Electricity Regulation 

In the US:

A Guide
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Electricity 

Regulation 

in the US: 

A Guide

March 2011

The Regulatory Assistance Project

Home Office

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Montpelier, Vermont 05602

phone: 802-223-8199

fax: 802-223-8172

www.raponline.org
ii

Electricity Regulation in the US: A Guide

Contents 

1 About This Guide To Utility Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

2 The Purpose of Utility Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

2.1 Utilities are Natural Monopolies 

2.1 The Public Interest is Important 

2.2 Regulation Replaces Competition as the Determinant of Prices

2.3 The So-Called Regulatory Compact 

2.4 All Regulation is Incentive Regulation 

3 A Brief History of Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

3.1 Grain Terminals and Warehouses, and Transportation 

3.2 Utility Regulation 

3.3 Restructuring and Deregulation 

4 Industry Structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

4.1 Overview

4.1.1 Investor-Owned Utilities (IOUs) 

4.1.2 Public Power: Municipal Utilities, 

Utility Districts, Cooperatives, and Others

4.2 Vertically Integrated Utilities 

4.3 Distribution-Only Utilities 

4.4 Federal vs. State Jurisdiction

4.4.1 Power Supply 

4.5 Power Supply Structure and Ownership

4.5.1 Federal Power Marketing Agencies 

4.5.2 Regulation of Wholesale Power Suppliers/ 

Marketers/Brokers 

4.5.3 Non-Utility Generators 

4.5.4 Consumer-Owned Utilities (COUs) 

4.5.5 Retail Non-Utility Suppliers of Power 

4.5.6 Transmission

4.6 Managing Power Flows Over the Transmission Network

4.6.1 RTOs, ISOs and Control Areas 

4.7 Natural Gas Utilities 

5 The Regulatory Commission . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

5.1 Commission Structure and Organization 

5.2 Appointed vs. Elected 

5.3 Limited Powers 

5.4 Consumer Advocates 

5.5 COU Regulation 
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Electricity Regulation in the US: A Guide

6 What Does The Regulator Actually Regulate? . . . . . . . . . . . . . . . . . . . . . . . . . 24

6.1 The Revenue Requirement and Rates

6.2 Resource Acquisition 

6.3 Securities Issuance

6.4 Affiliated Interests 

6.5 Service Standards and Quality 

6.6 Utility Regulation and the Environment 

7 Participation in the Rulemaking Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

7.1 Rulemaking 

7.2 Intervention in Regulatory Proceedings

7.3 Stakeholder Collaboratives 

7.4 Public Hearings 

7.5 Proceedings of Other Agencies Affecting Utilities 

8 Procedural Elements of US Tariff Proceedings . . . . . . . . . . . . . . . . . . . . . . . 31

8.1 Filing Rules 

8.2 Parties and Intervention 

8.3 Discovery 

8.4 Evidence

8.5 The Hearing Process

8.5.1 Expert Testimony 

8.5.2 Public Testimony 

8.6 Settlement Negotiations 

8.7 Briefs and Closing Arguments

8.8 Orders and Effective Dates 

8.9 Appeal 

9 The Fundamentals of Rate Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 

9.1 Functional and Jurisdictional Cost Allocation 

9.1.1 Interstate System Allocation 

9.1.2 Regulated vs Non-Regulated Services

9.1.3 Gas vs. Electric 

9.2 Determining the Revenue Requirement 

9.2.1 The “Test Year” Concept

9.2.1.1 Historical vs. Future Test Years 

9.2.1.2 Average vs. End-of-Period

9.2.2 Rate Base

9.2.3 Rate of Return

9.2.3.1 Capital Structure 

9.2.3.2 A Generic Rate of Return Calculation 

9.2.3.3 Cost of Common Equity 

9.2.3.4 Cost of Debt 

9.2.4 Operating Expenses 

9.2.4.1 Labor, Fuel, Materials and Outside Services 

9.2.4.2 Taxes 
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Electricity Regulation in the US: A Guide

9.2.4.3 Depreciation

9.2.5 Summary: The Revenue Requirement

9.3 Allocation of Costs to Customer Classes 

9.3.1 Embedded vs. Marginal Cost of Service Studies 

9.3.2 Customer, Demand and Energy Classification

9.3.3 “Vintaging” of Costs 

9.3.4 Non-Cost Considerations 

9.4 Rate Design Within Customer Classes 

9.4.1 Residential Rate Design 

9.4.2 General Service Consumers 

9.5 Bundled vs. Unbundled Service 

9.6 Advanced Metering and Pricing 

9.7 Service Policies and Standards 

9.8 Issue-Specific Filings 

9.9 Generic Investigations 

9.10 Summary: The Fundamentals of Regulation 

10 Drawbacks of Traditional Regulation and Some Fixes . . . . . . . . . . . . . . . . . 59 

10.1 Problems 

10.1.1 Cost-Plus Regulation 

10.1.2 The “Throughput” Incentive 

10.1.3 Regulatory Lag

10.2 Responses 

10.2.1 Decoupling, or “Revenue-Cap” Regulation 

10.2.2 Performance-based, or “Price-Cap” Regulation 

10.2.3 Incentives For Energy Efficiency or other Preferred Actions 

10.2.4 Competitive Power Supply Contracting 

10.2.5 Restructuring 

10.2.6 Prudence and Used-and-Useful Reviews 

10.2.7 Integrated Resource Planning 

11 Transmission and Transmission Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . 64 

11.1 Transmission System Basics

11.2 Transmission Ownership and Siting

11.3 Transmission Regulation 

12 Tariff Adjustment Clauses, Riders, and Deferrals . . . . . . . . . . . . . . . . . . . . . 69

12.1 Gas Utility-Purchased Gas Adjustment Mechanisms 

12.2 Electric Utility Fuel Adjustment Mechanisms 

12.3 System Benefit Charges for Energy Efficiency and Clean Energy 

12.4 Infrastructure and Other “Trackers” 

12.5 Weather-Only Normalization 

12.6 Deferred Accounting and Accounting Orders 
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Electricity Regulation in the US: A Guide

13 Integrated Resource Planning/Least-Cost Planning . . . . . . . . . . . . . . . . . . . 73

13.1 What is an IRP?

13.2 How Does an IRP Guide the Utility and the Regulator? 

13.3 Participating in IRP Processes 

13.4 Energy Portfolio Standards and Renewable Portfolio Standards .

13.5 How an IRP Can Make a Difference 

14 Energy Efficiency Progams . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77

14.1 Why Are Utility Commissions Involved?

14.2 Utility vs. Third-Party Providers 

14.3 Range and Scope of Programs

14.4 Cost Causation and Cost Recovery 

14.5 Total Resource Cost, Utility Cost, and Rate Impact Tests 

14.6 Codes, Standards, and Market Transformation 

15 Aligning Regulatory Incentives With Least-Cost Principles . . . . . . . . . . . . 85

15.1 Effect of Sales on Profits

15.2 Techniques for Aligning Incentives 

15.2.1 Decoupling 

15.2.2 Lost Margin Recovery 

15.2.3 Frequent Rate Cases

15.2.4 Future Test Years 

15.2.5 Straight Fixed-Variable Pricing (SFV) 

15.2.6 Incentive/Penalty Mechanisms 

16 Regulatory Treatment of Emission Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91

16.1 Currently Regulated Emissions 

16.2 Anticipated Regulation

16.3 Commission Treatment of Emissions Management Costs 

17 Low-Income Assistance Programs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94

17.1 Rate Discounts 

17.2 Energy Efficiency Funding

17.3 Bill Assistance 

17.4 Payment Programs

17.5 Deposits 

17.6 Provision for Uncollectible Accounts 

17.7 Disconnection/Reconnection

18 Service Quality Assurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98

19 Smart Grid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100

20 Summary: Regulation in the Public Interest . . . . . . . . . . . . . . . . . . . . . . . . . 104

Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 105
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Electricity Regulation in the US: A Guide
1

Electricity Regulation in the US: A Guide

1. About This Guide to 

Utility Regulation1

Over the past 140 years, society has undergone a fundamental 

transformation. The invention of the incandescent light bulb 

in the 1870s introduced lighting as one of the first practically 

available uses of electrical power. Electric utilities began to spring 

up in major cities during the 1890s, and by the 1900s they were spreading 

rapidly across the U.S. The National Academy of Engineering designated 

electrification as the 20th century’s greatest engineering achievement, beating 

the automobile, computers, and spacecraft. 

This conclusion is hardly surprising when one considers the intricate web 

of wires that connects every light switch in the U.S. to massive power plants, 

individual rooftop solar panels, and every source of electricity generation 

in between. Add to this the layer of pipes that run underground to feed 

stovetops, power stations, and factories with natural gas, and you have 

the foundation on which modern society has been built. The utility grid 

continues to grow as the U.S. population expands and demand for energy 

increases. In 2009, the U.S. consumption of energy was 95 quadrillion 

Btus; this energy powers industry, transportation, residential homes, and 

commercial establishments throughout the country. Regulation of the utility 

system has also evolved over the past 140 years to ensure that the system is 

reliable, safe, and fairly administered. This guide will focus on electric and 

natural gas utility regulation in the U.S., and is meant to provide a basic 

understanding of the procedures used and the issues involved. 

The purpose of this guide is to provide a broad perspective on the universe 

of utility regulation. The intended audience includes anyone involved in the 

regulatory process, from regulators to industry to advocates and consumers. 

The following pages first address why utilities are regulated, then provide 

1 Material from two federally produced handbooks to the utility sector are used and referenced 

liberally throughout these pages, as are many historical works. This guide was written 

primarily by RAP Senior Advisor Jim Lazar, an economist with over 30 years’ experience in 

utility regulation. The RAP review team included Rick Weston, Rich Sedano, Riley Allen, 

David Farnsworth, Christopher James, Edith Pike-Biegunska, Wayne Shirley, and Camille 

Kadoch. Editorial and publication assistance was provided by Thad Curtz and Diane Derby.
2

Electricity Regulation in the US: A Guide

an overview of the actors, procedures, and issues involved in regulation of 

the electricity and gas sectors. The guide assumes that the reader has no 

background in the regulatory arena, and serves as a primer for new entrants. 

It also provides a birds-eye view of the regulatory landscape, including 

current developments, and can therefore serve as a review tool and point of 

reference for those who are more experienced.

These chapters will briefly touch on most topics that affect utility 

regulation, but will not go into depth on each topic as we have tried to keep 

the discussion short and understandable. For more in-depth analysis of 

particular topics, please refer to the list of reference materials at the end of 

each section. RAP Issuesletters, which provide a more comprehensive review 

of many topics in this guide, are available online at www.raponline.org. Also, 

a lengthy glossary appears at the end of this guide to explain utility-sector 

terms. 
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Electricity Regulation in the US: A Guide

2. The Purpose of 

Utility Regulation

Electric and natural gas utilities that deliver retail service to 

consumers are regulated by state, federal, and local agencies. 

These agencies govern the prices they charge, the terms of their 

service to consumers, their budgets and construction plans, and 

their programs for energy efficiency and other services. Utility impacts 

on air, water, land use, and land disposal are typically regulated by other 

government agencies. Environmental regulation is generally beyond the 

scope of this guide, but the pages that follow do identify ways in which 

utility regulation can be reformed so as to achieve, or at least not undermine, 

environmental policy objectives.

Two broad, fundamental principles justify governmental oversight of the 

utility sector. First, since a utility provides essential services for the wellbeing of society — both individuals and businesses — it is an industry 

“affected with the public interest.” The technological and economic features 

of the industry are also such that a single provider is often able to serve the 

overall demand at a lower total cost than any combination of smaller entities 

could. Competition cannot thrive under these conditions; eventually, all 

firms but one will exit the market or fail. The entities that survive are called 

natural monopolies — and, like other monopolies, they have the power to 

restrict output and set prices at levels higher than are economically justified. 

Given these two conditions, economic regulation is the explicit public or 

governmental intervention into a market that is necessary to achieve public 

benefits that the market fails to achieve on its own.

This section covers the overall context in which utility regulation operates, 

as a preface to discussing the structure of the current industry and the 

regulatory framework that has evolved with it. 

2.1. Utilities are “Natural Monopolies”

In 1848, John Stewart Mill published an analysis of natural monopolies, 

noting that, “(a) Gas and water service in London could be supplied at lower 

cost if the duplication of facilities by competitive firms were avoided; and 
4

Electricity Regulation in the US: A Guide

that (b) in such circumstances, competition was unstable and inevitably was 

replaced by monopoly.”2 The natural monopoly concept still applies to at least 

the network components of utility service (that is, to their fixed transport 

and delivery facilities). However, even where there is sufficient competition 

among the providers of energy supply and/or retail billing service, the utility 

sector’s critical role in the infrastructure of modern, technological society 

justifies its careful oversight.

2.2. The Public Interest Is Important

Regulation is intended to protect the “public interest,” which comprises a 

variety of elements.

Utilities are expected to offer (and in the United States, provide) service to 

anyone who requests it and can pay for it at the regulator’s (or government’s) 

approved prices. In this sense, service is “universal.” A connection charge 

may be imposed if providing service involves a significant expenditure by the 

utility, but even that is subject to regulation and, in many cases, is subsidized 

in some manner by other customers or taxpayers.3

While some public services, like fire and police protection, are provided 

by government without many direct charges to users, utilities (even 

when government-owned) are almost always operated as self-supporting 

enterprises, with regulations dictating the terms of service and prices.

Utilities must also adhere to strict government safety standards, because 

their infrastructure runs throughout our communities and the public 

would be affected by sagging wires, ruptured pipes, and other problems. 

The production and distribution of electricity and natural gas also have 

environmental and public health impacts — by the emission of pollutants, 

on scenic views and land uses, and even from noise — that can adversely 

affect the public. Generating power often produces pollution; transmission 

lines have both visual and physical impacts on land use; and the availability 

of natural gas creates opportunities to use less-polluting fuels than oil or coal. 

2 John Stewart Mill, cited in Garfield and Lovejoy, Public Utility Economics, 1964, P. 15

3 Strictly speaking, a subsidy exists when a good or service is provided at a price that is below 

its long-run marginal cost — i.e., the value of the resources required to produce any more 

of it. While some market theorists argue for pricing based on short-run marginal cost, that 

issue here is, in our view, an accident of history. In general equilibrium — where the market 

is operating as efficiently as it can and total costs are minimized — long-run and short-run 

marginal costs are the same, because the cost of generating one more unit from an existing 

power plant is the same as the cost of building and operating a new, more efficient power 

plant. Certainly, the long run —that period of time in which all factors of production (capital 

and labor) are variable — is the sensible context in which to consider the public-policy 

consequences of utility matters, since investments in utility infrastructure are, for the most 

part, extremely long-lived.
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Electricity Regulation in the US: A Guide

Regulators may therefore impose environmental responsibilities on utilities to 

protect these public interests.

Because most utility consumers cannot “shop around” between multiple 

providers as a result of the natural utility monopoly, regulation serves the 

function of ensuring that service is adequate, that companies are responsive 

to consumer needs, and that things like new service orders and billing 

questions are handled responsively. In addition, the utility is often a conduit 

— through the billing envelope or other communications — for information 

that regulators consider essential for consumers to receive.

Finally, given utilities’ crucial role in the economy and in society’s general 

welfare, service reliability standards are often imposed as well.

2.3. Regulation Replaces Competition as the 

Determinant of Prices

For most businesses, the prices of goods or services that are sold are 

determined by what the customer or market will bear. In economic terms, 

markets will “clear” at the point where marginal costs equal the value that 

consumers, in the aggregate, set for the good or service; that is at the point 

where supply intersects with demand. A different approach to price-setting 

is required for utilities, since competition and free entry into markets does 

not exist in natural monopolies. Regulators use a cost of service approach 

to determine a fair price for electric service, by which the aggregate costs 

(including a reasonable return of, and on, investment) for providing each 

class of service (residential, commercial, and industrial) are determined. 

Prices are set to recover those costs, based on the sales volumes for each class.

2.4. The So-Called Regulatory Compact

It is occasionally argued that regulation constitutes an agreement between 

a utility and the government: the utility accepts an obligation to serve in 

return for the government’s promise to set rates that will compensate it fully 

for the costs it incurs to meet that obligation. This agreement is sometimes 

called the regulatory compact.

Although this phrase is often heard, there is in fact no binding agreement 

between a utility and the government.4 Regulation is an exercise of the 

police power of the state, over an industry that is “affected with the public 

interest.” Its need arises primarily from the monopoly characteristics of the 

4 This is true in the United States. In other parts of the world, however, regulation by contract 

is quite common.
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Electricity Regulation in the US: A Guide

industry, and its general objective is to ensure the provision of safe, adequate, 

and reliable service at prices (or revenues) that are sufficient, but no more 

than sufficient, to compensate the regulated firm for the costs (including 

returns on investment) that it incurs to fulfill its obligation to serve. The legal 

obligations of regulators and utilities have evolved through a long series of 

court decisions, several of which are discussed in this guide.5

2.5. All Regulation is Incentive Regulation

Some analysts use the term incentive regulation to describe a system in 

which the regulator rewards utilities for taking actions to achieve, or actually 

achieving, explicit public policy goals. However, it is critical to understand 

that all regulation is incentive regulation. By this we mean that every regulation 

imposed by government creates limitations on what the utility can do; 

but every regulation also gives the utility incentives to act in ways (driven 

generally by the desire to maximize net income, or earnings) that may or 

may not promote the public interest. Given any set of regulations, utilities 

will take those actions which most benefit their principal constituencies — 

shareholders and management — while meeting the requirements of the 

regulations.

For more details:

•	 NW Energy Coalition, 1993, Plugging People Into Power. www.raponline.

org/docs/NWENERGY_PluggingPeopleIntoPower_1993.pdf

•	 People’s Organization for Washington Energy Resources, 1982, The People’s 

Power Guide.www.raponline.org/docs/WER_PeoplePowerGuide_1982.pdf

•	 U.S. Department of Energy 2002, A Primer on Electric Utilities, Deregulation, 

and Restructuring of U.S. Electricity Markets. www1.eere.energy.gov/femp/

pdfs/primer.pdf

5 U.S. Supreme Court case law on the topic begins with its 1877 decision in Munn v. Illinois, 94 

U.S. 113 (which itself refers to settled English law of the 17th century — “when a business 

is ‘affected with the public interest, it ceases to become juris privati only.’”), and runs at least 

through Duquesne Light v. Barasch, 488 U.S. 299 (1989). Nowhere in that series of cases, 

including Smyth v. Ames, 169 U.S. 466 (1898), FPC v. Hope Natural Gas, 320 U.S. 591 

(1944), and Permian Basin Area Rate Cases, 390 U.S. 747 (1968), is the notion of a regulatory 

compact accepted.
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Electricity Regulation in the US: A Guide

3. A Brief History of Regulation

Utility regulation has evolved from historical policies regulating 

entities that are “affected with the public interest” into a complex 

system of economic regulation. One of the earliest forms of 

business regulation was the requirement in Roman and medieval 

times that innkeepers accept any person who came to their door seeking a 

room. Customers could be rejected only if they were unruly or difficult.6

This section presents a very brief history of utility regulation, setting the 

stage for a discussion of the traditional regulation now practiced in most of 

the United States, and certain alternatives that are practiced in some states.

3.1. Grain Terminals and Warehouses, and Transportation

In the 19th century, a series of court decisions in the United States held that 

grain elevators, warehouses, and canals were “monopoly” providers of service 

“affected with the public interest”7 and that their rates and terms of service 

could therefore be regulated.8 When railroads emerged in the second half of 

the 19th century, regulation in the U.S. became more formalized with the 

creation of the Federal Railroad Commission (which later became the Interstate 

Commerce Commission9

) to regulate rail transportation, and later, trucking.

. 

3.2. Utility Regulation

Initially, electric and gas utilities competed with traditional fuels (e.g., 

peat, coal, and biomass, which were locally and competitively supplied), and 

were allowed to operate without regulation. If they could attract business, at 

whatever prices they charged, they were allowed to do so. Cities did impose 

“franchise” terms on them, charging fees and establishing rules allowing them 

6 The Regulation of Public Utilities, Phillips, 1984, pp. 75-78.

7 The term “affected with a publick interest” originated in England around 1670, in the 

treatises De Portibus Maris and De Jure Maris, by Sir Matthew Hale, Lord Chief Justice of the 

King’s Bench.

8 Munn v. Illinois, 94 U.S. 113 (1877).

9 The Interstate Commerce Commission has since been dissolved.
8

Electricity Regulation in the US: A Guide

to run their wires and pipes over 

and under city streets. Around 

1900, roughly 20 years after 

Thomas Edison established the 

first centralized electric utility 

in New York, the first state 

regulation of electric utilities 

emerged.10 The “cost of service” 

principles of regulation (discussed 

in detail in Chapters 3-8 of this 

guide) have evolved over the 20th 

century from this beginning. 

3.3. Restructuring and 

Deregulation

In about 1980, electricity prices began to rise sharply as a new era 

of power plants began to come into service. Following developments in 

the structure of the telecommunications and natural gas industries, large 

industrial-power users began demanding the right to become wholesale 

purchasers of electricity. This led, a decade or so later, to the period of 

restructuring detailed in the next section, during which some states 

“unbundled” the electricity-supply function from distribution on the 

theory that only the wires (the fixed network system) constituted a natural 

monopoly, while the generation of power did not. In some cases, largevolume customers (big commercial and industrial users) were allowed to 

negotiate directly with wholesale power suppliers that competed with the 

services provided by the utility at regulated prices. In other states, the utilities 

were forced to divest their power-plant ownership, and the production of 

power was left to competitive suppliers. In both cases, the utilities retained 

the regulated natural monopoly of distribution.

For more details:

Bonbright, 1961, Principles of Public Utility Rates.

Garfield and Lovejoy, 1964, Public Utility Economics.

Phillips, 1984, The Regulation of Public Utilities.

Property does become clothed 

with a public interest when 

used in a manner to make it of 

public consequence, and affect 

the community at large. When, 

therefore, one devotes his property 

to a use in which the public has an 

interest, he, in effect, grants to the 

public an interest in that use and 

must submit to be controlled by the 

public for the common good ...

— U.S. Supreme Court, Munn v. Illinois,

94 USC 113, 126 (1877)

10 Photographs of lower Manhattan at the turn of the 20th century vividly display the 

economically and aesthetically (if not environmentally) destructive consequences of the overbuilding of the first duplicative and unnecessarily costly networks of wires that competitive 

individual firms were constrained to deploy during this period. Ultimately (and, as it turned 

out, quite quickly), the natural-monopoly characteristics of the industry doomed the less 

efficient providers to bankruptcy or acquisition by a single firm. (In New York, this company, 

founded by Thomas Edison, eventually became the aptly named Consolidated Edison.)
9

Electricity Regulation in the US: A Guide

4. Industry Structure

The electric utility sector is economically immense and vast in 

geographic scope, and it combines ownership, management, and 

regulation in complex ways to achieve reliable electric service. 

This section discusses the industry’s organization and 

governance: its forms of ownership, the jurisdiction of federal and state 

regulators, and how utilities across the country cooperate and coordinate 

their activities.

4.1. Overview

The U.S. electric industry comprises over 3,000 public, private, and 

cooperative utilities, more than 1,000 independent power generators, three 

regional synchronized power grids, eight electric reliability councils, about 

150 control-area operators, and thousands of separate engineering, economic, 

environmental, and land-use regulatory authorities. We’ll attempt to make all 

of these terms meaningful.

4.1.1. Investor-Owned Utilities (IOUs)

About 75% of the U.S. population is served by investor-owned utilities, or 

“IOUs”. These are private companies, subject to state regulation and financed 

by a combination of shareholder equity and bondholder debt. Most IOUs 

are large (in financial terms), and many have multi-fuel (electricity and 

natural gas) or multi-state operations. Quite a few are organized as holding 

companies with multiple subsidiaries, or have sister companies controlled by 

a common parent corporation11.

4.1.2. Public Power: Municipal Utilities, Utility Districts, Cooperatives 

Consumer-owned utilities, COUs, serve about 25% of the U.S. population, 

including both cities and many large rural areas. (In addition, there are a small 

number of consumer-owned natural gas utilities.) These utilities include:

• City-owned or municipal utilities, known as munis, which are 

governed by the local city council or another elected commission;

11 The investor-owned utilities are organized through a trade and lobbying group called the 

Edison Electric Institute, or EEI. www.eei.org
10

Electricity Regulation in the US: A Guide

• Public utility districts (of various types) which are utility-only 

government agencies, governed by a board elected by voters within the 

service territory;12

• Cooperatives (co-ops), mostly in rural areas, which are private 

nonprofit entities governed by a board elected by the customers of 

the utility.13 Most co-ops were formed in the years following the Great 

Depression, to extend electric service to remote areas that IOUs were 

unwilling to serve; there are also some urban cooperatives;14

• Others: A variety of Native American tribes, irrigation districts, mutual 

power associations, and other public and quasi-public entities provide 

electric service in a few parts of the U.S.

4.2. Vertically Integrated Utilities

Vertically integrated utilities are responsible for generation, transmission, 

and distribution of power to retail customers. In many cases, they own all 

or some of their power plants and transmission lines, but they may also buy 

power through contracts from others, giving them the operational equivalent 

of power-plant ownership. Most use a combination of owned resources, 

contract resources, and short-term purchases and sales to meet their customer 

demands, and a combination of their own transmission lines and lines owned 

by others to move power from where it is produced to the communities they 

serve. The mix of these varies widely from utility to utility.

4.3. Distribution-Only Utilities

Many electric utilities (and most natural gas utilities) are not vertically 

integrated, and provide only distribution service. By sheer number, the vast 

majority of distribution-only utilities are smaller consumer-owned ones, but 

some are large investor-owned utilities serving in states that have undergone 

restructuring. These distribution-only utilities either buy their power from 

one or more upstream wholesale providers, or, in the restructured states, 

consumers may obtain their power directly from suppliers, with the utility 

providing only the distribution service.

12 The public power districts and municipal utilities are organized through a trade and lobbying 

group called the American Public Power Association, or APPA. www.appanet.org

13 While public power districts conduct elections like other governments, with a one-person, 

one-vote principle, co-op elections are normally limited to the consumers of the utility — 

typically on a one-meter, one-vote basis, including business consumers and persons ineligible 

to vote in general government elections.

14 The cooperatives are organized through a trade and lobbying group called the National Rural 

Electric Cooperative Association, or NRECA. www.nreca.org
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Electricity Regulation in the US: A Guide

Generating 

Station

Generator 

Step-Up

Transformer

Substation 

Step-Down

Transformer

Transmission

Customer

128kV or 230 kV

Secondary

Customer

120 V or 240 kV

Primary

Customer

13 kV or 4 kV

Subtransmission

Customer

26 kV or 69 kV

Transmission Lines

765, 500, 230, and 138 kV

4.4. Federal vs. State Jurisdiction

Some aspects of the industry, such as interstate transmission and 

wholesale power sales, are federally regulated; some, such as retail rates and 

distribution service, are state-regulated; and some, such as facility siting and 

environmental impacts, may be regulated locally. Some functions, such as 

customer billing, are treated as monopoly services in many jurisdictions, but 

are treated as competitive in others.

In most cases, the U.S. Constitution allows federal intrusion into private 

economic activity only where interstate commerce is involved. Interstate 

transmission of electricity and natural gas clearly meets this test, and the 

courts have concluded that other parts of the electricity and natural gas 

supply system that affect interstate commerce, notably wholesale energy 

transactions, are subject to federal regulation, federal guidance, and/or federal 

oversight. 

The Federal Energy Regulatory Commission (FERC) handles most of the 

federal regulation of the energy sector, but some activities are regulated by the 

Environmental Protection Agency (EPA), federal land agencies (such as the 

Bureau of Land Management), or other federal bodies. 

State regulators adopt construction standards for lower-voltage retail 

distribution facilities, quality of service standards, and the prices and terms of 

service for electricity provided by investor-owned utilities. They also regulate 

consumer-owned (i.e., cooperative and municipal) utilities in some states, 

but in most states this is left to local governmental bodies and elected utility 

boards. 

4.4.1. Power Supply

Figure 4-1 shows the most essential elements of the power grid: 

generation, transmission, and distribution facilities.

Figure 4-1

Elements of the Grid

Source: US-Canada Power System Outage Task Force final report, April 2004.

Transmission

Distribution

Generation
12

Electricity Regulation in the US: A Guide

Most electricity in the United States is generated by coal, natural gas, and 

nuclear power plants, with lesser amounts from hydropower and renewable 

resources such as wind and solar.15 Licensing of nuclear and hydropower 

facilities is federally administered by FERC, while licensing of other types of 

power production — about 75% of the total — is managed at the state and 

local levels.

Figure 4-2: 

U.S. Electricity By Fuel, 2009

Source: U.S. Energy Information Administration

4.5. Power Supply Structure and Ownership

Individual utilities or utility consortia are responsible for most power 

generation, with some coming from federal agencies and an increasing 

amount from independent, non-utility suppliers.

4.5.1. Federal Power Marketing Agencies

Federal power marketing agencies (PMAs) were created to market power 

produced by federal dams. In some cases, they have also been given authority 

to build and own thermal power plants. These federal PMAs include the 

Bonneville Power Administration, the Southeastern Power Administration, 

the Southwestern Power Administration, and the Western Area Power 

Administration. The Tennessee Valley Authority is technically not a PMA, 

but operates in much the same way. Generally the PMAs only sell power at 

wholesale to local, vertically integrated utilities or local distribution utilities. 

However, BPA and TVA also operate extensive transmission grids, serving 

numerous local distribution utilities. 

Coal

Nuclear Natural Gas

Hydro

Renewables

Other

15 Less than 1% of U.S. net electric generation came from oil-fired units in 2009. See Table 

8.2 Electricity Net Generation: Total (All Sectors) 1949-2009, U.S. Energy Information 

Administration, available at: www.eia.doe.gov/emeu/aer/txt/ptb0802a.html.
13

Electricity Regulation in the US: A Guide

4.5.2. Regulation of Wholesale Power Suppliers/Marketers/Brokers

FERC has clear authority to regulate wholesale power sales, except when 

the seller is a public agency. The federal power marketing agencies, such as the 

Tennessee Valley Authority and Bonneville Power Administration, and local 

municipal utilities are specifically exempt from general regulation by FERC.

Hundreds of companies are registered with FERC as wholesale power 

suppliers. While some own their own power plants, marketers often do not; 

instead they buy power from multiple suppliers on long-term or spot-market 

bases, then re-sell it. Brokers arrange transactions, but never actually take 

ownership of the electricity.

4.5.3. Non-Utility Generators

A non-utility generator (NUG), or independent power producer (IPP), owns 

one or more power plants but does not provide retail service. It may sell its 

power to utilities, to marketers, or to direct-access consumers through brokers. 

Sometimes a NUG will use a portion of the power it produces to operate its 

own facility, such as an oil refinery, and sell the surplus power. Some enter 

into long-term contracts, while others operate as merchant generators, selling 

power on a short-term basis into the wholesale market. Some NUGs are 

owned by parent corporations that also operate utilities; in this situation, the 

regulator will normally exercise authority over affiliate transactions.

4.5.4. Consumer-Owned Utilities (COUs).

Consumer-owned utilities, including munis, co-ops, and public power districts, are often distribution-only entities. Some procure all of their power from 

large investor-owned utilities, some from federal power-marketing agencies. 

Groups of small utilities, mostly rural electric cooperatives and munis, 

have formed generation and transmission cooperatives (G&Ts) or joint action 

agencies to jointly own power plants and transmission lines. By banding 

together, they can own and manage larger, more economical sources of 

power, and the G&Ts may provide power management services and other 

services for the utilities. Such G&Ts typically generate or contract for power 

on behalf of many small-sized member utilities, and often require the 

distribution cooperatives to purchase all their supply from the G&T. 

A significant number of COUs do own some of their own power resources, 

which they augment with contractual purchases, market purchases, and/

or purchases from G&Ts. A few COUs own all their supply, and sell surplus 

power to other utilities.16

16 The 24 largest consumer-owned utilities are organized through a trade and lobbying group 

known as the Large Public Power Council, or LPPC. These utilities collectively own about 

75,000 megawatts of generation. www.lppc.org
14

Electricity Regulation in the US: A Guide

4.5.5. Retail Non-Utility Suppliers of Power 

Beginning in about 1990, Britain and Wales began restructuring their 

utilities to allow direct access by letting customers choose a power supplier 

competitively and pay the utility only for distribution service. Under 

restructuring, utilities may provide combined billing for both the distribution 

service (which they provide) and for the power (which is supplied by others). 

(The term retail electricity service is widely used overseas to mean the business 

that actually interacts with the consumer, issuing bills and collecting revenues. 

In the U.S., distribution utilities perform these functions almost exclusively.)

After 1994 the British experiment was followed by some U.S. states, now 

including California, Illinois, Texas, and most of New England. In most cases, 

investor-owned utilities in these states had previously owned power plants, 

but sold them to unaffiliated entities, or transferred them to non-regulated 

subsidiaries of the same parent corporation. 

These states made provisions for a default supply — also referred to as 

basic service — for those consumers that do not choose a competitive 

supplier, or whom the competitive market simply does not serve. While 

a significant percentage of large industrial-power users are direct-access 

customers, most residential and small-business consumers are served by the 

default supply option.17 

Source: www.eia.doe.gov/cneaf/electricity/page/restructuring/restructure_elect.html

Not Active

Active

Suspended

17 America’s experience with retail competition in supplying electricity has revealed that the costs 

of acquiring and administering the accounts of low-volume users generally exceed the profit 

margins that sales of the power as a commodity, separate from distribution, allow.

Figure 4-3: 

States With Restructuring Activity As of 2010
15

Electricity Regulation in the US: A Guide

In states that have restructured their retail electric markets, separate 

companies exist to sell commodity electricity to local individual consumers. 

Some companies specialize in selling “green” power from renewable energy, 

while others specialize in residential, commercial, or industrial service. These 

suppliers may own their own power plants, buy from entities that do, or buy 

from marketers and brokers.

4.5.6. Transmission

Power from these various resources is distributed over high-voltage transmission networks, linked into three transmission synchronous interconnections

(sometimes termed interconnects) in the continental United States. These are 

the Eastern Interconnection, covering east of the Rockies, excluding most of 

Texas, but including adjacent Canadian provinces; the Western Interconnection, from the Rockies to the Pacific Coast, again including adjacent Canadian 

provinces; and the Electric Reliability Council of Texas (ERCOT), covering 

most of Texas. 

Because 47 states (excluding ERCOT, Hawaii, and Alaska) have interconnected transmission networks, FERC sets the rates and service standards for 

most bulk power transmission. More recently, FERC has been granted federal 

authority over the siting of transmission facilities in certain areas designated 

under federal law as having insufficient facilities to provide reliable service.18

Figure 4-4: 

Three Synchronous Interconnections

Source: USDOE http://www.eia.doe.gov/electricity/chg_stru_update/chapter3.html

18 FERC was given limited authority in the Energy Policy Act of 2005 to step in where state siting 

authorities have withheld approval for transmission lines for a period of at least one year. 

Western 

Interconnect

Eastern 

Interconnect Texas 

Interconnect

WSCC

ERCOT

MAPP

SPP

SERC

MAIN

ECAR

NPCC

MACC

FRCC
16

Electricity Regulation in the US: A Guide

4.6. Managing Power Flows Over the Transmission Network

Because large batteries and pumped storage dams are very expensive, 

electricity cannot be stored economically — so it must generally be produced 

at the same time it is consumed. This requires sophisticated control of 

power plants and transmission lines to provide reliable service. A number of 

organizations manage the flow of power over the transmission network. The 

continental U.S. is divided into eight reliability planning areas, under the 

oversight of the North American Electric Reliability Council (NERC). NERC 

has adopted specific reliability standards that are legal requirements under 

FERC authority.

Figure 4-5: 

U.S. Electric Reliability Councils

Source: North American Electric Reliability Council

WECC

MRO

SPP

TRE

SERC

FRCC

RFC

NPCC
17

Electricity Regulation in the US: A Guide

4.6.1. RTOs, ISOs and Control Areas

Within the NERC regions, a multitude of entities actually manage 

minute-to-minute coordination of electricity supply with demand: regional 

transmission organizations (RTOs), independent system operators (ISOs), 

and individual utility control areas.

Regional transmission organizations and independent system operators 

are similar. Both are voluntary organizations established to meet FERC 

requirements. ISO/RTOs plan, operate, dispatch, and provide open-access 

transmission service under a single tariff. The ISO/RTO also purchases 

balancing services for the transmission system. 

To accomplish their mission, ISO/RTOs must have functional control of 

the transmission system. Their purpose is to foster competitive neutrality in 

wholesale electricity markets and reliability in regional systems. 

In 1996, FERC articulated 11 criteria that ISOs would need to meet in 

order to receive FERC approval.19 Four years later, FERC had approved (or 

conditionally approved) five ISOs, but it had also concluded that further 

refinements were needed to address lingering concerns about competitive 

neutrality and reliability. In 1999, FERC issued Order 2000 establishing nonmandatory standards for RTOs.20 Again, it did not mandate an obligation to 

form RTOs; instead, it simply laid out the 12 elements that an organization 

would have to satisfy to become an RTO. Many of features mirrored the 

earlier ISO requirements. As of October 2010, seven non-profit organizations 

Source: FERC www.ferc.gov/

industries/electric/indus-act/rto/rto-ma

Figure 4-6: 

Regional Transmission Organizations

19 Order 888, FERC Stats. & Regs., (1996).

20 Order 2000, FERC Stats. & Regs., (1999).
18

Electricity Regulation in the US: A Guide

had been approved as either an ISO or an RTO.21

Some parts of the country are served by RTOs, and some by ISOs. Some 

are not served by either.

Some smaller grid areas within each NERC reliability planning area are 

managed by individual utilities, mostly large investor-owned ones, and some 

by the federal power marketing agencies. These are called control areas or

balancing authorities. In the Western interconnection, there is no region-wide 

RTO or ISO (only California has an ISO), and the individual control-area 

operators must coordinate with each other to ensure regionwide reliability of 

service.

Figure 4-7: 

U.S. Control Area Operators

4.7. Natural Gas Utilities

Most natural gas utilities do not own their own gas wells. Utilities typically 

operate as distribution-only entities, buying gas from multiple suppliers 

over multiple pipelines to serve their retail consumers. Like electric utilities 

under restructuring, most natural gas utilities also allow larger consumers to 

Source: USDOE; http://www.eia.doe.gov/electricity/chg_stru_update/fig8.html

21 PJM is registered as a general Limited Liability Corporation. However, it is not profit-driven, 

and is structured in a way that makes it operate more like a not-for-profit entity than a forprofit corporation. For an analysis of PJM’s corporate governance model see LAMBERT & 

IHM LLP, Principles of Corporate Governance and PJM’s
19

Electricity Regulation in the US: A Guide

purchase gas directly from wholesale gas suppliers, and pay the local utility to 

deliver the gas from the interstate pipeline. 

However, unlike distribution-only electric companies, gas utilities typically 

buy gas from suppliers, then pass the cost through to consumers in rates 

without any additional markup or “profit” component. It is common for 

gas utilities to sell “bundled” supply and distribution service to residential 

and small commercial customers, but sell only “transportation” service to 

large users, leaving these customers to negotiate gas-supply contracts with 

marketers and brokers.

Figure 4-8: 

2008 U.S. Retail Sales of Electricity By Type Of Utility

Type of 

Utility

Number of 

Utilities Consumers

Sales

(MWh)

2008 Revenue 

x $1000

Average 

$/kWh

Investor-Owned 211 94,996,996 2,229,654,009 $215,122,267 $0.096

Public 1,948 20,747,699 558,814,282 $49,178,880 $0.088

Cooperatives 938 18,167,208 392,103,539 $36,631,821 $0.093

Power Marketer 70 6,313,397 212,354,909 $25,331,745 $0.119

Total: 3,159 140,225,380 3,392,926,739 $326,263,913 $0.096

Source: USEIA 2008 Data 

For more details: 

U.S. Department of Energy, 2002, A Primer on Electric Utilities, 

Deregulation, and Restructuring of U.S. Electricity Markets.

www1.eere.energy.gov/femp/pdfs/primer.pdf
20

Electricity Regulation in the US: A Guide

5. The Regulatory Commission

Most state regulatory commissions and FERC follow generally 

similar procedures. Local regulatory bodies that govern 

COUs, however, can use very different processes. Regardless 

of the procedures or standards followed, the regulatory body 

ultimately performs the same basic functions in all cases, by:

• determining the revenue requirement;

• allocating costs (revenue burdens) among customer classes22;

• designing price structures and price levels that will collect the allowed

revenues, while providing appropriate price signals to customers;

• setting service quality standards and consumer protection requirements;

• overseeing the financial responsibilities of the utility, including reviewing

and approving utility capital investments and long-term planning; and

• serving as the arbiter of disputes between consumers and the utility.

This section discusses the structure and organization of the regulatory 

commissions. Later sections discuss how they actually operate.

5.1. Commission Structure and Organization

Most state commissions consist of three or five appointed or elected 

commissioners and a professional staff.23 The staff may carry out some or all 

of the following functions:

• managing their own personnel, facilities, operations: administrative staff;

• conducting hearings: administrative law judges, hearings examiners,

attorneys;

• analyzing rate filings through testimony (usually pre-filed): economic,

accounting and engineering staff;

22 While data is reported to the USEIA in only three classes, Residential, Commercial, and 

Industrial, there is no uniformity in how customers are classified. Nearly all utilities place 

residential consumers in a separate class. Some try to separate commercial from industrial 

consumers, while others organize business users by size or voltage. Many have separate 

classes for agricultural and government consumers. 

23 The state commissions and FERC are organized through the National Association of 

Regulatory Utility Commissioners, or NARUC. www.naruc.org
21

Electricity Regulation in the US: A Guide

• enforcing rules and tariffs: compliance staff, attorneys; and

• providing technical assistance to the commissioners: advisory staff,

attorneys. 

The California PUC is organized along functional lines. Although it is 

larger than most state commissions, its organizational chart provides an 

illustrative overview of the range of functions that a commission performs. 

Figure 5-1: 

California PUC Organizational Structure

Not every commission carries out each of these functions. In some states, 

the commission staff does not prepare any evidence of its own. A few states 

include the consumer advocate (discussed in more detail shortly) within the 

commission — but in most states that have a consumer advocate, that office 

is located in a separate agency, often in the attorney general’s office. 

In some states, the commissioners actually sit through hearings and listen 

to the evidence, asking questions and ruling on motions. In other states, the 

hearings are conducted before a hearing officer (sometime called a hearing 

examiner), typically an attorney sitting in the role of a judge, who then writes 

a proposed order to the commissioners. The commissioners then may only 

hear or review arguments on the proposed order before rendering a decision. 

In some states, both approaches are used.

Governor

General 

Counsel

Chief 

Administrative 

Law Judge

President

Executive

Director

Director

Division of

Ratepayer

Advocates

Deputy Executive 

Director for 

Administration 

and Operations

Deputy Executive 

Director for Policy

Commissioner Commissioner Commissioner Commissioner

Consumer 

Services & 

Information

Consumer 

Protection & 

Safety

Information & 

Management 

Services

Water 

& Audits

Strategic 

Planning

Office of 

Governmental 

Affairs

Communications Energy
22

Electricity Regulation in the US: A Guide

5.2. Appointed vs. Elected

In the majority of states, the commissioners are appointed by the governor, 

subject to confirmation by the legislature. However, a number of states have 

elected commissioners. In some of the states with elected commissioners,24

very strict rules govern campaign contributions and conflicts of interest. Most 

commissioners serve terms of four to six years. In some states there are limits 

to how many consecutive terms a commissioner may serve. 

5.3. Limited Powers 

Commissions are limited-power regulators. Their authority is defined by 

law, and their decisions are subject to appeal to the state courts (or federal 

court, in the case of FERC). In general, courts will defer to the expertise of 

the regulators; but if they find that regulators have exceeded their statutory 

authority, misinterpreted the law, or conducted an unfair process, they will 

take appropriate remedial action. 

In a few states, the regulatory agency is established in the state constitution 

and has constitutional duties and powers beyond the scope of legislative 

authority, although the legislature may augment the agency’s authority or 

duties through legislation. A commission that is granted specific authority by 

the legislature in statute may be authorized or directed to promulgate rules. 

Statutes govern the affairs of state and federal agencies. The authority to make 

rules is delegated to agencies by the executive or legislative branch. Rules 

implement statutory mandates, and provide guidance on how the law is to be 

carried out. The rules, once adopted, have the force of law. In general, state 

commissions do not regulate consumer-owned utilities, but there are many 

exceptions. 

5.4. Consumer Advocates

Most states have a designated consumer advocate. Many of these are 

housed within the state attorney general’s office, but some are located in 

other agencies or are stand-alone offices with leaders appointed either by 

the governor or the attorney general. The consumer advocate represents the 

public in rate proceedings, and generally has a budget for some technical 

staff and expert consultants. Some consumer advocates are charged with 

representing all customers (or at least those not otherwise adequately 

24 The elections may be statewide or by district. In South Carolina, commissioners are elected 

by the state senate.
23

Electricity Regulation in the US: A Guide

represented), while others are explicitly limited to residential and, possibly, 

commercial customer classes. Consumer advocates tend to focus on the 

total revenue requirement, the allocation of that revenue requirement 

between customer classes, and rate design. They typically do not concern 

themselves with environmental impacts or costs, except where those costs are 

internalized in the costs of providing service.25

5.5. COU Regulation

Consumer-owned utilities (COUs) typically have very different regulatory 

structures. City utilities (“municipals” or “munis”) are generally subject to 

control by the City Council or a special board or committee that may or may 

not ultimately answer to the City Council. Public utility districts generally 

have dedicated boards, elected by the voters at large. Cooperatives generally 

have dedicated boards, elected by the consumers of the utility (including 

business consumers). In general, COUs have much more streamlined 

processes for setting rates and policies —and sometimes no visible process at 

all, except for a decision by the relevant body in open session. 

In some states, the legislature has given the state commission full 

regulatory authority over cooperatives, and in a few cases, limited authority 

over munis. 

25 The state consumer advocates are organized the National Association of State Utility 

Consumer Advocates, or NASUCA. www.nasuca.org
24

Electricity Regulation in the US: A Guide

6. What Does the Regulator 

Actually Regulate?

Different regulators control different parts of the utility industry. 

Some of this is done through legislative-style rulemaking, and some 

through a quasi-judicial hearings process.

At the federal level, FERC has authority over hydropower licensing, 

interstate transmission, and wholesale power sales, although in Texas, Alaska, 

and Hawaii, where there are limited (or no) interstate connections26, it 

only regulates licensing for construction and operation of power-producing 

dams.27 FERC transmission regulation is discussed in Section 10. Nuclear 

power plant design, construction, operational safety and nuclear material are 

regulated by the Nuclear Regulatory Commission.

The state regulatory commission normally regulates all investor-owned 

utilities in a state. A few exceptions exist where cities have regulatory 

authority over IOUs (in some cases, pre-dating statehood). In most but not 

all states, municipal utilities and public utility districts are not subject to 

any economic regulation by the state utility regulator. In about 20 states, 

cooperatives are subject to some form of state regulation.

Depending on state law, local cities and counties may control local 

transmission and power plant siting. In most states, however, one or more 

state agencies are responsible for issuing permits necessary to build and 

operate generation and transmission, pre-empting local authorities. The local 

government within which the utility operates generally also regulates such 

matters as the location of poles and overhead wires, and coordination with 

other utilities on construction. 

26 An interconnection encompassing multiple states is considered to be in interstate commerce, 

and therefore within FERC’s jurisdiction when the power flows on both sides of the state 

line are synchronous. To avoid FERC jurisdiction, Texas (through ERCOT) has limited 

interconnection across state lines to so-called back-to-back DC interconnections, through 

which power is converted from alternating current to direct current, transferred to the 

adjacent synchronous interconnection, and then converted back to alternating current. 

In this case, the transaction over the DC intertie is actually FERC jurisdictional, but the 

interconnection behind the DC intertie in Texas is not considered to be in interstate 

commerce.

27 Hydropower regulation is beyond the scope of this guide. More information on the regulation 

of power producing dams may be found at www.ferc.gov/industries/hydropower.asp.
25

Electricity Regulation in the US: A Guide

Federal, state, and local environmental regulators have authority over 

air and water emissions and land disposal of waste from power plants, but 

this environmental regulation is largely beyond the scope of this guide. 

Federal regulators also have authority over projects on federal land, or which 

are undertaken by federal governmental agencies.28 Additionally, federal 

regulators have authority over off-shore wind projects and projects under the 

control of federal management agencies.29

The balance of this section deals with the role of the state utility regulatory 

commission, although the local utility regulators for COUs generally have the 

same set of powers.

6.1. The Revenue Requirement and Rates

The first and best established functions of the state commission are to 

determine a utility’s revenue requirement and to establish the prices or rates 

for each class of consumers. The process for determination of the revenue 

requirement is discussed in detail in Section 8. However, in the case of 

industrial customers with direct access to high-voltage transmission lines, 

transmission rates set by FERC may represent almost the consumer’s entire 

bill from the local electric utility.

6.2. Resource Acquisition

The commission generally has some authority over the utility’s choice of 

power sources to serve its consumers, but that authority varies greatly from 

state to state.

Portfolio Standards: Many state legislators, commissions, and voters have 

adopted energy portfolio standards, which require utilities to meet a 

certain percentage of their sales with designated resource types, generally 

28 The Energy Policy Act of 2005 calls for utility-grade wind and solar energy development on 

federal land in Section 211, and also calls for west-wide and east-wide energy corridors for 

oil, gas, and hydrogen pipelines and electricity transmission and distribution facilities on 

federal land in Section 368. The National Environmental Policy Act of 1969 (NEPA) requires 

federal agencies to consider environmental impacts of their proposed actions and evaluate 

reasonable alternatives to those actions. Such an impact would be evaluated through an 

environmental impact statement (EIS). The Energy Policy Act therefore triggers a review 

under NEPA for large-scale energy projects. Additionally, natural gas pipelines and other 

projects undertaken by the federal government may trigger a NEPA review.

29 For example, CapeWind, the off-shore wind farm off the coast of Cape Cod, is currently 

undergoing review under NEPA, the Massachusetts Environmental Policy Act, and other 

environmental statutes. Projects undertaken by federal management agencies, such as the 

Bonneville Power Administration, also trigger review by federal regulators.
26

Electricity Regulation in the US: A Guide

a defined set of renewable ones.30 Some states have explicitly required 

utilities to meet a portion of power needs by reducing demand through 

energy efficiency programs.

Integrated Resource Planning (IRP): An IRP is a long-term plan prepared 

by a utility to guide future energy efficiency, generation, transmission, and 

distribution investments. Some commissions require IRPs and review the 

plans. IRP is discussed in Section 13.

Construction Authorization: Many state commissions have the authority 

to consider and approve, or reject, proposed power plants. Some 

states require a specific approval (sometimes called a certificate of public 

convenience and necessity), while others may use an integrated resource 

planning (IRP) process to determine whether construction of a power 

plant is necessary, or some combination of the two. (See Section 12 for a 

discussion of these.)

Prudence: Once a power plant or other capital project is completed, the 

commission may conduct a prudence review to determine if it has been 

constructed or implemented as proposed, according to sound management 

practices, and at a reasonable cost and with reasonable care. This review 

may compare utility performance to a previously reviewed set of goals, or 

it may be prepared on an ad hoc basis for a specific project.

Energy Efficiency: Energy efficiency is typically the least expensive way 

to meet consumer needs for energy services. Some states have adopted 

mandatory energy efficiency standards for buildings, appliances, and 

other equipment. Utility-funded investments in energy efficiency pay for 

measures that benefit the utility system, but the energy efficiency measures 

would not otherwise be implemented by consumers for a host of possible 

reasons. Even when investments in efficiency are not required by state law, 

most state regulators have adopted policies and principles that set criteria 

for making investments in efficiency measures, and provide a mechanism 

for recovery of the investments made by utilities (or other designated 

administrator).

30 About half of the states, totaling about 75% of the nation’s population, have renewable 

portfolio standards of some type. The definition of eligible resources varies by state. See 

http://apps1.eere.energy.gov/states/maps/renewable_portfolio_states.cfm#map.
27

Electricity Regulation in the US: A Guide

6.3. Securities Issuance

When a utility seeks to issue additional stock or bonds to finance or 

refinance its investment in utility facilities, in many states it must get 

permission from the regulator. This ensures that the terms of the securities 

are reasonable, and also ensures that the utility does not indebt itself in such 

a way as to harm its access to capital. Access to capital at reasonable cost is 

essential to the utility’s ability to provide safe and reliable service, especially 

in the event of a major failure (e.g., storm damage or an unplanned plant 

outage) or for major construction projects.

A merger between utilities, or acquisition of a utility by another 

corporation, involves a form of securities issuance, and therefore normally 

requires approval of the regulator. Typically mergers must pass a public 

interest test. In some states a no-harm standard is imposed, while in others a 

net benefit standard must be met.

6.4. Affiliated Interests

The regulator generally has authority over the relationship between 

the utility and affiliated interests, meaning a parent corporation, another 

subsidiary of the utility’s parent corporation, or a separate company that 

is in some other way deeply intertwined with the utility. These regulations 

are intended to prevent self-dealing — where, for example, the utility pays 

above-market prices for services provided to it by an unregulated affiliate 

or, conversely, it provides services to its unregulated affiliate at belowmarket costs. In both circumstances, the utility is taking advantage of its 

captive monopoly customers to give its unregulated affiliate an economically 

unjustified advantage over its competitors. Where regulators have authority 

over affiliated-interest activities, they generally take care to ensure that 

utility consumers are not harmed by the often risky actions taken by the 

unregulated affiliates.31

6.5. Service Standards and Quality

Commissions adopt specific standards for voltage, frequency, and other 

technical requirements in electric service, generally based on industry 

standards. This is generally limited to the distribution service, not to 

31 Perhaps the most extraordinary of these situations was when Enron went bankrupt. Enron 

owned several utilities, including Northern Natural Gas and Portland General Electric. While 

the consumers of these utilities were adversely affected in terms of price and reliability by the 

Enron collapse, utility regulators took steps to ensure that catastrophic impacts did not occur.
28

Electricity Regulation in the US: A Guide

transmission, which is subject to FERC regulation. Commissions may also 

adopt regulations governing the terms on which service is offered, the charges 

that apply when lines are extended, and the process by which customers 

may be disconnected for nonpayment. A few regulators have implemented 

minimum energy efficiency standards for new homes and commercial 

buildings. Many commissions have adopted service quality indices (SQI) 

based on specific indicators to measure the quality of utility service, such 

as the frequency and duration of outages, the speed with which companies 

respond to telephone inquiries, the speed with which they respond to unsafe 

conditions, and so on. Service quality is discussed further in Section 18.

6.6. Utility Regulation and the Environment

Utility regulation and environmental regulation are increasingly recognized 

as unavoidably intertwined.32 In most states, the utility regulator is tasked by 

statute as an economic regulator, leaving the enforcement of environmental 

laws to other agencies. However, in many states the regulator has evaluated 

environmental implications and risks to encourage utility investment in lowpollution alternatives such as renewable resources and energy efficiency in 

recognition of the large environmental impacts of the electric sector. 

Because the future cost of power to consumers will probably be 

significantly affected by the environmental impacts of power production, 

utility regulators are increasingly paying attention to utility resource 

decision-making through the IRP process. (See Section 13.) Decisions by 

environmental regulators also affect utility investment, as states implement 

plans to meet EPA standards for air, land, and water quality. Utilities may 

seek to recover the costs of their investments through utility regulators; or, 

in restructured states, they may pass along the costs of their investments 

through regional electricity markets. In fact, in a few states the utility 

regulator has a direct role in some aspects of environmental regulation.33

32 See: Clean First, Regulatory Assistance Project, www.raponline.org/docs/RAP_CleanFirst_

AligningPowerSectorRegulation_2010_09_17.pdf

33 For example, in Washington State, the Energy Facilities Site Evaluation Council (EFSEC) is 

the permitting agency for major power plants. The Washington Utilities and Transportation 

Commission is one of the agencies holding a voting seat on EFSEC.
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Electricity Regulation in the US: A Guide

7. Participation in the 

Rulemaking Process

Utility regulators provide multiple avenues for public participation in 

the process. Some opportunities are complex and legalistic, while 

others more clearly invite citizens’ input.

This section describes the various forums through which consumers, 

environmental advocates, business groups, and others can participate in the 

regulation of utility prices, policies, and resource planning.

7.1. Rulemaking

Commissions make two types of rules. Procedural rules guide how the 

regulatory process works; operational rules govern how utilities must offer 

service to consumers. There is normally an opportunity for public comment 

when rules are proposed or amended. In some states, the legislature or the 

attorney general may have authority to review and approve proposed rules.

7.2. Intervention in Regulatory Proceedings

Intervention in a formal regulatory proceeding is probably the most 

demanding form of citizen participation. Utility hearings are normally held 

under state administrative law rules, and function very much like a courtroom. 

While an individual may usually participate without an attorney, requirements 

of the rules of procedure and evidence must nonetheless be met.

7.3. Stakeholder Collaboratives

In the past decade or so, many commissions have formed stakeholder 

collaboratives to engage utilities, state agencies, customer group 

representatives, environmental groups, and others in a less formal process, 

aimed at achieving some degree of consensus on dealing with a major issue. 

These collaboratives may meet for a few months or more, then collectively 

recommend a change to regulations, tariffs, or policies.
30

Electricity Regulation in the US: A Guide

7.4. Public Hearings

Utility regulators hold two types of public hearings. When a rate case is 

underway, the entire process of cross-examination of witnesses is generally 

termed a public hearing, but is usually a very technical process not really 

designed for public involvement. As discussed in Section 8, one element of 

these may be an opportunity for the general public to speak on the issues in 

the rate case.

In addition, however, regulators often hold public hearings on matters 

pending before the commission in a policy investigation or rulemaking 

context. Public hearings of this type offer the commission an opportunity to 

hear opinions of the public on the particular issue before the commission. 

Anyone may speak at a public hearing. Public testimony at these types of 

hearings is normally not subject to the evidentiary hearing process, meaning 

members of the public will not be cross-examined by an attorney or the 

commission. The commission considers all of the information presented at 

the hearing, including testimony from the public.

Many regulatory bodies hold periodic “open mike” sessions where any 

person may speak to any issue that is not currently before the commission in 

a formal proceeding. These are opportunities to suggest such things as new 

approaches to regulation, new utility programs, or new evaluation standards 

to be applied to utility performance. There is typically no obligation for 

the commission or any party to give a formal response to an open mike 

presentation.

7.5. Proceedings of Other Agencies Affecting Utilities

Many governmental agencies other than the utility regulator have 

proceedings that affect utilities. State energy offices34 may make rules affecting 

resource planning, energy efficiency, or renewable resources. Environmental 

and land use regulators may control the siting, construction, and operation 

of utility facilities. Safety and labor standards may be administered by other 

separate agencies, and each type of public agency with regulatory authority 

may have its own rules, processes, and procedures. 

For more details:

NW Energy Coalition, 1993, Plugging People Into Power.

www.raponline.org/docs/NWENERGY_PluggingPeopleIntoPower_1993.pdf

34 Each state has an agency designated as the recipient of federal State Energy Program (SEP) 

funding. In most states this is a separate agency, but in some it is incorporated in a larger 

agency. Most are separate from the utility regulator. The state energy offices are organized 

under the National Association of State Energy Officials (NASEO). See www.naseo.org/.
31

Electricity Regulation in the US: A Guide

8. Procedural Elements of 

US Tariff Proceedings

A commission’s approved conditions, terms, and prices of utility 

services are published in document called a tariff. Regulatory 

commissions primarily review utility rates and these other elements 

of their service in general rate cases. In these rate adjustment 

proceedings, the commission determines a new rate base, a new rate of 

return, and new rates for most or all customer classes.

Some states require a general rate case on a fixed schedule, but most do not. 

While most utilities file for general rate increases every two to five years, some 

utilities have gone more than 10 years without a general rate case. The commission normally has the authority to initiate a rate review on its own motion, 

but this is quite rare. In theory, an individual consumer submitting a formal 

complaint that the utility’s rates were not in compliance with the requirements 

of law (which generally say that that rates should be “fair, just, and reasonable”) 

could trigger a general rate review, but this almost never happens. 

When an investor-owned utility applies to its regulator for a rate or 

policy change, it triggers a well-established formal regulatory proceeding. 

Understanding the steps of the process in advance can help an interested 

party decide if, how, and when to take action. Figure 8 shows a typical 

procedural schedule. 

Figure 8: 

Typical Schedule for a Major Rate Case

Activity Calendar Date Months From Filing Date

Notice of Intent to File 15-Jan -2

Initial Filing of Tariffs and Evidence 15-Mar 0

Discovery Period Ends 15-Jun 3

Staff and Intervenor Evidence Due 1-Jul 3.5

Rebuttal Evidence Due 1-Aug 4.5

Rebuttal Discovery Period Ends 15-Aug 5

Expert Witness Hearings Sept 1-20 6

Public Witness Hearings Sept 25-27 6.5

Briefs Due 1-Nov 7.5

Commission Decision 15-Dec 9
32

Electricity Regulation in the US: A Guide

This section describes the procedural elements of a general rate 

proceeding: who does what and when. It is intended to help the reader 

understand the sequence and other formalities of a general rate case.

8.1. Filing Rules

Most commissions have specific filing rules that specify the information 

and public-notice requirements associated with a utility’s request for a change 

in rates or other tariff terms. For example, the Washington Utilities and 

Transportation Commission’s rules define a “general rate case” as one where the 

utility is requesting more than a 3% increase in overall revenues, and requires 

detailed information to be submitted with the initial request. Applications 

involving smaller changes in rates, or changes affecting only a small number of 

consumers, are typically subject to less-detailed filing requirements.

8.2. Parties and Intervention

There are statutory parties — those whose right to participate in a 

commission proceeding is established in law — such as the utility, the 

commission staff, and the consumer advocate. Other participants, or 

intervenors, such as representatives of industrial consumers, low-income 

consumers, and environmental groups, are granted the right to participate 

by the commission, sometimes after demonstrating a particularized interest 

that is not better represented by the statutory parties. Most commissions 

have rules that set out the terms of permissive intervention, when petitions 

to intervene must be filed (typically at the very beginning of the process), 

and the intervenors’ obligations. Typically intervenors must attend hearings, 

answer discovery requests (see next section), file required documents in a 

timely fashion, and be respectful of the legal aspects of the process.

A federal law, the Public Utility Regulatory Policies Act (PURPA), gives 

consumers of large electric utilities a statutory right to intervene in any 

proceeding relating to rates where issues addressed in PURPA (relating mostly 

to rate design) are considered.35 While this law appears to guarantee a right to 

intervene, it does not proscribe the commission (or local regulator of a COU) 

from setting rules regarding intervention, or from determining whether the 

PURPA ratemaking standards are at issue in any given proceeding.

35 16 U.S.C. §2631 PURPA has three major parts. First, it required state commissions to 

“consider and determine” on a one-time basis whether certain ratemaking standards were 

appropriate. Second, it provides for a means of consumer intervention in the regulatory 

process. Third, it requires utilities to purchase power at “avoided cost” from “qualifying 

facilities,” meaning small power plants owned by independent power producers. This last 

element of PURPA is the one most often identified with the Act.
33

Electricity Regulation in the US: A Guide

8.3. Discovery

When a utility seeks a change in the tariff and the commission schedules 

a hearing, the utility must provide information to the parties. Commissions 

establish guidelines as to the form in which parties may request information 

from other parties (as well as the utility). These are called discovery requests, 

interrogatories, or information requests. The commission also sets deadlines for 

the required responses to these requests.

Some of the information requested may be commercially sensitive or 

protected from public disclosure by law. In these situations, the utility may 

refuse to provide the information, or may request a confidentiality agreement.

The commission then decides what must be disclosed and the terms of 

disclosure.

8.4. Evidence

All parties to a tariff proceeding may submit evidence, presented by 

witnesses. Evidence normally takes the form of pre-filed written testimony 

and exhibits. Testimony expresses the position of the witness, while exhibits 

contain detailed factual support, technical analysis, and numerical tables and 

worksheets. Before 1980, testimony was often delivered orally at the hearing, 

and in many states it is still written in question-and-answer format as though 

it were a transcript of oral direct examination by an attorney. 

Direct testimony and exhibits are normally filed by the utility at the time it 

makes its tariff request. The commission then sets a schedule for when other 

parties must file their direct evidence. The applicant, normally the utility, 

is allowed to submit rebuttal evidence, which is evidence that the utility 

provides to rebut some evidence or testimony submitted by another party. 

Sometimes additional rounds of surrebuttal evidence — evidence in response 

to rebuttal evidence — are allowed. 

8.5. The Hearing Process

The hearing process allows the attorneys, or non-attorney representatives, 

of the parties to ask questions “on the record” of the expert witnesses. All of 

the evidence is given under oath (subject to the penalties of perjury), and 

recorded in a transcript.

In most states, after all the direct and rebuttal evidence is filed, all of the 

witnesses are scheduled in a single hearing process that may take days or 

weeks. Some state commissions hold hearings in stages, as the evidence is 

submitted: the applicant’s direct evidence first, followed by a gap in time, 

then the testimony of other parties, then finally the rebuttal evidence.
34

Electricity Regulation in the US: A Guide

8.5.1. Expert Testimony

Persons presenting detailed technical testimony and exhibits under oath 

are typically called expert witnesses. Expert testimony is ordinarily scheduled 

in advance, so that the other parties can be prepared to question specific 

witnesses on specific dates. Sometimes commissions will group witnesses by 

topic — for example, scheduling all of the cost-of-capital witnesses during 

a single day or week. The schedule is generally made after asking each 

party how many hours of questions they will have for each witness, and in 

consideration of the schedule of out-of-town witnesses.

Expert witnesses may be questioned as to their actual expertise on the 

topic. While few commissions completely dismiss evidence if a witness is 

found to lack genuine expertise, such a finding definitely affects the weight 

given to the testimony. Intervenors must make certain that their witnesses do 

not go beyond the scope of their expertise.

8.5.2. Public Testimony

Nearly all commissions also set aside a time, in hearings on major rate 

increases or other important proceedings, for testimony from the general 

public. Sometimes these are held at the beginning of the process, as soon 

as the applicant’s direct evidence is available. Sometimes they come after all 

of the parties have testified, and the issues have become more focused; this 

option is generally more effective for intervenors who want their members 

and supporters to speak at the public hearing.

In some states, members of the public speak under oath, but they are 

not required to be experts and they may speak to any topic being addressed 

in the proceeding. However, it’s important that supporters understand the 

basics of the process: hearings are conducted like a court proceeding, and 

a courtroom demeanor is important. The commission may not give the 

same weight to public testimony as it does to expert testimony, but there is 

no question that public participation in the hearing process can affect the 

result. A large turnout with a clear, concise, relevant message can inform a 

commission’s decision where the evidence and law give the commission some 

discretion to craft an equitable resolution. 

8.6. Settlement Negotiations

Once the testimony of all parties is filed (or even before), it is common for 

the parties to enter into settlement negotiations, with the goal of presenting 

an agreed position on all issues (or a partial settlement on some issues) to the 

commission. 

This gives intervenors an opportunity to have an important influence on 

the final result. All parties normally participate in settlement negotiations, and 
35

Electricity Regulation in the US: A Guide

having an all-party settlement is important because it increases the likelihood 

that the commission will approve the settlement and thereby put an end to 

the formal hearing process. This saves all of the parties the time and expense 

of the expert-witness hearings. It also typically gets the utility a rate decision 

sooner than going all the way through the six-to-12-month hearing process.

8.7. Briefs and Closing Arguments

If the proceeding goes all the way through the expert-witness hearing 

stage, the parties file final briefs and/or make final closing oral arguments 

to the commission once the hearings are complete. These summarize the 

evidence and describe how it supports their positions. 

8.8. Orders and Effective Dates

After reviewing the record, the commission will deliberate and issue a final 

order. In some states, the deliberations are open to the public, and in others 

they are not.

In states where the hearing is held before an administrative law judge 

or hearing examiner, the examiner will typically release a proposed order 

detailing a recommended resolution of the contested issues. The parties then 

file written exceptions to the proposed order, indicating where they believe 

the record supports a different conclusion. The proposed order and the 

exceptions are reviewed by the commission, which then issues a final order. 

The order will specify a date when the rates may take effect. 

Generally, the parties have the opportunity to file motions for 

reconsideration or clarification of an order before considering an appeal.

Sometimes a commission will allow rates to take effect prior to the 

conclusion of the proceeding; in these cases, the rates are allowed to go into 

effect subject to refund, meaning that if the commission subsequently decides 

that a lower rate increase is appropriate, the utility will have to refund the 

difference to consumers. This process is sometimes used when the commission 

cannot complete its analysis before the deadline imposed by state law.

8.9. Appeal

Any party that believes the commission has deviated from that which is 

allowed by law may appeal the order to the courts. In general, the courts 

defer to the expertise of the regulatory body, but will reverse or remand 

a decision if they find it clearly violates some principle of law. Nearly all 

appeals from state commissions occur in state court, but some are appealed 

directly to federal courts on federal legal or constitutional grounds.
36

Electricity Regulation in the US: A Guide

9. The Fundamentals 

of Rate Regulation

This section summarizes the analytical process that a regulatory 

commission follows in a tariff proceeding.36

Because commissions are supposed to set rates that provide 

utilities an opportunity to earn a reasonable rate of return after 

expenses, they need to determine the utility’s costs for providing service in 

their state. This includes both the costs associated with the rate base (the 

utility’s investment in facilities and related capital costs, including interest on 

debt and a return on equity) and its operating expenses (labor, fuel, taxes, 

and other recurring costs).

This section is the most technical and lengthy part of this guide. It takes 

the reader through the key elements of a general rate case. These include 

determining the overall level of expenses and investment to be recovered in 

rates, determining the appropriate rate of return (profit and interest), and 

then dividing the required revenue between customer classes and developing 

rates to recover that revenue. It ends with a discussion of a few of the minor 

issues that commissions deal with in these cases. Most states have a process 

that considers all of these issues, although each commission does this a little 

bit differently.

9.1. Functional and Jurisdictional Cost Allocation

Some utilities have multistate operations, are part of holding companies 

with both regulated and non-regulated operations, or have more than one 

regulated service (such as both natural gas and electric operations). In these 

cases, the regulator must first determine what investments and expenses are 

associated with the service that is the subject of the rate case.

36 The terms tariff proceeding, rate proceeding, general rate case, and rate case are used 

interchangeably to refer to the regulatory proceeding wherein a commission considers an 

application for an increase in utility rates —one that increases the total amount of money 

received, and generally applies increases to all or most of the customer classes served by the 

utility. There are limited issue proceedings that may not involve all the analysis of a general 

rate case.
37

Electricity Regulation in the US: A Guide

9.1.1. Interstate System Allocation

When a utility serves more than one state, the commission conducting 

the proceeding must decide which facilities serve its state. Identifying 

distribution facilities and expenses is fairly straightforward, because they are 

located in specific states and serve only customers in that state. Allocating a 

utility’s costs for administrative headquarters, production, and transmission 

investments and expenses can be more controversial. Over time, most states 

have developed methods for interstate allocation that are considered to be fair 

in their jurisdictions, though in rare instances the total amount allowed in 

each state does not add up to the total of the company’s actual operations. In 

the case of some multi-state utility holding companies, FERC determines the 

allocation of generation and transmission costs between jurisdictions.

Commissions split production and transmission costs (including the 

investment in generating facilities and transmission lines, the operating costs of 

those facilities, and payments made to others for either power or transmission), 

based on various measures of usage. Some costs are assigned in proportion 

to each area’s share of peak demand (the highest usage during a period) and 

others according to energy consumption (total kilowatt-hours during a period), 

using principles similar to those employed to allocate costs between customer 

classes. Administrative facilities are generally allocated in proportion to some 

combined measure of the number of customers in the state, the state’s share 

of the utility’s peak demand and energy use, and occasionally its share of total 

utility revenues. Federal taxes are normally divided proportionally, on the basis 

of taxable income, among all states in a system. 

State and local taxes are more complex. Property taxes associated with 

distribution facilities that serve only one state are normally assigned to that 

state. However, a power plant located in one state and subject to property tax 

there may serve consumers in several states; it is fair for all the consumers 

who benefit from the facility to pay their share of its property taxes. 

9.1.2. Regulated vs. Non-Regulated Services

Many utilities are also part of larger corporations that engage in both 

regulated utility operations and non-regulated businesses, which may or may 

not be energy-related. While most costs relate only to specific business units 

such as the electric or gas utility, some are common to all the corporation’s 

activities, such as the expenses for officers and the board of directors, for 

corporate liability insurance, and for headquarters facilities. The commission 

may need to allocate a portion of these administrative costs to the state 

utility, leaving the balance assigned to the parent company or to other states. 

Non-regulated operations are typically riskier business ventures, and the 

commission must carefully allocate the costs so that utility consumers do not 

bear these risks. Allocation of these costs requires an assessment of relative 
38

Electricity Regulation in the US: A Guide

risks and relative benefits, and can become highly contested.

9.1.3. Gas vs. Electric

Utilities that provide both gas and electric service (and sometimes 

telecommunications and even steam heat) need to have their shared 

investments in the rate base and operating expenses separated, so that electric 

rates cover only the costs of providing electric service, and gas rates only 

those of gas service. Formulas that are typically used for dividing the shared 

costs will consider the numbers of customers, the amount of plant investment 

directly associated with each service, the labor expenses associated with 

each service, and the total revenue provided by each service.37 If the service 

territories for electricity and gas are not the same geographically, these 

allocations can be quite complex and controversial. 

9.2. Determining the Revenue Requirement

Most of the evidence in a rate case is directed at determining the revenue 

requirement, or the total amount of revenue the utility would need to provide 

a reasonable opportunity to earn a fair rate of return on its investment, given 

specified assumptions about sales and costs. The utility is most concerned 

with this; the other elements of a rate case divide that total allowed revenue 

among different customer classes and among consumers within classes, and 

do not affect the utility’s overall profit.

The basic regulatory formula for determining the revenue requirement is 

given in Figure 9-1.

Figure 9-1: 

The Basic Revenue Requirement Formula

37 Approaches vary widely from state to state and even utility to utility. This isn’t surprising, 

given that economic theory offers little guidance on the allocation of joint and common costs. 

A commission’s judgment and sense of fairness are called for in exercises such as this.

Rate Base Investment X Rate of Return + Operating Expenses = Revenue Requirement

Each of these is described in greater detail below.

9.2.1. The “Test Year” Concept

Rate cases are based on the concept of a test year, which presents the costs 

and revenues of the utility on an annual basis. The test year may be a recently 

completed actual year, or may be a future, estimated year. All the costs for 

the rate base, operating expenses, and sales revenues are computed for the 

same period, so that total costs can be appropriately compared with total 
39

Electricity Regulation in the US: A Guide

revenues, with the full effects of weather and other annual impacts included, 

to determine if there is a revenue deficiency (or a revenue surplus, implying 

that a rate decrease is appropriate). 

9.2.2. Historical vs. Future Test Years

A historical test year takes as a starting point the actual investments, actual 

expenses, and actual sales of the utility for a recently completed 12-month 

period. The utility proposes adjustments to the recorded data to bring them 

up to date, reflecting changes in costs that have occurred since the test year 

or which are reasonably expected to occur before the new rates take effect. 

A future test year (sometimes called a forecasted test year) is an estimate 

of the same data for a future period, usually based on detailed budgets and 

expected changes in costs that are subject to examination by the commission. 

Typically, rates adopted in a rate case are estimated the first year the rates are 

in effect.38

In either case, the investment in a major addition to the rate base such as 

a new power plant may be reflected in the test year, so that the new rates will 

enable the utility to recover those costs in the future when that plant will be 

providing service, i.e., when it will be used and useful. In general, used means 

that the facility is actually providing service, and useful means that without 

the facility, either costs would be higher, or the quality of service would be 

lower. However, each state has its own regulatory history that determines 

what is allowed to be included.

Finally, the term rate year is sometimes used to denote the first full year in 

which new rates will be effective. This term is used even in historic test-year 

jurisdictions, but typically would be about the same period that would be 

used for a future test year. 

Figure 9-2 depicts a typical period for a historical test year of 2009, a 

rate filing in the second quarter of 2010, consideration of the filing for nine 

months, and both a future test year and a rate year beginning in the second 

quarter of 2011. 

38 Some jurisdictions refer to these adjustments as known and measurable changes. They can be, 

naturally, a subject of debate.

Figure 9-2 

Typical Period for a Historical Test Year

Year 2009 2010 2011 2012 

Month Jan Apr July Oct Jan Apr July Oct Jan Apr July Oct Jan Apr July Oct

Commission

Consideration

Historical Test Year of Rate Case

Rate

Case 

Filing

New 

Rates

Future Test Year

Rate Year
40

Electricity Regulation in the US: A Guide

9.2.1.2. Average vs. End-of-Period

When historical test years are used, the utility may seek to adjust all 

investments and all expenses to the level in effect at the end of the 12-month 

period. This is called an end-of-period rate base. However, traditional 

accounting principles generally recommend using the average rate base for 

the year, because that more accurately reflects the entire time during which 

the revenues were collected. New facilities and expenses may have been 

added during the year to serve new customers that come onto the system, but 

these also generated new revenues. 

9.2.2. Rate Base

The rate base is the total of all long-lived investments made by the utility 

to serve consumers, net of accumulated depreciation. It includes buildings, 

power plants, fleet vehicles, office furniture, poles, wires, transformers, pipes, 

computers, and computer software. 

Traditionally, utilities have only been allowed to add investments to rate 

base once they are completed and providing service to consumers. During the 

construction period, utilities have been allowed to accumulate an allowance 

for funds used during construction (AFUDC), so that when the construction 

is completed and commissioned, they earn a return not only on the money 

invested, but also on the carrying costs during the construction period. 

When construction programs become very large, these carrying charges 

can become a significant financial burden for the utility. To address this, 

utilities have often sought to include construction work in progress (CWIP) in 

rate base during the construction period. This allows them to earn a current 

return, covering the interest and dividends on the capital, even before 

construction is completed. CWIP, then, allows return on the cost of capital 

during construction, while AFUDC defers this accumulated cost of invested 

capital until after the plant is in service.

The inclusion of CWIP in rate base has been extremely controversial 

since the 1970s, when spiraling nuclear and coal construction costs created 

difficult circumstances for utilities, that were stretched thin trying to finance 

additions to the generating capacity. Where CWIP was allowed into the 

rate base, customers paid for interest and shareholder return during the 

construction process; in many cases, the power plants were never finished 

and never provided service, leaving consumers with a share of the dry-hole 

risk. A few states have allowed CWIP for new nuclear construction programs.

The rate base also includes some adjustments for working capital and 

deferred taxes. It may also include adjustments for certain deferred costs 

(as regulatory assets) incurred by the utility in furtherance of regulatory or 

policy objectives. The term rate base is sometimes erroneously used to mean 

the entire revenue requirement, but in fact the term applies only to the 
41

Electricity Regulation in the US: A Guide

investment in long-lived assets used to provide service (adjusted for working 

capital, regulatory assets, and deferred taxes).

The basic formula for the utility’s rate base is given in Figure 9-3. The 

variables entering into the formula are described in more detail below.

Figure 9-3: 

The Rate Base

Total Plant In Service At Original Cost

- Accumulated Provision for Depreciation

= Net Plant in Service

+ Working Capital Allowances

- Accumulated Deferred Taxes

+/-Other Adjustments Approved by the Commission

= Rate Base

Generally, to be allowed in rate base an investment must be both used and 

useful in providing service and prudently incurred. The utility has the burden 

of proving that investments meet these well-established tests, but often enjoys 

presumption of use -and-usefulness and prudence in the absence of evidence 

to refute it. 

Working capital is the amount of cash the utility must have on hand to pay 

its bills when they are due, since consumers will normally not pay their utility 

bills until some time after they receive service.39 While it is not invested in 

hard assets that provide service, the utility is employing this capital for the 

benefit of the consumers, and it is therefore allowed to earn a return on it.40

Deferred income taxes reflect provisions in federal tax laws that allow 

utilities to collect money for taxes years before they actually pay them. 

Consumers have paid these taxes to the utility before the utility pays them to 

the government — so the utility, in effect, has a balance that the shareholders 

and bondholders did not provide; consumers did. Reducing the rate base 

by the amount of the previously paid taxes means that consumers pay lower 

39 Some utilities have moved to pre-payment systems, in which some consumers pay for power 

before they use it. Under these circumstances, a working capital credit (reduction) should be 

applied to the rate base for the customer classes or sub-classes subject to pre-payment.

40 Like all capital, working capital has a time value. If it were not being used to cover the 

utility’s costs until the revenues are received through payment of customers’ bills to cover 

those costs, the capital would be put to other productive uses on which a return can be 

earned. Thus, the return that working capital earns is the opportunity cost of foregoing those 

other uses.
42

Electricity Regulation in the US: A Guide

rates over time, because part of the utility’s investment is being supported 

with ratepayer-supplied funds.

“Other adjustments” may include ratepayer-supplied capital (such as 

payments made for line extensions), allowed construction work-in-progress, 

investments in terminated projects allowed into rates, and other minor 

elements. Some of these reduce the rate base, while others increase it.

9.2.3. Rate of Return

Utilities are allowed to earn a regulated annual rate of return on their rate 

base. Legal precedent requires that rate to be sufficient to allow the utility to 

attract additional capital under prudent management, given the level of risk 

that the utility business faces. Two key U.S. Supreme Court decisions, known 

as Hope41 and Bluefield42, set out the general criteria that commissions must 

consider when setting rates of return.

Several different sources of funding provide capital for the utility, and the 

commission sets different rates of return for each source (shareholder equity, 

bondholder debt, and some others). Debt receives a lower rate of return than 

equity, because the debt holders bear less risk; they have the first call on the 

utility’s revenues after operating expenses, before any dividends can be paid 

to stockholders. Short-term debt also generally carries lower interest rates, 

because the lender is not making a long-term commitment to the utility. 

9.2.3.1. Capital Structure

The utility’s capital structure consists of the relative shares of its capital 

that are supplied by each source: common equity, preferred equity, long-term 

debt, and short-term debt. Because these all have different cost rates, the mix 

greatly affects its overall (weighted) rate of return. In addition, because the 

utility is subject to income tax on its return on equity, and gets an income tax 

deduction for its interest payments on debt, a higher share of equity quickly 

calculates to higher rates for consumers. The commission rules on the capital 

structure because it is an essential element in the calculation of the revenue 

requirement.

In general, U.S. utilities have between 40%-60% debt, and between 40%-

60% equity. There is no “right” level of equity: in Canada, equity ratios are 

more typically around 30%-35%, reflecting higher investor confidence in the 

certainty of utility earnings, so the utility can more easily attract bond investors 

and use lower-cost debt to provide a higher percentage of its total capital.

41 Federal Power Commission vs. Hope Natural Gas Company, 320 U.S. 591 (1944) (“Hope”).

42 Bluefield Water Works and Improvement Company vs. Public Service Commission, 262 U.S. 679 

(1923) (“Bluefield”).
43

Electricity Regulation in the US: A Guide

The commission’s approved capital structure is often different than the 

utility’s actual capital structure, especially where the company has significant 

non-utility operations or has excessive or insufficient equity in its capital 

structure. (In such cases, the approved version is called a hypothetical or 

imputed capital structure.) A utility will sometimes seek an allowed capital 

structure with more equity than its current level, in effect asking to increase 

its equity ratio. This can be problematic, because if it does not actually 

achieve the allowed share of equity, it collects revenues for shareholder equity 

costs (and income tax costs) that it does not actually incur.

9.2.3.2. A Generic Rate of Return Calculation

The basic formula for rate of return (with each element separately 

determined by the commission) is given in Figure 9-3, and Figure 9-4 

provides an example of a rate of return calculation.

Figure 9-3: 

The Generic Rate of Return Formula

Common Equity A % B% A% x B% 

+ Preferred Equity C% D% C% x D%

+ Long Term Debt E% F% E% x F%

+ Short Term Debt G% H% G% x H%

+ Other I% J% I% x J%

= Rate of Return 100% Sum 

Common Equity 45 % 10% 4.50%

+ Preferred Equity 5% 8% 0.40%

+ Long Term Debt 45% 7% 3.15%

+ Short Term Debt 5% 5% 0.25%

= Rate of Return 100% 8.30%

Percentage 

of Capital 

Structure

Percentage 

of Capital 

Structure

Cost of 

Capital for 

Element

Cost of 

Capital for 

Element

Weighted 

Cost of 

Capital

Weighted 

Cost of 

Capital

Figure 9-4: 

Hypothetical Rate of Return Calculation
44

Electricity Regulation in the US: A Guide

9.2.3.3. Cost of Common Equity

The return on (or cost of) common equity is typically one of the most 

hotly contested issues in a rate case, in part because there is no precise way 

to measure it.43 While the cost of debt and preferred stock are usually set 

in advance, and precise data on what the utility will actually pay for those 

sources is known, the return to common stockholders must be determined 

in light of market conditions at the time of the rate case. Conceptually, the 

allowed return on equity is the return that the utility must offer to investors 

to get them to invest in the company. In recent years, most commissions have 

determined this to be around 10% (after the utility’s federal income taxes 

are covered), but it has been as low as 6% and as high as 16% in the past. 

Typically, each of the major parties in a rate case presents an expert witness 

on the appropriate level for the allowed return on equity.

Several methods are used to estimate the cost of equity, each based on 

economic theory and decades of research. Some commonly used methods 

include:

• Discounted Cash Flow (DCF): Estimates the present value of the earnings 

an investor in an equivalent company would receive over a long period 

of time.

• Equity Risk Premium: Measures the premium that investors require to 

make higher-risk equity investments compared with lower-risk bonds. 

• Capital Asset Pricing Model (CAPM): Uses a statistical measurement of the 

relative risk of the utility company, compared with risk-free investments 

like government bonds.

Commissions sometimes consider the results of multiple methods, and 

ultimately use their own judgment to determine a “fair” rate of return on 

common equity.

9.2.3.4. Cost of Debt

Utilities finance part of their investment with debt, because debt is lower 

in cost than equity and because interest payments on it are treated as a cost of 

business for tax purposes. A utility’s debt is usually a mix of long-term debt 

(bonds) and short-term debt (bank borrowings and/or direct short-term loans 

from mutual funds or other companies called “commercial paper”). Utilities 

routinely use some level of short-term debt, because they need unpredictable 

amounts of capital at any given time. The cost of debt is the average cost of 

the utility’s borrowed funds for the test year.

43 While the public generally perceives the return on equity as the utility’s “profit,” in the ratecase context it is usually referred to as the cost of equity because it is the amount the utility 

must pay an equity investor in order to use the investor’s money, just as interest on debt 

represents the cost of borrowing from a bond investor.
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Electricity Regulation in the US: A Guide

While the cost of equity is always an estimate of what the market requires, 

utilities do have actual debt outstanding, and actual interest rates on that 

debt can be exactly calculated, except in the relatively rare situation where a 

utility issues variable-rate debt. However, particularly in states that use future 

test years, the commission sometimes estimates the cost of debt that will be 

issued in the near future, and includes this in an estimated cost of debt. 

In recent years, average costs for long-term utility debt have been around 

5%-7%, but during the dramatic inflation years of the early 1980s they 

reached 12% or more. 

9.2.4. Operating Expenses

Operating expenses include labor, power purchases, outside consultants 

and attorneys, purchased maintenance services, fuel, insurance, and other 

costs that recur regularly. They also include state and federal taxes and 

depreciation expense, which is discussed below. The regulatory standard for 

operating expenses generally assumes an expense is necessary and prudent 

unless it is demonstrated to be inappropriate.

Some operating expenses are sporadic. Storm damage is an example — in 

some years, there may be no storms, while in others weather may be severe, 

causing millions of dollars in damage and repair costs. Rate case expenses are 

another example of sporadic costs, because utilities do not have rate cases 

every year. For these types of costs, a multi-year average is typically allowed 

as an expense in the rate case, not the amount actually incurred or projected 

for the test year. 

Some operating costs vary continuously and unpredictably (like those for 

fuel and purchased power). Most states provide for these cost shifts through 

automatic changes to rates, under formulas called adjustment clauses. Many 

have other adjustment mechanisms or tariff riders dealing with other costs, 

such as those for nuclear decommissioning, infrastructure replacement, and 

energy-efficiency program expense. Some adjustment mechanisms provide 

for dollar-for-dollar recovery of actual expenditures, while others operate 

under formulas designed to give the utility an incentive to control costs. 

(Adjustment clauses are discussed in Section 11.) 

9.2.4.1. Labor, Fuel, Materials and Outside Services

Most operating expenses cover labor, fuel, materials, and outside services 

— costs that are directly associated with providing service. Typically, most of 

these expenses are only evaluated by the commission in a general rate case. 

Most commissions exclude costs that are not required to provide service, 

such as charitable contributions by the utility, political lobbying expenses, 

and image-building advertising.
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Electricity Regulation in the US: A Guide

9.2.4.2. Taxes

Utilities also pay a variety of taxes, including federal and state income taxes, 

property taxes, and, in many states, gross revenue taxes. Normally these are 

all included in allowed operating expenses. In many cases, local cities and 

counties also impose franchise fees or gross revenue taxes. Because they are 

location-specific, these are often added onto customers’ bills in these specific 

communities, rather than being included in the statewide revenue requirement.

9.2.4.3. Depreciation

While the rate of return is a return on capital (a payment for the use of 

facilities that work), depreciation is the return of capital, as it is used up, to 

the utility’s investors. Utility facilities wear out, and utilities are allowed to 

accrue depreciation expense to pay for eventual replacement costs. These 

are non-cash operating expenses — the utility does not actually pay them to 

anyone every year. Instead, the utility collects depreciation over time, and 

uses the funds to retire debt (or even buy back stock), or to reinvest in new 

facilities to provide continued service.

Accounting for depreciation expense takes two forms: operating expense

and reduction to rate base. First, it is included as an operating expense on 

an annual basis in determining each year’s revenue requirement. Second, as 

the utility accrues depreciation over the life of a plant, the built-up balance 

is applied as a reduction to the rate base, so customers are only paying a 

rate of return on the remaining value of those investments. In this manner, 

consumers pay for long-lived equipment over its entire operating lifetime. 

When a unit is finally retired from service, both the plant in service and the 

offsetting accumulated provision for depreciation are removed from the rate 

base. If they are exactly equal, which they should be, there is no change in 

the revenue requirement unless the asset is replaced with a more expensive 

(or cheaper) unit. 

Amortization is slightly different from depreciation. While depreciation 

is the recovery, over time, of a capital investment in a tangible plant that 

provides service, amortization is the recovery over a period of years of 

an investment in intangible plant. An example is the payment to a city for 

entering into a franchise agreement, or the investment in an abandoned 

power plant that no longer provides service, but for which the regulator has 

determined that recovery of the investment from consumers is appropriate.

9.2.5. Summary: The Revenue Requirement

The end result of the commission’s analysis is a determination of rate base, 

rate of return, and operating expenses. Together these determine the revenue 

requirement. Rates are then set at a level designed to recover the revenue 

requirement, based on sales levels in the test year.
47

Electricity Regulation in the US: A Guide

9.3. Allocation of Costs to Customer Classes

In a general rate case, the commission next decides how each class of 

consumers should contribute to meeting the revenue requirement, based on 

the usage characteristics of each class. 

Not all states use the same categories for customers. Some have separate 

classes for single-family and multi-family residential consumers, on the 

theory that the cost of serving apartment buildings is lower because 

more customers are served by a given amount of investment. Some have 

agricultural classes; some have institutional classes for government buildings; 

others have special classes for unique needs — for example, to provide 

power to cruise ships when they dock (these are seldom-used but very 

large connections). Determining the right customer classes for each utility is 

important, and no single method is right for all systems.

Some costs are allocated based on the number of customers, some on the 

basis of their peak demands, some on their total energy consumption, and 

some on other aspects of usage. There are as many ways of doing this as there 

are analysts doing cost-allocation studies, and no method is “correct” for 

every utility. Often a commission will consider the results of multiple studies, 

and make an informed judgment that considers all of them.

9.3.1. Embedded vs. Marginal Cost of Service Studies

Cost of service studies use complex arithmetic models, and their methods 

are highly controversial. This subsection gives only a very general overview of 

the two generic kinds of studies used.

Embedded cost studies rely on the same costs used to determine the 

revenue requirement — that is, the historic accounting, or actual, costs that 

the utility incurs — and divide those costs among the customer classes in 

the various ways outlined in the previous section. They assign each cost 

that makes up the revenue requirement to the various classes of customers, 

so that the total for all customer classes equals the revenue requirement. 

Rates are then developed within each class to produce the allocated revenue 

requirement. About 30 states rely on embedded cost studies to allocate costs.

Marginal cost studies are very different. First, they calculate what it would 

cost to provide incremental (additional) service at the current costs of adding 

facilities and acquiring additional power. This may come to more or less 

than the utility’s actual costs, both because of inflation (that is, changes up 

or down in prices throughout the economy), and because the utility may 

not have exactly the right mix of resources and facilities to serve its current 

needs. Marginal cost studies then apportion the revenue requirement between 

the classes, in proportion to the costs each class would pay if the utility 

expanded, based on the incremental costs of adding to the system rather than 
48

Electricity Regulation in the US: A Guide

the average costs of the existing system. About 20 states use marginal cost 

studies to set rates.

Although in each category there are dozens, perhaps hundreds, of 

different methods for determining the relevant costs and their allocations, the 

results of marginal and embedded cost studies are, in broad terms, similar. 

Residential and small-business customers are assigned higher total costs per 

kilowatt-hour of usage, because they require more distribution investment 

and generally have usage concentrated in the on-peak periods of the day and 

year. Industrial customers are assigned lower total costs per kilowatt-hour, 

because they require fewer distribution facilities and have more uniform 

usage patterns. However, if the costs of new facilities are dramatically 

different than those of existing facilities, the results of a marginal cost study 

can vary significantly from those of an embedded cost study. 

If a marginal cost approach is used, the commission needs to be aware of 

the differences between short-run marginal costs (costs that shift immediately 

with changes in demand, given a fixed amount of production capacity) and 

long-run costs. In the long-run, all costs are variable — the utility will have 

to replace power plants and transmission lines over time, and will hire new 

and different staff to provide service. 

If the time horizon in a marginal cost study is too short, the results may 

be very different from the results of an embedded cost study, because the 

investment costs associated with eventually replacing long-lived power plants 

and transmission lines may be excluded in whole or in part. If the utility 

is in a surplus or deficit power situation, using short-run marginal costs 

may distort the results by shifting costs between customer classes unfairly. 

Reliance on short-run marginal cost when a utility has a surplus of generating 

capacity may also result in rates for incremental usage that are so low as to 

encourage additional consumption, which in the long run will require new 

investments at higher cost.

9.3.2. Customer, Demand, and Energy Classification

In both embedded and marginal cost studies, costs are apportioned based 

on the number of customers, the peak demand, and the total energy usage. 

The choice of how to allocate each type of cost typically requires judgments 

on the part of the commission, and is often heavily contested in rate cases. 

The customer count and energy usage for each class are known with great 

accuracy, but the peak demand is generally estimated, because detailed peak 

load metering is typically only installed for larger-volume customers.44

44 Modern smart-grid meters do allow collection of interval data for low-volume users, and the 

accuracy of data for cost allocation will likely improve significantly as these data are collected 

and analyzed. For this and other reasons, it is important that advanced metering equipment 

be considered usage-related plant in cost allocation studies and rate design.
49

Electricity Regulation in the US: A Guide

For a typical U.S. electric utility, residences make up about 90% of the 

customers, cause about 50% of the peak demand, and use about 40% of the 

energy sold.45 As a result, costs allocated based on the number of customers 

will fall overwhelmingly on the residential class, and those allocated on peak 

demand fall more heavily on residential and small commercial customers 

than on large-use commercial and industrial users. Costs allocated based on 

energy usage fall equally on all classes of customers, in proportion to their 

kilowatt-hour (or therm) usage. For these reasons, residential representatives 

in rate cases often advocate for a heavier weighting to energy usage in the cost 

classification debate, while industrial representatives often advocate for a 

heavier weighting to customer and demand usage factors.

For the purpose of allocating demand-related costs, some studies define 

peak as only a few hours of the year, while others consider the highest peak 

demand in each of several months of the year or the highest 200 or more 

hours of the year. Some studies divide energy costs by season or by time 

of day; others do not. Different definitions of peak can have very different 

impacts on specific customer classes. For example, air-conditioning users 

contribute to summer peak demands but not winter demands, and a 

12-monthly-peak method assigns them much less cost than a summer-peak 

method.

Because baseload power plants are so expensive, in both relative and 

absolute terms, their costs are invariably highly contested elements in the 

allocation debate. These hydropower, nuclear, and coal plants, and associated 

long-distance transmission lines, are typically a big part of the revenue 

requirement for a vertically integrated electric utility. Their high initial cost 

is justified because the units are used day and night. Baseload power plants 

have low fuel costs compared with peaking power plants like natural gas 

turbines, which cost less to build but more to run. If these incremental 

investment costs for baseload power plants are treated as demand-related — 

as needed to meet peak period requirements — then most of the cost will 

be borne by residential and small business customers. But if the costs are 

properly treated as energy-related— incurred to meet total year-round usage 

— then more of the cost will be borne by large commercial and industrial 

customers.46

9.3.3. “Vintaging” of Costs

Some commissions reserve certain low-cost resources for particular 

classes of customers. These types of set-asides may reserve limited low-cost 

hydropower to meet the essential needs of residential consumers, or choose 

45 Customer and energy sales data is reported annually by the U.S. Energy Information 

Administration. The contribution to peak load is a rough average, based on a sampling of 

specific utility rate filings. All these usage factors can vary widely from utility to utility.
50

Electricity Regulation in the US: A Guide

to treat a specific power plant as serving a specific industrial customer whose 

demand “caused” its construction.47

In the country as a whole, industrial loads have grown slowly or 

declined as we have transitioned to a service economy; at the same time, 

commercial (retail and office) loads have grown rapidly. Some regulators have 

apportioned the cost of new facilities built to serve growth to the customer 

classes with the most rapidly increasing demands for service, so that slowgrowing loads do not bear the cost of expensive new resources needed to 

supply growing demands.

9.3.4. Non-Cost Considerations

As these examples imply, rate setting, and especially allocation decisions, 

can be partly judgmental and partly political, not just technical. Commissions 

do apply considerations other than cost when setting rates. Much of their 

action is guided by law; but that law also gives them a certain degree 

of discretion, although abuses of it may well be overturned on appeal. 

Commissions may seek to encourage economic development by offering 

lower rates to new or expanding industrial customers. They may want to 

limit rate increases to residential consumers, who vote. One often hears 

arguments based on the need for gradualism to be the guiding principle when 

rates are rising, with the rationale that large rate changes should be avoided 

46 The treatment of capacity costs in excess of the lowest-cost capacity (e.g., single cycle gas 

turbines) as energy-related is justified by system planning imperatives. Electricity, which 

cannot be inexpensively stored, must be produced on demand. Therefore the system must 

be designed to meet peak load, i.e., the highest combined, instantaneous demand. This is, in 

effect, a reliability standard and, if it were the only criterion to be met, the planner would opt 

for that combination of capacity that satisfied it at the lowest total capacity cost. This would, 

very likely, produce a generation portfolio of combustion turbines. However, the system 

must also be capable of meeting customers’ energy needs across all hours. While combustion 

turbines cost little to build, they are very expensive to run, such that the average total cost 

(capacity and operating) per kilowatt-hour will be high, in comparison to the average total 

costs of other generating units whose capacity cost is greater than that of the turbine, but 

whose energy (operating) cost are lower, often significantly lower. Such units become costeffective, relative to the alternatives, the more they operate. Given this general characteristic 

of generating facilities (i.e., low capital cost units typically have higher operating costs and 

vice versa), it will make economic sense to substitute capital (fixed investment cost) for 

energy (variable fuel cost) as hours of operation increase. As a result, it is right to see those 

incremental capital costs as incurred not to meet peak demands, but rather energy needs.

47 For example, for many years the state of Vermont reserved low-cost hydropower to provide 

the first 200 kWh/month of usage by residential consumers. Above that level, residential 

customers paid higher rates based on non-hydro power costs; non-residential consumers 

did not get any allocation of the low-cost hydropower. The state of Maryland assigned a 

specific low-cost coal plant to a specific aluminum smelter, excluding it from rate increases 

for new facilities. Similar approaches have been used at times in the Pacific Northwest, in 

California, and by the Tennessee Valley Authority. See: Residential Baseline Inverted Rates,

Washington State Senate, 1981, available at http://www.raponline.org/docs/WashingtonState_

BaselineRate1981Study.pdf.
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Electricity Regulation in the US: A Guide

where possible to provide some continuity of cost to all customers. This is 

especially true where one or more classes appear to be paying an excessive or 

insufficient share of the total revenue requirement. In the end, regulation is 

not purely an arithmetical science. 

9.4. Rate Design Within Customer Classes 

Typically, the last important topic that regulators address in a general rate 

case concerns the design of the retail rates paid by specific customer classes. 

Rates can include a fixed, recurring monthly (or daily) customer charge and 

energy and demand charges (the distinction is explained below), as well as 

other miscellaneous charges relating to the impacts of customer loads on power 

quality. These other charges often vary according to season and time of day.

9.4.1. Residential Rate Design

Residential rates typically consist of a monthly customer charge (or 

basic charge), plus an energy charge in cents per kilowatt-hour based on 

the amount of usage. This energy charge may be a flat rate (the same for all 

usage), inverted (with higher rates for usage over a base level) or declining 

(with lower rates for usage over a base level). 

As the following example shows, these three basic rate forms affect 

consumers with different usage levels quite differently, even though a 

consumer using 1,000 kWh/month pays the same bill under each rate design.

Figure 9-5: 

Illustrative Residential Electric Rate Design

Customer Charge $5.00 $5.00 $5.00

First 500 kWh $0.10 $0.05 $0.15

Over 500 kWh $0.10 $0.15 $0.05

Customer Bill

0 kWh $5.00 $5.00 $5.00

500 kWh $55.00 $30.00 $80.00

1,000 kWh $105.00 $105.00 $105.00

1,500 kWh $155.00 $180.00 $130.00

Flat

Rate

Inverted 

Block 

Rate

Declining 

Block 

Rate
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Electricity Regulation in the US: A Guide

Figure 9-6: 

Illustrative Residential Bills With Different Rate Designs

48 The inverse relationship between price and demand, referred to generally as elasticity of 

demand, is well-established in theory and practice. It describes the percentage change in 

demand response to a given percentage change in prices. Estimates of these precise values 

can vary widely. Short-run elasticity estimates for electricity, however, will include timeframes 

for which the capital stock of appliances and end-use devices change. Estimates of long-term 

elasticity then are typically higher.

$200

$150

$100

$50

$0

0 300 600 900 1200 1500

Monthly Bill

kWh/Month

Flat Rate

Declining 

Block Rate

Inverted Rate

Low-income advocates frequently focus on rate design issues in rate cases. 

Most low-income consumers have below-average usage, and an inverted rate 

design will favor them. Some low-income consumers, however, particularly 

those with large extended families or living in older inefficient housing, may 

have higher-than-average usage.

In most states, the customer charge is set to recover customer-specific 

costs, such as metering, meter reading, and payment processing. In other 

states, higher charges are established that recover portions of the distributionsystem investment and maintenance. For any given revenue requirement 

for residential consumers, a higher customer charge implies a lower perunit usage charge, which favors large-usage consumers and leads to higher 

consumption levels.48

Time-of-use (TOU) pricing is becoming more common for residential 

consumers, particularly those with high usage. This sets a lower rate for 

nights and weekends, which are off-peak times when the utility system has 

available capacity, and higher rates during the peak periods, when additional 

usage can force the utility to rely on peaking power plants not needed at 

other times, and also to incur higher line losses. 
53

Electricity Regulation in the US: A Guide

Figure 9-7: 

Illustrative Residential Time of Use Rates

Flat

Rate

Mild 

TOU Rate

Steep 

TOU Rate

Customer Charge $5.00 $5.00 $5.00 

Nights/Weekends $0.10 $0.07 $0.05 

Mornings / Evenings $0.10 $0.10 $0.15 

Afternoon Peak $0.10 $0.13 $0.25 

In general, residential time-of-use rates are voluntary, while larger 

commercial and industrial customers may face mandatory TOU rates. The 

proper design of a time-of-use rate will depend on the specific circumstances 

of a utility, the nature of its resource mix, and the shape of its load through 

the day and through the seasons. Even if the cost differentiation is not great 

enough to motivate consumers to alter their usage patterns, a TOU rate can 

still be appropriate to ensure that all consumers pay an appropriate amount 

for the power they use: consumers with primarily off-peak usage cost less 

to serve, and arguably should pay lower bills. The expected deployment 

of advanced meters and so-called smart grid devices may eventually result 

in greater utilization of TOU rates, including mandatory TOU rates for 

residential customers.

9.4.2. General Service Consumers

General service customers are businesses of any kind, including office, 

retail, and manufacturing enterprises. Rates for these commercial and 

industrial customers are generally more complex than residential rates. They 

normally include a customer charge that is higher than the one residential 

consumers pay, reflecting higher metering and billing costs, and other cost 

characteristics that make them more expensive to serve. The general service 

energy charge per kWh may be priced by blocks or be differentiated by 

season or by time of day. For larger businesses, there is also usually a demand 

charge based on the customer’s highest demand during the month, whether it 

occurs at the time of the system peak or not. In more advanced rate designs, 

the demand charge may also be differentiated by season or by time of day, 

with higher demand charges applying during the system (coincident) peak 

demand period. Demand charges often have a ratchet feature, which adjusts 

the customer’s monthly demand charge on the basis of its maximum demand 

during a preceding period, usually 12 months. 

Because the demand charge recovers some of the costs associated with 

power supply, transmission, and distribution facilities, the energy charge 
54

Electricity Regulation in the US: A Guide

for businesses that pay one is typically lower than that for residential or 

small-business consumers. This does not necessarily mean their overall cost 

per kilowatt-hour is lower. In the example below, the average total revenue 

contribution for commercial usage will be about $0.10/kWh, roughly the 

same as in the residential example above. However, as a general matter, 

the rate structure does give the customer an incentive to moderate its peak 

demands, thereby reducing its capacity charges and lowering its average total 

cost per kilowatt-hour.

Figure 9-8: 

Illustrative General Service Flat and Time-Of-Use Rates

Flat

Rate

Mild 

TOU Rate

Steep 

TOU Rate

Customer Charge $20.00 $20.00 $20.00 

Demand Charge / kW $10.00 $10.00 $10.00 

Energy Charge 

 Nights/Weekends $0.07 $0.05 $0.04 

 Mornings/Evenings $0.07 $0.07 $0.08 

 Afternoon Peak $0.07 $0.10 $0.15 

9.5. Bundled vs. Unbundled Service 

Most vertically integrated utilities only provide bundled service, or power 

supply plus distribution. In restructured states, most utilities provide only 

distribution service — which may include non-bypassable riders (discussed 

earlier) that the commission deems should be paid by everyone, while also 

offering an optional last-resort or default service for power delivery.

In some states that generally have vertically integrated utilities, industrial 

customers have requested, and commissions have granted, optional 

distribution-only direct access rates. These allow the industrial user to 

purchase its power in the wholesale market directly from competitive 

suppliers, and to pay the utility only for delivering that power.

9.6. Advanced Metering and Pricing

Utilities are introducing advanced metering, which allows them to measure 

usage in very short intervals by time of day, and to communicate information 

to and from the customer. Advanced meters enable utilities to more easily 

establish more detailed rate designs by more accurately matching costs 
55

Electricity Regulation in the US: A Guide

to usage. Smart meters can record customer usage by the minute, and can 

communicate back to the utility without a meter reader needing to travel from 

building to building. Smart meters can also receive signals from the utility—

which may, for example, reset a thermostat to reduce load based on preset 

customer preferences. These smart meters have become quite inexpensive, and 

will likely be the norm in the future even for residential consumers.49

Some advanced rates are simple, with time-of-use blocks as discussed above, 

while others are more complex, targeting specific short periods of time when 

usage pushes up against system capacity. Rates that change in response to 

changes in market prices for power are generically known as dynamic pricing. 

One form of dynamic pricing provides real-time rates, in which the amount 

that customers pay for energy changes every hour, or several times a day, in 

response to changes in wholesale market prices. The customer only knows a 

few hours, or a day in advance, what the rate for the next time period will be. 

These are typically restricted to very large industrial customers, but have been 

tested for smaller customers in a few utilities.

Another approach to dynamic pricing is designed to encourage consumers 

to cut back usage, during limited periods, when asked to do so by the utility. 

These are often called critical period pricing rates, and they take many forms 

but are usually an add-on to a time-of-use rate. They increase sharply when 

the utility experiences so much demand for power that its facilities are 

stretched thin. 

The customer is notified of critical periods, typically a day ahead, but 

sometimes only a short time before the prices spike up. Customers who can 

cut back on short notice can help the system avoid the high costs of peaking 

power plants, additional transmission and distribution capacity, and the high 

line losses that occur during peak periods. In theory, when these consumers 

are given sharply higher prices during critical periods but slightly lower 

rates the rest of the time, both the customer and the system can save money 

when customers change their usage based on price signals. Those that cannot 

cut back during critical periods pay rates that reflect the high cost of power 

during that period. Unlike real-time pricing, this approach usually sets the 

rates for the extreme periods in advance — but only invokes those rates when 

the system is under stress and prices in the wholesale power market spike.

49 There is controversy over whether utilities should replace all existing meters with smart 

meters and commissions are addressing the issue. However, smart meters have become the 

norm when installing meters on new buildings or replacing worn-out meters, even though all 

of their features may not be used for many years.
56

Electricity Regulation in the US: A Guide

Figure 9-9: 

Illustrative Critical Period Pricing Rate Design

Flat

Rate

Mild 

Critical 

Peak Price

Steep 

Critical 

Peak Price

Customer Charge $5.00 $5.00 $5.00 

Nights/Weekends $0.10 $0.07 $0.05 

Mornings / Evenings $0.10 $0.09 $0.10 

Afternoon Peak $0.10 $0.12 $0.15 

Critical Peak Hours $0.25 $0.50 

A variant is called a peak time rebate. In this design, the customer is given a 

discount if load is reduced at the critical peak time.

Many dynamic pricing rates are strictly voluntary: customers can choose 

to participate, or to stay with a more traditional rate design. It’s probable that 

over time, both larger residential consumers and business consumers will 

increasingly be served through mandatory TOU and/or dynamic pricing rates. 

9.7. Service Policies and Standards

All the utility’s rates, policies, and standards are subject to change by the 

regulator during a rate case. A variety of issues may be raised by the utility or 

by intervenors, including the line extension policy for new construction, the 

disconnection/reconnection policy and charges for consumers who do not 

pay their bills on time, the rules for low-income energy assistance programs, 

and the design of energy efficiency programs. Many of these are discussed in 

the sections that follow.

Issues such as these may be raised by utilities when they file their initial 

evidence in rate proceedings, or may often be introduced by intervenors 

during the proceeding. The commission will sometimes agree to resolve 

issues raised by intervenors, or may rule on them outside of the scope 

of the rate case. In the latter situation, if the issues are important, many 

commissions will initiate a separate proceeding to resolve them. 

9.8. Issue-Specific Filings

Utilities make issue-specific filings between rate cases. These do not 

fall into any particular category. Some are as simple as changing a tax rate 

when a local government adopts a new tax schedule; some would make 

additional services available to consumers, without changing service to 
57

Electricity Regulation in the US: A Guide

other consumers. Others request accounting orders to clarify or change 

the accounting treatment of certain costs, so the utility can proceed with 

confidence about the process of cost recovery until the next rate case. The list 

of possibilities for issue-specific filings is nearly infinite.

Utilities normally take the position that these are important reasons to 

adopt new tariffs, or to impose minor changes in rates, but do not justify 

re-opening the entire range of issues considered in a general rate case. 

Consumer advocates sometimes criticize this as single-issue ratemaking, 

in which the utility seeks to raise rates for those elements of cost that are 

increasing, without considering offsetting factors that may be decreasing 

costs. Some commissions’ rules define the threshold at which a tariff filing 

becomes a general rate case, in which all issues may be considered.

9.9. Generic Investigations

Occasionally a regulator will launch a generic investigation into an issue 

of regulatory importance. These typically involve multiple utilities, in an 

attempt to determine if a different type of regulation is appropriate. Examples 

include a generic investigation into rate design approaches, a decision of 

whether to modify energy efficiency programs, or consideration of decoupling 

or incentive regulation (see sections 10 and 15). Investigations like these 

typically have no immediate impact on the revenue requirement or rate level 

for any individual utility; instead they explore policy changes that may be 

implemented in future rate proceedings.

9.10. Summary: The Fundamentals of Regulation

This abbreviated overview introduces the multitude of issues a regulatory 

commission deals with in setting utility rates and policies. The additional 

resources below provide more guidance on some of the specific topics 

discussed, but no single resource is a complete guide to the long and unique 

regulatory history of each state.

For more details:

Bonbright, 1961, Principles of Public Utility Rates.

“Estimating The Cost Of Equity: Current Practices And Future Trends In The 

Electric Utility Industry,” Engineering Economist Magazine, 1999.

www.entrepreneur.com/tradejournals/article/59705097.html

Garfield and Lovejoy, 1964, Public Utility Economics.

Missouri Office of Public Counsel, Rate Case Tutorial. 
58

Electricity Regulation in the US: A Guide

www.mo-opc.org/upload/small_rate_case_tutorial.doc

Palast, Oppenheim, and MacGregor, 2003, Democracy and Regulation.

Phillips, 1985, The Regulation of Public Utilities.

Regulatory Assistance Project, 2000, Charging for Distribution Services. 

www.raponline.org/docs/RAP_Weston_

ChargingForDistributionUtilityServices_2000_12.pdf

Regulatory Assistance Project, forthcoming, Pricing Do’s and Don’ts.

www.raponline.org/docs/RAP_PricingDosAndDonts_2011_04.pdf
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Electricity Regulation in the US: A Guide

10. Drawbacks of Traditional 

Regulation and Some Fixes

The system of traditional regulation described in the previous 

section sets a revenue requirement based on a calculated rate base, 

an estimated rate of return requirement, and carefully examined 

operating expenses and taxes. In the United States during the 20th 

century, this structure oversaw and facilitated the development of the world’s 

most reliable and reasonably priced electric system. Even so, it has some 

drawbacks. This section identifies some of the more important ones, and 

responses to them. Section 14 discusses some newer and more innovative 

approaches to one of these problems, the throughput incentive.

10.1. Problems

In other sectors of the economy, competition is widely believed to produce 

powerful incentives for cost minimization by producers, ultimately leading 

to lower prices for consumers. Critics of traditional regulation often charge 

that the natural-monopoly characteristics of the utility industry, coupled 

with regulation that in effect provides companies with cost plus a fair rate of 

return, eliminates or reduces these efficiency incentives and leads to higher 

costs for consumers.

10.1.1. Cost-Plus Regulation

One of the most common critiques of traditional regulation, based on 

what is called the Averch-Johnson Effect, suggests that utilities will overbuild 

because their allowed return is a function of their investment.50 Utilities 

have been accused of spending more on power plants, transmission, 

and distribution facilities than would be expected by a cost-minimizing, 

profit-maximizing enterprise. According to this theory of excessive capital 

investment, a company that is allowed what is seen by management as a 

return on its investment in excess of its actual cost of capital will tend to over50 Averch, H. and L. Johnson. “Behavior of the Firm Under Regulatory Constraint,”

American Economic Review 52 (1962): 1052-1069.
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Electricity Regulation in the US: A Guide

invest, or gold-plate its system.

In addition to high investment levels, traditional utility regulation may 

also encourage excessive operating expenses, because its cost-plus structure 

means that all approved costs will be passed through to consumers. While 

commissions do review and sample operating expenses to determine if they 

are reasonable before approving them, it’s questionable whether they have the 

ability to really examine them in detail in every rate case.

Also, the higher the operating expenses were in the test year, the more 

the company is allowed to earn in the year after the rate case is resolved. 

As discussed in Section 9, the allowed revenue requirement is based on the 

allowed operating expenses, plus the product of the net rate base and rate of 

return. However, the utility does still have some incentive to reduce expenses. 

Once the rates are set, they stay in place until changed, regardless of whether 

the operating expenses are the same, higher, or lower than in the test year; so 

the utility earns more if it incurs lower costs.

10.1.2. The Throughput Incentive

As awareness of the need to constrain energy use has grown in recent 

years, the incentives that traditional regulation provides for utilities to 

increase sales have been of particular concern. The “Averch-Johnson Effect” 

posits that the utility increases profits by increasing its rate base, and that 

additional investments in the rate base are justified by and require additional 

sales — so there is also an incentive to increase usage.

But even without the Averch-Johnson effect, utilities still have an incentive 

to increase sales in the short run. If a utility can serve increased usage 

with existing facilities, and if current fuel and operating costs (the costs to 

produce and deliver another kilowatt-hour with the existing power plants 

and distribution facilities) are lower than the retail rates, increased sales will 

increase profits in the short run. This is known as the throughput incentive, 

because utilities have a profit incentive to increase sales. The throughput 

incentive may be an important reason that utilities resist the implementation of 

energy efficiency programs that would achieve long-run savings for consumers 

but reduce near-term utility sales, resulting in lower short-run profits.

10.1.3. Regulatory Lag

Regulatory lag refers to the time between the period when costs change 

for a utility, and the point when the regulatory commission recognizes these 

changes by raising or lowering the utility’s rates to consumers. Regulatory 

lag is generally cited by utilities as a problem with regulation, because rates 

do not keep up with rising costs. As a result, utilities have requested — 

and some commissions have granted — mechanisms to deal with changes 

between rate cases, such as fuel adjustment clauses (these are discussed in 
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Electricity Regulation in the US: A Guide

some detail in Section 12). However, as the throughput problem implies, 

regulatory lag can also work in the utility’s favor: if costs decline or sales 

increase between rate cases, the utility’s profits may rise with no change in 

rates required. While commissions generally have the authority to order rate 

decreases, this is unusual, and the “lag” between when the excess profits 

begin and when the commission takes action is typically longer than the lag 

when costs increase and utilities seek higher rates.

10.2. Responses

Many regulatory concepts have evolved to address these problems. Several 

are outlined here.

10.2.1. Decoupling, or “Revenue-Cap” Regulation

Decoupling is a slight but meaningful variation on traditional regulation, 

designed to ensure that utilities recover allowed amounts of revenue 

independent of their sales volumes. The general goal is to remove a 

disincentive for utilities to embrace energy efficiency or other measures that 

reduce consumer usage levels. Decoupling begins with a general rate case, in 

which a revenue requirement is determined and rates are established in the 

traditional way. Thereafter, rates are adjusted periodically to ensure that the 

utility is actually collecting the allowed amount of revenue, even if sales have 

varied from the assumptions used when the previous general rate case was 

decided. If sales decline below the level assumed, rates increase slightly, and 

vice-versa. Sometimes the allowed revenue is changed over time to reflect 

defined factors, such as growth in the number of consumers served. This is 

known as revenue-cap or simply revenue regulation. (Decoupling is discussed 

in greater detail in Section 15.)

10.2.2. Performance-based, or “Price-Cap” Regulation

Performance-based regulation (PBR) ties growth in utility revenues or rates 

to a metric other than costs, providing the utility with opportunities to 

earn greater profits by constraining costs rather than increasing sales. For 

example, a five-year rate plan might allow a utility to increase rates at one 

percent below the rate of inflation each year. In other schemes, a commissiondetermined adjustment, sometimes called a Z-Factor, may be included to 

capture predictable changes in costs other than inflation and productivity. 

Then if the utility invests in expensive new facilities, its costs will grow faster 

than its revenues, so it has an incentive to constrain expenditures. In the 

absence of a decoupling component to the PBR plan, this approach is often 

referred to as price-cap regulation.
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Electricity Regulation in the US: A Guide

Figure 10-1: 

Comparison of Traditional Regulation and Price-Cap PBR

Traditional 

Regulation

PerformanceBased Regulation

Rate Base Rates in Period 1

X Rate of Return + Inflation

+ Operating Expenses - Productivity

= Revenue Requirement + / - Z-factor

/ Sales = Rates = Rates in Period 2

Commissions have learned to establish strict service quality standards 

when approving multi-year PBR mechanisms, because experience showed 

that some utilities took actions to improve earnings at the expense of 

reliability and customer service quality. See Section 17, on Service Quality.

10.2.3. Incentives For Energy Efficiency or other Preferred Actions

Some commissions have established incentive mechanisms to reward 

utilities that take specific actions or that achieve specific goals. These may, 

for example, include a bonus to the rate of return for exceeding commissionestablished goals for energy efficiency programs, or penalties for failure to 

maintain commission-established goals for reliability. In most cases, the 

incentives are tied to the value of the goals the commission is seeking to 

achieve, and are large enough to be meaningful to the utility, but not so large 

as to create significant rate impacts for consumers. Appropriate incentives 

or rewards for effective performance are increasingly recognized as sound 

regulatory practices, for which consumers are well-served.

10.2.4. Competitive Power Supply Contracting 

Several commissions have required regulated utilities to conduct open 

competitive bidding when new power supply resources are needed. The 

utility is often allowed to bid in the process, but if a non-utility provider 

offers an equivalent product at a lower cost, the utility is obligated to buy 

the lower-cost power. This ensures the utility cannot gold-plate its power 

facilities, because a competitive provider will be able to underbid it. Some 

commissions have required that renewable resources be acquired by contract, 

but still allow utilities to invest in conventional power plants.
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Electricity Regulation in the US: A Guide

10.2.5. Restructuring

Other states have gone further, as described in Section 4.4.1, by 

requiring utilities to divest their power plants and requiring that all power 

for consumers be provided by other suppliers. This eliminates any profit 

in the power-supply segment of the business, as well as possible problems 

with gold-plating and cost-plus regulation in that segment (although it may 

cause other problems). Restructuring, however, creates other challenges for 

regulators. Most important of these is finding an equitable and economical 

way to provide a default power-supply service for consumers who do not 

choose a competitive supplier.

10.2.6. Prudence and Used-and-Useful Reviews

When an expensive new power plant or major transmission facility enters 

service, regulators often perform a prudence review to determine if the facility 

was built in an economic fashion. Often consultants with power-sector 

construction experience are retained to perform the review. If the planning or 

construction is deemed imprudent, the commission may disallow a portion 

of the investment, refusing to include it in the rate base. A similar review may 

determine if the plant is actually used and useful in the provision of service 

to customers; if not, excess generating capacity or other plant costs may be 

excluded from the rate base. 

In some states, a pre-approval process for major investments is used, 

so that the commission reviews major projects for cost, consistency with 

resource planning goals, and other factors before they are built. This is 

becoming increasingly important as older power plants face significant 

environmental retrofit costs. (See section 16 on environmental issues.)

10.2.7. Integrated Resource Planning 

Integrated resource planning (IRP), which is discussed in more detail in 

Section 13, requires the utility to develop a publicly available, long-range 

plan for the best way to meet consumer needs over time, usually anywhere 

from 10-20 years. Typically the commission will review the plan, order 

modifications if necessary, and approve it as the guidance document for 

future utility investment and operations decisions. In most states, the plan 

itself is not “approved” per se, but is found to be a reasonable guide to future 

actions.
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Electricity Regulation in the US: A Guide

11. Transmission and 

Transmission Regulation

Most power in the grid flows from large generating plants into 

the transmission system, then to the distribution systems of 

individual utilities, and ultimately to individual homes and 

businesses.51 The transmission system allows utilities to use 

diverse resources — such as wind, coal, or geothermal energy — even if they 

are located far from consumers. Wind plants need to be constructed where 

the wind is strongest and most consistent; building coal plants near the mines 

and shipping the electricity over long-distance transmission lines may be 

cheaper than hauling the coal by railroad to a power plant near users. Utilities 

also often sell power to one another, and that power must be moved from one 

system to another. In some cases, utilities may have long-term contracts for 

power produced more than 1,000 miles away.

The U.S. Constitution reserves to Congress the power to regulate interstate 

commerce. Because power moves between states over transmission lines, 

FERC has authority over the pricing for most transmission services. Public 

power entities such as the New York Power Authority, Arizona’s Salt River 

Project, North Carolina’s Santee Cooper, or the Los Angeles Department of 

Water and Power are not under FERC jurisdiction. Federal power marketing 

authorities, such as the Bonneville Power Administration, the Western Area 

Power Administration, and the Tennessee Valley Authority are also selfgoverning, and fall outside FERC’s general regulatory authority. Finally, 

most of Texas and all of Hawaii and Alaska are outside FERC jurisdiction 

because they are not connected, or not tightly connected, to the interstate 

transmission grid. However, the entities not subject to direct regulation by 

FERC generally consider FERC policy and adhere to similar standards.

This section briefly describes the function of the transmission system, and 

how transmission pricing is regulated. 

51 A small amount of power is produced by distributed generation in small power plants at 

homes and businesses. This power may be used where it is produced, or transferred onto the 

distribution system and used by another customer nearby.
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Electricity Regulation in the US: A Guide

Source: US-Canada Power System Outage Task Force final report, April 2004. 

Generating 

Station

Generator 

Step-Up

Transformer

Substation 

Step-Down

Transformer

Transmission

Customer

128kV or 230 kV

Secondary

Customer

120 V or 240 kV

Primary

Customer

13 kV or 4 kV

Subtransmission

Customer

26 kV or 69 kV

Transmission Lines

765, 500, 230, and 138 kV

11.1. Transmission System Basics

The transmission network moves power at high voltages over long 

distances. Generally, the term transmission applies to lines that carry power 

at voltages of 115 kV (115,000 volts) and above through big wires, mostly 

on steel towers. Sub-transmission consists of lines operating at 34.5 to 115 

kV. These sub-transmission lines may be classified as transmission, subject 

to federal regulation, or as distribution lines subject to state regulation; this 

depends on whether they move bulk power from power plants to different 

utilities, or move power around within a single utility system to serve retail 

consumers. Lines carrying 34.5 kV volts or less are almost always considered 

distribution lines, subject to state regulation.

Power is actually generated at lower voltages, and stepped up through transformers before it enters the transmission network. This is because higher voltage 

lines can carry more power and will experience lower line losses. Sometimes 

power is transformed up a second time, to be loaded onto very high voltage 

lines – 345,000, 500,000, or 765,000 volts – for long-distance transmission.

In a few areas, power is also converted from alternating current (AC) to 

direct current (DC) for transmission purposes, since DC is more efficient 

for moving power very long distances. DC interconnections can also be 

used to move power between the Eastern U.S., the Western U.S., and Texas; 

these three grids (Quebec is also a separate grid) are not synchronized with 

each other, so AC cannot be transferred directly between them. At about 10 

locations along the boundary between the three U.S. interconnections, there 

are facilities where power is converted from AC to DC and back to AC so it 

can be moved from one grid to another.

Very large industrial customers sometimes receive power at transmission 

voltages, directly from the transmission system. Most customers, however, 

take power at lower voltages. The power must be stepped down through 

transformers before customers take delivery at sub-transmission voltages, 

primary voltages, or secondary voltages, as shown in this diagram: 

Figure 11-1: The Transmission System

Transmission

Distribution

Generation
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Electricity Regulation in the US: A Guide

If the transmission system is robust, with a certain amount of redundancy 

built in, it can withstand the failure of its most critical lines or other 

components. In fact, a set of standards promulgated by the North American 

Electric Reliability Corporation and enforced by FERC holds transmission 

owners and operators accountable for being prepared for contingencies. This 

is critical to reliability: if one transmission element fails, the effect can cascade 

through a system without protection systems in place. On a few occasions, 

entire regions of the country have been plunged into darkness because 

of the failure of one segment of transmission and a cascade of resulting 

failures. For this reason, great attention has been given to maintaining 

transmission reserves, to provide spare capacity when something goes wrong; 

to monitoring transmission reliability, and to funding needed transmission 

system upgrades.

11.2. Transmission Ownership and Siting

Most transmission facilities in the U.S. are owned by individual utilities, 

including the federal power-marketing agencies. Some are jointly owned 

by multi-utility groups. In some cases, transmission lines are owned by 

independent entities other than utilities, which receive payment from all 

users of the lines.

With the U.S. system of franchised utilities, each individual utility is likely 

to invest in transmission based solely on the needs of its own service territory. 

It may perceive no incentive to invest to protect reliability for adjacent areas. 

Moreover, the state regulatory framework may provide no legal basis for its 

regulator to require such additional investments, or to compel public power 

utilities or cooperative utilities to cooperate. Many regional power pools 

and other arrangements have evolved over the history of the industry to 

build transmission networks and manage them cooperatively, but these have 

become more formalized since the Energy Policy Act of 1992, and FERC 

Order 888. Reliability problems have persisted in some locations where there 

is more demand for transmission capacity than existing facilities provide, and 

this has led FERC to support the creation of RTOs and ISOs that do consider 

multi-utility reliability issues.

Transmission lines require long rights of way across the property of 

multiple owners, the land-use jurisdictions of multiple local governments, 

Native American tribes, and states. Lines cross city, county, and state 

boundaries, traverse public and private lands, and affect the allowable land 

use in their immediate vicinity. For this reason, the transmission-siting 

approval process remains one of the most complex aspects of providing 

adequate transmission facilities. A mixture of local, state, and federal 

government agencies holds jurisdiction over who can build what, where they 
67

Electricity Regulation in the US: A Guide

can build it, when they can build it and who pays for it. 

In some states, authority for approving new transmission lines has been 

vested in a single agency to expedite the evaluation process and reflect the 

general value to all of a network system. In other areas, separate approval 

must be obtained from each city and county through which a line passes, 

plus each governmental territory the lines pass through. 

FERC has limited authority to override local authorities to provide for 

construction of lines that address the national interest, as deemed by a 

periodic U.S. Department of Energy assessment. In some parts of the U.S., the 

lack of new transmission lines has hampered the development of renewable 

energy resources, because current transmission lines do not necessarily lie 

in areas that are most advantageous to renewable energy. Also, transmission 

pricing has generally evolved to serve baseload coal and nuclear projects; that 

pricing structure creates challenges for intermittent power sources like wind 

and solar that FERC is evaluating.

11.3. Transmission Regulation

FERC regulates the pricing of wholesale transmission transactions, both 

what is charged to utilities and what’s charged to individual industrial 

consumers who buy power directly at transmission voltages. Transmission 

pricing takes several forms, including postage stamp pricing (one rate 

regardless of distance), license plate pricing (a price within specified zones), 

and point-to-point distance-sensitive pricing. Transmission rates are also often 

pancaked — meaning that as power moves across multiple lines, from one 

transmission owner to another, each owner gets paid for the use of its 

facilities. These layers can add up to substantially more than they would if a 

single owner controlled all of the facilities. One reason for creating regional 

power pools, RTOs, and ISOs is to develop systems of joint pricing for 

transmission services.

When utilities deliver power to industrial consumers at transmission 

voltages under direct access or restructuring, the charges they apply for 

transmission service must be the rates approved by FERC. They may also 

charge for any additional services they provide, at rates regulated by the state 

commission.

The procedure, evidence, and timing in a FERC rate-setting case are 

similar to a state utility general rate case. However, there is currently no 

consumer advocate for the FERC process, so the parties do not routinely 

include representatives of the public unless one or more state commissions or 

state consumer advocates intervene. 

In addition to several acts of Congress, including the Energy Policy Acts 

of 1992 and 2005, three key decisions by FERC guide current transmission 
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Electricity Regulation in the US: A Guide

regulation:

Order 888 (1996) detailed how transmission owners may charge for use 

of their lines, and the terms under which they must give others access 

to them. Order 888 also required utilities to separate their transmission 

and generation businesses, and to file open access transmission rates 

through which they provide non-discriminatory transmission service. 

FERC hoped that this separation would make it impossible for a 

utility’s transmission business to give its own power-generating plants 

preferential access to the company’s lines. FERC also provided for the 

creation of separate transmission owning companies, generally known 

as transcos, that could build lines where local utilities would not.

Order 889 (1996) created an open access same-time information system

(OASIS), through which transmission owners could post the available 

capacity on their lines, so all companies that wanted to use the system 

to ship power could all track the available capacity. 

Order 2000 (1999) encouraged transmission-owning utilities to form 

regional transmission organizations. FERC did not require utilities to 

join RTOs; instead, it asked that the RTOs meet minimum conditions, 

such as having an independent board of directors. FERC gave these 

regional organizations the task of developing regional transmission 

plans and pricing structures that would promote competition in 

wholesale power markets, establishing the transmission system as a 

highway distribution system for that wholesale commerce. 

For more details:

Matthew H. Brown, National Conference of State Legislatures; 

Richard P. Sedano, The Regulatory Assistance Project, 2004, 

Electricity Transmission: A Primer.

www.raponline.org/docs/rap_brown_transmissionprimer_2004_04_20.pdf

U.S. Department of Energy, 2002, A Primer on Electric Utilities, 

Deregulation, and Restructuring of U.S. Electricity Markets.

www1.eere.energy.gov/femp/pdfs/primer.pdf
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Electricity Regulation in the US: A Guide

12. Tariff Adjustment Clauses, 

Riders, and Deferrals

This section describes a number of mechanisms that allow for cost 

recovery outside of the general rate case process. Those include 

adjustment clauses for various expenses, energy efficiency funding 

mechanisms, and tracking mechanisms.

Adjustment clauses are used to change utility rates between general rate 

cases, to account for changes in specific costs or for changes in sales. These 

rate changes typically require little scrutiny by the regulator, because the 

adjustments are governed by formulas and rules that were themselves fully 

litigated. Adjustment clauses deal with specific factors that have effects on 

costs and the company’s bottom line and are beyond the control of utility 

management — e.g., factors of production, changes in demand, and changes 

in the broader economy. In each case, the commission has determined 

that recovery should be allowed (or considered) outside of a general rate 

case.52 Periodic audits check to see if the mechanisms are being properly 

implemented.

The most common and most important of these mechanisms are purchased 

gas adjustment (PGA) mechanisms and fuel adjustment clauses (FACs). 

However, there are many different types of adjustment mechanisms and tariff 

riders in place.

12.1. Gas Utility-Purchased Gas Adjustment Mechanisms

Most natural gas utilities own their distribution networks, but no gas wells. 

They purchase gas from producers and pay pipeline companies to deliver that 

gas to their systems. As Figure 12-1 shows, the price of gas can change greatly 

on short notice, and the gas utility has little ability to influence the price of gas 

(except by signing multi-year contracts with fixed or indexed prices). 

52 Not all regulators and policymakers accept this argument. The contrary position holds that 

it is not, by itself, direct control over a cost or revenue item that matters, but rather whether 

the risks it imposes can be managed through steps such as alternative investments, changes 

in operations, financial hedges, or changes in consumer behavior. It concludes that regulation 

should be based on which party — the utility or the consumer — is better fitted to manage 

and bear the risk in question.
70

Electricity Regulation in the US: A Guide

Figure 12-1: 

Wholesale Natural Gas Prices 1999-2009

$10

$8

$6

$4

$2

$0

1999 2001 2003 2005 2007 2009

The cost of purchased gas typically makes up about two-thirds of a gas 

utility’s total costs, and a sudden surge in wholesale gas prices can severely 

affect earnings and the ability to pay dividends. 

Most PGA mechanisms pass changes in purchased gas prices and transmission costs directly on to consumers. Some also provide for flow-through of the 

changes in the cost of gas — like liquefied natural gas or gas from underground 

storage reservoirs — used during extreme weather to meet peak demand, 

because these are often owned by entities separate from the utility. 

Some PGA mechanisms adjust rates annually, but most allow for more 

frequent adjustments, particularly if costs change quickly.

12.2. Electric Utility Fuel Adjustment Mechanisms

Electric utilities in the U.S. generate most of their power with coal and 

natural gas, and both of these are subject to significant price volatility. 

Utilities also buy power from other utilities and from non-utility generators, 

and those prices are also subject to change in response to market forces. 

During the oil embargoes of 1973-74 and 1978-79, when fuel costs shot up 

suddenly, most electric utilities sought and received approval for their first 

fuel adjustment clauses. 

These have since evolved into more complex mechanisms. Some track 

only fuel cost, some include short-term purchased power, some include all 

purchased power, and some include all power costs (including the investment 

costs in utility-owned power plants). Some allow for dollar-for-dollar flowthrough of actual costs, while others have specific formulae that require the 

utility to bear some risk of cost variations between general rate cases. 

For most utilities, the FAC creates much more variation in consumer 

prices than the changes approved in general rate cases do, because these costs 
71

Electricity Regulation in the US: A Guide

are large and volatile. Many utilities manage these costs by buying their fuel 

on long-term contracts, or even buying the coal mines and gas wells that 

provide the fuel. FACs have been criticized for removing the incentive that 

utilities have to manage, stabilize, and contain their fuel costs.

12.3. Benefit Charges for Energy Efficiency

Most electric and gas utilities provide energy efficiency services to their 

consumers. In recent years, the amount invested has become more significant 

for many utilities, and they have sought approval for adjustment mechanisms 

to recover these costs. The most common form, a system benefit charge (SBC), 

applies to all consumers using the distribution system.

An SBC is typically structured so that utilities collect a surcharge, often 

calculated as a percentage of revenues, on all sales of electricity or natural gas. 

This goes into a separate, dedicated account, and the utility makes expenditures 

from that to support consumer efficiency programs. If the programs are very 

successful and the funds run out, the utility may seek an increase to the SBC at 

any time. See Section 13, Energy Efficiency, for more information.

A variation on the energy efficiency system benefit charge is one that applies 

for additional purposes, such as demand response costs or clean energy. 

A clean energy surcharge can be used to recover the premium a utility pays 

for renewable power that is not covered in its base rates; this is particularly 

applicable for utilities without an FAC or other cost recovery mechanism.

12.4. Infrastructure and Other “Trackers” 

An assortment of other adjustment mechanisms and trackers are used 

to ensure that some cost, revenue, tax, or other element of utility rates is 

recovered, and that changes in those cost elements need not await a general 

rate case to be recognized. One kind of tracker is a surcharge to recover local 

government taxes that may not be uniform throughout the utility service 

territory, and which can be changed without approval of the utility regulator. 

A surcharge can also collect money for extraordinary costs that are timelimited, such as storm damage or the refund of a one-time tax benefit. Others 

adjust for such things as nuclear decommissioning costs, new investment in 

infrastructure between rate cases, and refunds of specific amounts of money 

ordered by the commission.

All these adjustments are implemented separately from a general rate case, 

are associated with specific cost accounts, and are typically noted separately 

on the consumer bill. Consumer advocates are often critical of these singleissue trackers, asserting that they mostly follow increasing costs, while other 

costs that may be decreasing over time are only addressed in periodic general 
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Electricity Regulation in the US: A Guide

rate cases, creating a “heads I win, tails you lose” situation for the utility. 

Consumer advocates also point to cases where these trackers proliferate such 

that consumers do not see any of them clearly as they examine their bill. 

They argue that instead of conducting single-issue rate making, commissions 

should consider all costs, including those that decline over time due to 

productivity, technological innovation, and other causes.

12.5. Weather-Only Normalization

A weather-only normalization mechanism adjusts the utility rates 

periodically so that weather variations do not affect utility profits. This is 

particularly relevant for natural gas utilities, where weather can dramatically 

affect sales and profits. Utilities use sophisticated computer models in each 

rate case to calculate how their sales vary with weather, and commissions are 

familiar with their methods. Weather-only mechanisms use the same model 

to calculate how much sales varied from the level assumed in the rate case. 

Compared with the flat rate shown in Figure 9-5, if weather caused lower 

utility sales, the utility would be allowed to recover an additional $.05 in 

revenue for each kWh of sales reduction due to weather, and vice-versa if 

sales were higher than assumed in the rate case: a small surcharge (surcredit) 

would recover (refund) the difference. Weather-only normalization is a form 

of limited decoupling, which is described in Section 15.

12.6. Deferred Accounting and Accounting Orders

Under normal accounting principles, expenses such as fuel costs incurred 

in one period must be deducted from income in the same period. In order for 

a utility to keep an expense on its books for future recovery, the commission 

must approve an accounting order. This provides some assurance that future 

recovery is likely, and that therefore a deviation from normal accounting is 

appropriate. Similarly, under normal accounting rules, once an asset is placed 

in service, the utility must begin recording depreciation expense each month, 

accounting for the asset being used up.

While all the tracking mechanisms described above generally do have 

accounting orders to support them, accounting orders are often used without 

any immediate change in rates. For example, a utility may have a new power 

plant come into service before a rate case is decided, and the commission 

may allow the utility to accrue a return on that plant investment, for future 

recovery in rates that take effect at the end of the rate case. In essence, the 

accrual of interest during construction may be allowed to continue after 

completion until new rates are implemented.
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Electricity Regulation in the US: A Guide

13. Integrated Resource Planning/

Least-Cost Planning

I

ntegrated resource planning (IRP, or least-cost planning) evolved in the 1980s, 

in the wake of the significant costs of a variety of expensive new power 

plants — some finished, and some abandoned during construction — that 

caused sharp electric-rate increases in many parts of the United States.

Of course, all utilities do some sort of long-range planning, but not all 

these plans are developed with the involvement of the regulator and other 

stakeholders. Not all regulators require IRPs to be prepared; of those that do, 

not all approve them, while others accept them without ruling; and some 

utilities prepare them without any regulatory requirement to do so. 

This section discusses a formalized system of planning for future power 

supply, transmission, and distribution needs, including a provision for public 

involvement and commission oversight.

13.1. What is an IRP?

IRPs examine forecasted load growth for a utility, and evaluate alternative 

means of meeting that growth.53 These documents look at a wide range of 

options to meet future needs, including continued operation of existing 

power plants, building new power plants, or buying power from nonutility generators,. They may also consider non-generation alternatives, 

such as investing in energy efficiency programs, promoting efficient new 

construction, reducing transmission and distribution system line losses, 

encouraging customer-owned generation, and any other available, reliable, 

and cost-effective means of meeting customer needs.

Some IRPs also consider local and regional transmission requirements, 

setting forth a plan for future upgrades to existing lines and/or construction of 

new lines. Because utilities sell power to one another, additional transmission 

interconnections may eliminate the need for construction of new power plants.

The goal of an IRP is to identify the least-cost resource mix for the utility 

and its consumers. Least-cost in this case means lowest total cost over the 

planning horizon, given the risks faced. The best resource mix is typically the 

53 In some cases, utilities may be facing predicted load declines, rather than increases. Even so, 

the principles of integrated resource planning remain the same.
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Electricity Regulation in the US: A Guide

one that remains cost-effective across a wide range of futures and sensitivity 

cases — the most robust alternative — and that also minimizes the adverse 

environmental consequences associated with its execution. Most IRPs do 

not consider distribution-plant improvements that can reduce line losses 

and avoid the need for generation; but increasingly, utilities are including 

consideration of non-traditional alternatives. 

13.2. How Does an IRP Guide the Utility and the Regulator?

An IRP compares multiple alternatives, and examines the costs, reliability, 

and environmental impacts of each. The utility will use the results of the 

IRP to decide what types of resources to acquire, whether it’s better to own 

power plants or buy power from others, and how to manage its programs 

to achieve the desired results. The regulator may use the IRP to determine 

what investments the utility may make, and it should use the IRP as one 

tool in evaluating the prudence of the utility’s actions over time. However, 

simply including a proposed resource in an IRP (whether approved or merely 

accepted by the regulator) does not necessarily “make it prudent” or confer 

pre-approval, nor does it excuse the utility from continuous re-examination 

of proposed projects in light of such factors as changing loads, changing 

costs, and emerging alternatives. 

Roughly 30 states rely on IRPs, and the manner in which they do so varies. 

Some consider the IRP approval process to be pre-approval of the investments 

that follow, but most still conduct project-specific prudence review before 

those investments are included in rates. The detailed and complex nature 

of an IRP often means that its success or failure depends critically on the 

commitment of utilities to the process, and on the involvement of the 

commission and stakeholders. 

13.3. Participating in IRP Processes

Where the regulator requires an IRP, it often provides for the participation 

of stakeholders — consumers’ groups, industries, environmental advocates, 

business groups, and others — in the planning or review process. 

An IRP advisory group may be formed to review drafts, propose 

alternatives for evaluation, and report to the regulator when the finished 

product is submitted for review. Sometimes stakeholders can intervene in the 

formal regulatory process; each state that requires IRPs has its own approach. 

The detailed and complex nature of the IRP can make it a challenging and 

resource-intensive vehicle for stakeholders. 

Environmental regulators participating as stakeholders can also inform 

the IRP process. Any new power plant that receives a certificate of approval 

from a utility regulator will also usually require environmental permits. 
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Electricity Regulation in the US: A Guide

Environmental regulators may also want to ensure that the IRP assumptions 

are consistent with those used by air, land, and water regulatory agencies in 

their respective resource-planning efforts. The IRP can help environmental 

regulators determine, first, whether their existing standards are adequately 

protective; second, the level, timing, and stringency of future air, land, and 

water standards; and third, the potential role of energy efficiency in helping 

to meet current and future environmental requirements.

Some regulators examine the proposed IRP in detail, and may order 

changes. Others will conduct a more cursory review, and only determine 

whether the document meets the minimum requirements of their law or rules. 

13.4. Energy Portfolio Standards and Renewable Portfolio 

Standards

Most states have adopted specific resource portfolio standards for utilities. 

Most of these require each utility to meet a specific portion of its energy 

requirements with qualifying renewable resources; these are known as 

renewable portfolio standards (RPS). Several have required a specified mix of 

energy efficiency resources and renewable energy resources; these are known 

as energy portfolio standards. A few, including California, Washington, and 

Minnesota, have adopted requirements for utilities to secure all cost-effective 

energy-efficiency resources.

The map below shows states with RPS requirements as of November 2010.

Figure 13-1: 

State RPS Requirements

Source: Database of State Incentives for Renewables and Efficiency. 

www.dsireusa.org/summarymaps/index.cfm?ee=1&RE=1
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Electricity Regulation in the US: A Guide

13.5. How an IRP Can Make a Difference

The most sophisticated IRP in the United States is probably the regional 

power plan prepared by the Northwest Power and Conservation Council. The 

Council is a four-state body (Washington, Oregon, Idaho, Montana), created 

by Congress in 1980 as part of a regional electric power act that expanded 

the authority of the Bonneville Power Administration. The Council planning 

process is set out in federal law.54

The First Power Plan, published in 1983, led to the termination of two 

partially completed nuclear power plants in which over $2 billion had been 

invested. Once lower-cost and lower-risk alternatives were identified, it 

became clear that continued preservation of the mothballed units was not 

economic. Billions of dollars were saved by the substitution, over the next 

27 years, of energy efficiency investments for supply-side investments. This 

represents a tangible difference for consumers.

The Sixth Power Plan, released in 2010, contains more than 5,000 pages of 

analysis, and recommends that the Pacific Northwest take the following actions:

• 	 Invest in 5,900 megawatts of energy efficiency, virtually all of which is

cost-effective even without any carbon dioxide mitigation requirement;

• 	 Improve energy building codes for residential, commercial, industrial,

and agricultural facilities;

• 	 Invest in approximately 5,000 megawatts of wind and geothermal

resources;

• 	 Plan for the possibility of some additional natural gas generation,

particularly for peaking;

• 	 Potentially retire existing coal plants and replace them with new

generating facilities, which will become cost-effective if the price of 

carbon exceeds $40/ton.

The Council process is public, transparent, and very technically 

sophisticated. While IRPs in other states may also be highly sophisticated, 

none currently come close to the detail, rigor, or transparency of that 

prepared by the Council. 

For more details:

National Association of Regulatory Utility Commissioners, 1989, 

Profits and Progress Through Least-Cost Planning.

www.raponline.org/Pubs/General/Pandplcp.pdf

www.raponline.org/docs/rap_moskovitz_leastcostplanningprofitandprogress_ 

1989_11.pdf 

Northwest Power and Conservation Council, 2010, Sixth Power Plan.

www.nwcouncil.org/energy/powerplan/6/default.htm

54 Pacific Northwest Electric Power Planning and Conservation Act, 16 USC 839
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Electricity Regulation in the US: A Guide

14. Energy Efficiency Programs

Energy efficiency is considered cost-effective when the cost of 

installing and maintaining measures that improve the efficiency of 

energy usage, compared with what the consumer would otherwise 

do, is less than the total cost of building, maintaining, and operating 

the generation, transmission, and distribution facilities that would otherwise 

be needed to supply enough energy to achieve the same end-use over the 

same lifetime. There are also environmental costs of both energy supply and 

some energy efficiency measures, which can and should be considered in 

measuring cost-effectiveness.

Energy efficiency is a superior resource to meet consumer needs for many 

reasons. First, it is reliable: high-efficiency air conditioners and lighting 

systems don’t break down in thousand-megawatt increments like power 

plants and transmission lines. Second, a kilowatt saved is worth more than 

a kilowatt supplied, because the utility system avoids transmission and 

distribution costs and line losses, plus it avoids the reserve capacity needed to 

assure reliable service. Last, but not least, the society avoids the pollution and 

other externalities caused by power production. 

This section describes utility involvement in energy efficiency, and 

alternative methods to achieve high levels of energy efficiency in a local area.

14.1. Why Are Utility Commissions Involved?

It is not usually natural for a business to try to reduce the demand for its 

services — yet utilities may be uniquely qualified to play a role in improving 

the efficiency of energy usage. They have relevant technical knowledge, and 

they have a business relationship with all of the energy users in their service 

territory. At a minimum, utilities should be involved in energy efficiency 

planning, because the degree to which consumers invest in efficiency affects 

the extent to which utilities must invest in more costly new supplies and 

efficiency — and this also affects the reliability of the grid. Regulators must be 

involved to ensure that the economic benefits of energy efficiency investment 

are achieved, and to ensure that the regulatory systems in place are adequate 

to allow timely cost-recovery even when sales diminish or decline through 

the utility’s own efforts. 

Economic theory suggests that competition will produce an efficient 
78

Electricity Regulation in the US: A Guide

allocation of goods and services if certain preconditions are met. These 

include the requirements that goods be perfect substitutes for each other 

(rather than unique objects, like the Mona Lisa), that all producers and 

consumers have perfect information, that no producer or consumer is large 

enough to move the market, that there is free entry and exit, and that capital 

is fungible and can be instantly redeployed. None of these precepts holds true 

in the energy field. In particular, consumers seldom have perfect information; 

and low-income households, small businesses, and others have limited or 

very limited access to capital. 

While many of these market failures can be addressed through better 

consumer information, by more accurate, forward-looking pricing of energy, 

or through strict codes and standards, evidence shows that those options 

will not achieve all cost-effective energy efficiency. For this reason, most 

states have determined that there is a role for utilities in achieving what the 

market cannot achieve — wide deployment of cost-effective energy efficiency 

measures.

Utilities usually invest in energy efficiency because their commission or 

state legislature requires them to draw on efficiency as the least expensive, 

most environmentally benign, most reliable, and most “local” energy 

resource available. Even without a commission mandate, utilities may have 

an increasing desire to use energy efficiency as a low-cost solution to the 

risk associated with large anticipated increases in generating costs, and 

in emissions costs (arising, for example, from putting a price on carbon 

dioxide emissions). When mandating energy efficiency, regulators set the 

parameters for an efficiency program or a portfolio of programs, determine 

who will operate the programs, establish the criteria by which programs 

will be evaluated, handle complaints if the program runs into problems, and 

determine the level and timing of the utility’s cost recovery. 

14.2. Utility vs. Third-Party Providers

In some states, third-party providers such as the Energy Trust of Oregon 

and Efficiency Vermont implement statewide energy efficiency efforts. These 

providers receive funding from consumers through the utilities, but they 

are separate economic entities, and generally are subject to oversight and 

regulation by the utility regulatory commission.

Evidence suggests that these third-party providers do at least as well in 

achieving energy savings goals as the most motivated utilities. However, 

it is crucial for them to coordinate with the utilities, so that in addition to 

reducing power plant and transmission needs, the savings are concentrated 

in the locations where they are needed, to avoid distribution-system upgrade 

costs, and coordinated with utility system planning and operations.
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Electricity Regulation in the US: A Guide

14.3. Range and Scope of Programs

Energy efficiency programs address barriers that keep consumers from 

investing in efficiency on their own. These programs are effective only if 

consumers and other market actors voluntarily participate. (Building energy 

codes and appliance and equipment energy standards, to be discussed later, 

are mandatory when they are enforced but do not reflect all cost-effective 

energy efficiency measures.) The barriers to be addressed include lack of 

consumer awareness that savings can be achieved, and lack of information 

about what to do and how to do it. Barriers also include financial limitations 

faced by the consumer, and market failures owing to lack of awareness and 

training among vendors, builders, etc. 

In several states, the utility (or third-party provider) is charged with 

procuring all cost-effective energy efficiency. These organizations must 

operate a complete range of programs directed at all end-uses of energy and 

all classes of consumers. They promote efficiency in both new construction 

and retrofit applications, and work with residential, commercial, industrial, 

institutional, and agricultural customers. 

In other states, utilities are only required to operate limited efficiency 

programs, restricted to some class of consumer, by a limited budget or 

savings-achievement target, or by other specified constraints. 

Utilities or third-party providers offer grant and loan programs to help 

consumers pay for energy efficiency. They also provide technical assessments 

of energy efficiency measures and cost-effectiveness. They engage in market 

transformation programs, to help more efficient technologies become 

commercially viable. And, perhaps most important, they engage in detailed 

program evaluation to ensure that their expenditures provide a net benefit to 

consumers.

In 2009, electric and gas utilities invested over $5 billion in energy 

efficiency programs.
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Electricity Regulation in the US: A Guide

Figure 14-1: 

U.S. Utility Investment in Energy Efficiency Programs 2006-09 

6000

5000

4000

3000

2000

1000

0

Millions Sold

2006 2007 2008 2009

Commercial 

and Industrial

Residential

Low Income

Load Management

Other

Not Allocable 

by Sector

Source: Nevius, M., Eldridge, R., and J. Krouk. 2010. “The State of the Efficiency 

Program Industry: Budgets, Expenditures, and Impacts 2009.” Boston MA: 

Consortium for Energy Efficiency. Retrieved from http://www.cee1.org/eepe/2009AIR.php3 

The level of program activity and expenditure varies dramatically from one 

state to another. In general, the far West and the Northeast have moved more 

aggressively than other regions on implementing energy efficiency, but recent 

movement in Minnesota and Wisconsin and a few other upper Midwestern 

states indicates that the trend is expanding.

2600

3100

3700

5300
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Electricity Regulation in the US: A Guide

Figure 14-2: 

Annual Per-Capita Utility Investment 

in Energy Efficiency Programs by State

Vermont

New Jersey

Pacific Northwest**

Connecticut

Hawaii

California

Massachusetts*

Rhode Island

New York

Iowa

Wisconsin

Nevada

Maine

New Hampshire*

Utah

Minnesota*

Colorado

Arizona

New Mexico

Florida

North Carolina†

Michigan

Wyoming

Illinois*

Maryland

Texas

Missouri

Kentucky†

Nebraska

South Carolina

Arkansas

Indiana

Georgia†

Tennesee Valley Authority

Ohio*

Oklahoma

Mississippi†

Alabama†

Louisiana

Kansas*

South Dakota

North Dakota

$0 $10 $20 $30 $40 $50

0 10 20 30 40 50

* Information from at least one known 

electric program administrator is missing 

from this state.

** Includes aggregated data from Idaho, 

Montana, Oregon, Washington, 

the Northwest Energy Efficiency 

Alliance and the Bonneville Power 

Administration.

† A portion of this state’s budget is 

incorporated into Tennessee Valley 

Authority’s regional budget.

Source: Nevius, M., Eldridge, R., 

and J. Krouk. 2010. “The State of the 

Efficiency Program Industry: Budgets, 

Expenditures, and Impacts 2009.” 

Boston MA: Consortium for Energy 

Efficiency. Retrieved from http://www.

cee1.org/ee-pe/2009AIR.php3

49.38

33.57

28.68

27.64

27.54

27.16

27.09

22.38

19.41

18.52

17.96

16.13

15.83

12.33

11.78

11.03

9.46

7.56

7.26

7.24

7.20

5.01

4.93

4.9

4.89

4.06

3.84

3.76

3.4

3.26

2.69

2.13

2.11

1.67

1.62

1.03

0.93

0.88

0.51

0.33

0.31

0.25

$10.94 Mean per capita
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Electricity Regulation in the US: A Guide

14.4. Cost Causation and Cost Recovery

In most states, all electric consumers pay into the energy efficiency fund 

through a system benefit charge, and all electric consumers are eligible 

to participate in the programs. However, some programs are limited to 

residential and small business consumers; in some states, some or all of the 

amounts paid by large industrial customers are sequestered, and available 

only for the use of the customer that paid them, an approach termed selfdirection. 

In general, the utility is allowed to recover all of its expenditures for 

energy efficiency through a tracking mechanism. In some states, both 

the revenue and expenditures for certain classes of customer are handled 

separately. 

14.5. Total Resource Cost, Utility Cost, and Rate Impact Tests

Regulators and utilities use several different cost “tests” to determine if 

energy efficiency programs are producing good value.

The most important of these is the total resource cost (TRC) test, which 

compares all the costs of energy efficiency measures to all the costs of the 

energy supply alternative. In the TRC, it is critical to count all non-energy 

benefits of efficiency measures, considering their implications for water, 

sewer, natural gas, and other savings. It is equally critical to count all the 

costs of the power supply alternative, including production, transmission, 

distribution, line losses, reserve power plants to cover outages, quantifiable 

environmental costs of power supply, and any cost incurred directly by the 

customer.55 A variation of the TRC, called the societal cost test, includes nonmonetary costs and benefits such as environmental damage and health impact 

costs, on the one hand, and improved customer amenity value derived from 

efficiency measures on the other.

The program administrator cost test (PACT, utility cost test, or UC test) 

measures only those costs and benefits that affect the utility or the customer’s 

bill from the utility. The non-energy benefits of efficiency, as well as costs 

paid directly by the customer (not through the utility), are not counted. The 

only environmental costs and benefits included are those for which the utility 

must actually pay. For example, if a utility pays a 50% incentive for a lighting 

retrofit, only half the cost of the efficiency measure would be counted, and 

55 Some states have applied the TRC in a more limited fashion, excluding avoided transmission 

and distribution capacity costs, marginal line losses, quantifiable environmental costs, or 

non-energy benefits such as water, sewer, and soap savings. Where costs or benefits are 

excluded, the value of the analysis is impaired.
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Electricity Regulation in the US: A Guide

compared with 100% of the energy savings benefits as measured by the 

utility’s cost of providing energy. Conversely, a high-efficiency clothes washer 

provides energy, water, sewer, and soap savings, but the PACT counts only 

the energy savings. The PACT also excludes many of the environmental costs 

of generating electricity. The PACT is a useful tool for determining if a utility’s 

limited efficiency budget is helping achieve the maximum level of efficiency, 

but it does not measure the overall cost-effectiveness of the program.

The ratepayer impact measure (RIM) test measures whether a given 

efficiency program causes rates to rise or fall for non-participants in the 

program. Most energy efficiency measures that save a significant amount of 

energy fail the RIM test. Utility costs go up to pay for all or part of the cost 

of energy efficiency measures. In addition, utility revenues decline because 

the customers installing the energy efficiency measures use less energy. As a 

result, higher utility costs must be divided among fewer utility sales in setting 

rates, and rates per unit of energy go up, even though the total of customer 

energy bills goes down. Some efficiency programs focused on peak-period 

usage do pass the RIM test, because they avoid the need for expensive, 

seldom-used resources needed only to meet peak demands while not 

reducing overall revenues much.

14.6. Codes, Standards, and Market Transformation

Many energy efficiency measures are so cost-effective that state or federal 

law mandates require them. The most familiar of these are building energy 

codes for new construction, and appliance efficiency standards for major 

home appliances. Such codes and standards generally are implemented after 

measures have been proven up through incentive programs offered by utilities 

or third-party providers. 

In a variety of ways, utility or government investment in energy efficiency 

research, development, and demonstration can lead to market transformations,

through which an improved mix of products is offered to and purchased by 

consumers. For example, offering incentives to manufacturers may lead to 

the availability of higher-efficiency products, and educating architects and 

developers may lead to the specification of higher-efficiency measures in 

new buildings. These methods may be far less expensive than programs to 

influence ultimate consumers.

Many states have adopted energy efficiency resources standards (EERS) 

for their utilities. An EERS requires a utility to meet a specified portion of 

its energy needs through energy efficiency — in effect, energy efficiency 

would decrease the demand for power by a certain amount and can thus 

be considered a resource in its own right. The standards do not necessarily 

require that the utilities invest funds directly in actual installations: support 
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Electricity Regulation in the US: A Guide

of codes, standards, and encouragement of voluntary programs may suffice 

to achieve some or all of the required energy efficiency. As of 2010, 24 states 

have adopted EERS of some form, and four have pending standards.56

For more detail:

Regulatory Assistance Project, 2007, Energy Efficiency Policy Toolkit.

www.raponline.org/Pubs/Efficiency_Policy_Toolkit_1_04_07.pdf 

Renewable Energy and Energy Efficiency Partnership, 2010, 

Compendium of Best Practices: Sharing Local and State Successes 

in Energy Efficiency. www.raponline.org/docs/RAP_REEEP_

CompendiumofBestPractices_2010_05_28.pdf

Regulatory Assistance Project, 2010, Smart Policies Before Smart Grids: 

How State Regulators Can Steer Smart Grid Investments Toward 

Customer-Side Solutions. www.raponline.org/docs/RAP_Schwartz_

SmartGridACEEEsummerstudy_2010_8_17.pdf

American Council for an Energy Efficient Economy, 2010, State Energy 

Efficiency Policy Database. www.aceee.org/sector/state-policy/utility-policies

Consortium for Energy Efficiency, Energy Efficiency Program Budget and 

Expenditure Data. www.cee1.org/ee-pe/2009AIR.php3#budgetdata 

56 A survey of EERS in place is available from the American Council for an Energy Efficient 

Economy at www.aceee.org/node/5981
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Electricity Regulation in the US: A Guide

15. Aligning Regulatory Incentives 

with Least-Cost Principles

I

n Section 9, we discussed some problems with conventional regulation, 

including the incentives it gives utilities to maximize sales. Commissions 

have become increasingly concerned with these incentives, and have 

pursued options to align the utility’s interest in maximizing net income 

with the consumer’s interest in minimizing energy costs by reducing energy use.

This section discusses how implementation of energy efficiency may 

reduce utility profits, and how regulators can change the traditional 

regulatory framework to improve utility receptiveness to energy efficiency 

programs.

15.1. Effect of Sales on Profits

While energy efficiency is generally the most cost-effective way to meet 

the demand for additional energy services, in general if utility sales go 

down, revenues and profits decline. Because the utility’s return is embedded 

in the rate per unit for electricity (or gas), each incremental sale brings 

incremental profit, and each lost sale costs the utility net income. As we 

noted in discussing the throughput problem in Section 10, utility rates 

generally are designed by regulators to reflect long-run costs, such as 

permanent employees, power plants, and distribution lines. But in the short 

run, between rate cases, the only significant change in utility costs as sales 

go up or down is the variable cost of producing or purchasing more or less 

power. Because incremental sales produce revenue that usually exceeds 

incremental expense in the short run, a utility has a strong motive to increase 

its throughput.57 If sales go up, the existing investment in power plants 

and power lines is spread out over a larger number of units, so the utility is 

getting more revenue out of them. 

57 This economic characteristic—that of marginal revenue almost always exceeding shortrun marginal cost—is a general feature of natural monopolies and is a powerful driver of 

management behavior. Average cost, on which prices are based, usually exceeds short-run 

marginal cost, across very wide ranges of demand. It’s particularly true of distribution-only 

utilities, which face virtually no incremental cost (in the short run) for the delivery of an 

incremental unit of energy.
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Electricity Regulation in the US: A Guide

15.2. Techniques for Aligning Incentives

A number of measures have attempted to overcome this throughput 

incentive, with varying success and side effects. Some of these have reduced 

financial risk for utilities by giving them greater certainty of earning their 

expected return. (In general, measures that reduce utility risk should 

be accompanied by a review of the allowed rate of return to ensure that 

consumers pay a fair rate for both the service provided and the risk borne by 

the utility.)

15.2.1. Decoupling

Decoupling can reduce throughput incentives, since (as noted earlier) 

it ensures that the utility’s revenues, in certain defined categories, are not 

affected by sales volumes.58 Traditional regulation sets a revenue requirement, 

based on costs, then divides that by sales and calculates rates. The rates 

remain constant, even though the sales may vary. Decoupling turns this 

around. It adjusts rates in response to changes in sales, so that the amount of 

revenue recovered stays at the level approved by the commission. 

Some costs do go up and down with sales volumes. Fuel and purchased 

power are examples; but for most utilities, these are recovered through the 

fuel adjustment clause (FAC). A decoupling mechanism typically recovers 

all the utility’s costs that are not covered by the fuel and purchased power 

adjustment clause (FAC) or by other adjustment clauses. All distribution 

and power supply costs excluded from the adjustment clauses are recovered 

through the decoupling mechanism. For example, a one percent decrease in 

sales would cause a less than one percent increase in the rates, because there 

are some variable power cost savings resulting from reduced production (e.g., 

avoided fuel costs).

Some decoupling mechanisms operate on a current basis, applying the 

necessary change in rates as bills are sent out each month to ensure that 

the right amount of money is collected. Most mechanisms operate on a 

deferral basis, with any amounts not recovered or over-recovered due to 

sales variations being deferred and recovered, or refunded, the following 

year. Some mechanisms set a fixed or formula amount of revenue to be 

recovered each month or year, while others set an amount to be recovered per 

customer, so that changes in the number of customers results in changes in 

utility revenues. In all cases, however, consumers continue to pay volumetric 

rates, so that reduced usage by any one consumer means a lower bill for that 

consumer.

58 This is an abbreviated discussion of the topic; two detailed RAP papers on decoupling are 

available on the RAP website. See www.raponline.org.
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Electricity Regulation in the US: A Guide

Decoupling mechanisms are divided into three categories:

• Full Decoupling: All variations in sales volumes are included in the 

calculation of the decoupling adjustment.

• Limited Decoupling: Only specific causes of changes in sales volume 

are included. For example, changes in sales due to weather may be 

excluded, with sales volumes recalculated based on the normal weather 

conditions used in the rate case.

• Partial Decoupling: Only a portion of the revenue lost or gained due to 

sales volume variations is included in the calculation of the decoupling 

adjustment. For example, the commission may allow only 90% of the 

lost or gained revenue to be included.

Decoupling is relatively simple to administer. Each billing cycle, month, 

or year, the amount of revenue allowed in the rate case is compared to the 

amount actually recovered. A surcharge or credit is imposed to make up the 

difference. Except for the effects of weather, typical surcharges or credits are 

no more than a few percent, because sales volumes from non-weather causes 

typically do not vary all that much from the levels assumed in the general 

rate case. In limited decoupling mechanisms, where changes in sales due 

to weather are normalized, the rate changes are typically a fraction of one 

percent, but customers are exposed to higher bills during months of severe 

(hot or cold) weather.

Sometimes decoupling is referred to as formula rates, in which the 

commission adopts a rate formula in the rate case, and the rates themselves 

are adjusted periodically between rate cases by updating the data used in the 

formula, including sales volumes. However, formula rates can also encompass 

other types of incentive and adjustment mechanisms.

15.2.2. Lost Margin Recovery

Lost margin recovery, or lost contribution to fixed costs, is a form of 

limited decoupling. Lost margin recovery provides a mechanism through 

which the utility recovers any revenues lost as a result of utility-operated 

energy efficiency programs. In the flat rate design shown in Figure 9-5, for 

example, the utility has about $.05/kWh included in the rate for costs that do 

not change as usage changes. The utility would get to recover an additional 

$.05 for each kWh of sales displaced by utility efficiency programs. However, 

the utility would not get any recovery of lost margin if consumers invested 

in efficiency themselves, or if sales declined due to economic conditions, 

weather, or other factors. Because fewer costs are included, the rate changes 

are generally smaller than under full decoupling. 

Lost margin recovery requires a more extensive review and analysis of 
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Electricity Regulation in the US: A Guide

the amount and value of savings. As a result, it may lead to more significant 

disputes in the rate-setting process. Further, added sales still redound to the 

benefit of the utility, so the throughput incentive to build load remains.

15.2.3. Frequent Rate Cases 

Filing frequent rate cases is another way in which a utility can keep its 

allowed revenue and the actual revenue tracking closely, so that reduced 

sales from efficiency measures do not lower profits very much or for very 

long. Even if efficiency efforts are reducing sales, if the utility files a new rate 

case every year, it is never more than one year of sales change “off” from the 

level set in the rate case. However, even in that short period of time, energy 

efficiency will diminish profits slightly; utilities may be unmotivated to have 

efficiency programs succeed; and increased sales still benefit the bottom 

line. Frequent rate cases are also time-consuming and expensive: between 

the utility, the commission, and the intervenors, a rate case can easily cost 

$5 million in staff time, expert witnesses, and attorney fees. While there are 

good reasons to have a periodic rate case, going through the process solely for 

the purpose of reflecting the effects of energy efficiency, when a decoupling 

mechanism can have the same effect, is quite burdensome. 

15.2.4 Future Test Years.

Some commissions use future test years to set rates. As Section 8 describes, 

these set the expected sales based on forecasts of costs and sales. If the utility 

has forecast that sales will decline due to efficiency efforts, this will already be 

reflected in the sales estimate used in the rate case, and the utility will recover 

the “right” amount of revenue if energy efficiency achievement is as expected. 

Even in this situation, however, the utility would earn higher profits if energy 

efficiency achievement were lower, so the throughput incentive remains. In 

theory, a commission could set rates for several years in advance, building 

in rate adjustments based on forecasts, to avoid annual rate cases. However, 

this would have the same problem — if the energy efficiency performance 

fell short of the forecast, utility earnings would increase, creating a multi-year 

throughput incentive. 

15.2.5. Straight Fixed-Variable Pricing (SFV).

Some utilities and regulators have implemented pricing schemes that 

collect not only customer-specific costs, but all of the distribution costs that 

do not vary with sales in the short run as a fixed charge each month. They 

then include only the variable costs of fuel and purchased power in the rate 

per unit. This is called straight fixed/variable pricing, or SFV. This compares 

to the rate design discussed in section 9.4, in which the customer charge is 

based solely on the cost of meters, meter reading, and billing. 
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Electricity Regulation in the US: A Guide

Figure 15-1 shows an example of SFV, assuming fuel (and other variable) 

costs of about $.05/kWh. While SFV pricing protects utility profits from 

erosion when sales decline, and does not give the utility a load-building 

incentive, this type of pricing deviates from the economic principle that rates 

should, as a general matter, be based on long-run marginal costs. Moreover, 

SFV may be considered inequitable: it imposes much higher bills on lowvolume users, since the fixed portion of the charge is, in effect, spread 

across fewer units of sale than it is for higher-volume users. Typically small 

users are less expensive to serve, because they are closer together (smaller 

homes; apartments, condos, and mobile homes), and because they require 

smaller wires and transformers. SFV rates also have the effect of insulating 

the customers’ bills from their own consumption, significantly reducing the 

value of energy efficiency to customers. There is also a political concern about 

raising the total bill by such a significant percentage (44% in the example in 

Figure 15-1) for low-usage customers.

SFV rates favor the largest residential users, at the expense of smaller 

users. Large residential users are typically those with space conditioning 

loads — heating and cooling. Those loads are the most expensive to serve, 

because they are so weather-sensitive, requiring investment in seldom-used 

generation, transmission, and distribution capacity. Compared with invertedblock rates, an SFV rate masks the full cost of serving space conditioning 

loads.

Figure 15-1: 

Illustrative Straight-Fixed Variable Rate Design

$200

$150

$100

$50

$0

0 300 600 900 1200 1500

Monthly Bill

kWh/Month

Flat Rate

Straight 

Fixed/

Variable 

Rate

Inverted Rate
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Electricity Regulation in the US: A Guide

15.2.6. Incentive/Penalty Mechanisms

Some commissions have simply created profit incentives and/or penalty 

mechanisms for energy efficiency. If the utility achieves or exceeds its target, 

it receives a financial reward, typically a percentage of the energy cost savings 

that consumers receive. If it falls short of the target, it may be subject to a 

penalty.

Early efforts at providing incentives in this manner rewarded the utility 

with a percentage of the spending on energy efficiency; however, this 

approach rewards spending rather than efficiency gains. A few states have 

tried granting a bonus to the return on equity in efficiency investment, but 

have found this encourages gold-plating, not maximization of cost-effective 

investment. Most commissions that have incentive structures have abandoned 

the percent of budget approach in favor of a shared net benefits approach, 

in which the utility garners some share of the underlying real value of the 

efficiency programs.

For more details:

Regulatory Assistance Project, 2006, Energy Efficiency Policy Toolkit.

www.raponline.org/Pubs/General/EfficiencyPolicyToolkit.pdf

Regulatory Assistance Project, 2008, Revenue Decoupling — Standards and 

Criteria, A Report to the Minnesota Public Utilities Commission. www.

raponline.org/docs/RAP_RevenueRegulationandDecoupling_2011_04.pdf

Regulatory Assistance Project, Forthcoming, Revenue Regulation & Decoupling: 

Theory and Application Guide. See www.raponline.org.

Customer Charge $5.00 $5.00 $55.00

First 500 kWh $0.10 $0.05 $0.05

Over 500 kWh $0.10 $0.15 $0.05

Customer Bill

0 kWh $5.00 $5.00 $55.00

500 kWh $55.00 $30.00 $80.00

1,000 kWh $105.00 $105.00 $105.00

1,500 kWh $155.00 $180.00 $130.00

Flat

Rate

Inverted 

Block 

Rate

Straight 

Fixed/Variable 

Rate
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Electricity Regulation in the US: A Guide

16. Regulatory Treatment 

of Emission Costs

Coal-fired power plants produce almost half of America’s electricity, 

and natural gas plants provide another quarter of it. Burning either 

of these fossil fuels emits pollutants currently regulated under the 

Clean Air Act, along with carbon dioxide and pollutants likely to 

be regulated in the future, such as mercury. 

This section briefly discusses how regulatory commissions treat emissions 

costs.

In general, regulatory commissions have allowed utilities to recover the 

cost of required pollution control equipment, but there are a few exceptions. 

In particular, if a commission finds that a utility has been imprudent, it may 

disallow a portion of these costs.

16.1. Currently Regulated Emissions

Sulfur Dioxide (SO2): A nationwide cap-and-trade program on SO2 

emissions has been in place since 1990 to reduce acid rain and other 

adverse effects. The program initially granted free allowances to utilities, 

based on their pre-1990 emissions levels; but it has reduced these 

allowances each year, and now only about half as much sulfur is allowed 

to be released as when the program began. Under the proposed Transport 

Rule issued by the U.S. EPA in August, 2010, SO2 levels will have to be 

reduced substantially below current levels.

Nitrogen Oxides (NOX): Emissions of nitrogen oxides have been reduced 

by over 60% since regulations took effect in 1998 in California, the 

Northeast, and the Mid-Atlantic states. NOX regulations will likely be 

strengthened in the future.

Particulates: Power plants emit small particles of solid matter when they 

burn fuel. This is particularly significant for coal- and wood-fired plants, 

but burning oil also emits particulates. EPA’s Clean Air Visibility Rule 

requires states to develop and implement plans for electric generating 

units that were placed into service between 1962 and 1977. Current 
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Electricity Regulation in the US: A Guide

regulations govern particles down to 2.5 microns in diameter. There is 

evidence that even smaller particulates, known as nano-particulates, have 

adverse health effects, and these may be regulated in the future.

Water: Power plants are subject to regulations, both on the amount of 

cooling water they can draw and on the pollutants they may discharge 

with it. These standards are likely to be strengthened in the future.

16.2. Anticipated Regulation

Carbon Dioxide (CO2): In New England, utilities are already subject 

to limitations on CO2, and are required to purchase allowances from 

a regional auction. A portion of the proceeds from those transactions 

pay for energy efficiency and renewable energy programs, and a portion 

goes to the states for general tax purposes. Regulators in New England 

review utility operations to see if they are acting prudently in acquiring 

power from plants that emit CO2, and acquiring allowances to meet their 

obligation. The costs they judge prudent flow through to consumers. 

Nationally, CO2 will likely be regulated either by the U.S. EPA under the 

Clean Air Act, or in a separate program if carbon regulation is approved 

by the Congress. The forms of future regulation is not known, nor are the 

associated costs that utilities will incur.

Mercury: Many states currently regulate mercury emissions. The U.S. EPA is 

currently implementing regulations for emissions of mercury on a national 

basis. These regulations will likely require retrofits of many coal-fired 

power plants.

Coal Ash: The ash that is precipitated from coal smokestacks contains 

an assortment of hazardous materials, dependent on the chemical 

composition of the coal. EPA is proposing new regulations for 

management and disposal of coal ash under the Resource Conservation 

and Recovery Act. 
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16.3. Commission Treatment of Emissions Management Costs

In the past, regulatory commissions have generally allowed the cost of 

emission regulation to flow through rates to consumers. Some have done so 

using the traditional regulatory model, considering these costs along with 

all others in general rate cases. Others have created separate adjustment 

mechanisms to flow the actual varying costs through between general rate 

cases.

In the future, regulatory commissions will be faced with additional 

requests from utilities dealing with increased emissions costs. Because the 

regulations are not all being implemented simultaneously, it is crucial that 

regulators look at these costs prospectively — requiring utilities to consider 

not only those emission regulations that are imminent, but also those that are 

likely in the future. 

In some cases, it may not be cost-effective to continue operating existing 

units once the additional regulations are in place, taking into account the 

remaining life of the units, the cost of retrofits, and the operating costs 

of pollution control equipment. Alternatives, including energy efficiency, 

renewable energy resources, or high-efficiency natural gas generation may be 

less expensive than continued operation of older power plants. 

Commissions will have to determine whether or not to allow utilities 

to invest in and recover the costs of the retrofits and emission allowances 

needed to continue operating those plants, and perhaps whether to 

allow them to recover the costs of remaining investment in uneconomic 

power plants that are shut down. It is important that commissions look 

comprehensively at the costs of future environmental compliance for 

power plants, so that plants for which it is cost-effective to meet all future 

requirements are improved, and those that are not are phased out.

For more details:

Regulatory Assistance Project, Forthcoming, 

Regulatory Treatment of Emission Costs. www.raponline.org/docs/RAP_

RegulatoryTreatmentofEmissionCosts_2011_05.pdf 
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Electricity Regulation in the US: A Guide

17. Low-Income 

Assistance Programs

Utilities in many states provide various forms of assistance for 

low-income consumers, augmenting state and federal programs. 

Low-income advocates often use general rate cases as a forum to 

seek new or augmented low-income assistance programs. A few of 

these are summarized here. 

17.1. Rate Discounts

In many states, rates to all customers are cost-based, with no policy-driven 

subsidies. Other states explicitly allow or direct the commission to subsidize 

rates. For example, many utilities have various forms of lifeline rates, such 

as a discounted rate for all or for some energy used by income-qualified 

consumers. Rates to all are higher to fund this discount, and all consumers 

are considered to be better off because utility service to consumers with the 

lowest incomes is more secure. 

A lifeline rate should not be confused with a baseline inverted block rate,

which provides every consumer with a certain amount of low-cost power, 

then prices usage above that at levels reflecting long-run marginal costs. An 

inverted block rate is cost-based. A lifeline rate is typically an overt discount, 

not based on costs at all — although if the lifeline discount applies only to a 

limited amount of power, it may have the effect of creating an inverted rate 

design for eligible consumers in a system that otherwise has flat rates. 

Some programs waive the basic monthly charge for income-eligible 

consumers. This has the effect of reducing bills without reducing the 

incentive to use electricity wisely, because the rate per kWh (or per therm) 

remains the same.
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Electricity Regulation in the US: A Guide

Figure 17-1: 

Illustrative Examples of Lifeline Rates

Customer Charge $5.00 $5.00 $ –

First 500 kWh $0.10 $0.05 $0.10

Over 500 kWh $0.10 $0.10 $0.10

Customer Bill

0 kWh $5.00 $5.00 $ –

500 kWh $55.00 $30.00 $50.00

1,000 kWh $105.00 $80.00 $100.00

1,500 kWh $155.00 $130.00 $150.00

Non-Lifeline 

Rate

Lifeline 

Rate

Block

Zero 

Customer 

Charge

17.2. Energy Efficiency Funding

Because low-income consumers typically cannot afford to pay even a 

part of the cost of energy efficiency measures, typical insulation levels and 

appliance efficiency are much lower in their homes. Some federal programs 

support weatherization of low-income homes, but they typically do not 

pay all of the costs, and there can be a lengthy waiting period that misses 

opportunities. Neither do typical utility efficiency programs available to all 

consumers pay all costs. 

However, many states have combined utility and federal programs to 

provide full funding for installing low-income energy efficiency measures. 

In some states, additional programs funded partly or wholly by utilities pay 

for lighting conversion, refrigerator replacement, and other measures to help 

low-income consumers reduce their usage and their bills.

17.3. Bill Assistance 

Federal funds in the Low Income Home Energy Assistance Program 

(LIHEAP) provide direct grants for bill assistance, but in most areas these 

typically fall short of the need. Utility bill assistance programs may come from 

donated funds, shareholder funds, ratepayer funds, or some combination of 

these. Some states have dedicated utility deposits abandoned by consumers 

to providing low-income bill assistance. When all or a portion of the 

costs of bill-assistance programs is included in rates to other consumers, 
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Electricity Regulation in the US: A Guide

representatives of commercial and industrial consumers often contest 

whether all customer classes should share in the burden. 

17.4. Payment Programs

Most utilities have budget billing programs that provide a uniform bill each 

month. These are typically available to all consumers; but in many states, 

commissions have established specific payment programs for low-income 

consumers. These may include a deferral without interest, a bill limited to 

a percentage of income with the balance covered by bill-assistance funds, a 

fixed monthly credit to the bill, or other approaches. 

17.5. Deposits

Utilities often require customers applying for utility service to pay a 

deposit related to the average or expected monthly bill, to protect the utility 

from non-payment. Utilities typically credit interest on this deposit to the 

consumer, at the utility’s short-term borrowing cost; a few also pay interest 

on any overpayment or credit balance at the same rate they charge consumers 

with delinquencies. 

Nonetheless, deposits can be a burden for low-income consumers, 

who often seek to minimize these requirements. Some states require that 

deposits be waived for consumers who can establish creditworthiness, and 

some require that they be refunded after a year or so if a customer pays bills 

regularly. 

17.6. Provision for Uncollectible Accounts

In general rate cases, commissions establish a provision for uncollectible 

accounts, which is typically a percentage of the total utility revenue 

requirement. This is typically estimated on a multi-year average of actual 

experience. The rates for all customers are then designed to produce a little 

bit more than the utility’s actual revenue requirement, recognizing that a 

small percentage of the energy delivered to consumers will not be paid for. 

Therefore all consumers, not utility shareholders, generally bear the cost of 

unpaid bills.
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17.7. Disconnection/Reconnection

When low-income consumers do not pay their bills, utilities eventually 

disconnect their service, following policies and procedures that regulators 

establish. These typically involve at least two written notices, and often 

require actual physical notice posted at the premises before disconnection 

— because postal notices are not always seen, and disconnection can cause 

serious health problems for consumers who rely on electricity for medical 

devices.

Many states prohibit disconnection during winter months, and some have 

other weather-related limitations, generally designed to protect consumers 

from health risks.

The actual cost of sending utility personnel to the property is quite 

significant, particularly during nights and weekends. Commissions have 

generally been reluctant to impose this entire cost on low-income consumers 

who are in difficulty; and the reconnection fee, which is often decided along 

with other rate-design issues in a general rate case, seldom covers the full cost 

to the utility of the staff time required for disconnection and reconnection. 

Smart meters, discussed more fully in connection with Section 19, 

will allow utilities to avoid these costs by remotely disconnecting and 

reconnecting service — but some low-income advocates have expressed 

concern about disconnection without notice or personal contact. Perhaps 

local social services staff can substitute for the utility visit at lower cost. 

Engineers concerned with safety have also expressed reservations about 

remote reconnection: appliances left on during a disconnection can create fire 

hazards if reconnected when no one is present.

For more details:

Fisher, Sheehan and Colton, Home Energy Affordability Gap.

http://www.homeenergyaffordabilitygap.com/08_AboutFSC2.html

Palast, Oppenheim, and MacGregor, 2003, Democracy and Regulation.

People’s Organization for Washington Energy Resources, 1982, The People’s 

Power Guide, www.raponline.org/docs/WER_PeoplePowerGuide_1982.pdf

See the website of the National Consumer Law Center: www.nclc.org
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Electricity Regulation in the US: A Guide

18. Service Quality Assurance

Many regulators have established standards for the reliability of 

service or quality of customer assistance. This is particularly 

important when setting up multi-year rate plans, where 

the likely result is that the utility will not be in front of the 

commission for an extended period, such as the PBR mechanisms discussed 

in Section 10.

Some of these are formal service quality index (SQI) programs, which 

penalize a utility financially if significant aspects of service fall below 

accepted standards. In a few cases, rewards are also available for exceeding 

standards. SQIs include specific measurable standards, a penalty mechanism 

for shortcomings, a process for review of performance, and some form of 

communication to consumers. These are typically initiated when a utility 

negotiates a multi-year rate agreement, in order to assure that utility earnings 

do not come at the expense of customer service quality. 

Figure 18-1: 

Puget Sound Energy 2009 Service Quality Report
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Electricity Regulation in the US: A Guide

For more details:

Alexander, “How to Construct a Service Quality Index in Performance-Based 

Ratemaking,” Electricity Journal, April 1996.

Regulatory Assistance Project, 1996, Consumer Protection 

Proposals For Retail Electric Competition: Model Legislation 

And Regulations. www.raponline.org/docs/RAP_Alexander_

ConsumerProtectionProposalsforElectricCompetition_1996_10.pdf
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Electricity Regulation in the US: A Guide

19. Smart Grid

The so-called Smart Grid is an important current topic in utility 

regulation. This guide touches on the topic, while other RAP 

publications address Smart Grid issues in more detail. Simply 

stated, a Smart Grid is an integrated system of information 

processing and communication applications integrated with advanced 

metering systems, sensors, controls, and other technologies from the bulk 

power system to individual end-uses that allows the electric utility to manage 

the flow of electricity through the grid more precisely, improve reliability, and 

reduce cost. 

It is hoped that the Smart Grid will eventually:

(1) enable consumers to manage their energy usage and choose the most 

economically efficient way to meet their energy needs;

(2) allow system operators to use automation and a broad array of 

resources to help maintain delivery system reliability and stability; and

(3) help utilities to rely on the most economical and environmentally 

benign resources – generation, demand-side, and storage alternatives – 

to meet consumer demands.

Smarter grids should improve reliability, increase consumer choice, and 

reduce the economic cost and environmental impact of the utility system.

Smart Grids include several key components, including:

• System Control: Supervisory Control and Data Acquisition (SCADA) 

systems to monitor and control power plants, transmission lines, and 

distribution facilities. SCADA systems are being upgraded to handle much 

larger amounts of data at high speed. 

• Smart Meters: Historically residential electric meters have only measured 

consumer energy usage and displayed that data for utility meter readers. 

In addition to energy use, Smart Meters can measure voltage and in the 

future even residential meters may be able to measure reactive power, 

which could encourage improved power factor. Smart Meters collect this 
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data in short time intervals, record the data, and can communicate them 

electronically to the utility, the customer, and customer-designated energy 

service companies.

• Meter Data Management: All of the data from individual meters must 

be received, processed, and converted for billing and other purposes. 

For example, some utilities provide consumers with the data through 

information portals via the Internet.

• Implementation Policies and Programs: In order to achieve the 

goals of Smart Grid, utilities and their regulators must adopt policies 

and practices to make use of Smart Grid assets to enable consumers 

to optimize their power usage and reduce costs. These include 

interoperability standards that ensure that systems and products all work 

together without special effort by the consumer, new rate designs that 

shift load from the highest-load hours of the year, customer assistance and 

education, automated load shedding, enhanced billing, integrating Smart 

Grid capabilities with energy efficiency programs and outage management 

systems, and other elements. 

The hypothetical benefits of Smart Grids are immense, but the realization 

of these benefits is not assured without such supportive policies. Examples of 

the potential benefits include:

•	 Integrating renewable resources like wind by automatically turning

water heaters on and off to keep the system in balance;

•	 Facilitating the charging of large numbers of electric cars to the grid

without overloading existing facilities;

•	 Enabling new rate designs that encourage consumers to better control

their energy bills by reducing usage during high-cost periods, with 

technology that automates response to high prices;

•	 Optimizing voltage and reactive power on distribution systems to

reduce line losses and energy use in homes and businesses; 

•	 Quickly identifying the cause of service outages, even predicting them,

and improving the speed of service restoration;

•	 Automatic meter reading, remote disconnection and reconnection, and

remote identification of power quality problems;

•	 Detecting and responding to problems on transmission grids in realtime; and
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Electricity Regulation in the US: A Guide

•	 Adding intelligence to transformers to protect against faults and

overloads.

Regulators must consider whether the benefits of distinct elements of 

investment comprising Smart Grids exceed the costs. This is a complex 

and necessarily subjective analysis, because the value of reliability and 

rapid restoration of service after an outage are not easily quantified, and 

the environmental costs of utility operations are not precisely knowable. 

The most contentious issues have been the costs of replacing meters and 

utility system control equipment, ensuring that the additional costs of 

that equipment (e.g., installed to help reduce meter-reading costs and 

control energy costs) are properly addressed in rate design, and alternative 

policies options related to rate design implementation (e.g., optional or 

mandatory time-of-use pricing). Some regulators have supported Smart Grid 

investments, and others have found that the benefits do not justify the costs 

in the specific cases before them.

Many of the benefits of Smart Grids can be secured without new rate 

designs. Some categories of benefits – particularly those associated with 

load response – require prices that reflect incremental costs during the 

periods of extreme demand on the utility, and also require communications 

capability between the utility and the customer’s premises to automate the 

control of end-use equipment. The question of whether to make these rates 

optional (opt-in), discretionary (opt-out), or mandatory will be addressed by 

Commissions, and the result of their evaluation may be different for larger 

consumers than for smaller ones.

For more details:

Smart Grid or Smart Policies: Which Comes First?, Regulatory 

Assistance Project, 2009, http://www.raponline.org/docs/RAP_

IssuesletterSmartGridPolicy_2009_07.pdf

Is It Smart if It’s Not Clean? Questions Regulators Can Ask About Smart Grid and 

Energy Efficiency. Pt 1: Strategies for Utility Distribution Systems, Regulatory 

Assistance Project, 2010. http://www.raponline.org/docs/RAP_Schwartz_

SmartGridDistributionEfficiency_2010_05_06.pdf 

Lisa Schwartz, Smart Policies Before Smart Grids: How State Regulators Can Steer 

Investments Toward Customer-Side Solutions, 2010 ACEEE Summer Study on 

Energy Efficiency in Buildings, http://raponline.org/docs/RAP_Schwartz_

SmartGrid_ACEEE_paper_2010_08_23.pdf
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The Smart Grid: An Annotated Bibliography of Essential Resources, NARUC, 

2009, http://www.naruc.org/Publications/NARUC%20Smart%20Grid%20

Bibliography%205_09.pdf 

The Need for Essential Consumer Protections: Smart Metering Proposals and 

the Move to Time-Based Pricing, 2010, http://www.nasuca.org/archive/

White%20Paper-Final.pdf
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Electricity Regulation in the US: A Guide

20. Summary: 

Regulation in the Public Interest

The role of the regulator is complex. Ensuring reliable service at 

reasonable cost involves balancing the interests of utility investors, 

energy consumers, and the entire economy. The lowest possible cost 

generally sacrifices important public goals, so this is generally not 

the result, and regulation is about managing the balance of important public 

goals. Limiting the environmental impacts of the utility system while also 

assuring reasonable prices, reliability, and safety is the daunting challenge that 

utility regulators face. Evolving technology provides new opportunities, but 

also creates new challenges.

In a general rate case, all aspects of utility service are reviewed. Often, 

issue-specific cases are docketed as well, to provide limited review of a 

particular topic. Participating in any of these cases offers opportunities to 

make important changes, but also obliges one to educate oneself about both 

technical issues and the policy framework of regulation.

Most utility regulators welcome public involvement, and are tolerant of 

the limited experience of new participants. In exchange, they expect respect 

for regulatory principles and for the dignity of the process. Regulators also 

expect participants to focus on facts and reasonable theories, and not simply 

rant about high prices.

When a major proceeding begins, all parties need to do their best to 

identify the issues they wish to address, and to make sure the commission 

agrees that those are appropriate for resolution. This avoids costly and 

time-consuming misunderstandings that can become very challenging if left 

unresolved until later in the proceeding.

The end result of progressive regulation should be a constructive working 

relationship among the various participants, and an efficient, thorough, open, 

and complete resolution of important issues.
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Electricity Regulation in the US: A Guide

Glossary

A

Accumulated Deferred Income Taxes (ADIT): An adjustment to rate base 

reflecting timing differences in taxes for book and ratemaking purposes. 

Accelerated tax depreciation is one of the drivers of ADIT.

Adjustment Clauses: Allow for recovery of specified costs as incurred, e.g., 

on a monthly or annual basis. 

Advanced Metering Infrastructure (AMI): Meters and data systems that 

enable two-way communication between customer meters and the utility 

control center. (See Smart Grid.)

Allocation: The assignment of utility costs to customers, customer groups, 

or unbundled services based on cost causation principles. 

Allowance for Funds Used During Construction (AFUDC): The capital 

costs that would have been accumulated on capital committed to a new 

utility plant during the construction period.

Alternating Current (AC): Current that reverses its flow periodically. 

Electric utilities generate and distribute AC electricity to residential and 

business consumers.

Ancillary Services: Services needed to support the transmission of energy 

from generation to loads, while maintaining reliable operation of the 

transmission system. These include regulation and frequency response, 

spinning reserve, non-spinning reserve, replacement reserve, and reactive 

supply and voltage control. 

Annualization: An adjustment to a cost-of-service study to reflect the 

effect over 12 months of a rate base, income, or expense item that is only 

actually in effect for part of the year. 

Average Cost: The revenue requirement divided by the quantity of utility 

service, expressed as a cost per kilowatt-hour or cost per therm. 
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Electricity Regulation in the US: A Guide

Average Cost Pricing: A pricing mechanism basing the total cost of 

providing electricity on the accounting costs of existing resources. 

(See Marginal Cost Pricing, Value-Based Rates.) 

Avoided Cost: The cost of providing additional power, including the cost 

of the next power plant a utility would have to build to meet growing 

demand, plus the costs of augmenting reliability reserves, additional 

transmission and distribution facilities, environmental costs, and line 

losses associated with delivering that power.

B

Baseline Rate: A rate which allows all customers to buy a set allowance of 

energy at lower rates than additional usage. (See Lifeline Rates.)

Baseload Capacity: The generating capacity normally operated at all times 

to serve load. Typically, this includes units with low fuel and operating 

costs such as coal and nuclear generators. 

Billing Cycle: The period of time between customer bills, typically one or 

two months. 

BTU (British Thermal Unit): A standard unit for measuring the quantity of 

heat energy, equal to the quantity of heat required to raise the temperature 

of one pound of water by one degree Fahrenheit. 

C

Capacity: The maximum amount of power a generating unit or power line 

can provide safely.

Capacity Factor: The ratio of total energy produced by a generator for a 

specified period to the maximum it could have produced if it had run at 

full capacity through the entire period, expressed as a percent. 

Capital Structure: The mix of common equity, preferred equity, and debt 

used by a utility to finance its assets.

Capitalized Costs: Utilities capitalize costs of investments that provide 

service over multiple years. (See Operation and Maintenance Costs.)

Carbon Intensity: The carbon dioxide a utility emits divided by its energy 

sales, typically expressed in tons/megawatt-hour. 

Classification: The separation of costs into demand-related, energy-related, 

and customer-related categories.
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Cogeneration: A method of producing power in conjunction with providing 

process heat to an industry, or space and/or water heat to buildings. Also 

called Combined Heat and Power (CHP).

Coincident Peak Demand: The maximum demand that a load places on a 

system at the time the system itself experiences its maximum demand. 

Combined Cycle: A generating plant that uses fuel to drive a turbine and the 

waste heat to operate a boiler, thereby achieving greater fuel efficiency. 

Commodity Costs: Gas supply costs that vary with the quantity supplied.

Congestion: A condition that occurs when insufficient transfer capacity 

is available to implement all the preferred schedules for electricity 

transmission simultaneously. Congestion prevents the economic dispatch 

of electric energy from power sources. 

Connection Charge: An amount to be paid by a customer to the utility, in a 

lump sum or in installments, for connecting the customer’s facilities to the 

supplier’s facilities. 

Construction Work in Progress (CWIP): Charges included in current rates 

to cover the cost of borrowing money for major energy projects still being 

built. 

Cooperative Electric Utility (Co-op): A private non-profit electric utility 

legally established to be owned by and operated for the benefit of those 

using its service. About 10% of Americans are served by co-ops.

Cost-Based Rates: Electric or gas rates based on the actual costs of the 

utility (see Value-Based Rates).

Cost of Debt: The interest rate paid by a utility on bonds and other debt.

Cost-of-Service Regulation: Traditional electric utility regulation, under 

which a utility is allowed to set rates based on the cost of providing service 

to customers and the right to earn a limited profit. 

Cost-of-Service Study: A study that allocates the costs of a utility between 

the different customer classes, such as residential, commercial, and 

industrial. There are many different methods used, and no method is 

“correct.” 

Critical Period Pricing or Critical Peak Pricing (CPP): Rates that 

dramatically increase on short notice when costs spike, usually due to 

weather or to failures of generating plants or transmission lines.
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Customer Charge: A fixed charge to consumers each billing period, 

typically to cover metering, meter reading, and billing costs that do 

not vary with size or usage. Sometimes called a Basic Charge or Service 

Charge.

Customer Class: A group of customers with similar usage characteristics, 

such as residential, commercial, or industrial customers.

D

Declining Block Rate: A rate structure that prices successive blocks of 

power at increasingly lower per-unit rates. (See Inverted Block Rate.)

Decoupling: A regulatory design that breaks the link between utility 

revenues and energy sales, typically by a small periodic adjustment to 

the rate previously established in a rate case. The goal is to match actual 

revenues with allowed revenue, regardless of sales volumes.

Deferred Costs: An expenditure not recognized as a cost of operation of 

the period when it occurred, but carried forward so as to be recovered in 

future periods. 

Demand: The rate at which electrical energy or natural gas is used, usually 

expressed in kilowatts or megawatts, for electricity, or therms for natural gas. 

Demand Charge: A charge based on a customer’s highest usage in a onehour or shorter interval during a billing period. 

Demand-Side Management (DSM): The planning, implementation, 

and monitoring of utility activities designed to encourage consumers to 

modify patterns of electricity usage, including the timing and level of their 

demand. 

Depreciation: The loss of value of assets such as buildings and transmission 

lines, due to age and wear. 

Direct Access: The utility provides only distribution service to the 

consumer, while the consumer purchases the power from a different 

supplier.

Direct Current (DC): An electric current that flows in one direction, with a 

magnitude that does not vary or that varies only slightly. 

Distribution: The delivery of electricity to end users via low-voltage electric 

power lines (usually 34 kV and below).

Dynamic Pricing: Dynamic pricing creates changing prices for electricity 

that reflect actual wholesale electric market conditions. Examples of 

dynamic pricing include critical period pricing and real-time rates. 
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E

Eastern Interconnection: One of three major AC power grids in North 

America, reaching from central Canada eastward to the Atlantic coast 

(excluding Quebec), south to Florida, and west to the foot of the Rocky 

Mountains (excluding most of Texas). 

Economic Dispatch: The utilization of existing generating resources to serve 

load as inexpensively as possible. 

Elasticity (of Demand): The percent change in usage with respect to a one 

percent change in price. 

Embedded Costs: The costs associated with ownership and operation of a 

utility’s existing facilities and operations. (See Marginal Cost.)

Energy Audit: A program in which an auditor inspects a home or business 

and suggests ways energy can be saved. 

Energy Charge: The part of the charge for electric service based upon the 

electric energy consumed or billed. 

Energy Intensity: Economy-wide energy intensity measures units of energy 

relative to units of gross domestic product (GDP). EIA computes energy 

consumption (measured in Btu) relative to the constant dollar value of the 

GDP. 

Energy Portfolio Standard: A regulatory requirement that a utility meet a 

specified percentage of its power requirements from a combination 

of qualified renewable resources or energy efficiency investments. 

(See Renewable Portfolio Standard.)

Externalities: Costs or benefits that are side-effects of economic activities, 

and are not reflected in the booked costs of the utility. Environmental 

impacts are the principal externalities caused by utilities (e.g. health care 

costs from air pollution).

Extraordinary Items: An accounting term meaning significant items 

of income or loss resulting from events or transactions in the current 

period that are unusual and infrequent. Extraordinary storm losses are an 

example. 

F

FERC: The Federal Energy Regulatory Commission. 

Firm Power: Electricity delivered on an always-available basis. 

(See Interruptible Power.)
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Fixed Cost: Costs that the utility cannot change or control in the short-run, 

and that are independent of usage or revenues. Examples include interest 

expense and depreciation expense. In the long run, there are no fixed 

costs, because eventually all utility facilities can be retired and replaced 

with alternatives.

Flat Rate: A rate design with a uniform price per kilowatt-hour for all levels 

of consumption.

Franchise Tax: Taxes levied by states and localities as a condition of utility 

operation, usually in lieu of charging rental for public rights of way. 

Fuel and Purchased Power Adjustment Clause (FAC): An adjustment 

mechanism that allows utilities to recover all or part of the variation in 

the cost of fuel and/or purchased power from the levels assumed in a 

general rate case. Sometimes called by other names, such as Energy Cost 

Adjustment Clause.

Functionalization: The separation of costs among utility operating 

functions, which traditionally include: production, transmission, 

distribution, customer accounting, customer service and information, 

sales, and administrative and general. 

Fully Allocated Costs or Fully Distributed Costs: A costing procedure 

that spreads the utility’s joint and common costs across various services 

and customer classes. 

Future Test Year: A regulatory accounting period that estimates the rate base 

and operating expenses a utility will incur to provide service in a future 

year, typically the first full year when rates determined in that rate case 

will be in effect.

G

Greenhouse Gases: Gases that trap heat in the atmosphere, including 

carbon dioxide emitted from power plants. 

Green Power: An offering of environmentally preferred power by a utility to 

its consumers, typically at a premium above the regular rate.

H

Heat Rate: A measure of generating-station thermal efficiency commonly 

stated as Btu per kilowatt-hour.

Historical Test Year: A regulatory accounting period that measures the costs 

that a utility incurred to provide service in a recent year, typically adjusted 

for known and measurable changes since that year.
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Electricity Regulation in the US: A Guide

I

Incentive Regulation: A regulatory framework in which a utility may 

augment its allowed rate of return by achieving cost savings or other goals 

in excess of a target set by the regulator.

Incremental Cost: The additional cost of adding to the existing utility 

system.

Incremental Pricing: A method of charging customers based on the cost of 

augmenting the existing utility system, in which low-cost resources are 

sold at one price, and higher-cost resources at higher prices. 

Independent System Operator (ISO): A non-utility that has regional 

responsibility for ensuring an orderly wholesale power market, the 

management of transmission lines, and the dispatch of power resources to 

meet utility and non-utility needs.

Integrated Resource Planning (IRP): A public planning process and 

framework within which the costs and benefits of both demand and 

supply side resources are evaluated to develop the least total-cost mix of 

utility resource options. Also known as least-cost planning. 

Interest Coverage Ratio: The annual net income divided by the annual 

interest charges on debt. It indicates the margin of safety for bondholders. 

Intervenor: An individual, group, or institution that is officially involved in 

a rate case. 

Interruptible Power: Power made available under agreements that 

permit curtailment or cessation of delivery by the supplier. Customers 

typically receive a discount for agreeing to have their power interrupted. 

Interruptions are usually limited to reliability needs, rather than the cost of 

power. 

Inverted Rates: Rates that increase at higher levels of electricity 

consumption, typically reflecting higher costs of newer resources, or 

higher costs of serving lower load factor loads such as air conditioning. 

Baseline and lifeline rates are forms of inverted rates.

Investor-Owned Utility (IOU): A privately owned electric utility owned 

by and responsible to its shareholders. About 75% of U.S. consumers are 

served by IOUs.
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J

Joint and Common Costs: Costs incurred by a utility in producing multiple 

services that cannot be directly assigned to any individual service or 

customer class; these costs must be assigned according to some rule or 

formula. Examples are distribution lines, substations, and administrative 

facilities.

K

Kilowatt-Hour (kWh): Energy equal to one thousand watts for one hour. 

The W is capitalized in the acronym in recognition of electrical pioneer 

James Watt.

L

Levelized Cost, Life-Cycle Cost: The present value of the cost of a 

resource, including capital, financing, and operating costs, converted 

into a stream of equal annual payments per unit of output. EPRI formula: 

PV(cost)/PV(kWh), using the same discount rate for both.

Lifeline Rate: A lower rate for qualified low-income consumers. The 

discount may apply only to the basic charge, only to the initial block of 

usage, or to all usage.

Load Factor: The ratio of average load to peak load during a specific period 

of time, expressed as a percent. 

Load Shape: The distribution of usage across the day and year, reflecting the 

amount of power used in low-cost periods versus high-cost periods.

Load-Serving Entity (LSE): The entity that arranges energy and 

transmission service to serve the electrical demand and energy 

requirements of its end-use customers. In restructured states, such entities 

are not necessarily the utilities that own transmission and distribution 

assets. 

Local Distribution Company (LDC): A utility engaged primarily in the 

retail sale and/or delivery of natural gas through a distribution system. 

Load Shedding: Disconnection of certain customers or circuits when system 

emergencies would otherwise cause a complete outage. 

Load Shifting: Moving load from on-peak to off-peak periods. 

Long-Run Marginal Costs: The long-run costs of the next unit of electricity 

produced, including the cost of a new power plant, additional transmission 

and distribution, reserves, marginal losses, and administrative and 

environmental costs. Also called long-run incremental costs.
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Electricity Regulation in the US: A Guide

Losses: The energy (kilowatt-hours) and power (kilowatts) lost or 

unaccounted for in the operation of an electric system. 

M

Marginal Cost Pricing: A system in which rates are designed to reflect the 

prospective or replacement costs of providing power, as opposed to the 

historical or accounting costs. (See Embedded Cost.)

Market Clearing Price: The price at which supply and demand are in 

balance, with respect to a particular commodity at a particular time. 

Minimum Charge: A rate-schedule provision stating that a customer’s bill 

cannot fall below a specified level. These are common for rates that have 

no separate customer charge.

Municipal Utility (Muni): A utility owned by a unit of government, and 

operated under the control of a publicly elected body. About 15% of 

Americans are served by munis.

N

Negawatt: A unit of saved power from energy efficiency programs equal 

to one megawatt at the generating level. Because of avoided losses and 

reserves, it takes only about 800 kilowatts of load reduction to avoid 1 

megawatt of power supply. (See Rosenfeld.)

Net Income: Operating income plus other income and extraordinary income 

less operating expenses, taxes, interest charges, other deductions, and 

extraordinary deductions. 

Non-Coincident Demand (NCD) or Non-Coincident Peak Load:

A customer’s maximum energy demand during a billing period or a 

year, even if it is different from the time of the system peak demand. 

(See Coincident Peak.) 

Non-Operating Revenues: Sometimes referred to as other operating 

revenues, these are revenues that are incidental to a utility’s revenues 

for primary service activities (e.g., investment income, land leases, pole 

rentals.) 

North American Electric Reliability Corporation (NERC): Oversees 

electric utility reliability standards. NERC is a self-regulatory organization, 

subject to oversight by the U.S. Federal Energy Regulatory Commission 

and governmental authorities in Canada. Regional and sub-regional 

reliability organizations are subject to NERC’s purview.
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O

Open Transmission Access: Provides all participants in the wholesale 

market equal access to transmission service, as long as capacity is 

available, with the objective of creating a more competitive wholesale 

power market. 

Operating Expenses: The expenses of maintaining day-to-day utility 

functions. These include labor, fuel, and taxes, but not interest or 

dividends.

Operating Revenues: Revenues directly related to the utility’s primary 

service activities. 

P

Path Rating: The maximum amount of power than can be transmitted 

through a particular “path” on the electric system — usually applied to 

high voltage transmission. A particular path may be thermally limited, 

based on the physical properties of the transmission medium (i.e. 

how much heat the line can take before it begins to fail or degrade). 

Alternatively, a path may be stability limited, based on the effect of the 

power flow on operational constraints such as voltage and frequency.

Payback Period: The amount of time required for the net revenues of an 

investment to return its costs. This metric is often employed as a simple 

tool for evaluating energy efficiency measures. 

Peak Load: The maximum total demand on a utility system during a period 

of time. 

Peak Shaving: Employment of supplemental power supply, demand side 

resources, or rate designs to reduce peak demand for short periods. 

Performance-Based Regulation: See Incentive Regulation.

Plant In Service: The cost of land, facilities, and equipment used to produce 

and deliver power as recorded on the utility’s accounting records. 

Power Factor: The fraction of power actually used by a customer’s electrical 

equipment compared to the total apparent power supplied, usually 

expressed as a percentage. A power factor indicates the extent to which a 

customer’s electrical equipment causes the electric current delivered at the 

customer’s site to be out of phase with the voltage. 

Power Factor Adjustment: A calculation or charge on industrial or 

commercial customers’ bills, reflecting an adjustment in billing demand 

based on customer’s actual metered power factor. 
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Electricity Regulation in the US: A Guide

Price Cap: A method of setting a utility distribution company’s rates whereby 

regulators establish a maximum allowable price level. Flexibility in 

individual pricing is allowed in some cases, and where efficiency gains can 

be encouraged and captured by the company. 

Program Administrator Cost Test (PACT): A measure of energy efficiency 

cost-effectiveness that looks only at the costs paid by the utility or nonutility program administrator, and only at benefits measurable in the 

revenue requirement of the utility. Also called the Utility Cost Test (UCT).

Prudence Review: The process by which a regulator determines the 

prudence of utility resource decisions. If a cost is found imprudent, it 

may be disallowed from rates. While retrospective, prudence reviews are 

typically determined in the bases of the information available to decision 

makers at the time the decision was made.

Public Utility Commission (PUC): The state regulatory body that 

determines rates for regulated utilities. Sometimes called a Public Service 

Commission or other names.

Public Utility Regulatory Policies Act of 1978 (PURPA): This statute 

requires states to examine ratemaking standards, implement utility 

efficiency programs, and create special markets for co-generators and small 

producers who meet certain standards.

Q

Qualifying Facility: A cogeneration or renewable resource meeting the 

standards of PURPA and selling its output the utility pursuant to a PURPA 

compliant tariff.

R

Rate Base: The total investment used to provide service, including working 

capital, but net of accumulated depreciation.

Rate Case: A proceeding, usually before a regulatory commission, involving 

the rates and policies of a utility.

Rate Design: The design and organization of billing charges to distribute 

costs allocated to different customer classes. 

Rate Impact Test (RIM): A test of energy efficiency cost-effectiveness that 

measures whether all utility consumers, including non-participants, 

receive lower rates as a result of implementing a efficiency measure.

Rate of Return: The overall cost of capital for a utility, weighting the cost of 

debt and the return on equity according to its capital structure. 
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Electricity Regulation in the US: A Guide

Real-Time Pricing: Establishing rates that adjust as frequently as hourly, 

based on wholesale electricity costs or actual generation costs. Sometimes 

called Dynamic Pricing. 

Regional Transmission Organization (RTO): An independent regional 

transmission operator and service provider established by FERC or that 

meets FERC’s RTO criteria, including those related to independence and 

market size. RTOs control and manage the high-voltage flow of electricity 

over an area generally larger than the typical power company’s service 

territory. Most RTOs also operate day-ahead, real-time, ancillary services, 

and capacity markets and conduct system planning. RTOs include 

PJM, ISO-New England, the Midwest Independent System Operator, 

the Southwest Power Pool, the New York ISO, and the California ISO 

(CAISO). 

Regulatory Asset: A utility investment that is allowed in rate base, but for 

a non-physical item determined by the regulator to be appropriate for 

recovery from consumers. Incentive awards for meeting performance 

requirements can create a regulatory asset until collected from consumers.

Regulatory Lag: The lapse of time between a petition for a rate increase and 

formal action by a regulatory body. 

Renewable Portfolio Standard (RPS): A regulatory requirement that 

utilities meet a specified percentage of their power supply using qualified 

renewable resources.

Renewable Resources: Power generating facilities that use wind, solar, 

hydro, biomass, or other non-depletable fuel sources. In some states, 

qualified renewable resources exclude large hydro stations or some other 

types of generation.

Reserve Capacity/Reserve Margin/Reserves: The amount of capacity that 

a system must be able to supply, beyond what is required to meet demand, 

in order to assure reliability when one or more generating units or 

transmission lines are out of service. Traditionally a 15-20 percent reserve 

capacity was thought to be needed for good reliability. In recent years, the 

accepted value in some areas has declined to 10 percent or even lower.

Restructuring: Replacement of vertically integrated electric utilities with 

competing sellers of electricity, leaving the utility as a distribution-only 

company. Restructuring allows individual retail customers to choose their 

electricity supplier but still receive delivery over the power lines of the 

local utility. 
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Electricity Regulation in the US: A Guide

Retail Wheeling: The process of moving electric power from a point of 

generation across third-party-owned transmission and distribution systems 

to a retail customer. In most cases, owners of power must pay transmission 

fees to system through which they wheel. Also called Direct Access.

Return on Equity: The profit rate allowed to the shareholders of an investorowned utility, expressed as a percentage of the equity capital invested. 

Revenue Requirement: The annual revenues that the utility is entitled to 

collect (as modified by adjustment clauses). It is the sum of operation and 

maintenance expenses, depreciation, taxes, and a return on rate base. In 

this document, revenue requirement and cost of service are synonymous. 

Rosenfeld: A unit of energy efficiency equal to 3 billion kilowatt-hours per 

year, the approximate annual output of a 500 megawatt coal-fired power 

plant. Named for Arthur Rosenfeld, longtime member of the California 

Energy Commission. (See Negawatt.)

S

Seasonal Rates: Rates that are higher during the peak-usage months of the 

year.

Self-Generation: A generation facility dedicated to serving a particular retail 

customer, usually located on the customer’s premises.

Shaping: Scheduling and operation of controllable generating resources to 

offset the changing output levels from variable sources of power such as 

wind.

Short Run Marginal Cost: Only those variable costs that change in 

the short run with a change in output, including fuel; operations and 

maintenance costs; losses; and environmental costs. Also known as system 

lambda.

Smart Grid: An integrated network of sophisticated meters, computer 

controls, information exchange, automation, and information processing, 

data management, and pricing options that can create opportunities for 

improved reliability, increased consumer control over energy costs, and 

more efficient utilization of utility generation and transmission resources.

Smart Meter: An electric meter with electronics that enable recording of 

customer usage in short time intervals, and two-way communication of 

data between the utility and the meter.

Societal Cost Test (SCT): A measure of energy efficiency cost-effectiveness 

that considers all costs and benefits, including non-monetized 

environmental costs and benefits. (See Total Resource Cost Test.)
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Electricity Regulation in the US: A Guide

Spinning Reserve: Unused, quickly accessible generating capacity available 

from units that are already connected to and synchronized with the grid to 

serve additional demand. 

Standby Service: Support service that is available, as needed, to supplement 

supply for a consumer, a utility system, or another utility if normally 

scheduled power becomes unavailable. 

Straight Fixed Variable (SFV) Rate Design: A rate design method that 

recovers all short-run fixed costs in a fixed charge, and only short-run 

variable costs in a per-unit charge. 

Stranded Costs: Fixed or sunk costs to be paid to the incumbent utility 

under restructuring when prudently incurred costs become uneconomic in 

a competitive market, such as the difference between the market value and 

book value of a power plant. Whether a utility is entitled to stranded cost 

recovery is usually a judgment call for regulators.

T

Tariff: A listing of the rates, charges, and other terms of service for a utility 

customer class, as approved by the regulator.

Test Year: A specific period chosen to demonstrate a utility’s need for a rate 

increase. It may or may not include adjustments to reflect known and 

measurable changes in operating revenues, expenses and rate base. A test 

year can be either historical or projected. 

Therm: A unit of natural gas equal to 100,000 Btu. The quantity is 

approximately 100 cubic feet, depending on the exact chemical 

composition of the natural gas.

Time-of-Use (TOU) Rates: Rates that vary by time of day and day of the 

week. 

Total Resource Cost Test (TRC): A measure of energy efficiency costeffectiveness that looks at all economic costs and benefits of a measure, 

including non-energy benefits and quantifiable environmental costs, 

regardless of who pays or receives them. 

Total Service Long-Run Incremental Cost (TSLRIC): A forward-looking 

measure of the cost to provide service of a newly developed utility 

system. It considers all facilities and services, including administration, 

management, hardware, software, labor, fuel, and other elements of cost. 

It is used to determine if regulated prices exceed the cost a new entrant 

would face to offer competing service.
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Electricity Regulation in the US: A Guide

Tracker: A rate schedule provision giving the utility company the ability to 

change its rates at different points in time, to recognize changes in specific 

costs of service items without the usual suspension period of a rate filing. 

(See Adjustment Clauses.)

U

Undergrounding: A program for relocating existing overhead transmission 

or distribution lines below ground. The cost is usually split between the 

utility and the municipality that requires it.

Used and Useful: A regulatory concept — often triggered when plant is first 

placed in service, but applicable throughout the life of the plant — for 

determining whether utility plant is eligible for inclusion in a utility’s rate 

base. While different state courts have interpreted the concept differently, 

generally used means that the facility is actually operated to provide 

service, and useful means that without that facility, service would either be 

more expensive or less reliable.

V

Value-Based Rates: Rates that are based on the cost a consumer would 

otherwise incur to obtain the same service some other way — for example, 

installing a stand-alone generator to produce their electricity.

Variable Cost: Costs that vary with usage and revenue, plus costs over 

which the utility has some control in the short-run, including fuel, labor, 

maintenance, insurance, return on equity, and taxes. (See Short Run 

Marginal Cost.)

Vertically Integrated Utility: A utility that owns its own generating plants, 

transmission system, and distribution lines, providing all aspects of 

electric service. 

Volt: The unit of measurement of electromotive force. Typical transmission 

level voltages are 115 kV, 230 kV and 500 kV. Typical distribution voltages 

are 4 kV, 13 kV, and 34 kV. 

Volumetric Rate: A rate or charge for a commodity or service calculated on 

the basis of the amount or volume actually received by the purchaser. 

W

Watt: The electric unit used to measure power. Kilowatt = 1,000 watts. 

Megawatt = 1,000,000 watts.

Watt-Hour: The amount energy generated or consumed with one watt of 

power over the course of one hour. (See also Kilowatt-Hour.)
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Electricity Regulation in the US: A Guide

Weatherization: A process or program for increasing a building’s thermal 

efficiency. Examples include caulking windows, weather stripping, and 

adding insulation to the wall, ceilings, and floors. 

Working Capital: Amount of cash or other liquid assets that a utility must 

have on hand to meet the current costs of operations until such time as it 

is reimbursed by its customers. 

Much of this glossary was adapted from The People’s Power Guide, People’s 

Organization for Washington Energy Resources, 1982. It was augmented with 

definitions from the National Regulatory Research Institute, the U.S. Department of 

Energy, and other sources.
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