This project lives at chrisgillett.org/ae-congestion.

Published in Works in Progress Magazine, Issue 24: Why American data centers can’t plug in.

The first state was a water utility.

In agricultural societies, before the first state, high variance of rainfall caused periodic droughts and floods that destroyed crops and killed people. Eventually, the village chiefs had the idea to construct levees and dams, to control floods and to store water during droughts, and to build canals to deliver the river’s water to farms. Through charisma or predation, they conscripted workers to build this system, and they raised a tax in grain to feed them.

This was a very productive investment. After the system was built, there were fewer floods and fewer droughts. Farms were more productive and there was a surplus of grain.

But the farms didn’t keep their surplus. It was taxed away by the chiefs who had coordinated the project. They used that surplus to employ people outside food production, to build ziggurats and to produce luxury goods. Over time their spending developed a class of urban artisans and merchants.

But why did the farms not keep their surplus? A fair arrangement would be to tax only enough grain to maintain the public works, to expand them as the population grew, and to provide the water utility’s administrators an income comparable to the farmers. To create this outcome, the farmers could have violently over-powered the utility administrators. Why didn’t they?

The farmers didn’t know how the irrigation system worked. They didn’t know that there were stations for lifting water uphill using animal power. They didn’t know how to make the concrete that was used to make the levees and dams. They didn’t know about the system of “priests” who relayed information about water levels across the system, or about how that was used to decide which dams to open.

Only the largest estates even knew how to bargain with the priests, how to go before a court and argue for a larger allocation of water, a different delivery schedule, a lower tax rate, or a different route for a planned canal.

And the utility administrators misdirected the farmers. They didn’t want the farmers to think about the irrigation system. So they told the farmers that they weren’t engineers, lawyers, and politicians but instead they were priests. And they said that their control of the river didn’t come from their public works but from their relationship with the gods. They said that the gods lived inside their ziggurat, so the farmers couldn’t enter it. But really, their ziggurat wasn’t a temple, it was their headquarters, and contained no gods but only records of grain taxes, rainfall, and water levels. If a farmer entered the ziggurat, he wouldn’t have known how to read the records, and he couldn’t have imagined how they were being used to plan the system.

The farmers’ surplus was extracted by the chiefs because of information asymmetry. At one level, they lacked the specific technical knowledge to operate the system that their lives depended on. More fundamentally, they were misdirected away from noticing the system at all. They were insufficiently oriented to reality to be able to participate in the real politics of their society.

The farmers relate to the system through a false story, but ultimately they see its results. They know that if there are floods or droughts and the crops don’t grow, the pharaoh must go. That’s inevitable, because the system can’t soften hundred-year floods and droughts. And when it happens, the pharaoh is said to have lost the favor of the gods, and he is replaced from within the priest class, and the farmers don’t question the system itself. The pharaoh earns the lion’s share of the surplus by risking to sit in the scapegoat seat. In Ancient Egypt, the pharaoh’s dynastic succession was interrupted by usurpation by a priest many times, but never in thousands of years was there a popular revolt.

Analysis

This story isn’t a metaphor. I think it’s more or less the true development story of most civilizations. The first public works most civilizations undertake is irrigation, which requires the formation of an authority to levy compulsory taxes, and that tax authority keeps most of the surplus through information asymmetry, which then funds further development. As the civilization develops in scope and scale, power necessarily becomes less centralized.

What are the lessons of this story for today?

What I like about this story is that it forces us to realize how similar we are to the peasant farmers in the story. Until recently, I didn’t know anything about where the water came from, where the electricity came from, or where the trash went. It never occurred to me to wonder who owns the local airport or how the road system is planned. I only have the fuzziest idea of how railroads and mines work. When I look at satellite images of the outskirts of my city, I mostly don’t know what I’m looking at. People today know less about the material foundations of our civilization (not just the engineering, but the operations, financing, and governance) than ancient peasants.

And I do think that is somewhat by design. The people who run the industrial system don’t want the public to think about them too much or understand them too well. For example I closely observe a power utility, and I often notice them saying less than they know and sharing less than they could. They don’t talk much about their transmission planning, employee safety, fuel supply, power plant outages, certain environmental programs, etc.

There’s even misdirection going on. Utilities talk a lot about their ancillary programs - rooftop solar, demand response, water conservation, etc. - that make up a small percent of their supply portfolio. And often times they talk very little about their key assets.

Is this information asymmetry intended to facilitate extraction? No. The organization that I’m most familiar with is not extractive. There is a community of observers who understand these industries and are keeping them honest.

I think every decision to be less transparent than they could be is individually rational and is intended to reduce their attack surface area, in terms of physical security or politics, by terrorists or ideological opponents. That logic, applied across every department of every organization in every industrial sector, adds up to significant information asymmetry.

The information asymmetry has a strange effect on discourse. When a governor talks about the affordability or reliability of electricity, he knows that his constituents don’t understand the system he’s talking about. He’s rewarded for symbolism. For example the pledges by the data center companies to pay for their own power, announced at the State of the Union, were entirely symbolic, as far as I can tell. The processes that actually matter for cost allocation are playing out in state utility commissions, but they’re too arcane to matter politically.

What matters politically, in the end, is the system’s tangible results. People notice when the system breaks - gas shortages, rationing at grocery stores, power outages, large price increases, etc. This creates a modern ‘mandate of heaven’ effect. When the crops don’t grow, the pharaoh must go.

We don’t have a pharaoh, we have political parties, but they serve a similar role in this context. When the system fails, people switch parties. Crises occur periodically, and the party in the White House gets punished for it, regardless of the actual cause-and-effect involved. These random events are a major contingent force in history.

In the 1970s energy crisis, the public never understood why the crisis was happening. Polls found that 80% of Americans believed that the crisis was artificial, the result of a supply-withholding conspiracy by the oil companies. No one knew what the Federal Power Commission was. Liberal politicians promoted that theory, which they knew was untrue, because it gave them an advantage in the real negotiations over the regulatory processes that the public didn’t know or care about. The crisis was the fault of New Deal Democrats in the 1960s, but by chance a Republican was president when the crisis hit, so republicans were punished for it. Then they the crisis resurged in the late 1970s, under Carter, Reagan was elected even though he and Carter had pretty similar approaches to the crisis in the ways that mattered - but important symbolic differences.

Does the industrial system actually matter? In the long term, it’s the most important thing. I think that the rise and fall of civilizations is best explained in industrial terms. And the disconnect between popular politics and industrial regulation is one of my long-term concerns. We see the importance of the industrial system especially at the pointy end of politics, in military operations, where infrastructure assets are frequently targets.

But the lesson of this story doesn’t only apply to the industrial system. Most sectors of society, including the post-industrial sectors, are too complicated to be generally understood by the public. So the same information asymmetry exists, creating a disconnect between the ground-level real politics and the symbolic politics for general audiences. Maybe one difference about the non-industrial sectors is that failures in those sectors don’t create immediate large changes to daily life, so there’s less of a ‘mandate of heaven’ loss that requires correction.

Anyway, I think the lesson to take away from the above story is to ignore the symbolic and focus on the concrete. Don’t be the peasant with very sophisticated opinions about the gods and no specific knowledge about the levees and dams.

Building behind-the-meter load at existing power plants

Amazon and Talen Energy had the idea to build a large data center at an existing nuclear power plant, Susquehana, and to connect the data center directly to the power plant, not to the grid. By avoiding a grid connection, the data center wouldn’t have to go through PJM’s interconnection queue process.

But FERC rejected the plan for complicated cost allocation reasons. Basically, when Susquehanna was built, the local utility spent a lot of money building transmission upgrades to support the plant. All PJM customers are now paying back the utility for those investments. If the Susquehanna now disconnects from the grid to supply Amazon directly, PJM grid users would be stuck paying off Susquehanna’s upgrades, which doesn’t seem fair now that they won’t be getting the benefits of having Susquehanna’s capacity on-grid.

So it seems that this strategy is dead. Once a power plant is on-grid, you can’t take it off-grid. Amazon has pivoted that data center project to being on-grid.

Restarting mothballed power plants

Microsoft and Constellation had the idea to restart the mothballed Three Mile Island nuclear power plant (yea, that one). This is an on-grid strategy, so Microsoft’s data center would have to go through the interconnection queue. Slow. But it seemed like a relatively fast way to bring online nuclear capacity to provide clean, firm power to Microsoft’s data center.

Unfortunately, it’s turned out that Three Mile Island’s grid interconnection is effectively gone and will have to start from scratch. It still has its physical connection to the grid, but in the time that it’s been offline, the “backbone” transmission capacity that it had has been filled by other generators. New backbone capacity will have to be built before the power plant can come online, which means it has to go to the back of the interconnection queue like any other project.

Taking over interconnections from shuttered loads, like closed down factories, is unlikely to work, for the same reason.

There’s still an advantage to restarts. It’s always faster to restart than to build from scratch. But it’s not a strategy for jumping the queue, like people hoped.

Off-grid data centers

Fermi had the idea to build off-grid power generation that data centers could connect to behind-the-meter. That way, both the load and the generation skip the interconnection queue. And it avoids the cost allocation problem of Susquehana because the grid is mostly irrelevant to a mostly off-grid project.

Off-grid has inherent disadvantages. Grid power, which is produced by an optimal mix of thousands of plants, is always going to be cheaper and more reliable, on average, than off-grid power. The trade is that, theoretically, off-grid power can come online faster because it doesn’t have to go through the interconnection queue and wait for transmission upgrades to be built.

The problem Fermi ran into is that the wait time to procure generating units - nuclear AP1000s and natural gas turbines - stretched into the 2030s. At that rate, you might as well get into the interconnection queue to get the benefits of grid power. Their customer backed out.

What strategies remain viable?

Traditional development. Maybe slow and steady wins the race. Just get in the queue and manage the project as best you can.

Large flexible loads. If grid operators can rely on data centers to turn off during the tightest 1% of hours on the grid, then data centers could come online before their transmission upgrades have been built. This depends on policy changes from the various grid operators, and it brings up complicated operational, market, and regulated cost allocation questions. But I’m optimistic that this will work.

Data centers could take over the interconnection of other large loads. A developer buys an aluminum or a cement plant, shuts it down, and builds a data center in its place, plugging the data center into the old plant’s grid interconnection. Presumably there’d be no issue from the grid operator’s perspective, as long as the data center’s peak load is less than that of the plant it’s replacing. But the local politics would be brutal. You’d be shutting down a plant that presumably employs hundreds of people in a community to replace it with a data center that would employ dozens of the people. You’d need the community’s permission to build the data center, and I don’t think they’d be too happy with you. I wouldn’t bet on this.

Distributed energy resources - like residential/commercial solar and battery storage - can be deployed quickly to take existing residential load off of the system and make room for new large data center loads. This will tend to be more expensive than utility-scale generation because the fixed install costs are spread over a much smaller capacity at every individual site. There’s also a big operational overhead to acquiring customers, installing the resource, and maintaining it. But it’s the fastest way to get capacity on the grid. In order for data centers to benefit from it, grid operators would need to account for this increased distributed generation in their planning models in order for it to “make room” for new large loads. There would also need to be rules by which a large load gets credit for supporting distributed generation. At the moment, a data center developer can’t move ahead in the interconnection queue by supporting distributed generation.

Space-based compute is a very complicated and expensive way to build a 1 GW data center, but it’s probably the only way to build a 100 GW data center. It’s the most scalable approach. So if scaling laws are still holding in, say, 2040 and AI labs want to build truly ludicrously large clusters, whoever is ahead on space-based compute will run away with the game. The question is whether SpaceX / xAI can stay solvent until then. Unfortunately, this project, which should be the coolest thing ever, is likely to be ruined with a stupid name that Elon Musk thinks is funny. My money is on ‘Skynet’ or a pun based on that.

The vast majority of energy use goes to space heating, water heating, air conditioning, and refrigeration. Air conditioning and refrigeration are nearly 100% electric around the country, while heating space and water is done almost entirely with natural gas and propane. A significant portion of energy usage is categorized as “Other” - a long tail of mostly electrified conveniences.

The next graph is a detailed look at uses of electricity. Although electricity makes up a small share of space heating and water heating, these are still the most significant uses of electricity.

Most electricity consumption comes from activities that follow daily patterns. While the refrigerator runs consistently, washing machines may run any time, and microwaves use too little power to matter, three highly correlated activities - air conditioning, space heating, and water heating - together consume 56.6% of electricity.

Water heating (15.5% of electricity usage) is primarily used for showers and faucets, which are primarily used in the morning and at night. And heating and cooling demand (41.1% of electricity usage) is correlated across households as the temperature changes throughout the day. These factors, plus the general increase in activity during the day versus at night (e.g. for lighting and other things), are what gives the grid its load shape.

Heating is nearly universal (ranging from 87% of square feet in the South to 93% of square feet in the Midwest), but the presence of air conditioning varies more by region.These regional differences are driven by the climates found in the regions.

The graph below breaks down the square footage of the four Census regions by climate. The size of the block represents the number of square feet of a given climate (X-axis) in the given region (Y-axis). Darker colored squares have a greater proportion of air conditioned square feet.

The relatively low adoption of air conditioning in the Northeast is because that part of the country is very cold. And the relatively low adoption of air conditioning in the West is because much of that part of the country (or rather, much of the square footage in that region) enjoys the mild weather of the Pacific coast.

Although there’s nearly as much cooled square feet of housing as heated square feet, residential buildings use much more energy for heating than for cooling. Partly it’s because cooling is a more efficient process for thermodynamic reasons. It takes less energy to remove heat than to create heat.

It’s also because heating is typically used more frequently than cooling. Winter lasts longer than summer in most places. And while hot days are never more than 30 degrees hotter than a comfortable temperature, on cold days temperatures can drop much more than 30 degrees below the setpoint.

The next graph again breaks down the country’s square footage¹ by Census region and climate, but now the shading represents the energy intensity of space heating (energy used for heating per square foot of heated space). Space heating is most intense in the cold regions because it’s used more there. (The same is true for air conditioning in hot regions).

As I’ve said, the heating of space and water is mostly powered by natural gas, and electricity mostly powers everything else. But heating is also powered by propane and fuel oil / kerosene, and this fuel mix differs regionally. The Midwest and West both have ~80% natural gas, while the South has the most electricity and the Northeast has by far the most fuel oil in their heating fuel mix.

These differences actually have more to do than the year in which a house was built than its region. Older homes are more likely to use propane or fuel oil for space heating because the natural gas system was only completed in the 1960s. Newer homes are more likely to use electricity for space heating because electric heat pumps were first commercialized in the 1990s.

Because the South has experienced more economic growth than the Northeast since 1960, homes in the South are newer than in the Northeast. 32.6% of housing units in the Northeast were built before 1950 (compared with 7.9% in the South).

Let’s now narrow our focus to spending (in dollars) on electricity. We’ve already seen the long tail of electricity-power activities and the amount of energy that each consumes. Let’s see the cost of that total consumption in dollars.

Residential spending on electricity totalled $161.5B. The average household spent $1,380/yr on electricity in 2020 (which is actually quite a bit lower than other estimates I’ve seen - but I’ll use it for this article). Comparing that figure to the 2020 BLS consumer expenditures survey, that’s about as much as the average household spent on apparel, education, and gasoline but quite a bit less than was spent on entertainment and food.

This graph shows the average annual cost of an end use to a household that actually has that end use. For example, the average household does not spend $302/yr on pool pumps, but the average household that has a pool spends $302/yr on the electricity for their pool pump.

What stands out to me here is how cheap the energy costs are for incredibly useful things. The marginal cost of using your microwave, dishwasher, and washing machine is measured in cents, not dollars.

And then some things are surprisingly expensive. Everyone knows that air conditioning and heating consume a lot of power - we have the trope of the father admonishing the children to conserve air conditioning - but I think a lot fewer people think about water heating, even though in this study it’s even more expensive. Maybe the father’s efforts are better spent encouraging shorter showers. Even still, the marginal cost of a warm shower is measured in cents, not dollars.

Pool pumps seem expensive. (I’m not sure how pool heating is accounted for, since there’s a “hot tub heaters” category but not one for pools. Maybe pool heating is included in overall water heating?) But water is heavy and it takes a lot of energy to move heavy things. Plus pool pumps run continuously.

EV charging costs $280/yr on average. That’s enough to make a noticeable difference on the monthly bill, but it’s tiny compared to what people typically spend on gasoline.

Looking at adoption of various household energy uses, I’m shocked by how low the adoption of dishwashers and clothing washers/driers is. It’s commonly said that when countries first begin to develop, the first major energy-related purchase that households tend to make is a refrigerator, typically followed by air conditioning, televisions, and washing machines. Those first three items have nearly universal adoption even among Americans in deep poverty, but washing machines are owned by only 56.4% of households earning less than $5k/yr.

I don’t think it’s the cost of the appliances that’s limiting their adoption. Refrigerators have a similar upfront cost, and higher operating costs, compared with washer/drier sets. Although the refrigerator has significantly more utility, I still find it surprising that adoption of these other appliances is so much lower.

I think this is partly explained by the fact that those appliances require plumbing hookups, while refrigerators can be plugged into a regular socket. The lowest income people are much more likely to live in older buildings and apartments, which are less likely to have hookups to allow for dishwashers.

Electricity can be a particularly stressful budget item for many people. Although utility bills are low compared to most other spending categories, it’s such an essential service that there aren’t many options for cutting back without discomfort. When seeking to lower electricity spending, most people first seek to use less heating or air conditioning.

The EIA survey indicates that 9.9% of households have left their home at an “unhealthy temperature” to reduce their bill. This varies by income from 24.8% of households earning <$5k/yr to 4.0% of households earning >$150k/yr. 10.0% of households (<$5k=26.6%, >$150k=1.5%) received a notice advising them that their service will be disconnected if they don’t pay by a certain date. But actual disconnections are rare. Only 0.2% of households experienced a disconnection for nonpayment. (Presumably this figure has the same income distributional characteristics as the others, but the number of households experiencing disconnection was too low for the survey to break it down by income.)

Now let’s look at the adoption of various energy technologies that are changing how residential buildings interact with the grid. For each technology I’ll look at what building structure or household demographic statistics most strongly predicts adoption.

The first thing I notice is that respondents weren’t even asked about battery storage. When the next EIA survey comes out, I bet that they’ll ask about residential battery storage, and I bet that solar adoption will be much higher.

The technology with the most adoption is smart meters (or AMI - Advanced Metering Infrastructure). Maybe this is unsurprising, since it’s the only technology that consumers generally don’t choose for themselves; it’s installed for them by the utility and the cost is socialized.

A building’s AMI adoption is most strongly predicted by its structure type. Just 14.8% of large apartment buildings have AMI, while 32.8% of detached single family homes do. This is probably because the metering infrastructure for a detached single family home is much simpler than for a large apartment complex.

Adoption of back-up generation is surprisingly high at 14.3% overall. This is typically a portable gasoline-fueled generator with enough power for essential loads, costing around $1,000. Adoption is most strongly predicted by the structure type, since it’s hard to imagine how an apartment dweller could opt into backup generation.

Back-up generation is apparently popular in places with frequent natural disasters, like the hurricane-prone Gulf Coast. But the data shows higher adoption in New England (22.3%) than the East South Central and South Atlantic (which include the most hurricane-prone areas in the U.S.). Maybe the cold temperatures in New England make back-up power more safety-critical?

The level of adoption of back-up power is also interesting because it’s a strong indication of how much people value having reliable power. Everyone knows that power outages happen. The average electricity customer experienced 366 minutes of power outages in 2023 (and much less if you exclude extreme events like hurricanes). And most people know that a backup generator can be purchased for around $1,000. So when someone buys a generator, they’re saying that avoiding 366 minutes of outage is worth $1,000 to them. And when someone doesn’t, they’re saying avoiding outages is worth less to them.

Residential electricity customers vary widely in how much they’d pay to avoid outages. Typically this is correlated with income (and we see this in the EIA data here), but there are other factors like health concerns. Elderly people may be less able to bear the discomfort of outages, and people who use medical equipment may require electricity for their health.

But when the grid goes down, it goes down for everyone. You can’t pay more or less to get more or less reliable electricity service (except by buying on-site back-up power). Investments in reliability are socialized over the whole system, regardless of how an individual customer values reliability. Utilities and grid operators commission studies to estimate the weighted average value of reliability to all customers, but it’s very challenging and those studies have a suspicious tendency of landing on round numbers like $5,000/MWh and $10,000/MWh.

Moving on to smart thermostats, we see that income most strongly predicts adoption (<$5k=3.1%, >$150k=25.7%). That makes sense because you can install a smart thermostat in any structure, even as a renter. Its only value is as a minor convenience. And there aren’t many income-based subsidies for smart thermostats.

Solar adoption varied most widely by climate. Mixed-dry climates have a 7.8% adoption rate while adoption is lowest in mixed-humid areas (1.7%). I actually think that Census region is the driving factor due to state incentives, but climate region happens to have a bit more signal because although it’s closely associated with Census region it also picks up things like income effects.

EVs are a similar story. EV adoption varies most widely with income, followed by climate region.

There are three basic functions on the grid: generating power, transmitting and distributing it, and selling it to end customers. Some utilities do all three. Some do one or two. And some do none! (I’ll get back to this.)

And utilities have many different types of owners. Investor-owned utilities (IOUs) are generally publicly traded companies. There are non-profit utility cooperatives (co-ops), and there are utilities owned by federal, state, municipal, and other government entities.

And these utilities have different market postures. There are “poles and wires” utilities (TDUs) that own transmission and distribution but never take ownership of the power they transmit. The utilities that do own power either get it by generating it or by buying it wholesale, and they sell it either on the wholesale market or to end customers (retail). You can imagine this as a 4x4 matrix, and there are utilities in every quadrant.

And every state has a mix of utility types, postures, and ownership types. A state’s mix reflects its geography and political history. Because the power grid has been around so long, it’s passed through and been changed by a succession of political orders. Because the power grid involves so much connected physical infrastructure, reforms typically build around rather than replace the old order. And because the power grid is primarily regulated at the local and state levels, different reform movements have penetrated to different degrees in different places.

This is what gives the grid its complexity. I’ll now try to cut down that complexity and get the lay of the land. Let’s start by comparing three states that represent the three market structure regimes: Florida, Tennessee, and Texas.

Florida represents the first era of utility regulation. The first utilities were owned by investors and/or municipalities. Today, 68% of the electricity consumed in Florida is generated by investor-owned utilities (IOUs) and 10% is generated by municipally-owned utilities (munis).

Most IOUs and munis were founded in the late 1800s and early 1900s. They have names like “[City] Power & Light” or “[city] Utility District”. Electric utilities were just one of many new industrial-era companies building linear infrastructure with monopolistic network properties. There were also railroads, telegraphs, and oil and gas pipelines. In the Progressive Era, states established commissions - with names like the “Public Utility Commission”, the “Public Service Commission”, or “Corporations Commission” - to regulate these industries as public utilities. Electric utilities were given geographic monopolies as vertically-integrated owners of generation, transmission, distribution, and retail marketing. Florida’s three IOUs still have retail and transmission monopolies.

In Florida, some large cities like Jacksonville, Gainesville, and Orlando generate most of the power that they consume, but dozens of cities produce no power and instead buy it wholesale, only managing the distribution system and the retail marketing. Munis typically buy their power from IOUs and IPPs. Florida is unique for having the Florida Municipal Power Agency, which generates power and sells it wholesale to member munis.

This graph shows the market posture of all the utilities in Florida. In the top right are IOUs and large munis that mostly generate their own power and sell directly to consumers. In the top left are the two major wholesale utilities. The Florida Municipal Power Authority is a muni that generates power and sells it wholesale to the smaller munis in the bottom right corner. These smaller utilities own distribution (and sometimes transmission) and sell the power directly to consumers, but don’t generate it themselves. And the Seminole Electric Cooperative is similar, but it sells to co-operative utilities (co-ops). These retail-only utilities might also buy power wholesale from IOUs and independent power producers (IPPs).

I haven’t explained co-operative utilities or IPPs yet. They’re not a major force in Florida, generating 4% and 18% of power, respectively. These forms of utilities came along later in history and penetrated Florida to a lesser extent than other states. To explain them, let’s move forward in time.

The next force that majorly shaped the electric power industry was the New Deal era. During the New Deal, the federal government got into the business of generating power (e.g. building the Hoover Dam) and of being an electric utility. That brings us to Tennessee.

In Tennessee, 85% of power is generated by the Tennessee Valley Authority (TVA), a federally owned utility created by Congress in 1933. The TVA sells all of its power wholesale to several dozen municipal and co-operative utilities that own distribution lines and sell power to end customers.

The federal government had a natural role to play in the early days of electric power because hydroelectric power was a popular generation technology and most rivers are managed by the federal government. At the same time electric power was taking off, rivers were being dammed for irrigation and flood control by the U.S. Bureau of Reclamation and U.S. Army Corps of Engineers. Adding hydroelectric power made perfect sense.

During the Great Depression, Congress appropriated unprecedented funding to public works in a series of economic relief acts. Dam and hydroelectric construction accelerated. At the same time, there was enormous backlash against IOUs as many retail investors had lost their savings in a massive mania in utility stocks. Among other reforms, the government became an active player by establishing four principal federally-owned utilities. The TVA is by far the largest.

Although power generation in Tennessee is highly concentrated, the retail sale of power is divided between 82 utilities. While TVA sells 87% of its power wholesale, it does have some retail contracts with large federal customers (e.g. national labs, military bases, etc.) and large industrial customers (e.g. aluminum smelters). The rest of retail sales are split between munis (57%) and co-ops (24%).

Co-operatives were also established during the New Deal to provide power in areas too rural for IOUs or munis. In the mid-1930s there were still massive stretches of territory with no electric power, especially in the South where Roosevelt’s support was strongest. This 1921 map scaling states by the proportion of the population with electricity service shows how limited electricity was to the industrial Midwest and Northeast.

So Congress passed the Rural Electrification Act in 1936 to give loans to establish electric cooperatives. Today there are 604 co-ops, with the highest concentration being in states with more rural areas.

There are basically two kinds of co-ops: distribution co-ops and generation & transmission co-ops. Distribution co-ops own distribution lines and sell power to end customers, but they generate no or very little power. They buy power exclusively from generation & transmission co-ops (G&Ts), which are like a wholesale version of a co-op. They don’t sell to end customers. They sell only to their distribution co-op members, and they own the transmission lines to reach them. G&Ts vary in how much they generate of the power they sell. In the bottom left corner there are G&Ts that don’t generate any power but instead act as a buyer pool and a trading desk for their members.

Where do they buy their power from? I suppose they could buy from anyone, but probably most commonly they buy from IPPs and on managed spot markets.

During the 1970s energy crisis, a number of energy reform laws were passed, including the Public Utility Regulatory Policies Act of 1978 (PURPA). PURPA created small exceptions to the utilities’ generation monopoly, allowing non-utility companies to own power plants and to sell their power to utilities under long-term agreements. Over time, the exceptions grew, but the IPP industry was limited by the fact that it faced a market of a small number of buyers who regarded them as competition.

During the Neoliberal era, the IPP opportunity expanded with the creation of Regional Transmission Operators (RTOs). An RTO is a regional grid that both ensures the physical stability of the system (e.g. that load and generation are balanced and that transmission lines aren’t overloaded) while managing a spot market for wholesale power and dispatching power plants in the RTO accordingly. Utilities in RTO territory would have to buy power from the wholesale market. Instead of negotiating long-term bilateral agreements with utilities, IPPs could now sell directly into the wholesale market.

RTOs were eventually established in most of the country and today they cover two thirds of electricity load. Some states not only required the utilities to participate but also required them to sell their power plants to IPPs, reducing them to “pole and wires” utilities (TDUs). And some states allowed for the creation of third-party power marketers who would buy power from the wholesale market and then sell it to end customers, without owning power plants of their own.

That brings us to Texas, the prime example of this competitive model for electricity market structure. In Texas, power generation is dominated by IPPs. In fact, this graph understates the role of IPPs at 87% of generation. Inside Texas’s RTO (ERCOT), the IOUs were turned into TDUs. The three IOUs on this graph are located in Texas but outside of ERCOT. The three remaining utilities engaged in non-negligible power generation are the LCRA (a state-level version of TVA), and two municipal utilities.

Texas is also a state with retail choice. The traditional investor-owned utilities no longer sell power either wholesale or retail. Co-ops and munis still exist, but the vast majority of power purchased in Texas is purchased from retail power marketers.

Nationally, retail competition hasn’t spread as far as deregulated wholesale markets. Electricity retail is regulated at the state level, and some states choose to participate in ISOs/RTOs while limiting retail competition. For example, Indiana participates in the MISO deregulated grid but has no competitive retail, with the minor exception of PPAs that large industrial customers might have with IPPs. While two thirds of load is generated on deregulated grids, only 20.5% ($67.6B) of retail sales were by competitive retailers.

A very large portion of competitive retails sales are in Texas. Retail competition is widespread in Texas because the state ended retail sales by IOUs, forcing their customers to switch to competitive retailers. Other states allowed IOUs to remain in the retail business, and most customers have stuck with IOUs due to simple inertia.

The entity that supplies your power tells you something about the history of its development. If you’re in the territory of an IOU, your city was probably prosperous around the turn of the twentieth century. You probably have a football team for the same reason. If you have a municipal utility, then your city was a city at the time but not a prosperous one. If you have a cooperative utility, then you’re living in a place that was still very rural in the 1930s. And if your power is generated by a a federally-owned utility, then there are probably lots of powerful rivers nearby.

General

1. List the name of every person directly elected by you to represent you in government (1 point each).
2. List every election in which you voted in the last eight years (1 point each).

Local government

1. Identify one capital investment being made by your city government that is currently under construction (extra point for identifying the largest investment under construction).
2. Identify whether your city has a strong mayor or a city manager system.
3. Name one quasi-independent authority or board in your city and what it controls.
4. Name the agency in your city most responsible for homelessness.

State government

1. Identify one bill that was passed in the most recent session of your state legislature.
2. Name as many state agencies or commissions as you can (no points for the first 5).
3. For each of those state agencies, state whether it is a single-executive agency or a board-governed agency.
4. For each of those state agencies, state whether its leaders are elected or appointed (if appointed, state who appoints).

National government

1. Name someone who chairs a committee in either chamber of the U.S. Congress and what committee they chair.
2. For whichever industry you are most familiar with, name any federal agencies, laws, and Congressional committees that are relevant to it (legacy industries will be easiest).

Infrastructure

1. Identify the entity providing each service, and whether they are a private, local, state, federal, or other entity: electricity, water, gas, waste, bus, airport (1 point each).
2. Describe who owns and maintains local roads, state highways, and interstates.
3. Name the agency that approves major transportation projects.
4. Explain the source of your city’s water.

Generating heat (for space heating, water heating, and cooking) is overwhelmingly done with natural gas, and electricity overwhelmingly powers other tasks. Natural gas is better suited to heating than electricity because natural gas converts directly to heat when burned. Electricity is better suited to everything else because it’s a very precise and controllable (“high-grade”) form of energy.

High-grade energy is relatively expensive. While electricity accounts for 60.13% of energy consumption (on a Btu basis), it accounts for 84.25% of energy expenditures. It makes sense that electricity is more expensive than natural gas, considering that natural gas is (on average) a major input to producing electricity and there are losses in that process.

There are 96.423 billion square feet of commercial building floorspace in the US, across 5,918,000 buildings. That works out to a median annual energy consumption of 45,000 Btu per square foot (an amount of energy equivalent to 37% of a gallon of gasoline) and an expenditure of $1.46 per square foot.

The energy intensity (energy consumed per square foot) of a building depends on its purpose. Most building purposes have similar energy intensities, reflecting lighting and HVAC load. Buildings with higher energy intensities have a higher density of “other stuff” - refrigerators, cooking, equipment, etc.

We can confirm this by looking at how much each end use contributes to the fuel intensity of each building type. Cooking, refrigeration, computing, and miscellaneous plug loads set the highly energy intensive building activities apart. (There’s also a surprising amount of difference in HVAC intensity between building types. Inpatient hospitals use 105,000 Btu while hotels use 34,600 Btu per square foot.)

Of course, building types differ significantly in their number and square footage. Here’s the aggregate energy consumption of the different building types. Education, one of the least energy intensive building types, is one of the largest energy consumers because there are so many buildings of this type and they are very large.

This next graph shows the effect that building count and floorspace has on energy usage. Building types to the right of the line have disproportionately high square footage per establishment, and building types to the left have low square footage per establishment.

Inpatient hospitals stand out for having a very high square footage per establishment (second only to Enclosed Malls) and also a high electricity intensity due to unusually high plug load. These factors combine to make Inpatient hospitals the highest energy consumers per establishment by far (4.8 MMBtu versus 3.5 MMBtu for Enclosed Malls).

Instead of looking at consumption of all energies (in TBtu), let’s start to focus on spending on electricity (in $). This next graph teases apart the impact of floorspace on electricity spending.

Building types to the right of the line have disproportionately high aggregate spending for their aggregate square footage. Unsurprisingly, these building types have high spending intensity.

The 5 most electricity-intensive building activities are, in order: Fast Food, Grocery Store, Convenience Store, Restaurant, and Refrigerated Warehouse. All but the last one are Food Service / Food Sales. That’s no surprise. We see below that the electricity intensity of Food Service and Food Sales is mostly due to cooking and refrigeration loads.

The “Other” category’s electricity intensity includes significant computing load, which leads me to believe that light data centers are included in this survey under “Other”. The other building activities with significant computing load are Inpatient and Outpatient health care establishments and Office buildings, three building types that frequently have on-premises computing.

As is tradition on this blog, let’s now do a big 3D scatterplot.

A few takeaways:

• Very high spending per building for Enclosed Malls ($712k), Inpatient hospitals ($621k), Refrigerated Warehouses ($356k), and Laboratories ($211k) due to buildings of these types having both high electricity use per square foot and high square footage per building.
• Other building types have very similar spending per establishment because although they vary in square footage per establishment, they have a similar electricity intensity per square foot.
• Building types with the highest aggregate spending are Admin./Pro. Office ($13.1B), Strip Shopping Center ($9.0B), Retail Store ($5.8B), Inpatient hospital ($5.6B), and Mixed-use Office ($5.2B) due to high total floorspace.

Now that we have our heads around where electricity consumption is coming from and going towards, let’s figure out who’s paying the bill. That’s important because owner-occupied structures have a greater incentive to make energy efficiency investments, and government-owned structures may have special requirements to do so.

Education and public order establishment floorspace is overwhelmingly government-owned. Religious and Inpatient establishment floorspace is overwhelmingly owner-occupied. The other establishment types are a mix of owner- and tenant-occupied, with warehouse, office, and mercantile floorspace having a higher proportion of tenant-occupied floorspace.

Although Mercantile establishments are among the highest aggregate spenders on electricity, their low proportion of owner-occupied floorspace would seem to make them a relatively poor candidate for energy efficiency investments. Warehouse spaces have the most owner-occupied square footage, but their low electricity intensity makes them middling consumers in aggregate. The high proportion of owner-occupied Inpatient floorspace makes that establishment type a great candidate considering its overall high consumption.

It’s not worth visualizing, but the survey data indicates that in government and owner-occupied structures, the owner is almost always responsible for managing the structure’s energy systems. For tenant-occupied structures, 53% of floorspace has its energy system managed by the owner.

Finally, let’s look at how many buildings have on-site generation.

Unsurprisingly, the most safety-critical building types - public order (e.g. police and fire stations) and inpatient hospitals - are most likely to have backup diesel generation.

Building types with a high proportion of diesel backup aren’t much more likely to have a higher proportion of solar. That’s because the two on-site generation technologies achieve different goals. Diesel generation is used as a backup when grid power goes out, whereas solar panels are used to lower the cost and carbon emissions of the building’s electricity use.

When this survey was taken in 2018, only 1.6% of all buildings had solar panels, and the only building types with solar panels were Public Assembly (3.3%), Education (3.2%), Mercantile (1.9%), and Office (1.8%). Warehouses, which have lots of roof space, had no solar panels in the survey. This shows how rapid the buildout of rooftop solar has been, as a cursory look at Google Maps shows many distribution facilities in my area with solar panels today.

But ownership type predicts solar penetration better than building type in this survey. While 1.2% of all non-governmental buildings had solar panels and 0% of state or local buildings did, 3.6% of local buildings had solar panels.

Retail electricity rates are rising

That can be seen clearly in this monthly graph of the national average electricity rate:

The dataset ranges from November 1978 to present, and over that whole period the compound annual growth rate (CAGR) has been 3.09% (growing 313.04% in total). Since Jan 2020, the CAGR has been more than twice that at 6.66% - a figure with ominous portends.

This post-2020 price growth has a few distinct periods. In the year 2022, prices spiked 14.29% (for a CAGR of 14.29%, of course) because natural gas prices spiked after Russia invaded Ukraine in February 2022. Natural gas prices returned to their original level in May 2023.

The periods before and after the 2022 spike, 2020-2022 and 2023-2025, had growth rates somewhat higher than the historical average at 4.75% and 3.22% CAGR respectively. But so far in 2025 electricity prices are spiking harder than they did in 2022, with a CAGR of 15.39% so far this year (as of June).

And electricity rates will probably continue to rise. Many of the rate increases that have begun in 2025 include additional increases to be phased in over future years, and other utilities are considering their own new rate increases.

Why rates rise

Before discussing the drivers of electricity rate increases today, let me briefly explain how utility rates work and give historical context on past periods of rising rates.

There are multiple components that go into the final $/kWh rate. There’s a regulatory charge, which pays for the transmission and distribution (T&D). It’s the “regulatory” charge because it’s set by the state regulator, who approves T&D expenses and charges a rate that will allow the T&D Utility (a.k.a TDU) to recoup that expense plus a profit.

Then there’s the rate which pays for producing the electricity and other utility expenses. Typically there’s a flat $/kWh rate, or tiered rates that increase as your usage increases, or time-of-use rates that have different rates at different times of the day. Some utilities (typically co-op or municipal-owned) pass through their fuel costs. These charges add up to one $/kWh rate that the customer is charged for their usage.

Retail rates rise when utility costs increase. These cost increases could come from operating expenses (e.g. rising natural gas or wholesale power prices) or capital expenses (e.g. building new power plants or T&D). Capital expenses come from routine replacements of aged equipment, expanding the system to connect new customers, and construction of new generation to serve increasing load. Economy-wide inflation impacts both O&M and capital expenses.

History of electricity rates

Prior to the current one, there have been four periods in U.S. history when electricity rates rose faster than inflation: the early 1970s, the early 1980s, the mid 2000s.

This chart compares the year-over-year percent change in overall CPI and electricity CPI. Positive values are years where the cost of electricity grew faster than overall prices.

For a more cumulative perspective, this graph plots the ratio of electricity CPI to overall CPI. When the line rises, electricity is getting more expensive relative to overall prices.

In the 1970s, under-investment in oil exploration resulted in recurring shortages caused by overseas supply disruptions. This deeply shocked American leaders and the public, and it had sweeping consequences for American energy policy. The stark reality of the energy limits to growth shaped the psychology of the nascent environmental movement. The utility industry was partially deregulated, with independent companies now allowed to build power plants and sell power to the regulated utilities.

To hedge against rising fossil fuel prices, utilities invested in nuclear power projects that experienced extreme delays and cost overruns. All nuclear plants permitted after 1973 were ultimately canceled in the face of the inflation, high interest rates, deteriorating utility finances, and slowing economic growth and therefore power demand brought by the energy crisis. The cost of these expensive projects resulted in another period of electricity rate increases in the early 1980s, which began to look absurd against a backdrop of an oil glut and easing inflation. This was a significant contributing factor to the eventual total deregulation of wholesale power production in the 1992 Energy Policies Act.

Finally, there was a period of rising electricity prices in the early 2000s caused by an oil price shock. Unlike previous shocks, there was no supply disruption. Instead, the rapid growth of China - who went from being a net exporter of oil in 1992 to the third largest importer in 2007, with most of that consumption growth coming in the 2000s - significantly increased worldwide demand. But for whatever reason, production couldn’t rise to meet the demand and prices rose considerably. These fuel price increases were reflected in electricity rates in the 2000s.

The 2008 financial crisis collapsed fuel prices and, along with investments like energy efficient lightbulbs, depressed electricity demand until 2020. That brings us to today.

Today’s drivers of rate increases

Looking at actual spending in recent years, a few things stand out to me.

The spike in O&M expenses for power production in 2022 is clearly due to the spike in natural gas prices as a result of the war in Ukraine. These expenses fall in 2023 and are now back to $3.02/MMBtu as of June 2025. Natural gas prices don’t explain the continued rise of electricity prices in 2025.

The two categories with the most consistent growth are transmission and distribution capital expenses. These expenses are caused by the replacement of aged equipment and by system expansion as new customers are connected.

Although my perception is that there’s been increased interest in ‘smart grid’ and distribution resiliency investments in recent years, I think that the amount of distribution investment is largely the same but growing on a dollar basis due to inflation.

There’s no one data series that tracks the costs faced by utilities, but one highly indicative one is the PPI for electrical equipment manufacturing.

While overall CPI has grown at a compound annual growth rate of 4.06% since 2020, the producer price index for electrical equipment manufacturing has grown 8.26%.

There will also be increases in the rate of transmission investments in coming years. In Texas, $48 billion in transmission projects have been approved for construction that aren’t yet reflected in retail rates. While Texas may be an extreme case because of the amount of grid investments occurring there, it indicates a nationwide pattern.

There is likely to be increased need for transmission across the country in the coming years as both new generation and new loads are likely to be in more remote areas.

The vast majority of new generation resources are expected to be renewables, which tend to be sited in remote areas because they require large swaths of land and because the windiest and sunniest parts of the county happen to be in less populated areas. Since those areas tend to have less grid infrastructure built out, there is a continuing need for building new transmission.

On the load side, the large new data centers loads being interconnected require transmission investments also. While these loads tend to choose to site near existing power infrastructure, they could theoretically be built anywhere. This would break the historical pattern of load building near other existing load, and it would necessitate further transmission investments.

It’s important to understand that unlike power generation, transmission and distribution services are still fully regulated and their costs are still socialized across the system. Regulators approve projects based on forecasts for future loads, and whether or not their forecasts are correct, the public pays. This is the “regulated” charge on your bill. The share of this regulated charge on customer bills has increased since the start of electricity deregulation in Texas.

In the above chart of actual utility spending, there isn’t an increased in capital expenses for power plants. But that’s because the chart stops in 2023. After almost 20 years of almost no load growth on the grid in the U.S., electricity usage has started to increase and is projected to increase significantly. This will necessitate investments in new capacity.

The cost of those capacity investments has likely increased much faster than inflation. Utilities around the country and the world are now looking to invest in gas-fired generation resources at the same time. The demand to build far exceeds the capacity of manufacturers to make turbines. The result is increased lead time and prices.

So far, turbine producers have been cautious to increase turbine production capacity. Power generation development is a boom and bust industry, and the manufacture of inputs to that industry is even moreso. This is the subject of a famous Michael Porter HBS case study “General Electric vs. Westinghouse in Large Turbine Generators”. A similar bust occurred in the early 2000s. Turbine makers are therefore reluctant to invest in production capacity that may go underutilized in another bust.

Of course if these capacity investments are not made, electricity prices will still increase. Instead of increasing to pay off capital costs, electricity rates will increase to reflect the higher average wholesale power prices that will result from more frequent scarcity conditions if generation capacity is inadequate to meet growing load. Wholesale prices reflect not just fuel prices but also the frequency of shortages, and retail prices eventually reflect wholesale prices.

So far, wholesale power prices are not rising. The average wholesale power price was down from 2023 to 2024 at most trading hubs. But wholesale prices are volatile. An unusually hot 2023 and unusually mild 2024 could be masking structural changes in power markets. There are plenty of indications that scarcity conditions will be more frequent in coming years.

ERCOT’s regular report assessing system resource adequacy shows decreasing operating margins, with shortages occurring in 2028 and then becoming more frequent. PJM’s capacity auction cleared at record highs in 2024 and 2025, essentially sending a very strong signal that more capacity is needed to avert shortages.

Electricity rates have risen so far this decade in response to a natural gas price shock and inflation of electrical equipment prices. But as load continues to grow for the first time in almost 20 years, there is a need for additional generation investments even as manufacturing limitations promise to continue driving the cost of those investments.

Possible implications of rate increases

Every period of rising electricity rates has triggered a policy response. Electricity rates are politically sensitive because they can seriously pinch the budgets of people with low incomes and because they are a material cost driver for politically influential industrial and manufacturing firms.

One risk is that generation capacity will be overbuilt. Most of the load growth projections are highly uncertain as they depend on the capital plans of a small number of tech firms. It is easy to imagine an economic shock that causes those firms to pull back their capital plans, putting power producers in a distressed position.

If this were to happen, I can’t imagine that there would be political fallout in deregulated areas as it was only private money that was risked. Many independent power producers would go bankrupt and wholesale power prices would be depressed. This would have the effect of lowering retail electricity rates. It would be comparable to the boom in telecom investments after telecom deregulation in 1996, in which a lot of useful infrastructure was put down but many investors lost money.

But in regulated territories without wholesale markets, I could see those utility monopolies coming under significant scrutiny. Unlike in regulated areas where electricity rates would come down, regulated areas would see rates rise to pay off the construction of power plants that would sit largely unused. That disparity would be hard to ignore, and it could be a catalyst not just for the deregulation of wholesale power generation but also electricity retailing.

There could also be increased scrutiny of transmission monopolies. As transmission and distribution costs make up larger and larger portions of customer bills, very pro-competition states like Texas might become interested in alternative cost allocation mechanisms.

Finally, when rates rise there is always a renewed focus on efficiency. But since user energy efficiency is near its maximum potential (i.e. everyone has the efficient lightbulb and EnergyStar appliance), I think there will be more interest in deferring capacity investments by incentivizing demand response a load peaks.

This chart compares the year-over-year percent change in overall CPI and electricity CPI. Positive values are years where the cost of electricity grew faster than overall prices.

For a more cumulative perspective, this graph plots the ratio of electricity CPI to overall CPI. When the line rises, electricity is getting more expensive relative to overall prices.

The early 1970s

For the entire history of the electric power industry, power prices were getting cheaper year after year. In 1892, the average residential electricity customer paid $4.53/kWh (in 1996 dollars), but this fell quickly to $0.62/kWh in 1927, $0.47/kWh in 1937, $0.22/kWh in 1947, and finally $0.09/kWh in 1969.

These savings were first driven by network effects. As more customers joined the grid (or as neighboring grids were interconnected) the utilization of power plants increased, amortizing the fixed cost of those assets over more users, allowing for price reductions. Additional savings were found in economies of scale of power plants. As the capacity of plants increased, their marginal cost of production decreased, lowering utilities’ costs.

By the late 1960s, these tailwinds had slowed. The impact of network effects tapered off as the industry entered post-war maturity, and by coincidence power plant designers were approaching fundamental limits in turbine efficiency at around the same time. But the most significant factor by far that contributed to the rise in electricity prices in the 1970s was the oil shock.

In the 1950s and 1960s, it seemed that the easily accessible oil had been drilled, and exploration for new oil had turned to increasingly more costly and environmentally sensitive areas, like Alaskan wilderness or off the Pacific and Gulf Coasts. And fuel demand boomed along with postwar American consumerism. But the federal agencies that had largely set fuel prices since the New Deal failed to increase prices to reflect these pressures. The result was under-investment. In 1956, the number of exploratory wells dug peaked. And in 1968 oil exploration had fallen to such a low level that more oil was consumed than new oil (in reserves) was discovered. Inventory drawdown had begun.

For the first time since the hydrocarbon revolution had brought about the modern world, an expiration date for that modern world was now in view - the date when the last reserves would be depleted. American leaders were chastened. Around that time, three highly influential books were published that meditated on the theme of resource scarcity: “The Population Bomb” (1968), “The Limits to Growth” (1972), and “A Time to Choose: America’s Energy Future” (1974).

Under-production was made up for with imports. Net oil imports doubled from 1970 to 1973 to make up 36% of total U.S. consumption. But in 1973, OPEC countries cut off their oil exports to the United States in response to our support for Israel in the Yom Kippur War. This quickly resulted in widespread shortages of fuel in the U.S.

The oil shock is one of the most significant events in American economic history. It was widely compared to Pearl Harbor, at a time when Pearl Harbor was not a distant memory. People were killed in fights that broke out in the long lines at gas stations. Truckers went on strike, shutting down interstates with their trucks. And to enforce that strike, some of them attacked non-striking trucks, including by shooting rifles at them from overpasses. Riots broke out in Levittown, the car-dependent “icon of postwar suburbia”, in which 169 people were arrested. Shortages, and unrest, continued off-and-on throughout the 1970s. (And to save you a Google search - yes, the first Mad Max film was released in 1978.)

The most significant consequence of the 1970s energy crisis was that it shattered confidence among American leaders in the New Deal regime of price controls. They turned instead to Neoliberalism. President Carter largely removed fuel price controls and deregulated fuel-dependent industries like airlines and trucking. The New Deal coalition, which had been strained on its right by the Civil Rights movement and on its left by Vietnam, fell apart.

For our purposes, the most significant impacts of the crisis were rising electricity rates, partial utility de-regulation, the mainstreaming of energy conservation, and shifts in power plant investment.

Despite the controls, natural gas prices increased through the 1970s and as a result so did electricity rates. From 1969 to 1979, the average residential electricity rate had doubled from $0.021/kWh to $0.044/kWh (unadjusted). The electricity CPI measure doubled over that period also. This was the first period when electricity prices ever rose significantly.

Implications for utility regulation

One policy response to the energy crisis was the Public Utility Regulatory Policies Act of 1978. It aimed to promote energy efficiency and non-traditional power generation technologies. But its most lasting impact was to partially deregulate the utilities industries by allowing independent companies to build certain kinds of fuel-efficient power generation resources - biomass, waste, renewable, and co-generation - in the territory of regulated utilities. Regulated utilities were required to buy the power that those facilities.

PURPA opened to door to full deregulation by discrediting the assumption that power generation was a natural monopoly. It showed that independent companies could be cost-competitive with regulated utilities, and it created a framework for them to interconnect their own resources to the grid.

The 1970s also brought energy conservation into the mainstream. Previously, U.S. energy leaders had felt that more electricity usage was always good because increasing utilization of fixed cost power generation assets could lower costs. But now that there was a shortage of fuel, there was no choice but to encourage energy conservation.

Beginning in the early 1970s, Americans were told for the first time to turn down their thermostats, to use less hot water, and to turn off the lights before leaving the house. The utilities established conservation departments and distributed booklets encouraging household energy conservation measures.

Following several state laws, a maximum speed limit of 55mph was set nationwide in 1974 and not raised until 1987. Nixon requested gas stations to close on Sundays to discourage weekend roadtrips, and several states enforced this by law. Cars got smaller. Carpooling was patriotic, and Christmas lights were not. To show their sensitivity to the energy crisis, the Daytona 500 shortened their race to 450 miles in 1974.

The early 1980s

The rate increases of the 1980s were different from the increases of the 1970s. In the 1970s, rates were driven by soaring fuel prices resulting from fuel supply constraints. In the 1980s, rates were driven by huge capital investments that largely didn’t pan out. These investments were began in the 1970s, in response to the fuel crisis.

Facing an indefinite period of oil and gas shortages, a number of energy alternatives received government support in the 1970s. Renewable power and synthetic fuels first received government support during this period, but only as speculative basic R&D projects. Energy efficiency and conservation was also a major project, as we’ve discussed, but it would only go so far.

If electricity usage was to continue growing in the 1970s and 1980s as it had in the 1960s, which was what everyone expected, new power generation capacity needed to be built. And in the 1970s, the only viable power generation technologies that didn’t require oil or gas were coal and uranium.

Coal had been losing share of generation since the mid 1950s, and thousands of mines had been closed, in large part because of growing public concern about air quality causing utilities to shift towards cleaner-burning oil-fueled power generation. But after the oil shock, utilities switch their focus back to coal.

Although coal was the workhorse from the 1970s, the 1970s were nuclear’s time to shine.

Utilities hadn’t show much interest in nuclear power since it was made available to industry in 1954, preferring to stick with tried-and-true gas- and coal-fired technologies as those fuels were still inexpensive. The few plants built in the 1950s and early 1960s were expensive demonstration projects that relied on significant government support. The next batch of nuclear starts came in the mid 1960s when the two nuclear manufacturers, General Electric and Westinghouse, built plants at significant losses to stimulate utilities’ interest.

Nuclear orders exploded in the late 1960s. Over the preceding 10 years, utilities had gained nuclear operating experience and costs were approaching a range where they were comparable to coal. Electricity consumption was growing at an enormous pace, but by the late 1960s the oil and gas supply picture had begun to sour and the environmental movement was starting. As previously mentioned, coal capacity had been declining due to the nascent environmental movement. Nuclear was seen as a potential resource of the future that could meet baseload requirements while hedging fossil fuel costs while providing clean air benefits. Almost all nuclear capacity ever built were those projects planned from 1965 to 1973.

The nuclear bust

When the energy crisis began in 1973, there was a second wave of nuclear orders as Presidents Nixon, Ford, then Carter made nuclear a cornerstone of their energy strategies. But these nuclear projects were financial disasters. Not one of the 41 reactors ordered after 1973 was built.

The energy crisis brought high inflation and borrowing costs, while slowing economic growth and with it projections of future power demand. Meanwhile utilities faced deteriorating financial conditions as their fuel costs increased. Nuclear orders dropped abruptly from 1974 to 1975 with the nuclear trade magazine Nucleonics Week writing in January 1975 that utilities had “no idea how to finance nuclear plants.”

Over the following 10 years, construction timelines increased as accidents at operating plants revealed problems requiring redesigns and retrofits. With the most creditworthy utilities paying 17.5% on their bonds, these delays were extremely expensive. A Department of Energy study in 1984 found that 77% of operating nuclear plants had cost overruns of 100% or more.

And many, many plants were never finished. Environmental groups, which had been neutral on nuclear, come out against it in the mid 1970s, with the Sierra Club first taking that position in 1974. The Three Mile Island accident in 1979 required a new round of redesigns and retrofit. Perhaps more significant to the economics of nuclear, fuel prices began to decline in 1980 and in 1981 the Power Plant and Industrial Fuel Use Act of 1978 was repealed, end a ban on new gas-fired power plants. The TVA abandoned $4 billion of investments in planned nuclear plants in 1984.

Any normal company would have been bankrupted by the delays, cost overruns, or writeoffs that the utilities faced as a result of their bad nuclear investments. But power utilities were regulated monopolies. They could always pass the cost of these failed investments on to the public. And they did. As nuclear costs began to be reflected in electricity rates, prices continued to grow, even against a backdrop of easing inflation and easing fuel prices.

(However utilities are not immune to liquidity shortfalls, and some experienced severe financial destress when they were slow to get rate increases. In 1983, the Washington Public Power Supply System defaulted on $2.25 billion of bonds. PSNH, the largest power utility in New Hampshire, went bankrupt in 1988 - the first utility bankruptcy since the late Depression years.)

Although these price increases were extremely unpopular, they were absorbed by the public over time. By the mid 1980s price began to fall relative to inflation as fuel prices remained low until the 2000s. The next significant change in utility regulation was the Energy Policies Act of 1992, which significantly expanded competition in wholesale power generation and allowed states to begin retail electricity competition.

The mid 2000s

The next rise in electricity prices came during a general inflationary episode from 2005 to 2009, in which energy prices rose faster than overall inflation. A 2006 Brattle report found that increased fuel costs accounted for ~95% of cost increases (and therefore rate increases) in the preceding 5 years.

The prime mover of this period of rising rates was likely a sudden rise in oil prices. Oil prices had been growing steadily in the early 2000s after ~25 years of stability. Then from August 2007 to June 2008, the price of oil jumped suddenly by ~60%.

This was one of the biggest oil shocks in history. But it’s unique for being the only oil shock that didn’t involve a disruption in supply. Instead, what occurred was a failure of production to increase to meet growing demand.

China had been experiencing significant growth on a percentile basis for many years, but in the early 2000s they’d grown large enough to be globally significant. From 1992 to 2007, China went from being a net exporter to being the world’s third largest oil importer, with most of that growth happening in the early 2000s. Because of demand from China, global oil demand grew significantly in the early 2000s.

But for some reason, production didn’t increase to meet this demand and keep prices stable. Production had been declining at major oil fields in the U.S., the North Sea, etc. The Saudis had been the swing producer keeping prices stable, but for whatever reason they didn’t in the early 2000s. The result was rising prices.

Because all fossil fuels are substitutes for each other to varying degrees, the oil shock was reflected in the price of coal and natural gas. These increased fuel prices came to be reflected in electricity rates in the mid to late 2000s.

Although it was a major shock in terms of price, it didn’t have the political and cultural impact of the 1970s shock because there were no shortages. The long lines at gas stations were what made the 1970s oil shocks so toxic, and because the 2005-2008 shock occurred in a price de-control regime, there were no shortages. Still, there was a political response in the form of the Energy Policy Act of 2005, which promoted energy efficiency measures and alternative power generation technologies.

The 2008 financial crisis brought a severe pullback of economic activity that collapsed fuel prices and depressed electricity load growth. Electricity rates entered a period of over 10 years of declines relative to overall inflation on average. And due to slow economic growth and energy efficiency investments, electricity load remained almost completely flat from 2005 to 2020.

2022 - present In 2022, electricity rates began to rise again. That is discussed in another post.