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

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.

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.

This article is about Load Wars.

Specifically, it is about ERCOT’s version of “Co-Location” or “Bring Your Own Generation.” ERCOT is calling this a “Withdrawal-Limited Private Use Network” (WLPUN). ERCOT just posted two sets of comments/proposed rule updates in this topic area:

1. Thursday April 30 ERCOT Comments: Updates to existing language for Batch Zero and PCLR (for improvements and in response to market comments)

2. Friday May 1 ERCOT BYOG Comments: Latest comments plus the scope of WLPUNs.

At today’s Batch Study Workshop (the eighth in a series), we ran through the details of the newly filed proposal in a three-hour meeting. ERCOT staff outlined how co-located generation will be treated, noting that consultations with their operations team led to significant modifications over prior informal stakeholder discussions.

According to staff, the most substantial change to the proposal dictates that grid stability—not the total capacity of your on-site generation—will serve as the ultimate cap on the load (effectively meaning the generator is seen as “off” for the planning analysis that caps the load withdrawal limit). That being said, ERCOT is implementing strict “anti-shrinkage” rules for the generation assets tied to these projects to preserve the validity of the interconnection studies - IOW, do not show up with a signed 500 MW generator interconnection agreement (“SGIA”) for the WLPUN configuration if you committed 800 MWs of generation to ERCOT for the studied WLPUN configuration.

To receive credit for the generation portion of the WLPUN, both the load and the generation must meet strict alignment deadlines. On the generation side, this specifically means meeting the requirements to be included in the Steady State Working Group (SSWG) base cases, as laid out in Planning Guide Section 6.9, paragraph 1. There is no netting in studies (generator study progress cannot be used to render a large load “more ready” under load study criteria), but synchronized deadlines for both are necessary.

ERCOT staff also articulated broader design choices to rely on participant behavior to maintain system reliability. A proposed withdrawal limit and correction window for overwithdrawal (QSE receives this instruction for the load) would be established after screening for stability and cascading risks, meaning that any remaining constraints are expected to be limited to thermal and voltage considerations - and thus staff has proposed a rapid response time to an overwithdrawal of no more than one minute.

Stakeholders raised a few concerns:

• ERCOT’s methodology may systematically overstate transmission needs by not crediting on-site generation in planning analyses, even while requiring that generation for operational compliance.

• Another key point of discussion was the level of maturity required for generation resources to qualify under the WLPUN construct—specifically whether a generator must have an active interconnection study underway or whether earlier-stage projects can participate.

• In practice, the proposal could enable a WLPUN project to receive an “allocated load” value that exceeds its withdrawal limit, since the amount of power it can reliably draw from the grid is not gated primarily by the size of its on-site generation. And, if the co-located generation trips or underperforms, the load must quickly reduce to its withdrawal limit, which may be substantially lower. Under the WLPUN construct therefore, “allocated load” should be understood as a conditional, study-based quantity rather than a firm transmission right. The binding constraint for operational and commercial purposes is the withdrawal limit, not the allocated load. This distinction will be central to how projects are structured, financed, and evaluated going forward.

Over the past few weeks, I’ve heard a lot of skeptics in the hyperscale customer service space say that co-location configurations will be an easier engineering solution than PCLR because the loads in co-location configurations could “rely on the generator” to avoid ERCOT having “sovereign control” over the load. I cannot emphasize the degree to which this is a gross mispresentation of how grid connection dynamics work in practice. As the WLPUN proposed rules are clearly demonstrating, dynamic management of a load in a generation-paired scheme still requires mechanical and electrical configuration solutions to ensure the load is available for a “curtailment of last resort,” even if the loads are not directly compliant in ERCOT SCED as they would be in a PCLR registration under five-minute instruction. In fact, the WLPUN scheme proposes that QSEs enforce a load overwithdrawal correction in one minute or less.

Much is left to be worked out as these rules are refined over the next few weeks. Nevertheless, it is impressive to see ERCOT’s commitment to enable a voting-ready package for WLPUN this month at PRS and ROS, two committees that review NPRRs and PGRRs, respectively. Brownie points for those paying attention: these rules are technology and fuel-type agnostic. Any type of generation or batteries, i.e. anything that can be a Resource in ERCOT today, may qualify as the paired generation for a WLPUN.

Last but certainly not least: NOGRR282 is interestingly a reliability standard that is also a potential market-enabling mechanism for the shaping WLPUN world. By demonstrating that the intelligent control systems required for NOGRR282 subsecond response can also seamlessly manage WLPUN generation contingencies, there is some opportunity to move beyond conservative planning assumptions for the load’s withdrawal limits and unlock the value of co-location.

Deep details on today’s clarifications and pros/cons for Luminary’s paid subscribers below.

Read more

• PGRR134 (Nov. 1, 2025)

• Heatmap (Nov. 4, 2025)

• Houston Chronicle (April 8, 2026)

  

  

  Here is the breakdown of Provisional Controllable Load Resources (PCLRs)—the “flexible” heavy hitters of Batch Zero.

The article below explains the meat of the details and information we have unique access to and the best understanding of.

For example, we explain how the formula applied for provisional CLRs actually enables Connect and Manage for AI Loads. The formula basically ensures that the PCLR pays a price that reflects its impact on the grid's local traffic jams. It’s a market-based "tether" that keeps these massive loads from destabilizing local power prices, but, dispatches loads after generators. When loads receive a signal flag to curtail, they are responsible to manage their consumption differential with any private solution - batteries, flex, backup run, prime power switchover, etc. There’s even more to it, and the nuance matters.

Learn more. Subscribe and enjoy.

• A.S.F.

Read more

Speed to Power, Grids, Power Studies, PGRR134, #ENERGYFORAI

Comments are due on the RFI on Nov. 21 2025 via email as noted on the proposal.

Feel free to cite from below: arguments, information, and language your comments.

What Happened This Week in the Stakeholder Process

SPP rule revision request- RR 696, formally titled “Integrate & Operate High Impact Large Loads,” was rejected yesterday by stakeholders at SPP’s MOPC (7/16).

• Averaged Approval: 53.73%

• Percentage of TU's Approving: 38.71%

• Percentage of TO's Approving: 68.75%

A motion was made on the floor to hold a special MOPC workshop with further consideration of RR696 no later than the end of September 2025, which passed with 69.85% average approval. In the words of my friend Jim, who goes to these meetings and spares me the trouble, “the MOPC is signaling to the SPP Board not to make any decisions yet because they are generally supportive but need more time to digest and provide feedback and redlines. Stakeholders were generally opposed to the pace of the proposal, not necessarily the merits. The SPP Board technically has the authority to approve RR696 without stakeholder approval, but more likely than not, the Board will not push this through and may let the stakeholder process extend another month or two.”

Interestingly, and quite obviously, SPP re-stated the obvious at this meeting: there are very few data centers actually routing to SPP states, so missing out on the economic opportunities is not an option. Lanny Nickell’s opener slide at the July 1, 2025 introductory meeting stated that ““We’re at a turning point. This isn’t just about adapting to growth — it’s about leading it.”

The SPP Board could still bring the matter to a vote at its August 4, 2025 Board meeting even with the expressed intent of stakeholders to push things out to September - feedback from any special meetings the MOPS takes between now and August 4, 2025 could influence the materials presented at the Board meeting for consideration.

More Engagement Coming - July 25

Joint Large Load Integration Stakeholder Engagement Forum

LOCATION: Virtual

TIME: July 25, 2025 9:00AM - 1:00PM

LOGIN REQUIRED TO REGISTER: https://spp.org/calendar-list/joint-large-load-integration-stakeholder-engagement-forum-20250725/

PROGNOSIS

RR696 (Integrate & Operate High Impact Large Loads has hope of passage, but stakeholders will be stakeholders! The rule revision set packs every mechanism SPP needs to study and energize hyperscale campuses in one go. Rather than drilling separate trenches for generation and load, it proposes a unified process that truly is pathbreaking in the optionality it provides to investment-ready hyperscalers. It is to be noted that these are all seen by SPP and their TOs as interim measures only, to bridge to SPP’s future Consolidated Planning Process (CPP). What’s THAT? It proposes to fully integrate transmission planning, generator interconnection and long-term transmission expansion into a single framework. Not bad thinking: a proposed, end‑to‑end framework that replaces today’s piecemeal studies by simultaneously planning transmission expansion, generator interconnection, and long‑term system upgrades in one holistic process sounds like the dream. It would merge formerly siloed queues—Integrated Transmission Planning (ITP), Definitive System Impact Studies (DSIS), and interconnection requests—into a single coordinated assessment, ensuring more accurate forecasts, cost‑sharing opportunities, and faster, more efficient project delivery.

What’s in RR696

Bundles studies
A single queue evaluates both the load’s demand and its co‑located generation—eliminating the sequential drag that can add years to interconnection timelines. This, is HILLGA (High Impact Large Load Generation Interconnection Assessment).

Defines three clear “HILLGA” paths

1. Common Bus: Shared delivery point, zero net export, separate meters.

   

2. Local Area: Generation within two adjacent substations, output capped to agreed MW.

   

3. Deliverability Area: Anywhere in the same deliverability footprint, subject to a rapid NRIS study.

Introduces CHILL as a stand‑alone option
Any large load—even without paired generation—can elect curtailable, interruptible service for up to five years, getting energized in months, not years.

Aligns cost causation
Credits on‑site batteries and generators directly against deferred transmission upgrades, rather than socializing every dollar across non‑participants.

Creates a provisional load backstop
The AX Provisional Load Process (pending FERC approval) sits alongside CHILL, giving stakeholders another pathway to interim service while CPP takes shape. The level of optionality here is literally crazy - any developer worth their salt had better be figuring out fastest path to power their campuses effectively immediately!

Why RR 696 Matters — The Stakes for Grid and Growth

As AI data centers scale from experimental labs to hyperscale campuses, their electricity footprints are set to balloon—from a few gigawatts today to potentially 44 percent of U.S. load‑growth by 2028 (?!). This isn’t a niche problem: SPP’s central‑U.S. network sits at a crossroads of affordable generation, robust wholesale markets, and under‑tapped transmission capacity - and a lot of utilities that have discretion to do things utilities in other markets just will not do, or cannot do (like Texas utilities, which generally are actually more constrained than their neighbors). If SPP sits in its status quo and does not modernize its planning playbook, deliberate, sequential studies will continue to push large loads toward more agile regions—undermining SPP’s competitive position and squandering billions in potential economic development. What is interesting is that CHILLS is a very expensive service - hyperscalers who sign up for this are clearly interested in speed at any cost. CHILLS service, unlike convention MWh NITS, will be a Non-Firm, Point-to-Point transmission product billed on a non‑coincident peak (MW) basis, not on energy (MWh) consumed. In practice, CHILLS customers reserve a fixed MW of point‑to‑point capacity each month and pay demand for the highest period of use of the campus irrespective of alignment with the grid peak—and if they’re curtailed, their billed demand drops to the curtailed level.

Granting five years of interruptible service without firm backstops in the CHILLS proposal raises red flags too. Even with mandatory curtailment rights, there’s anxiety that extreme events (heat waves, storms) could see multiple CHILL customers shed simultaneously, straining emergency reserves. Emergency reserves are generation or demand‑side resources that the system operator holds back to cover sudden outages (e.g., a big generator tripping) or unexpected demand spikes. They’re sized so that if a single large unit goes offline (“N‑1” contingency), the grid can immediately call on reserves to keep supply and demand in balance. CHILL customers sell the right to be the first to get cut if the grid runs tight—so in an emergency, the operator ramps them down or disconnects them before firm customers. If only a few CHILL customers exist, that “spill” into their curtailment bucket is plenty to protect the system. But if dozens—or hundreds—of hyperscale loads sign up for CHILL, all of that curtailable capacity could be tapped at once during heat waves, storms, or equipment failures. In effect, the operator exhausts its entire demand‑side cushion by shedding CHILL loads, and still faces a shortfall if generation trips or non‑CHILL demand surges. That leaves the system without its planned emergency margin and risks more drastic measures (firm load shedding or rotating outages).

In short: CHILL creates a ready pool of shedding, but if it’s too big and used up too quickly, the operator loses its backstop for genuine “last‑resort” emergencies.

More updates coming when we have them. Tune back in at the end of month for a stakeholder process post mortem.

A.S.F.