All five weekday entries (Monday June 22 through Friday June 26) are present in the research log. This digest covers them in full. Two prior watch items remain unresolved: ERCOT Batch Zero PUCT approval (scheduled June 18, no confirmation in any entry through June 26) and the Illinois CRGA ICC June 30 deadline (four days away; no decision logged). Both are flagged below.

The week’s defining narrative is the convergence of demand-side validation from every direction simultaneously. NERC’s 2026 Summer Reliability Assessment — covered in detail in the June 23 entry — marks the first time the continent’s reliability watchdog has explicitly credited demand response and data center curtailability with reducing seasonal risk in official assessments: SERC Central DR availability surged 172% year-over-year, SPP rose 25.8%, and ERCOT’s net internal demand forecast was cut by 3.7 GW (4.6%) specifically because data centers are now curtailable. At the same time, Google disclosed that in addition to the Voltus 100 MW VPP (first covered in the June 12 digest), it has separately committed 1 GW of demand response capacity across five U.S. utility partners — I&M, TVA, Entergy Arkansas, Minnesota Power, and DTE Energy — establishing hyperscaler load flexibility as a standard contractual element rather than a pilot program. Wood Mackenzie and ACP projected the U.S. storage fleet will quadruple to 200 GW/655 GWh by 2031, with domestic manufacturing now at 100% of national demand capacity, providing the physical resource base that VPP and DERMS programs will need to dispatch. And nine states have now legalized plug-in solar, creating an unmetered distributed generation class that traditional interconnection tracking systems will not see.

Against this demand-side momentum, the week also documents the compounding cost of inaction on three parallel tracks: the DOE’s third 90-day renewal of the Indiana coal emergency orders (Schahfer and Culley, at an estimated $195,000/day in consumer costs), the first federal authorization of PJM data center curtailment during a May heat event — making explicit that data center demand has become a direct reliability threat — and the D.C. Circuit hearing the first legal challenge to whether the DOE even has statutory authority to issue these orders. The week closes with House Energy Committee Ranking Member Pallone calling for a national data center moratorium, a political escalation that strengthens the regulatory case for DR and VPP programs as the politically viable middle ground between moratorium and unconstrained load growth.

🔋 Energy Storage

Q1 2026 set the highest single-quarter U.S. storage installation record ever, and Wood Mackenzie projects a fourfold increase to 200 GW/655 GWh by 2031. The Solar Energy Industries Association reported 9.7 GWh installed in Q1 2026 — 32% above Q1 2025 — with records in all three market segments: utility-scale (1.5 GW/7.8 GWh), commercial/industrial (648 MWh), and residential (515 MWh). California led with 1.1 GW, Texas 900 MW, Arizona 500 MW, and Nevada 300 MW. SEIA projects cumulative U.S. deployment will reach 613 GWh by 2030, increasingly driven by data center co-location demand. The residential segment’s 515 MWh in a single quarter is the most operationally significant number for VPP program designers: those installations are behind-the-meter batteries that can participate in programs like Austin Energy’s Power Partner (see Utility Programs section) or the cooperative battery programs covered in the June 19 digest — and at 32% annual growth, the enrollable fleet will be several multiples larger by the time programs launched in 2026 reach full maturity in 2028–2029. (Source: SEIA, Utility Dive, Energy-Storage.News — June 23 entry)

Wood Mackenzie and ACP’s Q2 2026 Storage Monitor projects 200 GW/655 GWh cumulative by 2031, backed by a domestic manufacturing milestone. The combined Wood Mackenzie/American Clean Power Association report finds the U.S. energy storage fleet on track for a fourfold increase from today’s installed base, underpinned by two structural changes that have not previously been simultaneous: the One Big Beautiful Bill Act’s preservation of the storage investment tax credit (even as it accelerated phase-out of wind and solar ITCs, giving storage a relative policy advantage), and the Energy Storage Coalition’s confirmation that U.S. factories now have sufficient manufacturing capacity to supply 100% of domestic demand — a supply-chain independence milestone reinforced by Ford and GM redirecting planned EV battery facilities to energy storage production. The commercial/community/industrial segment alone is projected to grow 26% through 2031, with at least 215 MW of community-scale projects already in development, each representing a potential DERMS-dispatchable node. EIA’s parallel projection of U.S. electricity consumption rising 76 billion kWh in 2026 and 126 billion kWh in 2027 confirms storage deployment is racing to meet demand growth, not outpacing it. For DERMS procurement teams, the 200 GW/655 GWh trajectory means that planning assumptions for VPP-enrollable fleets will need to be revised upward substantially in any IRP looking past 2028. (Source: Wood Mackenzie/ACP, EIA — June 26 entry)

☀️ Distributed Solar & Community Solar

Nine states have enacted plug-in solar legislation, and 35 states plus D.C. have introduced bills — “guerrilla solar” is now the fastest-growing DER category. Inside Climate News documented on June 25 that a “plug-in solar” era has arrived in the United States, with Colorado, Connecticut, Maine, Maryland, New Hampshire, New York, Utah, Vermont, and Virginia exempting certified small solar systems ($500–$1,000, 300–800W) from traditional interconnection requirements. Homeowners can install these systems on balconies, rooftops, or backyards and connect through a standard wall outlet without requiring an electrician or utility approval — a regulatory model based on Germany’s experience, where approximately 1 million plug-in systems are officially registered. New York’s SUNNY Act, passed June 1, 2026, is the most recent enactment. For utilities and DERMS procurement teams, plug-in solar creates an emerging DER category with three distinct planning implications: (1) it expands DER access to renters and lower-income households excluded from traditional rooftop solar, creating new prosumer segments for future VPP enrollment; (2) it generates unmetered distributed generation that traditional interconnection tracking systems will not capture — precisely the visibility gap that DERMS platforms address; and (3) it creates the pathways through which customers who start with a $1,000 plug-in panel may subsequently invest in paired battery storage eligible for DR program enrollment. The legislative momentum in 35 states also signals a broader policy shift toward reducing DER permitting barriers that aligns with the Pew April 2026 priority recommendations documented in the June 19 digest. (Source: Inside Climate News, Clean Energy States Alliance, pv magazine USA — June 26 entry)

⚡ Virtual Power Plants (VPP) & Demand Flexibility

Google disclosed 1 GW of demand response capacity committed across five U.S. utility partners — a separate and larger program than the Voltus BYOC VPP, establishing hyperscaler DR as a standard contract term. Beyond the 100 MW Voltus “Bring Your Own Capacity” VPP in PJM (first covered in the June 12 digest and confirmed in June 19), Google disclosed that it has embedded demand response in long-term energy contracts with Indiana Michigan Power (I&M), Tennessee Valley Authority (TVA), Entergy Arkansas, Minnesota Power, and DTE Energy — cumulatively representing 1 GW of committed flexible load capacity. The DTE Energy contract is the most complex in scope: it pairs 450 MW of energy storage and 1.6 GW of renewables with DR provisions to serve Google’s Michigan data center complex. Amanda Peterson Corio, Google’s global head of data center energy, has explicitly framed the Voltus BYOC arrangement as the cost-effective path when data center capital costs make own-facility curtailment too expensive — but the 1 GW utility contract portfolio shows that Google is simultaneously making its own facilities more flexible when the contractual structure permits. For DSM/DR program designers, the utility contract portfolio is the more transformative precedent: it demonstrates that the largest data center operator in the world has concluded demand response is valuable enough to embed as a contractual commitment across regulated IOUs (I&M), federal power agencies (TVA), and cooperatives (Minnesota Power is a cooperative), spanning multiple market structures. The implied total addressable market for data center DR across all hyperscalers is 5–10 GW or more. (Source: Google Blog, Renewable Energy World, Carbon Credits — June 24 entry)

Austin Energy launched a residential battery VPP pilot targeting 78 MW of DR by 2027 using the EnergyHub DERMS platform — a replicable model for municipal and cooperative utilities. Austin Energy’s Power Partner Battery Pilot offers homeowners a $500 upfront incentive to install a home battery (Tesla, FranklinWH, SolarEdge, or Enphase systems) plus an average of $300+ annually in performance awards in exchange for utility dispatch rights during peak demand. The 1,500-system pilot is aggregated using the EnergyHub DERMS platform alongside the utility’s existing Power Partner EV and thermostat programs in a multi-DER VPP architecture. Austin Energy’s Resource, Generation and Climate Protection Plan targets 78 MW of DR by 2027 and 270 MW by 2035 — representing approximately 2.8% and 9.6% of the utility’s ~2,800 MW peak demand, respectively, aligning with the 5–15% peak demand reduction range that the Brattle Group identifies as cost-effective. Austin Energy has also partnered with local home energy company Base Power to accelerate residential battery deployment across the service area. The program’s significance for the broader market is the replicability signal: a municipal utility operating outside FERC jurisdiction and PJM capacity markets is independently arriving at the same DR program economics as the structured RTO markets, validating the avoided-cost framework across multiple market structures. (Source: Austin Energy, EnergyHub, American Public Power Association — June 22 entry)

RMI outlined three commercial models for VPP-data center integration and projected VPPs can meet 20%+ of U.S. peak demand by 2030 — a market scale on par with projected data center load growth. RMI’s 2026 policy brief argues that virtual power plants (targeting 80–160 GW by the DOE’s 2030 goal) can scale at the same pace as data center load growth, with three commercial models that give utilities and regulators concrete program structures to propose: (1) hyperscaler-funded VPPs where data center operators finance third-party distributed flexibility (the Google/Voltus precedent); (2) utility-operated VPPs where utilities deploy distributed resources and offer data centers guaranteed capacity in exchange for flexible interconnection commitments; and (3) flexible interconnection agreements where data centers accept curtailability provisions for faster queue access. The flexible interconnection model directly addresses the 2 TW stuck in national interconnection queues: where FERC’s show-cause orders (June 19 digest) mandate new tariff pathways, RMI’s model gives utilities the contractual architecture to implement those pathways. For DERMS procurement teams evaluating platform capabilities, the RMI brief defines the three program structures that DER orchestration software will need to manage simultaneously — and the 80–160 GW scale target makes clear that today’s pilot-scale deployments need to expand by two orders of magnitude within four years. (Source: RMI, Utility Dive, MIT Technology Review — June 23 entry)

Columbia CGEP analysis frames demand response as the first-line defense against electricity price increases already running at twice inflation. Columbia University’s Center on Global Energy Policy released commentary on June 23 arguing that grid-enhancing technologies and demand response are the most immediately deployable tools to contain the electricity price escalation driven by data center load growth. Average U.S. residential electricity prices rose at more than twice the rate of inflation in 2025, breaking the 2019–2024 trend of roughly tracking inflation. The commentary quantifies the advanced conductor opportunity ($180 billion in savings by 2050 from replacing existing transmission lines with commercial-available grid-enhancing conductors) and frames large-load flexibility, energy efficiency, and demand-side response as the mechanism to optimize the existing system before expensive new supply-side infrastructure comes online. The analytical framing directly serves IRP-filing teams: DR program costs at $20–30/MWh are an order of magnitude cheaper than the infrastructure buildout that would otherwise be financed through rates, and the Columbia analysis provides an independent academic citation for that proposition alongside the market-monitor data (PJM’s $329/MW-day capacity price cap) that the June 19 digest documented. (Source: Columbia CGEP, Utility Dive — June 24 entry)

🔌 DERMS & Grid Integration Technology

NERC’s formal crediting of demand response in reliability assessments creates a new category of DR citations available for IRP and DERMS business cases. The most operationally significant development in the June 23 entry is not the raw demand response numbers — it is that NERC, the continent’s reliability watchdog, has for the first time explicitly credited demand management and data center load flexibility with reducing projected reliability risk in its official 2026 Summer Reliability Assessment. ERCOT’s net internal demand forecast was reduced by 3.7 GW (4.6%) because “more data centers can be curtailed by grid operators.” The SERC Central region (including TVA territory) saw DR availability surge 172% year-over-year due to new DSM programs and industrial load enrollments, while SPP increased 25.8% and ERCOT itself rose 54.9%. Separately, PJM’s independent market monitor found that NERC had previously undercounted 8 GW or more of behind-the-meter generation and DR capacity in MISO — meaning the actual demand-side resource base available to grid operators is substantially larger than official forecasts reflect, and that DERMS platforms capable of aggregating and dispatching these resources have a larger addressable market than current estimates suggest. For DERMS procurement justifications and IRP filings, NERC’s formal crediting is a regulatory gold standard: it makes DR a documented reliability asset, not merely an economic resource, in regulatory proceedings. (Source: Utility Dive, NERC 2026 Summer Reliability Assessment — June 23 entry)

🏗️ Data Centers & Large Load Growth

Rep. Frank Pallone called for a national AI data center moratorium — the highest-ranking House Democrat with energy jurisdiction to do so — strengthening the political case for DR/VPP as the viable middle ground. House Energy and Commerce Committee Ranking Member Frank Pallone (D-NJ) called for a national moratorium on AI data center construction during an Energy Subcommittee markup of eight infrastructure bills on June 24, citing Lawrence Berkeley National Laboratory projections that data centers may account for over 15% of total U.S. electricity consumption by 2030 (up from ~4% in 2023) and noting that four New Jersey towns — Asbury Park, Red Bank, Old Bridge, and Sayreville — have already enacted local moratoriums. A national moratorium faces long odds in the current administration, but Pallone’s position as the ranking member with jurisdiction reflects growing bipartisan concern about residential ratepayer impact — the same concern driving the Columbia price-inflation research (June 24), the PowerLines $1.4 trillion CapEx analysis (June 22), and the NV Energy affordability protests documented at the EEI conference. For DSM/DR program designers, the moratorium debate creates a specific and usable political framing: rather than arguing on cost-effectiveness grounds alone, DR and VPP programs can be positioned as the mechanism that allows data center growth to proceed while protecting residential ratepayers — the political middle ground between a moratorium and the status quo of unconstrained load growth financed through rate increases. FERC’s June 18 show-cause orders (June 19 digest) already operationalize this framework; Pallone’s call will likely accelerate state-level actions mandating demand-side alternatives before approving large-load interconnections. (Source: The Hill, Heatmap News, House Energy and Commerce Committee Democrats — June 26 entry)

DOE authorized PJM to curtail data centers during a May heat event — the first explicit federal data center curtailment authorization, marking data center demand as a direct reliability threat. On May 18, 2026, DOE issued Emergency Order No. 202-26-23 authorizing PJM to curtail data centers and other large loads with backup generation as a last resort before implementing rolling blackouts. PJM requested the authority during unseasonably hot weather with more than 40 GW of generation on planned maintenance outages, leaving fewer than 5,800 MW of reserves with Maryland and Virginia under particular stress. The order’s own text notes that “significant amounts of backup generation in the United States have remained largely untapped during grid emergencies” — a direct operational argument for DERMS-coordinated dispatch of commercial and industrial behind-the-meter generation and battery storage. This is the first 202(c) order that explicitly authorizes curtailment of data centers by name, a significant escalation from prior orders that targeted coal plant retirement deferral. Combined with the 43+ total Section 202(c) orders documented since May 2025 (covering at least 4.4 GW of deferred coal retirements), the PJM order completes a picture in which every tool in the federal emergency toolkit — supply retention and now demand curtailment — is being activated in response to the same data center load growth that demand response programs are designed to address preemptively. (Source: Utility Dive, DOE Order No. 202-26-23, POWER Magazine — June 22 entry)

DOE issued a third 90-day renewal of Indiana coal emergency orders — Schahfer and Culley now ordered available through September 19 — while CenterPoint’s own president called the retained unit “inefficient and increasingly unreliable.” On June 18, DOE issued Order No. 202-26-29 requiring NIPSCO and MISO to keep Schahfer Generating Station Units 17 and 18 available through September 19, 2026, the third renewal since the original December 2025 order. CenterPoint Indiana’s president publicly described the companion Culley plant as “inefficient and increasingly unreliable” and accounting for less than 1% of regional installed capacity; NIPSCO’s Schahfer units are currently offline for turbine and boiler maintenance despite the order requiring availability. Sierra Club analysis estimates the combined consumer cost at $174,000/day (Schahfer) plus $21,000/day (Culley) — approximately $195,000/day total. DOE cites MISO load growth “expected to accelerate in 2027 and beyond” as justification, the same future load that demand response, VPPs, and storage programs are designed to address. FERC has authorized MISO tariffs to recover coal retention costs from ratepayers — a cost structure that directly exceeds the per-MW cost of DR programs delivering equivalent capacity. For DSM/DR business case developers in MISO territory, the third Indiana renewal sharpens the economic argument: the federal government is spending ratepayer money at a documented per-day rate to retain coal capacity that utility executives themselves describe as unreliable, because demand-side alternatives have not been deployed fast enough to replace it. (Source: Indiana Capital Chronicle, DOE Order No. 202-26-29 — June 23 entry)

The D.C. Circuit heard the first merits-stage legal challenge to the 202(c) emergency orders — a decision later this year could either validate or invalidate the 43+ orders and reshape the DR business case argument regardless of outcome. On May 15, 2026, the U.S. Court of Appeals for the D.C. Circuit held oral arguments in the states of Michigan, Minnesota, and Illinois challenging the DOE’s Campbell coal plant retention order as exceeding statutory authority. The states argue that DOE cannot use emergency powers to block planned coal retirements without demonstrating an actual grid emergency, and that the orders interfere with state-approved utility resource plans. DOE countered that the Secretary is not required to wait for a blackout. A decision is expected later in 2026 and will set precedent for all 43+ pending orders. For DSM/DR program designers, the outcome reshapes the business case argument in either direction: a court ruling upholding the orders confirms that resource adequacy gaps justify extraordinary intervention, strengthening the argument that proactive DR deployment avoids the need for that intervention; a ruling striking them down reasserts state authority over resource planning and removes the federal backstop that has been masking the consequences of inadequate demand-side investment. Either outcome makes the DSM program justification stronger than the current regulatory status quo. (Source: S&P Global, Utility Dive, State Energy & Environmental Impact Center — June 24 entry)

WEF/DNV analysis frames grid connectivity as the binding constraint on AI growth — with a Dutch grid study showing interruptible connections unlock 5–15% of additional capacity without compromising security. The World Economic Forum published a DNV-authored analysis on May 18 arguing that grid connectivity — not chips, capital, or algorithms — has become the binding constraint on AI advancement, with grid connection timelines of 4–10 years outpacing data center build cycles of 2–3 years. DNV projects AI data centers will reach approximately 6,400 TWh — 11% of final global electricity demand — by 2060, with North America consuming half of global data center demand by 2030. A DNV study of the Dutch transmission network found that interruptible connections could unlock 5–15% of additional capacity in congested areas without compromising system security. The four near-term mechanisms the analysis recommends — behind-the-meter assets, interruptible emergency lane connections, demand flexibility through workload deferral, and phased connections — map precisely onto what U.S. regulators are already implementing: SPP’s CHILLS service (June 5), FERC’s flexible load directives (June 18, June 19 digest), Texas mandatory curtailment for 75+ MW loads. The Dutch 5–15% capacity unlock from interruptibility provides international evidence for the same magnitude of benefit now being implemented in U.S. RTO tariff structures. (Source: World Economic Forum, DNV — June 25 entry)

U.S. investor-owned utilities plan $1.4 trillion in capital spending through 2030 — a 27% increase over 2025 projections — with residential ratepayers potentially absorbing $0.7 trillion through rate increases. PowerLines’ analysis of 51 investor-owned utilities found that 30+ cite data centers as a top driver of capital expenditures. Average residential electricity prices are projected to rise 5.1% in 2026, utilities filed $9.4 billion in rate increase requests affecting 81 million people in Q1 2026 alone, and the CapEx is led by Duke Energy ($102.2 billion) and Southern Company ($81.2 billion). For DSM/DR business case developers, this report quantifies the investment that demand-side alternatives are competing against and, critically, identifies the ratepayer risk that creates regulatory space for DR programs: every megawatt of peak demand avoided through DR, VPP, or energy efficiency directly reduces the capital spend that ratepayers must finance through rates. The 27% CapEx acceleration between 2025 and 2026 projections represents the cost of not having deployed demand-side resources preemptively — a number now publicly cited in earnings reports and accessible to state public utility commissions as evidence for avoided-cost arguments in IRP proceedings. (Source: CBS News, PowerLines, Tech Insider — June 22 entry)

📋 Regulatory & Policy

Illinois CRGA June 30 deadline is four days away — no ICC decision has appeared in the research log. The Illinois Commerce Commission’s statutory deadline to approve, modify, or reject ComEd’s scheduled dispatch VPP tariff ($300/kWh distributed storage rebate, $10/kW dispatch compensation) is June 30, 2026. No ruling has been logged in the research log through Friday June 26. As flagged in the June 19 digest, this is the first state-mandated VPP tariff to reach an approval decision in the current policy cycle, and the ICC’s treatment of participation compensation and scheduled dispatch architecture will set the reference benchmark for Virginia, New Jersey, Massachusetts, and Maryland proceedings. Monitor for the ruling on or before Tuesday June 30. (See June 5 entry and June 17 SEPA tracker for original coverage)

ERCOT Batch Zero PUCT approval — still unconfirmed after two consecutive weeks without a research log entry for June 18. The Public Utility Commission of Texas was scheduled to vote on Batch Zero approval on June 18. The June 18 entry was absent from the June 19 digest (as noted in that digest), and no confirmation has appeared in the June 22–26 entries either. If approved, developer submissions are due July 15 — 19 days from today. ERCOT Batch Zero’s mandatory curtailment requirement (≥75 MW loads) means every approved project is also a potential DR resource. Seek confirmation through external sources if log entry remains absent. (See June 15 entry and June 19 flags for original coverage)

FERC 30-day resource adequacy reports due ~July 18, 2026. No submissions have appeared in the research log yet. These informational reports from all six RTOs/ISOs (required by the June 18 show-cause orders, June 19 digest) will document, in each RTO’s own words, the resource adequacy gaps where demand-side resources can compete — making them critical inputs for IRP avoided-cost arguments. Watch for filings on or around July 18.

FERC SPP CHILLS and DOE Stanton order: no new developments this week. Both items were covered fully in the June 19 digest. The June 25 entry provides additional detail and context on both, deduplicated here. (Previously covered in full — June 19 digest)

🏭 Utility Programs & Deployments

NERC data confirms demand response is delivering measurable grid reliability results across multiple regions — DR is now a formal reliability asset, not just an economic resource. The June 23 entry’s NERC Summer Reliability Assessment data documents program growth that extends well beyond ERCOT’s 3.7 GW demand reduction (first reported in the June 12 digest). New figures: the SERC Central region (which includes TVA’s service territory and the broader southeastern utility footprint) saw demand response availability surge 172% year-over-year due to new DSM programs and industrial load enrollments; SPP’s DR availability rose 25.8%; and ERCOT’s rose 54.9%. Most significantly, PJM’s market monitor found that NERC had undercounted 8 GW or more of behind-the-meter generation and DR capacity in MISO — revealing that the actual demand-side resource base available to grid operators is substantially larger than official counts reflect. For utilities building IRP filings, the NERC assessment provides the regulatory gold standard of evidence: a reliability watchdog citation that DR and VPP capacity reduces risk in official seasonal assessments means the same programs can be cited as reliability assets, not just cost-effectiveness tools, in commission proceedings. (Source: Utility Dive, NERC 2026 Summer Reliability Assessment — June 23 entry)

Not-for-profit utility storage for wholesale demand management: previously covered. The June 24 entry documents Connexus Energy’s 2.5 MW/10 MWh substation battery and Meeker Cooperative’s residential battery pilot, both previously covered in depth in the June 19 digest (NRECA cooperative BESS section). (Deduplicated — see June 19 digest, NRECA cooperative BESS flag)

🔬 EPRI Research Spotlight

No new EPRI-published research appeared in the June 22–26 research log entries. The week’s developments, however, directly extend the applied context for two prior EPRI findings: (1) the EPRI/Boston University Nature Energy paper (Volume 11, February 2026, covered in the June 12 EPRI spotlight) documented 25% software-only power reduction in AI data center workloads — a finding that maps directly onto the Pallone moratorium framing this week (DR as the political alternative to a moratorium) and the D.C. Circuit case (DR programs as the demand-side tool that reduces the need for 202(c) emergency orders); (2) EPRI’s work on IEEE 2030.5 as a DER communication standard, relevant to the SCE deployment documented in the June 19 EPRI section, is now the implicit backdrop for NERC’s formal crediting of DERMS-coordinated DR resources in reliability assessments.

Watch for EPRI comment filings in the FERC 60-day tariff-revision proceedings triggered by the June 18 show-cause orders; those filings are due by approximately August 17, 2026, and EPRI input will be critical for utilities shaping DR program definitions under the new “flexible large load” tariff categories.

🚩 Utility-Sector Relevance Flags

⚑ Illinois CRGA ICC Decision Due June 30: Four Days Away
Topic: Regulatory / VPP / Program Design
Relevance: The Illinois Commerce Commission’s ruling on ComEd’s scheduled dispatch VPP tariff will be the first public-record decision on state-mandated VPP program economics in the current policy cycle. The $300/kWh distributed storage rebate and $10/kW dispatch compensation structure being evaluated will become the reference benchmark — either validated or modified — for Virginia (Appalachian Power 150 MW pilot), New Jersey (E.O. 2 BPU program), Massachusetts (3.5 GW E.O. 654 target), and Maryland (PC77 docket). An approval signals that state-mandated VPP economics are regulatorily defensible; a modification reveals where compensation structures fail scrutiny.
Action Signal: Engage — Monitor the ICC ComEd VPP docket for the June 30 decision; if you have VPP programs under development or pending IRP filings in any of the listed states, the ICC’s reasoning on participation compensation, M&V, and scheduled dispatch architecture is directly applicable to your program design and regulatory strategy.

⚑ NERC Credits DR as Reliability Asset — IRP Citation Opportunity Now
Topic: Demand Response / IRP / Reliability
Relevance: NERC’s 2026 Summer Reliability Assessment formally credits demand management and data center curtailability with reducing regional reliability risk — SERC Central up 172%, SPP up 25.8%, ERCOT net demand down 3.7 GW. This is the first time NERC has made this explicit in an official seasonal assessment. Additionally, PJM’s market monitor found NERC undercounted 8+ GW of BTM generation and DR in MISO. Utilities filing IRPs or DR program cost-effectiveness analyses can now cite NERC — the continent’s reliability watchdog — in support of demand-side resources as reliability assets, not just economic resources. This is a qualitatively different standard of evidence than third-party research.
Action Signal: Implement — Incorporate NERC 2026 Summer Reliability Assessment citations into pending IRP filings; update DR program cost-effectiveness analyses to include reliability value alongside capacity and energy value; engage with MISO’s accounting of BTM resources to ensure your program’s assets are counted correctly in official tallies.

⚑ Google 1 GW Utility DR Portfolio: Large-Load DR as Standard Contract Term
Topic: Demand Response / Large Load / Program Design
Relevance: Google’s 1 GW DR commitment across I&M, TVA, Entergy Arkansas, Minnesota Power, and DTE Energy — spanning regulated IOUs, a federal power agency, and a cooperative — establishes that demand response is now a standard element of hyperscaler utility service agreements, not a pilot accommodation. For utilities in these and adjacent territories, this is a negotiating reference: hyperscalers expect and accept DR as a contractual condition. For utilities elsewhere, it is a market signal that large-load DR programs designed to serve data center customers have credible demand from at least one of the largest data center operators.
Action Signal: Implement — Review rate structures and service agreements for existing or planned hyperscaler customers; model whether a formal DR program offer (volume DR obligations in exchange for favorable interconnection treatment or capacity credit) could replicate the Google-utility contract model in your territory; use the DTE 450 MW storage + 1.6 GW renewables + DR structure as a reference architecture for integrated large-load service agreements.

⚑ Pallone Moratorium Call: DR/VPP Programs Now Have a Political Risk-Management Framing
Topic: Regulatory / Policy / Program Justification
Relevance: Rep. Pallone’s call for a national moratorium — even if it fails legislatively — signals that utilities justifying infrastructure rate increases driven by data center load growth face growing political opposition that demand-side resources can help neutralize. DR and VPP programs can now be framed to state commissions not only as cost-effective alternatives to supply-side investment, but as the mechanism that allows data center load growth to proceed without triggering the moratorium debate. This is a qualitatively new regulatory argument available in state proceedings, particularly where commissions are concerned about ratepayer affordability impacts of data center-driven rate increases.
Action Signal: Engage — Incorporate the political middle-ground framing into DR program proposals in state proceedings; engage with state energy offices and PUCs in data-center-heavy regions (Virginia, Georgia, Texas, Indiana) to position demand-side programs proactively as the alternative to moratorium-level regulatory intervention.

⚑ 202(c) Emergency Orders: PJM Curtailment Order Establishes Data Centers as Direct Reliability Threat
Topic: Regulatory / Data Centers / Demand Response
Relevance: DOE Order 202-26-23 — authorizing PJM to curtail data centers during the May 18 heat event — is the first federal acknowledgment that data center demand requires emergency demand-side intervention, not just supply-side retention. Combined with DOE’s own text noting that “significant amounts of backup generation in the United States have remained largely untapped during grid emergencies,” the order makes the strongest possible regulatory argument for DERMS-coordinated dispatch of commercial and industrial BTM generation and battery storage: the federal government has already authorized the curtailment; the tools to implement it systematically without emergency orders are what DERMS platforms provide.
Action Signal: Implement — For utilities in PJM and MISO territories with significant C&I customer BTM generation: begin or accelerate programs to enroll those resources in formal DR programs, ensuring they can be dispatched without requiring emergency orders in future stress events; the DOE’s “untapped backup generation” language provides regulatory language directly usable in program justifications.

⚑ 202(c) D.C. Circuit Case: Watch for Decision That Reshapes DR Business Case
Topic: Regulatory / Legal / Program Justification
Relevance: The first merits-stage challenge to 202(c) orders — Michigan, Minnesota, and Illinois v. DOE — will produce binding D.C. Circuit precedent for all 43+ orders. Either outcome changes the DR regulatory environment: upholding the orders reinforces that proactive DR deployment avoids the emergency intervention; striking them down reasserts state planning authority and removes the federal backstop, making state-mandated DR programs the primary mechanism for resource adequacy. Neither outcome weakens the case for demand-side programs; both make the argument stronger in different regulatory forums.
Action Signal: Watch — Monitor D.C. Circuit docket; when a decision issues, update IRP and DR program filings to incorporate the precedent — if upheld, cite 202(c) cost data as the avoided-cost benchmark for proactive DR; if struck down, update state IRP filings to emphasize state planning authority and the resource adequacy obligations that demand-side programs fulfill.

⚑ Wood Mackenzie 200 GW Storage Forecast: Update VPP Fleet Sizing Assumptions
Topic: Energy Storage / VPP / Program Planning
Relevance: The projection of 200 GW/655 GWh of cumulative U.S. storage by 2031 (4x from today), backed by 100% domestic manufacturing capacity, means that planning assumptions for VPP-enrollable battery fleets are likely materially understated in programs designed in 2024 or earlier. With nearly 50% of new residential solar systems already paired with batteries in Q1 2026, and the commercial/community/industrial segment growing 26% through 2031, VPP programs launched in 2026–2027 will have access to an enrollable fleet several times larger than their initial capacity planning assumed by the time they reach full operation.
Action Signal: Implement — Revise VPP program enrollment capacity projections in IRP filings and DERMS procurement scoping documents to reflect the Wood Mackenzie/ACP forecast trajectory; DERMS platforms specified for today’s fleet should be tested for scalability to the 2029–2031 fleet sizes implied by the forecast.

⚑ Plug-In Solar / Guerrilla Solar: Emerging Unmetered DER Category Requires Planning Model Updates
Topic: Distributed Solar / Distribution Planning / DERMS
Relevance: Nine states have enacted legislation exempting plug-in solar from interconnection requirements; 35 states plus D.C. have introduced bills. As Germany’s experience shows (1 million registered systems, likely many more unregistered), widespread adoption creates a material, unmetered distributed generation base that traditional interconnection tracking will not capture and that will materially affect distribution-level load profiles and daytime peak demand. For utilities in the nine enacted states or the 35 with pending legislation, the question is not whether this load class will arrive but how quickly.
Action Signal: Watch — Assess the pace of plug-in solar legislation in your state; if enacted, update distribution planning models to account for unmetered BTM generation; evaluate whether DERMS platforms in procurement can accommodate plug-in solar monitoring (even without formal interconnection registration) to improve hosting capacity visibility.

📌 Sources

June 26, 2026 Entry
– The Hill — Pallone, Top Energy Democrat, Backs AI Data Center Moratorium (June 24, 2026)
– Heatmap News — Key House Democrat Calls for a National Data Center Moratorium (June 25, 2026)
– House Energy and Commerce Committee Democrats — Press Release (June 24, 2026)
– Utility Dive — US Sees Record Q1 2026 Energy Storage Installations Amid Rosy Outlook (June 23, 2026)
– Wood Mackenzie/ACP — U.S. Energy Storage Monitor Q2 2026
– EIA — Short-Term Energy Outlook June 2026
– Inside Climate News — The ‘Guerrilla Solar’ Era Has Arrived, and Here’s What to Know (June 25, 2026)
– Clean Energy States Alliance — What States Need to Know About Plug-In Solar (2026)
– pv magazine USA — New York Legislature Passes SUNNY Act Plug-In Solar Legislation (June 1, 2026)

June 25, 2026 Entry
– Utility Dive — FERC Approves SPP Non-Firm, Large-Load Transmission Service (June 8, 2026)
– Utility Dive — 6 Takeaways From FERC’s Data Center Interconnection Decision (June 22, 2026)
– FERC — Launches Aggressive Targeted Action to Speed Large Load Integration (June 18, 2026)
– Utility Dive — DOE Orders OUC’s 465-MW Coal Unit in Florida to Continue Running (June 5, 2026)
– DOE — Emergency Order No. 202-26-26 (June 4, 2026)
– World Economic Forum — Is Power Grid Connectivity the Strategic Bottleneck for AI? (May 18, 2026)
– DNV — Global 2025 Energy Transition Outlook

June 24, 2026 Entry
– Utility Dive — GETs, Demand Response Can Ease Near-Term Data Center Electricity Price Pressure: Report (June 23, 2026)
– Columbia CGEP — Addressing America’s Rising Electricity Prices (June 2026)
– Google Blog — Google Signed 1 GW of Data Center Demand Response (March 2026)
– Renewable Energy World — Google Has Integrated 1 GW of Data Center Demand Response With US Utilities (March 2026)
– Carbon Credits — Google Turns Data Centers Into Grid Assets With 1 GW Flex Power Deal (2026)
– Utility Dive — Not-for-Profit Utilities Turn to Energy Storage as Data Centers Drive Cost, Reliability Concerns (June 2026)
– S&P Global — Appeals Court Wrestles With Energy Emergency Claim in DOE Plant Order Case (May 15, 2026)
– Utility Dive — DOE Exceeded Its Authority With Coal Retirement Delay, States Tell Appeals Court (May 2026)
– State Energy & Environmental Impact Center — Tracking AG Activity on DOE Emergency Orders (2026)

June 23, 2026 Entry
– Indiana Capital Chronicle — Trump Administration Renews Order Keeping Indiana Coal Plants Open for the Third Time (June 22, 2026)
– DOE — Federal Power Act Section 202(c): NIPSCO Order No. 202-26-29 (June 18, 2026)
– Utility Dive — Demand Management, Data Center Flexibility Boost Regional Reliability: NERC (May 27, 2026)
– NERC — 2026 Summer Reliability Assessment (May 2026)
– Utility Dive — US Energy Storage Installations Hit Q1 Record, Up 32% Year Over Year: SEIA (May 2026)
– Energy-Storage.News — US Installed 9.7 GWh of New BESS in Q1 2026, SEIA Reports (May 2026)
– SEIA — Energy Storage Market Outlook (2026)
– RMI — How Virtual Power Plants Can Help the United States Win the AI Race (2026)
– Utility Dive — How VPPs Can Help Data Centers Connect to the Grid Faster (2026)
– MIT Technology Review — How Virtual Power Plants Could Provide Energy for Data Centers (June 3, 2026)

June 22, 2026 Entry
– Utility Dive — Google to Fund 100-MW Virtual Power Plant in PJM in ‘First-of-Its-Kind’ Deal (June 3, 2026)
– Voltus — Voltus and Google Bring Your Own Capacity (June 2, 2026)
– DOE — Federal Power Act Section 202(c): PJM Order No. 202-26-23 (May 18, 2026)
– Utility Dive — PJM Gets Emergency Approval to Curtail Data Centers, Large Loads During Hot Weather (May 19, 2026)
– POWER Magazine — DOE’s Section 202(c) Emergency Orders Since May 2025: 43 and Counting (Updated April 2026)
– CBS News — Data Centers Could Spur a Utility Spending Spree, Report Finds (April 14, 2026)
– PowerLines — 2026 CapEx Report (April 2026)
– Austin Energy — Austin Energy Launches Innovative Power Partner Battery Pilot Program (March 2026)
– EnergyHub — Austin Energy Partners with EnergyHub to Expand Multi-DER Virtual Power Plant (March 2026)
– American Public Power Association — Austin Energy Launches Innovative Power Partner Battery Pilot Program (March 2026)