Households and businesses served by investor-owned utilities pay billions of dollars in profits to utility investors each year. Until now, no one has put a precise number on how much of an electric bill is made up of that profit. Using publicly reported financial data, this report provides the first systematic look at how much of each dollar spent on electricity ultimately goes to investors.
EPI analyzed financial data from 110 investor-owned operating electric utilities nationwide between 2021 and 2024, including several utilities that bill customers jointly for electric and gas service. We also incorporated 2025 filings for 79 investor-owned utilities that had reported annual results to the SEC in time for inclusion in this analysis.
EPI also developed a calculator that will allow customers to discover how much of their monthly utility bill goes directly to profits. Electric utilities kept about 15 cents of every dollar they collected as profit last year. For a customer paying a $200 monthly electric bill, that means roughly $30 went to corporate profits. This profit share has been rising, up from around 13% on average between 2021 and 2024, as further detailed in this analysis.
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Key findings include:
- From 2021 through the latest available 2025 filings, the electric utilities examined in this report collected more than $200 billion in net income — profit drawn from electricity revenue collected by those utilities. Between 2021 and 2024 alone, those utilities reported approximately $186 billion in profit.
- Over the same four-year span, utilities retained an average of 12.8 percent of their revenue as profit. This means that the utilities examined in this report kept about 13 cents of every dollar customers paid as profit.
- Preliminary 2025 data (covering about three-quarters of the target utilities) show margins running even higher, with an average of 14.6 percent among reporting utilities, suggesting profit shares remain elevated.
- Some utilities consistently operate at significantly higher margins than the average. The top 10 utilities by average margin over 2021–2024 include MidAmerican Energy (27.22%), Florida Power & Light (23.51%), Nantucket Electric (23.24%), Empire District Electric (22.45%), Florida Public Utilities (20.35%), CalPeco (20.28%), Public Service Electric & Gas (19.44%), Duke Energy Carolinas (19.07%), Alabama Power (18.71%), and AEP Texas (18.63%).
- Among the 79 utilities reporting 2025 results as of this analysis, the highest margins were seen at FPL (27.44%), MidAmerican Energy (27.16%), SoCal Edison (26.11%), Georgia Power (22.57%), and AEP Texas (22.19%).
- Profit margins vary regionally. In particular, utilities in the Southeast that operate outside of organized wholesale power markets – meaning they are predominantly vertically integrated, serve captive retail customers, and do not participate in multi-state markets – reported average margins of nearly 16 percent from 2021 through 2024. This stands in contrast to lower average margins for utilities in markets such as PJM (11.8 percent) and regions in New York and New England.
These patterns suggest that a substantial share of what customers pay for electricity is consistently flowing to investors as profit, a finding that is especially significant as consumers face persistently high energy costs and financial stress.
About 30 percent of the country’s electricity is sold by non-profit utilities, most of which are either cooperatives or municipally owned. Those utilities do not collect profit, and typically charge lower rates.
Introduction
Electricity bills are rising across much of the United States, placing growing pressure on household budgets and drawing increased attention from policymakers. Customers served by investor-owned electric utilities (IOUs) in many states have experienced sharp increases in what they pay for power in recent years. These increases come at a time when many families are already struggling with the rising costs of housing, food, healthcare, and other essentials, making electricity affordability an increasingly urgent concern.
In response, regulators and elected officials across the country are facing mounting pressure to explain why power bills are climbing and what can be done to bring them down. State utility commissions have seen elevated levels of rate cases and fuel cost adjustment filings in recent years, while lawmakers in several states have held hearings or introduced legislation aimed at addressing rising electricity costs.
Governors have also begun publicly questioning the drivers of higher bills as customer complaints mount. In Pennsylvania, for example, Gov. Josh Shapiro has pushed for changes to regional electricity market rules and greater scrutiny of utility profits after warning that current market structures could impose billions of dollars in additional costs on consumers. Amid concerns about skyrocketing electricity bills in Illinois, Gov. JB Pritzker championed legislation that aims to curb costs. And Indiana passed bipartisan energy legislation aimed to change utilities’ profit incentives.
Utilities and policymakers often point to a variety of factors behind rising electricity bills. Methane (natural) gas prices have fluctuated in recent years, increasing the cost of generating electricity in some regions. Utilities are also investing billions of dollars in new infrastructure, including transmission lines, grid modernization projects, and power plants, costs that are typically recovered from customers through rates. At the same time, extreme weather events and changing energy markets have created new pressures on utilities to rebuild or harden infrastructure.
These explanations capture part of the picture. But one factor that is rarely examined closely in public discussions of rising electricity bills is utility profits.
Investor-owned utilities typically operate as regulated monopolies within defined service territories, where customers cannot choose another provider and state regulators approve the rates utilities charge. Those rates are designed not only to cover the costs of operating the electric system but also to provide utilities with a return on investment for shareholders. In other words, a portion of every electric bill ultimately goes to investors.
Despite its central role in the utility business model, the share of electricity revenue that utilities retain as profit is rarely analyzed across the industry in a systematic way.
This report provides a nationwide look at utility profit margins using publicly reported financial data from operating electric utilities. By examining how much of utilities’ revenue ultimately becomes profit, the analysis offers a clearer picture of the role investor returns play in the economics of electricity service.
EPI analyzed financial data from 110 operating electric utilities across the United States between 2021 and 2024, including several utilities that provide both electric and gas service. We also examined 2025 filings for 79 utilities that had reported annual results in time to be included in this analysis.
The findings reveal that utilities consistently retain a substantial share of the revenue they collect from customers as profit, and that those margins have increased as electricity bills have risen.
The sections that follow examine these profit margins across the industry, identify the utilities with the highest profit shares, and explore how profitability varies across regions of the United States.
Section 1. How Utility Profits Work
Understanding how investor-owned utilities earn profits and why those profits show up in customer bills requires a brief look at the regulatory framework that governs the industry.
The Regulatory Model
The electric utility business model in most of the country rests on a government-granted monopoly. Private companies receive exclusive service territories, eliminating competition and guaranteeing a customer base, under the theory that electricity infrastructure is most efficiently built once, by a single entity. The trade-off, in theory, is that those companies submit to rate regulation that prevents them from exploiting their market power. State public utility commissions (PUCs) conduct that oversight, reviewing utility costs and setting the rates customers pay. The system is designed to hold utility profits to a level that fairly compensates investors without extracting more from captive customers than service actually costs.
That rate-setting process is known as a rate case. When a utility seeks to raise its rates, or when regulators require a periodic review, the utility files extensive financial documents with the PUC laying out its costs and making the case for the revenue it says it needs to serve customers and provide a return to investors. Regulators review those filings, often over months of proceedings that include testimony from utility witnesses, commission staff, independent experts, and consumer advocates. At the end, the commission issues an order setting rates that will remain in effect until the next rate case is decided.
Rate of Return and Return on Equity
Central to any rate case is the question of how much profit the utility should be allowed to earn. Commissions determine this through two related concepts: the allowed rate of return (ROR) and the allowed return on equity (ROE).
A utility’s capital structure consists of two types of financing: debt (bonds and loans) and equity (capital contributed by shareholders). The rate of return is the blended, weighted average cost of those two sources of capital — essentially, what the utility is expected to earn across its entire invested capital base, which regulators call the rate base. Because debt is less expensive than equity, and because regulators allow utilities to earn a return on equity as profit for shareholders, the allowed ROE is typically higher than the overall rate of return.
PUCs set allowed ROEs by examining what investors could expect to earn from investments of comparable risk. That standard has a long legal pedigree: the principle that a utility’s rate of return should equal its actual cost of capital — no more, no less — traces back to a concurring opinion by Supreme Court Justice Louis Brandeis in 1923 and was formally adopted by the full Court in its landmark 1944 Hope Natural Gas decision. Under this standard, a return above the cost of capital is not “just and reasonable.” It is, as the Court framed it, an unjust enrichment of investors at the expense of customers.
While a utility’s cost of debt is straightforward to determine — it’s the interest rate lenders charge — its cost of equity is not directly observable. It has to be estimated, using financial models that are contested and that critics argue consistently produce inflated results. Because a utility’s stock market value scales directly with the gap between its authorized ROE and its actual cost of equity, utilities have an incentive to push for ROEs as high as possible. They devote substantial legal and financial resources to doing exactly that in rate proceedings.
The evidence suggests they’ve been winning that argument for decades. Utility stocks have traded at roughly twice their book value for the better part of the last 15 years — a signal that authorized ROEs are approximately twice what utilities’ actual cost of equity would justify. Wall Street long-term return forecasts offer a separate benchmark: in 2024, the average authorized ROE for regulated U.S. utilities was 9.7%, while the average of 34 major investment firms’ long-term equity return forecasts for the broad U.S. market was 6.7%. Even the highest individual forecast — 8.3% — was lower than the average authorized utility ROE. That gap is particularly striking because utilities, with their regulated monopoly status and predictable earnings, are lower-risk investments than the market as a whole; their cost of equity should be below the market average, not above it.
One recent analysis from the American Economic Liberties Project estimated that excess ROEs cost customers approximately $50 billion per year, or roughly $300 per household annually. That is money ratepayers are paying not for electricity, not for infrastructure, but for profits that exceed what investors need to be fairly compensated for providing capital.
Why Bill Profit Sharing Is Different from ROE
A key concept for understanding this report is that the profit in a customer’s bill is not the same number as the utility’s allowed ROE. They measure fundamentally different things, and understanding why requires thinking not just about percentages, but about time.
ROE describes what percentage of shareholders’ invested capital they earn as profit. How much of a customer’s bill is profit describes what fraction of each dollar collected from customers ends up as profit for the utility.
The profit share of a customer’s bill is typically higher than the authorized ROE, not lower. ROE is earned on shareholder equity invested in the rate base. For capital-intensive utilities, that equity base is usually larger than the revenue collected from customers in any single year. If a 10% return is applied to an equity base larger than annual customer revenue, the profit portion of a customer’s bill will exceed 10%. The ROE levels that dominate rate case debates are therefore not the ceiling on how much of a customer’s bill goes to profit.
A second, equally important dimension: what an annual ROE costs customers over the decades-long life of utility infrastructure.
Consider a home mortgage. A 5% interest rate on a home mortgage sounds reasonable. But a homebuyer who finances a $300,000 mortgage at 5% over 30 years will make total payments of roughly $580,000: the $300,000 they borrowed, plus nearly $280,000 in interest. By the end of the 30-year term, the homebuyer has paid close to twice what they originally borrowed. What may have seemed like a modest interest rate ballooned into a much larger cumulative cost, and profit to the bank.
The same dynamic operates in utility ratemaking. When a utility builds a new power plant, it doesn’t recover that cost all at once. The asset is placed in the rate base and depreciated over its useful life, often 30 years or more. Each year, customers pay back a slice of the original investment through depreciation. But they also pay a return on whatever asset value remains in the rate base. As the asset depreciates, the annual return shrinks, but it does not stop until the asset is paid off. Year after year, customers are paying a return on a declining but not-zero balance, until the plant is fully paid off.
On a $1 billion power plant financed with equal shares of debt and equity — using an example 10% ROE and 5% debt rate over 30 years — customers would pay roughly $775 million in profits to shareholders alone, on top of the full $1 billion in capital recovery. Add in debt interest, and total customer payments for that single asset approach $2.2 billion. A $1 billion investment, paid for more than twice over. The graphic below illustrates how this parallels what happens with a mortgage.
Utilities are perpetually adding new assets to the rate base. Old assets depreciate off the rate base while new ones are added, keeping the total balance, and the annual return payments, persistently high. The cumulative profit extracted from customers across a utility’s entire infrastructure portfolio, year after year, is what makes the profit share of the electric bill so consequential.
How Profits Are Set by Policy and What Policymakers Can Do
The profit share embedded in an electric bill is not a natural phenomenon. About 30 percent of the country’s electricity is sold by non-profit utilities, most of which are either cooperatives or municipally owned. Profit levels are the product of policy decisions made by state utility commissions, typically in contested rate proceedings, using methodologies that have evolved over decades. That means they can be changed.
Policymakers and regulators have several tools available:
- Lower allowed ROEs. Return on equity benchmarks are set case by case, and commissions have great discretion. States that adopt more conservative benchmarks, better calibrated to current market conditions, reduce the profit margin embedded in customer bills. States can enact new legislation or use existing regulatory authority to lower ROEs.
- Scrutinize capital structure assumptions. The mix of debt and equity in a utility’s capital structure affects the overall rate of return. Commissions that push back on utilities seeking to hold more equity, which earns a higher return, can reduce allowed profits.
- Reform ratemaking. Traditional rate-of-return regulation guarantees utilities a profit regardless of efficiency or customer outcomes. Some states are experimenting with performance-based ratemaking structures that link utility earnings to measurable results, which may create incentives to control costs and improve service rather than simply building more into the rate base.
- Strengthen consumer advocacy in rate proceedings. Research has found that states with independent consumer advocates in utility rate proceedings authorized meaningfully lower returns on equity by almost half a percentage point on average across more than 1,600 rate cases studied over nearly three decades.10 Utilities arrive with large legal and financial teams; residential customers rarely have equivalent representation without a funded advocate.
Section 2. What the Data Show About Utility Profit Margins
To better understand how profits fit into the economics of electricity service, EPI analyzed publicly reported financial data from operating electric utilities across the United States. The analysis examined financial disclosures from 110 investor-owned electric utilities between 2021 and 2024, as well as 2025 filings available for 79 utilities that had reported results in time to be included in this report.
The results show that utilities consistently retain a substantial share of the revenue they collect from customers as profit, and that these profit levels have risen in recent years.
Utility profit margins averaged nearly 13 percent from 2021 to 2024
Across the utilities examined in this report, the median profit margin between 2021 and 2024 was 12.9 percent. In other words, utilities retained about 13 cents of every dollar in revenue as profit during this four-year period.
The average profit margin was nearly identical at 12.8 percent, indicating that the results are broadly representative of the sector and are not driven by a handful of unusually high-profit utilities. These figures reflect sustained trends over multiple years rather than one-time spikes.
In total, the utilities examined in this report reported almost $186 billion in profit between 2021 and 2024.
Profit margins of this scale are high relative to most sectors of the U.S. economy. Companies in most industries typically report net profit margins in the single digits, making the margins reported by many electric utilities comparatively large.
Many utilities report substantially higher profit shares
While the industry average margin was 12.8 percent, many utilities reported profit shares well above that level.
Between 2021 and 2024, nearly 40 utilities averaged profit margins above 15 percent, meaning they retained more than 15 cents of every revenue dollar as profit.
Some utilities reported even higher margins. The utilities with the highest average profit shares over the four-year period were:
- MidAmerican Energy – 27.22%
- Florida Power & Light (FPL) – 23.51%
- Nantucket Electric – 23.24%
- Empire District Electric – 22.45%
- Florida Public Utilities – 20.35%
- CalPeco – 20.28%
- Public Service Electric & Gas – 19.44%
- Duke Energy Carolinas – 19.07%
- Alabama Power – 18.71%
- AEP Texas – 18.63%
Several of these utilities sustained profit margins above 20 percent for multiple years during the period analyzed.
Early 2025 data show profit margins running higher
Available 2025 filings covering 79 utilities suggest that profit margins are currently running higher than the four-year average.
Among these utilities, the median profit margin was almost 15 percent, while the average was approximately 14.6 percent.
While these results are preliminary and do not yet include all of the investor-owned utilities, they suggest that profit shares have increased over the average levels observed between 2021 and 2024.
Among the utilities reporting the highest profit margins so far in 2025 were:
- Florida Power & Light – 27.44%
- MidAmerican Energy – 27.16%
- Southern California Edison – 26.11%
- Georgia Power – 22.57%
- AEP Texas – 22.19%
Profit margins vary significantly by region
The analysis also found notable regional differences in utility profit margins.
Utilities in the Southeast that operate outside of organized wholesale electricity markets reported the highest average profit shares. Between 2021 and 2024, these utilities retained nearly 16 percent of revenue as profit.
By contrast, utilities operating within organized electricity markets reported significantly lower margins. For example, utilities in the PJM regional market serving the Mid Atlantic averaged about 11.8 percent, while utilities in New York and New England reported similar or lower levels.
These regional differences reflect, in part, how electricity markets are structured. In the Southeast, where utilities are typically vertically integrated, a single company owns generation, transmission, and distribution — meaning the profit margin captured in this analysis reflects all of utility earnings that flow through customer bills. In competitive wholesale markets like PJM, there are local regulated utilities that own only transmission and distribution; generation is often owned by independent power producers whose earnings are not captured by this analysis.
Lower margins in competitive markets do not by themselves indicate better overall outcomes for customers — PJM’s data center boom, failure to interconnect new generation, and capacity market shortfalls have led to soaring prices for customers, for example — but the gap between Southeastern utilities and their counterparts in competitive markets is large enough to warrant scrutiny of whether vertically integrated monopolies operating outside of RTOs are consistently extracting more profit from captive customers than is necessary to provide safe and reliable electricity service.
Section 3. Methodology
EPI collected financial data for 110 investor-owned electric utilities providing service in the United States for the years 2021 through 2024, and for 79 utilities that reported 2025 results to the SEC in time for inclusion in this analysis.
Data Sources
The data we reviewed for this report comes from the investor-owned utilities. We used U.S. Securities and Exchange Commission filings, specifically 10-K annual reports, as our primary data source where available. SEC filings are standardized, audited, and publicly accessible, making them the most reliable basis for this type of analysis.
Where a 10-K did not have the required data, we used data from the utility’s Form 1 filing to the Federal Energy Regulatory Commission. The Form 1 is an annual financial report that all utilities meeting applicable size thresholds are required to submit to FERC, and it provides operating company-level detail that some consolidated SEC filings may obscure or that some utilities are not required to file. For instance, some utilities are owned by parent companies based outside the United States and may not be required to file a 10-K.
We also used data from non-SEC financial reports that one major company, FirstEnergy, publishes to its website for each of its utilities.
Utilities owned or acquired by private equity or foreign holding companies may have limited or no SEC filing data for recent years.
Scope
This analysis covers investor-owned utility operating companies only. We did not include municipal utilities, rural electric cooperatives, or other non-investor-owned entities. These organizations are fundamentally non-profit entities. They operate under fundamentally different economic and governance structures.
For utilities that provide both electric and gas service, we used electric-only financial data wherever the source material allowed for it. Where a utility bills customers jointly for electric and gas service, as is the case for PG&E in California for example, we used consolidated data reflecting the combined service. Our goal was for the data to correspond as closely as possible to the actual bills that customers pay.
Utilities that were taken private or otherwise ceased to be publicly reporting investor-owned entities during the analysis period were excluded from the dataset.
For regional comparisons, when a utility served multiple regions, we assigned it to the region where the utility is headquartered.
We reported utilities that merged, sold, or otherwise changed ownership with as much data as was available during the time-period reviewed. For example, Penn Power, West Penn Power, and Met Ed have merged with Pennsylvania Electric. Our reporting reflects each entity’s standalone financials for the years in which they filed separately. Once a utility is absorbed into another entity, its data ends at the last year of independent reporting.
Calculating Bill Profit Share
To calculate the approximate percentage of a utility’s customer bill that flows to investors, we divided net income by total operating revenues per year. This ratio, net income as a share of revenue, is our primary metric throughout this report. This metric does not isolate the electric portion of revenue in cases where utilities report consolidated electric and gas operations.
This is a deliberately straightforward calculation. It is not a cost-of-service analysis, and it does not purport to determine whether a given utility is earning exactly its allowed rate of return or over- or under-earning relative to that benchmark. It answers a simpler question: for every dollar this utility collected from customers, how much ended up as net income?
The net income figures in this analysis are reported after income taxes. Utilities collect enough revenue to cover both their income tax liability and their return to shareholders, meaning customers fund both. The profits reported here reflect only what utilities retain as net income after taxes are paid; they do not include the income taxes customers effectively pay on utilities’ behalf. The total profit-related share of customer bills — net income plus income taxes — is higher than the figures reported here.
Section 4. Glossary of Terms
Capital structure — The mix of debt (loans and bonds) and equity (shareholder investment) that a utility uses to finance its assets. The proportion of debt to equity directly affects the overall rate of return a utility earns: because equity commands a higher return than debt, utilities with more equity in their capital structure extract more profit from customer bills.
Cost of capital (COC) — The average cost a utility pays to raise money from lenders and investors to build and run its system.
Cost of equity (COE) — The return that equity investors require to provide capital to a utility, reflecting the risk of the investment. Unlike the cost of debt, which is directly observable from lenders’ interest rates, the cost of equity must be estimated, a process that is methodologically contested and that critics argue has consistently produced results higher than actual market conditions warrant in recent years.
Depreciation — The portion of a utility bill that gradually repays the cost of building power plants, transmission lines, and other infrastructure over the life of those assets. Customers also pay a return each year on the remaining unpaid portion of that investment, so over time the total amount paid for an asset typically exceeds what it originally cost to build.
FERC Form 1 — An annual financial report that utilities meeting certain size thresholds must file with the Federal Energy Regulatory Commission (FERC). It provides operating-companylevel financial detail that can be more granular than consolidated SEC filings, and is EPI’s secondary data source where 10-K data was insufficient.
Investor-owned utility (IOU) — A privately owned, for-profit electric utility company. IOUs normally receive an exclusive geographic franchise and an obligation to serve all customers in exchange for accepting rate regulation and state oversight. They are distinguished from publicly owned utilities by their shareholder ownership and profit motive.
Just and reasonable — The legal standard governing utility rates, derived from the U.S. Constitution and codified in federal and state law. Rates that enrich investors beyond the cost of capital are not “just and reasonable” under the standard affirmed by the Supreme Court in FPC v. Hope Natural Gas Co. (1944).
Net income — A company’s profit after all operating costs, interest payments, and taxes have been deducted from revenues. Net income is the numerator EPI uses to calculate each utility’s profit margin in this report.
Operating utility — A regulated electric utility that directly provides electricity service to customers.
Parent company — A holding corporation that owns one or more utility subsidiaries.
Performance-based ratemaking — An approach to utility regulation that ties a utility’s allowed earnings to specific, measurable outcomes — such as reliability, cost efficiency, or customer satisfaction — rather than guaranteeing a return on capital regardless of performance. It is intended to align utility incentives with customer interests.
Profit margin or bill profit share — Net income expressed as a percentage of total revenue for a given year. These terms are used interchangeably in this report to describe the portion of each customer dollar that the utility retains as profit rather than spending on operations, infrastructure, or debt service.
Public utility commission (PUC) — A state regulatory body responsible for overseeing investor-owned utilities, setting the rates they can charge customers, and reviewing their costs and financial performance. Also called a public service commission (PSC) or state corporation commission (SCC) in some states
Rate base — The total net value of assets on which a utility is permitted to earn a rate of return. Typically includes power plants, transmission lines, distribution infrastructure, and other utility capital investments, minus accumulated depreciation. A larger rate base means larger annual returns collected from customers.
Rate case — A formal proceeding in which a utility requests approval from its state commission to change the rates it charges customers. Rate cases typically involve extensive financial filings and expert testimony and often unfold over months before the commission issues an order.
Rate of return (ROR) — The overall percentage return a utility is permitted to earn on its rate base, calculated as the weighted average of its cost of debt and its authorized return on equity. Sometimes called the weighted average cost of capital (WACC).
Regional transmission organization (RTO) / Independent system operator (ISO) — An independent entity that manages high-voltage transmission infrastructure and operates competitive wholesale electricity markets across multiple states.
Regulated monopoly — A market structure in which a single utility is granted exclusive service territory in exchange for oversight of its rates and operations.
Return on equity (ROE) — The authorized percentage return that a utility’s equity investors earn on their invested capital, as set by regulators in rate proceedings. ROE is a component of the overall rate of return, applies only to the equity portion of the capital structure, and is set with reference to what investors could earn on comparable-risk investments elsewhere.
Rider/surcharge — An additional charge added to customer bills to recover specific costs, such as environmental compliance or infrastructure upgrades.
SEC 10-K — The annual report that publicly traded companies, including most large investor-owned utilities, are required to file with the U.S. Securities and Exchange Commission. 10-Ks include audited financial statements and are EPI’s primary data source for this analysis.
Vertically integrated utility — A utility that owns and operates the full electricity supply chain: generation (power plants), transmission (high-voltage delivery), and distribution (local delivery to homes and businesses).
Wholesale electricity market — A market where electricity generators sell power to utilities or other buyers before it is delivered to retail customers.
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