Who Dispatches
Vertically integrated utility, independent system operator, transmission system operator, and why the operator’s perimeter determines what a price can mean.
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.
Everything in Part Two (How a Price is Made) assumed an entity that sees and controls everything in the system, known as an operator. An operator receives offers, runs optimisation, decides which machines start, publishes price and instructs plants to move. That entity has appeared in every chapter so far without being described, and its identity defines the shape of a power market, or if a market exists at all.
Three arrangements exist. In one, the operator owns the generation it is dispatching. In another, it owns nothing and runs both the grid and the market. In the third, it runs the grid while somebody else entirely runs the market. In all three the operator runs the grid.
The utility that owns everything
The original arrangement, where everything is owned and run by a single entity as a vertically integrated utility, is still the arrangement for roughly 30% of US electricity demand. One company owns the power stations, the transmission lines and the distribution wires, holds an exclusive franchise to serve customers in a territory, and dispatches its own fleet to serve its own load at least cost.
Worldwide around 13% of demand is vertically integrated, 47% is a hybrid of partially unbundled and partially market facing, and 40% is a fully competitive wholesale market, according to the IEA. Vertical integration is close to absent in the European Union, where separating the transmission network from generation and supply has been compulsory since the Third Energy Package of 2009.
No wholesale price emerges from vertical integration, because nothing is being bought or sold. The utility decides internally which of its plants to run. Its customers pay a regulated tariff, and the tariff is set in a proceeding before a state commission, which reviews the utility's costs, decides which were prudently incurred, and permits a rate of return on the capital deployed.
Readers arriving from a market background tend to treat vertical integration as an unreformed existence. It survives across the US Southeast, most of the Mountain West and much of the Northwest. Instead of a market determined price, a regulator and a prudency review take place. Regulators approve how much capacity to build in an integrated resource plan. Whether a plant is worth building is answered by a prudency review. External feedback to a vertically integrated system arrives via a regulatory process rather than through a price, and the risk of getting it wrong sits with customers and taxpayers rather than with investors.
The operator that owns nothing
The American alternative arrived through FERC Orders 888 and 889 in 1996, which required transmission owners to offer other people access to their wires on the same terms they gave themselves, and Order 2000 in 1999, which encouraged the formation of regional transmission organisations. Seven independent system operators (ISOs) and regional transmission organisations (RTOs) now serve around 70% of US demand: PJM, MISO, CAISO, ERCOT, NYISO, ISO New England and SPP. None of them appeared in 1996. The orders made them possible and the building took a decade. ERCOT in Texas converted first, in 1996. PJM and ISO New England became independent operators in 1997, California followed in 1998 and New York in 1999, and MISO was the first organisation FERC approved as a regional transmission organisation, in December 2001, with SPP later still. PJM itself long predates all of it, having begun in 1927 as a pool between three utilities, which is where its initials come from.
What is the difference between an ISO and RTO? Independent system operator, ISO, is the older term, from the 1996 orders. Aregional transmission organisation is the status FERC defined in Order 2000, with twelve required characteristics covering regional scope, independence and authority over the network. Both run the grid and clear the market, and several bodies that took the newer status kept the older name on the door, which is why the two acronyms ISO and RTO get used almost interchangeably. ERCOT sits outside FERC's jurisdiction altogether, so the distinction never applied to it.
The defining feature of an ISO is that the operator owns no generation. It has no commercial interest in which machine runs, so it can in theory be trusted to be more fair and balanced with a decision worth billions a year to the parties on either side of it. Contrast this with an integrated dispatcher that owns a coal plant, facing an obvious temptation to hold that plant back, and risk a shortage, every time doing so would lift the clearing price paid to the rest of its fleet.
It owns no wires either, which raises the obvious question of who does. The lines, substations and transformers belong to transmission owners: investor-owned utilities, most of them subsidiaries of listed holding companies, alongside municipal utilities, member-owned rural cooperatives, federal agencies such as the Bonneville Power Administration, and a small number of independent companies that own transmission and nothing else. Those owners hand the ISO functional control, meaning the right to direct switching, schedule outages, dispatch across the network and plan its expansion. They keep the title, maintain the steel, and recover what they spend through transmission rates FERC approves. So the operator instructs assets it does not own, and the owner is paid a regulated return for building and maintaining them whatever the market does that day.
Distribution is a separate answer again. The poles, the local wires, the transformer on the street and the meter belong to the local utility, are regulated by the state rather than by FERC, and never pass to the ISO at all. The ISO itself is a non-profit, funded by an administrative charge on the participants in its market under the same FERC-approved tariff, so it recovers its costs and earns no return on anything. In PJM that charge ran between 56 and 59 cents per megawatt-hour in early 2026, against a wholesale energy price usually in the tens of dollars, and the organisation collecting it employed about 1,265 people to run a market serving 65 million.
How the owner’s return is set explains where utility capital has been going. FERC allows a transmission owner a return on the equity share of what it has invested, lately around 9 to 10%, plus 50 basis points for belonging to an RTO at all. An owner can also be allowed to earn on construction still in progress rather than waiting for the line to be finished, and to recover its costs if a project is abandoned for reasons outside its control. Most bill through formula rates that true up annually, so little time passes between spending the money and earning on it, and transmission costs are collected through charges on demand rather than on energy sold, so almost no volume risk attaches. Against the alternative of building a power station into a market that may or may not pay for it, this is one of the most attractive risk-adjusted returns in the industry.
The number is contested, and the contest can run a very long time. In March 2026 FERC set the base return for the New England transmission owners at 9.57%, backdated it to October 2014, and ordered roughly 1.5 billion dollars of refunds to customers, closing complaints first filed in 2011. Fifteen years is a long time for a rate of return to stay open. Europe answers the ownership question the other way, which is the subject of the next section.
An American ISO runs the grid and the market together, in one optimisation. The markets it operates are the day-ahead market and the real-time market of Chapter 9. The same calculation that decides which units are committed also produces the day-ahead prices at which everyone settles, which is why a locational price in PJM is a physical statement about the network rather than the outcome of a separate trading venue.
The operator that runs the wires but not the market
Europe divided the same three jobs: owning the generation, operating the grid and running the market.
A European transmission system operator, or TSO, such as RTE in France or Amprion and TenneT in Germany, owns and operates the high-voltage network, runs balancing in real time, and carries out the redispatch described in Chapter 15. Dispatch decides what runs; redispatch changes a dispatch schedule when the original schedule cannot physically be delivered. A European transmission system operator does not run a day-ahead market like an ISO does in the US. That is done by power exchanges, EPEX SPOT and Nord Pool among them, which are commercial businesses competing for trading volume, clearing an auction across bidding zones.
So the market clears at an exchange, against a simplified picture of the network, and the transmission operator afterwards makes the physical adjustments the exchange result requires. Chapter 15 describes the cost of that arrangement.
Watch the acronym. In the United States an ISO is the market and grid operator, as in CAISO or NYISO. In Europe an ISO is one of three permitted structures (ISO, ownership unbundling and the independent transmission operator) for separating a transmission network from the generation and supply business. A European ISO leaves the assets with the owner and hands their operation to an independent body. That body runs the network and nothing else. The market is still there, cleared by a power exchange as described above, which is what an American ISO would have done itself. So, confusingly, the same three letters, ISO, describe a different institution in the US and in Europe.
Those three European structures come from the Third Energy Package of 2009. Ownership unbundling, the strictest of the three, bars a generation or supply business from owning the transmission network at all. The ISO model just described sits in the middle. The independent transmission operator model, the lightest, leaves both ownership and operation inside the group under ring-fencing rules intended to secure non-discriminatory access. Most of Europe took the strictest of the three, ownership unbundling.
Table 14-1: How European (EU) electricity networks were separated
| Structure | Who owns and who operates | Share of electricity TSOs | Countries |
|---|---|---|---|
| Ownership unbundling | Neither. The network belongs to a company with no generation or supply business | 70% | 17 |
| Independent transmission operator | Both stay inside the group, under ring-fencing rules | 12% | 7 |
| Independent system operator | The group keeps the assets, an independent body operates them | 6% | 2 |
Shares are from the European regulators’ own status review of how the Third Energy Package of 2009 was implemented, counting electricity transmission operators rather than nat gas. They do not add to 100, because some systems hold derogations, mostly small or isolated ones, and a few were not certified when the review was taken. The two lighter structures were concessions to countries whose networks were owned by incumbents, chiefly Germany and France, which held out against full ownership unbundling until a compromise was struck in March 2009. Nothing has moved since: a 2019 recast of the electricity directive left the 2009 structures and adoption in place.
Three arrangements, side by side
Table 14-2: Who does what under each arrangement
| Vertically integrated | US ISO or RTO | European TSO plus exchange | |
|---|---|---|---|
| Owns generation | Yes | No | No, after unbundling |
| Runs the grid | Yes | Yes | Yes |
| Clears the energy market | No market exists | Yes, in the same optimisation | No. A power exchange does |
| Network model in the clearing | Internal, invisible | Full, thousands of constraints | Simplified to zone boundaries |
| Who bears a bad build decision | Customers, via the tariff | Investors, via the price | Mixed, depending on the capacity mechanism |
Why the American reform stopped where it did
The restructuring wave of the 1990s was expected to continue until it covered the remaining 30% of the US operating as integrated systems without markets. It stopped in 2001 due to California. California restructured, ran into the crisis of 2000 and 2001, and produced rolling blackouts, a bankrupt utility and a set of federal investigations. States that had been preparing to follow watched what happened and declined.
Chapter 2 covers what actually went wrong there, and the short version is that the failure had specific causes in a specific design rather than being an indictment of markets in general. What matters here is the institutional consequence. The map of who dispatches American electricity was frozen for two decades by a single episode, which left a third of the country outside organised markets and produced the awkward situation Chapter 17 has to describe.
The map is moving again
Now for the first time in twenty years, the market structure boundary is being redrawn, and the pressure comes from the same load growth driving Chapter 25.
The Western Energy Imbalance Market, a real-time-only arrangement run by CAISO, has delivered around 5.6 billion dollars of benefits since 2014 by letting western utilities share resources across balancing areas five minutes at a time. That success made a day-ahead version attractive, and CAISO launched its Extended Day-Ahead Market on 1 May 2026, with PacifiCorp joining at launch and Portland General Electric following in October.
SPP came at the same territory from the opposite end. Where CAISO grew a market upward, from a real-time imbalance service into a day-ahead one, SPP brought a full PJM-style regional transmission organisation with embedded day-ahead and real-time markets across from the plains. On 1 April 2026 it extended that organisation into the Western Interconnection, becoming the first such organisation to operate across two interconnections, covering utilities in seven states from Arizona to Montana. Its separate Markets+ offering has commitments from further utilities for 2028.
A western region that spent two decades as the clearest example of vertically integrated utilities coexisting without a market is now being competed over by two organisations offering to dispatch it. The pattern is familiar from Chapter 2: the arrangement changes when the technical case becomes overwhelming enough to overcome the institutional inertia, and rarely before.
What the dispatch choice decides
Who dispatches is the first of the three axes because it constrains the following two (location and capacity), discussed over the next two chapters.
A vertically integrated utility has no need of locational prices, because it has no counterparties to send a signal to, and no need of a capacity market, because its regulator approves construction directly. A grid operator that doesn’t own generation must produce a price, because a price is the only instrument it has for communicating between load (demand) and generators (supply). The further a system moves from ownership toward coordination, the more of its decisions have to be expressed as numbers that strangers will act on.
Chapter 15 takes the second axis, how location is priced, and Chapter 16 the third, how capacity is paid for.