines, cannot offer capacity consistently or for prolonged periods as they need to keep their own core operations running." https://lnkd.in/gh9U7Sp5

🚀 Reforming Australia’s energy markets: A $19 billion DER opportunity 💰 My submission to the National Electricity Market (#NEM) Wholesale Market Review, prepared for Solar Citizens, outlines how outdated rules and market design are stifling $19 billion in net benefits from distributed energy resources (#DER) by 2040. As pv magazine Australia highlights, this isn’t just about rooftop solar—it’s about redesigning markets to prioritise DER as critical infrastructure for affordability, reliability, and decarbonisation. DER—including solar, batteries, EVs, and flexible demand—could deliver: $11 billion in avoided network costs (poles, wires, substations), and $8 billion in reduced large-scale generation/storage needs. 20% of contingency FCAS raise is already provided by aggregated DER today. Yet current market rules and network revenue regulation: * Impose 1MW bid minimums, reducing competition * Lock households and SMEs out of the wholesale demand response mechanism * Let networks prioritise costly infrastructure over DER solutions * Include no minimum demand equivalent of the RERT (emergency peak supply), and * Are not designed for a majority renewable electricity system. See my submission for the details of this series of principles to support the participation of aggregated DER in markets: * Market design should be prepared from first principles * Value resilience to extreme weather events in reliability * Consider how greater deployment of SAPS and microgrids could be facilitated * Ensure fair and non-discriminatory access for all forms of aggregation to all markets and regulatory procurement * Ensure equitable, fair compensation * Facilitate robust competition, especially through the lowest reasonable minimum bid sizes *Establish the best way to manage minimum demand * Enable value stacking to maximise benefits Ensuring fair and inclusive consumer participation: * Voluntary consumer participation * Tiered participation options * Ensure appropriate consumer protections, including transparency about benefit splits Technical and regulatory enablers of #ADER: * Create open data and open communication protocols, use open-source software, make detailed network data available and allow third party access to real-time smart meter data with consumers’ permission * Implement Dynamic Operating Envelopes * Upgrade Market Systems #EnergyPolicy #RooftopSolar #NEMReform #aggregatedDER Integrate To Zero, IEEFA Australia, The Superpower Institute, UTS Institute for Sustainable Futures, NSW Decarbonisation Innovation Hub, Blunomy, Tim Nelson, Paula Conboy, NACD.DC GAICD