In a utility rate case, depreciation is how a regulated electric, gas, or water company recovers the original money it spent on poles, pipes, plants, and meters — spread across each asset’s expected service life and billed to customers as an operating expense year after year. It also quietly reduces the rate base on which the utility earns its authorized profit, so the depreciation numbers a public service commission approves shape both what you pay and what shareholders take home. That is why utility depreciation in rate cases draws some of the sharpest disputes between companies, commission staff, and consumer advocates.
Where Depreciation Sits in the Rate Formula
Every rate case is built around a single equation. The Federal Energy Regulatory Commission expresses it this way: multiply the rate base by the overall rate of return to get the allowed profit, then add operating and maintenance expenses, administrative costs, depreciation expense, and taxes, and subtract any revenue credits.1Federal Energy Regulatory Commission. Cost-of-Service Rates Manual The result is the total revenue the utility is allowed to collect from all customers combined.
Depreciation shows up twice inside that formula. It appears once as an explicit operating expense the utility recovers each year, and again indirectly through the rate base, because accumulated depreciation reduces the asset value on which the utility earns its return. A single change in a depreciation rate therefore moves two numbers in opposite directions: raise the annual depreciation and expenses go up while the rate base shrinks a little faster; lower it and expenses drop but the utility earns a return on a larger book value for longer. This is why parties fight over decimal points.
Return of Capital, Not Wear and Tear
Depreciation in ratemaking is not really an accounting estimate of an asset rusting or wearing out. Regulators call it a “return of capital” to distinguish it from the “return on capital,” which is the profit. The cost of every power line, pipe, and substation gets spread across the years that asset is expected to serve customers, and each year’s slice shows up as an operating expense in the cost-of-service formula.2National Association of Regulatory Utility Commissioners. Rate Case Process and Rate-Based Ratemaking
Commissions almost universally use straight-line depreciation for this purpose. If a transformer costs $100,000 and the commission assigns it a 25-year life, the annual depreciation expense charged to ratepayers is $4,000. Even allocation keeps rates predictable. Accelerated methods would front-load recovery into the early years of an asset’s life, causing rates to spike when major construction is completed and then decline over time — a pattern that shifts costs unfairly between current and future customers.
As accumulated depreciation builds each year, the rate base shrinks unless the utility adds new capital. A utility that invested $1 billion and has accumulated $400 million in depreciation has a rate base of $600 million. Next year, after another round of depreciation, that base drops further, and the utility’s authorized profit declines with it. That dynamic creates a constant incentive for utilities to propose new capital projects, and it is why commissions scrutinize each addition to confirm it genuinely serves customers.
How Depreciation Rates Get Set
The depreciation rate for each category of equipment is not a rough estimate. It comes from a detailed engineering and statistical study the utility submits as sworn evidence during the rate case. These studies use actuarial survivor curve analysis to model how long various assets actually last in the field, drawing on decades of retirement data to estimate the average service life for everything from wooden poles to underground cables.3National Association of Regulatory Utility Commissioners. Depreciation Expense – A Primer for Utility Regulators
Net salvage value is where the fights get sharp. This figure accounts for the cost of tearing down and disposing of an asset at the end of its life, offset by whatever scrap value the components have. For many asset classes, demolition cost far exceeds scrap value, producing a negative net salvage that increases the annual depreciation charge. If a category of poles has a negative 30 percent net salvage ratio, customers pay 130 percent of the original cost over the asset’s life rather than just 100 percent. Consumer advocates routinely challenge these projections, arguing that utilities base them on short historical windows that overstate future removal costs. The difference between a utility’s proposed salvage ratio and an advocate’s counter-proposal can swing annual depreciation expense by tens of millions of dollars.
Commission staff and consumer intervenors do most of the pushback. Many states fund participation by residential customer groups through intervenor compensation programs that reimburse legal and expert witness fees. Without that funding, the technical complexity and cost of hiring depreciation specialists would leave the utility’s study essentially unopposed. Once the commissioners issue a final order, the approved depreciation percentages remain in effect until the next rate case changes them.
Tax Depreciation and the Normalization Rules
A separate depreciation calculation exists for federal income taxes, and it almost never matches the one used for ratemaking. The Internal Revenue Code allows utilities to use accelerated cost recovery on their tax returns, so a transformer straight-lined over 25 years in rates might be written off in half that time for tax purposes. In the early years, the tax deduction exceeds the regulatory expense, meaning the utility pays less in taxes than it collected from customers for that purpose. The difference becomes accumulated deferred income tax, and it reduces the rate base because that money is effectively a zero-cost loan from ratepayers.
Federal law imposes strict normalization rules to keep utilities from handing that timing difference to customers as an immediate rate cut. Under 26 U.S.C. § 168(i)(9), a utility that uses accelerated depreciation on its tax return must track the tax savings in a deferred tax reserve and flow the benefit to ratepayers gradually over the asset’s regulatory life, not all at once.4Office of the Law Revision Counsel. 26 USC 168 – Accelerated Cost Recovery System Violating those rules is costly: the utility loses the right to use accelerated depreciation entirely, producing both higher taxes and higher customer rates going forward.
The 2017 Tax Cuts and Jobs Act made this vivid. When the federal corporate tax rate dropped from 35 percent to 21 percent, every utility’s deferred tax reserve suddenly held more money than needed. That excess became a regulatory liability owed back to customers, but the TCJA requires utilities to return it using the average rate assumption method, which spreads the refund over the remaining life of the underlying assets.5Internal Revenue Service. Revenue Procedure 2020-39 For long-lived assets like transmission towers, those refunds will trickle back to customers for decades. Even when Congress delivers a tax break, ratepayers cannot get it quickly without triggering the normalization penalty.
Amortization of Regulatory Assets and Liabilities
Not every recoverable cost is tied to a physical piece of equipment. When an ice storm destroys miles of power lines or a utility discovers contamination at an old industrial site, the resulting expense can be enormous but one-time. Rather than forcing the utility to absorb it all at once or spiking rates in a single year, the commission can allow the utility to defer the cost as a regulatory asset. Under accounting standards, an incurred cost qualifies for deferral when the utility can show it is probable the cost will be recovered through future rates.6U.S. Securities and Exchange Commission. Emera Inc. – Regulatory Assets and Liabilities
Recovery of a regulatory asset happens through amortization, which works like depreciation but with one key difference: the schedule is set entirely by the commission’s order rather than by the physical life of an asset. A commission might direct that $50 million in storm recovery costs be amortized over ten years, adding roughly $5 million per year to the cost of service. In some cases, the commission also allows the unamortized balance to sit in the rate base and earn a return, compensating the utility for carrying the cost until customers have fully repaid it.6U.S. Securities and Exchange Commission. Emera Inc. – Regulatory Assets and Liabilities
Common categories of regulatory assets include storm restoration costs, environmental cleanup obligations, pension and retiree benefit shortfalls, and the unamortized balance of debt that was refinanced at a loss. Each one represents a promise: the commission has agreed that customers will pay this cost, just not all at once. If a commission later reverses that promise, the utility must write off the asset as a loss, which is one reason utility credit ratings are sensitive to the regulatory climate in the states where they operate.
Regulatory liabilities are the mirror image. They arise when a utility has collected more from customers than it ultimately owes, or when a specific accounting treatment creates an obligation to reduce future rates. The most significant recent example is the excess deferred income taxes produced by the TCJA rate cut. Other common regulatory liabilities include overcollections of fuel or purchased gas costs, trued up periodically through rate adjustments, and state tax benefits from deducting repair costs that were capitalized on the utility’s books. The amortization periods for TCJA-related excess deferred taxes range from one year to roughly 65 years depending on the age and type of asset involved.7U.S. Securities and Exchange Commission. UGI Corporation – Utility Regulatory Assets and Liabilities and Regulatory Matters
When Depreciation Stops Early: Stranded Assets
When a power plant or other major asset is retired before it has been fully depreciated, the remaining book value becomes a stranded cost, and someone has to pay for the undepreciated balance. Federal regulations define stranded costs as any legitimate, prudent, and verifiable cost incurred to serve a customer that can no longer be recovered through normal rates because the customer has left the system or the asset has been taken out of service.8eCFR. 18 CFR 35.26 – Recovery of Stranded Costs by Public Utilities and Transmitting Utilities
The most common response is to create a new regulatory asset for the undepreciated balance and amortize it over a period set by the commission. Customers keep paying for the retired plant even though it no longer generates electricity or pumps gas. That keeps the utility financially whole but adds a legacy line item to bills that can persist for years.
A growing number of states have turned to securitization as a lower-cost alternative, particularly for early coal plant retirements. Securitization works like refinancing a mortgage. Instead of recovering the stranded cost at the utility’s blended rate of return, which effectively charges customers 8 to 10 percent, the utility issues special bonds backed by an irrevocable surcharge on customer bills. Because that surcharge is guaranteed by legislation, the bonds carry interest rates far below typical utility financing costs, often 2 to 4 percent. Customers still pay for the retired plant, but at a fraction of what traditional cost recovery would require. States including Wisconsin, Michigan, New Mexico, Montana, and Colorado have enacted securitization legislation in recent years.
The Prudency Limit on What Gets Depreciated
A utility does not automatically earn depreciation and a return on every dollar it spends. The commission must find that each investment was both prudently incurred and used and useful in serving customers before it enters the rate base.9National Association of Regulatory Utility Commissioners. Ratemaking Fundamentals and Principles Prudency is judged based on what a reasonable utility manager would have decided at the time the commitment was made, not with the benefit of hindsight. The standard asks whether management adequately researched the project, estimated costs with reasonable accuracy, and considered alternatives before proceeding.
When a commission finds an investment imprudent, the financial consequences are immediate and permanent. The disallowed amount comes straight out of the utility’s earnings. No depreciation on it, no return on it, no recovery from customers. State commissions have disallowed hundreds of millions of dollars in individual cases, including a $215 million disallowance by Arizona regulators after finding that a utility’s installation of pollution-control equipment was imprudent, and nearly $60 million across four utilities in Minnesota for mismanaged natural gas operations.
An indirect form of disallowance occurs when a commission permits the asset to remain in the rate base but strips away the return on equity for an extended period, allowing only a below-market return. That is nearly as painful as a full disallowance because shareholders still bear the unrecovered cost of the investment. If a utility abandons a project entirely, it must remove the asset from its books and recognize the loss unless the commission grants a regulatory asset for the unamortized balance.