Note: Thursday, June 18 entry is absent from the research log. This digest covers four available entries: Monday June 15, Tuesday June 16, Wednesday June 17, and Friday June 19. The ERCOT PUCT vote on Batch Zero (scheduled June 18) and the California DSGS budget outcome (June 15 deadline) are flagged below as status-pending watch items with no confirmed result in the log.

The week’s defining event is FERC’s unanimous June 18 vote to issue Section 206 show-cause orders to all six RTOs/ISOs — the direct delivery on the RM26-4 large-load interconnection watch item flagged in the June 12 digest. Rather than a traditional rulemaking, FERC chose show-cause orders under the Federal Power Act, giving each grid operator 60 days to justify or rewrite tariffs across five categories that structurally embed demand flexibility as a condition of large-load grid access. This was flanked by two parallel regulatory milestones: FERC’s June 5 approval of SPP’s CHILLS non-firm transmission framework (the second RTO-level large-load curtailability precedent after ERCOT Batch Zero), and Gartner’s confirmation that AI-optimized server electricity demand is growing at 84% year-over-year — the underlying load pressure that is forcing every RTO, state regulator, and hyperscaler toward demand-side solutions. Microsoft’s proposed Nevada ratepayer protection tariff begins moving cost-causation from regulatory theory to hyperscaler-initiated practice. NRECA’s finding that rural cooperatives are tripling battery storage capacity by 2028 reveals an underappreciated DERMS procurement segment. PJM’s market monitor has now quantified the ratepayer cost of inaction: data centers drove 63% of the 10× capacity price spike in PJM’s 2025/26 auction, translating to $9.3 billion in costs to be recovered through higher bills — a figure that gives demand-side program designers a market-monitor-backed avoided-cost argument with nine zeros in it.

🔋 Energy Storage

Rural electric cooperatives are tripling battery storage capacity by 2028 — and doing it without rate-of-return incentives. The National Rural Electric Cooperative Association (NRECA) reported 439 MW/1,047 MWh of operating cooperative BESS as of summer 2025, with projects in development that could more than triple that total by 2028. The economic driver is not regulated return on equity — cooperatives don’t earn one — but wholesale demand charges based on a single monthly peak hour, which can represent one-third of total power purchase costs. That math makes battery-based peak shaving an immediate, transparent cost-avoidance calculation requiring no complex IRP modeling. Specific deployments documented in the June 17 entry include: Guadalupe Valley Electric Cooperative (Texas) expanding residential BTM batteries from 2 MW to 50 MW with Base Power, finding distributed assets more cost-effective in ERCOT than grid-scale storage; the Electric Power Board of Chattanooga operating 45 MW/95 MWh and planning to double to 90 MW within 12 months for TVA demand charge reduction; Connexus Energy (Minnesota) registering a 2.5 MW/10 MWh substation battery as a MISO capacity asset to stack wholesale market revenue; and Blue Ridge Power Agency (Virginia) deploying 25 MW of distribution-connected storage across five sites and three member utilities to address PJM capacity constraints. TVA itself is targeting 1.5 GW of storage by 2029, starting with a 200 MW/800 MWh Alabama deployment. For DSM/DR program designers, the cooperative segment serves 42 million Americans across 56% of the U.S. landmass, faces the same wholesale capacity cost pressures that DR programs are designed to address, and — as Clean Grid Alliance noted in comments to Utility Dive — can move without the regulatory lag that constrains IOU program launches. (Source: Utility Dive, NRECA — June 17 entry)

☀️ Distributed Solar & Community Solar

No new distributed solar or community solar items appeared in the June 15–19 research log entries. The CalChoice/Lunar Energy DERMS-VPP program (August 2026 go-live) flagged in the June 12 digest remains on track per prior reporting; no update to report this week.

⚡ Virtual Power Plants (VPP) & Demand Flexibility

Virginia and Massachusetts enact the week’s most consequential new VPP mandates — state policy infrastructure is scaling faster than utility program deployment. The SEPA/NCCETC Q1 2026 VPP policy tracker (published May 2026, covered in June 17 entry) documents two new VPP laws enacted in Q1: Illinois S.B. 25 (previously covered in the June 12 digest for its June 30 ComEd tariff deadline) and Virginia H.B. 562/S.B. 487. The Virginia law authorizes electric cooperatives to create VPP programs beginning in 2027 and separately requires Appalachian Power to propose a 150-MW DER aggregation pilot by July 2027 — the first statutory VPP obligation in a traditionally conservative utility regulatory jurisdiction, with direct implications for the Xcel CapacityConnect model spreading to the Mid-Atlantic (see June 12 digest). Massachusetts Governor Healey’s Executive Order 654 sets a 3.5 GW load-management target by 2035 — the first governor’s executive order to quantify VPP and DR capacity as a co-equal planning resource alongside supply-side additions (5 GW storage, 10 GW total new resources), not a supplementary program. New Jersey’s Executive Order 2, previously reported in the June 12 digest, directed the BPU to develop a VPP program enabling PJM capacity market participation within 180 days; the SEPA tracker confirms that timeline is running. For DERMS vendors, the tracker identifies three near-term RFP triggers: Minnesota CapacityConnect (DERMS deployment already specified), Illinois scheduled dispatch VPP (software orchestration required for June 30 tariff), and Maryland’s PC77 docket (directing utilities to inventory DSM programs and propose expanded participation). (Source: SEPA, DSIRE Insight — June 17 entry)

Google/Voltus BYOC — additional sourcing, no new developments. The Utility Dive and Voltus press coverage captured in the June 16 entry provides additional sourcing for the Google/Voltus 100-MW bring-your-own-capacity agreement in PJM, first reported in the June 12 digest (June 3 entry). No new facts materially change the June 12 analysis; that item is deduplicated here. (Previously covered in full — June 12 digest)

Illinois CRGA June 30 deadline: imminent. The Illinois Commerce Commission’s statutory deadline for approving, modifying, or rejecting ComEd’s scheduled dispatch VPP tariff (filed February 9, 2026) is June 30, 2026 — now 11 days away. No outcome has been logged yet. This is the first state-mandated VPP tariff to reach an approval decision in the current policy cycle; the ICC’s treatment of the $300/kWh distributed storage rebate and $10/kW dispatch compensation will set the reference benchmark for other state proceedings. (Source: SEPA, Illinois Commerce Commission — June 5 entry, June 17 tracker)

🔌 DERMS & Grid Integration Technology

SCE’s integrated ADMS-DERMS deployment advances — new technical specifics establish a 2026 procurement reference architecture. The Southern California Edison Grid Management System, reported in the June 12 digest from DISTRIBUTECH coverage, received additional technical documentation in the June 19 entry that is directly relevant to utilities preparing DERMS RFPs. The SCE GMS adopts IEEE 2030.5 as the DER telemetry and dispatch communication standard — resolving a multi-year debate about whether DNP3, IEEE 2030.5, or OpenADR should be the primary DER interface protocol in North American utility deployments. Forward-looking phases include DERMS forecasting and multi-interval optimization, flexible interconnection use cases, and coordination with advanced Fault Isolation and Service Restoration (FISR) and Volt/Var Optimization (VVO) — a scope that defines the architectural benchmark for next-generation utility DER orchestration platforms. The decision to integrate DERMS into the ADMS platform rather than deploying a standalone system, and the inclusion of flexible interconnection as a core use case, are both defensible RFP requirements backed by a named large-utility deployment. Separately, Itron reported that its IntelliFLEX DERMS solution dispatched over 70 GWh of flexible customer load and generation in 2025 and now manages over 20 MW of battery storage and tens of thousands of EVs across Australia — the first large-scale IntelliFLEX production performance data publicly disclosed, confirming that grid-edge DERMS platforms are achieving operational scale in live deployments. The global DERMS market is forecast to grow from $1.7 billion in 2026 to $5.5 billion by 2033 at an 18.3% CAGR. (Source: DISTRIBUTECH 2026, GE Vernova, Itron — June 19 entry)

Pew State Policy Explorer reveals a gap between technology adoption policies and operational/market frameworks. The June 19 entry provides supplemental detail on the Pew DER State Policy Explorer (443 policies across all 50 states, 2021–2025; the report was covered in the June 12 digest from the April 28 release). The explorer’s breakdown is analytically notable: EVs accounted for 48% of enacted policies, solar 37%, and storage 32% — indicating that state-level DER policy has heavily weighted enabling-technology deployment over the operational and market frameworks (DERMS integration, VPP participation, DR program design) that utilities need to use those resources as grid assets. This gap is the DERMS vendor opportunity: states have created the technology base through policy but have not yet mandated the software and program architecture to dispatch it. (Source: Pew Charitable Trusts — June 19 entry; report previously covered June 12 digest)

🏗️ Data Centers & Large Load Growth

Gartner confirms 84% annual growth in AI server electricity — and states definitively that grid supply will be structurally insufficient. Gartner’s June 10, 2026 forecast is the most granular segmentation of data center power demand published to date: global data center electricity reaches 565 TWh in 2026 (+26% from 447 TWh in 2025), with AI-optimized servers consuming 175 TWh in 2026 (growing 84.2% year-over-year) versus conventional servers at 195 TWh (growing just 1.2%). AI-optimized servers will surpass conventional servers in 2027 at 258 TWh versus 200 TWh. Total power demand reaches 132 GW in 2026 and is projected at 290 GW by 2030 and over 1,200 TWh annually. Gartner’s conclusion is unequivocal: “Grid supply will be insufficient to meet the demands of future data center construction, affecting all data center users.” For DSM/DR program designers, the segmentation directly validates the Nature Energy EPRI field demonstration (June 12 digest, June 3 entry): the 84%-growth AI server category is precisely the category demonstrated to deliver 25% power reduction via software-only workload coordination. At 175 TWh of AI server consumption in 2026, even 10% participation at 25% reduction yields ~4.4 TWh of annually flexible energy — a DR resource pool requiring no hardware modifications. (Source: Gartner — June 15 entry)

PJM market monitor documents data centers drove 63% of the capacity price spike — $9.3 billion in 2025/26, up to $163 billion through 2033. Monitoring Analytics, PJM’s independent market monitor, has quantified the ratepayer cost of failing to deploy demand-side alternatives at scale. Data center load growth was responsible for 63% of the capacity price increase in PJM’s 2025/2026 Base Residual Auction ($9.3 billion in data-center-attributable costs), and 40% of the $16.4 billion total in the most recent 2026/2027 auction ($6.5 billion). Prices surged from $28.92/MW-day in 2024/25 to $269.92/MW-day in 2025/26 and $329.17/MW-day in 2026/27 — hitting FERC’s approved price cap for two consecutive auctions. IEEFA projects cumulative ratepayer exposure through 2033 at $100–$163 billion. Pepco customers in Washington, D.C. are already paying $21/month more from capacity cost pass-through. For DSM program designers preparing IRP filings in PJM territory, the market monitor’s 63% cost-causation attribution is an authoritative, public-record citation: every MW of DR or VPP capacity that clears in PJM capacity auctions below the $329/MW-day cap directly reduces the capacity cost allocated to all other ratepayers. The avoided-cost valuation case has never been stronger. (Source: IEEFA, Utility Dive, Monitoring Analytics — June 19 entry)

Sightline Climate: 30–50% of 2026 global data center pipeline will not materialize — bottleneck has shifted from chips to transformers. Sightline’s 2026 Data Center Outlook, tracking 190 GW across 777 projects announced since 2024, finds that of the 16 GW announced 2026 pipeline, only approximately 5 GW is actually under construction. The binding constraint has shifted from GPU supply to electrical infrastructure: transformer delivery timelines have extended from a pre-2020 baseline of 24–30 months to as long as five years, exceeding the typical 18-month data center build cycle. Community opposition is now described as “a true material driver of attrition.” For IRP analysts, this introduces a critical planning nuance: Gartner’s 132 GW and IEA’s 950 TWh projections represent announced demand, not committed capacity. Actual load may arrive 2–5 years later than forecast — which is precisely the scenario where demand-side resources excel. DR, VPPs, and DERMS-dispatched DER can be deployed and scaled incrementally as load materializes; supply-side generation and transmission require multi-year commitments against uncertain demand curves. Projects delayed by community opposition represent load that was planned for but will not arrive; supply-side investments sized for that phantom load become stranded assets. (Source: Sightline Climate, Latitude Media — June 16 entry)

NRG TH Wharton: first new Texas peaker in a decade — and a benchmark for demand-side comparisons. NRG Energy’s 456-MW TH Wharton Generating Station reached commercial operations May 26, 2026, the first new gas peaker built in Texas in approximately a decade and among the first completions under the Texas Energy Fund. The plant starts in ~30 minutes and can serve 100,000+ Texas homes during peak hours. For DSM/DR business case developers, TH Wharton provides a concrete supply-side cost reference: it required years of permitting and construction, 500+ jobs, ongoing fuel costs, and emissions — while NERC’s summer 2026 assessment documented a 3.7 GW reduction in ERCOT net internal demand from data center curtailability alone, equivalent to approximately eight TH Wharton plants, achieved through a regulatory policy change rather than physical construction. Texas is now simultaneously deploying supply-side peakers (TH Wharton) and demand-side frameworks (Batch Zero mandatory curtailment, ERCOT Competitive Reliability Services) — a planning posture that reflects the consensus that load growth is too fast and too large for either strategy alone, but that demand-side resources should be the first-deployed rather than the backstop. (Source: Axios Houston, NRG Energy — June 15 entry)

📋 Regulatory & Policy

FERC issues landmark Section 206 show-cause orders to all six RTOs/ISOs — demand flexibility becomes a structural tariff requirement. On June 18, 2026, FERC voted unanimously to issue tailored show-cause orders under Section 206 of the Federal Power Act to PJM, MISO, SPP, CAISO, ISO-NE, and NYISO — plus their transmission owners — directing each to either justify why their current tariffs remain just and reasonable or file tariff changes within 60 days across five reform categories: (1) efficient transmission service application and study processes including alternative transmission technologies; (2) cost transparency and prevention of cost shifting; (3) co-location agreements and behind-the-meter generation accommodation; (4) new transmission services for flexible large loads; and (5) processes for studying generating facilities serving electrically proximate large loads. Category 4 is the most consequential for demand-side programs: the explicit mandate for “new transmission services for flexible large loads” requires every RTO/ISO to create tariff pathways for curtailable, dispatchable demand-side resources at large load sites — directly expanding the addressable market for DERMS-coordinated DR and VPP services at data center scale. Additionally, each RTO/ISO must submit within 30 days an informational report on how it will ensure adequate generation to serve existing and new large loads — reports that will document resource adequacy gaps where demand-side resources can compete directly. FERC used Section 206 show-cause orders rather than the traditional ANOPR-NOPR-Final Rule pathway, making the action faster and harder to challenge legally; left the RM26-4 ANOPR docket open for further action, signaling this is a floor not a ceiling; and reached approximately 200 million Americans in 30+ states covering nearly two-thirds of commission-jurisdictional electricity load. (Source: FERC, Renewable Energy World, POWER Magazine — June 19 entry)

FERC approves SPP CHILLS — non-firm transmission framework establishes second RTO-level curtailability precedent. On June 5, 2026, FERC approved the Southwest Power Pool’s “Conditional High Impact Large Load Service” (CHILLS) framework, providing non-firm transmission service for up to seven years to large loads while firm-service network upgrades are constructed — conditioned on SPP’s ability to curtail these loads during transmission constraints or grid emergencies. CHILLS directly addresses the structural timing mismatch between the 5–10 year transmission upgrade timeline and the 12–24 month data center build cycle: large loads can begin operating immediately on non-firm service, with mandatory curtailability as the enabling condition. Every megawatt admitted under CHILLS is simultaneously a load addition and a built-in demand response resource. CHILLS is the second RTO-level curtailability precedent in 30 days, following ERCOT’s Batch Zero mandatory curtailment requirement (≥75 MW loads from 2026 onward, approved June 2, ERCOT board). With FERC’s June 18 show-cause orders now mandating that all RTOs develop “new transmission services for flexible large loads,” CHILLS and Batch Zero are likely templates for what those tariff filings will look like. For DERMS platform vendors, the convergence of ERCOT, SPP, and the six-RTO FERC orders strongly suggests mandatory or incentivized load curtailability will become a nationwide standard — creating a substantial new market for DERMS systems capable of managing curtailment dispatch, compliance tracking, and settlement for loads in the hundreds of megawatts. (Source: Utility Dive, RTO Insider — June 16 entry)

ERCOT Batch Zero PUCT approval — status pending. The Public Utility Commission of Texas was scheduled to vote on final Batch Zero approval on June 18, 2026 — the same day as the FERC show-cause order vote. As of the June 19 research log entry, the PUCT outcome is not confirmed in the log (Thursday June 18 entry is absent). If approved as expected, the Batch Zero timeline activates: developer submissions due July 15, 2026; study results by January 29, 2027; capacity allocations for 2028–2032. The mandatory curtailment condition (≥75 MW loads) means every Batch Zero entrant is also a potential DR resource. Watch for outcome confirmation. (Source: June 15 entry; outcome pending)

Microsoft proposes Nevada “Ratepayer Protection Tariff” — cost-causation moves from regulatory theory to hyperscaler-initiated practice. Microsoft filed a proposed tariff with the Public Utilities Commission of Nevada (PUCN) in May 2026 creating a new “Hyperscale Energy Users” tariff class that would require large data center operators to pay the full cost of grid upgrades their load growth necessitates, cap residential rate increases at 2%, and establish a public cost-tracking ledger from planning through operation. This is the first instance of a hyperscaler proactively proposing a tariff that embeds cost-causation principles — the same analytical framework that underpins avoided-cost DR business cases in IRP proceedings — rather than waiting for regulators or consumer advocates to impose cost allocation after the fact. For DSM/DR program designers, the Microsoft tariff increases the avoided-cost value of demand-side resources directly: if large loads bear the full marginal cost of grid upgrades they trigger (rather than socializing costs across all ratepayers), every MW of DR that reduces or defers those upgrades avoids not just wholesale energy and capacity costs but the full capital cost of the avoided infrastructure. The PUCN will accept public comment through October 2026 with evidentiary hearings in January 2027 — a timeline that could produce the first hyperscaler-initiated cost-causation tariff in a U.S. jurisdiction by mid-2027. The Nevada proceeding, combined with the Pennsylvania “but for” model tariff (May 2026, June 12 digest) and the FERC RM26-4 cost-allocation questions, is building a multi-jurisdictional record for cost-causation tariff design. (Source: Utility Dive, Energy Central, Latitude Media — June 16 entry)

DOE Emergency Order 202-26-26: Florida coal plant retained explicitly for data center demand growth. On June 4, 2026, Energy Secretary Chris Wright issued Order 202-26-26 keeping the Orlando Utilities Commission’s 465-MW Stanton Energy Center Unit 1 running through September 1, 2026, instead of its planned cold shutdown. The order’s stated justification cites “a shortage of generation facilities and expected electricity demand growth associated with a burgeoning data center industry in Florida” — one of the clearest instances of the federal 202(c) emergency authority being exercised specifically for projected hyperscaler load growth rather than an acute weather event. Power Magazine’s tracker now documents 43+ Section 202(c) orders since May 2025, preventing at least 4.4 GW of coal retirements at an estimated $235 million in ratepayer cost (Sierra Club analysis). For DSM/DR business case developers, the Stanton order sharpens the economic argument: the federal government is spending ratepayer money to keep aging coal online because demand-side alternatives have not been deployed fast enough in regions experiencing data-center-driven load growth. Every MW of DR or VPP capacity deployable in Florida and similar markets directly reduces the need for future 202(c) orders and their above-market coal retention costs. (Source: Utility Dive, DOE — June 17 entry)

🏭 Utility Programs & Deployments

ERCOT mandatory curtailment is producing measurable reliability results — 3.7 GW demand reduction documented before Batch Zero even launches. NERC’s summer 2026 assessment (covered in the June 12 digest from the June 10 entry) documented a 3.7 GW reduction in ERCOT net internal demand specifically attributable to data centers being more frequently curtailable. This result was achieved before the PUCT votes on Batch Zero and represents the baseline from Texas’s existing 2025 curtailment rules. As Batch Zero brings hundreds of additional GWs of data center capacity into ERCOT’s interconnection pipeline — each with mandatory curtailment obligations — the measurable demand-side resource pool will grow substantially. ERCOT’s Competitive Reliability Services market (also watch-listed from June 12) is the mechanism through which this curtailment capacity will eventually settle into formal market participation. (Source: June 15 entry, referencing NERC summer 2026 assessment from June 10 entry)

FERC Order 2222 ISO-NE (November 1, 2026) remains on track — under four months away. No new update this week, but the clock is running. ISO-NE utilities (National Grid, Eversource, Unitil, Green Mountain Power) have fewer than four months to complete eligibility assessments for enrolled DR assets under the new wholesale market framework. This was flagged as an “Implement” action in the June 12 digest; the urgency has increased by one week. (See June 12 digest for full treatment)

🔬 EPRI Research Spotlight

No new EPRI-published research appeared in the June 15–19 research log entries. However, the FERC Section 206 show-cause orders and the DERMS industry context from this week directly build on the EPRI/Boston University Nature Energy paper (Volume 11, February 2026) covered in the June 12 EPRI spotlight — the peer-reviewed validation that AI data centers can deliver 25% power reduction through software-only workload coordination. That paper’s findings are now embedded in the practical policy context created by this week’s FERC action: FERC’s Category 4 requirement for “new transmission services for flexible large loads” will produce RTO tariff filings that must define the MW capabilities of curtailable demand-side resources, and EPRI’s documented 25% reduction capability is the reference standard for what AI data center DR can deliver. Additionally, the SCE deployment of IEEE 2030.5 as its ADMS-DERMS DER communication standard (June 19 entry) reflects a protocol with EPRI involvement in development; the standard’s adoption by the largest California IOU signals its likely spread to other large-utility DER deployments. Watch for EPRI comment filings in the 60-day RTO tariff-revision proceedings triggered by FERC’s June 18 orders — those filings will be critical inputs for utilities shaping their DR program designs in response.

🚩 Utility-Sector Relevance Flags

⚑ FERC Section 206 Show-Cause Orders: 60-Day Clock Is Running
Topic: Regulatory / Demand Response / DERMS
Relevance: FERC’s unanimous June 18 action formally requires all six RTOs/ISOs to either justify existing tariffs or file changes within 60 days — meaning tariff revision filings are due by approximately August 17, 2026. Category 4 (new transmission services for flexible large loads) and the 30-day resource adequacy informational reports are the most directly relevant to demand-side program designers. The resource adequacy reports will document, in each RTO’s own words, the gaps that demand-side resources can fill — making them critical inputs for IRP avoided-cost arguments. Utilities with DR programs serving large C&I customers should review whether those programs could qualify under new “flexible large load” tariff pathways as they are filed.
Action Signal: Implement — Begin now: (1) inventory existing large C&I DR program enrollment and capabilities; (2) identify which RTO show-cause proceedings affect your service territory; (3) prepare comments or engage in each RTO’s stakeholder process for the 60-day tariff revision, specifically to shape how demand flexibility is defined as a qualifying service; (4) monitor the 30-day resource adequacy reports for gaps that DR programs can document addressing.

⚑ SPP CHILLS + ERCOT Batch Zero: Curtailability as Interconnection Currency
Topic: Regulatory / Demand Response / Grid Integration
Relevance: CHILLS and Batch Zero together establish a clear multi-RTO pattern: large loads that accept curtailability get accelerated or conditional grid access, while loads that cannot demonstrate demand flexibility face longer queue timelines or cost-of-firm-service premiums. With FERC’s June 18 orders mandating similar frameworks across all six RTOs, curtailability is becoming a standard condition of large-load interconnection nationwide. For DSM/DR program designers, this creates a market pull for formal DR programs that didn’t exist two years ago: data center developers now have a direct financial incentive to enroll in utility DR programs to demonstrate curtailability credentials as part of their interconnection applications.
Action Signal: Engage — Utilities in SPP and ERCOT territories should engage proactively with large-load customers about how utility DR program enrollment can support their interconnection applications under CHILLS and Batch Zero; begin developing large-load DR program designs that can document curtailment capability in a format acceptable to RTO interconnection studies.

⚑ PJM Capacity Costs: $9.3 Billion Market-Monitor Citation for DR Avoided-Cost Arguments
Topic: Demand Response / IRP / Cost Justification
Relevance: PJM’s independent market monitor — not a DR vendor, advocacy group, or consultant — has documented that data centers caused 63% of the 10× capacity price increase in the 2025/26 auction, translating to $9.3 billion in additional ratepayer costs. In the 2026/27 auction, data centers represent 40% of $16.4 billion in total capacity costs. These figures are directly usable in IRP avoided-cost calculations: a DR program that reduces or defers data center capacity additions in PJM territory avoids costs measured at the $329/MW-day capacity price cap, not at the historical baseline of $28.92/MW-day. The market-monitor attribution also strengthens the argument for large-load-specific DR program structures — if data centers caused the cost increase, large-load DR programs targeting data center customers are the natural mitigation mechanism.
Action Signal: Implement — Incorporate the Monitoring Analytics cost-attribution data into next IRP filing and any pending DR program cost-effectiveness analyses; use the $329/MW-day price cap as the avoided-cost benchmark for PJM-territory DR programs; cite Monitoring Analytics (not advocacy sources) for maximum regulatory credibility.

⚑ Microsoft Nevada Ratepayer Protection Tariff: Cost-Causation Framework in Active Proceeding
Topic: Regulatory / Large Load / Program Finance
Relevance: The PUCN proceeding (public comment through October 2026, hearings January 2027) will produce the first evidentiary record for a hyperscaler-initiated cost-causation tariff. If approved, it directly increases the avoided-cost value of DR programs in NV Energy’s territory by making infrastructure costs attributable and avoidable — every MW of peak reduction translates to documented avoided grid upgrade costs that Microsoft and other large-load customers would otherwise bear. The proceeding is also a test case for whether cost-causation frameworks can attract hyperscaler support rather than opposition. Utilities in states considering similar large-load cost allocation proceedings (see Pennsylvania “but for” tariff, June 12 digest) should monitor this docket as regulatory precedent.
Action Signal: Watch — Monitor PUCN Docket [Microsoft Ratepayer Protection Tariff]; assess whether similar tariff designs are actionable in your state; model how full cost-causation attribution would change the avoided-cost calculation for DR programs serving large-load customers.

⚑ NRECA Cooperative BESS Expansion: Underappreciated DERMS Market Segment
Topic: Utility Programs / DERMS / Energy Storage
Relevance: Rural electric cooperatives are deploying battery storage at scale without regulated rate-of-return incentives, driven by wholesale demand charge economics. At 42 million customers and 56% of U.S. landmass — and with a governance structure that allows faster program adoption than regulated IOUs — cooperatives represent a significant and underserved DERMS procurement opportunity. The specific programs documented (Guadalupe Valley scaling to 50 MW, EPB Chattanooga doubling to 90 MW, Connexus registering assets in MISO capacity markets) demonstrate that cooperative deployments are reaching the scale where DERMS orchestration is required for dispatch, forecasting, and market participation. TVA’s 1.5 GW storage target is an accelerant: as TVA deploys, its member cooperatives have direct pressure to optimize demand charges against the TVA rate structure.
Action Signal: Engage — DERMS vendors and DSM program administrators should assess cooperative membership in TVA, NRECA, and G&T cooperative service territories as a distinct market segment; cooperative peak shaving programs can qualify for MISO and PJM capacity market revenue without IOU regulatory complexity.

⚑ Illinois CRGA June 30 Deadline: Benchmark Decision in 11 Days
Topic: Regulatory / VPP / Program Design
Relevance: The Illinois Commerce Commission will approve, modify, or reject ComEd’s scheduled dispatch VPP tariff by June 30, 2026. The ICC’s ruling on the $300/kWh distributed storage rebate and $10/kW dispatch compensation structure will be the first public-record decision on a state-mandated VPP tariff with specified economics — a benchmark that other state commissions, utility program designers, and DERMS vendors will reference in ongoing proceedings (Virginia, New Jersey, Massachusetts, Maryland). An approval signals that state-mandated VPP program economics are regulatorily defensible; a modification will reveal where the ICC found the economics deficient.
Action Signal: Engage — Monitor the ICC ComEd VPP docket for the June 30 decision; if you have VPP programs under development in any state, the ICC’s reasoning on participation compensation, measurement and verification, and scheduled dispatch architecture will directly inform your program design and regulatory strategy.

⚑ ERCOT Batch Zero PUCT Vote: Status Pending — Action Trigger if Approved
Topic: Regulatory / Large Load / DERMS
Relevance: If PUCT approved Batch Zero on June 18 as scheduled, the developer submission deadline is July 15 — three weeks away. Batch Zero’s mandatory curtailment requirement (≥75 MW loads) means every project that submits becomes a potential DR resource in ERCOT by 2028–2032. Utilities and DERMS vendors in ERCOT territory should be preparing for the coordination challenge of managing tens of GWs of batch-allocated large loads, all with curtailment obligations, entering the grid in a compressed multi-year window.
Action Signal: Watch — Confirm PUCT approval; if approved, begin scoping DERMS architecture requirements for managing Batch Zero large-load curtailment dispatch at scale; engage with ERCOT’s Competitive Reliability Services program design as the settlement mechanism for this capacity.

📌 Sources Consulted

June 19, 2026 Entry
– FERC — FERC Launches Aggressive Targeted Action to Speed Large Load Integration (June 18, 2026)
– Renewable Energy World — FERC Takes Historic Action, Orders US Grid Operators to ‘Defend or Revise’ Large Load Interconnection Tariffs (June 18, 2026)
– POWER Magazine — FERC Orders All Six Regional Grid Operators to Justify or Rewrite Large-Load Tariffs (June 18, 2026)
– IEEFA — Projected Data Center Growth Spurs PJM Capacity Prices by Factor of 10 (2026)
– Utility Dive — Data Centers Were 40% of PJM Capacity Costs in Last Auction: Market Monitor (2026)
– Utility Dive — Data Centers ‘Primary Reason’ for High PJM Capacity Prices: Market Monitor (2026)
– DISTRIBUTECH 2026 — Delivering a Reliable and Resilient Grid Through SCE’s Integrated ADMS and DERMS Journey with GE Vernova
– GE Vernova — ADMS vs. DERMS: Key Differences Explained (2026)
– Itron — Itron and GE Vernova Pioneer Unification of Grid Edge and Grid Operations Data (2026)
– Pew Charitable Trusts — Explore How States Are Advancing Distributed Energy (2026)
– Pew Charitable Trusts — Distributed Energy Can Unleash the Resilient, Affordable Grid of the Future (April 2026)
– Pew Charitable Trusts — Pew Report Charts Path to Accelerate Use of Distributed Energy Nationwide (April 28, 2026)

June 17, 2026 Entry
– SEPA — VPP and Supporting DER Policy Developments: Q1 2026 (May 11, 2026)
– DSIRE Insight — VPP and Supporting DER Policy Developments: Q1 2026 (May 13, 2026)
– Utility Dive — DOE Orders OUC’s 465-MW Coal Unit in Florida to Continue Running (June 4, 2026)
– DOE — Federal Power Act Section 202(c): Orlando Utilities Commission Order No. 202-26-26 (June 4, 2026)
– Power Magazine — DOE’s Section 202(c) Emergency Orders Since May 2025: 43 and Counting (April 2026)
– Utility Dive — Not-for-Profit Utilities Turn to Energy Storage as Data Centers Drive Cost, Reliability Concerns (June 9, 2026)
– NRECA — Battery Energy Storage Projects at Rural Electric Cooperatives (2026)

June 16, 2026 Entry
– Utility Dive — Google to Fund 100-MW Virtual Power Plant in PJM in ‘First-of-Its-Kind’ Deal (June 2026)
– Voltus — Voltus and Google Announce Bring Your Own Capacity Agreement (June 2026)
– Microgrid Knowledge — Google Signs 100-MW Virtual Power Plant Deal with Voltus (June 2026)
– Utility Dive — FERC Approves SPP Non-Firm, Large-Load Transmission Service (June 2026)
– RTO Insider — FERC OKs SPP’s Non-Firm Service for Large Loads (June 2026)
– Utility Dive — Microsoft Seeks Nevada Tariff to Shield Ratepayers From Data Center Costs (June 2026)
– Energy Central — Has Microsoft Cracked the Ratepayer Protection Code? (June 2026)
– Latitude Media — Big Tech Pledged to Pay for Power — But Some Tariffs Already Require It (June 2026)
– Sightline Climate — Data Center Outlook: Half of 2026 Pipeline May Not Materialize (2026)
– Latitude Media — Up to Half of the World’s Data Centers May Be Delayed This Year (2026)
– Semafor — Data Centers Hit by Power Delays, Equipment Shortages (February 2026)

June 15, 2026 Entry
– Gartner — Data Center Electricity Consumption to Grow 26% in 2026 (June 10, 2026)
– Houston Public Media — ERCOT Votes to Streamline Process for Data Centers Looking to Join the Power Grid (June 2, 2026)
– Foley & Lardner — ERCOT’s Proposed “Batch Zero” Process: What Developers of Large Loads Need to Know (2026)
– Seyfarth Shaw — ERCOT’s Batch Zero Proposal and What It Means for Large-Load Projects in Texas (2026)
– Axios Houston — NRG Energy Opens First New Power Plant in a Decade (June 11, 2026)
– NRG Energy — Powering Texas: New NRG Peaker Units Bring Needed Power to Texans (2026)
– The Energy Mag — Texas Adds 456 MW of Gas-Fired Power in Houston as ERCOT Braces for Summer Demand (June 11, 2026)