1. When PJM hit near-record demand over the July 4th heat wave, it leaned on thousands of megawatts of paid demand response to stay under the line — flexible load is now first-resort grid infrastructure, not a last-resort backstop.

2. New Jersey’s data center tariff bill mandates demand-response programs and curtails hyperscalers ahead of residential load, handing other states a template for making big loads fund their own flexibility.

3. Illinois approved ComEd’s utility-run VPP the same fortnight ComEd was calling demand response to survive record heat — reliability stress is pulling VPP programs from statute to dispatch.

News Roundup

Grid Reliability · 🟢 Bullish

PJM secures emergency DOE orders, dispatches Capacity Performance DR as heat wave threatens all-time record 📅 Published: 07/02/2026

• PJM forecast a July 2 peak of 166,241 MW, above the grid’s all-time summer record of 165,563 MW set in 2006. The Department of Energy granted PJM a 202(c) order to curtail data centers and other large loads with backup generation as a last resort, plus a second order relaxing environmental permit limits on generating units. PJM’s own emergency procedures postings show it went beyond alerts: it dispatched Pre-Emergency Load Management actions calling “Capacity Performance DR” — the successor product to the old Special Case Resource (SCR) category — across nearly every zone including AEP, BGE, ComEd, Dominion, and PECO on both July 2 and July 3. Preliminary DR performance reached about 6,113 MW on July 2 alone.

Utility RFP & Procurement · 🟡 Neutral

PJM stakeholders approve data center reliability backstop procurement plan 📅 Published: 07/02/2026

• PJM stakeholders approved a two-part plan letting utilities and data centers request a one-time capacity auction, capped at $555/MW-day. The board plans to file the proposal with FERC this month, targeting a September auction ahead of the Dec. 9 capacity auction for the 2029/30 delivery year. A separate “connect and manage” framework for curtailing data centers didn’t reach consensus; PJM staff instead proposed a large-load registry for state regulators.

Policy & Legislation · 🟢 Bullish

New Jersey lawmakers send data center tariff bill — with DR mandates — to governor 📅 Published: 07/01/2026

• New Jersey’s legislature passed a bill requiring the BPU to set tariff standards for all data centers of at least 50 MW. The bill mandates development of demand-response and efficiency programs, requires flexibility-performance reporting, and prioritizes curtailing data centers before residential customers in emergencies. It now heads to Gov. Sherrill, whose office reportedly helped shape the final version.

Utility Programs · 🟢 Bullish

Illinois regulators approve ComEd VPP under new clean energy law 📅 Published: 07/08/2026

• One week after leaning on demand response through the heat wave, ComEd got Illinois Commerce Commission approval for a battery-based “scheduled dispatch virtual power plant,” or SDVPP. It replaces a narrower proposal ComEd withdrew last November after the Clean and Reliable Grid Affordability Act passed. The law mandates 3 GW of storage by 2030 and directs utilities to build VPPs from residential and small-commercial batteries, EV chargers, and HVAC controls. Enrolled customers commit to five consecutive summer seasons and earn seasonal performance payments based on energy injected during peak events — the statutory storage target converting into dispatchable capacity in near real time.

Grid Reliability · 🟢 Bullish

ComEd declares “critical strain” on Chicago-area grid as PJM calls DR in its zone 📅 Published: 07/01/2026

• ComEd sent an immediate energy-reduction alert to 78,000 customers on Chicago’s West Side and southwest suburbs as feels-like temperatures hit 104°F, asking customers to delay EV charging until after 8 p.m. and raise thermostats. That residential ask was voluntary, but PJM’s emergency procedures postings show ComEd’s zone was simultaneously subject to PJM’s dispatched Capacity Performance DR calls on July 2–3 — meaning the ComEd area’s enrolled DR fleet, not just goodwill, was doing real work during the peak.

Grid Reliability · 🟡 Neutral

NYISO issues Energy Watch, calls for conservation as New York approaches its 2013 demand record 📅 Published: 07/02/2026

• NYISO forecast a July 2 peak of 32,410 MW, closing in on the state’s all-time record of 33,956 MW set in July 2013. On the afternoon of July 2 it issued an Energy Watch — the alert triggered when operating reserves are projected below 2,620 MW for more than an hour — but said the grid was operating normally with adequate resources to meet demand. Gov. Hochul asked residents to voluntarily raise thermostats and coordinated with Con Ed and NYISO on large-customer conservation. Unlike PJM, New York did not escalate to dispatching its paid SCR/EDRP demand-response fleet during the event — a reminder that the flexibility is only proven when the grid actually calls on it.

Utility Programs · 🟢 Bullish

Eversource launches targeted ConnectedSolutions+ pilots, dispatches an all-call on its base ConnectedSolutions program 📅 Published: 07/01/2026

• Eversource launched substation-targeted DR pilots in Greater Boston and southeastern Massachusetts, recruiting batteries, EVs, and smart thermostats. Boston-area battery participants can earn a $400/kW performance incentive, and the pilots are live now during the regional heat dome. The parent ConnectedSolutions program wasn’t just standing by either: program manager Jenn Runyon told NBC Boston on July 1 that Eversource had issued “an all call” for that evening’s 5–8 p.m. peak, pre-cooling and cycling enrolled thermostats and batteries.

Utility RFP & Procurement · 🟡 Neutral

Massachusetts utilities ink contracts for 4.5 GWh of energy storage 📅 Published: 07/07/2026

• Eversource, National Grid, and Unitil filed long-term contracts for about 1,068 MW / 4,472 MWh across three utility-scale storage projects toward the state’s 5 GW-by-2030 goal. The projects sit in the same Greater Boston and southeastern Massachusetts zones where Eversource is piloting the localized VPPs above. It is front-of-meter procurement, not a VPP program — but it maps the exact congestion pockets where distributed flexibility will compete for the same reliability value.

Product Announcements · 🟢 Bullish

Eaton named FranklinWH’s preferred smart-breaker supplier 📅 Published: 07/09/2026

• Eaton and FranklinWH will integrate Eaton’s AbleEdge smart breakers directly into FranklinWH storage systems, with Eaton as the preferred load-management supplier. The breakers add circuit-level load control and VPP functionality in both retrofit and new-construction installs. Baking VPP-ready load management into the hardware stack lowers the enrollment friction aggregators currently absorb after the sale.

📊 By the Numbers

• 166,241 MW — PJM’s forecasted July 2 peak, above the grid’s 2006 record of 165,563 MW. The actual result was 168,154 GW.

• ~6,113 MW — preliminary demand response PJM says it performed on July 2.

• 32,410 MW — NYISO’s forecasted July 2 peak, approaching New York’s 2013 record of 33,956 MW.

• $555/MW-day — cost cap on PJM’s new data center reliability backstop capacity procurement for the 2029/30 delivery year.

• $400/kW — Eversource’s performance incentive for battery curtailment in its Boston ConnectedSolutions+ pilot.

• 4,472 MWh — utility-scale storage newly contracted by Massachusetts utilities (~1,068 MW).

• 3 GW — energy storage Illinois utilities must deploy by 2030 under the law enabling ComEd’s SDVPP.

🗓️ On the Radar

• September 2026 — PJM’s targeted date for holding the data center backstop capacity auction.

• Sept. 18, 2026 — DERVOS early-bird tickets now on sale, starting at $499.

• Dec. 9, 2026 — PJM’s capacity auction for the 2029/30 delivery year, which the backstop procurement is meant to precede.

💬 My Take

In my last post I put forward a framework on how utility-run VPPs have antifragile characteristics following extreme weather events. As a reminder, a one sentence summary of an antifragile system is one that “increases in capability to thrive as a result of stressors.” Here are some concrete examples: APS has seen success with their VPP and they want to look to grow it significantly with the success as well as the underlying need for more flexible load. This is mirrored across other utilities’ VPPs like Duke and Eversource. The extreme weather helps prove and validate the value of these portfolios and creates a feedback loop for them to grow and the software to support them to become more capable. This feeds back into rate cases that can unlock more funding for these programs over time.

With the heat dome covering much of the Eastern United States over 4th of July weekend causing capacity forecasts to be close to record peaks in PJM and New York, my intuition is that wholesale market participation of VPPs should increase with increased value and increased utilization. In PJM, I see the opposite.

I see short term barriers that are specific for the commercial and residential customers preventing growth through the 2028-2029 participation year. The mechanics of Reliability Backstop Procurement (RBP) have the potential to change that. I forecast DR will start to grow by the 2029-2030 participation year. My takeaway is that VPP growth in PJM has slower feedback loops than utility-led VPPs. This is resulting in barriers to short-term growth.

VPP supply hasn’t responded to increased prices, yet

Two ways to quantitatively measure stress on PJM’s grid and the value for VPPs is the annual duration of emergency dispatches from PJM’s Emergency Load Response Program (ELRP) and increased value for VPP’s services, especially capacity. Both metrics increased since 2025:

1. PJM has experienced significant increases in clearing prices for capacity since the 2024 to 2025 delivery year.

2. There was no year with more than 10 cumulative hours of dispatch from 2019-2025, with the single exception of Winter Storm Elliott. Last year we saw 30 hours of dispatching for emergency resources on the grid. And as of July 18th 2026, there have already been over 20 dispatch hours

   

So we have higher value for VPPs participating in PJM’s capacity market, and those resources are being used more. But if you look at the nameplate capacity being offered into the market since the 2018/19 supply year, it has gone down. From the 2024-2025 to 2025-2026 season we saw one of the largest ICAP drops of 1.3 GW of DR nameplate capacity. This was the same season prices cleared at the price cap. Since 2025, third-party aggregators have either decreased or maintained the nominated capacity of VPPs in the market (ICAP). When adjusted for Effective Load Carrying Capacity (ELCC) - how much of a resource’s nameplate capacity will be available during the hours the grid is most likely to fall short - the portfolio has fluctuated as PJM has allowed VPP participation to count in more hours of the year. While there was an increase in the UCAP value of demand response in 2027-2028, this was entirely driven by the change in ELCC calculation (69% up to 92%). This means that the same ~8 GW of VPP capacity had a 33% increase in value per capacity because of the change in ELCC.

My question is why hasn’t third party VPP capacity increased in PJM? Shayle Kann asked Steve Piper at S&P Global Energy the same question in an interview for Catalyst in July of 2025. He made the point that there would be a “period of adaptation” with the changes to capacity accreditation to include winter months. With a year of additional data, I see some additional reasons that are specific to residential and commercial customers.

Barriers to residential VPP participation

There is a barrier across residential participation just with third-party aggregator access to utility interval data and enrollment data in PJM’s wholesale market. Utilities across PJM have made access to residential interval data extremely challenging. This barrier resulted in Voltus attempting to enroll 20,000 residential Resideo thermostat customers in ComEd and only 4% being able to participate. By comparison, just requiring an account number for enrollment results in only up to 16% of customers completing enrollment according to Brattle Group and Uplight. This means that in ComEd, there was a 4X decrease even compared with requiring details like account number.

Some ISOs like CAISO allow sampling techniques where average performance across a subset of the customers is used for measurement and verification. PJM, however, has also prevented statistical sampling for DR performance results for homes that already have smart meters installed. Both the barriers to statistical sampling and smart meter data severely block growth from a significant new source of wholesale market flexibility.

There are also barriers for EVs and batteries that make smart thermostats the dominant asset for future growth:

1. EVs are blocked by baselines: PJM’s baseline looks at peak load contribution across the prior year’s peak hours and penalizes increased load during peak hours from one year to the next. This makes EV participation challenging because the first year of EV ownership can result in higher peak load during the peak hour.

2. Residential storage effectively cannot be compensated for export: This caps nominations and energy revenue at the net load of the household. While there is an Energy Storage Resource enrollment pathway that in theory could result in residential batteries being compensated for exports, this is effectively blocked. My read is that requirements like the day ahead state of charge of the battery, round trip efficiency and ramp rate are not practical for residential storage (Section 2.3.4B).

3. Residential storage deployment is limited in PJM: In Wood Mackenzie’s US Energy Storage Monitor Q1 2026 and 2025 Year In Review, the team found that Illinois is the only state in PJM that is in the top 5 states for residential battery storage deployment. While this will continue to change, there has not been near the available battery resource in PJM that is now dispatchable in California, Texas or Puerto Rico.

Barriers for commercial participation

By contrast, there has been robust commercial and industrial participation in PJM’s capacity market for over 15 years. And yet, third-party demand response providers on net are decreasing the size of their portfolios’ capacity.

One barrier is increased performance risk for third-party DR providers. In the summer of 2025, average performance for demand response was 67% of UCAP. The target is 100%. Tests are in some ways more forgiving than grid emergencies:

1. Emergencies can be longer than historic test events that run 2 hours.

2. When there are no events in PJM, aggregators are evaluated exclusively on test results and they have options to retest if they underperform.

Low performance in PJM can result in penalties that erase all capacity revenue up to 1.5X the committed capacity value (Section 8.4A). With 2025 levels of performance and an expectation of more events than was common historically, third-party demand response providers have more exposure to penalties. Voltus and Enel highlight that they don’t pass on penalty payments directly to end customers outside of offsetting other revenues. With revenue shares as low as 9%, for example between Voltus and the Commonwealth of Virginia, third-party aggregators have a strong incentive to manage penalty risk by right sizing nominations for underperforming customers.

Another barrier is that with PJM’s upcoming Reliability Backstop Procurement (RBP), third-party aggregators have an incentive to leave some assets on the side lines for the 2028-2029 because they could get 70% more value (average $555/MW-day compared to the price cap of $325/MW-day for 2028-2029 participation season) for the asset if it can be demonstrated to be net new capacity for 2029-2030 participation season. For commercial battery projects in particular that have any risk of delays of the June 1st participation window, aggregators may be better off being conservative on the project timeline so that they can lock in 15-year stable contracts at a higher price ceiling. The contract duration could be critical for batteries seeking stable, long term contracts for financing. Notably this addresses the short term concern I had for Voltus and Google’s BYOC contract that had a 3-year duration.

What does this mean for the 2029-2030 participation year?

I see the risks I identified largely being addressed for incremental commercial participation. The right sizing on nominations should largely be addressed over the last two years. And the RBP will result in a bump in incremental capacity. In May I was skeptical of Voltus’s CEO’s assessment that RBP could result in 10 GW of VPP procurement. I forecast 2.5-5 GW largely driven by commercial and industrial demand response assets and new commercial storage development. With the new information since May including more details on the timeline and mechanisms for procurement, I haven’t seen a cause for a significant shift.

I had previously written about development cycles easily being 18 months for commercial batteries. This means that batteries being evaluated now could come online by Q1 2028, far ahead of the April or May of 2029 deadline. I see this auction potentially being highly valuable for commercial batteries that could come online with long-term stable prices at the price cap for the RBP.

One lever that I’m following closely especially in states like New Jersey and Illinois is simplified enrollment pathways to enable residential customer participation. As an example for a single aggregator in one utility in PJM: if 75% of Voltus’s 20,000 interested customers in ComEd with an average nomination of .7 kw per home in the summer could participate, it would result in 10 MW for next year. There are 3 aggregators (Renew Home, Leap and Voltus) and 19 utilities in PJM where similar sized customer populations could try to enroll. This could unlock up to an additional 500 MW beyond my current forecast.

If this growth does take off in 2029-2030, the contrast between utility-led VPPs and wholesale markets is not that one is antifragile and one is not. Rather wholesale market participation is resulting in slower feedback loops than utility programs. If this is true across wholesale markets, utility-led VPPs could grow faster than VPPs in wholesale markets.

What Did I Miss — or Get Wrong?

Spot a story that should have been in this week’s issue? Disagree with the way I’m interpreting the facts? Just comment in notes with a link to the story or your take.

Opinions are my own and not the views of my employer. Research and drafting for this issue was produced with the assistance of Claude AI. Special thanks to Michael Schweitzer for feedback on PJM’s market dynamics. All editorial decisions are mine.

The three interrelated questions I see across these podcasts are:

1. What will be the tailwinds for VPP growth over the next three years?

2. What are the headwinds to VPP growth today?

3. How are utilities, aggregators and data center developers and operators working together to enable this market?

If you want this as a playlist, here’s the Spotify playlist. I included links to each episode on both Apple Podcasts or YouTube and Spotify.

1. Ryan Hledik — USEA Power Sector Podcast (April 2026)

Podcast Overview: If you only have time for one episode to get your bearings on VPPs in 2026, make it this one. Hledik has been tracking the economics of load flexibility longer than most, and his conversation with journalist Herman Trabish covers the full arc: where VPPs started, what’s actually moved the needle on adoption, and why the affordability crisis has changed the calculus for utilities, regulators, and investors.

🎧 Listen here 🎙️ Apple Podcasts

Why? Hledik frames how VPPs fit into the current electricity affordability crisis across the country. He highlights the speed and cost advantages of VPPs. That value proposition is critical for understanding current market drivers. He also highlights headwinds like lack of trust for VPPs as a resource. I agree with his insights on the potential for VPPs to provide meaningful savings compared to traditional alternatives.

2. Caroline Golin — Open Circuit (January 2026) Latitude Media

Podcast Overview: Affordability is the defining energy issue of 2026, and this episode maps the two competing strategies for tackling it: the Trump administration’s blunt-force federal play to reshape PJM capacity markets, and the quieter state-level push in Illinois, Virginia, and New Jersey to use VPPs to flatten peak demand without building more gas. Golin — formerly Google’s global head of energy market development — brings a sharp lens to how bring-your-own-device programs fit into PJM’s supplemental auction and what it actually takes to turn grid constraints into policy leverage.

🎧 Listen here 🎙️ Apple Podcasts

Why? This conversation is for understanding how Bring-Your-Own-Distributed-Capacity fits into addressing grid constraints related to data center buildout and PJM’s supplemental auction. This is the best framework I’ve heard for understanding how hyperscalers think about the opportunities and barriers of working with VPPs to bring data centers online faster. I learned about the gaps aggregators need to address to make VPPs an easy yes for hyperscalers: risk allocation, incremental customer acquisition and contract simplicity.

3. Mark Dyson — Build, Repeat. / A Paces Podcast (March 2026)

Podcast Overview: The best historical context for the current moment I’ve come across. Dyson, Managing Director of Electricity at RMI, reaches back to the 1960–2000 grid build-out — when US utilities grew demand 4–5x while cutting real electricity prices by 20% — to argue that today’s data center surge is a solvable problem, not a crisis. The policy and market design lessons from that era translate directly to the VPP case. His core claim is blunt: VPPs are cheaper than gas peakers or batteries for meeting new peak demand and faster to deploy. He also tackles the hyperscaler flexibility paradox — why data center operators resist curtailment at the project level and how paying others to flex resolves that tension.

🎧 Listen here 🎙️ Apple Podcasts

Why? VPPs often get touted as a new technology. Demand response started with the 1973 oil embargo. Understanding the historical context is critical to understanding this moment in the electricity market and lessons we can take from prior demand booms.

4. Kerri Carnes — The Grid Mod Pod / AEIC (March 2026)

Podcast Overview: Carnes, Director of Customer Solutions at Arizona Public Service, tells the story of how APS built trust — with customers, with operations teams, and with regulators — for a 165 MW VPP combining smart thermostats, behavioral demand response, C&I DR, and batteries. This isn’t a pitch; it’s a post-mortem on what actually worked and what didn’t. With APS projecting significant peak demand growth over the next five years, hearing how a utility leader thinks about program design, customer economics, and operational credibility is essential.

🎧 Listen here 🎙️ YouTube

Why? Hearing how a utility leader is thinking about the value and needs for these programs in their territory is critical for understanding the future of VPPs. LBNL estimates that 60% of VPP programs are led by utilities.

5. Seth Frader-Thompson — Volts (January 2026)

Podcast Overview: Frader-Thompson, CEO of EnergyHub, lays out a maturity framework for VPPs — walking through exactly what it takes for a distributed fleet to move from “enhanced demand response” to something a utility control room operator genuinely cannot distinguish from a conventional peaker. The episode covers dispatch predictability, event performance, telemetry requirements, and the operational trust-building that has to happen before utilities will lean on VPPs the same way they lean on gas turbines.

🎧 Listen here 🎙️ Apple Podcasts

Why? EnergyHub put forward a framework on when VPPs would be able to directly replace a peaker plant in a control room and a utility operator wouldn’t be able to tell the operational difference. This is a great primer on thinking about where VPP operations are going within utility-led VPPs. I valued this for thinking about when VPPs will reach parity with traditional power plants, and their potential to eventually provide value beyond traditional power plants.

6. Varun Sivaram — Catalyst with Shayle Kann (April 2026)

Podcast Overview: The conversation that cuts through the data center flexibility hype. Sivaram, CEO of Emerald AI, returns to Catalyst to explain the mechanics of what actually makes a data center grid-interactive — breaking down temporal, spatial, and resource-based flexibility, the emerging “Watt-Bit spread” that makes power flexibility economically rational for hyperscalers, and why Emerald’s partnership with NVIDIA is the first real test of a 96 MW truly power-flexible AI factory. The episode also surfaces the harder coordination problem: aligning utilities, cloud providers, and grid operators around a common dispatch architecture.

🎧 Listen here 🎙️ Apple Podcasts

Why? Thinking through the economics and capabilities for data center flexibility is complex and there is a lot of hype. This conversation outlines the value to data center operators and the entities that need to be coordinated to make data center flexibility a reality. Google already has 1 GW of flexibility and there are pathways where data centers’ flexibility may come to the grid outside of utility or market constructs (May 18th Brief). I see data center flexibility as a large risk and opportunity: it could be a boon for VPPs or uncompensated capacity that decreases the value of VPPs. If data center developers and operators are pushed into interruptible tariffs and emergency load-drop requirements, grid flexibility could be enabled without participating in markets and cannibalize the value for VPPs.

7. Bruce Nordman — Volts (May 2026)

Podcast overview: Veteran research scientist Bruce Nordman argues that dynamic, time- and location-specific retail prices — sent directly to consumer devices — are a better coordination mechanism than VPP aggregators for most use cases. No middleman, more value captured by customers, cleaner market signals. It’s the strongest version of the “prices over programs” argument you’ll hear, and worth sitting with even if you disagree. The practical limits of price responsiveness at current device penetration levels are real, but the long-run question Nordman is raising — how we coordinate billions of connected devices across a home — is one the industry will have to answer.

🎧 Listen here 🎙️ Apple Podcasts

Why? There are regular debates about the value of dynamic rates in addition to VPPs for creating grid flexibility. This is one of the most thoughtful articulations of the argument I’ve heard. I don’t agree about this, at least in the short term, because of the limits of flexible assets in most customers’ homes and businesses. And I think price’s ability to shape load scalably will be critical for billions of devices to coordinate within homes and businesses. This is important for the industry and markets to consider for a 5-10 year time horizon.

💬 My Take

Listening to all of these podcasts I want to synthesize the top three tailwinds and headwinds for the industry:

1. What will be the tailwinds for VPP growth over the next three years?

   1. Affordability is forcing the issue. Ryan Hledik’s Brattle Group study found VPPs run 40-60% cheaper than gas plants or batteries for the same peaking capacity. This has regulators and governors looking for this as a tool to help mitigate rate increases.

   2. Speed to power is VPPs’ edge for data centers. Mark Dyson highlighted that VPPs deploy in months, not years, and get procured incrementally as load shows up — no billion dollar check on day one.

   3. Extreme weather increases VPPs’ value. Kerri Carnes walked through how Arizona Public Service built and now runs a 165 MW VPP to respond to extreme weather events in APS’s territory. And the success they are experiencing is pushing APS to grow this portfolio. In utility programs this is a virtuous cycle that leads to VPPs’ value increasing after extremes and setting up growth in the process. This characteristic of growing with increased volatility strongly reminds me of Nassim Nicholas Taleb’s concept of an antifragile system.

2. What are the headwinds to VPP growth today?

   1. Flexibility may cannibalize VPP revenues. Some of the ways markets are speeding up data center interconnection is with flexibility requirements that aren’t market integrated (more here). Data centers could be a source of VPP growth and a threat to future revenues.

   2. Capacity accreditation and trust. VPPs are still building the credibility for grid operators who are used to working with traditional generation. EnergyHub’s framework and Hledik’s blockers highlight how the industry is building that over time. How reliably VPPs show up also impacts contracting with data center developers. VPP providers need to get comfortable owning the risk for non-response.

   3. Variable prices scale. TOU rates and other tariffs could scalably coordinate DERs without any VPP required. And they could result in higher conversion rates than we’ve generally seen in VPP programs. We already see early signs of this with how dynamic pricing tariffs for residential EV customers and coincident peak management for commercial customers can create limited value for both customers to participate in VPPs.

In the last year, I see the VPP industry over-emphasizing the impact of data centers on the VPP market and under-emphasizing the increasing value from extreme weather. I think the reality is VPPs as an asset class are cheap, fast to deploy and antifragile. This is a more holistic value proposition for VPPs across applications on the grid.

What Did I Miss — or Get Wrong?

Disagree with the way I’m interpreting the facts? Just comment in notes with a link to the story or your take.

Opinions are my own and not the views of my employer. Research and drafting for this issue was produced with the assistance of Claude AI. All editorial decisions are mine.

1. Tesla’s New England lease model shows VPP revenue can make storage hardware cheaper up front instead of just paying back over time — a pitch every storage competitor will now have to answer.

2. Sunrun, Tesla, and Renew Home just showed residential VPPs can put gigawatt-scale capacity behind data center load without new hardware, new interconnection, or new generation.

3. FERC and Texas regulators are both steering large loads toward curtailment-based interconnection instead of new generation — a tacit endorsement of demand flexibility as grid infrastructure.

News Roundup

Regulatory & FERC · 🟢 Bullish

FERC Issues Show-Cause Orders to All Six RTOs/ISOs on Large-Load Interconnection 📅 Published: 06/18/2026

• FERC issued Section 206 show-cause orders to PJM, MISO, SPP, CAISO, ISO-NE, NYISO, and their transmission owners, giving them 60 days to justify or revise large-load interconnection tariffs and 30 days to file resource-adequacy reports. Co-location and behind-the-meter generation are explicitly named among the five reform categories. That puts DER aggregators with data-center-adjacent flexibility plays directly in the rulemaking conversation as DOE’s RM26-4 ANOPR advances in parallel.

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Grid Reliability · 🟢 Bullish

IESO Summer 2026 Reliability Outlook: Peak Perks Tops 320,000 Participants, Commercial “Peak Performance” DR Program Debuts 📅 Published: 06/19/2026

• IESO’s seasonal reliability outlook reports Save on Energy Peak Perks, Canada’s largest residential VPP, has passed 320,000 participants and now delivers 200+ MW of demand reduction. A new commercial “Peak Performance” demand-response program is also launching this summer, while the existing Industrial Conservation Initiative (ICI) — which lets large industrial and commercial customers cut their Global Adjustment charges by shedding load during the province’s five annual coincident peaks — is expected to deliver roughly 1,500 MW this season. The backdrop is a system peak that could approach 26,000 MW under extreme weather, with battery storage now at 17 projects and 1,050+ MW — triple last summer’s fleet.

Product Announcements · 🟢 Bullish

Tesla Launches Discounted Powerwall Leases Tied to Mandatory VPP Enrollment in New England 📅 Published: 06/18/2026

• Tesla is piloting Powerwall leases in Massachusetts and Connecticut that cost $30–$60 less per month — close to half off a standard lease — in exchange for mandatory enrollment in Tesla-controlled VPP dispatch. The structure inverts the usual model: VPP revenue now subsidizes the lease price instead of arriving as a bonus after the sale. If the pilot holds up, it gives Tesla a sharper customer-acquisition edge over storage competitors still selling VPP enrollment as an add-on.

Partnerships · 🟢 Bullish

Tesla, Sunrun, and Renew Home unveil 16.8 GW VPP framework for data centers 📅 Published: 06/24/2026

• The three companies are aggregating home batteries from Sunrun and Tesla with more than 8 million smart thermostats and devices from Renew Home into what they’re calling the largest VPP in the country. 300 MW is available now in Virginia, with a path to 500 MW by 2030, using existing residential infrastructure — no new hardware, interconnection, water, or land required. This is the clearest signal yet that aggregators see hyperscaler load as a bigger near-term revenue opportunity than utility programs.

Utility Programs · 🟢 Bullish

FranklinWH + Ava Community Energy Launch $6,000 VPP Incentive for Income-Qualified Bay Area Homeowners 📅 Published: 06/16/2026

• Ava Community Energy, a CCA serving 2M+ households in Alameda and San Joaquin counties, is offering CARE/FERA-qualified homeowners up to $6,000 upfront plus roughly $36/month to enroll a FranklinWH battery in its VPP — more than five times the roughly $1,080 available to market-rate customers. Homeowners can choose to share 40%, 60%, or 80% of battery capacity with the grid. It’s a notable design choice: most VPP incentive programs still skew toward customers who can already afford storage without a subsidy.

Partnerships · 🟢 Bullish

Rivian Joins ChargeScape for Managed EV Charging 📅 Published: 06/16/2026

• Rivian has joined ChargeScape, the automaker-backed managed-charging platform that already includes Tesla, Ford, BMW, Honda, Nissan, and Stellantis. Utilities can now shift Rivian owners’ charging off-peak directly through the Rivian app, with no separate program enrollment required. The move adds another ~large EV fleet to ChargeScape’s addressable base as utilities lean on managed charging to absorb data-center-driven load growth.

Regulatory & FERC · 🟡 Neutral

Texas, facing 438 GW queue, approves initial large-load interconnection process 📅 Published: 06/22/2026

• The PUCT approved ERCOT’s “Batch Zero” framework, which studies large-load interconnection requests in groups rather than sequentially. The tradeoff: customers who accept curtailment during transmission constraints get a faster path to connect. It’s not a VPP program, but it normalizes the same curtailment-for-access logic aggregators have been selling utilities for years — now applied directly to data centers.

Research & Reports · 🟢 Bullish

GETs, demand response can ease near-term data center electricity price pressure: report 📅 Published: 06/23/2026

• New research finds grid-enhancing technologies and demand response can blunt the near-term price impact of data center load growth faster than new generation can come online. It’s a useful data point for any utility making the case for DR/VPP spend over a new peaker plant in front of a rate case.

Research & Reports · 🟡 Neutral

Wood Mackenzie releases Q2 2026 US Energy Storage Monitor 📅 Published: Wed, Jun 24, 2026

• Wood Mackenzie and the American Clean Power Association released the Q2 2026 edition of their quarterly US Energy Storage Monitor, covering deployments, pricing, and policy across front-of-meter and behind-the-meter markets. Wood Mackenzie estimates that 28 GW cumulative residential energy storage will be installed by 2031.

Utility Programs · 🟢 Bullish

Platte River, EnergyHub partner to deploy 39-MW Colorado VPP 📅 Published: 06/24/2026

• Platte River Power Authority is partnering with EnergyHub on a 39-MW residential VPP deployment in Colorado — incremental, but another Western utility moving from pilot to live program this year.

📊 By the Numbers

• 320,000+ — residential and small-business participants now enrolled in Ontario’s Peak Perks, Canada’s largest residential VPP.

• 1,500 MW — expected demand reduction from Ontario’s new commercial “Peak Performance” DR program launching this summer.

• 60 days — window FERC gave all six RTOs/ISOs to justify or revise large-load interconnection tariffs.

• $6,000 — upfront incentive available to income-qualified Bay Area homeowners enrolling a FranklinWH battery with Ava Community Energy.

• 16.8 GW — combined dispatchable capacity Sunrun, Tesla, and Renew Home say they can offer utilities and data centers.

• 438 GW — size of ERCOT’s large-load interconnection queue, ~89% of it data centers.

• 39 MW — size of Platte River’s new residential VPP deployment with EnergyHub in Colorado.

🗓️ On the Radar

• July 18, 2026 — Deadline for RTOs/ISOs to file 30-day resource-adequacy reports under FERC’s large-load show-cause order.

• August 17, 2026 — Deadline for RTOs/ISOs and transmission owners to file compliance responses to FERC’s Section 206 large-load tariff order.

• August 2026 — ERCOT expected to notify “Batch Zero” applicants of their large-load project classification.

💬 My Take

Over the last two weeks, announcements by Tesla, Sunrun, Renew Home and FranklinWH all point to different ways to potentially integrate residential batteries into VPPs. They point to the scale of capacity that could quickly be brought online and how VPPs could enable decreased costs for residential customers to access batteries. I see us going from a world where about one third to 45% of residential batteries are participating in VPPs today to a future where VPPs are the default option for low cost lease payments and over 60% of new customers purchasing with a lease are participating.

The size of residential storage and VPPs

According to Ohm Analytics, residential batteries have grown from 870 MW of cumulative residential battery nameplate capacity enrolled in VPPs in 2024 to 2,200 MW of cumulative nameplate capacity in 2025. This growth was driven by Puerto Rico’s CBES program and California’s Demand Side Grid Support (DSGS). Ohm Analytics also estimates that 45% of deployed batteries are integrated into VPPs. That implies total deployed battery capacity according to Ohm Analytics is 4,888 MW by the end of 2025.

I wanted to compare that with other sources like the recently announced Wood Mackenzie Energy Storage Monitor because they have been tracking the residential storage market longer than Ohm Analytics. Wood Mackenzie’s public data shows there was 5.8 GW of residential storage installed between 2021 and 2025 alone (2021, 2022-2023,2024-2025). Looking at residential storage installed data prior to 2021, I estimate approximately an additional .5 GW of residential capacity was installed assuming an average 2-hour duration system. If there are approximately 6.3 GW of installed residential storage as of 2025, approximately one third was participating in VPPs.

With Tesla and other companies’ recent announcements to integrate VPP revenues into decreased lease payments, I see the potential for doubling this historic VPP-participation rate.

When VPPs made residential storage about the price of two phone lines

On June 18th, Tesla announced that they would bundle VPP participation in Connecticut’s ESS program and ConnectedSolutions (CS) that would result in up to 29% savings in CS and 49% in CT ESS monthly savings. They estimate the savings at $30 per month in ConnectedSolutions and $60 per month savings in CT ESS. If I assume that the high end monthly savings percent aligns with the month savings amount, I estimate that you could get a powerwall for around $70 per month ($30/.29-$30) when you sign up for their VPP in ConnectedSolutions and around $60 per month ($60/.49-$60) in CT ESS. Tesla’s announcement isn’t the first to do this.

The idea was pioneered by Swell. While they were not able to make the economics and scale work at the time, the concept of decreasing the cost of a battery by enabling VPP participation was initially iterated on in utility programs like Green Mountain Power in Vermont starting in 2017. The utility now offers a lease of $55 per month. Liberty Utility offers a $50 per two battery lease in New Hampshire.

In Texas, a number of retailers have partnered or integrated batteries at no or low cost. In January 2025, Sonnen and Solrite developed a $0 offering for residential storage in Texas. Base Power’s REP offering in Texas is premised on a similar framework where a customer pays $19-29 per month for a battery and a lower cost for electricity. Octopus Energy and Lunar Energy’s PowerStore Partnership announced in April 2026 is also premised on a $45/month lease payment and 8 cents/kwh. These are not all apples-to-apples comparisons with nuances on the reserve capacity available to the homeowner and associated retail rates. However, they point to a future where batteries in large parts of the country are under $75 per month and by default would be enrolled in a VPP.

Why this matters for the future of residential storage VPPs

Storage leases are becoming more important because third party owners can still access the investment tax credit for batteries. In Sunrun’s Q1 2026 investor presentation they highlight that prior to the loss of the ITC, Third-Party-Owned (TPO) solar systems were 50% of the market according to Wood Mackenzie. I am assuming this is a reasonable proxy for the share of storage systems that are leased prior to the ITC expiring for loan and cash payments. If lease providers can find ways to cut the cost of a lease payment with VPP revenue streams, it decreases the cost of energy storage while simultaneously increasing VPP participation rates above the one third of battery storage participating in the US today.

Tesla, Sunrun and Renew Home’s new capacity discovery tool is an indication of what could be possible. While the full portfolio is 16.8 GW, the storage nameplate capacity from Sunrun and Tesla in the VPP capacity explorer tool is 7.8 GW. This is 1.5 GWs above Wood Mackenzie’s market size from just two companies. Tesla and Sunrun are clear that not all of that capacity is deployed today, but could be deployed in “months, not years.” If these companies can work with partners to get long term contracts for capacity, those predictable revenues could unlock residential storage lease discounts and increase adoption for VPPs and energy storage.

The scale of growth potential is also supported by a recent Brattle report on Operationalizing and Quantifying the Demand Stack. Brattle noted with data from Uplight that just moving enrollment to the point of sale would increase conversion rates from 5-10% to 40%-75% without changing anything around incentives. If you layer in improved incentives, they estimate being able to get incremental participation. I think a 60% participation rate for new customers is feasible because the incentives associated with enrolling can be north of 50% of the lease payment. And if this can be paired with Bring-your-own-capacity style contract, additional regions beyond New England and Texas could be unlocked with longer term market pricing.

Wood Mackenzie forecast in the recent Energy Storage Monitor that there will be 21 GW of incremental residential storage capacity above 2025 capacity (14% of ~150 GW of incremental capacity). If these offerings were available nationwide and lease financing held at ~50% of systems, a 60% participation rate for new systems would add ~6 GW of incremental residential storage VPP capacity by 2031, nearly 3X the cumulative residential storage VPP capacity in 2025.

What Did I Miss — or Get Wrong?

Spot a story that should have been in this week’s issue? Disagree with the way I’m interpreting the facts? Just comment in notes with a link to the story or your take.

Opinions are my own and not the views of my employer. Research and drafting for this issue was produced with the assistance of Claude AI. All editorial decisions are mine.

1. Voltus is assembling a fully integrated battery deployment stack in PJM — AI-powered site assessment, a deep storage leadership bench, and a Google-anchored BYOC contract all landed within two weeks of each other.

2. Permissionless plug-in storage is graduating from concept to commercial reality, with David Energy proving the interconnection-free path can aggregate at scale in one of the country’s most constrained grid markets.

3. Virginia’s 450-MW state-mandated VPP filing shows Dominion’s initial approach across EV chargers, on-site batteries and smart thermostats.

NEWS ROUNDUP

M&A · 🟢 Bullish

Voltus Acquires Brightfield AI to Accelerate Energy Storage Deployment

📅 Published: June 10, 2026

• Voltus acquired Brightfield AI, a platform that compresses commercial battery site assessment from 6–8 weeks to minutes. The deal brings Brightfield CEO Tim Hade in as SVP Battery Division and Larsh Johnson as CTO — and focuses Voltus’s storage buildout squarely on PJM, where its 100-MW BYOC contract with Google needs behind-the-meter capacity to fill. C&I buildings represent 60% of US electricity consumption but less than 1% of deployed BESS capacity; Voltus is betting speed-to-site is the unlock.

Product Announcements · 🟢 Bullish

New York is becoming a plug-in battery test-bed

📅 Published: June 11, 2026

• David Energy has installed 120V plug-in batteries at 500+ NYC small businesses using EcoFlow hardware, with 2,000 more sites earmarked — no interconnection queue, no utility permission required. The model runs as a full-stack retail VPP, sidestepping ConEd’s interconnection freeze entirely. Northeast and New England expansion is planned for later in 2026, making this the most direct test yet of whether permissionless storage can aggregate to grid-relevant scale.

Utility Programs · 🟢 Bullish

‘Virtual power plants’ will launch soon in Virginia. Here’s what that means.

📅 Published: June 12, 2026

• Dominion Energy filed a proposed 450-MW VPP pilot with the Virginia SCC, mandated by the state’s 2025 Community Energy Act, covering ~11 programs including EV chargers, on-site batteries, and smart thermostats. SCC approval is expected this summer, with customer enrollment beginning later in 2026 and the pilot running through July 2028. Clean energy advocates at the SCC hearing pushed for expanded residential battery programs and higher customer compensation — the filing may see material changes before final approval.

Utility RFP & Procurement · 🟢 Bullish

CPower Awarded Contract as Demand Response Provider for the State of New Jersey

📅 Published: June 10, 2026

• CPower signed a new agreement with New Jersey’s Division of Property Management & Construction to enroll state government facilities in PJM demand response and energy flexibility programs at no cost to participants. Facilities earn revenue by curtailing lighting, HVAC, and IT loads during grid-stress events, or by dispatching on-site generators and batteries — adding a state-government procurement channel to CPower’s commercial VPP book.

📊 BY THE NUMBERS

450 MW — capacity targeted by Dominion Energy’s state-mandated VPP pilot in Virginia

60% vs. <1% — C&I buildings’ share of US electricity consumption versus their share of deployed BESS capacity, the gap Voltus/Brightfield AI is targeting

500+ — plug-in batteries already deployed by David Energy at NYC small businesses, with 2,000 more earmarked

🗓️ ON THE RADAR

Summer 2026 — Virginia SCC expected to rule on Dominion’s 450-MW VPP pilot filing

June 15, 2026 — California legislature’s deadline to pass the 2026–27 budget; outcome determines continued DSGS funding (the nation’s largest VPP program)

June 30, 2026 — Illinois ICC deadline to establish a scheduled-dispatch VPP program under the Clean and Reliable Grid Affordability Act

October 14-15, 2026 — Latitude Media is hosting Flex Summit in Austin looking at the VPP market and grid flexibility.

💬 MY TAKE

This week there were two different stories about new approaches in the commercial storage market to unlock VPP capacity. David Energy has aggregated 500 permissionless batteries across 250 sites with a pitch to lower bills compared to ConEd. And Voltus acquired Brightfield AI to speed up commercial storage deployment. Both have a similar argument: different parts of the commercial market have not been effectively served by batteries yet and there are large markets that could be unlocked with different business models. VPP revenue is a critical component.

I wanted to orient myself on how big the commercial and industrial energy storage market is today and then assess the potential of these opportunities in that context. My take is that commercial energy storage is really two separate markets: data centers and everything else. Both of these announcements focus on opportunities outside of data centers - small plug in batteries and a faster automated proposal tool for those without batteries. Synthesizing recent market research and the reasoning behind each of these announcements, I see commercial storage out of data centers will drive less than 500 MWs of VPP capacity annually in the next two years.

How big is the US behind-the-meter C&I storage market?

According to Wood Mackenzie and American Clean Power in the Q1 2026 Energy Storage Monitor, the community-scale, commercial and industrial (CCI) market for energy storage was 191 MWs in 2025. I should note that not all of this capacity is behind the meter because community storage in Massachusetts and Illinois can be in front of the meter. The team at Wood Mackenzie forecast a slight decrease in capacity in 2026 driven by Illinois community storage projects having delays to their commercial operation date. The primary markets today are California, Massachusetts and New York with Connecticut and New Mexico representing promising new markets. By 2030 they forecast 39% growth in the CCI energy storage market to 265 MW annually. In short they don’t forecast a meaningful growth over the next 5 years when compared to the size of the current residential market (deployed 2.7 GW in 2025) or utility-scale storage (16 GW in 2025).

By contrast, SEIA and Benchmark forecast in the Q2 2026 Energy Storage Market Outlook that there will be 3.97 GW/8.1GWh of C&I storage installed between 2024 and 2026 that are not associated with uninterruptible power supply (UPS) systems. Assuming a similar 2-hour average duration system, I estimate approximately 1.3 GWs of C&I capacity was installed behind the meter at C&I sites in 2025 based on the 2.617 GWh of C&I storage announced in 2025. According to the report, much of that is driven by the large storage projects announced at various data centers. One example of these kinds of projects is a 2 GW expected to come online from Energy Vault across multiple data center campuses.

These are wildly different numbers. My interpretation is that Benchmark counts data-center-adjacent BTM C&I storage that WoodMac’s CCI segment doesn’t. The Wood Mackenzie report represents the behind the meter storage capacity that is not associated with data centers or UPS systems. For small plug-in storage and Brightfield’s faster proposal software, I interpret them both going after the same under-served C&I opportunity Woodmac estimated at 191 MW in 2025. As Voltus pointed out in their press release, given the size of commercial energy consumption, this is a tiny fraction of the possible market. David Energy and Voltus are tackling this opportunity from two different angles.

Are small C&I batteries a big deal?

David Energy is on pace to installing 2,000 permissionless energy storage systems this year. In New York where they launched, I see a confluence of factors that make small commercial batteries appealing:

1. Installation friction: In New York there are key components for installation friction of a larger commercial battery. There is limited space for larger batteries that can potentially win on price per kwh, there is significant friction to get the certificates to get larger systems installed by licensed engineers, and interconnection queue delays.

2. Monetization: There is a pathway to monetize these smaller systems through demand charge management, retail-supply arbitrage and VPP revenue in ConEd.

3. Avoiding tenant/landlord conflicts: There are many commercial customers that do not own their buildings and cannot easily sign a long term energy storage lease agreement. Permissionless storage avoids the conflict between the incentives of the tenant and the incentives of the landlord. Every Electric is implementing a similar strategy for permissionless storage in New York apartments for a similar reason, though likely with a lower economic value proposition.

In the near term, I wonder how many other entities can take advantage of operational requirements and full stack integration for monetization of these assets in New York City or other markets. With 2,000 systems at 1.2-1.4 kw per system, this could be 2.4-2.8 MWs of capacity added for David Energy. David Energy already flagged they are seeing barriers to the supply chain just with their first 2,000 installs. Let’s say another 5 companies can get to David Energy’s scale by the end of 2027 like retailers in Texas or a VPP aggregator with small end customers like Enersponse. This would result in a total installed capacity of 10-15 MWs of permissionless commercial storage. The fundamentals of speed and avoiding conflicts between the tenant and landlord make me think this could be impactful for commercial storage by 2028 if other REPs or aggregators copy David Energy’s approach. In my most bullish scenario, supply chains are not constrained on these smaller batteries, the business model is replicable by many entities across major deregulated markets, and commercial customers that can’t install traditional storage clamor for this and installations 10X this could be close to 100 MWs of incremental capacity annually that Woodmac currently doesn’t forecast.

The monetization strategy and tenant/landlord conflicts could have much broader applications for David and other REPs that are vertically integrated across deregulated markets. Where there is lower installation friction than New York City, I question if a company like Base Power wouldn’t be able to offer higher value for resilience and savings at a lower cost with the same vertical integration. I see a limit for the total market size of small batteries when larger systems can easily be installed.

Does removing friction for storage proposals unlock Voltus’s battery business?

Looking at larger battery storage systems, Voltus made a bet acquiring Brightfield.ai. Looking across the press release and news outlets, they outlined three related components of their strategy:

1. Brightfield’s software unlocks automated initial proposals with access to interval data.

2. Voltus has existing relationships with over 13,000 sites as of 2024 with access to this data and tariff information.

3. Voltus’s BYOC contract in PJM provides fixed pricing to help the economics. Latitude Media described the last point this way: “BYOC provides a long-term fixed price signal for projects, while leveraging Brightfield’s tools are designed to bring down soft costs and accelerate timelines so that more of those projects can be built quickly.”

Brightfield was a 1-year old company with four industry veterans focused on a detailed problem they understood. I believe they could have developed a better initial proposal tool. The challenge for them before acquisition is they would need to access sites either one by one or through their channel partners. Voltus solves this problem with access to their full suite of customers’ existing interval and tariff data. This alignment I find compelling for starting conversations with existing customers.

I doubt 1-year of development even with Stem’s former CTO results in a defensible moat for this kind of software. I would expect companies like Stem, Energy Toolbase and other software companies to also fairly quickly be able to spin up a similar tool to automatically generate these kinds of reports for retailers and aggregators’ customers. This decrease in soft costs by saving 6-8 weeks on proposals paired with existing customer relationships could speed up new commercial storage projects.

Where I am skeptical is if Brightfield’s software will bring meaningful capacity to the BYOC contract in PJM. Others have written about the term mismatch between a 3-year fixed price of the BYOC contract versus the 15-20 year underwriting for a residential or commercial storage system. I would add that supply chain constraints especially for distribution switchgear that Wood Mackenzie estimates at over 10 months lead times could easily lead to an 18 month development cycle. While a battery could come online in 2028 for a conversation that starts in 2026, the 6-8 weeks of an initial contract are not the barrier to transformative speed of installation. I am also skeptical that Google’s BYOC pricing is so much better than market rates that it could underwrite the remaining 13-18 years of the battery.

Ultimately, because of the supply constraints that are not impacted by the proposal software, I’m skeptical that this software capability results in more than 100 MW annually of new installation in 2028 for Voltus. Still, unlocking merchant BTM C&I storage in PJM would be a meaningful incremental market driver compared to Woodmac’s base scenario. Looking at both of these bets together, I can see a world where both can result in a step change for the non-data center commercial storage market by adding an incremental 200 MW to a market already poised to get to over 200 MW annually. Simultaneously ~400 MWs annually is small compared to the annual growth of the US VPP market (4.5 GW annually) or residential storage market (2.7 GW annually).

WHAT DID I MISS — OR GET WRONG?

Spot a story that should have been in this week’s issue? Disagree with the way I’m interpreting the facts? Just comment in notes with a link to the story or your take.

Opinions are my own and not the views of my employer. Research and drafting for this issue was produced with the assistance of Claude AI. All editorial decisions are mine.

1. Hyperscalers now have a contract structure for directly funding demand-side capacity: Voltus’s Google deal is the first proof point in PJM.

2. Billions spent on smart meters won’t unlock gigawatts of stranded residential and small commercial VPP capacity as long as PJM utilities block aggregators from accessing the data.

3. The biggest lever for VPP growth in a representative SPP utility isn’t technology. It’s friction reduction: a Brattle/Uplight report found enrollment and marketing improvements drive 59% of all incremental capacity potential.

News Roundup

Partnerships · 🟢

Voltus and Google to Deliver Grid Capacity Through Bring Your Own Capacity Agreement 📅 Published: June 2, 2026

• Google has signed a three-year BYOC deal with Voltus to aggregate up to 100 MW of PJM-accredited DERs annually — the first time a hyperscaler has directly funded a VPP. Voltus absorbs the accreditation risk and delivers capacity via a contract structured like a standard PPA, which Google said was the commercial prerequisite no other aggregator could meet. The VPP goes live in 2027 and is designed as a replicable blueprint for other large-load customers facing the same capacity gap.

Utility Programs · 🟢

Massachusetts ‘vehicle-to-everything’ demonstration hints at EV batteries’ grid potential 📅 Published: June 2, 2026

• MassCEC has begun deploying free bidirectional chargers to 4 municipal entities, 5 school districts, and 45+ residents under a two-year V2X demonstration — eligible vehicles include the F-150 Lightning, Kia EV9, and five e-bus models. Enrolled light-duty EVs can earn roughly $3,000 per summer via the ConnectedSolutions VPP; electric school buses can clear $12,000 annually. The school bus use case is already described as making “economic sense,” which makes fleet electrification and grid services planning decisions increasingly inseparable.

Research & Reports · 🟢

Customer experience, better modeling can boost demand-side portfolio: report 📅 Published: June 3, 2026

• A new Brattle Group report commissioned by Uplight finds that stacking demand response, energy efficiency, and time-of-use rates can unlock 89 MW of additional demand-side capacity by 2030 for a representative SPP utility — moving from 3% to 5% of total system load. Enrollment-focused strategies alone (one-click enrollment, personalized outreach) account for 53 of those 89 MW. Brattle says the framework is directly portable to other RTOs, including regions with high data center load growth.

Regulatory & FERC · 🔴

Utilities aren’t sharing smart meter data in PJM. That’s a problem. 📅 Published: June 4, 2026

• A Voltus and Mission:data Coalition complaint to FERC (filed October 2025) alleges utilities across PJM — including Exelon’s ComEd, PSE&G, and Duquesne Light — are blocking aggregators from accessing smart meter data needed to enroll residential and small commercial customers in demand response programs. The practical effect: Voltus had 20,000 customers enrolled at ComEd but could get only 4% through the utility’s data system, losing ~23 MW of capacity. Emily Orvis, Voltus VP of energy markets, says “gigawatts of capacity are stranded” across PJM.

Policy & Legislation · 🟢

As Energy Demand Rises, More States Turn to Virtual Power Plants 📅 Published: June 4, 2026

• Inside Climate News rounds up this year’s most significant state VPP actions: Massachusetts Governor Healey’s March 13 executive order targets 3.5 GW of demand management (including VPPs) by 2035 — nearly 13% of the entire New England grid’s peak demand. Minnesota’s PUC approved Xcel’s CapacityConnect program on May 13, a first-of-its-kind utility-owned distributed battery procurement deploying 200 MW of 1–3 MW neighborhood-scale batteries. NC State’s Autumn Proudlove, who tracks VPP legislation nationally, calls 2026’s pace a “steady uptick.”

Regulatory & FERC · 🟢

Illinois Clean and Reliable Grid Affordability Act VPP tariff deadlines 📅 Effective: June 1, 2026

• Illinois’s CRGA went into effect June 1, requiring ComEd and Ameren to file initial VPP tariffs by June 1 for ICC approval by June 30. The short-term program — scheduled to launch no later than June 30 — compensates participating storage customers at a floor of $10/kW of average dispatch. The long-term program (effective December 31, 2028) expands eligibility to smart thermostats, EV batteries, and other behind-the-meter devices. Note: ComEd had previously withdrawn a proposed VPP tariff in November 2025; the CRGA removes utility discretion on whether to file.

Product Announcements · 🟡

Eve — multi-DER orchestration platform by ev.energy 📅 Published: June 4, 2026

• ev.energy has launched “Eve,” a four-module platform covering the full utility VPP lifecycle: business case modeling (Eve Insight), customer enrollment (Eve Programs), real-time multi-DER dispatch (Eve Sync), and settlement-grade M&V with regulatory reporting (Eve Ops). The platform claims 55+ utility programs in North America and Europe, including Con Edison, Avangrid, and Ameren, with ~95% US EV household reachability via its OEM/EVSE integrations. The “Plan and Defend” positioning — building the business case and the rate case filing on a single stack — addresses the two phases most utility DERMS platforms skip entirely.

📊 By the Numbers

100 MW — Annual DER capacity Voltus will aggregate for Google’s PJM VPP under the three-year BYOC deal.

$12,000 — annual VPP revenue potential for electric school buses enrolled in Massachusetts’ ConnectedSolutions program.

3.5 GW — Massachusetts’ demand management target (including VPPs) by 2035, per Governor Healey’s March 13 executive order.

$100B — estimated consumer savings over the next decade from better grid utilization through solutions like VPPs, per a Brattle Group analysis cited in the Voltus/Google press release.

$6B / 12M meters — what PJM utilities have spent installing smart meters that aggregators say they can’t access to enroll customers in demand response programs.

🗓️ On the Radar

June 30, 2026 — Illinois Commerce Commission deadline to approve initial VPP tariffs filed by ComEd and Ameren under the CRGA. First mandatory utility VPP program in the Midwest.

End of June 2026 — FERC intends to act on the large-load interconnection rulemaking (RM26-4) this month. The rule could define how AI data centers connect to the grid — directly shaping the capacity gap that the Voltus/Google BYOC model is designed to fill.

💬 My Take

In Voltus’s and Google’s BYOC announcement for 100 MW of annual capacity, they said they aim to establish a “repeatable path for other large energy users to follow.” How big could BYOC (sometimes called BYODC) be as a lever for VPP market growth? In context, Woodmac estimates that from 2024 to 2025 VPPs added 4.5 GW of incremental capacity. Assuming similar growth in 2026, this deal alone would be 2% of VPP growth in 2026. For this to be a meaningful growth lever, other organizations need to be able to offer similar kinds of contracts to hyperscalers so that offers can be standardized, driving down contracting costs and making it as simple as a solar PPA. My question is, aside from Voltus, who else in the VPP market can provide this type of contract offer for hyperscalers to create competition in the next year?

In a January 2026 Open Circuit Podcast Caroline Golin, Google’s former Global Head of Energy Market Development & Innovation, explained that when Google was looking for a VPP BYOC offering, only Voltus could provide a contract that Google would consider because they took on two key risks:

1. The aggregator needs to take on capacity accreditation risk. This means if a resource doesn’t qualify for capacity credit in the market, that’s Voltus’s problem, not the data center opperator’s. To evaluate this risk - what entities have the market expertise to take this on?

2. The aggregator takes on being able to do customer acquisition. This execution risk was critical for Google to consider this kind of offering. To evaluate this risk, who has the scale to add a similar size of 100 MWs annually?

In addition to which entities can take on these two risks, I think about where geographic demand is strongest to deploy this contracting structure.

Spoiler: I think this kind offer is going to be largely concentrated in PJM and there are likely 5 companies that have the capabilities to make this offer to Google or other hyperscalers in the next year.

Geography & accreditation risk:

My first gate for thinking about this question is where would this be most valuable in the next 1-3 years. Looking at Datacenter.fyi data center growth is most dramatic in Texas, Virginia, Ohio and Indiana. Most of these are either partially or completely in PJM. PJM’s capacity prices have increased dramatically with this increase in demand.

PJM also is likely for additional BYOC-contracts because of the market mechanism for a VPP provider to take on capacity accreditation risk. In a Sightline write-up of a presentation by Dana Guernsey, CEO of Voltus, one key enabler for this type of offering is market capacity accreditation like what exists in PJM. The accreditation is enabled by being able to assess locational constraints where the VPP would need to be located to offset capacity from a data center.

While Texas has clear demand, there are market barriers that make me skeptical. Texas has already implemented Senate Bill 6 that results in flexibility capacity coming online outside of a capacity market. Texas’s energy-only market also creates a barrier for VPP capacity accreditation. Between both of these, I am skeptical of a BYOC-style contract in Texas in the near term.

While less dramatic than PJM or Texas, parts of MISO and CAISO are also experiencing significant data center growth. They also have capacity accreditation for demand response that could enable experts in those markets to potentially take on similar risks. Each has challenges: CAISO’s bilateral contracting creates significant incremental complexity with a third party data center operator. State-level bans for third party DR in MISO’s territory block large parts of the territory from being commercially viable. I am watching these markets as a second tier for BYOC offerings. To construct a list of top organizations, I’m going to limit the list geographically to PJM.

Customer acquisition & execution risk:

Caroline’s point about customer acquisition raises a second gating item - what companies can add 100 MWs of capacity in PJM annually? There are 56 registered Curtailment Service Providers in PJM. Many of these are utilities and energy retailers that offer some DR. Retailers definitely have the customer relationships to build out this kind of offering and the balance sheet to take on capacity accreditation.

I’d argue retailers, however, would not be able to get comfortable with owning capacity accreditation risk in the time frame needed to sign a contract in the next two years without a partnership or acquisition to enable the type of DR capabilities Voltus has developed. There are three companies I’m watching from traditional retailers.

NRG acquired CPower and partnered with Renew Home in Texas to stand up a 1 GW VPP. They mentioned wanting to spin up a similar VPP in PJM. I think the combined CPower/NRG could put forward a compelling offering.

Constellation partners with GridBeyond in PJM, and they are targeting 1 GW of VPP capacity within 2 years. While they split out Nuclear and non-Nuclear capacity in their 8-k filings, they have no specific line item for total DR capacity. This indicates to me that their DR capacity is not meaningful enough today to put into regulatory filings. Given their lack of transparency on their current portfolio, I’d exclude them from the current list.

Shell’s MP2 has 575 MWs of dispatchable C&I load between PJM and ERCOT. Shell acquired Next Kraftwerke in 2021 and operates 15.5 GWs in Europe. However, Shell Energy and Next Kraftwerke haven’t announced any collaboration and Next Kraftwerke hasn’t highlighted any opportunities in North America. I would exclude MP2 because I think they lack the technical capabilities to be comfortable with taking on capacity accreditation risk.

The companies on this list that are aggregators with capacity can take on accreditation risk and have the scale to add this volume of capacity: Voltus, Enel, Renew Home (formerly OhmConnect) and Leap. Enel has retail relationships, is experienced enabling VPPs across the US at scale and has capabilities in house from their legacy EnerNOC acquisition to manage accreditation risk. I would expect Renew Home to explore a similar partnership for this kind of work in PJM given their prior partnership in TX and existing utility relationships through Rush Hour Rewards.

I should disclose I work at Leap, so weigh this section accordingly. That said: Leap’s partner ecosystem allows them to unlock capacity from other OEMs, aggregators and financiers. As a result they have doubled capacity year-over-year from 2024 to 2025. They also had a webinar in March, outlining the different monetization pathways for data centers they are pursuing.

Looking through press releases, this is a view on the size of each of these organizations’ existing capacity:

For BYOC to unlock meaningful VPP capacity, we need a competitive market for this offering. I’m optimistic that by the end of 2027 there will be at least 2 addional public BYOC contracts with entities on this list. If that happens, BYOC could start to drive VPP growth upward. If it doesn’t, I’m skeptical BYOC contracts will be meaningful to data center build out or the VPP market.

What Did I Miss — or Get Wrong?

Spot a story that should have been in this week’s issue? Disagree with the way I’m interpreting the facts? Just comment in notes with a link to the story or your take.

Opinions are my own and not the views of my employer. Research and drafting for this issue was produced with the assistance of Claude AI. All editorial decisions are mine.

1. Background VPPs represent the clearest near-term path to residential scale: EnergyHub, ecobee, and Renew Home are converging on a model that captures capacity from users who gave access to optimize their thermostat load. Renew Home and ecobee estimate 6.8 GW available from existing opt-in customers — roughly 18% growth on top of WoodMac’s 37.5 GW 2025 baseline.

2. Record Q1 battery storage deployments — 9.7 GWh, up 32% YoY — confirm the physical resource base VPPs depend on is scaling with 1.1 GWh being the meter between commercial and residential sites.

3. Shatterdome’s quant-trading founding thesis — autonomously dispatching aggregated DERs into ancillary markets — is a differentiated bet on ancillary services volatility over raw MW competition, and it’s consistent with where margin is actually available in deregulated markets today.

News Roundup

Research & Reports · 🟢 Bullish

US Installed Record 9.7 GWh of Battery Storage in Q1 2026, Up 32% YoY: SEIA 📅 Published: May 21, 2026

• SEIA and Benchmark Mineral Intelligence’s Q2 Energy Storage Market Outlook reported 9.7 GWh installs in Q1 — with California (60.6 GWh cumulative), Texas (29.2 GWh), and Arizona (20.2 GWh) leading. This was across 7.8 GWh utility-scale, 648 MWh C&I, and 515 MWh residential capacity. Notably larger battery installs are being added to Data centers including 200 MW/1.6 GWh project with Meta in Wyoming.

Product Announcements · 🟢 Bullish

Shatterdome Energy Emerges From Stealth With $3.5M Pre-Seed for AI VPP Trading Platform 📅 Published: May 21, 2026

• Crucible Capital led the round for Shatterdome, founded by quant trader Amann Shariff, which aggregates renewables, batteries, and flexible industrial demand into an autonomously dispatched VPP network initially focused on ancillary services markets. The company claims 200 MWh traded in its first three months with 1.5 GW in pipeline across North American and European deregulated markets — early-stage numbers, but the quant-trading founding thesis is a differentiated entry point in a crowded space.

Product Announcements · 🟢 Bullish

ConnectM Reports Q1 2026 Results: Keen Labs Activates VPP Kit Supply Business 📅 Published: May 28, 2026

• Keen Labs, ConnectM’s subsidiary, generated $1.9M in product revenue in its first full quarter supplying bundled solar, storage, and balance-of-system gear under “VPP kit” arrangements to installation partners including Greentech Renewables and Sun Solar LLC. It’s a small-cap signal that VPP-aligned hardware bundling is being productized as a distinct B2B revenue line — not just a pilot model.

Product Announcements · 🟢 Bullish

EnergyHub Launches Background VPP to Unlock Capacity from Non-Enrolled Thermostat Customers 📅 Published: May 27 2026

• EnergyHub’s Background VPP taps the automated energy-saving features already running on smart thermostats for customers who haven’t enrolled in a DR program. The company says integrating this latent capacity can potentially double a utility’s available MW with little to no customer impact.

Grid Reliability · 🟡 Neutral

California Energy Leaders Issue Summer 2026 Grid Reliability Outlook 📅 Published: May 2026

• CEC, CPUC, and CAISO’s Summer Energy Reliability Workshop cited adding >6,000 MW of nameplate capacity added in each of the past two years, keeping Diablo Canyon open and 17 GW of battery storage capacity all creating healthy reserve margins. This provides context for the ongoing fight over zeroing out the DSGS budget after 2026.

Utility Programs · 🟢 Bullish

Tesla Launches VIBES 2.0 VPP Program in US Virgin Islands With Powerwall Owners 📅 Published: May 15, 2026 (outside strict coverage window; flagged for author review)

• Tesla and the Virgin Islands Energy Office expanded the VIBES pilot into a territory-wide residential VPP, offering Powerwall owners incentives for grid stabilization on an islanded grid. It’s Tesla’s first territory-scale VPP deployment outside the continental US — the islanded grid use case stress-tests aggregation logic that continental RTOs don’t require.

📊 By the Numbers

9.7 GWh — US battery storage installed in Q1 2026, a new quarterly record (+32% YoY)

$3.5M — Pre-seed raise for Shatterdome Energy’s AI-native VPP trading platform

~9 GW — Revised PJM backstop reliability auction target (down from 14.9 GW), per Jefferies

2.6M — Devices informing EnergyHub’s Dynamic Load Shaping optimization engine

💬 My Take

Two items stand out from this week’s news:

1. Background VPPs a key growth driver for thermostat VPP capacity.

2. Shatterdome could help unlock energy trading for more VPP capacity participating in ancillary services markets.

I see Background VPPs as one of the key drivers of 1-2 year growth for residential thermostat participation in VPPs. Energyhub’s product update builds on ecobee’s grid resiliency platform and Renew Home’s Energy Shift Capacity to enable utility and wholesale market participation of customers who opt-in to thermostat optimization. Renew Home estimates this can unlock up to 4 GW of capacity. Ecobee’s grid resilience portfolio shifted 108 MWs in CAISO, ERCOT and SPP in 2025 and estimates up to 2.8 GW of available capacity.

In context 6.8 GW of potential capacity represents 18% growth for the entire VPP market from WoodMac’s estimated 37.5 GWs from 2025. Berg Insights estimated 13.9 GWs of residential only VPPs capacity across North America in 2025; background thermostat VPPs from Renew Home and ecobee could result in up to 48% growth for the residential VPP market.

Two of the top 10 thermostat OEMs by market share according to Parks Associates already have features that could be used to unlock similar functionality. Amazon already has a Choose Cleaner Energy feature for matching the carbon intensity of the grid that could be the foundation of something very similar to Renew Home’s Energy Shift Capacity. Sensi has some TOU and Ongoing Energy Efficiency Optimization that could similarly be the foundation for unlocking residential thermostats to support utility capacity programs. I forecast other thermostat OEMs are going to build out a similar capability for background VPPs participation to drive incremental revenue and possible discounts at the point of sale in the next 2 years.

Shatterdome’s launch makes a bet on ancillary services volatility to enable trading for VPP capacity. I agree with the bet on the increasing need and volatility for ancillary services (see May 5th issue). And the space for VPP optimization is crowded: aggregators have ancillary services optimization and dispatching in-house; GridBeyond, Fluence and Stem all offer this.

The differentiation I see is that Shatterdome is less focused on selling software or participating in ancillary services than trading off the volatility in these markets. With CPower’s acquisition by NRG, I would expect CPower’s capacity to be able to participate through NRG’s trading desk. Enel trading capabilities would provide similar offerings for Enel’s VPPs capacity. Shatterdome’s unlock is if they can add incremental value working with the battery software layers like Stem and Fluence and the VPP aggregators who don’t have trading desks today like Leap and Voltus.

What Did I Miss — or Get Wrong?

Spot a story that should have been in this week’s issue? Disagree with the way I’m interpreting the facts? Just comment in notes with a link to the story or your take.

Opinions are my own and not the views of my employer. Research and drafting for this issue was produced with the assistance of Claude AI. All editorial decisions are mine.

1. PJM’s emergency data center curtailment powers unlocked data center flexibility during a possible emergency outside of any market participation.

2. In NERC’s summer reliability assessment, there are deeper concerns during the spring season with early summer heat and many power plants offline for spring maintenance.

3. The most operationally proven state-run VPP program in the country is heading toward elimination, and the ELRP fallback Governor Newsom is proposing is a structural downgrade for every aggregator operating in California.

News Roundup

Grid Reliability · 🟢 Bullish

DOE emergency order authorizes PJM to curtail data centers during heat-driven grid stress 📅 Published: May 19, 2026

• DOE invoked emergency authority May 18 allowing PJM to curtail data centers with backup generation as a last resort after PJM flagged under 5,800 MW of reserves during an unseasonably hot peak, with Maryland and Virginia most stressed. The event required no VPP dispatch — but it is the clearest operational argument yet for why dispatchable behind-the-meter resources need market access before the next heat event, not after it.

Policy & Legislation · 🔴 Bearish

California’s signature VPP program faces a funding cliff as Newsom proposes eliminating DSGS in 2027 📅 Published: May 20, 2026

• Gov. Newsom’s biennial budget zeroes out DSGS funding in 2027 and proposes shifting enrolled customers into utility-run ELRP — a transition clean energy groups call costly and counterproductive. DSGS dispatched 539+ MW average output over two hours during July 2025 test events, making it one of the most operationally proven consumer demand response programs in the country. The California Legislature must pass a budget by June 15 and finalize by August 31.

Research & Reports · 🟢 Bullish

Berg Insight: 13.9 GW of residential VPP capacity online in North America at end of 2025; 32M DERs connected by 2030 📅 Published: May 20, 2026

• Berg Insight’s first-edition Residential Virtual Power Plant Software Market report puts 10.6 million residential DERs connected to VPP platforms in North America at end of 2025, representing 13.9 GW of flexible capacity — with smart thermostats the dominant asset class and home batteries and EV chargers accounting for smaller shares. The forecast to 2030 is 32 million DERs at an 18.1% CAGR, with Renew Home and EnergyHub ranked as the leading North American platforms by connected assets.

Research & Reports · 🟡 Neutral

NERC 2026 Summer Reliability Assessment: 58 GW added, but data-center demand forecasting problems grow 📅 Published: May 20, 2026

• NERC added 58 GW of summer resource capacity to the bulk power system year-over-year and cut at-risk areas from six to four — but flagged data-center interconnection delays as a worsening demand forecasting problem that complicates operational planning. The deeper concern is during the spring season with early summer heat and many power plants offline for spring maintenance. NERC called out “widespread and unexpected” large load reductions and wind down ramp events in 2024–2025 as a growing reliability risk that adequate summer reserves don’t address.

Research & Reports · 🟢 Bullish

IESO 2026 Annual Planning Outlook projects 65% Ontario demand growth by 2050; DSM named a moderating force 📅 Published: May 20–22, 2026

• IESO’s 2026 APO projects Ontario net annual energy demand growing 65% by 2050, driven by EVs, data centers, and electrification — and for the first time, the outlook explicitly names energy efficiency and demand-side management programs as a structural moderating force on load growth. IESO ran stakeholder engagement on the APO this week (May 20–22), with a new addition this year: high/low demand scenarios alongside the reference case, giving DSM advocates more surface area to make the load-flexibility argument.

Research & Reports · 🟢 Bullish

SEPA/NCCETC Q1 2026 VPP Policy Update: Two states pass VPP legislation, Massachusetts sets 3.5 GW load-management target 📅 Published: May 13, 2026 (published just before this week’s window — included given the June 1 Illinois deadline)

• Q1 2026 saw two states enact VPP legislation, Massachusetts set a 3.5 GW load-management target, and Minnesota greenlight Xcel’s $430M CapacityConnect program. Illinois’s CRGA VPP tariff — the first formal third-party aggregator framework in the state — hits its June 1 implementation deadline this week, making the Q1 state policy sweep directly relevant to practitioners tracking where the next aggregator opportunity opens.

Regulatory & FERC · 🔴 Bearish

FERC RM21-14 withdrawal takes effect, preserving state veto over third-party aggregators 📅 Published: May 21, 2026

• FERC’s April 16 termination of RM21-14 became legally effective May 21, locking in states’ authority to block third-party aggregator bids from RTO/ISO markets — covered in depth in the April 20 issue.

📊 By the Numbers

• 13.9 GW (Berg Insight) — Total flexible capacity of residential DERs connected to VPP platforms in North America at end of 2025, across 10.6 million connected assets.

• 32M (Berg Insight) — Residential DERs forecast to be connected to VPP platforms in Europe and North America by 2030, an 18.1% CAGR from current levels.

• 539+ MW (Utility Dive) — Average DSGS dispatched output over two hours during July 2025 test events, the program Newsom’s 2027 budget would eliminate.

• <5,800 MW (Utility Dive) — PJM reserve margin during the May 18 heat peak, the threshold that triggered DOE emergency authority.

• 58 GW (Utility Dive) — New summer resource capacity added to the bulk power system year-over-year, per NERC’s 2026 Summer Reliability Assessment.

• 65% (IESO) — Projected Ontario net energy demand growth by 2050, per IESO’s 2026 Annual Planning Outlook.

🗓️ On the Radar

• June 1, 2026 (SEPA/DSIRE) — Illinois CRGA VPP tariff deadline; the first formal aggregator tariff framework in the state reaches its implementation milestone.

• June 2026 — FERC expected to act on RM26-4 (large load interconnection rulemaking), which FERC commissioners have explicitly flagged as intersecting with DR and load flexibility as alternatives to costly transmission buildout.

• June 15, 2026 (Utility Dive) — California Legislature must pass its budget; DSGS 2027 fate expected to crystallize.

• August 31, 2026 (Utility Dive) — California budget finalization deadline; final DSGS/ELRP transition decision confirmed.

💬 My Take

This spring is an unusually early start to the demand response season, especially in PJM and NY. I forecast that we are going to continue to see increased dispatching through the spring for VPPs as a result. And some of the fallout will lead to more data center developers and operators planning to be flexed for grid reliability.

Historically the summer season really kicks off in July and goes through September in much of the country. This year it starts in May. And there are structural reasons related to weather, power plant planned maintenance, and data center load drops that are driving this need. Let me start with the signals I’m seeing:

1. Last week NERC flagged that early heat in the spring, planned maintenance for a number of power plants make this time a high risk period for the grid. They noted March was the hottest on record for the last 132 years in the contiguous United States. NERC noted there are longer maintenance windows in the Western United States due to “limited availability of engineering, procurement, and construction contractors.”

2. NERC also flagged New England’s decreased firm imports by 836 MWs from last year. This lowers the Anticipated Reserve Margins this summer to 14%, 1% above NERC’s reference level. This could push ConnectedSolutions dispatches to start in the first half of June rather than July.

3. In parallel PJM got emergency powers from DOE to require data centers to run their backup generators through May 20th given the early heat, forecasted peak loads and 40 GWs of power plant outages. PJM did not need to activate this power and was instead able to use the traditional demand response resources across four utility territories.

4. In April NYISO issued a projected reliability shortfall of 1,679 MWs during a 3-day heat wave above 95 degrees in New York City for this summer.

5. And May 5th NERC issued a level 3 reliability alert due to data centers’ sudden load loss. This could trip voltage sensitivities on the grid without ancillary services support.

Source: FERC data

The PJM emergency power from DOE is another signal that any new data center should plan to be shut off even if they aren’t on a base interruptible tariff today. PJM is not a one-off example: Texas has codified new data center shutoffs during emergencies into law under Texas Senate Bill 6 in June of 2025. Both the emergency order and SB6 create a mechanism to drop data center load that can be triggered during an emergency.

SPP is pushing forward with an interruptible tariff framework called CHILLS (Conditional High Impact Large Load Service) for sites that can’t yet be serviced with a firm transmission service. In this scenario they are able to interconnect earlier. In exchange the site has non-firm service for up to five years while system upgrades are completed.

As other regions experience significant data center load growth, I would expect legislation mandating dropping data center load during an emergency, interruptible tariffs or fast track for curtailable load to be mirrored by other states and markets. All of these examples point to a future where data center flexibility is brought to the grid for emergency events outside of markets or utility programs. This could pose a challenge for aggregators unless they can support data centers coming online faster through Bring-Your-Own-Distributed-Capacity (discussed in detail last week).

I have previously thought of flexibility coming from three primary sources:

1. tariffs like interruptible tariffs, time of use and demand charges

2. wholesale market demand response participation

3. utility programs.

I now see another avenue - mandatory flexibility that is not compensated in markets, but may be compensated through earlier interconnection.

What Did I Miss — or Get Wrong?

Spot a story that should have been in this week’s issue? Disagree with the way I’m interpreting the facts? Just comment in notes with a link to the story or your take.

Opinions are my own and not the views of my employer. Research and drafting for this issue was produced with the assistance of Claude AI. All editorial decisions are mine.

1. A coal plant scheduled to retire in 2023 just got a 12-year lease on life to serve Amazon and Google with a contract estimated at $164,250/MW-year. This deal displaced the use of bring-your-own-distributed-capacity to enable demand flexibility.

2. Con Edison’s RFI for 125 to 750 MW of flexible capacity in New York City is the most direct VPP procurement opportunity to emerge in the Northeast this year.

3. Every demand forecast in this week’s news — NEMA’s 55% growth, NYISO’s summer shortfall, Fluence’s 12 GWh hyperscaler pipeline — points to the same constraint: the grid can’t interconnect new capacity fast enough. Gridcare’s $64M raise is a direct bet on solving that problem, and the company is explicitly framing VPPs as a core piece of the answer.

News Roundup

Regulatory & FERC · 🔴

PJM may be ‘too big to function’: FERC Chairman Swett 📅 Published: May 13, 2026

• FERC Chairman Swett’s declaration that PJM’s governance is “completely eroded” carries more weight than political rhetoric because she is the regulator with compulsory tariff jurisdiction — not a legislator waiting on Congress. That said, the July 23 conference is more likely to produce a NOPR and extended comment period than structural action; PJM’s 13-state stakeholder complexity makes rapid redesign nearly impossible. Track this alongside the Order 2222 compliance thread — they’re the same governance problem approached from different directions.

Utility RFP & Procurement · 🟢

Con Edison to spend $29B shoring up NYC area grid as electrification rises 📅 Published: May 12, 2026

• CECONY issued a request for information for “feasible, effective, timely and cost-effective” options to meet a 125 MW capacity gap by 2032, growing to 750 MW by 2036, driven by retiring generators and rising EV and building electrification load in New York City. NYISO has separately projected a potential -1,679 MW reliability shortfall in an extended heat wave scenario this summer. This RFI is a direct procurement opening for VPP aggregators and DER operators in the CECONY service territory.

Grid Reliability · 🔴

Amazon and Google are paying a premium for coal capacity in Indiana 📅 Published: May 11, 2026

• NIPSCO’s GenCo subsidiary locked in 500 MW of Hallador’s Merom coal plant via a 12-year, $1B contract at $450/MW-day or $164,250/MW-year — more than four times recent MISO capacity prices — to serve Amazon and Google data center load in Indiana. The deal includes 342 MW of BESS in a shared pool, but the structural signal is clear: utilities are solving data center reliability through centralized, long-duration supply contracts, not distributed flexibility. Third-party VPP aggregators are not in the room for this procurement model.

Research & Reports · 🟢

What ‘zombie’ power plants miss about the grid’s real problem 📅 Published: May 12, 2026

• Jason Kraus of Accruent argues in a Latitude Media op-ed that the U.S. grid operates at approximately 50% utilization, and the Brattle Group pegs the economic value of closing that gap at $110–170B over a decade. Reviving fossil plants adds supply but leaves the utilization gap intact. The piece provides analyst-grade framing for the VPP value proposition in any procurement or regulatory proceeding.

Partnerships · 🟢

Fluence Energy signs master supply agreements with two ‘major’ hyperscalers 📅 Published: May 12, 2026

• Fluence announced master supply agreements with two unnamed hyperscalers on its May 7 earnings call, pushing its data center BESS pipeline to roughly 12 GWh and total backlog to a record $5.6B. The company flagged that AI workloads cause power swings of up to 50% within minutes — a dynamic NERC’s Level 3 alert this month named as a bulk system reliability threat. Hyperscaler BESS demand is hardening into a distinct market segment, with grid quality-of-power specs that increasingly mirror demand response technical requirements.

Project Finance · 🟢

Gridcare raises an oversubscribed $64M Series A 📅 Published: May 14, 2026

• Gridcare closed an oversubscribed $64M Series A led by Sutter Hill Ventures, with National Grid Partners, Future Energy Ventures, and John Doerr participating. The company’s AI platform claims to cut interconnection timelines from years to months by surfacing latent grid capacity — and its pitch explicitly frames VPPs as a key flexibility mechanism. With 2+ GW of AI compute load engaged across 12+ markets, Gridcare is positioning itself at the intersection of data center interconnection and distributed flexibility.

Research & Reports · 🟡

US annual electricity consumption to grow 55% by 2050: NEMA 📅 Published: May 13, 2026

• NEMA projects U.S. net electricity consumption will grow from 3,936 TWh in 2024 to 6,130 TWh by 2050, with the steepest growth front-loaded into the current decade. Data center energy demand is forecast up 300% in 10 years; EV demand up 2,000% through 2050. For VPP practitioners, this is the macro demand environment underpinning every program expansion conversation happening simultaneously across this week’s news.

📊 By the Numbers

• $164,250/MW-year — Hallador’s Merom coal capacity price with NIPSCO GenCo; more than 4x recent MISO market prices

• $5.6B — Fluence Energy’s record total order backlog as of Q2 FY2026

• -1,679 MW — NYISO projected reliability shortfall under an extended 3-day heat wave scenario in New York City this summer

• $110–170B — Brattle Group estimate of economic value from closing the U.S. grid’s utilization gap over a decade

• 50% — Power swing range AI workloads can cause within minutes, per Fluence’s investor data

🗓️ On the Radar

• July 23, 2026 — FERC convenes PJM governance reform conference; structural redesign of the largest U.S. grid market openly on the agenda

💬 My Take

The central tension running through stories this week: to what extent can Bring-Your-Own-Distributed-Capacity (BYODC) and onsite data center flexibility meet the scale, geographic constraints and timelines of data center buildout? The narrative of BYODC is compelling: a data center can be interconnected faster by unlocking DERs to enable flexibility in load pockets where it is most needed. VPPs are also faster to build than traditional power plants. The gap in this story is that individual aggregators don’t have the scale to meet a significant amount of the data centers’ need for incremental capacity, within the geographic and temporal constraints required.

The way I think about quantifying the answer to this question is what amount of capacity from VPPs will be under a BYODC contract by 2029? I see a low scenario of ~2 GW if aggregators continue with the current pace of collaboration and consolidation to support data centers. The high end could be 10 GW if aggregators can partner and collaborate to aggregate massive, new, geographically-constrained VPPs. This assumes that 10-20% of the 759 GW of data center capacity hits significant project milestones. For a sense of scale, Voltus was listed as the largest aggregator in the US in September 2025 with 7.5 GW under management. If VPPs can get this right, we can help drive the $110-170 billion Brattle estimates in economic value from higher utilization of the electric grid.

On the one hand ConEd’s RFI for 125 MW by 2032 and GridCare’s investment round point to a vision of load flexibility enabling dramatic electricity growth both with existing DERs and the increasing flexibility data centers can enable. ConEd’s RFI is not directly tied to data center load growth, but new buildings requesting 20-25% more power than comparable buildings and EV chargers for residential EVs, buses and medium/heavy-duty trucks. This reaffirms my stance that VPPs have the ability to support broad electrification and stabilize the grid from transient large loads like High-Voltage DC chargers and data centers.

GridCare’s oversubscribed investment round underlines the clear value of insights that can speed up data center interconnection. The insights from their software capability enable data centers and utilities to work together to identify load pockets to speed up finding and interconnecting a site. The software can also help determine what flexibility is needed from a combination of onsite flexible and BYODC. These insights can dramatically speed up collaboration between utilities, data centers and aggregators for expanding their VPP offerings.

On the other hand, Amazon and Google’s contract with NIPSCO’s GenCo subsidiary locked in 500 MW of Hallador’s Merom coal plant and 342 MW of front-of-the-meter (FTM) batteries on the MISO side of Indiana. This is in spite of both companies’ goals on clean energy that would lead these companies to prefer clean alternatives to coal. Amazon is still procuring 100% renewable energy and Google is still targeting 24/7 clean energy. Where was the BYODC or data center flexibility that could have been enabled at $164,250/MW-year?

Google or Amazon haven’t announced being able to flex load at these sites as part of this deal. My hypothesis is this happened because there wasn’t a mechanism for the companies to be compensated for the flexibility they could provide leading to faster interconnection. On the utility’s side, NiSource (NIPSCO’s parent company) specifically called out new power plants and batteries as an unlock for faster build out with Amazon. And there is strong evidence Google in particular could flex their data center: on the PJM side of Indiana Google has a data center campus that can already be flexed by the local utility for demand response, and beyond this specific site Google announced 1 GW of data center demand flexibility in March. They also have developed new API tiers that result in having jobs that can be shifted. This points to having the capability but not the incentive for flexibility initially.

What about BYODC? MISO does have enough VPP capacity additions annually that could support this, but the industry doesn’t yet have the capability to bring on 100s of MWs of incremental VPPs in Indiana. MISO cleared 9 GW of DR capacity in its 2025 auction and added between 400 and 900 MW in each of the last two years. However, no BYODC capacity contract has been announced tied to specific projects in North America yet. Today there are partnership announcements of Voltus’s partnerships with Cloverleaf Infrastructure and Octopus and there are utility tariffs proposed and implemented across a number of states. I forecast these partnerships and utility tariffs will lead to signed deals by the end of 2026 or early 2027.

Companies like GridCare, forward looking utilities like ConEd and partnerships between VPP providers will be able to provide more scale than the limited capacity of legacy plants. I also see acquisitions like NRG’s acquisition of CPower and Piclo’s recent growth enabling aggregators to work together to get to the necessary scale and speed within specific geographies. If this trend picks up over the next year I forecast 2-10 GW in BYODC portfolios by 2029 because of scale unlocked by the industry collaborating on this massive opportunity.

What Did I Miss — or Get Wrong?

Spot a story that should have been in this week’s issue? Disagree with the way I’m interpreting the facts? Just comment in notes with a link to the story or your take.

Opinions are my own and not the views of my employer. Research and drafting for this issue was produced with the assistance of Claude AI. All editorial decisions are mine.

1. The most important near-term fight for VPPs is inside PJM’s stakeholder process: two design details in the reliability backstop auction — the definition of “net new” capacity and the planning requirements imposed on DER aggregators — will determine if up to 10 GWs of behind-the-meter resources can actually participate.

2. NERC’s rare Level 3 alert over data center load instability makes the case for dispatchable demand-side resources having increased value in ancillary services markets.

3. Two data points from Texas — Base Power’s research that 60% of customers never switch providers and findings from TXU’s EV charging partnership with ChargeScape — make the case that DERs convert the REP’s core liability (a commodity product with no retention mechanism) into a service relationship that can enable differentiated offerings.

News Roundup

Regulatory & FERC · 🟢 Bullish (with caveats)

PJM’s data center auction may be the break VPPs have been waiting for 📅 Published: May 4, 2026 (one day before coverage window — included for direct VPP relevance)

• PJM’s emergency backstop procurement could unlock over 10 GW of behind-the-meter capacity, according to Voltus CEO Dana Guernsey — but two design questions will determine whether that potential is realized. First, PJM’s definition of “net new” VPP capacity must account for new assets installed at existing sites; defining it too narrowly excludes some of the cheapest, fastest-to-deploy options in the market.

• Second, DER aggregators are currently being asked to produce locked-in 15-year retail contracts while traditional generators only need a “pathway to readiness.”

• Running in parallel: a Voltus/Mission:data FERC complaint arguing that PJM’s smart meter data barriers effectively block residential participation — without statistical sampling allowances, the backstop auction remains out of reach for homeowners regardless of how the design question is resolved.

Regulatory & FERC · 🔴 Bearish

PJM floats three paths to overhaul its capacity market — all of them structural 📅 Published: May 7, 2026

• PJM’s CEO declared the “current situation not tenable” in a white paper outlining three reform paths: Path A stabilizes the existing capacity market with longer forward contracts; Path B introduces differential reliability standards and potential rationing; Path C replaces the capacity market entirely with an energy-only market. Stakeholder discussions will run through 2026, but VPP and demand response developers are now facing a world where their primary revenue stream is structurally unsettled.

Grid Reliability · 🟢 Bullish

NERC issues rare Level 3 alert over data center load losses 📅 Published: May 5, 2026

• NERC activated its highest-level alert after data centers unexpectedly oscillated load, creating instability across the bulk power system. Seven mandatory actions were issued to grid entities, with an acknowledgment deadline of May 11. The alert underscores a secondary value for VPPs: the same large loads driving capacity demand are themselves introducing a new category of reliability risk — and dispatchable demand-side resources may be further valued to stabilize the grid, especially in ancillary services markets.

Policy & Legislation · 🔴 Bearish

Scoop: Trump is sitting on an executive order pushing advanced transmission 📅 Published: May 5, 2026

• The White House has been holding a long-delayed EO that would direct FERC to require grid operators and utilities to identify where advanced transmission technologies — dynamic line rating, advanced reconductoring, power flow control — can substitute for new wires. For VPPs, the congestion relief ATTs deliver is a supply-side story: more electrons reaching load pockets collapses the locational price premiums that demand response depends on, more renewable throughput compresses the energy market spreads that battery dispatch monetizes, and improved deliverability adds supply-side competition that drives down capacity clearing prices. A parallel signal: the Pennsylvania House unanimously passed a bill this week requiring utilities to study ATT potential before proposing new transmission, suggesting state-level momentum is building independent of the EO.

Policy & Legislation · 🟢 Bullish

New Jersey regulators announce structural review of the utility business model 📅 Published: May 8, 2026

• The New Jersey Board of Public Utilities announced it will examine whether the state’s “century-old utility business model — one that rewards electric distribution companies for capital spending even when cheaper alternatives exist — should be replaced with a framework tied to performance, affordability, and long-term cost stability.” Pennsylvania Governor Shapiro made a near-identical argument to his state’s utilities in the same week — both moves point to coordinated political pressure on the capex-reward model from which VPP economics benefit.

Opinion: Competitive markets are best for virtual power plants, consumers 📅 Published: May 7, 2026

• Shannon Anderson, director of VPP policy at Solar United Neighbors, argues that utility ownership of behind-the-meter storage crowds out the private-sector competition that makes VPP programs scale. She cites Puerto Rico’s customer battery-sharing program — which grew from 40 MW to 500 MW in one year — and California’s 1,100 MW Demand Side Grid Support program as evidence that third-party-led VPPs outperform utility-owned alternatives. The piece is a useful map of where the utility-versus-aggregator ownership fight is currently being contested state by state.

Research & Reports · 🟢 Bullish

Rewiring America: six state policies could make home DERs a “win-win-win” for utilities, data centers, and ratepayers 📅 Published: May 7, 2026

• A Rewiring America report published exclusively with Latitude Media found that six state policy changes — including simplified interconnection, requiring data centers to fund residential DER capacity, and utility-funded electrification recovered through bill savings — could deliver an average of $26,000 in lifetime savings per household. The group’s prior research estimated that household energy upgrades could meet 93 GW of near-term data center demand. The report frames households as energy infrastructure, not passive bill-payers — a framing that directly supports the BYOC (bring-your-own-capacity) paradigm gaining traction in several state legislatures.

E3: managed EV fleet charging could cut PG&E residential rates 4.5% by 2035 📅 Published: May 7, 2026

• An E3 analysis found that managed electric truck fleet charging could reduce PG&E residential rates by roughly 4.5% — about $20 per year — by 2035, while unmanaged charging delivered materially less benefit. The finding validates flexible large-load management as a rate-reducing strategy, strengthening the economic and political case for VPP programs that compensate fleet operators for demand curtailment and time-shifting.

Base Power bill study: 7,000 Texas electricity bills reveal loyalty penalty, neighbor rate gaps, and a brand premium 📅 Published: May 2026

• Base Power analyzed 7,148 real Texas electricity bills and found non-switchers pay a median 16.0¢/kWh vs. 14.0¢ for customers who’ve switched seven or more times — a gap worth roughly $307/year at average Texas usage. Only ~40% of the bill submitters had ever exercised their right to choose a provider. For VPP aggregators operating in ERCOT, the data quantifies the customer inertia they’re working against: the same switching friction that lets incumbent REPs charge loyalty premiums also makes DER enrollment slow and expensive. Caveat: this is self-published marketing content by Base Power, a Texas REP-plus-battery company; bill sample is voluntary and likely skewed toward cost-conscious consumers.

Utility Programs · 🟢 Bullish

Ann Arbor launches first U.S. city-owned residential solar-and-storage utility 📅 Published: May 5, 2026

• The Ann Arbor Sustainable Energy Utility (A2SEU) began installing FranklinWH solar-plus-storage systems in the city’s Bryant neighborhood — the first time a U.S. city-owned utility has directly purchased and deployed residential solar and battery systems at scale. Texture’s energy management platform will aggregate the installations into a utility-scale VPP. The pilot targets 150 homes this year, scaling to 1,000 in 2027. The ownership model is distinct: A2SEU is neither a traditional utility-owned program nor an aggregator-led VPP, but a municipality acting as direct owner and operator of distributed assets — a new template for how cities can build behind-the-meter capacity without relying on the incumbent IOU. A separate November ballot initiative would begin full municipalization; DTE Energy has spent $1.8M opposing it.

TXU Energy’s managed EV charging model could work in any competitive retail market, ChargeScape says 📅 Published: May 6, 2026

• Ford’s EV Free Miles program, run through TXU Energy and ChargeScape, shifted 515 MWh of EV charging off-peak across the ERCOT market in 2025. ChargeScape’s CEO told Utility Dive the model is replicable in any of the 13 states plus DC with broadly competitive retail electricity markets. The company is also piloting bidirectional (V2G) charging with PSE, which would convert EV fleets from passive load-shifters into active grid resources — a meaningful expansion of the addressable VPP asset base.

📊 By the Numbers

• 10+ GW — Behind-the-meter capacity Voltus CEO Dana Guernsey estimates PJM’s backstop auction could unlock, if the design questions are resolved correctly

• $11.5B — Cost of transmission congestion in the U.S. in 2023, according to Grid Strategies; the figure the White House EO proponents cite as the case for ATT deployment

• 4.5% — Projected reduction in PG&E residential electricity rates by 2035 from managed electric truck fleet charging (E3 analysis)

• $26,000 — Average lifetime savings per household if six state-level DER policies are enacted, per Rewiring America

🗓️ On the Radar

• May 11 — NERC Level 3 alert acknowledgment deadline; grid entities must confirm receipt and intent to comply with all seven mandatory actions

• May 20 — DOE SPARK program full proposal deadline; $1.9B available for advanced transmission projects including ATTs; awards expected August 2026

💬 My Take

There is a lot happening in VPPs across the US this week. Here are the themes that stand out to me:

1. I don’t buy that 10 GWs of VPP capacity will get bilateral contracts through the PJM incremental auction. And I still see a very feasible path to growth of 2.5-5 GW being added with higher prices bringing possible sidelined assets to market and more batteries being installed. In September 2025, Wood Mackenzie estimated there were 37.5 GWs of VPPs participating in the US. Voltus’s CEO, Dana Guernsey, estimates that up to 10 GWs could come from VPPs. That alone would represent a 26% increase in growth for the market; more than double last year’s growth rate for the entire market. I am skeptical that enough blockers will be removed for VPPs to show up with incremental capacity at this scale. In particular the barriers to residential participation stem from how utilities implement customer data access. This means PJM will have to work with a utility to enable any change prior to September. I think the timeline is too tight to make any changes for this year on data access because of the latency for utilities to prioritize and implement changes to their customer data systems.

2. I am skeptical of any significant changes to be implemented from within PJM in the next 8-10 years in spite of the recent market reform white paper. For context, I went back to FERC Order 2022 implementation timelines. The order was released in 2020. PJM plans to implement changes to come into compliance with this order by 2028. That timeline is roughly what I’d expect for any major internal PJM reform, given the number of stakeholders required to align. I am more concerned about states or utilities leaving PJM individually within 2-3 years that could pose risk to future VPP revenues from the wholesale market. New Jersey’s review of the utility business, Governor Shapiro’s similar concerns in Pennsylvania and AEP’s threats about exploring leaving the market are all recent signals for this risk.

3. I realized this week that AI training loads are likely to increase the need and value for ancillary services. Prior to the NERC level 3 alert, I have always considered AI development as primarily a capacity problem: we need to build enough power plants and VPPs to enable more load to come online. But seeing the load drop concerns in NERC’s alert, I realize adding all these large loads could destabilize the frequency of the grid and cause blackouts. NERC had a prior white paper in March 2026 walking through the high likelihood of oscillation of hundreds of MWs in a few seconds. I am skeptical that data center operators are going to change their behind-the-meter batteries and backup generation to provide these ancillary services because they traditionally have wanted these assets exclusively for reliability and the revenues pale against value from their core business. This leaves real upside for VPPs, especially batteries, to help stabilize the grid.

4. Base Power’s research and the summary of TXU’s Free Miles program build the case that sculpting residential DERs’ loads can allow residential retail energy providers (REPs) in Texas to win on price and customer experience. What most struck me in Base Power’s research is that Octopus delivers the lowest average cost of any supplier. They have been framing their customer value by shaping customer load. This data reflects that they are able to pass that value onto customers through lower prices. The psychological pull of ‘free gas’ for EV drivers would drive loyalty on its own. Smaller REPs are building flexibility as part of their core value proposition. These companies include Octopus, David Energy, Rhythm and Tesla. Larger REPs are acquiring these capabilities through partnerships: Vistra is working with Sunrun and Enphase; NRG has announced a VPP partnership with Renew Home that already has 150 MWs with a target of 1 GW by 2035. I am confident that competition for services enabled through flexible assets will only increase in Texas.

What Did I Miss or Do You Disagree?

Disagree with the way I’m interpreting the facts? Spot a story that should have been in this week’s issue? Just comment in notes with a link to the story or your take.

Opinions are my own and not the views of my employer. Research and drafting for this issue was produced with the assistance of Claude AI. All editorial decisions are mine.

1. California is entering summer VPP season with DSGS, its flagship incentive program, formally constrained — the CEC suspended emergency dispatch and capped 2026 enrollment for the largest state-run residential VPP program in the US. Simultaneously there are bills advancing in the state legislature to take the learnings from this program into wholesale market participation.

2. FERC capped PJM’s capacity auction ceiling at $325/MW-day through the 2029-30 delivery year — limiting maximum revenue for demand response and VPP resources in the nation’s largest grid.

3. The Pew Charitable Trusts just handed policymakers a bipartisan DER playbook — six policies, 18 months in the making, that could guide how states integrate VPPs into utility planning nationwide.

News Roundup

Regulatory & FERC · 🟡 Neutral

FERC Approves Capacity Auction Price Collar to Next Two PJM Auctions

📅 Published: May 1, 2026 | Utility Dive

FERC approved PJM’s proposal to extend its capacity auction price collar — a cap of ~$325/MW-day and a floor of $175/MW-day — to the 2028-29 and 2029-30 delivery year auctions, down from the uncollared ceiling of ~$500/MW-day that would otherwise have applied. The collar limits revenue upside for demand response and VPP resources selling capacity into PJM, but the $175 floor provides a meaningful revenue floor for those resources. The approval had backing from all 13 PJM-region governors, the White House, and DOE — a rare alignment that signals the importance for energy affordability across the political spectrum.

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State Programs · 🔴 Bearish

CEC Adopts DSGS 5th Edition Guidelines, Suspending Option 1 and Capping 2026 Enrollment

📅 Published: April 27, 2026

The California Energy Commission formally adopted the fifth edition of its Demand Side Grid Support program guidelines, suspending Option 1 (emergency dispatch) for the entire 2026 program year and capping enrollment and payment commitments for Option 3 storage aggregations — citing the Newsom administration’s proposal to defund the program. The largest state-run residential VPP in the US is entering its highest-value season with its most dispatch-intensive option capped, squeezing revenue for aggregators.

Research & Reports · 🟢 Bullish

Distributed Energy Can Unleash the Resilient, Affordable Grid of the Future

📅 Published: April 28, 2026 | The Pew Charitable Trusts

The Pew Charitable Trusts released a six-policy DER playbook developed over 18 months with a bipartisan advisory council, charting a path for states to integrate distributed energy resources — including VPPs — into utility planning and procurement, reduce permitting and grid access barriers, and deploy DERs for community resilience. Pew’s institutional credibility and bipartisan framing make this a useful tool for VPP advocates trying to move skeptical state legislatures, particularly in states where “virtual power plant” remains a politically contested term.

Policy & Legislation · 🟢 Bullish

A New Bill Would Help VPPs Replace Peaker Plants in California

📅 Published: April 29, 2026 | Canary Media

SB 913, the Clean Local Power Act, would require the CPUC to develop a methodology that gives VPPs — solar-charged batteries, EV chargers, heat pumps — credit for energy exported to the grid and simplifying enrollment. If enacted, distributed resources would compete on a cost-of-capacity basis directly with gas peakers rather than depending on subsidy programs like the beleaguered DSGS, a structural shift in how the state values flexible load.

📊 By the Numbers

• $325/MW-day — PJM capacity auction price cap approved by FERC, down from ~$500/MW-day that would have applied without the collar

• $109.5 million — Total DSGS program budget now being actively rationed by the CEC, with Option 1 suspended and Option 2 enrollment capped for 2026

🗓️ On the Radar

• June 15, 2026 — California state budget deadline; lawmakers must decide whether to restore or eliminate DSGS program funding in 2027 before this date

• August 31, 2026 — Michigan MPSC staff report deadline for VPP technical conference findings

• August 31 – September 1, 2026 — Virtual Power Plants USA 2026 summit, Houston, TX

💬 My Take

I see two broad pathways for VPPs to continue to scale over the next five years: utility-led VPPs and wholesale market participation. The news this week sheds light on removing blockers for each of those pathways while showing why state-funded VPPs are difficult for sustained growth.

The Pew Report outlines removing blockers for Utility-led VPPs. Pew’s 6 proposals move VPPs into utility’s planning processes, align utility incentives with the growth of these programs and remove blockers for installing incremental assets quickly. I am optimistic that in Republican-led states, this framework can be used to enable VPPs as a tool for affordability, reliability and consumer choice.

The Clean Local Power Act in CA takes learnings from DSGS, especially enabling compensation for exports and simplified enrollment, and could bring them into resource adequacy. These would be concrete steps to remove key barriers to wholesale market participation.

The same DSGS experience that produced these design lessons is also showing why state-funded programs won’t be the long-term scaffolding. DSGS’s funding constraints and how late in the spring the final decision was made indicate to me the challenge of the industry relying on state budgets for funding. State programs can be changed quickly, have funding cycle volatility and create real challenges for longer-term planning.

By contrast in PJM, I see the price collars providing increased price certainty for VPPs. The cap reflects state concern that prices would clear higher without the collar, which gives aggregators short-term forecast certainty. The $175 floor is arguably the bigger story for VPPs — it provides downside protection that lets aggregators underwrite multi-year customer acquisition in PJM.

On net, I see these stories indicating that barriers to growth for VPPs are being removed for utility-led VPPs and wholesale market participation because of continued structural pressure of rising electricity costs. Affordability pressure especially is causing governors and legislatures to push wholesale market and utility reform to enable VPPs — while state-funded programs like DSGS show why they can’t carry this growth alone.

Did We Miss Something?

Spot a story that should have been in this week’s issue? Just comment in notes with a link to the story.

Opinions are my own and not the views of my employer. Research and drafting for this issue was produced with the assistance of Claude AI. All editorial decisions are mine.

1. Third-party demand response aggregators just lost their most significant federal lever — FERC’s permanent termination of RM21-14 locks in utility veto power over wholesale DR participation in 18 states with no regulatory off-ramp in sight.

2. The Texas residential battery market is graduating from pilots to product — Base Power’s 50 MW GVEC scale-up and the Octopus/Lunar PowerStore launch land in the same week, signaling that subscription-style home BESS aggregation is now an off-the-shelf retail offering.

3. VPP operators are opening new revenue pathways beyond capacity and energy — Voltus’s Carbon Response win and SRP’s validation of “background VPP” thermostat programs both show the market pricing grid services that sit outside traditional DR baselines.

News Roundup

Regulatory & FERC · 🔴 Bearish

FERC Withdraws Demand Response Opt-Out Inquiry, Terminates RM21-14 Proceeding

📅 Published: April 21, 2026

• At its April 16 public meeting, FERC voted to withdraw its 2021 Notice of Inquiry and permanently terminate Docket No. RM21-14-000, which had examined whether to eliminate the provision allowing states to block third-party aggregators from bidding retail demand response into wholesale markets. After reviewing comments that included heavy opposition from NARUC, the Commission concluded the DR landscape hadn’t changed enough to warrant removing the opt-out — effective May 21, 2026.

• Commissioner Rosner dissented, warning the decision “limits consideration of options at a time when we need every tool in the toolbox.”

Utility Programs · 🔴 Bearish (Op-Ed)

Minnesota Got One Thing Right on Distributed Storage — But It Missed the Bigger Opportunity

📅 Published: April 21, 2026

• Coalition for Community Solar Access CEO Jeff Cramer argues in Utility Dive that Xcel’s Capacity*Connect is a “learning curve” program where ratepayers bear all the financial risk while Xcel earns a guaranteed utility return — and notes it is the only approved distributed storage program in the country with a cost-benefit ratio below one.

• Cramer’s framing sharpens the central VPP ownership debate of 2026: whether the Minnesota precedent encourages utilities nationally to pursue rate-based VPPs over market-based programs, and whether regulators elsewhere will replicate it rather than requiring competitive procurement.

Utility Programs · 🟢 Bullish

Base Power Partnership to Mitigate Price Spikes, Load Peaks for South Texas Co-op

📅 Published: April 22, 2026

• Guadalupe Valley Electric Cooperative has expanded its partnership with distributed battery storage company Base Power to 50 MW of contracted capacity across GVEC’s 3,500-square-mile Texas territory — scaling up from a 2 MW pilot — with 20 MW targeted to be online by end of 2026 and 15–20 MW added annually thereafter. GVEC participates directly in the ERCOT wholesale market, an unusual arrangement for a distribution co-op that makes the VPP capacity directly substitutable for the 50–100 MW wholesale power tranches GVEC normally procures.

• This is one of the cleaner proof points for the residential BESS aggregation model: a small co-op using a third-party platform to build utility-scale capacity from distributed assets, without rate-basing infrastructure or waiting in an interconnection queue, in a market (ERCOT) that has historically moved slowly on residential VPPs.

Partnerships · 🟢 Bullish

Octopus Energy and Lunar Energy Launch Battery-Powered Retail Electricity Plan in Texas

📅 Published: April 23, 2026

• Octopus Energy and Lunar Energy launched PowerStore, a Texas retail electricity plan that bundles a fixed 8¢/kWh three-year contract, a 30 kWh Lunar battery (no money down, $45/month subscription), and automatic enrollment in a statewide VPP — all in a single offering. Lunar provides the hardware and initial dispatch software; Octopus’s Kraken platform handles the retail and grid-services layer.

• PowerStore packages the rate, the asset, and the VPP into one consumer-facing product — the model Base Power and Solrite have proven works in ERCOT, but with a Lunar/Octopus twist: it’s open to any Texas ratepayer regardless of solar status. The companies have explicitly framed it as a template for regulated markets and as a pitch to data-center developers looking to expand local grid capacity, which is the more interesting strategic signal.

Product Announcements · 🟢 Bullish

Voltus Carbon Response Program Earns 2026 Environment+Energy Leader Award

📅 Published: April 22, 2026

• Voltus announced its Carbon Response program — which dispatches VPP assets specifically during high-carbon-intensity grid periods and monetizes the avoided CO2 through voluntary corporate buyer funding — has won a 2026 Environment+Energy Leader Award. Since launching as a pilot in 2023, the program has generated 8,450 metric tons of CO2 reductions.

• Carbon Response represents a structurally new VPP revenue stream: instead of dispatching for reliability or capacity revenue, assets are dispatched for emissions timing, with corporate buyers funding the payments — similar in structure to Voltus’s Bring Your Own Capacity™ model for data centers, but targeting sustainability budgets rather than interconnection queues. If this scales, it opens VPP participation to a corporate buyer class that currently has no pathway into DR markets.

Utility Programs · 🟢 Bullish

As Utility Costs Rise, Can “Background” Smart Thermostats Help the Grid?

📅 Published: April 21, 2026

• Salt River Project and Renew Home (with EnergyHub providing the data integration layer) reported that ~28,500 Phoenix-area homes enrolled in Renew Home’s Energy Shift program delivered ~1.1 kW per thermostat, or ~27 MW total, across six test events last August and September — about 85% of the per-device load reduction SRP gets from its formal demand-response program (~1.3 kW from 75,000 enrolled customers). Renew Home’s Energy Shift program operates without utility enrollment and now covers ~5 million customers / 4 GW nationally.

• This is the first utility-grade dataset validating the “background VPP” thesis: that retail-led, customer-facing thermostat optimization delivers DR-equivalent peak reduction without utility program overhead. SRP is now exploring incentive structures to deepen participation, which would shift the commercial model from utility-funded DR to retail-funded flex with a utility top-up — a meaningful precedent for how utilities monetize the load-shifting that’s already happening on their grids.

📊 By the Numbers

• 50 MW — Contracted residential battery capacity Base Power will deliver to GVEC in Texas, up from a 2 MW pilot.

• 30 kWh — Battery size of the Lunar Energy system bundled into Octopus’s new Texas PowerStore plan, leased at $45/month with no money down.

• 27 MW — Average peak load reduction delivered by 28,500 SRP-area homes in Renew Home’s Energy Shift program across six test events, with no utility-managed enrollment.

• 4 GW — National Energy Shift program footprint across ~5 million customers, per Renew Home.

• 8,450 — Metric tons of CO2 reductions generated by Voltus’s Carbon Response program since its 2023 pilot launch.

💬 My Take

This week’s articles highlight two core questions for VPPs today.

1. Who will own the assets underpinning VPPs? I put more weight on financiers using different company vehicles like Base Power to control assets, especially batteries. Financiers can enable standardized offers across regions and can move faster than utility-rate cases. I am skeptical that utilities will be able to replicate Xcel’s program fast enough and across enough geographies where utilities will own a large amount of battery capacity in the next 5 years.

2. Will VPPs be monetized increasingly by utilities or wholesale markets? This question varies by region across the US. The FERC decision means states that invoke the opt-out in MISO will be the domain of utility-run VPPs, if they exist at all, for the next 5 years. I think this is a mistake because, compared to traditional power plants, VPPs can quickly scale at lower costs to offset the load growth we are forecast to see across the country.

Tying these together, we are going to continue to be left with financiers and OEMs wanting more standardization across VPP offers while the quirks of US energy markets and utility regulations result in more of a balkanized VPP landscape.

Did I Miss Something?

Spot a story that should have been in this week’s issue? Let me know: vppbrief@gmail.com

VPP Week-In-Review is published by VPP Brief. Opinions are my own and not the views of my employer. Research and drafting for this issue was produced with the assistance of Claude AI. All editorial decisions are mine.