How Do Utilities Make Money? [Electric & Gas]

Investor-owned utilities in electricity and gas are some of the most heavily regulated companies in the United States. This means the way they make money is dependent on policy set by regulating bodies like state legislatures and public utility commissions, and also federal agencies like the Federal Energy Regulatory Commission.

These government bodies dictate how much a utility may earn, the reason being they want to ensure utility customers, (i.e. you and me), aren't charged exorbitant prices and utilities operate in the public interest. Understanding how regulated utilities earn money means we are more informed about what goes into our utility bills each month and how innovations translate to cleaner energy, reliable power, and lower costs.

Business Models: Utilities Make Money By Investing in Tangible Assets

Utilities are unique from typical businesses in the way they make money and the model they use to earn profits. Traditional businesses determine the price they charge based on several factors. While input costs like material and labor drive a lot of their break-even analysis, they also balance their price against other businesses with similar goods, ensuring they don't over charge and dissuade customers from buying their product. This last piece is what makes utilities unique.

Utilities traditionally don't have competitors. Instead, most utilities have a geographic monopoly with captive customers overseen by state public utility commissions to deliver electricity. This risks monopoly pricing, meaning that utilities can charge whatever they want. Regulators are aware of this issue and prevent utilities from charging too much. This manifests through regulating the utility's revenues based on the total cost of the business assets used to generate and deliver electricity. Therefore, companies are incentivized to invest in tangible assets like power plants, solar farms, transmission lines, distribution infrastructure, and other assets under the utility business model. The total value of these assets, in its simplest form, is called the company's Rate Base.

What is Rate Base?

Rate Base is the value of utility assets minus the accumulated depreciation of those assets. The assets a utility may include in the rate base depends on the applicable utility regulator’s definition of rate base. Accumulated depreciation is subtracted from Rate Base because it represents the value of  wear and tear on these assets, detracting their total value and “usefulness” before needing to be replaced.

A utility then negotiates with a regulator and stakeholders via a "rate case" to determine what allowed return on Rate Base they may earn. Based on this agreement, a utility establishes its "revenue requirement". This represents the total amount of revenue a utility needs to earn to cover agreed upon costs, including a fair rate of return on their investments in order to earn reasonable profit. Utilities will file rate cases, generally every few years, to determine their revenue requirement before a public utility commission.

The regulator decides the utility's revenue requirement and bases it on a number of factors, such as the value of a utility's assets, the cost of capital (including debt and equity), operating and maintenance costs (O&M), plus administrative costs.

A basic formula to follow for understanding the revenue requirement and how it relates to rate base is as follows:

Total Revenue Requirement = Rate Base * Authorized Rate of Return on Rate Base + Expenses.

The authorized rate of return on rate base is the weighted average cost of capital, or WACC. This includes the blended return on debt and the cost of equity capital, or authorized return on equity (ROE). Regulators use market benchmarks to determine appropriate ROE measures, meaning the best way to increase a utility's earnings comes from growing rate base.

What Are Some Investments Utilities Make to Grow Rate Base?

Power Plants (aka Generation)

The most basic way to grow rate base is to increase the number of power plants, or update older plants so that the plant becomes more valuable. Power plants are capital-intensive projects that require years to plan, approve, and build.

This section includes "generation" in the title because power plants, in the traditional sense, are not the only generation assets. Solar and wind farms are becoming popular alternatives for utilities to build as the world increasingly focuses on curbing greenhouse gas emissions. While nuclear plants have the best record for reliability in providing power and are less polluting, they are expensive to build and take years to go from conception-to-operation.

Assets like solar and wind farms are cheaper to build and maintain, and quicker to get operational. However, their generation output tends to be lower. Choosing whether to build a renewable or non-renewable asset must take into account factors like projected demand by the time a plant is operational, cost factors, generation factors, and regulations and incentives from state and federal regulators that make non-renewable assets more expensive or renewable assets cheaper.

Transmission and Distribution Infrastructure

Transmission and Distribution infrastructure (T&D) is another way utilities can grow their rate base, and in some cases, may be their only way. There are numerous transmission-only electric utilities whose method of making money is earning a rate of return from the value of their transmission infrastructure.

Recent changes by the FERC and the Department of Energy are pushing companies to invest more in large voltage transmission with the expectation of increasing the size of the country's transmission infrastructure by 60% by 2030, and even triple it by 2050. This provides a key opportunity for electric utilities to increase their rate base by investing in transmission infrastructure with large support from the private and public sector.

Distribution is also prioritized as the United States focuses on improving our electric grid. Spending on distribution systems has been on an upward trend for the past 20 years and continues to rise.

According to the Energy Information Administration, utilities spent a combined $57.4 billion on electric distribution, a 6% increase from 2018 and a 64% increase from 2000 when adjusted for inflation. Half of that number went to capital investments for new or improved infrastructure. This will only increase further as state regulators encourage development of distributed energy resources (discussed below) that require robust distribution infrastructure.

Energy Efficiency and Demand-Side Management Programs

Energy Efficiency Programs (EEPs) are incentives from utilities to customers to prioritize consumption on off-peak hours or even decrease the overall amount of energy they consume. It may seem counterintuitive that utilities would encourage this behavior given that they charge for energy consumed, but there are several reasons a utility would use a model like this.

Electricity is what is called a "rivalrous" good in economics, meaning only one person can consume a unit of electricity and there is a finite supply of electricity throughout the day. If all customers wanted to consume a lot of electricity at a single hour in the day (also called peak-hours, or peak demand), a utility can struggle to ensure it has enough to go around, resulting in a power outage. This is where Energy Efficiency and Demand-Side Management Programs come in.

Utilities may offer incentives like lower rates during off-peak hours so customers prioritize their consumption away from peak hours. This improves reliability of service from the utility. Implementing energy efficiency programs are usually faster and easier than building a new power plant, so utilities can encourage customers to decrease their overall use to better improve reliable delivery for all customers. Many utilities offer these programs themselves or state regulators may require them.

Distributed Energy Resources (DERs)

Also called distributed generation, DERs are technologies that individuals or businesses use to generate their own electricity or plug into a microgrid, potentially selling their excess electricity to the utility responsible for transmission and distribution.

DERs are most commonly seen as rooftop solar, small wind turbines, or can even be biomass or waste incineration plants for industrial sites or small cities. This is becoming more popular as technologies become cheaper and easier to install.

At the same time, this changes the calculus utilities make in deciding how much power to generate from their own plants. Vertically-integrated utilities (utilities that control generation, transmission, and distribution) may increasingly spend money on distribution infrastructure to accommodate micro-grids and DERs, buying electricity from small-time generators, and relying less on wholesale markets or their own generation assets.

Less investment in generation assets means that metrics like rate base will increasingly rely on transmission and distribution assets under the "cost-of-service" model. State utility regulators are supporting many of these initiatives along with policy updating the "cost-of-service" model to more accurately reflect modern needs and innovations.

How Do Utilities Bill Customers?

Regulated utilities are permitted to earn a certain rate of return on their capital investment as defined in their revenue requirement. However, the utility ultimately makes money by charging consumers for their electricity.

Called electric rates, these are the per kilowatt-hour or per kilowatt charges utilities put on consumers depending on their consumption level and customer class. This is split between residential, commercial, and industrial customer classes where rates are grouped together in rate tariffs or schedules.

Utilities also offer incentives for customers to prioritize electricity consumption on off-peak hours through Time-of-Use or Interruptible tariffs.

Are There New Utility Business Models?

As technology continues to innovate the electric industry, new business models are being created to match and bring new ideas to what many see as an antiquated industry model. It's important to understand how some of these models work and the trend of the industry overall because it ultimately changes the investment and money-making incentives for utilities. These generally fall under two categories: deregulated/competitive markets, and cost-of-service reforms.

Competitive/Deregulated Electric Markets

Competitive (or "deregulated") electric markets are a free-market: retail electric providers (REPs) compete with each other to gain your business. This is not how most utilities operate. In reality, state regulators give a monopoly to utilities over a set service area while regulating how much that utility may charge for electricity to prevent the utility from abusing their monopoly status. This has been the traditional model for over 100 years, but is increasingly being challenged as new innovations break into the electric market and disrupt the norm.

Texas contains one example of a deregulated market where the generation and distribution of electricity became a competitive "free" market while the Electric Reliability Council of Texas continues to control all transmission and distribution services for a large area of the state. ERCOT is unconnected to other states, making it unique because it largely avoids Federal oversight where other competitive markets, like New England, do have Federal oversight. These markets are relative new comers to the industry, with claims that they improve the renewable footprint as evidenced in Texas, and less price volatility after deregulation in New England.

Innovations in the "Cost-of-Service" Model

There are numerous innovations that can benefit both utilities and consumers that still stay within the boundaries of the traditional Cost-of-Service model. This has been seen as a strong alternative to complete deregulation.

Revenue Decoupling

This focuses on breaking the tie between the amount of energy a utility delivers to customers and how much it receives in revenue. The idea is to prevent utilities from being incentivized to make more energy than necessary, hence keeping more in line with a utility's revenue being enough to cover costs and not much higher than that. Advocates of this method state that decoupling methods should be tied with policy incentives to improve energy efficiency at the same time, otherwise utilities may have little incentive to improve performance. However, studies show that revenue decoupling may lead to higher electric rates for consumers but only marginally while providing greater cost-saving measures for utilities and regulators.

Multi-year Rate Plans

Decreases the number of times a utility must engage in a rate case by using predicted expenditures rather than historical numbers, allowing for limited rate increases between rate cases without needing regulator permission. Also called MRPs, these rate plans are becoming more popular with regulators as it reduces the need for typical "general" rate cases that consume a lot of time and resources for both regulators and regulated utilities. They also provide cost-saving incentives for utilities and create predictable rate increases that both energy producers and consumers know are coming and can plan for.

Performance Incentive mechanisms

Regulators may create rewards and incentives for utilities meeting performance outcomes or to encourage certain behaviors. For example, utilities in California were offered tax incentives if they engaged with the California PUC in experimental DER programs that would impact a utility's expenditure on distribution infrastructure. These type of programs are additional factors in determining costs and revenues within a cost-of-service model.

Only Scratching the Surface

What we've discussed in this article only scratches the surface on fully understanding how an investor owned utility makes money. However, this article gives a short overview of the key decisions utilities make in interacting with regulators, customers, and how that informs their business models going into the future. These models will change as new technologies, innovations, and public policy come to market and impact the energy industry.