Incorporating 

Environmental Costs 

in Electric Rates

Working to Ensure Affordable Compliance with 

Public Health and Environmental Regulations 

Authors

Jim Lazar and David Farnsworth

October 2011
Electronic copies of this paper and other RAP publications 

can be found on our website at www.raponline.org.

To be added to our distribution list, 

please send relevant contact information to 

info@raponline.org.

Acknowledgements

The authors would like to thank the following people for their help in 

the review and preparation of this paper: Ken Colburn, Brenda Hausauer, 

Janine Midgen-Ostrander, Ajith Rao, Richard Sedano, and Lisa Schwartz. 
1

Working to Ensure Affordable Compliance with Public Health and Environmental Regulations

List of Figures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

Foreword . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

1. The Need for Comprehensive Analysis of 

Aging Power Plants . . . . . . . . . . . . . . . . . . . . . . . 4

2. New and Forthcoming Public Health and 

Environmental Regulations . . . . . . . . . . . . . . . . . 7

3. What Kinds of Requests Will Regulators 

Likely See From Utilities? . . . . . . . . . . . . . . . . . 13

a. The Age of U.S. Coal-Fired Power Plants. . . . . . . 13

b. The Cost of Retrofits for Control of 

Criteria Pollutants. . . . . . . . . . . . . . . . . . . . . . . . 14

c. Emission Costs May Justify Permanent 

Closure of Some Plants. . . . . . . . . . . . . . . . . . . . 15

d. Preapproval of Expenditures. . . . . . . . . . . . . . . . 17

e. Requests for Adjustment Clauses. . . . . . . . . . . . . 17

4. Costs of CO2 Reduction or Mitigation . . . . . . . . 19

5. What Should Regulators Require of Utilities? . . 21

a. Utility at Risk for Elements Not Evaluated. . . . . . 23

b. Examination of Non-Generation Alternatives. . . . 24

c. Time Horizon for Analysis. . . . . . . . . . . . . . . . . . 25

d. Example Analyses That Considered 

Only Immediate Costs. . . . . . . . . . . . . . . . . . . . . 26

e. Example Analyses That Consider Future 

Potential Costs. . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Table Of Contents

6. Cost Recovery For Refurbishment 

or Abandonment . . . . . . . . . . . . . . . . . . . . . . . . 30

a. Planning-Stage Consideration of 

Renovation Costs. . . . . . . . . . . . . . . . . . . . . . . . . 30

b. Evaluation-Stage Consideration of 

Renovation Costs. . . . . . . . . . . . . . . . . . . . . . . . . 31

c. Stranded Cost Treatment of Abandoned 

Project Costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

d. Prudence, Used and Useful, Rate Base, and 

Amortization. . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

e. Strategy for Commissions Faced With 

Coal Retrofit Costs. . . . . . . . . . . . . . . . . . . . . . . . 33

f. Key Elements For An Integrated 

Resource Plan. . . . . . . . . . . . . . . . . . . . . . . . . . . 34

7. Treatment in Rate Design . . . . . . . . . . . . . . . . . 35

a. Clear Focus on Long-Run Marginal Costs. . . . . . 35

b. Reflecting Emissions Costs In 

Cost Allocation and Rate Design. . . . . . . . . . . . . 36

c. Time-of-Use Element to Emissions. . . . . . . . . . . 38

d. CO2 Costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

8. Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

Reference List . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

Appendix 1: Acronym Glossary . . . . . . . . . . . . . . . . 46

Appendix 2: EPA Rulemakings Affecting 

Power Plant Operations . . . . . . . . . . . . . . . . . . . 47
2

Incorporating Environmental Costs in Electric Rates

Fig. 1. Mohave Alternatives and Complements Study 

Table of Contents. . . . . . . . . . . . . . . . . . . . . . . . . . 6

Fig. 2. Major EPA Rulemakings Impacting 

Power Plants. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Fig. 3. Compliance Technology for the Cross-State 

Air Pollution and Mercury/Air Toxics Rules. . . . . 10

Fig. 4. Representation of Air Pollution Controls. . . . . 11

Fig. 5. Pollution Control Retrofit Costs for a 

Representative 500-MW Coal Unit in the 

PJM Regional Transmission Organization 

Interconnection. . . . . . . . . . . . . . . . . . . . . . . . . 11

Fig. 6. Pollution Control Retrofit Cost Estimate 

Ranges for Coal Generation in the PJM Regional 

Transmission Organization Interconnection. . . . . 12

Fig. 7. U.S. Coal-Fired Power Plants as of 

December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . 14

Fig. 8. Cost Estimates for Proposed Pollution 

Retrofits on Selected Western Coal Plants. . . . . . 15

Fig. 9. Illustrative Example of Potential 

Cumulative Retrofit Costs At A Single Plant. . . . . 15

Fig. 10. Selected U.S. Coal Plants Closed or 

Scheduled To Close Due to Emissions Costs. . . . 16

Fig. 11. Approximate CO2 Emissions of 

Electricity Generation. . . . . . . . . . . . . . . . . . . . . 19

Fig. 12. Illustrative Coal Plant Capital, Operating, 

and Emission Costs . . . . . . . . . . . . . . . . . . . . . . . 23

Fig. 13. Illustrative Measure Lifetimes and Levelized 

Costs for Various Coal, Natural Gas, and 

Energy Efficiency Resource Options . . . . . . . . . . 25

Fig. 14. Costs for Operating, Renovating, or 

Replacing Ontario’s Coal Plants. . . . . . . . . . . . . . 27

Fig. 15. Options Considered for Continuing 

Operation of Boardman Coal Plant. . . . . . . . . . . 28

Fig. 16. Costs Associated with Alternative Options 

for Continued Operation of Boardman 

Coal Plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Fig. 17. Xcel Energy’s Economic Analysis for 

Cherokee Plants. . . . . . . . . . . . . . . . . . . . . . . . . . 29

Fig. 18. Methods of Allocating Production Costs 

Among Customer Classes. . . . . . . . . . . . . . . . . . 37

Fig. 19. Illustrative Retail Rates With and 

Without $30/ton CO2 Costs for Gas and Coal. . . 38

Fig. 20. Alternative Forms of CO2 Regulation. . . . . . . 39

Fig. 21. Implementation Timeline for 

EPA Regulations. . . . . . . . . . . . . . . . . . . . . . . . . . 52

Fig. 22. The Cross-State Air Pollution Rule 

Programs and Affected States. . . . . . . . . . . . . . . . 54

List of Figures
3

Working to Ensure Affordable Compliance with Public Health and Environmental Regulations

I

t has always been part of a utility regulator’s job to 

weigh the relative merits of utility company requests 

to include certain costs in rates. Recently, with the 

potential for requests associated with Environmental 

Protection Agency (EPA) regulatory compliance costs 

with significant price tags aimed at consumers across the 

United States, RAP concluded that there would be value in 

focusing on this topic. 

With various strategies and compliance choices facing 

companies over the next several years, regulators will want 

an acute sense of how to identify, assess, and approve 

both effective and cost-effective company strategies. 

Furthermore, regulators will need to determine how these 

costs, once approved, will be included in rates, and what 

incentives are best put into place to ensure that company 

management will control costs so that customer rates and 

bills over time stay as low as possible.

Moody’s recently observed:

Foreword

by Richard Sedano

Director of U.S. Programs, Regulatory Assistance Project

The credit risk factors associated with energy and climate 

legislation have existed for decades and managing these risks 

are considered a core competency for all utility operators, 

whether they are regulated or un-regulated, public or 

privately-owned.1

Although utility operators have this awareness, utility 

regulators will benefit from deeper understanding of these 

challenges and choices. 

Following up on RAP’s July publication of Preparing for 

EPA Regulations: Working to Ensure Reliable and Affordable 

Environmental Compliance,”2

 this paper, Incorporating 

Environmental Costs in Electric Rates: Working to Ensure 

Affordable Compliance with Public Health and Environmental 

Regulations, takes the next step and explores issues associated 

with potential rate effects and rate treatment of utility 

company compliance choices. We hope that this paper will 

help regulators as they work through these issues.

1 Moody’s Investor Service, 2011.

2 Farnsworth, 2011. 
4

Incorporating Environmental Costs in Electric Rates

1. The Need for Comprehensive Analysis 

of Aging Power Plants

Many of us share the 

experience of owning an 

older car that requires one 

repair after another, with 

the cumulative cost far exceeding the 

value of the vehicle. Power plants can be 

similar, except the costs are measured in 

millions and even billions of dollars, not 

thousands. The question is whether retrofit 

or replacement makes more sense.

The purpose of this paper is to give 

utility regulators an appreciation for the 

breadth of issues that may cause cost 

impacts on fossil-fuel power plants over the coming 

decades. The paper begins with a brief recital of major 

forthcoming public health and environmental regulations 

for power plants. It identifies some of the costs of 

compliance with these existing and potential regulations. 

It then turns to how these costs will likely be presented 

to utility regulators and discusses how regulators should 

evaluate them. Regulators will need to determine what 

costs should be allowed for cost recovery, what costs should 

be rejected, and how to treat the remaining investments in 

power plants that are no longer economical to revamp. It 

concludes with a discussion of how emission management 

costs should be reflected in retail rates.

The United States is served by a fleet of nearly 1,500 

coal-fired power plants, which provide over 300,000 

megawatts (MW) of generating capacity and produce nearly 

half of the country’s electricity. More than half of the coalfired plants in the country were built before 1970; they are 

already at or beyond the end of their original economic life.3

Many of these older plants (and some newer ones) lack 

modern air and water pollution control 

devices and have poor management of 

combustion residuals, and none captures 

carbon dioxide (CO2) emissions. Retrofit 

costs to control pollution and carbon 

emissions can be extremely expensive, 

often far more than the current investment 

in the plants, and in some cases, more 

than the cost of replacing the units with 

energy efficiency or new generation. Utility 

regulators should take a comprehensive 

view—evaluating long-term resource 

alternatives for meeting environmental and 

reliability requirements—when they consider requests from 

regulated utilities for investment in and cost recovery for 

retrofit measures, or for approval to dispose of these units. 

The alternative could be piecemeal expenditures over time 

that exceed the value of a new power plant—the equivalent 

of a $50,000 restoration of an aging Chevy Caprice. 

Several recent studies have estimated that as much as 

78,000 MW of power plants may be retired over the next 

decade as utilities examine plant economics in light of age, 

emission control strategies and replacement power costs.4

If the potential for future CO2 regulation were considered, 

this total would rise. Reasoned decisions about which power 

plants should be renovated, which should be mothballed 

(deferring a decision to a later date), and which should be 

retired include consideration of the relevant risks.

About half of these power plants are owned by 

investor-owned utilities subject to state utility commission 

regulation; these are the primary focus of this paper. Some 

plants are owned by municipal and cooperative utilities; 

their local regulators are city councils, public power district 

3 U.S. Energy Information Administration, 2008.

4 For example, see several studies cited at Farnsworth, 2011, p. 24; see also Miller, 2011.

Regulators will need to 

determine what costs 

should be allowed 

for cost recovery, 

what costs should be 

rejected, and how to 

treat the remaining 

investments in power 

plants that are no 

longer economical to 

revamp. 
5

Working to Ensure Affordable Compliance with Public Health and Environmental Regulations

boards, and cooperative boards. The same principles 

apply to these regulators as do those we discuss for state 

regulators. Some plants are owned by non-regulated 

merchant generators, industries, tribal authorities, and 

others; these owners will need to develop their own 

appropriate criteria to evaluate the future economic 

viability of their units.

This need for long-range thinking and comprehensive 

analysis is illustrated by an industry press article about 

the Four Corners coal plant in New Mexico: 

The Environmental Protection Agency is proposing that 

the most stringent pollution control equipment available 

be added to the 2,060-MW Four Corners plant, a move 

that adds to the challenges facing the generating station in 

northwestern New Mexico. To improve visibility in the Four 

Corners region, EPA wants the plant’s owners to install 

selective catalytic reduction [SCR] equipment to the plant’s 

five units, which could cost roughly $730 million to $890 

million.

...

However, both the Four Corners and Navajo power 

plants face various difficulties beyond the possible 

requirement that they add SCR equipment. Other pending 

environmental regulations that would affect the plants 

include tougher restrictions on mercury and carbon 

dioxide emissions as well as coal combustion [residuals] 

requirements...5

In recent years, utilities such as Duke Power, Exelon, 

and the Tennessee Valley Authority have announced 

retirement of more than 20 older coal-fired plants 

because they are uneconomical. In many cases, the 

operating costs alone are too high; in others, the cost 

of bringing them up to modern performance and 

environmental standards is excessive compared with 

alternative power and energy efficiency options.6

 

A comparison of the history of two power plants in 

the West shows the value of comprehensive analysis. The 

Centralia and Mohave plants were both built in the early 

1970s, both are about the same size, and both originally 

owned by consortia of utilities. Their destiny, however, 

differed.

5 Platts, October 11, 2010.

6 CoalSwarm, “Existing U.S. Coal Plants,” 2011. 

Mohave: Nevada 

The Mohave power plant, located near Laughlin, 

Nevada, was built in 1970 by a group of electric utilities. 

In 1999, the owners executed a consent decree to 

either install SO2 controls or close the plant by 2005. 

In 2003, Southern California Edison approached 

the California Public Utilities Commission (CPUC) for 

approval of the preliminary engineering costs for the 

retrofit. After an extended hearing, the CPUC ordered a 

comprehensive review of the future of the Mohave project. 

The Mohave Alternatives and Complements Study 

(MACS) was completed in 2005. It examined alternatives 

to a retrofit of Mohave, found a wide variety of costeffective options, and at the conclusion of the study, the 

Mohave plant was closed permanently on Dec. 31, 2005. 

Centralia: Washington 

The Centralia power plant, located between Seattle 

and Portland, was built in I972 by a group of electric 

utilities. 

In 1998, the owners agreed to install scrubbers 

for sulfur dioxide (SO2) to reduce haze at Mt. Rainier 

National Park. In exchange, the state of Washington 

agreed to long-term tax breaks for the plant owner. 

A few years later, after the plant was sold to a new 

owner, the coal mine serving Centralia was largely played 

out and the owner invested in rail system upgrades. 

ln 2012, the owner is expected to install controls for 

mercury. The pending EPA rulemakings could require 

additional compliance-related expenditures. The 

Washington Legislature approved a subsidy package in 

April 2011 to enhance the economic viability of Centralia 

and protect the owners from future emission regulation 

costs. 

There has never been a publicly available 

comprehensive review of the economics of any of these 

piecemeal upgrades and the viability of Centralia’s 

continued operation. 
6

Incorporating Environmental Costs in Electric Rates

The Mohave Alternatives and Complements study 

(MACS), prepared at the direction of the CPUC, is an 

excellent example of the type of comprehensive analysis 

that regulators should insist on as a condition of emissions 

compliance investment at an existing power plant.7

 The 

study’s table of contents provides a sense of the breadth of 

the MACS analysis (Fig. 1).

Figure 1 

7 Synapse Energy Economics, 2006.

Mohave Alternatives and Complements 

Study Table of Contents

I. Existing Plant

II. Integrated Gasification / 

Combined Cycle Technology

III. Solar Technology

IV. Wind Technology

V. Natural Gas Combined Cycle Technology

VI. Demand Side Management / 

Energy Efficiency Technology

VII. Other Renewable Energy Technology

VIII. CO2: Sequestration

IX. Tribal Issues

X. Financial Issues

XI. Generation and Demand Issues

XII. Transmission Issues

In theory, a merchant power plant owner will always 

have an incentive to consider the entire picture. Merchant 

plants sell power into a competitive market, and if the 

life-cycle revenues will not exceed the life-cycle costs, 

they will lose money. This is not necessarily the case for 

regulated utilities, which have the opportunity to earn 

a fair rate of return on their allowed rate base—that is, 

their investment in a utility plant that serves customers 

as approved by the regulator. A regulated utility might be 

allowed to collect more than the power is worth over time, 

if permitted to do so by a regulator that allows incremental 

decisions and gradual cost recovery. This can be true even 

if the individual decisions are cost-effective when viewed 

in isolation. When considering the investment in pollution 

controls, regulators therefore should look at the totality of 

the costs that might be required for multiple investments in 

order to ensure the prudency of the expenditures.
7

Working to Ensure Affordable Compliance with Public Health and Environmental Regulations

8 To address rate implications, this paper focuses on a limited list of regulatory actions. Readers should be aware, however, that the 

electric industry is subject to other public health and environmental regulations (e.g., likely changes to ground-level ozone standards in the 2013-14 timeframe). 

9 For a more complete discussion of forthcoming EPA regulations, see Farnsworth, 2011.

10 Federal Register, April 20, 2011, pp. 22174-22288.

11 U.S. Environmental Protection Agency, March 2011.

12 U.S. Environmental Protection Agency, March 2011.

13 This discussion is based in part on a presentation by Hewitt, 2010.

2. New and Forthcoming Public Health 

and Environmental Regulations

To ensure the reasonableness of pollution control 

investments, regulators should be aware of what 

areas the new and forthcoming public health and 

environmental regulations cover. 

In response to legal obligations imposed by Congress 

and the federal courts, the United States Environmental 

Protection Agency (US EPA) is in the process of 

promulgating a suite of public health and environmental 

rules that will have a significant impact on investment 

decisions to be made by the electric sector. What follows 

is a brief discussion of these newly proposed and 

forthcoming EPA rules.8

 (A more complete description is 

found at Appendix 2.9

) These descriptions are intended 

as illustrations of these rules as of Fall 2011; thus, readers 

should consult the latest administrative enactments, 

statements of agency policy, and judicial decisions for a 

more complete picture of their status.

The following rulemakings—one being developed under 

the Clean Water Act, three under the Clean Air Act (CAA), 

and one under the Resource Conservation and Recovery 

Act (RCRA)—are in various stages of consideration, 

adoption, and implementation:

•	 316(b) Cooling Water Rule

•	 Wastewater Rule

•	 Cross-State Air Pollution Rule

•	 Mercury/Air Toxics Rule

•	 New Source Performance Standards (CO2)

•	 Coal Combustion Residuals Rule

316(b) Cooling Water Rule

As part of a settlement agreement with environmental 

groups in litigation under the Clean Water Act, the EPA 

will issue regulations designed to “reduce injury and death 

of fish and other aquatic life” caused by cooling water 

intake structures at existing power plants and factories.”10

The proposed 316(b) rule will establish requirements for 

existing facilities that (a) withdraw more than 2 million 

gallons per day of water from waters of the United States, 

and (b) use at least 25% of the water they withdraw 

exclusively for cooling purposes. The EPA estimates that 

670 of these facilities are power plants, including both 

coal and natural gas-fired units.11 The final rule must be 

signed by July 27, 2012 under the terms of a settlement 

agreement, and compliance deadlines for fossil plants are in 

10 years and for nuclear facilities in 15 years.12

Wastewater Rule

The Wastewater Rule (1982) focuses on the steam 

electric subcategory of all electric generating activities, 

including fossil-fueled (coal, oil, gas) power plants.13 A 

major focus of the Wastewater Rule is on toxic pollutants 

released into wastewater and ash ponds as part of the flue 

gas desulfurization (FGD) process. Currently guidelines 

cover suspended solids, oil and grease from ash ponds, and 

FGD discharges. Although some of the newest power plants 

have zero liquid discharge (ZLD) systems, most existing 

power plants release substantial amounts of water used 
8

Incorporating Environmental Costs in Electric Rates

14 Ground-level ozone is a pollutant created through the interaction of NOx, volatile organic compounds or “VOCs,” and sunlight.

15 Code of Federal Regulations Title 40, Parts 51, 52, 72, 78, and 97. 

16 Federal Register, May 3, 2011.

17 Harder, 2011. 

18 Federal Register, June 21, 2010. 

19 According to the U.S. EPA, “[b]eneficial use refers to use of material that provides a functional benefit — that is, where the use 

replaces the use of an alternative material or conserves natural resources that would otherwise be obtained through extraction or 

other processes to obtain virgin materials;” see U.S. Environmental Protection Agency, “Frequent Questions: Coal Combustion 

Residues - Proposed Rule,” 2011.

in boilers, cooling systems, and pollution control systems 

back into the environment. Unregulated pollutants are 

present in ash ponds, and related discharges include metals 

that are bioaccumulative (e.g., mercury, selenium, arsenic), 

nutrients (e.g., nitrates, ammonia), and chlorides.

According to the EPA, the schedule for the development 

of a Wastewater Rule requires the EPA to collect technical 

and financial information for analysis, an effort that is now 

underway. No rule has been proposed, but the EPA intends 

to issue proposed regulation in mid 2012 and a final rule in 

late 2013. Dischargers are likely to be required to apply for 

National Pollutant Discharge Elimination System (NPDES) 

permits. Compliance is expected to start 3 to 5 years after 

the final rule, in 2016 to 2018.

Cross-State Air Pollution Rule 

In the Cross-State Air Pollution Rule (CSAPR), the 

EPA seeks to “limit the interstate transport of emissions 

of nitrogen oxides (NOx) and sulfur dioxide (SO2) that 

contribute to harmful levels of fine particle matter (PM2.5) 

and ozone14 in downwind states.”15 These emissions—

referred to as “criteria pollutants” under the federal CAA—

are carried downwind as SO2 and NOx or, after being 

transformed in the atmosphere, as fine particles or ozone. 

By reducing emissions in upwind states, air quality in 

downwind states is improved, thereby helping downwind 

states meet National Ambient Air Quality Standards 

(NAAQS). The EPA published the final rule in June 2011.

Mercury/Air Toxics Rule

The “National Emissions Standards for Hazardous 

Pollutants,” commonly referred to as the “Mercury/

Air Toxics Rule,” is the first national standard to reduce 

mercury and other toxic air pollution from coal- and 

oil-fired power plants.16 Pollutant emissions that the rule 

covers include mercury, arsenic, other toxic metals, acid 

gases, and organic air toxics such as dioxin. The final rule is 

expected in November 2011.

New Source Performance Standards (GHG)

The CAA requires the EPA to establish categories of 

major polluters and to develop New Source Performance 

Standards (NSPS) for new or modified sources in each 

category. In December 2010, the EPA entered into 

a settlement in which it agreed to develop NSPS for 

greenhouse gases (GHG) from new and modified electric 

generators and emission guidelines for existing electric 

generators. On September 14, 2011, the EPA announced 

that it would miss the September 30, 2011 deadline for 

the proposed rule and stated that it would announce a new 

timetable in the near future.17 

Coal Combustion Residuals Rule

The EPA proposed a rule on Coal Combustion Residuals 

(CCRs) from electric utilities in June 2010 but has not 

set a date for a final rule.18 CCRs are byproducts from 

the combustion of coal that include fly ash, bottom ash, 

boiler slag, and FGD materials. In 2008, over 136 million 

tons of CCRs were produced in the United States. This 

waste is currently disposed of in various ways. It is placed 

in approximately 300 CCR landfills and in 584 surface 

impoundments at approximately 495 coal-fired power 

plants across the nation. It is also placed in mines or is 

“beneficially” used (e.g., in building materials.)19
9

Working to Ensure Affordable Compliance with Public Health and Environmental Regulations

Proposed Regulation

316(b) Cooling Water 

Rule

Wastewater Rule

Cross-State 

Air Pollution Rule 

Mercury/Air

Toxics Rule

New Source Performance 

Standards for 

Greenhouse Gases

Coal Combustion 

Residuals Rule

Targeted Pollutant

Cooling water intake design

Wastewater toxic metals

Reduced downwind 

contribution to ozone and 

PM2.5 non-attainment

Hazardous air pollutants 

(Hg, HCl, metals, organics)

Greenhouse gases

Coal combustion waste disposal

Control Options

Intake design upgrades: 

cooling water intake structures

Treatment or zero discharge

NOx removal: selective 

catalytic reduction (SCR) 70-

95%; selective non-catalytic 

reduction (SNCR) 30-75%;

SO2 removal: scrubber ≥95%; 

dry sorbent injection <70%

Hg removal: fabric filter 

baghouse (FF) -activated 

carbon injection (ACI) 

80-90%; Scrubber-SCR 

co-benefit >90%

CCS, market-based 

approaches

Phase out wet surface 

impoundments (ash ponds); 

composite liners; other 

changes for disposal sites

Schedule

•	 Proposed rule April 20,

2011

•	 Final rule July 2012

•	 Facility compliance due

by 2020

•	 Proposed rule July 2012

•	 Final rule January 2014

•	 Final rule July 2011

•	 Unit compliance due in

stages:

•	 Phase I begins January

2012

•	 Phase II begins January

2014

•	 Phase II CSAPR

rulemaking 2012?

•	 Proposed rule May 3, 2011

•	 Final rule due November

16, 2011

•	 Unit compliance due by

November 2015 

(3 years, case-by-case 

1-year extension)

TBD

•	 Proposed rule March 2010

•	 Final rule TBD

•	 Ash pond closures 5-7

years after final rule 

(2016-2018)

Figure 2 

Major EPA Rulemakings Impacting Power Plants20

Abbreviations: CCR, carbon capture and storage; CSAPR, Cross-State Air Pollution Rule; HCl, hydrochloric acid; Hg, mercury.

20 Based on Silva, 2011.
10

Incorporating Environmental Costs in Electric Rates

Abbreviations: SCR, selective catalytic reduction; SNCR, selective 

non-catalytic reduction; FGD, flue gas desulfurization; DSI, dry 

sorbent injection; ACI, activated carbon injection

Potential Costs of Pollution Controls

Meeting the requirements of these regulations will call 

for significant investment in compliance technology. We 

consider several examples here, one under the Clean Water 

Act and two under the CAA. 

Although a generator might comply with cooling 

regulations by installing screens or nets or by reducing 

cooling water intake velocity, many generators will have 

to construct a cooling tower or towers at their facilities. 

Modelers have estimated the costs of cooling towers to be 

directly influenced by the physical layout of a plant and the 

rate at which it pumps water. The North American Electric 

Reliability Corporation (NERC) has estimated the cost of 

cooling technology within a range of $170 to $440 (2010 

dollars)/gallons per minute for typical plants and higher for 

more constrained locations (i.e., plant sites with insufficient 

space to locate cooling towers).21 Edison Electric Institute’s 

estimates range from $319 to $459/gallons per minute, for 

fossil plants and nuclear plants, respectively.22

Likewise, investment required by the Cross-State Air 

Pollution and Mercury/Air Toxics Rules can be expected 

to be significant and, depending on the generation unit, to 

require the installation of a combination of controls. Figure 

3 depicts the types of controls that are likely to be installed 

in response to these two air rules. 

It should be noted that some of these technologies 

can help generators meet reduction requirements from 

21 North American Electric Reliability Corporation, October 2010, p. 48. 

22 ICF International, January 2011, Appendix A.

23 For a more complete discussion of compliance technologies, see Farnsworth, 2011, pp. 26-27, 36, Appendix 2. 

Pollutant

NOx

SO2

Mercury

Particulates

Compliance Technologies

SCR/SNCR

FGD/DSI

ACI

Fabric Filters (plus ACI/DSI)

both rules. For example, FGD can be used to reduce SO2

emissions required by the CSAPR as well as the emission of 

acid gases and mercury required by the Mercury/Air Toxics 

rule.23

Figure 4 shows some of the key investments that may 

be incurred to meet the criteria and hazardous pollutant 

standards discussed previously; it does not show the 

operating costs or the power losses for each of these 

measures. CO2 compliance is not included in this diagram 

but is discussed in Section 4.

Figure 3 

Compliance Technology for the Cross-State 

Air Pollution and Mercury/Air Toxics Rules
11

Working to Ensure Affordable Compliance with Public Health and Environmental Regulations

Control

Technology

FGD

DSI

SCR

SNCR

Fabric Filter 

+ ACI

Capital Cost

($/kW)

$501

$40

$197

$19

$155 + $9

Fixed O&M

($/MW-yr)

$8,150

$590

$720

$260

$630 + $40

Variable O&M 

($/MWh)

$1.81

$7.92

$0.66

$1.33

$0.15 + $0.93

Type of Emissions 

Controlled

SO2

SO2

NOx

NOx

Particulates

Figure 4 

Representation of Air Pollution Controls24

24 The Brattle Group, December 2010. As with other figures provided in this paper, this figure is intended as an illustration. 

Individual plants, because of site-specific factors, will come with their own costs.

25 PJM Interconnection, August 26, 2011, Table 2. 

Figure 5 provides a 

representation of these types 

of air pollution controls and 

their related capital and fixed 

and variable operation and 

maintenance (O&M) costs as 

applied to a 500-MW coal unit. 

Because of the economies of 

scale associated with retrofit 

installations, the larger the unit, 

the lower the likely capital costs 

per kW and fixed O&M costs per 

MW of capacity. Also, the larger 

the unit, the higher the variable 

O&M costs per MWh of output.

Figure 5

Pollution Control Retrofit Costs25

For a Representative 500-MW Coal Unit in the 

PJM Regional Transmission Organization Interconnection

SCR: $50-60 million 

for a 300MW plant

Cooling tower:

$60-90 million 

(300MW)

Low NOx 

Burners

Reduces NOx

Bottom Ash

A by-product useful 

in concrete and other 

products, or stored

Fly Ash

A by-product 

useful in 

concrete 

and other 

products, or 

stored 

Gypsum

A by-product 

useful in 

wallboard

Emission Monitoring

Continuously monitors 

many types of emissions

Limestone

Fabric Filter

Captures particulate 

matter and mercury

Selective 

Catalytic 

Reduction

Reduces NOx 

and enhances 

mercury 

removal

Wet ESP

Reduces 

fine 

particulate 

and sulfuric 

acid mist

Scrubber

Removes SO2

and mercury

Steam Generator

High efficiency 

boiler produces 

less emissions per 

megawatt output

Coal & Pet Coke

Pulverizers

Fabric Filter

Economizer NH3 Injection

Combustion Air

Air Heater

Burners

FD Fans 

SO2 Reduction

Wet FGD

PC Boiler with Low 

NOx Combustion 

System

Scrubber:

$100-120 

million 

(300MW)

ACI & Baghouse:

~$30 million (300MW)
12

Incorporating Environmental Costs in Electric Rates

Control

Technology

FGD Range

(Average)

DSI Range

(Average)

SCR Range

(Average)

SNCR Range 

(Average)

Fabric Filter 

+ ACI Range 

(Average)

Capital Cost

($/kW)

$331-$1,149

($677)

$9-$273

($89)

$175-$427

($263)

$11 - $136

($48)

$118-$468

($225)

Fixed O&M

($/MW-yr)

$1,580-$44,710

($12,100)

$170-$5,670

($1,780)

$550-$15,600

($4,130)

$140-$4,900

($1,190)

$520-$9,340

($1,190)

Variable O&M 

($/MWh)

$1.01-$3.81

($1.93)

$2.00-$15.54

($5.71)

$0.20-$1.41

($0.47)

$0.34-$2.16

($1.12)

$0.52-$1.59

($1.09)

MW Size 

Range

28-1,300 MW

(211 MW)

43-1,320 MW

(408 MW)

16-554 MW

(161 MW)

45 – 1,300 MW

(256 MW)

16-1,320 MW

(299 MW)

26 PJM Interconnection, August 26, 2011.

27 PJM Interconnection, August 26, 2011, Table 3. 

28 For example, see several studies cited at Farnsworth, 2011, 

p. 24; see also Miller, 2011.

29 For an extended discussion of preapproval issues, see 

National Regulatory Research Institute, 2008.

Figure 6

Pollution Control Retrofit Cost Estimate Ranges27

For Coal Generation in the PJM Regional Transmission Organization Interconnection

Figure 6 shows a range of 

costs for pollution control 

retrofits for coal-fired units 

in PJM associated with the 

Cross-State and Mercury/

Air Toxics Rules. Although 

factors associated with 

individual plants will drive 

actual retrofit decisions, both 

Figures 5 and 6 highlight 

the likelihood that smaller 

and less efficient plants will 

be more challenged to make 

the case for investing and 

retrofitting. As noted by PJM, 

“higher costs mean that small 

units will require greater 

revenues per MW of capacity 

to pay for pollution control 

retrofits.”26

Combined Costs of Compliance for 

Combined Rules

The ultimate cost of compliance with the EPA’s public 

health and environmental regulations will depend on the 

final form that these rules take and will vary from company 

to company, plant to plant, and region to region, depending 

on what controls are currently installed and what more are 

needed. Several analysts have prepared estimates of the cost 

of compliance, and the number of plants that may become 

uneconomical 

as a result of the 

rules.28 None of 

these, however, 

also addresses the 

effect that CO2

regulation may 

have on plant 

viability.

Our purpose 

in this paper is 

not to discuss 

whether the rules 

are appropriate 

or needed, but 

rather to educate 

utility regulators as to the need for comprehensive analysis 

of retrofit costs so that reasoned decisions can be made 

on whether incremental retrofit expenditures should be 

approved. In some states, approval takes place before 

expenditures are made (preapproval), and in others, only 

after the utility has made investments and seeks to include 

those costs in rates in a general or other rate proceeding.29

A retirement decision must compare the present value 

or levelized cost of a compliance strategy and operating an 

existing power plant with the least-cost alternative. That 

alternative may be increased operation of other existing 

power plants, construction and operation of new fossil or 

renewable power plants, investment in energy efficiency 

measures, or a combination of these. 

A retirement decision must 

compare the present value or 

levelized cost of a compliance 

strategy and operating an 

existing power plant with the 

least-cost alternative. That 

alternative may be increased 

operation of other existing 

power plants, construction 

and operation of new fossil 

or renewable power plants, 

investment in energy 

efficiency measures, or a 

combination of these. 
13

Working to Ensure Affordable Compliance with Public Health and Environmental Regulations

Approximately half of the coal plants in the 

United States are owned by utilities subject 

to state regulation. The others are owned by 

a mix of federal agencies, Indian nations, 

consumer-owned utilities, industrial facilities, and nonutility generators. This section addresses how state utility 

regulators should consider requests related to retrofits and 

closures from the utilities they oversee.

Regulators should expect to receive piecemeal requests 

from utilities for preapproval and rate case approval of 

their investment in emission control measures at older 

power plants and the operating expenses associated with 

these emissions controls. Rather than seek approval for 

the full suite of improvements needed to address SO2, 

NOx, hazardous air pollutants like mercury, CO2, and 

other environmental compliance issues, it is likely that 

many applications will address only one pollutant at a 

time, so that the full picture of long-run costs is never 

before regulators in a single docket. To be fair, it may 

be that specifics of some of the future rules are not fully 

known at any point. A comprehensive analysis can include 

an estimate of future compliance costs for regulators to 

evaluate.

Some of these requests will likely seek recovery for 

emission management costs as part of a general rate case. 

In many cases, however, the requests will seek dollar-fordollar recovery through adjustment clauses rather than 

consideration in general rate cases and inclusion in base 

rates. 

Some requests will come in the form of preapproval 

requests for such things as budget approval, certificates of 

public convenience and necessity (CPCN), and integrated 

resource plan (IRP) proceedings. Other requests will come 

to regulators only after the expenditures are made in 

3. What Kinds of Requests Will Regulators 

Likely See From Utilities?

30 CoalSwarm, “Scrubbers,” 2011.

31 China has closed some 50,000 MW of small coal plants in recent years; see Power Magazine, August 5, 2009.

general or special purpose rate cases. 

Regulators must insist on a full analysis of the effect of 

current and prospective environmental compliance costs 

and should also examine the residual public health and 

environmental damages before approving any investment. 

Failure to consider all prospective costs can result in 

incremental uneconomical decision-making.

In addition, regulators need to consider alternative ways 

to meet customer needs, environmental requirements, and 

reliability standards. Energy efficiency, demand response, 

and distributed generation need to be considered in 

addition to supply-side options. A full IRP analysis, similar 

to what the Oregon PUC required of Portland General 

Electric (PGE) before approving a plan for the Boardman 

plant is an example of this (see Section 5, below).

a. The Age of U.S. Coal-Fired Power Plants

Figure 7 shows the age of coal-fired power plants in the 

United States. Generally, those built before 1980—about 

70% of total existing capacity—were built without any 

modern pollution control equipment. Some have been 

retrofitted in the intervening years with some emission 

control equipment, but only one third of the coal capacity 

has SO2 scrubbers.30 The newest plants generally have the 

most sophisticated pollution control equipment and will 

be subject to the fewest additional regulations. The oldest 

plants—one third of the total capacity, most of which 

are more than 40 years old—will require very expensive 

renovation if they are to continue to operate. These are 

also generally smaller generating units, for which the lack 

of economies of scale mean that retrofit will be less costeffective than for the newer, larger generating units.31
14

Incorporating Environmental Costs in Electric Rates

32 U.S. Energy Information Administration, 2008.

33 North American Electric Reliability Corporation, October 2010, pp. 50-55. 

b. The Cost of Retrofits for Control of 

Criteria Pollutants

Criteria pollutants include specific emissions for which 

there are specific standards, including oxides of nitrogen, 

sulfur dioxide, plus toxic substances like mercury. Initially, 

these requests will likely include the cost of SO2 scrubbers, 

SCR, and mercury controls. They will involve baghouses 

and fabric filters. These will be needed to continue 

operations once forthcoming regulations are implemented. 

Based on recent experience, these types of controls will 

likely cost $200 to $500 per kW of capacity—enough to 

double the current rate base associated with these older 

units.33

But these investments may be followed by requests to 

cover the costs of carbon regulation and other measures, 

such as cooling towers to address once-through cooling 

issues, and waste disposal equipment, transportation, and 

waste disposal sites to address coal combustion residual 

issues. Those costs may not be knowable and may be very 

high or quite moderate, depending on the timing and form 

Figure 7

U.S. Coal-Fired Power Plants as of December 31, 200832

of carbon regulation ultimately adopted.

Finally, all of these investments will involve operating 

expenses for staff, chemicals, and the power to operate the 

equipment. (See, for example, Fig. 9.) In many cases, the 

pollution control equipment will reduce the power output 

of the generating station (in some cases, plants may be 

upgraded to higher capacity during the retrofit shutdowns). 

And finally, if carbon sequestration becomes the viable 

alternative that many fossil energy companies believe will 

occur, there will be additional capital costs, operating costs, 

and very significant energy costs to separate, transport, and 

sequester CO2. 

Figure 8 shows estimates for actual proposed retrofits for 

several Western U.S. coal plants for SO2, NOx, and particulate emissions. These estimates range from $22/kW to 

$1,327/kW. The more expensive retrofits justify more comprehensive analysis beyond just the three pollutants being 

addressed. The figures below do not reflect the changes in 

operating costs or plant efficiency that are inevitable.

Figure 8 does not include any estimates for compliance 

costs associated with hazardous air pollutants (e.g., 

1000

900

800

700

600

500

400

300

200

100

0

100%

90%

80%

70%

60%

50%

40%

30%

20%

10%

0%

Before1970 1970-1979 1980-1989 1990-1999 2000-2008

Number of plants built

Percentage of megawatts produced

115,942 MW

122,636 MW

80,171 MW

12,946 MW 6,605 MW
15

Working to Ensure Affordable Compliance with Public Health and Environmental Regulations

34 National Park Service, 2010.

35 U.S. Energy Information Administration, 2008.

Figure 8 

Cost Estimates for Proposed Pollution Retrofits on Selected Western Coal Plants34

Plant MW In-Service Total $ SO2 $/kW NOx $/kW PM10 $/kW Total $/kW 

Naughton 700 1963 $491,896,704 $304 $222 $177 $703 

Boardman 617 1980 $470,800,000 $401 $362 — $763 

Johnston 330 1959 $438,000,000 $1,008 $77 $242 $1,327 

Bridger 2,120 1974 $423,359,784 $21 $173 $6 $200 

Big Stone 475 1975 $223,100,000 $297 $172 — $470 

Boswell 375 1958 $194,318,000 $211 $205 $102 $518 

Wyodak 335 1978 $93,900,000 — — — $280 

Coal Creek 550 1979 $81,482,700 $139 $10 — $148 

Sherburne 1,373 1976 $30,600,000 $5 $17 — $22 

mercury), CO2 or other 

climate change mitigation 

measures, ash management, 

or cooling. The total of these 

costs can easily be of the same 

magnitude or greater. Other 

estimates of retrofit costs have 

been published in reports 

previously cited in this paper.35

c. Emission Costs May 

Justify Permanent 

Closure of Some 

Plants

If all potential emission 

control and compliance costs 

are considered, it is likely 

that many power plants will 

be found uneconomical and 

closed permanently.

The key risk, however, 

Current Cost 2011 $200.00 $0.006 $0.030 $0.036 

Selective Catalytic Reduction 2014 $200.00 $0.006 $0.005 $0.046 

Low-NOx Burners 2014 $100.00 $0.003 $0.049 

SO2 Scrubbers 2016 $400.00 $0.011 $0.005 $0.066 

Particulate Baghouse 2016 $100.00 $0.003 $0.001 $0.070 

Cooling Tower 2018 $300.00 $0.009 $0.003 $0.081 

Coal Residuals Disposal 2018 $0.003 $0.084 

CO2 Allowances @ $30/ton 2020 $0.030 $0.114 

Cost Element

Year 

Incurred

Investment-Related Cost 

 Expressed 

as $/kW 

Expressed 

as $/kWh 

 Operating 

Cost 

 $/kWh 

 Cumulative 

Retrofit 

Cost 

 $/kWh 

Note: Investment costs converted to $/kWh using a 15% fixed charge rate and 60% capacity factor.

Figure 9

Illustrative Example of Potential Cumulative Retrofit Costs 

At A Single Plant
16

Incorporating Environmental Costs in Electric Rates

36 CoalSwarm, “Retrofit vs. Phase-Out of Coal-Fired Power Plants,” 2011; Boardman data from Hirsh, Northwest Energy Coalition; 

In-service dates from U.S. Energy Information Administration, 2005 and 2008.

Plant Name Principal Owner Megawatts

Initial 

In-Service 

Date(s)

Shutdown 

Year

Principal Shutdown 

Cause(s)

is that these expensive measures will 

come before regulators on a piecemeal 

basis, rather than in a comprehensive 

review. This can lead to more money 

spent over time than the final product 

is worth. Figure 9 shows an illustrative 

example of what might be spent for 

emission compliance on an older 300-

MW coal-fired power plant; the costs 

are representative, but the in-service 

dates are entirely dependent on what 

is required and when, which is highly 

uncertain.

A power plant subject to all of these 

needed retrofits will be a more likely 

candidate for permanent shutdown 

Mohave

Boardman

Lee, Sutton, Cape Fear, 

Weatherspoon

Gorsuch

Wabash

Arapahoe

Cameo

Cromby, Eddystone

Centralia

SCE

PGE

Progress

American 

Muni Power

Duke

Xcel

Xcel

Exelon

TransAlta

1,636

601

1,500

200

350

160

66

732

1360

1971

1980

1951, 1954, 

1956, 1949

1988

1953

1951

1957

1954, 1960

1972

2005

2020

2013-2017

2011

2010

2015

2010

2012/2013

2020/2025

SO2, CO2, NOx, water, 

slurry pipeline

SO2, CO2; may be 

repowered

SO2

SO2, NOx

SO2, NOx

NOx, CO2

CO2

Overall operating cost

Legislatively negotiated

and replacement with a newer lowemission generating unit, renewable 

energy resources, or energy efficiency 

investments. At some point during 

the gradual retrofit, the operating 

costs alone might make the plant 

uneconomical to run, independent of 

the investment costs required to keep 

it available for service; for example, 

rising coal commodity costs, due to 

increased exports to countries where 

coal displaces petroleum, are not even 

reflected in this illustrative example. 

Many units have been scheduled 

for closure as a result of environmental 

compliance and other costs. Figure 10 is 

If all potential emission 

control and compliance 

costs are considered, it is 

likely that many power 

plants will be found 

uneconomical and closed 

permanently.

The key risk, however, 

is that these expensive 

measures will come before 

regulators on a piecemeal 

basis, rather than in a 

comprehensive review. 

Figure 10 

Selected U.S. Coal Plants Closed or Scheduled To Close Due to Emissions Costs36

Abbreviations: PGE, Portland General Electric; SCE, Southern California Edison.
17

Working to Ensure Affordable Compliance with Public Health and Environmental Regulations

a partial list of units that have been closed or are scheduled 

to be closed (or re-powered) for various reasons. 

d. Preapproval of Expenditures

Utilities often request preapproval of expenditures for 

pollution control equipment. Preapproval means that the 

regulator generally reviews the proposed investment and 

the associated budget and then, barring imprudence in 

implementing an approved plan, allows cost recovery. The 

concept of “prudence” can include such things as failure 

to consider factors known to management in the original 

proposal, failure to effectively manage the retrofit process, 

or failure to reconsider the project as additional cost 

information becomes available.

Preapproval is a common practice, and once obtained, 

cost recovery is highly likely. For example, under Ohio 

law, under an automatic recovery rider, utilities are able to 

recover the costs of environmental compliance, including 

“the cost of emission allowances; and the cost of federally 

mandated carbon or energy taxes...” and a “reasonable 

allowance for construction work in progress ... for an 

environmental expenditure for any electric generating 

facility of the electric distribution utility....”37

Some state laws require a preapproval process, and 

some regulators have a policy of considering requests for 

preapproval without any legislative requirement. Others 

insist that investment decision-making is a management 

responsibility and will only review the actions of 

management when the investment is completed and enters 

service. Each regulator must make his or her judgment on 

this, guided by state law and regulatory precedent.

If preapproval is to be considered, regulators should 

insist on a clearly stated comprehensive plan for investment 

that can be reasonably anticipated given the state of the 

regulations, with some sensitivities, and a comprehensive 

analysis of project cost-effectiveness after the investment 

is completed so consumers are not signed up to pay for 

something that may not be completed or that may not work 

as expected once finished. Using the previous legislative 

example, a comprehensive analysis would evaluate the 

value of the project under a range of possible outcomes, 

including an explicit future price for carbon.38 As discussed 

in what follows, such an analysis would include a 

consideration of future compliance costs and an evaluation 

of short-term and long-term alternatives to investment in 

an older power plant.

e. Requests for Adjustment Clauses

Some utilities have requested, and some regulators have 

granted, separate adjustment clauses for pollution control 

equipment costs. An adjustment clause (also sometimes 

referred to as a “cost tracker” or “tariff rider)” is a separate 

surcharge (or sur-credit) to track specific costs in rates, 

independent of the utility costs and rates established in a 

general rate case.39

One benefit of adjustment clauses is that the utility 

recovers dollar for dollar exactly the level of costs incurred. 

When rates are set in a general rate case, if sales volumes 

increase, the utility recovers additional revenues for which 

there may be no associated costs (and vice versa if sales 

decline). For example, retrofits of power plants often 

include modifications that increase the capacity of the 

units, meaning that more power can be produced from the 

modified plant and potentially sold on the market if the 

capacity is not needed for jurisdictional customers. In this 

case, there should be an offset for what customers pay for 

the upgrades or the customers should receive the value 

(minus an incentive payment) of the off-system sales to 

offset the cost of the pollution control upgrade. 

One thing regulators will need to consider is whether 

emission management costs bring with them offsetting cost 

savings. For example, if scrubbers are installed at a coal 

plant to reduce sulfur emissions, the utility will avoid the 

need to buy SO2 allowances. In addition, the utility may 

be able to operate the plant more of the time, avoiding 

purchasing or generating higher cost power from other 

sources. These issues can be considered in either a special 

purpose rate proceeding or a general rate proceeding.

37 Ohio Revised Code, Section 4928.143(B)(2)(a)and (b).

38 For the purpose of this discussion, a price for carbon could come in the form of a carbon tax, a cap-and-trade mechanism, or an 

offset requirement; the issue is that some future price for carbon emissions would be evaluated.

39 For a general discussion of adjustment mechanisms, see Lazar, Regulatory Assistance Project, March 2011. 
18

Incorporating Environmental Costs in Electric Rates

40 Costello, 2009. 

41 Costello, 2009.

42 Costello, 2009.

According to the National Regulatory 

Research Institute (NRRI), regulators 

have traditionally approved adjustment 

clauses under “extraordinary 

circumstances,” characterized as (a) 

unpredictable and volatile, (b) largely 

outside the utility’s control, and (c) 

involving costs that are substantial 

and recurring.40 Also, historically, in 

order to get cost recovery through this 

mechanism, “regulators required that all 

three conditions exist....” 41 According 

to NRRI, their popularity “reflects the 

perception that these mechanisms are 

necessary to prevent a utility from earning a rate of return 

substantially below what was authorized.” 42

In general, emission management costs are not volatile; 

they involve large capital investments and predictable 

periodic operating costs. But they do meet the other two 

criteria: outside the utility’s control, and substantial and 

recurring. 

Regulators should consider whether or not one-time 

environmental compliance costs meet the criteria for costtrackers, and if this or another approach better guarantees 

that company management, as it develops environmental 

compliance strategies, will make leastcost choices. Because they provide 

for the automatic inclusion of predefined costs in rates, cost-trackers 

largely take away a utility company’s 

incentive to minimize costs. Costtracker mechanisms typically come with 

the opportunity for an after-the-fact 

prudence review, but they place the 

burden of demonstrating imprudence 

on the public advocate or other 

stakeholders. 

Denials of cost recovery in this 

context could also appear inequitable 

by comparison to a more traditional regulatory approach 

that makes company management responsible for 

demonstrating, in the first place, the reasonableness of its 

decisions and related costs before they are put into rates. 

Also, with the high cost of pollution control, utilities seek 

to minimize their risk by transferring more and more costs 

to consumers. Furthermore, this issue of raising capital 

becomes more contentious when dealing with multi-state 

utilities in which individual utilities compete with their 

affiliates for parent company funds.

Regulators have 

traditionally approved 

adjustment clauses 

under “extraordinary 

circumstances,” 

characterized as (a) 

unpredictable and volatile, 

(b) largely outside the 

utility’s control, and (c) 

involving costs that are 

substantial and recurring.
19

Working to Ensure Affordable Compliance with Public Health and Environmental Regulations

4. Costs of CO2 Reduction or Mitigation

Approximate CO2 Emissions of 

Electricity Generation 43

2,500

2,000

1,500

1,000

500

0

Figure 11

Pulverized 

Coal

IGCC

Coal

Natural Gas 

Combined 

Cycle

Nuclear, 

Hydro, 

Renewables

Abbreviations: IGCC, integrated gasification combined cycle.

The biggest wildcard in the future of coal- and 

fossil fuel-fired electricity generation is the 

potential cost of reducing or mitigating emissions 

of CO2. Coal combustion results in the highest 

level of CO2 emissions per unit of electricity of any major 

resource. Figure 11 compares CO2 emissions from various 

electric generation technologies.

Currently there is no commercialized and cost-effective 

means of removing carbon from electric generator 

emissions as there is for other pollutants. Carbon capture 

and storage (CCS) is one of the CO2 compliance strategies 

that industry has started to explore. According to the 

U.S. Department of Energy (DOE), “capture technologies 

available today are not cost-effective when considered in 

the context of sequestering CO2 from power plants.”44

There are a number of reasons for this.

Before CO2 can be collected and sequestered from 

sources like power plants, it has to be captured as a 

relatively pure gas. This is a challenge because power plants 

use air-fired combustors, a process that exhausts CO2

43 Regulatory Assistance Project calculation based on Synapse 

Energy Economics, 2006, Chapter ES; only generation-related 

emissions are reflected, not construction or fuel-production 

emissions.

44 U.S. Department of Energy, “Carbon Capture Research,” 

2011. 

45 U.S. Energy Information Administration, 2011. 

46 U.S. Energy Information Administration, 2011.

47 It should be noted that the U.S. Department of Energy has 

been supporting pilot CCS projects and regional partnerships 

around the country; see U.S. Department of Energy, “Carbon 

Sequestration Regional Partnerships,” 2011; see also Wood, 

2011.

diluted with nitrogen (typically 10-12% CO2 by volume 

for coal plants) and requires that the gas be separated and 

concentrated.45

In pilot programs, CO2 is currently recovered from 

combustion exhaust by using amine (derivatives of 

ammonia) absorbers and cryogenic coolers. The cost of 

CO2 capture using this approach, however, is on the order 

of $150 per ton of carbon, which could increase the cost of 

electricity by 2.5 to 4 cents/kWh, depending on the exact 

type of process used. This is a significant increase over the 

U.S. average retail price of electricity, which was 9.87 cents 

in May 2011.46

Furthermore, the “capture” of CO2 from combustion 

exhaust is only one part of CCS. There are also significant 

costs associated with the development of CO2 storage, 

transport, and sequestration options. Technical innovation 

could dramatically change these estimates in the future.47

Although the EPA is expected to issue New Source 

Performance Standards for GHGs in the fall of 2011, it 

is not clear what form they will take. According to some 

commentators, the EPA has a significant degree of flexibility 

in setting them:

Given agency discretion to define uncertain statutory 

terms like “best system of emission reduction,” and given 

Pounds per Megawatt-Hour
20

Incorporating Environmental Costs in Electric Rates

the potential of compliance flexibility 

mechanisms to reduce costs while 

preserving total emissions reduction 

goals, EPA and the states should be able 

to fit a variety of flexible approaches into 

the statutory criteria for performance 

standards.48

If the EPA is able to grant compliance 

flexibility to states, this could pave 

the way for the use of market-based 

compliance approaches, potentially 

lower-cost alternatives to CCS or related 

control technology approaches that are 

still at a research, development, and 

demonstration level. Existing marketbased compliance approaches include: 

(1) the 3-year-old Regional Greenhouse Gas Initiative, in 

which 10 northeastern states implemented a cap-and-trade 

program for electric generation; (2) the EU Emissions 

Trading Scheme (ETS),49 started in 2005; (3) California’s 

greenhouse gas program,50 slated for a January 2012 start; 

and (4) the federal CAA’s 20-year-old acid rain program. 

48 See for example, Wannier et al, 2011, p. 1; and Litz et al, 2011.

49 See European Commission, 2011. Europe’s carbon market or “Emission Trading Scheme.” http://ec.europa.eu/clima/policies/ets/

index_en.htm 

50 In 2006, California adopted “the Global Warming Solutions Act of 2006,” which establishes various programs, including a 

market-based program to reduce greenhouse gases that is supposed to start in January 2012; see California Environmental 

Protection Agency, 2011. 

51 China’s national energy regulator, the National Development Reform Commission, is in the process of developing cap-and-trade 

pilot programs in regions like Heilongjiang, Liaoning, Guangdong, and Hubei, and municipalities like Beijing, Tianjin, Shanghai, 

and Chongqing. See also New Zealand Ministry for the Environment, 2011; Tokyo Metropolitan Government, Bureau of the 

Environment, 2010; and Nishida, 2011.

Market-based compliance mechanisms 

would allow those better situated 

economically to make the decision 

to invest in compliance technology 

to reduce emissions and then sell/

trade any extra emissions reductions 

(allowances) to other affected sources for 

which investment in technology would 

be a more expensive option. Note also 

that other countries and jurisdictions, 

including China, New Zealand, and 

Tokyo, Japan are considering these 

issues and adopting or piloting similar 

programs.51

Although the political debate between 

command-and-control and other 

market-based approaches is beyond the 

scope of this paper, one day carbon emissions are likely to 

carry a cost. Regulators need to be prepared to recognize 

this, quantify its attendant risks, and include it in their 

analyses of proposals for cost recovery of environmental 

compliance costs.

Although the political 

debate between commandand-control and other 

market-based approaches 

is beyond the scope of this 

paper, one day carbon 

emissions are likely to 

carry a cost. Regulators 

need to be prepared to 

recognize this, quantify 

its attendant risks, and 

include it in their analyses 

of proposals for cost 

recovery of environmental 

compliance costs.
21

Working to Ensure Affordable Compliance with Public Health and Environmental Regulations

Should Utility Regulators Oppose 

Implementation of New Health and 

Environmental Regulations on Power Plants? 

Regulators may be asked by non-regulated 

generators to help oppose implementation of health 

and environmental regulations, on the basis that 

these regulations will increase market prices for 

power, and thus drive up wholesale and retail power 

rates. This is clearly a political role, and regulators 

will need to determine if participation in this type of 

issue is appropriate under the circumstances of their 

office. However, there are some important economic 

factors. To the extent that new gas-fired generation or 

renewable energy resources are available at lower costs 

than the sum of existing costs for older power plants 

plus the cost of needed upgrades, those resources will 

be competitive, and the owner of existing generation 

will be limited in how much they can charge. To the 

extent that energy efficiency resources are available at 

lower costs, an aggressive energy efficiency program 

may put downward pressure on the entire supply 

curve of competing generation, bringing huge 

offsetting economic benefits to consumers. 

The role of utility regulators is to provide a 

framework in which utilities recover prudently 

incurred costs associated with provision of 

service to consumers, while ensuring that 

consumers do not pay either inappropriate costs or provide 

excessive profits to utilities. In addition, regulators have the 

responsibility to allocate these costs fairly among customer 

classes and to design rates that are fair, just, and reasonable.

This section addresses the information that regulators 

should expect utilities seeking approval for retrofit 

investments to provide. It also addresses the risks that 

utilities should bear as part of the process of plant 

5. What Should Regulators Require of Utilities?

refurbishment, and what consumers should expect as a 

final result.

Regulators should establish clear requirements for 

utilities seeking cost recovery for investments in older 

power plants. The most important requirement is that 

a comprehensive analysis be prepared, considering all 

pending and potential investments that may be required to 

allow the unit to operate into the future. Regulators need all 

the facts or best available information and opinions at the 

time the utility asks for something, and should not accept 

only part of the story when rendering such momentous 

decisions.

At a minimum, the analysis should include the elements 

in the following checklist at the time regulators review any 

request for cost recovery for any emissions controls for an 

existing power plant:

•	 Operating history for the power plant and associated

cost data

•	 Remaining life of major components of the power

plant

•	 Status of compliance with existing public health and

environmental regulations 

•	 Cost of retrofits required in the short run to continue

operations in compliance with existing regulations

•	 Cost of potential retrofits or other strategies required

in the long run to continue operations, given 

forthcoming state environmental regulations

•	 Cost of potential retrofits or other strategies required

in the long run to continue operations, given 

forthcoming EPA rules

•	 Range of estimates of potential CO2 regulation costs

•	 Available alternative conventional generation

resources

•	 Available alternative renewable generation resources

•	 Available energy efficiency resources in the utility

service territory

•	 Available demand response (peak load management)
22

Incorporating Environmental Costs in Electric Rates

resources in the utility service territory

•	 Available distributed generation resources, including

combined heat and power, wind energy, and 

customer-sited solar

•	 Available transmission and distribution system

efficiency improvements

•	 Potential new transmission connections to available

cleaner resources outside the utility service territory

•	 A life-cycle cost analysis comparing plant

refurbishment and operation to the least cost 

alternative mix of supply and demand resources 

available if refurbishment is not pursued

•	 Evaluation of options within a portfolio of power

plants to concentrate retrofits on larger, newer plants 

for which the per-kWh retrofit costs are reasonable, 

and continue to operate older, smaller, dirtier plants 

on an as-needed basis, provided the total emissions 

meet overall emission goals 

The required analysis and data should accompany the 

request for consideration of compliance cost recovery. 

For many utilities, the proper way to prepare such an 

analysis is in the context of an IRP, portfolio management, 

or some other planning process. IRPs consider all available 

options to meet future requirements and compare them, 

considering cost, risk, reliability and other factors. The 

value of an IRP in this context is that all future potential 

costs and risks for a retrofit project are considered over 

the remaining lifetime of the resource and compared to 

alternatives.

Some utilities obtain much or all of their power from 

a wholesale supplier or suppliers, which may limit their 

contractual ability to substitute resources. Others operate 

in restructured states, and their power supplies are 

unregulated while their distribution service is subject to 

state regulation. This paper is primarily directed at the 

role of state utility regulators with respect to traditional, 

vertically-integrated utilities that own (or have long-term 

contracts for) generating facilities in addition to their 

distribution facilities.

In June 2011, in an investigation by the Oklahoma 

Corporation Commission (OCC) on the potential effects 

on Oklahoma of existing and forthcoming federal 

environmental regulations,52 one environmental group 

proposed that the OCC adopt “Integrated EnvironmentalCompliance Planning.” It is an approach that, in many 

ways, works like an IRP.53 It considers supply-side, 

demand-side, and delivery options in an integrated manner. 

It focuses, however, more closely on the requirements of 

forthcoming public health and environmental regulations. 

These concerns include emissions of CO2, SO2, NOx, 

mercury and other hazardous pollutants, coal combustion 

wastes, and limiting the amount of water necessary to cool 

thermal electric generating plants. Whether a commission 

employs integrated resource planning or integrated 

environmental-compliance planning, reviewing investments 

in an “integrated” manner is the key:

Responding to these requirements piecemeal will result in 

inefficient and unnecessarily expensive decisions. The sheer 

number and wide coverage of these pending rules mandates 

that the Commission and the utilities consider their potential 

impact in a comprehensive, rather than case-by-case basis, 

for both planning and cost recovery. The Commission should 

expect to see the anticipated costs and the potential risks 

of existing and emerging regulations for the whole range of 

pollutants in utility evaluations of their investment proposals. 

Given the capital-intensive and long-lived nature of 

investments in the electric industry, if the final form or timing 

of a regulation is unknown, the analysis should include both 

an expected value of the cost of compliance and the range of 

plausible costs.54

Figure 12 emphasizes the importance of planning by 

looking ahead to all likely environmental costs that may be 

candidates for inclusion in utility rates. It compares, in a 

simple illustrative way, the cost of power from an existing 

52 Oklahoma Corporation Commission, 2011.

53 Colorado’s “Clean Air – Clean Jobs Act” (HB 10-1365) is another example of Integrated Environmental-Compliance Planning. 

The Act anticipates new EPA regulations for NOx, SO2, and particulates, mercury, and CO2. It requires Colorado’s two investorowned utilities to consult with the Colorado Department of Public Health and Environment on utility plans to meet current 

and “reasonably foreseeable EPA clean air rules,” and to submit a coordinated multi-pollutant plan to the state Public Utilities 

Commission; see Colorado Legislative Council, 2011.

54 Sierra Club, July 18, 2011, p. 5. 
23

Working to Ensure Affordable Compliance with Public Health and Environmental Regulations

0.12

0.10

0.08

0.06

0.04

0.02

0 1 2 3 4 5

$/kWh

Potential CO2

Allowances

Potential Mercury, 

Ash , Water

Current SO2, NOx 

Regulation

Sunk Capital Cost

Fuel and O&M

Figure 12 

Illustrative Coal Plant Capital, Operating, 

and Emissions Costs

a. Utility at Risk for Elements Not 

Evaluated

The utility will be motivated to do a comprehensive 

analysis if it understands that the shareholders, not 

the ratepayers, will be at risk for any costs that are not 

considered when the first request for consideration of 

pollution control costs is filed. There is no reason the utility 

should have any greater assurance of cost recovery for 

these types of costs than for any other investment it makes, 

particularly if they cannot demonstrate having examined 

available alternatives over the life cycle of the proposed 

investment. 

These are not impositions “beyond the control” of the 

utilities; the utilities are firmly in control of the decision 

of whether to renovate or whether to choose alternatives. 

Utilities are required to follow many other requirements, 

from local government land use regulation to industryimposed safety and reliability standards. Environmental 

and public health regulations are just a part of the mix of 

regulations that utilities deal with as a part of their ordinary 

business risk—they also face labor, workplace safety, landuse, and other regulations imposed by local, state, and 

federal agencies.

For example, if the utility prepares a partial analysis 

considering only NOx and SO2 costs but not costs such 

as combustion residuals management or CO2, then the 

regulator should make it clear that the utility is at risk for 

future incremental costs that were not considered. 

This is most important to prevent piecemeal evaluation. 

The utility may fear that presenting a complete picture may 

lead to the regulator rejecting a request for cost recovery 

of retrofit costs. That rejection could leave the utility 

with a non-operable plant, and recovery of the remaining 

investment may be at risk (see an extended discussion of 

this topic later in this paper).

The role of the regulator is to apply reason and judgment 

to any decision. For example, if the utility considers all 

known and probable retrofit requirements and concludes 

that it is cost-effective to modify a plant for continued 

operation, and additional unanticipated regulations are 

55 For more information on planning, see Moskovitz, 1989; for a discussion of the Colorado Clean Air – Clean Jobs Act, see Farnsworth, 2011, p. 21.

coal plant without retrofit, with two levels of retrofit and with 

carbon costs. The first bar shows only the operating costs of 

the plant under existing regulations. The second bar adds 

the capital recovery of the remaining investment in the plant; 

most utilities and some regulators would consider these 

“sunk” costs and not a part of a forward-looking economic 

analysis. The third bar adds a rough amount for the costs of 

meeting current SO2 and NOx emissions regulations. The 

fourth bar adds a rough amount for the costs of meeting 

potential mercury, ash, and water regulations. The last bar 

adds a rough amount for the costs of meeting potential CO2

regulations. The point of this illustrative example is not to 

assign specific values to each element but to indicate the 

rough order of magnitude of these costs. 

The “fully renovated” power plant in this illustrative 

example would have costs of about $0.11/kWh, compared 

with $0.03/kWh for the current operating costs and $0.036 

for the current fully allocated costs, including a return 

on the existing investment. This renovated cost is well 

above the estimated cost of energy efficiency, wind, and 

geothermal generation and approaching the cost of solar 

and nuclear generation. The regulator would clearly want 

to consider whether it is cost-effective to consider plant 

renovation, given the future exposure that is evident.55
24

Incorporating Environmental Costs in Electric Rates

imposed later, the regulator could consider an additional 

cost recovery request. Regulation is not a static science.

The point of all of this is that the regulator must require 

the utility to do a thorough, objective, and transparent 

analysis of potential costs, and put that analysis to public 

scrutiny through the IRP process or an issue-specific 

proceeding.56 If it is cost-effective to improve and operate 

the power plant, the regulator should have the information 

to make that judgment. If it is not cost-effective, the 

regulator should have that information so that a reasoned 

judgment can be made on the disposition of the retrofit 

project. And if something is left out of the analysis, the 

utility should be at risk for the costs not considered.

The prudence standard as imposed by most regulators 

considers what the utility knew or could have known 

at the time of a decision. In the 1980s, when high-cost 

coal and nuclear plants were coming into service and 

electric rates were rising sharply, nearly every regulatory 

commission considered the prudence of these investments 

based on what was known and measurable at the time. 

Many regulators disallowed portions of the costs of both 

completed projects and abandoned projects. The potential 

retrofit costs and incremental operating costs for existing 

power plants are as large as or larger than the costs of new 

resources added in past decades. 

b. Examination of Non-Generation 

Alternatives 

Integrated resource planning compares power plants 

to non-generation alternatives such as demand response 

and energy efficiency. In states without IRP or other 

related processes for consideration of these alternatives, a 

process to compare coal plant retrofits with non-generation 

alternatives may not be well developed.

Demand Response: If the generating units being 

considered for retrofit are needed only to meet peak 

demand for a few days or weeks of the year, then demand 

response programs may be able to replace the units. 

“Demand response” is a term used to describe programs to 

change patterns of electric consumption in response to 1) 

changes in the price of electricity, or 2) incentive payments 

designed to induce lower electricity use at times of high 

wholesale market prices or when system reliability is 

jeopardized.57

Distributed Generation: New small generating 

resources located at customer facilities permit the utility to 

avoid not only generation costs, but also costs associated 

with transmission, distribution, line losses, and reserves. 

A full analysis of potential combined heat and power 

potential, customer-site solar, small wind generation, 

and other local generation is needed to fully examine 

distribution generation options.

Energy Efficiency: Improving the efficiency of energy 

end-use reduces total kWh consumption as well as peak 

demand. In most cases, the impact on peak demand is 

even greater than the average impact, simply because most 

energy-using devices (e.g., air conditioners) have usage 

concentrated in the on-peak period. Energy efficiency 

therefore can help displace the need to renovate older 

power plants regardless of whether these units are needed 

only during peak periods or if they operate as intermediate 

or baseload generating units.58

Renewable Energy Resources: Full consideration 

needs to be given to renewable energy alternatives available 

at the utility level, including wind, solar, geothermal, 

hydro, wave and current energy, and other options, plus 

energy storage options, such as pumped storage, that can 

convert as-available generation into firm capacity.

Natural Gas Generation: New natural gas generation 

is a common choice for utilities and non-utility generators 

to meet customer demand. Modern natural gas generators 

with state-of-the-art emission controls have extremely low 

56 For example, the Oregon Public Utilities Commission created an issue-specific docket for consideration of the Best Available 

Retrofit Technology analysis for the Boardman power plant, and then folded that analysis into the Portland General Electric IRP 

process. Both parts had transparency and public participation.

57 Federal Energy Regulatory Commission, 2011.

58 In evaluating the contribution of energy efficiency, it is crucial to consider the marginal line losses and marginal impact on 

generation reserves. A discussion of these topics is presented in Lazar and Baldwin, 2011.
25

Working to Ensure Affordable Compliance with Public Health and Environmental Regulations

emissions of criteria pollutants and less than half the CO2

emissions per unit of output compared with coal units. 

Use of natural gas in existing coal boilers may be an option 

if carbon capture and sequestration is anticipated to be 

available within a reasonable period of time.

Knowing the hourly load shapes is important to 

evaluating non-generation alternatives when considering 

renovation of older power plants for meeting peak demand. 

Groups in New England and the Pacific Northwest have 

done extensive end-use load analysis to examine the shape 

of hundreds of end-uses for electricity. This information 

informs the analysis as to what alternatives will best meet 

customer demands and what savings can be achieved 

through energy efficiency, allowing more accurate analysis 

of the relative value of alternatives to retrofitting any 

particular power plant.59 

c. Time Horizon for Analysis

The time horizon for comparison between the renovation 

of an older power plant and available alternatives should 

extend at least to the end of the lifetime of the renovated 

plant. For example, if renovation to address emissions would 

allow the plant to be operated for another 20 years, then the 

evaluation should encompass at least this life cycle.

Because replacement resources, including both generation 

and non-generation options, may have a shorter or longer 

lifetime than the renovated plant, it is important that the 

analysis be prepared on a levelized unit-cost basis. Use of 

this approach allows for the reasoned (“apples to apples”) 

comparison of measures with different lifetimes. Figure 13 

compares on an illustrative basis two generation options 

with long lifetimes to several energy-efficiency measures with 

shorter lifetimes. The actual costs for each of these options 

would be technology-, situation-, and region-specific.

The utility would be expected to implement all available 

measures costing less than coal plant renovation prior 

59 For more information on evaluation of energy efficiency as an alternative to generation, see Northwest Power and Conservation 

Council, 2010, Chapter 4. 

60 These are not actual costs for any specific analyzed resource; they are roughly accurate and intended to be illustrative of the 

concept that CO2 costs can push coal plant retrofit expense above the cost of alternatives.

Measure 

(illustrative only; no

specific cost data used)

Coal plant renovation w/o CO2

Coal plant renovation w/ CO2

@ $30/ton

New gas combined cycle w/o 

CO2

New gas combined cycle w/ 

CO2 @ $30/ton

Residential weatherization 

retrofit

Residential new construction 

code upgrade

Commercial lighting retrofit

Industrial motor upgrade

Measure 

Lifetime

20

20

25

25

30

50

12

15

Levelized 

Cost $/MWh

$50

$80

$60

$75

$55

$20

$25

$10

Figure 13 

Illustrative Measure Lifetimes and 

Levelized Costs 60

For Various Coal, Natural Gas, and 

Energy Efficiency Resource Options

to consideration of that renovation. Without any CO2

costs, coal would clearly be cheaper than natural gas. If 

the regulator determined that CO2 costs were likely to 

be incurred at a level of $30/ton, then the entire list of 

alternatives would be less expensive than renovation of 

the coal unit. A properly completed IRP will detail the 

available supply of energy efficiency and the achievable 

implementation schedule, allowing a determination of the 

adequacy of energy efficiency to displace existing (or new) 

supply-side resources.
26

Incorporating Environmental Costs in Electric Rates

61 CoalSwarm, “Boswell Energy Center,” 2011. 

62 Minnesota Power, 2011. 

63 Environmental Defense Fund, 2011. 

64 Beyond Coal Arkansas, 2011. 

65 Mother Nature Network, 2009. 

66 DSS Management Consultants, 2005. DSS Management Consultants, 2005. 

d. Example Analyses That Considered 

Only Immediate Costs

Minnesota: Boswell

The Boswell 3 power station is a 375-MW coal-fired 

generating unit that began operation in 1973.61 In 2006, 

Minnesota Power, the operator, requested that the Minnesota 

PUC consider and approve the estimated costs of $198 

million, or over $500/kW. The retrofits are designed to 

reduce 81% of NOx emissions, 90% of SO2 emissions, 93% 

of particulates, and up to 90% of mercury emissions.62

Minnesota Power applied to the Minnesota PUC 

for approval of the “Boswell 3 Plan” to bring this plant 

into compliance with state regulations, and requested 

an associated tariff rider for cost recovery. The plan set 

forth the proposed retrofit elements and associated costs. 

Included in this was the cost of upgrading the plant turbine 

to increase its generating capacity, replacing that which 

would be lost due to the energy use of the pollution control 

equipment.

The Minnesota PUC approved the Boswell 3 Plan, 

including a tariff rider that provides for full recovery. The 

increased capital and operating costs thus were recovered 

outside of a general rate case. The decision did not 

include any analysis of the potential cost of forthcoming 

environmental mitigation measures: the EPA’s Mercury/Air 

Toxics rule, New Source Performance Standards for CO2, 

or other pending EPA rulemakings, some of which may be 

more stringent than the Minnesota state regulation. It did 

not inventory available energy efficiency, renewable energy, 

or demand-response resources. It is unknown whether 

an alternative path may have been lower cost for electric 

consumers in the long run.

This is an example of incremental approval of very large 

expenditures without a complete picture of the potential 

future costs associated with continued operation of an aged 

power plant.

Entergy: White Bluff, Arkansas

White Bluff is a two-unit, 1,700-MW power plant near 

Redfield, Arkansas built in 1980. The owner, Entergy, 

proposed an expenditure of $1.04 billion for reduction of 

SO2 and NOx emissions. White Bluff is one of the 25 largest 

mercury emitters in the United States.63 Critics, including 

the Sierra Club Arkansas chapter, have requested that the 

Arkansas Public Service Commission evaluate White Bluff 

on a comprehensive basis, looking at SO2, NOx, mercury, 

and CO2 compliance costs together.64 They contend that if 

all of the potential costs are considered, plant retirement is 

the cost-effective option.65

e. Example Analyses That Consider 

Future Potential Costs

There have been several analyses of coal plant renovation 

costs that follow the criteria discussed previously: 

full consideration of certain, probable, and potential 

compliance costs. In some cases, these have also examined 

the public health and environmental costs of the residual 

environmental impacts. Some have fully considered 

potential CO2 costs. The following three examples illustrate 

some of the more complete analyses.

Ontario

In April 2005, the Ontario Ministry of Energy released 

a report on Ontario’s coal-fired generation.66 This study 

examined the potential cost of operating existing coal plants 

under the then-current regulatory scheme, renovating the 

plants, or replacing the units with either natural gas or 

nuclear generation. In each case, both the direct economic 

costs and the externalized public health costs associated 

with electricity generation were considered, although the 

analysis did not consider non-generation alternatives.

The final result of this study is shown in Figure 14. 

All alternatives were compared on a life-cycle cost basis. 
27

Working to Ensure Affordable Compliance with Public Health and Environmental Regulations

demand-side options.69 It analyzed available 

renewable energy resources and the transmission 

capacity required to bring them to market. 

Energy efficiency alternatives were not a part of 

the MACS report, because California already required 

utilities to acquire all cost-effective energy efficiency 

resources by the time the study was initiated.

The study itself did not recommend renovation 

or abandonment. Upon release, however, the project 

owners, led by Southern California Edison (SCE), 

elected to close the unit permanently.70 A federal 

review of this decision states:

Ultimately, it was a business decision that led to the 

closure of the Mohave Generation Station. From the 

perspective of the plant owners, the significant expenses 

related to the installation of pollution abatement 

equipment along with issues related to fuel supply 

outweighed the incremental costs of finding alternative 

sources of power. The Mohave Generation Station was 

closed due to concerns about the high levels of SO2, NOx, 

and particulate matter resulting from plant operations, a 

situation common to many of the Nation’s older coal-fired 

plants.71

Oregon: Boardman

The Boardman unit, built in 1980, is a 601-MW 

pulverized coal generating station located in eastern 

Oregon. It is jointly owned by PGE and several minority 

partners. 

The unit was built without scrubbers and was subject 

to review due to regional haze issues. As a part of the Best 

Available Retrofit Technology (BART) review, PGE examined 

three alternatives, each of which involved increasing costs, 

coupled with a longer plant operating lifetime. PGE ultimately proposed to discontinue coal use at the plant in the year 

2020, rather than invest significantly more in renovation to 

The most expensive option (the Base Case) was continued 

operation of the units without environmental controls, 

because of the public health impacts of unimproved 

operation. The total public health and environmental 

impacts associated with unimproved coal plant operation 

were estimated at $0.137/kWh—more than the total retail 

cost of electricity.

California: Mohave

The Mohave generating station, a 1,580-MW pulverized 

coal unit built in 1970, was in need of major renovation. 

In December 1999, a consent decree was reached with 

the Grand Canyon Trust and other groups that required 

installation of SO2 scrubbers by December 31, 2005, but 

the plant also needed refurbishment of other components. 

The estimated cost of renovation was $1.2 billion. The 

California PUC ordered a complete analysis of alternative 

and complementary options for Mohave.68

The Mohave Generating Station Alternatives/

Complements Study compared both supply-side and 

Figure 14 

Costs for Operating, Renovating, 

or Replacing Ontario’s Coal Plants 67

Scenario

Total Present Value

(2007-2026)

($Billions)

Annualized Costs 

($Millions)

Levelized Costs

($/MWh)

Health and 

Environmental 

Proportion

*Note: Values shown in parentheses are based on acute premature 

mortality damage estimates.

2 

All 

Gas

$29

($26)

$2,605

($2,279)

$98

($86)

20%

(9%)

3 

Nuclear/

Gas

$22

($18)

$1,942

($1,635)

$72

($61)

21%

(6%)

4 

Stringent 

Controls

$32

($21)

$2,802

($1,895)

$105

($71)

51%

(28%)

1 

Base 

Case

$49

($21)*

$4,377

($1,836)

$164

($69)

77%

(46%)

67 DSS Management Consultants, 2005.

68 California PUC, 2004. 

69 Synapse Energy Economics, 2006. 

70 Southern California Edison, 2011.

71 U.S. Energy Information Administration, “Southwest 

Weathers Closure of Mohave Generation Station.” 
28

Incorporating Environmental Costs in Electric Rates

continue operations to 2040.72 Figure 15 shows the options 

that were evaluated, showing additional measures required 

to continue operation further into the future.

The Boardman study itself did not consider 

alternative generation or non-generation options. 

The evaluation of Boardman was folded into 

PGE’s overall IRP update, however, which did 

consider alternatives to Boardman. The IRP 

analysis included CO2 costs in a range of $12 

to $65/ton. The IRP concluded that the value of 

Boardman was limited and that early termination 

actually carried a lower present value of revenue 

requirements for the utility consumers, as 

shown in Figure 16 from the PGE IRP.74 On 

the basis of its IRP analysis, PGE ultimately 

proposed termination of coal use at Boardman 

Existing Rules

DEQ Option 1

DEQ Option 2

DEQ Option 3

2011 NOx

NLNB/MOFA

NLNB/MOFA/SNCR

NLNB/MOFA/SNCR

NLNB/MOFA

2014 SO2

SD Scrubber

SD Scrubber

DSI

—

2017 NOx

SCR

—

—

—

Closure Date

2040+

2020

2018

5 years after SIP approval 

(2016?)

72 Portland General Electric Company, 2010. 

73 Portland General Electric Company, 2010. 

74 Portland General Electric Company, 2009. 

75 Oregon Public Utility Commission, 2010, 

pp. 7-17. IRP acknowledgment does not 

guarantee favorable ratemaking treatment; it 

means the plan seems reasonable at the time 

acknowledgment is given; see Oregon Public 

Utility Commission, 2007, pp. 2, 24-25. 

76 Black and Veatch, 2010. 

Figure 15 

Options Considered for Continuing Operation of Boardman Coal Plant 73

Abbreviations: BART, Best Available Retrofit Technology; DEQ, Department of Environmental Quality; DSI, Dry Sorbent Injection; 

NLNB/MOFA, New Low NOx Burners with Modified Overfire Air; NLNB/MOFA/SNCR, New Low NOx Burners with Modified Overfire

Air and Selective Non-Catalytic Reduction; SD, Semi-Dry; SCR, Selective Catalytic Reduction; SIP, State Implementation Plan.

2010-2040 Net Present Value of Revenue Requirement 

$ in Millions

35,500

35,250

35,000

34,750

34,500

34,250

34,000

33,750

33,500

33,250

Diversified 

Green with 

On-Peak 

Energy 

Target

Diversified 

Thermal 

with 

Green

Boardman 

through 

2014

Boardman 

through 

2011

Boardman 

through 

2017

Figure 16 

Costs Associated with Alternative Options for 

Continued Operation of Boardman Coal Plant 76

at the earliest date that the utility felt resulted in adequate 

reliability for its customers: 2020. The Oregon PUC 

acknowledged this approach in its order on PGE’s IRP.75

Portfolios
29

Working to Ensure Affordable Compliance with Public Health and Environmental Regulations

Colorado: Cherokee

Xcel Energy (Public Service Company of Colorado) 

decided to retire the Cherokee generating station, a fourunit coal plant located in the Denver Metropolitan area. 

The decision process, and economic logic, is an excellent 

example of a utility looking ahead and making a decision 

based on current and anticipated emission regulations and 

availability of alternative generation and energy efficiency 

resources.

The Cherokee units were built in 1957 to 1968. Retiring 

the two oldest and smallest units was a relatively easy 

decision, as they were comparatively uneconomical even 

before considering retrofit costs. Cherokee 3 and 4 had 

more promising economics, as they are newer and larger 

(151 MW and 351 MW, respectively). 

The Colorado Clean Air – Clean Jobs Act of 2010 

provided a roadmap for coal plant refurbishment and 

retirement.77

Under the directive of this Act, Xcel examined the 

retrofit costs for SCR for NOx control, Lime Spray Dryers 

for SO2 control, and ACI for mercury control. The total 

estimated retrofit costs were $762 million—about $1,500 

per kW. The estimated cost of a replacement combinedcycle generating unit was $900 to $1,200 per kW, but the 

expected fuel costs were higher.

The estimated savings of $148 million, present value, 

were clearly dependent upon the estimated future 

additional cost of carbon regulation for a coal plant, 

compared with a natural gas unit (see Figure 17). This 

included an assumption that Xcel would be allowed to 

Figure 17 

Xcel Energy’s Economic Analysis 

for Cherokee Plants 79

SCRs

Other Refurbishment

Replacement Capacity

Fuel

CO2 (Cherokee Excess)

Accelerated Depreciation

Total Cost

Savings from Retirement

Refurbish

$316

$446

$709

$264

$1,735

Retire

$246

$1,300

$41

$1,587

$148

recover the undepreciated remaining rate base in the 

Cherokee units.78

Xcel then examined an alternative in which more 

aggressive energy efficiency was used to delay (but not 

eliminate) the need for replacement capacity. In this 

scenario, a savings of $204 million was estimated.

Xcel made the decision to retire Cherokee, accelerate 

its energy efficiency program, and consider replacement 

capacity.80 The Colorado PUC approved the plan on 

December 9, 2010.

77 Colorado General Assembly, 2010. 

78 Wishart, 2011. 

79 Wishart, 2011.

80 See, e.g., Edison Electric Institute, 2011.
30

Incorporating Environmental Costs in Electric Rates

a. Planning-Stage Consideration 

of Renovation Costs

The Boswell 3 discussion earlier in this 

paper is an example of planning-stage 

consideration and preapproval of renovation 

costs. At the same time it considered approval 

of the expenditures for plant renovation, the 

Minnesota PUC approved the cost recovery 

mechanism for the costs and the rate design 

through which the costs would be recovered.

The Mohave and Boardman examples are instances 

of planning-stage consideration of renovation costs by 

regulatory bodies, but not the cost recovery mechanism or 

rate design. In the case of Mohave, no costs were incurred 

after the study for renovation, but the cost of replacement 

resources will be examined in appropriate regulatory 

proceedings. In the case of Boardman, some costs are being 

incurred for interim improvements, but the Oregon PUC 

has not yet approved the inclusion of these costs in rates. 

The Mohave and Boardman examples do not constitute 

instances of “preapproval” of expenditures. 

In the case of Mohave, the owner, SCE, originally 

requested an accounting order to defer preliminary retrofitrelated engineering costs. The California PUC ordered 

a complete analysis of SCE’s proposal. As a result of the 

analysis and SCE’s determination that proceeding with 

retrofit was not economical, SCE determined not to make 

the investment.81 In the case of Boardman, PGE examined 

alternatives and submitted its analysis to the Commission 

for review as part of an integrated resource planning 

process, ultimately agreeing to end coal combustion at 

Boardman by the year 2020. 

81 The California PUC is now faced with two related decisions: 

the treatment of the abandoned project costs and the 

disposition of allowance values for SO2 credits no longer 

needed by the utility.

Utility regulators must 

consider whether the cost 

of all utility investments, 

including pollution control 

measures, will be recoverable in rates 

from electric consumers. Depending 

on state policies, these reviews take 

place before, and in some cases after, 

the expenditures are made. In either 

case, however, the role of the regulator 

is always to determine if the utility’s 

course of action is prudent, considering cost-effectiveness, 

reliability and availability of alternatives. In some states, 

regulators are limited in their authority to allow cost 

recovery for abandoned projects, but in most states the law 

allows regulators flexibility to act with a broad definition of 

the “public interest.”

Prudence is a multi-faceted measurement, ultimately 

determining if the utility did the right thing under the 

circumstances, as they could reasonably be understood at 

the time. The need to consider carbon management costs is 

increasingly evident in the industry and in the marketplace. 

Here we discuss some of the methodologies used 

by regulators to make pre- and post-expenditure 

determinations of prudence, and provide several examples 

of regulatory disallowance of costs where the utility’s 

expenditure was determined inappropriate for recovery.

To date there have been few if any disallowances of 

pollution control equipment costs after they were incurred. 

The magnitude of these costs and the range of possible 

solutions, coupled with the uncertainty of future regulations, 

however, increases the likelihood of challenges in the 

future. In their role to regulate in the public interest, utility 

regulators must look beyond any frustration with federally 

imposed regulations to the fundamental question of what 

is the best path forward to meet local energy needs at the 

lowest total combined cost, including direct costs, indirect 

costs, and a reasonable assessment of prospective costs.

6. Cost Recovery For Refurbishment or Abandonment

The role of the regulator 

is always to determine 

if the utility’s course 

of action is prudent, 

considering costeffectiveness, reliability 

and availability of 

alternatives.
31

Working to Ensure Affordable Compliance with Public Health and Environmental Regulations

b. Evaluation-Stage Consideration of 

Renovation Costs

Many regulatory bodies will not consider preapproval 

of expenditures, instead reserving judgment until projects 

are completed and proposed for addition to the utility 

rate base in a general rate case or single-issue proceeding. 

Their logic is that it is the responsibility of management to 

make prudent decisions and to manage projects efficiently, 

whereas the role of the regulator is to pass judgment once 

management’s decisions are complete.

The costs associated with power plant renovation are 

so large that nearly all utilities will seek some sort of 

pre-determination of the acceptability of their project 

plans. Even when plans are “accepted” or “approved” 

by the Commission, however, there is still a need to 

review whether the ensuing expenditures were prudently 

managed.

The Kettle Falls generating station is a 60-MW woodwaste-fired plant in northeast Washington State owned by 

Avista Utilities (formerly The Washington Water Power 

Company). When it was originally constructed in 1983, 

the Washington and Idaho Commissions retained a 

consultant to review the cost-effectiveness of the project. 

Based on evidence presented at hearings, the Commissions 

concluded that the project was not cost-effective and 

found that the utility’s own studies showed that a natural 

gas power plant would have been less expensive from a 

lifecycle cost perspective. Both Commissions elected to 

exclude 10% of the investment from the utility’s rate base. 

That disallowance has continued throughout the operating 

life of the plant.82

In New York in the late 1970s, Niagara Mohawk was 

building the Nine Mile Point nuclear plant, and suffered 

(like the rest of the industry) severe cost overruns. The 

New York Commission established a maximum cost for 

Nine Mile Point of $4.2 billion, and required the utility 

sponsors to absorb any costs in excess of that amount. This 

led to significant losses for the utilities.83

In the era of the 1980s, when a combination of high 

construction costs for coal and nuclear power, sharp 

inflation, a soft economy, and significant excess generating 

capacity occurred, more than 100 regulatory disallowances 

were considered by U.S. regulatory commissions. It was 

in this era that many of the principles addressed below for 

evaluating prudence and ruling on allowable costs evolved.84

c. Stranded Cost Treatment of 

Abandoned Project Costs

“Stranded costs” are the undepreciated value in a power 

plant that ceases to be “used and useful” to serve consumers.85 A coal plant can cost over $1 billion to build and has 

an expected lifetime of about 40 years. The investment is 

recovered through depreciation expense over the life of the 

plant. In the case of a coal-fired power plant that is shut 

down because probable environmental compliance and 

operating costs exceed the value of the output, this can mean 

tens or even hundreds of millions of dollars of undepreciated 

investment remains on the books of the owners.

Typically coal plants that are facing a shutdown analysis 

today are older plants, and the original investment has 

been fully recovered or nearly so through depreciation 

expense included in electric rates. But every year that 

a plant operates, investments are made in renewals 

and replacements of components of a plant, and these 

investments are added to the “plant in service” balance 

upon which depreciation expense is calculated. These 

investments may also extend the plant’s original service 

life. There is typically a significant plant balance for any 

operating plant—and often exceeding the original plant 

investment that was long ago fully depreciated.

If a plant is permanently closed, accounting rules require 

that the investment be removed from the “Plant in Service” 

classification. At that point, the regulator must decide 

whether the utility or its consumers will bear the burden of 

the unamortized expense. In some states this is dictated by 

law, and in others it is left to the Commission to make an 

82 Washington Utilities and Transportation Commission, 1983.

83 Bang-Jensen, 1986. 

84 Lyon and Mayo, 2005. 

85 ‘Used and useful’ is a term for describing a utility asset. ‘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;” see Lazar, 2011, p. 38. 
32

Incorporating Environmental Costs in Electric Rates

equitable determination of cost responsibility. We consider 

several examples here.

The Trojan nuclear plant was a 1,100-MW power plant 

near Portland, Oregon, which entered service in 1975. 

After a comprehensive analysis of the plant’s economic 

viability, the primary owner, PGE, decided to close the 

plant in 1993 because the cost of needed retrofits exceeded 

the value of the project. The Oregon PUC initially allowed 

direct recovery of the undepreciated costs of the project. 

After a court rejected this, the Commission allowed an 

indirect offset to these costs, making the utility nearly 

whole for its remaining investment.

By contrast, when the state of California ordered its 

investor-owned utilities to divest themselves of their fossilfired power plants in 1998-99, stranded cost recovery 

was fully and explicitly allowed, through a stranded costs 

charge applicable to both utility customers and those 

who chose other energy supply companies. The price 

utilities were able to secure when the plants were sold was 

less than the remaining undepreciated book value. The 

anticipated benefits of utility restructuring were such that 

the Commission determined that utilities should not bear 

losses due to above-market costs of older generating units. 

The utilities were allowed to recover 100% of the difference 

through a surcharge to electric consumers. This was 

pretty typical in the states where divestiture or corporate 

separation took place.

The issue that will arise with large coal plants is quite 

significant. Assume, hypothetically, that an existing plant 

cost $1 billion to construct in 1985. Since that time, 

most of the original capital has been recovered through 

depreciation expense, but minor upgrades during the 

operating life, in the meantime, put the remaining book 

value at $400 million.

If the utility looks at the cost of measures for SO2, 

NOx, particulate, mercury and other air toxics, carbon 

combustion residuals, cooling water, and CO2 that will 

be required to extend the life of the plant for 20 years, 

the new costs may exceed the original cost of the unit. 

Depending on the alternatives available, the utility may 

reach the conclusion that alternatives to these retrofits are 

less expensive. They are then faced with retiring a project 

with a significant investment still on the books. Regulators 

will need to examine these costs, and determine if they are 

appropriate for rate recovery under the legal framework of 

the individual state.

d. Prudence, Used and Useful, Rate Base, 

and Amortization

The evaluation by regulators of the costs to be allowed 

into utility rates varies by state, but nearly all use some 

basic concepts that are common:

Prudence: A utility’s actions are considered prudent 

if they are reasonable and least-cost, given the facts and 

circumstances known or which reasonably should have 

been known at the time a decision is made. Simply because 

the decision to begin a project is prudent does not mean 

that the continuation or completion of the project is ipso 

facto prudent. A company must continually evaluate a 

project as it progresses to determine if the project continues 

to be prudent from both the perspective of need for the 

project and its impact on the company’s ratepayers.86

Used and Useful: In most states, investments by 

utilities can be allowed into rates only if the assets are 

“used and useful.” Although court interpretation of these 

terms has varied, in general “used” means that the facility 

is actually operated to provide service to consumers, and 

“useful” means that without the facility, either the cost of 

service would be greater, the quality of service would be 

worse, or both.

Rate Base: “Rate base” is a term used to describe the 

investments that utilities make in facilities that are included 

in rates. This consists of the original amount invested, 

any improvements made over time, less any depreciation 

expense collected during the time the asset has been in 

service. The recovery consists of a return of the investment 

(depreciation expense) and a return on the investment (rate 

of return). 

Amortization: In many cases in which full rate base 

treatment is denied, most often for an asset that either was 

not completed or that has ceased to be used, regulators 

allow amortization of the remaining investment. This 

means that the utility is allowed to recover the actual 

amount of undepreciated investment over a period of years, 

but no profit, or rate of return, during the amortization 

86 Most of this language was taken from Washington Utilities 

and Transportation Commission, 1984. 
33

Working to Ensure Affordable Compliance with Public Health and Environmental Regulations

period.

In evaluating whether, and how, 

to allow utilities to collect for the 

undepreciated investment in projects 

no longer in service, the regulator will 

need to consider all of these issues. In 

many states, where the regulator finds 

that the utilities’ actions are prudent, 

that the facility was used and useful for 

an extended period of time, but that 

it should be replaced with a newer, 

better resource, they have allowed full 

recovery of and on the undepreciated 

value. 

In some states, the regulator is limited to allowing 

only amortization of the undepreciated amount, without 

a return. This can create a perverse incentive in which 

the utility may be allowed to earn a return if it keeps 

an obsolete generating plant in service, but not if they 

prudently retire it. The authority of the regulator to 

encourage the right behavior will, to some extent, be 

limited by state law.

Several state regulators have found ways to compensate 

utilities for abandoned projects without using either 

traditional rate base treatment or traditional amortization. 

For example, Washington allowed a utility to transfer 

unused investment tax credits, which normally would 

have flowed to ratepayers over 30 years, to shareholders 

in a 3-year period, in exchange for the utility absorbing a 

portion of the investment in an abandoned nuclear plant.87 

e. Strategy for Commissions Faced with 

Coal Retrofit Costs

For any regulator faced with such a coal retrofit scenario, 

the first challenge is to ensure that the full picture of 

potential future costs is known before any incremental 

costs are authorized for rate recovery. If the facility is costeffective over its lifetime with the additional costs to be 

incurred, then it should be renovated, but only after the 

full review noted below. Because all of the requirements of 

the forthcoming EPA rulemakings are not yet known and 

the potential for additional regulations 

is always present, this challenge is not 

trivial.

Regulators can protect consumers 

by insisting that utilities seeking 

approval for compliance strategies 

prepare a comprehensive plant-specific 

and fleet-wide analysis of known and 

potential future costs, and present that 

to the regulator at the earliest point 

in time possible for review. Interested 

parties, including both supporters 

and skeptics of renovation, should be 

invited to comment on the analysis and 

participate in the evaluation. 

At a minimum, utilities should be required to examine 

these potential costs when actual compliance proposals are 

submitted. Ideally utilities will examine the potential costs 

through an integrated process, in which retrofit or other 

compliance costs can be compared with all generation and 

non-generation alternatives. 

The Mohave analysis is an excellent example of a 

unit-specific analysis undertaken prior to a commitment 

for major retrofit investments. The conclusion was that 

investments to extend the life of the plant were not 

justified. The Boardman analysis, discussed earlier, is 

an excellent example of an analysis undertaken in the 

context of an IRP for the utility. The conclusion was that 

minor retrofit costs to achieve a limited life-extension were 

justified, but major investments to achieve an extended lifeextension were not. The eventual prudence of the utility 

decisions for both of these will be subject to review in 

general rate cases. 

Regulators can insist on a checklist and cost estimate 

for all known retrofit requirements and strategies that may 

be imposed by the pending EPA rulemakings. They can 

insist on cost estimates of ranges of costs for compliance 

with potential CO2 regulation, knowing these are more 

uncertain. Ultimately, like most elements of utility 

regulation, there is a role for reasoned judgment on the part 

of the regulator.

87 Washington Utilities and Transportation Commission v. Puget Sound Energy, Cause U-86-131, 1987.

Regulators can protect 

consumers by insisting that 

utilities seeking approval 

for compliance strategies 

prepare a comprehensive 

plant-specific and fleetwide analysis of known and 

potential future costs, and 

present that to the regulator 

at the earliest point in time 

possible for review. 
34

Incorporating Environmental Costs in Electric Rates

f. Key Elements For An Integrated 

Resource Plan

One of the best ways to evaluate a prospective 

investment plan for renovation of a power plant is within 

a utility IRP. An IRP can consider a range of potential load 

scenarios, a range of potential economic scenarios, and 

a range of possible costs for both renovation of existing 

resources and acquisition of potential new resources. An 

IRP can compare the cost-effectiveness of demand-side 

measures with supply-side options. 

For an IRP to perform these tasks well, it needs to be 

quite sophisticated in design, in software, and in data. 

Many utilities and regulatory consultants have appropriate 

tools for this work, but they are time-consuming and 

relatively expensive. When hundreds of millions of dollars 

are at stake, this can easily be a good investment.

The following list is just an example of the critical 

elements that are necessary for an IRP to adequately 

measure the value of an existing resource requiring 

extensive retrofit with a portfolio of alternative resources:

•	 Existing load shape

•	 Existing resource mix

•	 Available supply-side resources

•	 Available demand-side resources

•	 Ability to model fuel cost uncertainty

•	 Ability to model emissions regulation uncertainty

•	 Ability to model load growth uncertainty

•	 Ability to model changes in transmission

interconnections

•	 Ability to value the benefit of short lead-time

resources

With a sophisticated model, an open public process to 

utilize the model, adequate time to get the benefit of the 

IRP process, and attention to detail, regulators can get a 

good sense of what is likely to be economical and what 

is likely to be uneconomical. The best models can do no 

more than provide a range of reasonable outcomes under 

uncertainty. In the end, however, judgment is an essential 

element of the process. 
35

Working to Ensure Affordable Compliance with Public Health and Environmental Regulations

Ultimately whatever costs are allowed by 

regulators into the utility’s revenue requirement 

are reflected in the rates paid by consumers. 

The customer will pay. But how? This section 

addresses the cost-causation basis of emission-related 

compliance costs and how these costs should be treated 

in retail rate design. In other words, the regulator must 

determine how to include in retail rates emissions control 

costs for plants that are renovated and the undepreciated 

costs for plants that are retired because it is uneconomical 

to renovate them.

Simply stated, although the investment costs for 

renovation are in part a function of the size of the plants, 

for rate design purposes emission costs 

are primarily associated with each kWh of 

energy produced by a generating plant, not 

with the plant’s availability to meet peak 

demand. 

Utilities have historically invested in 

emission control equipment for baseload 

power plants but have been hesitant to 

do so for intermittent or peaking units 

that are only used during the hours of 

the year when loads are at their highest 

levels. This is because the high capital cost of retrofits 

cannot be justified when a plant is seldom needed. As 

shown in Section 3, the renovation costs for a coal plant 

can easily exceed $1,000 per kW, whereas a modern lowemission peaker costs less than $1,000 per kW. The cost 

of a demand-response program to shave peak demand is 

typically much lower still. 

Simply stated, coal plant renovation costs would 

essentially never be cost-effective to meet peak demand. 

The economic benefit of coal plants is in their ability to 

produce baseload energy at favorable costs. 

Several principles should guide the inclusion of emission 

management costs in retail rates. 

7. Treatment in Rate Design

•	 Focus on Long-Run Marginal Costs: If we were 

building a new system with today’s rules, what would 

the costs be? 

•	 Coal Units are Baseload/Intermediate, Not Peaking:

For nearly all utilities, coal plants operate as baseload 

and intermediate generating units. 

•	 Retrofit Costs Can Only Be Justified If Spread Over

Many Hours: This is the only way that spending the 

huge sums needed for plant renovation can be justified.

Rate case advocates will take strong positions on these 

issues. Those classes with higher load 

factors (more uniform use of power 

throughout the day and year) will advocate 

that the emission retrofit costs be treated 

as capital cost additions to the plant 

investment and allocated on the basis of 

class contribution to peak demand. That 

has the effect of imposing the retrofit costs 

on peak-hour usage, while leaving the 

low fuel costs of these units as a benefit to 

off-peak usage, where their consumption 

is dominant. Conversely, advocates for residential and 

small commercial consumers will advocate that the costs be 

assigned to energy usage. 

Most of the emission control related costs are designed 

to clean up the energy production characteristics of the 

plant, and regulators should look to incorporate them into 

rates in a manner that is consistent with how the resources 

are used. 

a. Clear Focus on Long-Run Marginal Costs

One principle of economics is that efficient allocation of 

resources occurs if certain pre-conditions are met, one of 

which is that all goods are priced at their relevant long-run 

Ultimately whatever 

costs are allowed 

by regulators into 

the utility’s revenue 

requirement are 

reflected in the rates 

paid by consumers. 

The customer will pay. 
36

Incorporating Environmental Costs in Electric Rates

marginal costs. This is the price at which the market can 

produce more of the item being purchased and cover all of 

the investment and operating costs of doing so. 

This principle is particularly important for electricity, 

in which capital-intensiveness means that the capital costs 

of production can be 80% or more of the total cost. For a 

coal-fired power plant, for example, the investment-related 

costs can easily be twice as large a part of the total cost as 

the fuel cost. 

When evaluating whether to renovate an existing coal 

plant, a utility (perhaps in the context of an IRP) will 

compare the cost of the renovated coal plant to the likely 

costs of other alternatives—new supply-side resources like 

natural gas power plants, renewable energy resources, and 

market purchases (plus the associated transmission costs), 

and energy efficiency and demand response resources. The 

mix of capital and operating cost for all of these options is 

different, but what really matters is the total cost.

In the case of substituting a new combined-cycle natural 

gas unit for a coal unit, the investment required in the 

natural gas unit may be much lower than the investment 

needed to renovate the coal plant, but the fuel costs could 

likely be higher. The only relevant comparison is on a total 

incremental cost basis—what costs would the utility and 

its consumers incur under each option, including capital 

costs, operating costs, fuel costs, and emission costs. This 

is a long-run marginal cost basis. A societal cost test would 

also include the public health and other environmental 

costs that remain after implementation of the option being 

examined. The regulator should insist that the lowest-cost 

option be preferred. But the regulator may then be faced 

with the question of regulatory treatment of the stranded 

costs of a retired unit.

b. Reflecting Emissions Costs In Cost 

Allocation and Rate Design

The causal relationship between plant life extension 

costs and potential fuel cost savings is relevant in 

determining how renovation costs are reflected in the rate 

design, because no customer or customer class should 

receive a disproportionate share of the cost as a result 

of the decision made. If choosing the least-cost option 

would raise residential rates by $0.02/kWh, but choosing 

a more expensive option would only raise residential 

rates by $0.01/kWh (with higher costs shifted to business 

consumers), the residential class would prefer the more 

expensive option—an irrational outcome.

A problem with rate design arises if regulators treat 

investment costs differently than fuel costs in the rate 

design. If the capital costs of a coal-plant retrofit are treated 

as fixed costs, are classified as capacity-related, and are 

allocated on the basis of peak demand, a large share would 

be assigned to the residential and small business classes. 

Conversely, if instead the utility built a gas-fired peaking 

plant (at a lower capital cost), and all of the higher fuel 

costs were treated as variable costs, classified as energyrelated, and allocated on the basis of energy usage, a larger 

share would normally be assigned to the large commercial 

and industrial classes. 

Hourly cost allocation methods that assign all costs of 

all resources equally to the hours when they are used can 

avoid these imbalances. Methodologies such as the peakcredit or equivalent-peak methods, that assign to peak 

hours only the costs that would be incurred for a peaker 

(not baseload plant costs) can avoid these imbalances. As 

a practical matter, the cost allocation methodology should 

ensure that the least-cost solution for the total utility system 

is also the least-cost solution for each of the customer 

classes on the system. Some methods that allocate capital 

costs of baseload power plants based on class usage at 

peak hours have the effect of shifting costs associated with 

baseload generation to those customer classes with high 

on-peak operation, even though their peaking needs are 

typically met with lower-emission natural gas generating 

plants.

One solution to this is to use a long-run marginal cost 

allocation study to assign all costs on the system between 

customer classes. About one third of states already do this. 

Another is to examine only the incremental costs of various 

alternatives, but to allocate all of the incremental costs 

between classes on a per-kWh basis, so that the least-cost 

option affects all classes equally. The best method will vary 

from state to state, but the principle should be the same: 

cost allocation should not make any customer class better 

off if a higher total cost alternative is pursued.

Generally speaking, the emissions of power plants are 

in proportion to their generation in kWh. Logically, the 

cost of ameliorating those emissions should be paid for 

in proportion to the kWh usage. One easy way to ensure 

that all classes benefit from the least-cost solution to 

emissions reduction is to allocate the incremental cost of 
37

Working to Ensure Affordable Compliance with Public Health and Environmental Regulations

achieving that benefit on a kWh basis among all classes. 

This is a different approach than many commissions use for 

allocating the investment-related costs of existing baseload 

coal-fired power plants, but may be the only effective way 

to ensure that all customers benefit from the choice of the 

least-cost option. 

Method

Peak Responsibility

12 Monthly Peaks

Non-Coincident Peak

Average and Excess 

Demand

Loss of Load 

Probability

Base-IntermediatePeak

Peak Credit 

(also known as 

Equivalent Peaker)

Pure Energy

General Description

Class contribution to system coincident peak 

demand (1 hour, peak hours in peak months, or 

multi-hour).

Average of class contribution to system 

coincident peak hour(s) in each of 12 months.

Highest demand of each class at whatever hour 

that demand occurred.

Percent of costs equal to system load factor 

allocated between classes on average demand; 

additional costs allocated to class contribution 

to system coincident demand in excess of class 

average demand.

Those costs deemed related to peak demand 

assigned based on probability of insufficient 

capacity to meet load.

Fixed and variable costs of plants allocated to 

hours in which those plants operate, divided 

among classes based on class energy usage 

during those hours.

Percentage of baseload plant costs equal to the 

cost of a peaking unit allocated on basis of peak 

demand; remaining costs allocated on basis of 

energy usage.

All costs allocated on basis of energy usage.

Appropriate Application

Systems with very high load factors and 

all generating capacity having similar cost 

characteristics.

Systems with very high load factors, different 

classes peaking in different months, and 

all generating capacity having similar cost 

characteristics.

Systems with different clases peaking in different 

times, and all generating capacity having similar 

cost characteristics.

Systems with significant seasonal capacity 

constraints, including hydro or renewables.

Systems with mix of capital-intensive baseload 

plants, and less capital-intensive intermediate and 

peaking plants.

Systems with mix of capital-intensive baseload 

plants, and less capital-intensive intermediate and 

peaking plants, and in particular, systems with 

storage hydro capacity.

Systems with excess capacity.

88 Adapted from Lazar, 1992. 

Figure 18 shows some of the methods used to classify 

and allocate production costs among customer classes. 

They include methods that are most focused on the peak 

hours of the year, methods that focus on both peak demand 

and baseload energy, and an approach that ignores peak 

capacity requirements entirely.

Figure 18 

Methods of Allocating Production Costs Among Customer Classes88
38

Incorporating Environmental Costs in Electric Rates

c. Time-of-Use Element to 

Emissions

Another approach to fair allocation of plant 

emission compliance costs is to employ a timeof-use methodology and then flow those costs 

through into the retail rates based on the time 

when each class uses power. This is often referred 

to as the Base-Intermediate-Peak cost allocation 

methodology, in which the costs of baseload 

power are allocated to all hours equally, while the 

cost of peaking power plants are allocated only 

to the peak hours. This is used to ensure that all 

classes pay for the resources that serve them.

Because coal plants generally operate as 

baseload or intermediate units, this approach 

would assign the renovation costs to a broad 

number of hours, not to the peak capacity 

function. If the regulator does not generally 

use a long-run marginal cost approach for cost 

allocation, this is a good alternative.

This may seem counterintuitive that off-peak would be 

more expensive, because one principle of time-of-use pricing 

is to make the off-peak power less expensive to reduce pressure on the need to add capacity to meet higher peak loads. 

If the cost of lowering emissions, however, is a significant additional cost for a coal plant, mitigated in part by the higher 

fuel cost for a natural gas unit, then it is appropriate that the 

internalization of emission costs would narrow the percentage gap between on-peak and off-peak rates. 

In a dynamic pricing framework in which hourly prices 

are implemented or prices are higher during critical peak 

periods, a slightly different approach may be needed. First, 

a long-run marginal cost approach will still work well. 

During off-peak hours, the cost of building and operating 

a baseload plant (including emission and CO2 costs) 

is applicable. In the extreme peak hours, when system 

stability is at risk, the long-run marginal cost is either the 

cost of a peaking generator such as an internal combustion 

engine, or the cost of a demand-response program, 

whichever is lower. The dynamic price can gradually be 

raised until it triggers demand-response, or until it reaches 

the cost of building and operating a new peaker. 

Figure 19 shows on an illustrative basis how a uniform 

cents/kWh surcharge for emission compliance recovers 

Customer Charge

Demand Charge

On-Peak Energy 

Charge

Gas at the margin

Off-Peak Energy 

Charge

Coal at the margin

Ratio of On- Peak 

to Off-Peak

Before 

Emission 

Costs

$10.00

$10.00

$0.08

$0.05

160%

Emission 

Costs

$ –

$ –

$0.015

$0.03

$30/ton 

CO2

With 

Emission 

Costs

$10.00

$10.00

$0.10

$0.08

119%

$/Month

$/kW

$/kWh

$/kWh

%

emission costs from all units and reduces the relative 

percentage spread between on-peak and off-peak rates for 

a demand-metered commercial or industrial customer. It 

assumes that the marginal emission costs from coal are 

twice as great off-peak, consistent with Figure 11, showing 

that coal plant (off-peak) emissions are about two times 

those from natural gas (peaking) units.

The same logic may apply to some hot-region utilities 

with respect to seasonal rates. In the summer, the utility 

may draw on natural gas combustion turbines to meet 

incremental power needs, whereas in the winter it uses 

primarily baseload coal units. If the renovation costs are 

collected based on the marginal costs at the times when 

the coal-fired units and gas turbines are operated to serve 

incremental load, it will have the effect of causing larger 

increases in the off-season rates than the peak-season rates. 

Again, narrowing the gap between the rates is justified by 

the incremental costs of emission compliance. 

d. CO2 Costs

The discussion above has primarily been focused on the 

pollution control retrofit costs for existing power plants. 

If state, regional, or federal legislation results in a price for 

CO2 emissions, then regulators will need to address these 

Figure 19 

Illustrative Retail Rates With and Without 

$30/ton CO2 Costs for Gas and Coal
39

Working to Ensure Affordable Compliance with Public Health and Environmental Regulations

expenses in the ratemaking process.

 Where CO2 is subject to a price, utilities will need to 

either acquire allowances for those emissions, pay a tax for 

those emissions, or will be given free allowances that they 

can either use or sell. Figure 20 describes three different 

methods for CO2 regulation, and two alternatives that may 

be allowed to meet CO2 emission mandates, all of which 

will have implications for utility regulators.

In any of these approaches, there is a market value for 

CO2 emissions, and this value needs to be built into the 

price of electricity. Ideally every customer should see, at 

the margin, the marginal cost of CO2 emissions, whether it 

is a tax, a free allowance that can be sold, or a purchased 

allowance that can be avoided. 

There are several important elements here. 

Method

Carbon 

Tax

Cap and 

Trade

Cap and 

Auction

Offsets

Sequestration

General Description

Government sells rights to emit CO2

at a defined price. All emitters must 

purchase rights.

Government gives free allowances to 

historical emitters, declining in number 

over time. They can trade among 

themselves.

Government auctions allowances to 

emitters (and perhaps others), declining 

in number over time. Purchasers can 

trade among themselves.

Utility purchases carbon offesets from 

forestry or other carbon-offsetting 

activities to meet all or a portion of the 

allowance requirement under a carbon 

tax or carbon cap framework.

Utility installs equipment on a fossil 

generator to capture CO2 before it is 

emitted, and store it in a geological 

formation or chemical form.

Example

British Columbia, 

Canada

California Air 

Resources Board 

implementation 

of AB32 beginning 

in 2013

Regional Greenhouse 

Gas Initiative 

(New England)

Permitted in the 

California Cap and 

Trade System up to 

4% of total compliance

obligation

Experimental 

technology under 

development at 

several locations

Ratemaking Elements

The cost of the carbon tax becomes an element 

of utility expense, either directly for power the 

utility generates, or embedded in purchased power 

expense. Commission must determine if a leastcost path was followed.

The revenues from sales of excess allowances, 

and the purchase costs for needed allowances 

are elements of utility expense. Allowance costs 

will be embedded in purchased power prices. 

Commission must determine if a least-cost path 

was followed.

The cost of the allowances becomes an element 

of utility expense, either directly for power the 

utility generates, or embedded in purchased power 

expense. Commission must determine if a leastcost path was followed.

The cost of the offsets becomes an element of 

utility expense, either directly for power the utility 

generates, or embedded in purchased power 

expense. Commission must determine if a leastcost path was followed.

The cost of the sequestration equipment becomes 

an element of rate base and operating expense for 

the utility. Commission must determine if a leastcost path was followed.

Figure 20 

Alternative Forms of CO2 Regulation

First, if the utility receives some of its needed allowances 

for free, it is still important to reflect the marginal cost of 

incremental allowances in the marginal price for electricity. 

This marginal price is equally relevant if the utility receives 

surplus allowances, if it is allowed to sell the surplus in 

a competitive market. An inverted block rate design or 

rolling baseline rate design with the CO2 allowance costs 

reflected only in the incremental block rate may be the 

best way to do this, so that customers see the full long-run 

marginal cost for incremental usage.

Another issue is that the costs of CO2 emissions from 

coal plants should generally be assigned to the hours when 

the coal unit is used. If the utility has time-of-use rates, 
40

Incorporating Environmental Costs in Electric Rates

these costs should be more predominant in the rate design 

during the off-peak hours, when coal is likely the dominant 

fuel (and may be the marginal fuel). The on-peak hours are 

more likely to be served at least in part with lower-emission 

power from natural gas units (with higher fuel costs that 

are already reflected in on-peak charges). Although both 

on-peak and off-peak costs increase as a result, the effect of 

this is to slightly mute the relative on-peak/off-peak price 

signals that guide consumption and demand-response 

efforts, consistent with the focus on long-run marginal costs 

(including environmental costs) that is the thesis of this 

section.

A third issue is that utilities are adding carbon-free 

resources, including renewable energy and (in a few cases) 

planned new nuclear units. It is unlikely that these carbonfree resources will be the marginal (dispatchable) resource 

for more than a few hours per year; rate design should 

continue to focus on the long-run marginal cost of leastcost resources. In a future scenario, this might be nuclear 

units for baseload, wind on an as-available basis backed by 

pumped storage hydro, and solar during peaking periods; 

the costs might be very different from today’s costs, but 

the principle is unchanged: replacement costs for new 

resources, including appropriate environmental costs, 

should form the basis of retail rates.

A long-run marginal cost approach to rate design 

(independent of whether marginal costs are the basis of cost 

allocation between classes) can work well for this. During 

off-peak hours, incremental generation may come from coal 

units, and the CO2 costs associated with coal would be the 

marginal cost in those hours. During on-peak hours, while 

the coal plants are still running, the marginal generation 

more likely comes from natural gas units with higher fuel 

costs but lower CO2 costs and the long-run marginal cost 

would be based on that of a gas-fired unit. The effect of 

tracking these marginal costs will be to increase prices at 

all hours, but it likely will moderate the difference between 

on-peak and off-peak prices, because the emissions are 

generally lower for the marginal (gas-fired) units dispatched 

to meet incremental loads at the time of system peaks.89

The same principle should apply to utility integrated 

resource planning efforts, whether they are distribution 

utilities with default service obligations or fully integrated 

utilities. The IRP needs to continuously look at existing 

and new resource options, on a full-cost basis, with 

environmental costs incorporated. The estimates for future 

environmental costs will inevitably be imprecise—but zero

is clearly the wrong figure to assume for future CO2 costs 

and for future costs for other emissions, given the panoply 

of environmental and public health issues implicated by 

power system operations.

89 An offsetting factor to this in rate design is that most current rate designs do not fully reflect marginal line losses or marginal 

generation reserves costs during on-peak periods. These marginal losses can be as high as 30% during critical peak periods. See 

Lazar and Baldwin, August 2011.
41

Working to Ensure Affordable Compliance with Public Health and Environmental Regulations

of each state. The goal of the regulator 

should be to make the utility that does the 

prudent thing better off than the utility 

that chooses the option that carries higher 

total costs to society. 

Looking ahead, regulators need to 

insist that utilities regularly evaluate their 

future resource plans and fully incorporate 

best estimates of future environmental, 

public health, and safety regulations. IRPs, 

long-term power contracts, transmission 

expansion, renewable resource 

development, and energy efficiency investments will all 

be affected by assumptions as to future environmental 

regulations. To fail to consider the likely, probable, and 

potential costs is to hide from the future. 

The significant number of EPA rulemakings underway 

addressing many different aspects of power plant 

operations and emissions makes this a difficult time for 

state utility regulators. They must look ahead 20 to 30 years 

to make reasoned decisions. This requires a thoughtful 

process for ensuring that utilities study all their reasonable 

options before committing to the first step of investment in 

plant rehabilitation and upgrade that ratepayers will have 

to pay. 

Otherwise there is the risk that today’s older coal plants 

could become the power sector equivalent of a fullyrestored $500,000 Edsel of tomorrow. Interesting, perhaps, 

but not a good choice for everybody. 

There are existing coal-fired 

power plants that will become 

uneconomical as a result of a 

series of updated environmental 

regulations, including the prospect of 

carbon regulation. Some of these may have 

been already rendered uneconomical on a 

running-cost basis due to low natural gas 

prices, improved technology for renewable 

resources and energy efficiency, and the 

cost of routine maintenance and upkeep of 

the coal units, many of which are old. All 

these forces and trends together will put further pressure 

on the role of coal in a least-cost supply portfolio. 

The role of the regulator is to ensure that utilities have 

a framework in which to operate that is predictable, 

sensible, and provides for reliable electric service at least 

cost. The regulator must ensure that money is not wasted 

on uneconomical units, but also, if utilities do invest 

prudently, that they are able to recover their costs and get 

a fair return on their investments. This includes both the 

incremental costs to meet emission requirements on a leastcost basis, and fair treatment of the costs of generating units 

that are retired after providing economical service.

For plants that are not fully depreciated but are retired 

due to the high cost of emission management, regulators 

will need to decide whether to allow recovery of these costs 

in rates. This decision should be guided by traditional 

regulatory principles of prudence and the legal framework 

8. Conclusions

The role of the 

regulator is to ensure 

that utilities have a 

framework in which 

to operate that is 

predictable, sensible, 

and provides for 

reliable electric service 

at least cost. 
42

Incorporating Environmental Costs in Electric Rates

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Presentation.pdf 
46

Incorporating Environmental Costs in Electric Rates

ACI Activated Carbon Injection

BART Best Available Retrofit Technology

CAA Clean Air Act

CO2 Carbon Dioxide

CO2e Carbon Dioxide Equivalent

CCR Coal Combustion Residuals

CCS Carbon Capture and Storage

CPCN Certificates of Public Convenience and Necessity

CPUC California Public Utilities Commission

CSAPR Cross-State Air Pollution Rule

DOE US Department of Energy

DSI Dry Sorbent Injection

EPA US Environmental Protection Agency

ETS Emissions Trading Scheme

FGD Flue Gas Desulfurization

FIP Federal Implementation Plan (see SIP)

GHG Greenhouse Gas

Hg Mercury

IRP Integrated Resource Plan

kW Kilowatt

MACS Mohave Alternatives and Complements Study

MW Megawatt

Appendix 1: 

Acronym Glossary

NOx Nitrogen Oxide

NAAQS National Ambient Air Quality Standards

NERC North American Electric Reliability Corporation

NLNB/MOFA New Low NOx Burners with Modified 

Overfire Air

NLNB/MOFA/SNCR New Low NOx Burners with 

Modified Overfire Air and Selective Non-Catalytic 

Reduction

NSPS New Source Performance Standards

NPDES National Pollutant Discharge Elimination System

O&M Operation and Management

OCC Oklahoma Corporation Commission

PGE Portland General Electric

PM Particulate Matter

PSD Prevention of Significant Deterioration

RCRA Resource Conservation and Recovery Act

SCE Southern California Edison

SCR Selective Catalytic Reduction

SIP State Implementation Plan

SNCR Selective Non-Catalytic Reduction

SO2 Sulfur Dioxide

VOC Volatile Organic Compound

ZLD Zero Liquid Discharge
47

Working to Ensure Affordable Compliance with Public Health and Environmental Regulations

The Cross-State Air Pollution Rule

Under the Clean Air Act (CAA), National 

Ambient Air Quality Standards or 

“NAAQS” define the maximum permissible 

concentrations in the air for certain pollutants, 

known as “criteria pollutants.” NAAQS have been set for 

carbon monoxide, particulate matter, sulfur oxides, oxides 

of nitrogen, lead, and ozone.90

Based on air monitoring data, the EPA determines 

whether areas in states meet or do not meet these 

standards. On this basis, the EPA designates areas as being 

in “attainment” or “non-attainment” of the NAAQS. States 

are required to submit federally enforceable plans, known 

as state implementation plans or “SIPs,” to demonstrate 

that they have in place air programs that will ensure the 

state’s continued attainment with NAAQS, or—if in nonattainment—how the state will come into attainment by 

specific deadlines. Under certain circumstances, the EPA 

rather than states will promulgate a Federal Implementation 

Plan or “FIP” for the state.

In the Cross-State Air Pollution Rule (CSAPR), the 

Appendix 2

EPA Rulemakings Affecting Power Plant Operations

EPA seeks to “limit the interstate transport of emissions 

of nitrogen oxides (NOx) and sulfur dioxide (SO2) that 

contribute to harmful levels of fine particle matter (PM2.5) 

and ozone91 in downwind states.”92 These emissions 

are carried downwind as SO2 and NOx or, after being 

transformed in the atmosphere, as fine particles or ozone. 

By reducing emissions in upwind states, air quality in 

downwind states is improved, thereby helping downwind 

states meet NAAQS.93

Section 110(a)(2)(D)(i)(I) of the CAA requires states 

to prohibit emissions that “contribute significantly to 

nonattainment in, or interfere with maintenance by, any 

other State with respect to any such national ... ambient air 

quality standard....”94 The EPA has found that emissions 

of SO2 and NOx in 27 eastern, midwestern, and southern 

states (including the District of Columbia) violate this 

“significant contribution” standard with regard to at least 

one of the following air quality standards: the annual PM2.5 

(fine particulates) NAAQS (developed in 1997), the 24-hour 

PM2.5 NAAQS (2006), and/or the ozone NAAQS (1997).95

The rule also sets out a process for determining each upwind 

state’s responsibility to protect downwind air quality (i.e., the 

90 Code of Federal Regulations, Title 40, Part 50.

91 Ground-level ozone is a pollutant created through the interaction of NOx, volatile organic compounds or “VOCs,” and sunlight.

92 Code of Federal Regulations, Title 40, Parts 51, 52, 72, 78, and 97. These states include Alabama, Arkansas, Florida, Georgia, 

Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana, Maryland, Michigan, Minnesota, Mississippi, Missouri, Nebraska, New Jersey, 

New York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Texas, Virginia, West Virginia, and Wisconsin. The 

EPA will address these emissions through Federal Implementation Plans.

93 The rule defines the obligations of upwind states to reduce pollution “significantly contributing to downwind nonattainment 

and maintenance areas” depending on the magnitude of a state’s contribution; cost of controlling pollution from various sources; 

and air quality impacts of reductions; see U.S. Environmental Protection Agency, “Cross-State Air Pollution Rule: Reducing Air 

Pollution, Protecting Public Health.” 

94 U.S. Code, Title 42, § 7410(a)(2)(D)(i)(I), § 110(a)(2)(D)(i)(I).

95 The EPA has also proposed to extend the rule’s ozone-related NOx reductions to six additional states. See Figure ___ for a list of 

states covered by the final rule and the emissions they will need to control, including the six states proposed in the supplemental 

notice of proposed rulemaking to be included for ozone season NOx emission reductions; see U.S. Environmental Protection 

Agency, “Fact Sheet: The Cross-State Air Pollution Rule,” p. 5.
48

Incorporating Environmental Costs in Electric Rates

amount of emissions reductions that state must make).

Emissions control technology for NOx includes Selective 

Catalytic Reduction (SCR) and Selective Non-Catalytic 

Reduction (SNCR). The typical controls for SO2 are flue gas 

desulfurization (FGD) and dry sorbent injection (DSI).96

The rule also provides for an alternative compliance 

route by creating several intra- and interstate SO2 and NOx 

trading programs:

•	 Annual SO2 Group 1 Sources (i.e., those that need to 

make larger reductions);

•	 Annual SO2 Group 2 Sources (i.e., those that need to 

make smaller reductions);

•	 Annual NOx emissions; and

•	 Ozone-season NOx. 

Trading is allowed among emissions sources in the same 

program (e.g., ozone season NOx). For 2012 compliance, 

the EPA will allocate emissions allowances to affected 

facilities; states can develop their own allocation schemes 

by 2014.

Phase 1 compliance begins January 1, 2012 for annual 

SO2 and NOx reductions and May 1, 2012 for ozoneseason NOx reductions. More stringent SO2 reductions 

begin January 1, 2014 for “Group 1” states (Illinois, 

Indiana, Iowa, Kentucky, Maryland, Michigan, Missouri, 

New Jersey, New York, North Carolina, Ohio, Pennsylvania, 

Tennessee, Virginia, West Virginia, and Wisconsin).

Mercury/Air Toxics Rule

The 1990 CAA amendments require the EPA to develop 

an emissions control program for certain listed toxic air 

pollutants. Power plants are responsible for half of the 

nation’s mercury emissions and half of the acid gases. The 

EPA estimates that there are approximately 1,350 coal- and 

oil-fired units at 525 power plants that will be subject to 

this rule. On March 16, 2011 the EPA proposed the first 

national standard to reduce mercury and other toxic air 

pollution from coal- and oil-fired power plants, the “National 

Emissions Standards for Hazardous Pollutants,” commonly 

referred to as the “Mercury/Air Toxics Rule.”97 This rule 

regulates emissions of mercury, arsenic, other toxic metals, 

acid gases, and organic air toxics such as dioxin. 

The legal standard for toxic emissions from existing 

sources states that Maximum Achievable Control Technology 

(MACT) “shall not be less stringent, and may be more 

stringent than the average emission limitation achieved by 

the best performing 12% of the existing sources...in the 

category or subcategory...” This calculation is referred to as 

the “MACT floor” and does not take cost into account but 

does reflect what existing and deployed technology can do. 

The EPA can require what are referred to as “beyond-thefloor” reductions if cost-effective technologies are available. 

Section 112 states that “new” source controls “shall not be 

less stringent than the emission control that is achieved in 

practice by the best controlled similar source, as determined 

by the Administrator.” 

The proposed Mercury/Air Toxics Rule contains significant 

flexibility provisions, including facility-wide and monthly 

emissions averaging, the use of surrogate pollutants, and 

fuel-switching to coals with lower mercury or chlorine 

content. Un-scrubbed units will need to install “electrostatic 

precipitators” or fabric filters for particulates or make use of 

alternative sorbents such as activated carbon or halogen additions for mercury and DSI (e.g., Trona, Sodium Bicarbonate, or Hydrated Lime, i.e., dry-scrubber technologies) for 

strong acids (hydrochloric and hydrofluoric).

The schedule for compliance under the Mercury/Air 

Toxics Rule varies for existing and new sources. Existing 

sources are required to meet standards within 3 years from 

the date of the final rule, with the opportunity for a 1-year 

extension. Compliance for new and reconstructed sources 

will be required going forward on issuance of the final rule.

Regulation of GHGs

The EPA’s plans to regulate CO2 and other GHGs are 

based on several administrative actions and rules, including 

the GHG Reporting Rule, the Tailoring Rule, permitting, 

and New Source Performance Standards.98 These are briefly 

described here.

96 For a discussion of compliance technologies, see, e.g., Foerter, 

2010. 

97 U.S. Environmental Protection Agency, March 16, 2011.

98 For a more complete discussion of the EPA’s GHG Reporting 

Rule, Endangerment Finding/Light Duty Vehicle Rule, 

Johnson Memorandum Reconsideration, Tailoring Rule, and 

New Source Performance Standards, see Farnsworth, 2011, 

pp. 11-14.
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Working to Ensure Affordable Compliance with Public Health and Environmental Regulations

Reporting

In October 2009, the EPA proposed a GHG Reporting 

Rule that requires nearly all facilities that emit 25,000 

metric tons or more per year of CO2 equivalent (CO2e)99 

emissions to monitor their GHG emissions and submit 

detailed annual reports to the EPA starting in 2011. The 

Final Rule was issued in October 2010, and March 2011 

was the first reporting deadline.100

The Tailoring Rule 

The Tailoring Rule, proposed by the EPA in October 

2009, applies GHG regulations to major sources.101 The EPA 

proposed this rule because it recognized that the existing 

thresholds in its air permit programs were not realistic for 

GHGs. Existing thresholds for air pollutants were far too low 

(e.g., 50-100 tons per year) to apply to GHGs, which are 

emitted in greater amounts. The EPA thus chose to “tailor” its 

GHG thresholds to avoid capturing numerous small sources 

under federal GHG permitting programs. 

Permitting

Power plants are subject to air quality permit 

requirements and regulations for GHGs will be implemented 

in several phases. In January, the EPA issued phase one of its 

GHG permitting rule and followed with a second phase in 

July. The first phase requires new and modified sources that 

already needed an EPA “major source” air permit (and which 

emit at least 75,000 tons per year of GHGs) to include in that 

permit a limit on GHG emissions. Under Phase II, a source 

that emits over a threshold of 100,000 tons per year, whether 

or not the source already requires EPA permits for any other 

pollutant (or whose major modification results in greater 

than 75,000 tons per year) must acquire a permit. 

Preconstruction or “PSD” Permits

The CAA requires a company planning to build a new 

power plant or perform major modifications on an existing 

plant to get a preconstruction permit under the Prevention 

of Significant Deterioration (PSD) program. The purpose of 

the PSD program is to prevent new sources of pollution from 

degrading air quality. The CAA requires a PSD permit for a 

facility being planned for an area in attainment for NAAQS 

or if the facility is going to emit a pollutant for which no air 

quality standards have been created, which is the case with 

GHGs. Facilities subject to PSD permitting requirements 

must conduct Best Available Control Technology (BACT) 

reviews to determine what type of GHG control technology 

they will have to install to meet GHG permit limits.

Title V or “Operating” Permits

After July 1, 2011, sources that emit over 100,000 tons 

per year of GHG will need an operating permit. These 

permits are typically issued once a source has begun 

operation and typically do not include additional control 

requirements. Title V operating permits, issued by state or 

local permit authorities, are intended to be comprehensive 

and bring together all state and federal emissions control 

requirements in one document.

New Source Performance Standards

The CAA requires the EPA to establish categories of 

major polluters and to develop performance standards for 

new or modified sources in each category.102 In December 

2010, the EPA entered into a settlement in which it agreed 

to develop NSPS for new and modified electric generators 

and emission guidelines for existing electric generators by 

July 26, 2011 and final regulations by May 26, 2012.103

Under Section 111(b), the EPA sets emissions limitations 

on new and modified sources within each source category 

that it has completed (e.g., Stationary Gas Turbines). The 

EPA is required to take “into account the cost of achieving 

such reduction and any non-air quality health and 

environmental impact and energy requirements...” as the 

EPA determines.104

With regard to existing sources, Section 111(d) requires 

the EPA to issue “guidelines” to the states that they must 

follow in preparing state plans to meet the standards 

for existing categories. Under Section 111(d), states are 

required to submit a plan to impose NSPS requirements on 

all existing sources in the state. Guidelines contain targets 

99 CO2e is a measure of the global warming potential of all 

GHGs.

100 Federal Register, October 28, 2010.

101 Federal Register, 2009.

102 Pearson and Monast, 2011, p. 2. 

103 U.S. Environmental Protection Agency, “Settlement 

Agreements to Address Greenhouse Gas Emissions from 

Electric Generating Units and Refineries Fact Sheet.”

104 U.S. Code, Title 42, § 7411(a)(1), § 111(a)(1).
50

Incorporating Environmental Costs in Electric Rates

based on demonstrated controls, emissions reductions, 

costs, and installation and compliance timeframes. 

Standards for existing sources can be less stringent than 

standards for new or modified sources. States have 9 

months after the publication of guidelines to submit plans 

for EPA approval.

Although the EPA is expected to issue performance 

standards for GHGs soon, it is not clear what form these 

standards may take. According to several commentators, 

the EPA should have a significant degree of flexibility in 

setting NSPS for GHGs:105

Given agency discretion to define uncertain statutory terms 

like “best system of emission reduction,” and given the 

potential of compliance flexibility mechanisms to reduce costs 

while preserving total emissions reduction goals, EPA and the 

states should be able to fit a variety of flexible approaches 

into the statutory criteria for performance standards.106

If the EPA is able to grant compliance flexibility to states, 

this could allow for such approaches as allowance trading 

and other related, market-based compliance approaches.

Water and Solid Waste Regulations

In addition to being subject to various air regulations, 

electric generators will be affected by the outcome of other 

rulemakings under the Clean Water Act and the Resource 

Conservation and Recovery Act.

Cooling Water Rule (316(b)) 107

The proposed 316(b) rule will establish requirements 

for all “existing” power generating facilities and existing 

manufacturing and industrial facilities that (a) withdraw 

more than 2 million gallons per day of water from waters 

of the United States, and (b) use at least 25% of the water 

they withdraw exclusively for cooling purposes. The EPA 

estimates that 670 of these facilities are power plants, 

including both coal- and natural gas-fired units. 

The proposed national requirements, which would 

be implemented through National Pollutant Discharge 

Elimination System (NPDES) permits, would establish 

national requirements applicable to the location, design, 

construction, and capacity of cooling water intake 

structures at these facilities by setting requirements that 

reflect the Best Technology Available (BTA) for minimizing 

adverse environmental impact. 

The purpose of the rule is to “minimize adverse 

environmental impacts, including substantially reducing 

the harmful effects of impingement and entrainment.”108

Fish and smaller organisms die because they are either 

unable to swim away from water intakes and are 

“impinged” against the screen or pass through screens and 

become “entrained” in the cooling system. The 316(b) rule 

would set performance standards for fish mortality caused 

by impingement and would establish a requirement that 

entrainment standards be developed by facilities on a caseby-case basis.

New Facilities

The proposed rule would require new units constructed 

at an existing facility to comply with provisions for 

impingement and entrainment mortality based on a closedcycle system. These standards are similar to standards set 

out for new facilities. This can be accomplished by either 

including a closed cycle system or by making any other 

105 See, for example Wannier et al, 2011, and Litz et al, 2011. 

106 Wannier et al, 2011, p. 1.

107 Hewitt, 2010. The EPA is also developing a “Steam Electric Effluent Limitations Guideline” that focuses on the steam electric 

subcategory of all electric generating activities, including fossil-fueled (coal, oil, gas) power plants. A major focus of the Effluent 

Rule is on toxic pollutants released into wastewater and ash ponds as part of the flue gas desulfurization process. According to 

the EPA, the schedule for the development of an effluent rule requires the EPA to collect technical and financial information for 

analysis, an effort that is underway. No rule has been proposed yet. The EPA intends to issue proposed regulation in mid-2012 

and a final rule in late 2013. The Rule will have an effective date 60 days after publication. Dischargers are likely to be required 

to apply for NPDES permits. Compliance with a rule is expected to start 3 to 5 years after the final rule, 2016 to 2018.

108 U.S. Environmental Protection Agency, March 28, 2011. 
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Working to Ensure Affordable Compliance with Public Health and Environmental Regulations

changes that would result in impingement and entrainment 

reduction equivalent to the reductions associated with 

closed-cycle cooling.109

Coal Combustion Residuals 110

The EPA proposed a rule on Coal Combustion Residuals 

(CCRs) from electric utilities in June 2010 but has not 

set a date for a final rule.111 CCRs are byproducts from 

the combustion of coal that include fly ash, bottom ash, 

boiler slag, and FGD materials. In 2008, over 136 million 

tons of CCRs were produced in the United States. This 

waste is currently disposed of in various ways. It is placed 

in approximately 300 CCR landfills and in 584 surface 

impoundments at approximately 495 coal-fired power 

plants across the nation. It is also placed in mines or is 

“beneficially” used (e.g., in building materials).112

Applying its solid waste authority under the federal 

Resource Conservation and Recovery Act (RCRA), the EPA 

has proposed two alternative approaches for regulating 

the disposal of CCRs produced by electric utilities and 

109 U.S. Environmental Protection Agency, March 2011. 

110 Discussion of the EPA’s proposed Coal Combustion Residual Rule based, in part, upon presentation by Devlin, 2010. 

111 Federal Register, June 21, 2010. In its May 2010 pre-published version of the proposed rule, the EPA indicated that it “has 

not projected a date for a final rule at this time.” Discussion of the EPA’s proposed Coal Combustion Residual Rule based on 

presentation by Devlin, 2010. 

112 According to the EPA, “[b]eneficial use refers to use of material that provides a functional benefit—that is, where the use replaces 

the use of an alternative material or conserves natural resources that would otherwise be obtained through extraction or other 

processes to obtain virgin materials;” see U.S. Environmental Protection Agency, “Frequent Questions: Coal Combustion Residues 

- Proposed Rule,” 2011.

113 RCRA is divided into subtitles. Subtitles C and D set out the framework for the EPA’s solid waste management program. Subtitle 

C establishes the framework for managing “hazardous” waste (from generation to its disposal), whereas Subtitle D sets out a 

system for managing primarily “non-hazardous” waste.

independent power producers. The first and more stringent 

approach, designated “Subtitle C,” would treat CCRs like 

hazardous waste.113 For example, under this approach, 

parties who create, transport, or store CCRs would be 

subject to various requirements including permitting, 

ground water monitoring, and financial assurance. 

Existing landfills would be required to install groundwater 

monitoring within one year of the effective date of the rule. 

If monitoring were to show groundwater contamination, 

remedial action would be required. New or expanded 

landfills would be required to install composite liners 

and groundwater monitoring before the landfill begins 

operation.

Under the less stringent “Subtitle D” approach, CCRs 

would continue to be classified by the EPA as a “nonhazardous” waste. Facilities would be subject to national 

minimum criteria governing CCR disposal. Subtitle D 

engineering requirements (e.g., liners and groundwater 

monitoring) would be similar to Subtitle C. Under either 

proposal, an exemption from regulation would remain in 

place for “beneficial uses” of CCRs.
52

Incorporating Environmental Costs in Electric Rates

114 Adapted from Sierra Club, July 11, 2011. 

Potential Flexibility in the EPA’s Air Regulations

In each of the air regulations described here there 

exists opportunities for flexibility in meeting compliance 

requirements. Under the CSAPR, the adoption of cap-andtrade, a market-based compliance mechanism, will allow 

emitters to trade allowances to meet compliance obligations 

in a least-cost manner. 

The Mercury/Air Toxics Rule contains a number of 

significant flexibility provisions. First, it allows for facilitywide averaging for all emissions of hazardous air pollution 

from existing units within the same subcategory, thereby 

providing environmentally equivalent but less costly ways 

of achieving emissions standards. Second, the proposed 

rule would allow for averaging of facility emissions 

Figure 21 

Implementation Timeline for EPA Regulations114

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

AIR

Cross-State Air 

Pollution Rule

Cross State Air 

Pollution II

Mercury/

Air Toxics Rule

New Source 

Performance 

Standards for GHG

GHG 

Permitting

WATER

Cooling Water Rule 

316(b)

WASTE

Coal Combustion 

Residuals

Phase 1 Phase 2 Caps

Pending Revised NAAQS

5-Year Phase-in, Pending Rule

Pending Final Rule

Existing Units: Pending EPA/State Rulemakings

National Emission Standards

ss

s

s

s

s

s

PSD & Title V s

New Units s

to accommodate generators’ operational variability. 

Averaging would be allowed over a 30-day period. Third, 

the proposed Mercury/Air Toxics Rule also provides for 

flexibility and less costly compliance demonstration 

methods through the use of “surrogates” (i.e., the control 

of one pollutant as a proxy for others). This would allow 

an emitter to demonstrate control over the emission of one 

pollutant that typically accompanies another pollutant by 

simply demonstrating control of the first pollutant. For 

example, there are emissions limits for particulate matter as 

a surrogate for non-mercury metals. 

With regard to GHG regulation, by focusing first on 

large emitters of GHGs, the central effect of the EPA’s 

Tailoring Rule focuses on fewer larger sources of GHGs. 
53

Working to Ensure Affordable Compliance with Public Health and Environmental Regulations

115 U.S. Environmental Protection Agency, March 28, 2011.

Permitting requirements direct application of the rule to 

sources already subject to the standard and then only to 

larger sources first. The BACT standard applied in PSD 

permits also takes into account “energy, environmental and 

economic impacts and other costs.” As rulemakings go 

forward, stakeholders will have the opportunity to provide 

the EPA with input as to cost-effectiveness. With regard to 

New Source Performance Standards, although no guidance 

has been issued by the EPA, the analysis under CAA Section 

111 for setting NSPSs allows for the consideration of cost, 

non-air quality health and environmental benefits, and 

energy requirements. The standard also emphasizes the 

“best system” of emissions reduction and avoids imposing 

specific technology standards.

Potential Flexibility in the EPA’s Water 

Regulations

There is potential for flexibility in meeting compliance 

requirements of the 316(b) cooling water rule. For 

example, the 316(b) rule provides existing sources 

with choices of how to comply with BTA standards for 

impingement. For addressing entrainment mortality, 

the rule provides for facilities to study and develop 

information as part of the permit application process and 

then establishes a process by which the BTA for that facility 

would be determined. Existing sources have 8 years to 

install screens or nets or to reduce cooling water intake 

velocity. Existing fossil and nuclear units that are required 

to build cooling towers have, respectively, 10 and 15 years 

to do so. For new facilities or modifications of existing 

facilities, the EPA allows generators to build a closed-cycle 

system or to make “other changes that would result in 

impingement and entrainment reduction equivalent to the 

reductions associated with closed-cycle cooling.”115

Potential Flexibility in the EPA’s CCR Regulations

The EPA’s proposed CCR regulations contain significant 

potential for compliance flexibility. Despite one avenue 

of regulation (Subtitle C) being especially restrictive 

and more expensive to implement, the rule as actually 

proposed contains a number of less stringent alternatives. 

It also preserves certain exemptions to CCR regulation. In 

addition, although the EPA proposed a rule in May 2010, 

the EPA has decided to refrain for the moment from setting 

a date for a final rule, leaving regulated entities time to 

consider alternatives and plan their compliance strategies.
54

Incorporating Environmental Costs in Electric Rates

Reducing Emissions 

of NOx

During the Ozone 

Season

(1997 Ozone NAAQS)

Reducing Annual 

Emissions of

SO2 and NOx 

(1997 Annual

PM2.5 NAAQS)

Reducing Annual 

Emissions of

SO2 and NOx 

(2006 24-hour

PM2.5 NAAQS)

Figure 22 

The Cross-State Air Pollution Rule Programs and Affected States 116

Alabama ◆ ◆ ◆

Arkansas ◆ 

Florida ◆ 

Georgia ◆ ◆ ◆

Illinois ◆ ◆ ◆

Indiana ◆ ◆ ◆

Iowa ◆ (proposed) ◆ ◆

Kansas ◆ (proposed) ◆

Kentucky ◆ ◆ ◆

Louisiana ◆ 

Maryland ◆ ◆ ◆

Michigan ◆ (proposed) ◆ ◆

Minnesota ◆

Mississippi ◆ 

Missouri ◆ (proposed) ◆ ◆

Nebraska ◆

New Jersey ◆ ◆

New York ◆ ◆ ◆

North Carolina ◆ ◆ ◆

Ohio ◆ ◆ ◆

Oklahoma ◆ (proposed) 

Pennsylvania ◆ ◆ ◆

South Carolina ◆ ◆

Tennessee ◆ ◆ ◆

Texas ◆ ◆

Virginia ◆ ◆

West Virginia ◆ ◆ ◆

Wisconsin ◆ (proposed) ◆ ◆

116 Based on U.S. Environmental Protection Agency, “Fact Sheet: The Cross-State Air Pollution Rule.”
55

Working to Ensure Affordable Compliance with Public Health and Environmental Regulations
56

Incorporating Environmental Costs in Electric Rates
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