Energy Literacy: 7 things you need to know about RTOs and ISOs

Blame it on Samuel Insull.

More than 100 years ago, the British-born immigrant (1859-1938) created the business model for America’s massive corporate utilities and interstate transmission lines, which became the foundation for the complex, increasingly expensive electric power system serving us today.

Beginning in the 1890s in Chicago, Insull marketed cheap electricity to American households and businesses by building large power plants and interstate transmission lines to achieve the economies of scale that allowed him to undercut or buy out any competition. By the 1920s, utilities controlled by Insull were providing power to an estimated 4 million customers in 5,000 cities and towns in 32 states across the country.

It was also Insull who came up with the idea for utilities to be granted regional monopolies regulated by state commissions and, in 1926, was caught donating $160,000 — about $2.8 million in 2025 dollars — to help a favored candidate win election to the U.S. Senate.

In other words, who controls the grid — how electric power is generated and gets to consumers, and who pays for it — has been an integral part of the evolution of the U.S. energy industry from its earliest days. Today’s grid operators — called regional transmission organizations (RTOs) and independent system operators (ISOs) — are the latest iteration of the system Insull built.

While often operating out of the public view, they are a major force in the U.S. clean energy transition, whether as living laboratories for innovation or gatekeepers limiting renewables’ access to the grid.

They have also been in the news a lot lately, in stories about rising electric bills and the resurgence of natural gas and nuclear plants to meet the rapid growth of electric power demand. 

I spent four years as a reporter and editor at RTO Insider, an industry trade publication that covers these organizations in at times exhaustive detail. I was actually writing for NetZero Insider, a spinoff of RTO, but ended up learning more about U.S. energy markets and transmission systems than any reasonable human being should. 

Which is that the history and current workings of RTOs and ISOs are incredibly complicated, encased in multiple layers of jargon and vitally important for shaping the future of our electric power system.

The industry is wrestling with the tradeoffs between the urgent need for additional electricity to power data centers and artificial intelligence, and the equally urgent need for the U.S. to accelerate its transition to clean energy to slow climate change and compete with China in global markets.

RTOs and ISOs are major players, and my goal here is to provide a bit more clarity and transparency about why and how, for better or worse, they control our electric grid. 

The history of the U.S. transmission system — how we got from Insull to today’s RTOs and ISOs — is not easy to condense into a few paragraphs of plain language, but here goes.

First, when we say transmission we are talking about the big stuff — the swooping wires and giant pylons running along highways or railroad tracks or across woodlands or open fields. These are the interstate lines that move large amounts of electricity across long distances at high speeds, as opposed to distribution, which are the local poles and wires that bring electricity to homes and businesses.

The evolution of transmission has always been about connection (reliability), economies of scale (affordability) and control (access). In the Insull era, individual utilities had their own, self-contained distribution and transmission systems, which meant they couldn’t provide backup power to each other in emergencies or times of high demand, a problem that came to the fore during World War I. 

The next step was the creation of power pools, voluntary groups of utilities that coordinated the planning and operation of electric power generation and transmission in specific geographic regions so they could send or receive power across their systems. PJM Interconnection, the RTO that now covers 13 Mid-Atlantic and Midwestern states and the District of Columbia, started out in 1927 as a power pool, the Pennsylvania-New Jersey-Maryland Interconnection.

The catch here was that regional planning and operation were still controlled by the vertically integrated, monopoly utilities, which tend to be anticompetitive by nature.

Deregulating state energy markets and opening them up to competition – which occurred between the 1970s and ‘90s – was aimed at cutting costs and breaking down or at least loosening the grip of the corporate utilities in some states. The early results in a few cases were disastrous – like California’s energy crisis of 2000-2001, with its soaring prices and rolling blackouts – allowing utilities to maintain control of regional grids and keep independent power companies out.

Enter the RTOs and ISOs. Under a series of federal orders, these grid operators were created as nonprofit organizations that would ensure reliability, foster competition and affordability and provide open, equitable access to interstate transmission systems for all forms of generation. 

So, what’s the difference between an RTO and ISO? It’s minimal and mainly geographic. An ISO can serve one state or multiple states, while RTOs are by definition multistate systems.

At present, the U.S. has seven RTOs and ISOs, covering about two-thirds of the country (the map here is from the Federal Energy Regulatory Commission, commonly called FERC). The ISOs are ISO-New England, the New York ISO, the California ISO and the Electric Reliability Council of Texas (ERCOT).

The RTOs are PJM and the Southwest Power Pool. MISO — the Midcontinent ISO — is both an ISO and RTO. 

With the exception of ERCOT, all the ISOs and RTOs are regulated by FERC.  Texas did not want its grid to be federally regulated and so has carefully limited its connections to interstate systems. It’s a rule unto itself, which has allowed it to do some interesting, innovative things, more on which later.

What’s going on in the Southeast and West would require another article to untangle. As per the map, neither region has an RTO or ISO, and whether the states involved will form one of their own or join a neighboring entity is an open and complicated question (which RTO Insider has been covering with insightful detail).

Here’s where things get very wonky. RTOs and ISOs don’t own anything — power generation or transmission. Rather, they operate their regional systems, including various markets that ensure enough power is produced and sent wherever it’s needed on a moment-by-moment basis, as reliably and affordably as possible. 

There are day-ahead markets, real-time markets, ancillary services markets, capacity markets and energy imbalance markets (follow links for detailed definitions). 

They also regulate how much and where new power can be connected to the grid, as well as determining when and where to upgrade existing transmission lines or build new ones to ensure new power can get online to meet growing demand. 

It all sounds pretty straightforward, but how and how well individual RTOs and ISOs perform these key functions varies widely across the country.  

Let’s start with interconnection queues, the pipeline of new projects that apply to RTOs and ISOs to get connected to the grid. 

In the early 2000s, the projects applying to get online were mostly big fossil fuel or nuclear plants — not too many a year — which were processed on a first-come, first-served, case-by-case basis. The advent of solar, wind and storage, with hundreds of projects applying for a grid connection, resulted in backed-up queues, with projects waiting years to get online. 

PJM essentially shut down its queue in 2022, accepting no new applications till it cleared its backlog, which it expects to do sometime in 2026. Similarly, MISO skipped a cycle in its interconnection process, giving itself a year with no new applications so it could work through its backlog. 

According to figures from interconnection.fyi, a website that provides regularly updated tracking of interconnection requests, the U.S. currently has about 2,000 GW of new electric power projects waiting to get online, most of which are solar, wind and battery storage. The average waiting time, from application to getting connected, is three to five years.

On the plus side, changes to interconnection processes are being made, with a strong push from a 2024 FERC order, and queues are shrinking (which I wrote about here).

Another sign of progress, PJM recently announced a new partnership with Google to use AI to speed up its regional planning and interconnection processes.

While RTOs and ISOs are supposed to ensure that all forms of generation have open and equal access to transmission, in practice, they can influence or prioritize what projects are approved and when. 

One example: The queue backlogs — along with lack of timely planning for new transmission — have meant that some fossil fuel plants scheduled for retirement are being kept online. 

In the meantime, utilities and some RTOs are responding to the expected explosion in demand growth from data centers and AI by setting up emergency interconnection queues to allow certain projects to jump to the head of the line. 

PJM was the first, setting up a special process that in less than six months resulted in 54 projects — most of them natural gas and nuclear — being cleared for grid connections ahead of dozens of renewable projects that have been waiting for years.

MISO and SPP are also in the process of setting up fast-track interconnection processes, again with natural gas plants being prioritized for approval. 

The RTOs have said these initiatives will be temporary or one-time exceptions to their regular approval processes for new generation. But given ongoing growth in electricity demand — and President Trump’s war on clean energy — additional queue jumping would not be surprising. 

Renewables are also subject to generation bias at some RTOs and ISOs; that is, solar, wind and storage may be classified as “intermittent” and “unreliable” and rated differently — lower — than the fossil fuel or nuclear plants seen as 24-7 power. The lower rating means that in some cases, renewable projects are counted differently and are less likely to participate in certain markets.

The reliability arguments of these RTOs are being upended by other grid operators that are prioritizing renewables and adjusting the way they operate their systems to take advantage of the dynamic and flexible power they provide. 

California and Texas are the two states that in recent years have faced real energy emergencies, respectively from wildfires and extreme winter storm weather. In both cases, they have worked on grid upgrades while bulking up on renewables and storage and speeding up permitting and interconnection. 

ERCOT has a unique “connect and manage” strategy for interconnection, which allows new generation to quickly connect and provide power to the grid, with the caveat that a project may be curtailed — essentially, disconnected — as needed to balance supply and demand.

In the wake of the catastrophic 2018 wildfires, California raised its target for energy storage to 52 GW by 2045. By the end of 2024, the state had installed 13.3 GW.

Both states now have more than 50% clean power on their transmission systems, which has allowed them to ride out heat waves and other extreme weather events. (Find out more in my Energy Literacy piece on inertia, here.)

So, what does all this have to do with rising electric bills?

The answer here involves getting a bit wonky about capacity markets, which are the yearly auctions some RTOs and ISOs hold to lock in power to meet their anticipated future demand. The way it was explained to me is that the grid operators choose a bunch of power plants to put on retainer — they pay them a certain amount to be on standby at a future date, whether their power is actually needed or not.

PJM’s recent capacity auction in July was nailing down power for 2026-2027. Due to growing demand and backed up queues, less power was available to reserve for the future, and for the second year in a row, prices spiked.

In 2023, the going price for the projects on standby in PJM was about $28.92/MW-day. In 2024, the price was $269.92 and the most recent auction came in at $329.17. (A MW-day is the equivalent of the power a 1 MW plant would produce over 24 hours, or about 24 MW.)

In laymen’s terms, we’re talking increases of billions of dollars, which trickle down from the RTO to utilities and their customers. 

Which is why understanding where your power comes from, how it is generated and who is controlling the whole process is so important. Backed-up interconnection queues, implicitly discriminatory practices and putting more fossil fuel plants on the grid will almost certainly lock in price increases for years to come. 

Renewables and well-planned transmission have their costs — electric bills are going up, period — but in the long run, clean energy will keep the grid flexible and reliable, the earth cooler and utility bills lower. 

We must insist that our grid operators work openly and transparently to ensure that we have the connected, reliable transmission we need and that renewables can connect equitably and at speed.