This week’s most consequential development was Virginia Governor Abigail Spanberger signing legislation establishing the largest state-level energy storage procurement mandate in U.S. history — 20.78 GW across Dominion Energy and Appalachian Power by 2045 — fundamentally reshaping IRP planning in PJM’s most load-pressured service territory. The mandate arrives against a backdrop of escalating grid-reliability alarms: NERC issued a rare Level 3 “Essential Actions” alert over data center load-loss events occurring at 1,000+ MW in seconds, while PJM published a white paper acknowledging its capacity market is in a “credibility trap” and proposing three structural reform pathways that will directly determine DER and VPP revenue streams across 13 states. Taken together, this week’s developments frame an urgent, multi-front transition in which demand-side resources, distributed storage, and DERMS platforms are shifting from programmatic optionality to operational necessity across the Eastern Interconnection.
🔋 Energy Storage
Virginia 20.78 GW Mandate — Largest State-Level Storage Target in U.S. History (Fri)
Governor Spanberger signed HB895 and SB448, requiring Dominion Energy Virginia to procure 16,000 MW of short-duration and 3,480 MW of long-duration storage (LDES) by 2045, and Appalachian Power to procure 780 MW of short-duration and 520 MW of LDES by 2040–2045. The mandate exceeds total U.S. installed battery storage capacity as of early 2025 (~22 GW). Form Energy iron-air and Energy Dome CO2-based LDES technologies (targeting $20/kWh) are positioned as candidates for the long-duration carve-outs. The law builds on an existing 450 MW Dominion residential VPP pilot and will demand DERMS platforms capable of coordinating behind-the-meter residential batteries, distribution-connected BESS, and bulk transmission-connected storage within a unified operational architecture. New Jersey’s parallel Garden State Energy Storage Programme (355 MW approved in Round 1; 645 MW in Round 2) reinforces the regional pattern of state-level action in response to PJM capacity market failures.
EIA 2026 Battery Storage Buildout — Record 24 GW Utility-Scale Additions (Wed, referenced Thu)
EIA’s April 2026 Electric Power Monthly projects 24 GW of utility-scale battery storage additions in 2026 — up 60% from the 2025 record of 15 GW — bringing total U.S. battery storage capacity from 44.6 GW to over 67 GW by Q1 2027. Solar and storage together comprise nearly 80% of the record 86 GW of all planned new U.S. generating capacity this year. Geographic concentration is high: Texas 12.9 GW (53%), California 3.4 GW (14%), Arizona 3.2 GW (13%); PJM and MISO footprint states remain underrepresented in the utility-scale pipeline, reinforcing the relative importance of distribution-connected and demand-side programs in those regions. Small-scale (distributed) solar has also surpassed 60 GW cumulative, with 6+ GW added in the trailing 12 months. The deployment pace drives down per-kWh costs for behind-the-meter programs system-wide.
California Achieves 17,000 MW Cumulative Storage; Three Consecutive Summers Without Flex Alert (Tue)
California energy leaders at the annual Summer Reliability Workshop (CEC/CPUC/CAISO, May 11) credited 17,000 MW of cumulative battery storage and 31,000+ MW of new efficient capacity since 2020 for eliminating Flex Alerts in 2023, 2024, and 2025 despite record heat. Up to 4,500 MW of contingency resources — including DR and VPP programs — are available for summer 2026 through the Strategic Reliability Reserve. CAISO’s Extended Day-Ahead Market (launched May 1) now allows California’s demand-side contingency pool to be optimized within a broader Western footprint during extreme weather.
California SB 913 — Distributed Batteries and EVs as Resource Adequacy Capacity (Mon)
State Sen. Becker introduced SB 913 to update CPUC RA rules to credit aggregated residential batteries and EVs as qualifying RA capacity. California is currently adding approximately 8,000 battery systems (~100 MW) per month. Simultaneously, Ava Community Energy launched its $11.25 million SmartHome Battery program: $500/kWh rebates for income-qualified customers, $90/kWh for market-rate, and $3/kWh-month participation payments under tiered sharing tiers (40%/60%/80% of battery capacity). The tiered structure provides a replicable design for aligning customer incentives with grid value.
Minnesota Capacity*Connect — CCSA Critique of Utility-Owned Model (Mon)
CCSA CEO Jeff Cramer’s post-approval analysis quantified Xcel’s Capacity*Connect at $430 million in ratepayer funding for 200 MW over approximately five years (implied ~$2,150/kW) — a cost structure significantly above LADWP’s DR expansion (~$574/kW for 340 MW). Cramer acknowledged the program validates utility-scale distributed storage but argued competitive procurement could achieve the DOE’s 80–160 GW VPP target by 2030 at lower cost. Minnesota PUC declined to explore behind-the-meter VPP pathways alongside the utility-owned model.
⚡ Virtual Power Plants (VPP) & Demand Flexibility
Puerto Rico CBES — 82% Participation, 48 MW Dispatch from 81,000+ Customers (Fri)
The Puerto Rico Energy Bureau approved continued auto-enrollment of residential battery customers (Tesla, Sunrun, SunStrong) in LUMA Energy’s Customer Battery Energy Sharing program, now the largest behind-the-meter VPP in the United States. Operational metrics: 81,000+ enrolled customers; participation rates as high as 82% during demand response events (substantially above the 50–60% assumed in most mainland utility VPP planning models); demonstrated dispatch of ~48 MW from approximately 70,000 home batteries (~0.7 kW average per unit). The auto-enrollment mechanism — customers opted in by default — is the primary driver of the elevated participation rate and a design insight directly applicable to mainland VPP programs currently relying on opt-in enrollment.
Austin Energy Power Partner Battery Pilot — 78 MW IRP Target by 2027 (Fri)
Austin Energy (ERCOT, municipal utility) launched its Power Partner Battery Demand Response Pilot on March 24, 2026, offering a $500 upfront incentive plus $300+ annual performance payment for 1,500 approved residential battery systems. Initial battery vendors: Tesla, FranklinWH, SolarEdge, Enphase. The pilot operates in ERCOT’s energy-only market — value is derived entirely from peak shaving and avoided wholesale costs, without capacity market revenues. The utility’s Resource, Generation and Climate Protection Plan targets 78 MW of demand response by 2027 and 270 MW by 2035, providing an IRP integration framework where residential batteries operate within a portfolio alongside smart thermostats, EV chargers, and commercial DR.
CPower-Vertiv Data Center BESS VPP — 1 MW Ohio Pilot Across PJM Markets (Fri)
Announced at Transition-AI 2026, Vertiv integrated its EnergyCore Grid BESS (LFP, starting at 4 MW, 1–8 hour duration, purpose-built for data centers) with CPower’s VPP platform. The collaboration’s first output: a 1 MW microgrid at Vertiv’s Ohio Customer Experience Center monetized across PJM capacity, economic, and ancillary services programs. The model demonstrates that data center BESS can serve dual purposes — facility resilience and grid resource — and targets interconnection hotspots in Illinois, Ohio, Texas, and Virginia. Eos Energy separately announced a joint development agreement with Turbine-X for up to 2 GWh of zinc-based BESS for AI data center private power, with deployments targeted for 2027.
PJM Backstop Auction — 15 GW Procurement and the DER Market Access Debate (Wed)
PJM’s proposed framework for a 15 GW emergency backstop procurement (bilateral contracting + RTO-administered) was initially designed around conventional supply-side resources; VPPs and demand-side resources were included only after advocacy by a coalition including Voltus, Verrus, Calibrant, and Mainspring Energy. Voltus CEO Dana Guernsey estimates the auction could unlock 10+ GW of flexible behind-the-meter capacity if two design issues are resolved: (1) the definition of “net new” VPP capacity (currently risks excluding new BTM storage at sites already in PJM’s database) and (2) asymmetric planning requirements (DER aggregators currently face 15-year retail contract requirements vs. “sell offer plan” credibility standards for conventional generators). A parallel FERC complaint from Voltus and Mission:data challenges PJM’s smart meter data requirements that block residential participation.
Base Power Illinois — Retail-Side Demand Flexibility Bypassing Wholesale Market Complexity (Wed)
Base Power (Texas residential battery startup) secured a retail electricity license in ComEd territory, exploiting Illinois’s unique cross-portfolio netting of demand-related capacity and transmission charges: when one Base customer’s battery exports during peak hours, the negative demand offsets peak usage from other customers across the portfolio — creating effective demand-side flexibility via state retail regulation, bypassing PJM aggregation rules and delayed Order 2222 implementation. Business model: vertically integrated (manufacture, install, own, operate residential batteries); customers receive below-market fixed electricity rates. Base is also developing BYOC data center partnerships in the ComEd territory.
Pew DER Policy Playbook — Six Recommendations, 79% Surge in State DER Policy Adoption (Tue)
The Pew Charitable Trusts released its DER policy playbook on April 28, developed over 18 months with a bipartisan DER Advisory Council. The companion State Policy Explorer documents 400+ DER policies enacted across U.S. states from 2021–2025, with a 79% increase in newly adopted DER policies in 2025 vs. 2024. Six recommendations cover IRP integration, VPP capacity targets, utility financial incentive alignment, permitting automation, interconnection streamlining, and DER backup capacity for resilience. Case studies include New York REV, Virginia’s Dominion VPP pilot, Puerto Rico, UK, and Australia’s AEMO IRP reform — which Pew highlights as a working model for treating DER capacity as a primary planning input rather than a supplemental resource.
🔌 DERMS & Grid Integration Technology
CAISO Extended Day-Ahead Market (EDAM) Launched May 1 — First Organized Western Day-Ahead Market (Tue)
CAISO and PacifiCorp successfully launched EDAM, adding PacifiCorp’s ~12 GW of diverse generation (coal, gas, hydro, wind, solar) across six states (CA, OR, WA, ID, UT, WY) into a coordinated day-ahead optimization. Portland General Electric joins October 2026; LADWP and others in 2027. For demand-side resource planners, EDAM creates three specific value enhancements: broader geographic footprint increases the effective capacity credit of aggregated DR portfolios through diversity; earlier day-ahead scheduling visibility gives DERMS operators more lead time to pre-position resources; and locational congestion signals identify where distribution-level DER and DR investments deliver greatest system benefit. California’s 4,500 MW contingency pool — including DR and VPPs — can now be optimized within the broader Western market during extreme weather.
NERC Level 3 Alert — Data Center Load-Loss Events Mandate Grid Operator Action by August 3, 2026 (Thu)
NERC issued its Level 3 “Essential Actions” Alert on May 4, 2026 — the reliability watchdog’s highest severity classification — responding to a documented pattern of 1,000+ MW computational load losses occurring in seconds since 2022. The alert mandates seven actions for transmission planners, operators, planning coordinators, reliability coordinators, and balancing authorities by August 3, 2026, including: detailed computational load modeling requirements; annual stability margin studies for areas with computational loads; commissioning processes testing data center facilities at full and no load; and installation of dynamic fault recording devices. For DERMS program designers, this creates a compelling new dimension to the demand-side resource business case: fast-responding distributed resources — batteries, VPPs, and aggregated DR — are now validated as necessary counterbalances to rapid computational load fluctuations, not merely cost optimization tools.
📋 Regulatory & Policy
PJM Capacity Market Reform — Three Pathways With Direct DER Implications (Thu)
PJM published “Powering Reliability Through Market Design” on May 6, formally acknowledging a “credibility trap” after 1,000%+ capacity price spikes across the last two auctions. PJM CEO David Mills stated the region has “years, not decades” to act; FERC approved a price collar extension on April 28; Jefferies analysts expect reforms before the May 2027 auction. Three pathways: Path A (market stabilization via long-term forward hedging) requires DER aggregators to demonstrate same forward commitment capabilities as conventional generators; Path B (differential reliability/load prioritization) would position large-load DR as a customer-controlled reliability tool; Path C (energy and ancillary services primacy) would enable fast-responding resources — batteries, VPPs, aggregated DR — to compete on operational value rather than solely on capacity availability, potentially unlocking new distribution-connected DER revenue streams.
MISO 35% Peak Load Forecast — 121 GW to 163 GW by 2035 (Mon)
MISO’s updated long-range forecast projects a 35% increase in regional peak demand over the next decade, driven primarily by data centers, which are projected to reach 20% of MISO’s total electricity consumption by 2030 and 25% by 2040. The grid operator expects 8–14 GW of data center load to interconnect during 2026–2027 alone, concentrated in Illinois, Indiana, and Michigan. MISO acknowledged significant forecasting uncertainty from opaque development pipelines and rapidly evolving AI workloads. For utility DSM planners, the pace of data center interconnection in 2026–2027 means that DR, distributed storage, and load flexibility programs represent the fastest-deployable capacity resources to bridge the gap between load growth and infrastructure completion.
FERC June Action on Large-Load Interconnection; DR Aggregation Docket Closed (Mon)
FERC’s April open meeting produced two consequential developments: (1) The Commission set a June deadline for action on DOE’s proposed principles for data center interconnection — Chairman Swett emphasized preserving federal-state jurisdictional boundaries, with NARUC arguing states are best positioned for large-load interconnection decisions; (2) FERC closed the RM21-14 rulemaking that would have prohibited states from blocking aggregated DR from participating in wholesale markets — leaving the current patchwork of state opt-out provisions in place under Order 745. Commissioner Rosner dissented from the DR closure, arguing that large-load demand response (100s of MW per customer) warrants RTO-wide market access, and that data center DR represents an under-leveraged grid integration tool.
Eversource “Resisting Data Centers” — Regional Strategy Divergence (Thu)
Eversource CEO Joe Nolan stated during Q1 2026 earnings that data centers are of “no value” to customers and that Eversource is actively resisting data center interconnection — the first public refusal stance by a major U.S. utility CEO, contrasting sharply with Southern Company (42% data center sales growth in Q1), AEP, and PPL (28.3 GW pipeline). ISO-NE wholesale prices still rose to $112.71/MWh in Q1 2026 (from $99.02/MWh in Q1 2025) despite low data center exposure. For DR program designers, this highlights a regional divergence in urgency: utilities accommodating data center growth (PJM, MISO, ERCOT) need demand-side resources as capacity bridges; New England’s resistance strategy shifts the DR value proposition toward wind variability management and load-shaping over peak reduction.
🏭 Utility Programs & Deployments
Maryland PC44 Flexible Load Proposals — Up to 440 MW Across Four Utilities (Referenced Mon/Wed)
The Maryland PSC is reviewing flexible load pilot proposals from BGE (188 MW), Pepco (185 MW), Delmarva (34 MW), and Potomac Edison (18–33 MW), for a combined potential of ~440 MW. All four proposals include residential batteries and EVs alongside commercial devices. PSC staff (April 1 filing) requires “measurable, dependable and locationally relevant” peak load reductions — a performance standard reflecting Commission awareness that flexible load programs must deliver genuine capacity value. Because all four utilities are filing within the same PC44 proceeding, Maryland will generate directly comparable cross-utility data on acquisition costs, enrollment rates, dispatch reliability, and capacity value per enrolled MW.
Illinois CRGA VPP Tariff Deadline — June 1, 2026 (Referenced Mon/Wed)
ComEd and Ameren must file initial VPP tariffs with the ICC by June 1, 2026 as required under the Clean and Reliable Grid Affordability Act (signed January 2026). Illinois targets 3 GW of cumulative storage by 2030, with an initial ~1 GW IPA procurement scheduled August 26, 2026. The VPP tariff filings will produce the first detailed utility proposals for VPP program design in the PJM ComEd and MISO Zone 4 footprints — the primary near-term pathway for monetizing distributed storage in these territories, given FERC’s closure of the DR aggregation docket and projected delays to wholesale DER market access until 2029–2030.
🚩 Utility-Sector Relevance Flags
⚑ VIRGINIA 20.78 GW STORAGE MANDATE
Topic: Storage / Regulatory
Relevance: This binding procurement target requires Dominion Energy and Appalachian Power to file SCC petitions for 20.78 GW of combined short- and long-duration storage — the largest state-level storage deployment obligation ever enacted — fundamentally restructuring IRP planning, DERMS procurement scope, and T&D integration requirements across PJM’s fastest-growing service territory. Utilities in neighboring PJM states should treat this as a leading indicator of storage mandate escalation driven by data center load growth and capacity market failure.
Action Signal: Implement (Virginia utilities — begin IRP and DERMS roadmap updates immediately); Watch (all PJM-footprint utilities monitoring state legislative precedent)
⚑ NERC LEVEL 3 ALERT — DATA CENTER LOAD-LOSS MANDATORY ACTIONS DUE AUGUST 3
Topic: DERMS / Grid Reliability
Relevance: The Level 3 “Essential Actions” designation mandates concrete grid operator responses by August 3, 2026, and reframes data center load not only as a demand-growth challenge but as a two-sided reliability threat requiring fast-response distributed resources for bidirectional frequency support. Any utility with significant data center load or a growing VPP/DR portfolio should evaluate whether current DERMS capabilities and DR dispatch speeds meet the balancing requirements NERC is now formalizing.
Action Signal: Implement (utilities with data center exposure — begin compliance gap assessment against seven mandated actions)
⚑ PJM CAPACITY MARKET REFORM — THREE PATHWAYS DETERMINE DER REVENUE STREAMS
Topic: Regulatory / VPP
Relevance: The three proposed pathways each create materially different revenue frameworks for demand-side resources across 13 states and 65 million customers: Path A raises the commitment bar for DER aggregators; Path B positions DR as a customer-controlled reliability hedge; Path C — the most DER-favorable — makes energy and ancillary services the primary investment signal for fast-responding resources. The stakeholder window is open now; the outcome is expected before the May 2027 auction.
Action Signal: Engage (file comments and participate in stakeholder process; Path C alignment would most benefit DR/VPP program economics)
⚑ PJM BACKSTOP AUCTION DER DESIGN DETAILS — 10+ GW BTM CAPACITY AT STAKE
Topic: VPP / Regulatory
Relevance: The “net new” capacity definition and asymmetric planning requirements currently under debate could either open or effectively close the 15 GW backstop procurement to behind-the-meter resources — Voltus estimates 10+ GW of flexible capacity is available if design issues are resolved. Utilities with existing or planned residential VPP programs in PJM should monitor this proceeding for its direct implications on program participation eligibility and planning commitment requirements.
Action Signal: Engage (utilities and DR aggregators should submit comments on “net new” definitions and advocate for parity with the DR “sell offer plan” credibility standard)
⚑ FERC DR AGGREGATION DOCKET (RM21-14) CLOSED — STATE PROGRAMS ARE PRIMARY NEAR-TERM PATHWAY
Topic: Regulatory / DR
Relevance: The closure of RM21-14 leaves the current state patchwork on wholesale DR market access intact, meaning utility-administered state programs — not federal wholesale market reform — will be the dominant monetization channel for aggregated DR and distributed storage through at least 2029–2030. Utilities should prioritize building robust distribution-level DR and VPP program capabilities rather than waiting for RTO-level access reform.
Action Signal: Implement (accelerate state-level VPP and DR program development; do not defer investment pending federal wholesale market access reform)
⚑ PUERTO RICO CBES VPP — OPERATIONAL BENCHMARKS FOR IRP PLANNING ASSUMPTIONS
Topic: VPP
Relevance: The CBES program’s 82% participation rate (vs. 50–60% assumed in most mainland IRP models), 48 MW dispatch from 70,000 home batteries (~0.7 kW/unit average), and validated auto-enrollment mechanism provide the most data-rich residential VPP performance dataset available to U.S. utility planners. These figures should be incorporated into VPP capacity credit assumptions in IRP and resource adequacy filings.
Action Signal: Watch (update VPP planning assumptions in next IRP cycle; consider auto-enrollment tariff designs to replicate participation rates)
⚑ MISO 35% LOAD GROWTH FORECAST — URGENCY CASE FOR DSM AS NEAR-TERM CAPACITY BRIDGE
Topic: Regulatory / DR
Relevance: With 8–14 GW of data center load expected to interconnect in MISO during 2026–2027 and peak demand projected to reach 163 GW by 2035, demand-side resources are now the fastest-deployable capacity class to bridge the gap between load growth and supply-side infrastructure completion times of 5+ years. Utilities in Illinois, Indiana, and Michigan face the most acute urgency.
Action Signal: Implement (update IRP models with revised MISO load forecasts; advance DR/VPP programs as near-term capacity resources in regulatory filings)
⚑ CALIFORNIA SB 913 — DISTRIBUTED BATTERY RA QUALIFICATION AS NATIONAL PRECEDENT
Topic: Solar/Storage / Regulatory
Relevance: If enacted, SB 913 would embed distributed battery RA credit directly into CPUC’s wholesale construct — the first legislative RA reform of this type in a major U.S. market — potentially influencing FERC and other state PUCs to adopt equivalent frameworks. Utility resource adequacy teams in other jurisdictions should monitor the bill’s progress and evaluate whether analogous RA rule changes could improve the cost-effectiveness of residential VPP programs in their own IRPs.
Action Signal: Watch (track SB 913 legislative progress; begin internal analysis of distributed battery RA credit implications for your jurisdiction)
📌 Sources Consulted
May 15 (Friday)
– Energy-Storage.News — Virginia Governor Spanberger Signs Legislation Mandating 20.78 GW of Energy Storage
– WSLS — Gov. Spanberger Signs Bills to Address High Energy Costs
– MAREC Action — Governor Spanberger Signs Virginia Energy Storage Bill
– Vertiv — CPower and Vertiv Collaborate to Help Data Centers Accelerate Interconnection
– PR Newswire — CPower and Vertiv Collaboration Announcement
– Energy-Storage.News — US Roundup: BESS Developers Highlight BYOC Model
– Energy-Storage.News — Puerto Rico Approves Aggregated Residential Energy Storage Motion
– Tesla Support — Virtual Power Plant in Puerto Rico
– Austin Energy — Power Partner Battery Pilot Program Launch
– American Public Power Association — Austin Energy Launches Power Partner Battery Pilot
– Austin Energy — Demand Response Program Delivers Record Results in 2025
May 14 (Thursday)
– Utility Dive — NERC Issues Level 3 Alert, Mandates Action to Address Data Center Load Losses
– NERC — Level 3 Computational Load Alert (May 4, 2026)
– Utility Dive — PJM Floats Options for Capacity Market Overhaul
– PJM Interconnection — Powering Reliability Through Market Design White Paper
– Utility Dive — Eversource CEO: ‘We Are Resisting Data Centers’
May 13 (Wednesday)
– Latitude Media — PJM’s Data Center Auction May Be the Break VPPs Have Been Waiting For
– Latitude Media — PJM’s Emergency Backstop Auction Framework
– Latitude Media — Base Power Is Adapting Its Distributed Battery Storage Program for PJM
– pv magazine USA — Solar and Storage to Lead 86 GW Capacity Surge in 2026
– U.S. Energy Information Administration — Electric Power Monthly (April 2026)
May 12 (Tuesday)
– The Pew Charitable Trusts — Distributed Energy Can Unleash the Resilient, Affordable Grid of the Future
– pv magazine USA — Policy Playbook Shows How to Tap Into Distributed Energy Resource Solutions
– Pew — DER State Policy Explorer
– CAISO — EDAM Is Live: PacifiCorp and CAISO Successfully Launch New Market May 1
– Utility Dive — CAISO Expects ‘Solid Launch’ for EDAM
– Modo Energy — What the Launch of EDAM Means for Renewable Investments
– CEC/CAISO/CPUC — Summer Energy Reliability Workshop (May 11, 2026)
– California Energy Commission — California Energy Storage System Survey
May 11 (Monday)
– Utility Dive — MISO Expects Load to Jump 35% by 2035 on Data Center Growth
– RTO Insider — MISO Load Forecast: Data Centers Drive 163-GW Peak by 2035
– Data Center Dynamics — ERCOT and MISO Forecast Huge Increases in Peak Load
– Utility Dive — Distributed Batteries Get Legislative, Utility Lift in California
– California Legislature — SB 913 Bill Text
– Ava Community Energy — SmartHome Battery Program
– Utility Dive — Minnesota Got One Thing Right on Distributed Storage — But It Missed the Bigger Opportunity
– Utility Dive — Minnesota Approves Xcel’s Utility-Owned Battery Program
– Rewiring America — Distributed Resource Grid Capacity Analysis
– Utility Dive — FERC Tees Up June Decision on Data Center Interconnection Reform
– FERC — Notice of Intent to Act on Large Load Interconnection
– FERC — Order Closing Demand Response Aggregation Proceeding RM21-14-000
Generated automatically by der-weekly-summary scheduled task · Week ending May 15, 2026 · Synthesized from five daily DER Research Log entries (May 11–15, 2026)