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centers to annually report electricity and water usage data to the PUC; and • Repeal sales tax exemptions and other outdated or unnecessary incentives for data centers; and • Require data centers to reduce impacts on local communities by implementing best practices such as setbacks,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.

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.

At New York and Houston Energy & Climate Weeks, my most productive moments were the five‑minute safe spaces I created in noisy corners. Leaders leaned in to confide: “I’m doing this wrong. I need a moment of clarity. Push me.” CEO‑only dinners and curated peer circles helped too, but the spark missing there is the one this article is about - pushing someone to tell you that you have a first instinct fallacy problem. And in a group of similarly-minded CEOs, it is quite hard to push this onto a colleague when you yourself are in need of a fallacy correction. This is where advisors come in, and this is where I come in.

On the tail end of a whirldwind through energy and climate week events around the country, my work as an advisor and evangelist for energy-tech CEOS has been significant. This article is for CEOs and their teams, and those aspiring to be in those positions. Enjoy, and if I saw you in the past 3 weeks, thank you for stopping by to say hi.

• A.S.F.

I am repeatedly asked - and often quietly so - to help CEOs check their own wrongness. The CEOs who reach out to me, and find me after speaking engagements in noisy melees, are tired of others on their teams, boards, and peer groups simply mirroring and validating. On these occasions, I recite learnings from Adam Grant’s Think Again. The book encapsulates in the first chapters the same energy which CEOs bring with their questions for me: they want to think again, and they want someone to help them correct their first instinct fallacies. My article reviews a few such fallacies and traps that we covered in those conversations.

The Hiring and Delegation Trap

In a recent conversation with a software company executive, I simply stated “you’re not trained to check your own move for wrongness. All day, people mirror your mission back to you and validate it. Almost no one says plainly: think again. So you keep doing it yourself or deputizing the loyal. That feels safe. It’s often the wrong move though, and I need you to step back for yourself and read this section of Adam’s book.”

The words were prompted by a conversation the CEO was having with me about needing a revelatory moment, after weeks of feeling frustrated that their cofounder was neither capable of evangelizing for the company, nor were teammates under the founders capable of taking this task on. We reviewed the delegation trap, and discussed the different traps the CEO had fallen into in lieu of taking the obvious step to hire an evangelist and let go of the idea that the “founding team has to do it all, I have to do it all. The message shouldn’t come from anyone else, it should come from me.”

The chart above reflects a hybrid of Adam’s work in Think Again and my own experience. The latter builds from the learned sufferings of tech companies trying to build energy things - without energy people. Or utilities trying to do distributed energy things, with cost accounting veterans leading the way instead of value-based accounting expertise. Adam names the overall trap: the first‑instinct fallacy. The diagram above explains my perspective on how the fallacy continues to repeat itself through multiple layers of idealogue, as a founder goes from feeling frustrated that someone else on the team doesn’t “have it,” to trying to do it themselves, and avoiding the idea that the path they are on is completely wrong for the outcome they seek.

Various First Instinct Fallacy Traps: Arushi’s Happy Hour Chats

My “happy hour” chats over the past three weeks have pretty much turned into a diagnostic exercise that looks like this - quick hit reports from CEOs on various topics, and diagnosis questions from me which they have taken back with them to their home bases.

CEO’s Personal Involvement is Epic and Too Much
CEO directly handles tasks.

(My Recent Feedback: Why? Has anyone yet told CEO to reroute? Who was the first person telling CEO to reroute and did you reward or reject that gesture? Who else can we find to be that person in your day-to-day? Are there any hiring/delegation traps that need to be removed? See prior section - this one is huge.)

CEO Wonders About Team’s Capabilities
CEO doubts the team’s delivery ability. Does anyone else know this, and why not?

(My Recent Feedback: Board trust factors in here - the governance structure is not there just to criticize the CEO though: the board’s fiduciary duty is to lean in, so compel the board to lean in and partner with the CEO to unlock new capabilities in the team).

CEO Engages in Unrecognized Loyal Deputation
CEO assigns tasks to loyal individuals which is not the same as the right individuals.

(My Recent Feedback: This one is hard. CEOs often have that person, who has so much value in other areas like keeping up executive level morale, one can get confused about value and start giving that person the things they don’t want to do or just are not even good at doing.)

CEO Wonders about Unhired Talent
The work requires skills of people not yet hired but CEO isn’t hearing the call from team managers to hire and now has doubts.

(My Recent Feedback: Boards and advisors to companies directly, both have a role here, but typically team leaders need to lift up this ask and justify it. A CEO is not in the weeds every day, or should not be: so someone needs to surface the hiring ask from the inside. If that clear ask is not coming, perhaps resetting team expectations and directions to create more space for the ask, is the salve. Or perhaps, the CEO has already done something which has managers too risk-averse to suggest that the right talent be brought in).

Internal Candidate Reluctance is Bothering the CEO
Internal candidates are being considered to take on big asks from the CEO, but the CEO has not considered that those individuals would be reluctant and feel like they have to say yes, “or else.”

(My Recent Feedback: That’s a toxic place to be: for the employee. It is one thing to know that an employee has room to grow and contribute at higher levels of success and participation in the company. It is another though, to create tension around that person’s path to success and retention by simply not asking what that person envisions the path to be. I’ve told every CEO I’ve met the same thing of recent: have your top performers self-evaluate regularly and keep it short and simple, trying to gauge their vision for themselves so you don’t slot them in the wrong growth trajectory and wind up losing them altogether to a competitor or supplier.)

Support Networks for CEOs: Break Fallacies about Competing Interests between Work and Non-Work

Home and family are examples of “not work” which mean different things to different people. To me, it has meant different things in every decade of my professional career - twenties, thirties, and now forties. On the other hand, I did some life-changing things quite early compared to peers early enough to have stronger perspective on its value - birthing children, buying and selling a house, switching from one high-profile job to the next, all before I was thirty.

Every once in a while, I tell people who ask about my energy levels and where they come from, that “I was born very very old, aged, with memories that seem to come out of a lifetime that is not my current one. I am as tired by this cumulative experience of my own just as much as I am energized by the chance to enable yours.”

If there is one thing us tired old souls cannot stand, it is poor information that causes suffering. Advising thus comes with an instinct to catch someone who is falling and help them stand up. In CEO advising world, this is what it pretty much looks like:

If you give a company the energy you’d give a real baby, what energy is left for the actual family or your actual needs - the ones you’ve buried along with the best version of the ideas you have to grow your company? How about energy for all those organizational leadership moments involving serving funders and overseers?

Founders in particular love the “baby” metaphor, but the corporate entity is not a child and labor/capital are not heartbeats. There is indeed a nascent creature—an idea in conscious experience—that needs to mature under supervision: sometimes this is what CEOs are really talking about. It is my role to make sure they can distinguish the two - one version of this narrative is about nurturing a vision and experience with TLC, and another is about spending hours “at work” instead of “not at work”, which is just disastrous all around.

I think about this issue in terms of the fallacy of how CEOs can use all of their care particles. CEOs risk pouring every care particle into one accelerating engine—their hours for the company—and then go home with nothing left. If the CEO does not defend a reserve of care particles by adopting a more sober take than “that company is my baby,” their ability to socialize, emote, and connect erodes. They show up worse off the next day, and that is worse for the company which they think is their baby.

As an empath, and as a parent who had children young before CEO‑type pressures hit, this perspective is often my most valuable contribution: the advice is that one cannot elimiate the human-ness of human-to-human relationships and expect to get away with it forever. It matters that every day you show up after doing things and spending time in human-to-human engagement which shows you your best self: engagement that energizes you for running a corporate machine.

I sometimes articulate the mismatches by creating an allocation metaphor for the person I am speaking with. I say, “the job is to mature your company with TLC without extractive behaviors which drain you or drain your teams. It is about efficiently moving all of your care particles to where they are needed, and having “not work” things which energize you and restore your particle count.”

A lesson I learn myself best by explaining it to others: block time that reliably restores your ability to socialize, emote, and connect. If you show up drained, the company you think you are protecting gets the worst version of you. The people you live with, and your community, get the worst version of you too. What version of you is left for you to enjoy, if this happens?

In an interesting bit of newer experience, some CEOs I have met are a lot like me. Deep, intensive hobbies (mine is classical dance) mirror our deep intensity in our professions.

Others are not like me, and have more simple “non work” desires which create physiological openings and psychological wellness. In both instances, I am happy when I find that this recognition is strong in CEO conversations. And in others, I advise on how to break the fallacy which pushes them to exhaustion from which there is no return.

The fallacy to break is that either one of these approaches (serious hobbies or light but frequent non-work activity) is “too much” for a competent leader to handle outside their “work life.” To the contrary, the push we give ourselves cognitively to leave thinking about work so we can think about the “non-work” is the same type of cognitive push which is essential to discipline how we allocate time among tasks at work. The mind has to exercise competence in sorting: without this competence, the mind is exactly what you think it is - a wonderful servant, and a terrible master.

We can all do with this next and last tip: block non‑work as infrastructure, not as indulgence. Protect sleep, movement, art, prayer, family—whatever reliably refills your care‑particle ledger.

Then measure yourself by the quality of decisions you make, and ensure people know their boundaries around you and that your boundaries have an intentionality to them which is more than: “I am a busy person and I do not have time for you.”

Of recent I have found that letting go of the need to do it all myself, has helped me move entire teams I work with into the same mindset of co-created success. I am so surprised sometimes, to see how much others will do when the space is created for doing. This particular strategy is an art form for me, since my usual is to fill space very quickly. For others- CEOs who need to overcome a natural tendency to over-delegate, the opposite instinct is needed.

In both cases, however, having “non-work” decisions to make, which force themselves up against the decisions you must make on the job, is like working muscles. The more you work them, the better you get at making the lift and walking around with a feeling of self-created safety as you accomplish increasingly difficult tasks.

Praise Successful Leaders

American companies rise when leaders feel special and meaningfully supported—not in a self‑aggrandizing way, but with a purpose‑built commitment which lets them metabolize life around the business. This is the best face of capitalism in America.

I am not talking about dopamine hits driving their every waking moment. Rather, our CEOs need those hits in a more sustained, accessible ways. The bucket CEOs dump their energy into is oversized and often underfilled. Filling it is a many‑to‑one job for the benefit of many, intermediated by one leader.

Sometimes when a CEO asks me whether they are doing well and I say they are, I am hit with the feeling of energetic absence in the space where many other people should have already said the same thing to that person.

Break the fallacy that CEOs don’t need praise. They need accurate, timely, specific recognition which ties effort to effect and signals to “do more of this.” Praise is not pampering; praise is calibration. It tells a nervous system it can keep going without burning through every care particle.

It has been my pleasure to engage in work that energizes me this month - helping people at all stages of growing their companies to identify these fallacies and move themselves along the path to breaking them.

Reference: Adam Grant, Think Again: The Power of Knowing What You Don’t Know (Viking, 2021).

— A.S.F.

Investing now in a smarter, more flexible distribution grid is not a "cost shift"—it is a necessary correction for the historical cost shift utilities have long imposed: inefficient, ballooning capital expenditures that have failed to deliver what ratepayers actually want—fewer outage minutes, faster restoration periods, cleaner energy, and affordable electricity bills.

What is the DERP Proposal?

See: New Orleans City Council Docket UD-24-02

• A comprehensive program proposed by Together New Orleans (TNO) and the Alliance for Affordable Energy (AAE).

• Aims to expand distributed energy resources (DERs) in New Orleans by supporting solar-plus-battery installations.

• Designed to create a citywide Virtual Power Plant (VPP) by linking hundreds of customer-sited battery systems.

• Leverages settlement funds (not new ratepayer charges) for upfront battery incentives.

• Requires participants to enroll in demand response programs, ensuring active grid support.

Key Features of the Proposal

Program Timeline and Structure:

• Initial 3-Year Period (Phase 1):

  • Targeted Enrollments:

    • 1,500 residential customers

    • 500 commercial/institutional customers

  • Annual Enrollment Goals:

    • Roughly 500 residential and 150-170 commercial sites per year.

  • Transition to Tariff: After initial period, the program would evolve into a permanent "pay-for-performance" demand response tariff.

Eligible Customers:

• Residential homeowners with rooftop solar or planning to install.

• Small commercial businesses.

• Critical community facilities (e.g., schools, health centers, shelters).

Incentives and Funding:

• Upfront incentives for battery purchase and installation.

• Funded through existing settlement funds (e.g., SERI credits).

• Supplemental incentives linked to performance in demand response events.

Grid Benefits:

• Supports distribution feeder reliability.

• Provides dispatchable energy during peak demand or grid emergencies.

• Reduces outage minutes and speeds restoration.

• Offsets need for expensive centralized generation and transmission upgrades.

Implementation Details:

• Participants must:

  • Agree to DERMS (Distributed Energy Resource Management System) enrollment.

  • Allow dispatch of their batteries up to a set number of times per year.

  • Meet equipment standards (e.g., smart inverters, performance certifications).

    

Long-Term Vision:

• Transition from reliance on centralized assets to a decentralized, resilient, customer-participating grid.

• Create permanent market structures for distributed batteries to provide capacity, ancillary services, and grid support.

Pictured Above: Excerpt from Filing of Together New Orleans & Alliance for Affordable Energy - December 2024 in response to Resolution and Order R-24-624 (Docket No. UD-24-02)

Breaking Down Entergy New Orleans’ Position (Cost Shifting)

“The DERP Proposal seeks to expand the number of participants in ENO’s current residential BESS program by incentivizing up to 1,500 residential and 500 commercial/institutional sites over a three-year period. However, the DERP Proposal would increase the size of ENO’s behind-the-meter (BTM) battery fleet at significant cost to ENO’s customers and without sufficient demonstration that these expenditures would be offset by corresponding benefits. ENO has previously submitted analysis to the Council estimating a nominal $457.6 million cost shift to non-participating customers from existing NEM and community solar programs over the period 2025–2044. The Company is concerned that expanding DER participation through the DERP as proposed would exacerbate these cost shifts if not carefully structured and implemented.” — Entergy New Orleans, Docket No. UD-24-02​

In this filing, Entergy New Orleans warns that expanding access to rooftop solar and batteries under the AAE/TNO Distributed Energy Resource Program (DERP) could worsen a projected $457 million "cost shift"—one they estimate across the next twenty years. Yet their filing conveniently ignores that the DERP – adding batteries to existing solar systems and new solar-battery systems – is specifically designed to eliminate exactly these concerns by coupling rooftop solar with battery storage, demand response obligations, and virtual power plant (VPP) enrollment—transforming passive solar customers into active, grid-supporting assets.

Entergy New Orleans’ cost shift claim is not just exaggerated — it is prospective. The $457.6 million figure they cite covers a speculative 20-year period stretching to 2044​. It assumes a static policy environment where nothing is done to correct the supposed “shift”—an environment where solar adoption continues to grow but no batteries are deployed alongside it, no demand response strategies are implemented, and no grid modernization occurs. It also completely ignores the critical fact that if batteries were paired with most or all Net Energy Metering (NEM) systems—as proposed by the DERP—there would be no cost shift to speak of.

The "cost shift" narrative is not only half-baked — it redirects attention away from the systemic root problems we need to crush around the country as we hear talk of rising electric bills and know that downward pressure on utility cost recovery will come from somewhere: systemic utility inefficiencies are a cost shift onto the very customers who pay for every decision that has led to rising distribution and transmission costs nationwide while wholesale power prices themselves have remained relatively stable. In a proposal like the DERP filed by AAE and TNO, where customers are putting private market dollars on the table - it is unseemly and illogical for a utility operator and its regulator not to take the deal. Market-supported, battery-enabled VPP programs eliminate the solar cost shift specter for concerned utility operators and arrest the systemic cost shifts that have led to rising electricity bills.

Batteries turn uncontrolled rooftop exports into dispatchable grid assets. They absorb surplus solar energy during low-demand periods and discharge when the grid needs it most. They flatten feeder loads, help maintain voltage, and deliver fast frequency response. With batteries participating in a citywide virtual power plant (VPP), NEM customers shift from being seen as “avoiding” costs to actively offsetting system costs. The very problem Entergy projects over the next two decades could be solved now—at a fraction of the cost—by implementing the DERP, not by resisting it.

Let’s learn a bit about this issue.

Entergy New Orleans' March 2025 filing in Docket UD-24-02 opposes the AAE/TNO Distributed Energy Resources Proposal (DERP), raising the familiar argument that rooftop solar and batteries could cause a "cost shift" to non-participating ratepayers. Ironically, while warning of theoretical future cost shifts, the utility simultaneously acknowledges that the DERP would support up to 1,500 residential customers, and up to 500 institutional or commercial customers, installing batteries over the next three years. Entergy’s own Demand Response (DR) Battery Energy Storage System (BESS) pilot, operated under the Energy Smart program and funded by all ratepayers, currently enrolls just 94 residential customers and two commercial sites—an enrollment rate so low that it cannot meaningfully provide grid services, offset generation costs, or improve resilience at the community or feeder level.

When we think about the classic “cost shift” argument against rooftop solar—a favorite of regulated utilities including Entergy New Orleans in their March 2025 filing opposing rapid expansion of the EnergySmart-derived DR BESS pilot program—the argument collapses under even basic mathematical scrutiny. A regulator in a grid area like New Orleans should be far more concerned with the utility’s own cost shifts.

For starters, the utility funds the DR BESS pilot from all ratepayers today, but only 94 homes and 2 commercial sites are enrolled (Entergy New Orleans, LLC, Comments of Entergy New Orleans, LLC, Docket No. UD-24-02, at 2 (Mar. 14, 2025). The program is so small, it cannot possibly hit any of the value streams we associate with shared ratepayer benefits: community-wide resilience access or the value of residential concentrations that can strengthen distribution grid resilience at a feeder level. And certainly at this size, the utility cannot manifest a dispatchable asset of any size to offset more expensive capacity in its generation/PPA stack, nor can it rely on the concentration of distributed devices to help manage outage risk conditions on its system or support its restoration efforts by helping it prioritize scarce resources to neighborhoods and feeders that do not have backed up homes.

The conventional (pre-DER) utility model channels all ratepayer dollars into a one-way, utility-owned grid—locking ratepayers into centralized infrastructure investments that create single points of failure. This, too, is a cost shift: one already happening. Every downed transformer on a single feeder is paid for not just by customers on that feeder, but by the entire rate base. Every new pole, wire, substation upgrade, or centralized plant—whether or not it benefits an individual customer—is paid for collectively.

The "cost shift" narrative against solar is a red herring in this proceeding - and arguably, always, in cost-plus utility regulation models. All poles-and-wires investments are socialized. All utility program funds are collected from ratepayers and spent across the service territory - find me a record of which pole and wire truck roll benefited which exact meter?! For those utilities that own generation or PPA risk, all power plants backing load-serving obligations, and fees to carry that power are financed with ratepayer-backed capital, even when they fail, underperform, or serve only a privileged fraction of customers - the ones who may benefit from upgraded feeder-level infrastructure (reinforced areas of the system, three-phase transformers), better vegetation management, better construction, or sheer luck in a storm.

We are entering a period, thankfully, where battery energy storage systems (BESS) are giving distributed rooftop solar new value as an active grid asset. Smart investment strategies—combining installer incentives, federal support, and targeted ratepayer funding—can transform solar from a perceived "burden" into an integral part of virtual power plants that deliver measurable system benefits. Enabling dispatchable two-way power flows motivates smarter investment in maintaining and modernizing the distribution grid, and actually increases participation across the rate base in sharing the costs of keeping the system reliable—not exempting distributed energy participants from grid policies or cost responsibility. Batteries enrolled in virtual power plants are not only available during emergencies; they also provide grid services on ordinary "blue sky" days, earning payments for capacity, load shifting, and ancillary services that reduce system costs for everyone. Far from abandoning the grid, distributed solar and battery owners strengthen it, becoming active contributors to grid stability, reliability, and affordability. In doing so, they help reverse the very cost shift utilities claim to fear, by turning passive meters into revenue-generating, grid-supporting assets. Doing so with market-based support as proposed in the AAE/TNO DERP – a combination of installer incentives (energy service partner contracts, third party agreements), federal or state program dollars, and ratepayer monies smartly allocated to up-front and performance incentives in a VPP model – immediately catapults the value of every ratepayer dollar spent, and monetizes rooftop solar and becomes the fix for all of the legacy and current complaints utilities have voiced.

The conventional “solar shifts costs” argument is on its death knell with the obvious evolution of net energy metering programs into battery programs. Adding batteries to solar rooftops immediately turns what some may consider a stranded asset to the utility grid, into an active asset.

A Note on Cost-Shifts and California

Discussion Note: Recent happenings in California are challenging the solar-only cost shift argument: scholars who have examined the real reasons for rising electricity prices in places like California have asserted that rooftop solar is not the culprit. As Ahmad Faruqui, a nationally recognized economist and grid expert, points out, California’s residential rates have been substantially higher than the U.S. average since 1979, long before rooftop solar adoption​. The true drivers noted in California are inflated utility overhead, managerial inefficiencies, excessive executive compensation, and bloated transmission costs — not the modest growth of customer-sited generation​. Along with eleven other experts including a former FERC Chairman and the former Vice President of the regulated utilities’ research organization EPRI, he filed a letter with Governor Newsom explaining as much in December 2024. The experts on that letter:

· Ahmad Faruqui, Economist-at-Large, former Principal, The Brattle Group

· Clark Gellings, former Vice President, Electric Power Research Institute

· Mark Z Jacobson, Professor, Civil & Environmental Engineering, Stanford University

· Daniel M Kammen, Professor, University of California, Berkeley and Coordinating Lead Author, Intergovernmental Panel on Climate Change

· Jim Lazar, Author, Electricity Regulation in the US: A Guide and formerly Senior Advisor, Regulatory Assistance Project

· Ronnie Lipschutz, President, Sustainable Systems Research Foundation and Emeritus Professor of Politics, University of California, Santa Cruz

· Bruce Mountain, Professor and Director of Victoria Energy Policy Centre at Victoria University, Australia

· Dustin Mulvaney, Professor, Environmental studies, San Jose State University

· Karl Rabago, Rabago Energy, LLC and former Commissioner, Public Utility Commission of Texas

· Karl Stahlkopf, CEO and Partner at SPS Energy & Finance, and former Senior Vice President, Hawaiian Electric and President, EPRI Solutions and Vice President, Electric Power Research Institute

· Jon Wellinghoff, CEO, Grid Policy, Inc. and former Chairman of the Federal Energy Regulatory Commission

· Greg Wikler, Clean Energy Professional and former Executive Director for the California Efficiency and Demand Management Council

When Solar Becomes a Problem - And Why We are Eons Ahead of that Problem with Battery Deployments

Perhaps it is time for the New Orleans regulator to ask for similar information. Blaming solar customers for rate increases is a self-serving distraction from the structural inefficiencies embedded in the utility model. Worse, it delays and undermines the very distributed energy solutions—including solar-plus-storage, home electrification, and grid-edge flexibility—that are critical for building an affordable, resilient, and decarbonized energy future.

For those familiar with utility narratives in other states and countries, the importance of recognizing feeder-level penetration rates and the operational changes required for a solar-heavy grid cannot be overstated. Australia, for example, sources over 30% of its residential electricity from rooftop solar, while rooftop solar provides over 11% of total electricity supply nationally, far surpassing the penetration seen in the United States. In leading U.S. states, rooftop solar adoption is rising but remains modest: California tops the list with about 10% of households having installed rooftop solar, followed by Nevada (approximately 7%), Arizona (approximately 6%), and Hawaii (approximately 5%). Nationally, only about 5% of single-unit U.S. homes had rooftop solar installed as of 2023.

Australia’s experience shows that as solar adoption increases to these dramatic levels, utilities must then fundamentally change how they operate distribution networks. Integrated Distribution System Planning (IDSP)—as outlined by Australian utilities in a 2024 study—demonstrates that intelligently managed low-voltage grids can save billions in system costs while enabling high levels of distributed energy resource (DER) integration. Key strategies include motivating battery adoption to mitigate midday "duck curve" effects and manage low-load days with high solar exports, deploying or enforcing smart inverter standards for voltage and reactive power control (Volt/VAR optimization), and designing dynamic curtailment protocols where necessary.

Critically, Australia's utilities experience highlights that failing to coordinate DERs forces a future in which the country could spend billions on network upgrades, whereas strategic investment now in system monitoring, DERMs, and batteries, converts the potential liability into an incontrovertible asset.

New Orleans has a rare opportunity to get ahead of these challenges – years before U.S. grids could experience anything like Australia’s rooftop experience. By motivating battery adoption alongside rooftop solar today, the city can proactively address future grid management needs before penetration levels portend - in the opinion of the utility or the regulator - to become disruptive. Deploying batteries now ensures that rooftop solar systems are not just exporting uncontrolled power, but are dynamically supporting grid reliability, providing dispatchable capacity, and flattening load curves. Building a smarter, more flexible grid through distributed energy and storage is not a cost shift—it is the intelligent modernization of the system that will save money, improve resilience, and deliver the clean, reliable electricity future that New Orleanians deserve.

Some Light Reading:

1. Ahmad Faruqui, Are California’s electricity prices rising because customers are installing solar panels?, pv magazine USA (Nov. 8, 2024).

2. Luminary Strategies, New Study from Australian Utilities Explains How to Save Consumers Billions via Integrated Distribution System Planning with DERs, LinkedIn (Aug. 8, 2024).

3. U.S. Department of Energy, Solar Futures Study (2021).

4. Lawrence Berkeley National Laboratory, Tracking the Sun Report (2023).

5. Australian Energy Networks Association, The Time is Now: Getting Smarter with the Grid (2024).

Last week, the ERCOT Technical Advisory committee approved the updated Governing Document for the ADER program, v3.3. Find the materials here.

In October, visit Austin. You’ll find me on a Latitude Media stage, discussing this origin story, and ERCOT, discussing the state of play today. It’s been capacity growth from household batteries, multiple providers, which has driven this program forward.

“ADERs” providing real-time grid services however, represent a fraction of the demand management capacity available in Texas. There is so much more.

ADER is private capacity management and grid control and visibility to real-time behavior from aggregations. Provisional Controllable Large Loads is privatized delivery risk management and grid visibility and control of real-time behavior from distributed large loads.

What happens when you put those two together?

For anyone wondering, wonder less. The entirety of my work running as a venture studio is to enable founders to help me achieve the next scale: bigger and better power and transmission risk markets, mesh networks integrations for private capacity management, the most astounding virtual PPA structures, give the grid operators tools to do the job, and ensure people have power. If your venture is building software to figure this out, if you’ve drafted Flex SLAs and Flex PPAs, send us a note, email us your deck.

Original Article:

“While processes for demand-side participation have been longstanding in the ERCOT region, aggregated participation from distributed devices has never included a population of devices that, on an individual basis, can be net-injectors of electricity in times of scarcity or grid need, with committed performance equivalent to that expected of traditional generation resources dispatched by ERCOT. This is the distinction between current demand response and price response programs administered in the ERCOT region and the new market participation mechanisms being piloted in the ERCOT ADER Pilot Project. More simply, the ADER pilot pioneers in the ERCOT region the ability for controllable DERs at an aggregated location to participate in 5-minute dispatch.”

- Comments of Tesla, Inc., filed by Arushi Sharma Frank, former Tesla US Energy Markets Policy Lead & Senior Counsel, Texas PUC ADER Task Force Vice Chair, July 18, 2023

There are just a few topics in the universe of energy nerdism where I find myself uniquely situated to provide a true and complete anthology of events, some foreseeable and others not so much. Written for sharing with a lay audience, students, and energy policy professionals in state energy offices, advocacy organizations and government.

VPP Phase I: Winter Storm Uri, a new ERCOT CEO, and Competitive Spirit.

Some time in early May 2021, just a few months after Winter Storm Uri showed us how badly we needed to bring dispatchable megawatts to the Texas grid, I had a conversation with a good friend, who also happened to be the incoming CEO of ERCOT - Brad Jones. It was his first week on the job, and he absolutely made time for this conversation. Notable from our chat, even though the focal point of the conversation was how similar Texas is to Australia, (where Tesla’s gigantic and successful Powerwall VPP continued to grow), was his statement “I don’t like hearing that ISO-NE has done ANYTHING before us!”

That was Brad, reacting to my pointing out that the New England grid operator had already achieved a grid-integrated Virtual Power Plant aggregation with Green Mountain Power (GMP). GMP was utilizing Tesla Powerwall to participate in load frequency control services, or Regulation Service. This is a grid service that brought fine-tuned grid control from residential batteries to the constrained New England grid. The aggregation also participated in the New England capacity market, promising reliable, dispatchable megawatts at the same performance standard as power plants. And, the utility had founded this program years ago. Texas could have already had it too.

The competitive spirit certainly drives ERCOT - it’s the most competitive market in the country. And it drove this particular company I worked at. And it absolutely drove me. I did not need to hear more. It was off to the races: a timeline we should replicate everywhere - before a massive weather crisis invokes momentum for change.

ADER Phase II Preamble: California Wildfires Lead to Rapid Export Compensation for Battery VPP

In California within that year (2021), the state’s public utility commission had started changes to the Emergency Load Reduction Program that would for the first time, allow net injection from individual batteries in an aggregation to export power in concert and be paid for that export under the same terms as load reduction. [See, e.g., ELRP Landing Page, “Customers with distributed energy resources that can generate energy (e.g., behind-the-meter solar plus storage, electric vehicles, cogeneration, etc.) that have permission to export.”]. Note: Program has evolved further since, ELRP is replaced by DSGS. The life-altering wildfires of recent California summers - and now, in the dead of winter months - were part of the impetus to loosen up the program and get capacity on the grid to help the utilities’ distribution systems with these sorts of day-ahead conditions:

• After RUC results reviewed: RUC is infeasible for one or more hours compared to the published Day-Ahead forecast. (Per the “RUC under-supply” column in the Day-Ahead System Summary report).

• EEA Watch is being declared

• Gas curtailments that reduce capacity awarded by the DAM

• Ongoing grid issue (Fire, Natural Disaster) o Resource constraints/restrictions not known ahead of the DAM

Customers got officially compensated in summer peak season 2022, but they actually got unofficially compensated before that too in Summer 2021. Governor Newsom issued a July 30, 2021 emergency summer supply directive, which allowed for the first time net injection, or exports, from residential batteries to be paid to support the grid under the load curtailment program (ELRP). “That is generally not true of California policy frameworks that govern VPPs, including for resource adequacy need…This is one thing about ELRP that is a step in the right direction,” stated Kate Unger, a California trade association rep to Utility Dive on the matter.

The formal program for 2022 onwards thus came out of a state weather emergency which forced the state government to rethink its position on grid exports from residential batteries and act quickly.

VPP Phase II: Replicate Emergency Needs in Texas for Rapid DER Advancement

Tesla identified the equivalent of an “ELRP” model in Texas - the Aggregated Load Resource Framework (ALR). After asking customers to volunteer their systems’ capacity for some amazing VPP testing, Tesla announced the results of that testing at a public ERCOT workshop with several companies in attendance, who all put forward a solid case to quickly modify the ALR Framework to effectuate the same outcome to compensate grid injection. This was the first public gathering where Tesla announced its advocacy proposals, along with allies at other VPP and retail energy providers, in Texas. Its conception, delivery, and what happened next, is a months-long endeavor I embarked on after Storm Uri with the support of Brad Jones. It precedes the constitution of the ADER task force by several months:

Importantly, California ELRP was distinguished from the ERCOT’s ALR Framework in one important way: ELRP had already been an active program for small residential loads to aggregate and get paid for load reduction behind the meter. ERCOT’s framework for the same - small <1 MW loads, had never been utilized but was also more sophisticated in its entry requirements - being tied to telemetry requirements to participate in non-spinning reserves so that ERCOT could pay for the capacity day-ahead and deploy load reduction in the 5-minute market for events lasting up to four hours. The ALR Framework had consequently been on a shelf for nine years, years in which small batteries did not exist in any number to make a case for ALR qualification. So, through a product of various circumstances, Tesla was the first entity in nearly a decade to attempt to bring it to life. And it was of course nonsensical in the aftermath of Uri, to suggest that batteries only be paid for half of their value (load reduction at a premise) and not the other half (dispatchable exports while home needs are served).

The entirety of the test demo and subsequent ERCOT VPP workshop, hosted by Tesla, was handily covered in several trade press and blog articles:

What’s Up Tesla - June 2022

Thereafter, Tesla filed a request with ERCOT to update the ALR Framework - citing the need for urgent consideration of the fact that Powerwall alone in the state could help the grid if customers were motivated to share their energy in a VPP program.

Here’s where it got tricky. Utilities and ERCOT both reacted strongly to the idea that residential exports could get compensated in a load reduction framework. Well, there were not any wildfires chomping down wealthy homes in Texas, when I filed the OBDRR. Instead, the market was in a reactionary shock period: why and how were so many Powerwall available to sell power, how come no one else was pushing this, why is Tesla ignoring the utilities?

That’s where this gets even more fun. If you want a sense of how fun, you can read Russell Gold’s article in the Texas Monthly - rather ironically titled given current tidings, it is the only major press piece in which I am mentioned directly along with my former boss, Mr. Elon Musk. Elon Musk Came to Texas to End the Oil Age - Texas Monthly

The thing is, in Texas, distribution utilities manage the distributed grid. The high-voltage grid sends and delivers its power through the auspices of ERCOT, the centralized grid operator for the market which then delivers to utility-owned and operated distribution networks. Unlike, say, in Australia, or, say, Florida Power and Light, different entities in ERCOT own different parts of the physical infrastructure of the grid, and know different things about various parts of the grid (and no one knows perfectly about all of it). That is what the challenge came down to, and why our proposal to replicate ELRP principles in Texas was challenged. In California, the large load-serving entities are the same entity as the poles and wires utilities, and the same entities that largely procure and own/operate generation, or contract for it. They also are integrated as Load-Serving entities with the California Grid Operator - the CAISO. That’s not true in Texas. Visibility and accountability are split. [Learn about that in one of my earliest market design teaching posts on Energy Central]. In Texas, unless you are in a municipally or cooperative vertically regulated entity, or you live in El Paso Electric’s or Entergy’s service area, your grid providers are manifold. ERCOT and the load-serving entities, i.e., the competitive retail energy providers, talk to each other about real-time energy dispatch through a network of shared systems. ERCOT and the poles-and-wires utilities - which neither serve commodity load/schedule it, nor do they own and operate generation - don’t talk to one another the same way. The market, as a result of the close-to-perfect competition in deregulation we have in Texas, is also multiple layers of complexity in relationships between who governs and manages physical infrastructure, and who governs and manages the flow of power across the high voltage and low voltage systems.

So, the OBDRR proposal did not work. The primary reasoning for this, was the fractured nature of the utility-ERCOT-load serving relationship, and it is well described in the utilities’ joint filing opposing the OBDRR:

Oncor, AEP, CNP, TNMP and STEC (“Joint Transmission and/or Distribution Service Providers (TDSPs)”) submit these comments to express concerns with Tesla’s proposal for establishing an Aggregate Load Resource (ALR) in the ERCOT market. The Other Binding Document (OBD) entitled “Requirements for Aggregate Load Resource Participation in the ERCOT Markets” initially developed nearly ten years ago does not appropriately address the operating characteristics of the ALR proposed by Tesla. As initially conceived, the OBD addressed ALR participation as Demand response, whereas Tesla’s proposed ALR would actually inject energy into the electric Distribution System, potentially presenting system management issues for Distribution System operators. This energy injection behavior poses several concerns:

· Distribution Service Providers (DSPs) review and certify Customer-owned Distributed Generation (DG) interconnections to the Distribution System. To the extent that battery systems included in the proposed ALR were not studied nor certified by the interconnecting DSP to operate in the manner being proposed, Customers would need to notify the DSP of any changes in operations pursuant to applicable Interconnection Agreements. Coordination with the interconnecting DSP(s) is a necessary step in the creation of ALRs to ensure compliance with Interconnection Agreement provisions, or modification of such provisions if necessary.

· DSPs have not evaluated the impacts of residential battery systems simultaneously injecting into the Distribution System during an Ancillary Service deployment. Customer location matters greatly, and the injection behavior could impact power quality for other Customers served by the same or proximate distribution facilities. The interconnecting DSPs must be afforded the opportunity to evaluate impacts of the ALR behavior to their Distribution System facilities and other Customers the DSP serves. This should occur through an interconnection process similar to other Resources, beginning with an initial application, a technical study to evaluate system impacts and potential facility upgrades, commissioning and testing with the interconnecting DSP and ERCOT, tracking and modeling, and a contractual agreement approving the operation and requiring a notification of any operational changes.

· Several market rules have recently been established for distribution-connected Ancillary Service providers, specifically Distribution Generation Resources (DGRs) and Distribution Energy Storage Resources (DESRs). A review process for these Resource types led to several Protocol, Operating Guide, and Planning Guide revisions. Any new Ancillary Services providers, such as the ALRs being proposed in Other Binding Document Revision Request (OBDRR) 041, need to be evaluated in similar fashion to identify operational, planning and market impacts prior to developing new market rules. Such impacts may include, but not be limited to, the implications of ALR Customers connected to the distribution system via feeders included in a DSP’s Manual Load Shed or Under-Frequency Load Shed programs.

· Since Real-Time system conditions often differ from planning studies, the DSPs will also need the ability to preempt any ALR wholesale market deployment instruction in the event the injection to the grid, either alone or in combination with others, creates a reliability issue on the Distribution System.

· Finally, since these ALRs will be injecting power into the grid and then subsequently into the transmission system, it is appropriate to limit aggregations to an individual transmission Point of Interconnection (POI). Constraints can happen within the large areas of the grid defined by Load Zones and, therefore, it is critical that ERCOT takes the differing impacts of these resources into account in their clearing and deployments. It is the Joint TDSPs’ understanding that this nodal treatment of such resources parallels the treatment provided by many of the RTO’s compliance plans with FERC Order 2222.

Comments of Oncor Electric Delivery Company LLC; American Electric Power Service Corporation (AEP), CenterPoint Energy Houston Electric, LLC (CNP); Texas-New Mexico Power Company; South Texas Electric Coop., Inc. (STEC) (“Joint Transmission and/or Distribution Service Providers (TDSPs)”).

Web Link to all OBDRR Comments: https://www.ercot.com/mktrules/issues/OBDRR041#keydocs

So, that’s how I found myself making a middle-of-the-day filing from a hotel room in Austin, advising the PUC after a spur-of-the-moment chat earlier that day, drafting inter-hour comments to support a sensible pilot administered by the PUC instead of a change to the ALR framework. My goal was to ensure we protected the mission, and made sure that everyone in the utility stakeholder community felt more secure about studying the impacts of VPP exports on their mini-grids, and on the ERCOT -managed central grid. No one at the Commission had told me what would happen at this open meeting where the Commissioners pushed me on the need for a solution. Rather, in real-time at that open meeting, I heard the details from the dais-led discussion, of proposals that various other parties (utilities in particular) had put forward. But, I work fast, think fast, and care too much about the outcome to let that bother me. So with the surprises digested, in my hotel room, right after the meeting, this is what I wrote and immediately filed- and yes, I was still wearing my LFDECARB shirt from that morning:

Supplemental Comments of Tesla, Inc. response to PUC Texas Open Meeting discussions on June 16, 2022. [Search PUC Texas Project 51603 for more - this is where all the work happened before the ADER Task Force was constituted].

One important win that I can vouch for, which no one else will ever talk about, is that at that open meeting, there was a push suggested in the discussion (I don’t know who it came from) to make the pilot limited to NOIEs - as if, excluding the entire retail competitive market from being able to deliver VPP services to millions of Texans was a good idea. It was not, and I said so. Loudly, and clearly. And I won. The ADER pilot was scoped for the entire competitive market, and the NOIEs. And today, both are participating. Here’s the excerpt of an argument written from the JW Marriott:

Excerpt from Tesla Policy Lead Filing, June 16, 2022 - Available at https://interchange.puc.texas.gov/Documents/51603_65_1216243.PDF

The weeks that followed were filled with news articles. Many of them, from Tesla customers and fans who just did an incredible job helping me personally in a space that felt like a lonely vacuum. There were also retail energy provider CEOs and policy directors, and a great consultant I worked with, Eric Goff, who pushed me to get deep into ensuring the success of an ADER pilot project.

A lot of the subsequent work, that resulted in the constitution of the ADER Task Force, has been covered in my other posts and in news stories since. But one anecdote I will tell you about, also something no one else knows, is how relieving and supportive it was for me to suddenly get a LinkedIn message from an executive at CenterPoint, Jason Ryan, one day after the fateful open meeting. On June 17, 2022, Jason wrote, “Good to meet you briefly yesterday. If you'd like to discuss a pilot in Houston, please let me know! cheers. jmr”.

Jason then became the formidable ally I needed to make DER grid integration a reality in Texas markets. In our early days putting the task force charter recommendations together, we collaborated constantly, and made the experience fun and supportive of each other as dedicated professionals looking for solutions above all else. There were times, when he and I led task force meetings, where we wore matching suits, drank matching diet cokes, and generally tag-teamed the most gloriously productive volunteer regulatory effort the state has ever seen. The federal government took notice, and showed up in our back yard at the Mitchell Foundation in Austin to figure out how we did it. Pretty much two things, we told them: committed subject matter experts, utility leaders, collaborative regulator & grid operator working together - and transparent, clear public process.

Pictured below: DOE’s Visit to Austin. Note Pablo Vegas had already assumed ERCOT’s leadership at this point and is pictured below with DOE Secretary Jennifer Granholm. My colleague Brad succumbed to cancer on November 8, 2023, and was interim CEO of ERCOT through Nov. 1, 2022. A scholarship fund is set up in his name, viewable here.

In the early days of the task force, the two of us (Jason is still Chair, I am now an independent advisor on the task force, but started as Vice Chair while at Tesla) and a DOE Fellow with Commissioner Will McAdams (Tiffany Wu), and VA Stephens, staff to Commissioner Jimmy Glotfelty: a little Avengers team came together to create a monumental shift in the public’s perception of the speed and success rate of stakeholder-led, collaborative market reforms. The assembly thereafter of a task force of 20 dedicated volunteers who built consensus for the pilot rollout, was critical to our success.

What we accomplished in that first year, and then in the subsequent anniversary year, is well documented in Tesla’s public filings:

ADER 1 Year Reviews: https://interchange.puc.texas.gov/Documents/53911_52_1311452.PDF

https://interchange.puc.texas.gov/Documents/53911_55_1331785.PDF

I hope you’ll really read these if you’re into figuring out grid-integrated VPP anywhere in the world. If you read news articles talking about “slow progress” and that “interoperability” is the largest barrier to the pilot, please stop reading that news. There are 12 technical advancements ERCOT accomplished along with market participants who actually provide this product, within a year, irrespective of how much participation there was in the first year. The advancements in technical know-how, market confidence, and commercial agreements relying on interoperability standards, are tremendous. Quotes from spokespersons who do not know this material, and refuse to learn it, will continue to hyperfocus on second order problems. The first order ones - does it work, can we measure it, can we pay customers, can it scale - we solved through the work of the task force, in one year flat. Compare that to what is happening around the country with Order 2222 implementation speeds and have a good think.

Now, the ADER Task Force is working with ERCOT to kick open the doors on growing the program in some fascinating, critical ways. I spoke to Utility Dive about it quite recently, and I’m very optimistic that Texas’ success in this space will barrel forward in the new year.

— Arushi Sharma Frank