Texas changed the question

For much of the data center boom, the race in Texas has been about securing the ingredients needed to build: land, capital, fiber, equipment and, increasingly, electricity.

Now Texas itself is becoming another variable in that equation.

On August 3, Governor Greg Abbott directed ERCOT and the Public Utility Commission of Texas to take a closer look at data center projects seeking access to the grid. The action interrupted ERCOT’s expected Batch Zero timeline and introduced a broader review of how proposed facilities intend to operate in Texas.

The questions go well beyond how many megawatts a project wants.

Developers are being asked about projected annual and peak electricity consumption, how dependent their facilities will be on the ERCOT grid, whether they plan to build or procure on-site generation, and what measures they can take to reduce grid demand.

That represents an important change in how Texas is thinking about large loads.

A proposed 150 MW data center can no longer be understood simply as 150 MW of future demand. Its location, timing, flexibility, generation strategy and reliance on the grid increasingly matter too.

For developers, that moves the power conversation much earlier in the life of the project.

Long before the first server turns on, and long before there is an electricity bill, the economics of that future load are already becoming part of the development decision.

Why Texas Is Doing This Now

Texas is not reacting to a theoretical problem.

Electricity demand in ERCOT is expected to grow much faster than in most of the country. EIA forecasts electricity sales in the ERCOT region to rise by roughly 22% between 2024 and 2026, compared with about 4–5% nationally.

Much of the pressure comes from a new class of very large electricity users.

ERCOT is tracking hundreds of gigawatts of proposed large-load projects, and data centers account for the overwhelming majority of that pipeline.

The headline numbers are enormous. But they can also be misleading.

A megawatt in an interconnection request is not the same thing as a megawatt consuming electricity.

Some projects are already energized. Others have planning studies approved. Many remain under review. A significant portion of the longer-term pipeline has not yet submitted studies at all.

That distinction is becoming one of the most important questions in Texas electricity planning.

ERCOT and policymakers have to make decisions about transmission, generation and grid reliability years before they know exactly which projects will reach commercial operation.

Building infrastructure around too little demand creates one set of problems.

Building around load that never materializes creates another.

That helps explain why Texas is asking developers for more evidence about how their projects will actually use the grid.

The state’s questions around peak demand, annual consumption, on-site generation and grid dependence are effectively trying to determine something more useful than a project’s headline MW number:

What will this load actually mean for ERCOT?

And that creates a new problem for the developers themselves.

Power Strategy Starts Before the Meter

For an operating facility, electricity procurement usually begins with something tangible: a meter, historical usage and an existing contract.

A data center under development may have none of those.

Consider a developer planning a 150 MW AI campus in ERCOT. The site may already be under control. Transmission discussions may be underway. An interconnection application may be filed. Capital has been committed and a commercial operation date is on the calendar.

But the facility is not consuming electricity yet.

Its power question is therefore very different from that of an operating commercial building.

It isn’t:

“Are we paying too much for electricity?”

It is:

“How should we economically secure and structure 150 MW of power in ERCOT?”

That question reaches beyond a retail electricity contract.

Where the project is located matters. So does when its load ramps, how consistently it operates, how much supply it expects from the grid, whether it can reduce consumption during constrained periods, and whether generation or storage sits behind the meter.

Two projects can each request 150 MW and create very different economic relationships with ERCOT.

One may operate near full load around the clock and depend almost entirely on the grid.

Another may ramp gradually, maintain on-site BTM generation, install battery storage or have the ability to curtail part of its demand. Introducing the idea of a multi-faceted energy strategy including PPAs, REP funneled power, BTM, storage, etc, all of which depend on clean energy economics.

The engineering requirement may still be expressed in megawatts.

But the economic character of those megawatts is different.

That distinction is becoming increasingly important as Texas evaluates not simply how much electricity a project wants, but how the project intends to source and manage it.

For developers, power strategy can no longer wait until a facility is approaching commercial operation.

It begins while the load still exists on paper.

TheGridLetter

Texas energy markets, seen through our lens.

By Atai

Moving Power Economics Upstream

That is the problem Polaris is beginning to find success in addressing.

Based in Houston, Polaris has traditionally approached electricity from the operating side of the meter: understanding a company’s load, placing it in ERCOT market context, and using that information to make better procurement decisions.

For a developing data center waiting for interconnection, the starting point has to change.

There may be no historical usage to analyze yet. Instead, Polaris can begin with the characteristics of the project itself: site, expected COD, initial and full-build MW, ramp schedule, load factor, operating profile, grid dependence, curtailment capability, and any planned generation or storage.

Those inputs create what Polaris calls an Economic Power Position.

The objective is not to tell developers how to engineer an interconnection or design a substation. It is to understand what the planned load means economically before hundreds of megawatts are committed to a particular power structure.

A 150 MW project, for example, can be evaluated through several economic scenarios: full grid dependence, partial behind-the-meter generation, storage, or a defined amount of curtailable load.

The question is not simply which architecture is technically possible.

It is how each choice changes the project’s exposure to ERCOT, the forward market, supplier pricing, and ultimately the cost of operating the facility.

That is where Market-Based Procurement becomes relevant.

Rather than waiting until COD approaches and asking suppliers to quote an existing meter, Polaris can bring a future load profile to its procurement network and ask a different question:

How would the market structure supply for this projected load beginning several years from now?

That gives developers earlier visibility into how suppliers are valuing the project, and creates a way to connect development assumptions with actual market economics.

The Market Is Already Pricing the Uncertainty

The challenge is that understanding future demand does not automatically tell a developer what future power will cost.

ERCOT’s forward market is constantly repricing expectations about generation, fuel, transmission, weather and load growth. Data centers are now part of that equation, but they are only one part.

Looking at Houston forward electricity prices, the market is not treating every future year the same.

That matters for a project whose COD may still be several years away.

A developer targeting 2028 or 2029 is not buying electricity in a single market called “ERCOT.” It is exposed to a particular location, delivery period, load shape and contract structure, each of which the market can value differently.

And those values move.

A new transmission assumption can change expectations around congestion. Additional generation can soften one part of the curve. Delayed data-center projects can push anticipated demand farther out. New policy requirements can change the economics of how large loads eventually connect.

The practical implication is simple:

A project can have a path to interconnection and still make a poor commercial power decision.

That is why Polaris is building visibility into both the project and the market around it.

The Economic Power Position establishes what the future load looks like economically. Market-Based Procurement then connects that position with forward market conditions and competitive supplier structures.

The objective is not to predict ERCOT perfectly.

It is to help the developer understand what the market is offering, what assumptions sit underneath those prices, and how much economic risk the project is taking by acting, or waiting.

Read More From Us

Commercial Electricity Procurement Has Quietly Changed

Commercial electricity procurement used to be a relatively straightforward exercise.

A business would approach contract renewal, request pricing from several suppliers, compare proposals, and select the offer that best aligned with its objectives.

That process still exists.

What has changed is everything happening behind the scenes.

Texas is entering a period of sustained electricity demand growth, driven largely by data centers, industrial expansion, and electrification. At the same time, renewable generation is reshaping when electricity is abundant, when it becomes scarce, and how wholesale prices form throughout the day.

As those market dynamics become more complex, so too does the process of pricing commercial electricity.

Suppliers aren’t simply responding to higher demand.

They’re adapting to a market whose behavior is fundamentally different than it was only a few years ago.

For buyers, that raises an important question.

If the market has changed, should procurement change with it?

The Market Suppliers Price Today Isn’t the Market They Priced Yesterday

The U.S. Energy Information Administration expects ERCOT to experience the strongest electricity demand growth of any major power market through 2026.

Much of that growth is expected to come from large, continuous electrical loads, particularly data centers.

At the same time, ERCOT continues adding significant amounts of renewable generation and battery storage, changing not only the amount of electricity available, but also the way prices form throughout the day.

Those changes don’t automatically make electricity more expensive.

Nor do they automatically make procurement more difficult.

They do mean suppliers are evaluating facilities within a market that behaves differently than it did in previous procurement cycles.

That context matters.

Because before a supplier ever produces pricing, they first have to understand how your facility fits into today’s market, not the market of five years ago.

A Different Market Demands a Different Level of Analysis

Demand growth is only part of the story.

The more meaningful change is where that demand is coming from.

For decades, electricity demand followed relatively familiar patterns. Residential consumption rose in the evenings. Commercial buildings were busiest during the day. Industrial facilities often operated on predictable production schedules.

Today’s growth looks different.

Much of ERCOT’s projected demand is coming from facilities that consume enormous amounts of electricity around the clock. Data centers, particularly those supporting AI workloads and cloud infrastructure, don’t slow down when the workday ends. Their demand remains remarkably consistent, regardless of the hour, the weather, or the day of the week.

Looking at ERCOT’s interconnection pipeline, that trend becomes difficult to ignore. The overwhelming majority of proposed large-load projects are data centers, representing hundreds of gigawatts of potential demand over the coming years.

This doesn’t mean all of that capacity will ultimately connect to the grid.

It does, however, illustrate where both developers and market participants expect future electricity demand to concentrate.

For suppliers, that changes the nature of procurement.

Pricing a continuously operating 50 MW data center is fundamentally different from pricing an office building or a manufacturing facility that shuts down overnight. The market conditions that matter, the risks that must be evaluated, and the contract structures that make sense all become more nuanced.

As the composition of demand changes, supplier analysis naturally becomes more sophisticated.

Not because suppliers have changed.

Because the market they’re pricing has.

Markets Price Expectations, Not Just Today’s Conditions

The same idea begins to appear when looking beyond physical demand and into forward electricity markets.

Forward prices aren’t forecasts. They’re financial instruments reflecting what market participants collectively believe future electricity will be worth under current information.

Across major U.S. wholesale markets, ERCOT North continues to trade among the highest relative to its historical contract lows. That doesn’t guarantee higher future prices, but it does suggest that participants are assigning meaningful value to future supply-demand uncertainty.

For businesses planning facilities with operating lives measured in decades rather than years, those expectations matter.

Procurement decisions are no longer being made against a static backdrop.

They’re being made within a market that is continuously repricing future risk as new generation, new demand, transmission constraints, and policy changes reshape the system.

That raises another question.

If suppliers are evaluating both where the market is heading and how an individual facility behaves within that market, what exactly are they looking for before they ever produce a quote?

Every Facility Has a Different Economic Power Position

Two data centers can consume exactly the same amount of electricity each year and receive meaningfully different procurement outcomes.

On paper, they might appear nearly identical.

Each operates around the clock.

Each consumes tens of megawatts.

Each requires long-term price certainty.

Yet suppliers rarely evaluate facilities using annual consumption alone.

Because annual consumption tells you how much electricity a business uses.

It tells you very little about how that electricity is consumed.

That distinction becomes increasingly important in a market where price formation is evolving.

As renewable generation continues reshaping wholesale electricity markets, the economics of a facility are no longer determined solely by the volume of electricity it purchases. They’re increasingly influenced by when electricity is consumed, how consistently demand behaves, and how those consumption patterns interact with the market itself.

In other words, two facilities purchasing the same number of kilowatt-hours may present very different procurement opportunities.

Beyond Consumption

This is why suppliers request historical interval data before producing a quote.

They’re not simply confirming annual usage.

They’re building a picture of how a facility behaves.

Questions they’re attempting to answer include:

• Is demand relatively consistent throughout the day or highly variable?

• How exposed is the facility to the hours where prices tend to become more volatile?

• Does the operational profile align well with today’s market structure?

• Which contract structures are likely to produce the most competitive long-term outcome?

Those questions aren’t designed to make procurement more complicated.

They’re designed to reduce uncertainty.

Because in commercial electricity markets, suppliers don’t simply price electricity.

They price the uncertainty of delivering it.

Markets Evolve. So Do The Characteristics That Matter.

Looking at Houston Hub pricing over the past several years, a notable pattern begins to emerge.

The traditional distinction between expensive daytime hours and inexpensive overnight hours has narrowed considerably. Peak-hour prices have compressed, while off-peak prices have gradually moved closer to those daytime averages.

That doesn’t mean volatility has disappeared.

It means the market is expressing risk differently than it once did.

The implication for buyers is subtle but important.

A procurement strategy built around yesterday’s pricing behavior may not fully reflect today’s market dynamics.

As the shape of prices changes, understanding how a facility’s operating profile aligns with that shape becomes increasingly valuable.

It’s no longer sufficient to ask, “What rate can we get?”

A more useful question may be:

“How does today’s market evaluate the way our facility consumes electricity?”

That question sits at the center of modern commercial electricity procurement.

It’s also the question that led us to develop what we call an Economic Power Position a framework for understanding how market conditions and facility characteristics come together before procurement ever begins.

Understanding Your Economic Power Position

Every facility enters the electricity market differently.

Some of those differences are operational. Others are structural. Many are shaped by market conditions entirely outside the buyer’s control.

Together, they form what we refer to as a facility’s Economic Power Position.

An Economic Power Position isn’t a single metric or score. It is a framework for understanding how the electricity market interacts with the way a facility consumes power, and how that relationship ultimately influences procurement economics.

It brings together two sides of the same transaction.

The market:

Forward prices.

Congestion.

Scarcity and volatility.

Generation mix.

Regional price behavior.

And the facility:

Load profile.

Operating schedule.

Consumption consistency.

Peak exposure.

Location.

Contract objectives.

Neither side tells the full story on its own.

A favorable market does not necessarily mean every facility will receive favorable pricing. And an attractive load profile does not eliminate the influence of timing, location, or broader market conditions.

The economics emerge where the two intersect.

That intersection is your Economic Power Position, and understanding it gives you a clearer view of how the market may value your load, where procurement leverage exists, and what competitive power should reasonably cost before you begin asking suppliers for prices.

Markets Change. So Does Your Position.

One of the most important ideas in commercial electricity procurement is that a facility’s buying position is never truly fixed.

The facility may not change.

Its operating schedule may remain consistent. Its load profile may look nearly identical year after year. Its annual consumption may stay within the same range.

But the market surrounding that facility is constantly moving.

Consider the forces we’ve explored throughout this article.

Demand is growing.

Large continuous-load facilities are becoming a greater share of ERCOT’s future load.

Renewable generation is reshaping when electricity is abundant, and when it isn’t.

Forward markets are continuously repricing expectations for future power.

Peak and off-peak pricing relationships are evolving.

Congestion patterns shift as generation, transmission, and demand change across the grid.

None of these changes originate from the facility itself.

Yet each can alter the economic environment in which that facility buys power.

That means the same data center, consuming electricity in essentially the same way, can hold a very different Economic Power Position from one procurement cycle to the next.

A load profile that was relatively expensive to serve under one set of market conditions may become more attractive under another. A contract structure that made sense three years ago may no longer reflect the economics available today.

This is why procurement should not begin with a simple question:

“What rate can we get?”

It should begin with a more fundamental one:

“How is our facility positioned in today’s market?”

Because the market moves.

And your Economic Power Position moves with it.

Context Creates Better Decisions

Take two identical 40 MW data centers.

Place one in North Texas.

The other near Houston.

Their annual consumption may be nearly identical.

Their operations may be nearly identical.

Even their procurement objectives may be the same.

Yet they participate in different regional pricing dynamics, experience different congestion patterns, and interact with different local market conditions.

The objective isn’t to determine which facility is “better.”

It’s to understand the context each facility operates within before procurement begins.

That’s ultimately what an Economic Power Position seeks to provide.

Not certainty.

Context.

Because procurement decisions become more effective when they’re informed by both how your facility operates and the market it’s operating within.

The Economic Power Report

That thinking ultimately led us to develop the Economic Power Report.

Not because electricity buyers needed another report.

But because we believed they should have access to the same kind of market context suppliers use when deciding how to price their load.

The Economic Power Report is built around a simple question:

How does today’s electricity market view your facility?

Rather than looking only at what a facility has historically paid for electricity, the report examines the relationship between how the facility consumes power and the market in which that power is being purchased.

It brings together:

• Historical interval usage.

• Load shape and consumption consistency.

• Current and forward market conditions.

• Regional pricing dynamics.

• Peak and off-peak exposure.

• Procurement and contract considerations.

And ultimately, the facility’s Economic Power Position.

The result is an independent view of how the facility is positioned before supplier pricing enters the conversation, what characteristics may strengthen or weaken its buying position, where procurement leverage may exist, and what competitive power should reasonably cost under current market conditions.

The objective is not to predict where electricity prices will move next.

It is to give buyers enough market context to make a more informed procurement decision before committing millions of dollars to a power contract.

From there, the intelligence can be used in either direction:

Take the report to market independently, or use Polaris to run the competitive procurement process on your behalf.

Either way, the principle is the same:

Understand your position before you negotiate from it.

Learn More

Procurement Is Becoming an Analytical Discipline

For much of ERCOT’s history, commercial electricity procurement was largely a pricing exercise.

Gather competitive bids.

Compare contract structures.

Select the supplier that best aligned with the organization’s objectives.

Those fundamentals haven’t disappeared.

But the market surrounding them has become considerably more complex.

Demand growth is accelerating.

Generation is changing.

Wholesale price formation continues to evolve.

Forward markets continuously reprice expectations.

As those dynamics become more interconnected, procurement increasingly depends on understanding why suppliers produce the prices they do, not simply comparing the prices themselves.

That’s a subtle but meaningful shift.

The question is no longer just:

“Who offered the lowest rate?”

It’s increasingly:

“What assumptions about our facility and the market produced that rate?”

Understanding those assumptions doesn’t eliminate uncertainty.

Electricity markets will always evolve.

Weather will change.

Infrastructure will expand.

Demand forecasts will be revised.

No framework can remove that uncertainty.

What better analysis can do is provide context before decisions are made.

And in markets where millions of dollars in operating expense are committed years in advance, context has value.

A Better Starting Point

One of the recurring themes throughout this publication is that electricity procurement doesn’t begin with a supplier quote.

It begins with understanding the market you’re entering.

The more accurately a business understands both its own operating profile and the market dynamics surrounding it, the better positioned it is to evaluate procurement options, ask informed questions, and make decisions aligned with its long-term objectives.

That’s ultimately the purpose of the Economic Power Report.

Not to replace the procurement process.

Not to recommend a particular supplier.

But to provide buyers with a clearer picture of how today’s market views their facility before procurement begins.

Because better procurement doesn’t start with better negotiations.

It starts with better understanding.

About The Grid Letter

The Grid Letter is a research publication covering ERCOT, Texas electricity markets, infrastructure, and commercial power procurement. Our goal is to help business leaders better understand how electricity markets work, and what those changes mean for their organizations.

Interested in understanding your facility’s Economic Power Position?

Learn more about the Economic Power Report at Polaris.

Learn More

The facility is going to consume power whether the market is favorable or not. The more useful question is how that electricity is sourced and whether the buying process produces an efficient financial outcome for the business.

At scale, small differences matter.

Consider a facility operating at an average load of 10 MW. Over a year, it would consume roughly 87.6 million kWh. At an illustrative rate of 7¢/kWh, that represents about $6.13 million in annual energy cost. At 6¢/kWh, the same consumption represents about $5.26 million.

Nothing about the facility changed.

The difference is the rate at which its demand was priced.

This does not mean every business can simply negotiate one cent off its electricity rate. Commercial electricity pricing does not work that way.

It does illustrate something more important.

The larger a facility’s electricity consumption becomes, the more economically consequential the process used to price that consumption becomes.

Most businesses approach electricity from the perspective of necessity: We need power. What will it cost us?

There is another way to look at the same transaction.

A large facility isn’t only buying electricity. It is bringing millions of kilowatt-hours of recurring demand into a competitive electricity market.

And demand has value.

Understanding that distinction is the starting point for understanding how commercial electricity rates can be sourced more effectively in Texas.

Your Electricity Rate Starts in a Market

If a facility’s demand has value, the next question is: who determines what that demand is worth?

In Texas, there is no single answer.

The commercial rate a business receives sits at the end of a much larger market process. Wholesale electricity prices, the facility’s consumption profile, location, contract term, market timing, supplier risk and margin can all influence the price ultimately offered to the buyer.

That matters because the market underneath those offers is constantly moving.

Looking at average Q1 Day-Ahead Market prices in Houston, that movement has become increasingly visible. Average prices rose from roughly $26/MWh in Q1 2024 to $32/MWh in Q1 2025 and $39/MWh in Q1 2026.

Three years of Q1 pricing do not, by themselves, prove that electricity prices will continue rising. Weather, generation availability, fuel costs, renewable output, transmission conditions and demand can all change the market from one period to another.

But the progression illustrates the problem with treating an electricity rate as a static number.

The supplier quoting a commercial facility must price the obligation to serve that load against the market conditions surrounding it. As those conditions change, so does the economics of serving the customer.

This creates an important distinction.

A commercial buyer sees a rate.

The market sees a load that must be served over time.

That load has a location, shape, operating pattern and risk profile. Suppliers can value those characteristics differently, which means the price available to a facility is not necessarily one universally agreed-upon number.

And that is where the buyer’s position becomes interesting.

Because if multiple suppliers can place different values on the same demand, the objective is no longer simply to ask a supplier for its price.

It is to understand the market well enough to make suppliers compete to price the demand.

There Is No Single Texas Electricity Price

This is where commercial electricity procurement becomes more nuanced.

It is tempting to think of the power market as having a prevailing price: electricity is either expensive or inexpensive, and the buyer’s job is to wait for the right moment to purchase.

But electricity is not priced that simply.

The market assigns different values to power depending on where it will be delivered, when it will be consumed and how far into the future that delivery occurs.

Looking at Houston Hub forward prices during 2026 makes the distinction clear.

By late July, the market was pricing Cal-27 near $47/MWh while Cal-30 remained around $56/MWh. Earlier in the year, those same contracts had traded much closer together.

The important point isn’t whether $47 or $56 represents a “good” price.

It is that both prices existed in the same market at the same time.

A facility entering a one-year agreement, a three-year agreement and a five-year agreement is exposing itself to different parts of the forward market. Change the location, load profile or timing of the transaction, and the economics can change again.

This is why asking whether Texas electricity prices are currently “high” or “low” has limited usefulness for a commercial buyer.

A better question is:

What is the market currently offering for the electricity our facility actually needs to buy?

Price alone also doesn’t tell the entire story.

Periods of extreme market tightness can influence supplier risk even when average electricity prices appear relatively manageable. ERCOT’s recent scarcity history makes that distinction useful.

Scarcity frequency fell dramatically from 2023 through 2025 before increasing again in 2026 year to date. That does not tell us where scarcity will go next. It does show why a procurement decision cannot be reduced to a single average market price.

Suppliers are pricing an obligation to serve electricity in a market whose value changes across time, location and risk.

Commercial buyers are purchasing that same obligation from the other side.

Once you understand that, sourcing a lower rate becomes less about finding a supplier with a cheaper number and more about understanding where your specific demand fits inside the market.

And that brings us back to the facility itself.

Your Load Has Economic Value

Once electricity is viewed as a market transaction rather than simply a utility expense, the role of the facility begins to look different.

Every commercial facility brings demand to the market. For larger consumers, that demand can represent tens or hundreds of millions of kilowatt-hours over the life of a contract.

Suppliers want the opportunity to serve that load.

But not every megawatt of demand looks the same.

Consider two facilities that consume the same amount of electricity annually. One operates continuously with relatively predictable consumption. The other experiences large peaks, seasonal swings and irregular operating hours.

Their annual usage may be identical, but the economics of serving them can be very different.

A facility’s load shape, load factor, peak demand, operating schedule, location and seasonality all help determine how its consumption interacts with the market. Contract length, product structure, credit and timing add another layer.

This is why simply knowing how much electricity a facility consumes isn’t enough.

The more useful question is how that consumption is positioned.

We call this a facility’s Economic Power Position: the relationship between its electricity demand, the market conditions surrounding that demand, and the commercial terms available to serve it.

This changes the way procurement can be approached.

Instead of beginning with:

“Which supplier can give us a lower rate?”

A buyer can begin with:

“What does our load look like, how is the market likely to value it, and how can we create competition around that demand?”

That distinction matters in a deregulated market.

Suppliers already compete for commercial load. Each has its own portfolio, hedging position, risk tolerance, cost structure and commercial objectives. As a result, two qualified suppliers evaluating the same facility do not necessarily have to arrive at the same price or contract structure.

The buyer’s opportunity is to make that competition work in its favor.

Not by trying to predict every movement in ERCOT.

Not by becoming a power trader.

And not simply by negotiating harder against a single quote.

The objective is to bring an understood block of demand to an informed group of suppliers and allow the market to compete for it.

The supplier has supply.

The facility has demand.

Both sides bring something economically valuable to the transaction.

The procurement process should reflect that.

How to Put Your Demand to Work

Understanding a facility’s Economic Power Position is useful only if it changes how electricity is sourced.

The conventional procurement process often starts near the end: a contract is approaching expiration, the business requests pricing, a supplier provides a rate, and negotiations begin.

A market-based approach starts earlier, with the facility itself.

The framework is relatively straightforward.

1. Analyze the load.
Start with the facility’s historical electricity data. Ideally, this includes at least 12–24 months of interval and billing information. The objective is not simply to calculate annual usage, but to understand when and how the facility consumes power.

2. Establish the buying position.
Compare those load characteristics with current and forward market conditions. This connects what the facility needs to buy with the market available to serve it.

3. Determine the procurement strategy.
Contract term, product structure, timing and risk tolerance should reflect the business behind the meter. A manufacturer operating continuously may have different priorities from a facility with seasonal or highly variable demand.

4. Create competition for the demand.
Present the same structured opportunity to multiple qualified suppliers. Instead of negotiating against one supplier’s view of the market, the buyer can observe how several suppliers independently value the same load.

This is where the process becomes powerful.

If one supplier values the load differently because of its portfolio, hedging position, risk appetite or commercial objectives, competition gives the buyer an opportunity to discover that difference.

5. Evaluate the outcome.
The lowest headline rate is not automatically the best contract. Price matters, but so do contractual terms, risk allocation, pass-through provisions and how well the product fits the facility’s operating profile.

The objective is not simply to collect more quotes.

It is to create a market for your demand.

And none of these principles are exclusive to Polaris. A commercial electricity buyer can build this process internally, work through an advisor, or develop its own supplier relationships.

Polaris applies the same framework through its internal analytics, market intelligence and supplier network. The advantage of that infrastructure is execution: taking raw facility data, determining its Economic Power Position, and running a structured sourcing process across suppliers including NRG, Constellation and ENGIE.

The methodology itself is simpler:

Understand the load. Understand the market. Then make the market compete for the load.

Read More From Us

What is the average commercial electricity rate in Texas?

It’s one of the most searched questions by businesses questioned by the market and it’s an understandable place to start.

Published benchmarks often place commercial electricity somewhere between 7 and 9 cents per kilowatt-hour, depending on supplier, contract structure, business size, and market conditions.

Those figures provide a useful snapshot of the market, particularly for smaller commercial customers comparing publicly available offers.

For larger commercial and industrial facilities, however, the conversation changes.

The number on a supplier’s proposal isn’t pulled from a pricing sheet. It’s the result of an underwriting process that evaluates how your facility is expected to interact with the Texas electricity market over the life of the contract.

We’ve seen facilities with similar annual energy consumption receive meaningfully different pricing, not because the market changed overnight, but because suppliers viewed the underlying risk differently.

Likewise, Polaris has facilitated transactions for qualifying commercial loads in roughly the 4.5–6.5¢/kWh range, due to competitive procurement and a deeper understanding of facility-specific risk can materially influence outcomes.

The question, then, isn’t whether one published rate is “right” and another is “wrong.”

It’s understanding why two facilities can receive entirely different prices for what appears to be the same product.

That answer begins long before a supplier ever produces a rate.

Suppliers Don't Price Electricity. They Price Risk.

They begin by asking, “What are we being asked to serve?”

Behind every commercial electricity proposal is roughly 24 months of interval data, typically measured every 15 minutes. That history allows suppliers to build a forward-looking risk profile of your facility, much like a lender evaluates credit history before issuing a loan or an insurer assesses risk before setting a premium.

Annual consumption is only one piece of that picture though.

Suppliers also evaluate how consistently your facility consumes electricity, how much demand it places on the grid during peak periods, how consumption changes across seasons, and whether that load aligns with hours that are expected to be more expensive to serve.

Looking at ERCOT’s recent market dynamics, another trend begins to emerge. The premium historically associated with peak afternoon hours has narrowed considerably over the past several years.

That doesn’t mean timing no longer matters, it means the market is evolving, and suppliers are continually updating how they value different load characteristics.

This is why two facilities consuming the same number of kilowatt-hours each year can receive materially different pricing.

They’re not buying the same risk.

They’re buying two entirely different operating profiles.

Once a supplier understands how your facility behaves, they still have to answer a second question:

What will it cost us to supply that electricity over the next three, four, or five years?

That answer comes not from your facility, but from the market itself.

Every Supplier Sees a Different Market

Understanding your facility is only half of the pricing equation.

Suppliers must also determine what they believe electricity will cost over the life of your contract.

Every commercial electricity proposal is built upon forward wholesale markets that continuously adjust to new information. Changes in natural gas prices, weather forecasts, transmission constraints, generation additions, reserve margins, and Texas’ rapidly growing electricity demand all influence those expectations.

The result is something that looks remarkably familiar to anyone who has spent time in the financial markets.

Ask five equity analysts to value the same company, and you’ll likely receive five different price targets.

The business hasn’t changed, each analyst simply has a different view of future earnings, risk, and market conditions.

Commercial electricity works much the same way.

Ask five suppliers to price the same facility, and you’ll often receive five different offers.

Your building hasn’t changed. Your interval data hasn’t changed. What changes is how each supplier interprets your load profile alongside their own expectations for the future wholesale market.

The rate on your proposal is ultimately the intersection of two forecasts:

• How your facility is expected to consume electricity.

• How the supplier expects the Texas market to evolve over the life of the contract.

Understanding both sides of that equation creates a fundamentally different procurement strategy than simply requesting quotes and comparing cents per kilowatt-hour.

For most commercial buyers, that underwriting process happens entirely behind closed doors.

Suppliers understand your position in the market long before you ever see a proposal.

The question becomes:

Turning Market Intelligence Into Better Procurement

One of the advantages of Texas’ competitive electricity market is that every commercial facility already possesses the information needed to better understand its position.

The same 24 months of Smart Meter Texas (SMT) interval data suppliers use to evaluate risk is available to the customer as well.

The challenge has never been access to the data, it’s transforming millions of interval readings into information that can improve procurement decisions.

Whether a facility analyzes that information internally or works with Polaris, the process is fundamentally the same:

1. Analyze historical interval data to understand how the market is likely to evaluate your load profile.

2. Translate that analysis into an Economic Power Report that identifies procurement opportunities, pricing characteristics, and facility-specific risks.

3. Introduce competitive market participation by allowing multiple qualified suppliers to price the same informed load profile.

4. Improve financial outcomes through stronger market positioning, greater pricing transparency, and procurement decisions supported by better information.

The objective isn’t simply to obtain another quote.

It’s to enter the market with a clearer understanding of how your facility is being valued before suppliers begin assigning prices.

Final Closing

The search for the average commercial electricity rate in Texas is a logical place to begin.

But commercial electricity isn’t priced from an average.

It’s priced from expectations, about your facility, about the market, and about future risk.

Facilities that understand those expectations before entering procurement aren’t simply comparing rates.

They’re participating in the market from a position of greater economic visibility.

Read More From Us

This post will be an informative post breaking down market dynamics and giving internal insight on the market from the lense of Polaris where we’re seeing rates between 4.5 - 6 cents per Kwh.

Polaris is an energy intelligence infrastructure platform that helps facilities consuming large amounts of power maximize cash flow through better power economics and visibility. Already having helped facilitate $9M+ in cashflow after only being released to the public in April of 2026.

The important thing is not the rates themselves, but how they emerge from the load dynamics of the ones searching this term “average commercial electricity rates”. How suppliers look at their 24 month interval data to determine their risk profile, what that risk profile even consist of (load factor, peak load, seasonal consumption patterns, placement of consumption, congestion risk, on peak/off peak patterns, etc) and how those searching for clarity in the market can use Polaris, an energy intelligence infrastructure platform to generate this information fir them at no cost using an economic power report, derived from the same interval data their suppliers are using to produce their rates.

Because Texas is a deregulated market, there a wide range of pricing strategies from suppliers, and because of this, each supplier prices demand differently. This also illuminates to why demand side active participation in this market is important, as a consumer (demand) limiting themselves to the dynamics of one supplier rather than multiple suppliers bidding for their load puts them at a market disadvantage where each numerical change in rates can equate to thousands, even millions at times.

Competition is naturally created due to how ERCOT is structured and only 1 side of the market currently is playing ball. Demand has to realize just how much of an advantage they can have in this market if they actively competed against supply side. Much like the financial markets, if supply is in control of the asking price and demand hits those ask without any push from bids then that’s a favorable outcome for suppliers. Consumers typically generate competition through negotiation with a single supplier, at the mercy of information integrity. Its a different ball game when suppliers have to compete with other informed suppliers for consumers.

In this publication I want to keep it short but informative, mentioning Polaris throughout, as that’s where internal data/information comes from.

Problem (rising YoY power prices, facilities over leveraging their load in the market, overpriced contracts, lack of supplier level visibility into their facility, etc) → Solution (Polaris produces power reports complimentary to demand side of the market, no upfront risk, sales processes, 1-2 week process for measurable savings, etc. Uses the same data their supplier uses to generate detailed information on position risk and savings opportunities. Greater clarity into how their facility interacts with the current Texas power market

Texas Just Changed Again

ERCOT did not simply set another demand record this week.

It moved the ceiling.

On July 22, instantaneous electricity demand crossed 91 GW for the first time, reaching approximately 91.3 GW. That was more than 5 GW above the record that had existed only two days earlier.

Extreme heat across Texas was a major part of the story. Air-conditioning demand remained elevated across the state’s largest population centers while commercial, industrial, and digital infrastructure continued drawing power throughout the day.

But demand was not the only record being set.

ERCOT also reached new highs for both solar generation and battery discharge, with solar producing approximately 34.6 GW and batteries delivering as much as 11.9 GW back to the grid.

That combination matters.

Texas met record electricity demand with more renewable generation and more stored energy than ever before. The grid absorbed the load. Reliability held. New resources performed a role that would have been difficult to imagine only a few years ago.

And yet, wholesale prices still became sharply elevated later in the day.

That is the tension worth examining.

Texas is adding enormous amounts of solar and battery capacity. Those resources are helping the grid serve unprecedented demand and suppressing prices during periods of abundant production.

But they are not making every hour cheaper.

They are changing which hours are cheap, which hours are expensive, and how quickly the market can move between the two.

A Record Built on More Than Demand

The most important part of the 91 GW record may not be the number itself.

It is the shape of the system behind it.

ERCOT is becoming a grid where record demand, record solar output, record battery discharge, and elevated wholesale prices can all occur within the same day.

Those outcomes are not contradictory.

They are features of a market increasingly shaped by variable generation, fast-changing net load, and large consumers that do not stop operating when the sun goes down.

To understand why prices can remain moderate during one part of the day and rise rapidly only a few hours later, it helps to look beyond total demand.

The more important variable is what remains after renewable generation begins to fall.

That is where the duck curve begins.

The Grid Doesn’t Follow the Sun. Solar Does.

Electricity demand doesn’t disappear when the sun begins to set.

Homes are still cooling.

Factories are still producing.

Hospitals continue operating.

And data centers continue consuming electricity around the clock.

What changes is the supply available to meet that demand.

During the middle of the day, Texas now produces enormous amounts of solar generation. As that electricity enters the grid, it displaces higher-cost generation and increases the overall supply of available power. The result is often lower wholesale prices during daylight hours, particularly in the spring and summer when solar output is strongest.

That has been one of the defining characteristics of ERCOT’s changing generation mix.

But solar follows a predictable schedule.

As the afternoon turns into evening, solar production begins to decline rapidly, even as electricity demand often remains elevated. The grid must replace tens of gigawatts of generation within a relatively short period of time, relying on dispatchable resources such as natural gas, battery storage, imports, and other flexible generation to fill the gap.

That transition is commonly referred to as the duck curve.

It’s less a story about rising demand than it is about rapidly changing supply.

Lower Prices Don’t Necessarily Mean Lower Costs

One of the more interesting consequences of this shift is that renewable generation can both suppress and amplify electricity prices within the same day.

Abundant solar production can create periods of exceptionally low wholesale prices during daylight hours.

As that production fades, prices can rise quickly as the grid replaces those resources with generation capable of responding in real time.

For businesses that operate primarily during daylight hours, those lower-priced periods may provide meaningful economic benefits.

But facilities with continuous electricity demand don’t have that flexibility.

They consume electricity when prices are low.

They also consume it when prices are high.

Looking at recent North Hub block pricing, that distinction is becoming increasingly important. While daytime prices continue to benefit from strong renewable production, both on-peak and off-peak pricing have shown upward pressure over time, reflecting a market that is evolving rather than simply becoming cheaper.

For large, continuous-load facilities, the question is no longer whether renewables reduce prices.

The more relevant question is how the changing shape of prices aligns with the way their business consumes electricity.

Data Centers Experience Both Sides of the Duck Curve

Most discussions around the duck curve focus on the grid.

Data centers experience it as an operating cost.

Unlike many commercial facilities, data centers don’t scale their electricity consumption around the availability of renewable generation. Their demand is largely continuous, with servers, cooling systems, and supporting infrastructure operating every hour of every day.

That means they participate in every pricing regime the market produces.

When solar generation is abundant and wholesale prices soften during the afternoon, data centers benefit alongside everyone else.

When solar output falls, net load rises, and more expensive generation is dispatched to meet demand, those same facilities continue consuming electricity through the highest-priced hours of the day.

The economics are fundamentally different from businesses whose operations are concentrated within traditional working hours.

For continuous-load facilities, the shape of electricity prices can become just as important as the average price itself.

A Structural Trend, Not an Isolated Event

That distinction becomes increasingly relevant when looking at where new electricity demand is being built.

North Texas has emerged as one of the country’s fastest-growing markets for data center development, with a significant concentration of announced projects connecting within the ERCOT North Hub. Similar growth is occurring around Houston and Central Texas, but the Dallas-Fort Worth region has become one of the primary focal points for hyperscale and AI infrastructure.

This isn’t simply adding more demand to the grid.

It’s adding demand that is remarkably consistent.

Unlike many industrial processes or commercial operations, large data centers don’t meaningfully reduce consumption overnight. Their electricity demand remains relatively stable regardless of whether it’s noon or midnight.

As a result, they are exposed to every hour of the market, not just the favorable ones.

That reality is becoming more important as the difference between midday and evening price formation continues to evolve.

The conversation is no longer just about how much electricity a facility consumes.

It’s increasingly about when it consumes it, and how that consumption aligns with the changing behavior of the grid.

If these structural changes are becoming more pronounced, the next question is whether the market recognizes them.

Looking at forward prices, recent block pricing, and the widening spread between Day-Ahead and Real-Time markets, the answer appears to be yes.

The Market Is Already Pricing This Reality

Structural changes to the grid rarely stay confined to engineering discussions.

Eventually, they begin appearing in market prices.

That’s increasingly what we’re seeing across ERCOT.

Looking at recent North Hub pricing, wholesale electricity is no longer simply becoming more expensive, it is becoming more dynamic. Midday prices continue to benefit from abundant solar generation, while evening and overnight hours are exhibiting greater price persistence than many buyers have historically expected.

For facilities operating around the clock, those overnight hours aren’t incidental.

They’re part of the cost structure.

Volatility Doesn’t End When the Sun Sets

One observation from recent North Hub block pricing is that off-peak electricity prices have remained surprisingly resilient.

Historically, overnight hours often represented some of the least expensive periods of the day. Today, those hours are increasingly influenced by a combination of growing baseload demand, changing renewable output, transmission constraints, and the resources required to balance the system after solar production declines.

For a manufacturing facility that shuts down overnight, that trend may have limited financial significance.

For a data center operating at a consistently high load factor, those hours represent thousands of megawatt-hours of annual consumption.

As the shape of prices changes, so does the value of understanding how a facility’s load profile aligns with the market.

The Difference Between Expectation and Reality

The widening spread between Day-Ahead (DA) and Real-Time (RT) prices tells a related story.

On July 22, Real-Time prices climbed dramatically during the evening ramp, materially exceeding prices established in the Day-Ahead Market only hours earlier.

That spread isn’t necessarily evidence that the Day-Ahead Market is “wrong.”

Rather, it illustrates the challenge of forecasting a system increasingly influenced by rapidly changing renewable output, weather conditions, and real-time operating constraints.

As the grid becomes more dynamic, electricity prices become more responsive to changing conditions.

For buyers, that reinforces an important principle:

Procurement isn’t only about securing a competitive price.

It’s also about understanding how contract structure allocates exposure to those market dynamics.

Some contracts transfer much of that volatility away from the customer.

Others pass portions of that risk directly through.

Understanding the difference is becoming just as important as understanding the quoted rate itself.

Markets Don’t Just Price Today. They Price Expectations.

Forward markets provide another perspective.

Unlike spot markets, which reflect current operating conditions, forward prices represent what market participants collectively expect future electricity to cost.

Across the North Hub, forward contracts remain substantially above their historical lows, with some delivery years among the most elevated relative to history of any major U.S. wholesale market.

Forward markets are not predictions.

They’re expectations, constantly adjusting as new information becomes available.

But they do suggest something important:

The market is not behaving as though today’s conditions are temporary.

Participants are assigning value to a future where electricity demand continues to grow, renewable penetration continues to increase, and managing reliability becomes increasingly complex.

For businesses making multi-year procurement decisions, that distinction matters.

The relevant question isn’t whether electricity prices will rise every year.

It’s whether delaying procurement places your business into a market that may become progressively more expensive over time.

The Grid Is Changing. Strategy Should Change With It.

The duck curve is often presented as an engineering problem.

In reality, it’s becoming an economic one.

As renewable generation continues expanding across Texas, the market is becoming increasingly capable of producing two seemingly contradictory outcomes at the same time:

Periods of abundant, low-cost electricity.

Periods of elevated prices and greater volatility.

Neither is inherently good or bad.

They are simply characteristics of a grid whose generation mix is evolving.

For businesses, particularly those operating continuous electrical loads, the implication isn’t that electricity is becoming prohibitively expensive.

It’s that electricity is becoming less uniform.

The value of a kilowatt-hour increasingly depends on when it’s consumed, how it’s purchased, and how exposure to market risk is structured.

That represents a meaningful shift from the procurement environment many organizations became accustomed to over the past decade.

What This Means For Buyers

Markets don’t ask businesses to adapt.

They simply change.

The organizations that consistently achieve better procurement outcomes are rarely those that predict the market perfectly.

They’re the ones that understand the market they’re participating in.

As ERCOT continues adding renewable generation, battery storage, and large flexible loads, buyers should expect electricity markets to become increasingly dynamic rather than simply more expensive.

That changes the questions worth asking during procurement.

Instead of asking only:

“What’s the lowest rate available today?”

Businesses may increasingly benefit from asking:

• How does our load profile interact with today’s market?

• Which hours create the greatest economic exposure?

• Does our contract structure reflect how our facility actually consumes electricity?

• What risks are we retaining and which are we transferring?

• How should today’s forward market influence procurement timing?

Those questions don’t eliminate uncertainty.

But they can improve the quality of the decisions made within it.

A Final Thought

One of the more interesting aspects of electricity markets is that they don’t care whether participants understand them.

The same forces that shape wholesale prices; weather, generation availability, transmission constraints, demand growth, and market expectations, will influence procurement outcomes regardless.

Our view is simple.

Businesses shouldn’t need to become ERCOT analysts to make informed energy decisions.

They should have access to the context, market intelligence, and analytical tools necessary to understand how those forces affect their own operations.

That’s ultimately why we study these markets.

Not to predict every price movement.

But to help businesses make better decisions in markets that continue to evolve.

Subscribe now

About Polaris

The Grid Letter is published by Polaris, an energy intelligence infrastructure platform focused on maximizing cash flow through better power economics for commercial electricity procurement in Texas.

We believe businesses deserve greater visibility into the markets that shape one of their largest operating expenses.

Every article we publish, every analysis we produce, and every assessment we deliver is built around the same objective:

Help businesses better understand the market before they enter it.

Access Polaris

If you’d like to see how these market dynamics apply to your own facility, Polaris provides economic power reports built from historical interval usage data, the same information commercial electricity suppliers use to evaluate your business during procurement.

Because better procurement doesn’t begin with better prices.

It begins with a better understanding of your purchasing position.

Read more from us

Section 1 — The Market Changed

For the last several weeks, I’ve been comparing historical ERCOT hub prices against something entirely different: what has physically changed on the Texas grid since 2022.

At first, the data didn’t make much sense.

Texas has added thousands of megawatts of solar. Battery storage has become a meaningful part of grid operations. Peak electricity demand continues to set new records, and data center development has accelerated into one of the largest sources of projected load growth the market has ever seen.

On paper, those changes suggest a market becoming increasingly constrained over time.

Yet earlier this year, ERCOT forward power contracts were trading near their lowest levels in years.

That isn’t necessarily a contradiction.

It’s a reminder that electricity markets don’t price today’s conditions, they price expectations of the future.

Looking across the forward curve, the market appears to have viewed the rapid growth in renewable generation and storage as sufficient to offset much of the near-term demand pressure. But markets are dynamic. Expectations evolve as new information arrives, and those same forward contracts have already begun moving higher from their lows.

That raises a more interesting question than whether electricity prices are “high” or “low.”

What exactly is the market repricing?

Because once you begin looking beneath the average price, it becomes clear that the Texas electricity market hasn’t simply become cheaper or more expensive.

It’s become structurally different.

Section 2 — The Shape of Electricity Prices Has Changed

One of the more interesting discoveries wasn’t that electricity became cheaper.

It was when electricity became cheaper.

For years, the traditional assumption in ERCOT was straightforward: the afternoon and early evening carried the highest value. That’s when demand was elevated, system flexibility was limited, and suppliers priced the greatest amount of risk.

That relationship has changed.

Between 2023 and today, average prices during the historical peak window (HE14–20) have fallen by roughly 72%, while prices during the remaining hours have changed far less dramatically. The result is a market with a much flatter daily pricing profile than it had only a few years ago.

That isn’t happening by accident.

Texas has added thousands of megawatts of utility-scale solar, dramatically increasing electricity supply during the middle of the day. At the same time, battery storage has begun shifting energy into the evening hours, helping reduce some of the price pressure that historically defined the afternoon peak.

The important takeaway isn’t that volatility has disappeared, it hasn’t.

It’s that the market is expressing volatility differently than it did just a few years ago.

Average prices tell us what electricity costs over time.

The shape of prices tells us when the market is under pressure.

For anyone responsible for buying electricity, that distinction matters. Procurement decisions aren’t made against an annual average. They’re made against the hourly risk profile suppliers expect to manage over the life of a contract.

Section 3 — Suppliers Don’t Price Average Electricity

One lesson kept appearing as I compared year after year of ERCOT pricing data.

Average prices tell you what electricity usually costs.

They tell you almost nothing about how risky the market is to serve.

Imagine two years with the same average price.

One reaches that average through relatively stable daily pricing.

The other reaches it because a handful of hours trade hundreds or even thousands of dollars above normal.

From a procurement standpoint, those are entirely different markets.

Looking at the frequency of higher-priced hours, the shift becomes much clearer.

Between 2023 and 2025, the number of hours settling above $200/MWh fell by more than 90%. That wasn’t simply a cheaper market, it was a market that experienced far fewer periods of acute stress.

That distinction matters because suppliers don’t hedge an annual average.

They hedge uncertainty.

Every commercial electricity quote reflects an opinion about what the market could do over the next several years. Forward prices are one input. But so are scarcity events, congestion, weather risk, customer load shape, and the probability that those risks occur while a facility is consuming power.

Two businesses can consume the same amount of electricity each year and still receive materially different pricing because they expose a supplier to different types of market risk.

That’s why procurement is rarely just a comparison of cents per kilowatt-hour.

It’s an exercise in understanding how your operation interacts with the market when conditions are no longer average.

Section 4 — Understanding Your Position Before You Go to Market

One idea has become increasingly difficult to ignore while studying ERCOT.

Commercial buyers and suppliers often enter the same procurement process with very different levels of market context.

The supplier already understands the forward curve they’re hedging against. They have a view on volatility, expected congestion, weather risk, and how a customer’s historical consumption affects the economics of the contract they’re about to offer.

Most buyers don’t.

They see a quoted electricity rate.

The supplier sees a risk profile.

That difference doesn’t imply suppliers are doing anything wrong. Pricing uncertainty is part of their business. The challenge is that many buyers negotiate without first understanding how their own facility appears from the other side of the table.

That’s the question we’ve been trying to answer at Polaris.

Rather than beginning with supplier quotes, we start by building an Economic Power Report from a facility’s historical interval usage. The objective isn’t to predict the market or identify the “lowest” supplier. It’s to understand how the facility interacts with today’s market structure before procurement begins.

That means asking questions like:

• Does this facility consume heavily during the hours suppliers perceive as highest risk?

• How consistent is its load profile throughout the year?

• How has the market changed since its current contract was signed?

• Does today’s forward market create a stronger buying position than the current agreement reflects?

Those questions create context.

And context leads to better procurement decisions.

Sometimes that results in measurable savings.

Sometimes it simply provides confidence that an existing contract remains competitive.

Both outcomes have value because they’re grounded in market understanding rather than assumptions.

Conclusion — The Market You Buy Isn’t the Market You See

When I first started studying ERCOT, I thought procurement was primarily a pricing exercise.

Find the right supplier.

Negotiate the right contract.

Lock in the lowest rate.

The more time I’ve spent studying historical prices, forward markets, and the physical changes occurring across the Texas grid, the less I believe that’s true.

Procurement is ultimately an exercise in understanding where your liquidity (load) sits within a changing market.

Not every business is entering today’s market from the same starting point.

Some companies are renewing contracts signed in 2023, when forward prices reflected a very different set of market expectations.

Others are rolling off agreements negotiated during the elevated pricing environment of 2021 and 2022.

Meanwhile, new facilities are entering the market for the first time, buying electricity under an entirely different set of supply, demand, and forward pricing dynamics.

They’re all purchasing electricity.

They’re just purchasing it from different economic positions.

At the same time, suppliers typically have far more market context than the businesses they’re quoting. They understand forward markets, historical volatility, congestion, load shape, and how each facility’s consumption profile influences the risk they’re assuming. That informational advantage naturally becomes part of every quote they produce.

For buyers, that changes the objective.

The question isn’t simply, “Who has the lowest rate?”

It’s, “What is my position within today’s market, and how does that influence the price of my power consumption?”

That realization has shaped how we’re building Polaris.

Before comparing supplier offers, we believe businesses should first understand their own Economic Power Position, how their historical usage, contract timing, and load characteristics fit into today’s market.

The purpose of an Economic Power Report isn’t to tell a business what decision to make. It’s to provide the market context needed to make that decision with greater confidence.

Because better procurement doesn’t begin with collecting quotes.

It begins with understanding the market you’re entering, and the position you’re entering it from.

Get Free Economic Power Report

Read More From thegridletter

Subscribe now

Texas Electricity Has Entered A Different Era

For much of the past decade, commercial electricity procurement was largely a pricing exercise.

Businesses gathered supplier quotes, compared contract terms, and selected the offer that best matched their objectives.

That approach worked in a market where electricity supply consistently outpaced demand and pricing remained relatively stable.

Today, the economics of Texas electricity are changing.

Population growth, industrial expansion, electrification, and unprecedented demand from data centers are increasing pressure on the ERCOT grid. As electricity demand rises, businesses are entering a market with different supply dynamics, greater uncertainty, and a higher cost of getting procurement decisions wrong.

The objective hasn’t changed, businesses still want reliable electricity at competitive prices.

The environment they’re buying into inevitably has.

Texas Is Leading The Nation In Electricity Demand Growth

The numbers help explain why.

According to the U.S. Energy Information Administration, ERCOT is expected to experience the fastest growth in electricity demand of any major U.S. power market through 2026.

Unlike many regional grids experiencing modest increases, ERCOT is being reshaped by multiple structural forces at once:

• Population growth

• Large-scale industrial investment

• AI and data center development

• Manufacturing expansion

• Transportation electrification

Each new megawatt of demand increases competition for generation resources and places greater importance on how electricity is produced, delivered, and ultimately purchased.

Demand growth alone doesn’t guarantee higher electricity prices.

It does, however, create a market where procurement decisions deserve more attention than they did just a few years ago.

Wholesale Electricity Prices Are Trending Higher

Growing demand is only one side of the story.

The other is how the market has responded.

Looking at ERCOT’s Day-Ahead Market (DAM), average first-quarter wholesale electricity prices have increased for two consecutive years. Compared to Q1 2024, average prices were approximately 20.4% higher in Q1 2025 and 23.2% higher again in Q1 2026.

While wholesale markets will always fluctuate from season to season, the broader trend is difficult to ignore: businesses are operating in a market that has become materially more expensive than it was only a few years ago.

For commercial electricity buyers, this changes the economics of procurement.

When wholesale prices were consistently lower, procurement often focused on finding the cheapest supplier.

As wholesale costs increase, even relatively small differences in contract pricing can translate into significant changes in annual operating expenses, particularly for facilities with large or continuous electricity demand like food processors, petrochemical manufactures, cold storage facilities, etc.

The market hasn’t simply become more volatile.

It has become more valuable to understand how your business is being priced.

A Higher-Cost Market Raises the Value of Better Procurement

Higher wholesale prices don’t necessarily mean every business will pay more for electricity.

Commercial electricity contracts are influenced by many factors, including market timing, contract structure, supplier competition, and the characteristics of a facility’s electricity usage.

What the data does suggest is that procurement decisions now carry greater financial consequences than they once did.

When electricity represented a smaller operating expense, inefficiencies in procurement were easier to absorb.

As prices rise, we see those same inefficiencies become increasingly expensive.

The question is no longer simply:

“What electricity rate can we get?”

It’s becoming:

“How competitive is our purchasing position in today’s market?”

The Forward Market Is Telling a Similar Story

Wholesale electricity isn’t only traded for today.

Every day, market participants also buy and sell electricity for future delivery. These forward prices reflect current expectations about where the market may be headed over the coming years.

While forward markets constantly evolve as new information becomes available, they offer valuable insight into how today’s market is pricing tomorrow’s electricity.

Current forward prices for both the Houston Hub and North Hub continue to reflect a market that expects power to remain materially more expensive than the conditions many businesses became accustomed to just a few years ago.

That doesn’t mean prices can’t fall.

It does mean businesses should recognize they’re entering procurement discussions in a different market environment than they were only a few contract cycles ago.

(note: at the time of writing this current forward strips are at lows, signaling a good opportunity to lock in new commercial electricity rates and contract structures.)

Procurement Should Adapt to the Market You’re Buying In

Every electricity contract is negotiated within the context of current market conditions.

Businesses can’t control wholesale electricity prices, but they can control how they approach procurement.

That’s becoming increasingly important as electricity represents a larger share of operating costs across manufacturing, data centers, healthcare, commercial real estate, and other energy-intensive industries.

The objective isn’t to predict where electricity prices will go next.

It’s to understand today’s market well enough to make better purchasing decisions within it.

Because procurement isn’t just about buying electricity.

It’s about buying electricity well.

So, If wholesale prices are changing.…and market conditions are changing...

Then procurement should probably change as well.

That raises a more important question:

What does effective electricity procurement actually look like in today’s market?

Procurement, A Story Of Change

For many businesses, electricity procurement has traditionally followed a familiar process.

A contract approaches renewal.

Suppliers are invited to submit pricing.

Quotes are compared.

A decision is made.

While that approach may still produce competitive offers, it often begins after the most important question has already been overlooked:

How does the market actually value our business?

Every commercial electricity supplier evaluates historical usage before preparing a proposal.

They’re not simply calculating annual electricity consumption.

They’re assessing the characteristics of your facility that influence pricing, including how and when your business consumes electricity, how consistent operations are throughout the year, and the level of risk associated with serving your load.

Those characteristics help determine how your business is priced before the first quote is ever submitted.

The procurement process hasn’t become more complicated.

It’s become more data-driven.

Visibility Creates Purchasing Power

The most informed buyers don’t begin by requesting quotes.

They begin by understanding their position.

Questions such as:

• How competitive is our current electricity contract?

• How does our facility compare to similar electricity users?

• What characteristics of our load influence supplier pricing?

• Does today’s market support going out for procurement?

• Where does our greatest purchasing leverage exist?

These questions are difficult to answer from a monthly electricity bill alone.

They require context.

Because procurement isn’t simply about buying electricity.

It’s about understanding the market you’re buying from—and how that market evaluates your business.

How To Win

Better procurement doesn’t begin with supplier quotes.

It begins with understanding your purchasing position.

Rather than starting with price comparisons, work backward from the characteristics that suppliers use to evaluate commercial electricity buyers.

By understanding those characteristics first, businesses can enter procurement with greater visibility into how the market is likely to price their electricity demand.

01 Analyze Your Historical Usage

Evaluate the same interval electricity data suppliers use during procurement, identifying the characteristics that influence pricing.

02 Create An Economic Report

Benchmark your current purchasing position, identify pricing strengths and weaknesses, and uncover procurement opportunities before entering the market.

03 Run a Competitive Procurement Process

When appropriate, invite suppliers to compete for your business using current market conditions and your facility’s purchasing profile.

04 Improve Financial Outcomes

Better visibility leads to more informed procurement decisions, stronger purchasing power, and improved financial outcomes over the life of an electricity contract.

Skip the manual work and let Polaris run the process for you - no risk.

Get My Economic Power Report

Better procurement doesn't begin with better prices. It begins with a better understanding of your purchasing position.

Dive Into Your Next Lesson Below.

Most Texas businesses know how much they spend on electricity each month.

Far fewer understand why they’re paying that amount.

A commercial electricity bill shows total usage, demand, and the amount due. It doesn’t show the operating characteristics that influence how commercial electricity suppliers evaluate your facility or how your next electricity contract may be priced.

Questions such as:

• When does your facility consume the most electricity?

• How consistent is your electricity demand throughout the day?

• How does your operation change across seasons?

• How exposed are you to ERCOT peak demand periods?

• What does your load profile actually look like?

Those answers aren’t found on your monthly bill.

They’re contained in your historical interval electricity data.

For businesses operating in Texas’s competitive electricity market, that information can usually be downloaded directly from Smart Meter Texas at no cost.

You don’t need to contact your utility.

You don’t need to request the data from your Retail Electricity Provider (REP).

If you’re responsible for a commercial or industrial facility, you can access the same historical electricity usage data suppliers use during the commercial electricity procurement process.

Here’s how.

What Is Smart Meter Texas?

Smart Meter Texas is a secure online portal that allows residential, commercial, and industrial electricity customers to access the data recorded by their advanced electricity meter.

For businesses operating in Texas’s competitive electricity market, the platform provides access to historical electricity usage, interval meter data, and other account information that can be used during a commercial electricity procurement process.

Unlike a monthly electricity bill, Smart Meter Texas shows how your facility consumes electricity over time, not just how much energy was used.

That information is valuable because commercial electricity suppliers often request historical interval usage when evaluating a facility for a new electricity contract.

Whether you’re preparing for a contract renewal, benchmarking commercial electricity rates, or simply trying to better understand your operation, Smart Meter Texas provides direct access to the underlying data at no

What Information Can You Download?

Once you’ve created an account and verified your service address, Smart Meter Texas allows you to download the same historical electricity usage data used throughout the commercial electricity market.

Depending on your meter and account permissions, you can typically access:

• Historical interval electricity usage (15-minute or hourly data)

• Up to 24 months of usage history

• Meter read information

• Your ESI ID (Electric Service Identifier)

• Service address and account details

• Downloadable CSV files for further analysis

For most commercial facilities, the interval usage file is the most valuable data asset.

Rather than summarizing electricity consumption on a monthly bill, it records how much electricity your facility used during each interval throughout the day. This creates a detailed load profile that reveals when your business operates, how consistent demand is over time, and how electricity consumption changes throughout the year.

That historical usage data is commonly requested by commercial electricity suppliers because it provides a much clearer picture of how a facility consumes power than annual energy usage alone.

What Is Interval Electricity Data?

Interval electricity data is a time-series record of how much electricity your facility consumes throughout the day.

Instead of showing only your total monthly usage, an advanced meter records electricity consumption at regular intervals, typically every 15 minutes for commercial customers.

That produces up to 96 readings per day, creating a detailed picture of your facility’s operating characteristics.

This information forms what’s commonly known as your load profile.

Your load profile reveals much more than total energy consumption. It shows:

• When your facility consumes the most electricity

• How demand changes throughout the day

• Whether operations are consistent or highly variable

• Seasonal changes in electricity consumption

• Exposure to peak demand periods

For commercial electricity suppliers, this data provides a far more complete understanding of a facility than annual energy usage alone. Two businesses may consume the same amount of electricity each year, but very different load profiles can lead to different procurement strategies and pricing outcomes.

Understanding your interval electricity data is the first step toward understanding how your business benefits from ERCOTs competitve market.

Why Commercial Electricity Suppliers Request Historical Usage

When your business requests pricing for a new electricity contract, commercial electricity suppliers don’t rely solely on one variable.

They also evaluate how your facility consumes electricity.

Historical interval data helps suppliers assess the operational characteristics of your facility and estimate the risk of serving your load over the life of a contract.

Among other factors, suppliers may evaluate:

• Total annual electricity consumption

• Daily and seasonal usage patterns

• Load factor and operational consistency

• Peak demand exposure

• Variability in electricity usage over time

• Expected purchasing and hedging risk

This helps suppliers determine how your electricity demand aligns with wholesale market conditions and influences the pricing they offer.

For commerical and industrial businesses, the same data provides an opportunity to better understand their purchasing position before entering a commercial electricity procurement process.

Rather than treating historical usage as paperwork required for a quote, it’s more useful to think of it as the foundation for evaluating how your business appears to the electricity market.

What To Do After Downloading Your Data

Downloading your historical electricity usage is only the first step.

The real value comes from understanding what that data reveals about your facility and using those insights to make better procurement decisions.

Most businesses use their Smart Meter Texas data in one of three ways:

1. Renew an Existing Electricity Contract

Many electricity suppliers request historical interval usage before preparing a renewal quote. Providing complete usage data allows suppliers to evaluate your facility more accurately.

2. Run a Competitive Procurement Process

Historical interval data can be shared with multiple commercial electricity suppliers to obtain comparable pricing based on the same load profile. This creates a more consistent procurement process and allows businesses to evaluate offers on equal footing.

3. Analyze Your Load Profile

Historical usage data can also be used to better understand how your facility consumes electricity. Reviewing your load profile may reveal operational patterns, seasonal demand changes, peak usage periods, and other characteristics that influence purchasing strategy.

Regardless of which path you choose, understanding your electricity consumption before entering the market places your business in a stronger position than relying on a monthly bill alone.

Receive Your Economic Position Report

Maximize cash flow through better power economics.

Through Polaris we can transform your historical usage data into a clear assessment of your facility’s purchasing position.

Your economic report highlights load quality, pricing competitiveness, procurement opportunities, and the market dynamics that may influence your next electricity contract.

Your Economic Position Report is yours to keep whether you procure independently or partner with Polaris.

Receive Economic Your Position Report

Dive Into These Next

Most Texas businesses know how much they spend on electricity.

Far fewer know exactly how they consume it.

Your monthly electricity bill may show total usage, peak demand and the amount owed. But it doesn't show the operating characteristics behind that consumption.

Questions like:

• When does your facility consume the most electricity?

• How consistent is your load throughout the day?

• How seasonal is your operation?

• How exposed are you to peak demand periods?

Those answers are contained in your interval usage data.

For most facilities operating in Texas’s competitive electricity market, that data can be downloaded directly from Smart Meter Texas at no cost.

You don’t need to contact your utility.

You don’t need to request it from your electricity provider.

If you’re responsible for a commercial or industrial facility, you can retrieve it yourself.

Here’s how.

What you’ll need

Before getting started, have a recent electricity bill available.

Depending on your account, you may need:

• Your facility’s ESI ID

• Your meter number (via electricity bill)

• Your current Retail Electricity Provider (REP)

• The service or billing address associated with the meter

Your ESI ID identifies the physical electricity service location. It is different from your account number.

Step 1 — Visit Smart Meter Texas

Go to: SmartMeterTexas.com

If your facility already has an account, sign in.

If not, register using the requested account information.

Step 2 — Verify your meter

After logging in, confirm your facility’s meter appears in your account.

If it does not, follow the prompts to add it using the information from your electricity bill.

If your organization operates multiple facilities or meters, repeat the process for each service location.

Step 3 — Export your usage data

Select the meter you want to export.

Choose the available report or export option.

When prompted, select:

15-minute interval energy data

Avoid exporting only monthly billing information.

Monthly bills show what happened.

Interval data shows how it happened.

Step 4 — Select your history

Choose the longest historical period available.

For many commercial facilities, this may include up to approximately 24 months of interval data.

A longer history captures:

• Seasonal operating changes

• Summer and winter demand patterns

• Production variability

• Planned shutdowns

• Load growth

• Unusual operating events

The more representative the history, the better the analysis.

Step 5 — Download the CSV

Export the report as a CSV.

Depending on the report size, Smart Meter Texas may generate the file immediately or make it available once processing is complete.

Upload the original CSV where you want to serve it without changing its structure.

Looking for power savings? Upload your load data to see what you could be saving.

Get Your Load Quality Assessment

Why interval data matters

Two facilities can each consume 5 MW on average while representing very different operating profiles.

One may operate continuously with a stable baseload.

Another may experience large daytime swings, seasonal production cycles or sharp demand spikes.

Those differences influence energy decisions because they change how suppliers evaluate and price the opportunity.

Interval data allows buyers to understand characteristics such as:

• Load factor

• Baseload consistency

• Peak demand exposure

• Operating schedule

• Seasonal variability

• Demand volatility

• Overall load profile

In other words, it explains how your facility consumes electricity, not simply how much.

Your data. Your decision.

Downloading your interval data does not begin a sales process.

It does not change your electricity provider.

It does not obligate you to sign a new contract.

It simply gives you access to the same operating information used throughout the procurement process.

If you’d like a second set of eyes, Polaris offers Load Quality Assessments for commercial and industrial facilities. Which can be used independently to source better Texas electricity rates.

Upload your Smart Meter Texas interval data and we’ll benchmark your load profile, explain what the data says, and help you understand how it may affect procurement options through our network of retail electricity providers, including companies such as NRG, Constellation and ENGIE.

Whether you use that information yourself or decide to work with us is entirely your decision.

The objective is simple:

Turn your usage into a competitive advantage to save on power cost.

01.

The spread as scorecard

Between June 11 and June 17, Texas energy markets told a story.

On June 14–15, Real-Time price spiked to roughly $67/MWh while Day-Ahead sat well below it. A day later, the gap reopened: Real-Time near $70/MWh against a Day-Ahead forecast that hadn’t anticipated it. In between those two spikes, for about a day and a half centered on June 13–14, the two lines nearly overlapped, both drifting in the low $20s to low $30s.

That gap between Day-Ahead and Real-Time is the market’s running estimate of its own forecast error. Day-Ahead prices reflect what generators, load, and weather were expected to do. Real-Time reflects what they actually did. When the two diverge sharply, something in the forecast broke down and increasingly in ERCOT, that something seems to be renewable generation.

02.

What renewables were doing

The period tightest between Day-Ahead and Real-Time; June 13–14, was also a period of relatively low wind and solar output, as you can see on our annotated pricing chart.

Then, moving into June 14 through June 16, ERCOT’s wind generation fell from about 19 GW down to a trough of roughly 3–5 GW, before climbing back to around 20 GW by June 17.

Solar, over the same stretch, kept around its normal daily cycle, rising and falling with the sun.

The timing lines up. Wind bottoms out through June 14–16, the same window in which Real-Time prices twice broke sharply above Day-Ahead expectations.

A wide band of cloud cover was visible over Texas and the Gulf on satellite imagery from June 16, consistent with a weather system moving through the region during this stretch.

Still, the pattern is consistent with what operators have described elsewhere: large-scale weather systems can suppress wind and solar output across wide geographic areas at once, which is a different kind of risk than a single plant tripping offline.

When wind output falls by 15 GW across the fleet, something else has to make up the difference; batteries, gas peakers, or price-responsive demand cutting back. That replacement generation tends to be the most expensive marginal resource available at that hour, which is one reason Real-Time prices can spike well above what Day-Ahead markets priced in.

03.

The tradeoff underneath the chart

None of this argues that wind and solar are bad for the grid.

Averaged across the year, more renewable capacity on the system tends to suppress the prices of power compared to other US power markets due to more supply, near-zero marginal cost, competing down the stack. That’s a big part of why Texas has built as much of it as it has.

The June data is a reminder that average price and price volatility are within the same boat in my opinion. Texas currently had about 35.6 GW of solar, battery, and wind capacity permitted and planned to come online back in 2025, more than double the combined pipeline of California and Arizona for that year.

That buildout in theory is supposed to bring average prices down over time but we’re seeing a different story unfold.

As shown here, power prices have actually increased YoY, and by a pretty measurable margin.

That is the tension worth sitting with: a grid that leans more heavily on wind and solar can suppress prices compared to peer grids while also being more exposed to weather-driven swings at the same time. Both things can be true, equating to overall increases in pricing if that makes sense.

For anyone buying power under a newer contracts in Texas that’s exposed to real time or day ahead pricing; a data center, an industrial facility, a large commercial account, how you source power is now becoming increasingly more important to business operations, especially as ERCOT’s load continues to grow year over year.

Jump into these next

Competitive Procurement - Explained

How ERCOT Prices Electricity — A Plain Language Guide

Within This Issue, We Cover

Section 01 — Why Texas Is a Different Market
Section 02 — What the Forecast Actually Shows
Section 03 — What Competitive Procurement Actually Is
Section 04 — Why Load Size Is an Asset
Section 05 — The Price Signal the Averages Are Hiding
Section 06 — What to Do With This

If you’re new here, start with these:

Competitive Procurement - Official Value Assessment

How AI and Data Centers Are Quietly Reshaping Texas

Section 01

Why Texas Is a Different Market

Texas runs its electricity grid differently from every other state in the country. That sentence gets repeated often enough that it has started to feel like regional pride rather than a functional fact. It is worth being precise about what the difference actually means.

The Electric Reliability Council of Texas, ERCOT, is an independent system operator. It controls approximately 37,000 miles of transmission lines and coordinates the movement of electrons from generation sources to the customers consuming them across one unified market.

Most other states operate through regional transmission organizations that span multiple states and answer to federal jurisdiction. Texas does not. It minimizes its interstate transmission connections deliberately, keeping the vast majority of its grid infrastructure within state lines. The result is that the Federal Energy Regulatory Commission, FERC, has almost no authority over how Texas runs its power market.

The insulation from federal oversight gave Texas the ability to build market structures that other states could not.

It accelerated the adoption of renewable generation by reducing permitting friction. It enabled faster interconnection of new resources. It created a fully competitive wholesale market where thousands of generators, retail electric providers, and large buyers transact in real time. Texas now leads the country in wind generation capacity and is building solar at a pace that is difficult to track quarter to quarter. The market structure made that possible.

What it also created, by design, is a market that rewards participants who understand it and prices those who do not. That asymmetry is not a flaw in the system but instead It is the system working as intended.

Competition requires informed participants on both sides of the transaction. On the supply side, retail electric providers compete aggressively for load. On the demand side, most commercial buyers have never engaged with that competition at all.

Subscribe now

Section 02

What the Forecast Actually Shows

In April 2025, ERCOT presented its long-term load forecast to its board of directors.

The numbers in that document are not projections built on optimistic assumptions. They are the result of ERCOT’s own methodology applied to officer-attested load requests submitted by Texas’s transmission and distribution service providers, adjusted downward using actual observed data on how quickly large loads come online.

Even after those adjustments, the picture is striking. Peak demand on the ERCOT grid sat near 94 GW in 2025. The ERCOT adjusted forecast for 2030 shows that figure rising to approximately 138 GW. The TSP-provided forecast, which includes more aggressive assumptions about data center development, puts 2030 peak demand at 218 GW. The two methodologies disagree on magnitude but they do not disagree on direction.

From 2002 to roughly 2022, ERCOT’s load grew on a relatively linear trajectory. New demand came in gradually, generation kept pace, and the system expanded steadily. The post-2024 curve does not continue that trajectory, it inflects.

The growth rate changes character entirely, driven primarily by a single load category: data centers.

In 2025, data center load in Texas accounted for approximately 8 GW of peak demand.

By 2028, that figure is projected to exceed 40 GW, according to a January 2026 report from Bloom Energy cited by the Texas Tribune. Texas is expected to become the largest data center market in the country within two years, surpassing states like Oregon and California that have tighter restrictions on new gas generation. Data center developers are drawn by available land, relatively inexpensive natural gas, and a regulatory environment that does not slow them down.

By 2030, 1 in 5 data centers nationally is expected to exceed 1 GW in maximum energy demand. By 2035, that number is projected to be 1 in 3.

The grid that commercial businesses operate on today is not the grid they will operate on in five years.

The load composition is changing. The demand curve is changing. The supply margin that buffers against price spikes will come under sustained pressure in ways it has not faced before. This is by no means “speculative”, It is in ERCOT’s own forecast documents, adjusted “conservatively”.

Share

Section 03

What Competitive Procurement Actually Is

Most people who have heard the term competitive procurement interpret it as “shopping around for a lower rate”. That is the surface-level version.

In ERCOT, competitive procurement refers to a structured process in which a commercial or industrial customer’s load profile is taken to the supply market and multiple retail electric providers are asked to compete for that business.

Instead of auto-renewing with an existing provider, or accepting a default rate, or calling one supplier and taking whatever they quote, the buyer puts their load out for competitive bids. The supplier who offers the best combination of price, risk structure, and contract terms wins the business.

Use our free savings calculator | See how much you can save

A broker or procurement advisor manages that process, typically at no direct cost to the buyer. The broker’s compensation comes from the supplier side. What the buyer receives is a structured comparison of competing offers across multiple dimensions: price per kilowatt-hour, contract length, pass-through provisions, demand charge exposure, load shape alignment, basis risk, and seasonal pricing exposure. The goal is not just to find the cheapest number. The goal is to engineer the buyer’s exposure to a volatile market.

Arushi Sharma Frank, an energy policy strategist and procurement specialist who helped bring Tesla’s energy business to Texas and now advises Nvidia-backed companies, put it plainly in a recent conversation: “There’s no other market in the country where an industrial customer can curtail or run on-site generation or use demand response assets where they can cut their annual transmission bill by 25 to 40 percent.” (Source: Redefining Energy Podcast, timestamp: here)

On a $100,000 annual electricity bill, a 25 to 40 percent reduction represents $25,000 to $40,000 in annual savings. That number compounds. Here’s a great post that uses storm Uri 2021 as a case study scenario.

It improves operating margins on every dollar of revenue the business generates. And it comes not from a capital investment or an operational change, but from a procurement strategy.

Think of competitive procurement as insurance with a return. You buy insurance to protect yourself against elevated-cost events you cannot predict. You pay a premium for that protection. In competitive procurement, there is no premium.

You are locking in a below-market rate ahead of anticipated price increases, and the protection is the rate itself. The business that signed a well-structured fixed-price contract before Summer 2025 was not paying more for certainty. It was paying less, and getting the certainty as part of the transaction.

The decision variables in a real procurement engagement are more numerous than most buyers realize: price, risk exposure, timing, basis risk, load shape alignment, contract flexibility, pass-through mechanics, seasonal exposure, and demand profile fit.

None of those variables optimize themselves.

Main takeaway:

A buyer going directly to one supplier sees one offer, structured by the supplier, in the supplier’s interest. A buyer running a competitive process sees multiple offers, structured by competition, and evaluated by someone whose job is to find the best fit for the buyer.

Section 04

Why Load Size Is an Asset

The commercial and industrial buyer occupies a different position in this market than a residential customer. The difference reflects a simple economic reality about how supply-side pricing works.

A retail electric provider makes money on the margin between what it pays for wholesale power and what it charges the end customer. A large commercial account consumes more electricity, generates more revenue, and justifies more aggressive pricing to win the business. A residential customer consumes far less individually.

Offering a residential customer a deeply discounted rate would shrink the supplier’s margin without generating the volume to compensate. The math does not work in the buyer’s favor at small scale.

The relationship is direct: larger load equals more attractive counterparty, which equals more competitive pricing. A business with meaningful electricity consumption is offering something the supply side wants. It’s essentially a form of leverage, and most commercial buyers have never used it.

“Pricing knows no limits nor morality”

Suppliers in ERCOT are sophisticated. They price based on load profiles, demand patterns, contract length, and counterparty creditworthiness. A well-structured commercial account with predictable load is exactly the kind of counterparty that brings out competitive pricing.

The supplier who prices aggressively for that account and wins it has made a business decision that works for them.

The buyer who fails to invite that competition has left money in the market.

See What You Can Save

Section 05

The Price Signal the Averages Are Hiding

Average electricity prices are a useful summary statistic. They are also, in certain conditions, a misleading one.

Houston Hub average prices in Q1 2023 and Q1 2024 were essentially flat: $22.68 per megawatt-hour and $22.52 respectively. By Q1 2025, that average had jumped to $29.65, a 31.7 percent year-over-year increase. The trend is clear but the averages do not show the full picture of what buyers are exposed to.

Within any given quarter in the Houston Hub, maximum spike prices are running 1.5 to 4 times the average. That means a business exposed to real-time or index-linked pricing is not paying the average but the volatility hidden in those averages averages.

North Texas tells an even sharper story.

Average prices in Q1 2026 were $32.18 per megawatt-hour, only modestly elevated compared to prior quarters. But in January 2026, the maximum spike reached $318.

That is a 9.9 times spike-to-average multiple. A buyer with index exposure in that month paid nearly ten times the average rate during the peak interval.

The explanation for the North Texas pattern is geographic concentration. Data center load is clustering in North Texas.

That concentration creates localized transmission constraints. When demand spikes in a geography where supply cannot respond quickly enough, prices spike sharply and briefly. The average stays calm. The tail is violent.

A fixed-rate contract does not eliminate electricity costs, it only eliminates the tail risk.

The buyer on a well-structured fixed contract during January 2026 in North Texas paid their contracted rate. The buyer on an index-linked or pass-through contract experiences a billing event that looked nothing like their average month.

Consider what that looks like in practice. Two businesses. Same geography. Same operational profile. Same energy consumption during that January. The only variable is the contract structure they signed months earlier.

Business A: entered the month on a fixed-price contract, negotiated through a competitive procurement process. Their electricity cost for January was predictable, budgeted, and consistent with prior months.

Business B: The second was on a variable or index-linked rate. Their January bill reflected wholesale conditions during the spike. The same kilowatt-hours that cost one business their contracted amount cost the other business multiples of that, for no operational reason, on no advance notice.

That scenario is a smaller-scale version of what played out during Winter Storm Uri in February 2021.

Wholesale prices hit the ERCOT market cap of $9,000 per megawatt-hour and held there for days. A business consuming 50,000 kilowatt-hours during that period on a normal rate would have expected an energy cost in the range of $4,000.

On wholesale-linked exposure at the market cap, that same consumption represented $450,000 in pricing. The contract structure, signed before any of that was foreseeable, determined the outcome entirely.

Weather changes. Risk doesn’t.

Section 06

What to Do With This

The structural case for competitive procurement in ERCOT is not complicated.

1. The market is built to reward buyers who compete for their supply.

2. The forecast shows that demand pressure on this grid will intensify over the remainder of this decade.

3. The price data shows that volatility is already embedded in the system, episodically and increasingly at the geographic level.

4. The risk of doing nothing is quantifiable, because the market has already produced events that demonstrate what that risk looks like when it materializes.

Three things are worth knowing about your current situation.

First: what rate structure you are currently on. Fixed, index-linked, variable, or some combination with pass-through provisions. Most business owners do not know the answer without pulling their contract. The structure of that contract determines your exposure to everything described above.

Second: when your current contract expires. Rolling into a new contract at peak summer pricing, or defaulting to a variable rate at the wrong point in the demand cycle, is the most avoidable cost in commercial energy management.

Third: whether your load profile has ever been taken to the market competitively. If it hasn’t, you have not tested whether the supply side will compete for your business. In a market where data center operators, industrial facilities, and large commercial accounts are all actively procuring, the buyers who are not participating in that process are the ones the market prices at will.

The ERCOT market was designed around competition. That competition exists on both sides of the transaction. The question is whether your business is using it.

Ready to find out what the supply market will offer for your load? Polaris works with Texas businesses to run a structured, competitive procurement process at no cost to the buyer.

See How It Works At Zero Risk

Sources:

ERCOT. Long-Term Load Forecast Update (2025–2031) and Methodology Changes. Board of Directors Meeting, April 7–8, 2025. ercot.com

Cobler, Paul. “Texas forecast to be top market for data centers in two years, increasing grid demand.” Texas Tribune, January 20, 2026. texastribune.org

Sharma Frank, Arushi. Energy policy strategist, grid systems expert, and procurement specialist. Podcast interview referenced at 6:10 mark.

Subscribe now

Texas electricity markets are in a period of structural transformation.

ERCOT’s own adjusted forecast projects peak demand reaching 154 GW by 2035, nearly doubling from today. Transmission Service Provider (TSP) interconnection queue data suggests the number may be conservative, with some forecasts approaching 227 GW when large load interconnection requests are included.

Data centers alone account for the majority of incremental demand growth, scaling from roughly 3.7 GW of load in 2025 to a projected 86 GW by 2031 in the TSP queue model.

Against that backdrop, the question of whether commercial and industrial buyers should competitively procure their electricity supply, rather than remaining on default utility pricing or direct spot exposure, becomes worth examining carefully.

Not as a sales proposition but as a genuine market question.

The mechanics, plainly stated

Competitive procurement replaces a commercial buyer’s default energy supply arrangement, whether that’s a utility pass-through rate, an index-based contract, or unmanaged spot exposure, with a negotiated fixed or structured supply contract from a Retail Electric Provider. The buyer selects a term, a product type (fixed, indexed, hybrid, block-and-index), and a counterparty.

The REP prices the contract based on current forward curves, informed negotiation, embedded risk premiums, and their own cost-to-serve assumptions.

In ERCOT’s deregulated market, this process is entirely voluntary for commercial accounts above certain thresholds. The competitive market is real. The pricing signals are real.

The question is simply whether the mechanism delivers value, to whom, and under what conditions.

The value of procurement is not binary. It depends on when you do it, what you buy, and whether anyone in the transaction is working from complete information.

For more info;

The Bill Is Coming: Why Texas Business Owners Can No Longer Ignore the Power Market.

A structured assessment across five factors

Share

Where the data is unambiguous

(Note: Q1 is the focal point due to its less volatile nature. You tend to see more raw structural volatility)

The volatility insulation argument is the strongest case for procurement in ERCOT, and the pricing data makes it concrete. HB_Houston’s, the hub capital of the US, maximum daily spike prices ran 1.5 to 4 times average prices within a single quarter across Q1 2023–2025.

HB_North (DFW area hub) recorded a spike-to-average multiple of 9.9x in January 2026, a $318/MWh max against a $32.82 monthly average. These are not tail events in a statistical sense anymore. They are a structural feature of a grid absorbing load concentrations faster than transmission infrastructure can redistribute.

For commercial buyers with continuous, non-deferrable load; manufacturing operations, data center colocation, cold storage, hospitality, this volatility is pure cost variance with no upside.

A fixed supply contract converts that variance into a known, plannable number. Whether that number is “good” relative to what spot would have averaged over the contract term is a hindsight question. Whether it removes budget uncertainty is not.

The economic value of certainty is not equivalent to the economic value of a lower average cost.

For businesses with fixed revenue streams and tight operating margins, predictability has standalone value independent of whether the fixed rate outperforms spot in hindsight.

The two are often conflated in conversations about procurement, usually by parties with an interest in one framing over the other.

Free Savings Calculator | See How Much You Can Save

Where value is real but capture is incomplete

Forward curves already embed market expectations of future scarcity. When a buyer locks a three-year fixed rate in a structurally rising demand environment, they are not escaping that signal, they are buying a point on it. The question is whether they are buying it before or after the market has fully repriced the new demand regime.

The TSP load forecast data, showing data center load growing from 3.7 GW to 86 GW between 2025 and 2031, suggests that full repricing has not yet occurred in long-dated forward contracts.

The market digests this data gradually, through interconnection queue filings, ERCOT planning reports, and REP forward book updates. There is likely a window, though its duration is uncertain, in which forward curves still reflect partial rather than complete demand expectations.

The more persistent limitation is on the execution side. The standard channel through which most commercial buyers access competitive supply, retail brokers compensated by the REP on a per-kWh commission basis, creates an information asymmetry.

Commission structures of $0.002–$0.005/kWh embedded in contract pricing are not disclosed to buyers in most transactions. The incentive created by those structures points toward longer terms and higher-margin products, not necessarily the optimal outcome for the buyer’s load profile and risk tolerance.

The product exists. The market need is genuine. The gap between available value and captured value is almost entirely an information problem, not a market structure problem.

This does not mean procurement fails to deliver value through standard channels. It means a meaningful portion of available value is absorbed in the transaction rather than passed to the buyer.

How much depends on the specific REP, product, term, and market conditions at execution, none of which the buyer can independently evaluate without market data and an informed visibility.

Subscribe now

What makes the current window different

The ERCOT grid has experienced demand growth before.

What is structurally different now is the nature and concentration of the incremental load.

Base residential and commercial load grew roughly 9% over the 2025–2031 forecast window in TSP data. With commercial electricity use will likely surpass residential in 2027: EIA

Data centers, crypto mining, industrial electrification, and hydrogen production account for the remaining growth, load categories that are price-insensitive, geographically concentrated, and highly continuous.

Price-insensitive load does not respond to high prices by curtailing. It bids for supply regardless of clearing price, compressing reserve margins and widening the volatility envelope for all remaining buyers. The HB_North spike multiplication, from 5.3x in 2023 to 9.9x in Q1 2026, is a direct readout of this dynamic.

North Texas, where data center suitability scores and announced projects concentrate most heavily, is already showing the grid stress that the rest of ERCOT will experience over the next several years as load grows and geographic concentration increases.

On timing:

The question of whether to procure is separable from the question of when. In a structurally rising price environment, the timing decision carries real economic consequence.

Buyers who procured in 2022–2023, when HB_Houston averages were in the low $20s/MWh range, are sitting on favorable fixed rates relative to current market.

Buyers evaluating procurement today are pricing against a market that has already absorbed one significant repricing event (+31.7% YoY in Q1 2025) and has not yet fully priced the demand trajectory through 2031.

What the data supports, and what it doesn’t

Competitive procurement scores 7.3 out of 10 in our weighted assessment across the five dimensions most relevant to commercial buyers in ERCOT’s current market.

That is a genuinely high score and the grid data supports it: demand is growing non-linearly, volatility is structurally widening, and the geographic concentration of new load creates localized price stress that will propagate through the system over the next several years.

What the data does not support is the conclusion that procurement is uniformly valuable regardless of how it is executed. The single highest-leverage variable is the quality of information the buyer brings to the transaction.

A buyer who understands their load profile, current forward market conditions, embedded commission structures in REP offers, and the directional demand signal from ERCOT’s own planning data is in a fundamentally different position than one who is not.

The market exists. The value is real. Whether it reaches the buyer depends almost entirely on how the buyer approaches it.

Put It to the Test

Theory is useful. Your own electricity account is more useful.

We’re currently offering a limited number of complimentary Competitive Procurement Audits for Texas commercial and industrial businesses. We’ll review your current position, benchmark it against today’s market, and provide an objective assessment of where opportunities, or risks may exist.

If there’s value to uncover, we’ll show you. If there isn’t, we’ll tell you that too.

Request a complimentary audit → Here

Sources:

• ERCOT Adjusted Long-Term Load Forecast · ERCOT DAM HB_HOUSTON, HB_NORTH historical pricing

• Commercial electricity use will likely surpass residential in 2027: EIA

• TSP Large Load Interconnection Queue (2025)

• GeoTel Data Center Inventory (2024).

• ERCOT sourced RT/DA market data

  ---

TDL analysis reflects publicly available market data as of Q2 2026. This publication does not constitute financial, legal, or energy procurement advice.

Table of Contents

• Section 01 — The Quarter That Wasn’t Just About Weather

• Section 02 — What the Houston Hub Data Actually Shows

• Section 03 — The Load That Is Already in the Ground

• Section 04 — What Most Commercial Buyers Have Never Been Shown

• Section 05 — What NRG Said on May 6th

• Section 06 — What Paying Attention Looks Like Before Summer

Summary

NRG Energy’s Texas segment posted $299 million in Adjusted EBITDA in Q1 2025, a 36.5% year-over-year increase, while Houston hub average electricity prices jumped 31.7% in the same period, after two flat years.

The structural driver is a data center load wave already registered in ERCOT’s interconnection queue and confirmed by ERCOT’s own planning forecasts, with data center capacity growing from zero to 24,195 megawatts by 2031 in the adjusted scenario.

By the time you finish reading, you will understand what that structure is, what it costs businesses operating without that knowledge, and what three things to do with the information before summer peaks set next year’s transmission costs.

If you’re new here, start with these:

The Grid Behind the Lights: Understanding ERCOT and Why Texas Energy Is the Market Most People Sleep On: Here

Why Texas Electricity Prices Spike Every Summer (And What It Costs Businesses Who Wait): Here

Section 01

The Quarter That Wasn’t Just About Weather

NRG Energy’s Texas segment generated $299 million in Adjusted EBITDA in the first quarter of 2025. That is up $80 million from the same quarter in 2024, a 36.5% increase in a single year.

For context, NRG’s Texas business is built on the Reliant brand, which has operated more than a million Houston-area commercial and residential accounts since NRG acquired it in 2009. When Texas performs, it is Houston performing as well.

The explanation NRG offered in its SEC filing is as follows:

“higher economic gross margin, including impact of weather, strong plant performance, and supply optimization.”

Weather appears first. It is a real contributor. But a market explanation that begins and ends with weather misses something the data makes plain.

The Houston hub average electricity price was $29.65 per megawatt-hour in Q1 2025, up from $22.52 the prior year.

Two years of essentially flat averages (Q1 2023 at $22.68, Q1 2024 at $22.52) followed by a jump of nearly one-third in a single quarter. A sign that market structure beginning to register a new load reality.

The NRG earnings are where that structure became visible in financial results. The ERCOT data is where it was already visible to anyone watching.

Section 02

What the Houston Hub Data Actually Shows

The average price is the least useful number in the ERCOT market. It is not wrong, it is just incomplete in a way that consistently misleads buyers.

Here is what three years of Houston hub data shows.

In Q1 2023, the average daily price was $22.68 per megawatt-hour. The maximum daily spike that quarter hit $89, nearly four times the average. In Q1 2024, the average slipped slightly to $22.52 while the maximum spike came in at $64, still close to three times the mean. A business watching headline averages through this window saw stability. What the averages did not show was the envelope around them, the range within which prices could move and did, every single quarter.

Then Q1 2025. Average price: $29.65. Maximum spike: $45, or 1.5 times the average.

The spike magnitude narrowed in dollar terms while the floor moved sharply upward. For a commercial buyer on a pass-through or indexed contract, both facts matter. For a buyer who renewed into a fixed rate during the 2022–2024 low-average window, the Q1 2025 jump represents the pricing environment they are now walking into at renewal.

The forward picture is more explicit.

An EIA analysis published by Utility Dive in March 2026 modeled ERCOT prices rising 79% under a high data center demand scenario by 2027, compared to a 4% increase under the same scenario in PJM, the largest eastern grid interconnection.

The comparison is the point: PJM has neighboring grids to draw from when demand spikes, plus is a capacity market, unlike ERCOT which is a large ISO energy only market.

This means ERCOT operates as an isolated system, which means localized scarcity events have nowhere to dissipate. The EIA number is a modeled scenario, not a contracted outcome. But no comparable analysis models the condition reversing. (Utility Dive, March 16, 2026, citing EIA analysis.)

Share

Section 03

The Load That Is Already in the Ground

Between December 2024 and November 2025, ERCOT’s large-load interconnection queue grew from 63 gigawatts to 226 gigawatts. A 300% increase in only twelve months. Seventy-three percent of the requests in that queue were from data centers.

In 2025 alone, 225 new large-load requests were filed, more than the entire 2022–2024 period combined. The average project size jumped from 415 megawatts to 725 megawatts, with many now exceeding one gigawatt.

ERCOT VP Kristi Hobbs said publicly in December 2025 that the grid had “outgrown the process.”

Not all of that queue will materialize though of course. ERCOT, Latitude Media, and market analysts have all noted the phantom load problem, speculative requests that inflate the queue without corresponding to real projects.

The article’s argument does not require 226 gigawatts to arrive. It requires enough to strain the grid.

ERCOT’s own Capacity, Demand and Reserves report uses an adjusted forecast that already discounts for attrition. The adjusted scenario shows data center large-load additions growing from essentially zero today to 6,660 megawatts in 2027 and 24,195 megawatts by 2031, the single largest large-load category by 2027.

ERCOT’s adjusted peak demand forecast grows from 85,199 megawatts in 2024 to 154,077 megawatts in 2035.

Subscribe now

Those abstract numbers have concrete, public, addresses. Check them out here: Houston Data Centers Map

At 15555 Cutten Rd in Houston’s Cypress Creek corridor, near the former Compaq headquarters, in the middle of an established tech cluster, Serverfarm’s CTX2 campus is in the final months of a twelve-month build.

TDLR permit TABS2025014250.

Filed March 2025. Construction window July 2025 through July 2026. Four hundred thirty-eight thousand square feet. A 60-megawatt AI-ready campus built for rack densities above 50 kilowatts per rack. Structural topping out completed January 2026.

These are named facilities at real addresses commissioning into the Houston hub this summer, Serverfarm is jus one of at least 62 data centers already operating in the Houston metro. More are behind it.

The analogy that fits this moment is the early years of shale production in the Permian Basin. The volumes themselves were not immediately the headline, the infrastructure response to those volumes was. Pipelines and processing capacity took years to catch up with production, and during the lag, pricing diverged in ways that created asymmetric costs for buyers and asymmetric margins for sellers.

The Texas grid is in a similar lag. Load is arriving faster than generation and transmission can absorb it. That gap is where the volatility and risk live.

The reserve margin trajectory confirms it: ERCOT’s CDR projects 17.2% for summer 2026, falling to 9.0% in 2027, and turning negative at -4.4% in 2028. (ERCOT CDR, May 2025 update.) Negative reserve margin does not mean the lights go out, it means the grid has no cushion when the unexpected arrives.

Texas Senate Bill 6, signed in June 2025, addresses the structural problem the article describes: new interconnection requirements, cost-sharing protocols, mandatory curtailment provisions for large loads above 75 megawatts.

Frame it for what it is:

confirmation that the problem is real enough to require legislation. PUCT rulemaking under SB6 extends to December 2026. Commercial buyers are not yet on the other side of it. (Yes Energy, February 2026.)

Want to add to the discussion? Feel free to leave a comment.

Leave a comment

Section 04

What Most Commercial Buyers Have Never Been Shown

The Texas electricity market is not opaque by design. It is opaque because it was built for a different era of load and because information does not travel through it symmetrically.

Suppliers track the forward curve as a matter of daily business. Most commercial buyers do not.

The result is a structural gap between what a buyer typically sees when a contract comes up for renewal, a quote from an incumbent supplier and what a full competitive market process produces.

See How Much You Can Save ↓

Free Savings Calculator

The incumbent has no incentive to price at the bottom of what they would accept, and the buyer has no reference point unless they generate one by soliciting competing offers against the same load data and the same contract terms.

The gap between a single-source renewal and a multi-supplier competitive process is not always material. In a market where the structural floor has moved up 31.7% in a year, it usually tends to be.

Beyond the commodity price, most commercial buyers in Texas do not have clear line-of-sight into the cost components that sit alongside the energy itself.

Demand charges are determined by your own behavior, not the market average. A single fifteen-minute interval of peak consumption can set a demand level that is billed for the entire month. The charge is on your bill but the mechanism that drives it often is not explained.

4CP transmission costs (the Four Coincident Peaks) are how ERCOT determines each customer’s share of statewide transmission infrastructure costs for the following year. Your load during the four highest demand hours on the ERCOT grid each summer sets your transmission allocation for the next twelve months.

Those hours occur somewhere in the June-through-September window. They are not announced in advance. They are determined by when peak industrial, data center, and weather-driven demand converge on the same afternoon.

Capacity charges are the cost of maintaining reserve generation, the buffer the grid keeps available for peak conditions. These are allocated to load-serving entities and passed through to customers, often embedded in contract pricing without a dedicated line item.

A business that does not know what its 4CP exposure looks like before summer is, as a practical matter, flying without instruments into the window that sets next year’s transmission costs. That is not a failure of the individual buyer. It is a function of what the market makes legible and what requires deliberate effort to find.

Share TheGridLetter

Section 05

What NRG Said on May 6th That’s Shocking

Three weeks before this article went to production, NRG held its Q1 2026 earnings call. The Texas segment had a rough quarter by comparison, $216 million in Adjusted EBITDA versus $299 million in Q1 2025.

The reason, per CFO Bruce Chung on the call:

“Houston on-peak prices averaged $29 per megawatt hour, down approximately 13% from last year. Texas experienced the impact of unfavorable weather on our home energy volumes as well as lower average power prices and minimal market volatility.”

Heating degree days were down 30% year-over-year. A mild winter.

The Chung quote continues:

“favorable weather was a big factor in making 1Q 25 a record first quarter for NRG, thereby making the year over year comp for 1Q 26 more challenging.”

That is the structural argument in a single CFO sentence: the Q1 2025 outperformance was real, the Q1 2026 softness is weather, and the base trend is intact. The EBITDA dip and the structural thesis are not in tension. They are the same story told from opposite ends of a weather coin.

Then CEO Robert Gaudette spoke about where the market is heading.

NRG has signed data center retail power agreements targeting front-of-meter pricing at $90 to $95 per megawatt-hour. Behind-the-meter structures imply levelized revenue in the range of $150 per megawatt-hour. (NRG Q1 2026 Earnings Call, May 6, 2026.)

The Houston on-peak average in the same quarter was $29 per megawatt-hour. The spread between $29 and $90 is not the result of one company’s pricing power. It is the result of a grid that cannot easily expand supply to meet the demand curve being priced in those contracts.

Gaudette cited ERCOT’s preliminary long-term load forecast on the call: large-load requests reaching 367 gigawatts by 2033, “more than four times today’s record peak in under a decade.”

He then said:

“even if a fraction of what is in that pipeline arrives on those timelines, this market looks fundamentally different from the one we’re operating in today.”

That is the largest retail energy provider in Texas, on a public earnings call, stating the thesis of this article in plain language.

The 4CP window opens June 1st. It runs through September 30th. NRG’s own guidance for 2026 full-year performance was reaffirmed on that same call. The company has not changed its view of the summer ahead.

Section 06

What Paying Attention Looks Like Before Summer

Three things separate a business that is positioned for this market from one that is not.

1. Know what you are currently paying, not the blended rate on the bill, but the component breakdown: energy commodity, transmission and distribution, demand charges, and any pass-through costs embedded in the contract.
   
   Most businesses can produce a per-kilowatt-hour number. Fewer can identify what portion of that number is 4CP-sensitive and what it will cost them if this summer’s peaks are anything like Q1 2025.
   

2. Know when your contract expires. Fixed-rate contracts renewed during the 2022–2024 flat-price window locked in rates when the structural conditions described in this article had not yet registered in market pricing.
   
   Those contracts are coming off. The renewal quotes arriving now reflect the market as it currently exists. Running a competitive quoting process, soliciting prices from multiple suppliers against the same load data and the same contract structure, is what gives you a reference point to evaluate those quotes against. That is not a sophisticated procurement strategy. It is the minimum due diligence in a market where the structural floor moved 31.7% in a single year.
   

3. Know what your demand exposure looks like before the 4CP window closes. Your load during the four peak hours this summer heavily determines your transmission cost allocation for the following year. That exposure can be audited before the window opens. Once it closes, the number is set.

Most commercial buyers in Texas are not doing all three of these things.

That is not a criticism. The market does not make them easy to do, and the consequences of not doing them tend to appear at renewal rather than in real time.

The businesses paying attention to their 4CP load profile in May and June are operating with information that most of their peers will not have until October (or ever at that), when ERCOT publishes the coincident peak data.

The Texas electricity market is not designed to be easy for buyers. Understanding the structure is the advantage.

See How Much You Can Save

TheGridLetter covers what is actually happening in the Texas electricity market; grid conditions, pricing mechanics, procurement strategy, and load growth, one issue per week.

This piece is one of the first in a series on how Texas businesses are navigating the current market.

For those curious about what competitive procurement is read this: [post]

Don’t forget to share!

Sources:

• NRG Q1 2025 SEC Form 8-K — https://investors.nrg.com/static-files/e557d982-0a0a-4fc7-af3e-c9fd28e868ab

• ERCOT Large-Load Queue (Utility Dive, Jan 2026) — https://www.utilitydive.com/news/ercots-large-load-queue-jumped-almost-300-last-year-official/808820/

• Serverfarm CTX2 TDLR Permit — https://www.tdlr.texas.gov/TABS/Search/Project/TABS2025014250

• ERCOT CDR Report (Feb 2025) — https://www.ercot.com/news/release/02132025-ercot-releases-capacity

• ERCOT Large Load Interconnection Q&A (Dec 2025) — https://www.ercot.com/files/docs/2025/12/24/Large-Load-Interconnection-Process-Q-A.pdf

• NRG Q1 2026 Earnings Call Transcript (May 6, 2026) — https://www.sahmcapital.com/news/content/transcript-nrg-energy-q1-2026-earnings-conference-call-2026-05-06

• EIA / 79% price hike analysis (Utility Dive, March 2026) — https://www.utilitydive.com/news/data-center-demand-spike-could-drive-79-ercot-price-hike-in-2027/814804/

• Houston data centers aggregator — https://www.datacentermap.com/usa/texas/houston/

  ---

  Thanks for reading TheGridLetter! This post is public so feel free to share it.

  Share

  ---

Table of Contents

• Section 01 — The Numbers That Changed Everything

• Section 02 — What The Data Actually Shows

• Section 03 — Why This Isn’t A Temporary Spike

• Section 04 — What The Market Doesn’t Make Easy To See

• Section 05 — What The Grid Is Doing Right Now

• Section 06 — What Paying Attention Looks Like

Summary

The ERCOT large-load interconnection queue grew nearly 300% in a single year from a base that was already unprecedented and data centers now account for more than 70% of the 233+ gigawatts waiting in line.

That concentration exists because Texas spent decades removing the friction that slows grid growth everywhere else in the country.

Commercial, industrial, and residential buyers who signed contracts before this demand curve became visible are approaching renewals in a market that no longer resembles the one that priced those deals.

If you’re new here, start with these:

How ERCOT Prices Electricity — A Plain-Language Guide

Understanding 4CP: Why Texas Electricity Prices Spike Every Summer

Section 01

The Numbers That Changed Everything

Texas didn’t just get “lucky” with data centers. It built the conditions for them decades ago.

The result of that construction is now visible in a single dataset: ERCOT’s large-load interconnection queue.

By the end of 2025, it held more than 233 gigawatts of pending requests. Data centers account for over 70% of that total. One year earlier, the queue was a fraction of that size, meaning it grew nearly 300% in twelve months alone.

For context, Texas’s current real-time grid load runs around 64 gigawatts. The queue represents demand requests that, if fully built, would require the grid to support three to four times what it serves today.

Most commercial electricity buyers in Texas are aware that something is happening with the grid.

Fewer understand that the structure of the market has already shifted around them. The queue isn’t just a forecast though, It is a signal of where demand is heading and the pricing implications are already appearing in real-time settlement data.

Section 02

What The Data Actually Shows

The load forecast numbers are large enough to require grounding before they land.

ERCOT’s own adjusted planning forecast shows peak demand rising to approximately 138 gigawatts by 2030 and 154 gigawatts by 2035. The TSP-provided forecast, a separate scenario developed from utility transmission service providers, puts the upper bound at 218 gigawatts by 2030.

These two numbers should not be averaged or split. They represent a genuine range of uncertainty. ERCOT itself discounts data center requests in the adjusted forecast by roughly 73% from maximum demand, to account for ramp uncertainty and what the industry calls “phantom” load, speculative interconnection requests that may never materialize.

The lower-bound scenario is plausible. So is the upper. The honest answer is that no one knows exactly how much of this queue becomes real load, or how fast.

What is not uncertain: the direction.

Historical ERCOT peak demand was flat for more than two decades, plateauing in the 75–85 gigawatt range from 2002 through 2024. The forecast inflects sharply starting in 2025. Annual energy consumption is projected to more than double, from approximately 461,000 gigawatt-hours in 2024 to roughly 1.14 million gigawatt-hours by 2035.

Now, pricing knows no limits nor morality therefore it’ll always be a reliable indictor of economic and systematic stress.

At Houston Hub (HB_HOUSTON), Q1 average settlement point prices rose 31.7% between 2023 and 2025, from $22.68 per megawatt-hour to $29.65. That is not a spike. That is a rising average, which is a different and more durable problem.

The North Hub tells a sharper version of the same story. In January 2026, HB_NORTH posted a spike-to-average multiple of 9.9 times. The average settlement price for the period was $32.18 per megawatt-hour. The intra-period maximum hit $318. That multiple, nearly ten dollars of maximum price for every one dollar of average, does not happen in a grid with comfortable reserve margins and short-term stability.

The delta between a commercially-locked fixed rate and spot exposure is going to widen over the 2025–2030 window.

That is not because spot prices will spike on every trading day they won’t. It is because the floor is rising and the ceiling is getting higher.

Both movements work against unhedged buyers.

Share

Section 03

Why This Isn’t A Temporary Spike

The standard mental model for electricity price spikes treats them as weather events. Something causes unusual demand. Prices jump. The event passes. Prices fall back.

That model doesn’t apply here.

Texas built its grid advantages intentionally, over decades, through a specific set of structural choices. ERCOT is an intrastate ISO, a single entity operating more than 37,000 miles of transmission lines entirely within Texas. Because the system doesn’t cross state lines in a meaningful way, it sits outside FERC jurisdiction. (FERC, Federal Power Act exemption documentation) The Public Utility Commission of Texas and the Texas Legislature are the relevant regulators, not boards in Washington. That regulatory insulation allowed Texas to move faster on generation interconnection, price discovery, and market structure than any other region in the country.

The interconnection speed differential is the clearest illustration. PJM’s average application-to-commercial-operation timeline ran under two years in 2008. By 2025, that same process took over eight years. (RMI, February 2026; Grid Strategies Generator Interconnection Scorecard, March 2024)

ERCOT, through 2023, averaged 22.2 months, compared to CAISO’s 43.4 months and PJM’s 24.4 months at the time. (Clean Power Association Interconnection Fact Sheet, 2023) Faster interconnection meant more generation built sooner. More generation meant competitive retail pricing. Competitive retail pricing meant lower costs for large consumers. Lower costs attracted hyperscale buyers. Their arrival drove more generation investment. The loop fed itself.

That positive feedback loop is now self-stressing. The data center queue has outgrown the process designed to absorb it. ERCOT VP Kristi Hobbs said it directly in December 2025: “We have outgrown the process.”

The median battery storage project timeline has stretched from 3.5 years to 4.1 years. Senate Bill 6 reform is underway, but the queue is already deep. The speed advantage that defined ERCOT’s first era is under pressure from the very demand it created.

A useful reference point: this is what it looks like when infrastructure built for one scale of demand encounters the next scale. US data centers consumed approximately 415 terawatt-hours of electricity globally in 2024, roughly 1.5% of total global electricity use, growing at 12% annually.

The IEA’s base-case projection puts that figure near 945 terawatt-hours by 2030. By that point, US data centers alone are projected to exceed total heavy manufacturing electricity consumption. A hyperscale data center draws 100 to 500 megawatts continuously (90-100% uptime), with no demand response, no seasonal dip, and no off-peak moderation. These loads compress reserve margins at the exact hours when grid operators historically relied on industrial flexibility to buffer system stress.

The grid hardened for weather after Winter Storm Uri. During Winter Storm Elliott in December 2022, ERCOT set a winter demand record of 74,100 megawatts. Physical responsive capability never dropped below 4,052 megawatts. There was no Emergency Energy Alert declaration. (ERCOT Winter Storm Elliott Public Report, March 2023)

Contrast that with Uri, which triggered an EEA Level 3 declaration and resulted in the loss of 48.6% of installed capacity at peak. The weatherization effort worked.

But weatherization addresses weather. It does not address the demand curve. The new structural challenge is different: hardening legacy infrastructure while simultaneously interconnecting hundreds of gigawatts of new always-on load, with the same capital budget, the same transmission corridors, and the same time constraints.

Those two objectives are not easily reconciled. You cannot harden existing assets and build net-new transmission at the same pace when one is consuming the resources the other needs.

This is why the price signals at HB_NORTH aren’t one off. They are simply previews.

Section 04

What The Market Doesn’t Make Easy To See

The data center load concentration in North Texas is not uniformly distributed across the ERCOT grid. It clusters. Dallas, Houston, San Antonio, and Austin carry the highest suitability scores, but the density around North Texas is striking.

That geographic concentration maps directly onto the HB_NORTH hub boundary. The 9.9 times spike multiple in January 2026 is not a market-wide event. It is a localized event at the exact hub where the load is heaviest.

Most commercial electricity buyers in Texas operate without a clear view of this. The information required to fully understand your supply position as a C&I buyer is not presented in a single place. It exists across settlement point price feeds, interconnection queue reports, forward curve data, contract terms, and demand charge calculations. None of these are difficult to find individually. Together, they require either dedicated staff or a procurement process designed to surface them.

What that information gap creates in practice:

1. The competitive quoting gap.

   Most commercial buyers receive pricing from one or two retail electric providers.
   
   A full market process; running quotes across the available REP market simultaneously, typically surfaces a materially different price range. The spread exists because REPs price risk differently based on their own book positions.
   
   Without competitive tension in the quoting process, buyers absorb whatever margin the counterparty has elected to take.
   

2. Hidden cost mechanisms.
   
   Three cost components determine a commercial electricity bill in Texas beyond the energy charge itself. Demand charges reflect peak kilowatt draw in a given month. 4CP transmission costs are calculated from your facility’s load during the four highest demand hours on the ERCOT grid each summer; June through September and that calculation determines a portion of your transmission charges for the entire following year.
   
   Capacity charges reflect grid-wide reserve margin obligations allocated to buyers based on load profiles. Together, these can represent 30–50% of a commercial electricity cost. Most buyers know they exist. Fewer know how each is calculated or what operational decisions affect them.
   

3. The compounding cost of not knowing.
   
   A C&I buyer who signed a two-year fixed contract in 2022 at market rates for that year made a reasonable decision with the information available.
   
   That same buyer, renewing in 2025 or 2026, is entering a structurally different market. The average price at Houston Hub Q1 2025 is 31.7% higher than Q1 2023. North Hub is posting 9.9 times spike-to-average multiples. The ERCOT queue holds 233 gigawatts of new load.

   
   A renewal priced without a full market process, against a backdrop of rising averages and widening volatility, costs more than the rate difference on any single contract. It costs the delta between informed and uninformed procurement compounded across a multi-year term.

C&I Savings Calculator | Estimates based on ERCOT + Internal benchmarks

Share

Section 05

What The Grid Is Doing Right Now

The 4CP window opens in June. It closes in September.

Those four months contain the four highest demand hours on the ERCOT grid for the year and the load your facility carries during those specific hours determines a portion of your transmission costs for the entire following twelve months.

This is not a fee that adjusts month to month and is set once, based on peak summer performance, and applied across the calendar year ahead. For a C&I buyer with significant demand exposure, the difference between active load management during 4CP windows and passive operation during those same hours can represent tens of thousands of dollars in annualized cost.

The forward curve is reflecting current market conditions in the pricing available to buyers locking contracts now versus contracts locked after summer peaks are established. Rates priced before summer carry different uncertainty premiums than rates priced after the grid’s peak demand profile is known. It’s how forward markets work.

What is different in this market is the magnitude of the uncertainty being priced. With 233+ gigawatts of pending large-load requests and a forecast inflection point that has no historical precedent in ERCOT data, the premium for post-peak certainty is larger than it has been in prior years.

Contract expiration mechanics matter here. A commercial buyer whose fixed-rate contract expires during or after summer peak season faces a renewal in a market with fresh volatility data. A buyer whose contract expires before the 4CP window has time to evaluate forward pricing before that data exists. Neither timing is inherently better. But understanding which position you are in determines what information you need to gather and when.

The supply and demand gap is not closing in the near term. The infrastructure required to serve the demand coming into ERCOT’s queue takes years to interconnect and build.

The grid will face repeated localized scarcity events with rising average prices as the structural baseline, not as episodic exceptions. That is the condition buyers are pricing against when they sign contracts in this market.

Section 06

What Paying Attention Looks Like

Three things put you in a different position than most commercial buyers in Texas right now.

The first is knowing what you currently pay fully, not just the energy rate. Pull your last twelve months of bills and calculate the total delivered cost per kilowatt-hour, including demand charges, transmission fees, and any capacity components. Most buyers who do this for the first time discover their effective rate is meaningfully different from the rate they negotiated. That number is your baseline. You cannot evaluate a renewal or an alternative offer without it.

The second is knowing your contract expiration date and what happens after it. If your contract expires and you have not signed a renewal, you likely roll to a variable or indexed rate at whatever the market is doing at that moment. In the current market, that moment matters. Know the date. Know the default terms. Know whether your REP provides any notice period before the rollover takes effect.

The third is understanding your demand exposure before the 4CP window opens in June. If your facility has significant peak demand; heavy HVAC load, industrial equipment, high-draw operations then you have some ability to manage when that demand hits the grid during the four critical summer months. That management is not complicated, but it requires knowing the window exists and what the operational levers are.

None of this requires a consultant.

It requires the same attentiveness you apply to any other major cost center in your operation.

The Texas electricity market is genuinely complex, and it is getting more complex as load growth accelerates. But the buyers who navigate it well are not the ones with the most sophisticated models. They are the ones who know their numbers, know their timing, and ask the market for competitive pricing rather than accepting the first offer placed in front of them.

Texas built a grid that runs on competition. That competition works in your favor only if you participate in it.

Primary Sources

• ERCOT — 2025–2031 Long-Term Load Forecast Update and Methodology Changes April 7, 2025 https://www.ercot.com/files/docs/2025/04/07/8.1-Long-Term-Load-Forecast-Update-2025-2031-and-Methodology-Changes.pdf

• ERCOT — Winter Storm Elliott Cold Weather Operations Public Report March 27, 2023 https://www.ercot.com/files/docs/2023/03/27/December-2022-Cold-Weather-Operations-Public-Report.pdf

• ERCOT — Real-Time Market Documentation (SCED/LMP, Settlement Point Prices) Ongoing https://www.ercot.com/mktinfo/rtm

• FERC — Introductory Guide to Electricity Markets (ERCOT Jurisdictional Exemption) Ongoing https://www.ferc.gov/introductory-guide-electricity-markets-regulated-federal-energy-regulatory-commission

• International Energy Agency — Energy and AI Report 2025 https://www.iea.org/reports/energy-and-ai

• Utility Dive — "ERCOT's Large Load Queue Jumped Almost 300% Last Year" January 6, 2026 https://www.utilitydive.com/news/ercots-large-load-queue-jumped-almost-300-last-year-official/808820/

• Utility Dive — "Reliability Risk Isn't Just About Capacity Anymore" March 2026 https://www.utilitydive.com/news/winter-texas-reliability-risk-capacity-ercot/811748/

Internal / Original Data Work

TheGridLetter Analysis — Q1 Volatility Envelope, HB_HOUSTON, 2023–2025 Source data: ERCOT Settlement Point Prices, HB_HOUSTON, Q1 hourly real-time data

TheGridLetter Analysis — Q1 Volatility Envelope, HB_NORTH, 2023–2026 Source data: ERCOT Settlement Point Prices, HB_NORTH, Q1 hourly real-time data

Summary

On April 27, 2026, the Houston wholesale market cleared at $748 per megawatt-hour. The same hour five days earlier cost $61.

ERCOT’s energy-only market is engineered to price at the extreme, not the average, which means small shifts in supply and demand during constrained periods produce outsized price swings by design.

What you walk away knowing in today’s article is how that risk travels from market dynamics and directly into your invoice, and why how you position in this market can save any business thousands in energy cost.

In This Issue

• Section 01 — Laying The Groundwork

• Section 02 — A Tale of Five

• Section 03 — Why Renewables Don’t Lower Your Bill During a Spike

• Section 04 — The Settlement Point Between the Wholesale Market and Your Meter

• Section 05 — Summer Is When the Margin Gets Expensive

• Section 06 — What Knowing This Changes

  ---

  If you’re new here, start with these:

  • The Bill Is Coming: Why Texas Business Owners Can No Longer Ignore the Power Market

  • Understanding 4CP: Why Texas Electricity Prices Spike Every Summer

  ---

Section 01

Laying The Groundwork

To help visually illuminate on the concepts which will be discussed throughout the publication, let’s take a look into an actual five day span on settlement point prices in April 2026.

On April 27, 2026, the Houston wholesale market cleared at $748 per megawatt-hour at 9:30 PM. Five days earlier, at the same hour, it cleared at $61.

Remember, it’s very important to realize that this is not a market malfunction. This is simply a market working exactly as it was designed. You can find ERCOTs real time SPPs here.

Now that we have some actual examples of real-time price volatility let’s proceed to understanding just how and why this happens.

Subscribe now

Section 02

A Tale of Five

Those two data points are not outliers pulled from different seasons or different stress events. They are the same market, the same hour, only five days apart in April. That gap is the volatility envelope in action.

Now the examples are only within a five day time span, but what do you see when looking a data spanning multiple years?

Analyzing historical average DAM pricing data from 2023 to 2026, here’s what we can confidently say:

Two things are true about this market simultaneously. The market is both stable and increasingly more volatile. When conditions tighten, the numbers do not “drift” upward. They move in orders of magnitude.

August 2023 averaged $265 for the entire month, with a single day breaching $1,081.

January 2026 averaged $67.50, roughly double a typical winter month, with a single-day spike to $574.

The 2024 summer is also worth noting. Averages stayed between $23 and $35 through July and August. No dramatic spikes.

That relative calm is real price action. But it was the product of favorable conditions: milder weather, adequate reserves, winds cooperating during peak hours. The market rewarded that luck. It does not guarantee it moving forward. When conditions become unfavorable you get months like August 2023.

What the full dataset shows is not that prices are always high. It is that when the conditions for a spike exist, the pricing response is non-linear. Small increases in demand during constrained periods do not produce small increases in price.

Again, this is not a flaw in the design. It is the design itself.

Section 03

Why Renewables Don’t Lower Your Bill During a Spike

Texas runs more wind and solar than any other state in the country. On a good spring afternoon, renewables can cover more than half of total ERCOT demand. That fact leads most people to a reasonable but wrong conclusion: more renewable generation means lower prices.

It does, most of the time. The problem is the hours that are not “most of the time”.

ERCOT’s pricing mechanism does not care how much cheap generation ran earlier in the day. It cares about the most expensive unit of generation required to meet demand right now. By 8 PM on a hot August evening, solar output is near zero.

Wind in Texas tends to slow during the hottest parts of summer. What remains to meet a grid still carrying heavy cooling load is dispatchable thermal generation: natural gas peakers with high marginal costs. Those units set the price. Every other generator on the grid, including the wind farm that ran at near-zero cost all afternoon, gets paid that same clearing price.

This is the mechanic the merit order graphic makes visible. The grid ranks every available power source from cheapest to most expensive and dispatches them in order until demand is met.

The last unit turned on to satisfy demand sets the price for everyone. Wind and solar sit at the far left of that stack. Gas peakers sit at the far right.

When demand is low, the market never reaches the right side of the stack. When demand is high and cheaper sources are unavailable, the market has to reach those peakers, and the price resets to whatever it costs to run them.

Here, Energy Bad Boys highlights how lower renewable output during Winter Storm Fern coincided with a sharp increase in wholesale power costs, demonstrating how supply shortfalls can amplify price volatility during periods of elevated demand.

The energy industry calls this transition the duck curve.

Solar generation creates a wide belly of low-cost midday supply, then drops sharply into the evening hours just as residential and commercial cooling loads remain elevated.

The net load (the demand that dispatchable generators must cover) ramps steeply upward in a short window. That ramp is where the marginal unit changes. That is where your risk exposure lives.

The renewable buildout in Texas has made the belly of the duck wider and cheaper. It has also made the evening ramp steeper, because more of the daytime load is now covered by generation that cannot follow the sun past sunset.

Businesses that understand this frame make different decisions than businesses that do not. The question is not whether your electricity comes from renewables. The question is what is setting your price during the hours when the grid is tight. Right now, that answer is almost always natural gas. And natural gas peakers do not get cheaper as the grid adds more solar.

Share TheGridLetter

Section 04

The Settlement Point Between the Wholesale Market and Your Meter

The wholesale market prices electricity at thousands of individual electrical nodes across the grid, every five minutes.

Each node has a Locational Marginal Price, called an LMP that reflects the marginal cost of serving one additional megawatt of demand at that exact location, including the cost of energy, the cost of transmission congestion, and line losses.

During a stress event, LMPs at different nodes can diverge significantly depending on where the grid is congested and which generators are available locally.

Your business does not transact at a node. Almost no commercial customer does.

What your bill settles against is a Settlement Point Price. An SPP is a simplified financial price derived from groups of LMPs, depending on the type of settlement point: a hub, a load zone, or a specific node.

The Houston Hub (HB_HOUSTON) is the settlement point most relevant to commercial customers in the greater Houston area. It aggregates LMP data across the Houston load zone into a single tradeable price that your retail electricity provider uses to structure and hedge your contract.

Subscribe now

The practical implication is this: wholesale volatility does not hit your meter at one-to-one.

Your retail provider sits between the wholesale market and you. They hedge a portion of your expected load against forward prices and DAM prices. They build a margin into your rate.

They absorb some of the basis risk between the hub price and the nodal price at your specific location. What reaches you is a version of wholesale risk, shaped by how your contract is structured.

That shaping cuts both ways. A fully fixed contract insulates you almost entirely from real-time price swings (although through rate increases on contracts factoring past volatility, you’ll still feel the heat)

A variable or indexed contract passes wholesale exposure through directly.

Most commercial customers on multi-year agreements sit somewhere between those poles, with fixed energy charges but exposure to capacity, transmission, and ancillary service costs that adjust annually. Those adjustments are where summer volatility propagates downstream, even inside a contract that looks fixed on the surface.

The settlement layer is not a firewall. It is a translation mechanism. What happens at the wholesale level eventually finds its way to your rate. The only variable is timing.

Section 05

Summer Is When the Margin Gets Expensive

The 4CP window opens June 1.

Those four letters determine a line item on your electricity bill that most business owners have never heard of and cannot find on their invoice.

4CP stands for Four Coincident Peaks, the four highest demand hours on the ERCOT grid during June, July, August, and September. Your load during those four hours, measured against total grid demand, sets your share of transmission costs for the following calendar year.

That allocation shows up as a capacity charge embedded in your rate. It does not announce itself. It simply arrives.

ERCOT does not publish the peak hours in advance. They are identified after the fact. What the data does show is when they tend to occur: weekday afternoons between 3 PM and 7 PM, during the hottest days of August, when cooling load is highest and solar is fading.

The August 2023 data makes the window visible. A month that averaged $265 per megawatt-hour, with a single day breaching $1,081, produced the kind of demand spikes that set 4CP hours. Your load profile during those hours followed you into 2024 whether you knew it or not.

The forward strip reflects this.

Suppliers pricing 12 or 24-month contracts right now are building summer 2026 volatility into the rate they quote you today.

Every week that passes without a signed contract is a week closer to peak pricing being baked into your baseline. Locking before the summer strip fully prices in is not a guarantee of the lowest possible rate. It is a guarantee of pricing against a market that has not yet confirmed its worst case.

Your contract expiration date matters here. Rolling into an unplanned renewal during July or August means your supplier sets the terms against the most expensive forward curve of the year. That is not a negotiation. That is a default.

The reserve margin tightens as load climbs. Thermal outages cluster in heat. Evening solar contribution falls to zero.

The Operating Reserve Demand Curve (ORDC), ERCOT’s mechanism for pricing scarcity into real-time markets, activates when reserves fall below target thresholds, adding adders to the clearing price that compound on top of an already elevated marginal cost.

Those adders are not hypothetical. August 2023 produced them. January 2026 produced them. The conditions that generate them are present every summer to varying degrees.

Summer does not just raise prices. It widens the range of outcomes. The floor stays roughly where it was. The ceiling lifts.

Section 06

What Knowing This Changes

You now have a frame that most business owners in Texas do not have.

You know the grid prices at the margin, not the average.

You know renewables lower costs during calm hours and do nothing to protect you during stressed ones.

You know the settlement layer between the wholesale market and your meter shapes but does not eliminate your exposure.

And you know the window for acting ahead of peak pricing is measured in weeks, not months.

None of that requires you to become an energy analyst. It requires only three things.

1. Know what you are currently paying per kilowatt-hour, all-in, including capacity and transmission line items.

2. Know when your contract expires.

3. Know whether your rate structure has any variable components that pass through wholesale or capacity cost changes. Those three data points tell you whether you are positioned or exposed heading into summer.

Most commercial customers in Texas are exposed to elevated risk which diminish margins and do not know it.

Not because they made a bad decision but because the system is not designed to make that exposure visible.

The businesses that will pay more this summer than they needed to are not the ones that looked at the market and bet wrong. They are the ones that never looked.

The market is not going to get simpler. The load is not going to shrink. The evening ramp is not going to flatten as more solar comes online.

Understanding how this system prices risk is not an edge that expires. It compounds.

Share

Sources

• ERCOT Settlement Point Prices (SPP) — HB_HOUSTON, April 2026 ERCOT DAM

• Daily Average Prices — HB_HOUSTON, 2023–2026 ERCOT Market Prices Dashboard

• ERCOT Supply and Demand Dashboard

• ERCOT Real-Time LMP Contour Map — ercot.com/content/cdr/contours/rtmLmp.html

• ERCOT ORDC Biennial Report, 2022

• The Bill Is Coming: Why Texas Business Owners Can No Longer Ignore the Power Market — TheGridLetter, April 22, 2026

On the evening of April 27th, Houston electricity customers paid an estimated $32 million above normal market rates in four hours. Not during a heat wave. Not during a “freeze” grid emergency. On a Monday night in spring, while most people were at home sleep with no idea what their meter was recording.

That number comes from ERCOT’s own public load data for the Coast weather zone, cross-referenced against real-time settlement prices from the same evening. The math is public, verifiable. The implication is the part nobody is talking about.

4CP season hasn’t even opened yet.

The Meter Was Running While You Weren’t Watching

The week of April 22nd produced three separate price events in the Houston wholesale market. Each one worse than the last.

April 22nd, Monday evening: Houston cleared at approximately $61/MWh. Normal for that hour now runs $20 to $50/MWh, aligning with some claims (referenced below).

Post source: r/texas

Over a decade experience of wholesale pricing most never touch so imagine the feeling of those who were never even exposed to wholesale prices to begin with.

April 25th, Saturday afternoon, 1:15PM: no weather event, no grid emergency, no demand surge. Houston hub hit $96.83/MWh. Normal spring wholesale runs $25 to $35/MWh. Nearly 3 to 4x above baseline on a weekend afternoon in April.

Then April 27th arrived.

The settlement sequence from ERCOT’s own records: $495, $502, $565, $686, $803. That is not a flash spike. That is a sustained event running from 6:45PM through 9:45PM on an ordinary spring night. Houston hub average peaked at $803/MWh at 9:30PM. During that single hour, ERCOT’s load data shows the Coast zone carrying 17,119 MWh. At $803/MWh against a $40 normal evening baseline, that one hour cost Houston approximately $13 million above a normal Monday night.

Three events. Seven days. All before summer (4CP).

The Grid Isn’t Broken. It’s Working Exactly as Designed.

Someone with deep wholesale electricity experience dropped into my comments this week. His observation: spring 2026 price spikes are already worse than any August or September he has seen in his career. That is not a forecast. That is a pattern read from someone who has been watching this market for over a decade.

The same night Houston was printing $803/MWh, the Permian Basin was producing so much wind generation that prices went negative. Generators were paying to offload power they couldn’t move. Between that surplus and Houston’s demand sit roughly 400 miles of transmission infrastructure that was not built for what this grid is being asked to carry in 2026.

You are not paying high prices because there isn’t enough power. You are paying high prices because the power can’t get to you. That distinction matters, because one of those problems gets fixed eventually and the other one doesn’t.

The Actors Who Profit When You’re on Autopilot

While you’re auto-renewing and assuming it’ll sort itself out, the market is actively pricing against that assumption. Here’s who benefits when you’re not paying attention:

• Retail electricity providers set renewal rates based on what the market will bear from customers who don’t shop. If you haven’t compared rates recently, your renewal price reflects that.

• Suppliers with index-priced contracts passed every dollar of the April 27th spike directly to customers on variable or real-time pricing plans. No buffer. No warning.

• Businesses that do shop are locking fixed rates right now, before summer forward pricing bakes in the peak premium. They will pay less than you next January for the same kilowatt-hours.

• The transmission system itself charges you a capacity cost calculated from four specific peak hours each summer. Most commercial customers have never heard of this charge. The ones who have are managing their load around it.

Inaction is a choice. Right now, it’s an expensive one.

April Was the Warm-Up Act

Here is the mechanism most Texas business owners have never been shown.

ERCOT calculates a major portion of your commercial transmission costs using the four highest peak demand hours across the entire grid each summer, June through September. Those four hours are called the Four Coincident Peaks, or 4CP. Whatever load you are running during those four hours determines what you pay in transmission charges for the entire following calendar year.

Most commercial operators discover this in January. By then the season is over and the number is fixed.

4CP season opens June 1st. The three price events above, $61, $96.83, and $803/MWh, all happened before it did. Forward strip pricing for summer contracts is being set right now, off a baseline that already includes April’s volatility. Every week you wait to review your contract, you are pricing off a higher floor.

Thinking about it later is a position. It just costs more than thinking about it now.

Three Questions Worth Answering Before June

You do not need to become an energy analyst. You need five minutes and your most recent electricity bill to save you potentially hundreds to thousands this year.

1. What rate structure are you on?

Fixed, indexed, or variable. Those three words determine everything about your exposure to what happened on April 27th.

Fixed rate: you were protected. The spike passed you by.

Indexed or variable: you paid some version of that $803/MWh that evening. How much depends on your contract terms, but it showed up.

If you don’t know which one you’re on, find your contract or call your provider today. That single answer changes every decision that follows.

2. When does your contract expire?

Pull the date. Write it down.

If it expires between June and September, you are at risk of rolling into a default or variable rate during 4CP season, the most expensive window of the year to be unprotected. Renewing early on a fixed term, even at a slightly higher rate than last year, beats rolling into a variable plan mid-summer by a significant margin.

If it expires after September, you have time. Use it to shop properly before next spring.

3. Do you see a transmission or capacity line item on your bill?

If you’ve never noticed it, find your bill right now and look for terms like TDSP charges, capacity charges, or demand charges. They are there. Every Texas commercial customer pays them.

That line item is directly connected to 4CP. The four peak demand hours last summer set what you are paying on that line today. The four peak hours this summer are setting what you will pay next January. Most people find out after the fact. You don’t have to.

Those three answers cost you nothing to find. Acting on them before June is the entire difference between being ahead of this or behind it.

Want to go deeper on how ERCOT actually works and why it affects your bill the way it does?

Start here: Friend or Foe? A deep-dive into ERCOT

Sources: ERCOT Real-Time Settlement Point Prices, HB_HOUSTON hub, April 22–27 2026. ERCOT NP6-345-CD Actual System Load by Weather Zone, April 27 2026. ERCOT Real-Time Nodal LMP Heat Map, April 27 2026 23:50.

TheGridLetter translates what’s happening in the ERCOT market into plain language for Texas business owners. One issue per week. No jargon. No filler.

If this was useful, forward it to someone whose electricity bill you think about.

Issue #4 · April 29, 2026

Why Texas Electricity Prices Spike Every Summer (And What It Costs Businesses Who Wait)

Every summer, Texas businesses feel a spike they could have seen coming in April.

The bill arrives. The number is higher. The reaction is the same: frustration, a quick Google search, maybe a call to the provider. By then, the market has already moved. The price you are reacting to was set weeks before you felt it.

This is not bad luck. It is a pattern. And patterns can be anticipated.

What the Data Actually Shows About Texas Electricity Rates

Texas electricity demand is not growing gradually. It is accelerating. Data centers, industrial expansion, and population growth are stacking on top of each other at a pace the grid was not built to absorb. By 2032, total power demand in ERCOT could reach four times what it is today, driven largely by AI infrastructure and large-scale industrial load.

That matters to your business for one specific reason: data centers are price-insensitive buyers. They need power regardless of cost. When they compete for supply during tight conditions, they win. You pay the difference.

The market has already shown what that looks like under pressure. Between 2021 and 2023, wholesale electricity prices in Texas rose over 200%. That was not a fluke. It was the system behaving exactly as designed under stress.

Here is how the pricing mechanism actually works, plainly stated. ERCOT runs on marginal pricing. Every hour, the grid lines up available power sources from cheapest to most expensive and turns them on in order until demand is met. Whatever the last, most expensive unit costs sets the price for everyone on the grid that hour. During normal conditions, that last unit is relatively cheap. During high demand periods, when cheaper sources are already maxed out, natural gas generation steps in as the marginal source. Natural gas is expensive. When it sets the price, everybody pays a gas price for electricity, regardless of how much wind or solar was running that same hour.

The system does not average costs. It prices at the margin. Small increases in demand during constrained periods do not produce small increases in price. They produce large ones. That is not a flaw in the design. It is the design.

Why Texas Electricity Price Increases Are Structural, Not Seasonal

Think about every essential resource a modern society runs on. Water. Gas. Oil. Electricity. Every one of them faces the same pressure: demand compounds as society scales, but the infrastructure supporting supply moves slowly. What you are seeing in Texas electricity prices is not a regional quirk. It is that universal dynamic playing out in one of the fastest-growing markets in the country, accelerating faster than most people realize.

Texas is not just adding residents. It is adding data centers, manufacturing plants, and industrial operations that consume electricity at a scale no single household ever could. These are not price-sensitive buyers who reduce consumption when costs rise. They are locked-in, always-on loads that the grid has to serve regardless of conditions. Grid infrastructure to support that demand will not be fully in place until the 2030s. The gap between what the market needs and what the system can deliver is where prices live right now.

This is the part most business owners miss. They think of electricity as a utility cost that fluctuates seasonally, the way fuel prices do, something that goes up in summer and comes back down. That mental model is outdated. The underlying market has structurally shifted. Wholesale prices that spiked over 200% between 2021 and 2023 did not fully retreat. The floor moved up. Each new demand layer, each new data center, each new industrial connection raises the baseline that future prices are built on top of.

There is a useful parallel in how the internet changed commercial real estate. Before widespread adoption, location was the primary cost driver for businesses. After, bandwidth and connectivity became non-negotiable operating costs that repriced everything around them. Electricity in Texas is undergoing the same transition. It is moving from a background utility to a strategic input that directly determines margin. The businesses that recognize that transition now will make fundamentally different decisions than the ones that figure it out after the next spike.

The System Working Against Uninformed Business Electricity Buyers

Here is what the system does not advertise.

Suppliers in the Texas electricity market build their pricing around one assumption: that most buyers are not paying attention. When your contract comes up for renewal, the default path is the easiest one. You renew, you move on, you absorb whatever rate the market is offering at that moment. The supplier knows this. They price accordingly.

What most business owners never see is the spread between what they paid and what a competitive process would have produced. Without running the market, you never know how many suppliers would have competed for your account, or what that competition would have driven the price down to. The quote you accepted was not necessarily the best available. It was simply the one in front of you.

Beyond the rate itself, there are cost layers most businesses have never been shown:

Transmission and delivery charges have been rising steadily since 2021, independent of energy prices. These are system costs, infrastructure costs, the price of moving electricity from where it is generated to where you consume it. They flow directly into your bill whether energy markets are calm or volatile.

The 4CP mechanism. Four Coincident Peaks. During the four highest demand hours on the ERCOT grid each summer, your facility’s consumption is measured and used to calculate a portion of your transmission costs for the following year. Most businesses have never heard of it. The ones who have structured their operations around it pay materially less than the ones who have not.

The system is not designed to be opaque. It is simply optimized for participants who understand it. Every supplier, every retailer, every large industrial buyer is running their own calculation, hedging their own risk, optimizing their own outcome. The business owner who auto-renews without running a competitive process is the only player at the table who is not playing the game. That is not a moral failing. It is an information gap. And information gaps in this market have a direct dollar cost.

Why Late May Through June Is the Highest-Risk Window for Texas Business Electricity Rates

The late May to mid-June window is not a forecast. It is where three things converge simultaneously every year.

Physical stress. Texas shifts from mild seasonal load to sustained cooling demand faster than the grid can fully adjust. Thermal generation units are still completing spring maintenance cycles. Wind output, strong through spring, fades precisely when temperatures begin to climb. The grid becomes more dependent on natural gas at the exact moment demand starts accelerating. Less supply flexibility meeting rising demand is where volatility begins.

Financial impact. May usage produces June bills. Businesses do not react to market forecasts. They react to actual numbers on actual invoices. By the time the bill arrives reflecting elevated May and June rates, forward contracts for the remaining summer are already priced off the stress period baseline. The market moved before the bill landed.

Narrative amplification. Early summer is when media coverage ignites. Headlines about grid pressure, heat warnings, and electricity costs reach people who were not paying attention to market mechanics. Search volume spikes. Attention peaks. The audience is primed and looking for answers.

You do not need a crisis for all three to stack. You need heat, bills, and headlines arriving close together. Late May through mid-June is where that happens most reliably.

A secondary window opens in early September, driven by sustained heat accumulation, thermal stress on generation units, and Gulf weather uncertainty adding fuel supply risk. Different trigger, same outcome.

By the time the spike is obvious, forward pricing has already absorbed it. The contract you sign in July is priced off June conditions. The contract you sign in April is not.

That is the entire argument for acting now rather than later. Not urgency for its own sake. Mechanics.

What Getting Ahead of Texas Electricity Costs Actually Looks Like

None of this requires you to become an energy analyst.

It requires three things. Know what you are currently paying per kilowatt hour and what structure your contract is in, fixed or variable. Know when your contract expires. Know what your peak usage looks like heading into summer, because that determines your exposure before the window opens.

That is the entire checklist. Businesses that have those three answers are already ahead of the majority of commercial buyers in this market. Most are operating on autopilot, renewing without running a competitive process, unaware of the transmission cost layer, and completely unfamiliar with how their summer consumption patterns affect what they will pay next year.

You do not have to predict the future to position ahead of it. You just have to understand the pattern well enough to move before it repeats. The market will do what it always does. The only variable is whether you are in front of it or behind it when it does.

Free Commercial Electricity Audit — No Commitment

If you own or operate a commercial facility in Texas, here is what a no-cost rate audit covers:

• Your current rate structure, fixed vs. variable, and what it exposes you to this summer

• A competitive market analysis across available suppliers for your account

• Your 4CP exposure and what it means for next year’s transmission costs

• Contract timing recommendations based on current forward pricing

No obligation. No pressure. A clear picture of where you stand before the window opens

Initial Audits Are Complimentary - Sign Up Here

If this was useful, forward it to a business owner whose electricity bill you think about. One conversation before summer could be worth real money.

A Texas business owner opens their electricity bill. It's higher again. They don't know why.

They sign the renewal because that's what they always do.

Lets run a quick experiment. Open your last electricity bill. Look at the total. Now compare it to the same month two years ago.

If it’s higher and you don’t know exactly why, you’re not alone. But “not alone” isn’t the same as “not at risk.” The businesses around you that do understand what’s happening are making decisions right now that will lock in lower costs for the next two to three years. The ones that don’t are going to absorb whatever the market hands them.

This is not a rate spike. It's not a weather event. It's not a blip. What's happening to the Texas power grid right now is structural, and it moves in one direction.

Section 01

What’s actually happening right now

Texas electricity wholesale prices rose 45% in 2026. Not over a decade. Not over a market cycle. In a single year. And that number didn’t come from a bad winter or a surprise outage. It came from something that isn’t going away.

According to a report cited by the Texas Tribune, Texas is on track to become the largest home for data centers in the country within two years. The grid demand from those facilities alone is expected to exceed 40 gigawatts by 2028. In 2025, it was 8 gigawatts. That’s a fivefold increase in three years on a grid that was already running near capacity during summer peaks.

And just this week, ERCOT released a preliminary forecast showing peak energy demand could quadruple by 2032. Even ERCOT’s own CEO said the number is likely overstated. But that’s almost beside the point. When the grid operator says demand could quadruple and then walks it back to “probably less than that,” they’re still describing a market under serious structural pressure. A University of Houston professor told KPRC 2 plainly: prices are likely to rise in the short term as infrastructure is built to meet that demand. Especially in Houston.

Your bill is already reflecting some of this. The rest is still coming.

Section 02

This isn’t a cycle. It’s a regime change.

Every technology that permanently changed the way humans operate had one thing in common. It created dependency. Language. Fire. Oil. The internet. Each one became so embedded in how people and businesses function that opting out stopped being an option.

AI is doing the same thing, and it’s doing it faster. But here’s what’s different this time: the dependency is hitting businesses first. Large organizations are already building AI into their operations. The ones that don’t will eventually compete against the ones that do. That’s not a prediction. That’s already happening.

The chain looks like this. Businesses need AI to stay competitive. AI runs on data centers. Data centers run on electricity. And they don’t run a little. A single large data center can consume more power than a small city.

“By 2030, one in five data centers is expected to exceed one gigawatt in maximum energy demand. By 2035, that’s expected to be one in three.”

Bloom Energy, via Texas Tribune, January 2026

Texas became the destination for this build-out because of cheap land, access to natural gas, and a deregulated market that moves faster than other states. That’s why 387 data centers are already here. That’s why more are coming. And that’s why the grid pressure you’re starting to feel on your bill is not a temporary condition.

The internet analogy is worth sitting with. Businesses that moved early built advantages that compounded for years. The ones that waited played catch-up in a market that had already moved past them. The inflection point for energy costs in Texas is the same kind of moment. You either get ahead of it or you absorb it.

Section 03

Who’s making money while you’re not paying attention

The system is not designed to save you money. It’s designed to price you at what it thinks you’ll accept.

• Suppliers price contracts based on what they believe you’ll sign, not what the market actually supports. Without competitive quotes from multiple providers on the same day, you have no way to know the difference.

• 30 or more suppliers are actively pricing your market right now. Most quotes are valid for 24 hours. You’ll never see the majority of them without a process specifically designed to surface them.

• Businesses in deregulated markets that actively shop their contracts are switching at higher rates than ever. The ones that don’t shop are quietly subsidizing the ones that do.

• 78% of Texas business owners don’t know how demand charges are calculated. Demand charges can represent 30 to 70% of a commercial electricity bill. That’s not a rounding error. That’s the bill.

Inaction is a choice. And right now, it’s an expensive one.

Section 04

Why now is not a drill

Fixed-rate contracts lock in at today’s price. The longer you wait, the higher the floor you’re locking into. Summer pricing on ERCOT is already baked into forward market strips. If you’re signing in Q3 or Q4, you’re pricing off a base that reflects peak demand season. You’re not getting ahead of it. You’re buying into it.

Every month on an indexed plan or a supplier’s default rate is a month of full exposure to whatever the market does. And this summer, the market has more structural upward pressure than it’s had in years.

The 4CP window opens in June. That’s the period when ERCOT identifies the four highest-demand hours of the summer, and those hours determine a significant portion of your transmission costs for the following year. Most business owners have never heard of it. The ones who have are already managing their load in advance. The ones who haven’t are going to see it on their bills in January and wonder where it came from.

Thinking about it later is a position. It just costs more than thinking about it now.

Section 05

What getting ahead of it actually looks like

It doesn’t require an energy team. It doesn’t require understanding every mechanism in the ERCOT market. It requires knowing three things: what you’re currently paying versus what’s available, when your contract expires and whether now is a good time to move, and what your 4CP exposure looks like before summer starts.

That’s it. Those three things determine whether you’re in front of this or behind it.

The businesses that are moving right now aren’t doing something complicated. They’re paying attention in a market where most people aren’t. That gap is the entire opportunity

sources:

• https://www.texastribune.org/2026/01/20/texas-top-data-center-market-power-grid/

• https://www.click2houston.com/news/local/2026/04/22/ercot-texas-power-demand-could-surge-by-2032-but-experts-say-forecast-likely-overstated/

• https://www.utilitydive.com/news/electricity-prices-demand-to-continue-rising-in-2026-eia/805395/

There are 34,000 miles of transmission lines running through Texas. 464 terawatt-hours of electricity generated in a single year. Enough to power every home, business, data center, and strip mall in the second-most populated state in the country — and only one organization sitting at the controls.

No, it’s not BlackRock. It’s not a government agency either, at least not in the way most people think. It’s not a utility, and it’s not your electricity provider.

It’s ERCOT.

Most Texans have heard the name, usually during a winter storm or a summer heat warning when the news starts throwing around phrases like “grid stress” and “conservation appeal.” But the conversation almost always stops there: ERCOT bad, power outages bad, move on. What never gets explained is what ERCOT actually is, how the market it oversees actually functions, and why any of this matters beyond keeping your lights on.

That’s what this piece is for.

By the end of it, you’ll understand why Texas runs a fundamentally different electricity system than almost anywhere else in the country, how the price you pay for power is actually calculated, and why I think the Texas energy market is quietly becoming one of the more interesting economic stories of this decade. Not because of some hot take, but because of what’s already happening — and what the data is already showing.

This is a long one. Bookmark it.

Part One: Why Texas Is Different (And Why That Actually Matters)

Let’s start with the thing that separates Texas from virtually every other state: deregulation.

In most of the United States, electricity works like a utility. A single company generates the power, owns the wires, and sends you a bill. You don’t choose your provider. You don’t have exposure to wholesale market prices. You pay whatever the regulated rate is, set by a state commission, and that’s the end of it.

Texas, for the most part, is not that.

In 2002, Texas restructured its electricity market. The goal was to introduce competition: if generators had to compete for customers, prices would theoretically drop, efficiency would improve, and consumers would have choices. Today, roughly 90% of the state’s load is served through a deregulated market. If you’ve ever gone online and compared electricity plans the way you’d compare phone plans — that’s deregulation at work.

But deregulation doesn’t mean no structure. It means a different kind of structure, and ERCOT is the organization that holds it together.

Texas also made another consequential decision: its grid is largely islanded. The ERCOT grid connects with neighboring states only through a small number of limited DC ties, not the kind of deep integration that would make it part of the Eastern or Western Interconnection. This was a deliberate choice, rooted in a desire to keep the grid under Texas jurisdiction and out of federal regulation. The Federal Energy Regulatory Commission (FERC) oversees interstate electricity commerce. Texas, by staying disconnected, largely avoids FERC oversight. The grid is Texas’s to run.

That independence is both a strength and a vulnerability, and understanding it is the first step to understanding everything else.

Texas by the numbers:

The scale here is genuinely staggering. Texas is the largest electricity-consuming state in the country — consuming more than twice as much energy as California, the second-highest state, and more than three times as much as Florida. Between 2007 and 2023, Texas’s energy consumption increased 21%, while U.S. energy use decreased 5% over the same period. U.S. Energy Information Administration On the production side, ERCOT’s total generation reached 464 TWh in 2024, Dallas Fed a figure that continues to climb. Texas leads the nation in wind generation and is the second-largest solar producer, with utility-scale solar growing nearly four times over between 2021 and 2025. U.S. Energy Information Administration Wind and solar together now supply roughly 36% of ERCOT’s total electricity.

Projected demand growth adds another layer. ERCOT projects that peak demand could increase from approximately 85,000 MW today to as much as 145,000 MW within five years, Sierra Club driven by data centers, AI infrastructure, crypto mining, and continued population growth. The EIA is even more direct about the near term: electricity demand within ERCOT is expected to grow at an average rate of 11% in 2025 and 2026, making it the fastest-growing grid in the United States. U.S. Energy Information Administration The reasons behind that growth are worth understanding on their own, which is where we’re headed next.

Part Two: Energy as an Emerging Market

There’s a pattern that shows up every time a major technological shift happens: the infrastructure that new technology runs on becomes extraordinarily valuable, usually before most people think to look at it.

When the internet scaled in the late 90s, the obvious play was the software companies. The less obvious play — the one that became obvious in hindsight — was the fiber, the data centers, the physical plumbing that made the internet real. The same logic applies here, just with electrons instead of fiber.

AI and data centers are not a cyclical trend. That point is worth sitting with. S&P Global Energy, framing their 2026 Global Power Markets Conference, put it plainly: AI and data centers aren’t a cycle, they’re a new baseline. Load forecasts are being revised multiple times per year because the growth keeps coming in faster than modelers expected. Reliability risk has moved from an operational concern to a board-level issue at major companies.

Think about what that means structurally. Every query run through a large language model requires compute. Every dollar of compute requires power. The equilibrium between human consumption of electricity and technological consumption of electricity is shifting, and it's shifting quickly. From artificial intelligence to electric vehicles, business growth and power-hungry tech applications are driving up energy demand, making accurate forecasting more crucial than ever Texas Comptroller — and ERCOT is revising those forecasts constantly just to keep up.

That’s not a metaphor. It’s a procurement challenge.

The grid constraints this creates are real. Intermittency without firming capacity isn’t financeable, which is why S&P Global frames “clean plus reliable” as the actual benchmark, not “clean only.” Portfolio diversity equals investment confidence. Technology alone won’t solve the growth problem — it requires alignment across policy, capital, infrastructure, and operations. Execution risk now outweighs strategy risk.

Here’s the thing about energy that most people miss when they’re scanning headlines for the next big market: it’s not glamorous. It doesn’t have a founder giving TED talks. It doesn’t trend on social media. But it is the substrate. Everything that does trend, everything that does have a founder giving TED talks, runs on it. Understanding the infrastructure underneath the thing everyone is paying attention to is, historically, a very good way to see what’s coming.

Texas is where a lot of this is landing. The data center buildout happening across the state right now is not a rumor. It’s in the interconnection queue. It’s in ERCOT’s demand forecasts. It’s in the load growth numbers that keep getting revised upward. The state’s combination of land, relatively low-cost power, and deregulated market structure has made it a destination.

This is the context you need to understand why ERCOT, and the market it runs, is worth understanding closely.

Part Three: What ERCOT Actually Is (And What It Isn’t)

ERCOT stands for the Electricity Reliability Council of Texas. The name tells you something: reliability is first. It was established in 1970 and became the ISO (Independent System Operator) for the Texas market as part of deregulation.

Here’s the cleanest way to understand ERCOT’s role: it’s the referee and the game board. It does not own generation. It does not own transmission lines. It does not sell you electricity. It operates the bulk power system, runs the wholesale market, and ensures that the physics of the grid stay in balance every second of every day.

ERCOT’s core responsibilities break down into three areas: ensuring reliability, maintaining competitive wholesale markets, and facilitating retail operations. Its independent market monitor, Potomac Economics, publishes regular assessments of market performance and competitive conditions — and is one of the better public data sources for anyone trying to understand what’s actually happening in the market.

The three-layer structure most people don’t know about:

When you flip a light switch in Texas, there are actually three distinct types of entities involved, and most people conflate them.

First, there are generators: companies that produce electricity and sell it into the wholesale market. This includes large natural gas plants, wind farms, solar developers, nuclear operators, and increasingly, battery storage facilities.

Second, there are utilities: companies that own and maintain the physical wires that carry electricity from the transmission grid to your neighborhood. In Texas, these are called Transmission and Distribution Utilities, or TDUs. CenterPoint Energy in Houston, Oncor in the Dallas area, AEP Texas in West Texas. When your power goes out after a storm and a crew comes to fix it, that’s the TDU. They charge a regulated “delivery fee” that appears on your electricity bill regardless of who you buy power from.

Third, there are Retail Electric Providers, or REPs. These are the companies you actually choose from when you go to PowerToChoose.org — the state’s official comparison website. Reliant, TXU, Constellation, and hundreds of others. They buy power in the wholesale market and sell it to you with a retail margin built in.

ERCOT sits above all of this. It runs the wholesale market where generators sell and load-serving entities buy. It dispatches generation in real time to keep supply and demand balanced. It manages the interconnection queue for new generators wanting to come online. It coordinates with TDUs on transmission planning.

What this means for you as a consumer: your bill is the product of multiple separate pieces. The commodity cost of electricity, set by wholesale market conditions. The delivery charge, set by the TDU and regulated. And the REP’s margin and any products they’ve structured on top.

Understanding which of those pieces is moving, and why, is the beginning of understanding your exposure to the market.

Part Four: How the Market Actually Works

This section gets technical. But I want to take you through it in plain terms, because once you see the structure, you can’t unsee it.

The four physical constraints that govern every grid:

Any power grid, everywhere in the world, operates under four fundamental physical constraints. These aren’t policies or choices. They’re physics.

The first is instantaneous balance: supply must equal demand in real time. Not yesterday, not in five minutes. Right now. The grid runs at 60 Hz, and any significant deviation from that frequency causes equipment damage and, eventually, cascading failures. This is why grid operators exist — to maintain that balance continuously.

The second is network constraints: power flows across transmission lines according to the laws of electrical impedance, not according to contracts. When too much power tries to flow through a line, you get congestion. Congestion limits what generators can produce and what loads can consume at a given moment.

The third is ramping and commitment limits: generators take time to start up, ramp up, and shut down. You can’t order a gas plant to go from zero to full output in thirty seconds. This means grid operators have to plan ahead, committing resources before they know exactly what demand will be.

The fourth is weather dependence: both load and renewable output are meteorologically determined. A hot afternoon in August means peak demand. A cloudy, windless day means low solar and wind output simultaneously. This creates volatility — and in extreme cases, what statisticians call “fat tails”: low-probability, very high-impact outcomes. Winter Storm Uri in February 2021 was a fat tail event. The grid came closer to total collapse than most Texans know.

The market structure: four layers

ERCOT’s energy market has three core trading structures plus a settlement layer.

The first is the OTC market: bilateral contracts negotiated outside of ERCOT’s central clearing. Two parties agree on a price and quantity for future delivery. This is where a lot of the longer-term commercial volume happens.

The second is the Day-Ahead Market (DAM): a centrally-cleared auction run by ERCOT for the next operating day. Generators submit offers to sell, loads submit bids to buy, and ERCOT clears a price for each hour of the following day. This is a forward market — participants are committing to produce or consume at prices set today for tomorrow.

The third is the Real-Time Market (RTM): a physical balancing market that runs continuously, settling every five minutes. As actual conditions diverge from the day-ahead schedule — a generator trips, demand surges, wind drops unexpectedly — the RTM adjusts, dispatching units up or down and setting real-time prices.

The fourth layer is settlement: the accounting and payment process that reconciles what was committed in the DAM with what actually happened in the RTM.

Here’s a simple way to think about it: DAM and RTM together constitute the market. Real-time price movement is the liquidity signal. The scarcity adder, which we’ll get to in a moment, is where the volatility lives.

How prices are calculated:

The price of electricity in ERCOT is not one number. It’s a function of location, time, and scarcity.

There are two core pricing mechanisms. The first is the Locational Marginal Price (LMP): the cost of supplying one additional megawatt-hour of electricity at a specific location on the grid. It has three components: the system-wide energy cost, a locational component that reflects congestion and line losses at that specific node, and a scarcity adder.

The second is the Settlement Point Price (SPP): the price used for commercial settlement. ERCOT calculates SPPs for nodes, hubs, and load zones.

Understanding those three reference points matters. A node is a specific physical location on the transmission grid, typically associated with a large generator or major load. A hub is a financial reference point: an aggregated average of node prices in a region, used for hedging and trading. A load zone is an aggregated demand-side reference point that reflects average prices across a geographic area — it’s what most retail contracts are indexed to.

The scarcity adder is where things get interesting. ERCOT uses an Operating Reserve Demand Curve (ORDC) to add value to energy prices when reserve margins are tight. As available reserves fall, the scarcity adder rises, sometimes dramatically. During periods of extreme stress, ERCOT can hit its administrative price cap of $5,000 per MWh. In normal conditions, prices might be $30-50 per MWh. The range is extraordinary.

This is structural volatility, built into the market by design. The logic is that high prices during scarcity should incentivize new generation investment. Whether that signal is working as intended is one of the more contested questions in Texas energy policy right now. S&P Global’s framing is apt: pricing volatility is structural, not temporary. Policy risk must be priced explicitly.

The biggest players:

On the supply side, the most consequential market participants are pivotal suppliers (generators whose output is critical to meeting demand in certain conditions) and generators located in constrained zones (areas of the grid where transmission limits their ability to export power freely).

On the demand side, the most consequential participants are large loads and large flexible loads (LFLs). LFLs are loads that can respond to price signals by curtailing or shifting consumption — crypto mining operations are the most cited example, but industrial facilities and increasingly data centers fall into this category. These are not passive consumers. They participate in the market, and their behavior affects clearing prices.

The QSE (Qualified Scheduling Entity) layer sits between all of this and ERCOT’s central systems. QSEs are the market participants authorized to submit bids and offers to ERCOT, procure and offer ancillary services, and represent supply and demand. If you’re a generator or a large load, you either become a QSE or contract with one. They are the execution layer.

Part Five: Where This Is Going

So here’s where we land.

Texas has a deregulated, islanded, competitive electricity market operating at massive scale. That market is governed by a sophisticated pricing system that rewards efficiency and punishes scarcity. It’s growing, driven by population, industrialization, and now, significantly, by the AI and data center buildout that isn’t slowing down.

The S&P Global framing from their 2026 Global Power Markets Conference is worth keeping in mind as a calibration point for where institutional energy thinking currently sits: demand shock has become a structural shift, grid constraints are the real bottleneck, capital is available but selective — it’s going to bankable projects with reliable offtake, not technology promises. The behind-the-meter revolution is underway, as customers demand control, cost certainty, and resilience. And growth requires coordination across policy, capital, infrastructure, and operations. Technology alone won’t get it done.

None of this resolves cleanly. There are legitimate open questions: whether the scarcity pricing model can attract enough investment to meet the coming demand wave; how reliability standards will evolve as data centers require near-zero downtime; what the regulatory response looks like as ERCOT’s load forecast keeps getting revised upward; and how an average Texas household ends up experiencing all of this in their monthly bill.

Those are the questions worth tracking. That’s what TheGridLetter is here to do.

Energy isn’t a boring utility play. It’s the substrate of the modern economy, and Texas is sitting at the front of a wave that’s still building. The lights are on. The question is what comes next.

Sources and further reading:

• ERCOT public market data and reports: ercot.com

• Potomac Economics (ERCOT IMM annual state of the market reports): potomaceconomics.com

• U.S. Energy Information Administration (EIA), Texas electricity profile: eia.gov

• S&P Global Energy, Global Power Markets Conference 2026 (macro themes deck)

• PowerToChoose.org (Texas retail electricity comparison, Public Utility Commission of Texas)

• Public Utility Commission of Texas: puc.texas.gov