Data Centres
Data centres, the interconnection queue as the real constraint, co-location and behind-the-meter, and who carries the risk when a fifteen-year grid asset is built for a five-year-old business.
Words the industry uses are marked like this at the sentence that defines them, so you can tell a term you will hear on a desk from a phrase this book happens to be using.
Data centres consumed somewhere around 4 to 5% of American electricity in recent years. Lawrence Berkeley National Laboratory's projections for 2030 span 9.5 to 15.3%.
A range that wide, from a serious institution, over five years, is the most informative thing in this chapter. Every participant in this industry is making twenty-year commitments against a forecast whose credible spread is a factor of one and a half, and the commitments are transmission lines, capacity auctions and power plants.
This chapter therefore concentrates on the parts of the situation that hold whichever forecast turns out to be right.
The queue measures interest
Chapters 17 and 18 gave the figures. Nationally the generation interconnection queue (generators waiting to be connected to the grid) has run to thousands of gigawatts, against a peak US current demand somewhat over 700. ERCOT's large-load queue passed 400 gigawatts against a peak near 91.
Those numbers describe requests rather than projects. A speculative developer shopping one power campus across six sites appears six times, and a queue position costs a fraction of what a data centre costs. Both ERCOT and the federal regulator reached the same conclusion within about two years and applied the same remedy: stop studying requests one at a time, study them in batches, and require applicants to demonstrate readiness to hold a place.
The constraint for anyone trying to build has stopped being the cost of generation and become the wait for permission to connect, which is a procedural problem rather than an engineering one. Developers are finding sites, constructing shells and even energising plants while they wait for permission to connect.
The plug in the side of the power station
If connecting through the grid takes years, an obvious alternative presents itself. Build the data centre next to an existing power station and connect it directly, behind the meter, bypassing the transmission system entirely.
The test case was Talen Energy's Susquehanna nuclear station in Pennsylvania, alongside which Amazon Web Services built a campus. When the parties sought to expand the behind-the-meter arrangement from 300 to 480 megawatts, the federal regulator rejected the interconnection agreement, and upheld that rejection on rehearing in April 2025.
The objection was about cost allocation rather than engineering. A large load sitting behind the meter uses the grid for backup when its host plant trips, and benefits from the reliability the transmission system provides, while contributing nothing toward its cost. Every dollar it avoids is a dollar recovered from everybody else.
The commercial answer arrived in June 2025, when the parties restructured the deal as a seventeen-year power purchase agreement worth around 18 billion dollars for up to 1,920 megawatts from the 2.5 gigawatt station. The transaction happened. It happened in front of the meter, through the market, paying network charges.
The regulatory answer followed in December 2025, when the commission directed PJM to write proper rules for co-location, creating defined service options rather than case-by-case adjudication, with further compliance orders on bring-your-own-generation arrangements through 2026.
The co-location fight is the oldest question in regulated utilities. When a large customer can partially exit the shared system, who pays for the shared system? The same argument was had about industrial self-generation and rooftop solar net metering, and it produces the same fault line each time.
Net metering is the one that has run furthest, and the way it resolved is the template. The original design paid exports at the full retail rate, which bundles the energy together with the network and the policy costs, so an exporting customer stopped paying for a system it still leaned on. The answer was to unbundle: pay for the commodity at avoided cost, which is what the utility would otherwise have spent on that energy, and charge for the network separately. California’s net billing tariff of April 2023 cut the average export rate by roughly three quarters, from about 30 cents a kilowatt-hour to about 8, and Hawaii had made the same move in 2015 with Arkansas, Arizona, Indiana, Louisiana, Michigan and Utah following. North Carolina added a grid access charge and a minimum bill so the network is paid for whatever the net energy turns out to be, and every one of them grandfathered existing customers for a term, which is what keeps a repricing from being a confiscation.
So the question has an answer, and it is the one the commission is reaching for in asking PJM to write defined service options rather than settling each case on its own facts. Charge the exiting party for the commodity, bill it for the network directly, and protect what was already built.
The assumption nobody had examined
Every queue, capacity auction and planning study in this book treats a large load as firm: present at full size, at every hour, forever.
A study from Duke University's Nicholas Institute asked what happens if that assumption is relaxed slightly. Examining 22 large balancing authorities, the entities responsible for matching supply and demand across a defined area, covering about 95% of national peak demand, it found that the existing system could absorb around 76 gigawatts of new load, close to 10% of national peak, if that load accepted curtailment for an average of 0.25% of its maximum uptime. At 0.5% the figure rose to about 98 gigawatts, and at 1.0% to roughly 126. By region at the half-per-cent level, PJM could take about 18 gigawatts, MISO 15, and ERCOT and SPP around 10 each.
A quarter of one per cent of a year is about twenty-two hours. The finding is that a very small quantity of flexibility converts into a very large quantity of headroom, because the grid is sized for a peak that occurs rarely and sits underused the rest of the time.
Duke University Nicholas Institute, covering 22 balancing authorities and about 95% of national peak. The finding is contested and its assumptions matter: that curtailment can be called where and when the system needs it, that load genuinely reduces rather than switching to onsite generation, and that the contracting machinery exists. Its contribution is that the firmness of large loads is an assumption rather than a fact.
The result is contested, and reasonably so. It assumes curtailment can be called where and when the system needs it, that the load can genuinely reduce rather than merely shifting onsite generation, and that the contractual and computational machinery exists to arrange it. None of that is free. What the study establishes is that the firmness of large loads is an assumption rather than a fact.
Data centres are also better placed to provide flexibility than most load. AI training runs can be paused and rescheduled in ways a steel furnace cannot, AI inference (day to day AI queries) can be slowed imperceptibly, and Chapter 7 noted that these are the first new loads in decades large enough, concentrated enough and sophisticated enough to negotiate about when they consume.
Whose risk is it
The durable question underneath all of this concerns duration mismatch.
A transmission line is planned, permitted and built over the better part of a decade and depreciates across forty years. A nat gas plant is a thirty-year asset. They are being built for customers whose industry is a few years old, whose demand forecasts have a fifty per cent spread, and whose siting decisions can change with a tax regime or a fibre route.
If the load arrives and stays, the investment is sound and the cost is spread across a larger base, which lowers everybody's bills. If it arrives, then consolidates onto fewer, more efficient sites elsewhere, the asset remains in the rate base and existing customers pay for infrastructure built for a tenant who left.
Which is why the serious regulatory work is happening in large-load tariffs rather than in market design: minimum take obligations, contract terms matched to asset lives, collateral, and exit fees. Those provisions decide who holds the risk, and they are being written now, mostly in state proceedings, at speed, with far less attention than the capacity auctions in Chapter 16 attract. If you move fast, sometimes things break.