Understanding Utilities: The monopoly we are okay with, for now
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Last time, I did a deep dive into electricity trading and how electrons are bought and sold to ultimately ensure your lights turn on when you want them to. This week, I’m writing about electric utilities, which you are probably aware of but likely don’t give much thought, as long as your power works and your monthly electric bill isn’t absurdly high. There are three categories of utilities, all of which I will describe in further detail below, and all three are regulated monopolies, meaning they are granted the exclusive right to sell electricity in a specific geographic region (i.e. they are allowed to operate without competitors). In return for this regulated monopoly status, utilities must subject themselves to the regulators — the FERC at the federal level and PUCs at the municipal level — who determine how the utility is allowed to operate and, critically, how much the utility can charge for services.
Why are utilities granted monopoly status in the US when almost every other industry is closely monitored to protect consumers from emergent monopolies? This is because utilities provide an important public good, electricity, and providing this good reliably was historically much more straightforward and economically sensible with singular ownership and operation of generation and transmission + distribution. So governments decided that granting these entities legal monopoly status was worth it, and they hedged the risk of granting such power by mandating regulation and oversight of their operations.
Types of Utilities
There are three types of utilities serving customers today: investor-owned utilities (IOUs), public power utilities, and electric membership cooperatives (co-ops). Across these three, there is a range of different models of generation, transmission and distribution asset ownership. Vertically integrated utilities own generating assets, transmission + distribution (T&D) assets, and serve retail customers. Generation + transmission utilities own generation and transmission assets and sell to other utilities, who then sell to retail customers. Lastly, and most common, are distribution utilities, which own distribution only and buy power from other utilities or energy wholesalers and sells to retail customers. In regulated energy markets, vertically integrated utilities are allowed but not in deregulated energy markets.
Now for a deeper look at the three types of utilities: investor-owned, public power, and co-ops.
IOUs
IOUs are the most straightforward utility model to understand for people from a markets or economics background, like me. IOUs are for-profit businesses that are more often than not publicly-traded and owned by private shareholders (retail investors, pension funds, endowments, etc.) — they optimize for profits and returning earnings to shareholders. IOUs comprise about 10% of all utilities in the US but serve 65% of end customers, meaning they have massive market share compared to any public power utility or co-op. This makes sense, since IOUs are concentrated on the heavily populated coasts and urban centers across the country. Because IOUs are granted monopoly status and are profit-making, it is critical that they are subject to oversight, as they could easily take advantage of captive customers and engage in price gouging or other hostile tactics. This regulation is handled by the Public Utilities Commission (PUC) in the relevant geographical operating region.
Public Power Utilities
In contrast to IOUs, Public Power Utilities are strictly not-for-profit entities that are directly or indirectly run by government entities. Public power supplies 12% of total electricity customers in the US. Since public power utilities are operated by municipal or local governments, ownership of the entity lies with the taxpayers and locally elected officials or a set of individuals appointed by those elected officials take care of operations. This set-up means public power does not pay taxes and instead funnels its earnings to the local municipality’s general fund. And, because it’s run by government or government proxy and does not involve any sort of profit-seeking, there is almost no regulation by the PUC.
Co-ops
Rounding out the utility trifecta are co-ops. As a Berkeley alum, I am allowed to say that these co-ops remind me of the stereotypical Berkeley hippie’s ideal utility — not-for-profit, collectively owned and operated by community members, and serving smaller, rural communities underserved by traditional IOUs or public power utilities. Community members elect a board of directors which is responsible for operating the co-op and ensuring it reliably supplies power to the community. This is great alignment of incentives, in my mind, because those running the operation benefit directly / suffer depending on the co-op’s performance. However, I think this model would suffer dramatically in a more densely populated setting due to greater dispersion of social pressure that reduces a board’s desire to deliver for the community (it’s hard to care deeply about your neighbors in a city of millions of people). Co-ops do not pay taxes nor contribute customer payments to a general fund, since ownership sits with the co-op members rather than taxpayers at large, and any incidental profit gets returned to co-op members.
How utilities make money
The only utility that makes money, or takes a profit, is an IOU. Recall that public power and co-ops are not-for-profit, so none of the following will apply to them. IOUs operate in a cost-of-service model, which has a few rules associated with it. First, IOUs have to sell power without a markup to consumers. This alone leaves utilities with very poor incentives to build the infrastructure needed to deliver this power to customers. So, to make sure they build this infrastructure, the PUC agrees on a rate of return on the infrastructure that IOUs can realize, and this return is guaranteed so long as the infrastructure gets built and the investment is “prudent” (which is another standard determined by the PUC). The result of such a model is lots and lots and lots of utility infrastructure being built, which is great news in times that demand massive buildup of infrastructure to bring coverage to many places. It’s less great news when the grid doesn’t need more infrastructure, which I will touch on further below.
Time to get into the weeds of how this actually works. A utility’s revenue (revenue requirement) must cover the cost of supplying energy and building and maintaining the infrastructure needed to transport and deliver that energy to end customers — anything leftover is profit. This leftover piece is generally due to returns on investment in infrastructure, which is a function of returns on debt and returns on equity used to finance the infrastructure. Determining the revenue requirement for a utility is done by the PUC, and utilities are typically very interested in this process, as it spells out how much money the utilities are likely to make in a given year. This great presentation from the Regulatory Assistance Project lays out how this happens. First, the PUC determines a utility’s revenue requirement using the following framework:
Revenue Requirement = (Rate Base Investment × Rate of Return) + Operating Expenses,
where Rate Base Investment is all major capital expenditures (transmission lines, buildings, fleets of vehicles, compute power), Rate of Return is the return utilities make on their infrastructure investment, and Operating Expenses are recurring costs like power purchases, labor, and insurance. Breaking down these components even further:
- Rate Base Investment: this is the existing assets owned by the utility, and includes all generation, transmission, and distribution infrastructure net of depreciation, working capital, and regulatory assets.
- Rate of Return: this is a weighted average of the cost of debt and the cost of equity, where cost of debt is determined by interest rates and cost of equity is the return shareholders target in return for their financing of the utility. The rate of return typically sits below the rate of equity due to the drag of the lower cost of debt and is guaranteed so long as the investments in infrastructure align with the PUC’s definition of “prudent”.
Two things jump out from this set-up. One, the relationship between the PUC and the utility is certainly not a neutral one, and any information asymmetry between the two with respect to the true need for new infrastructure likely drives investment in assets that do not really adhere to the PUC’s definition of prudent.
Second, and related, because the rate of return is more or less fixed, the only lever utilities can pull to generate higher cash margins is to grow the rate base by investing in more infrastructure, perhaps above and beyond what is truly needed. That higher rate base investment drives more cash in the utility’s pocket when it gets multiplied by the fixed rate of return.
The over-building of infrastructure to drive up cash margins has been studied and is called the Averch-Johnson effect. While overbuilding is not economically efficient from a grid infrastructure perspective, there are upsides to the set rate of return that drives this phenomenon. Guaranteeing a return ensures utilities can get access to the capital they need to improve infrastructure to adequately serve all customers, which is an important reason they are granted monopoly status in the first place.
However, the cost-of-service model starts to make less sense in the world we now live, where we have plenty of T&D infrastructure. Beyond just cost and reliability of power, which the cost-of-service model accounts for, customers increasingly care about resilience and decarbonization of power sources. These two preferences are reached most effectively through non-infrastructure solutions like software and small-scale DERs, as well as non-utility third parties that connect DERs to each other in a micro-grid. As David Roberts summed it up in his Vox article on the subject,
“To put it more bluntly: utilities’ strong preference for capital investments puts them intrinsically at odds with smarter grids and privately owned DERs. Smarter grids and privately owned DERs have the effect of reducing demand for grid power and grid infrastructure — that’s good for customers, but it reduces utility shareholder profit.”
Challenges
That is a nice segue into challenges utilities will face in the future. As alluded to by the David Roberts piece, the current cost-of-service model is directly at odds with the deployment of DERs across the grid, since these resources negatively impact all components of the revenue requirement equation utilities care deeply about.
DERs reduce the need to pay utilities for electricity, reduce the amount of new infrastructure and infrastructure upgrades needed, and increase operating expenses. Thus utilities who want to stay in business under the current regulatory regime are actively dis-incentivized to invest in integrating DERs into their systems. In other words, utilities are choosing to ignore growing demand for resilience and decarbonization to preserve their business model and short-term profit potential.
Another challenge to the model is the throughput incentive and how it disincentives scaling up of energy efficiency programs and distributed generation. Assuming costs are 100% fixed, utilities can make more profit by selling more power, which means utilities are generally unfriendly to any initiative that would decrease customers’ consumption and thus the utility’s sales. Both energy efficiency programs and distributed generation do this. Energy efficiency programs get customers to perform the same activities but use less power doing so, and distributed generation shifts some of a customer’s base power demand from the utility to a distributed generation asset (like a heat pump or solar panel) owned by the customer. Again, these things are good for grid resilience and grid decarbonization, and again, the utility business model under the current regulatory regime is at odds with those objectives. Seems like a bad customer experience to me.
Conclusion
Proliferation of DERs will continue to grow in the coming years, creating an opportunity for the business model of utilities to reform and start to incorporate these elements into their business plans. Vibrant Clean Energy, an energy software company, developed a model called WIS:dom-P (deck linked here) which shows a range of scenarios under which DERs could be integrated into the grid to lower costs and increase reliability and resiliency of the grid. It’s a poor business decision to ignore the early signals of the value of DERs and distributed generation, and the WIS:dom-P model highlights just how valuable these assets will be to a future version of the grid. If utilities as they exist today want to see that future and profit from it, they would be wise to read the writing on the wall and adjust their profit function to more closely align incentives with decarbonization and resiliency.
Beyond utilities, there are other models that serve end retail customers reliably and cheaply while allowing for the integration of DERs. That is the retail energy provider (REP) model, and next time I am going to deep dive into the history of the model, how it works, and develop a thesis on how I think it will evolve across the US.
