This week: California made distributed flexibility a paid grid resource in statute, as Gov. Newsom signed SB 913, which directs the CPUC to value customer-owned battery VPPs, and SB 905, which requires utilities to publish circuit-level grid-utilization data and run load-flexibility programs. He also vetoed a 4-GW community-solar bill on cost grounds. The device base proved it can deliver: on October 6, 85,774 California Powerwall homes dispatched a record 601 MW, beating the previous record after just 27 days. And the week’s resource plans showed how far the demand side still has to go: Ameren Missouri filed for about 10.6 GW of new gas with demand response left unquantified, while hyperscalers such as Google began writing load-shaping and demand-response terms into their own supply deals.
Put those together and the week’s argument is about who gets credit for flexibility. California is writing the valuation rules that would pay a customer’s battery for peak exports. Tesla’s fleet showed that roughly 600 MW of that flexibility can be called on short notice. Two investor-owned and public-power IRPs still left the demand side out of the preferred plan, while the largest data-center buyers are building flexibility into their contracts without the utility. Flexibility is now plainly available. The open question is whether a utility counts it inside its plan, or watches customers and hyperscalers capture its value outside it.
⚡ Virtual Power Plants & Demand Flexibility
A residential battery fleet delivered 601 MW in October, and the growth rate matters more than the record. On Tuesday, October 6, with CAISO statewide demand at 45,622 MW at 5 p.m. and daily peaks above 44,000 MW Monday through Wednesday, 85,774 participating Tesla Powerwall homes reached a 601-MW peak and delivered 932 MWh. The whole California Powerwall fleet, including non-participants, peaked at 634 MW, which works out to roughly 7 kW per participating home. The previous record of about 500 MW from about 69,000 owners on September 9 lasted 27 days. In under a month, enrolled homes grew about 24% and peak output about 20%, compared with just over 7,000 participating Powerwalls in 2023. The figure is not directly comparable to the 580-MW combined Tesla/Sunrun dispatch of September 21, which included non-Tesla batteries.
For a DR business case, the lesson is that a ~600-MW resource can be enrolled and dispatched within weeks. Its durability depends on program funding, not on the technology. California owners are generally paid through DSGS and ELRP, and in May Tesla told the CPUC it had been “forced to transition thousands of customers” from DSGS to ELRP because of DSGS’s budget shortfall. ELRP pays $2/kWh to non-residential participants, including aggregators, and events can be called through the end of October. Accredit this capacity with a funding-continuity discount, and note that Tesla did not name the calling program or disclose payouts for the event. (Source: TeslaNorth, October 8 — October 9 entry)
The aggregator business is consolidating into whole-home orchestration. On October 6, Renew Home, which manages more than 8 million residential smart thermostats, rebranded as Everyday Electric and acquired connected-vehicle platform Smartcar. Its new “whole-home” VPP draws on HVAC, EVs, stationary batteries and solar together. For utilities it packages hyper-local dispatch, AMI-based M&V, real-time forecasting and load shaping on a pay-for-performance basis with no platform or marketing fees. This tackles the soft cost of standing up a demand-side portfolio. The caveat is that no utility customers are named for the new product, and Everyday Electric’s own dispatchable MW are not broken out from the ~17-GW Sunrun/Tesla coalition figure it belongs to, so the scale is a platform capability rather than contracted capacity. (Source: Utility Dive, October 7 — October 8 entry)
Illinois’s VPP design questions now have a utility author. In an October 6 op-ed, ComEd VP Andrew Plenge called the approved Scheduled Dispatch VPP “just a first step” and said ComEd will file a broader multi-device framework, potentially covering EVs and smart appliances, by the end of 2027 under the Clean and Reliable Grid Affordability Act. He names three design problems:
- Incentive levels high enough to attract participation that still produce net benefits for all customers.
- Dispatch frequency and duration that meet grid needs without causing customer fatigue.
- Coordination across load-flexibility programs so they serve both system-wide and localized peaks.
These map directly onto the avoided-cost model’s three biggest sensitivities: $/kW-year incentive cost, achievable dispatch hours and attrition, and the split between system value and T&D-deferral value. Treat the 2027 filing as the template to watch for multi-device VPP tariffs. The piece gives no MW, enrollment or payment figures. (Source: Utility Dive, October 6 — October 9 entry)
Carried — SEPA’s Q2 2026 VPP/DER policy roundup (Illinois scheduled-dispatch tariffs, DTE’s $105/kW-year battery pilot, Hawaii’s competitively selected third-party edge-DERMS agent, Entergy Louisiana’s $81M DR suite). This was reported in the July 24 digest and carried through September. It re-entered the log this week as a gap-fill and adds nothing new.
🔌 DERMS & Grid Integration Technology
The binding constraint on flexible interconnection is control-room software, according to the utilities doing it. In an October 5 Latitude Media analysis, utility and RTO staff say the obstacle to trading load flexibility for faster large-load interconnection is operational, not regulatory. Control-room tools “wasn’t designed to manage dynamic curtailment stacks” (“the tools just don’t do it today”), and operators lack real-time visibility into large loads’ actual curtailable capability and contract terms. The stakes are already live:
- Arizona Public Service holds roughly 400 MW of flexible-interconnection agreements, used as a reliability backstop.
- Southwest Power Pool is fielding 32 large-load requests totaling about 15 GW through new flexible pathways.
The soft barriers are named too: large customers resist curtailment (“being treated like a second-class citizen just doesn’t sell very well”), and utilities worry about brand risk with premium customers. For a DERMS or ADMS RFP, this means curtailment-stack management and large-load telemetry are now requirements, not roadmap items. It is the same visibility gap a distribution DERMS solves, now showing up at the transmission interconnection layer. (Source: Latitude Media, October 5 — October 6 entry)
CESA turned VPP risk into a three-word DERMS specification. The Clean Energy States Alliance’s report “The ABCs of VPPs” frames utility risk around three questions:
- Visibility: can the utility see what the VPP is doing before, during and after dispatch?
- Schedulability: does it respond predictably to dispatch instructions?
- Availability: is it reliably there across seasons?
These are, in plain English, the telemetry, dispatch and performance-measurement layers a DERMS must provide. The report frames VPPs as avoided-cost resources and invokes the RIM test to surface cost shifts between participants and non-participants. That is the right screen to bring into any VPP filing after this week’s California community-solar veto (see Distributed Solar below). Scale context: DOE’s 80–160 GW by 2030 target against roughly 37.5 GW enrolled last year (Wood Mackenzie). It is a maturity checklist rather than a procurement template, so it pays off only once it is turned into enforceable contract terms. (Source: pv magazine USA, October 2 — October 5 entry)
Itron packaged AMI 2.0 edge intelligence as a reliability outcome. On October 8, Itron launched GEI Catalyst: Feeder Reliability, a turnkey bundle for selected feeders. It combines distributed-intelligence Riva meters, Gen 5/Gen 6 networks, the Intelligent Edge OS, reliability analytics, hosted infrastructure and implementation. It works alongside SCADA, OMS and ADMS with open integration. Itron cites 6–12 minutes of SAIDI improvement (about 10%) in assessments at three unnamed North American utilities and estimates $40M–$90M a year of value for a ~1M-customer utility, but does not disclose the model’s assumptions. The release never mentions DERMS. Still, the same feeder- and transformer-level visibility layer is what DERMS hosting-capacity and locational-dispatch functions depend on. Treat the value figures as unvalidated in any benefit-cost model. The outcome-based packaging is worth tracking alongside the capacity-as-a-service DERMS models covered last week. (Source: Itron, October 8 — October 9 entry)
🏗️ Data Centers & Large Load Growth
Hyperscalers are now writing demand response into their own supply contracts. On October 6, Constellation and Google announced a 20-year PPA for 890 MW of new nuclear capacity from uprates at 11 units across six sites in Illinois, Pennsylvania and New Jersey. It is a $4.3B investment with the first uprate online in 2028, alongside a separate 15-year, 2,700-MW supply agreement across PJM. It is framed as a response to PJM’s “bring your own power” expectation amid the ~6.8-GW 2028/29 shortfall. The DER-relevant clause is that the deal includes operational load-shaping and demand-response capabilities to cut use during grid stress. No MW, mechanism or timeline is given, so treat the demand-side value as directional. The structural point is that even a nuclear-anchored hyperscaler deal now carries a flexibility obligation, which makes curtailable large-load capability a standard term. (Source: Utility Dive, October 6 — October 8 entry)
The industry has a standards body for flexible data centers. The AI Energy Management Alliance, founded September 17 by Google, NVIDIA and Emerald AI and chaired by Google’s Tyler Norris, aims to make flexible, grid-responsive operation a standard data-center capability. Launch partners include Anthropic, AES, Constellation, National Grid, NRG, RWE, Fluence, GridUnity and Voltus. Google says it has already integrated 1 GW of demand response into long-term utility contracts (OPPD, I&M, TVA, Entergy Arkansas, Minnesota Power, DTE). Norris argues that reducing net grid withdrawal for under 100 hours a year could unlock dozens of GW of capacity, compared with 5–7+ years for traditional upgrades, backed by companion Brattle and Aurora Energy Research reports. It is a standards and advocacy coalition, not a deployment, so its influence will show up first in tariff and interconnection design. (Source: Data Center Dynamics, September 17 — October 8 entry)
The economics got a headline number, and so did its limits. A Reuters explainer of October 8 cites a Duke University Nicholas Institute estimate that data-center flexibility could save $40–150B in capital investment over the decade. It pairs this with EPRI projections of U.S. data-center use rising from 177–192 TWh (2024) to 383–793 TWh (2030), surveyed facilities reporting 10–30% peak-reduction potential, and OpenAI agreeing to cut grid draw by up to 1 GW from a planned 3.2-GW Georgia facility during stress events. The barriers the piece lists are the practical ones: operations data centers can absorb without disrupting customers, tariffs and markets that actually reward flexibility, and capital plus coordinated policy. The $40–150B figure is a capital-savings estimate from one study, not total grid savings, so cite it that way. (Source: Reuters via 93.3 The Drive, October 8 — October 8 entry)
Planners are pricing curtailment risk as the cost of speed. An October 8 Utility Dive analysis argues that large-load planning keeps missing near-term options. The ESIG/Brattle July report Transmission Planning with Large Loads calls for proactive, least-regrets planning with load flexibility built in, and names reconductoring and advanced conductors as “fast and cost-effective near-term options.” SPP offers the most concrete ladder of service tiers, each trading interconnection speed for curtailment exposure:
- HILL/HILLGA, approved by FERC in January, with studies taking about 90 days.
- Conditional HILL (CHILL), for loads that accept curtailment when transmission is inadequate.
- Price Adaptive Load Service (PALS), pending at FERC, which SPP calls “true connect and manage”: no matched generation or transmission, in exchange for significant curtailment risk.
All six RTOs/ISOs asked for more time on FERC’s June 18 show-cause orders. Model these tiers as a distinct flexibility resource with explicit curtailment risk, separate from conventional DR capacity. (Source: Utility Dive, October 8 — October 9 entry)
Carried — ComEd’s ~40-GW data-center pipeline against a 23.8-GW historic peak, and its line that planning has moved from “forecasting the future” to “negotiating the future.” This is from the May 11 IEEE PES T&D session coverage that entered the log this week. It is new to this series as a quotation, but it is five months old, so cite it as the May figure.
📋 Regulatory & Policy
California put a price on distributed flexibility in statute. On October 1–2, Gov. Newsom signed Sen. Josh Becker’s paired bills:
- SB 913 directs the CPUC to establish a valuation methodology under which customer-owned batteries and other behind-the-meter DERs are paid for peak-period exports, with VPP-competition rules finalized by June 30, 2028, explicitly to cut reliance on aging gas peakers.
- SB 905 requires the large IOUs to publish distribution grid-utilization (load-factor) metrics so regulators can see which circuits and substations have headroom. It also requires annual grid-utilization improvement and load-flexibility programs that reward off-peak use.
This series first reported SB 913 in May, when it was in committee. This week’s signing moves it from a tracked bill to law. Together the two bills give planners the price signal (SB 913) and the circuit-level data (SB 905) needed to bid a flexible-load portfolio against deferred generation and T&D. Read beside last week’s CPUC mandate for a “Load Flexibility Scenario” in distribution planning, California has now required flexibility to be modeled, measured and paid. The caveat comes from Becker’s own camp: the methodology will be written at the CPUC under the next governor, so the rulemaking, not the signing, decides customer savings. (Source: pv magazine USA, October 2 — October 5 entry)
Carried — FERC’s six June 18 §206 show-cause orders (EL26-67 through EL26-72) on large-load integration. These were reported repeatedly from June through September and re-entered the log this week as a stand-alone gap-fill. The only movement is in the Oct. 8 planning analysis above: all six RTOs/ISOs requested extensions.
Carried — Columbia CGEP’s GETs-plus-DR affordability analysis (June 23). This was reported in the June 26 digest and carried through September 11. It is not re-reported.
☀️ Distributed & Community Solar
Affordability is now the gatekeeper for DER deployment, and it cut against community solar. Newsom vetoed AB 1813, which would have created a community-solar program capped at 5 MW per project and 4 GW in total. He called it “structurally flawed,” saying it would set a price “that exceeds the value that generation provides to the grid,” and his office put the added cost at about $1.5B a year. Supporters cited an Aurora Energy Research estimate of $6.5B in 20-year system savings. The gap is a methodology dispute, but the lesson for demand-side practitioners is clear: any DER or DR program whose compensation is not tied to avoided-cost value is now exposed to a RIM-style cost-shift challenge. That is the strongest argument yet for building programs on valuation methods like SB 913’s. (Source: Energy-Storage.news, October 2 — October 5 entry)
California also opened the country’s largest plug-in solar market. SB 868 (Sen. Scott Wiener) legalizes plug-in “balcony” solar up to 1,200 W (AC) with no utility interconnection application, subject to UL certification and automatic shutoff in outages. About 14 million rental units become eligible. Each system has little grid impact, but the base of customer-sited DER is growing. The caveat is that these systems are invisible to the utility by design, so without metering they add to the unobservable-DER problem in distribution planning rather than to dispatchable flexibility. (Source: pv magazine USA, October 1 — October 5 entry)
🏢 Utility Programs & Resource Plans
Two IRPs answered data-center load with supply and left demand response unquantified. That gap is where intervenors can come in.
- Ameren Missouri (filed September 28) projects demand growth of 2.9–3.9 GW by 2030, 5–6 GW by 2035 and 6–9 GW by 2045, tied to data centers and large primary-service customers. It proposes about 10.6 GW of new gas, which inverts last year’s 60%-clean-by-2045 target. It does add 2,400 MW of batteries by 2030, ~1,300 MW of solar and 1,200 MW of new nuclear by 2040. EE and DR appear only as “continued implementation,” with no quantified targets. (Source: mgrid.org, September 30 — October 6 entry)
- Santee Cooper (September 29) raises its winter peak forecast by about 1,250 MW by 2030 and 1,375 MW by 2040 against its 2023 plan. It identifies a ~350-MW firm-capacity need for 2027–2032 ahead of a joint NGCC unit around 2035, plus the Fairfield (V.C. Summer) nuclear restart and a 300-MW Pinopolis battery. The public summary does not foreground DR or DSM. (Source: American Public Power Association, September 29 — October 6 entry)
The 2027–2032 window in Santee Cooper’s plan is exactly where a demand-side portfolio is the only resource that arrives in time, and Ameren’s unquantified DR line invites an intervenor’s avoided-cost counter-case. Both are summaries, so check the full filings before arguing from them.
A distribution plan shows what the alternative looks like. PNM’s draft 2026 Distribution System Plan (October 1) reports 48,635 DER installations totaling ~692.6 MW already on its system. It is moving toward fully automated feeder-by-feeder hosting-capacity analysis and public hosting-capacity maps, funded by a Commission-approved $344M, six-year grid-modernization plan (AMI, distribution automation, ADMS, FLISR, Volt/VAR, cybersecurity). It explicitly treats DR, DSM, managed EV charging and EE as non-wires alternatives that can defer distribution projects. This is the avoided-T&D mechanism written into a utility’s own plan, and a useful capital and capability benchmark for ADMS/DERMS costing. It is a draft, so the deferral value depends on how aggressively PNM puts the screening into practice. This also follows last week’s EPRI/PNM microgrid item, where PNM cited only ~40 MW of balancing-authority flexibility against ~300 MW of proposed data centers. (Source: PNM, October 1 — October 6 entry)
🔬 EPRI Research Spotlight
No new EPRI publication dated inside this week’s window was found in a direct check: the thirteenth dry week in a row. EPRI’s research still showed up secondhand. The October 8 Reuters explainer relies on EPRI’s 383–793 TWh by 2030 data-center consumption range and its survey finding of 10–30% facility-level peak-reduction potential (see Data Centers above). As in prior weeks, this is reported as a pattern in EPRI’s publishing, not a gap in coverage.
Standing watch: Aurora/DCFlex 96-MW Manassas commissioning (still targeted for late 2026); the NERC Computational Load Owner/Operator Rules of Procedure comment period, which was unconfirmed last week and remains unconfirmed; and whether EPRI’s DER-integration team publishes the microgrid-standardization work referenced in last week’s PNM feature.
🚩 Utility-Sector Relevance Flags
⚑ California Wrote VPP Valuation Into Law — Prepare for the CPUC Rulemaking, Not the Headline
Topic: VPP Valuation / Load-Flexibility Mandate / Avoided-Cost Method
Relevance: SB 913 requires a CPUC valuation methodology for peak-period exports from customer-owned batteries, with VPP-competition rules due June 30, 2028. SB 905 requires published distribution grid-utilization metrics, annual utilization improvement and load-flexibility programs.
Action Signal: Engage — The money will be decided in the rulemaking under the next administration. Arrive with an avoided-cost-grounded methodology drafted, because this week’s AB 1813 veto shows that compensation not tied to grid value will be attacked as a cost shift. Outside California, propose SB 905’s circuit-level utilization disclosure as a smaller, more winnable first step. It produces the data that targets deferral value.
⚑ Accredit Battery-VPP Capacity With a Funding-Continuity Discount
Topic: Residential VPP Performance / Program Funding Risk
Relevance: 601 MW from 85,774 homes on October 6, beating the Sept. 9 record (~500 MW) after 27 days. Tesla moved thousands of customers from DSGS to ELRP because of DSGS’s budget shortfall.
Action Signal: Implement — The technology question is answered and the funding question is not. When counting residential-battery VPP capacity, apply a discount tied to the remaining authorized life of the program that pays for it, and make program continuity an explicit planning input.
⚑ IRPs Are Leaving Demand Response Unquantified Against Data-Center Load — That Is the Intervention Point
Topic: IRP Resource Mix / DSM-DR Underweighting
Relevance: Ameren Missouri: ~10.6 GW new gas, EE/DR with no quantified targets. Santee Cooper: ~350 MW firm need for 2027–2032 before a ~2035 NGCC, with DR not foregrounded.
Action Signal: Engage — File an avoided-cost counter-case aimed at the near-term gap years, when gas cannot arrive and DR, storage and flexible load can. Make sure demand-side resources are priced as capacity available by a date, not only per kW-year.
⚑ Flexible Interconnection Is Now a Control-Room Requirement — Put It in the RFP
Topic: DERMS/ADMS Requirements / Large-Load Curtailment
Relevance: Utilities say control-room tools can’t manage dynamic curtailment stacks and lack real-time visibility into large-load capability. APS holds ~400 MW of flexible agreements, and SPP has 32 requests totaling ~15 GW. SPP’s HILL → CHILL → PALS tiers trade speed for curtailment risk.
Action Signal: Implement — Add curtailment-stack management, large-load telemetry and contract-term visibility to ADMS/EMS/DERMS requirements as pass/fail items. Model curtailable service tiers as a separate flexibility resource, not as DR capacity with an avoided-cost value.
⚑ Hyperscalers Are Contracting Flexibility Directly — Offer a Utility Product or Lose the Value
Topic: Large-Load Flexibility / Bring-Your-Own-Power
Relevance: Constellation–Google (890 MW nuclear uprates, 2,700 MW supply) includes load-shaping and demand response. Google reports 1 GW of DR already in utility contracts. The AI Energy Management Alliance aims to standardize flexible data centers.
Action Signal: Engage — Flexibility negotiated bilaterally between a hyperscaler and a generator does not show up in the utility’s plan. Offer a standard flexible-interconnection or large-load DR tariff with defined depth, notice and M&V, so this capacity is counted inside the regulated planning process.
⚑ Multi-Device VPP Tariffs Are Coming — Use ComEd’s Three Questions as the Design Checklist
Topic: State VPP Program Design
Relevance: ComEd will file a broader VPP framework (EVs, smart appliances) by the end of 2027. The open design questions are incentive level vs. net benefits, dispatch frequency vs. fatigue, and system vs. local peak coordination.
Action Signal: Watch — These three parameters are the main sensitivities in a VPP avoided-cost model. Write them down explicitly in your own program filings now, so the 2027 Illinois record can be used as a benchmark when it arrives.
📌 Sources
October 5, 2026 Entry
– pv magazine USA — How California’s Latest Climate and Energy Bills Reshape the Grid (SB 913, SB 905; October 2, 2026) (SB 913 previously reported in May at the committee stage; signing is movement)
– Energy-Storage.news — Newsom Signs VPP and Balcony Solar Bills, Vetoes Community Solar Legislation (AB 1813; October 2, 2026) (first appearance)
– pv magazine USA — Newsom Signs California Plug-In Solar Bill (SB 868; October 1, 2026) (first appearance)
– pv magazine USA — Reducing VPP Risk for Utilities, Participants and Other Ratepayers (CESA “The ABCs of VPPs”; October 2, 2026) (first appearance)
October 6, 2026 Entry
– Latitude Media — Where Are the Barriers to Flexible Interconnection? (October 5, 2026) (first appearance)
– PNM — Draft 2026 Distribution System Plan (October 1, 2026) (first appearance)
– mgrid.org — Ameren Missouri Files for 10.6 GW of New Gas (September 30, 2026) (first appearance)
– American Public Power Association — Santee Cooper 2026 Integrated Resource Plan (September 29, 2026) (first appearance)
October 7, 2026 Entry
– McGuireWoods — FERC Issues Section 206 Show Cause Orders to All Six RTOs/ISOs (June 22, 2026) (carried; the orders were reported June through September)
– Utility Dive — GETs, Demand Response Can Ease Near-Term Data Center Electricity Price Pressure (June 23, 2026) (carried; reported June 26, last carried September 11)
– SEPA — VPP and Supporting DER Policy Developments: Q2 2026 (July 23, 2026) (carried; reported July 24 onward)
– T&D World — Utilities, Regulators Grapple With Data Center Growth and Grid Reliability at IEEE PES T&D (May 11, 2026) (first appearance; five months old — cite as the May figure)
October 8, 2026 Entry
– Utility Dive — Smart Thermostat Aggregator Rebrands, Launches ‘Whole-Home’ Virtual Power Plant (October 7, 2026) (first appearance)
– Data Center Dynamics — Google, Nvidia and Emerald AI Found the AI Energy Management Alliance (September 17, 2026) (first appearance)
– Utility Dive — Constellation, Google Deal Will Bring 890 MW of New Nuclear to PJM (October 6, 2026) (first appearance)
– Reuters via 93.3 The Drive — Explainer: Data Centers’ Flexible Power Usage Could Save the Grid Billions. Can They Scale? (October 8, 2026) (first appearance)
October 9, 2026 Entry
– Utility Dive — Power System Plans to Meet Large-Load Demand Miss Near-Term Solutions: Analysts (October 8, 2026) (first appearance)
– TeslaNorth — 85,774 California Powerwalls Just Broke a Grid Record That Lasted Less Than a Month (October 8, 2026) (first appearance; secondary source relying on Tesla’s dashboard and post)
– Itron — GEI Catalyst: Feeder Reliability (October 8, 2026) (first appearance; vendor-modeled value figures)
– Utility Dive — A New VPP Framework Can Center the Energy Transition in Illinois Around Customers: ComEd VP (October 6, 2026) (first appearance; the underlying Scheduled Dispatch VPP approval was reported previously)
Method: All five weekday entries (Monday October 5 through Friday October 9) are in the research log. The October 9 entry was written as a catch-up on October 10 because the scheduled daily run did not fire, and this digest was built and published the same day for the same reason. Items are reported on the day they entered the log, with their original publication dates shown. Several carry pre-week dates: the FERC show-cause orders (June 18), the Columbia GETs analysis (June 23), the SEPA Q2 roundup (July 23), the IEEE PES T&D session (May 11) and the AI Energy Management Alliance launch (September 17). Cross-week check against all prior digests: the FERC show-cause orders, the Columbia GETs analysis and the SEPA Q2 roundup were already reported and are carried in one line each; SB 913 was reported in May at the committee stage, so its signing is treated as movement. Zero source URLs overlap last week’s Sources section. EPRI direct check: no publication in the window.