All five weekday entries (Monday July 27 through Friday July 31) are present in the research log. This digest covers them in full. Several items required consolidation: the Bank of America 230-GW capacity-gap forecast appeared in both the July 28 and July 31 entries (deduplicated — and it was already covered in the July 24 digest, so it is treated as context here); the “DERMS moves from innovation budget to capital plan” theme appeared in both the July 29 (GE Vernova GridOS) and July 31 (T&D World) entries and is consolidated below; the NERC 2026 State of Reliability report and the FERC ISO-NE Order 2222 approval re-surfaced from last week’s digest and are covered only for their new details. The headline development this week is external: last week’s #1 open action — pulling the six RTO/ISO generation-adequacy reports filed July 20 in Dockets EL26-67 through EL26-72 — is now resolved via NEPOOL counsel’s July 23 summary memo, and the contents (led by ISO-NE’s proposal to exclude large loads from its capacity market entirely) are the most consequential regulatory material this series has carried in weeks.
The six generation-adequacy reports FERC ordered from every RTO/ISO — filed July 20, summarized July 23 by NEPOOL counsel, and absent from both the daily log and trade press until this series pulled them directly — reveal a structural divergence in how organized markets intend to absorb large loads. ISO-NE goes furthest: a “bring your own new generation” (BYONG) requirement for new large loads paired with excluding them from the Installed Capacity Requirement altogether, so the capacity market simply will not procure on their behalf — detailed rules coming in 2027, with SPP’s CHILLS conditional-service model (effective July 1) cited as the template. MISO files its Zero Injection GIA on or about July 31 and a 120-day Large Load Parallel Study Process by end-September; PJM files its Reliability Backstop Procurement proposal on or about July 31 and an insufficient-resource-adequacy service framework August 7; SPP is building a Price Adaptive Load service for large, fully dispatchable loads (filing by November 16); CAISO targets a November 16 filing; NYISO files around March 2027 and is considering assigning resource-deficiency responsibility directly to the large loads that cause it. Every one of these mechanisms — conditional service, curtailment obligations, load-generation pairing, price-adaptive dispatchability — converts load flexibility from a program nicety into a condition of interconnection, which is the strongest structural tailwind yet for the DERMS-orchestrated flexibility this series tracks. The week’s operational proof point runs the other direction: Green Mountain Power’s VPP is now Vermont’s largest single power resource at 110 MW, dispatched 90 MW during the early-July heat wave to save customers an estimated $6 million, and has already retired two peaker plants permanently. And the week’s caution is quantified: North America’s VPP fleet grew only 13.7% to 37.5 GW — a pace that recedes from DOE’s 80–160 GW-by-2030 target — with compensation adequacy named as the binding constraint.
🔋 Energy Storage
No standalone storage item entered the log this week; storage developments ran through the VPP and DERMS threads instead. The notable storage-adjacent facts: Green Mountain Power’s 110-MW VPP (below) is anchored by 53 MW of residential batteries — 10,000+ units across 5,000+ customers — now supplying nearly 10% of Vermont’s summer peak, the highest storage-to-state-peak ratio in New England; and the SEPA Q2 roundup’s live battery-VPP compensation benchmarks (DTE’s proposed $105/kW-year residential battery pilot, Hawaii’s performance-prioritized edge-DERMS design) give storage-program planners current, citable per-kW anchors. (Sources: Electrek — July 30 entry; SEPA — July 27 entry)
⚡ Virtual Power Plants (VPP) & Demand Flexibility
Green Mountain Power’s VPP is now Vermont’s largest single power resource — 110 MW, dispatching 90 MW during the early-July heat wave to cut an estimated $6 million from all customers’ peak costs (after $11 million the prior year), and enabling the permanent retirement of peaker plants in Vergennes and Rutland through the ISO-NE process. This is the clearest operational realization of the avoided-cost thesis this series has carried: energy-cost avoidance, capacity value, and generation deferral, all realized in dollars rather than modeled. The 90-MW dispatch was roughly equivalent to removing 50,000 homes from the grid at peak; the program’s tariffed design ($55/month two-Powerwall lease or $5,500 upfront, plus a bring-your-own-device path) is a replicable regulatory template; and the peaker retirements — with more planned — are a documented substitution of demand-side flexibility for dispatchable-generation CapEx. For IRP work, GMP is the reference case that converts the ~$66/kW-year avoided-capacity benchmark from a modeling assumption into a demonstrated outcome. (Source: Electrek — July 30 entry)
Against that proof point, Utility Dive’s scaling analysis lands the week’s caution: North American VPP capacity grew just 13.7% over the past year to 37.5 GW, a pace that leaves DOE’s 80–160 GW-by-2030 target increasingly out of reach — and the binding constraint is compensation adequacy, whether energy, capacity, and ancillary-service payments at wholesale and retail are rich enough to sustain enrollment. This is the demand-side mirror of the supply-side capacity gap: the flexibility exists, but the market-design and tariff signals to mobilize it lag — the same market-signal failure PJM’s capacity auction quantified last week when DR cleared fell 277 MW at the price cap. Read together with GMP, the lesson is program design: the VPPs that scale are tariffed, performance-paid, multi-year utility constructs, not merit-order hopefuls waiting on wholesale price signals. (Source: Utility Dive — July 31 entry)
The state-policy scaffolding for exactly those constructs thickened measurably this week, across three separate items. SEPA’s Q2 2026 VPP policy roundup catalogs the wave: Hawaii’s PUC (Docket 2026-0084) specified a VPP grid-services program built on remote dispatch “managed by a 3rd-party edge DERMS agent, selected competitively” with a five-year minimum term and performance-prioritized compensation — a procurement template utilities can lift directly; Illinois approved ComEd’s and Ameren’s Rider SDVPP scheduled-dispatch tariffs plus a bring-your-own-device load-reduction program; Michigan’s DTE proposed a $105/kW-year residential battery VPP; Louisiana approved Entergy’s $81M 2026–2030 DR suite; and Maryland’s PSC ordered BGE, Delmarva, and Pepco to align interconnection tools and DERMS timelines with forthcoming VPP applications. Pew’s July 23 synthesis adds two IRP-integration landmarks: Colorado approved Xcel’s Aggregator VPP — third-party aggregators bundling batteries, smart devices, and water heaters into VPPs weighed against conventional resources in the IRP, 25 MW/year toward 125 MW by 2030 (distinct from the utility-owned Capacity*Connect program this series watches) — and Illinois S.B. 25 now requires utilities to include VPPs in ICC-reviewed IRPs. And New Jersey’s BPU released a VPP straw proposal (Docket QO26030099) under Gov. Sherrill’s January energy-emergency executive order, with a statutory definition that reads like this series’ thesis verbatim — aggregated DERs that “can defer or avoid transmission or distribution upgrades, providing savings to the ratepayer” — enrollment either directly with utilities or through aggregators, and a July 30 stakeholder meeting opening a three-year program-design window. A high-cost, import-dependent PJM state treating demand-side flexibility as a front-line affordability tool is the political tell. (Sources: SEPA/NCCETC — July 27 entry; Pew Charitable Trusts — July 30 entry; ROI-NJ — July 29 entry)
Eversource and National Grid added vehicle-to-grid EVs to ConnectedSolutions — the 280,000-DER, 800+ MW, five-state demand-response VPP EnergyHub orchestrates — enrolling V2G-capable cars through The Mobility House’s platform as diversified flexible capacity inside the existing pool rather than a standalone dispatch asset. The design choice is the story for DERMS procurement: folding EV batteries into a heterogeneous flexibility portfolio alongside thermostats, home batteries, and C&I load is exactly the aggregation model a mature DERMS exists to run, and the three-vendor value chain (EnergyHub as DERMS spine, Mobility House as V2G platform, utility program wrappers) confirms grid-edge VPP delivery is now a multi-party integration problem. Eversource’s “ConnectedSolutions+” tier paying enhanced incentives in grid-constrained areas is early locational value-stacking of DR — the refinement that strengthens avoided-T&D arguments in IRP filings — and National Grid’s parallel fleet V2G (starting with school buses) extends last week’s MassCEC school-bus economics ($12K/year) into an operating utility program. (Source: Energy-Storage.News — July 28 entry)
Puget Sound Energy’s 2026 Demand Response RFP is a working template for DR procurement mechanics: net-new, turn-key flexible capacity on top of an existing 129-MW portfolio, a required pathway to ≥50 MW by 2030, no duplication of existing program participation, and — the DERMS thread made explicit — a requirement that bidders “provide integration solutions to PSE’s enterprise systems.” Multi-aggregator bids must name a single primary contract owner accountable for firm capacity commitments, reflecting the M&V and reliable-dispatch rigor regulated DR must meet to count as accredited IRP capacity. The dual-peak (winter and summer) framing and the incrementality requirement — new DR must not cannibalize existing enrollment — are directly liftable into other utilities’ solicitations. (Source: Puget Sound Energy — July 28 entry)
🔌 DERMS & Grid Integration Technology
DERMS crossed the procurement-maturity threshold in 2026 — two independent items this week (consolidated) document utilities moving DERMS out of the innovation budget and into the capital plan alongside ADMS, substation automation, and AMI, writing procurement specs that demand SCADA-grade 24/7 reliability, defined response times, and failover/redundancy, in a market growing to roughly $935M this year from ~$780M in 2025. T&D World’s editorial establishes the specification bar second-generation DERMS must clear: interoperability with adjacent OT systems (ADMS, OMS, GIS, SCADA), scalability to arbitrary endpoint counts, and coordination of grid-side and customer-side assets in integrated workflows — with the NERC Category 2 registration effective date (May 15, 2026) tightening visibility expectations as aggregated resources enter wholesale markets. GE Vernova’s GridOS for Distribution is the platform-architecture marker of the same shift — ADMS, DERMS, network modeling, field execution, and visual intelligence unified on one AI-ready foundation rather than a DERMS module bolted onto legacy ADMS — and, notably, resolves a standing watch item in this series: GE Vernova’s competitive response on the DERMS layer, previously unlogged, is now on the record. For DSM/DR business cases the implication is direct: the orchestration layer that converts enrolled flexibility into accredited, dispatchable capacity is now being funded as durable infrastructure, de-risking the M&V and dispatch-reliability assumptions the avoided-cost value stack rests on. (Sources: T&D World — July 31 entry; GE Vernova — July 29 entry; consolidated)
Order 2222 implementation now converges across the eastern markets by year-end: FERC’s May 29 approval of ISO-NE’s revised DER-aggregation rules (covered last week for the NRC/CNRC qualification fix) sets energy and ancillary-services participation for November 1, 2026 — and the new detail this week is the full convergence timeline, with PJM targeting Q1, ISO-NE November 1, and NYISO Q4. Within a single planning cycle, DER aggregations across most of the eastern US will compete against conventional generation for energy, capacity, and ancillary-service revenue. FERC’s earlier 3-1 concern that ISO-NE’s metering and telemetry requirements could unduly bar individual DERs from aggregations frames the design tension every DERMS procurement should anticipate: participation thresholds low enough to aggregate small resources, measurement rigor high enough to satisfy market operators. (Source: Troutman Pepper — July 31 entry; movement on ISO-NE Order 2222 watch item, previously covered)
🏗️ Data Centers & Large Load Growth
PG&E’s Q2 disclosure is the West-Coast counterpoint to the PJM cost-shift narrative: a 12.7-GW data-center pipeline (490 MW under executed interconnection agreements, 3.9 GW in final engineering) that the utility deliberately vets “for quality, not size” — expecting to actually serve just 1.8 GW of new data-center load by 2030, priced to be rate-reducing for other customers, inside a $73B five-year capital plan. The pipeline’s volatility under stricter methodology (7.3 GW → 5.4 GW → retroactively 5.1 GW before rebounding) is a caution against planning on queue figures anywhere, and the compositional shift matters for distribution planning: sub-gigawatt “smaller” data centers now dominate PG&E’s queue, and many mid-size interconnections stress feeders and hosting capacity differently than a few hyperscale campuses — pulling DERMS coordination and locational hosting-capacity analysis into the load-serving conversation. (Source: Utility Dive — July 27 entry)
Texas hard-wired cost-causation and demand flexibility into large-load interconnection: the PUCT’s post-Abbott-directive roadmap requires large loads to post financial security and pay direct interconnection costs (rulemaking complete by December), evaluates 75-MW-plus loads collectively through ERCOT’s “Batch Zero” study allocating transmission capacity by location and year through 2032, and is building the Senate Bill 6 reliability program that pays large users to curtail before grid emergencies. This is movement on the ERCOT Batch Zero watch item, and the SB6 program is the operative DR fact: institutionalizing large-load curtailment as a planned, compensated reliability resource — with required disclosure of curtailment and backup-generation capability — is the state-level analogue of the flexible-load categories FERC’s show-cause orders are forcing on the RTOs. Completed actions already bar redirecting existing generation to serve new data centers. (Source: Data Center Knowledge — July 30 entry; movement on watched item)
GE Vernova’s gas-turbine backlog jumped to 116 GW from 100 GW in Q1 — shipping 3 GW in the quarter while booking 20 GW of orders, now taking 2031 delivery reservations with slots more than half-booked and lead times running four to five years, matching Siemens and Mitsubishi. Roughly 20% of demand now comes from ~100 data-center customers across 26 countries; analyst pricing runs ~$790/kW for heavy-duty turbines to ~$1,800/kW for aeroderivatives. This is hard market confirmation of the series’ central benchmark: demand response and efficiency (~$20.70/MWh versus $45–108/MWh new combined-cycle) deploy in months against a half-decade turbine queue — the firm-supply path is not just expensive but unavailable inside the planning window in which the 100+ GW capacity gap must be managed. (Source: Utility Dive — July 27 entry)
Adequacy context (deduplicated, previously covered): the Bank of America forecast — 230+ GW needed by 2030 against ~93 GW of accredited utility additions, ~125 GW of data-center load driving a 4.1% demand CAGR, 7.5+ GW of behind-the-meter data-center generation under construction with 60+ GW pre-construction, coal life-extensions across seven states — re-surfaced in both the July 28 and July 31 entries; it was covered in the July 24 digest and remains the standing scarcity citation. Similarly, NERC’s 2026 State of Reliability report re-surfaced with new detail worth logging: beyond the EFOR spike to 9.2% covered last week, the report documents ~1,800 MW (February 2025) and ~1,300 MW (June 2025) customer-initiated data-center load-drop events, nine ERCOT crypto load losses over 100 MW, an EPRI-identified ride-through root cause, and draft Rules of Procedure creating a new computational-load registered-entity category — the standards trajectory feeding the August comment window. (Sources: Utility Dive — July 28/July 31 entries; Data Center Knowledge — July 30 entry; both previously covered)
📋 Regulatory & Policy
The six RTO/ISO generation-adequacy reports (filed July 20, Dockets EL26-67 through EL26-72) are now summarized — resolving this series’ #1 open action via NEPOOL counsel’s July 23 memo, since neither the daily log nor trade press captured their contents — and they sketch six different answers to the same question, with load flexibility embedded in nearly all of them. All six operators report near-term adequacy but concede the speed, scale, and concentration of large loads require new tools. The divergences are the story. ISO-NE proposes the most radical construct: new large loads must “bring their own new generation” (BYONG) and are excluded from the Installed Capacity Requirement entirely — the capacity market will not procure on their behalf; they bring supply or accept curtailment, on the model of SPP’s CHILLS (effective July 1: long-term non-firm energy service, seven-year maximum, ahead of upgrades). MISO files its Zero Injection GIA (co-located generation that never injects to the grid, studied at substation scope) on or about July 31 and a 120-day Large Load Parallel Study Process (loads ≥250 MW paired with generation capped at 150% of load) by end-September. PJM confirms its Reliability Backstop Procurement filing on or about July 31 with the insufficient-resource-adequacy framework — requiring under-supplied large loads to reduce withdrawals before other load is curtailed — following August 7. SPP is developing a Price Adaptive Load / PAL Service market-participation model for large, price-responsive, fully dispatchable loads (filing by November 16), plus a pending Reliability-Registered Demand Response Program (requested effective January 1, 2027). CAISO routes compliance through its Large Load stakeholder initiative (straw proposal August 12, Board October 28, FERC filing November 16). NYISO targets a March 2027 filing and is weighing assigning resource-deficiency responsibility to the specific large loads that cause it. The through-line for this series: every regional answer makes flexibility, curtailability, or self-supply a condition of large-load service — structurally raising the value of the DERMS, telemetry, and M&V infrastructure that proves a load can actually deliver the flexibility its service depends on. (Source: Day Pitney NEPOOL memo, July 23 — external docket pull; resolves carried backfill item)
FERC Chairman Laura Swett gave PJM until the end of September to adopt governance and stakeholder reforms — or the Commission will impose them — framing the RTO’s “grave legitimacy crisis” as the direct product of two data-center-driven capacity auctions that cleared at scarcity prices yet summoned almost no new supply. Consensus reforms include a MISO-style advisory stakeholder process (ending sector-weighted two-thirds voting), a more independent board, Section 205 filing rights for PJM states (which they uniquely lack), and codifying “public interest” in PJM’s mission; new CEO David Mills says PJM is “fully committed,” and AEP has openly floated leaving. For DR/DERMS practitioners, governance is upstream of market access: a board empowered to act in the public interest and states able to file at FERC are likelier to open capacity and interconnection pathways to demand-side and aggregated resources than the member-captured process that produced two failed auctions. Note the calendar collision: PJM’s governance deadline, its RBP filing, its market-design workshops, and the show-cause answer date (August 17) all land within seven weeks. (Source: Utility Dive — July 27 entry)
DOE issued its second Section 202(c) emergency order in roughly two weeks — Order No. 202-26-37 to the Southwest Power Pool (July 26, expiring August 3), at SPP’s own request, directing dispatch of specified units and authorizing backup generation to run as a last resort before an EEA-3 — and put a number on the latent flexibility pool: more than 35 GW of unused backup generation nationwide. The recurrence pattern (PJM July 14–21, now SPP) confirms 202(c) as a standing summer operational tool, and the 35-GW figure quantifies exactly the resource this series has argued should be converted from emergency-only dispatch into programmatic, DERMS-orchestrated demand response — capacity that already exists, interconnects behind the meter, and deploys in seconds, sitting outside every market construct. (Source: American Public Power Association — July 29 entry; movement on 202(c) recurrence watch item)
Columbia’s Center on Global Energy Policy supplies the affordability frame for all of it: data-center bill increases aren’t inevitable — demand response and grid-enhancing technologies can blunt near-term price pressure — but only if regulation stops rewarding capital deployment over system optimization. With IOUs seeking a record $18B in rate increases last year (66% of requested dollars approved) and data centers projected at 9.5–15.3% of US load by 2030 (from 4.7% in 2024), the structural critique lands on the mechanism this series keeps encountering: cost-of-service returns of ~9–10% on capital systematically under-reward DR and GETs, and the ~$130M-net-benefit class of DR portfolio stays uncaptured until performance-based regulation or alternatives-evaluation mandates change the incentive. This is the citable articulation of why operationally superior demand-side resources chronically under-deploy — useful in any PUC filing proposing shared-savings or PBR treatment for DSM. (Source: Utility Dive/Columbia CGEP — July 28 entry)
🔬 EPRI Research Spotlight
No new EPRI-sourced research entered the log for the third consecutive week, and a direct check of EPRI’s press room confirms no major announcement since the Flex MOSAIC framework (March) and the nine-site DCFlex expansion (February). EPRI’s fingerprints are nonetheless on two of this week’s items: NERC’s 2026 State of Reliability report attributes the data-center ride-through diagnosis — the root cause behind the 1.8-GW and 1.3-GW load-drop events — to EPRI research, and that finding now feeds NERC’s draft computational-load registered-entity category. The standing watch holds: the 45-day comment period on NERC’s computational-load draft standards opens in August (Board approval targeted December 5), and EPRI’s DCFlex demonstration data (Emerald AI/Silicon Valley Power; the 96-MW Aurora AI Factory in Manassas, online late 2026) remains the most likely technical reference framework in that record. With the log dry, next run should check EPRI.com directly again.
🚩 Utility-Sector Relevance Flags
⚑ ISO-NE’s BYONG + Capacity-Market Exclusion: The Most Radical Large-Load Construct Yet
Topic: Capacity Market Design / Large Load / Cost Allocation
Relevance: ISO-NE proposes that its capacity market simply not procure for new large loads — they bring their own new generation or accept curtailment, on SPP’s CHILLS model — the fullest expression of cost-internalization on the table anywhere, and one that makes demonstrated load flexibility the price of admission for large loads in New England. Detailed rules come in 2027.
Action Signal: Engage — New England utilities and aggregators should enter the 2027 rules process early; everywhere else, treat BYONG as the outer bound of the construct spectrum when modeling large-load tariff scenarios, and note ISO-NE’s parallel demand-flexibility workstream with the states as the DER hook.
⚑ The Adequacy-Report Filing Calendar: Five FERC Filings in the Next 16 Weeks
Topic: Regulatory / Large Load / Market Design
Relevance: PJM’s RBP (~July 31) and insufficient-RA framework (Aug 7), MISO’s ZGIA (~July 31) and Parallel Study Process (end-September), SPP’s PAL/PALS and CAISO’s compliance filing (both November 16) will define large-load flexibility obligations market by market — each a distinct venue where flexible-load and DER interests need representation. Show-cause answers remain due August 17, stakeholder comments September 16 (Category 4 = flexible load), abeyance requests August 3.
Action Signal: Engage — Calendar all five filings for review on docket posting; prepare September 16 comments centered on flexible-load definitions; MISO-footprint utilities should evaluate ZGIA applicability to customer co-generation proposals immediately.
⚑ PJM Governance Ultimatum: End of September or FERC Imposes Reforms
Topic: RTO Governance / Market Access
Relevance: Section 205 filing rights for states, an advisory stakeholder model, and a public-interest mandate would each independently improve demand-side resources’ market access in PJM; the deadline stacks onto the RBP filing, the September backstop auction, and the show-cause calendar in a seven-week crunch.
Action Signal: Watch — Governance outcome determines whether the DR-hostile auction results of 2026 get structural remedy; PJM-state utilities should brief commissions now on what Section 205 rights would enable.
⚑ New Jersey VPP Straw Proposal: A Three-Year Program-Design Window Just Opened
Topic: VPP Program Design / State Policy / Avoided-T&D Value
Relevance: The statutory VPP definition — aggregated DERs that “defer or avoid transmission or distribution upgrades” — writes the avoided-cost thesis directly into program law, and the dual utility/aggregator enrollment design puts DERMS interoperability at the center. Docket QO26030099’s design choices (compensation levels, utility-vs-aggregator roles) will become the PJM-state reference just as ComEd’s SDVPP is for tariffed dispatch.
Action Signal: Engage — Participate in the BPU stakeholder process; utilities in other PJM states should track the compensation design as the emerging benchmark for affordability-framed VPP programs.
⚑ DERMS Is Now Capital-Plan Infrastructure With SCADA-Grade Specs
Topic: DERMS Procurement / Grid Modernization
Relevance: The ~$935M 2026 market, SCADA-grade reliability specifications (24/7, response times, failover), and GE Vernova’s unified GridOS platform (resolving a standing watch item) together mark the end of DERMS-as-pilot. Procurement leverage now favors utilities that specify second-generation requirements — interoperability, endpoint scalability, grid-and-customer-side coordination — rather than accepting bolt-on modules.
Action Signal: Implement — Write SCADA-grade reliability, OT interoperability (ADMS/OMS/GIS/SCADA), and Order 2222 registration/M&V support into any active DERMS RFP; use PSE’s enterprise-integration requirement and Hawaii’s competitively procured edge-DERMS-agent model as drafting references.
⚑ GMP’s VPP: The Operational Citation for Every Avoided-Cost Filing
Topic: VPP Value Realization / IRP / Non-Wires Alternatives
Relevance: $6M realized in one heat wave ($17M over two years), 110 MW as the state’s largest resource, ~10% of state summer peak, and two permanently retired peakers — the complete avoided-cost stack (energy, capacity, generation deferral) realized in dollars through a replicable tariffed design.
Action Signal: Implement — Cite GMP alongside the PJM $555–$777/MW-day scarcity anchors in IRP demand-side justifications: one quantifies scarcity value, the other proves programmatic capture; the $55/month lease construct is the enrollment template.
⚑ VPP Growth at 13.7% vs the DOE Target: Compensation Adequacy Is the Binding Constraint
Topic: VPP Scaling / DR Compensation / Program Strategy
Relevance: 37.5 GW against an 80–160 GW-by-2030 target quantifies the enrollment shortfall, and the diagnosis — inadequate energy/capacity/ancillary compensation at both wholesale and retail — matches PJM’s cleared-DR decline at the price cap. The programs scaling (GMP, ConnectedSolutions, SDVPP) are tariffed and performance-paid, not wholesale-signal-dependent.
Action Signal: Watch — Benchmark program compensation against the live 2026 set (DTE $105/kW-yr; MassCEC $3K/summer V2G; GMP lease; ComEd seasonal performance payments); under-compensated programs will show up as under-enrollment before they show up in evaluations.
⚑ Second 202(c) in Two Weeks + a 35-GW Latent Backup Fleet
Topic: Emergency Authority / Backup Generation / DR Conversion
Relevance: DOE’s own >35 GW estimate of unused backup generation quantifies the largest untapped DR resource in the country, currently reachable only through emergency orders at ~$550M/year in ratepayer cost. Texas’s SB6 program and PJM’s insufficient-RA framework are both converting the same latent capacity into planned, compensated flexibility.
Action Signal: Engage — Utilities should inventory interconnected backup generation in their territories and scope enrollment/telemetry requirements for programmatic dispatch; the SPP order expires August 3 — watch for a third order as the recurrence test.
📌 Sources
July 27, 2026 Entry
– SEPA / N.C. Clean Energy Technology Center — VPP and Supporting DER Policy Developments Q2 2026 (July 23, 2026)
– Utility Dive — FERC Chairman Gives PJM Until End of September on Governance Reforms (July 24, 2026)
– Utility Dive — PG&E Claims 12.7 GW Data-Center Pipeline as Utility Courts Smaller Loads (July 24, 2026)
– Utility Dive — GE Vernova Gas-Turbine Backlog Climbs to 116 GW (July 23, 2026)
July 28, 2026 Entry
– Energy-Storage.News — Vehicle-to-Grid Added to Massachusetts Utilities’ ConnectedSolutions Demand-Response VPP (July 27, 2026)
– Utility Dive — AI Data-Center Growth Reshapes Utilities’ Generation Plans: Bank of America (July 17, 2026) (deduplicated with July 31 entry; previously covered July 24 digest)
– Puget Sound Energy — 2026 Demand Response Request for Proposals
– Utility Dive — GETs, Demand Response Can Blunt Data-Center Price Pressure: Columbia CGEP (June 23, 2026)
July 29, 2026 Entry
– ROI-NJ — Board of Public Utilities Proposes Virtual Power Plant Idea to Save Ratepayers Money (July 28, 2026)
– American Public Power Association — DOE Issues Emergency Order Directing SPP to Dispatch Generation Units (July 26, 2026)
– McGuireWoods — FERC Issues Section 206 Show Cause Orders to All Six RTOs/ISOs (June 22, 2026) (previously covered; superseded by the docket pull below)
– GE Vernova — GridOS for Distribution Launch
July 30, 2026 Entry
– Electrek — Vermont’s Largest Energy Source Is Now a Virtual Power Plant (July 28, 2026)
– The Pew Charitable Trusts — State Action Is Accelerating Distributed Energy (July 23, 2026)
– Data Center Knowledge — Texas Pushes AI Data Centers to Pay Their Own Grid Costs (July 27, 2026)
– Data Center Knowledge — NERC Flags AI Data-Center Grid Risks in Report (July 3, 2026) (previously covered July 24 digest; new detail only)
July 31, 2026 Entry
– T&D World — Why DERMS Is Earning a Place Alongside SCADA (July 2026)
– Utility Dive — In 2026, Virtual Power Plants Must Scale or Risk Being Left Behind
– Utility Dive — AI Data-Center Growth: Bank of America (July 2026) (duplicate of July 28 entry)
– Troutman Pepper — FERC Approves ISO-NE Updated Market Rules for Distributed Energy Resources (June 2026) (previously covered July 24 digest; convergence-timeline detail new)
External Verification / Docket Pull
– Day Pitney LLP — Memorandum to NEPOOL Reliability and Transmission Committees: Summary of ISO/RTO Informational Reports on Resource Adequacy for Large Loads, Dockets EL26-67 through EL26-72 (July 23, 2026)
– FERC — RTO/ISO Show Cause Orders Presentation, June 2026 Commission Meeting