All five weekday entries (Monday July 6 through Friday July 10) are present in the research log. This digest covers them in full. One long-overdue watch item resolved this week: the Illinois Commerce Commission approved ComEd’s Scheduled Dispatch VPP tariff on June 30, closing a gap that had gone unconfirmed across three consecutive prior digests. The ERCOT Batch Zero PUCT vote remains unconfirmed, and with developer submissions due July 15 if approved, this is now an urgent external-verification item ahead of next week’s run.

The week closed out the July 4th heat dome with hard numbers: EEI confirmed the U.S. grid delivered a record 100,996 GWh of output in a single week (June 28–July 4) — the first time weekly generation has crossed 100,000 GWh — while PJM wholesale prices tripled past $2,000/MWh and capacity clearing prices surged 11-fold to $333.44/MW-day, with Monitoring Analytics attributing 63% of that increase (~$9.3 billion) directly to data center demand. A fourth DOE Section 202(c) emergency order extended the crisis framework into the Carolinas as Duke Energy faced a 36,196 MW peak. Against that backdrop, the week produced two structural policy moves: the Illinois ICC approved the first state-mandated VPP tariff in the current regulatory cycle, and Google and Voltus launched the first hyperscaler-funded “Bring Your Own Capacity” VPP in a U.S. wholesale market — a 100 MW/year PJM deal explicitly designed to let a data center operator pay for community-level flexibility rather than build new generation. FERC’s June 18 show-cause orders also came back into sharper focus, with this week’s coverage confirming a July 20 generation-adequacy report deadline (10 days out) and a “cost causer pays” framework aimed at data centers. EPRI revised its national data center load forecast 60% upward from 2024 estimates, and a Forrester-validated 184% ROI study for DERMS-embedded ADMS platforms appeared twice in the log, underscoring how central that business case has become to utility capital planning.

🔋 Energy Storage

IEA’s Global Energy Review 2026 confirms battery storage as the fastest-growing power technology worldwide — 108 GW deployed globally in 2025, up 40% year-over-year, with installed capacity now eleven times higher than in 2021. LFP chemistry now accounts for roughly 90% of deployments (up from under 50% five years ago), reflecting a structural cost decline driven by manufacturing scale and suitability for the frequent cycling that grid-scale and VPP applications require. The report also surfaces a data point directly relevant to the data center flexibility debate running through this week’s log: battery-based UPS capacity additions at data centers rose 30% to 45 GW in 2025 — a large pool of behind-the-meter storage currently limited to short-duration backup that could, in principle, be aggregated into VPP dispatch if DERMS platforms and market rules permitted dual-use operation. China accounted for 60% of global additions, with roughly 80% of new capacity utility-scale and 20% behind-the-meter, and average durations lengthening from the two-hour standard toward four-plus hours as solar penetration rises. For DSM/DR business case developers, the IEA data confirms that storage cost curves continue to move in the same direction as the demand-side business case — a rare instance where supply-side technology trends and program economics reinforce each other rather than compete. (Source: IEA, Energy Industry Review — July 7 entry)

⚡ Virtual Power Plants (VPP) & Demand Flexibility

Google and Voltus launched the first hyperscaler-funded “Bring Your Own Capacity” VPP in a U.S. wholesale market — a three-year, 100 MW/year deal in PJM that pays residential, commercial, and industrial customers to shift usage rather than flexing Google’s own data center load. Announced June 2, the BYOC agreement aggregates batteries, smart thermostats, EV chargers, and other flexible assets across PJM, with Google’s global head of data center energy explaining the rationale directly: idling data center hardware carries “billions and billions of dollars” in opportunity cost, so it is cheaper to pay other customers to flex than to curtail compute. The deal lands squarely on top of this week’s PJM capacity-cost story (see Data Centers section) — Brattle Group’s analysis accompanying the announcement estimates VPPs could save U.S. consumers more than $100 billion over the next decade through better utilization of existing grid resources, a figure that reframes hyperscaler-funded DER programs as a partial, self-correcting offset to the $9.3 billion in data-center-driven capacity cost increases documented elsewhere in this digest. For DERMS procurement teams, BYOC is a new aggregation category requiring the same real-time visibility and dispatch infrastructure as existing residential and C&I VPP programs, and sits alongside the Tesla/Sunrun/Renew Home 16.8 GW framework (covered in the July 3 digest) as a second, structurally distinct hyperscaler-VPP model — sleeved financing through a dedicated aggregator rather than direct multi-vendor capacity transfer. (Source: Utility Dive, Voltus, Data Centre Magazine — July 7 entry)

The Illinois Commerce Commission approved ComEd’s Scheduled Dispatch VPP tariff on June 30 — resolving a watch item flagged as overdue in the last three digests and establishing the first state-mandated VPP tariff to clear final approval in the current policy cycle. The program, authorized under the Clean and Reliable Grid Affordability Act (CRGA), requires participating battery-storage customers to commit to five consecutive summer seasons (June–September) starting 2027, with seasonal performance payments for grid injection during scheduled peak events. ComEd already has roughly 1.8 GW of connected DERs across its 4-million-customer northern Illinois territory and has distributed more than $2.5 billion in energy efficiency incentives — a substantial existing pool of DER-equipped customers who could migrate into the VPP. CRGA’s broader mandate requires 3 GW of grid-scale storage statewide by 2030 and EV inclusion in VPP tariffs by 2029. This approval is the reference point the last three digests flagged as the benchmark other state proceedings (Virginia, New Jersey, Massachusetts, Maryland) would measure against — it is now available for direct citation. Notably, the log’s June 30 approval date exactly matches the statutory deadline that this project’s prior digests had described as passed without a ruling; the daily log’s July 9 entry is the first to confirm the outcome, meaning the ruling occurred on schedule but was not reflected in the log until nine days later. (Source: BusinessWire, Utility Dive — July 9 entry)

New York’s PSC-approved Con Edison “Bring Your Own Battery” program ties NYSERDA’s residential storage incentive directly to demand-response enrollment, creating a built-in customer-acquisition channel for VPP programs. Under the April 16 order, customer-sited batteries become eligible for the first time to participate in Con Edison’s Direct Load Control demand response framework, and NYSERDA will condition its Residential Storage Incentive on BYOB program enrollment — meaning every state-subsidized battery installation now carries an automatic pull toward grid-dispatchable status rather than remaining a passive backup asset. Con Edison is seeking vendors for the full program stack (enrollment, telemetry, real-time dispatch), implying a DERMS procurement requirement comparable to the EnergyHub/Tesla/Virtual Peaker model documented elsewhere in this log. The Commission separately approved National Grid’s transition to net load forecasting, incorporating behind-the-meter generation and storage into distribution peak projections — a methodology shift that will affect how NY utilities size future infrastructure investment relative to demand-side alternatives. (Source: New York Department of Public Service — July 9 entry)

Eversource’s substation-targeted load management pilots in Massachusetts pioneer dual-purpose DR — curtailing summer evening peaks while absorbing midday solar reverse-flow — at three Greater Boston substations plus a southeastern Massachusetts site. The ConnectedSolutions+ pilot enrolls roughly 2,800 behind-the-meter devices (thermostats, water heaters, EV chargers, batteries) across the Alewife, Hyde Park, and Dewar substations, while the companion Managed Charging+ pilot at the Industrial Park substation specifically incentivizes midday EV charging to absorb excess solar generation. Incentive rates are $400/kW for residential battery dispatch performance and $250/kW for commercial battery curtailment. This is a useful non-wires-alternative case study: the same DERMS-coordinated program design is being used to solve both a peak-demand problem and a high-solar-penetration reverse-flow problem on the same feeders, strengthening the avoided-cost argument for DERMS investment beyond single-purpose peak shaving. (Source: Utility Dive — July 8 entry)

Minnesota’s Xcel Energy Capacity*Connect Phase 2 — the $430 million, 200 MW utility-owned VPP first confirmed in the July 3 digest — drew formal opposition from SEIA and MnSEIA this week over ratepayer risk concentration. This is a movement update, not a new item: the PUC’s April 2 approval was already reported as a new confirmed deployment in last week’s digest. New this week is the trade-association pushback, arguing that Xcel’s utility-ownership model (batteries owned and operated directly by the utility rather than aggregated through third parties) shifts financial and operational risk onto ratepayers relative to market-based alternatives like the Google-Voltus BYOC deal or the Tesla/Sunrun/Renew Home framework. The implied cost of ~$2,150/kW installed is notably higher than LADWP’s ~$750/kW demand-response program cost (reflecting that CapacityConnect includes full battery hardware and installation, not just program administration), giving IRP teams a concrete comparison point between utility-owned distributed storage and traditional gas peakers ($800–$1,200/kW). (Source: Utility Dive — July 9 entry; movement update on July 3 digest coverage)*

DSIRE Insight/SEPA’s Q1 2026 VPP policy tracker confirms VPP deployment in 24+ states is now driven primarily by legislative and regulatory mandate rather than voluntary utility adoption — largely reaffirming the June 19/26 digest coverage, with Montana’s cooperative-utility VPP authorization as the notable new detail. Illinois’ S.B. 25 and Montana’s S.B. 487 were the two VPP-specific bills enacted in Q1; Montana’s law is the first VPP authorization specifically targeting the electric cooperative model that serves much of rural America, with cooperative programs beginning in 2027. Massachusetts’ 3.5 GW demand-management executive-order target (roughly 13.4% of New England’s 2025 peak demand) and Vermont Green Mountain Power’s Resilient Neighborhood 2.0 battery pilot were also reaffirmed. Lawrence Berkeley National Laboratory now counts approximately 180 VPP projects nationally with 19 GW of combined potential capacity. This tracker was already summarized in the July 3 digest’s June 29 entry coverage; it is noted here only for the Montana cooperative detail, which had not previously been called out. (Source: DSIRE Insight/SEPA — July 10 entry; deduplicated against July 3 digest coverage)

🔌 DERMS & Grid Integration Technology

A Forrester Consulting Total Economic Impact study of Schneider Electric’s EcoStruxure ADMS-with-embedded-DERMS platform — appearing twice in this week’s log — quantifies 184% ROI over five years, a $40.0 million NPV, and a 16-month payback for a composite 1.2-million-customer utility. The study models $61.8 million in risk-adjusted benefits against $21.8 million in costs, with the breakdown directly mapping to utility business-case categories: $18.7 million in deferred capital expenditure (leveraging DER flexibility to avoid grid upgrades), $12.1 million in DER integration time savings (17 hours saved per connection-analysis request), $21.1 million in field crew productivity (35% time reduction via mobile tools), $5.5 million in control-room optimization, plus smaller contributions from legacy-system retirement and avoided outage penalties. The 16-month payback compares favorably to the 10–20 year cost-recovery horizons typical of utility infrastructure investment, and the $18.7 million CapEx-deferral figure maps directly onto the avoided-cost framework this log’s IRP-focused readers rely on. TD World’s companion analysis this week reinforces the same conclusion from a different angle: DERMS platforms are migrating from innovation-budget pilots into formal 3-, 5-, and 10-year capital plans, earning the same institutional treatment historically reserved for SCADA — a reclassification that unlocks rate-base treatment and longer amortization schedules. Combined with GE Vernova’s GridOS for Distribution launch (covered in the July 3 digest), the DERMS market’s $1.7 billion 2026 valuation, projected to reach $5.5 billion by 2033, now has independent, vendor-validated ROI evidence behind it. (Source: Schneider Electric/Forrester Consulting — July 6 and July 10 entries, deduplicated; TD World — July 8 entry)

NERC’s 2026 Summer Reliability Assessment and FERC’s companion market assessment — synthesized in POWER Magazine’s “tail risk to design baseline” analysis — document 790 GW of net internal summer demand (up 10 GW year-over-year) against 58 GW of new on-peak capacity, 14.7 GW of which is batteries. The capacity mix entering summer 2026 is 16.4 GW solar, 14.7 GW batteries, 6.7 GW gas, and 1.6 GW wind. PJM’s demand response delivered more than 4,000 MW of load reduction during the June 2025 heat wave’s 162,401 MW peak (third-highest in PJM history) with no firm load shed — a concrete, NERC-referenced validation of DR effectiveness at scale that predates but directly parallels this week’s July 2026 heat wave events. The analysis also carries a drought warning relevant to resource adequacy planning: Lake Powell inflow is forecast at just 13% of average (lowest since 1964), putting up to 4,500 MW of Colorado River hydropower — including the 2,000 MW Hoover Dam — at risk by August, while Canadian hydropower exports to the U.S. fell 28% in 2025 to a 22-year low, reducing flexibility available to NYISO, ISO-NE, and MISO. For DERMS/ADMS procurement teams, the article frames Southern California Edison’s integrated GE Vernova deployment, PG&E’s three-release ADMS rollout, and utility-managed EV charging programs (PG&E WeaveGrid, SCE ORCHARD, Con Edison SmartCharge) as now-standard grid-adaptation tools rather than pilots — consistent with the capital-plan-migration theme documented above. (Source: POWER Magazine, NERC, FERC — July 7 entry)

🏗️ Data Centers & Large Load Growth

EEI confirmed the U.S. grid delivered a record 100,996 GWh of output during the week of June 28–July 4 — the first time weekly generation has exceeded 100,000 GWh — while more than 200 million Americans faced heat indices as high as 115°F. The new record beats the prior mark of 99,445 GWh (set during the July 2022 heat wave) by 1.6%, and represents output roughly 22% above average weekly generation and nearly double New York City’s annual electricity consumption. EEI frames the achievement around the $239 billion in 2026 utility capital investment ($1.4 trillion through 2030) that kept the lights on, but the same data validates the demand-side contributions this log has tracked all week: PJM’s 4,000+ MW of emergency demand response, DOE’s 202(c)-authorized backup generation curtailment, and distributed solar output that Grid Strategies confirmed was “consistently high every day” during peak demand. The grid held without firm load shed despite localized distribution-level flickering in Philadelphia, New York, and Cape Cod. For DSM/DR business case developers, EEI’s $239 billion annual capital-spending figure is a useful denominator: a $20 million, 70 MW DR portfolio represents less than 0.01% of that figure while potentially deferring supply-side expenditures orders of magnitude larger. (Source: PR Newswire/Edison Electric Institute — July 10 entry)

PJM wholesale prices tripled past $2,000/MWh on July 2 as operating reserves collapsed from 10,996 MW to 5,091 MW in a single day, and capacity clearing prices surged 11-fold to a record $333.44/MW-day — with Monitoring Analytics attributing 63% of that increase (~$9.3 billion) directly to data center demand growth. PJM’s demand peaked at approximately 163 GW on July 2, falling just short of the 165,563 MW 2006 all-time record but confirming that data center load growth has structurally eroded the margin separating normal summer peaks from record emergencies. PJM projects 32 GW of demand growth through 2030, with all but 2 GW attributable to data centers. This $9.3 billion capacity-cost figure, now landing on ratepayers across 13 states, is the most concrete “cost of insufficient demand-side investment” citation to reach this log — it converts the abstract avoided-cost argument DSM/DR business cases typically rely on into a documented, recurring charge. (Source: OilPrice.com, Yes Energy, Utility Dive — July 6 entry)

DOE issued its fourth Section 202(c) emergency order of the July heat wave for Duke Energy Carolinas and Duke Energy Progress on July 2, authorizing maximum generation output through July 6 as the Southeast faced a 36,196 MW peak. This extends the emergency framework beyond PJM into a second grid operator during the same heat event, following the PJM data-center-curtailment order, the PJM environmental-waiver order, and an earlier Duke order. The cumulative count of 202(c) orders issued in 2026 — spanning January cold, May maintenance, and the ongoing July heat wave — now approaches or exceeds the full-year 2025 total, confirming the pattern flagged in the July 3 digest: 202(c) authority has shifted from an exceptional single-event mechanism to a recurring, multi-regional operational backstop, with each invocation carrying direct costs (emissions waivers, backup diesel generation, administrative overhead) that a well-designed DR/VPP portfolio would avoid. (Source: DOE, CBS 17 — July 6 entry)

Marketplace’s post-weekend assessment credits solar with materially helping the grid survive the July 4th holiday heat wave, even as Philadelphia hit 101°F for three consecutive days — the first time since 1870s recordkeeping began. More than 20 cities hit record highs and roughly 160 million Americans across 30 states were under heat alerts through the holiday weekend. Grid Strategies’ Michael Goggin confirmed solar output was “consistently high every day” during peak demand periods in the Mid-Atlantic — a reliability contribution, not merely a baseload-displacement effect — directly supporting DERMS and VPP business cases that depend on solar-plus-storage availability during extreme events. The grid held overall but experienced localized distribution-level flickering in Philadelphia, New York, and Cape Cod, underscoring that much of the underlying distribution infrastructure is more than 50 years old and needs targeted investment (ADMS, DERMS, transformer upgrades, dynamic line rating) even where bulk-system reliability holds. (Source: Marketplace, AccuWeather — July 7 entry)

New Jersey’s legislature sent data center tariff bill A796/S731 to Governor Sherrill on June 30 — NRDC calls it “trailblazing” legislation that mandates demand response participation, an 85% take-or-pay commitment, and priority curtailment of data centers ahead of residential customers during emergencies. The bill applies to new and existing facilities at or above 50 MW (lowered from an original 100 MW threshold during negotiations) and aggregates related facilities under common ownership to prevent threshold avoidance. Unlike Virginia’s HB 284 (voluntary DR framework complicated by the EPA 50-hour rule, flagged in the July 3 digest), New Jersey’s bill makes DR participation a regulatory obligation for covered data centers — a more direct precedent for large-load DR mandates elsewhere. The bill also creates interconnection queue priority for projects committing to clean energy procurement and on-site storage, a pull-through mechanism for co-located DER development. As of this digest, the bill awaits the Governor’s signature; the signing decision is a direct next-step watch item. (Source: Utility Dive — July 8 entry)

PJM stakeholders approved a $555/MW-day cost-cap backstop reliability procurement mechanism on June 30, while the companion “connect and manage” large-load interconnection governance framework failed entirely — none of 11 competing proposals reached the required two-thirds vote. The approved backstop auction is designed to secure additional capacity commitments ahead of the December 9 Base Residual Auction for the 2029/2030 delivery year, with PJM’s board expected to submit a final proposal to FERC in July. The $555/MW-day cap (~$202,575/MW-year) is roughly 30 times the ~$66/kW-year avoided-cost value of demand-side resources under the Brattle methodology this log’s DSM business cases rely on — a stark, quotable ceiling-price benchmark for arguing DR/VPP cost-effectiveness in IRP filings. The interconnection-governance failure leaves unresolved who bears grid-upgrade costs when hyperscale loads connect, with direct implications for whether co-located DER and storage become conditions of future large-load interconnection agreements. (Source: Utility Dive/PJM Inside Lines — July 8 entry)

📋 Regulatory & Policy

This week’s coverage of FERC’s June 18 show-cause orders confirms a July 20 generation-adequacy report deadline (10 days from this digest) and details a “cost causer pays” framework requiring large loads to bear their own interconnection costs — both materially sharper than the July 3 digest’s ~July 18 estimate. The orders, issued to PJM, MISO, SPP, CAISO, ISO-NE, and NYISO under Section 206 of the Federal Power Act, define large load as ≥50 MW at >69 kV and require each RTO to justify or reform its tariff within 60 days (~August 17) across five areas: efficient study processes (including mandatory grid-enhancing-technology evaluation and 60–90 day study targets), cost-shift prevention via the cost-causer-pays framework, co-location and BTM generation rules, flexible transmission services for curtailable loads, and — the July 20 deadline specifically — generation adequacy reports demonstrating each RTO can serve both existing customers and new large loads. This generation-adequacy requirement creates a direct regulatory nexus for DER advocates: if RTOs must document adequacy before approving large-load interconnections, demand-side resources that reduce net load growth become a citable, discoverable component of that adequacy case. Separately noted this week: Virginia’s first-of-kind data center electricity consumption tax ($0.011/kWh) took effect July 1. (Source: Utility Dive — July 10 entry; date and framework detail update on July 3 digest coverage)

ERCOT’s Batch Zero PUCT vote, scheduled for June 18, remains unconfirmed after four consecutive weeks without a research-log entry — and if approved, developer submissions are now due July 15, just five days out from this digest. No entry from June 22 through July 10 has addressed the vote’s outcome. This is now the most time-sensitive unresolved item in the series and should be confirmed directly through the PUCT docket before next Friday’s run rather than waiting on the daily log, given the imminent submission deadline. (Note: no new log entry this week; carried forward from the July 3 digest as an escalating watch item.)

🏭 Utility Programs & Deployments

Pew Charitable Trusts’ DER policy playbook — first given full item-level treatment in this week’s log despite its April 28 publication date — frames distributed energy as the lowest-cost path to grid affordability, citing 6%+ national rate increases and 1-in-6 U.S. households behind on utility bills. The report organizes six recommendations across three goals (integrate DERs into utility planning and procurement, reduce permitting/interconnection barriers, strengthen community resilience) and includes an interactive state-by-state DER policy dashboard. This report’s dataset was previously cited only as a source link in the July 3 digest’s June 29 entry; this week’s July 6 entry gives it a full write-up with the affordability statistics above, which had not previously appeared in this series. The rate-increase and bill-delinquency figures are directly usable ammunition for DSM/DR program scope justifications before state PUCs, since demand-side resources both reduce system costs and provide direct bill relief to enrolled customers. (Source: Pew Charitable Trusts — July 6 entry)

🔬 EPRI Research Spotlight

EPRI’s Powering Intelligence 2026 report revised its national data center load forecast 60% upward from 2024 estimates, projecting U.S. data centers will consume 9–17% of national electricity by 2030 — with Virginia’s current 25% share potentially reaching 41–59%, and seven additional states (Arizona, Indiana, Iowa, Nebraska, Nevada, Oregon, Wyoming) possibly exceeding 20% by the same year. The 60% upward revision is itself the headline finding: EPRI’s methodology now uses commercial project development data rather than industry self-reporting, which had historically inflated projections in the opposite direction from what actually happened here — the revision confirms load growth is accelerating faster than even EPRI anticipated 18 months ago. The state-level detail is the most actionable element for capacity planning: the seven newly flagged states have not yet experienced the large-load interconnection pressure concentrated in PJM and Dominion territory, meaning DERMS and DR program design conversations are about to expand into ISOs and utilities without prior large-load DR program experience. EPRI also notes AI workloads currently represent only 15–25% of data center electricity consumption but are growing at disproportionately faster rates with higher per-rack power density — meaning total GW figures understate the operational complexity distribution systems and DERMS platforms must accommodate. This 60% revision directly increases the avoided-cost denominators used throughout this log’s IRP-focused DSM/DR business cases, since the cost of new generation, transmission, and distribution infrastructure to serve data center load is the baseline against which demand-side alternatives are measured. (Source: EPRI — July 9 entry)

Watch for EPRI comment filings in FERC’s 60-day tariff-revision proceedings (due ~August 17); EPRI’s revised state-level scenario data will be directly relevant as RTOs define “flexible large load” tariff categories in response to the July 20 generation-adequacy reports.

🚩 Utility-Sector Relevance Flags

⚑ EEI’s 100,996 GWh Weekly Record: The Grid Held, But the Margin for Error Is Now Documented as Thin
Topic: Reliability / Demand Response Validation / Capacity Planning
Relevance: The first-ever week above 100,000 GWh of national output, delivered without firm load shed despite PJM approaching an all-time peak record, validates that demand response, distributed solar, and DOE emergency intervention are jointly sufficient at current penetration levels — but EEI’s own framing implies any one pillar failing would have produced a different outcome.
Action Signal: Watch — Use the 100,996 GWh figure and the $239B annual utility capital-investment context as a citable “system worked, but margins are thin” data point in IRP filings arguing for continued DR/VPP program expansion rather than complacency.

⚑ Illinois ICC VPP Tariff Approved: The First State-Mandated Benchmark Is Now Live
Topic: VPP / Program Design / Regulatory Precedent
Relevance: ComEd’s Scheduled Dispatch VPP tariff, approved June 30, is the first state-mandated VPP tariff to clear final approval in the current cycle — resolving a watch item flagged as overdue for three consecutive digests and giving Virginia, New Jersey, Massachusetts, and Maryland proceedings a concrete reference design (five-season commitment, seasonal performance payments, CRGA’s 3 GW storage mandate).
Action Signal: Engage — Utilities in states with pending VPP legislation should benchmark program design (commitment structure, payment mechanism, DERMS platform requirements) against ComEd’s now-approved tariff terms.

⚑ ERCOT Batch Zero: Five Days to a Developer Deadline With No Confirmed Vote
Topic: Regulatory / Large Load / Interconnection
Relevance: The scheduled June 18 PUCT vote remains unconfirmed after four consecutive weeks without a log entry, and the associated July 15 developer submission deadline (if approved) is now imminent. This is the most time-sensitive unresolved item in the series.
Action Signal: Watch — Confirm directly via the PUCT docket before next Friday’s digest; do not wait on the daily research log for this item given the imminent deadline.

⚑ FERC July 20 Generation-Adequacy Deadline: Confirmed Date, 10 Days Out
Topic: Regulatory / Large Load / IRP
Relevance: This week’s coverage sharpens the deadline from the July 3 digest’s ~July 18 estimate to a confirmed July 20, alongside new detail on the “cost causer pays” cost-shift framework. All six RTOs must disclose, in their own words, where generation adequacy is tightest — a directly citable input for pending IRP avoided-cost filings.
Action Signal: Implement — Monitor each RTO’s July 20 filing directly upon release; incorporate disclosed adequacy gaps into IRP filings and DR program cost-effectiveness analyses as they publish.

⚑ Google/Voltus BYOC: A Second, Structurally Distinct Hyperscaler-VPP Model
Topic: VPP / Program Design / Competitive Benchmarking
Relevance: Alongside the Tesla/Sunrun/Renew Home 16.8 GW capacity-transfer framework (July 3 digest), Google’s sleeved BYOC deal with Voltus establishes a second commercial template for hyperscaler-funded VPPs — this one financing third-party aggregation directly rather than transferring capacity from device manufacturers.
Action Signal: Engage — PJM-territory utilities with hyperscaler customers now have two live commercial templates (capacity-transfer and BYOC-sleeved) to evaluate against locally negotiated alternatives before backstop-auction capacity is captured by either model.

⚑ PJM’s $555/MW-Day Backstop Cap: A 30x Ceiling-Price Benchmark for DR Cost-Effectiveness
Topic: Capacity Markets / DR Capacity Value / IRP
Relevance: The approved backstop procurement cap (~$202,575/MW-year) is roughly 30 times the ~$66/kW-year avoided-cost value of demand-side resources under the Brattle methodology — a stark, board-ready number for arguing DR/VPP cost-effectiveness against supply-side reliability procurement.
Action Signal: Implement — Cite the 30x ratio directly in IRP filings and capacity-planning presentations arguing for prioritizing DR/VPP investment ahead of backstop-auction supply-side procurement.

⚑ EPRI’s 60% Upward Load Revision: Seven New States Enter the Large-Load Planning Conversation
Topic: Data Centers / Capacity Planning / IRP
Relevance: Arizona, Indiana, Iowa, Nebraska, Nevada, Oregon, and Wyoming may all exceed 20% data center electricity share by 2030 — a set of states without the large-load DR program experience already built up in PJM and Dominion territory.
Action Signal: Engage — Utilities in the seven newly flagged states should begin scoping large-load DR/DERMS program design now, using PJM/Dominion program templates as a starting reference rather than building from scratch once load materializes.

⚑ New Jersey Data Center Tariff Bill: Awaiting Governor’s Signature
Topic: Regulatory / Large Load / Demand Response Mandates
Relevance: A796/S731 would make New Jersey the first state after Illinois this cycle to mandate (not merely incentivize) data center DR participation, with priority curtailment ahead of residential customers during emergencies — a template Virginia’s voluntary HB 284 approach does not provide.
Action Signal: Watch — Confirm the Governor’s signing decision before next week’s digest; if signed, compare enforcement and DERMS integration requirements against the now-approved Illinois ICC tariff.

📌 Sources

July 10, 2026 Entry
– PR Newswire / Edison Electric Institute — America’s Electric Grid Delivered Record-Breaking Output as Heat Dome Blanketed the Nation (July 9, 2026)
– Schneider Electric Blog / Forrester Consulting — Unlocking Grid Efficiency and ROI: Findings from a Forrester TEI Study of EcoStruxure ADMS with Embedded DERMS (July 3, 2026)
– Utility Dive — 6 Takeaways from FERC’s Data Center Interconnection Decision (June 22, 2026)
– DSIRE Insight / NC Clean Energy Technology Center / SEPA — VPP and Supporting DER Policy Developments: Q1 2026 (May 13, 2026)

July 9, 2026 Entry
– BusinessWire / Utility Dive — ComEd Receives Approval to Launch its First Virtual Power Plant Program for Customers in 2027 (June 30, 2026)
– EPRI — Powering Intelligence 2026: Data Center Load Growth in Context
– New York Department of Public Service — Commission Improves Customer-Centered Electric Demand Response Programs (April 16, 2026)
– Utility Dive — Minnesota Approves Xcel’s Controversial Utility-Owned Virtual Power Plant (April 2, 2026)

July 8, 2026 Entry
– Utility Dive — Eversource Launches Targeted Load Management Pilots in Massachusetts (July 1, 2026)
– Utility Dive — New Jersey Lawmakers Send Data Center Tariff Bill to Governor (July 1, 2026)
– Utility Dive / PJM Inside Lines — PJM Backstop Procurement, Connect and Manage, Data Centers (June 30, 2026)
– TD World — Why DERMS Is Earning a Place Alongside SCADA (2026)

July 7, 2026 Entry
– Marketplace — Power Grid Put to the Test During Weekend Heat Wave (July 6, 2026)
– AccuWeather — Heat Wave Raises Power Grid Concerns as Outages Exceed 100,000 Nationwide (July 2026)
– 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 Announce Bring Your Own Capacity Agreement (June 2, 2026)
– Data Centre Magazine — Google: Turning to Virtual Power Plants for Data Centres (June 2026)
– POWER Magazine — From Tail Risk to Design Baseline: How the Grid Is Adapting to Extreme Heat (June 9, 2026)
– NERC — 2026 Summer Reliability Assessment (May 19, 2026)
– FERC — 2026 Summer Energy Market and Electric Reliability Assessment (May 21, 2026)
– IEA — Global Energy Review 2026: Technology: Battery Storage (2026)
– IEA — Global Energy Review 2026: Key Findings (2026)
– Energy Industry Review — Battery Storage Capacity: Record Growth and Trends in 2026

July 6, 2026 Entry
– OilPrice.com — Power Prices Triple on PJM as Heat Wave and Data Centers Collide (July 3, 2026)
– Yes Energy — PJM Is About to Set an All-Time Record (July 2026)
– Utility Dive — Heat Wave Tests Power Grid as PJM Anticipates New Record (July 2026)
– Schneider Electric — Forrester TEI Study Full Report (October 2025)
– DOE — Energy Secretary Secures Carolinas’ Grid Amid Period of Hot Weather (July 2, 2026)
– DOE — 2026 DOE 202(c) Orders
– CBS 17 — Emergency Order Issued for Duke Energy Amid North Carolina Heat Wave (July 2, 2026)
– Pew Charitable Trusts — Distributed Energy Can Unleash the Resilient, Affordable Grid of the Future (April 28, 2026)
– Pew — Press Release: Pew Report Charts Path to Accelerate Use of Distributed Energy Nationwide (April 28, 2026)
– Pew — Explore How States Are Advancing Distributed Energy (Interactive Dashboard)