All five weekday entries (Monday August 17 through Friday August 21) are present in the research log. One item required consolidation: the Bloomberg/Insurance Journal investigation into AI load volatility physically damaging data-center equipment appeared in both the August 17 and August 20 entries from the same URL and is deduplicated into a single item. The SEPA/NCCETC Q2 2026 policy roundup (August 17 entry) was covered in the July 31 and August 14 digests and is carried here only where its Illinois Rider SDVPP detail directly underwrites this week’s new SOLRITE deployment item. Two watch items this series has carried for weeks resolve this week, both inside a single filing and a single deadline: PJM’s Interim Resource Adequacy Service docket is ER26-3515, filed August 13, and MISO’s Zero Injection Generator Interconnection Agreement is confirmed as a named initiative in its August 17 show-cause response. Several items carry pre-week publication dates (NV Energy’s IRP from May 19, ConnectedSolutions V2G from July 27, NERC’s Summer Reliability Assessment from May 27); they are reported on the day they entered the log with original publication dates shown.
Last week’s digest argued that flexibility had become a condition of large-load service. This week the largest RTO in the country wrote it into a tariff filing, and the sentence that matters is a list. In PJM’s August 13 filing in FERC docket ER26-3515 — its answer to the June 18 show-cause order — a new large load may energize before matching firm supply exists, but the portion of its demand not covered by “qualifying new capacity” becomes curtailable under Interim Resource Adequacy Service. The qualifying resources that let a load erase that exposure include new generation, uprates, surplus interconnection service, repowers, fuel conversions, storage, and — the words are PJM’s — “certain demand resources and distributed energy resource aggregations.”
That is DR and DER aggregation named inside the capacity-substitution mechanism of the largest organized market in North America, not as an accommodation but as a qualifying resource on the same list as a gas uprate. Every avoided-cost argument this series has made for six months has been an argument that regulators and planners should treat demand-side flexibility as substitutable for firm supply. PJM has now proposed a tariff in which it formally is.
The second half of the filing is the one a ratepayer advocate will read first. Beginning with the 2029/30 delivery year, excluded New Large Load would be subtracted from the Region Reliability Requirement in the VRR curves — PJM would not procure RPM capacity for speculative large load, and existing customers would not fund it. Curtailment of unsupported large load fires before PJM calls Pre-Emergency Load Management Response, which makes the unbacked data-center block the grid’s first-called, lowest-priority load rather than something the demand-response fleet absorbs on its behalf. Comments are due September 3; PJM requests an October 12 effective date.
The same week produced the wider record. All six RTOs’ show-cause responses came due Monday, August 17 across dockets EL26-67 through EL26-72, with intervenor comments running roughly 30 days out to mid-September. Pennsylvania made fast-track permitting conditional on bring-your-own-firm-clean-power and full cost causation. And the supporting analysis arrived on cue: a GridLab/Kevala/E3 blueprint putting California’s already-installed flexible load at more than 15% of state peak and ~$550 million a year, and a Regulatory Assistance Project panel reframing VPPs as affordability instruments gated not on technology but on compensation design and revenue-grade metering.
The through-line is worth stating plainly, because it is a change in kind rather than degree. Demand-side flexibility spent this cycle being argued into the resource stack. This week it started being written into the instruments that govern the stack — a capacity-substitution list, a curtailment priority order, a state permitting consent order, a reliability-requirement subtraction. The advocacy question shifts accordingly: less whether flexibility counts, more on what terms it counts, at what verification standard, and who gets paid.
🔋 Energy Storage
The Northwest Power and Conservation Council’s draft Ninth Power Plan proposes a 2032 portfolio of roughly 9 GW of renewables, 5.2 GW of energy storage, and just 2.1 GW of natural gas — storage outscoped against gas by two and a half to one — against regional demand projected to grow about 50% in six years and potentially double over twenty. The Council published the draft August 12 and approved it August 13 for public comment, with hearings across Oregon, Washington, Idaho, and Montana in September and October and final adoption targeted for late 2026 or early 2027. The instruction that gives the plan force is the one directed at the Bonneville Power Administration, which is legally bound to acquire resources consistent with the Council’s strategy: favor renewables for energy needs, and “weigh batteries against new gas plants for capacity.” That phrasing treats storage as a first-order capacity substitute rather than an energy-shifting supplement, which is the analytical move most IRPs still decline to make. Two demand-side provisions belong in any regional filing this cycle: the draft proposes energy-efficiency standards for new data centers and calls for working with operators on flexible electricity consumption — demand response and backup-generation use — putting curtailable large load inside the resource plan rather than in a sensitivity appendix. The cost framing is the persuasive part for a commission: an estimated $2.3 billion fixed cost in 2032, about 0.15% of the four-state region’s $1.46 trillion GDP, for a portfolio designed to stay adequate across the full range of load outcomes. The method matters as much as the portfolio — testing against load variability, extreme weather, transmission availability, and hydro operations before committing to build is the discipline that keeps DR, efficiency, and storage in the capacity comparison instead of losing them to a firm-gas default. (Source: Utility Dive, August 18 — August 20 entry)
NV Energy’s 2026 Integrated Resource Plan scopes more than 5.4 GW of storage and more than 4.3 GW of solar against 1.2 GW of new gas turbines the filing states are needed “exclusively” for data-center load — storage at more than four times the incremental gas — while projecting data centers to climb from roughly 5% of sales today to 64% of NV Energy sales and 82% of Sierra Pacific Power sales by 2046. The plan, filed with the Public Utilities Commission of Nevada and retained in the log as the freshest substantive avoided-cost value-stack anchor, is the single-utility version of the same storage-versus-gas adjudication the Northwest Council is running regionally, and it is more honest about the tension than most: the filing concedes it will miss its 2027 Renewable Portfolio Standard primarily because of data-center growth. The 180 MW of geothermal rounds out a preferred portfolio that is, on its face, demand-growth-driven decarbonization running into a firm-capacity floor. The intervenor argument is the one worth exporting — Western Resource Advocates warns that large loads left unregulated could back out of contracts or self-build gas with little oversight and shift costs to ordinary ratepayers, which is the cost-causation exposure Pennsylvania’s executive order and PJM’s ER26-3515 filing both attack from the supply side. For value-stack work, the illustrative regulated-method avoided-cost figures in circulation for these cases — roughly $134/kW-year generation, $69/kW transmission, and $21/kW distribution — are the deferrable costs a DR or storage megawatt must be valued against before a gas turbine is the least-cost answer. Those are illustrative anchors, not commission-adopted values; cite them as framing and source jurisdiction-specific numbers for any filing. (Source: Western Resource Advocates, May 19 — August 21 entry)
⚡ Virtual Power Plants (VPP) & Demand Flexibility
A GridLab report prepared with Kevala and Energy and Environmental Economics finds that virtual power plants built from technologies already installed in California could meet more than 15% of state peak demand and save utilities and customers roughly $550 million annually — and that the binding constraint is program fragmentation, not technology. Unlocking California’s Flexible Load: A Durable Blueprint for Affordability and Reliability argues the state should consolidate and standardize its tangle of flexible-load programs so that EVs, home batteries, smart thermostats, water heaters, and commercial buildings already in the field can be dispatched as grid resources instead of sitting idle. The framing that makes this quotable in a proceeding is the comparison the report builds its case on: planned utility-scale storage procurement set against the far larger installed base of behind-the-meter storage and EVs. Demand-side flexibility is stranded capacity that a standardized market could monetize — that is this series’ avoided-cost thesis stated at state scale with a dollar figure attached. Three recommendations are the operative ones for anyone building a DR business case or a DERMS specification: common technical requirements across programs, consolidated program designs, and compensation paid on verified grid performance rather than enrollment. The third is the discipline that separates a bankable resource from a headcount, and it is the same M&V requirement that underpins the roughly $66/kW-year avoided-capacity value this series tracks. For DERMS procurement, standardized enrollment and telemetry requirements across programs are precisely the interoperability layer a single orchestration platform needs to forecast and dispatch a heterogeneous fleet at scale — a point that lands harder when read against this week’s Hyundai item and its 3,000-utility interoperability wall. (Source: RTO Insider, August 18 — August 19 entry)
At an August 18 Regulatory Assistance Project webinar, utility and aggregator experts reframed VPPs as affordability instruments rather than reliability curiosities — and named the three conditions that determine whether customer participation scales: robust and predictable compensation, “revenue-grade metering,” and penalty-free opt-out. RMI’s Kevin Brehm framed VPPs as a non-wires alternative that generates “value for all the customers being asked to contribute to the cost of the grid” — cutting demand when wholesale prices spike and shaving capacity and transmission costs on the bulk system, while freeing interconnection headroom and deferring incremental investment on the distribution grid. Sunrun’s Bronte Payne supplied the verification discipline: revenue-grade metering to measure performance, plus customer protections including penalty-free opt-out. That combination — pay reliably, measure to revenue grade, don’t punish exit — is a program-design checklist a commission can rule on, and it is more actionable than another megawatt-potential study. The deployments cited make it concrete. National Grid is tapping DER aggregations across 19 non-wires-alternatives projects in Massachusetts, with 7.2 MW active or committed between its ConnectedSolutions+ residential program and a market-based C&I framework, and screens each constrained node for existing dispatchable resource before deciding whether an RFP is even needed — a sequencing practice worth copying outright. Xcel Colorado is pivoting to a “direct-participant model” emphasizing DERs’ capacity value, driven by the operational reality that 1 GW of rooftop solar on a 7-GW system produces voltage swings and reverse power flow that have to be managed rather than tolerated. Brehm’s three-way taxonomy — utility-run, “market participant,” and “bring your own capacity” VPPs — is the vocabulary to use in an RFP, and it maps directly onto the make-versus-buy fight now live in Minnesota. A GM-commissioned study pegging bidirectional EV value at up to 15x one-way managed charging is the number to test rather than repeat, but it sets the direction of travel. (Source: Utility Dive, August 19 — August 20 entry)
Eversource and National Grid have added vehicle-to-grid-capable EVs to the EnergyHub-run ConnectedSolutions VPP — a five-state program orchestrating more than 280,000 participating DERs and over 800 MW of flexible capacity. EnergyHub president Seth Frader-Thompson calls it the “gold standard” for how utilities scale VPPs, and whatever one makes of vendor superlatives, the numbers are the right benchmark for a DERMS RFP: a live program already coordinating smart thermostats, home batteries, and C&I resources now adding EV batteries — initially in Massachusetts, used as additional storage inside the aggregate rather than as standalone assets — with Sunrun’s grid-services arm and The Mobility House supplying the V2G layer. That is the cross-DER orchestration problem stated as a working system rather than a requirement document. Two design details carry beyond the program. The ConnectedSolutions+ tier pays higher incentives in grid-constrained areas — the demand-side analogue of non-wires-alternative geographic targeting, and the same load-pocket logic Louisiana advocates pressed for on Entergy’s portfolio last week. And National Grid’s parallel V2G deployment for light- and medium-duty fleets, starting with school buses, signals that fleet and passenger EV storage are being folded into one orchestration envelope rather than two programs. For the DR business case, 800-plus MW of aggregated, incentive-compensated behind-the-meter flexibility is the deliverable-capacity proof point behind the ~$66/kW-year value this series tracks. (Source: Energy-Storage.News, July 27 — August 18 entry)
SOLRITE Energy extended its finance-build-own residential VPP into ComEd and Ameren Illinois on August 20, pairing no-upfront-cost solar at 12¢/kWh with an unusually large 60 kWh whole-home battery — roughly four times a typical residential unit. The vendor offer is not the point; the policy scaffolding it plugs into is. Illinois’ Clean and Reliable Grid Affordability Act (January 2026) set a 3 GW-by-2030 storage target and requires utilities to build VPP programs that pay customers to dispatch batteries, thermostats, and EV chargers at peak. In June the Illinois Commerce Commission approved ComEd’s and Ameren’s Rider SDVPP (Scheduled Dispatch Virtual Power Plant) tariffs, plus ComEd’s Bring-Your-Own-Device Load Reduction program, with a cost-effectiveness evaluation due end-2026. Those tariffs are the enrollment-and-compensation rails a third-party aggregator needs to convert a fleet of home batteries into dispatchable capacity — and the arrival of a commercial aggregator within two months of tariff approval is the cleanest available evidence that standardized tariffs, not incentives alone, are what mobilize private capital into VPP capacity. The scale arithmetic this series uses applies directly: a 50,000-home fleet at roughly 2 kW of controllable load per home is about 100 MW of dispatchable DR. For DERMS procurement, the requirement this surfaces is ingestion of heterogeneous third-party-owned aggregations under a common tariff and telemetry standard — not just utility-owned devices on a utility-selected platform. As a vendor announcement it is thinner on verified performance than the regulatory items here; treat it as a deployment signal against a codified mandate rather than as performance data. (Sources: GlobeNewswire/SOLRITE Energy, August 20 — August 21 entry; Rider SDVPP detail from DSIRE Insight/NCCETC & SEPA, July 23 — August 17 entry, previously covered)
NERC’s 2026 Summer Reliability Assessment records demand-side resources moving the reliability needle in measurable, region-by-region terms — and the ERCOT adjustment is the one to cite. NERC cut its 2026 ERCOT net internal demand forecast by 3.7 GW (4.6%) and total internal demand by 1.9 GW (2.3%) “because more data centers can be curtailed by grid operators when needed to prevent grid emergencies.” That is the reliability watchdog counting curtailable large load as accredited capacity that offsets firm supply need — the single most useful sentence available for a large-load flexibility filing, because it comes from the entity whose job is to be conservative. The statutory mechanism behind it is Texas law requiring loads of 75 MW or more interconnecting from 2026 onward to accept mandatory curtailment during firm load-shed events, which is the compelled-curtailment end of the spectrum whose voluntary, compensated alternative is what utilities should be offering. Regional DR-availability shifts versus 2025 give a benchmark map: SERC Central +172.3% (attributed to new demand-side-management programs and industrial-load enrollments in the TVA footprint), ERCOT +54.9%, SPP +25.8%, New England −13.3%, and WECC-Northwest at a structurally thin 2 MW. ISO-New England’s 8,000-plus MW of behind-the-meter solar already trims peak-hour demand by more than 1,700 MW and continues to reshape the net-load curve. Read the SERC Central figure carefully — a 172% jump off a modest base is a program-design proof point, not a capacity claim, but it does demonstrate that a utility that decides to build DSM can move a region’s posture inside a single assessment cycle. (Source: Utility Dive, May 27 — August 18 entry)
🔌 DERMS & Grid Integration Technology
The New York Public Service Commission has directed the state’s electric utilities to submit amendments improving the interconnection process for new distributed energy systems — the unglamorous enabling layer that determines whether behind-the-meter solar, storage, and DER can be connected fast enough to be aggregated at all. This belongs in the DERMS lane rather than the regulatory one because of what it implies about sequencing: interconnection friction, not resource scarcity, is increasingly the binding constraint on DER growth. A VPP or DERMS platform can only orchestrate assets that have cleared the utility’s queue, so faster and more standardized DER interconnection is a precondition for the hundreds-of-megawatts aggregations this series tracks elsewhere, not a parallel workstream. The action also confirms a pattern across jurisdictions — Maryland’s third-party-accessible DER registry and interconnection-tool alignment, Hawaii’s competitively-procured edge-DERMS design, now New York’s process amendments — in which regulators treat DER data access and interconnection workflow as core grid infrastructure rather than administrative overhead. Note that New York is reforming both ends of the queue simultaneously: this DER proceeding runs alongside its separate large-load interconnection proceeding, Case 26-E-0045. For DERMS and ADMS procurement, the specification consequence is direct — interconnection-management tooling and DER visibility must be scoped to align with the forthcoming process amendments, so newly interconnected resources flow into the orchestration platform without a manual reconciliation step. (Source: RTO Insider, August 18 — August 19 entry)
Hyundai Motor Group is consolidating its smart-charging and bidirectional (V2H/V2G) capabilities across Hyundai, Kia, and Genesis under a single global entity, AllDayEnergy — and the article’s most useful contribution to a DERMS specification is the friction number it names. AllDayEnergy launches in Kia’s UK app before expanding to Europe, the U.S., and Korea, starting with managed off-peak charging (load-shifting plus time-of-use savings) and layering in bidirectional charging that turns the EV into dispatchable home backup and a grid-export asset. For a utility, an automaker assembling millions of vehicles onto one managed-charging-and-V2G platform is exactly the kind of large, forecastable flexible resource a DERMS must ingest and co-orchestrate alongside thermostats, home batteries, and C&I load. The barrier the piece names is the structural one: the U.S. has roughly 3,000 electric distribution companies, each with a distinct combination of rates, rules, permitting, and interconnection requirements. That is why the standardization arguments elsewhere in this digest — GridLab’s common technical requirements, New York’s interconnection amendments, Maryland’s registry — are not housekeeping items but the precondition for converting an OEM platform into deliverable grid capacity. The competitive map is worth tracking as a procurement variable: ChargeScape (founded by BMW, Ford, Honda, and Nissan; since joined by Rivian, Tesla, and Stellantis) and GM Energy are the rival aggregation platforms, which means OEM-mediated V2G is consolidating into a handful of counterparties a utility will negotiate with rather than a long tail it can dictate terms to. Plan integration work around three or four platform APIs, not around individual vehicle models. (Source: Utility Dive / WardsAuto, August 18 — August 19 entry)
Read this week’s DERMS items against the PJM filing and a procurement conclusion falls out. PJM’s Independent Market Monitor is fighting for explicit real-time telemetry in the proposed Large Load Registry and a monthly validation schedule for capacity claims. CAISO’s August 12 straw proposal specifies monitoring, telemetry, and modeling data as large-load interconnection deliverables. The RAP panel names revenue-grade metering as the gate on VPP participation. GridLab recommends compensation on verified grid performance. Four independent proceedings this week converged on the same requirement: measurement good enough to settle money against. A utility scoping a DERMS in 2026 should treat metering-and-telemetry fidelity as the primary specification and dispatch logic as secondary, because every regulatory venue in this digest is now gating value on verification rather than on capability.
🏗️ Data Centers & Large Load Growth
Bloomberg’s investigation into AI power volatility — deduplicated, appearing in both the August 17 and August 20 entries from the same source — documents that AI training workloads swing hundreds of thousands of GPUs on and off within milliseconds, spiking power draw as much as 50% above design capacity, and that the shocks are physically destroying equipment. A 1 GW facility can briefly pull 1.5 GW. Gas turbines have cracked at xAI’s Memphis Colossus site and at smaller UK data centers; stabilizing batteries have needed replacement “within months or even weeks”; arc flashes are damaging chips. Based on interviews with more than three dozen power experts, the reporting establishes that the damage does not stop at the fence line — Schneider Electric’s power-quality lead warns these “extremely dynamic” loads can induce sub-synchronous oscillations and voltage instability that damage equipment elsewhere on the network. The number that will end up in filings is NERC’s: evaluating more than 33 GW of operational data centers, NERC found roughly three-quarters of their load models “insufficient to represent data-center dynamic behavior” and issued a rare Level-3 alert requiring large data centers to address the risks, with responses due August 3. Set that beside last week’s PJM disclosure — 3,800 MW of Northern Virginia load tripping off a normally-cleared fault — and the picture is consistent and uncomfortable: the largest new loads on the system are both poorly characterized in the models planners use and physically volatile in ways those models would not capture anyway. For DERMS and IRP work the conclusion is that co-located storage, capacitors, flywheels, and power-quality equipment, plus flexible-operation and ride-through requirements, are interconnection prerequisites rather than optional add-ons, and that curtailable, well-modeled large load carries a reliability value stacked on top of its capacity-deferral value. The financing subtext deserves a line of its own: some AI facilities are reportedly seeing uptime closer to 80% against a 24/365 design assumption, a shortfall that could hit project economics within 12–24 months — which would tighten merchant-generation financing further and, incidentally, thin the pipelines every utility is currently planning against. (Source: Insurance Journal / Bloomberg, August 12 — August 17 and August 20 entries; deduplicated)
Ascend Analytics projects ERCOT peak demand could reach 120 GW by 2030 — more than 30% above the unofficial record set July 22 — while warning that more than 80% of new large loads seeking interconnection will not have matching generation online by decade’s end. The supply-side arithmetic is the constraint: gas-turbine shortages, multi-year development timelines, EPC and high-voltage-equipment bottlenecks, and permitting delays cap how fast dispatchable supply can be built, regardless of demand. ERCOT’s large-load queue has grown by more than 200 GW since 2024, with transmission providers reporting 208 GW of 2030 load against ERCOT’s 138 GW adjusted forecast; Ascend’s 120 GW figure assumes a 55.4% success rate, which is itself a useful published discount factor to cite when a proceeding treats a queue as a forecast. The structural finding is the one with the longest reach: the energy-only market “no longer provides enough revenue certainty to finance the dispatchable generation needed,” and lenders increasingly demand contracted rather than merchant revenue — a financing squeeze that stalls merchant storage alongside merchant gas. If firm generation structurally cannot keep pace with queued load, curtailable large load, demand response, and contracted or firmed storage become the fastest-deployable marginal capacity by default rather than by preference, and the “bring-your-own-new-generation” concept Ascend floats is precisely what PJM filed six days later. One operational note worth putting in a seasonal readiness plan: Ascend flags September as an emerging risk window — reduced solar output against lower evening wind — which is exactly the net-load ramp where dispatchable DR and storage earn their capacity payment. (Source: Utility Dive, August 12 — August 18 entry)
Utility Dive’s synthesis of more than two dozen Q2 2026 earnings calls finds the sector’s story flipping from chasing data-center growth to proving cost recovery won’t land on existing customers — and buried in it is Southern Company’s first codified gigawatt of “flexible demand response” inside a data-center contract. TD Cowen’s Shelby Tucker: “growth remains intact, but affordability is emerging as [a] key constraint.” The supply-side scarcity that gives demand-side resources their opening is quantified in the turbine backlogs — GE Vernova 116 GW (now quoting 2031 deliveries), Siemens Energy ~70 GW, Mitsubishi 35 GW — multi-year lead times that cap how fast firm supply can respond no matter what a resource plan says. Exelon said it has a “high probability” its data-center load falls roughly 40% to 11 GW as it weeds out speculative projects through transmission-security agreements, which now stands alongside PG&E’s 490-MW-of-12.7-GW disclosure from last week as the second citable demonstration that a financial-commitment filter collapses a large-load pipeline by close to an order of magnitude. But the item to carry forward is Southern Co.: contracted large load up to 17 GW, including a 3.2 GW OpenAI campus near Savannah with 1 GW of flexible demand response written in for peak shaving — the company’s first codified flexibility provision with a data center. That is curtailable large load migrating from concept into signed contract terms, and a 1-GW-inside-3.2-GW ratio is a bargaining benchmark worth quoting in the next large-load tariff negotiation. (Source: Utility Dive, August 17 — August 19 entry)
Evergy disclosed 3 GW of executed large-load electric-service agreements and plans for more than 5 GW of new generation through 2032 — then said the quiet part in the earnings call. The signed 3 GW comprises 2.5 GW of data centers under its large-load power-service tariff plus 500 MW of smaller loads, underwriting 7–8% retail-sales growth through 2030 against a current fleet of roughly 15.8 GW. The build is 3.9 GW natural gas, ~800 MW solar, and 450 MW battery storage. CEO David Campbell’s statement that load beyond the signed 3 GW “is expected to require incremental generation resource needs and incremental capex” is the avoided-cost fulcrum stated in the utility’s own words: every megawatt of peak that DR, curtailable large load, or storage shaves defers exactly this gas-and-CapEx escalation and the rate-base pressure behind it. The capital exposure is understated in the headline number — the generation build in Evergy’s pending IRPs is not in the announced $21.6 billion five-year capital plan, and the pending resource plans add roughly $1 billion more. With advanced discussions underway for another 1–2 GW and an incremental pipeline “well over 10 additional GW” primarily beyond 2030, the deferral opportunity compounds rather than expiring. The 450 MW of storage and ~800 MW of solar already in the stack show DER entering firm supply planning rather than sitting adjacent to it; the IRP discipline is to force DR, non-wires alternatives, and flexible large-load terms into the same avoided-cost comparison as the 3.9 GW gas build before that build is treated as settled. (Source: Utility Dive, August 11 — August 18 entry)
Data Center Knowledge’s large-load-flexibility explainer is the clearest available statement of what actually gates a flexibility commitment — and it is honest enough to be useful in a tariff negotiation. The piece defines large-load flexibility as temporarily shifting a data center’s draw off the grid, typically onto on-site backup generation, during hours when demand approaches system capacity, and argues it is moving from voluntary goodwill gesture to tightening regulatory expectation. Two limits determine whether a commitment is bankable rather than aspirational: flexibility depends on sustained on-site generation, so facilities with only short-duration UPS or battery backup cannot maintain a grid bypass, and cold-start generators that take minutes to spin up may not respond fast enough for rapid-onset grid strain. Those are the exact reasons revenue-grade telemetry, ramp specifications, and dispatch verification are prerequisites rather than niceties — and they are why PJM’s Market Monitor is fighting for real-time telemetry in the Large Load Registry rather than accepting attested capability. The piece is also candid that flexibility’s value is conditional on grid stress: it helps when load is high enough to trigger the shift, and it does not make a data center energy-neutral. Utilities should price it that way — as capacity and reliability value at coincident peak, not as an energy product. The regulatory throughline is FERC’s June 2026 action pressing large loads to show how they will secure adequate generation “without burdening the grid,” to which flexibility is the most plausible answer an operator can offer and the one that buys faster interconnection in return. For DERMS procurement, a curtailable large load is a dispatchable resource the platform must forecast, call, and settle against measured performance — the same as any enrolled DER, at a thousand times the unit size. (Source: Data Center Knowledge, August 19 — August 21 entry)
Demand context, carried: Gartner projects worldwide data-center electricity consumption growing 26% in 2026 to 565 TWh (from 447 TWh in 2025) and power demand up 27% to 132 GW, heading to 290 GW by 2030 and past 1,200 TWh, with AI-optimized servers reaching 31% of data-center power consumption this year and surpassing conventional servers by 2027. The analyst framing is the planning-relevant part — “AI capacity is now constrained by power availability” — which makes grid access the binding constraint and pushes efficiency, storage, and flexible-load orchestration from optional to load-bearing. Treat the 26–27% single-year growth rate as corroboration that large-load demand belongs at the center of the resource plan, and treat the global totals as directional rather than as inputs to a service-territory forecast. (Source: Gartner, June 10 — August 17 entry)
📋 Regulatory & Policy
PJM’s August 13 filing in FERC docket ER26-3515 proposes a conditional-reliability framework that resolves this series’ two-week-old open item on the Interim Resource Adequacy Service docket number — and does considerably more than that. A “New Large Load” is defined as a cumulative peak of at least 50 MW at a single site entering service after June 1, 2027, with affiliated sites within one mile treated as one. Such a load may energize before equivalent new supply exists, but the portion of demand not covered by “qualifying new capacity” becomes subject to curtailment under IRAS — and that curtailment fires before PJM calls Pre-Emergency Load Management Response, placing the unsupported data-center block ahead of the demand-response fleet in the curtailment order. The Bring Your Own New Capacity path lets a load erase its IRAS exposure using new generation, uprates, surplus interconnection service, repowers, fuel conversions, storage, and “certain demand resources and distributed energy resource aggregations.” Two things follow. First, DR and DER aggregation are named as capacity-substitution instruments in the tariff of the largest RTO in North America — the definitional win this series has been arguing toward, subject to whatever qualification standards survive the docket. Second, the RPM mechanics carry a ratepayer-protection signal with teeth: from the 2029/30 delivery year, excluded New Large Load would be subtracted from the Region Reliability Requirement in the VRR curves, so PJM would not procure — and existing customers would not fund — capacity for speculative large load. PJM cites roughly 70 GW of new large-load demand by 2038 against ~15 GW of retirements since 2022 as the adequacy gap driving the design. The Independent Market Monitor’s pushback is where demand-side interests should concentrate: Joseph Bowring wants supporting evidence, a monthly validation schedule, and explicit real-time telemetry for the proposed Large Load Registry. That is the M&V-and-provenance layer that separates a bankable capacity claim from a paper one, and it is the same verification standard a DER aggregation must meet to qualify. Comments are due September 3; PJM requests an October 12, 2026 effective date. (Source: Data Center Knowledge, August 17 — August 21 entry)
All six RTOs’ show-cause responses came due Monday, August 17 — dockets EL26-67 (PJM), -68 (SPP), -69 (NYISO), -70 (MISO), -71 (CAISO), and -72 (ISO-NE) — and MISO’s response resolves a watch item this series has carried for three consecutive weeks. MISO’s filing acknowledges that the concentrated, fast-moving nature of new large-load demand requires new tools and previews two concrete initiatives: the Zero Injection Generator Interconnection Agreement (ZGIA) and a new Large Load Parallel Study Process. The ZGIA has been an unconfirmed filing rumor since late July; it is now a named element of MISO’s federal response, which is a materially firmer footing even though the tariff language itself still has to arrive. The five reform areas remain the frame — study procedures, transmission-cost transparency, co-location and behind-the-meter generation rules, transmission service for flexible large loads, and treatment of generation dedicated to electrically proximate loads — and the fourth is where FERC comes closest to treating demand flexibility as a compensable grid service. Commissioner David Rosner’s remarks on the orders make the mechanism explicit: flexible loads and electrically proximate generation can reduce network-upgrade requirements when properly studied, which is transmission-deferral value assigned to load flexibility by a sitting commissioner. Interested parties have roughly 30 days from the August 17 filings to respond, putting the comment window in mid-September — and that record, not the June orders, is the venue where demand-side and DER interests actually shape the outcome. Two related items remain open: which operators, if any, filed the August 3 abeyance requests is still unconfirmed in public reporting, though the August 17 deadline appears to have held across the set; and FERC’s proposed large-load definition (peak load above 50 MW, interconnecting at 69 kV or above, single site, non-co-located) still sits alongside PJM’s ER26-3515 threshold and NERC’s Computational Load Entity criteria as a third, differently-scoped screen. (Sources: Microgrid Media, August 17; Climate Solutions Legal Digest; FERC — external verification)
Pennsylvania Governor Josh Shapiro’s August 18 executive order makes preferential state permitting for data centers above 25 MW conditional on bring-your-own-firm-clean-power and full cost causation — the state-level analogue of what PJM filed five days earlier. Projects above 25 MW get rolling DEP review rather than waiting until all local, water, and wastewater permits are in hand, but only if the developer signs a consent order committing to the state’s February infrastructure-development standards: sourcing new generation from the same local PJM zone, paying “all costs caused in whole or in part” by interconnection and network upgrades, and meeting firm-clean-energy requirements ramping from 10% on January 1 to 14.5% three years later and 32% by 2035. Note the framing tension worth flagging: coverage of the order divides between describing it as granting fast-track access on conditions and describing it as removing data centers from fast-track permitting absent those conditions. Both readings describe the same instrument — conditional access — but a filing should quote the consent-order mechanism rather than either characterization. The market read sharpens the stakes. Jefferies analysts said the order “should further close the door” on independent power producers (Talen, Vistra, PSEG Power) selling existing generation to Pennsylvania data centers under long-term contracts, though Talen’s Susquehanna-to-Amazon arrangement appears safe. More consequential for utility planning, the analysts warned that slowing data-center growth would pressure the transmission investment Exelon, FirstEnergy, and PPL are materially increasing with data-center demand as a stated driver — investment currently cost-shared with residential customers. PPL alone reports roughly 20.7 GW of potential data-center load under service agreements. And the broader siting environment continues to tighten: 81 or more cities and counties now have data-center moratoria. For IRP and DERMS planning, requiring large loads to be firm-clean-power-backed and zone-local pushes storage, demand flexibility, and co-located resources to the front of the queue by construction. (Source: Utility Dive, August 19 — August 20 entry)
FERC’s approval of ISO-NE’s Order 2222 DER market rules stands as the near-term calendar item on wholesale DER access: energy and ancillary-services go-live November 1, 2026. The Commission approved the revised rules May 29, moving New England from compliance-filing limbo to operational access for DER aggregations — batteries, demand response, managed EV load, distributed solar — competing as deliverable wholesale capacity rather than settling for retail-rate offsets. That market layer is what determines whether a DERMS or VPP business case can monetize the roughly $66/kW-year capacity value this series tracks. The national picture remains footprint-specific and slow: MISO’s full implementation does not land until June 2029, so wholesale DER value is a map question before it is a technology question. The procurement consequence of a live market is a step change in requirements — telemetry, metering, aggregation, and settlement must be market-grade rather than pilot-grade to capture value, which is a different specification and a different cost. Planners in and adjacent to New England should treat November 1 as the date aggregated DER value becomes bookable rather than theoretical, and should have the settlement architecture in place before it, not after. (Source: Troutman Pepper / Washington Energy Report, June 2026 — August 17 entry)
Verification items, updated. NERC’s Computational Load Entity revised draft remains anticipated in August and is not confirmed posted as of this writing. The initial draft posted April 1 for a 45-day comment period that closed May 15; the criteria are unchanged — aggregate connected load capability of 20 MW or greater, at a single point of interconnection to the Bulk Power System at 60 kV or above, hosting 1 MW or more of computational load. Board approval is targeted for December 5 and the FERC filing for December 31, per FERC’s year-end directive. This item stays open into next week. CAISO’s August 19 double header — the revised demand-response framework under the DDEMI initiative and the large-loads technical-standards workshop — produced no coverage in the log or in targeted searching as of August 21; both remain unresolved and carry forward, with September 2 comments on the large-loads straw proposal and a November 16 FERC compliance filing still the governing dates. (Sources: NERC Rules of Procedure posting; Steptoe; CAISO Large Loads Initiative — external verification)
🔬 EPRI Research Spotlight
A direct check of EPRI confirms no new major EPRI publication entered the log this week, making this the sixth consecutive week without fresh EPRI output in the research log — a drought long enough that it is now itself a finding worth stating rather than a gap worth apologizing for. The FlexMosaic framework and the DCFlex expansion remain the most recent substantive releases.
What the direct check did surface is the item most worth foregrounding this week, because it converts DCFlex from a coordination initiative into a measurable demonstration on a near-term clock. In late 2026, EPRI, NVIDIA, Emerald AI, and partners plan to bring the 96-MW Aurora AI Factory online in Manassas, Virginia — a data center explicitly designed for flexibility, intended to validate workload flexibility at scale rather than infer it from simulation. The location is not incidental. Manassas sits inside the Dominion Northern Virginia zone where roughly 3,800 MW of data-center load tripped off a normally-cleared fault on July 22, the event that reframed unmanaged large load as a stability problem in last week’s digest. A purpose-built flexible facility coming online in the same load pocket that just produced the largest correlated trip in PJM history is the cleanest natural experiment the sector is going to get, and its results will land directly into the NERC computational-load standards proceeding and PJM’s ride-through rulemaking.
The DCFlex initiative now spans nine demonstration sites (six added in February 2026) with a coalition including Compass Datacenters, Constellation, Emerald AI, Google, National Grid, Nebius, NVIDIA, Oracle, and PADO AI, and has expanded into Europe. Nine sites testing real-time flex for grid reliability and faster interconnection is the empirical record that the ride-through and flexibility proceedings currently lack — every RTO in this digest is writing requirements against load behavior that has not yet been systematically measured.
The FlexMosaic five-class taxonomy remains the valuation grammar to expect in binding flexibility agreements: Class A (infrequent extreme stress) through Class E (frequency stabilization), keyed to notification time, duration, frequency, depth, and speed of response, with Classes D and E identified as unlocking the most system value. Read against PJM’s ER26-3515 filing, the taxonomy acquires a specific new job: if “certain demand resources and distributed energy resource aggregations” are to qualify as capacity that erases IRAS exposure, someone must specify which response characteristics qualify — and FlexMosaic is the only published vocabulary for saying so precisely. Expect it, or something like it, to appear in the comment record by September 3.
Carried forward: the 2026 Duke University Nicholas Institute finding that shaving 1–2% off data-center peak demand lowers electricity rates 0.5–2.8% while protecting reliability remains the cleanest rate-impact number available for a demand-side intervention, expressed in the units a commission rules on. EPRI’s supporting projections — U.S. data-center demand at 66 GW in 2027 from 31 GW in 2025, summer peak share rising to 8.5%, up to 17% of U.S. electricity by 2030 — are the demand-side anchors.
Standing watch: the NERC Computational Load Entity revised draft, and Aurora AI Factory commissioning data. Check EPRI.com directly again next run.
🚩 Utility-Sector Relevance Flags
⚑ PJM Named DR and DER Aggregations as Qualifying Capacity in a Tariff Filing
Topic: Capacity Substitution / RTO Tariff Design / DER Monetization
Relevance: ER26-3515’s Bring Your Own New Capacity path lists “certain demand resources and distributed energy resource aggregations” alongside new generation, uprates, surplus interconnection service, repowers, fuel conversions, and storage as resources a New Large Load may use to erase its Interim Resource Adequacy Service curtailment exposure. This is the largest organized market in North America proposing demand-side flexibility as a formal substitute for firm supply, not as an accommodation. The open question is qualification standards — what response characteristics, verified how, at what validation cadence — which is exactly what the Market Monitor is contesting.
Action Signal: Engage — File by September 3. The comment that matters is not whether DR should qualify but on what terms: argue for qualification criteria that a real aggregation can meet (aggregate performance, statistical M&V, portfolio-level firmness) rather than criteria written for a single generating unit. If DER aggregation qualification is drafted to generator standards, it will be nominally available and practically unusable.
⚑ Curtailment Priority Now Puts Unsupported Large Load Ahead of the DR Fleet
Topic: Curtailment Order / DR Program Integrity / Cost Causation
Relevance: Under PJM’s proposal, IRAS curtailment of large load not backed by qualifying new capacity fires before Pre-Emergency Load Management Response is called. That ordering protects enrolled demand-response customers from absorbing the consequences of speculative large-load energization, and it is a precedent every other RTO’s show-cause record should be pressed to match. From the 2029/30 delivery year, excluded New Large Load is also subtracted from the Region Reliability Requirement in the VRR curves, so RPM would not procure capacity for it and existing customers would not pay for it.
Action Signal: Implement — Check your own tariff’s emergency-action sequence against this ordering and document where unbacked large load currently sits relative to your DR programs. Utilities that call enrolled DR before curtailing unsupported new load are subsidizing the latter with the former’s goodwill, and that is a program-attrition risk as well as an equity problem.
⚑ MISO’s ZGIA Is Real — and the September Comment Record Is the Live Venue
Topic: FERC Show-Cause Record / Interconnection Reform / Advocacy Timing
Relevance: MISO’s August 17 response names the Zero Injection Generator Interconnection Agreement and a Large Load Parallel Study Process, closing a watch item open three weeks. All six responses (EL26-67 through EL26-72) are now filed, with roughly 30 days for interested parties to respond — mid-September. The flexible-large-load service reform area is where FERC comes nearest to treating demand flexibility as a compensable grid service, and Commissioner Rosner has stated on the record that flexible loads and proximate generation can reduce network-upgrade requirements when properly studied.
Action Signal: Engage — Concentrate advocacy resources on the September comment window rather than on the original June orders. Read all six responses side by side and identify where regional approaches diverge on flexible-load service; divergence is where FERC has the most room to impose a common floor, and a comparative record is the most useful thing an intervenor can put in front of the Commission.
⚑ Four Proceedings Converged on Revenue-Grade Measurement in One Week
Topic: M&V Standards / DERMS Specification / Program Design
Relevance: PJM’s Market Monitor wants real-time telemetry and monthly validation for the Large Load Registry. CAISO’s straw proposal makes monitoring, telemetry, and modeling data interconnection deliverables. The RAP panel named “revenue-grade metering” as a gate on VPP participation alongside predictable compensation and penalty-free opt-out. GridLab recommends compensation on verified grid performance rather than enrollment. Independent venues, same requirement: measurement good enough to settle money against.
Action Signal: Implement — Make metering and telemetry fidelity the primary line in the next DERMS specification and dispatch sophistication secondary. Every venue in this digest now gates value on verification rather than capability, which means a platform that dispatches beautifully but settles approximately will fail the proceeding that determines whether it earns revenue.
⚑ Pennsylvania Conditions Permitting on Bring-Your-Own-Firm-Clean-Power
Topic: State Large-Load Policy / Cost Causation / Transmission CapEx Risk
Relevance: Data centers above 25 MW get rolling DEP review only under a consent order requiring same-PJM-zone new generation, payment of all costs caused by interconnection and network upgrades, and firm clean energy ramping 10% → 14.5% → 32% by 2035. Jefferies reads it as closing the door on IPPs selling existing generation into PA data-center contracts, and warns that slowing data-center growth pressures the transmission investment Exelon, FirstEnergy, and PPL are increasing on data-center rationale — investment currently shared with residential customers. PPL alone reports ~20.7 GW of potential data-center load under service agreements; 81-plus localities now have moratoria.
Action Signal: Watch — Track whether other PJM states copy the consent-order mechanism, and stress-test any transmission capital plan that leans on data-center load growth against a scenario in which state siting policy, not interconnection capacity, becomes the binding constraint. The residential cost-share exposure is the piece a commission will examine first.
⚑ Southern Wrote 1 GW of Flexible DR Into a 3.2 GW Data-Center Contract
Topic: Large-Load Tariff Negotiation / Flexibility Benchmarks / Contract Terms
Relevance: Southern Co.’s contracted large load reached 17 GW, including a 3.2 GW OpenAI campus near Savannah with 1 GW of “flexible demand response” for peak shaving — its first codified flexibility provision with a data center. Roughly 31% of a single campus’s load committed as curtailable, in a signed contract rather than a tariff proposal. NERC separately cut ERCOT net internal demand 3.7 GW on curtailable data-center load, so the accreditation pathway for this kind of commitment already exists.
Action Signal: Implement — Use the ~1-in-3.2 ratio as an opening benchmark in large-load service negotiations, and pair it with NERC’s ERCOT demand adjustment as evidence that contracted flexibility is counted as capacity by the reliability authority. A utility that negotiates flexibility terms without a public comparable concedes the framing; this is the comparable.
⚑ Two Regional Plans Scoped Storage Above Gas for Capacity in the Same Week
Topic: IRP Method / Storage-vs-Gas Substitution / Avoided Cost
Relevance: The Northwest Council’s draft Ninth Power Plan proposes 5.2 GW of storage against 2.1 GW of gas by 2032 and directs BPA to “weigh batteries against new gas plants for capacity.” NV Energy’s 2026 IRP scopes 5.4 GW of storage against 1.2 GW of gas the filing says is needed exclusively for data centers. Two independent planning processes, both treating storage as a first-order capacity substitute rather than an energy-shifting supplement. The Northwest draft also proposes data-center efficiency standards and flexible-consumption terms inside the plan itself.
Action Signal: Engage — Cite both in any IRP proceeding where storage is being scoped as a supplement rather than a capacity resource; two contemporaneous plans make it method, not outlier. Northwest hearings run September–October across OR/WA/ID/MT with final adoption targeted late 2026 or early 2027, and BPA’s statutory obligation to acquire consistently with the strategy makes the comment window unusually consequential.
⚑ Illinois Shows the Tariff, Not the Incentive, Is What Mobilizes Capital
Topic: VPP Tariff Design / Third-Party Aggregation / DERMS Ingestion
Relevance: The ICC approved ComEd’s and Ameren’s Rider SDVPP scheduled-dispatch VPP tariffs in June; a commercial aggregator (SOLRITE) announced territory-wide residential VPP deployment in August. Two months from tariff approval to private capital entry, against Illinois’ 3 GW-by-2030 storage target and its statutory requirement that utilities build VPP programs paying customers for peak dispatch. Cost-effectiveness evaluation is due end-2026.
Action Signal: Engage — For utilities and commissions designing VPP programs, the sequencing evidence favors standardized enrollment-and-compensation tariffs over bespoke incentive programs: the tariff is what a third party can underwrite against. Utilities should also confirm their DERMS roadmap can ingest heterogeneous third-party-owned aggregations under a common telemetry standard, because that is what a functioning tariff produces.
⚑ Three-Quarters of Data-Center Load Models Can’t Represent Real Behavior
Topic: Dynamic Load Modeling / Reliability Prerequisite / Planning Data Gap
Relevance: NERC evaluated more than 33 GW of operational data centers and found roughly 75% of load models insufficient to represent dynamic behavior, issuing a rare Level-3 alert with responses due August 3. Bloomberg documents millisecond swings up to 50% above design capacity, cracked turbines, batteries replaced in weeks, and the risk of sub-synchronous oscillations propagating across the network. Every RTO in this digest is writing large-load requirements against behavior that has not been systematically measured — which is precisely the gap EPRI’s nine DCFlex sites and the 96-MW Aurora AI Factory in Manassas are built to close.
Action Signal: Implement — Require validated dynamic load models and EMT model delivery as an interconnection deliverable now, ahead of the 2027 NERC ride-through specifications, and treat correlated multi-gigawatt trip exposure as a named planning scenario in any territory with clustered campuses. Where models cannot be validated, that is an argument for conservative interconnection terms rather than a reason to wait.
⚑ The Financial-Commitment Filter Is Now a Three-Utility Pattern
Topic: Load Forecasting / IRP Discipline / Capital Allocation
Relevance: Exelon expects its data-center load to fall ~40% to 11 GW through transmission-security agreements. PG&E carries executed agreements on 490 MW of a 12.7 GW pipeline and forecasts serving 1.8 GW by 2030. Ascend applies a 55.4% success rate to ERCOT’s queue and still finds more than 80% of new large loads without matching generation by 2030. Three independent filters, all collapsing headline figures by roughly an order of magnitude.
Action Signal: Implement — Use executed-agreement load and the utility’s own served-load forecast as the denominator in every avoided-cost and deferral calculation, and state the filter explicitly. Ascend’s published 55.4% success rate is now a citable third-party discount factor for queue-based forecasts, which is more durable in a proceeding than an intervenor’s own assumption.
⚑ September Is a Four-Deadline Month
Topic: Regulatory Calendar / Filing Strategy
Relevance: September 2 — CAISO large-loads straw-proposal comments. September 3 — PJM ER26-3515 comments. Mid-September (~16) — responses to the six RTO show-cause filings. September 30 — PJM backstop auction opens (runs to October 21). Plus Northwest Council hearings across four states in September and October, PJM’s DR evaluation in early September, and the end-September PJM governance deadline. Ascend separately flags September as an emerging ERCOT tightening window on low solar and weak evening wind.
Action Signal: Engage — Assign filing ownership for all four windows this week. They are close enough together that a single coherent demand-side position filed across CAISO, PJM, and the show-cause record is more effective than three separately-drafted comments, and the arguments genuinely do overlap: qualification standards for flexible resources, verification requirements, and who bears the cost of load that cannot be firmed.
📌 Sources
August 17, 2026 Entry
– Insurance Journal / Bloomberg (Naureen S. Malik) — AI’s Volatile Power Demand Is Physically Damaging Data-Center Equipment (August 12, 2026)
– DSIRE Insight (Autumn Proudlove, NCCETC & SEPA) — VPP and Supporting DER Policy Developments, Q2 2026 (July 23, 2026)
– Troutman Pepper / Washington Energy Report — FERC Approves ISO-NE Updated Market Rules for Distributed Energy Resources (June 2026)
– Gartner (Linglan Wang) — Data Center Electricity Demand to Grow 26% in 2026 (June 10, 2026)
August 18, 2026 Entry
– Utility Dive (Marlene Wilden) — Supply Constraints Will Limit ERCOT Peak Demand Growth: Ascend Analytics (August 12, 2026)
– Utility Dive (Diana DiGangi) — Evergy Large Loads, Resource Plan, Earnings (August 11, 2026)
– Energy-Storage.News (Molly Green) — Vehicle-to-Grid Added to Massachusetts Utilities’ ConnectedSolutions Demand Response VPP (July 27, 2026)
– Utility Dive (Brian Martucci) — Demand Management, Data Center Flexibility Boost Regional Reliability: NERC (May 27, 2026)
August 19, 2026 Entry
– RTO Insider (Robert Mullin) — GridLab California Flexible Load Demand Report (August 18, 2026)
– Utility Dive (Meris Lutz) — 2026 Q2 Roundup: Utilities Emphasize Project Execution, Ratepayer Protection (August 17, 2026)
– RTO Insider (John Cropley) — New York Orders Tariff Changes for Distributed Energy Interconnection (August 18, 2026)
– Utility Dive / WardsAuto (Bengt Halvorson) — Hyundai Unifies Vehicle V2X Capabilities With AllDayEnergy Entity (August 18, 2026)
August 20, 2026 Entry
– Utility Dive (Brian Martucci) — VPP Value Proposition Expands to Affordability, Reliability and Resilience (August 19, 2026)
– Utility Dive (Marlene Wilden) — Northwest Council Proposes 11 GW of New Generation, 5 GW Storage by 2032 (August 18, 2026)
– Utility Dive (Ethan Howland) — Pennsylvania Executive Order on Data Centers (August 19, 2026)
– Insurance Journal / Bloomberg (Naureen S. Malik) — AI Power Swings Are Damaging Data Centers and Threatening Grid Stability (August 12, 2026) (deduplicated with August 17 entry)
August 21, 2026 Entry
– Data Center Knowledge (Shane Snider) — PJM’s New Deal for Data Centers: Bring Power or Face Cuts (August 17, 2026)
– Data Center Knowledge (Christopher Tozzi) — Can Large Load Flexibility Ease Data Center Energy Concerns? (August 19, 2026)
– GlobeNewswire (SOLRITE Energy) — SOLRITE Energy Expands to Illinois, Bringing Home Batteries and VPP Technology to ComEd and Ameren Customers (August 20, 2026)
– Western Resource Advocates — NV Energy 2026 IRP (May 19, 2026)
External Verification (targeted searches, not from the daily log)
– Microgrid Media (Jonas Muthoni) — FERC Large Load Deadline Arrives for Six U.S. Grid Operators (August 17, 2026)
– Climate Solutions Legal Digest — RTOs and ISOs Answer: A National Preview of How All Six Grid Operators Plan to Respond to the Large Load Surge (July 2026)
– FERC — Commissioner Rosner’s Remarks on the Large Load Show Cause Orders (June 18, 2026)
– FERC — NYISO Show Cause Order, Docket EL26-69-000 (June 18, 2026)
– NERC — Computational Load Entity, Summary of Changes (April 2026 posting)
– NERC — FERC Sets Year-End Deadline for NERC to Finalize Registry Criteria and Standards for Computational Loads
– Steptoe — NERC Releases Proposed Registration Requirements for “Computational Load” Customers
– EPRI — DCFlex: Data Center Flexible Load Initiative
– CAISO — Large Loads Stakeholder Initiative