Author Note:

Infrastructure historically forces economic activity to organize itself around the geography of The Network, The Locus, The Center. Increasingly, technology allows the economic activity, the load, and perhaps eventually the energy itself to arbitrage that geography. For years, I wrote about my work on distributed systems: smaller grids, microgrids, distributed energy grids, and battery-powered grids, from the lens of “DER” language. I don’t need that language anymore. I am in the business of electron arbitrage across space and time.

“The conceptual inversion is wild: on Earth, electricity infrastructure is organized around centers of literal and intrinsic power, title-bound rights-of-way and physical wires. In space, we are designing around generation and load that may communicate through beams, making arbitrage around physical infrastructure the new face of infrastructure itself.” - Arushi Sharma Frank, Luminary Strategies, LLC

What is the Department of Energ Doing about Solar in Space?

This deserves more attention from the infrastructure world: DOE’s Integrated Energy Systems Office opened a $12 million Space Photovoltaics R&D program focused on advancing space-grade solar cells and, importantly, building the domestic manufacturing capability to produce them at scale. Applications for DOE’s Space PV program are due October 8, 2026, with an informational webinar on September 15. The funding announcement itself is straightforward - you can sign up to receive this office’s notices and ensure you whitelist this email address: cmei-funding@service.govdelivery.com.

The deal is that DOE wants better performance and durability from space PV, lower fabrication costs, higher manufacturing throughput, and prototype modules that can be independently validated in space or near-space environments. One funding track addresses next-generation cells at the R&D stage; the second moves toward high-volume manufacturing and demonstration.

High Performance, Low Cost, Long-Range

DOE and TechWerx [1] describe a space economy that is already moving beyond traditional individual satellites toward large constellations, with additional electricity demand potentially coming from wireless power transmission and orbital compute technologies. There is something slightly ironic about reaching this level of institutional acceptance around wireless power transmission in orbit while so much of the terrestrial electricity system remains constrained by the physical limits, siting timelines and political difficulty of building hardwired transmission on Earth. Space infrastructure is already being imagined around a much more fluid relationship between where power is generated, where it is consumed and how energy moves between the two.

Solar PV remains the dominant generation technology for these missions because it can provide power for years without fuel or meaningful maintenance. If these new sectors develop, however, the manufacturing base behind space power has to develop with them.

That is where this becomes an infrastructure story.

Today’s highest-performance space PV cells, based on III-V semiconductors, offer excellent efficiency and durability but remain extremely expensive and depend on critical minerals including gallium and germanium, with the associated supply-chain vulnerabilities. Silicon benefits from the gigantic manufacturing base already built for terrestrial solar, but it carries lower efficiency and greater radiation degradation for demanding space applications.

DOE’s June 2026 workshop with industry, government and national laboratories landed on essentially the same systems problem: the United States does not yet have one space-PV technology that combines high performance, long-duration durability, scalable production and low cost.

So DOE is working several layers at once: materials, cell performance, manufacturing, supply chains, testing and flight validation. Honestly, I think the grant size needs to be 10X.

Arbitrage Around Wires on Earth and In Space

What interests me most about DOE’s explicit treatment of wireless power transmission alongside orbital compute is the possibility of yet another form of arbitrage around the physical grid. If power can ultimately be generated, transmitted through space, and delivered to a commercial endpoint without relying on a continuous terrestrial wire path between generation and consumption, then some portion of electricity commerce begins to separate from the constraints imposed by the wires themselves. The wires do not disappear. The receiving load still has a physical electrical system, and terrestrial networks remain essential. But the commercial pathway between generation and consumption becomes less dependent on whether a particular transmission corridor can be permitted, financed, expanded or operated at the moment power is needed.

I already write regularly about two other versions of this same phenomenon. The first is real-estate portfolio flexibility: a large enterprise installs solar and batteries across facilities in multiple utility or franchise territories and uses those assets to hedge its exposure to utility charges, congestion and expensive network buildout. The enterprise does not need control of the utility system to reduce its economic exposure to it. It can create a portfolio-level hedge behind and around the wires. (See my DDR - Distributed Data Center - articles for more).

The second is geospatial compute flexibility. Compute can move between servers and campuses far more readily than transmission capacity can move between substations. Where firm grid limits are low and slow to increase, workloads can be routed toward locations where power is available rather than waiting for the physical network to catch up. (See my EmeraldAI articles for more).

Wireless power transmission introduces a third possibility: energy itself becomes more spatially flexible.

• Real-estate portfolios move the economics around the wires.

• Distributed computation moves the load around the wires.

• Wireless power transmission could begin to move the power around the wires.

That is the conceptual through-line I find so interesting, and I’ll be investing in the right companies and making the right picks to see these throughlines shape.

If meaningful compute infrastructure eventually moves into space, whats interesting that large parts of how we manage the electricity system, has to go with it. On Earth and in space, we need model and reality to govern how we think about integrated sytems: generation, transmission, firming and the right to move power (space interconnection).

For those of us thinking about the future of distributed infrastructure, our job descriptions are only going to get more interesting in our lifetimes.

-A.S.F.

[1] DOE established TechWerx through a competitively awarded Partnership Intermediary Agreement (PIA). The award went to RTI International, which operates TechWerx as a hub connecting DOE with companies, researchers, universities, small businesses, and other nontraditional performers. DOE uses intermediaries like TechWerx to move faster on outreach, technology scouting, commercialization, convening, and program administration than it often can through a conventional federal funding vehicle.

Hello from Paris! At CIGRE Paris in conjunction with the Rethink Electricity forum, I am teaching a masterclass on the breakthrough rules we have enabled in ERCOT power markets: the Provisional Controllable Load Resource (PCLR) architecture.

The core message: it is time for global grid planners to transition away from punitive administrative curtailment and toward automated, market-integrated operational dispatch. No program for administrative curtailment is an incentive for data centers to play better with the grid. Administrative solutions accomplish administrative outcomes: they are forcing functions on loads to remove themselves from the grid without any readiness standard for the power systems control plane or the computation flex control plane.

Decoupling Planning from Operations- A Design Baked in Texas

My presentation for CIGRE Study Committee C5 focuses on a 2026 Texas PCLR design change that successfully transforms provisional power use into a dispatchable market quantity. Proposed by in PGRR134, this world-first, technology-neutral load flexibility program allows massive loads—like AI factories and cryptocurrency mining—to energize in under two years.

The secret to this speed and flexibility is separating the planning floor from the operating quantity. We do this by establishing two key tiers:

1. Low Power Consumption (LPC): The grid-backed, firm planning floor (for example, a 150 MW base).

2. Maximum Power Consumption (MPC): The conditional operating band (up to 500 MW) that is authorized interval-by-interval through Security-Constrained Economic Dispatch (SCED).

The Grid Provides the Floor, Private Parties Firm the Rest

This is the core principle outlined in my newly released technical paper, Prosperous Infrastructure Technical Value Stacker No. 1: PCLR Builds the Moat for AI Loads.

Under PCLR, the customer owns the congestion risk above their firm floor. To manage this, we put the load inside ordinary dispatch using:

1. Bid-In Load: Utilizing energy bid curves and defined operating limits.

2. Network Sensitivities: Accounting for nodal shift factors and active active constraints to determine if reducing load actually provides relief.

3. Observable Telemetry: Making flexibility credible through real-time performance, ramping, and fallback data.

Bring Your Own Everything

Because PCLR is entirely technology-neutral, private parties can choose exactly how they want to firm their exposure. Replacing static flexibility classifications with dynamic "Bring Your Own Everything" rules invites batteries, localized generation, software controls, and AI workload management to compete around grid obligations.

Through Luminary Strategies, we are already backing a portfolio of ventures—ready to build this indelible solution for powering critical infrastructure.

You can read the full technical paper on the Rethink Electricity website. Thanks to the 100 people joining us for a preview in Paris at Rethink Electricity, the executive forum from the International Rethinking Electricity Forum (IREF) for scaling electric power to AI, computing, and IT facilities in a new way: faster, larger, lower-cost for society, and built for the sustainability expectations of the next economy.

A.S.F.

CIGRE World 2026 is in Paris, France. This week, papers and essays on the Substack will feature references to discussions and formal submissions from utilities around the world. First up, our very own U.S. Utility, Commonwealth Edison, submits a paper that is close to my <3, as it involves how they are managing DERS on overloaded feeders with limited transformer export headroom. Enjoy the piece, and please share our Substack!

Base Power’s move into Illinois exposes the real divide between DER market participation and DER network access. ComEd’s answer to the second problem looks remarkably like ERCOT PCLR, with power flowing the other way.

• Understand: Learnings from the CIGRE 2026 ComEd Delegation and Arushi Sharma Frank’s Work Building ADER and PCLR in ERCOT

• Compare: ComEd DER Dispatch Approach for DERS on Distribution Feeders with ADER Program in Texas

• Distill: ComEd’s Program is Closer to PCLR than ADER, but note the difference. ComEd has a controllable non-firm injection approach for DERS that can inject power (batteries) whereas ERCOT PCLR uses controllable non-firm withdrawal band to enable flexible energization of loads.

• Predict: ComEd is already wrestling with the same bankability question as PCLR—how a conditional access right gets translated into an expected curtailment profile that developers, independent engineers, lenders, and private firming assets can actually underwrite. That is the bridge from “DERMS is clever operations software” to my much larger thesis that non-firm access is becoming a real infrastructure product.

Base Power’s move into Illinois comes alongside my year-long journey to build a connect-around-congestion PCLR moat in Texas (accept grid congestion while waiting for firm connection). The two occurences are related in design and thesis, so this article walks through what’s what, and removes inaccuracies in the discourse about DERS. Especially leading up to the Series raise Base announced earlier this month, I’ve found many market briefs have been talking about Base Power’s Illinois expansion in terms of ADER in ERCOT (another program I originated in my previous job at Tesla) - which is incorrect for the reasons noted below.

Enjoy the piece, and thanks to the ComEd staff here at CIGRE Paris 2026, who walked me through a white paper they are presenting this session.

Read more

For most of the early cloud computing era, the fundamental gating factor on data center capacity was compute supply—specifically, how many GPUs an operator could procure, rack, and cool. The artificial intelligence expansion flipped that paradigm on its head, moving the primary constraint upstream to power, and more precisely, to *time-to-power*.

When xAI needed immediate grid access for its Colossus supercomputer in Memphis in late 2025, it bypassed the multi-year interconnection queue by building its own islanded infrastructure—pairing on-site gas turbines with Tesla Megapack batteries to energize the site ahead of full utility connection. While xAI represents a high-profile case with an exceptionally fast permitting path, the instinct behind it—**"bring your own power, on your own clock"**—has become the defining operating reflex of the AI buildout.

Across major U.S. power markets, grid congestion and interconnection backlogs have replaced technology capital costs as the primary barrier to digital infrastructure deployment. Connecting a major new load to the grid now takes a median of more than four years across most U.S. jurisdictions, with planning queues swelling faster than transmission utilities can expand physical capacity. Simultaneously, AI training workloads introduce unprecedented dynamic load profiles: synchronized, sub-second power swings of hundreds of megawatts as large training jobs start, checkpoint, and stop.

To address this challenge, market analysts and industry groups have put forward various recommendations. In July 2026, the Volta Foundation published an executive paper, *Where Batteries Can Win in Data Center Applications*, outlining the role of Battery Energy Storage Systems (BESS) in bridging grid delays. Notably, Item 3 of the paper’s policy recommendations urges grid operators and regulators across the country to standardize curtailment-based interconnection, clarify dispatch rights, and harmonize large-load tariffs across jurisdictions.

While the recommendation to streamline these frameworks across nearly three dozen U.S. jurisdictional environments is undeniably ambitious given the fragmented nature of state-level regulation, the underlying problem statement is correctly identified: **traditional, static transmission planning can no longer keep pace with hyperscale demand.**

Recent industry analyses, including podcasts and commentaries from Aurora Energy Research, further illustrate this trend, highlighting how asset owners in Europe and the U.S. are increasingly pairing BESS with large localized loads to bypass grid bottlenecks, maintain strict net import limits, and manage tight ramping conditions.

The central challenge, however, remains translating these high-level operational concepts into concrete, bankable market architectures. In Texas, Luminary Strategies faced this issue directly during the development of the **Provisional Controllable Load Resource (PCLR)** framework within ERCOT. By separating firm transmission planning allocations from real-time operational dispatchability, PCLR established a regulatory and operational model for co-located large loads and dispatchable resources. This article narrated our firm’s early challenges and successes (2025 summer onwards), providing readers with fully independent context to understand how batteries could help, and where they remain gated on data center speed-to-energization value.

Article Preview:

Part I: Luminary Shapes PGRR134 - the PCLR Foundation Stone- to Escape the Transmission Planning Trap — How standard steady-state planning cases created the Headroom Paradox and why financial netting fell short.

Part II: Planning Certainty v Operational Consumption — Decoupling Lower Power Consumption (LPC) firm floors from Maximum Power Consumption (MPC) dynamic ramps.

Part III: Behind-the-Meter Control Architectures — How to design N-1 resilient private firming schemes using separately metered BESS, fuel cells, and native SCED load shedding.

Part IV: Asset Matrix — A head-to-head operational comparison of BESS, diesel peakers, gas turbines, and software DR across 8 data center use cases.

Part V: The National Blueprint — Translating Texas mechanics into a scalable framework + a sister paradigm of PCLR is already here in Europe.

Read more

For most of the early cloud computing era, the fundamental gating factor on data center capacity was compute supply—specifically, how many GPUs an operator could procure, rack, and cool. The artificial intelligence expansion flipped that paradigm on its head, moving the primary constraint upstream to power, and more precisely, to *time-to-power*.

When xAI needed immediate grid access for its Colossus supercomputer in Memphis in late 2025, it bypassed the multi-year interconnection queue by building its own islanded infrastructure—pairing on-site gas turbines with Tesla Megapack batteries to energize the site ahead of full utility connection. While xAI represents a high-profile case with an exceptionally fast permitting path, the instinct behind it—**"bring your own power, on your own clock"**—has become the defining operating reflex of the AI buildout.

Across major U.S. power markets, grid congestion and interconnection backlogs have replaced technology capital costs as the primary barrier to digital infrastructure deployment. Connecting a major new load to the grid now takes a median of more than four years across most U.S. jurisdictions, with planning queues swelling faster than transmission utilities can expand physical capacity. Simultaneously, AI training workloads introduce unprecedented dynamic load profiles: synchronized, sub-second power swings of hundreds of megawatts as large training jobs start, checkpoint, and stop.

To address this challenge, market analysts and industry groups have put forward various recommendations. In July 2026, the Volta Foundation published an executive paper, *Where Batteries Can Win in Data Center Applications*, outlining the role of Battery Energy Storage Systems (BESS) in bridging grid delays. Notably, Item 3 of the paper’s policy recommendations urges grid operators and regulators across the country to standardize curtailment-based interconnection, clarify dispatch rights, and harmonize large-load tariffs across jurisdictions.

While the recommendation to streamline these frameworks across nearly three dozen U.S. jurisdictional environments is undeniably ambitious given the fragmented nature of state-level regulation, the underlying problem statement is correctly identified: **traditional, static transmission planning can no longer keep pace with hyperscale demand.**

Recent industry analyses, including podcasts and commentaries from Aurora Energy Research, further illustrate this trend, highlighting how asset owners in Europe and the U.S. are increasingly pairing BESS with large localized loads to bypass grid bottlenecks, maintain strict net import limits, and manage tight ramping conditions.

The central challenge, however, remains translating these high-level operational concepts into concrete, bankable market architectures. In Texas, Luminary Strategies faced this issue directly during the development of the **Provisional Controllable Load Resource (PCLR)** framework within ERCOT. By separating firm transmission planning allocations from real-time operational dispatchability, PCLR established a regulatory and operational model for co-located large loads and dispatchable resources. This article narrated our firm’s early challenges and successes (2025 summer onwards), providing readers with fully independent context to understand how batteries could help, and where they remain gated on data center speed-to-energization value.

Article Preview:

Part I: Luminary Shapes PGRR134 - the PCLR Foundation Stone- to Escape the Transmission Planning Trap — How standard steady-state planning cases created the Headroom Paradox and why financial netting fell short.

Part II: Planning Certainty v Operational Consumption — Decoupling Lower Power Consumption (LPC) firm floors from Maximum Power Consumption (MPC) dynamic ramps.

Part III: Behind-the-Meter Control Architectures — How to design N-1 resilient private firming schemes using separately metered BESS, fuel cells, and native SCED load shedding.

Part IV: Asset Matrix — A head-to-head operational comparison of BESS, diesel peakers, gas turbines, and software DR across 8 data center use cases.

Part V: The National Blueprint — Translating Texas mechanics into a scalable framework + a sister paradigm of PCLR is already here in Europe.

Part I: The Planning Paradox and the Origin of PCLR

The technical tension behind the PCLR framework emerged in mid-2025 during discussions with ERCOT and transmission service providers (TSPs) like Oncor regarding how co-located BESS and large data center loads were evaluated in steady-state transmission planning.

Under traditional ERCOT transmission planning procedures, when an Energy Storage Resource (ESR) and a large load apply for interconnection at a shared point of interconnection (POI), planners analyze maximum stress scenarios to evaluate system impacts:

1. **ESR at maximum discharge** while the co-located load is **not consuming** (maximum net export).

2. **ESR at maximum charge** while the co-located load is **consuming at peak** (maximum net import).

3. **ESR offline (0 MW)** while the co-located load is **consuming at peak**.

Missing from this standard planning matrix was the precise operational state that private infrastructure is built to deliver: **a battery actively discharging to offset load consumption during constrained grid conditions.**

When market participants inquired whether an on-site BESS could be credited in planning studies to mitigate thermal transmission overloads—thereby enabling a load to energize faster—planners noted that existing grid codes provided no clear mechanism to rely on private dispatch commitments to grant firm transmission capacity. Under traditional rules, a load's requested demand was treated as firm, static, and non-dispatchable. If a thermal overload appeared in the 5-year or 6-year planning model, the load was capped at a lower commissioning limit until full, multi-year transmission line upgrades were constructed.

Attempts to resolve this through financial netting or complex Remedial Action Schemes (RAS) / Special Protection Systems (SPS) ran into structural limits. Grid operators resisted expanding RAS/SPS protocols for load curtailment, fearing operational complexity and reliability risks. Furthermore, proposals like "Partial Wholesale Storage Load (WSL) Netting" provided financial and settlement mechanics for storage charging, but did not alter the fundamental transmission planning assumptions used by utility engineers.

This produced the **Headroom Paradox**: market modeling indicated that the grid possessed vast amounts of dynamic, non-peak headroom, yet loads remained locked behind multi-year queues because planning frameworks evaluated them strictly on an unmitigated, firm-peak basis.

Part II: The Core Insight — Planning Certainty vs. Operational Consumption

The breakthrough behind PCLR was acknowledging that static transmission planning and dynamic operational dispatch fulfill two entirely distinct functions, which can be decoupled without compromising grid reliability:

* **Transmission Planning** must remain conservative. TSPs and grid operators cannot socialize the risk of asset failure by assuming a private, third-party battery will operate flawlessly in perpetuity to preserve system voltage or prevent thermal overloads without enforcement mechanisms.

* **Operational Market Dispatch**, conversely, is dynamic. In a Security-Constrained Economic Dispatch (SCED) market, assets can be dispatched in real time based on physical grid constraints. If a load is capable of receiving and responding to five-minute SCED nodal instructions, its real-time consumption can be dynamically throttled.

Under the PCLR architecture, a large load is granted a dual operational identity:

1. **Lower Power Consumption (LPC):** The baseline, firm power withdrawal allocated through standard transmission planning studies (the level the site can safely draw unconstrained).

2. **Maximum Power Consumption (MPC):** The full requested load ramp, which the facility is permitted to draw *only* when real-time grid conditions permit or when co-located private assets (BESS, thermal generation, native load shedding) dynamically manage the site's net withdrawal at the Point of Interconnection (POI).

By placing the delivery risk directly on the private asset owner rather than grid planners, PCLR allows large facilities to energize up to their full MPC years ahead of major transmission buildouts, while ensuring the site automatically ramps down down to its LPC if grid constraints bind.

Part III: Decoupling Compliance Architecture from Electrical Architecture

A key operational challenge in implementing the PCLR framework was clarifying the distinction between market compliance rules and physical electrical architecture behind the meter.

Early market workshops occasionally described PCLR as a "Load-Only" construct, leading some developers to incorrectly assume that pairing BESS or on-site generation with a PCLR was prohibited. As Luminary clarified in emails with ERCOT staff (and worked up the updated which the public saw in revised Powerpoints through the Batch Zero workshop process), this misunderstanding stemmed from confusing *registration and settlement rules* with *behind-the-meter electrical design*:

Compliance & Market Boundary (At the POI): ERCOT requires that a Controllable Load Resource (CLR) satisfy its own telemetry, registration, ramp-rate, and SCED dispatch obligations independently. A co-located battery cannot be "netted" into the load's telemetry to fabricate CLR compliance if the load itself cannot respond to dispatch instructions. The BESS and the Load remain separately registered, metered, and settled market entities.

Electrical & Control Architecture (Behind the POI): Behind the high-voltage master substation, the developer is free to orchestrate an integrated microgrid stack. Separately metered BESS units, firm fuel cells, gas turbines, and segmented compute blocks can be connected across sectionalized buses, redundant transformers, and bus ties.

This multi-layered control design creates an N-1 resilient private firming scheme:

1. Layer 1 (BESS Fast Response): When real-time nodal congestion occurs or local thermal limits bind, the on-site BESS discharges to absorb the local demand, keeping the net withdrawal at the POI under the allowed threshold.

2. Layer 2 (On-Site Generation / Fuel Cells): If the transmission constraint persists beyond the multi-hour duration of the storage system, co-located generation or fuel cells ramp up to assume the baseload duty.

3. Layer 3 (Native SCED Load Response): If private generation assets experience an outage or reach operating limits, the site's control architecture reduces power draw on the AI compute clusters, obeying the PCLR SCED dispatch instruction down to the facility's firm LPC floor.

Part IV: Comparing Storage Capabilities in Data Center Applications

To evaluate where batteries fit within this architecture, it is helpful to examine how BESS compares to alternative energy assets across key data center operational use cases:

Part V: National Blueprint — From Local Friction to Standard Infrastructure Compounding

The dynamics driving PCLR in Texas reflect structural challenges facing power systems worldwide. As hyperscale AI loads expand across North America and Europe, traditional transmission planning processes are encountering clear physical and temporal limits.

With turbine lead times extending past 5–7 years and power transformer backlogs reaching historic highs, wait times for firm transmission capacity have become a central constraint on infrastructure development.

The evolution of market frameworks like PCLR offers several key takeaways for market participants, utilities, and regulators:

1. For Hyperscalers and Developers: Designing facilities with flexible, hybrid power architectures from day one allows developers to decouple project timelines from major transmission construction schedules. By establishing dispatchable capabilities at the POI, facilities can secure interim energization while long-term transmission upgrades are completed.

2. For Utilities and Grid Operators: Standardizing curtailment-based interconnection tariffs and dynamic load constructs reduces the pressure to over-build transmission infrastructure for short-duration peak conditions.

3. For Policy Makers and Regulators: Harmonizing large-load interconnection rules across jurisdictions can reduce market fragmentation and lower administrative barriers. Frameworks that clearly define dispatch rights, settlement rules, and operational boundaries provide market participants with the regulatory certainty needed to deploy capital efficiently.

Europe Interjection: Ireland (ESB Networks) vs. US Grid Management (PCLR / Dynamic Envelopes)

European energy users seeking increased network access also face a stark choice: wait years for costly capital infrastructure reinforcements or remain constrained by a lower Maximum Import Capacity (MIC). ESB Networks’ Dynamic Flexible Demand Connection introduces a pragmatic middle ground, contrasting sharply with both rigid, conventional firm connections—which guarantee 24/7 capacity but require fully upgraded grid infrastructure—and static Timed Connections, which restrict usage based on fixed schedule windows. By offering immediate access to an increased MIC in exchange for real-time operational curtailment during rare peak constraint events, dynamic flexible connections allow commercial and industrial facilities to bypass traditional grid bottlenecks while actively supporting distribution system stability. Guess what: it looks a heck of a lot like a combination of the Texas Senate Bill 6 Red Button policy + PCLR as originally submitted by Luminary Strategies in PGRR134. The details are below.

What it is: A temporary connection agreement allowing a commercial/industrial customer to obtain an increased Maximum Import Capacity (MIC) in a grid-constrained area without waiting for long-term capital infrastructure reinforcements (such as new 110kV stations).

The Trade-Off: In exchange for a faster connection and higher operating capacity during standard grid conditions, the customer agrees to reduce their load back to their original Firm MIC level when instructed by ESB Networks during periods of severe grid congestion.

Core Characteristics & Terms

1. Structure of the Connection

Total Demand Limit: Composed of Firm MIC + Flexible MIC.

Temporary Nature: The flexible arrangement remains in place until capital grid reinforcements are complete, at which point the customer transitions to a fully firm connection.

2. Operational & Response Requirements

Response Window: When notified, the customer must reduce demand within 15 minutes of the instruction.

Designated Contact Points: The customer must provide and monitor a dedicated email account and phone number 24/7.

Execution: How load is reduced is up to the customer (e.g., process shifting, turning off non-essential equipment, or adjusting production schedules).

Financial Terms: Customers are not paid for reducing demand under a Dynamic Flexible Connection; the primary financial benefit is earlier access to the higher MIC.

3. Penalties & Compliance Mechanisms

ESB Networks enforces strict operational safety tools if an instruction is ignored:

Immediate Failure to Respond: If a customer fails to curtail demand by the instructed flexible amount, ESB Networks will disconnect the customer's entire load immediately to protect system stability.

Repeated Non-Compliance: If a customer repeatedly fails to respond to curtailment instructions, the increased flexible capacity will be permanently revoked, returning the facility to its original Firm MIC level.

4. Customer Prerequisites & Hardware Requirements

To participate, a customer must meet specific technical and operational preconditions:

Proving Tests: Required engagement in testing before flexible access is officially granted.

Load Tolerance: Process operations must be capable of absorbing a sudden reduction down to Firm MIC levels.

5. Customer-Side Technology & Upgrades:

* Installation of switchgear enabling remote monitoring and remote disconnection by ESB Networks.

* Power Control System (PCS) implemented on the customer side.

* Willingness to absorb temporary supply outages required to complete hardware installation and switchgear upgrades.

* Payment of standard charges associated with MIC increases.

6. Reporting & Availability Metrics

ESB Networks provides an Indicative Flexible Import Availability Report during the planning phase to help customers assess viability:

Seasonal Breakdown: Evaluates availability across Summer (April–September) and Winter (October–March) periods.

Service Windows: Measures load profile impact in 3-hour blocks across daily delivery periods.

7. Key Report Variables:

* Peak Reduction (MW/MVA) required.

* MWh Requirement expected during service windows.

* Estimate of Capacity Available (MVA).

* % Flexible Energy Available relative to what a firm connection would deliver.

Thanks for reading. Please share this article if you enjoyed it!

-A.S.F.

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Citations:

1. Michael Liu, Volta Foundation & Applied AI & Data Center Infrastructure Committee, Where Batteries Can Win in Data Center Applications: Committee Insights Paper (July 2026), available at https://volta.foundation/committees.

2. Arushi Sharma Frank, The Journey to Build for AI: How PCLR Built the Moat for America’s AI Infrastructure Boom, Prosperous Infrastructure Series, Technical Value Stacker No. 1, Luminary Strategies LLC (July 2026). (SSRN Pending).

3. From Grid Bottlenecks to Battery Value: Europe's Storage Markets Evolve, Energy Unplugged by Aurora Podcast, Ep. 274 (2026), available at https://auroraer.com/resources/energy-unplugged/ep-274-from-grid-bottlenecks-to-battery-value-europes-storage-markets-evolve.

4. Aurora Energy Research, How Can Batteries Accelerate Data Center Deployment in the United States? (Webinar Insights, 2026), available at https://auroraer.com/resources/webinar/how-can-batteries-accelerate-data-center-deployment-in-the-united-states.

5. Unlocking Existing Grid Capacity for Large Loads via Flexible Interconnection, Duke University Nicholas Institute for Energy, Environment & Sustainability (2025).

6. ERCOT, Provisional Controllable Load Resource (PCLR) Framework and PGRR134 Mechanics, Large Load Working Group & Planning Load Working Group Proceedings (2025–2026).

7. U.S. Federal Energy Regulatory Commission (FERC), Notice of Proposed Rulemaking on Large Load Interconnection Protocols, NOPR Docket No. RM26-4-000 (2025–2026).

The execution of American energy policy has shifted toward a framework explicitly designated as "Energy Dominance." At the center of this transition is the structural retooling of the Department of Energy’s financial apparatus. For those catching up, the former Loan Programs Office (LPO) has been renamed the Office of Energy Dominance Financing (EDF), operating under expanded mandates established by the One Big Beautiful Bill (OBBB), specifically the Title 1706 Energy Dominance Financing Program. This framework treats energy abundance and supply-chain sovereignty as primary national security directives.

Understanding the operational reality of this strategy requires looking at three core components: the external non-profit policy network framing the agenda, the recent regulatory admissions made by administrative leadership, and the deployment of massive federal credit to anchor the domestic nuclear supply chain.

The Policy Matrix: Energy Infrastructure Alliance Forum

Navigating this new regulatory environment has prompted the formation of specialized outside organizations designed to bridge federal programs with private capital markets. Prominent among these is the Energy Infrastructure Alliance Forum, a non-partisan organization where Sheila Moynihan serves! Sheila is ex-LPO royalty, and I was delighted to be at the launch party for this new organization where she announced her role.

The Forum focuses its efforts on ensuring that these newly expanded federal financing tools are fully understood, utilized, and integrated with private investment to build out critical energy infrastructure and domestic supply chains.

The institutional thesis of the Forum, as outlined in its recent white paper, *Energy Dominance Financing Program: A Key Tool for Advancing the Energy Dominance Agenda*, positions the EDF as the primary lever to overcome the high capital intensity and prolonged permitting timelines that traditionally stall domestic energy infrastructure. The white paper establishes that the current administrative framework relies heavily on a sequence of executive actions from early 2025, including Executive Order 14156 (Unleashing American Energy) and a series of May 2025 Nuclear Executive Orders targeting a quadrupling of U.S. nuclear capacity to 400 GW by 2050.

The core analytical contribution of the Forum’s white paper is its focus on structural bottlenecks—specifically the "Federal Support Restriction," or double-dipping rule, which prevents projects from receiving EDF loans if they simultaneously benefit from other direct or indirect federal grants or off-taker contracts.

Chokepoints and Competitive Realities: The SIF Remarks

The practical limitations and friction points of this policy framework were made clear during a fireside chat at the US SIF annual conference in Arlington, Virginia. Remarks from an EDF official at the event highlighted the explicit tension between long-term strategic objectives and immediate market realities. (In a wonderful turn of events the author of this article also took the stage for a fireside chat about moving sustainable finance capital directly and closest to execution as possible, so we got to hear each other's talks.)

So, EDF’s speaker discussed that the administrative focus remains concentrated on winning the artificial intelligence race, securing critical mineral supply chains, and deploying baseload power. However, the EDF leadership acknowledged an operational friction point introduced by current statutory definitions. While the OBBB framework accelerates long-lead baseload assets like nuclear and grid uprates to meet the power demands of massive AI data centers, the policy creates a near-term chokepoint by disincentivizing wind and solar projects that can deploy on much faster horizons. The exact quote is important because it leans into the problem we've had across two administrations: “As there were criticisms of the IRA as it pertains to our mission in the previous administration, there are shortcomings of the OB3A as it pertains to our current mission. It helps set us up for long-term success in powering AI, but it also creates a short-term chokepoint by disincentivizing wind and solar projects that can deploy much quicker.” LinkedIn Post readout, Mark Bershatsky.

This explicit point underscores that the transition to an "energy dominance" framework represents an overt picking of technology winners, prioritizing long-term heavy industrial capacity and fuel-cycle independence over rapid, distributed generation.

Furthermore, the administration's policy execution is dictated by intense geopolitical pressure from China, which currently controls the global processing pipelines for critical inputs like lithium, graphite, and rare earth elements. The EDF strategy is to combat the tidal wave with long-term federal debt and thus isolate domestic utility supply chains from international market manipulation and predatory pricing.

Anchoring a Nuclear Renaissance

The theoretical frameworks of the white paper and the strategic mandates of the EDF converged in a landmark $17.5 billion conditional loan commitment announced by Energy Secretary Wright. This financing is directed to Westinghouse Electric Company and represents a fundamental departure from historical federal utility bailouts. Founded way back in 1886 by George Westinghouse (the guy who won the "War of Currents" against Thomas Edison to bring AC electricity to the masses), the company essentially built the foundation of commercial nuclear energy, developing the world's first full-scale commercial pressurized water reactor (PWR) back in 1957. Today, it operates as a specialized nuclear technology giant based out of Cranberry Township, Pennsylvania, owned by a consortium of Brookfield Renewable Partners and the Canadian uranium firm Cameco.

Instead of financing a single, specific generation facility prone to local cost overruns, this loan facility funds the procurement and manufacture of critical long-lead items for ten flagship AP1000 nuclear reactors across five distinct utility-sponsored projects. This structural approach attempts to solve the primary failure point of modern American nuclear deployment: supply chain fragmentation. By standardizing components and locking in bulk pricing before local permitting concludes, the mechanism aims to shorten commercial construction schedules by up to three years.

The project is designed to deliver over 11 GW of baseload power to the domestic grid while establishing an in-house nuclear fuel cycle that bypasses reliance on Foreign Entities of Concern (FEOC). Commenting on the structural design of the transaction, Sheila Moynihan recently observed in a LinkedIn post that the strategy directly addresses the historical nightmare of alignment schedules and volatile pricing that occurs when long-lead equipment orders are delayed by uncertain local permitting timelines. By shifting the financial risk of long-lead procurement to the federal balance sheet, the deal establishes a predictable cost baseline for the domestic utility sector.

Structural Friction: The Macro Case for Battery Storage and Seams Coordination

The critical flaw in the current execution of the Energy Dominance agenda is, in our view, its reliance on multi-decade horizons to address immediate, acute infrastructure constraints. While a $17.5 billion underwriting of the nuclear supply chain provides a structural foundation for the 2030s, it leaves the contemporary grid vulnerable to immediate capacity crunches. If the primary objective of the Office of Energy Dominance Financing (EDF) is to win the global AI race by securing immediate "speed to power," the program must pivot toward asset classes that can deploy inside a twelve-to-eighteen-month window.

To build near-term headroom on the American grid without defaulting to multi-billion dollar baseload timelines, the EDF should aggressively deploy its Title 1706 authority toward two high-leverage mechanisms: utility-scale Battery Energy Storage Systems (BESS) and market seams infrastructure.

The Capital Playbook for Merchant BESS

The operational reality of utility-scale battery storage has evolved from an emerging technology play into a mature, highly sophisticated software and merchant trading discipline. As demonstrated by the rapid scaling of BESS in ERCOT—which reached nearly 15 GW of operational capacity in early 2026—batteries are no longer just clean energy buffers; they are primary grid reliability tools that actively flatten net load peaks and lower wholesale energy costs during periods of extreme strain.

However, outside of fast-moving regions like Texas and California, deployment remains dangerously sluggish. In PJM—the epicenter of the AI data center buildout—the grid-scale battery fleet has historically languished due to regulatory structures and capacity market rules that protected legacy thermal assets. While PJM's recent market redesigns have sent per-MW revenues soaring to an attractive $62/kW-month, conventional project finance lenders remain hesitant to back large-scale merchant storage without long-term bilateral tolling agreements.

The EDF is uniquely positioned to break this bottleneck. By using its Title 1706 authority to provide long-term, low-cost debt and senior loan guarantees for merchant battery installations, the federal government can de-risk the cash-flow volatility that scares away conservative private capital.

Furthermore, because batteries have small physical footprints and minimal environmental impacts, they can be co-located directly at retired fossil fuel sites or adjacent to transmission bottlenecks. This provides an immediate, highly accessible pathway to unlock grid capacity and stabilize voltage near major load centers well before a nuclear foundation can be poured.

Capitalizing Market Seams: The Billion-Dollar Platform Finance

The second, and perhaps most overlooked, high-impact opportunity lies at the boundaries of our regional energy markets: **the seams**.

The physical and institutional disconnect between adjacent balancing authorities like PJM, MISO, SPP, and ERCOT represents a multi-billion-dollar inefficiency. When one region experiences a severe capacity shortage or a localized price spike, cheaper power sitting just across the geographic border often cannot move due to a lack of high-voltage intertie capacity or uncoordinated scheduling protocols. NERC talks about it plenty so it would make sense that DOE is looking at it seriously.

Building out market seams infrastructure—such as back-to-back High-Voltage Direct Current (HVDC) converter stations and strategic interties—is fundamentally a platform-level financing challenge. These are massive, capital-intensive infrastructure plays that can cost upwards of a billion dollars per project. Private developers struggle to clear the financing hurdles because the revenue models rely on capturing the shifting price differentials between two entirely separate regulatory jurisdictions.

By aggressively targeting Title 1706 funds toward merchant interties and cross-border transmission upgrades, the EDF can act as a catalytic platform financier. Constructing these physical bridges between markets allows the federal government to unlock thousands of megawatts of existing, unused capacity. This creates an efficient, unified national power market that naturally enhances reliability, dampens price volatility, and creates the resilient energy backbone necessary to support America’s digital and industrial future.

If you have other ideas for what they should be financing at billion dollar scales, drop them in the comments. Remember that in practice, the program serves as a heavy-industrial and infrastructure lender rather than a venture or mid-market option due to two realities:

1. The sheer volume of fixed transaction costs, underwriting fees, and multi-month federal compliance requirements means that loans or loan guarantees are typically $500 million or more to justify the overhead.

2. Because Title 1706 focuses on system-wide infrastructure—retooling regional grids, financing merchant platform plays, and anchoring multi-state utility supply chains—the portfolio naturally skews toward the billion-dollar tier. Great context in the IRA-enabled rulemaking of 2023.

-A.S.F

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[^1]: *Overview*, Energy Infrastructure Alliance Forum LinkedIn Page.

[^2]: Energy Infrastructure Alliance Forum, *White Paper: Energy Dominance Financing Program: A Key Tool for Advancing the Energy Dominance Agenda*

[^3]: *Id.* at 3.

[^4]: *Id.* at 4.

[^5]: *Id.* at 8.

[^6]: U.S. DOE Office of Energy Dominance Financing (EDF), *Fireside Chat with Bryan McGannon at US SIF Annual Conference*, LinkedIn Post, at https://www.linkedin.com/posts/mark-bershatsky-cfa-48564_had-a-blast-participating-in-a-fireside-chat-share-7477474183279587329-w39m/?utm_source=share&utm_medium=member_android&rcm=ACoAAALf-qoB2buNPDf5EG0rNHGO8oXBcpifxHo

[^7]: *Id.*; see also Energy Infrastructure Alliance Forum, *White Paper*, 2.

[^8]: U.S. Department of Energy, *Office of Energy Dominance Financing (EDF) Conditional Loan Commitment Announcement*, LinkedIn Post, https://lnkd.in/gUz7QU3b

[^9]: Sheila Moynihan, *Commentary on U.S. DOE Office of Energy Dominance Financing Announcement*, LinkedIn Post, https://www.linkedin.com/posts/sheila-moynihan-68563410_way-to-go-us-doe-office-of-energy-dominance-share-7475217424879960065-PBQd/?utm_source=share&utm_medium=member_android&rcm=ACoAAALf-qoB2buNPDf5EG0rNHGO8oXBcpifxHo.

The most useful VPP paper of the summer is not, strictly speaking, a VPP paper.

It is a distribution planning paper: Distribution Operational Potential of Grid Edge Resources, a May 2026 PNNL report prepared by Dale Murdock and Owen Goldstrom of ICF and Paul De Martini of ICF, with DOE Office of Electricity sponsorship. The paper gives the market new vocabulary (Grid Edge Resources in lieu of simply Distributed Energy Resources) and excellent framing to compare and contrast announcements involving hyperscalers and major DER/GER players.

That timing of the paper matters.In the span of a few weeks, the grid-edge market has started to reorganize around large-load demand management solutions that involve almost everything except curtailing the data center itself — what we think of at , as the privatization of firm delivery risk.

• Sunrun, Renew Home, and Tesla announced a framework to deliver more than 16 GW of flexible energy capacity to hyperscalers and utilities, drawing from hundreds of thousands of home batteries plus more than 8 million smart thermostats and devices managed by Renew Home.

• Voltus and Google announced a three-year Bring Your Own Capacity agreement in PJM under which Voltus will aggregate up to 100 MW per year of distributed energy resources from local homes and businesses into a Google-funded VPP.

• Sparkfund, through Distributed Capacity Procurement, is advancing a different model: 1–5 MW front-of-the-meter batteries and gensets deployed as distribution infrastructure, including Xcel Energy’s Capacity*Connect plan for up to 200 MW of distributed battery storage by 2028.

These are all being described as grid-edge capacity solutions. But they are not the same product. PNNL’s report provides an excellent sorting mechanism. The paper helps us dig into how the business models can achieve acceptance from load-serving and wires entities that need dependable capacity, at the right location, at the right hour, with the uncertainty priced and derisks under performance contracts.

Read more

From our experience, the tech sector is still operating in a frothy place - disingenuous and hopeful - in terms of what they believe can happen in Washington. Read on for a narrative of our past two weeks.

Read more

Juy 1, 2026 Update: Watch Neil, Arushi, Joseph, and Arthur - at the CSIS Energy & Climate Change Program

Share Teach What I Know - Energy & Policy Learning w/ Arushi

Original Article:

Snapshot: FERC started six regional countdown clocks, while offering a narrow 45-day window for each RTO/ISO to request a temporary abeyance if it can show a concrete path to a Section 205 tariff filing. This is both a warning shot and an invitation: fix your tariff yourself, fast, or litigate why FERC should not fix it for you. The article below covers the Open Meeting announcement of the six show-cause order dockets, and covers the one we’ve seen released in detail thus far, applicable to MISO, in Docket No. EL26-70-000.

At its June 18, 2026 open meeting, FERC announced six new show-cause dockets directed at the RTOs and ISOs under its jurisdiction. The Chair described the action as a suite of six orders, each tailored to a specific grid operator, finding that existing tariffs appear to be unjust and unreasonable because they do not adequately address how to integrate large and co-located loads onto the transmission system. The stated objectives were familiar but unusually concentrated in one package: fair cost allocation, transparency for ratepayers, respect for states’ rights, efficient markets, reliable service, and speed to power.

The first order we have in hand is the MISO order, Docket No. EL26-70-000. It is important because it shows the architecture of what FERC is now asking across the country.

First of all, being a FERC lawyer provides one lifelong interpretive superpowers. I am a recovering but active FERC lawyer and this superpower is my gift to you!

It’s important to note FERC did not issue to MISO any kind of replacement to its existing tariff. It is not fast action, it is not ERCOT writing PGRRs and NPRRs and they turn into tariff seemingly overnight with one PUC Texas vote. It is a Federal Power Act Section 206 show-cause order. FERC is telling MISO and its transmission owners: either explain why the existing tariff remains just and reasonable without these provisions, or explain what tariff changes would fix the problem if FERC ultimately finds the tariff unjust and unreasonable.

The order gives MISO and the transmission owners 60 days to respond, directs MISO to file a 30-day informational report on adequate generation to serve existing and new large loads, and allows interested parties to respond within 30 days after MISO’s filing. There is also an escape valve built into this mode of compliance. Chairman Swett emphasized that the orders “leave room for and encourage” filings under FPA sections 205 and 206 that address the concerns identified in the show-cause orders. She then explained that FERC will consider requests to hold all or part of a show-cause proceeding in abeyance if they are filed within 45 days and include enough detail about a plan to finalize and file a Section 205 proposal addressing the identified issues.

That is not a minor procedural footnote. It means the RTOs and ISOs have two paths. They can answer the 60-day show-cause order directly, defending their existing tariffs or proposing what a replacement tariff should look like. Or, within 45 days, they can ask FERC to pause all or part of the Section 206 proceeding so they can work through stakeholder processes and bring forward their own Section 205 tariff filing.

But the abeyance option is deliberately constrained. In the MISO order, FERC says any abeyance would run for up to 90 days, would begin as of the deadline to respond to the order, and would be considered only to give MISO and the transmission owners time to develop Section 205 filings that address the issues raised in the show-cause order. FERC also says it will not grant abeyances reflexively, will look with “great disfavor” on extension requests, and expects any successful request to include both a robust description of the future Section 205 filing and a specific explanation of when that filing will be made.

So the abeyance process is best understood as a structured off-ramp, not a slow-walk option. FERC is giving each region a chance to solve the problem itself, using its own stakeholder processes and regional tariff design. But the Commission is also preserving pressure: 45 days to ask for the pause, 60 days as the baseline response deadline, 90 days maximum for abeyance, and skepticism toward extensions.

That is FERC telling the markets: innovate regionally, but do not stall.

What FERC is actually asking for

The Chair previewed five categories of reform. The MISO order tracks them closely.

First, FERC wants clear application, study, and operational rules for transmission customers serving large loads. The MISO order says MISO’s tariff appears unjust and unreasonable without provisions addressing the application process, study procedures, and ongoing operational requirements for Eligible Customers seeking transmission service on behalf of large loads.

Second, FERC wants cost-shift protection and better transparency into Network Upgrade costs. So, the MISO order preliminarily finds that the tariff appears unjust and unreasonable because it lacks adequate mechanisms to mitigate cost shifting among transmission customers. It points to two missing pieces: public, systematic information about Network Upgrade costs needed to serve large loads, and a pro forma cost recovery agreement among MISO, the relevant transmission owner, and the Eligible Customer taking service for the large load.

Commissioner Rosner put that point in plain English at the meeting today: if new transmission infrastructure is built to serve a data center and that data center does not show up, other customers should not be left holding the bag. Those agreements are supposed to address stranded-cost risk and timing gaps before the large load actually energizes, with payments credited back toward transmission revenue requirements rather than simply protecting utility recovery.

Third, FERC wants clear tariff rules for co-location and behind-the-meter generation. The MISO order says the tariff appears unjust and unreasonable because it lacks clear provisions addressing the rates, terms, and conditions for co-location arrangements and for Eligible Customers taking transmission service on behalf of co-located load or load with behind-the-meter generation. This is an area where other ISO/RTO orders are going to look different - e.g., SPP is further along than MISO by a bit!

Fourth, FERC wants transmission services that recognize flexibility. This is the heart of the “speed to power” theory. The MISO order says the tariff appears unjust and unreasonable because it does not include transmission services for flexible large loads that are willing and able to limit their use of the transmission system under certain conditions. The order points to interim service while Network Upgrades are built, and permanent firm and non-firm contract-demand-style services, with necessary control technologies or protection systems to keep withdrawals within approved levels.

Recalling Chairman Swett’s comments from earlier today, FERC also walked back an important piece of its December PJM co-location ruling: it set aside the prior finding that loads with behind-the-meter generation could not take the new PJM transmission services. That matters because the MISO order now carries that openness into the broader show-cause framework. It treats behind-the-meter generation and co-located load as part of the same tariff-clarity problem, and asks whether MISO’s tariff remains just and reasonable without PJM-style transmission service options for customers whose load can be limited to an approved level.

As of today’s announcements, FERC has reopened the door to BTM configurations, and is now asking each RTO/ISO to explain, region by region, how its tariff will accommodate co-location, behind-the-meter generation, and flexible large-load service without unnecessary transmission buildout.

Fifth, FERC wants a pathway for generation serving electrically proximate or co-located load to be studied in a way that reflects that operational reality. The MISO order similarly asks whether MISO’s tariff is unjust and unreasonable because it lacks provisions allowing an interconnection customer serving electrically proximate large load or large co-located load to seek generator interconnection service that reflects the operational dynamics of serving those loads. (The Chairman said this morning, this should prevent unnecessary and expensive transmission buildout.)

The overlooked piece: alternative transmission technologies

There is another important thread in the MISO order that should not be lost.

FERC is not only asking whether MISO has large-load study rules. It is asking whether those studies must evaluate alternative transmission technologies — technologies the order also describes as grid-enhancing technologies — before defaulting to traditional Network Upgrades. The order specifically asks whether MISO’s tariff remains just and reasonable without requiring evaluation of these technologies using models capable of accurately accounting for them, and without requiring an explanation when traditional Network Upgrades are selected instead.

That connects directly to the meeting happenings from this morning. Commissioner Rosner emphasized that grid-enhancing technologies can help get more out of the existing grid, save consumers money, and connect projects faster. His framing was blunt: the cheapest transmission line is the one that already exists.

The jurisdictional bargain

FERC is also drawing a careful jurisdictional line.

The Chair stressed that interstate transmission rates and generator interconnection processes are within FERC’s jurisdiction, while states retain authority over resource siting, retail sales, and retail rate design. FERC’s role here is to prevent cost shifting among transmission customers. States must handle cost shifting among retail customers. That is why the transparency piece matters: FERC is trying to expose wholesale transmission costs so state regulators can decide how those costs should be allocated at retail.

That is the actual policy bargain. FERC is not telling states how to design large-load tariffs. It is creating the wholesale-side visibility and transmission-service machinery that states can then use.

Existing deals are not supposed to be blown up

One more point matters for market participants already in motion.

The Chair emphasized this mornign that the orders are not intended to disrupt existing commercial agreements or agreements already being negotiated. The MISO order says the same thing: this proceeding is intended to establish prospective reforms, with reasonable implementation periods and reasonable time to finalize agreements nearing completion when tariff revisions are filed. That language was reiterated by Chairman Swett this morning: these efforts are intended to avoid regulatory chilling effects and are prospective by design.

A time-consuming but transparency-driven national grid policy reset

This is the beginning of a national large-load tariff reset.

The MISO order shows the template even as details around the ironclad priorities will necessarily vary: clear study processes, cost-shift protection, Network Upgrade transparency, co-location rules, flexible-load transmission service, electrically proximate generation/load study pathways, alternative transmission technology review, and adequate-generation reporting.

The broader message from the meeting is that the Commission is not done. The transcript says the six show-cause orders are region-specific, that they leave room for Section 205 filings, that requests for abeyance may be considered within 45 days, and that the ANOPR docket remains open for further potential action beyond the RTO/ISO regions.

More orders, more filings, and more regional tariff fights are coming. The abeyance requests can be filed by any jurisdictional Transmission Owner, not just the RTO subject to the show-cause. If you need a list of who’s who, it’s in the appendix chart.** Enjoy!

Bring us more subscribers, too!

A.S.F.

***The abeyance off-ramp is principally for the RTO/ISO and relevant transmission owners — the entities with the tariff filing rights and the ability to work through stakeholder processes toward a Section 205 filing. Other interested entities can intervene and respond to MISO’s and the Transmission Owners’ filings, but the MISO order does not appear to invite non-RTO/TO parties to independently request abeyance.)

THAT’S A LOT OF TOS AND A LOT OF NONPUBLIC COMPANIES

On June 18, 2026, the Public Utility Commission of Texas approved PGRR145 at its open meeting, taking it up as Item 28 (Project No. 54445) ahead of the remainder of the rules-and-projects agenda. The protocol revision, adopted by ERCOT as the independent organization, arrived before the Commission with a staff recommendation to approve.

Staff’s recommendation

Staff opened by noting that the ERCOT board had approved PGRR145 and that staff recommended approval of the requests and the proposed order. Staff observed that multiple comments had been filed as recently as the day before. On enforcement, staff emphasized that the protocol language is strong: although eligible entities provide attestations, ERCOT retains the authority to require supporting documentation, verify it at any time, and take action accordingly.

The lone public commenter

One person signed up to speak on the item: Chris Patten, counsel for a Texas-based large load developer. Patten supported the general intent of PGRR145 but asked for narrow relief. Specifically, he requested that the Commission condition its approval on a directive requiring ERCOT to prioritize and validate the completion necessary to determine baseload eligibility for the load associated with the developer’s RTP projects before July 10, 2026.

Patten framed the request around two principles. The first was fair notice — encompassing no retroactivity, due process, committed capital, and reliance on the rules. The second was that projects should be judged on the merits of their submissions and not penalized because ERCOT took longer than expected to act (let’s just say, the embedded grievance in our view is that the TSP took longer to act, making it harder for ERCOT to act).

His concrete grievance: as of the meeting, 250 MW of the developer’s load was eligible and 150 MW was not, despite being the same developer and the same project.

Patten expressly reserved the broader retroactivity and fair-notice arguments for a later proceeding.

His ask before the Commission was deliberately limited — condition approval of PGRR145 on ERCOT completing its review of the remaining 150 MW of RTP project load so that it could be reflected in a batch zero clarification.

ERCOT and staff on affiliate reliance

ERCOT addressed the affiliate-structure question raised in comments (we’ve covered those on the side of the Substack). PGRR145 establishes an eligibility framework keyed to maturity criteria on the interconnecting entity, satisfied through attestation. Several commenters had sought clarification on whether an entity may rely on an affiliate to meet those criteria.

ERCOT’s position was that the requested clarification is reasonable and would not impair its ability to administer the process, and that ERCOT plans to implement PGRR145 to allow reliance on affiliates. To do so, ERCOT said it needs bright-line criteria to confirm that a claimed affiliate is in fact the entity’s affiliate, and that it intends to apply the definition in 16 Texas Administrative Code § 25.5(3)(A)–(E) — a provision written for public utilities, but one ERCOT would apply here regardless of whether the entity is itself affiliated. A commissioner confirmed the citation on the record.

The refund-split exchange

The Chairman used this item to work through an open implementation question with staff, flagging that a related rulemaking is in process. The question concerns the treatment of refundable versus nonrefundable amounts. The proposal began as 80/20 nonrefundable, with discussion of flipping it to 20% nonrefundable and 80% refundable.

The Chairman posed a hypothetical: if a company requests roughly a gigawatt of capacity backed by a credit of around $50 million, and then decides not to move forward after allocation, does the nonrefundable percentage apply to the full request or only to the allocated amount? Jesse Horn, for commission staff, answered that the ratio would apply to the allocated capacity — once ERCOT has studied a request and identified the capacity it can provide, and the applicant then withdraws, that allocated amount is subject to the nonrefundable portion. The Chairman confirmed that retained funds are not held to be applied elsewhere; they go toward the cost the applicant imposes on the system. Staff agreed, adding that the purpose is also to protect against stranded infrastructure costs.

The vote

After a brief clarifying exchange on maintaining consistent implementation across the protocol and the pending rulemaking, the Chairman entertained a motion to approve. The motion was made and seconded, and it prevailed. PGRR145 was approved, with ERCOT’s affiliate clarification stated on the record.

**One point worth flagging: the meeting record does not reflect the Commission expressly adopting Patten’s narrow conditioning relief — the 150 MW review and the July 10 deadline. His request was raised, but the proposed order the Commission approved incorporated the affiliate clarification ERCOT described, not the conditioning directive he sought.**

The precedent for Speed to Power

PGRR145 approval means that applicants seeking #speedtowpower with #PCLR, privately firming load deliverability, can confidently seek that treatment consideration in their entryway to the Batch Zero study process. Thanks to all of our collaborators - a marketplace of doers - for helping us bring first principles to the first market design that is ready-to-ship for large loads that actually solves reliability risk, transmission affordability, and siting loads to benefit all ratepayers, simultaneously. It is worth noting today that FERC announced a series of wind-around show causes and punted the market design decision to dozens of individual utility operators because that is the reality of the physics of making #speedtopower work. It is unavoidable. It is not red tape. The physics of a grid determine what solutions work - ERCOT is lucky that its regulator directly governs physics-based solutions. In ERCOT, we wrote the market standard and made it available to the public in 10 months because physical operator -to-regulator is a stone’s throw conversation. Much like #ADER, the #PCLR framework will go through maturity cycles, all of which we are stoked to work on and share with other grids.

Thanks for reading, bring us more subscribers y’all!

Subscribe now

-A.S.F.

The letter states:

The PUC and ERCOT shall submit a joint memorandum no later than July 17, 2026, to the Office of the Texas Governor, summarizing actions taken under existing authority, identifying statutory limitations, and recommending legislative proposals necessary to implement these objectives. The PUC shall initiate action to reduce residential ratepayer transmission costs by July 31, 2026.

In addition, I pledge to work with the legislature next session to: • Codify the PUC’s actions to require data centers to pay for their own electric infrastructure costs, resulting in lower residential ratepayer costs; and • Ensure data centers add to Texas’ electric capacity, not just its electric demand; and • Require that all new data centers be built with water-efficient technologies such as closedloop cooling systems; and • Require large data centers to annually report electricity and water usage data to the PUC; and • Repeal sales tax exemptions and other outdated or unnecessary incentives for data centers; and • Require data centers to reduce impacts on local communities by implementing best practices such as setbacks, noise-reduction technology, and other measures that take into account the concerns of neighbors.

Read the Governor’s Letter to PUC Texas and ERCOT.

Texas has been one of the most important growth markets for data centers, AI infrastructure, and behind-the-meter power development. But this week, the politics of that growth changed.

Governor Abbott’s June 10 directive to the Public Utility Commission of Texas and ERCOT does not ban data centers. It does not impose a new statewide emissions-control mandate. It does not directly regulate backup generators, sound walls, or diesel aftertreatment systems.

But it does something almost as important: it formally links data center growth to ratepayer protection, infrastructure cost allocation, sustainable resource management, local community impacts, setbacks, and noise-reduction technology.

That is a big deal!!! For those of you who work hard every session to kill the setback rules that oil and gas advocates slam on battery energy storage projects, you know what sort of big deal this is.

A data center can have a plausible interconnection strategy and still face local opposition. It can have engineering plans and still get bogged down in hearings, noise studies, setback fights, or concerns about water, transmission costs, and backup generation. It can be technically lawful and still politically vulnerable.

That is why the Governor’s directive is so important. I think it is a vote of support for some more chaos! If I’m wrong, well, I would like to be wrong.

The letter tells PUC and ERCOT to ensure that data center development does not burden ordinary Texans with infrastructure costs, does not negatively affect residential electric bills, and does not shift development risks and costs onto communities. It also previews possible legislation requiring data centers to add electric capacity, use water-efficient technologies, report electricity and water usage, revisit tax incentives, and reduce local impacts through practices like setbacks and noise-reduction technology.

Read that again: setbacks and noise-reduction technology are now part of the statewide data center policy conversation in Texas.

That is exactly where local politics becomes infrastructure policy.

Senate Bill 6 is the backdrop. SB 6 created a stronger framework for large-load interconnection, financial responsibility, planning discipline, operational standards, and reliability protection. It was about making sure large loads, including data centers, do not show up on the grid without the financial and operational seriousness required to serve them.

SB 6 says: if you are a large load, you need to meet the grid-access rules. The Governor’s directive says: even if you meet those rules, Texas still needs to ask whether your project shifts costs, risks, resource burdens, or local impacts onto Texans.

I have been building an emissions, noise and social-license thesis which is being commended today as “prescient.” The Governor’s directive gives new momentum to residential advocates seeking to tighten the rules around data center development. Expect increased setbacks, sound mitigation, and emissions capture to become part of a more standardized permitting playbook across Texas. It does not matter if this is not law - enough pain can be avoided by getting ahead of it. Anyone planning behind-the-meter development should be modeling these “social license” costs directly into the pro forma. That is the right frame.

Behind-the-meter generation can look attractive on a spreadsheet. It can promise speed to power, reliability, and insulation from grid delays. But if that generation brings noise, emissions, land-use impacts, fuel logistics, or community opposition, then the spreadsheet is incomplete.

The real cost of power includes the cost of being allowed to build. That may include setbacks. It may include acoustic mitigation. It may include emissions controls. It may include monitoring, reporting, community engagement, and redesign risk. It may include delay.

None of this means Texas has become a direct emissions-control mandate market.The Governor’s directive does not say every data center generator needs SCR, DPF, DOC, or any specific emissions-control technology. It does not turn SB 6 into an air-quality statute. It does not say diesel or gas backup generation is forbidden. But it does move Texas toward a project-defensibility market.

In a project-defensibility market, the question is not only what the law strictly requires today. The question is what a developer needs to do to get a project through the next wave of scrutiny.

• Can the project defend its noise profile?

• Can it justify its setbacks?

• Can it show it is not shifting infrastructure costs onto residential customers?

• Can it explain its water use?

• Can it account for backup or behind-the-meter generation?

• Can it show that local residents are not being asked to absorb the project’s externalities?

That is where this becomes relevant to the broader power infrastructure supply chain.

If data centers continue to rely on backup, bridge, prime, or behind-the-meter combustion assets, developers may increasingly need those assets to be cleaner, quieter, monitored, and easier to defend. That creates a stronger case for emissions controls, acoustic mitigation, and integrated compliance solutions.

But the signal is not one-directional.

The same pressure that supports cleaner and quieter generator infrastructure could also push some developers away from combustion entirely. This, is a real heck of a thesis, because we all know that there is gas, and there is batteries with solar. There is not much else.

It is time to double the staff of the PUC of Texas and ERCOT to meet all of these demands…otherwise, I don’t know how we get anything done fast enough to keep AI in the United States. Texas is the largest and most open market for this growth.

-A.S.F.

This is huge. It is like the Meta deal in Northern Louisiana, first of a kind and one of a kind.

What is gen-tailing?

Gen-tailing is the combination of generation (making the power) and retailing (selling the power directly to end-users).

To understand why it matters in this scenario, it helps to look at the specific corporate entities involved:

• NEE (NextEra Energy): The publicly traded parent holding company.

• NEER (NextEra Energy Resources): NEER’s unregulated, competitive generation arm. It is a massive developer of wind, solar, and battery storage.

• NEET (NextEra Energy Transmission): NEET’s competitive transmission arm that builds high-voltage wires outside traditional territories.

• Dominion Energy (D): The regulated utility bringing a massive transmission network and a captive retail rate base (ratepayers).

Combining Dominion and NEE creates a vertically integrated utility conglomerate with an unparalleled number of retail ratepayers and physical generation assets - largest in the country! To put the physical scale in perspective, the combined entity would own the only two operating nuclear facilities in New England (NextEra’s Seabrook and Dominion’s Millstone), and have 10 million (approximate) customer accounts, as described in today’s press release from the companies.

Because of this immense scale, the clean energy, Megawatt-hour (MWh), and Renewable Energy Certificate (REC) implications are massive. As NEER builds out significant renewable and storage projects across the country, and its transmission subsidiaries wheel that power, the value of the green attributes traded internally becomes highly significant. Ultimately, this creates a major clean energy upside that customers could capture.

Structurally, this combination could create a near-perfect internal financial hedge. When NEER (the unregulated generator) generates power, it pays the regional grid operator (like PJM) to wheel that power and covers the congestion costs. The grid operator then distributes those transmission revenues back to the Transmission Owner—which will now be Dominion.

Because NextEra owns Dominion, NextEra is effectively paying itself through its subsidiaries. The friction of moving power across the country becomes an internal hedge rather than a sunk cost paid to a third party.

Dominion completes this hedge with its large load tariff structures. It passes the ISO-allocated and Dominion state-approved tariff-based transmission costs down to its ratepayers by user class.

We already know that to handle the unprecedented demand from Virginia’s data centers, the State Corporation Commission has begun assigning transmission and distribution upgrade costs directly to the data centers themselves through specialized rate classes (like the GS-5 tariff) and mandatory 14-year minimum demand contracts.

This Sounds Hard to Get Approved: Why Would NextEra Want This?

NextEra gets to capture the unregulated upside of wholesale clean power generation and environmental attributes, while legally socializing the physical transmission upgrades across Dominion’s captive retail rate base that is under evolution to ensure large loads pay their fair share of grid costs.

There’s also the promise of massive financial shields—specifically within regional wholesale markets like PJM. As pointed out in a chat we had today, Dominion would be linked to NextEra’s massive generation fleet; the combined entity technically would have the leverage to opt out of PJM’s volatile capacity market under the Fixed Resource Requirement (FRR).

I agree with this view: by marrying their captive retail load to their new internal generation to cover their resource adequacy requirements, they can shield themselves from the severe price explosions we’ve recently seen in PJM’s Base Residual Auctions—spikes that have entirely bypassed the price “collar” strategies proposed by PJM governors like Josh Shapiro. (See my CSIS PJM Market Intervention Piece).

Moreso, in an era where building new power generation and transmission is difficult and expensive, this structure cements bankability on the IPP side. NextEra can aggressively finance clean energy projects, and there is upside to a large load tariff regime on the delivery side, financially de-risking the energy transition for the holding company while maximizing shareholder profit and zapping green electrons on wires to data center load. This is a publicly traded company, mind you - so do not think that “shareholders” are just bots in an ivory tower. Retail investors, institutional retirement funds, a lot of us bread-and-butter types own these stocks in a diversified portfolio offering. So, this could be good for us.

It’s going to be interesting to see how the state regulators feel about these entities effectively cornering the market on both the generation of clean power, moving the power on its own transmission lines, and captive retail delivery. The regulatory burdens are significant, and regulatory approvals will be, too.

My work with energy gen-tailing in Texas and the implications for this deal

Much of my work for Tesla in Texas involved solving the mechanics of enabling two-way value for retail loads via wholesale markets and enabling grid-scale owned/contract storage to hedge risks to serve retail load and increase revenues for developers using Tesla Megapack battery energy storage. I managed the public-facing strategy and shepherded the first-of-its-kind Texas gentailer into existence for Tesla (Tesla Electric). You can see the clearest articulation of this business model in a presentation I gave to the ERCOT Board of Directors here:

Also during this time period, I wrote a memo that broke down the foundational utility mechanics in this post on ’s Energy Central.

Furthermore, Dominion brings serious infrastructure execution to the table in other strength areas—they have an excellent commitment-based relationship with GE Vernova, they know how to work with their regulators, and they have a deep bench of technical experts. Dominion already has established operating and procurement relationships with GE Vernova across generation infrastructure, including deployment of GE Vernova turbine technology at facilities like Bushy Park in South Carolina. More importantly, in today’s constrained turbine market, relationships and manufacturing commitments themselves have become strategic assets. Utilities across the country are racing to secure limited gas turbine production slots amid explosive load growth from AI and data centers, and GE Vernova’s turbine backlog is apparently still quite sold out. Dominion’s experience navigating large-scale infrastructure procurement, regulator engagement, and generation deployment therefore becomes highly valuable in a combined platform attempting to execute at unprecedented scale. Former GE Chairman & CEO just joined Substack. Wonder what he thinks (tagging him, totally - ).

The teams that do gen-tailing right can come from anywhere. So, I want to step away from all the hype about utilities not being able to “manage” their regulatory relationships, as if that is the start and end of things. The reality is, gentailing is complex, no matter who does it - lots of competitive retailers have no idea how to manage their regulatory relationships either; they get in all kinds of trouble.

On that note, launching Tesla Electric took the wind out of me to ensure perfection in compliance and public opinion as we built the first retail energy operator for the company - ever. I was not only Tesla’s energy markets policy lead, I was also their senior regulatory counsel. I had to explain to new company compliance officers they were signing up for liability, complete the analysis to protect the company under PUHCA and state-specific retail-wholesale separation laws, work with the Tesla legal team to explain and support their efforts to derisk the business, design a master holding company thesis to enable Tesla to safely comply with multi-jurisdictional requirements, and, the most significant - show up in front of real people. I was in Texas Monthly. Consumers who would be relying on us for their power.

The teams responsible for design and execution consumed massive amounts of complexity to deliver and the effort was tireless. Yes, I did not sleep. But I was darn happy about it. I wrote in my prior piece today that competitive retailers invite customers to link up to their caboose. There is a lot of reward in getting this right.

How could this affect NextEra and Dominion Ratepayers Shareholders?

Both D and NEE trade on the public stock exchange. This deal doesn’t just impact ratepayers; it impacts retail shareholders who hold one or both stocks. For NEE, 4 out of 5 shares are held by large professional capital allocators, and 1 out of 5 by ordinary retail investors. Importantly, the institutional holders are not ‘Wall Street’ companies.

Roughly three-quarters to four-fifths of both NextEra and Dominion shares are held by institutional investors, much of that through retirement systems, index funds, pension allocations, insurance portfolios, and dividend-focused mutual funds.

Millions of ordinary Americans therefore hold economic exposure to these utilities indirectly through 401(k)s, public pensions, and broad-market ETFs.

Your savings/retirements have something to do with a utility asset portfolio. You should look into it.

Utilities like NEE and D occupy a uniquely important role in the architecture of modern retirement investing because they function as quasi-defensive, income-producing assets inside diversified portfolios. Large institutional holders—including pension systems, insurance companies, index funds, dividend-income funds, and target-date retirement products—rely on regulated utilities to generate comparatively stable earnings and predictable dividend streams across economic cycles.

In practical terms, millions of ordinary Americans indirectly own utility equities through 401(k)s, IRAs, state pension systems, union retirement plans, and broad-market ETFs managed by firms like Vanguard and BlackRock.

The underlying “utility equity social contract” is that regulators grant investor-owned utilities relatively predictable cost recovery and monopoly service territories in exchange for reliable infrastructure investment and universal electric service; investors, in turn, accept slower growth in exchange for lower volatility and durable dividends.

That stability is not merely a market preference—it underpins retirement income modeling, insurance reserve allocations, and conservative portfolio construction throughout the U.S. financial system. As a result, transformative utility mergers are not just industrial transactions; they directly affect the risk profile of retirement capital that depends on utilities as long-duration, dividend-generating infrastructure holdings.

If you own NEE or D stock tickers, you’ll see downward pressure on NEE for a bit, and upward swings in D. This is a classic M&A market reaction: the acquirer takes on the risk and pays the premium, while the target’s stock jumps to meet that premium. It’s actually a great time to teach your kids about retail investing and how institutional and insurance funds position themselves in investor-owned corporate entities like NEE. These massive funds rely on utilities for steady dividends, so a deal like this forces major portfolio rebalancing.

What are the Implications for Ratepayers?

For the ratepayers themselves, particularly large datacenter operators in Northern Virginia, owning both the infrastructure and the regulated generation will reflexively cause supply concerns regarding who supplies them. I expect this to ironically trigger a comprehensive review of existing supply contracts.

Additionally, as we’ve already seen in industry coverage and early advocacy reactions, consumer groups are likely to scrutinize NextEra’s regulatory and rate history closely, particularly as the company seeks to integrate a massive regulated footprint with a large competitive generation platform. State commissions in Virginia, the Carolinas, and beyond will almost certainly focus on ensuring that transmission expansion costs, generation procurement strategies, and merger-related financing obligations are not disproportionately shifted onto captive retail customers.

But the ratepayer implications are not confined to any single state or utility territory. This transaction would effectively turn the future structure of electric cost recovery, transmission investment, and clean energy integration into a multi-jurisdictional exercise spanning roughly 10 million customer accounts and tens of millions of individual residents and businesses across state lines. The scale alone changes the conversation. Decisions regarding where generation is built, how transmission upgrades are allocated, how large-load tariffs are structured, and how wholesale market exposure is hedged could influence retail electricity economics across multiple regional grids simultaneously.

That does not automatically mean rates rise dramatically; in fact, proponents will argue that greater scale, internal generation access, supply chain leverage, and transmission coordination could improve long-term system efficiency and reliability.

However, the central regulatory concern will likely become whether the financial benefits of this vertically integrated “gen-tail” structure flow meaningfully back to ratepayers—or whether the primary gains accrue to shareholders through enhanced earnings stability and internalized market economics. Be careful with this analysis - your child’s 2060 target fund relies on steady flow of dividends from low-risk stock. The mix has large IOU exposure, and you want that exposure to be stable, predictable, and not fraught with new risk created by “ratepayer protections” that block back on the utility system. What do you want, is for large loads to pay their way - at least in Virginia, that is happening.

Ultimately, regulators are not simply reviewing a merger between two utilities; they are evaluating whether a newly consolidated infrastructure platform of unprecedented scale can balance shareholder returns, grid modernization, and public-service obligations without concentrating too much market and operational leverage inside a single holding company.

What does this signal for future power industry deals?

Whoever controls the wholesale build, interconnection hardware and the retail meters controls the future of the grid. The primary signal here is scale...no next deal could really be as big as this one, could it?!

This is huge. It is like the Meta deal in Northern Louisiana, first of a kind and one of a kind.

If this goes through, we’re creating the world’s largest regulated electric utility. We are talking about combining NextEra/FPL’s roughly 6 million customer accounts with Dominion’s nearly 4 million. That is approximately 10 million retail meters under one roof, as they announced earlier today (https://www.prnewswire.com/news-releases/nextera-energy-and-dominion-energy-to-combine-creating-the-worlds-largest-regulated-electric-utility-business-and-north-americas-premier-energy-infrastructure-platform-benefiting-customers-302774600.html).

When a single entity captures that much load and pairs it with a massive unregulated generation arm, it fundamentally shifts the balance of power across three major fronts:

• The Hardware Supply Chain: Economics of scale build on economies of scale - supply chain dominance is a part of every deal; sometimes it is hidden, and sometimes it is very obvious. A “sleeper” aspect of this specific deal would be Dominion’s existing inventory of gas turbines and their secured production commitments from suppliers like GE Vernova. In an era of massive supply chain bottlenecks, acquiring guaranteed, locked-in hardware is just as valuable as acquiring customers.

• Wholesale Market Regulatory Rewrites: All massive power deals impact the active regulatory rewrites happening right now, particularly in regions like PJM and its states. We talked about that above.

• The End of the Pure Play: The obvious signal here is retreat from relying solely on competitive, deregulated markets. Future deals will likely lean into this gen-tailing blueprint if it works, but not at this scale.

Connecting the Dots

I hope you enjoyed this piece. Earlier today, a NextEra transmission (NEET) professional sent in a congratulatory note, and so did a former CEO of an RTO, on being the best in the game at connecting the dots. That, in my humble view, is the work of cognitive training. I train my cognition by connecting thousands of unrelated matters, objects, ingredients, data points, spatial clues. And when I wake up in the morning, I do not look at a screen. I look at a dog, and note thousands of little furs that whoosh together in a search of cheese and pets.

A.S.F.

I became a #foak [first-of-a-kind] expert in commodity-based swaps because I started my career in energy at the exact same time as the passage of Dodd-Frank.

I was 25.

Within a year, I knew as much about the interplay of financial and physical markets, FERC-CFTC overlap, and RTO swap and non-swap transactions, as anyone else. No one had a head start with a brand new law. It was the ultimate level playing field.

Chairmen Gensler and then Massad both appointed me to sit on behalf of the American Gas Association (AGA), and then the Electric Power Supply Association (EPSA), on the CFTC statutory advisory committee, EEMAC. I was the youngest appointee by a margin of about 12 to 15 years.

Shaping the Rules: My Regulatory Curriculum

While learning the Dodd-Frank Act at the same time as everybody else, I also became one of the best advocates in Washington for sensible regulation of end users and physically settled Power and Gas contracts by the CFTC.

My personal contributions to shaping energy commodities regulations all occurred between the ages of 26 and 31:

1. Leading natural gas regulatory strategy: I built and led the regulatory advocacy strategy on behalf of the natural gas utility industry for relief from swaps regulation. I crafted a request for interpretive guidance that taught most of Congress, and financial agencies, the intricacies of designing and settling natural gas interruptible power contracts, i.e., volumetric optionality. (Public doc).

2. Defeating private rights of action: The CFTC reneged on a proposal to act on an intent to impose private rights of action on Southwest Power Pool transactions. I successfully lobbied Debbie Stabenow to write to the agency. At my urging, the FERC engaged in a rarity—it filed comments in the CFTC proceeding to protect its jurisdiction. But my legal argument on consumer protection was the strongest. The CFTC told me in the order withdrawing its proposal that my comments on behalf of EPSA were moot because they were withdrawing the proposal. You can spend a lot of dollars on talking to high-up policymakers, but the unassailable work is inside the docket.

Fun Fact: My first meeting on this administratively contentious issue was with 16 CFTC staff, and just me, on behalf of EPSA. CFTC attendees included Jonathan Marcus and Rob Schwartz, General and Deputy General Counsel. Rob still jokes about the fact that he thought I was already in my late thirties when I took this meeting. I was 29.

3. Refining the volumetric optionality test: The CFTC also revised its 7-part volumetric optionality test, created the commodity trade option exemption to limit and shift reporting burdens for non-swap energy transactions away from energy end users, and did major cleanup that I passed through in real time to members of the trade associations I worked at. The cleanups saved my member companies and others millions in compliance risk.

4. Drafting CFTC Form TO: CFTC Form TO is partly based on my drafted language sent to the agency. So anybody who fills that form out now is filling out term fields which make more sense because I pushed the agency to be sensible—a great thing we can do in the United States because of the Administrative Procedures Act. If those forms are annoying, well, it used to be so much worse.

Trade School Faculty: Water-Testing with the Best

I had excellent peer and advisor-mentors teaching me physical power and gas while I led this work, water-testing all of my ideas until they were no longer stupid. And from there, I made it my commitment to them that I would be unassailable.

Those people are: Susan Bergles, Matt Picardi, Kenny Kam, Andrew Soto, Norma Iocova, Keith Emery, David Morenoff, Kathleen Magruder, Mark Stultz, Bob Reilly, Scott Butler, Jim Stanzione, Allison Lurton, Paul Hughes, Kevin Frank, David McIndoe (D-Mac), and more.

It is all about the Moat

Trader School = having a deep moat on fundamentals, understanding risk, contract structure, and doing something with that knowledge to build a better world and dispensing of the instinct to cry because the answer is neither simple nor homogeneous.

The idea of Trader School is to put yourself in a position where you learn and practice locational arbitrage. You learn to tolerate—and actually leverage—strategic diversification based on location, deeply understanding the absence of like-kind profile risks across different geographies. Apply that more broadly to how you design and execute strategy, and you will find that you are generally speaking, more unassailable than others in achieving more, sooner.

When you have that foundation, you never walk away with a lazy, one-size-fits-all approach. More importantly, you stop falling for the stupid political rambling—at both the local and national levels—about administratively selecting and subsidizing winners and losers.

Rejecting the Lopsided Argument

Here is a perfect example of why this mindset matters today.

It is incredibly hard to find a decent article on the issue of solar development on agrarian or wildlife-adjacent land that properly discusses locational benefits and risks. Instead, the discourse is flattened.

Consider the Wilburton Solar Farm in Cambridgeshire, UK. The reality of that project is fascinating: By day, this solar plant powers 1,500 homes. By night, it becomes a refuge for one of Europe’s rarest birds and may actually be helping save it from extinction.

Meanwhile, if you search the topic, you will find hundreds of articles doing nothing but complaining about solar on agricultural land. The perspective is almost always lopsided, ignoring the localized nuance of what a project can actually achieve when strategically sited.

My brain simply cannot handle it anymore. It actively rejects lopsided arguments and zero-sum design. The story I have told readers today is about a learned cognitive reflex.

Trading law, execution, and strategy work forces you to look at the whole board, respect the fundamentals, and build solutions that actually work in reality, not just in rhetoric.

A.S.F.

This weekend, #NEE announced its intent to acquire #D. Under this publicly traded parent entity sits NextEra Energy Transmission (#NEET). It is the competitive transmission arm. NEET bids on and builds high-voltage wires outside of FPL's traditional territory. They are the "wire builders" who can parachute into new regions to fix physical bottlenecks. Also under NEE is NEER: NextEra Energy Resources, a competitive, unregulated (IPP) subsidiary. It builds massive wind, solar, and battery farms across the country, and houses the high-octane trading desk that manages financial instruments and REC sales.

If this deal goes through, NEER's trading desk will have a field day and the trader compliance lawyers will sleep lightly (I used to be one of these!) NEER (the generator) pays PJM to wheel power and covers the congestion costs. PJM then distributes those transmission revenues back to the Transmission Owner—which is now Dominion, owned by NEE.

Thus, NEE is effectively paying itself through its subsidiaries. The friction of moving power from the Midwest to Northern Virginia becomes a massive internal financial hedge, rather than a sunk cost paid to a third party.

#Dominion completes the hedging with its large load tariff structures - it passes the ISO-allocated (and its own retail tariff) transmission costs to ratepayers. We know already that to handle unprecedented load, the SCC has begun assigning massive transmission and distribution upgrade costs directly to the data centers themselves through specialized rate classes (like the GS-5 tariff) and mandatory 14-year minimum demand contracts.

This is not illegal. It is legal. It is called gen-tailing, and it occurs with the benefit of a vertically integrated holding company that brilliantly straddles both a deregulated wholesale market and a captive, regulated retail rate base. NextEra gets to capture the unregulated upside of wholesale power generation and environmental attributes, while legally socializing the physical transmission upgrades across Virginia's hyperscalers and other classes of ratepayers.

I managed the #FOAK Texas gentailer public-facing strategy- and shepherded the entities into existence - for #TSLA. So, I know this can be done in competitive markets too...don't have to have captive retail customers who are tied to your caboose by law. Instead, they can come to the caboose willingly.

This acquisition announcement raises the question though: do we have time for replicating Texas-style solutions around the country? With this type of announcement, I think not. How about you?

A.S.F.

Post- Script: oh boy if you came here first thing on a Monday morning you deserve a picture of a cute dog.

To understand how we arrived at this moment—and where the smart capital is moving to solve it—we have to look at how the workhorse of corporate procurement is evolving, and why physical constraints are forcing the market to innovate.

If you're interested in the continued conversation I have been having on this topic on X, you can find that here: https://x.com/ArushiSF/status/2055134572812062753?s=20

Read more

Texas recently allowed its Renewable Portfolio Standard (RPS) to sunset, prompting the state to officially repeal the mandatory trading program. For a state that has historically served as a dominant hub for renewable energy, this policy shift might initially seem like a major blow to the industry. However, the loss of the Texas RPS is not causing a shock to the trading business or the broader Renewable Energy Certificate (REC) market. In fact, market participants view the expiration as largely immaterial.

A Massively Oversupplied Market for Compliance

To understand why the REC market is shrugging off the expiration of this mandate, you have to look at the sheer volume of renewables in the region. Texas has been accurately described as a "massively oversupplied wind and solar state". Even before the RPS expired, there was likely enough Texas wind and solar capacity built prior to 2010 to easily satisfy the state's baseline compliance requirements. If legacy wind and solar weren't enough, any remaining compliance obligations could have been seamlessly met using lower-quality alternative products, such as hydro or biomass.

Because of this immense, unconstrained scale, an estimated 45% of all voluntary RECs purchased nationwide actually originate out of Texas. This overwhelming volume effectively makes the state responsible for the ultimate baseload U.S. renewables product.

The National Voluntary Market: Dwarfing State Compliance

While the Texas compliance market is fading, the broader U.S. voluntary REC market is stepping on the gas, completely altering the demand landscape. To understand why the voluntary market outside of Texas is so disproportionately large, it is essential to look at how corporate mandates operate versus state policies. State-level RPS programs are inherently geographically constrained and capped by specific legislative targets. The voluntary market, by contrast, operates on an uncapped supply-and-demand balance driven by nationwide consumer and corporate sustainability commitments.

Technology companies, global manufacturers, and retail giants are procuring renewable electricity at levels far above what mandatory policy decisions require. Because these corporations have load footprints and ESG targets that span the entire globe, they seek verifiable clean energy instruments—like RECs—irrespective of local state mandates. Consequently, the national voluntary market acts as an unlimited demand floor that easily absorbs the excess REC generation pouring out of powerhouses like Texas.

Economics Outpacing Policy

The primary purpose of an RPS is to force renewable procurement and provide an extra financial incentive for grid decarbonization. But the current reality in Texas raises a pertinent question: does the state even need an RPS at this point?.

The answer largely lies in simple price parity. Driven by an 80% drop in production costs over the last decade, it is currently cheaper to build utility-scale solar in Texas than almost any other conventional energy source. If the fundamental economics make sense on their own, developers are going to continue building renewable assets regardless of whether a state-mandated incentive exists to push them along. If the fundamental economics have become stupid, then we are out of luck, and that's the way it should be because markets work. (We are not RPS fans, generally speaking).

Voluntary Demand and the Hyperscaler Shift

While the Texas RPS expiration might remove a couple million megawatt-hours of compliance demand from the system, that loss is a drop in the bucket compared to broader macroeconomic trends. Voluntary corporate demand is growing at a staggering rate that easily offsets this lost compliance load, with expected demand increases of 15 million megawatt-hours a year.

Furthermore, the procurement strategies of massive power consumers have fundamentally shifted. Large buyers, particularly tech hyperscalers, are actively seeking out long-term, bundled Power Purchase Agreements (PPAs) directly with developers that inherently include RECs. Because these corporate buyers hold a highly bullish view on forward Texas power pricing, they are essentially locking in long-term power rates and acquiring the associated RECs at a discount to the broader market in the process. When a PPA is priced without the green attributes, the power really isn't worth anything and the green attributes are worth a lot, and they get their asking price in primary and then secondary markets separately. When the PPA is a renewable PPA and the recs are included with the brown megawatt hours, the renewable attributes are getting acquired at a discount.

The Bottom Line

The expiration of the Texas RPS marks the end of a specific policy era, but it emphatically does not signal a retreat for the state's renewable energy sector. Texas has simply outgrown the need for forced compliance to drive physical infrastructure development. Music to the ears.

Propelled by undeniable cost advantages and an insatiable, uncapped appetite from the national voluntary corporate and hyperscaler markets, Texas will quietly remain the engine of the U.S. renewable baseload.

A.S.F.

**Works Cited**

• *Texas Renewable Growth Spurs US Voluntary RECs Market*, CCarbon (June 15, 2023), https://www.ccarbon.info/article/texas-renewable-growth-spurs-us-voluntary-recs-market/.

• Pub. Util. Comm’n of Tex., Order Repealing 16 Tex. Admin. Code § 25.173, Project No. 55323 (2023).

• *Understanding the Nature, History, and Impact of Renewable Energy Certificates*, Sustainable Infrastructure (Jan. 22, 2026), https://sustainableinfrastructure.org/understanding-the-nature-history-and-impact-of-renewable-energy-certificates/.

• Env’t Prot. Agency, *U.S. Renewable Electricity Market*, EPA.gov, https://www.epa.gov/green-power-markets/us-renewable-electricity-market (last updated Oct. 20, 2025).

• * *The Cost of Solar Energy vs Fossil Fuels: Which is Cheaper?*, Shop Texas Electricity (Feb. 20, 2026), https://www.shoptexaselectricity.com/learn/solar-vs-fossil-fuels-cost-and-savings/.

To understand why the grid curtails the cheapest power first, you have to look at the Security Constrained Economic Dispatch (SCED)—the silent math that runs the grid. The system operator doesn’t look at a plant and see "clean" or "dirty"; they see a location (a node) and a price. When a transmission line hits its physical limit, the grid must rebalance itself instantaneously. The most efficient way to resolve this bottleneck is to turn off the Lowest Cost Marginal Resource behind the constraint. Since wind and solar have zero fuel costs, they sit at the bottom of the merit order and are almost always the first to be "curtailed" or forced to shut down.

This creates the "Out-of-Merit" phenomenon. While the cheapest megawatts are trapped behind a congestion point, the grid is forced to fire up more expensive generators located on the "right side" of the bottleneck to serve the local load. These are often older gas peakers or Battery Energy Storage Systems (BESS) located closer to load centers which are causing the system peaks we care so much about dissipating quickly. If these resources turn on at a much higher price, they do indeed drive up wholesale costs for everyone. In this scenario, the "winner" is whoever is geographically lucky enough -or intentional enough- to be near the demand, regardless of their carbon footprint. This is why home batteries, substation and front-of-meter demand balancing batteries, rooftop solar, and other “close to load” trends are so important. These resources respond more quickly to pricing spikes forced by the presence of congestion, not by the absence of “baseload” generation.

A colleague of mine recently highlighted, viewing the market through a "trader/risk manager hat" is essential for survival. In liquid trading markets, you can exit a position in an instant, but in power development, you are "unwinding the position" over a 20-year asset life. The trader argument is simply that the modern market is less about supply and demand headlines and almost entirely about transmission deliverability. If a developer doesn't understand the physics of the wire, they aren't building a power plant; they are just gambling on a node.

The risk profile shifts dramatically depending on the market structure. In energy-only markets like ERCOT, nodal volatility is the only game in town. This has led to a "bearish" outlook for solar in the region because inverter-based resources like wind and solar often "cannibalize" the next megawatt, driving prices down for each other while the congestion remains unresolved.

Contrast this with PJM, where the market isn't necessarily "short electrons," but rather short on reliable capacity. PJM capacity auctions have recently cleared at the cap, but the forward energy curves haven't moved, suggesting the shortage only exists for about 0.5% of the year. For a developer, this is a nightmare: PJM capacity pricing is often capped—currently at roughly $10/kW-month—while the revenue requirement for a four-hour battery to mitigate that congestion sits closer to $14/kW-month. Without a clear energy arbitrage path, the "signal" for storage is too weak to fix the congestion.

This leads to the great disconnect between wholesale prices and retail bills. Hyperscalers (Google, Amazon, Meta) are currently subsidizing a massive buildup of generation through long-term Power Purchase Agreements (PPAs). While this adds supply that puts downward pressure on wholesale energy prices, it simultaneously triggers a massive spike in system infrastructure costs. Transmission upgrades, protection relays, and fiber costs are all surging, and these are the costs the retail consumer ultimately pays.

The "sophisticated" power teams at these hyperscalers are finding that their early procurements were "in the money," but contracts signed in the last five years are increasingly "out of the money". Some of the world's largest energy buyers are now sitting on billions of dollars in annual losses because they procured gigawatts without fully accounting for the real-time congestion and basis risk that separates a wind farm from their data center load. They are paying for power they cannot physically receive at the time they need it most.

And this is why we have so many folks pushing hard for all sorts of solutions, but doing it from a “climate” “baseload" “utilization” “Pick-Your-Hat” sort of perspective.

Let’s explore a few of them.

Technologically, the solution lies in moving away from conservative "seasonal" transmission limits toward ambient, real-time limits. Unlocking capacity from existing transmission via Dynamic Line Ratings (DLR), reconductoring, and advanced power flow controls is often "faster, cheaper, and more reliable" than building a new gas plant. DLR allows grid operators to see that a wire can carry more current when the wind is blowing—exactly when wind farms are producing the most—preventing unnecessary curtailment.

We are also entering an era where load management is as critical as generation. In the Southeast US, developers have identified "electrification of waste heat" as a major frontier. By using heat exchangers and compression cycles to capture industrial waste heat that is currently vented, companies can bypass the thermodynamic inefficiency of the thermal system. This creates "demand response" capability that treats load like a battery, allowing it to participate in the market to solve congestion rather than just being a victim of it.

Then, there is using SCED itself to dynamically incentive loads to do what otherwise power lines could do with modernized software and hardware packages. The ERCOT PCLR construct, if there is uptake, is a cheaper way for the grid and utilities to outsource the ask for dynamic grid management to loads instead of to the power lines, letting them rely on a better-known system to relieve congestion by just building more lines.

Ultimately, the grid transition is moving toward a "three-legged stool" of generation, transmission, and load. As the industry pivots away from tax-driven incentives that "sunset" in the 2030s, the winners will be those who use physics and thermodynamics to their advantage. The grid does not care about the climate debate; it only cares about the deliverability of the next megawatt. Until we address the nodal congestion that picks winners and losers based on the wire, we will continue to curtail our cheapest resources while paying a premium for the ones that happened to be in the right place.

Now isn’t that a refreshing take? We hope so.

• A.S.F.

“This is something that’s going to grow very, very rapidly,” says chief commercial officer Cal Lankton. “Second-life batteries could provide up to 50% of all of the U.S. grid storage needs by 2030 or 2031.” - Time Magazine, The 10 Most Influential Energy Companies of 2026 - Aimee Rawlins.

I love Time© magazine. It brings out the bull in all of us. Two of ’ advised companies are in the 2026 list.

But in normal life, I am more banyan tree, less bull.

Here is whatI am thinking about batteries in America, and how to be energy dominant with storage. If you’re in the venture space or employment space in this incredible growth story, I hope you enjoy this story.

Does it Matter How Bullish the U.S. is on Lithium Ion?

Redwood's batteries are lithium-ion. The company is taking end-of-life electric vehicle batteries (which are predominantly lithium-ion chemistries like NMC or NCA) and repurposing the ones that still hold a charge into modular, large-scale battery energy storage systems (BESS). The ones that are totally dead get ground down to recover the raw nickel, cobalt, lithium, and copper.

Of course, lithium-ion isn’t the only game in town anymore, but it is the cheapest game by all accounts to serve a heavily diversified user base as quickly as in five years.

Where I currently come down on this, is that having a cool, differentiated chemistry is not enough. My memory is sharp enough to constantly remember the moments that matter going forward. Take for example, that there was a surge in violent lithium-ion fires which had little to do with American-made anything in New York. But what happened because of that excursion, is impactful for every incredible America-made thing that comes next. NYC implemented strict fire codes, and many building owners outright banned the storage and charging of e-bikes and scooters (like my own Unagi, gorgeously covered in the same stuff as the SpaceX rockets) inside apartments. That exact same hyper-local fear scales up exponentially in my view, so it needs a cognizant hyper-local answer to guarantee a recurring revenue thesis around deployment in market (not time to market).

The Untied States of America

I got a pen as a participation token in a fifth grade spelling bee, with a little U.S. flag print icon on it. It had misppelled the word “United” - so I read off “Untied States of America” and thought about the implications of that, the entire school bus ride home. Later on in life, I felt the extent to which we are untied.

Hyperlocal permitting and public fear of the unknown are brutal bottlenecks which showcase the experience of how being so untied in our understanding and acceptance of batteries, is holding us back.

A former colleague of mine, Tessa Sanchez (now at Uber doing uber-cool things) had the best way of handling the insanity on behalf of our former employer, Tesla. She had, from what I saw, personal knowledge of every township’s core team - fire marshal, zoning board, electric service rules, and commerical zoning and neighborhood-to-county regulatory overlaps. Largely through the enablement of sheer wits of people like her, I learned the easy way that educating local officials is a massive human-capital problem. [1]

Here’s a public record of what it really looks like to get education done for a major area of a state that ostensibly already has embraced BESS technology in homes and vehicles:

During this meeting (which you can watch the entire recording of), representatives from EVgo and Tesla laid bare the brutal math of commercial deployment. In 2021, it took about 18 months to bring a DC fast charger online, but only about a month of that is actual construction. The remaining 17 months? Trapped in local permitting. The challenges listed in this report for electric vehicle charging stations (EVCS) mirror the exact quagmire that BESS installers face today. The EVgo team pointed out at this meeting, that Authorities Having Jurisdiction (AHJs) are severely resource-constrained, requirements for submittals are completely inconsistent, and the entire process is dizzyingly complex. In some cases, local boards were reviewing EV chargers for "aesthetics" rather than basic electrical safety.

Likewise, when we are trying to install a sizeable battery system, fighting physics or chemistry is not really the issue - the fight is essentially creating a J curve of understanding with local stakeholders as to the technology’s value and how the technology should be de-risked to a level of confidence that regulators and insurers (and property appraisors) can get behind.

The frontline strategy here to actually deploy all that recycled BESS goodness has absolutely nothing to do with building BESS (and solar) in America. It is pretty much doing what my own Substack is doing, which is, Teaching What [We] Know.

Little armies of highly educated, affinity-building STEM policy and communications professionals should be working together right now, enabling disjointed municipal departments to do things like “build the capacity to understand the legislation” (because the various local teams approving and insuring your BESS or EV installation are not the people who wrote the law or regulation you happily shoved in their faces) and enabling tax dollars to flow to these entities so that they can hire the people needed to execute projects faster.

For the companies that claim to be ready to conquer 50% of the U.S. grid storage needs by 2030, it is imperative that the ecosystem of support for these companies fully understand what it will mean to conquer the market.

In the upstream context, these companies (like Redwood) have enough on their plate - they are almost entirely focused on hardware availability, supply chain dominance, and software integration, so we are assuming someone else will fight the trench warfare and derisk the moat.

Martini Glass to Tumbler: 4 Questions for Assessing BESS Dominance

If you are evaluating a BESS manufacturer or their deployment partners for U.S. uptake, here are the four reality-check questions you can ask:

1. Are you conflating “Equipment Lead Time” with “Deployment Time” or do you understand the difference and what it means for your business?

Hardware companies love to boast about how their modular structures allow for “faster deployment than traditional infrastructure” or how they have cut their manufacturing lead times in half. But having a battery ready to ship from a factory in Nevada or Texas in three months does not mean a local zoning board will approve its installation in three months. If a company is touting speed, verify whether they have solved the supply chain bottleneck, or if they have actually solved the human capital bottleneck. Shipping a box is fast; getting it energized is slow. (Hint: if you had me on the phone in my prior job, pre-venture studio, I would have rattled off how personally accountable I am for seeing the entire thing through until the photo of a completed install is uploaded to a municipal approval records system).

2. Is your regulatory strategy top-down or bottom-up?

Many BESS companies boast impressive policy teams that are heavily involved in drafting state-level regulations, lobbying for federal tax credits, and addressing interagency overlaps. That top-down cover is necessary, but it is not sufficient.

Lobbying for a state-level framework does not magically educate a part-time town fire marshal who is terrified of thermal runaway in a local commercial park. Due diligence requires asking: Who exactly is fighting the hyper-local trench warfare? If the manufacturer is punting this to their deployment partners, those partners should have an army of local expediters. If they do not, you need to figure out where the risk is, and who is the least cost bearer of that risk, and who should pay for the work to get done.

3. Are you relying on technical engineering to solve human integration?

Watch out for companies that point to their proprietary software as the panacea for rapid scaling. Incredible Battery Management Systems (BMS) and pack-management software are brilliant for safely stringing together different battery chemistries into a unified microgrid. But don’t confuse an elegant electrical engineering solution with a municipal permitting solution. Software safely balances the voltage; it doesn’t convince a skeptical city planner to approve the site plan.

The last thing we need, truly, is more companies that are set to build the “best technology!” while ignoring the service standards and fire codes of thousands of jurisdictions and hoping they can solve that later.

Somebody has to derisk this for the company - who is it?

“Who” can be misleading here, so to clarify, let’s use a fun data center siting analogy. When a developer commits land option payments to a delighted landowner , the landowner should be taking the risk of oustanding zoning and other permit approvals as part of the deal - that party or entity is, almost always, the least-cost bearer of risk and also stands to gain the most from owning the problem statement.

4. Do macro headwinds prevent them from fighting in the unscalable trenches?

Keep a close eye on the manufacturer’s core business and capital runway. If a company is facing massive economic headwinds, i.e., if the macro environment forces the company to retreat to the factory and stop the bleed (labor cuts, wage cuts, etc.), their attention to the difficulties of the downstream deployment pipeline will stall. Attention deficit is the baseline of the modern economy anyway. We may think that asking AI bots to do things for us is messing up our individual cognition (it is), but the larger picture that drives my own investing of time and money is that well-capitalized companies lose attention on downstream risk and lose track of executing on the least-cost approaches to derisking early.

Preventative Medicine Costs Less Than Curative Treatment

Sometimes we cannot avoid spending millions on curing a defect. For that approach to feel justified, the defect needs to be latent, not patent. In other words, the problem must be so remote, so tenuous, that waiting to solve it makes more financial sense than spending in advance to de-risk the probability of its occurrence.

But that is not the math equation being used well or often by the leaders of complex tech and manufacturing industries today. The hyper-local human capital bottleneck is not a latent defect! It is a glaring, flashing, patent reality. When a town council slaps a moratorium on BESS installations because they saw a scary headline about thermal runaway (or when an data center developer gets trapped in a local battle) those are entirely predictable outcomes with serious price tags that merit early spending for early derisking. “Preventative medicine” in this space, looks like funding the gritty, unglamorous work of sitting down with 351 individual fire marshals, funding third-party educational grants for understaffed AHJs, and underwriting the J-curve of human understanding.

Lots of positive vibes in your direction, if BESS dominance is as much of your thing as it is mine. Tell us your BESS stories in the comments.

• A.S.F.

Post-Script: Preventative Medicine is My Thing

[1] My direct experience in all of this where my work made the most impact, was leading the gas utilities through the arduous task of lifting the public messaging up for natural gas development (which is not their job at all, since they distribute gas someone else fracked), in 2011-2015. In my role as Associate Counsel, Energy & Environment (later, Counsel, Regulatory Affairs) at the American Gas Association, I built and ran the Responsible Natural Gas Resource Development Group. I published a newsletter, dug up facts and figures, tracked all the voluntary and mandatory reporting requirements for producers, the improvements we were making from horizontal drilling over vertical drilling, etc. In fact, here is the exact position statement I drafted in my first year of employment at AGA - just days after graduating from law school.

• Real Estate Investment Trusts: they provide the “Powered Land”—actual sites with grid connectivity and physical space for infrastructure like solar, battery storage (BESS), and modular data centers. Companies like Prologis have already secured gigawatts of power capacity across their portfolios and Prologis is specifically discussed below. Prologis, Inc. (PLD) is the world's largest industrial real estate investment trust (REIT).

• Energy Enterprise Resource Planning software: This is the digital brain inside the business model of commercializing powered land. The article discusses Arcadia/ENGIE Impact example, explaining that the ERP software layer provides highly granular telemetry needed to “see” into the grid. It allows operators to programmatically identify distribution-level soft spots and match compute loads to available headroom in real-time, and on a planning horizong, enable REIT-style deals to unlock that headroom for lucrative turnkey load energization or optimization solutions.

Boring Ol’ REITs - A Business Model Ready for the Edge

Edge compute is dominating the squawk circuit right now, and for good reason. Building on our recent piece covering Distributed Data Resources (DDRs)—a term coined by —we are witnessing a massive shift in the capital cycle. The market is moving aggressively from the gigascale, grid-connected projects of 2022–2023 toward a new era of distributed, megascale investments. The idea here, is that smaller, distributed nodes can be bundled and sold to an offtake customer to power computation seamlessly across a decentralized campus. The business model is beautifully pragmatic: move compute infrastructure directly to commercial distribution nodes where grid headroom already exists, and where well-placed power generation solutions are available—either through legacy load-serving utilities or Independent Power Producers (IPPs).

While it all feels so new and snazzy, the business has been shaping for a while, much of spurred by the boring old “REIT” business model. A REIT - or Real Estate Investment Trust - is a vehicle typically focused on acquiring and leasing physical buildings. However, the smart developers realized early on that controlling the real estate footprint means controlling the local distribution grid: between the relationship from the customer meter to the utility substation, and the customer’s load to the load-serving energy sources, there is a full stack of utility-like services waiting to be optimized. This piece focuses on how real estate giants have spent the better half of the decade quietly (and loudly) tooling their massive property portfolios into physical power banks. And, we explore what sorts of synergies having advanced customer portfolios can bring to the space, even where the real estate owners/operators are diversified but the load meters of those entities are under common management by a third party energy ERP firm.

Relatedly, I am seeing that large load developers are fundamentally driven by a “firm power or go home” mentality if they indexed to some version of this thesis somewhere around 2021-2022. My own anecdotal experience confirms this: the loads already scheduled for grid upgrades are largely indifferent to experimental energy setups. Instead, they subscribe tightly to their version of a distributed data center thesis, locking into energy supply agreements and converted interconnection points that benefit from a legacy strategy of securing the real estate and the firm power first. Because established REITs already control these global and local footprints, they are perfectly situated to execute this strategy at scale.

To be clear, the appetite for bespoke, ground-up gigacampuses requiring 2N grid-connected power has not dried up: it is just that the capital available to allocate to new projects of this dimension, is dwindling. So, we are seeing a diversification play from sobered capital providers. They are excited to back projects that already have critical boxes checked: controlled real estate, a customer thesis capable of operating across an aggregation of smaller facilities, and guaranteed power-to-load structures that build on commercial energy service already procured at those locations.

Prologis Case Study: From Landlord to Decenralized Utility

Industrial real estate behemoth Prologis (NYSE: PLD) is executing exactly on this distributed thesis. They have evolved from a traditional development REIT into a global digital infrastructure provider, managing 1.3 billion square feet across 20 countries. In Q1 2026, they formalized a massive operational leap, committing $8 billion to $10 billion in data center investments over the next five years.

This pivot is anchored by what Prologis terms a “5.6 GW power bank.” This represents an aggregated portfolio of utility power capacity attached to their global logistics footprint.

The evolution required core competencies and executive-level FTE strategists who executed on capacities well beyond the traditional REIT model and well before we got excited about edge compute. In 2023, here is what a former Prologis power executive was up to:

1. Overseeing origination, sales, development, engineering, execution, asset management, and operations across the U.S., Canada, Europe (12 countries), Latin America, and Asia (Japan, China, Singapore, India).

2. Growing Prologis’ operating rooftop solar and storage portfolio to hit a clear path for 1 GW.

3. Expanding the energy portfolio, delivering behind-the-meter and front-of-the-meter solar, storage, energy supply contracts, PPAs, vPPAs, and customer meter management solutions.

4. Develop and cement C-suite relationships with electric utilities in 22 U.S. states and 12+ countries, showing up to position Prologis Energy to the top 50 electric utility CEOs at EEI CEO and Board of Directors meetings. (Prologis ambition for distributed digital infrastructure sites is 85% U.S.-heavy today).

5. Partner with real estate teams to enable power access for high-energy-intensity customers, data center interconnections, and onsite/offsite energy solutions.

6. Build, own, operate a front-of-meter energy storage business, including grid-scale battery storage solutions and C&I behind-the-meter offerings across multiple markets. A key component of this is developing a utility meter management program to accelerate the deployment of onsite energy solutions (like rooftop solar and storage) for Prologis customers.

7. Assemble pipeline with several GWs of strategic grid interconnections; this means mapping high-value Prologis real estate directly to utility substations and transmission lines that actually have capacity, essentially turning dormant land banks into highly lucrative, ready-to-deploy power distribution networks across major U.S. and European cities. This is power studies and power flow modeling work that aligns high-value Prologis real estate with energy infrastructure in major cities across the U.S. and Europe.

By leveraging partial or total deregulation in certain markets, companies in this space can diversify how they generate energy, pair their “powered land” with their own power sources, and structurally dictate better economics.

Additional Sections below include:

1. How to Build a Power-First REIT

2. Enterprise Resource Planning is a Grid Utilization Unlock for Distributed Capacity (Of Any Kind, Not Just AI Load)

3. The Shift from Commercial Meter Optimization to Distributed Compute

4. Managing AI Load Volatility at the Edge

Read more

Embodiment Anchors All Feelings, Including Grief

To start, my natural state is one of open resonance; I can step outside, touch grass, and hold onto the purpose of existing, and dying, and being reborn, this way. This capacity for embodied connection to the natural world means I often resonate with a person with whom I can channel a profound, immediate identity-shaping feeling that this person is kin of some kind, from some other time or life.

The Grief of Letting Go of the Delightful because the Time is Not Right

The recurring grief in my story stems from feeling people I have immediate resonance with, engage in retreat. A retreat that usually has absolutely nothing to do with me. That part is ok (that is exercise of autonomy), but the grief is in my action: I have to make a choice to step back and let go, because that retreat means they are not ready, or not resourced, to be with me. Imagine if you stepped on soft clean grass, and suddenly it crumbles to dust under your foot. A feeling of desolation.

You see, people are neither trees nor grass. They don't just exist in their largess with definitive purpose and strength like other parts of nature do. They exist in bodies which feel pain, and have minds that hold far more suffering still, regardless of the existence of bodily pain. And, bodies hold the memory of pain too, carrying it on behalf of the mind. So, it is a profound, recurring sorrow to come upon a kindred soul as I would wild grass or a tree, but stop short of pursuing an embodied bond. It is the grief of letting go of the Delightful because the Time is Not Right.

“Ungrieving”—letting go of the undelightful because Time is Up

I have also learned through choices that I can relieve the opposite kind of grief: the one you get from being stuck in bonds—whether you chose them or not—where your abundance suffers under the weight of someone else's subjective. This is “ungrieving”—it is letting go of the undelightful because Time is Up.

Those of us who grew up with severe insecure attachment trauma understand this and are relieved to get older and wield our own power to cut out insecure attachment. We can better value the secure ones too- because space has been created for those attachments to breathe. Andrew Knapp speaks of the grief of losing connection to his twenty-year-old self. I am cathartically connected to my twenty-year-old self: this line is critical to my own ungrieving. I know where my body holds the pain of my younger life, and so I actively look for ways to ungrieve. This way, I can pay my younger self back and thank her for suffering through it for my sake.

The Most Irrational Human Grief I Carry is Hindsight Grief

Of course, doing this thing—making oneself happier in the present—comes with a different kind of grief: the grief of human idealism. The idea we carry of a utopia in imagined hindsight… this type of grief befuddles our ability to look forward and onward, and enjoy the present. Yes, of course, you may recognize this as post-traumatic recall. But I tend to use words of nature, so I think of it this way: when I stomp on grass, does it wonder the next day, why it had such a bad day yesterday with me stomping on it and fantasize a reconstruction of yesterday’s outcome? No. It does not. It does not have time to wonder. It only has time to try to get up and weather the next stomp. Notice that anything you touch in nature does not hold this type of hindsight grief. It does hold pain, history, the desire for regeneration—but never the fantasy of a different wholly improbable past. Our human minds. Wonderful servants. Terrible masters. Our irrationality is our humanity.

So, these types of grieving are the context for my own thesis: naming your grief has functional utility. It is a blessing to name it early and often, and to empower and humble oneself along the way. In this way, we are all so young and capable of learning.

A.S.F.

Post Script:

Thanks Andrew for sharing your stories about Momo.

One of my pups’ nicknames is “Momo.” He also goes by “Moey,” “Moji,” “Moosie,” “Mussy” “Muzzy” and “Moju.” This is a unique thing bilingual++ family dogs have to deal with: we all babble our favorite “cute words” in multiple linguistic traditions and the pups just gotta figure it out. In this case, it is French, Hindi, English, Punjabi.