So what’s coming apart under the stress of all this?

As the information network and data center industry, known for the slogan “move fast and break things” collides with the electric utility world which has slogans 180 degrees opposite, a raft of conventional wisdom is failing. Both the economics and the industry ways of doing things are getting turned upside down. Note at the outset: the idea from State of the Union of customers building electric supply is not new. This was common first with paper and lumber mills burning wood for steam, then in a broad expansion of cogeneration of steam and power at industrials during the 1980s and 1990s, and now with rooftop solar boom of past decade.

Push to increase supply with increased costs

The utility industry originally expanded without raising costs through economies of scale, then with consumer energy efficiency, and most recently with renewable energy. The rush to build supply has scrambled economics with differing emphasis on basic priorities of speed, reliability and cost accountability.

Amongst the data center companies, powerplant economics are a mess. The rush to build supply has bid up the cost of conventional gas-fired plants (and deliveries are back-ordered for 5+ years). To work around that, big tech companies are bringing small truck-mounted turbines designed for short-term or peak use by the dozens. This is the opposite of economies of scale. These generators have roughly 50% higher fuel costs than a utility-grade combined cycle gas-burning plant, and the maintenance of a field of engines is multiples more expensive. That also means 50% more emissions pushed onto the local community, and tempting opportunities for developers to play fast and loose with air permitting rules. This is just a boom-town mentality that jeopardizes everything in the name of speed.

The two dominant existing economic structures for paying for plants reveal serious issues when seen in perspective. Where the old utility structure is still in place and costs are passed on to consumers, utilities are building expensive gas-fired generation and spreading the costs to all consumers. That is, when cost accountability is lost, the costs to consumers aren’t controlled.

In Texas competition is the governing principle. Texas (ERCOT region) does not have protected monopolies in the powerplant business and a costly decision is borne by the owner of that decision. In Texas, wind, solar and batteries are the dominant new supply additions from 2021-2025, and also winning in 2026 on both price and speed to market.  This competitive structure recognizes the falling costs of solar panels and battery storage, and gets new supplies added quickly.

Utilities’ costs claims

Utilities like to say they lower costs by adding more customers, but this old logic worked either when incremental supply was a lower price than previous supply, or there is existing unused capacity to serve new customers—neither are true today. Another utility favorite, making the data centers pay their fare share, breaks down when the data centers evade the basic principle of rates that those who cause the costs must pay the costs. This is most clear with transmission connections, but also with the spreading of costs of new, higher cost power supplies. Much of the proposed legislation seeks to sort this, as business-as-usual policies were established under assumptions that each customer was small and spreading costs was fair and reasonable.

Basic policies upended in current rush

Monopolies

So what’s on the policy-making agenda to allow data centers to transform the electricity industry? The biggie—utilities’ monopoly to connect and sell to new customers is threatened by the most dramatic schemes of data center plans to build off-the-grid, and generate all their own power. This expansion of the concept of a micro-grid has been enabled by legislation in a few states, as it revises the idea of a service territory franchise for the regulated monopoly with an obligation to serve. This scenario requires connections to a gas pipeline, a fiber communications network and probably a water source, but no electric utility connection. The data center developer brings their own electric supply attached to their new demand for that electricity. Utility companies hated this idea when US military bases tried to strengthen their resilience (and war-fighting ability) with power plants on-base. The Defense Department lost that fight in the US but use the on-base, mobile generator-approach when operating off the grid in hostile locations.

Planning

In normal times, utilities’ planning aimed to maintain reliability with gradual change and some direction from state clean energy laws. The data centers’ drive for speed is overwhelming all that. In simple terms, a data center can be built much faster than a new utility power plant. New transmission needs more time too. The largest utility planning organization, PJM, with an area of 13 states, the District of Columbia and the greatest concentration of data centers in the world began changing its transmission planning calculus in 2023 but hasn’t started to use that new approach. In the meantime, PJM has been unable to get new supplies connected to the transmission system fast enough. Late last year, after a few years of record high prices for new supplies, PJM conceded that the supply committed for summer of 2027 is not enough to be reliable as PJM normally defines adequate supply. This is a bad situation.

Expect more wonk in a utility discussion

To fill out this landscape survey, we need a few fundamental assumptions about how the rules work for electric utilities, public health and safety, and competition.

Fed-State jurisdictional boundaries

States have a range of authority related to heath, safety and consumer protection under the US constitution. At the start of his current term, President Trump declared an energy emergency and began down a path of scrambling assumptions and authorities. One extraordinary move has been issuing orders under Federal Power Act Section 202 (c) to keep fossil fuel plants from retiring, regardless of the owners’ economic decisions. These orders also override state air pollution limits, and a lot of other state protections. To speed data center expansion, the US DOE seeks proposed rule changes to widen Federal electric utility regulation with 14 proposed reforms that get into costs, planning, monopolies, obligation to serve described above as largely in the states’ authority. So far, states and utilities have opposed much of this. In a flip-the-script move, Utah requested that the Nuclear Regulatory Commission expand the state’s authority on microreactor licensing, fuel storage and reprocessing.

What new supplies to connect and how

Central to the idea of competition in the US electric power industry is open access to the transmission grid. New plants have been allowed to compete since the 1980’s with the assumption that they would have equal access to getting connected to the grid. After gridlock in that process that’s plagued new competitors, primarily wind, solar and batteries, this assumption is being swept aside. Policy changes, some subtle and others less so, are creating fast lanes and set-asides for new gas generators. Totally lost in all this are the quickest new sources available from virtual power plants linking existing distributed resources and procurements of energy efficiency and capacity. This makes a bad situation worse.

Another key rule for the energy supply broken by the current administration is the validity of permits and leasing processes that have been completed. Offshore wind projects with have been most reported, but federal lease agreements with renewable energy and their permits have been decimated by the Department of Interior. The impact on consumers in the Northeast is clear from this interference, as offshore wind contracted to the states make a significant contribution when gas supplies are exhausted and energy prices are high. In the midst of a bad situation, this is unconscionable.

Looking forward to a new change

In any crisis, new opportunities can arise. At the moment, the assumptions about energy storage (mostly batteries) are evolving quickly. Texas has met considerable demand growth with 2-hour batteries. California has adopted 4-hour batteries. In the data center world, some are saying storage is non-optional. Where utilities and data center companies have seen the future, significant new energy storage is in the plans.

The stress of so many data centers, often incredibly large, pushing demand for electricity is reshaping the electric power industry. The reforms proposed and already made to aid the data centers will have implications for the health and safety, as well as economic well-being of citizens in every state. Both state and federal policymakers have a role. Take this up with them.

That’s the clear takeaway from my study of data center transmission costs from earlier this fall.  My examination of utility filings showed costs shifted by local utilities to consumers in 2024 was at least $4.3 billion in just seven states (and $3 billion more in 2025) within the territory of PJM, the grid operator for the Mid-Atlantic (you can read the full policy paper here). In the weeks since, a consensus emerged that a review and reform of this practice is due.

A moment of consensus

Late last week, the US Secretary of Energy pushed for the Federal Energy Regulatory Commission (FERC) to begin a rulemaking regarding connection of large loads. That led FERC to initiate a rulemaking process the next day, the first formal steps to adopt rules requiring data centers pay their grid expansion costs. The US Secretary of Energy recognizes that pushing costs from data centers onto the bills of other consumers is a widespread and continuing problem. Prior to my report, these costs were a footnote in advocacy efforts. Now, the Secretary of Energy has put the solution on a fast track.

With the actions last week by Republican appointees, this appears to be a rare example of a bipartisan policy.  Past statements by members of Congress  and multiple public opinion polls show this is a widely held position.

For consumers, this part of the proposed rule change comes as welcome news. But this initiative also contains ideas that are not so consumer-friendly, such as changes to boost building gas-burning powerplants which will raise consumer costs and lead to more unhealthy carbon pollution. (And as a reminder, over two thirds of the country prefers renewable alternatives over increasing fossil fuel sources.)

Action is needed from FERC, as more data centers are coming and their transmission-connection costs will only grow beyond the billions of what I initially reported. Preliminary information shows $3 billion more in data center connection costs have made it through the first half of the process described in the earlier blog. And this is just a slice of the pie: many other states are seeing data center construction, but their respective utility cost shifts are obscured.  

State regulators are responding to reform suggestions from utilities at the same time that some of these issues need attention from FERC. UCS is active in cases in Illinois and Pennsylvania as data center policy is unfolding rapidly. Without some standards, that unfolding could lead to unraveling, with costs and reliability as collateral damage.

Billions in data center costs already paid by consumers

Here’s an update following the same process as my earlier study, accounting for some updated 2024 projects, definitive plans for 2025, and preliminary signs of more coming.

The utilities continue to plan and build transmission connections for data centers. In some instances, they have raised the cost for a project. In others, additional work on the grid was identified and is now included, raising my earlier summary of total costs carried by consumers within PJM’s territory for 2024 from $4.3 billion to $4.6 billion.

An identical process was conducted to examine plans within the region for 2025, which uncovered a projected $3.1 billion in data center transmission costs—all of which is expected to be paid for by consumers.

The third category is a count of the projects on the horizon for which the design and cost projections have not been prepared yet by the utilities. But the average cost-per-project over 2024 and 2025 was roughly $42 million—so if that holds, consumers would be on the hook for another $4.3 billion in costs from those 102 projects.

Reforms cannot wait

Just as in our September report, these numbers summarize the presentations made by utilities for planning their transmission and collecting payment from all their customers.  In September, we called for state and federal regulators to prevent these costs from falling through a gap and ending up on consumers’ bills.

Now, surprisingly, there is a policy consensus emerging and a formal proposal from the federal government to make this right.  We will make formal comments, arguing for clear and binding language for these new rules. The Secretary of Energy put a deadline of April 30, 2026 on this rulemaking.

There is likely going to be a jurisdictional fight from utilities, but we suspect the big data companies will accept these new rules if that speeds up the grid connections they so clearly want and need.

This problem stems from the jaw-dropping, unprecedented size of the electric demands of new data centers. Many data centers built recently have the electricity demand of small cities. New proposals for data center campuses have power demands comparable to the total power plants in small states.

Through a review of planning documents across states within the grid operator PJM’s jurisdiction, I found 130 examples of electric utilities connecting data centers to the grid with very expensive new lines while passing costs to consumers under old rules. From most perspectives, this is morally wrong and bad policy. However, from the perspective of the rules for electric companies making routine expansions of their transmission and distribution wires, this is standard practice.  

I have a lot of respect for what the utility industry does to keep the lights on, but this is a case where the old proverb  “With great power comes great responsibility” must be applied. The regulation of utility monopolies should provide affordable and reliable service for consumers and predictable terms and conditions for the utility business.  The data center boom is a historic business opportunity for the electric sector, and utility companies are aware consumers are already facing risks as a result. 

Utilities’ feeble reforms

Around the country, consumers are alarmed by rising utility bills while utilities are responding with insufficient changes to ensure that the large new data center customers are held responsible for simply paying their own bills. While the explosion in electric demand from data centers is leading to new spending for power supplies (covered widely by the media ) and costs for the wires to connect the data centers (subject of my new analysis), the flurry of reforms aim to set minimum commitments from the data centers to put up deposits and ensure that they will pay their bills for 10-15 years.  

These reforms do not change who pays for the new costs. The costs for both the new power plants and the transmission—even the wires to the data centers’ buildings—are paid for collectively by all the customers of the respective host utilities. Rates set by state and federal regulators have not adapted to costs caused solely by very large customers. The current practice assigns costs with outdated assumptions, illustrated in the graph below, with wires costs on the left side and customers paying on the right. The new costs from large customers’ transmission-level connections is shown in red.  

What are we paying for?

Totaling $4.3 billion in 2024 alone, the costs for the electric connections that extend from the existing transmission lines to the data center customers are immense. These are costs for directly connecting the data centers, often including new transformers and gear on the property of the data center. Many of these individual connections cost between $25 million and $100 million. The one-year totals for seven states are shown in Table 1 below. 

I’ll show you what I found. 

Utilities in the PJM regional transmission organization provide a brief look at the transmission they are planning for local needs, which includes improvements for customer service as well as replacing old equipment. For example, one transmission upgrade in Maryland, just north of the Virginia border, is shown in the two utility company slides below. (Other utilities plans can be found here.) 

This slide shows the need identified by the utility, which has a tracking number, marked with arrow at top. The lower arrow points to the description of a single customer that wants to use 300 MW (a city’s worth of demand), and they want it available as soon as possible. 

In the second slide, the utility describes how it will meet this need. The tracking number at the top is the same, and I have circled in yellow the drawing of the single new customer. Lower on the slide are descriptions of the investment the utility will make for this customer, with costs of $20.8 million plus an additional $14.6 million, and new tracking numbers for the construction of these facilities. Those tracking numbers, s3150.1 and s3150.2, will show up in the PJM Regional Transmission Expansion Plan as “Supplemental Projects.” 

The notoriety of the local plan

When these data center direct connections are included in the utility’s locally planned transmission plans, they become part of the regional transmission expansion plan without regulatory review. In addition, this step also allows the utility to include the costs in transmission rates. This sequence of essentially automatic approvals has caused controversy and calls for reform, even before the rise of data center costs.   

While the PJM process described here is more transparent than in many states and regions, every utility has the means to develop new transmission to connect new customers. This is a central function for electric companies. What is new here is the enormous size of these new customers and the eye-popping costs that their connections require. The size of these customers requires connection of these individual customers to the transmission system, a scenario not routinely anticipated by the rules for assigning costs to customers that cause those costs. 

A $4 billion loophole that gets bigger each year

Because of a gap in regulatory jurisdictions, the transmission costs are bundled together, filed at the Federal Energy Regulatory Commission (FERC), and then sent to the states as one amalgamated cost. The information describing the cause of certain costs as due to a single customer is lost. The rules for customers are generally set by the states, while the rules at FERC are only applied to wholesale customers and not meant to apply to retail customers.

When these enormous new customers arrived in recent years, their costs were allocated without respect for the principle of cost causation. Usually, regulatory decisions aim to assign costs to the entities that cause those costs. This problem needs to be fixed. Early indications for the coming year reveal $2.5 billion for more data center connections in these seven states so far, and dozens more in progress. 

Follow the money

The utility process for putting transmission costs onto customers’ bills follows from the regional expansion plan, as shown below. The two projects shown with red arrows are the same projects as shown above, with the tracking numbers on the left and the costs on the right. This is an excerpt from PJM’s 2024 Regional Transmission Expansion Plan reflecting the utility’s local plans.

When the annual costs for this utility’s transmission system are calculated, any costs in the Regional Transmission Expansion Plan are included, even these customer connection costs. That amalgamated cost number is carried over to the rates presented for customers bills at the state utility commission. The costs for transmission are spread to all of the utility’s customers, as illustrated by the graph of money flows above.

This spreading of costs isn’t illegal. It is simply out of date. Unfortunately the impact is very real. The wealthiest companies are building extraordinarily expensive data centers that you and I are subsidizing. Our policy brief walks through this problem and provides recommendations for several ways to assign the new costs to the customers that cause those costs. That is a responsibility of the rate-setting utility commissions. Our policy brief shows where to find the evidence needed to make this change. We are taking this argument to the regulators and telling everyone: data centers can pay for their own needs.

The brief can be found here. The accompanying appendix can be found here. 

There’s no question that data centers use a lot of electricity. Before AI-related data centers came onto the scene, electricity demand in the US grew very little for a decade or more. Now, Virginia has more data centers than anywhere, and in 2023 those data centers used over 25% of electricity sold in the state.

This sudden spike in electricity demand—on track to far outpace the growth in supply—raises unique challenges. The data center industry believes they are in a race to build computer capacity for artificial intelligence (AI), and meeting the data centers’ electricity needs is key to their growth. Getting enough electricity is limiting the development of data centers. And so, desperate times call for desperate measures, like Microsoft co-locating data centers with nuclear plants, or Meta commissioning the construction of dirty fossil fuel plants to power data centers. To understand conversations about co-location, here’s some basics that you need to know.

Why do data centers need so much energy?

There are two reasons why data centers are quickly growing as part of our electricity demand. One is simply more things we do require access to shared data, such as shopping online, streaming videos, and business communications. But growth from artificial intelligence data processing is the big driver for more data centers and more energy demand at each data center. AI requests require more data analysis than typical internet searches or even cryptocurrency mining, which in turn requires more energy—take a look at my colleague’s recent blog post on the topic to understand just how much we’re talking about. The next step up in energy-hungry activity is generative AI.

Electricity demand is so key that a data center’s size is routinely described by how much electric energy it requires. A 50 megawatt data center has the energy demand of a small city. But new data centers are now proposed to be 500 megawatt, grouped on campuses with electric demand greater than nuclear plants.

Most data center energy use is consumed by data processing computer chips, but this work also produces a lot of heat; the processors can run as hot as 175°F, and the cooling equipment needed to keep them from overheating  accounts for roughly 20% of the total electric energy consumed by the facility. Most data centers use conventional air conditioning for this purpose, but designs are available that keep the processing equipment submerged in mineral oil or similar liquid that is inherently more efficient than using air to absorb and move heat.

How do data centers get the electricity they use?

Today, thousands of data centers are attached to the electric power grid, like any other building or facility. The energy use is more intense than most buildings (often described as ‘energy dense,’ as in kilowatts per rack or cabinet), but until recently, most data centers were not so large as to overload the electric grid. That is no longer true. Commonly used AI processing chips were using 6-10 kilowatts per rack, which is a bit more than what my level 2 electric car charger in my garage can draw. Now, chips using 30–60 kilowatts are widely used. New data centers fill a large building with rows and rows of such cabinets.

All this growth in demand requires building the needed electrical supply for data centers as a central part of the growth of AI. Teaming up with an existing nuclear plant is just one of the dramatic approaches data companies pursue now.

Will data centers choose clean renewables or dirty fossil fuels?

Let’s look more closely at how the race to build AI is now a race to build more electricity supplies. Besides the five companies that own 39 US nuclear plants outside of monopoly utilities, the greatest opportunities for new data centers are in combination with new generation. The usual practice for typical growth of electricity use in the United States doesn’t require a new consumer to do more than call the local utility to bring a new pole and power line to the new business or residence.

Now, with data centers using as much energy as cities, that’s not going to work. The conventional approach to meeting the added demand from data centers requires more transmission lines, which can take 5-9 years to plan and build, as well as completing the construction of new power plants, which also require more transmission lines.

The options for today’s data center developers in a hurry are either to join in building fossil gas power plants or join in building clean energy power plants. The coordinated scheduling and planning of both supply and demand allows clarity of needs and solutions for these enormous investments at a time when confusion and delay are widespread in the electric industry over data centers.

Do data centers have a history of independent power generation?

Data centers, and other vital facilities, commonly have some amount of on-site electricity generation as a back-up for grid outages. The conventional approach in the past was an inexpensive, but inefficient internal combustion generator that was not expected, or permitted, to run much. Today, as developers’ ambitions grow, they have expanded this in hopes of bypassing delays in transmission expansion or the costs of transmission, or both.

The progression has moved from bringing data centers to existing generators to building both new data centers and electric generation where there is an untapped energy resource. This can mean using wind, solar, or fossil gas generators built with the data center. Broadly, the idea is to have redundant generation, such as solar plus batteries plus the grid connection, to improve the reliability above what “going it alone” might provide. For now, there is no standard approach to meeting the physical and legal challenges to on-site power supply. Further complicating matters, the global capacity to build conventional energy infrastructure, including gas-fired generators is already stretched to meet new demand.

There are already examples of using renewable energy attached to data centers to meet corporate and public goals. The most prominent example is Google planning to bring your own new clean energy, “BYONCE” (not to be confused with Beyonce’s song “Energy”).

Can on-site power production reduce costs on consumers imposed by data center growth?

Customers adding on-site electricity production is familiar these days. Millions of Americans have solar on their roofs. An even earlier arrangement, industrial cogeneration of heat and electricity, provides greater efficiency and cost savings for large energy consumers. In those situations, electricity flows to the grid when the on-site supply is greater than the demand, and power flows from the grid to the customer when more is needed than is being produced. These clean and efficient energy additions lower energy costs for everyone, especially when overall supplies are tight. When renewable energy supply goes up, prices go down.

Looking ahead, the role of data centers will be important for the cost of energy in the US. Unless there are many adopters of BYONCE, consumers’ costs will be going up in response to generator shortages and transmission needed for data center growth. Health and environmental costs will also rise if fossil fuels are used directly for the data center, or to replace a nuclear energy supply now dedicated to data center use.

Which regulators can protect consumers from costs from data centers?

Sales of electricity from a power plant to a data center is a retail sale, which are regulated by the states’ public utility commissions as part of the supervision of utility companies. States should require data centers to pay for any additional generation, grid upgrade, and operating costs to protect consumers from potential cost increases. While developers will claim that on-site generation allows them to avoid these costs, that is not the case.

The Federal Energy Regulatory Commission has opened an inquiry into the rules for a data center at the site of a nuclear plant. A decision should clarify options and opportunities for improvements over the current wholesale requirements, which are limited and few. Federal law describes electricity sales as “affected with a public interest” and primarily regulated by states. Some states are starting to set rules at their own pace, leaving a patchwork.

Why do data centers want to locate adjacent to nuclear power?

Before data centers arrived, nuclear power plants supplied regional power grids as some of the largest electric generators built. Nuclear plants usually have a large land area around them as a safety and security buffer that excludes customers’ facilities. Now, a few nuclear plant owners have made deals for data centers to be built adjacent to existing nuclear plants. This is not workable at every US nuclear plant, as half of the 94 reactors are more than 40 years old and only 39 are owned by independent companies that could make new deals to sell their electricity directly to data centers. Also, a recent update on nuclear plant safety from UCS is a reminder that old plants may not be a good solution for the future.

The information technology industry has become interested in nuclear power recently because some tech companies have carbon-reduction goals that they fear cannot be fully achieved without nuclear power. Several tech companies have purchased large amounts of renewable energy, primarily electricity from wind and solar. Some tech leaders have bought into the grand plans of new nuclear power companies that offer unlikely promises of new designs and easy access to the electricity vital for future data centers.

However, new nuclear plants are not likely going to meet the demand from data centers easily, starting with delays to building conventional new nuclear plants, untested new designs, high costs, and the lack of solutions to nuclear power’s problems.

The spread of AI data centers is larger, more numerous, and faster-growing than anything that has come before to the electric utilities. The potential for this to cause supply shortages and costs for consumers is plain to see, and yet also falling through gaps in the existing rules. Dialog between the larger data companies, some utilities and some regulators won’t solve the problems right away. This is going to take some time and effort. Investors, elected officials, and everyday consumers need to keep asking questions.

Broadly speaking, developers of data centers, which house the computers and servers that run AI tasks, are looking for three things: places to build, electricity to buy, and physical connections to the electric grid. The boom in forecasted electricity demand from this development has not been seen in 50 years. All of these proposed new data centers will require electrical hardware and grid improvements built by utilities. The electric power industry and its supply chain of manufacturers are backlogged and overwhelmed by the requests from data center companies. Water supplies used by data centers are stressed, too. 

One move by tech companies trying to build data centers faster is to bypass the utilities and attach new data centers to existing power plants. Owners of independent power plants (i.e., plants not owned by the local utility) are making deals to provide data centers with land, the grid connection, and the electricity, with the expectation that they can cut out the local utility entirely and avoid paying the utility to maintain the grid.  

You can imagine how appealing such a power grab—pun intended—looks to the companies that will benefit from it. Investment analysts say this is more profitable for the power plant. And they can avoid the queues that take years and years to move through in order to be approved to join the grid. Tech companies are so hungry for new data centers that they are pursuing deals to reopen shuttered nuclear plants, or build new ones with untried designs. The notion that an existing power plant can serve a data center, and not use the grid, is now before regulators for consideration. 

Attempts to bypass grid prompt federal inquiry 

The Federal Energy Regulatory Commission (FERC) has opened an inquiry into whether there is a justifiable reason to give data centers across the 13-state PJM region a discount by not paying for the electric grid. This financial break is premised on numerous deals with individual generators that claim to bypass the usual arrangement by which utility companies attach customers into the grid. Instead, the data centers want to have an exclusive connection to a single power plant and receive energy only from that one plant (plus whatever emergency power supplies they build on-site for back-up power). This is like showing up at the hospital for surgery, and saying you only want to pay for the few minutes the surgeon held the scalpel. Your surgery won’t happen without the rest of the supporting services. 

This inquiry will shed light on the murky claims that data centers are not using the grid if they have contracted to buy power only from an adjacent power plant. The view of PJM, the grid operator for Virginia and surrounding states, is that the data center is still “dependent on the reliable operation of the grid,” with its market monitor calling any claim to the contrary “just non-realistic.”   

Fact Check: Data centers will still be reliant on the grid 

Frankly, we agree with PJM. At the heart of this dispute over whether the data centers can avoid paying for electric utility infrastructure is the false claim that a direct connection to a generator means the data center is not supported by the grid. Since the generator is connected to the grid, and relies on the grid, this claim is suspect. The details prove that suspicion is correct. 

A closer look reveals that the single biggest challenge to this claim is the misconception that a data center has a smooth and unchanging demand for electricity that can be met by the host generator alone. In reality, data center energy demand fluctuates very rapidly from minute to minute, as well as on very short time scales—less than one second. Again, the fast-moving, computer-based data centers collides with the slow-moving, physically constrained electricity supply. Researchers have documented rapid changes in the demand for electricity at the start of computing tasks, and then the gyrations in electricity use while data is processed.  

Turning computer processors on and off for large computational tasks causes power demand to fluctuate, unpredictably. Utilities report cases where data centers change demand as much as 300 MW in 24 seconds—the equivalent power usage of Springfield, IL. In an industry-wide survey by the Electric Power Research Institute, 26% of responding utilities described challenges in balancing  supply and demand while data centers are operating. Other electric industry representatives describe data center behavior as causing problems for the supply of electricity, even in the usual arrangement where the data center is attached to the grid.  

Again, fluctuation in power demand means they can’t ‘go it alone’ 

Simply by looking at the changing demand, it’s easy to see these variations in demand (called “ramps” by utility operators) move faster than a solo generator can follow. If the change in load is faster than the adjacent generator can match, as these reports are all describing, the imbalance in the power flow will be the absorbed by the grid. This is exactly why a grid-connected generator can’t go it alone as a supply for a data center. 

When FERC rules on the issue of data centers avoiding paying for the grid support which is inherent in the proposed “co-location” behind the meter and inside the fence of existing generators, consumers will have physics on their side. The data centers and their host generators might wish they didn’t rely on the grid to handle rapidly changing power consumption, but they can’t operate without the grid. Therefore, FERC will have to conclude that the data centers do not deserve the discount they hope to receive. 

Don’t believe the hype. Power hungry computing needs are not exempt from the physical constraints of the real world. 

This experience, not far from Seattle and with ties to the information tech industry, highlights some of the issues surrounding the electric power needs of data centers. As we made arrangements to deal with this real power outage, I realized there might be a lesson to be learned about the debate over expanding energy on the grid for new data centers, or somehow building data centers with dedicated, separated energy sources.  

By 4:45 PM, daylight was fading, and the utility missed its target for restoring service where we were staying. My friend’s group—several families with children aged 5-12—were sharing a house with one family to a bedroom. These folks know each other well and began preparing for the night. The kids were organized to bring firewood in for the woodstove that would heat soup for dinner, as well as the upper level of the house. A few others cleared a path and moved a heavy back-up generator from the garage to an open area to run safely. 

After dinner, I walked back to my rented BnB across the main road that runs up the narrow valley. The owner, who felt compelled to tell me that he had 10 years experience with a well-known tech company, was very confident that he could keep the electric heat on in the apartment with “a small gas generator.” He was obviously oblivious to the fact that old-style electric heat (i.e. not heat pumps) requires a larger generator than he had. When he showed it to me, he picked it up with one hand like a lunch box. Imagine trying to power a surround-sound entertainment system and television with a hand-crank radio.  

Regardless, he quipped “electricity is electricity,” and didn’t seem to notice that the heat wasn’t on and the lights were wobbly, at best. Suddenly, the overcrowded house with a dozen kids was more appealing. I said we’d see how things were in the morning, and I went back across the road to sleep on a couch. 

Working together to stay warm—and dealing with physics 

Back at my friend’s house, the kids continued to text friends or enjoy their “screen time” while the grown-ups were problem-solving things—like making coffee and heating the downstairs bedrooms with the limited generator supply. Plans for the next day included cooking burgers on the grill and making a trip for more fuel for the generator. We had someone focused on keeping people fed and someone else focused on keeping the generator running safely. 

Luckily, I found a helpful role—interpreting the overall power system and sharing information. The utility’s web page reporting outages showed that power had been restored to part of the valley, and set a new goal for restoring power by the morning. We didn’t know it yet, but the outage affecting us would last much, much longer: ultimately, 45 hours.   

When I returned to my cold BnB the next day to collect my things, I checked the water at the faucet. I asked the owner, who still thought I would stay, if he had turned off the water. He assured me he hadn’t: “it doesn’t require electricity!”  

When I suggested that it might have frozen in the absence of operational heaters, he began to realize he had a problem. He later found a frozen, burst pipe. He explained that he would cancel my rental fees, but the peer-to-peer service company wasn’t responding to his request to cancel their fees for my rental. He eventually understood that 1) his solution was overly optimistic (e.g. not just any generator is sufficient), and 2) the rental company platform wasn’t prepared when circumstances required a change of plans. 

This demonstration of the connections between people and systems, and the need for collective solutions to complicated problems, came to mind when I read about an idea for a different real estate host technology:  nuclear power plant owners seeking to bring large data centers to co-locate on their land.    

Modernize, or bypass, the grid? 

First, some important background information. The electricity supply network of power plants, large transmission lines and smaller distribution lines—aka, the grid—has not been modernizing nearly as quickly as the technology that relies on it. In recent years, the focus of grid modernization has been on connecting new supplies. New clean energy, including combined solar and battery projects, have waited (and waited, and waited…) in interconnection queues. 

More recently, demand from data center growth has focused attention on the need to upgrade the power grid. In Virginia, where data centers already account for 25% of electricity use, $627 million in grid projects were approved in 2022 to get enough power over the wires to support this “data center alley.” In 2023, grid planner PJM approved more transmission upgrades for the region, costing another $800 million.  

The grid is vital to the economy and the daily lives of consumers and businesses alike. Delayed construction of clean energy means grid planners like PJM are struggling with rising demand and the loss of power plants, at significant cost to consumers. The region faces additional rate increases of 11-20% for the June 2025-May 2026 period as a result of PJM’s July 2024 capacity auction, which procured power supplies to meet future electricity demand 

How are nuclear and tech responding? 

One battle breaking out over how to get around this gridlock and rising costs involves nuclear plant owners striking deals with data center developers to connect directly to each other. While scores of data centers have attached to the utility transmission system, this group of tech companies is trying to avoid paying for grid services and transmission connections. This maneuver attempts to bypass the grid and the associated costs of building and maintaining that infrastructure.  

PJM recently argued before the Federal Energy Regulatory Commission that these costs can’t be avoided and that it doesn’t need to change its rules to create side deals for data centers that are connected to the grid, but claim to not be attached. As PJM put it, a legal complaint of one nuclear power plant owner, Constellation Energy, is a “not-so-veiled attempt to insert one party’s preferred method for co-locating data centers with large generators… simply to suit their preferred business strategies.” 

Again, physics  

The IT expert with the apartment rental underestimated his need for a larger energy supply, and the vulnerability of his water supply. We all have a tendency to simplify when looking at complicated systems, but physical realities don’t conform to our shorthand descriptions. The real world is layered with connections. Often, the full situation is only apparent when something adds stress—like a power outage, for instance. 

Similarly, neither nuclear power plants nor data centers have the flexibility and resilience necessary to go it alone. The premise of this battle is that these two can team up and make more money without any reliance or connection to the larger grid. But data centers, it turns out, are not steady and unwavering users of energy. They respond to instructions by very rapidly starting and stopping banks of processors that use small-city-amounts of energy. US nuclear power plants are neither currently designed nor licensed to change their output in a way that resembles this behavior of data centers. Despite the wishes or incomplete knowledge of business folks, both of these huge and expensive technologies rely on the collective functioning and shared infrastructure of those around them. 

Data center start-stop functions are also more difficult to follow than a gas power electric plant can handle. The electric power supply is provided by a grid for the very purpose of spreading out the burdens of meeting variation in both supply and demand. It’s an oversimplification to point to a single generator and a single load and say: “This will serve that.” That approach requires overbuilding and accepting expenses that are unnecessary when connecting to a grid.     

To stay warm 

We have a complex economy that relies on interconnected technologies, many of which are enabled by the electric system. We must continue to innovate and problem-solve if we are to have a livable planet and a viable social and economic system. This won’t work if we allow social costs and risks to be forced on consumers when tech champions cut corners. There needs to be a just governance approach that reflects the importance, the complexity, and the community that depends on the electric grid. 

PJM, one of the largest utility companies in the US, has been put in a hard spot by circumstances only partly of its own design. Numerous delays to new energy supplies, generally faulty planning, and then sudden changes to both supply and demand created $12 billion in new costs for the coming year—a cost that will be passed on to the 65 million people that rely on them for electricity. The sticker-shock of this rate increase is sure to gain attention, no matter how obscure a regulated monopoly might be.  

This utility, PJM Interconnection, is a regional transmission organization (“RTO”) governed by a limited liability corporation, or “LLC,” made up by and for the utilities and power plant owners in 13 Mid-Atlantic and Ohio Valley states. UCS is currently fighting what could be a series of annual $10 billion added costs for electricity with new strategies and allies, because the obstacles blocking supplies are not going to be solved by throwing more cash on existing power plant owners. 

Licensed and accountable 

PJM has real responsibilities (shared by any RTO approved by the Federal Energy Regulatory Commission,  or “FERC”), including transmission planning and processing requests from new energy suppliers in an interconnection queue. (This required queue process determines the costs for a new generator to attach and deliver electricity to the grid. Everywhere, this is a serious bottleneck. Here’s a great blog from my colleague describing one region’s interconnection queue.) Reliability is part of these duties, but that’s more complicated. Trying to pay for reliability with a market is where this story gets interesting.  

To bring public scrutiny to this monopoly and cost increases, UCS co-authored a legal complaint to FERC in the weeks following the announced jump in costs. Our complaint challenged unjust and unreasonable rules in PJM’s capacity market that have already caused $4 billion to $5 billion dollars in excessive costs for consumers in PJM’s most recent capacity auction—and that may cause $12 billion to $15 billion more in three upcoming capacity auctions unless the Commission requires reforms. Let me explain. 

What are we paying for? 

PJM has a market-like process for qualifying and paying power plants for meeting electricity demand in a future year. This process is constantly getting tweaked and is sometimes challenged in bigger ways in response to complaints like ours to FERC. In the past year, a set of rule changes for this “capacity market,” combined with one power plant owner deciding to close two old plants in Baltimore harbor, created conditions for the 2024 auction to result in record-high prices. The supply available in the auction was intentionally limited by many factors in PJM’s control, resulting in the auction paying 99.99% of the capacity offered. Because everything offered was bought, and the clearing price is set by the most expensive resource selected, this limited supply resulted in a price almost 10 times higher than past years. This is the immediate cause of the $12 billion in added costs announced in late July.    

UCS and other public interest organizations filed our complaint in September focused on one PJM practice that reduced the supply from power plants available for the auction. We took on the policy that allows plants that are paid by PJM to remain open for reliability but are not counted in this reliability auction process. (That is just like paying to repair your old car, keeping it ready to drive, and then buying a new car anyway.) Excluding these preserved plants essentially forces consumers to continue paying the old plants, while also paying extra-high prices for the immediate shortage caused by not counting them. In a region with many old plants headed for retirement, this one fix could save residents and businesses billions of dollars each year. 

Our action was followed by consumer advocates from four states in the PJM region filing an additional complaint at FERC in mid-November, arguing that several policies created this artificial supply shortage. They described PJM as granting too many existing plant owners exemptions from offering supply in the auction, and as too slow in the processing of new supplies in the interconnection queue.   

Since filing the UCS co-sponsored complaint, PJM has conceded that there are indeed problems with the auctions it runs and agreed to delay the next one. PJM is now preparing some changes on the issues raised, including the treatment of reliability payments for delaying plant closures. Besides these complaints, the PJM Board has had to answer letters pressing for change from governors, congressional representatives, and state regulators. The one agency providing directions to PJM that PJM has been reluctant to address is FERC, their regulator. 

FERC has long sought to increase competition amongst power plants, in part  to protect consumers from inflated rates, and PJM has long promised to facilitate this. However, the arrangement is stressed now as PJM tries to pay enough money to enough suppliers to ensure reliability in a time of new demands and new competition. Solar and solar-plus-storage are the major new competitors as the cheapest electricity source in history, but the PJM processing of the connection requests from potential new suppliers has been delayed 4 years or longer. FERC made rule changes in 2018 to enable competition from storage and solar-plus-storage with Orders 841 and 845. Those rules should have modernized the grid, but were unevenly adopted and implemented.  In particular, PJM has resisted keeping up with energy storage after once having been a leader in recognizing storage value on the grid. 

Recent conflict with regulators 

FERC began new efforts in 2021 to remove obstacles for interconnection and grid planning. UCS and many advocates and industry players welcomed new scrutiny of bad practices. Throughout this oversight process, PJM objected several times and now they’re on the brink of failure to comply with these reforms that would increase competition and allow more supplies.   

PJM continues to resist a key change for energy storage that UCS has pushed and other regions have adopted. PJM insists that it must plan for new batteries or other energy storage to buy power when prices are high and supplies are scarce, increasing strain on the system instead of relieving it. This “buy high, sell low” assumption frames batteries as a problem rather than a solution for meeting peak demands. In practical terms, this flawed philosophy forces battery projects to pay for expensive transmission, which defeats the purpose and the value of building batteries where supplies are hard to get, like Baltimore harbor. 

Where is this headed? 

PJM is not standing still. The organization and its members know there are problems with its supply forecast. In announcing the delay of the next auction, PJM has begun to meet some of UCS’ and consumer advocates’ concerns. PJM has not conceded much, but in stakeholder meetings, it is describing actions that will move a couple of reforms forward. (PJM says it plans to make changes so one retiring Baltimore harbor plant could be counted for a little while, and other supplies could be called on, and maybe storage has a place with solar and wind, all with caveats and limits. We’ll see soon what they propose.) 

The way PJM explains it, there’s not much hope for energy storage or renewables, so they’re offering fossil generation a four-year short-cut in the interconnection queue. Well, maybe PJM wasn’t that clear, but that is what they propose. However, the science shows how off base this assumption is—which is exactly why I’ve been advocating for years to bring PJM into the modern world and align their policies with science in service of their tens of millions of ratepayers.  

As I’ve said before about PJM, “a mess this big takes time.” PJM says it has several reforms to bring now to FERC and more to follow. Let’s make good use of this opportunity and actually deliver a more modern grid, a more reliable one, and a more affordable one. The ready-to-build clean energy and storage that have waited in the queue should be our first choice. 

I work in the electric utility sector, specifically on the grid issues that shape our energy supply choices. I heard some early warnings of data center growth running into grid limits first from tech companies and then from electric utility planners. But I could have seen the future just by looking at the younger generation of my own family. Amongst my kids and their cousins, four are adults and are all employed in data or internet jobs, and the fifth, still a teen, uses a smart phone like most other teens do: all the time. Some forecasting models must use observations of young people, no?

We need to plan for energy infrastructure that supports our economy and reduces harmful air pollution. The demand (and profits) from data centers seems to be motivating utilities to respond. Grid modernization and continued investment are on-going. It is better to understand this new driver in context so we can focus on solutions that serve all of society.

Electricity use by data centers is rapidly rising

In the energy sector, the rapid growth of data centers’ energy use has already changed the course of electricity supply and demand. Presently, there are five different states where data centers consume over 10% of statewide electricity used: Virginia (the US leader at over 25%), Oregon, Iowa, Nebraska, and North Dakota. And the latest projections estimate that globally, data center electricity demands will double in the next two years. This growth is a jolt to the usually slow-moving electricity sector. For more than two decades, demand growth in the electric utility world was very low. This slow growth weakened utility planning and supply chains. Workforce development also suffered. Electrical engineering students studied computers in vastly greater numbers than electric power. (That’s another indicator from the choices made by our younger generation that we all missed.)

Many new data centers are not going to support just “one thing” and so the development of a new data center is not always going to be transparently related to video conferences, or bitcoin mining, or artificial intelligence (AI) used by students and factory operations. Data centers support many internet-based services. Some services need to be physically closer to consumers to reduce delays, such as updating driving directions (and advertisements of nearby business) for drivers of moving cars. On the other hand, things like hotel reservations, credit card billing, email and hosting your photos are not so time sensitive that the data center needs to be nearby.

Newer services tend to use more data, and thus more energy. Processing large amounts of data is a central step in AI. The general practice of AI stems from “machine learning” from many, many pieces of data. The growth of AI is clearly causing growth of data centers and the size and energy needs of data centers.

The grid might not meet that demand

Electricity for data centers comes from the grid, and by extension, the mix of power plants that supply the grid. Single data centers can require as much electricity as small cities. New data center proposals can be of the scale of nuclear power plants and some even seek to connect directly to existing nuclear plants. A couple of those might happen, but there are limits that will foil the ambitions of more than a few data center developers. The most immediate limit is the physical ability of the grid today. The electric utility sector needs to expand both the wires and energy supply to support the growth of data centers. This needs some thought, as both the laws of physics and the principles of supply and demand will apply, even if legislatures and regulators have not yet spoken about allocating costs and resources related to data center energy demands.

Some of the better-known computer and data companies—understanding the impact of this much higher demand—have been actively buying energy from new renewable energy power plants. Solar and wind projects, as well as offshore wind projects, have been built with contracts from some data center owners. These owners understood both the need for a supply of energy, and the value and reliability of clean energy. A significant fraction of the clean energy built in the US was financed on the commitments by such high profile, public data companies. These firms recognized that they could not assume the risks of exacerbating climate damage from continued burning of fossil fuels.

Data centers’ total energy demand is challenging to meet. Across the US data center energy use grew 66% from 2020 to 2023, from 90 billion kilowatthours to 150 billion kilowatthours. The size and growth of US solar farms’ energy production has nearly matched this for those same years. Thus the progress so far with large-scale solar in reducing carbon emissions is offset by the present levels of energy use by data centers. Wind, solar and battery storage are the fastest growing electric energy sources and should be the first choice for a modern economy adapting new data technologies.

The growth in solar looks to be keeping up with the growth in data, according to the latest projection from the US Energy Information Administration. But that solar growth is nationwide and the data centers are generally located in geographic clusters. This surge in simultaneous but disparate supply and demand reveals how utility planning for growth has fallen behind in the regional transmission organization PJM, which includes Virginia, the state with the largest amount of data centers.

PJM has been notoriously difficult for solar and storage expansion on the grid. With continuously changing rules for power plant additions to the grid and credit for reliability, PJM has less than 1,400 megawatts (MW) of solar and only 14 MW of battery storage counted as meeting demand. Compared to PJM demand of 140,000 MW, that is 1 percent and 1/100^th of 1 percent, respectively. It is not a coincidence that PJM still hasn’t produced an official transmission plan that looks to the future and prepares for building a single new power plant or the closing of any old power plants. Required reforms are under way, and the first PJM plan under those new rules will be ready in…wait for it… 2030!

More planning, for the grid and the climate, is needed

The newest energy deployments on the grid, solar and storage, have a lot in common with data centers, the newest driver of electric utility investment. The transmission system that these technologies share, and that is also used by everybody else, needs forward looking modernization. Solar and wind energy development have already been stymied by inadequate transmission planning. Now, data center companies are also delayed by a lack of transmission.

The local transmission utility in Virginia, Dominion Energy, is responding to data center growth with a wave of new construction. Currently in the works are forty substations in Virginia for data centers, costing well over a billion dollars. Nothing like this has been seen before, yet we are told to expect much more. Dominion Energy can’t address the laws of physics, or even the laws of supply and demand, by themselves. If this is a new industrial revolution, we’re going to have to do better to protect our resources and climate than we have in the past.

If the modern economy is going to better deliver health and welfare, it won’t be due to voluntary actions by some data companies. For starters, the energy, climate and water issues exacerbated by data center demand need to be priced into the data business. We have the ways and means to do that. We just need to bring the political will.

In the electric utility industry, this conflict is on display in the debate over who makes decisions on new electric transmission and how to include policies set by state laws.

Because new transmission investments are widely needed for economic growth and decarbonization, attitudes among the central players in the electric power industry are changing. Leaders of states, regulatory agencies and grid planning bodies are motivated by what they are seeing and realizing they must act. But what action they take depends on where they stand in the industry.

State governments and industry plan the grid differently

“Transmission planning is essential to delivering economic growth, electric grid reliability, and cost savings for consumers,” wrote the governors from Illinois, New Jersey, Maryland, and Pennsylvania recently in a letter to grid operator PJM calling for respect of the state and federal rules and regulations regarding grid planning. The letter, and the heart of the debate, is who should be setting the tone and direction of planning for infrastructure over the next 10-20 years? Will it be the people of the state—in this case represented by their governors and legislatures—on the frontlines of climate impacts to the grid, or the owners in the power industry who have a deep financial stake in how new transmission is integrated to the grid? PJM directs the revenues and operation of the largest fossil fuel power plant fleet (124 gigawatts), making it the largest utility in the US. PJM is also a private limited liability corporation with voting members shaping its rules and practices.

To protect its markets, PJM’s governance, their way of doing business in other words, is hostile to the involvement of state governments and state policies. Their management often points to the difficulty of resolving differences between the varying policies of the 13 states in their region, even though they manage a stakeholder process with 1,000 members who also have differences that require some resolution. PJM does not provide the states in its area with membership, representation, or a vote in their stakeholder process. They have also taken numerous explicit positions to exclude state influence  over power plant additions or continued operation that it says interfere with their markets.

Bottom line: PJM doesn’t want the states, or the people, telling it what to do.

Transforming the grid takes time

Competition among energy suppliers means they must rely on the transmission system to connect customers to multiple power plants. If there isn’t access to using the transmission system, then a supplier’s customers can only get energy from the existing power plants that are already connected to the grid. When existing transmission limits new suppliers from connecting to the grid, this protects older, possibly uneconomic plants from competition, limits the growth of new supplies, and lowers the reliability of the electric system.  

With access to transmission so vital to enabling competition, and because of the obvious inherent conflict of interest, the Federal Energy Regulatory Commission (FERC) issued Order 890 in 2007 and recognized that planning for transmission needs to be done separately from the owners of power plants. More than a decade since that order was issued, the utility industry is debating how this can work better. FERC started an enormous review of transmission rules three years ago, including the rules for connection of new generators and the expansion of long-distance transmission. They have since split this into two efforts and have issued two packages of rule changes: Order 2023 and Order 1920.

Physically, the transmission system includes the expansions made for new generators and the miscellaneous upgrades for long distance and reliable service. The distinctions in the existing rules between these categories of transmission are all about the process and who pays. Once built, the uses and the users of the transmission system are all intermingled. FERC acknowledges the reforms in proposed Order 2023 and Order 1920 are unfinished business; they set a conference for this September to examine planning for new generators along with the routine planning utilities do for reliability. UCS asserted from the start that strong coordination of planning and new generator connections would determine the success of these rulemakings.

PJM’s perspective must be balanced with other stakeholders’ needs

What may be less obvious to folks who don’t closely follow these federal regulatory activities is that a struggle for control is smack in the middle of these more technical debates. PJM and its transmission owners have claims to the transmission process under authority of FERC. State governments control power plant decisions and transmission construction and siting. Power plant owners argue that financial interests and existing business practices should be the preeminent concern of any grid planning. These are all important interests that must be balanced in a successful process. Planning in PJM and other grids cannot give monopoly control to a single perspective. The way forward requires recognition of this shared influence and authority.

FERC reforms define the concepts and inputs for developing future planning scenarios.  Stakeholders advocates for consumer interests, and policy experts will argue about projected reliability and climate change impacts of the future electric power system and what transmission is required for that future. To date, PJM plans for future reliability have made no investment to prepare for old plants retiring or new plants to be constructed. Excluding these preparations from the planning scenarios has been consistent with an outdated and unfortunate practice of reactive responses to such changes. PJM has made it their practice to assign transmission costs to the utility customers most immediately impacted by the plant retirements or to the owner seeking to build a new plant.

PJM past practices maintained a dependence on existing, older power plants, and because of that dependence, generally higher prices were paid to those older plants. The voting members of PJM preferred this over and over again, rather than have PJM planning engineers make predictions and sometimes lengthy preparations for plant retirements before plant owners announced intentions to close old power plants. Today, this same passive protection of plant owners’ interests is seen as a threat to reliability.

Reliability of the power system due to old fossil plants retirements and new growth in electric demand is driving both FERC and PJM to emphasize planning for fossil plant retirements. PJM has twice in two years published analyses of future retirements, with projected fossil plant retirements totaling 40,000 megawatts by 2030 or 41,000 megawatts by 2035. For comparison, in 2023, 6,727 megawatts were retired. When stakeholders sit down and debate the assumptions for future scenarios, PJM’s perspective on reliability and plant retirements should and will be at the center of that discussion, as will the new supplies needed for replacement.

In its rules for scenario planning, FERC deliberately has included the need for new supply and the various public policy requirements set by states prescribing changes in energy supplies to reduce carbon and create renewables. Every state in PJM has some kind of state policy for subsidizing generation, either clean or fossil-fueled. Corporation interests, both suppliers and buyers of energy, are also acting on power plant emissions.

Opportunity for collaboration ahead

The federal and state involvement in transmission is good and necessary to counter the bias in utility stakeholder debates that do not account for all the potential beneficiaries. The state and federal government influence on transmission expansion is an adjustment to correct the assumption that the market will perfectly organize buyers and sellers, even for infrastructure assets that have 40- to 80-year lifetime and disperse benefits widely.

Everyone with a stake in this debate should be prepared to talk and to listen because transmission planning is a group activity. Important details surely will come to light in the regional planning debates, including new perspectives on the future. If energy experts from all sides and policy advocates don’t join these debates with a willingness to be flexible, to support the process, and to honestly press for progress, we together will miss a truly vital opportunity to transform the transmission system and create a grid that can meet the challenge brought on by climate change.

Some years ago, I began to feel the most important thing I could do was learn how to replace fossil fuel with renewable energy.  I had seen from an early age how oil dependency distorted and aggravated conflicts around the world, especially in the Middle East.

For 30 years I have been an advocate for offshore wind development off New England’s coast and for the creation of institutions to support a transition from fossil fuels to renewable energy. It was never going to be an easy task. New England has fewer energy production facilities and less experience with new energy development than most regions. In New England, the wind is powerful, but land with strong wind is limited.

After years of federal, state, and local efforts supporting the required environmental, engineering, and business plans to transition this region to clean energy, the arrival of wind farms out at sea is a reason to celebrate, yet the distortions and oil-driven conflicts continue.

Today, oil producers are spreading disinformation about offshore wind in the worst way. They are sowing distrust and doubt and wasting precious time during which we should be accelerating wind power development. Fossil fuel interests are manipulating people along the coast and throughout the US by redirecting attention away from their ongoing damage to the climate and towards endangered whales.   

I recently got a glimpse of this new energy supply out at sea, first from shore and then on a visit with others seeking to learn more. This long search for something so large in the ocean brought to mind the classic American novel, Moby Dick by Herman Melville. From a library shelf thick with New England literature, I found the villains in Moby Dick, like now, were dealers of oil.

Offshore oil and lies about killing whales

New England had a huge energy industry in an earlier era: the whaling industry.  It massacred whales to reduce their bodies to oil for lighting homes and lubricating machines.

Moby Dick is about a whale hunt organized in New England under the guise of the economics of the time, but the hunt was actually motivated by emotion. Melville’s villain, Captain Ahab, is maniacally focused on killing a particular whale that represents something other than just potential oil. The crew of Ahab’s ship, including Ishmael the narrator, sign on for a typical whale hunt, but they are unable to keep the captain from pursuing his irrational hunt in search of Moby Dick, an enormous white whale. The crew are motivated by whaling’s monetary incentives, and Ahab exploits them with an added reward for the first man who sights Moby Dick. Ahab manipulates the crew with disinformation and enticements of personal wealth.

Ahab accuses a whale named Moby Dick of being evil; he turns a hunt for oil into a righteous fight to cover his own flaws. Repeatedly, Ahab conjures fabulous lies to shroud his personal passion for vengeance. The story culminates in a confrontation with the whale that, unlike business as usual, was fatal for Ahab and nearly all of his crew.

Melville’s novel is a classic in part because it presents alternate perceptions of the crew’s experiences. Melville was an insightful critic of hypocrisy in America in the years before the Civil War and the emancipation of enslaved people in America. He clearly is sympathetic to the multicultural crew and respects people of color engaged in, what at the time was, a global endeavor.

Disinformation and hypocrisy today

Still, the crew killed whales for oil. If Melville were alive today writing about the energy industry, he likely would treat the fossil fuel industry’s spreading of disinformation about offshore wind with the same kind of warning about manipulated passions and ill-intended leaders.

Today, the oil industry has created a similar distortion of private interests and a portrait of evil cast on others. As with Ahab, there are dangers to those who are swept up in this disinformation.

Extracting oil is still dangerous for whales (and workers and the environment). After the 2010 Deepwater Horizon oil disaster in the Gulf of Mexico, scientists found that one of the whales killed by the oil spill was a member of a unique species called the Rice’s whale. The federal government has not yet officially recognized the species’ habitat or established regulations for drilling and ship movements that would protect that whale’s habitat, which is damaged by thousands of oil and gas platforms and underwater pipelines. But oil companies and congressional delegations from states along the gulf show no interest in protecting the whale. Their priority is to shield the offshore oil industry from regulations that would protect it.

The oil industry and its surrogates today run a disingenuous disinformation campaign to protect oil producers in the Gulf of Mexico, the center of US offshore oil production, from regulations recognizing endangered whales. That goal conflicts with the fossil fuel industry’s attempts to portray offshore wind as a problem for whales in the North Atlantic.

Oil industry advocates have created and backed a series of challenges to offshore wind, cynically crying concern about alleged risks to whales. They call for deregulating their own industry, while they call for greater regulatory oversight of offshore wind. This network of opponents to offshore wind includes the Texas Public Policy Foundation, Caesar Rodney Institute,  Manhattan Institute and Heartland Institute, all funded at times by fossil fuel companies ExxonMobil, ConocoPhillips and Chevron. These oil industry supporters have funded more than one unsuccessful fishermen’s suit against offshore wind permitting.

Warning from an American classic

Ahab saw in the whale the embodiment of all evil. He drove his ship and crew on a monomaniacal hunt. Melville, through his narrator Ishmael, warned that dictators will disorient their followers, appealing to their addictions to oil, big paychecks, and elusive promises. Following the captain, and following the manipulations of the oil industry captains today, without knowing why and without seeing yourself in this energy debate—that’s what is dangerous.

On my recent trip to see the Vineyard Wind offshore facility, I shared my efforts to build a positive engagement with offshore wind, an industry that now brings benefits to people in the coastal community with new jobs and harbor investments, as well as funding for energy resilience and bill payments. Local, constructive conversations about the first 800 megawatt Vineyard Wind and 132 megawatt South Fork Wind projects continue to shape the transition away from fossil fuels.

Ahab led his crew to their destruction and death. Similarly, the fossil fuel industry champions the pursuit of fossil fuel no matter the cost to people and the stability of our coastal communities. We can do much better. I have seen a calmer, steadier future.

First, the demand 

The ability of the current US power grid to handle growth in electricity demand is in doubt.   We are already having blackouts in extreme cold-weather, due to electric supplies dependent on an antiquated gas industry.  Local supply limits on the grid are causing delays for big new users of electricity, such as data centers and new US manufacturing. Internet communications, AI services and cryptocurrency mining, create city-sized demands for electricity. Smaller, decentralized growth in electric heat pumps for buildings, and electric transportation replacing fossil fuels also require more access to electricity and a modern grid.

Add the supply

 We have more energy-producing facilities than ever before, and the United States is producing record levels of energy. The problem is that energy needs to be distributed. New solar production on landfills, over parking lots, and in wide open spaces need to be able to transmit the electricity they generate. Lots of planned new windfarms, even offshore, also need transmission from the windy places to consumers.  Even new gas drilling uses electric power. All these new supplies depend on the grid to operate and produce. Today, inadequate grid facilities and slow-motion planning are blocking the addition of new electric generators, especially new clean supplies. Many new projects are stuck for years waiting just to learn grid connection costs and then learn that the costs and delays are too great for the projects to bear.

Now, collaborate

It is widely agreed that electric reliability is in everyone’s interest. The current difficulties in getting the grid improvements we need stem from insufficient collaboration at the local, state and federal levels. Planning rules at every level emphasize reliability, but the rules differ over changes in energy supplies and how to count benefits. Proposed reforms aim to address those differences. A recent review of over 1,300 proposed transmission lines shows the regional differences in approach are inhibiting planning for new supply and consumer cost savings in PJM grid region (Illinois to North Carolina) and the Southeast United States.   

As we work toward collaboration to help speed a modern grid, here are some recommendations:

• At the local level, developers and utilities must recognize the impacts from building new infrastructure are unequal in the way they impact different communities. UCS pushes for real engagement with real concerns from neighbors to create an equitable build-out of the power grid. That means more than a flashy campaign from developers is needed; meetings  with stakeholders should be held to discuss mitigation measures and ways to bring benefits to impacted communities, and follow-up is needed to make sure promises are kept.

• At the state level, governments need to do more to facilitate new transmission lines. State leadership can bring public attention to the need and opportunity to improve energy efficiency of homes, and simultaneously accommodate growth of renewables and new uses. In some states, when the legislature created new clean energy goals they also started transmission planning to help meet those goals. Texas went first in 2005, with a law called SB 20.  The law authorized the creation of new transmission to serve “renewable energy zones” and a process to identify and select such zones. That became a model used in the Illinois Clean Energy Jobs Act (CEJA), which also combined new clean energy goals and state designation of renewable energy zones and related transmission. Nevada adopted a law called SB 448 in 2021, directing utilities to build transmission that meets state goals.

• States can include more perspectives from the public and consider more policies related to energy, justice, the environment when convening this kind of planning. The example set by the California Renewable Energy Transmission Initiative demonstrated how state-led efforts can be collaborative, transparent and far more inclusive than typical transmission development efforts. When states are in charge, state priorities and participation standards will be included. Typical utility planning is often opaque, despite the involvement of independent grid operators.

States and federal system align, maybe

Where state laws, such as Illinois’s CEJA, require new discussions and actions for grid modernization and decarbonization, leadership can promote collaboration and more open process. The Illinois law calls for the state, not the utilities, to create an Illinois “Renewable Energy Access Plan” every two years to achieve clean energy goals. The first draft plan includes new collaborations with regional planners, and the local utilities, to discuss transmission plans before they are finalized and difficult to change. UCS promoted this as a way to make the best use of the mix of authority and responsibility for grid reliability, energy policy, and new investment. This can be especially helpful in planning proactively for transmission fixes needed to close old power plants.

States have only a few means to work with the federally-regulated regional grids to expand the transmission system, but regional and federal bodies are gradually adopting new approaches for state-led efforts. California ISO has a newly approved rule for state-sponsored transmission (which builds on cooperative agreements between the California ISO and the state) and the New England grid governance process is taking initial steps to support the states’ needs for transmission following years of advocacy by states. In the past, the provision in the PJM grid for a state agreement approach was a means to bypass regional attention to policy impacts on the grid.

While we wait to see how proposed but yet-unfinished new rules on transmission from the Federal Energy Regulatory Commission (FERC) will change practices, the US Department of Energy has been approving new money to help build multi-state transmission. Cost-sharing is a common snag for such transmission. The guiding principle is “beneficiary pays,” but the utility industry has a horrible record at defining benefits from transmission. The default has been, whoever asks for transmission must pay the whole cost. This isn’t the approach to any other infrastructure.  Reform around this is a huge and active policy debate.

Federal rules expand planning with states

In 2021, FERC opened two related initiatives: formal convenings with state regulators in a transmission task force and comprehensive review of rules for transmission and grid connection of new generators. Both of these are still in progress, with a new federal-state collaboration on broadly defined issues and imminent decision on transmission planning reforms.

FERC’s greatest impact will come from finishing and enforcing the proposed new rules for transmission planning. These can provide clear guidance and re-establish the balance of authority between utilities and public policymaking. FERC’s draft rule requires that transmission planning include the state, and local laws that affect future energy supplies, such as clean energy goals and renewable energy standards. FERC sees ignoring these laws, and also state approvals of utility supply plans, in transmission planning as bad for reliability and ripe for reconciliation with explicit new rules.

In a significant accommodation of states’ roles, the draft calls for providing state regulators with a formal opportunity to affect planning, cost-sharing and long-term transmission needs. The draft rules from FERC also encourage utilities to work with state officials to identify renewable energy zones. This insistence on power-sharing reflects the divided political opinions in government today, and may actually be the path forward.  

Time is now for transmission reform

FERC Chairman Phillips frequently points to the importance of ongoing transmission reforms. As he put it recently, “There is no single action that the Commission can take that will contribute more to enhancing the reliability, resilience and affordability of our electric grid than to facilitate the development of needed electric transmission at just and reasonable rates.”

UCS began pushing for strong planning with new rules as early as 2009. Unfortunately, FERC’s currently proposed rules allow most reforms to be optional. FERC also decided to delegate decisions on two fundamental things blocking investment in transmission: the recognition that new transmission widely benefits many users, and the allocation of costs in exchange for receiving the benefits of new transmission. Despite the fact that the proposed FERC rules include much discussion of benefits, they once again defer to utilities the task of defining benefits and beneficiaries. The FERC draft rules also fail to address the issue of cost sharing, other than the general instruction for utilities to find some agreement with the state or states where they operate.

To be successful, grid expansion will require collaboration. State government roles, economic considerations, and local interests all must be recognized. So far, the details of how that collaboration will work have yet to be decided by states, grid planners, or the soon-to-be released final FERC rules.

NERC—as well as the regional organizations across the country tasked with ensuring the electric grid remains reliable and secure—identify gas supply failures as not just a cause of deadly 2021 power outages in Texas, but also as an ongoing threat to the restarting the electric system following a blackout during an extreme cold weather event, which is called a “blackstart.”

Their findings related to blackstarts have not been widely reported because NERC and FERC released their report in late December, obscured the identities of the responsible parties, and made a very serious problem seem dull and esoteric.

Their new report on grid reliability vulnerabilities due to electric power plants’ overreliance on uncertain and unregulated gas supplies comes two years after FERC and NERC’s extensive analysis of gas failures causing power plant shutdowns. During the Texas energy market’s chaos in 2021, news organizations and industry players gave only brief attention to the worst-case scenario: an uncontrolled Texas electric grid blackout that could have lasted weeks or longer to get the lights back on. Gas-burning plants continued to go offline, bringing the grid precariously close—within 4 minutes and 37 seconds—of that happening, according to the CEO of the Electric Reliability Council of Texas (ERCOT), the grid operator for Texas.

The FERC-NERC report, which points out that the danger of trying to restart the electric system from a blackout using gas-burning power plants has been underestimated, also describes some astounding examples of out-of-date, ill-prepared practices for running the electricity system with gas.

What Happened in Texas?

In February 2021, extreme cold temperatures wreaked havoc with the electric supply controlled by ERCOT, the Southwest Power Pool (SPP) and the Midcontinent Independent System Operator (MISO) South, which manage electric grids covering large swaths of the country. The FERC-NERC review of the 2021 outages found 81 percent of freeze-related plant outages occurred at temperatures warmer than the plants were designed to meet and 87 percent of outages due to fuel issues were tied to natural gas. More than 240 people in Texas and Mexico died from exposure to the cold during these extensive energy system failures.

It Happened Before

The FERC-NERC review of electric system outages in cold weather follows several others that also surprised grid operators as well as the general public. Similar extreme cold weather caused grid emergencies in 2011, 2014, 2018, and again in 2022. These recurring electric supply crises revealed the vulnerability of conventional power plants and the gas supply to cold weather.

Before the US electric system became so reliant on gas, power outages happened more often during hot weather and nearly always were caused by wire failure, not by fuel and power plant failures. The repeated failures in cold weather reflect outmoded thinking about both gas and extreme cold weather. The FERC-NERC report cites warnings in their unheeded 2018 analysis that “the reliance on a single fuel type without firm fuel arrangements could impact the availability of blackstart and next-start resources during a scenario when natural gas is curtailed.”

What’s New?

This report is different. FERC and NERC now assert that the same problems that caused the lights to go out also will delay and threaten getting the power, communications and lights back on in the event that a blackstart is needed. This report calls out the same cold weather ill-preparation and disturbingly non-existent system restoration plans that should incorporate the needs of both the electric plants and the gas supply those plants require. And it points out that, unlike weather-related outages caused by downed power lines affecting only parts of a region, systemwide blackouts need detailed, coordinated blackstart system restoration plans to restart power plants that go offline when the power goes out.

NERC, FERC and US regional reliability entities have determined that the power plants responsible for restarting the system, designated as “blackstart units,” often failed in 2021 because of frozen equipment and gas supply failures. The new FERC-NERC report quietly asserts that when the lights are out and everyone’s priority is on restoring the electric system, relying on gas-fired plants might not work. As disturbing as that is, FERC and NERC maintain the fixes are only voluntary despite the potentially deadly consequences of leaving this problem unaddressed.

Here’s the FERC-NERC language regarding the need for crucial changes: “The report imposes no obligations…. The joint study team strongly urges that the report’s recommendations and observed practices be implemented by the entities necessary for blackstart system restoration.” “No obligations” will likely mean more people without power will die in the cold.

Could It Be Any Worse?

This report is astonishing. It doesn’t bother to mention that hundreds of people lost their lives in the 2021 power outage until Appendix 3. It does not even once cite the name of the entity responsible—ERCOT—that made blackstart reliability procurements that didn’t actually assure reliability. (The initial FERC-NERC report about the 2021 outage released in November 2021 did not shy away from naming responsible parties. It cited ERCOT 700 times. It also cited MISO 499 times and SPP 436 times.) And their new report skirts citing any entity by name that should follow its key recommendations. Their initial 2021 report named 28 gas pipeline companies and four grid operators, and described problems at more than 1,000 power plants.

What is most appalling is the tone FERC and NERC adopted when describing the absence of preventive measures, such as remote monitoring of key equipment temperature. That technology has been available to homeowners for more than a half century. In the 1970s, my dad had a gadget attached to the phone in our house that would let our family know if the heat went off when no one was home. The FERC-NERC report recommends this technology as if it were new. “Remote temperature monitoring allows operators to remotely monitor and continuously receive alarms through Supervisory Control and Data Acquisition (SCADA) if the temperature reaches certain thresholds,” the report states. “These participants also reported that they find it advantageous to have access to this advanced monitoring remotely because of the ease it provides in identifying and addressing issues.”

When we talk about a “modern” grid, we need to understand how vital electric grid equipment has suffered from consistent underinvestment, lack of accountability, and neglect—all shrouded as necessary under competitive market pressure. By contrast, the solar panels on my roof have modern electronic components (inverters) that incorporate monitoring and communications that the FERC-NERC report is suggesting that power plant owners adopt. Again, FERC and NERC are merely recommending, not requiring, these precautions.

Solar inverters offer homeowners remote access to data including temperature. (Source: Enphase Enlighten Manager)

FERC and NERC’s new set of recommendations for addressing gas vulnerabilities that threaten recovery from electric power outages follows their initial 2021 report that included 28 formal recommendations. But like their previous report, this report has no teeth. Once again, the two agencies only call for power plant and grid operators to make voluntary changes. Their recommendations from 2021 were largely ignored, and their new recommendations likely will suffer the same fate.

State and federal policymakers have two choices to address this situation. Congress can step in and require reliability standards for the gas industry for the first time ever. Unfortunately, that is unlikely. The alternative is for states to heed the FERC-NERC suggestion that renewable energy, such as wind and solar power; battery storage; and expanded interregional transmission are viable means to replace gas-dependent generation for restarting the electric grid after a blackout. These are the very solutions that the Union of Concerned Scientists and other clean energy advocates have been talking about for years, but the gas industry has fought them every chance they get. It’s time policymakers place the priorities of people over profits of an industry that has jeopardized so much.

The public’s practical reliance on electricity supply and the long-term, dispersed economic benefits from electric system upgrades reinforce the continued and evolving role of local, state and federal governments in the electric grid. Because a modern, robust electric power system needs investment to meet growth in electricity use and enable new energy technologies for the transition to cleaner energy and a healthier environment, state and federal governments are active in supporting new transmission and improvement of existing grid infrastructure.    

Since July, when I wrote about state governments planning for new grid infrastructure, a lot has happened and more needs to happen. Most important, the utility industry is still waiting for the Federal Energy Regulatory Commission (FERC) to finalize its pending regional transmission planning rule. The potential reforms to regional transmission planning FERC presented in July 2021 could address the vulnerabilities and reduce the recurrence of devastating power outages of the past few years. Grid reliability is part of FERC’s authority and responsibility.

While FERC has been reluctant to address the underlying reasons for inaction on transmission planning, other authorities have found the means to promote the public interest when it comes to grid infrastructure. Congress and state legislatures are helping build a modern grid. New funds for U.S. Department of Energy (DOE) efforts will address some obstacles blocking investment in interstate transmission. In the past month, DOE announced financial support for several large, impactful transmission projects.

DOE will contract in advance to use a portion of three transmission lines that it selected on October 30. Each of these lines will transport at least 1,000 megawatts (MW), which, at the scale of a conventional nuclear power plant, is large enough to provide economies of scale in land use, construction, and energy losses. The DOE commitments assure developers and lenders that customers and suppliers across state lines can fill the demand for these lines over time. Arranging all the smaller users of a large line is a bit of a chicken-or-egg problem. The announced DOE capacity commitment bridges these obstacles of timing and scale. DOE used this approach for transmission connecting Nevada and Utah, Arizona and New Mexico, and New Hampshire, Quebec and Vermont.

Transmission investment in large interstate projects is often hindered by a misapplication of the principle that “beneficiaries pay.” Compared to the broader approach to building infrastructure, this is a more recent constraint  on transmission funding. The federal and state involvement in transmission is good and necessary to counter the bias in utility stakeholder debates that do not account for all the potential beneficiaries. The government influence on transmission expansion is an adjustment to correct the assumption that the market will perfectly organize buyers and sellers, even for infrastructure assets that have 40- to 80-year lifetimes and disperse benefits widely.

The largest of the 58 grid partnership projects the DOE announced on October 18 gets right to the fallacy that current transmission planning and cost allocation is sufficient to identify and confirm beneficiaries across state and regional boundaries. In truth, significant present-day practices for grid investment do not even attempt to describe beneficiaries beyond the party that asks to expand the grid. The DOE will fund approximately one quarter ($464 million) of the costs of a set of transmission improvements between Midcontinent Independent System Operator and Southwest Power Pool, two grid operators that serve the Plains states. This “joint targeted interconnection queue” project will unlock approximately 30,000 MWs of new generation—primarily wind and solar energy—that has been proposed along the boundary between the two grids. This funding effectively acknowledges the public benefits of grid expansion, but these transmission investments would be too expensive for new generators to afford. 

State governments see that transmission is key to economic development, much as the federal investment in harbors, highways and communications has enabled economic growth across the country. Nebraska and New York have a long history of public investment in the power grid. Twenty years ago, there was another round of public support for electric transmission in Idaho, Kansas, South Dakota and Wyoming. Recent legislation established the Colorado Electric Transmission Authority based on lessons shared by the New Mexico Renewable Energy Transmission Authority and the North Dakota Transmission Authority. All of these states recognize that transmission policy is a key part of the supply chain for energy and the economy.

Public investment in transmission recognizes that such funding has broad and diverse benefits that are not typically captured in utilities and grid operators’ cost-benefit analyses. Those benefits are maximized when the voices of affected communities are heard and local priorities are acknowledged, a role that governments should be well-suited to play.

Illinois, Maine and Maryland have recently adopted legislation for transmission needs and energy storage that can build on other states’ experiences. In addition, the Union of Concerned Scientists has published equitable grid principles for transmission decisionmaking through conversation with communities. When the public is represented in transmission planning, more policy objectives, benefits and community safeguards can be included. Where public benefits are widely dispersed, and processes are ill-fitted, local, state and federal governments have to play a role in the determining the future of the electric grid. 

This is welcome news. The Union of Concerned Scientists (UCS) has long called for replacing old plants in urban areas with battery storage facilities, which can improve grid reliability, and renewable energy. FERC’s new rules for connecting batteries to the power grid remove a major obstacle to using big batteries for grid reliability. What may appear to be a small change may result in significantly cleaner air across the country.

The new rules, endorsed unanimously by FERC commissioners, incorporated UCS’s recommendation about the expected use of batteries in heavily populated areas. Because batteries can be scheduled to charge and discharge, UCS argued the demand they place on the grid is different than the demand from such typical daily activities as cooking dinner or running air conditioning on hot days. Grid planners consider that everyday electricity use as an unavoidable driver of peak demand. Until now, grid planners mainly assumed that the demand for energy to charge a large battery would happen at the same time the grid is most stressed by normal daily activities.

FERC’s rule change will enable grid planners to see that battery storage can be built in places where it is most needed without requiring utilities to install new transmission just to supply the batteries, which is what they used to do. Under the new rules, batteries will be able to compensate for insufficient electricity supply in areas dependent on old plants, thus accelerating the transition from fossil fuels, the decarbonization of the energy supply, and the removal of urban pollution sources. Before these new rules, utilities could delay closing old, polluting power plants until new transmission lines were designed and permitted to deliver peak demand electricity.

FERC’s recent action enables utilities to connect storage batteries to strategic points on the grid much more quickly and cheaply than replacing fossil fuel plants with new transmission. In addition, storage batteries should be able to store wind and solar energy when they are most abundant, and deliver lower cost energy to consumers. Many states support new investment in battery storage for just these reasons. Now FERC has lifted one of the last remaining obstacles for it to happen.

States should be heard on transmission

When regulators make policy, utilities listen. States’ roles in electricity decisions stem from their authority over public health, safety, and consumer protection. State regulators can call meetings for utilities to work on the modernization and decarbonization of the grid. Regulators can convene working groups of stakeholders to develop shared interests and goals, answer questions and work on solutions. Getting people together in dialogue does not mean the regulators have prejudged the merits of proposals that may come to the regulators in the future.

States’ jurisdiction on electricity supply and reliability are not limited to only reviewing proposed construction. Clearly, states’ adoption of clean energy standards put them into forward-looking roles, and often with authority over compliance with those standards.

States regulate electric utilities that own both long-distance transmission lines and the distribution wires in the streets. Both sets of wires are needed for reliability and for hosting clean energy. State laws and practices manage the grid as a monopoly and regulate the siting and construction of new transmission.

While the majority of states have clean energy portfolio laws, there are fewer that have taken on the task of expanding the grid to enable the clean energy transition and retirement of fossil fuel powerplants. But some states have taken significant steps. 

The earliest example is Texas, where legislation in 2005 for renewable energy zones led utilities to build 3,600 miles of new, high-voltage transmission lines—serving as a model today for other state legislatures, such as Illinois. After Texas, the California Renewable Energy Transmission Initiative demonstrated how collaboration initiated by state government could address siting concerns, industry needs, and state clean energy goals.

Recently, New Jersey’s regulatory commission, the Board of Public Utilities, implemented an agreement with regional grid operator PJM that provides mutual assistance between the state utilities commission and the regional transmission organization to implement the state’s selected transmission plan. With that experience, New Jersey regulators came back to PJM a second time this spring for another round of transmission for offshore wind procurement mandated by the state.

States belong in transmission planning for decarbonization

How do we know the states belong in the transmission planning process and have a key role? State governments, usually through the public utility commission, have decades of practice under states’ authority to approve or deny transmission construction, usually with a determination of need for the proposed infrastructure. States are present in Federal Energy Regulatory Commission (FERC) discussions of transmission planning, as seen in the extensive efforts of a Joint Federal-State Task Force and the anticipated roles for states in the FERC transmission rulemaking issued in April 2022. These settings show states’ interests in how utilities expand the transmission system, and the benefits of that expansion.

How individual states collect information and set grid priorities is a matter for them to decide. The early examples of Texas and California demonstrated structured public proceedings that involved many more perspectives than usual transmission planning does. Those state-led discussions set the goals for utility companies to meet with their own proposals. In this way, states brought a wider set of concerns, interests, and objectives to the utility sector to act on. When utilities brought specific plans for future transmission investment that conformed to the outlines from those earlier discussions, potential issues were already addressed, and proposals were less controversial.  

States have not done enough to support transmission

The split between federal authority and state requirements needs attention. To deliver new clean energy, the country will need changes in the priorities for building transmission. Currently, too many transmission planning efforts sanctioned by FERC are not proactive about meeting state requirements for clean energy. Without state utility commissions asking how their local utilities will have adequate transmission for a cleaner energy supply, existing practices will leave regulators, utilities and the public unable to prepare for decarbonization or comply with state clean energy laws.

When states take a role in transmission planning, this does not replace the utility or grid operator that has FERC authorization or designation as the transmission planner. Rather, states should be engaged with the public and their regulated transmission owners in preliminary discussions and fundamental planning work under public utility commission supervision. In addition to their role in transmission siting approvals, states can advance wider understanding of transmission planning. By convening people with varied interests and priorities, states can bring transparency and progress on state decarbonization goals. The states are best suited to protect the public interest in health, clean air, and siting renewable energy.

State collaboration can advance transmission

There are opportunities and examples of states collaborating in pursuit of clean energy and its transmission. States can work together when they see potential clean energy resources coming from the same area, and their clean energy procurements can be coordinated. State government support for clean energy is so consistent in the Northeast that its state governments have a record of collaboration (and unified pressure on the regional grid operator ISO-New England). New England states began collaboration without ISO-New England in coordinated energy procurements. This advanced into transmission, with the New England states’ Regional Transmission Initiative. Then eleven states in the Northeast, including New Jersey, New York, and New England states announced additional collaboration for offshore wind transmission.

What reform can bring

States have unique goals and legislative mandates regarding climate, fuels, and infrastructure. In addition, state governments have much greater potential for an inclusive dialogue amongst constituents than utilities do. When states set meeting agendas and scope to discuss transmission plans, there’s room for equity principles, and a focus on building transmission to maintain reliability as we replace fossil plants. Other economic benefits from energy development are also relevant to states—and currently excluded from FERC transmission planning requirements. States can engage in all these considerations—and FERC described states doing this in their recent rulemaking—while still abiding by FERC jurisdiction over planning and transmission rates.

We’re going to need investment in the grid, and the public will need to be involved. Where states have legal mandates for clean energy and decarbonization, who is in a better position to convene the conversations and bring the public in?

We know that consumers pay for electricity reliability and bear the cost when supplies are tight. We now know that gas power plant owners will vociferously deny responsibility for their failings. And we also know that extreme weather will create more challenges for reliability.

Utility companies, as well as state and federal government regulatory agencies, made a series of questionable decisions that together created the situation we find ourselves in today.

Three decades of deregulation allowed private companies, as opposed to public regulators, to make critical decisions about reliability. In many places state and federal utility regulators delegated decisions about energy supplies to the market. Since companies and policymakers do not want to pay a lot to ensure reliability, they both subscribe to the theory that the law of supply and demand will provide an adequate supply at a low cost.

In reality, cost cutting leads utilities to overrely on short-term gas suppliers, making an inadequate supply look like it will meet demand. That can prove disastrous. Consider what happened in New York City and northern New Jersey when Hurricane Sandy struck in 2012. After the storm hit, owners of backup generators at hospitals, data centers and municipal facilities found out that they all contracted with the same low-priced oil-delivery service that did not have the capacity to deliver enough oil to handle the spike in demand.

The same scenario has played out with the power plants that use fossil fuels, predominantly methane (“natural”) gas, delivered by pipelines. The electric power system is trapped by gas-dependent power plants that cannot obtain gas when it needs it to keep the lights on. It’s a persistent problem that the Federal Energy Regulatory Commission will take up at an open meeting and a forum on June 15 when it addresses a tangle of issues related to reliability in extreme weather and the markets meant to provide a reliable electric supply .

Stuck between the past and the future

In the past, state and federal policies granted electric utilities a monopoly over the supply of energy while regulators monitored company overspending. Regulators and consumers had no competing power supplies to compare on cost or performance, and utility companies claimed that every power plant was “needed for reliability.”

For a while, utilities made a combination of self-interest and reliability arguments to oppose technical innovation and deregulation. Market and competition advocates, however, ultimately won the policy fight, and paid some—but not enough—attention to reliability.

Through that transition from publicly regulated monopoly to competition, electric utilities focused on summer demand, which drove the need for plants that can produce electricity (capacity) as well as the fuel those plants required to produce that electricity. The electricity industry repeatedly turned to gas, available through pipelines that were primarily used to deliver heating fuel in winter, as the fuel source for summer peak electricity demand. Gas seemed to be available, state policymakers went along with market forces, and they raised too little concern over reliability risks. This system worked so well in the past that gas plants totally dominated new power plant investment from 1990 through 2014.

In much of the country, electric power plant choices are now made via competitive markets. As long as the electric industry’s reliability emphasis on summer went unchallenged, gas-burning power plants could cut costs on other types of reliability that were not priced into the markets. The gas markets still do not value flexibility or provide winter reliability that electricity demand requires. Several recent winter storms revealed that gas-fired power plants are often unable to obtain fuel. Such fuel inadequacies result in electricity outages. At the same time, extreme weather events are becoming more common as more fossil fuel is burned and carbon is released into the air. It’s a vicious feedback loop.

Renewable energy competition

Now that renewable energy sources are economically competitive, companies are building more wind and solar facilities. New renewable energy plants outpaced new fossil fuel facilities across the country in eight of the last nine years, according to the US Energy Information Administration. Meanwhile, lower costs and technological improvements in energy storage are making it an attractive investment as well. These changes have dramatically reduced the amount of fossils fuels burned for energy.

With less gas and coal burned—and a larger role for renewables—the electricity industry is unsure about what the right measure of grid reliability might be. (In the past, a power plant’s value for reliability was the product of its capacity in summer and its unplanned outage rate.) Today, grid operators recognize plants have correlated outages. Forcing this debate is the gas supply’s wintertime failings. Grid operators are now reconsidering how gas-fired power plants are valued for reliability.

Competing without a fuel supply

Once the electric utility world adopted markets, policymakers’ next step was to try to ensure the electric power supply’s reliability through a competitive auction. The realization that all gas plants have not included reliability as a part of their business strategy led to increasing efforts by regional grid operators to set rules incentivizing performance and penalizing nonperformance. The gas-burning power plants that were caught short of fuel last winter are now facing penalties and trying to shift blame. At the same time, wind farms produced well above expectations.

Can we fix this?

The problems of relying on gas are now evident. Market forces are moving private investment to renewables. Energy storage, combined with wind and solar, is lining up to get on the grid and further displace fossil fuel. Regulators and utilities can update market rules and reliability measures so combined renewables-plus-storage plants are treated the same as other combined cycle (gas turbine-plus-steam turbine) power plants. Modernizing grid planners’ measurements of reliability will help, too. There is no time to waste in preparing for a reliable system that recognizes the expanding role of renewables.

In the latest development, gas power plant owners are now facing performance penalties levied by the grid operator PJM and they are attacking PJM for enforcing the rules designed to ensure reliability. An added irony here is that the penalties—a total of more than $1 billion—are meant to pay incentives to the plants that over-performed their obligations, and that includes windfarms.

First, a bit more context.

The grid operator PJM, which covers the region from Illinois to Virginia, put these reliability rules and penalties into place in 2016 but this is the first full use of them. PJM already had in place a system of capacity payments which pay power plants to be ready to operate when needed. But the idea of these additional performance penalties was to impose financial incentives big enough to encourage plant owners to take precautions to keep their plants ready to run despite the weather.

PJM stakeholders voted on this policy to penalize energy suppliers who merely claim to be reliable and to use that money to reward the suppliers that actually exceed their expected performance. The self-governing PJM stakeholders put this in place after so many supposedly “firm” generators failed to perform in 2014. The Federal Energy Regulatory Commission accepted the rule, with the expectation such a carrot-and-stick approach fit with the broader market-based system that rewards generator owners in PJM.  

Putting power plants to the test

The policy was put to the test with very cold weather in a winter storm named Elliott that started on December 23, 2022. Demand for energy to heat buildings went up as temperatures fell.

Gas plant outages and performance failures mounted to account for as much as 23 percent of the expected supply, tracking closely the falling temperatures. Investigations continue, but PJM provided numerous charts of the causes as they were reported by the plant owners. The plants that are built to burn gas reported they failed to buy the gas, or had frozen pipes, or had common failures of equipment all across the region.

The penalty rules are complex in their details, but the idea is simple. If the plant doesn’t produce when needed, some of the money paid for reliable capacity is taken back as a penalty. For suppliers that exceed their committed capacity performance, the money paid as penalties will be paid as incentives for that extra performance.

Windfarms outperform

While American buildings have not been particularly well built for energy efficiency in this kind of weather, the growing deployment of windfarms to convert wind to electricity helped fill the demand. Along with the cold it brought, Winter Storm Elliott included prodigious winds and the windfarms in the PJM region did what they were built to do: make energy.  

The PJM system for counting reliability uses 13 percent as its windfarm value to meet demand, which put the expected requirement from wind for 2022 at around 2000 MW, depicted below in orange. As the chart below shows, the stormy weather drove the windfarm fleet in PJM to provide 2-3 times that much through to 2 am on December 26.

The results could hardly be clearer. But now that the time has come to collect the penalties and pay the incentives, gas plant owners in PJM are seeking to evade the penalties or even declaring bankruptcy.

It’s time for the gas plant owners to follow the rules they helped put in place. If we are going to have a grid reliability system that provides incentives, we can’t be gaming the rules every time the gas generators get caught with their plants down.

Reliance on fossil natural gas and the slow adoption of renewable energy contributed to electricity bills in New England in the first nine months of 2022 that are $5 billion higher than the prior year. Prices elsewhere in the country doubled.

Renewable energy policies are how we manage risks

The boom in gas production got us into this situation. Light-handed fracking gas well regulation and favorable treatment of gas-burning electric generation set the stage for our increased dependency on fossil natural gas. The gas industry saw the resulting gas glut as an export opportunity, and liquefied natural gas (LNG) export terminals as the best way to raise prices. That strategy has paid off very well for gas producers, particularly after the Russian invasion of Ukraine led to the cutoff of pipeline gas supply from Russia to Europe, prompting an increase in US LNG imports to fill the resulting supply gap.

For US consumers, gas and electricity this year are costing billions more because utilities are moving too slowly to adopt gas replacements, namely renewable energy, energy efficiency, as well as building electrification. Utilities, regulators and consumers need to make that transition to manage risks to energy security and cost spikes.

When gas production grew

The gas industry predicted in 2016 that LNG exports would raise the price of gas in the United States, and the Union of Concerned Scientists (UCS) warned that a slow approach to renewable energy made the country vulnerable to higher prices. Those predictions have come true. Instead of the gas production boom creating stable, lower costs, the United States is now experiencing higher prices tied to the world market because of LNG exports.

Picture those higher prices

Fossil gas is a primary fuel for electric generation, so rising gas prices mean higher electricity prices. Gas generated 53 percent of New England’s electricity in first nine months of 2022, and 47 percent in the central part of the country. These two examples illustrate my point: Relying on gas for electricity instead of renewables sets up the risky conditions for the high costs we see today.

From January through September, electricity in New England cost $5 billion more than during the same time period in 2021, according to data reported by ISO New England, New England’s grid operator, in its monthly operations reports. For the same months in southern Illinois, served by Ameren/Midcontinent Independent System Operator (MISO), wholesale electric prices on-peak nearly doubled, according to MISO data.

Below are two graphs of electricity prices from southern Illinois based on MISO reports on monthly averages for on-peak prices, and average national US gas market prices reported by the US Energy Information Administration. The graphs show very similar patterns, because higher gas prices drive higher electricity prices.

Renewables reduce the impact of gas prices on electric prices

There is a straightforward way to reduce the risk of high gas prices affecting electricity prices: Use less gas. The smaller the percentage of US energy needs that depends on gas with fluctuating prices, the lower the risk of unpredictable higher bills.

Let’s explore from the consumer perspective

Adding more renewable energy, either at home or in the utility supply mix, would reduce consumer risk of having to pay higher costs. That reduction comes from the fixed-cost nature of renewables. Once a wind farm or solar project is built and financed, the cost is not going to change for a given quantity of energy produced from that project. If that quantity is only 10 percent of the supply, then high gas prices will affect 10 percent less of the energy purchased. If the renewable supply is 60 percent of the supply, the quantity impacted by the price spike is 60 percent lower.

Let me explain with an illustration. Say prices rise $100 per megawatt hour (MWh) above the usual ~$35 per MWh, and the demand for electricity is 1,000 MWh per day. If all that was supplied by fossil natural gas—which has no price stability—consumers would pay $100,000 more than the norm each day. But if 60 percent of supply came from wind and solar, and only 40 percent is subject to the price spike, consumers would pay $40,000 each day above the usual amount.

Regions differ in exposure to high gas prices

New England entrepreneurs were early and aggressive in developing hydropower on the many rivers in the region, but that was a century or more in the past. Currently, new renewable energy has been limited by land availability and grid transmission. In New England, wind contributed only 3.4 percent of the electricity this year and solar provided 3.6 percent during the first 9 months, according to ISO-New England data. But that data do not include most of the region’s distributed solar, which is estimated at more than 4,700 MW.

Offshore wind will reduce Northeast gas needs

Northeast electric grids (and ratepayers) will soon enjoy the benefits of additional renewable energy from offshore wind. An analysis by ISO-New England of how much the first 800 MW offshore wind farm could lower prices found that 9 percent less gas would be needed for a cold snap with such a wind farm in operation. Contracts, permits and construction are in progress for wind farms that could provide five to 10 times more energy than 800 MW to Northeast grids. Those wind farms should be up and running in four to six years.

Looking forward, regions across the country have different approaches to grid planning and renewables development that can replace gas. Hopefully, they will take into account the risks of high prices—and the worst failures of the gas system—in those assessments.

Consumers, clean energy developers and state governments have all warned about a looming crisis of inadequate energy infrastructure. “Most of the nation’s transmission and distribution lines were constructed in the 1950s and 1960s, with a 50-year life expectancy, meaning they have reached or surpassed their intended lifespan” the American Society of Civil Engineers pointed out in a 2020 report.

Policy debates and calls for action are now focused on sorting out the root causes of conflicts and delays in building transmission after years of struggles that were boiling up as case-by-case problems. States are calling for transmission for new supplies in regional efforts and national state-federal collaboration. The benefits of updated transmission are obvious: greater reliability, lower energy costs, and a resilient modern power system with new clean energy sources.

Transmission planning makes energy choices possible

Most energy supplies in the United States are produced in one place and transported to consumers in other places. This isn’t much different than other commercial goods, be they lumber, food, cars, etc. Energy transportation, including the wires and pipes in local streets, are regulated to avoid monopolies overcharging consumers. Because federal rules apply to energy supplies traveling across state lines, advocates and policymakers need to understand how the Federal Energy Regulatory Commission (FERC) sets rules for how utilities and pipeline developers plan new construction.

FERC agenda’s root issues

FERC allows grid operators to plan grid upgrades in silos. This creates an expensive, nonsensical process where a utility making a transmission improvement that could lower costs for meeting energy demand does not consider the benefits of replacing wires and poles that are more than 65 years old (as the majority are). Consumers also lose out on potential savings when utilities replace aging infrastructure without considering clean energy requirements or the fact that there is a critical shortage of connections for new power plants. Because FERC fails to require utilities to look at modernizing the grid holistically, consumers, utilities and ratepayers will not get the full range of benefits when planners approve grid upgrades.

In many cases, FERC sets up transmission planning rules with no way to consider who might benefit. If there is no measurement of benefits, there is no reasonable way to control the cost to serve consumers. FERC has an outdated approach that puts planning for reliability—and maintaining the existing supply—far above any other consideration, so it is rare for new needs or approaches to make it into transmission plans. There are forward-looking regional plans, for example, that do not anticipate even one old power plant closing anytime in the next 10 years, or project that there may be more new plants other than the ones that were requested three years ago. Other planning abuses allowed by FERC include assigning to new wind farm developers the cost of reliability transmission fixes that the planners previously identified.

The Union of Concerned Scientists shared our critique of FERC’s current rulemaking to encourage the agency to require transmission planners to consider utility company supply plans, state laws that will shape future supply plans, and the age of old equipment. As long as transmission planners ignore the interrelationship among these factors, the grid will become even more dependent on fossil gas and, suddenly, world events. Making this process more inclusive and sorting out how to fully recognize such benefits as reliability in winter or lower consumer costs will speed investment in a modern grid and a reliable energy supply.

Firefighters have strategic plans regarding territory to address, as well as operational plans. Equipment includes fire trucks, protective gear and hoses. First responders need to share communications, so they can coordinate when an emergency requires more than just one department. This happens routinely where fire departments from multiple towns respond to a multiple alarm fire and provide mutual aid.

Electric utilities also have mutual aid agreements, equipment for generating and delivering electricity, and lots of planning. Preparing the grid to operate under extreme weather depends on all these things. In recent years, policymakers and planners have begun dealing with the impacts of extreme cold and extreme heat. This, rather than the damage to wires and resulting power outages from tornados, floods and hurricanes, is the subject of new attention.  

Electric utilities began early in the twentieth century to find economies of scale and operating efficiencies by consolidating adjacent service areas. Transmission lines connecting more power plants and cities increased reliability and lowered costs by allowing reserves needed for one set of customers to be shared.

Power grids are subject to equipment failures or outages, so there has always been some recognition of back-up supplies and needed flexibility to meet changing conditions on both supply and demand. Power “pools” across multiple utilities and multiple states took this sharing and mutual aid to a more formal level and allowed both planning and operations under a clear structure that benefited all the participants. Today’s regional transmission organizations, such as the Midcontinent Independent System Operator (MISO), the Southwest Power Pool, ISO-New England and PJM are multi-state, multi-utility grid operators.

For much of the 120-year history of electric power companies, regional reliability standards and coordinated operations have been voluntary. It was only after the 2003 Northeast blackout that federal law required reliability standards to be mandatory and carry inescapable penalties.

Firefighting was also provided on a private opt-in, participants-pay arrangement for more than a century. The problems of “free-riders” that benefit from fire protection without paying, and increased fire hazards due to spotty participation creating incomplete protection eventually led to municipal fire departments established as public institutions supported by combined public resources for the benefit of all.

Today, the Federal Energy Regulatory Commission (FERC) is asking how grid operators and planners are evaluating risks of extreme heat, cold and droughts—hazards that can cause system-wide problems for the electric power grid. In addition, regulators seek planning for more equipment to deal with large-scale emergencies (e.g. transmission between regions) and better communications (e.g. shared assumptions, quicker sharing of resources) between utilities across their service-area borders.

Setting up standards and requiring coherent, shared communications are wise precautions for utilities to adopt for the larger-scale outages that we see from extreme heat, cold and drought. Going back to the fire department analogy, the regulation of fire risks through building codes and safety standards has saved countless lives by preventing fires in the first place.

Since utility companies do not share modelling assumptions, have not set minimum standards for interregional capacity-sharing, or even established a commonly understood risk assessment for large-scale outages due to extreme weather, the risks of extreme weather leading to significant impacts are exacerbated by the lack of action by utilities.

In the midst of calls for action to enhance grid reliability, we must also not be stampeded by alarmist rhetoric. Monopoly utilities make greater profits through larger investments, so the incentive is to spend, spend, spend. Standards are necessary to both provide a reliable system and protect ratepayers from excessive costs.

For more than 50 years, the states have been using a reliability standard that tempers the impulse to ensure reliability at all costs and saddle ratepayers with the excessive costs of “gold plating” the system. That standard says “the probability of load exceeding the available generating capacity shall not be greater, on the average, than one day in ten years.”

The “one day in ten years” standard is set by the state agencies who have the authority over this important public health and safety issue. The recent Summer Resource Assessment from NERC (the North American Electricity Reliability Corporation) was widely cited and exaggerated for its statement that MISO faces a risk of insufficient supply if demand is higher than normal forecast (specifically a demand level expected with just 10%, or one-in-10, probability).

This is true, but it must be noted that the risk of insufficient supply dropped from one day in ten years to one day in 5.6 years. Should this be a call to action? Yes. But it should not be an excuse for alarmist rhetoric or, even worse, a call to turn back the clock on our efforts to modernize the electricity supply. NERC also did not highlight that MISO’s risk was based on using 54% less capacity from neighbors than the past summer. (See pages 14 and 16.)

Sensible planning, replacing old equipment, and effective communications bring great benefits for both fire protection and grid reliability. Hyperbole, like yelling in a crowded theater, just causes harm. FERC is working on numerous approaches to disentangle some of the bad practices that put the grid in need of modernization and upgrade. It is not hard to find bad old practices, and 50 year-old power plants running on 90 year-old designs, in our electric system.

New transmission, new power plants, better attitudes and less defending of old fiefdoms will get us through the energy transition. Let’s get on with the changes.

Shared Duties, with Leadership

The federal government funds space exploration. NASA, after all, is the National Aeronautics and Space Administration. We don’t have states launching rockets into space. Efforts to protect the planet from climate change, however, depend on the states and the federal government sharing responsibilities.

The federal government’s role is dominant in interstate commerce and the flow of electricity between states. Private utilities with multistate territories are accepted by state regulators. States approved utilities joining interstate regional grid operators. Federalism also means states have authority over power plant types and power plant construction, while the Federal Energy Regulatory Commission (FERC) has authority over the transmission system that links power plants and enables energy to flow across state borders.

Huge Opportunity

FERC is in the midst of a key rulemaking, with the potential scope and impact that comes along once a decade. The prospects for the United States reducing global warming emissions depends on planning and building an electric grid for a clean energy transition. Often the electric grid is described by an analogy to the road system that moves people and goods. But the history and capacity to build roads is thousands of years old. Every state and most every town in the United States has a highway or road department. By contrast, planning the electric grid just isn’t what most state and local governments do.

New Roles for States

FERC’s proposed rules introduce new grid planning roles for states. To make progress with an energy transition, FERC is directing electric utility companies and regional grid operators to include states in several vital decisions in which states previously did not participate. FERC is proposing that the states sit down with the utilities to define the sharing of benefits and costs from transmission, describe resource areas (think wind, solar, geothermal) where transmission would be desired, and the criteria to use in decisionmaking.

States, however, have limited resources and capability to participate in transmission planning negotiations. Back to the analogy, transmission is more like rocket science than road building. With that in mind, FERC should reconsider its proposed requirement that utilities “seek the agreement” of states on transmission cost sharing, and give states “a period of time to negotiate” amongst several states, generation owners, utilities, and consumer interests.

Let’s look at the topic of benefits from investing in the grid. Insufficient transmission contributed to the awful power outages in Texas in February 2021 that left more than 200 people dead. Insufficient transmission also is causing huge delays in building renewable energy facilities that displace coal and fossil gas power plants. Additional renewable energy supplies would protect consumers from price increases and geopolitical disruption of energy markets. FERC, for example, cited in its rulemaking Midwestern transmission upgrades that provide a $2.20 to $3.40 benefit from each dollar invested.

In fact, the FERC rulemaking uses the words “benefit” or “benefits” 580 times. The proposed rules include a table suggesting 12 categories of measurable, valuable electric system reliability and economic benefits that utilities may use in discussions with states and use in their cost allocation decisions. But, despite this recognition of benefits, FERC deferred to others to decide what benefits must be counted in decisions regarding what consumers and power plant owners will pay for new transmission. FERC passes those decisions on to the states in the lower 48, which are then expected to work with 125 utilities that provide transmission in any number of permutations and combinations.

Is This the Way Forward?

No, this is not the way forward. We know from past FERC rulemakings on transmission planning that when utilities have the option to limit planning, squelch competition, ignore benefits, and resist state directives, that’s what they will do. Even FERC knows this. The whole rulemaking is premised on failure of utilities to plan ahead for changes in the energy supply.

States Need to Speak Out

Two things need to change. First, benefits and beneficiaries simply are not optional. I expect lawyers will flesh out the standing principle that “beneficiaries pay.” Second, FERC commissioners should hear from states about the circuitous and unsupportable processes hinging on coordinating multiple states described in the proposed rule. FERC commissioners need an illustration of the steps necessary for two adjacent states to negotiate for one transmission line the costs, benefits and criteria with the affected utilities, the general public, and any commercial entities that want to shape that decision.

We have pressing needs to invest in the grid. This rulemaking needs to be more direct and more useful.

The grid operators need transmission plans that account for old plant retirements and integrate new policies that drive windfarm and solar plant construction. The planning base case is not a do-nothing case, and common-sense scenarios that are responsive to the expected pace and scale of change should prevail.

Recent efforts by two grid operators, the Midcontinent Independent System Operator (MISO) and the California Independent System Operator, show what can be accomplished with grid planning. Planning for both of these regions builds on a repeated practice of looking ahead to more renewable energy in the supply mix and less fossil fuel energy due to plant closures.

Midwest (Sort of) Continues a Proud Tradition

MISO’s current Transmission Expansion Plan calls for more than $3 billion in upgrades, spread over a region with 42 million people. MISO’s planning has struggled to keep up with the pace of change since large amounts of wind energy became available beginning in 1999. In recent years, MISO has been working with scenarios that recognize “the transmission system no longer serves the same resources for which it was designed, and transmission upgrades are needed to enable integration of new resources.”

MISO gets our support in recognition of its recent request that FERC approve cost sharing enabling an expected $10-billion package of additional transmission with economic benefits 2.6 times greater than the cost. With such planning and regulatory cost-allocation efforts, imperfect as they are, MISO is demonstrating the persistence and problem-solving required to move forward with the present light-handed FERC supervision of utility transmission investment and the persistent case of Entergy’s monopolistic behavior.

California Works with Planning Scenarios

The California ISO plans, both its annual Transmission Plan and its first 20-Year Transmission Outlook, build on state policy and procurement efforts. California has long set policy affecting retirements and procurement of new supply. The Transmission Plan reflects inputs and assumptions about year-to-year changes driven by the state.

The California ISO has taken planning to a new level with its draft 20-Year Transmission Outlook. California policy work is years ahead of other grid regions when it comes to decarbonizing the grid, electrifying transportation, integrating solar, and managing plant closures. In California ISO’s words: “The 20-Year Transmission Outlook provides a long-term conceptual plan of the transmission grid in 20 years, meeting the resource and electric load needs aligned with state agency input on integrated load forecasting and resource planning, as the basis for further dialogue.”

PJM Takes a Look at Renewable Planning

In November, PJM—the grid operator for 13 states from New Jersey to North Carolina and west to northern Illinois—published a transmission report describing the renewable supplies for meeting the region’s renewable electricity standards and offshore wind plans. PJM worked with the five coastal states via one-on-one meetings to determine relevant planning scenarios.

PJM has only recently considered the states’ energy policies as relevant to its FERC-authorized role as transmission planner for its region. When PJM released the transmission report, it surprised stakeholders with its approach and results because PJM planning currently relies only on already announced power plant owners’ binding commitments to close or open power plants. This short-sited approach constrains what information PJM considers, and its plans are exceedingly modest. With this new report and recognition of state policies, PJM is just starting stakeholder discussions about reforming its planning process.

What PJM Saw In Its First Look

PJM’s report developed five scenarios for the build-out to meet state requirements. By planning for a set of changes, rather than taking each change incrementally without forethought, the report estimated costs ranging from $627 million in the short-term to between $2.16 billion and $3.21 billion for long-term scenarios. In mid-March, I wrote that PJM and Illinois needed to work on changes to the grid and power supply to meet the Illinois Climate and Equitable Jobs Act carbon reduction goals. The 2021 law allows, but does not require, PJM to plan ahead because various fossil fuel plants must reduce and then cease emissions by a specific date.

What New England Sees

The markets in PJM and ISO-New England (ISO-NE) share origins and a mistaken belief that planning for change will undermine existing power plants’ profitability. These two grid operators also have lagged behind others in hosting wind and solar despite the widespread push for cleaner electricity across their regions. This led New England states to prod ISO-NE to start making planning reforms. In December, FERC approved an additional, supplementary ISO-NE transmission planning process for state-requested, scenario-based analysis to help policymakers, utilities and stakeholders understand grid needs for replacing fossil fuels with clean energy. ISO-NE is now unfolding an estimate of transmission investments needed to enable decarbonization efforts for 2035, 2040 and 2050.

SPP & MISO Show “You Won’t Know Until You Try”

The last of these recent initiatives demonstrates a first attempt at solving grid problems that cross the boundary between the Southwest Power Pool (SPP) and MISO. Late in 2020, these two grid operators set aside their own long-standing reluctance to embark on a joint planning process, and have identified, as the CEOs of the two put it, “transmission needed to remedy historical challenges facing generators near the shared boundaries between our two Regional Transmission Organizations (RTOs). These challenges have caused projects to drop out of the study process because costly network upgrades are triggered.”

This joint process is unusual because it looks at the benefits from interconnection-related transmission, and for a long time the RTOs were unable to navigate the obstacles of comparing their data and assumptions. Now, the challenges are still there, but the engineering is done. The lesson here is one for all grid operators: They began the necessary work without having answers to all the difficult questions, but found ways to go forward.

Looking to FERC For Planning Reforms

Transmission has always been a monopoly with regulations meant to ensure cost and service are reasonable and non-discriminatory. I looked at these new plans to see what is possible, and where some best practices might be applied to regions that are less engaged in planning.

Transmission customers, both for supply and demand, benefit from MISO considering expanded benefits in its multi-value plan, the California ISO provision of transmission to meet state requirements, and the joint effort by SPP and MISO. In other regions, the grid operators have not drafted new transmission plans that can be implemented, or worse, ignored the benefits of that planning.

When FERC inquired about current transmission planning practices, it received more than 170 sets of comments from customers and industry calling for planning reforms. Many of these comments raised issues that many wrongly assumed had been fixed by prior FERC utility transmission planning reforms, and all planning issues have real impacts on the electric power system.

Past FERC reforms expected that grid operator collaboration and information-sharing would respond to public needs and consumer interests. In practice, the grid operators’ selection of planning criteria, assumptions and scenarios ultimately determine what gets built, when, and who pays. The current FERC rules allow inappropriate grid operator practices and provide opportunities for abuse and discrimination, and the results muddy understanding of consumer costs for transmission and energy.

To achieve the consistent, widespread planning that is hinted at by the examples described here, FERC and state governments need to make changes. Inside and outside the regional grid organizations, grid modernization cannot wait for corporate self-interest in a monopoly setting. Practices within a utility and across utility boundaries should not exclude and discriminate to protect outdated assets and utility fiefdoms. Planning is key, and regulators must expand the scope of needs, solutions and measured benefits that planners count to modernize the grid.

Regional grid operators PJM and Midcontinent Independent System Operator (MISO) have recently circulated important documents that spell out how they will apply CEJA to power plant emissions. PJM, one of two regional grid operators in Illinois, runs the grid for the northern portion of the state serviced by Commonwealth Edison (ComEd). (See the map below indicating PJM’s footprint in the state with a shaded area and blue transmission lines.) PJM hasn’t provided estimates of its emissions or how it will use exemptions allowed under CEJA, so I made a first estimate.

For the ComEd/PJM region, I expect exemptions to the pollution limits will be given by PJM for reliability as often as once every five days. More emissions from more exemptions are likely. I only looked at the simplest of the three causes of what may be routine and persistent supply conditions requiring exemptions for reliability.

The CEJA law has a set of provisions for operating fossil fuel plants to protect grid reliability. These provisions allow PJM and MISO to provide exemptions to the emissions limits on gas-fired plants. PJM listed five continued uses for fossil fuel plants to ensure grid reliability. Without building lots of new renewable generation, three of them will require the fossil generators to run often. MISO has the same five, plus two more.

The ComEd region of Illinois has limited transmission, making the generators in the Illinois portion of PJM more vital to meeting customer demand than might be expected. Similarly, reducing demand on PJM by ComEd customers with dynamic pricing, flexible load management, distributed solar and storage will all reduce the amount of generation needed on any particular day. In the longer term, Illinois’ ability to reduce fossil fuel plant operations will be improved by increasing transmission connections that can bring a diverse mix of wind and solar to supplement local carbon-free generation.

Not all the needed new clean energy is available yet

The limits of the transmission system will affect the ability to supply electricity to consumers in Northern Illinois and hamper efforts to reduce fossil fuel use and related emissions. PJM defines three types of situations that will predictably occur and require fossil fuel plants to operate. With the supply and demand as it was in the past year, those conditions requiring the use of fossil fuel plants will occur roughly 20 percent of the days, based on just the most readily predicted of the three uses.

More exemptions when examining the basics

The other two uses of PJM’s exemptions, for transmission overheating and transmission voltage issues, are much more specific to transmission designs and require specialized modeling and data sets. However, these needs will certainly increase the number of days when fossil fuel generation is used in PJM’s Illinois region.

Depending on how loosely PJM and MISO define CEJA emissions limits, they will use CEJA’s provisions extensively, creating exceptions to the emissions ceiling to maintain the electric system reliability. The simplest way to understand the need is to compare supply and demand. Until developers, homeowners and community groups build a lot more renewables and energy storage—and make a lot more efficiency improvements—supply limits will dominate this situation.

Demand for reliable generation in PJM’s Illinois region is just under 25,000 megawatts (MW). The existing generating capacity in this region totals 26,443 MW, and roughly half of them are provided by carbon emitters, namely 3,842 MW from coal, 10,760 MW from gas, and 272 MW from oil. If demand does not exceed the supply available to northern Illinois from 10,517 MW of nuclear, 1,049 MW of wind and 3 MW of solar (these are the reliable capacity numbers for the existing generation counted by PJM) plus roughly 3,000 MW of imported electricity from other states, then PJM will not activate its fossil fuel plants for generator supply reasons.

I took a look at the past year’s demand data for the ComEd region and counted the days when it was greater than the current level of PJM’s non-emitting generation serving Illinois. My first estimate comes to 20 percent of the days in the past year.

Transition to clean energy requires replacing plants

You may have noticed that the total for solar power was just 3 MW. That will soon change as 1,000 times that number is under development in northern Illinois, and storage is often included. PJM is only counting the generation selected in the PJM capacity market, and due to a different collision with state policies, there have been delays in capacity market auctions. Across all of PJM, solar developers added 1,500 MW of capacity in the most recent capacity auction. Whether the current solar numbers for northern Illinois is the currently recognized 3 MW or the 3,000 MW that are in the queue, there is much more work to do to get to the clean economy future that we want.

In the meantime, PJM and MISO must recognize the spirit of CEJA’s limits. PJM and MISO use market rules to deal with emissions limitations that already exist, but apparently those rules have not been considered as relevant to CEJA-affected power plants. MISO and PJM’s newly posted reliability guidance expect CEJA has no effect on the economics or availability of the fossil-fired generation now limited by law. This is not a good way for grid operators to work with their states. Until some common ground is found, CEJA implementation is going to be a reminder that implementing climate-safe energy policies is both a matter of building new supplies and changing how states, grid operators and utilities run the energy system.

The gas industry’s widespread inattention to winter reliability must be addressed, and one way to fix it is for gas-burning power plants to take a closer look at their performance in colder weather.

Last winter, I described how cooler air allows gas-fired power plants to generate more electricity than the plant can generate in hot weather, because cooler air is heavier and able to absorb more heat. Despite this capability, nearly all new gas-fired power plants in the Mid-Atlantic during the past 20 years sought and received limits from grid operator PJM on their ability to use this physical capability through PJM’s process. Failing to implement this cooler-weather capability costs consumers money and makes it more likely there will be another power system failure this winter.

An analysis I conducted after the last February’s energy crisis in Texas found gas-fired plants suppressing their own capabilities in cooler weather in at least 27 states. Plant owners’ decision to report to grid operators no added capability or flexibility from their generators ignores good utility practice. When power plant owners request permission from their grid operator to connect a new power plant to the grid, they are expected to provide both winter (50 degrees F) and summer (90 degrees F) power plant output in the process. This is a standard process for adding large power plants to the grid, with detailed rules and standard forms. In some regions, the power plants provide the added winter capability and flexibility that lowers consumer costs and increases reliability. In some regions, they don’t.

Grid operators in New York and New England are getting this colder-weather contribution from 90 percent of the newer gas-burning power plants, what wonks would call natural gas combined-cycle units. These gas power plants have requested and received permission to operate at higher winter ratings than summer ratings.

In the three other regions of the eastern United States, most of the newer gas power plants have told grid operators that they will not produce more power in any weather than what they can produce at 90 degrees F. The connection requests and resulting plans for the operating gas power plants in the Southwest Power Pool show 33 percent in that 14-state region are providing higher output in cooler weather. In the 24 states in the Midcontinent Independent System Operator (MISO) and PJM power pools, only 10 to 15 percent do so. One piece of good news for Texas: The Electric Reliability Council of Texas (ERCOT) reports for the past year approximately 80 percent make the cooler capability available. (There are states that are in more than one power pool.)

The problem of cold weather reliability is caused by power plant owners cutting corners to save money. This is related to, but not the same reason for the energy problems in Texas last February triggered by Storm Uri. There, the biggest problem was gas suppliers—and to a lesser extent power plant owners—that were unprepared to keep their equipment from freezing.

A more widespread problem is due to plant owners showing no interest in how cooler temperatures will affect their plants. Instead of problems cropping up only when temperatures are at record-setting lows, which happened last February, their neglect undermines the grid in the spring, through the fall and winter, and during most of the summer, too. Because the power plants we are calling out choose to keep the hot weather de-rating that applies when the outdoor temperature is at 90 degrees F or above, economic and flexible capability is not available to the grid. That also increases costs for consumers.

The power system’s ability to integrate solar energy is also undercut by these gas plant owners’ wrongheaded decisions. The capability that should be available in cooler weather would provide flexibility for handling the Duck Curve caused by solar energy’s daily pattern. This is most pronounced in cooler weather in the spring, when solar panels are most productive because they work better in cooler ambient air. Using fewer, but more flexible, gas power plants is part of the path to decarbonize the electric supply, but only if they are used correctly.

UCS has been warning about risks of over-relying on gas for years, from reports in 2013 and 2015 to our current call to “red light” US approvals for new fossil fuel development on public land. The practice of ignoring colder weather has serious, near-term risks. If the industry isn’t interested in correcting this problem, the Federal Energy Regulatory Commission has plenty of authority and opportunity to use incentives, penalties or reliability rules to get gas-burning plant owners’ attention.