How utilities make money comes down to one mechanism: a state regulator authorizes the utility to earn a set percentage return on the money it has invested in physical infrastructure like power lines, substations, and pipelines. Because these companies operate as monopolies with no market competition to set prices, the commission decides how much profit the utility can collect from customers. The average authorized return on equity in electric and gas rate cases has hovered near 9.7% in recent years, which translates into billions of dollars in annual earnings tied directly to the assets that deliver energy to homes and businesses.
The Authorized Return on Rate Base
When a utility builds a substation, installs a gas main, or upgrades a transmission line, it adds those costs to what regulators call the rate base. The state public utility commission then sets a percentage return the utility can earn on that rate base each year. If a utility has $1 billion of approved capital investment and the commission authorizes a 10% return on equity, the utility collects $100 million in annual profit through customer rates, on top of recovering its actual costs.
This framework traces to the 1944 Supreme Court decision in Federal Power Commission v. Hope Natural Gas Co., which held that rates must be sufficient to maintain the utility’s financial integrity and keep it attractive to investors who supply the capital for infrastructure projects.1Cornell Law Institute. Federal Power Commission v. Hope Natural Gas Co., 320 U.S. 591 Without a reasonable return, no private investor would fund a power plant that takes decades to pay back. With too generous a return, customers overpay for a service they cannot get anywhere else.
For investor-owned electric utilities, the average authorized return on equity was 9.75% in rate cases decided during the twelve months ending March 2025, with gas utilities averaging 9.73% over the same period. The figures have been remarkably stable, rarely straying far from a 9.5% to 10% corridor. The authorized return typically accounts for roughly 15 to 20 percent of a residential customer’s bill.
Why Building Infrastructure Is the Growth Strategy
A retailer grows by selling more products. A utility grows by spending more on physical infrastructure. Every new mile of gas pipeline, every upgraded transformer, and every solar installation adds to the rate base. The return percentage stays roughly constant, so the only way to meaningfully increase total profit is to increase the capital that percentage applies to. This is the fundamental incentive built into the regulated model, and it explains why these companies pursue large infrastructure projects so aggressively.
Not every dollar a utility spends qualifies for the rate base. Regulators apply a “used and useful” standard that excludes assets not actively serving customers. A half-built power plant or a mothballed facility generates no authorized return. State commissions run formal rate cases, typically lasting 8 to 15 months, where utility engineers, accountants, and economists file testimony justifying each investment. Commission staff audit every line item, review depreciation schedules, and challenge anything that looks excessive or premature.2Department of Public Service. Major Rate Case Process Overview
Critics of the model point to what they call capital expenditure bias: an incentive to favor building new infrastructure over cheaper alternatives like energy efficiency programs or third-party contracts, even when those alternatives would cost customers less. A utility that signs a contract for battery storage from another company has no rate base addition and earns no return on that spending. A utility that builds its own battery facility does.
Costs That Generate No Profit
Fuel, purchased power, and day-to-day operating expenses work completely differently from capital investments. The utility earns zero profit on these costs. When natural gas prices spike during a cold snap or wholesale electricity prices climb in summer, the utility passes those costs to customers dollar-for-dollar. The fuel adjustment clause on your bill, that line item that fluctuates month to month, reflects this passthrough. The utility cannot mark up fuel costs, and it cannot pocket savings if fuel prices drop.
Federal law requires the Federal Energy Regulatory Commission to review these automatic adjustment clauses to confirm they create incentives for economical fuel purchasing. If the commission finds a utility is not purchasing fuel efficiently, it can order the utility to change its practices or modify the clause after an evidentiary hearing.3Office of the Law Revision Counsel. 16 USC 824d – Rates and Charges; Schedules; Suspension of New Rates; Automatic Adjustment Clauses Fuel costs make up a substantial share of most bills. Wholesale energy charges represent roughly 70% of the supply portion of a typical electricity bill.
Administrative expenses like salaries, office costs, and routine maintenance also pass through at cost with no profit margin. The utility recovers what it actually spent, no more. If it finds ways to cut these costs between rate cases, it temporarily keeps the savings, which creates a short-term efficiency incentive. When the next rate case arrives, the commission resets rates based on current spending levels, and any efficiency gains flow back to customers as lower rates going forward.
Debt, Equity, and the Weighted Cost of Capital
The return on equity is only part of the story. Utilities finance their infrastructure with a mix of borrowed money and shareholder investment, and regulators set the overall profit based on the blended cost of both. A utility with 55% debt at a 6.5% interest rate and 45% equity at a 9.5% authorized return would have a weighted average cost of capital around 7.85%. That blended rate, not the equity return alone, gets multiplied by the rate base to determine the dollar amount customers pay for the utility’s capital costs.
The mix matters for your bill. Equity costs more than debt because shareholders demand a higher return than bondholders for bearing more risk. A utility that loads up on equity financing drives up the weighted cost of capital and, with it, customer rates. Regulators scrutinize the capital structure for exactly this reason, sometimes requiring a utility to use a hypothetical capital mix if its actual balance sheet looks unreasonably equity-heavy compared to peers.
Revenue Stabilizers Between Rate Cases
Under traditional rate structures, a utility that sells less energy collects less revenue, which means successful conservation programs directly hurt the company’s bottom line. Decoupling solves this by guaranteeing the utility a set revenue level regardless of how much energy customers actually consume. If sales drop below projections, the utility adds a small surcharge to rates. If sales exceed projections, customers get a credit.
The mechanics involve a periodic comparison, monthly or quarterly or annually, between the revenue the commission authorized and what the utility actually collected.4Berkeley Lab. The Distribution of U.S. Electric Utility Revenue Decoupling Rate Impacts from 2005 to 2017 Any gap triggers an adjustment on the next billing cycle. From the utility’s perspective, decoupling reduces risk for shareholders by making cash flow more predictable. From the customer’s perspective, your per-unit rate might tick up slightly when neighbors use less energy, though the total amount the utility collects stays the same. The adjustments tend to be small in practice, a few dollars per month in either direction.
Weather Normalization
A related tool called the weather normalization adjustment smooths revenue when temperature swings cause unusual consumption. If a winter is milder than the 20-year historical average, customers use less heat and the utility collects less. The adjustment adds a small charge during warmer-than-normal months and issues credits during colder-than-normal months. Several states authorize these adjustments for gas utilities, typically during the heating season.
Multi-Year Rate Plans
Traditional rate cases are expensive, adversarial, and time-consuming. Multi-year rate plans lock in a rate trajectory for four or five years at a time, with built-in escalators for inflation and customer growth. Instead of filing a new rate case every two or three years, the utility operates under a predetermined formula that adjusts revenue automatically.5Lawrence Berkeley National Laboratory. State Performance-Based Regulation Using Multiyear Rate Plans for U.S. Electric Utilities
The key feature is that the revenue escalator tracks industry cost trends rather than the individual utility’s own spending. If the utility keeps costs below the industry-trend escalator, it pockets the difference until the plan expires and a new rate case resets everything. Research suggests that a five-year plan without earnings sharing produces cumulative cost reductions of about 5% after ten years compared to traditional regulation with frequent rate cases.
Performance Rewards and Earnings Sharing
The traditional model pays utilities for building things, not for performing well. Performance-based regulation layers financial consequences on top of the standard return: bonuses for exceeding targets, penalties for falling short. The most common metrics involve system reliability (how often power goes out and how long outages last), customer service responsiveness, and progress toward clean energy goals.6National Renewable Energy Laboratory. Next-Generation Performance-Based Regulation
Reliability metrics drive real financial stakes. Some states have penalized utilities with a reduction in their authorized return on equity for failing to meet improvement targets on outage frequency and duration. Customer service measures such as complaint volumes, call wait times, and satisfaction survey results also feed into reward-and-penalty calculations. Design matters. Poorly specified metrics produce gaming rather than genuine improvement. One state found that a customer satisfaction survey using a vague 1-to-5 scale generated meaningless data until regulators redesigned it with more objective questions.
Earnings sharing adds another layer. When a utility earns more than its authorized return, because load growth exceeded projections or costs came in below estimates, an earnings sharing mechanism splits that surplus between shareholders and customers. Most states that use these mechanisms allow the utility to keep all earnings within a deadband around the target, then share excess earnings above that band.
Revenue from Unregulated Affiliates
Utility parent companies often own subsidiaries that operate outside the regulated framework. These affiliates sell wholesale electricity on competitive markets, offer home warranty contracts, build renewable projects for commercial customers, or provide consulting services. Because these activities face market competition, profits are not capped by any authorized return. The parent company charges market prices and keeps whatever margin it earns.
The risk is that a parent company could use captive ratepayer revenue to subsidize its competitive ventures, or shift costs from the unregulated side onto the regulated utility’s books. Regulators address this through accounting separation rules, sometimes called ring-fencing. These rules require the utility to maintain a cost allocation manual specifying how shared corporate expenses like legal departments, IT systems, and executive salaries get divided between regulated and unregulated operations. When the regulated utility buys services from an affiliate, it pays the lower of fully allocated cost or market price. When it sells services to an affiliate, it charges at least market price. FERC and state commissions audit these affiliate transactions, and utilities that blur the line face penalties and rate disallowances.
Cooperatives and Municipal Utilities Work Differently
Not every utility is an investor-owned corporation earning a return on equity for shareholders. About a quarter of electricity customers are served by cooperatives or municipal utilities that operate under fundamentally different financial models.
Electric cooperatives are owned by their members, the customers themselves. When a cooperative’s revenue exceeds its expenses in a given year, the surplus gets allocated to members as capital credits based on how much electricity each member purchased. The cooperative uses that money to finance construction and system improvements in the meantime, which reduces the need for borrowed capital. Eventually, typically 20 to 30 years later, the board votes to retire those credits and return the money to members as a bill credit or check. There are no shareholders demanding quarterly earnings growth, and no authorized return on equity.
Municipal utilities work similarly. They aim to cover operating costs and debt service rather than generate profit for investors. A well-run municipal utility targets a balanced capital structure and a return sufficient to cover bond interest payments and build reserves for future investment. Any surplus stays within the municipal system, sometimes flowing to the city’s general fund as a transfer payment. The absence of a profit motive doesn’t make these utilities immune to financial pressure. They still need to attract capital for infrastructure, typically through municipal bonds rather than equity markets.
How Customers Can Push Back on Rates
Rate cases are not closed-door negotiations between utilities and regulators. Most state commissions allow customers, consumer advocates, and community organizations to formally intervene in the proceedings. Intervenors can review the utility’s filings, submit testimony from their own experts, cross-examine utility witnesses, and propose alternative rate designs. Nearly 20 states have established intervenor compensation programs that reimburse some of the costs of participating, recognizing that the process is expensive enough to shut out the very people it is supposed to protect.
Even without formal intervention, most commissions accept public comments during rate cases, and some hold community hearings where customers can testify about the impact of proposed rate increases. Commission staff independently audit the utility’s filing and represent the public interest, but staff priorities don’t always align with what residential customers care about most. Showing up, or funding an organization that does, is the most direct way to influence how much of your bill goes to utility profit versus actual service delivery.