DOE/EIA-0598

Distribution Category UC-950

Electricity Generation and

Environmental Externalities:

Case Studies

September 1995

Energy Information Administration

Office of Coal, Nuclear, Electric and Alternate Fuels

Coal and Electric Analysis Branch

U.S. Department of Energy

Washington, DC 20585

This report was prepared by the Energy Information Administration, the independent statistical and

analytical agency within the U.S. Department of Energy. The information contained herein should

not be construed as advocating or reflecting any policy position of the U.S. Department of Energy or

of any other organization.
Contacts

This report was prepared by the staff of the Coal and

Electric Analysis Branch, Analysis and Systems

Division, Office of Coal, Nuclear, Electric and Alternate

Fuels. General information regarding this publication

may be obtained from Robert M. Schnapp, Director,

Analysis and Systems Division (202-254-5392; Internet:

RSCHNAPP@EIA.DOE.GOV), or Betsy O’Brien, Chief,

Coal and Electric Analysis Branch (202-254-5490;

Internet: BOBRIEN@EIA.DOE.GOV). Specific questions

regarding the content of this report may be addressed

to Dr. Suraj Kanhouwa (202-254-5779; Internet:

SKANHOUW@EIA.DOE.GOV), Project Manager for

this report. Contributing authors are: Dr. Suraj

Kanhouwa and Rebecca A. McNerney (202-254-5469;

Internet: RMCNERNE@EIA.DOE.GOV).

ii Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
Contents Page

Executive Summary ......................................................................v

1. Introduction .........................................................................1

2. Economic Foundations of Environmental Externalities: An Overview ............................5

3. Environmental Externalities in Power Generation and the Regulatory Approach . . . . . . . . . . . . . . . . . . . 11

4. The Commonwealth of Massachusetts Case Study . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

5. The State of Wisconsin Case Study . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

6. The State of California Case Study . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

7. Externalities in a Changing Industry Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71

Appendix

Summary of State Public Utility Commissions’ Activities Regarding Externalities . . . . . . . . . . . . . . . . . 77

Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies iii
Tables Page

1. Generation and Estimated Emissions from U.S. Electric Utility Fossil-Fueled Steam-Electric

Generating Units, 1993 .................................................................2

2. Major Federal Environmental Laws Affecting Electric Utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

3. Massachusetts Externality Values . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

4. Environmental Risk Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

5. Number and Available Annual Electrical Energy Output of Projects Bid by New England Electric

System Companies on the Green RFP (by Type) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

6. Summary of Project Costs Versus Avoided Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

7. Impact of Carbon Adder on Projects Beginning in 1994 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

8. New England Electric’s Existing Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

9. Range of CO2 Externality Values Compiled by the Wisconsin Public Service Commission . . . . . . . . . . . . . 49

10. Wisconsin Electric Power Company Advance Plan 7, 1994-2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

11. Effect of Monetized GHG Externality Values on Wisconsin Electric’s Resource Mix and Costs . . . . . . . . . . 54

12. Summary of Environmental Regulations Affecting Electricity Generation in California . . . . . . . . . . . . . . . . 58

13. Comparison of Residual Emission Reduction Values for 1992 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60

14. Externality Values for California . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

15. Sources of Electric Energy for Pacific Gas and Electric (PG&E) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

16. Externality Values Used by Pacific Gas and Electric Based on Values Estimated by the California Energy

Commission for the 1994 Biennial Update . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

17. Pacific Gas and Electric’s Analysis of the Effects of Externality Values on Resource Additions . . . . . . . . . . 68

18. Externality Values for Different Pollutants, by State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72

A1. Summary of State Public Utility Commissions’ Activities Regarding Externalities . . . . . . . . . . . . . . . . . . . . 79

Figures

1a. Environmental Impacts Relative to the Fuel-Cycle Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

1b. Environmental Impacts Relative to the Fuel-Cycle Process (Continued) . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

1c. Environmental Impacts Relative to the Fuel-Cycle Process (Continued) . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

2. Integrated Resource Planning Process in Wisconsin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

3. Biennial Resource Plan Update: Timing of Significant Events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65

4. Utility Decisions That Could Be Affected by Considering Environmental Externalities . . . . . . . . . . . . . . . . 73

iv Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
Executive Summary

Electricity constitutes a critical input in sustaining the

Nation’s economic growth and development and the

well-being of its inhabitants.1 However, there are byproducts of electricity production that have an undesirable effect on the environment. Most of these are

emissions introduced by the combustion of fossil fuels,

which accounts for nearly 70 percent of the total electricity generated in the United States.

The environmental impacts (or damages) caused by

these emissions are labeled environmental “externalities.” Included in the generic term “externality” are

benefits or costs resulting as an unintended byproduct

of an economic activity that accrue to someone other

than the parties involved in the activity.2

This report provides an overview of the economic

foundation of externalities, the Federal and State

regulatory approaches, and case studies of the impacts

of the externality policies adopted by three States.

The Federal Role

Since the 1960s, the United States has witnessed a

growing concern over the degradation of the environment. This concern resulted in passage of The National

Environmental Policy Act (NEPA) of 1969, the first

major Federal initiative to protect the environment and

to reduce pollution to non-threatening levels. That

effort was followed by major laws that address air and

water pollution, solid waste recovery, pesticide and

toxic substance regulation, resource conservation, noise

abatement, endangered species protection, and other

areas of concern.

Federal regulations do not, by themselves, provide a

prescription for handling externalities in any systematic

manner. Rather, the Federal legislative initiatives seek

to restrict (or raise the cost of) using the environment

as a repository for emissions. Compliance with most

Federal environmental requirements results in added

costs to the electric utilities. These costs are reflected in

the costs of generating power and in the rates that

customers pay for buying electricity. Federal actions

may, therefore, be seen as a way of incorporating and

internalizing externalities.

Recent Federal regulations strive to shift the focus of

environmental regulations to market-based approaches

with the intent of containing pollution within specified

limits. Voluntary cooperation (without any legislative

mandate) is also being encouraged. Within the framework of these approaches, energy efficiency, conservation and demand-side management programs all have

a role to play.

The State Role

Treatment of externalities at the State level is far from

uniform. Recent reports indicate that slightly over half

of State utility commissions currently take environmental externalities into consideration in their resource

planning process. Of these, only seven States have

specified monetary externality values for designated air

emissions from power plants.3

Among the States that monetize externality values, the

general trend is to incorporate them within the framework of the integrated resource planning (IRP) process,

which requires the utilities to evaluate supply- and

demand-side options on a consistent basis to meet

future demand reliably at the lowest system costs.

The three States (Massachusetts, Wisconsin, and California) that were chosen for the case studies presented in

this report incorporate monetized externality values

within the IRP process. These States were selected for

a detailed study due to their proactive involvement in

handling externalities. They had regulations in place for

at least a few years so as to allow them to have some

effect. The selection of these States also provided a

1

To meet customer demand in 1993, net electricity generation in the United States totaled nearly 3 trillion kilowatthours using over

30 quadrillion Btus in composite energy resources. 2

The National Association of Regulatory Utility Commissioners uses a similar definition. See National Association of Regulatory Utility

Commissioners, Environmental Externalities and Electric Utility Regulation (Washington, DC, September 1993), p. 3. 3

These States are: California, Massachusetts, Minnesota, Nevada, New York, Oregon, and Wisconsin. Since December 1994, however,

Massachusetts no longer uses externality values.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies v
diverse regional mix. The objective was to evaluate the

impact externality incorporation had on resources

selected to meet future needs.4

The analysis presented in this report is based on a

review of documents available in the public domain

from State public utility commissions and electric

utilities. In addition, meetings were held with officials

at public utility commissions and with officials of the

largest investor-owned utility in each of the three

States.

Massachusetts

In December 1989, the Massachusetts Department of

Public Utilities (MDPU) directed the electric utilities in

the State to include an environmental externality component in their all-resource solicitation criteria. Dollar

values were established in 1990 for nitrogen oxides,

sulfur dioxide, volatile organic compounds, total suspended particulates, carbon monoxide, carbon dioxide,

and other pollutants. The externality values established

by the MDPU were to be used in the selection of required resources within the framework of the State’s

integrated resource management (IRM) process (which

treats the supply- and demand-side options on a consistent basis). These values were reaffirmed in November

1992 after a re-investigation.

Since then, the electric utilities in the State have had

only one occasion to file their integrated resource management plan with the incorporation of externality

values in 1994. From among these, the plan filed by the

New England Electric System (which is the largest

investor-owned electric utility in the State) provides a

good example of the issues considered. These include:

forecast of demand and energy use by retail customers;

an inventory of existing resources; identification of

future resource needs; projections of significant new

supply-side commitments and other new resource

additions; projection of demand-side resources to be

developed; plans for compliance with new environmental requirements; a 2-year plan for implementing

the integrated resource plan; and other information

required by the State laws.

The utility found that incorporation of monetized

externality values in its resource plan merely caused a

shift toward natural gas in its plans to acquire capacity.

The utility, however, also submitted what it termed a

“Green RFP” to permit an accelerated penetration of

renewable resources. This submission was prompted by

the possibility of more stringent environmental regulations and lower cost of renewables in the future. The

utility found it difficult, however, to obtain approval

from the three jurisdictions in which it operates—

Massachusetts, Rhode Island, and New Hampshire.5

Incorporating monetized externality values into the

IRM process has been challenged, and the IRM procedures issued in June 1995 do not embody the

MDPU’s externality policy. The Supreme Judicial Court

of the Commonwealth of Massachusetts issued a decision in December 1994 that the decision by the MDPU

on the value of environmental externalities was beyond

the range of its statutory authority. Thus, externality

values will not be used in the future.

Wisconsin

The Wisconsin Public Service Commission (WPSC) asserts that it had an early start with environmental

concerns initiated by the enactment of the Wisconsin

Environmental Policy Act of 1971 and followed by the

Power Plant Siting Law in 1975. The WPSC further contends that plans (called the Advance Plans or APs)

submitted by the utilities since 1978 have taken

environmental considerations of one kind or another

into account.

Currently, the WPSC has set monetized values only for

greenhouse gas emissions in the belief that such emissions would become subject to national or international

regulations. Utilities in the State are required to use

these values in comparing demand-side management

programs and in determining the economic cost of

resource options in their planning process. Greenhouse

gas emissions that are offset by other programs, however, are not monetized. The WPSC’s order is limited to

the risk of future regulations because there is significant

controversy over its authority in the area of air pollution.

Electric utilities in the State of Wisconsin are required

to undertake integrated resource planning jointly and

submit their plan to the WPSC. The joint plan contains

projections of statewide demand for electricity over a

20-year planning horizon together with recommendations with respect to the capacity acquisitions. The

plan also addresses major issues such as cost; reliability;

efficiency; and health, safety, and environmental effects

for meeting the future electrical needs of the State. In

addition to the submission of the joint plan, each utility

is also required to submit its own individual plan to the

4

Note that Massachusetts no longer incorporates externality values.

5

All the projects selected by the utility have since been approved by the three States.

vi Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
WPSC. Monetized values are used in evaluating

demand-side management potential and supply-side

resources.

The evaluation by the largest utility in the State,

Wisconsin Electric, shows that externality considerations did not lead to any significant changes in the

utility’s resource acquisition plans. For the utility,

natural gas will be the fuel of choice for most of the

new capacity in the future. The utility also plans to

bring some renewable capacity on line for reasons other

than economic cost considerations. In addition, the

utility is implementing some voluntary programs to

offset its greenhouse gas emissions.

California

The State of California has some of the highest levels of

pollution in the country. To alleviate this problem, the

State adopted its own Clean Air Act in 1988 to address

the unique air quality problems facing the State and to

establish procedures to attain ambient air quality standards. The State’s environmental regulations address

emissions from power plants as well as emissions from

other sources like automobiles and industrial facilities.

In its 1990 report, the California Energy Commission

(CEC) directed that all costs and emission impacts of

compliance with air quality regulations be accounted

for in the analysis of the cost-effectiveness of power

generation. The CEC specified externality values for

five categories of emissions, which include nitrogen

oxide, sulfur dioxide, particulate matter, reactive organic gases, and carbon. These externality values are

based on the estimates of the marginal cost of the best

available control technology. The values differ regionally depending on a region’s air quality and the

service area.6

Monetized externality values were used in the State

during the resource planning process in 1993. The CEC

noted that externality values have had negligible impact

on actual procurement and operations decisions of the

utilities. The CEC has subsequently considered marketable permits, environmental performance standards,

emission taxes and surcharges, and other methods of

evaluating externalities. In the CEC’s view, these

approaches may permit the “internalization” of externalities. Until this is achieved, its second-best approach

is to set standards as interim measures.

The Pacific Gas and Electric Co., the largest investorowned utility in the State, released its Electric Resource

Plan, which indicates that new supply resources will

not be required before 2002. In the meantime, its plan

calls for upgrades, license extensions, and environmental retrofits. The utility’s analysis shows little

impact on the mix of resources as a result of externality

considerations.

Conclusion

The requirement to incorporate externalities in the resource planning process had negligible impacts on the

planned resource mix of the utilities in each of the three

States. The scope of demand-side management activities

was also largely unaffected by externality considerations.

These findings are not surprising for the following

reasons:

• Current low natural gas prices result in natural

gas being the fuel of choice to meet the future

demand for electricity, with or without the consideration of environmental externalities.

• There has been little need for new capacity.

• Utilities have little experience with renewable

technologies (other than hydroelectric power).

• Where utilities operate in more than one State,

inter-jurisdictional issues make it difficult for

utilities to secure concurrence from all regulatory

authorities.

Notwithstanding what is stated above, many Federal

policies such as the Clean Air Act have affected

utilities’ resource plans and choices because the costs of

compliance have been fully internalized. The impact of

this issue has not been analyzed in this report.

As conditions change, incorporating environmental externalities into the resource planning process may affect

the role that energy efficiency or renewable technologies can play in the future. The States, however, continue to reiterate the need to explore new, innovative

methods to meet long-term environmental goals. This

is especially important since the potential for significant

operations and structural changes exists in the electric

utility industry, in part due to the enactment of the

Energy Policy Act of 1992. The manner in which such

goals will be achieved in an increasingly competitive

industry environment is not clear at this time.

6

Externality values specified by the CEC may be modified by the California Public Utilities Commission.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies vii
1. Introduction

The electric utility industry in the United States has

come a long way from its beginnings more than one

hundred years ago when Thomas Edison introduced

electricity into New York City.1 During this period,

electricity use has expanded and now constitutes a critical input in sustaining the Nation’s economic growth

and development and the well-being of its inhabitants.

Net generation from electric utilities amounted to 2,883

billion kilowatthours in 1993.2 This record power

output was produced by the consumption of 30.3 quadrillion Btus of energy resources representing 36

percent of total primary energy consumption in the

United States. Coal provided about 57 percent of total

net generation, followed by nuclear power at about 21

percent. Hydroelectric power and natural gas each

supplied around 9 percent of the total. Petroleum

products contributed over 3 percent of the output with

other renewable resources accounting for the balance.3

During the same year, the industry consumed large

volumes of fossil fuel—over 800 million tons of coal,

nearly 2,700 billion cubic feet of natural gas, and over

160 million barrels of petroleum products—to generate

nearly 70 percent of the domestic output of electricity.4

To sustain its operating capability at the levels indicated above, the industry owned nearly 700 gigawatts

of net summer generating capability in 1993 together

with associated transmission and distribution facilities.5

Significant levels of investment are required to own and

operate these facilities, making the electric utility

industry the most capital-intensive industry in the

country. Its assets in 1993 were approximately threefourths of a trillion dollars, with aggregate operating

revenues of about $200 billion.6 Taken together, these

impressive statistics accord the electric utility industry

an important place within the domestic economy.

Yet, the growth of the electric power sector has been a

mixed blessing. While electricity has proven itself to be

the sine qua non of industrialization and societal wellbeing, byproducts of its production and distribution

have an undesirable effect on the environment. Most of

these result from the combustion of fossil fuels used in

converting thermal energy into electrical energy.7

Pollutants in the air include nitrogen oxides, sulfur

dioxide, traces of heavy metal contaminants, organic

pyrolysis compounds, and others.

1

The term electric utility industry used in this report includes all segments of the industry consisting of investor-owned utilities, public,

Federal, and cooperative utilities. Nonutility generators including cogenerators are not included in the statistics reported unless

specifically stated. Nonutility sales to utilities represented 6.5 percent of the retail sales of electricity in 1993. For additional information

with respect to the industry structure, see Energy Information Administration, Electric Power Annual 1993 (Washington, DC, December

1994), pp. 1-7. 2

Energy Information Administration, Electric Power Annual 1994, Volume 1, DOE/EIA-0348(94/1) (Washington, DC, July 1995), p. 5. 3

The net electricity generation increased to 2,911 billion kilowatthours in 1994. Data for 1993, however, have been used since emissions

data for 1994 are not yet available. 4

Energy Information Administration, Annual Energy Review 1993, DOE/EIA-0384(93) (Washington, DC, July 1994), p. 237. 5

There were approximately 192,000 miles of transmission lines in 1993 with more than 13,000 miles planned for addition during the

next 10 years. For further details, see North American Electric Reliability Council, Reliability Assessment 1994-2003 (Princeton, NJ,

September 1994), p. 12. For data on generating capability, see Annual Energy Review 1994, DOE/EIA-0384(94) (Washington, DC, July 1995),

p. 231. 6

Energy Information Administration, Financial Statistics of Major U.S. Investor-Owned Electric Utilities 1993, DOE-EIA-0437(93)/1

(Washington, DC, January 1995) and Financial Statistics of Major U.S. Publicly Owned Electric Utilities 1993, DOE-EIA-0437(93)/2

(Washington, DC, February 1995). 7

The undesirable environmental effects are significantly larger when the impacts are considered with respect to the entirety of the fuel

cycle of any specific fuel. Power generation using conventional methods relies on extracting and transporting a fuel, its conversion into

electric power, and finally the disposition of residual products including generation facilities. More recent studies take into account the

totality of effects of each fuel cycle. As an example, methane (CH4) emissions from coal mining are considered to be a greenhouse gas

contributing to global warming. For further details, see Oak Ridge National Laboratory and Resources for the Future, U.S.- EC Fuel Cycle

Study: Background Document to the Approach and Issues, Report Number 1 (Oak Ridge National Laboratory, Oak Ridge, TN, November 1992).

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 1
In addition, fossil fuel combustion also produces carbon

dioxide, which absorbs radiant energy, contributing to

the greenhouse effect. According to available data, the

United States is the world’s largest source of energyrelated carbon dioxide emissions, accounting for about

22 percent of worldwide emissions in 1990. There is

concern that increasing concentrations of greenhouse

gases (including carbon dioxide, methane and manmade chloroflurocarbons) may enhance the greenhouse

effect and cause global warming.8 Note that environmental problems associated with nuclear or hydroelectric power generation are of a different dimension

not involving the release of greenhouse gases or other

pollutants into the atmosphere.

As indicated earlier, fossil fuels currently provide

nearly 70 percent of net domestic electricity generation

by electric utilities. They contribute to emissions of

various gases at significantly high levels into the

atmosphere. Estimated emissions during 1993 from

fossil-fueled steam-electric generating units were: sulfur

dioxide (SO2), 14.4 million tons; nitrogen oxides (NOx),

5.8 million tons; and carbon dioxide (CO2), 1.9 billion

tons9 (Table 1). Other major air emissions are: volatile

organic compounds, carbon monoxide, lead, and particulate matter less than 10 microns in diameter (PM10).10

There is growing recognition that such emissions adversely impact the environment—locally, nationally,

and globally. Economists label these impacts (or damages) environmental “externalities.” Included in the

generic term “externality” are benefits or costs resulting

as an unintended byproduct of an economic activity

that accrue to someone other than the parties involved

in the activity. As a result, externalities do not enter

into the market-pricing calculations of the parties

undertaking the activity.

Table 1. Generation and Estimated Emissions from U.S. Electric Utility Fossil-Fueled Steam-Electric

Generating Units, 1993

Fuel

Net Generation SO2 Emissions NOx Emissions CO2 Emissions

Billion

Kilowatthours

Percent

of Totala

Thousand

Short Tons

Percent

of Totala

Thousand

Short Tons

Percent

of Totala

Thousand

Short Tons

Percent

of Totala

Coal ............ 1,639 83.1 13,844 95.9 5,288 90.4 1,711,673 87.9

Petroleum . . . . . . . . 96 4.9 583 4.0 136 2.3 84,129 4.3

Gas . . . . . . . . . . . . 237 12.0 1 * 424 7.2 146,584 7.5

Total ......... 1,973 100.0 14,428 100.0 5,848 100.0 1,942,386 100.0

a

Total refers to the total quantity for fossil-fired steam-electric units only.

CO2 = Carbon dioxide.

NOx = Nitrogen oxide.

SO2 = Sulfur dioxide.

* = value less than 0.05.

Notes: •Data in this table are with specific reference to fossil-fueled steam-electric generating plants in the United States. •The

designation steam-electric excludes gas turbines, combustion turbines, and internal combustion engines. •Emissions estimates are

for steam-electric plants 10 megawatts and larger and are based on fuel consumption using average emissions factors as reported

in the Environmental Protection Agency's AP-42 Release IV.

Source: Energy Information Administration, Electric Power Annual 1993, DOE-EIA/0348(93) (Washington, DC, December 1994),

pp. 25-26, 34, 36-37, 76.

8

Energy Information Administration, Emissions of Greenhouse Gases in the United States: 1985-1990, DOE/EIA-0573 (Washington, DC,

September 1993), pp. ix -xii. Other greenhouse gases are methane, nitrous oxide and chloroflurocarbons. See “Glossary” for a clarification

of the term greenhouse effect. 9

The data include estimates of emissions from steam-electric generating unit plants with a capacity of 10 megawatts and more.

Emission estimates from gas turbine and internal combustion units are thus excluded. For further details, see Energy Information

Administration, Electric Power Annual 1993, DOE/EIA-0348(93) (Washington, DC, December 1994), pp. 71-85. 10Council on Environmental Quality (CEQ), Environmental Quality – 1993, (Government Printing Office, Washington , DC, April 1995),

pp. 435-441. Within the CEQ’s accounting framework, as stated in the National Environmental Policy Act of 1969, CO2 emission statistics

are not required. Data on CO2 emissions for the economy as a whole and for the electricity sector are compiled separately by the Energy

Information Administration in terms of the provisions of the Energy Policy Act of 1992. For further details, see Energy Information

Administration, Greenhouse Gases in the United States: 1987-1992, DOE/EIA-0573 (Washington, DC, November 1994).

2 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
In the prevailing rate-setting approach for power generation, only costs associated with providing electricity

are taken into account to the exclusion of costs related

to the unintended byproducts of producing electricity.

Included in this latter category are the costs of impacts

on the ecosystem and the environment in general, including human health, that are not fully included in the

market price. To the extent that these impacts remain

unaccounted for, the cost of power generation remains

lower than what it would otherwise be if the cost of

burdens imposed on society were also included.

Since the early 1970s, the realization that the environment consists of resources that are scarce and exhaustible has brought about a nexus between the environment and the economy. There has been an interest

in “getting the prices right” by including part or all of

the excluded costs.11 Considerations of environmental

externalities have thus become increasingly important

in the resource planning operations of domestic electric

utilities within a regulatory environment.

To reduce the adverse environmental impacts of electricity generation, State and Federal regulatory authorities have initiated several measures. The approaches

adopted by the Federal and State authorities, however,

differ significantly. The Federal Government passed a

significant amount of environmental legislation, such as

the Clean Air Act, the Clean Water Act, and the

National Environmental Policy Act, which resulted in

regulations that mandated compliance. The cost of

compliance becomes embedded in the costs of power

generation and is thus “internalized.” The States’ approach is to incorporate a qualitative or quantitative

assessment of the environmental externalities remaining

after compliance with the Federal regulations in planning for resources within an integrated resource

planning framework.

Recent reports indicate that more than half of the State

utility commissions currently take environmental externalities into consideration in their resource planning

process. In 1990, there were only 17 States with such a

requirement.12 The rationale for this increase in regulatory activity is that conventional electricity generation

activities involving the use of fossil fuels impose real

and substantial damage to human health and the environment.13 These effects were not taken into account

in planning capacity additions in the past.

This report describes the policies adopted by three State

regulatory authorities regarding the treatment of environmental externalities in the utility regulatory

process, and evaluates their impact on the resource

selection process. The States selected in this study—

Massachusetts, Wisconsin, and California—are among

the seven that in the past have been actively involved

in the quantitative consideration of environmental externalities within the regulatory process and provide a

regional diversification.

These three case studies were prepared by the Energy

Information Administration (EIA) in response to a

request by the International Atomic Energy Agency

(IAEA) in Vienna, Austria. The IAEA has been working

since the early 1990s toward the objective of providing

enhanced capabilities for comparative assessment of different electricity generation options to aid the process

of planning and decision-making for the electricity sector in developing countries. Under the aegis of what

has become known as the DECADES project, the IAEA

is developing a compilation of country-specific case

studies for presentation at the International Symposium

on Electricity, Health and the Environment in October

1995. It is EIA’s intent to provide this report in support

of the IAEA’s activities.

In addition, this report provides an overview of the

economic foundations of externalities within the framework of the theory of welfare economics and describes

the major forms of State and Federal regulatory approaches generally used to address environmental

impacts of power generation. It also examines the

potential future status of externalities within the framework of the integrated resource planning (IRP) process

resulting from the amendments to the Public Utility

Regulatory Policies Act of 1978 (PURPA) contained in

the Energy Policy Act of 1992 (EPACT).

11Oak Ridge National Laboratory and Resources for the Future, Estimating Externalities of Coal Fuel Cycles, Report Number 3 (Oak Ridge

National Laboratory, Oak Ridge, TN, September 1994), pp. E1-E22. 12National Renewable Energy Laboratory, Issues and Methods in Incorporating Environmental Externalities into the Integrated Resource

Planning Process (Golden, CO, November 1994), p. 11. 13Environmental degradation is also associated with hydroelectric power generation. Its impacts are somewhat different than those of

fossil-fueled power plants. Similar considerations apply to generation from nuclear power plants. For further details on this subject, see

Oak Ridge National Laboratory and Resources for the Future, U.S.-EC Fuel Cycle Study: Background Document to the Approach and Issues

(Oak Ridge National Laboratory, Oak Ridge, TN, report numbers 1 through 8). The first report was published in November 1992. Report

numbers 4 through 8, which deal with natural gas, oil, biomass, hydroelectric, and nuclear power generation, are in the process of being

published.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 3
2. Economic Foundations of Environmental

Externalities: An Overview

To assist the reader in understanding the origins of the

economic idea of “externalities,” this chapter provides

a brief conceptual overview of the term within the

framework of the theory of welfare economics and its

extension into the environmental field. The background

discussion with respect to externalities is extended to

electric power generation with a brief reference to

overall regulatory approaches.

Economic Foundations of Externalities

Welfare economics may broadly be viewed as a study

of the social desirability of alternative arrangements of

economic activities and the allocation of resources—that

are scarce and have alternative uses—toward a determination of efficient states in which no individual can

be made better off without making some other individual worse off.14 Economic theory on the subject

starts with a number of simplifying assumptions (e.g.,

perfect competition, unrestrained factor mobility, and

free trade) to provide a rigorous formulation of conditions under which a state of maximum social welfare

(or some variation thereof) becomes attainable.15

Among the conditions deemed necessary and sufficient

to attain maximum social welfare, the single most critical requirement is the existence of perfect competition

in all economic activities in all markets so that the

value at the margin of any class of factor (i.e., land,

labor, and capital) is the same in all occupations in

which it is employed.16

Welfare economics essentially aims to “test the efficiency of economic institutions in making use of the

productive resources of a community.”17 Achievement

of economic efficiency in the allocation of resources is

based on the equivalence between marginal costs and

prices.18 Product prices based on this equivalence are

14Dr. E.J. Mishan of the London School of Economics defines theoretical welfare economics as “that branch of study which endeavors

to formulate propositions by which we may rank, on the scale of better or worse, alternative economic situations open to the society.”

For a scholarly survey on welfare economics, see E.J. Mishan, “A Survey of Welfare Economics, 1939-1959,” Economic Journal, Vol. 70

(1960), pp. 197-256. Note that for the most part, welfare economics starts with income distribution as a given and makes no normative

investigative attempts in this direction despite significant studies that deal with decentralized mechanisms. Critics further note that the

theory does not fully take into account welfare implications that result from growth and development. Despite these criticisms, “the major

achievement of welfare economics has been to provide a rigorous framework for what seemed too vague and elusive and to create a

measuring rod for what was thought nonmeasurable.” For further details, see Kenneth J. Arrow and Tibor Scitovsky, A.E.A. Readings

in Welfare Economics (Richard D. Irwin, Inc., Homewood, IL, 1969), pp. 6-7. 15The earliest exposition on this subject is attributed to the French economist Vilfredo Pareto in his book Cours d’Economie Politique

published in 1896-1897. Pareto developed the familiar marginal conditions concluding that perfect competition maximizes welfare. English

translations of his major economic works are not available. Note that perfect competition is said to exist where the actions of a single

buyer or seller/firm have no effect on the price of a product. This requires a large number of buyers and profit-maximizing sellers and

the assumption of products being homogenous. In addition, entry and exit for the firms is assumed to be costless, implying mobility of

resources and complete knowledge. Product prices under these conditions are equal to marginal costs. 16Economists decompose this allocative rule into popular marginal conditions (e.g., marginal conditions for exchange, factor substitution,

and product substitution) necessary to maximize social welfare. Note that fulfillment of any one or all of the so-called marginal conditions

does not ensure that the welfare of a community is at a maximum, but the nonfulfillment of any one does indicate that welfare is not

being maximized since a change in the existing situation can benefit at least one person without harming the position of another person.

For a complete discussion of the conditions sufficient and necessary to attain maximum social welfare, see Mark Blaugh, “Economic

Theory in Retrospect,” Chapter 13, General Equilibrium and Welfare Economics (Richard D. Irwin, Inc., Homewood, IL, 1969), pp. 575-614.

Also, see C.E. Ferguson, Microeconomic Theory (Richard D. Irwin, Inc., Homewood, IL, 1972), pp. 478-502. 17Tibor Scitovsky, “A Note on Welfare Propositions in Economics,” A.E.A Readings in Welfare Economics, Eds. Kenneth J. Arrow and

Tibor Scitovsky (Richard D. Irwin, Inc., Homewood, IL, 1969), pp. 390-401. 18Development of the welfare theory (and its subsequent refinement) represents a departure from the earlier notions of welfare being

the arithmetic sum of individual welfares resting on the concept of cardinally measurable utilities of individuals or households. The

current underpinnings of welfare theory (attributable to Vilfredo Pareto in Cours d’Economie Politique published in 1896-1897 and Manuel

d’Economie Politique published in 1906) reflect a radical departure from the notion of cardinality of utility functions and are independent

of interpersonal utility comparisons. In addition, Pareto’s approach to welfare permitted the separation of efficiency from considerations

of equity with respect to the distribution of incomes.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 5
instrumental in the determination of rewards to factors

of production (which are land, labor, and capital).

Within the framework of welfare economics, it is

argued that demand represents the marginal social valuation or the marginal social benefit derived from an

additional unit of a commodity in question. Since the

additional units are all priced at marginal cost, the

price represents the marginal cost society must incur to

have an additional unit produced. The “marginal”

argument is extended to include the proposition that

social welfare maximization occurs when marginal

social costs equal marginal social benefits.19

Nonmarket Interdependence and

Externalities

Marginal conditions envisaged in the derivation of

social welfare maximization are seldom fully met in the

real world.20 As a result, divergences from the idealized equivalence between social costs (which include a

valuation for the impacts of externalities in addition to

private costs) and private costs (which broadly include

the opportunity cost of undertaking an economic activity) and social and private benefits emerge, casting a

pall over the grand design of social welfare maximization. Other things being equal, non-market interdependence with its associated attributes of external

economies or external diseconomies is identified as the

principal causal factor contributing to this

divergence.21 Both the terms—external economies and

external diseconomies—have since been abbreviated

into what are commonly called “externalities” or the

alternative term “spillover effects.”22

Generally speaking, external economies are realized if

the expansion of an industry’s output lowers the total

cost curve of each firm. Similarly, external diseconomies

are realized if the expansion of an industry’s output

raises the total cost curve of each firm.23 In both cases,

however, market failures cause their emergence (i.e.,

external economies or diseconomies) such that private

costs and social costs differ, leading to economic inefficiency and misallocation of resources in production.

These concepts have been instrumental in initially channeling economic analysis into areas that focus on

welfare maximization concepts. Subsequent theoretical

developments provide tools for performing cost-benefit

analyses and their application to issues of environmental policy.24

References to the concept of external economies or

diseconomies (together with a discussion of welfare

economics) appear in the writings of Marshall and

Pigou, both English economists.25 An external economy occurs when an action taken by an economic unit

results in uncompensated benefits to other firm(s) such

as an increase in its output.26 As an illustrative

example with respect to an external economy, assume

19For additional comments on this topic, see C.E. Ferguson, Microeconomic Theory (Richard D. Irwin, Inc., Homewood, IL, 1972), pp.

496-497. 20Assuming income distribution as a given, conditions necessary and sufficient to ensure optimal allocation of resources can be briefly

stated. First, the ratio of marginal utilities of two commodities must be the same for any two customers buying the same commodity.

Second, the ratio of the marginal products of the two inputs must be the same for any pair of producers using both inputs. Finally, the

marginal social benefit from an extra unit of any commodity should be equal to its marginal social cost. See Edwin Mansfield,

Economics—Principles, Problems and Decision (W.W. Norton and Co., New York, NY, 1974), pp. 721-735. 21Nonmarket interdependence is said to exist when the various production functions and preference functions are interdependent and

the activities of one group have either a beneficial or harmful impact on similar activities of another group. 22The term “spillover effects” or briefly “spillovers” first appears in Alfred Marshall’s writings (The Principles of Economics, published

in 1890) in connection with a competitive industry’s downward sloping supply curve. 23External effects may not be unambiguously economies or diseconomies. For further details, see James M. Henderson and Richard

E. Quant, Microeconomic Theory: A Mathematical Approach (McGraw Hill Book Company, New York, NY, 1980), pp. 143-145, 302-304. 24The initial purpose of a cost-benefit analysis is to undertake the appraisal of a project to include all social and financial costs and

benefits accruing to the project. Thus, in addition to employing the usual financial analysis approach, undertaking the valuation in money

terms of the social or welfare costs and benefits presents special problems. For further details, see Ezra J. Mishan, Cost-Benefit Analysis

(Praeger Publishers, New York, NY, 1976) for a discussion of the problems in this area. 25Alfred Marshall was the first economist to dwell on the subject of external economies and diseconomies. For further details, see

Alfred Marshall, The Principles of Economics (1890). Pigou, a prize student of Marshall at Cambridge made a clear-cut economic case for

a tax (or a subsidy) wherever an external diseconomy (or economy) creates a divergence between private marginal costs and social

marginal costs. For further details, see Arthur C. Pigou, The Economics of Welfare (Macmillan, 1920). While a number of eminent economists

have found the Pigouvian concept and its policy conclusions to be in error, the Pigouvian tax/subsidy doctrine still remains the

fountainhead for economic analysis in the area of welfare and its extension to environmental economics. See Ronald Coase, “The Problem

of Social Cost,” Economics of the Environment: Selected Readings, Eds. Robert Dorfman and Nancy S. Dorfman (W.W. Norton and Co., Inc.,

New York, NY, 1977), pp. 142-171. See also Mark Blaugh, “Economic Theory in Retrospect,” Chapter 13, General Equilibrium and Welfare

Economics (Richard D. Irwin, Inc., Homewood, IL, 1969), pp. 575-614. 26Edwin Mansfield, Micro-Economics: Theory and Applications, 3rd ed. (W.W. Norton and Co., Inc., New York, NY, 1979), pp. 456-458.

6 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
the simultaneous existence of apple-growing and beekeeping activities in a given region. An increase in the

activities of the apple-growing farmers to augment their

produce (apples) by an increase in factor utilization

(land, labor, or capital) provides an unexpected increase

in apple blossoms, which, in turn, tends to increase the

production of honey. Here, the apple farmer provides

the bee-keeper with additional benefits at no charge. It

can thus be argued that the apple-growing farmer

receives less than the value of his marginal social net

product while the bee-keeper gets more than the value

of his marginal social net product.27 Consider now the

case of an external diseconomy where the output of one

production activity adversely affects the production

activity of another. The classic example involves a poor

widow supporting herself by hand laundry (which is

hung outside to dry), and a factory next door emitting

smoke that blackens her laundry.28

The above two externalities arise due to ownership externalities and focus on production activities. Economic

literature also differentiates between pecuniary and

technological externalities. Pecuniary externalities result

from a change in the prices of some inputs or outputs

in the economy. For example, a change in the demand

for leather shoes affects the price of leather and hence

the welfare of potential leather handbag buyers. In

essence, the production function for the handbags

remains unchanged.29 Stated simply, it means that the

factor inputs used in producing a product do not

change. Such changes do occur, however, in the case of

a technological externality. In the case of hand-operated

laundry operation, more soap and labor, for example,

is required.30 Thus, technological externalities refer to

a more or less direct effect, other than price changes,

imposed by one decision unit on another that prevents

the efficient functioning of the market mechanism.

In cases of “common-property resources,” environmental externalities are concerned primarily with

property rights, on the assumption that the source of

externalities lies in the absence of fully defined

property rights. Take a typical common-property

resource like a lake where everyone has fishing rights.

Excessive fishing by some reduces the catch for

everyone else. A redefinition of property rights or the

imposition of some charges may correct the situation.

Such prescriptions, however, do not apply to air or

water where ownership rights are difficult to establish.

Somewhat similar difficulties arise in the case of a

resource for which there are competing but conflicting

uses, like a body of water that is useful for recreation

purposes as well as for dumping city sewage.

It is not necessary to provide a further elaboration in

classifying externalities given the subject matter of this

report. It is also pertinent to note that a precise

definition of the term “externality” beyond its generic

description is lacking. Some economists contend that

rigorous definitions of “externality” are difficult to

provide and that the “definitions of external economies

are few and unsatisfactory.”31 More recent attempts to

provide a definition continue to prove elusive. Some

economists note that they are aware of the implications

(of externalities), but attempts to define the notion still

fail to capture all its ramifications.32 More recent

extensions of the definition of externalities indicate that

the effects of the externality should be appreciable and

should fall on a third party or parties that are or were

not part of the transaction.33

Definitional problems aside, the impacts resulting from

the presence of externalities are not in dispute. Market

failures attributable to the divergence between social

costs/benefits and private costs/benefits lead to an

inefficient allocation of resources. Market forces are

likely to generate too much of an activity where

diseconomies prevail and too little where economies

prevail. To counteract these tendencies (which are not

reflected in market prices or in valuation of relative

goods) or to mitigate their impacts, some degree of

27The example cited here has been adopted from the writings of James Meade. See James E. Meade, “External Economies and

Diseconomies in a Competitive Situation,” in A.E.A. Readings in Welfare Economics (Richard D. Irwin, Inc., Homewood, IL, 1969), pp. 185-

198.28This example appears in C.E. Ferguson, Microeconomic Theory (Richard D. Irwin, Inc., Homewood, IL, 1972), pp. 496-497. 29A production function is a mathematical relationship between the output of a firm (or the economy) and the inputs used to produce

that output. The relationship can be so written that constant, increasing, or decreasing returns to scale can be exhibited. 30This distinction is attributable to Jacob Viner. For a discussion of the concept, see William J. Baumol and Wallace E. Oates, The Theory

of Environmental Policy (Cambridge University Press, New York, NY, 1993), pp. 29-31. 31James M. Buchanan and Wm. Craig Stubblebine, “Externality,” A.E.A. Readings in Welfare Economics, Eds. Kenneth J. Arrow and Tibor

Scitovsky (Richard D. Irwin, Inc., Homewood, IL, 1969), pp. 199-212. 32William J. Baumol and Wallace E. Oates, The Theory of Environmental Policy (Cambridge University Press, Cambridge, U.K. 1993), pp.

14-15. 33Richard Cornes and Todd Sandler, The Theory of Externalities, Public Goods and Club Goods (Cambridge University Press, Cambridge,

MA, 1986).

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 7
intervention is called for.34 Policy tools designed to

achieve these ends include taxes, user fees, subsidies,

and clarification of property rights.35

Problem areas still remain. Given that externalities

cause distortions in resource use primarily because

society fails to pay the price (positive or negative)

charged for a good (or a bad), the real problem is how

to configure the price to be charged since the normal

price mechanism does not usually work. In everyday,

normal transactions, prices are generally symmetrical

in nature between the supplier and the consumer, but

this symmetry is difficult to sustain where externalities

are involved.36 It is thus pointed out that assumptions

of asymmetry are necessary to induce efficiency.

Problems resulting from the existence of pecuniary

externality caused by market interdependence may not

be easy to resolve. Consider, for example, the advent of

competition (due to passage of the Energy Policy Act of

1992), which is likely to cause such structural changes

in the domestic electric utility industry that a number

of generating assets (still in operation but with higher

costs of production) may have to be treated as stranded

assets.

37 Such results are due to pecuniary externalities

and arise due to changes in some input or output prices

in the economy. Even though pecuniary externalities do

not cause inefficient allocation of resources under

conditions of pure competition, it is necessary to draw

attention to this aspect.

Limitations to the theory of welfare economics (with or

without the considerations of externalities) also need to

be noted. These limitations arise not from the lack of

rigor and elegance in the development of its theoretical

construct, but rather from the essentially static nature

of its conceptualization and with its treatment of

income distribution as a given. As a result, the applicability of welfare economics to more dynamic conditions

of economic growth and development may be limited.

Environmental Externalities and Electric

Power Generation38

Discussion in the preceding paragraphs makes it possible to take into account environmental externalities in

the context of electric power generation. Power generation involves a process in which the actions of the

electricity producer may not be appropriately reflected

in the market prices charged for their product. True

resource costs should include both the private costs

incurred to provide power and the external costs of

damage (or deterioration in quality) to the environment

caused by power generation. Because of this market

failure, the price charged for electric power is lower

than it would be if the costs of externalities were

internalized, i.e., included in the price charged to

consumers for electric power. Consumption of electric

power is thus encouraged, leading to a misallocation of

resources (in terms of their most efficient use), together

with an associated impact on social welfare.

The correct way, in terms of the Pigouvian teachings, is

to tax the producers by an amount equal to the magnitude of damages caused. The Pigouvian prescription

is embedded in the notion that economic efficiency

would be increased by government intervention. However, this simplified version conceals many problems

associated with its implementation. Challenges to the

Pigouvian concept have since been vocal. Some economists contend that government intervention to internalize should focus on property rights instead of taxing

producers and that there may be options that are less

expensive (than imposing taxes on producers) which

should be explored and used.39

34Following Pigou’s analysis in his book The Economics of Welfare, most economists have struggled with a conceptual formulation to

mitigate impacts resulting from the presence of externalities. Most prescriptive arrangements postulate that the costs of external damages

be recovered. Consensus building continues on who should pay these costs. 35Economic Report of the President, 1994 (U.S. Government Printing Office, Washington, DC, 1994), pp. 179-181. Note that taxes or

subsidies are not to be viewed as costs and benefits but rather as a transfer of resources from one segment of the economy to the other. 36The notion of symmetry implies that the seller receives the same monetary value (expressed in terms of market price) as the buyer

pays. In the case of externalities, factories that emit smoke and pollute the surrounding atmosphere may be subjected to a tax or a subsidy

(in the manner suggested by Pigou) to provide the required incentive to the supplier of the externality (the factory in this case) while

leaving the nearby residents with a zero price. Thus, the price treatment (required to induce efficiency) loses its intrinsic symmetrical

nature. For additional discussion, see William J. Baumol and Wallace E. Oates, The Theory of Environmental Policy (Cambridge University

Press, Cambridge, U.K., 1993), pp. 29-32. 37Stranded assets or investments may generally be defined as investments with a cost recovery schedule initially approved by

regulatory action that subsequent action has rendered not practically recoverable. 38This section focuses on externalities and electric power generation to the exclusion of other segments of the energy sectors. For a

further discussion, see Anthony C. Fisher and Michael H. Rothkopf, “Market Failure and Energy Policy: A Rationale for Selective

Conservation,” Energy Policy (August 1989), pp. 397-406. 39Ronald H. Coase, “The Problem of Social Cost,” The Journal of Law and Economics (October 1960), pp. 1-44.

8 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
Other economists recommend—in the tradition of

Pigou—that externalities associated with power generation be internalized. The term internalizing an

externality implies the creation of social conditions

where the damages (or benefits) from production and

consumption are taken into account by those who produce the effects. These social conditions can be created

by government regulation, a tort system, bargaining

between private parties, or other policy and institutional arrangements. A taxonomy of alternative

methods, including, for example, some form of tradable

emission permit system, will be discussed in the next

chapter. Note, however, that benefits and damages can

exist even when all externalities have been internalized.

Classification of Externalities in Power

Generation

Externalities attributable to electric power generation

may be classified in the following categories:40

• Air pollutants including sulfur dioxide, nitrogen

oxides, particulates, and heavy metals with impacts on human health, flora and fauna, building

materials, and on other social assets like recreation

and visibility

• Greenhouse gases including carbon dioxide,

methane, and chlorofluorocarbons suspected of

contributing to global climate change and thus to

potential impacts on agriculture and human

health

• Water use and water quality affected by electricity production, principally through thermal

pollution or hydroelectric projects that affect

aquatic populations

• Land use values affected by power plant sitings

and by waste disposal including solid, liquid, and

nuclear wastes.

It is possible to provide a different or an enlarged

version of externalities’ classification based on the

choice of criteria used in the process.41 Note that the

types of electric facilities and their functional roles

differ considerably from one to the other. Consider, for

example, the impacts caused by a hydroelectric power

plant in comparison to a pumped storage facility or, for

that matter, two identical plants located in areas with

different population densities or social infrastructures.

The environmental problems posed by each of these

power plants differ and so will their impacts. The task

of classifying externalities is further complicated by the

absence of a complete checklist of applicable Federal,

State, and local environmental laws that relate to all

aspects of the electric power industry.42 For these

reasons, a simplified classification scheme is desirable.

The Economists’ Approach

Economists’ interests focus on the creation of a social

arrangement that (in the presence of externalities) can

be relied upon to bring about an optimal allocation of

resources and thus a maximization of welfare. While

some adjustments may be cost free and are a possibility, it is the “common-property resources” that do

not lend themselves to simple solutions. The prescription to embody a set of Pigouvian taxes (subsidies) on

the generators of externalities to induce them to take

into account the full range of social costs (benefits) may

not necessarily be an ideal solution that can be universally applied. The general consensus seems to be that

no single device such as a tax will eliminate the divergences caused by externalities in private and social

costs.43 Moreover, the application of even well-defined

economic principles often faces problems in practice.

Moving away from theory into the realm of policymaking, there are many approaches that have been

adopted. Regulatory framework may first involve

setting environmental standards or targets for different

pollutants and then proceeding to install implementation strategies similar to the provisions of the Clean

40Federal Energy Regulatory Commission, Report on Section 808: Renewable Energy and Energy Conservation Incentives of the Clean Air Act

Amendments of 1990 (Washington, DC, December 1992). 41A recent publication lists 12 categories of environmental categories impacting on: (i) agricultural crops, timber, and livestock,

(ii) catastrophic accidents, (iii) ecosystems and biodiversity, (iv) environmental-cultural icons, (v) global climate change, (vi) human

morbidity and mortality, (vii) land use, (viii) materials, (ix) recreational opportunities, (x) regional economic structure, (xi) visibility, and

(xii) visual and audio aesthetics. See National Association of Regulatory Utility Commissioners, Environmental Externalities and Electric

Utility Regulation (Washington, DC, September 1993), p. 10. It is even possible to enlarge this listing if the classification scheme is based

on the criteria of impacts. 42Congressional Research Service, Electricity: A New Regulatory Order, A Report Prepared for the Use of the Committee on Energy and

Commerce, U.S. House of Representatives (U.S. Government Printing Office, Washington, DC, 1991), p. CRS-213. 43Ronald Coase, “The Problem of Social Cost,” Economics of the Environment: Selected Readings, Eds. Robert Dorfman and Nancy S.

Dorfman (W.W. Norton and Co., New York, 1977), pp. 142-171.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 9
Air Act Amendments of 1990. In some cases, a tax/

subsidy approach could be an option to promote the

entry of certain technologies like renewables. These and

other approaches are discussed in the next chapter. To

conclude, there exists an increasing awareness of the

environmental problems caused by power generation.

There is, however, a lack of consensus regarding what

really constitutes a coherent cost-benefit accounting

framework that could facilitate the adoption of some

common approach. These problems are discussed elsewhere in this report.

10 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
3. Environmental Externalities in Power Generation and

the Regulatory Approach

This chapter presents a broad overview of power generation externalities and the environmental regulatory

framework in which the electric utilities operate.44

Major Federal environmental laws that are applicable to

power generation are identified and described in this

chapter.45 Against this backdrop, the chapter discusses

various approaches—conceptual and operational—that

can be taken into account to incorporate environmental

externality costs into electric utility resource selection

processes. Relative advantages and disadvantages of

these approaches are also indicated.

Electric Utilities and the Regulatory

Framework

Historically, regulation of electric utilities has entailed

a coordinated division of Federal and State jurisdictions

with the result that the area of regulatory control

exercised by each of them has been delineated.46 Over

time, many events have shaped the evolution of the

regulatory format as it currently exists.

A complete discussion of the various nuances of

regulatory oversight at the Federal and State levels

(including its weaknesses and strengths) is outside the

scope of this chapter. State regulation is particularly

difficult to summarize even though, in many cases, it is

similar to Federal regulation. The principal difference

lies in the scale of regulation and the jurisdictional

scope exercised by each State regulatory authority.

Generally speaking, Federal regulation “followed State

regulation and is premised on the need to fill the regulatory vacuum resulting from the constitutional inability of the States to regulate interstate commerce.”47

To get an overview of the regulatory composition, one

possible classificatory scheme is to split the prevailing

regulatory design in two separate but interrelated areas,

depending on the purely economic or noneconomic

character of issues. Economic regulation includes

subjects like regulation of financial transactions; rate

regulation (including prudence reviews and other

issues); regulation of interconnection, wheeling, and

transmission; adequate service obligations, including

reliability; antitrust issues; and, currently, a myriad of

issues confronting the utilities after the passage of the

Energy Policy Act of 1992. Noneconomic issues also

have several elements. Some of these are: nuclear

power plant licensing, spent nuclear fuel and storage,

low-level radioactive waste disposal, and environmental

regulation that includes clean air, clean water, and

others.48

The listing above is not fully comprehensive but is

merely indicative of the extent of the scope of regulations. Both economic and noneconomic regulatory

activities are handled either at the State or at the

Federal level. Thus, subjects like rate regulation or

prudence hearings, which are singularly economic in

nature, fall within the sphere of States’ activity, while

mergers and acquisitions and/or interstate sales fall

44Following general practice, the term “regulation” used in the text includes laws that engender State and Federal regulations.

Accordingly, the terms “regulation” and “law” are used interchangeably. 45All States play a role in regulating various aspects of the environment (including power generation) within their jurisdictions.

However, a centrally codified version of existing State statutes that apply specifically to power generation is not readily available. 46Note that despite attempts to delineate jurisdictional areas between the States and the Federal regulatory authorities, differences do

occur as in the recent case between the Federal Energy Regulatory Commission and the Public Service Commission of the State of

California relative to integrated resource planning. See Independent Power Report, “IEP Will Ask FERC To Rehear Ruling Against

California’s BRPU Auction,” March, 1995, pp. 5-6. More recently, a Supreme Court decision expanded States’ authority over licensing

of hydroelectric projects by broadening their authority under the Clean Water Act. The decision brought forth protests from the

supporters of public power. See Public Power Weekly, “APPA, others urge Congress to clarify that FERC, not state regulators, has the final

say over hydro project,” March 6, 1995, p. 3. 47For a detailed discussion, refer to U.S. Congress, Committee on Energy and Commerce, Electricity: A New Regulatory Order? 102nd

Congress, 1st Session, Committee Print 102-F (Government Printing Office, Washington, DC, June 1991), pp. CRS-125 – CRS-235. 48Note that the division of regulatory activities into economic and noneconomic compartments is arbitrary since all regulatory actions

have financial consequences. The classification stated above has been abstracted from the report cited in the previous footnote.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 11
within the jurisdiction of Federal agencies. The same is

true of noneconomic regulations. Environmental regulation (which includes consideration and treatment of

environmental externalities) is essentially treated as a

major form of noneconomic regulation. Its implementation, however, has significant economic impacts on

the industry.

Environmental Externalities

in Power Generation

Environmental costs of power generation can be quite

significant if the accounting framework is designed to

incorporate various costs and benefits with respect to

the production and consumption of energy from each

fuel source used in power generation. Both upstream

and downstream externalities that emerge in the process of securing fuels for power generation, however,

are usually not included in the regulatory framework

that directly affects electric utilities.

Examples of upstream and downstream externalities

can be cited for nearly all conventional fuels, i.e., coal,

oil, natural gas, nuclear, and hydroelectric power.49

Upstream externalities for coal include mining and surface reclamation. Oil and natural gas use have issues

associated with drilling, pipelines, and spills.50 Hydroelectric power is associated with flooding, erosion, and

loss of aquatic life in addition to possible curtailment of

aesthetics and a loss of habitat for certain species.

Downstream externalities are associated with landfills/ash disposal, climate change (or global warming

potential), acid rain, transmission lines (electromagnetic

fields), and siting. Nuclear power generation has the

potential for serious accidents, besides problems with

mining, surface reclamation, and waste disposal.51

Recently, various studies have taken into account externalities (i.e., damages and benefits) associated with each

fuel cycle in power generation. A fuel cycle is the series

of physical and chemical processes and activities required to generate electricity from a specific fuel or

resource, including primary resource extraction and

preparation, transport and storage of resources and

materials, processing and conversion, and disposal.52

As an example, typical environmental interactions attributable to the coal fuel cycle for electricity production are given in Figures 1a, 1b, and 1c.

Environmental costs from the front end of the fuel cycle

(mining, milling, drilling, beneficiation, fuel processing,

equipment manufacturing, fuel transportation to site,

etc.) do not directly devolve on the electric utilities,

however. Therefore, impacts (or externalities as stated

above) that are a part of the complete fuel-cycle

approach are not normally taken into account when

considering power generation per se. Instead, the current regulatory endeavors are to control some of the

externalities directly related with power generation at

various plants/sites.53 Nonenvironmental externality

costs and other externalities whose valuation is a

problem have additionally been excluded from the prevailing regulatory framework.54

Despite the large exclusionary zones as indicated above,

there are still significant areas covered by the regulatory treatment of externalities. In the main, these focus

on the emissions into the air or water at the electric

utilities.

As indicated earlier, the process of burning fossil fuels

in power generation brings about emissions that pollute

the atmosphere. Among these, the more important

gases discharged into the atmosphere are sulfur dioxide

and nitrogen oxide. Carbon dioxide releases are

49Upstream externalities are those that arise before any fuel source is actually used in power generation. Downstream externalities are

associated with fuel consumption including plant siting and related issues (like the possibility of nuclear accidents at nuclear power plants

or the sudden bursting of a hydroelectric dam). Both these categories describe the negative impacts of power generation. Positive

externalities are also associated with power generation. Included in this category are: impacts on quality of life; enhanced opportunities

for employment; increases in productivity, competitiveness, and output; and contributions to national security. 50It is important to note that large portions of these damages in the coal, oil, and natural gas cycles are internalized.

51For additional details, see Electricity Consumers Resource Council, Profiles in Electricity Issues: Externalities (Washington, DC, October

1991), p. 6. 52Oak Ridge National Laboratory and Resources for the Future, U.S.-EC Fuel Cycle Study: Background Document to the Approach and Issues

(Oak Ridge, TN, November 1992), pp. 1-1 to 1-17. 53There is no implication that the externalities associated with production of various fuels are completely ignored. Environmental

regulations governing mining and the transportation of fuels do exist as do regulations pertaining to the disposal of mining wastes. To

the extent that these activities are not directly under the control of entities that are in the business of power generation, the related

regulations have been briefly stated but are not analyzed in this report. 54Some examples of nonenvironmental externalities of power generation are balance of payment effects and the national security costs

of oil imports. Examples where valuation poses a problem are increases in health care costs, damages to infrastructure in the public

domain, risk of nuclear proliferation, and global warming. See Pace University Center for Environmental Legal Studies, Environmental

Costs of Electricity (Oceana Publications, Inc., New York, NY, 1990), p. 17.

12 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
Figure 1a. Environmental Impacts Relative to the Fuel-Cycle Process

CO2 = Carbon dioxide.

SO2 = Sulfur dioxide.

NOx = Nitrogen oxide.

Source: Reproduced from Oak Ridge National Laboratory and Resources for the Future, U.S.-EC Fuel Cycle Study: Background Document to the Approach and Issues

(Oak Ridge, TN, November 1992).

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 13
Figure 1b. Environmental Impacts Relative to the Fuel-Cycle Process (Continued)

Source: Reproduced from Oak Ridge National Laboratory and Resources for the Future, U.S.-EC Fuel Cycle Study: Background Document to the Approach and Issues

(Oak Ridge, TN, November 1992).

14 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
Figure 1c. Environmental Impacts Relative to the Fuel-Cycle Process (Continued)

Source: Reproduced from Oak Ridge National Laboratory and Resources for the Future, U.S.-EC Fuel Cycle Study: Background Document to the Approach and Issues

(Oak Ridge, TN, November 1992).

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 15
considered to contribute to the global warming phenomenon.

Water pollution attributable to power generation includes thermal pollution, adverse impacts on fish populations or aquatic ecosystems, pollution of surface

water from coal storage piles, and waste water discharges from the plant.55

Federal Approaches to Handling

Environmental Externalities

Since the 1960s, the United States has witnessed

growing concern over the degradation of the human

environment. This concern has been expressed in

demands for measures to control or reverse damage

and improve the environment. The National Environmental Policy Act of 1969 (NEPA), the first major

Federal initiative, laid down new premises for U.S.

public policy in pursuing goals to protect the environment and to reduce pollution to nonthreatening levels.

This effort was followed by a spate of legislation in

other areas to improve the quality of the air we breathe

and the water we drink.56 Recently, the focus on

environmental issues has become even sharper due to

the potential for adverse climate changes resulting from

the impact of human activity.57

The determination and implementation of domestic

environmental policy can be viewed as a two-step

procedure. The first step is to set standards for environmental quality. This is done through a complicated

interactive legislative process which establishes the

criteria and the standards to be achieved.58 The next

step is for the designated administrative agencies to

define and implement the standards by developing regulations that establish procedures and address the steps

needed to put the legislation into practice. Disputes

concerning what needs to be done and/or how to do it

are resolved by judicial intervention, where necessary.

Determination of compliance procedures is critical since

related costs are passed through to various customer

classes.

Responsibilities for environmental control and oversight

(including evaluation, monitoring, and implementation

of regulations with respect to electric power generation)

are distributed among various agencies at the Federal

and State levels. Within the Federal Government, while

the Environmental Protection Agency (EPA) plays a

dominant role, the Nuclear Regulatory Commission

(NRC) and the Federal Energy Regulatory Commission

(FERC) have technology-specific regulatory roles.59

Generally speaking, the EPA oversees fossil-fuel generation, the NRC nuclear power plants, and the FERC

hydroelectric facilities.

Environmental regulations have a significant impact on

power generation since the costs of compliance are

passed on to the ratepayers/consumers as part of the

ratemaking process. Major Federal environmental laws

affecting the electric power industry are summarized in

Table 2. The three most significant are:

• The National Environmental Policy Act of 1969,

which requires all Federal agencies to undertake

the preparation of an environmental impact

statement prior to the construction of new nuclear,

hydroelectric, and, at times, fossil-fired power

plants and high voltage transmission lines

• The Clean Air Act of 1963 as amended in 1970,

1977, and 1990, which regulates the emissions of

particulate matter, sulfur dioxide, nitrogen oxides,

carbon monoxide, ozone, and lead from fossilfired power plants

• The Federal Water Pollution Control Act of 1972,

amended by the Clean Water Act of 1977, which

regulates the use and discharge of water by power

plants through required operating permits.

There are other laws, at both the Federal and State

levels, that affect—directly or indirectly—the operations

55Pace University Center for Environmental Legal Studies, Environmental Costs of Electricity (Oceana Publications, Inc., New York, NY,

1990), p. 280. 56An alternative view is that the environmental regulation of the electric utility industry serves the dual purpose of minimizing harm

to human health and environment and simultaneously securing public consent for necessary development. See Peter Huber, “Electricity

and Environment in Search of Regulatory Authority,” Harvard Law Journal (1987), pp. 1002-1065. 57At the Earth Summit in Rio de Janeiro, Brazil, in 1992, the United States joined 160 other countries in signing the Framework Convention

on Climate Change to address the danger of climate change resulting from increasing concentrations of greenhouse gases, especially carbon

dioxide, methane, and nitrous oxides. See U.S. Department of Energy, The Climate Change Action Plan: Technical Supplement (Washington,

DC, March 1994). 58It is also possible that in this “command-and-control” approach, the regulatory authorities may mandate the use of specific control

technologies to attain the desired levels of performance. 59Other Federal agencies like the Department of the Interior or the Army Corps of Engineers also have a role. This is not discussed

here.

16 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
Table 2. Major Federal Environmental Laws Affecting Electric Utilities

Legislation Brief Description of Impacts on Electric Utilities

The Federal Power Act of 1920

(amended by the Electric Consumers Protection

Act of 1986)

The Federal Power Act (FPA) provides the Federal Energy Regulatory

Commission (FERC) with exclusive authority to license non-Federal

hydroelectric power projects on navigable waterways and Federal lands.

The Electric Consumers Protection Act amended the FPA in 1986 and

required FERC, during its licensing/relicensing activities, to accord equal

consideration to environmental aspects of hydroelectric facilities in

addition to an evaluation and determination of a number of other factors

like power development and public interests. Environmental

considerations include the protection, mitigation of damage to, and

enhancement of fish and wildlife; the protection of recreational

opportunities; and the preservation of other aspects of environmental

quality.

The Federal Water Power Act of 1920 The Federal Water Power Act authorized the Federal Power

Commission, the precursor agency of FERC, to license certain

hydroelectric projects that are best adapted to the comprehensive

development of a waterway. The FERC’s responsibilities in regard to

overseeing the development of U.S. water resources were broadened

under later legislation including: the Flood Control Act of 1938 and

subsequent Flood Control Acts; the River and Harbor Act of 1945 and

subsequent River and Harbor Acts; and the Water Resources Planning

Act of 1965.

The Fish and Wildlife Coordination Act of

1934

(amended in 1946, 1948, 1958, and 1965)

The Fish and Wildlife Coordination Act requires that a Federal agency

licensing a “water resource development project” consult with and give

full consideration to the recommendations of the Fish and Wildlife

Service under the Department of the Interior. In addition, FERC must

include conditions in each license for the protection, mitigation of

damage to, and enhancement of fish and wildlife.

The Atomic Energy Act of 1954

(amended by the Energy Reorganization Act of

1974)

The Atomic Energy Act (AEA) was first enacted after World War II to

give the Federal Government direct control over the development of

nuclear power. Congress revised the Act in 1954 to allow for licensing

private facilities. The regulation of power plant licensing and siting under

the AEA presents significant public policy and legal issues.

Environmental and safety considerations are an important element of the

licensing process for nuclear power plants. This regulatory responsibility

was transferred to the Nuclear Regulatory Commission (NRC) in 1974

when Congress enacted the Energy Reorganization Act, which abolished

the Atomic Energy Commission. The NRC has the responsibility for

licensing and monitoring nuclear reactors and waste facilities, inspecting

nuclear facilities, and investigating nuclear accidents.

The Clean Air Act of 1963

(amended in 1967, 1970, 1977, and 1990)

The 1963 Clean Air Act (CAA), as amended, established a major

regulatory system to protect and enhance the Nation’s air that is directly

applicable to conventional electric power generation facilities. National

ambient air quality standards were put into effect for particulate matter,

sulfur dioxide, nitrogen dioxide, carbon monoxide, ozone, and lead. Of

these, particulate matter, sulfur dioxide, and nitrogen dioxide are emitted

in significant quantities by coal-fired electric power plants. The 1990

amendments to the CAA in large part were intended to meet

unaddressed or insufficiently addressed problems such as ground level

ozone, stratospheric ozone depletion, air toxins, and acid rain, the last of

which was directly addressed through the Acid Rain Program.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 17
Table 2. Major Federal Environmental Laws Affecting Electric Utilities (Continued)

Legislation Brief Description of Impacts on Electric Utilities

The Wild and Scenic Rivers Act of 1968 The Wild and Scenic Rivers Act prohibits FERC from licensing

construction of any project under the Federal Power Act “on or directly

affecting” a wild and scenic river. In addition, it limits the power of any

Federal agency to assist in the construction of any “water resources

project” having a “direct and adverse effect on the values” for which the

river was designated as wild and scenic.

The National Environmental Policy Act of

1969

(amended in 1975 and 1982)

The National Environmental Policy Act of 1969 (NEPA) requires all

Federal agencies to prepare a “detailed statement” for proposed major

actions which significantly affect the quality of the human environment.

This statement, called an “environmental impact statement (EIS),” must

include environmental impacts of the proposed action, alternatives to the

proposed action, and any adverse environmental impacts which cannot

be avoided should the proposal be implemented. Thus, in effect, where

a permit or a license is required for the construction of power plants or

associated facilities under Federal law, an EIS is usually necessary. The

NEPA does not include all actions taken by electric utilities. It may

exclude, for example, the construction of fossil-fuel plants. However, the

EIS process may still be triggered if such plants involve Federal approval

of any related matter.

The Endangered Species Act of 1973 The Endangered Species Act of 1973 provides a program for the

preservation of threatened plants, fish, and wildlife and the habitat in

which they are found. The building of dams for hydroelectric power

generation can disrupt the ecological environment and, therefore, must

adhere to regulations under this Act.

The Safe Drinking Water Act of 1974 The Safe Drinking Water Act of 1974 (SDWA) specifies that any

business that has 25 or more employees and is not on a public water

system must assure that its source of drinking water complies with

certain primary health-related standards.

The Toxic Substances Control Act of 1976 The Toxic Substances Control Act of 1976 (TSCA) requires proper

disposal of polychlorinated biphenyls (PCBs) and prohibits their

manufacture, processing, distribution in commerce, and use in other than

a totally enclosed manner. PCBs were used for many years in electrical

equipment, i.e., in the dielectric fluid used in transformers. The

Environmental Protection Agency (EPA) subsequently adopted rules

governing the marking and disposal of PCBs, and adopted regulations

prohibiting and restricting their continued use. Although a number of

statutes regulated chemicals after they had become “wastes” or

“discharges,” no legislation regulated hazardous and toxic substances

(other than those used in food or drugs) before they were wastes. TSCA

empowers EPA to manage the manufacture and use of toxic substances.

TSCA also allows EPA to monitor new or existing chemicals that pose an

unreasonable risk to health or the environment.

18 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
Table 2. Major Federal Environmental Laws Affecting Electric Utilities (Continued)

Legislation Brief Description of Impacts on Electric Utilities

The Resource Conservation and Recovery

Act of 1976

(extensively amended by the Hazardous and

Solid Waste Amendments of 1984)

The Resource Conservation and Recovery Act of 1976 is a statute

designed to provide “cradle-to-grave” control of hazardous waste by

imposing management requirements on generators and transporters of

hazardous wastes and upon the owners and operators of treatment,

storage, and disposal facilities. The disposal of certain waste by electric

utilities may be subject to provisions of this Act. The utilities must

comply with a set of standards authorized under this Act, including

handling wastes properly and preparing manifests to track the shipment

of the waste to treatment, recycling, or disposal facilities. EPA’s

regulations automatically exempt utility wastes from coal combustion

from being considered hazardous wastes.

The Clean Water Act of 1977

(amendment to the Federal Water Pollution

Control Act of 1972)

States were responsible, before 1970, for setting their own water quality

standards. Congress, however, in 1972, established the Federal Water

Pollution Control Act. Congress, in 1977, modified the Act to deal with

other pollutants, and renamed it the Clean Water Act (CWA). The CWA

established a system for setting national effluent standards for pollutant

discharges and a national water discharge permit program. The CWA

affects various types of electric power facilities in a significant way. Use

of large amounts of water for steam to drive turbines, for cooling, and for

process uses in conventional power plants and nuclear power plants

raises potential water issues. Similarly, the proximity to and dependence

of hydroelectric facilities on flowing water as a source of power also raise

potential water issues. Thus, electric power facilities can be subject to

various obligations including requirements to obtain operating permits

and to meet best available technology standards to minimize adverse

environmental impacts.

The Comprehensive Environmental

Response, Compensation and Liability Act of

1980

(also referred to as Superfund)

Electric utilities are among many business establishments that are

subject to reporting requirements for spills and other kinds of

environmental releases under the Comprehensive Environmental

Response, Compensation and Liability Act of 1980. Utilities must report

any release of any hazardous substance that exceeds the reportable

quantity for that substance (defined in Title 40 of the Code of Federal

Regulations) into the air, surface water, groundwater, or soil.

The Nuclear Waste Policy Act of 1982 The Nuclear Waste Policy Act of 1982 (NWPA) specifies that, while the

Federal Government has the responsibility to provide for the disposal of

high-level radioactive waste and spent nuclear fuel in order to protect

public health and safety and the environment, generators and owners of

the waste and spent fuel have the primary responsibility to provide and

pay for its interim storage. It also establishes procedures for disposal

site selection, licensing, construction, closure, decommissioning, interim

storage licensing, and retrieval of any spent nuclear fuel for reasons

associated with public health and safety, the environment, or the

recovery of the economically valuable contents of the spent fuel.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 19
Table 2. Major Federal Environmental Laws Affecting Electric Utilities (Continued)

Legislation Brief Description of Impacts on Electric Utilities

The Energy Policy Act of 1992 The Energy Policy Act of 1992 (EPACT) contains various environmental

provisions with respect to global warming issues. While there are no

mandatory requirements affecting electric utilities, voluntary reporting of

greenhouse gas emissions and reductions will be used by the

Department of Energy (DOE) to develop an inventory of the national

aggregate emissions of each greenhouse gas for each calendar year of

a baseline period. This inventory will be updated and analyzed annually.

EPACT also requires DOE to study and implement water conservation

measures at Federal water projects to provide more water for fish and

wildlife. In addition, EPACT contains numerous provisions designed to

foster development of renewable energy technologies that contribute little

to smog, acid rain, or greenhouse gas emissions.

The Wilderness Act of 1964

The Historic Preservation Act of 1968

The Water Quality Improvement Act of 1970

The Coastal Zone Management Act of 1972

The Federal Land Policy and Management

Act of 1976

Potential hydroelectric power generation projects may be constrained by

these miscellaneous laws if certain associated environmental regulations

apply.

Note: • Following general practice, the term “regulation” used in this table includes laws that engender Federal regulations.

Accordingly, the terms “regulation(s)” and “law(s)” are used interchangeably. • This section is based on information compiled from

various documents including Congressional Quarterly and the Environmental Law Reporter as well as others published by the

following organizations: the Environmental Protection Agency, the Congressional Research Service, Government Institutes, Inc.,

the Environmental and Energy Institute, the Environmental Law Institute, the Council on Environmental Quality, and the Federal

Energy Regulatory Commission.

of electric power generation. Certain categories of

wastes, such as the sludge from flue gas desulfurization

equipment at coal-fired plants, may be subject to the

provisions of the Resource Conservation and Recovery

Act of 1976 that require treatment of hazardous wastes

from “cradle to grave” and set forth a framework for

the management of nonhazardous solid wastes. The Endangered Species Act may affect siting or operation of

power plants such as wind facilities or hydroelectric

plants. The Electric Consumers Protection Act requires

FERC to consider specific environmental values in

making hydroelectric license determinations. Other

regulations like the Surface Mining Control and Reclamation Act of 1977 are directed toward coal mining

operations, while the Uranium Mill Tailings Radiation

Control Act of 1978 deals with mill tailings left behind

during the milling and mining stages of uranium recovery. Disposal of polychlorinated biphenyls is governed by the Toxic Substances Control Act of 1976.

The Energy Policy Act of 1992 (EPACT) contains

various environmental provisions addressing global

warming issues and reinforcing the authority vested in

FERC to require the construction of “fishways” in

hydroelectric power facilities. Title XVI of EPACT contains provisions on the subject of global warming

including requirements to assess alternative policy

mechanisms for addressing emissions of heat-trapping

“greenhouse gases,” creation of a greenhouse gas inventory (and issuance of guidelines for gathering

voluntarily collected data on greenhouse emissions),

carrying out an innovative environmental technology

transfer program, and development of a least-cost

strategy for future national energy plans.

It should be noted that Federal regulations do not by

themselves provide a prescription for handling externalities in any systematic manner. Rather, the Federal

actions greatly rely on a “command-and-control”

system of environmental regulations implicit in the

Clean Air Act Amendments prior to 1990 that sought to

restrict (or raise the cost of) use of the environment as

a repository for emissions. In this approach, the emphasis is on control rather than on prevention. More

recently, environmental regulations indicate a shift

toward market-based approaches that tend to contain

pollution within specified limits.60

60For additional information, see Energy Information Administration, “Environmental Externalities in Electric Power Markets,” Electric

Power Monthly, to be published in the fall of 1995.

20 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
For example, the provisions of the Clean Air Act

Amendments of 1990 (CAAA) require the Environmental Protection Agency (EPA) to establish the Acid Rain

Program, which in turn requires the utilities to

substantially reduce their emissions of sulfur dioxide

and nitrogen oxides. To achieve a predetermined level

of emissions, the CAAA uses market licenses (allowances) as opposed to regulations that specify actions to

be undertaken. Utilities are, therefore, endowed with

considerable operational flexibility since it is the total

quantity of emissions that matters and a utility can

achieve its target level through emission controls, fuel

switching, conservation programs, or by buying or

trading allowances.61 Within this market-oriented

framework, energy efficiency, conservation programs,

or demand-side management programs all have a role

to play.

Other areas of Federal regulation also include hydroelectric licensing; water pollution; and nuclear plant

construction, operation, maintenance and decommissioning, including disposal of radioactive waste. To the

extent that most of these Federal actions result in added

costs to the utilities, they may be construed as ways of

incorporating and internalizing costs even though not

all damages are completely eliminated.62

In addition to Federal regulatory requirements, participation in environmental efforts may also be voluntary.

Initiatives proposed under the Climate Change Action

Plan are designed to voluntarily reduce emissions of

greenhouse gases that contribute to global warming.63

Some efforts by electric utilities are voluntary in nature.

Observed results of the voluntary cooperation indicate

a noteworthy level of success without any specific

legislative authority.64

State Approaches to Handling

Externalities

Not all States take externality considerations into

account. As will be discussed in Chapter 7, slightly

over half the States consider externalities, either

qualitatively or quantitatively. From among these

States, the requirement to include externalities (in the

resource selection process) by using monetary values is

applicable only in seven States.65 These States attempt

to incorporate the externality costs of power generation.

Their undertakings, however, do not aim to achieve the

optimal regulation that may become necessary if all

stages of a fuel cycle were to be taken into account.66

Rather, their efforts are limited to possible investment

choices that utilities need to make when considering

additions to capacity.

“Integrated Resource Planning” (IRP) is the vehicle

generally used to evaluate future resource requirements. Within the context of the IRP process, the scope

of utility resource planning has broadened significantly

from its earlier focus on augmenting primarily supplyside options. Demand-side methods (like conservation

and efficiency improvements, load shifting/management) and non-traditional supply options (like

renewables, cogeneration, and output from qualifying

facilities) all now have to be considered in the process

61For a detailed discussion of the compliance strategies for control of emissions, see Energy Information Administration, Acid Rain

Compliance Strategies for the Clean Air Act Amendments of 1990 (Washington, DC, March 1994), pp. 13-39. 62The Pacific Northwest Electric Power Planning and Conservation Act of 1980 is different from most of the other Federal legislative

enactments. Its statutory requirements stipulate that a cost-effective methodology for determining environmental costs be submitted and

that conservation resources be accorded a 10-percent advantage over traditional resources. 63The Climate Change Action Plan (The Plan) issued by President Clinton on October 9, 1993, provides a road map by which the United

States can meet greenhouse gas reduction commitments. The primary objectives of this Plan aim to return U.S. greenhouse gas emissions

to 1990 levels by 2000 with cost-effective domestic actions. See U.S. Department of Energy, The Climate Change Action Plan (Washington,

DC, October 1993). Current analysis indicates that these objectives may not be attainable by the end of this decade. 64The “Climate Challenge” program initiated by the Department of Energy (DOE) and electric utilities is a good example of

participation by electric utilities in voluntary environmental efforts. On April 20, 1994, the DOE and five organizations representing

hundreds of electric utilities executed a memorandum of understanding (MOU) in which the utilities made voluntary commitments to

reduce greenhouse gas emissions. The collaborative program envisaged in the MOU is similar to EPA’s 33/50 voluntary cooperation

program with the industrial sector (initiated in 1991) to reduce releases of toxic chemicals—33 percent by 1992 and 50 percent by 1995.

See Sheryl Sturges and Jeffrey Hewitt, “Progress of a Policy Experiment: Climate Challenge Interim Report Card,” Electricity Journal

(January/February 1995), pp. 60-70. The authors contend the utilities have taken the “Climate Challenge” program seriously and that

significant results can be expected. 65These States are: California, Massachusetts, Minnesota, Nevada, New York, Oregon, and Wisconsin. Massachusetts, however, will

not use externality values in the future due to a decision given by the State Supreme Court in December 1994. 66A fuel cycle may be defined “as the series of physical and chemical processes and activities that are required to generate electricity

from a specific fuel or resource.” Based on this definition, the fuel cycle has the following elements: primary resource extraction and

preparation, transport and storage of resources and materials, conversion and processing, end-use services, and disposal. See Oak Ridge

National Laboratory, U.S.- EC Fuel Cycle Study: Background Document to the Approach and Issues (Oak Ridge, TN, November 1992), pp. 1-1

to 1-17.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 21
of determining how to meet future demand for electricity and capacity. Along with this new focus in

comparing supply-side and demand-side management

cost options on a consistent basis, an extension of this

planning process further includes consideration of environmental externality costs attributable to electricity

generation in comparing the cost of the resource

options.67

Regulators view the requirements that utilities consider

externalities in their comparisons of all supply-side and

demand-side options as analogous to providing a level

playing field to both sources. Accordingly, the approach to incorporating externalities within the IRP

process is grounded in the belief that power generation

imposes substantial environmental and societal burdens

that are not taken into account either in the traditional

least-cost planning and resource selection process or by

the prevailing regulatory controls. Another compelling

argument is the real possibility that environmental

controls will tend to become more stringent in the

future. Prudence, therefore, dictates that externality

considerations be taken into account at the time of

resource selection to avert the possibility of incurring

significant financial costs at a future date, given the 30-

or 40-year life span of power plants.

Regulatory support for including externality considerations in the planning process is further bolstered by the

expectation that inclusion (or internalization) of

environmental externalities in social costs may accelerate the penetration of renewables and demand-side

management options on a competitive basis. In fact,

recent developments associated with potential global

warming and climate changes may tend to accelerate

acceptance of renewable technologies if externality

considerations are extended to include all stages of a

fuel cycle with respect to a resource being used in

power generation.

Identification, valuation, and determination of environmental externality costs represent a set of controversial

issues which have not yet been fully resolved. The

initial conceptual framework to include externality costs

in power generation attempted to encapsulate essentially those externalities (or damages) that could

directly be attributed to power generation. As a result,

the role of the State regulatory authorities is rather

limited in its scope and does not really require the

utilities to fully internalize environmental costs in their

entirety.68

In other States that do not consider externalities, lack of

legal authority or lack of agreement on how to go about

it are the two principal reasons. Absence of reliable estimates of environmental damages may be another. It is

possible that the number of such States and of those

that use qualitative assessments may change in the

future.

Strategies for Valuation of Externalities

There is a lack of consensus in the literature in adopting a classification scheme that can encompass all

approaches currently employed by the States for calculating external costs. This diversity in taxonomical

representation is not indicative of fundamental differences in coverage but reflects preferences used to

describe more or less the same subject matter.

For example, one study identifies two basic approaches

to calculating external costs: “direct damage estimation”

and “cost of abatement.”69 Direct damage estimation

implies the feasibility of undertaking a monetary

67As defined in the Energy Policy Act of 1992, the term “integrated resource planning” means, in the case of an electric utility, a

planning and selection process for new energy resources that evaluates the full range of alternatives, including new generating capacity,

power purchases, energy conservation and efficiency, cogeneration and district heating and cooling applications, and renewable energy

resources, in order to provide adequate and reliable service to the customers at the lowest system cost. The term “system cost” means

all direct and quantifiable net costs for an energy resource over its available life including the cost of production, distribution,

transportation, utilization, waste management, and environmental compliance. 68The term “internalization,” although used commonly, remains undefined. One definition of “internalizing an externality” implies

the creation of “social conditions where damages (or benefits) from production and consumption are taken into account by those who

produce these effects. These social conditions can be created by government regulation, a tort system, bargaining between private parties,

or other policy and institutional arrangements. Benefits and damages can exist even when all externalities have been internalized.”

Another definition states that “internalization of externalities does not mean there are no environmental costs borne outside the utility

and its ratepayers. Instead, the utilities and its customers must pay for the environmental resources they consume, just as they pay for

concrete, labor and other inputs to the production of electricity.” Both these definitions are extensive in their coverage. See Oak Ridge

National Laboratory and Resources for the Future, U.S.- EC Fuel Cycle Study: Background Document to the Approach and Issues (Oak Ridge,

November 1992), p. xii, and National Association of Regulatory Utility Commissioners, Environmental Externalities and Electric Regulation

(Washington, DC, September 1993), p. 25. 69Lawrence Berkeley Laboratory, Energy and Environment Division, Comparative Analysis of Monetary Estimates of External Environmental

Costs Associated with Combustion of Fossil Fuels, Report # LBL-28313/UC-310 (Berkeley, CA, July 1990), p. 5.

22 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
valuation process with respect to the damage caused by

a given pollutant. Cost of abatement takes into account

the cost of pollution controls for a given pollutant.70 In

both these approaches, the value of reducing each

externality is monetized.

Another study identifies three valuation strategies:

“direct cost estimation,” “indirect cost estimation,” and

“contingent valuation.”71 Direct cost estimation is similar to the direct damage estimation technique discussed

above. The indirect cost estimation approach is used

where exact cost identification is a problem and an

indirect pricing (or hedonic) approach is used.72

The contingent valuation approach utilizes surveys and

controlled experiments to ascertain how various attributes are valued. All these methods offer different

ways of estimating damages.

It is possible to combine most current approaches into

broad generic approaches.73 In the process, specifics

tend to be masked and boundaries begin to overlap.

Accordingly, it is preferable to adopt a version that

provides more rather than less detail.

Seven main approaches have recently been identified

for addressing environmental externalities within the

integrated resource planning framework.74 These are:

• Qualitative Treatment

• Weighting and Ranking

• Cost of Control

• Damage Function

• Percentage Adders

• Monetization by Emission

• Multi-Attribute Tradeoff Analysis.

Qualitative Treatment

A number of State regulatory authorities currently

require utilities to adopt some kind of “qualitative”

consideration regarding the environmental impacts of

resource options without specifying any quantitative or

accounting mechanisms.75 This approach requires environmental impacts to be described and considered

when making choices, based on informal and flexible

assumptions. The impacts on several factors (with

perhaps several elements in each factor) such as health,

safety, reliability, environment, and others may be

taken into account. The impacts may be described in

descriptive terms like no impact, moderate, or significant impact.

The rationale for adopting the above procedure stems

from the difficulty of quantifying impacts, especially

when there is no agreed upon set of values for

adoption. An alternative explanation is the absence of

statutory or judicial authority to impose quantification

of externalities. These methods, it is maintained, lack

specific standards by which to compare options,

making it difficult “to assess exactly what effect

externalities had on a particular decision, or to predict

what effect it (they) will have on the next decision.”76

Despite its shortcomings, the qualitative approach has

the merit of initiating a start with respect to the

inclusion of externalities (based purely on application

of subjective factors) in the planning process. However,

whether the qualitative approach can possibly send the

right price signals (to equate private and social costs)

remains ambiguous and constitutes its major drawback.

70Cost of abatement approach is similar to the valuation methods adopted in another study. See Paul Chernick and Emily Caverhill,

“Methods of Valuing Environmental Externalities,” The Electricity Journal (March 1991), pp. 46-53. 71Electric Power Research Institute, Environmental Externalities: An Overview of Theory and Practice, Report EPRI CU/EN-7294 (Palo Alto,

CA, May 1991), p. III-1. 72Economists term this approach “shadow pricing.” This is a concept applied to situations where the actual prices cannot be charged,

or where the actual prices charged do not reflect the real sacrifice made when some activity is pursued. As an example, the cost to society

of using an unemployed laborer is zero even though the laborer, if employed, will have to be paid a wage. Alternatively, in periods of

excess demand for labor, the shadow price is higher than the wage rate. 73The Special Report on Externalities released by the National Coal Council in 1992, for example, adopts a somewhat different (but still

a broad and generic) classification for establishing externality values. 74The classification described here is based on a recent study completed by the National Renewable Energy Laboratory for the U.S.

Department of Energy. See National Renewable Energy Laboratory, Issues and Methods in Incorporating Environmental Externalities into the

Integrated Resource Planning Process, Report No. NREL/TP-461-6684 (Golden, CO, November 1994), pp. 24-35. 75Based on a study undertaken by the Consumer Energy Council of America Research Foundation, 17 States have adopted this

approach. See Consumer Energy Council of America Research Foundation, Incorporating Environmental Externalities into Utility Planning

(Washington, DC, July 1993). 76Public Service Commission, State of Wisconsin, Staff Issue Paper: Externalities (Madison, WI, October 1991), p. 9.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 23
Weighting and Ranking

The “weighting and ranking” approach has been aptly

characterized as a hybrid between the qualitative

approach and the quantitative approach.77 The approach recognizes externalities and applies relative

scores to competing resources. The impacts can be

weighted based on an assessment of their relativeimportance, and options can be ranked for a given

impact category. By combining the two, a “score” can

be derived for each option. These scores (or

percentages) can be related to a dollar value for use in

the planning process. Thus, monetary values emerge

even though a subjective evaluation process is used in

the initial stages.78 Proponents of this approach claim

that the use of weighting and ranking offers flexibility

as externality values undergo absolute and relative

changes over time.79 In addition, an element of

transparency is introduced which facilitates a better

understanding of the process involved.

Critics point out that, because the resulting monetary

values result from multiple layers of subjectivity, comparisons among impacts or among utilities become

confusing. Evaluations of tradeoffs between economic

and environmental impacts also become difficult.80

Cost of Control

The “cost of control” approach looks at the cost (in

monetary terms) imposed by regulatory requirements

(current or anticipated) for controlling emissions or

other pollutants. An example is the requirement in the

Clean Air Act Amendments of 1990 for a reduction in

the levels of various pollutants resulting from the use

of fossil fuels. The related costs of controlling emissions

can be readily observed as a basis for deriving

monetized measures and can be viewed as a proxy in

a limited sense for damage control costs.

The same approach is also described in the literature

under differing labels: the abatement cost approach, the

revealed preference approach, and the implied valuation method. Of these, the abatement cost approach

comes closest to describing the cost of control approach.

This approach starts with the assumption that direct

damage costs can never be adequately estimated. If,

therefore, regulations are set “efficiently” to equate

environmental benefits with abatement costs at the

margin, then compliance costs are a proxy for damage

costs. Doubts have, however, been expressed concerning the requirement to meet the efficiency criteria.

Critics point out that there may be “reasons to believe

that environmental regulations may not be set at economically efficient levels.”81 In such cases, abatement

cost evaluation is a poor indicator of damages. In

addition, this approach may well harm or protect the

environment at far higher economic costs than are

necessary.

The revealed preference approach is based on the

“shadow pricing” concept used by economists. Economic theory uses this concept where actual prices

cannot be charged or where the actual prices charged

do not reflect the real sacrifice when some activity is

pursued, leading to an imputed value. This approach

assumes that the regulators’ choices embody society’s

preference for pollution control. As a result, this

approach holds that the marginal costs of mitigation,

control, or abatement may be used as a proxy for

society’s willingness to pay. Many studies question this

concept and its applicability on the grounds that economic regulation is far from efficient and that the

uniform application of marginal costs and benefits ignores variations among regions.

The implied valuation method is very similar to the

above approach and starts with the assumption that the

cost of required control measures provide a reasonable

indication of what society is willing to pay to reduce

pollution. For example, if the cost of reducing sulfur

dioxide emissions is $2.50/lb, then the value of reductions from alternative sources like conservation or

demand-side management should also be worth at least

the same amount.82

Despite the conceptual problems implicit in employing

the implied valuation approach, many regulatory

77National Renewable Research Laboratory, Issues and Methods in Incorporating Environmental Externalities into the Integrated Resource

Planning Process (Golden, CO, November 1994), p. 25. 78Public Service Commission, State of Wisconsin, Staff Issue Paper: Externalities (Madison, WI, October 1991), p. 10. 79State of Connecticut, Department of Public Utility Control, DPUC Investigation of the External Costs and Benefits Associated with Energy

Consumption (Docket # 92-09-29 of December 30, 1993), p. 25. 80Public Service Commission, State of Wisconsin, Staff Issue Paper: Externalities (Madison, WI, October 1991), p. 10. 81For a detailed evaluation of the abatement cost approach, see Oak Ridge National Laboratory, U.S.-EC Fuel Cycle Study: Background

Document to the Approach and Issues (Oak Ridge, TN, November 1992), pp. 2-9 and 2-10. 82Paul Chernick and Emily Caverhill, “Methods of Valuing Environmental Externalities,” The Electricity Journal, March 1991, pp. 46-53.

24 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
authorities continue to rely on this method. The Massachusetts Department of Public Utilities, for example,

maintains that using the implied valuation “is the best

available proxy at this time” even though problems

with this approach were duly recognized in its proceedings.83

Damage Function

In contrast with the approaches described above, the

“damage function” has economic theory as its basis.

The approach aims to determine the amount individuals are willing to pay to avoid a damage that

results from a pollutant or the compensation individuals are willing to accept in lieu of the damages.

The first two steps in this approach involve identifying

impacts and quantifying them. Next, economic values

are assigned to impacts that have been quantified and

are aggregated to provide a total impact cost or value.

Use of this approach is the preferred option in the

recently completed U.S.- EC Fuel Cycle Study for estimating externalities of fuel cycles for the following

reasons.84 First, the approach highlights how technological and locational factors influence residual damage

(and benefits). Second, utilization of information about

physical and behavioral processes to quantify impacts

and residual damages provides an essential scientific

building block that could be used elsewhere. Third, the

approach identifies gaps in understanding of the

problems involved. Finally, pollutant-specific information that becomes available as a result of using this

approach is useful for subsequent research, development, and planning.85

Computation of damage estimates is more complex

than other approaches and requires significant engineering, environmental, and economic data inputs. Data

are required to measure source emissions and to convert emissions into impacts, which need to be translated

into valuations by using standard economic techniques.

Of these, the first step using engineering techniques is

perhaps the simplest in some cases. There is, however,

no agreed-upon methodology for handling the last two

steps. The evaluation of impacts is measurable in some,

but not all, cases. Monetizing the impacts is also a

problem. Finally, adoption of the damage function

approach does not really provide a solution to all the

environmental issues nor can it quantify all environmental effects (climate change, biodiversity loss, etc.)

when scientific knowledge does not support reliable

quantification.

As a result, impact evaluation methods and the economic techniques used to value them continue to

remain controversial even though methods to estimate

the damages have “gained broader acceptance during

the last two decades as theoretical valuation issues have

been resolved and the body of literature pertaining to

specific applications has grown.”86

Despite the above drawbacks, the U.S.- EC Fuel Cycle

Study maintains that the damage function approach

used in conjunction with “policy judgments is superior

to throwing the entire externality debate open to judgment.”87 The Federal Energy Regulatory Commission

(FERC) also records its preference for using this

approach even though it fully recognizes the limitations. The FERC analysis states that the “limitations of

the damage function approach can be overcome with

current and future research, while alternative approaches are subject to inherent flaws that cannot be

improved through further research.”88

Percentage Adders

Operational difficulties implicit in evaluating the externality costs in other approaches explain the use of

“percentage adders” in some regulatory jurisdictions. A

predetermined fixed percentage is added to (or

83Massachusetts Department of Public Utilities (MDPU), Rules to Implement Integrated Resource Management Practices, Docket No. 89-239,

(Order dated August 30, 1991), p. 83. A subsequent review of this directive by the MDPU in 1992 reiterated adherence to this approach

and affirmed that the implied valuation approach “remained the most reasonable basis for public policy.” 84Oak Ridge National Laboratory and Resources for the Future, U.S. - EC Fuel Cycle Study: Background Document to the Approaches and

Issues (Oak Ridge, TN, November 1992). 85Oak Ridge National Laboratory and Resources for the Future, Estimating Externalities of Coal Fuel Cycle, Report No. 3 (Oak Ridge, TN,

September 1994), pp. 4-22 through 4-24. 86Oak Ridge National Laboratory and Resources for the Future, U.S.- EC Fuel Cycle Study: Background Document to the Approach and

Issues, Report No. ORNL/M-2500 (Oak Ridge, TN, November 1992), pp. 2-2 through 2-5. For an additional discussion of the damage

function approach, see RCG/Hagler Bailly, Inc., New York State Environmental Cost Study (Boulder, CO, 1994). 87Oak Ridge National Laboratory and Resources for the Future, U.S.- EC Fuel Cycle Study: Background Document to the Approach and

Issues, Report No. ORNL/M-2500 (Oak Ridge, TN, November 1992), pp. 2-2 through 2-5. 88Federal Energy Regulatory Commission, Report on Section 808: Renewable Energy and Energy Conservation Incentives of the Clean Air Act

Amendments of 1990 (Washington, DC, November 1992), p. 18.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 25
subtracted from) the avoided cost of a source option.89

The percent amount to be added may be determined by

law, judgment, or estimates of control or damage

costs.90 Note, however, that the adder is used primarily for the purpose of resource selection with

respect to the capacity additions needed in the future

and is not added to the direct cost of the resource once

it is selected.

The use of adders is supported because they are presumed to be large enough to lead to changes in the

resource plan by improving the relative cost effectiveness of renewable technologies and demand-side

management or conservation programs by implicitly accounting for the full costs of other supply-side options.

As a result, resources are selected “based on the lowest

unit costs plus adders.”91 The process could also be

used in the noncompetitive bidding resource procurement process. Care is taken to ensure that the value of

the adders is not that large so that distortions can be

caused. While this situation can be easily avoided, it

offers the use of adders an additional advantage that

revisions to their use can be made readily as more

experience is gained or better insight becomes available.

Proponents would like to extend the applicability of

adders not only to the resource selection process but

also to dispatch decisions, bulk power transactions, and

retail pricing.92 Including adders and permitting dispatch on a least-cost resource basis would bring the

issue of emissions and rates into sharper focus than the

application of adders to marginal decisions.93

Critics point out that the use of adders does not imply

that externalities are being internalized since the only

effect is on resource selection.94 Thus, the adder approach merely “lends itself to the arbitrary manipulation of the resource selection process.”95 It is also

pointed out that the inclusion of environmental adders

in concert with emissions trading (as envisaged in the

Clean Air Act Amendments of 1990) is counter-productive. The effect of adding $1,500/ton for sulfur

dioxide emissions could add roughly one cent per kilowatthour to the cost of a coal-fired plant using clean

coal (0.8 percent sulfur).96 “This is half or more of the

fuel cost alone, and roughly 15 percent of the total cost

of a new plant.”97 These and other considerations of a

similar nature lead some other professionals to recommend that it may be time to stop the arbitrary adders,

”with their uncertain costs and environmental consequences, and adopt policies that achieve identifiable

environmental improvement at the lowest cost to the

society.”98

The debate on the use of adders is far from over and is

likely to continue.99 This is not surprising given the

limitations of available options for internalizing externalities and the use of adders, which has grown over

time.

Monetization by Emission

The “monetization by emission” approach is essentially

a variation of the percentage adder approach. In this

approach, valuations of externalities are expressed in

terms of dollars per ton of emission or in cents per

89This approach is also known as the “avoided cost consideration” approach. See Pace University Center For Legal Studies,

Environmental Costs of Electricity (Oceana Publications, Inc., New York, 1990), p. 564. 90Another variation of this approach is the “monetization by emission” approach discussed next. Note that these two approaches tend

to overlap in intent and impact. 91Electricity Consumers Resource Council, Profiles in Electricity Issues: Externality (Washington, DC, October 1991), p. 10. 92Stephen Wiel, “The New Environmental Accounting: A Status Report,” The Electricity Journal (November 1991), pp. 46-54. 93Consumer Energy Council of America Research Foundation, Incorporating Externalities into Utility Planning (Washington, DC, July

1993), pp. 100-101. 94This position is taken by the Electricity Consumers Resource Council on the grounds that electricity rates may not equal marginal

social costs. It may be noted that this argument holds for most other approaches as well. See Electricity Consumers Resource Council,

Profiles in Electricity Issues: Externality (Washington, DC, October 1991), p. 12. 95Electricity Consumers Resource Council, Profiles in Electricity Issues: Externality (Washington, DC, October 1991), p. 12. 96This is really a part of the “monetization by emission” approach. Instead of adding a percentage amount, externality valuations are

expressed in dollars per ton of emissions or in cents per kilowatthour. 97Benjamin Hobbs, “Environmental Adders and Emissions Trading, Oil and Water?,” The Electricity Journal, August/September 1992,

pp. 26-34. 98Paul Joskow, “Weighing Environmental Externalities: Let’s Do it Right!,” The Electricity Journal (May 1992), pp. 53-67. Dr. Joskow

identifies various conceptual and operational problems with the use of adders and favors the use of market-based approaches. 99A. Myrick Freeman, et al., “Weighing Environmental Externalities: How to Do it Right,” The Electricity Journal (August/September

1992), pp. 18-25. Also, Ajay K. Sanghi and Anthony L. Joseph, “Are Externalities Extraneous Under Emissions Cap and Off-set

Requirements?,” The Electricity Journal (January/February 1995), pp. 71-84.

26 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
kilowatthour of electricity. The values represent costs

imposed on society by residual emissions that remain

after compliance. Externality values can be transformed

into adjustments to prices to permit a cost comparison

of available options.100 Externality values may also be

assigned by regulatory authorities to out-of-State power

purchases.

Under this approach, utilities estimate, using the best

available information, monetized externality values

with respect to designated downstream emissions for

inclusion in the costing mechanism. This approach,

similar to the “percent adders,” provides an easy

method to integrate externalities within the framework

of the bidding and integrated resource planning processes. This approach has currently been used primarily

in the area of air emissions.

In addition to its applicability to the resource option

selection processes (as in the case of percentage adders),

advocates of this approach desire to broaden its scope

by including other areas such as existing resources,

repowering, dispatch, and transmission.101 Opposition

to the use of monetized adders at some regulatory level

rests on the desire to retain regional economic competitiveness; others would abandon its applicability in

view of the provisions of the Clean Air Act Amendments of 1990. In addition, this approach is also subject

to some of the same criticism as percentage adders.

Multi-Attribute Tradeoff Analysis

The subjective assessment approach of “multi-attribute

tradeoff analysis” has been developed to sidestep the

problems associated with estimating monetized values.

The approach avoids making an up-front determination

(as is done in the case of adders), but attempts to

analyze the tradeoff between costs and benefits of

different strategies.

The starting point for the multi-attribute tradeoff approach is the identification of important issues and the

related development of a set of attributes with which to

measure the performance relative to these issues. Concurrent with this phase of activity, multi-option

strategies and related uncertainties are identified where

each strategy is evaluated across a range of uncertainties to yield a set of scenarios. The scenario analysis

provides an attribute database used for comparative

analysis of the potential strategies. The scenario

analysis is continued until significant improvements in

attributes are either unlikely or difficult to analyze. At

this point, the decisionmakers or the stakeholders can

select a preferred strategy for adoption from among a

set of strategies along the tradeoff frontier.

Thus, the tradeoff approach theoretically permits

selection of an option from a group of those that are

feasible and robust and identifies variations in the

resource mix that differ in costs and impacts. Identification of a preferred strategy, or a set of strategies, is

then assumed to be an explicit valuation of society’s

willingness to pay to reduce environmental risks.

Existing cost-based planning tools, when used within a

multi-attribute framework, are deemed to be adequate

to identify lower social-cost-resource strategies and to

facilitate their selection under a competitive bidding

process.102

The main advantage of the tradeoff method is that it

forces overall consideration of the effects of various

decisions without being constrained by the inaccuracies/rigidities of quantification. While the process

encourages experimentation in searching for a low-cost

option, lack of a valuation process and application of

subjective techniques is perhaps its major drawback.

Other Approaches

The methods or approaches discussed above are those

with respect to which State regulatory authorities have

jurisdictional control. The cost-of-control and the damage function approaches attempt to value impacts; the

others are methods of applying the valuations. In

addition to these, there are still some other approaches

over which the State regulatory authorities may or may

not have complete jurisdictional control. Included in

these are:

• Command and Control

• Standards and Targets

• Emission Fees and Fuel Taxes

• Offset or Allowance Trading Policy

• Rate of Return Consideration

• Collaborative Consideration

• Set-Aside Considerations.

100Externality valuations are open to review and can be modified where necessary by the regulatory authorities. 101California applies monetized emission values to power acquisition as well. 102Since 1988, the Massachusetts Institute of Technology Energy Laboratory’s Analysis Group for Regional Electricity Analysis (AGREA)

has been developing and using the scenario-based multi-attribute (tradeoff) analysis techniques. For a detailed description of the approach

see Stephen R. Conners, “Side-Stepping the Adder: Planning for the Least-Social-Cost Electric Service,” Proceedings of the NARUC-DOE

Fourth National Conference on Integrated Resource Planning (Burlington, VT, September 1992).

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 27
Command and Control

Directives of the Clean Air Act Amendments prior to

1990 and other similar legislation fall into this category.

In these cases, utilities and other power generators can

choose from a variety of options to attain a stated

objective or goal regarding the attainment of emission

levels or other pollutants.

Standards and Targets

This approach is similar to the “command and control”

option in which the power generators have options to

meet the standards and targets that are prescribed by

legislation or directives that require compliance.

Reduction of carbon dioxide emissions by the year 2000

to the levels that prevailed in 1990 is a target that

various utilities may strive to attain. Standards, on the

other hand, may be prescribed for the use of certain

types of fuels.

Emission Fees and Fuel Taxes

Under this approach, users of specified fuels may be

asked to pay fees (or taxes on fuel) where the fuel’s

combustion leads to damaging emissions.

Offset or Allowance Trading Policy

“Offsets” are measures designed to mitigate or reduce

emissions from other sources in an attempt to compensate for (or offset) higher levels of emission from

the designated source(s). As an example, there is a

concerted effort to contain and reduce emissions of

carbon dioxide to their 1990 level by the year 2000 as

part of the Climate Change Action Plan. In some

instances, attaining this goal may not be feasible. In

such cases, utilities may have the option of initiating

activities that reduce levels of carbon dioxide by undertaking other activities like planting trees. Allowance

trading can be viewed as another form of offset. With

the allocation of allowances under the Clean Air Act

Amendments of 1990, utilities that are unable to reduce

sulfur dioxide emission levels to specified levels can

buy additional allowances. The resulting increase in

emissions from these utilities must then be offset, however, by a decrease in emissions from the companies

that sold the allowances.

Rate of Return Considerations

Regulatory authorities may award an increased rate of

return if certain designated, less polluting technologies

are used. In addition, some States may grant a similar

advantage to utilities that adopt demand-side management techniques. The intent is to induce industry to use

less polluting (or nonpolluting) techniques in generation or to accelerate the promotion of energy efficiency

and conservation through active demand-side management.103

Collaborative Consideration

The “collaborative consideration” approach involves

collaboration among utilities or among various State

agencies at the behest of the regulatory authorities to

establish externality values and the method of treating

them. Six States have been involved in this approach,

but tangible results have not yet been visible.104

Set-Aside Considerations

The “set-aside consideration” approach may be exercised by State regulatory authorities or mandated by

Federal regulations. As an example, the Public Utility

Regulatory Policies Act of 1978 required electric utilities

to interconnect with and purchase power from facilities

designated as “qualifying facilities” by the Federal

Energy Regulatory Commission. The legislation further

required that utilities pay for such power purchases at

approximately their incremental cost of alternative

energy or the “avoided cost” of power production.

Assessment of Approaches to

Incorporating Externalities

There is not yet a consensus on which approach of the

multiple approaches discussed above is best suited to

addressing externalities. Environmental impacts of

power generation differ regionally and are contingent

upon many other factors as well. Levels of generation,

location, population densities, and power usage levels

all contribute to environmental impacts and work

against adoption of a uniform approach. Accordingly,

experimentation with varying approaches is likely to

continue even though valuation methodologies for estimating damages or costs continue to be characterized

103Higher rates of return may be necessary to encourage the implementation of demand-side management (at least in some cases) to

compensate for revenue losses. 104Richard L. Ottinger, et al., Environmental Costs of Electricity (Oceana Publications, Inc., New York, 1990), p. 571.

28 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
by unresolved issues. Also, various other externality

issues associated with power generation have yet to be

actively taken into account. Some of these include

valuation of human health risks, transboundary issues,

site-specific issues, and the treatment of uncertainties.

There is also a lack of consensus with respect to the

incorporation of externality costs in electricity rates. The

privately owned segment of the industry (commonly

known as investor-owned utilities) asserts that the current incorporation of externality values is confined

primarily to the dollar valuation of impacts of one set

of externalities from one energy form, i.e., power generation by utilities that are subject to regulation. To the

extent other operators and energy sources are excluded

from a similar treatment, the approach is unbalanced

and works against privately owned utilities and their

customers. A full-scale inclusion of externality costs

pushes electricity prices upward. This development is

likely to affect competitiveness and employment unless

the nonutility power producers and alternative fuels are

also subjected to similar treatment. Next, it is also

pointed out that monetized values increase the cost of

supply-side options and thereby increase the costeffective range for demand-side management options,

thus distorting the decision-making process.105

This debate on the relevance and applicability of

externality values to the resource selection process is

likely to continue even as the industry struggles to

restructure in the face of increasing competition.

Accordingly, whether the attempt to incorporate

externalities in the planning process will eventually

result in embedding them through a process of internalization into costs of delivered power is difficult to

predict.

The next three chapters present the experience of three

States—Massachusetts, Wisconsin, and California—that

incorporate externalities within the framework of an

integrated resource planning process. A description of

the processes used in each State is provided. These

States were selected for a detailed study due to the

extent of their involvement in handling externalities.

Besides providing a diverse regional mix, these States

had:

• Specific monetary values for externalities

• Regulations in place for at least a few years so as

to allow them to have some effect

• Extensive public discourse on the subject, due to

public hearings, studies, and other sources of

information.

Contemporary studies on externalities focus on methodological issues, estimation procedures, compilation of

range of estimates, delineation of scope, problems of

applicability, and incorporation techniques. The States

selected for the case studies in this report have moved

away from these polemics and have attempted to find

solutions to these unresolved problems.

105Edison Electric Institute, Environmental Externalities: An Issue Under Critical Review (Washington, DC, 1994), pp. 1-1 to 1-5.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 29
4. The Commonwealth of Massachusetts Case Study

This chapter presents the experience of the Commonwealth of Massachusetts with respect to incorporation

of externalities within the framework of an integrated

resource planning process.106 The information presented in this chapter was gathered from a review of

the relevant decisions and orders by the Massachusetts

Department of Public Utilities (MDPU).107 In addition,

the largest investor-owned utility in the State, the New

England Electric System (NEES), was also contacted

and copies of its most recent resource plans were

obtained.108 This evaluation of the impacts of incorporating externalities is based on discussions with the

State regulatory authorities and the NEES officials in

Massachusetts.109

Early History and Procedural

Background: Decisions on Externalities

The MDPU opened an investigation into the pricing

and ratemaking treatment to be afforded to new

generating facilities in February 1986 (Docket No.

D.P.U. 86-36-G) with the objective of establishing a

regulatory framework that would result in utilities

meeting their obligations to serve reliably and at the

lowest cost. As a part of this effort, the MDPU

attempted to investigate options not only for cost

recovery of new investor-owned generating facilities,

but also for including all other resources, including

nonutility generators, conservation and load management measures, and other demand-side options as

a part of a utility’s least-cost integrated (supply and

demand) planning process. The MDPU sought further

comments on the proposed regulatory structure to be

designed with a view to eliminate potential conflicts.

The MDPU’s Order (Docket No. D.P.U. 86-36-G), issued

on December 6, 1989:

• Proposed regulations regarding the procedures by

which investor-owned electric utilities’ resources

are planned, solicited, and procured, and the

appropriate ratemaking treatment to be afforded

the implementation of such integrated resource

management (IRM)

• Established a regulatory review structure with

respect to the electric companies’ IRM practices,

including their procurement of resources with a

view to ensure that competitive resource

solicitations resulted in the selection of resources

that were least cost to society.110

On the subject of externalities, the MDPU stipulated (in

its order with respect to D.P.U. 86-36-G) that each

electric company include an environmental externality

component in its all-resource solicitation evaluation

criteria. This order required electric utilities to include

an environmental externality component in their criteria

for evaluating resources offered in response to the companies’ solicitations to acquire resources. The scope of

the order included solicitations to qualifying facilities,

assessments of the cost-effectiveness of conservation

and load management programs, power purchase

agreements, and any proposed utility generation

106Chapters 4, 5, and 6 draw on a recent study undertaken by the Oak Ridge National Laboratory (ORNL) with funding and direction

provided by the Energy Information Administration. See Oak Ridge National Laboratory, The Effects of Considering Externalities on Electric

Utilities’ Mix of Resources: Case Studies of Massachusetts, Wisconsin, and California (Oak Ridge, TN, July 1995). 107The discussion in this section is essentially chronological. It begins with a summary of major decisions made in the late 1980s and

the early 1990s that shaped the integrated resource planning process. Within this context, the MDPU initiated actions to incorporate

monetized externality values in resource selection. This process continued until the end of 1994. Developments in the State since

December 1994, stemming from a key decision by the State’s supreme court, are also provided. The MDPU’s decision to exclude

considerations of externalities in June 1995 has materially changed the way in which externalities will be handled in the State in the future. 108New England Electric System (NEES) is a public utility holding company with subsidiaries. “New England Electric(s),” as used in

this section, is the name by which the NEES is more commonly known and is understood to encompass the parent and its subsidiaries

(unless otherwise stated). 109Dr. Suraj P. Kanhouwa of the Energy Information Administration and Dr. Russell Lee of the Oak Ridge National Laboratory

participated in discussions with the State regulatory authorities in Massachusetts as well as with the officials of NEES. 110Based on Massachusetts D.P.U. 89-239 of August 31, 1990.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 31
capacity. The MDPU also directed companies to include

the interaction between new and existing resources in

their resource plans. Three different options for including environmental externalities were identified in

D.P.U. 86-36-G.111 However, the MDPU sought comments with respect to the propriety of adopting a

uniform externality method.

Thus, among other issues, the MDPU sought comments

in two critical areas—the IRM process and the

treatment of externalities. To allow the interested

parties to discuss the issues raised and permit them to

present their positions, the MDPU conducted various

technical sessions during 1990. Written comments were

invited and were followed by public hearings and

receipt of additional comments. Based on a review of

these proceedings, the MDPU’s final order was issued

on August 31, 1990 (D.P.U. 89-239).

MDPU’s Rationale for Incorporating

Environmental Externalities

The MDPU defined the cost of externalities “as the cost

of environmental damages caused by a project or

activity for which compensation to the affected parties

does not occur, regardless of whether the costs are

imposed within Massachusetts borders or elsewhere.”112 The electric utilities were required to

include environmental externalities to the fullest extent

practicable and quantifiable in their evaluations of

conservation and load management programs and other

resource options. Such an action encouraged resource

developers to consider the value of environmental

resources in project proposals and enabled environmentally clean projects to compete fairly.

The Procedural Debate

Regulatory framework designed to achieve the above

objectives called for inclusion of environmental externalities through the application of either price or

nonprice criteria.113 The MDPU expressed its willingness to value externalities in dollar terms to be added

to the resource price. Alternatively, a “weighting and

ranking” approach could be adopted.114 While there

was consensus among the parties concerned to include

externalities in the resource selection process, there was

disagreement with respect to the method of its

implementation. These issues were:

• Using an impact-based versus a technology-based

initial ranking system

• Monetizing versus weighting and ranking externality values

• Valuing externalities at the marginal cost of control versus cost of actual damages

• Determining the weight of environmental externalities relative to other project selection criteria

• Extending externality evaluations to site-specific

factors

• Extending externality evaluations to include entire

fuel-cycle costs

• Extending externality evaluations to include economic and social externalities

• Finalizing the transitional policy for environmental externalities.

The above issues fall into two categories. The first four

deal with the valuation and the method of incorporating externalities in the resource selection process

and the next three with the scope of externality

valuations. The MDPU’s assessment, based on comments from various parties, is briefly discussed below.

Regulatory Assessment of Externality

Approaches

An Impact-Based An Impact-Based Versus a Technology-Based Technology-Based

Scoring System Scoring System

The technology-based scoring system allocates fixed

points based on technology types (regardless of the

inplace attempts at mitigation).115 As a result, it takes

111These were technology-based, impact-based, and hybrid scoring systems. 112The assumption is that the cost of mitigating environmental damages by Federal, State, and local regulations are internalized in a

resource developer’s production costs and, therefore, in prices bid by developers and electric companies. Any residual damage occurring

after compliance with basic environmental regulations is assumed to occur without compensation to affected parties, thereby constituting

an external cost. See Massachusetts D.P.U. Docket No. 89-239, p. 51. 113Based on Massachusetts D.P.U. Docket No. 89-239, pp. 53-89. 114See Chapter 3 for a discussion of this approach. 115The words ranking and scoring have been used interchangeably. Note, however, that scoring is necessary for a ranking to be done.

32 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
away the incentive to invest in cleaner technology

because all projects using the same technology will

receive the same score. The impact-based scoring

system, which takes into account project-specific

environmental impact reductions for given technologies

or fuel configurations, more accurately reflects cost

differences among projects based on their emission

levels. Based on this difference, the MDPU concluded

that environmental externality evaluation methodology

should take cognizance of the expected environmental

impacts that are associated with specific project

proposals.

Monetization Versus Monetization Versus Weighting Weighting and Ranking Ranking

Some utilities in Massachusetts supported a weighting

and ranking (scoring) scheme with externalities

counting for 15 percent of the total score for a resource

option. In rejecting this approach, the MDPU supported

monetization, contending that the weighted values

would still need to be quantified. Its position was that

externalities should be monetized to the extent possible,

and that such values should be added to direct resource

costs for the purpose of evaluating and comparing

alternative resource options.116

In support of the approach to monetize externalities,

the argument is usually one of transparency and ease

with which monetized values, i.e., dollar values, can be

applied. The unresolved issues (in opposition to this

approach) are how to estimate the correct or the

appropriate level of monetary values and whether the

externality values need to be expressed in monetary

terms. The Massachusetts Institute of Technology

submitted that there were alternatives to monetization

and supported a system-based, multi-attribute evaluation.117 This approach uses distinct measures of cost,

environmental impacts, and reliability in the evaluation

of resource portfolios.

Implied Valuation Implied Valuation (or Cost of Control) Control) Versus the

Value of Value of Environmental Environmental Damages Damages

Working from the assumption that the cost of

mandated environmental controls is internalized, the

MDPU equated the value of environmental externalities

with the value of environmental damages from residual

emissions. Based on this concept, the MDPU noted that

the estimation of environmental externality values

enables comparison (on a consistent basis) of the social

costs associated with alternative energy resources that

differ in prices, emissions, and nonprice characteristics.

For such a comparison to be made (to aid the decisionmaking process), an estimate of environmental damage

for each resource becomes necessary. Difficulties in

estimating direct damage costs, which may be

unknown, lead to a search for alternatives.

Options to search for alternatives are varied. One of the

alternatives could include monetization because of its

simplified approach and because damage costs are

unknown or uncertain.118 Another alternative is to

use the marginal cost of control to reflect the value of

environmental impacts implied by the mandated

pollution standards.119

A method identified by the Massachusetts Division of

Energy Resources equates society’s willingness to pay

for pollution control with the cost of controlling

pollution imposed by regulatory requirements. This

method is called the “implied valuation method.” It implies that use of the cost of pollution control provides

an estimate or a measure of the price which society is

willing to pay to reduce the pollutant. In essence, this

method is in the nature of a proxy valuation.120

The MDPU still had to decide whether the damage

valuation (discussed later in this section) was more

appropriate than implied valuation. It opted in favor of

the implied valuation method as a reasonable alternative since formulation of comprehensive damage

estimates presented many insurmountable problems.

The MDPU adopted monetary values proposed by the

Division of Energy Resources using the implied

valuation method. These values were to be used by the

electric utilities in the State in their submission of IRM

plans (Table 3).

Determination of the Scope of

Externalities Applications

The MDPU examined whether site-specific and/or fuelcycle externalities should be included in the IRM resource evaluation process in Massachusetts. It decided

116Resource costs in this context are price bids of proposed resources and the avoidable costs of existing and planned resources. 117See Chapter 3 for a discussion of the “multi-attribute evaluation” approach. 118Note that “monetization” and “damage costs” are not mutually exclusive approaches. 119Conceptual amendments to these variations are possible. This statement is, however, based on the Massachusetts D.P.U. Docket No.

89-239. 120The “implied valuation method” has been discussed at some length in Chapter 3.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 33
Table 3. Massachusetts Externality Values

(1989 Dollars per Ton)

Pollutant Value Basis for Value

Nitrogen oxides (NOx) $6,500/ton Based on the cost of installing selective catalytic reduction on a

10 MW natural gas turbine

Sulfur oxides (SOx) $1,500/ton Based on the cost of installing flue gas scrubbing systems on

utility generatorsa

Volatile organic compounds (VOC) $5,300/ton Based on a U.S. Office of Technology Assessment study on

costs of control technologies for ozone nonattainment areas,

and on two studies conducted for the Environmental Protection

Agency on the costs of complying with various Clean Air Act

targets

Total suspended particulate (TSP)

matter

$4,000/ton Based on the cost of installing an electrostatic precipitator on a

high sulfur coal plant with low resistivity fly ash

Carbon monoxide (CO) $870/ton The total consists of a $820/ton ambient air quality component

(cost of increased oxygenation of gasoline) and a $50/ton

greenhouse gas component (the global warming potential of CO

relative to CO2)

Carbon dioxide (CO2) $22/ton In anticipation of CO2 regulations. Based on the marginal cost

of planting trees in a moderate effort to sequester carbon.

(Some individuals contend that tree planting costs alone may

understate mitigation and control costs since tree planting can

offset only a small fraction of CO2 emissions. But other

estimates are much less, say $15/ton.)

Methane (CH4) $220/ton Considering the warming potential relative to CO2

Nitrous oxide (N2O) $3,960/ton Considering the warming potential relative to CO2

Chlorofluorocarbons (CFCs) No value

assigned

No clear evidence of whether CFCs cause global climate

warming or cooling

Air toxics No value

assigned

Prudent to wait for decision by Environmental Protection Agency

Water use, land use, ash disposal No value

assigned

Impacts are only local or are addressed in the siting process.

Considering local siting-specific environmental impacts is not

feasible at this point.

a

The MDPU supported the use of market-based mechanisms. With respect to sulfur dioxide (SO2) emissions, however, the

MDPU noted that the Clean Air Act Amendments (CAAA) may not internalize all of the SO2-related damages. Its reasoning was

that the cap on emissions is only to address SO2 as a precursor to acid rain, and not all of the health and environmental impacts.

The MDPU noted, however, that if a utility obtains allowances under the CAAA or has offsets, then it will not have to apply an

externality value to its SO2 emissions, to the extent that it has allowances or offsets. At least one utility noted, however, that an

externality imposed by a ton of SOx in Massachusetts or New England is not necessarily equal to the marginal price of an allowance

in a nationwide trading market.

Note: These values may no longer be used due to a decision by the State’s Supreme Court. This is discussed later in this

Chapter.

Source: Oak Ridge National Laboratory, The Effects of Considering Externalities on Electric Utilities’ Mix of Resources: Case

Studies of Massachusetts, Wisconsin, and California (Oak Ridge, TN, July 1995).

34 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
to exclude such considerations in recognition of the

additional burdens it would impose in valuation and

application.

The MDPU also considered the positive economic and

social externalities resulting from power generation.

Examples are local job creation and improvement in the

quality of life. The MDPU decided, however, to exclude

their consideration in the IRM process due to insufficient information.

Summary of MDPU’s Findings on

Environmental Externalities (D.P.U.

89-239)

• An evaluation system based on project-specific

emissions/environmental impacts is preferable to

a scoring system that allocates fixed points based

on technology types.

• The Massachusetts Institute of Technology Energy

Laboratory argued that resource strategies

focusing exclusively on improving end-use efficiencies perform poorly in reducing emissions in

comparison with resource strategies that balance

efficiency improvements in conjunction with

supply- and demand-side options. To alleviate

these concerns, the MDPU directed electric utilities to optimize ranking of proposals to take into

account interactions among resources.

• The MDPU directed that externalities be monetized and that such values be added to direct

resource costs when evaluating and comparing

alternative energy resources.

• The MDPU concluded that the cost of pollution

control estimates that use the implied valuation

method to be the best available proxy at the

time.121 Accordingly, the MDPU adopted externality values expressed in dollars per ton of

emission that were based on the recommendations

of Division of Energy Resources estimates.122

Table 3 lists these values and the basis for these

estimates. Electric utilities under the jurisdiction of

the MDPU were directed to use these values in

their submissions on various issues in addition to

the IRM process.

• The MDPU permitted electric utilities to submit

weights of various categories of project selection

criteria for review. As a result of this option, the

weight of the combined price/externality category

could vary among utilities depending on nonprice

criteria.123 The utilities could thus monetize

externality values, put them on a consistent basis

with price and then allow the relative weights of

price/externality and nonprice criteria to vary.124

• The MDPU did not favor including local, sitespecific impacts in the evaluation process.

• The MDPU directed that priority be placed on

estimating environmental externalities that are the

direct results of power-plant operations, including

all downstream effects, leaving proposals to

expand the scope of the regulations to the entire

fuel cycle to a later time.

• Although the MDPU took a global view of

externalities, it deemed that local job “creation”

should not be counted as a positive externality. In

reality, jobs are mostly transfers of individuals

moving from one job to another. Granted, not all

jobs are transfer payments, and there may indeed

be some social and financial externalities from

new employment, but there is insufficient information to generalize.125 Thus, the MDPU took

the position that the benefits of “new” employment should be considered on a case-by-case

basis.

Post-1990 Developments

The primary objective of the Massachusetts D.P.U. 89-

231 findings was to ensure that the competitive resource solicitations within the framework of the IRM

process resulted in the selection of resources that were

of least cost to society. Environmental externality considerations were included in this effort to permit a

comparison of the environmental impacts of competing

resources.

121The MDPU issued the order on August 31, 1990. 122These estimates are in turn based on a study undertaken by the Tellus Institute. See Stephen Bernow and Donald Marron, “Valuation

of Environmental Externalities for Energy Planning and Operations: May 1990 Update,” (Tellus Institute, Boston, MA, May 18, 1990). 123Examples of nonprice criteria include reliability or system compatibility. 124D.P.U. 89-239, pp. 72-76. 125For a discussion on this aspect, see Oak Ridge National Laboratory and Resources for the Future, Estimation of Fuel Cycle Externalities:

Analytical Methods and Issues. Vol. 2 (Oak Ridge, TN, July 94), pp. 17-1 through 17-31.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 35
On May 20, 1991, the Massachusetts Electric Company,

the retail subsidiary of the New England Electric

System and the first company to submit an IRM filing,

proposed different externality values to replace all of

the MDPU’s recommended values listed in Table 3. The

MDPU decided to re-investigate whether the externality

values established earlier needed revision (by opening

D.P.U. Docket No. 91-131).

The MDPU noted that regulations have impacts on

ratepayers and considered that if externalities are

unaccounted for, then there is a significant risk of

future costs to ratepayers and to society. In the view of

the MDPU, the resulting risk of more stringent environmental regulation in the future was the most

important justification for utilities to position themselves in advance of such regulation. The MDPU also

considered externalities to be real costs borne by

ratepayers and by the rest of society in the form, for

example, of health care expenses. Therefore, in the long

run, the MDPU regarded this strategy of accounting for

externalities to be more efficient than deferring them.

Furthermore, the MDPU did not find evidence that

rates would increase greatly as a result of considering

externalities, estimating an increase of only 5 percent by

the year 2006.

Damage-Cost Estimates of Externalities

Several parties submitted testimony either to support

the externality values, change them, or add values for

impacts/pollutants not previously monetized (Table 3).

The discussion presented here deals only with the

“damage valuation” or damage-cost estimation method

that was not dealt with in D.P.U. 89-231.126

The key conceptual issue confronting the MDPU was to

determine whether to rely on the implied valuation

method or to adopt the values based on the damage

valuation method.127 The MDPU stated that its externality policy was to allow consideration of the residual

emissions of competing resource bids. It acknowledged

that the best solution would be to use comprehensive

damage costs where feasible. Nonetheless, externality

values using the implied valuation method were

adopted.

During the deliberations (in connection with D.P.U. 91-

131), some of the arguments made in support of

adopting the damage valuation method included the

following:128

• Damage valuation, by measuring damages from

pollutants, is conceptually correct since implied

valuation estimates provide no defensible basis.

• Damage valuation is based on sufficient scientific

information.

• Improvements in damage valuation can be made

as knowledge improves.

The adoption of damage valuation was opposed for the

following reasons:

• Reliance solely on a theoretically correct approach

to provide the best result may not always be

correct.

• Damage valuation estimates may not be reasonably credible and defensible.

• Estimating actual damage costs from residual

emissions is not an easy task.

• Proponents of the damage valuation method

failed to provide a factual showing for their

estimates.

• The damage valuation methods and estimates are

not accurate or comprehensive and may have the

effect of increasing externality values. In its

findings, the MDPU noted that monetizing environmental externalities does not eliminate the

need for subjective evaluation and that reasonable

bounds should be drawn when assessing them. In

the case of damage valuation assessment, the

126Based on D.P.U. 91-131. 127Implied valuation was also referred to as “revealed preference,” “marginal cost of control,” “highest cost of control,” or “cost of

control” method. Damage valuation has also been referred to as “marginal benefit of abatement” and “damage cost.” 128Testimony in support of the damage valuation method was also provided by Dr. Lester Lave and Dr. William Nordhaus. Dr. Lave

provided damage-cost estimates for criteria pollutants, i.e., SO2, TSP, NO2, volatile organic compounds, and carbon monoxide (CO).

Values for human health and all other effects, or “welfare effects,” were based on Dr. Lave’s professional judgment and the then existing

studies. The MDPU pointed out that some of the values recommended by Dr. Lave were incorrect or too high or based on poor data.

Dr. Nordhaus’ estimates of damage valuation with respect to CO2 emissions at $2/ton received support from some (but not all) utilities

in the State. The MDPU rejected Dr. Nordhaus’ recommendations on grounds that they oversimplified damages, and that uncertainties

associated with the results were largely ignored. In conclusion, the MDPU determined that the testimony of Drs. Lave and Nordhaus

failed to satisfy the criteria of comprehensiveness and reliability.

36 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
MDPU noted that the steps to be followed

included:

- Estimating the quantity of emission from the

source

- Modelling the chemical transformation and dispersion of the emissions

- Modelling the resultant pollutant exposure to

humans, animals, crops, materials, and other

affected systems

- Determining the response from those affected

by exposure to the pollutant

- Valuing the resulting damage.

All of the above steps are complex and difficult to

complete accurately. Valuation is extremely subjective

since none of the effects are traded in the market. While

conceding the relevance of the damage valuation

approach as an ideal, the MDPU still decided against its

adoption and lent its support to continuing the application of the implied valuation method.129 Stated

differently, the MDPU reaffirmed its commitment to the

implied valuation approach. The MDPU did not, therefore, set new values for incorporation in the resource

selection process.

Treatment of Other Pollutants

In addition to pollutants previously assigned values by

the MDPU, several other issues were taken up during

the proceedings initiated under D.P.U. Docket No. 91-

131. Externality values for specific pollutants (like

sulfur oxides, nitrogen oxides, volatile organic compounds, total suspended particulates, carbon monoxide,

and greenhouse gases) that had been assigned by the

MDPU (Table 3) were retained. The MDPU also looked

into impacts that were not assigned values in D.P.U. 89-

231. Included in this category were chlorofluorocarbons,

air toxics, water use, land use, and ash disposal. The

MDPU stated that it would prefer to wait for further

information on the subject of air toxics (expected to

become available from a special study of this topic

under provisions of the Clean Air Act Amendments of

1990). On other issues, the MDPU did not initiate any

new actions either because there was inadequate

evidence or because the impacts were damaging.

Incorporation of Externality Values

Within the IRM Process

The integrated resource management process in the

Commonwealth of Massachusetts is a four-phase process. Phase I involves a company’s submittal of the

draft initial filing and its review by the MDPU. The

IRM regulations require that the company’s (or the

utility’s) initial filing contain its demand forecast,

resource inventory, evaluation of resource need, evaluation of resource potential, resource solicitation request

for proposals (RFPs), and initial resource portfolio.

Phase II comprises the utility’s resource solicitation

process when it issues an RFP approved by the MDPU.

In Phase III, the MDPU reviews/evaluates the resource

mix submitted by the utility together with a list of the

proposed awards of contracts with respect to the resources to be acquired. Finally, in Phase IV, the MDPU

reviews and approves contracts provided by the utility

that resulted from the resource solicitation.

All electric utilities in the State are required to

incorporate monetized externality values within the

framework of the IRM process so that both supply- and

demand-side resources can be compared on a consistent

basis and so that electric power can be provided at the

least societal cost.130 The IRM regulations require that

a utility publicize its draft initial filing to notify all

interested parties, hold technical sessions to clarify plan

details, and establish procedures for exchange of

required information. The intent is for the utility to

reach an agreement with all interested parties on its

draft initial filing before its review by the regulatory

authorities. Areas where differences exist need to be

indicated. In other words, to facilitate its regulatory

review, the regulations require that the electric company negotiate a settlement, to the extent possible,

among the parties to a proceeding.

129With the recent completion of major damage-cost studies, however, these criticisms are considerably muted. These studies constitute

an order-of-magnitude improvement in the state of the art in damage-cost valuation. For an extensive discussion of this subject, refer

to Oak Ridge National Laboratory and Resources for the Future, Estimating Externalities of Coal Fuel Cycles, Report # 3 (Oak Ridge, TN,

September 1994). 130This requirement is no longer operative as a result of the Massachusetts Supreme Court decision in December 1994. In fact, the future

of externality considerations in the State is extremely uncertain.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 37
Resource Planning by the New England

Electric System (NEES) Companies: An

Overview131

New England Electric System (NEES) is a public utility

holding company and the largest investor-owned utility

in the Commonwealth of Massachusetts. Its retail

subsidiaries include Massachusetts Electric Company,

the Narragansett Electric Company, and Granite State

Electric Company and its wholesale generation and

transmission subsidiaries, the New England Power

Company and Narragansett Energy Resource Company.

In addition, NEES has three electric transmission

companies, as well as international operations, a

management consulting company, and an electric

service company. The NEES operates in three States:

Massachusetts, New Hampshire, and Rhode Island. It

is, therefore, under the jurisdiction of regulatory

authorities in these States.

The New England Electric companies submitted their

first NEESPLAN in 1979 followed by a second,

NEESPLAN2, in 1985. The second plan emphasized

integrated supply-side and demand-side least-cost

planning to meet demand. The NEESPLAN3, submitted

in 1991, took into account growing environmental

concerns and increasing cost pressures. In 1993, the

NEES companies and the regulatory commissions in

Massachusetts, New Hampshire, and Rhode Island

implemented a new approach to regional regulation of

the resource planning process in terms of which the

NEES prepares a 15-year system-wide integrated

resource plan every 2 years. Finally, NEESPLAN4,

based on the procedural requirements discussed above

and finalized late in 1993, was submitted to the MDPU

in June 1994.

Underlying Approach Underlying Approach in NEESPLAN4 NEESPLAN4

The NEESPLAN4 is an attempt to reconcile the pressures of increasing competition with the demands for

environmental improvement.132 The objectives of the

plan are to achieve the following:133

• Develop approaches to provide electric service in

a more environmentally sustainable manner

• Meet customers’ increasing expectations in areas

of cost and service

• Assure that services provided by NEES are valuable in an increasingly competitive electric market.

In addition, the NEES aims to remain flexible in

resource planning by avoiding the problem of investments becoming “stranded.” To encapsulate these

themes in its plan and to meet potential future challenges resolutely, NEES took several steps. Critical

among these was its collaboration with the Conservation Law Foundation in formulating NEESPLAN4.

Next was the adoption of the “options theory,” a form

of analysis that quantifies the value of flexibility in

specific resource alternatives. NEESPLAN4 contains the

following principal components:134

• Demand forecasts with and without incremental

demand-side management (DSM) impacts for

system energy requirements

• Resource inventory consisting of existing and

planned resources for which commitments have

been made

• Identification of future resource needs by application of a probability methodology

• A projection of significant new supply-side commitments and other new resource additions

• A projection of demand-side resources to be

developed

• Plans for compliance with new environmental

requirements

• A 2-year plan for implementing the integrated

resource plan

• Any other information required by State law.

The Planning Methodology

In preparing this plan, the NEES companies first generate a long-term forecast by including economic

131The term NEESPLAN signifies the IRM plan submitted by NEES to MDPU and other regulatory agencies. 132Based on its projection, NEES maintains that no new capacity will be required until 2002. 133Based on NEESPLAN4 documentation as submitted to the MDPU. 134NEES companies have developed an approach to regional regulation of their resource planning process due to its operation in three

States: Massachusetts, New Hampshire, and Rhode Island. In terms of a memorandum of understanding (MOU), a system-wide

integrated resource plan that complies with the separate requirements of each State regulatory authority is prepared every 2 years with

a 15-year horizon for submission to the three States.

38 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
variables and other system characteristics. Residential

and commercial sectors are modelled using an end-use

approach. Industrial sales are forecasted using an

econometric approach. Company-sponsored demandside management activity was initially excluded.135

System peaks are developed by allocating annual

energy to months, days, and hours of the year. System

costs are developed by including capital costs, operations and maintenance costs, fuel costs, customer costs

associated with demand-side management programs,

and the various environmental costs of candidate resource plans. The attempt is to keep prices as low as

possible (consistent with reliability) during the planning

horizon.

Environmental Considerations

NEESPLAN4 is predicated on compliance with existing

Federal, State, and local regulations. Steps currently

being taken and those planned for the future to meet

provisions of the Clean Air Act Amendments are

detailed.

In addition, several other potential issues likely to

emerge in the area of air quality requirements are also

taken into account. Significant items included in this

category are hazardous air pollutants, reductions in

nitrogen oxide emissions beyond 1995, and greenhouse

gas emissions. Based on these considerations, a range of

resource strategies is evaluated against several scenarios

to ensure that the “resource plan recommendations

would have sufficient flexibility to adopt a broad range

of possible outcomes.”136

All resource plans are also expected to comply with

existing regulatory requirements. For eight specific air

pollutants, emissions are projected based on an “ownload” dispatch. Emissions with respect to carbon

dioxide, sulfur dioxide, and nitrogen oxides in 2000 are

compared against stated goals to be achieved. Finally,

the system emissions are monetized using values

established by the MDPU.137

Areas of uncertainty, however, remain. Environmental

regulations are expected to be more stringent in the

future. The cost of compliance is not known and ranks

high on the list of uncertainties. The plan examines

environmental uncertainties in depth (Table 4). For each

environmental impact, there is an indication of the

probable cause of events and the related cost estimates.

Next is the possibility that not all resources that are

currently in use would continue to be in operation in

the face of changes in environmental regulations. To

confront these emerging issues, the NEES companies

have initiated several studies to examine cost and

technical data of various technologies that may be

needed to meet stricter environmental requirements.138

NEESPLAN4 embraces a novel approach to account for

the uncertainties. It uses the application of what the

company calls an “options theory.” It is a form of

analysis that “quantifies the value of flexibility in

specific resource alternatives.” Its operational impact in

resource planning is to place greater reliance on smallscale, short lead time projects that incorporate buyout

and termination provisions.139

Environmental Initiatives by NEES

As indicated earlier, NEESPLAN4 was drafted in

collaboration with the Conservation Law Foundation

(CLF). As a part of the planning process, the NEES

companies have set for themselves the goal of developing approaches to provide electric service in an

environmentally sustainable manner. Pursuing renewable energy projects is designed to meet this goal

partially.140

135For planning purposes, future demand-side management impacts are treated as a supply-side resource. 136New England Electric System Companies, Integrated Least Cost Resource Plan for the Fifteen Year Period 1994-2008, Vol. III, June 1994,

p. 244. 137The goal set in NEESPLAN4 is to reduce emissions during the 1990-2000 period as follows: carbon dioxide—20 percent, sulfur

dioxide—60 percent, nitrogen oxide—60 percent. See New England Electric System Companies, Integrated Least Cost Resource Plan for the

Fifteen Year Period 1994-2008, Vol. III, June 1994, p. 309. 138New England Electric System Companies, Integrated Least Cost Resource Plan for the Fifteen Year Period 1994-2008, Vol. IV, June 1994,

p. 347. 139The general strategy of the options theory is to manage company’s resources as a portfolio of options. In this approach, resource

options are used as “capacity insurance” to cover higher-than-expected growth or earlier-than-anticipated retirements. If the expanded

growth does not materialize, then the options will not be exercised, and retiring units will not be replaced. The concept is based on the

“Options Theory,” which deals with the subject of irreversible decisions that are made under uncertainty. See Avinash Dixit and Robert

Pindyck, Investments Under Uncertainty (Princeton University Press, Princeton, NJ, 1994). A brief summary of this approach is also

provided in the plan submitted by the NEES companies. 140Other options include stabilizing greenhouse gas emissions, reducing emissions from existing fossil-fuel plants, accounting for and

reducing all wastes, and maximizing efficiency of NEES’ operations and those of its customers.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 39
With a view to meeting the above goal, the New

England Electric System companies have also undertaken additional environmental initiatives to reflect

their commitment to reduce the adverse environmental

impacts of power generation by planning to use

generation technologies that reduce emissions. The

companies’ renewable energy initiative, “Green RFP,”

solicited bids from projects using renewable technologies. The solicitation sought for 200,000 MWh

annually or about 45 MW operating at 50 percent capacity scheduled to be in operation by 1997.

The companies received 41 bids, totaling about 1.4 million MWh (Table 5). These bids represented all of the

major renewable energy technologies and presented

projects that were located in all six New England States

and Canada. These bids for the projects were evaluated

and those projects that had the characteristics necessary

to provide the maximum value to the customers (and

also had the highest level of feasibility) were chosen

from among each renewable technology group. Based

on this criteria, seven projects for 36 MW were selected

(Table 6).141

In performing the economic analysis of the projects, the

companies compared the projected costs of these

projects with their future forecasted avoided cost.142

The companies also tested the renewable projects

against externality values as adopted by the MDPU.143

In addition, varying hypothetical values for carbon

dioxide emissions were also taken into account. The

effect of carbon dioxide adders was taken into account

(Table 7).144 The companies also considered raising

fuel prices by 1 to 2 percent above those assumed in

their original forecast.

In the aggregate, the expected costs of “Green RFP”

projects over their contract lives exceed the companies’

projected avoided cost on a present value basis (Table

6).145 The table also shows the comparative costs of

each project. The companies, however, noted that

individual project economics would change if

environmental externalities were included in the assessment. More specifically, the expected costs of the seven

projected renewable energy contracts would be $53.5

million below the companies’ projected costs on a

present value basis.146

Since the NEES companies operate in three States,

project contracts require the approval of utility

commissions in all of the three States. The MDPU

initially approved six of the seven projects on the basis

Table 5. Number and Available Annual Electrical Energy Output of Projects Bid by New England Electric

System Companies on the Green RFP (by Type)

Type of Project Number of Bids Received

Total Available Annual

Electrical Energy Output

(thousands of MWh)

Biomass . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 659

Hydroelectric . . . . . . . . . . . . . . . . . . . . . . . . . . 7 28

Landfill Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 200

Solar . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 34

Wind . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 209

Municipal Solid Waste . . . . . . . . . . . . . . . . . . . . 1 40

Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 210

Total ................................ 41 1,380

Source: New England Electric System Companies (Granite State Electric Co., Massachusetts Electric Co., and the Narragansett

Electric Co.), Request for Approval of Contracts Executed as Part of Companies' Renewable Resource Initiative, Volume 2:

Testimony and Exhibits, submitted August 1993 to the Massachusetts, New Hampshire, and Rhode Island Public Utilities

Commissions, pp. 11-12.

141Note that NEES selected projects for 36 MW even though it was initially planning to seek 45 MW of capacity. 142The avoided costs were for the year 2001 since NEES does not need any new capacity prior to 2002. 143Carbon dioxide values of $2 per ton, $10 per ton, and $24 per ton were used. 144The economics of all projects (considered by the NEES companies in their Green RFP) benefit from the adders since the net carbon

dioxide equivalent emissions are either zero or negative. 145The differences in 1993 and 1994 estimates result from a renegotiation of some of the contracts at a lower price. 146Based on the testimony of Mr. Michael E. Hachey before the MDPU in September 1994.

42 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
Table 6. Summary of Project Costs Versus Avoided Costs

Project

Energy

Source

Net

MW

Original Filing Cumulative

Present Worth 1993

(million dollars)

Current Filing Cumulative

Present Worth 1994

(million dollars)

Total

Contract

Payments

Avoided

Costs

Costs

Above

Avoided

Costs

Total

Contract

Payments

Avoided

Costs

Costs

Above

Avoided

Costs

Kenetech Windpowera . . Wind 20.0 43.7 26.9 16.8 38.5 25.8 12.7

Shirley ............. Municipal

Solid Waste

5.9 18.2 16.3 1.9 18.0 15.4 2.6

Johnston ........... Waste Heat 2.0 7.8 5.9 1.9 7.6 5.6 2.0

Plainville ............ Landfill Gas 3.0 11.0 9.5 1.5 9.2 9.2 0.0

Nashua ............ Landfill Gas 1.5 5.6 4.4 1.2 4.1 4.1 0.0

Randolph ........... Landfill Gas 2.6 12.6 10.0 2.6 10.3 10.3 0.0

Barre .............. Landfill Gas 1.0 4.4 3.3 1.1 4.5 3.0 1.5

Total .............. 36.0 103.3 76.3 27.0 92.2 73.4 18.8

a

The name of the contractor was changed from U.S. Windpower to Kenetech Windpower in 1994.

Source: New England Electric System, Request for Approval of Contracts Executed As Part of Companies’ Renewable Resource

Initiative, resubmitted to the Massachusetts Department of Public Utilities, September 1994, p. 18.

of their cost effectiveness. After renegotiation of

contract costs, the other States have also approved the

proposal. In effect, all projects have been approved.

The price impacts of proposed renewable acquisitions

are expected to be minor. Ratepayers in Massachusetts

will pay a real levelized cost premium of 0.006

cents/kWh. Rhode Island customers will pay nothing

above projected avoided costs, on a 1994 dollar net

present value basis, and the New Hampshire customers

would pay 3 percent above avoided costs or 0.005

cent/kWh real levelized premium.147

Externality Considerations and

New England Electric’s Projected

Resource Mix

New England Electric companies’ existing resources

total 5,610 MW (Table 8). In “The Resource Need

Evaluation,” the NEES companies stated that they will

have sufficient capacity to meet their load and required

reserve margins until 2002.

Generic resource additions during the 2003-2013 period

total 3,144 MW. The New England Electric companies

plan to build natural gas turbine units for a total of

1,507 MW to meet the peak-load demand. Of the

remaining 1,637 MW required to meet the baseload

demand, gas-fired combined cycle units account for the

1,355 MW, with coal accounting for the balance of 282

MW. Natural gas thus emerges as the fuel of choice in

NEESPLAN4.

The companies are concerned about this over-reliance

on one single fuel and will continue to evaluate the

alternatives available. In addition, the focus on

renewables and attempts to reduce greenhouse gases

will continue. Improvements in technology to reduce

emissions, as well as the push toward demand-side

management programs, will continue to be implemented.

Overall, the incorporation of monetized externality

values in resource planning may at best be viewed as

a shift toward natural gas. Renewable penetration—

based on the Green RFP—may be viewed as positive,

but the cost benefits accrue only if externality values

are internalized. It would thus be correct to say that

externality values had no effect on the makeup of the

implementation of NEESPLAN4.

147Based on submissions filed by the New England Electric companies before the State regulatory authorities.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 43
Table 7. Impact of Carbon Adder on Projects Beginning in 1994

Project

Technology

Type

$2/Ton CO2-Equivalent $10/Ton CO2-Equivalent $24/Ton CO2-Equivalent

A

¢/kwh

(1993

RLP)

B

¢/kwh

(1993

RLP)

C

1993

(million

dollars)

A

¢/kwh

(1993

RLP)

B

¢/kwh

(1993

RLP)

C

1993

(million

dollars)

A

¢/kwh

(1993

RLP)

B

¢/kwh

(1993

RLP)

C

1993

(million

dollars)

Kenetech Windpowera . . . Wind 0 (0.12) 16.0 0 (0.59) 12.7 0 (1.42) 7.1

Shirley . . . . . . . . . . . . . . MSW (0.14) (0.26) (0.6) (0.72) (1.32) (3.7) (1.73) (3.16) (11.2)

Johnston ............ Waste heat 0 (0.13) 1.6 0 (0.65) 0.8 0 (1.55) (0.5)

Plainville ............. Landfill gas (0.90) (1.02) (0.7) (4.50) (5.09) (10.0) (10.8) (12.2) (26.1)

Nashua ............. Landfill gas (0.90) (1.03) 0 (4.50) (5.14) (5.0) (10.8) (12.3) (13.7)

Randolph ............ Landfill gas (0.90) (1.02) (0.3) (4.50) (5.12) (11.1) (10.8) (12.3) (30.0)

Barre ............... Landfill gas (0.90) (1.03) 0.2 (4.50) (5.14) (3.2) (10.8) (12.3) (9.3)

Weighted Averageb .... (0.34) (0.46) (1.70) (2.31) (4.08) (5.53)

Total ............. 17.4 (19.5) (83.7)

a

The name of the contractor was changed from U.S. Windpower to Kenetech Windpower in 1994.

b

Average for projects weighted by their estimated annual generation.

A = Value of reduced greenhouse gas emissions due to reduction in emissions relative to existing emissions at the site. This

value is the “credit” that the project receives because it reduces emissions of greenhouse gases at the current site. For example,

a landfill has methane emissions. The landfill gas project would use the methane to generate electric power, effectively reducing

the emissions of methane at the landfill site. The value of the “credit” is based on the $/ton. CO2 value stated at the top of the table.

B = Column “A” plus the value of avoided greenhouse gas emissions from existing and new generating sources. The value in

Column B reflects an additional credit for the project, because the project would reduce the need to generate power from other units,

thus reducing the greenhouse gas emissions from those units. The value in Column B is the sum of Column A and this additional

credit from the project being a substitute for power from another unit.

C = Cumulative present worth of project costs above the utility’s projected avoided costs (including a credit for avoided

emissions). The value in this column is the difference between the total cost of power from the proposed project and the utility’s

projected avoided cost. The total cost of power from the project is its cumulative present value; future costs are discounted. The

project gets a credit for the value of the avoided emissions compared to the plant used to calculate the projected avoided costs.

The projected avoided cost is based on what the power would cost from a hypothetical natural gas plant.

RLP = Real levelized price.

CO2 = Carbon dioxide.

MSW = Municipal solid waste.

Note: Numbers in parentheses represent negative values.

Source: New England Electric System, Request for Approval of Contracts Executed as Part of the Companies’ Renewable

Resource Initiative, Vol. 2: Testimony and Exhibits, August 1993, p. 44.

The values were used for informational purposes, but

had no impact on future prices or emissions.

Recent Developments in Massachusetts

On December 22, 1994, the Massachusetts Supreme

Judicial Court found the designation of monetary

values by the MDPU to be beyond the range of its statutory authority. More specifically, the MDPU lacked

the authority to regulate the impact of power generation on the environment by imposing a levy on

power plant emissions. Protecting society from the

environmental impacts of power plant emissions was

deemed to be outside the scope of MDPU’s responsibility.

This case was brought before the supreme court by

Massachusetts Electric and the National Coal Association (NCA). The court did not agree with NCA’s

contention that the MDPU did not hold any authority

to order the consideration of environmental impacts for

planning purposes. However, the court agreed with

Massachusetts Electric’s contention that the MDPU’s

oversight should not result in extra costs to be borne by

the ratepayers.

44 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
Table 8. New England Electric’s Existing Resources

(Includes Committed Resources)

Description MW

Demand-side Management

(Supply-equivalent) .................. 300

Coal-fired Baseload Generation .......... 1,350

Oil- and Oil/Gas-fired Intermediate Capacity . 850

Hydroelectric Plants . . . . . . . . . . . . . . . . . . 580

Nuclear Entitlements and Participation . . . . 580

Utility Purchases ..................... 1,000

Nonutility Purchases . . . . . . . . . . . . . . . . . . 400

Pumped Storage, Diesels, and Other Facilities 750

Unit Sales to Other Utilities ............. -200

Total ............................. 5,610

Source: New England Electric System, Integrated Least Cost

Resource Plan for the Fifteen Year Period 1994-2008,

submitted to the MDPU on June 1, 1994.

While the court remanded the matter for consideration

by the MDPU, the operational impact of the court’s

decision will be to permit the utilities to exclude

incorporating externality values from their resource

planning submissions. In its June 1, 1995, order (D.P.U.

94-162), the MDPU supplanted the existing IRM procedures “by which resources are planned, solicited, and

procured by certain investor-owned electric companies

operating in the Commonwealth of Massachusetts” by

establishing procedures for integrated resource planning. These orders do not embody the MDPU’s externality policy.148

In view of what is stated above, it is possible to gain

the impression that consideration of environmental

externalities is no longer required. However, in a

Boston Edison Company demand-side management

preapproval case, the MDPU indicated that companies

were still required to include “reasonably foreseeable

environmental control requirements with cost implications for ratepayers,” when weighing resource

procurement alternatives (D.P.U. 95-1-CC at 12-14). The

MDPU, however, did not specify which method or

approach should be followed. Thus, each utility “must

present evidence that it has taken these potential costs

into account, and has included the avoidance of them

in its calculations of the cost effectiveness of its

demand-side management programs and its resource

decision process.”149

148D.P.U. 94-162. 149Theo MacGregor, Massachusetts Department of Public Utilities, “Environmental Externality Policy in Massachusetts,” paper presented

to the NARUC Energy Conservation Committee, Subcommittee on the Environment (Washington, DC, February 1995).

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 45
5. The State of Wisconsin Case Study

This chapter describes the decisions of the Wisconsin

Public Service Commission (PSCW) on externalities and

the manner in which the State’s largest investor-owned

electric utility, Wisconsin Electric Power Company

(WEPCO), has considered externalities in its resource

planning. The information presented in this chapter

was gathered from an analysis of the relevant decisions

and orders by the PSCW. Submissions made by

WEPCO were also analyzed. An evaluation of impacts

(of incorporating externalities) is based on discussions

with State regulatory authorities and the WEPCO

officials.

Treatment of Environmental Externality

Issues at PSCW

The PSCW maintains that it had “an early start with,

and has a proud tradition of, involvement with environmental concerns.”150 The starting point for the

PSCW was the enactment of the Wisconsin Environmental Policy Act in 1971 requiring the PSCW to

review the environmental effects of all its major actions.

This was followed by the passage of the Power Plant

Siting Law in 1975 requiring the PSCW to consider

health, safety, and environmental issues before approving utility plans. The State laws also require that

the advance plans for resources submitted by utilities

take environmental issues, among others, into account.

The PSCW maintains that all Advance Plans (APs) since

1978 have taken environmental considerations of one

kind or another into account.151 Advance Plan 2

(1980), for example, recognized that the impacts of air

pollutants (i.e., externalities) are costs that are not

reflected in the standard cost/benefit analysis. A major

study to examine the effects of acid deposition was

accordingly ordered. Subsequently, Advanced Plans 3

and 4 took other externality aspects into account.

Advance Plan 4 (1986) directed the utilities to submit

future plans through “integrated resource planning.”

Within this framework, costs and benefits including

those that are “Not Easily Expressed into Dollars

(NEEDS)” were also to be considered.152

Advance Plan 5 (1989) directed the electric utilities to

incorporate environmental costs in their evaluation of

options. Specifically, utilities were required to apply a

15 percent “noncombustion” credit to ways of satisfying

demands that do not involve the burning of fuels (in an

attempt to promote demand-side management resources). Critics point out that this requirement had

little impact on utility plans since the credit was not

enough to overcome the private cost disadvantages of

noncombustion options.153

The PSCW also recognized that there are externalities

other than those caused by combustion. Utilities were

directed to develop methods to permit inclusion of

other externalities in Advance Plan 6. While various

methods of incorporating externalities in the resource

planning process were advanced and debated, the

PSCW concluded that “monetization” represented the

most straightforward method since it sets a value for a

specific amount of externality.154 The PSCW emphasized setting monetized values for greenhouse gas

emissions, however, in the belief that emissions of

carbon dioxide, methane, and nitrous oxide would be

subject to national or international regulation.

150State of Wisconsin, Public Service Commission, Advance Plan 6: Staff Issue Paper - Externalities (Madison, WI, October 1991), p. 3. 151An “Advance Plan” is filed by Wisconsin’s electric utilities every 2 years, pursuant to 196.491 Wisconsin Statutes and Wisconsin

Administrative Code Chapter PSC 111. The purpose of the Advance Plan is to inform the PSCW and the general public of the utilities’

plans for the future. 152NEEDS was the term used by the PSCW to describe externalities. See State of Wisconsin, Public Service Commission, Advance Plan

6: Staff Issue Paper - Externalities (Madison, WI, October 1991), p. 4. 153This requirement also worked against the use of renewable technologies (like biomass) that used combustion to produce power.

See Research Triangle Institute, Accounting for Externality Costs in Electric Utility Planning in Wisconsin (Final Report) (Research Triangle

Park, NC, 1991), pp. 2-1 through 2-27. 154PSCW recognized the implicit appeal of the “damage cost method” in estimating the public’s willingness to pay to avoid externalities.

However, consideration of that method was not taken up for want of sufficient information. Docket No. 05-EP-6, p. 49. For additional

discussion of the methods considered by the PSCW, refer to State of Wisconsin, Public Service Commission, Advance Plan 6: Staff Issue

Paper -Externalities (Madison, WI, October 1991).

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 47
The above conclusions are reflected in PSCW’s order of

September 15, 1992, mandating that utilities use certain

monetized externality values when determining the

economic cost of resource options in their planning

process.155 Utilities are to use these values when comparing demand-side management programs as well as

generation capacity options. The values are to be applied plant by plant and are to be considered as energyrelated cost options. As such, there will be no impact

on demand- or capacity-related costs.

These externality values are also to be used in the

design and implementation of demand-side management programs. Hour-by-hour marginal energy costs,

including carbon dioxide costs, are to be projected and

compared to the costs of reducing the demand. This

procedure credits demand-side management programs

for the production of greenhouse gases that these measures avoid.

The utilities are also to keep these values in mind when

considering incentives for nonutility generators to use

renewable energy resources in producing the electric

power that they sell to utilities. In addition, the PSCW

requires utilities to consider externalities other than the

regulatory risks associated with greenhouse gases.

PSCW recognizes that some externalities cannot be

easily measured, but notes that damage-cost estimates

are appealing.

The PSCW limited its order to the risk of future regulation because of significant controversy over its

authority in the area of air pollution. Utilities claim that

legislation states that the PSCW may not reject a certificate of public convenience and necessity because of

air pollution impacts if the utility is in compliance with

regulations. The PSCW’s interpretation is that the

Wisconsin legislature did not intend to preclude the

PSCW from accounting for environmental externalities,

only that it not issue clean air standards that are more

stringent than State standards in effect. The PSCW

makes the important distinction that externality values

are not a way of imposing emission standards on

utilities. Rather, they are a means of more accurately

accounting for the total cost of a resource option, so

that its costs and benefits can be compared to other

options.

Two utilities are exempt from the application of the

externality values because they operate in several

States. Wisconsin considers it unreasonable to impose

its specific order on these utilities because other States

have other regulations. The utilities would be subject to

conflicting requirements.

Externality Values Adopted by Wisconsin

The externality values (in 1992 dollars) stipulated by

the PSCW for greenhouse gases are:156

• Carbon dioxide . . . $15/ton ($ 0.0075/lb)

• Methane ........ $150/ton ($ 0.075/lb)

• Nitrous oxide .... $2,700/ton ($ 1.35/lb).

These values are used as a hedge against the risk of

future greenhouse gas regulations. Utilities are to multiply the monetized values by the amount of greenhouse

gases that the plant will emit, and apply the resulting

costs to the energy-related costs of the plant for the

period during which the energy is generated.

The externality values adopted by the PSCW are a

compromise selected from a wide range of possible

values. As an example, carbon dioxide reduction values

presented to the PSCW (Table 9) ranged from a high of

$50/ton of carbon dioxide to almost nothing at all.

During the planning process, utilities in the State can

offset greenhouse gas emissions. As an example, a

utility could consider tree planting or forest protection,

thereby offsetting carbon dioxide emissions associated

with a resource plan.157 In such a case, the monetized

greenhouse externality values would then apply to the

remaining balance. The PSCW stressed that the offset

method should be reliable and persistent and should

cost less than the monetized value of carbon dioxide.

The Integrated Resource Planning (IRP)

Guidelines in Wisconsin

In February 1990 and July 1993, the PSCW revised and

approved the Integrated Resource Planning Guidelines for

Wisconsin. These guidelines were developed cooperatively with the electric utilities in the State and are

155Findings of Fact, Conclusion of Law and Order, with reference to the Wisconsin Public Service Commission’s Docket No. 05-EP-6. 156Analysis made by the Tellus Institute of Boston and the Wisconsin Commission staff show clearly that the effect of the CO2 value

on the increased costs dominates the effect of the externalities values of the other gases. The CO2 costs account for at least 97 percent

of the total increase in cost in both coal and natural gas plants. See Stephen Bernow, et al., Valuation of Environmental Externalities for

Electric Utility Resource Planning in Wisconsin (Tellus Institute, Boston, November 1991). 157Demand-side management programs were not considered as a feasible offset.

48 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
Table 9. Range of CO2 Externality Values Compiled by the Wisconsin Public Service Commission

Source of Estimate Value (dollars per ton CO2)

Nordhaus (for a 50-percent Reduction) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

Oregon PUC/U.S. Department of Energy 1991 Study (High End of Range) . . . 40

Nordhaus (for a 30-percent Reduction) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Citizens for a Better Environment Recommendation in Advance Plan 6 . . . . . 23

Massachusetts PUC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Nevada PUC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Nordhaus (for a 25-percent Reduction) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Wisconsin Commission Decision . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Oregon PUC/ U.S. Department of Energy (Low End of Range) . . . . . . . . . . . 10

California Energy Commission and Public Utility Commission, 1991 ........ 7.50

New York Public Service Commission ............................. 1

CO2 = Carbon dioxide.

PUC = Public Utility Commission.

Source: Reproduced from Wisconsin Public Service Commission, Docket No. 05-EP-6, Exhibit No. 363.

applicable to the planning process used by Wisconsin

Electric.158 Integrated plans evaluate and include

demand-side and supply-side resources on a consistent

basis to provide efficiency benefits to the ratepayers.

The PSCW requires that the integrated planning process

be done jointly by the utilities. This joint plan contains

projections of statewide demand for electricity over a

20-year planning horizon together with recommendations with respect to the acquisition of additions to

capacity. The joint plan addresses major issues such as

cost; reliability; efficiency; and the health, safety, and

environmental effects of various plans for meeting the

future electrical energy needs of the State. Resource

options are compared using avoided cost—the cost a

utility would not have to pay if it avoided supplying a

customer with power from a conventional power plant.

In addition, each utility also submits its own integrated

resource plan in the form of a report termed the

Advance Plan. The purpose of the Advance Plan is to

inform the PSCW and the general public of the utility’s

plans for the future.

In view of what is stated above, the integrated resource

planning is a two-step process in Wisconsin. In the first

step, a base forecast of need for electricity is developed

jointly by the utilities in the State. The second step is to

determine which resources individual utilities should

acquire. The PSCW issues an order once every 2 to 3

years approving an electric plan that includes new

power plants, energy conservation measures, and large

electric power transmission lines. The PSCW, however,

notes that the utilities’ willingness to plan jointly in this

type of process is changing due to an increase in competitive pressures.

Resource Planning by the Wisconsin

Electric Power Company159

In January 1994, Wisconsin Electric submitted its

Advance Plan 7, containing its forecast for the 1994-

2013 period. This plan shares the common features of

the joint plan submitted by the electric utilities in the

State in terms of which all utilities are required to use

the integrated resource planning guidelines in preparing the long-term plans. The process involves

evaluation and selection of a bundle of supply- and

demand-side options that provide energy requirements

reliably and at the lowest cost. The Wisconsin Statewide

Integrated Planning Committee (which is assisted by a

number of task forces) is entrusted with the task of

158For additional information on this subject, see “Prepared Testimony of Timothy Kay - Docket No. 05-EP-7 during the week of Nov.

28, 1994” and “Revision of the Least Cost Planning Guidelines for Wisconsin” issued by the PSCW on August 26, 1993. For a

chronological development of the integrated resource planning process in the State, see Edison Electric Institute, “Integrated Resource

Planning in the States - 1994 Source Book” (Washington, DC, 1995), pp. 409-420. 159Wisconsin Electric Power Company is commonly referred to as WEPCO.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 49
overseeing the formulation of utilities’ plans.160 Figure

2 depicts the flow diagram of the current integrated

resource planning process used in the preparation of

Advance Plan 7. The plan formulated by Wisconsin

Electric follows the outline shown in Figure 2.

In developing the long-term forecast, a number of

features are common to all utilities. These include:

• Development of an extensive information database

on demand-side options (energy efficiency measures, load management, etc.) and supply-side

options (conventional generation, new technologies, renewable resources, system efficiency

improvements, nonconventional sources including

purchases, etc.)

• Determination of objectives for demand-side options’ evaluation. Different perspectives on the

subject include costs for participating and nonparticipating customers, total and societal costs,

utility’s revenue requirements, etc. An appropriate

discount rate, environmental externalities, and

other socio-economic factors are also taken into

account. These considerations are intended to enhance quality, marketability, and reliability from

various perspectives.

Customers Market

Planning

Objectives

Demand-Side

Options

Supply-Side

Options

Evaluate Options

Plan Analysis Using

Integration Model:

- Externality Assessment

- Scenario Analysis

- Alternative Plans

Monitor

Implement Plan Integrated Resource Plan

Net Forecasts

Base Forecast

Figure 2. Integrated Resource Planning Process in Wisconsin

Source: Advance Plan 7: Planning Wisconsin’s Electrical Future, submitted by electric utilities to the Wisconsin Public Service

Commission on January 17, 1994, pp. C1-2.

160The task forces include Demand-Side Management, Power Supply Planning, Renewable Energy, Externalities, Load Forecasting, and

Environmental and Financial Analysis. Some of these functional task forces are further combined into a Joint Planning Task Force to

implement joint utilities’ planning.

50 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
• Consideration regarding interfuel substitution

options

• Assessment of the effect of externalities involved

using the monetized values as indicated earlier.

These values are: carbon dioxide – $15/ton,

methane – $150/ton, and nitrous oxide –

$2,700/ton. The cost of compliance with the Clean

Air Act Amendments is presumed to be internalized.161

• Coordination of plans with other utilities to determine if there exist any cost-effective options to

coordinate activities among utilities in the State

• Development of “contingency plans” to evaluate

various scenarios with demand rising higher or

lower than projected. Other perspectives may also

be included. Sensitivity analysis performed under

differing assumptions is also undertaken.

After taking the common elements of the planning/

forecasting process into account, Wisconsin Electric’s

base forecast was developed using a series of models

which incorporate historical data of its service territory,

sectoral energy sales forecast, and economic and energy

use assumptions.162

Supply-side options to meet the projected system load

include conventional and advanced technologies, nonutility power, and purchase options.163 Renewable

technologies including wind, wood and biomass, wasteto-energy, hydro, and solar were also considered. All

supply-side options were screened on the basis of

energy and capacity costs.164 Wisconsin Electric also

supports the Advanced Light Water Reactor program

but notes that its design availability is still 5 to 6 years

away.

Energy efficiency, conservation, and load management

constitute the core of Wisconsin Electric’s bundle of

demand-side options. All demand-side management options are screened using a cost-benefit model.165

Wisconsin Electric maintains that the cumulative impact

of these programs in the aggregate is to significantly

dampen the growth in summer peak demand.166

In the final step, the supply-side options were evaluated simultaneously with demand-side options to

determine their inclusion in the resource plan.167 In

the first case, the process was conducted in which only

internalized costs were considered followed by another

case in which greenhouse gases were monetized using

values specified by the PSCW. In neither of these

iterations were renewables options selected. Wisconsin

Electric then ran two more iterations with a “fixed” set

of renewable options assumed in the plan. The results

did not materially change.

Wisconsin Electric is required to include specific monetized values to cover the risk of future greenhouse gas

regulations in determining the economic cost of new

161Fossil fuel options are evaluated using the monetized costs in both dispatch decisions and as part of the annual cost of operation.

The PSCW further requires that the utilities expand their analysis by developing methods to consider “a broader array of all nonmonetized externalities attributable to demand-side and supply-side options as part of their evaluation process.” See Advance Plan 7 -

Planning Wisconsin’s Electrical Future, Appendix C1, (filed by the Wisconsin utilities in January 1994), pp. C1-4. 162The derivation of the base forecast uses two separate but related approaches. The econometric approach uses forecasts of underlying

economic variables and projected growth in population and other appropriate variables. The end-use or the engineering approach

evaluates sectoral demand growth as a function of factors specific to each sector. The end-use forecast then adds up all the end uses to

arrive at the total base forecast. 163Wisconsin Electric also took into account plants that may have to be retired during the planning period. As an example, the two

Point Beach nuclear units (a total of 984 MW) are expected to be retired around 2010 and 2012, though any decision will be based on

future relicensing studies. Two 500-MW coal units are used as place holders in Wisconsin Electric’s plans, in case the two nuclear units

are retired. 164Wisconsin Electric uses a large number of models to arrive at its forecast in addition to those prescribed for use by the PSCW. The

company also evaluated over 200 technologies (with respect to the conservation and load management) and included more than 130 in

its resource plan. These programs reduced its peak demand growth from 2.1 percent to 1.5 per cent per year during the 1994-2013 period. 165Demand-side options that were selected by the Wisconsin Electric (in the screening process) were those with a benefit/cost ratio of

1.0 or more. 166Wisconsin Electric’s plan also has more load management than in the least-cost plan. The plan is to have 592 MW of additional

demand reduction by 2003. The utility plans on increased demand-side management to reduce its system peak demand by about 540

MW by the summer of 1994 or 11.7 percent of its base peak demand to 955 MW in the year 2003, or 16.8 percent of base peak demand.

The “Smart Money” program offers financial rebates and low- or no-interest loans for installing energy-efficient appliances and equipment.

The company also offers fee incentives to pay for fees to evaluate or implement building efficiency improvements. 167Simultaneous evaluation of the demand- and supply-side options involves the use of IRP-Workstation - the software that the PSCW

requires utilities to use. Monetized values for the emissions are included in both supply- and demand-side costs. This cost also includes

a projected cost of SO2 emission allowances.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 51
generating plants. Thus, the externality values specified

by the PSCW were included in evaluating available

options. According to the documents submitted by the

utility, the development of demandside management

programs and the evaluation of fossil supply options

included monetized externality values.168

Uncertainty Analysis

Wisconsin Electric recognizes that there may be many

uncertainties in the future. Planning in an environment

of uncertainty “requires resource plans which embody

tradeoffs between cost minimization under current conditions and risk minimization with respect to future

uncertainties.” 169

Wisconsin Electric identifies critical areas that lead to

uncertainty. These include load forecast, fuel price

forecast, and monetized externality values. Different

combinations of these projections define different

scenarios. A decision-analysis methodology (which

allocates probability values to critical assumptions) was

used to evaluate plan performance under varying conditions.170

Wisconsin Electric’s plan resulting from the uncertainty

analysis did not suggest any significant changes. The

new construction mix turned out to be primarily gasfired with no new renewables in the plan. Yet, Wisconsin Electric decided to incorporate renewable energy

resources in its plan in the belief that improvements in

technology and cost may render renewables more attractive in the future.

Significant conclusions of Wisconsin Electric’s findings

include:171

• Natural gas will be the fuel of choice for most of

the new capacity in the future.

• There will be no new renewable energy capacity.

• Both dispatchable and non-dispatchable load management are included.

Wisconsin Electric’s Resource Current

Inventory and Future Requirements

Wisconsin Electric owns and produces most of the

electricity necessary to meet customer loads. Its 1993

total generating system consisted of 981 MW (19.5 percent) of nuclear generation, 3,531 MW (70.3 percent) of

coal-fired steam generation, 439 MW (8.7 percent) of

combustion turbine and diesel generation, and 75 MW

(1.5 percent) of hydro generation for a total of 5,026

MW. Based on this generating mix, the relative contribution of each energy source is currently as follows:

coal, 60 percent; nuclear, 30 percent; purchases, 8

percent; hydro and other renewable energy, 1.5 percent;

and gas and oil, 0.5 percent.172

Supply-side additions total 2,367 MW for the 1994-2013

period (Table 10). These include:

• 187 MW of renewable resources (102 MW wind,

60 MW wood/biomass, 9 MW hydro, 11 MW

waste-to-energy, and 5 MW solar)173

• 14 peaking units totaling 1,162 MW

• 4 intermediate load units totaling 800 MW

• One cogeneration plant of 218 MW.

Note that the inclusion of renewables is governed by

considerations other than externalities.

Wisconsin Electric’s Assessment of

Externality Considerations

Wisconsin Electric contends that the inclusion of externality values (in plan formulation and optimization)

168In evaluating supply-side options, monetized emissions were used both as a cost for dispatch decisions and as a part of the total

cost of operation. See Advance Plan 7: Technical Support Document D1 submitted by the Wisconsin Electric in January 1994 to the Wisconsin

Public Service Commission, p. D1.6-6. 169Advance Plan 7: Technical Support Document D1, submitted by the Wisconsin Electric in January 1994 to the Wisconsin Public Service

Commission, p. D1.6-7. 170The decision analysis model used by Wisconsin Electric is called “Multi-Objective Integrated Decision Analysis System (MIDAS).”

The model is used to compute the present value of revenue requirements for each scenario. The model compares planning and dispatch

combinations with and without monetization with respect to the greenhouse gas emissions. The MIDAS capacity plan is used with

another model to develop data for the IRP filing. 171However, in the near term, demand is met by purchases, gas-fired combustion turbines, and cogeneration projects. In this time

period, there are plans for a 4-MW waste-to-energy facility and a 2-MW wind demonstration project. 172Advance Plan 7: Planning Wisconsin’s Electrical Future filed by the Wisconsin Utilities with the Wisconsin Public Service Commission

in 1994, p. D1.1-2. 173Currently, Wisconsin Electric has 88.4 MW of renewable capacity (all hydroelectric).

52 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
Table 10. Wisconsin Electric Power Company Advance Plan 7, 1994-2013

(Number of Capacity Additions by Type and Size of Unit)

Year

Combustion

Turbine

Intermediate

Load Unit

Base

Load Unit

Capacity Purchase

1 Year Firm Multi-year Renewable

1994 . . . . . . . 2 (83 MW) 1 (280 MW)

1995 . . . . . . . 4 (83 MW) 1-WE (4 MW)

1996 ....... a1 (71 MW) a1 (147 MW)

1997 ....... b1 (100 MW) c1-W (2 MW)

1998 .......

1999 ....... 1-WE (7 MW)

2000 ....... 1-W (50 MW)

1-W/B (30 MW)

2001 . . . . . . . 1 (83 MW)

2002 . . . . . . . 1 (83 MW)

2003 . . . . . . . 2 (83 MW)

2004 . . . . . . . 1 (83 MW)

2005 . . . . . . . 1 (83 MW) 1-W (50 MW)

1-W/B (30 MW)

2006 ....... 1-H (9 MW)

2007 ....... 1 (200 MW)

2008 .......

2009 ....... 1 (200 MW)

2010 ....... 1 (200 MW) 1-S (5 MW)

2011 . . . . . . . 1 (83 MW) 1 (500 MW)

2012 ....... 1 (200 MW)

2013 ....... 1 (83 MW) 1 (500 MW)

a

Cogeneration unit.

b

13-year purchase.

c

Demonstration unit.

H = Hydro. MW = Megawatt.

S = Solar. W = Wind.

WB = Wood/biomass. WE = Waste to energy.

Source: Wisconsin Electric Power Co., Advance Plan 7: Technical Support Document D1 (Madison, WI, January 1994),

p. D1.C-13.

has only a small impact on the total internal costs and

thus on the selection of resources. In defending this

contention, the company states that it “is because the

least-cost plan optimized without externality values is

already primarily composed of demand-side management and new gas-fired generating facilities. Including

the value of externalities does not change the plan.”174

Wisconsin Electric evaluated the effects of including or

not including externalities in two interrelated decisions

(Table 11). The first decision concerns planning the

resource mix, for example, the decision on what type of

power plant capacity to add to the existing system. The

second decision concerns how to dispatch existing

capacity to meet demand. The internal costs for the

utility will be the lowest if externalities are not

considered for either decision. Therefore, the internal

cost in the second column is indexed at 100. The other

columns show all combinations for the two decisions.

The conclusion shown is that the difference in the total

costs is not large and the difference in Wisconsin

Electric’s internal costs increases at most by 1.3 percent.

A recently completed study indicates that externality

considerations by Wisconsin Electric only changed the

order of deployment of units; a 200 MW baseload unit

174Advance Plan 7: Planning Wisconsin’s Electrical Future filed by the Wisconsin Utilities with the Wisconsin Public Service Commission

in 1994, p. D1-16.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 53
Table 11. Effect of Monetized GHG Externality Values on Wisconsin Electric’s Resource Mix and Costs

(As a Percentage Relative to Actual Costs)

Cost Component

Optimal Resource Mix,

Without Considering Externalities

Optimal Resource Mix,

With a Consideration of Externalities

Operate With

Externalities

Operate Without

Externalities

Operate With

Externalities

Operate Without

Externalities

Internal ............ 101.1 100.0 101.3 100.2

External ........... 55.5 56.9 55.3 56.7

Total ............. 156.6 156.9 156.6 156.9

Note: GHG = Greenhouse gases.

Source: Wisconsin Electric Power Co., Advance Plan 7: Planning Wisconsin’s Electrical Future, “Technical Support Document

D1,” Submitted to the Wisconsin Public Service Commission in January 1994, pp. D1.C-9 through D1.C-18.

was substituted by a 200 MW intermediate-load range.

Further, the company points out that two changes were

made, in part, on qualitative consideration of externalities.175 Apart from this change, there were no

other effects on the supply side. Note, however, that:

• Atmospheric fluidized bed combustion coal plants

were considered for baseload only through 2004

when integrated gasification combined-cycle coal

units were assumed to offer greater efficiency and

emissions improvement.176

• Despite the fact that renewables were not costeffective, the utility incorporates some renewables

with the expectation that future cost reductions

will make them more attractive. The PSCW notes

that this explanation makes it unclear whether the

inclusion of renewables was based on cost advantages (i.e., economics) or externality considerations.177

Wisconsin Electric’s analysis shows that the overall

impact of including monetized externality values on

demand-side management programs is not significant.178 No other programs are affected by qualitative

externalities (other than implicitly) and no technologies

are excluded due to externalities. In addition, renewable

energy resources fail to be selected in Wisconsin Electric’s least-cost plan in both cases that include or

exclude monetized externalities for greenhouse gas

emissions (Table 11).

The use of the greenhouse gas externality values in the

analysis has only a very small impact on the total

(internal) costs of the system. According to Wisconsin

Electric, the reason is that the resource mix, without

consideration of externality values, already has a considerable amount of demand-side management programs and new gas-fired generating facilities.

The conclusion, then, is that the greenhouse gas externality values have little impact on the cost-effectiveness

of the renewables and a very small impact on demandside management programs.

Another point of interest is to note that the impact of

externality considerations on costs is rather small—

about 1 percent—as long as monetary values are used

only for planning purposes. If regulations for a carbon

dioxide tax are introduced, the cost impact will be

significantly higher.

175Oak Ridge National Laboratory, The Effects of Considering Externalities on Electric Utility’s Mix of Resources: Case Studies of Massachusetts,

Wisconsin and California (Oak Ridge, TN, July 1995). Also, see prepared testimony of David B. Iliff of the Wisconsin Public Service

Commission, Docket No. 05-EP-7, during the week of November 28, 1994. 176The utility’s analysis suggests that integrated gasification combined cycle (IGCC) plants would be cost-effective, with or without

consideration of the GHG monetary externality values. Discussions with the utility officials indicated that these IGCC coal-fired plants

were placeholders for the two nuclear plants in the event they were retired. 177Testimony of David B. Iliff of the Wisconsin Public Service Commission, Docket No. 05-EP-7, during the week of November 28, 1994. 178The overall impact of using GHG externality values on DSM is that they increased the projected level of DSM by as little as 10 MW

per year through the year 2013. As an example, in 2003, about 5 percent of the demand impacts (MW) and 8 percent of the MWh impacts

are due to using monetized externalities in the plan.

54 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
PSCW’s Assessment of the Impact of

Considering Externalities on Wisconsin

Electric’s Resource Mix

The PSCW staff released in July 1994 their assessment

of the electric utility plans with specific reference to

Advance Plan 7.2.179 Among other items, this assessment report details the directives issued to the utilities

for improving their plans.

The PSCW’s directives to the utilities were to use externalities in two ways. First, they were to add monetized

emission values to all power plants that produce greenhouse gases to reflect the expected costs of future

controls or taxes on greenhouse gases. This action was

expected to provide insurance against making wrong

decisions. Next, the PSCW directed the utilities to

develop their own method for considering environmental impacts that were not covered by the greenhouse adder. To perform this task, the utilities were to

rely on such current information that was transparent

and flexible.

The PSCW took notice of the fact that the power plants

proposed for new capacity additions do indicate a shift

generally from coal to natural gas. This impact would

be reasonable to anticipate if the externality values for

greenhouse gases were used in the evaluation process.

However, the utilities, including Wisconsin Electric,

maintain that the shift is due to economic reasons and

does not result from the incorporation of monetized

externality values. The utilities present a somewhat

similar argument to explain the increasing penetration

of demand-side management programs.180

The PSCW maintains that utilities’ consideration of

externalities other than the greenhouse gases is not as

clear.181 Only some utilities took externalities other

than greenhouse gases into account. The Commission

intends to collect additional information in this

area.182

The PSCW also attempted to visualize the future of

externalities within a competitive environment that the

utilities are likely to confront in the future. Including

externality costs will raise production costs which will

be reflected in retail rates. The utilities’ interest is to

keep costs down so that they can compete for (and retain) large industrial customers. Accordingly, the utilities may want to recover only the production costs.

The PSCW, however, maintains that increased costs (resulting from inclusion of externalities) would be offset

by a reduction in environmental costs. There was apparent disagreement between the PSCW and Wisconsin

Electric over the costs of wind power and the effectiveness (e.g., participation rate) of DSM programs. This

disagreement led to differences in their assessments of

the least-cost plan. The utility had fewer demand-side

management programs and less renewable energy in

their plan than the PSCW staff thought there should

be.183

Concluding Observations

Incorporation of externality considerations has not resulted in any perceptible shift in the resource selection

process at Wisconsin Electric. The switch to natural gas

is attributed to cost effectiveness rather than to externality considerations. The decision to use renewables is

more in the nature of an insurance against the uncertainty of regulatory changes. In addition, the utility

stands to gain experience as renewable technologies

mature with the added expectation that costs may go

down. With competition making inroads in electric generation, Wisconsin Electric’s priority will be to retain its

market share and the value of its equity. These objectives may be at odds with efforts to equate societal

costs with private costs.

179State of Wisconsin, Public Service Commission, Staff Assessment of Electric Utility Plans: Advance Plan 7 (Madison, WI, July 1994). 180State of Wisconsin, Public Service Commission, Staff Assessment of Electric Utility Plans: Advance Plan 7 (Madison, WI, July 1994), pp.

56-60. 181Some of the utilities in the State had (prior to the issuance of the AP-6 order) entrusted the Research Triangle Institute to prepare

a report dealing with the subject of environmental accounting. Its report, released in November 1991, deals with various methodological

issues and approaches to externalities. The extent to which any of the approaches discussed in the report were adopted for

implementation is not known. See Research Triangle Institute, Accounting for Externality Costs in Electric Utility Planning in Wisconsin (Final

Report) (Research Triangle Park, NC, November 1991). 182For example, for Wisconsin Electric, PSCW staff said that there was no description of any consideration. In data request responses,

the utility indicated that although there was “no explicit characterization” of qualitative externalities, they were still considered. See Oak

Ridge National Laboratory, The Effects of Considering Externalities on Electric Utility’s Mix of Resources: Case Studies of Massachusetts, Wisconsin

and California (Oak Ridge, TN, July 1995). 183Discussions with the officials of the Wisconsin Public Service Commission and Wisconsin Electric in November 1994. See Oak Ridge

National Laboratory, The Effects of Considering Externalities on Electric Utility’s Mix of Resources: Case Studies of Massachusetts, Wisconsin and

California (Oak Ridge, TN, July 1995).

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 55
6. The State of California Case Study

This chapter describes the decisions of the California

Public Utility Commission (CPUC) on externalities and

the manner in which the State’s largest electric utility,

Pacific Gas and Electric, has considered externalities in

its resource planning. An evaluation of impacts of

incorporating externalities is based on discussions with

State regulatory authorities and officials of Pacific Gas

and Electric.184

Treatment of Environmental Externalities in

California

The State of California experiences some of the highest

levels of air pollution in the country.185 To alleviate

this problem, the State air quality standards (in conjunction with Federal standards) specify allowable

ambient concentrations for pollutants.186 Controlling

power plant emissions is, therefore, a vital part of the

State’s strategy in meeting required air quality standards.187 A summary of environmental regulations

affecting electricity generation in California is shown in

Table 12.188

The California Energy Commission (CEC) identifies

options (for implementation) in an attempt to meet the

State’s need for improvements in air quality. In its 1990

Electricity Report, the CEC listed the following approaches to reduce emissions from power plants:

• Retrofitting existing facilities, replacing them with

cleaner and more efficient gas-fired units, or substituting for them either nonpolluting or less

polluting sources like demand-side management

programs or renewables189

• Placing a monetary value on in-State and out-ofState residual emissions with respect to each

major pollutant associated with electricity generation

• Stipulating offset availability within a marketbased approach.

The CEC also directed that all costs and emissions

impacts of compliance with air quality regulations be

accounted for in performing the analysis of the cost

effectiveness of power generation alternatives so that

the cost of electricity to society could be minimized.190

The mandate to initiate the above actions stems from

Assembly Bill 3995 passed by the California legislature

184Dr. Suraj P. Kanhouwa of the Energy Information Administration and Dr. Russell Lee of the Oak Ridge National Laboratory met

with the State regulatory authorities in California as well as with the officials of Pacific Gas and Electric Co. 185California Energy Commission, 1990 Electricity Report (Sacramento, CA, October 1990), pp. 5-1 through 5-18. 186Regulations to improve air quality standards have been in force in California since the 1960s, starting with the establishment of the

automobile exhaust emission standards and the introduction of catalytic converters in the 1970s. At the same time, smoke stack pollution

control devices were introduced to reduce emissions from power generation. The State’s Clean Air Act of 1988 was designed to address

California’s unique air quality problems. See California Energy Commission, 1990 Electricity Report (Sacramento, CA, October 1990), pp.

5-1 through 5-18. 187Environmental regulations cover emissions from power plants as well as emissions from other sources, such as automobiles and

industrial facilities. However, not all sources of emissions are covered by regulations and the regulatory authorities recognize that even

with current regulations in place, negative impacts remain with the result that their associated costs go unaccounted for in the price for

energy. The discussion in this report deals only with externality considerations as applicable to power generation in California. See

California Energy Commission, Staff Testimony on Internalizing Externalities, Docket No. 93-ER-94 (Sacramento, CA, September 15, 1994),

p. 1. 188According to the California Energy Commission, the environmental regulations listed in Table 12 are those that may require review

to ensure that environmental objectives are met or that may influence the development of the competitive electricity industry. See

California Energy Commission, Draft Final 1994 Electricity Report (Sacramento, CA, June 1995), p. 3-25. 189Capital and operating costs of these options vary. 190Note that minimizing the environmental costs of providing power is one of the several objectives of regulatory authorities. Other

traditional objectives are: ensuring the availability of reasonably priced power, its reliability, and the industry’s good financial health.

See California Energy Commission, 1992 Electricity Report (Sacramento, CA, January 1993), pp. 47-65.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 57
Table 12. Summary of Environmental Regulations Affecting Electricity Generation in California

Environmental

Regulation Applicability Implications for Electricity Generation and Competitive Futures

Best Available

Retrofit Control

Technology

(BARCT) Rules

Existing combustion

power plants located

in extreme, severe,

and serious

nonattainment areas

Air district where major utility boilers are located have all adopted Nitrogen Oxides

(NOx) BARCT rules. Most districts have plans for BARCT rules to control NOx

emissions from nonutility boilers and gas turbines. Districts have, or will soon adopt

BARCT rules for nonutility boilers and gas turbines. This should levelize the playing

field among existing power plants. Some existing BARCT regulations may have

been drafted specifically for electric utilities, and therefore, may require modification

to ensure that intent of regulations are met in a restructured industry. New power

plants are generally cleaner than existing power plants using BARCT. Although now

not enforced, regulations adopted in the early 1980s allow new cogeneration power

plants to obtain emission reduction credits from displacing utility system emissions. It

may be appropriate to reevaluate these regulations for a restructured electricity

industry.

Electric

Transmission Line

Safety and

Nuisance

Regulations

In- and out-of-State

transmission lines

A number of regulations govern the construction and operation of electric

transmission lines in- and out-of-State. These regulations are intended to mitigate

aviation hazards, fire hazards, communication interference, and shock hazards from

electric transmission lines. Some existing regulations may place requirements on

electric utilities to mitigate hazards, and therefore, may require modification to ensure

that intent of regulations are met in a restructured industry.

Endangered

Species Act

In- and out-of-State

power plants

The Endangered Species Act of 1973 (PL 93-205 as amended) established a

process for designating plants, insects, fish, and wildlife species in order to slow or

cease their decline, and developing recovery plans for such species. Recently, in

accordance with this legislation, several actions to protect endangered and

threatened species have occurred in the west. Both the Northwest Power Planning

Council and the NMFS have been developing revitalization plans for the listed

endangered salmon of the Columbia River Basin over the last few years. These

plans are likely to alter the current operations of the Northwest hydroelectric system

in this region and affect electricity supply options.

Hazardous

Materials

Handling and

Storage

In- and out-of-State

power plants and

transmission line

substations

Generally, gas-fired power plants do not use or produce significant amounts of

hazardous materials. The exceptions are chemicals for air and water pollution

control, solvents used to clean equipment, and some chemicals that were used in

transformers. Liability for hazardous waste cleanup of existing power plant or

transmission line substations sites may complicate divestiture of electric utilities under

restructuring.

New Source

Review (NSR)

Rules

New combustion

power plants located

in nonattainment

areas in- and out-ofState

NSR rules require the use of Best Available Control Technology (BACT) and require

that the emission reductions be obtained from other existing sources to offset any

emission increases for the new source. Availability and costs of offsets may affect

the viability of merchant projects. Merchant projects may increase volatility of offset

or RECLAIM markets. Although BACT requirements will likely become more

restrictive, over time, no significant implications for electricity generation are

expected.

Prevention of

Significant

Deterioration

(PSD)

New combustion

power plants located

in attainment areas

in- and out-of-State

PSD require use of BACT (Federal definition),a limit the degree projects can degrade

air quality, and protect visibility in national parks and wilderness areas. PSD may

affect viability of new in- and out-of-State electricity resource options that might

degrade visibility in national parks.

Reasonably

Available Control

Technology

(RACT) Rules

Existing combustion

power plants located

in moderate

nonattainment areas

RACT that apply to existing power plants in moderate nonattainment areas consist of

low NOx burners and combustion modifications. Protection of visibility in national

parks may lead to emission retrofit requirements for existing sources, including

electric generating facilities, both in- and out-of-State. RACT controls may be

required for some power plants to limit visibility impacts, and may apply to NOx,

Sulphur Oxides (SOx), and PM10 emissions, which may affect competitiveness of

some sources.

58 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
Table 12. Summary of Environmental Regulations Affecting Electricity Generation in California (Continued)

RECLAIM All large NOx and

SOx sources in

South Coast AQMD

...Rule 2001 (i) (2) excludes electric utility sources from SOx trading program.

Restructuring could void this excerpt...

SO2 Acid

Deposition

Trading

Existing combustion

power plants in- and

out-of-State

Current regulations require SO2 reductions from utilities. EPA is currently evaluating

possibility of expanding regulations to non-utility sources.

Toxic Air

Contaminants,

Title VIII

In- and out-of-State

power plants

Generally, in-State requirements are more significant than out-of-State requirements.

Natural gas-fired power plants will not generally have significant emissions, although

ammonia for SCR NOx controls may be of concern. Coal-fired, municipal solid waste

or geothermal power plants may have toxic and carcinogenic pollutants which may

require regulation in the future.

Water Quality Act In- and out-of-State

hydropower plants

The Clean Water Act, originally enacted in 1972 (PL 92-500), controls pollutants

released in the nation’s lakes, rivers, and coastal waters. Among other things, the

Act provides funding to local and State agencies for water treatment programs,

requires discharge limits on pollutants, and establishes permit requirements. In

Jefferson County PUD No 1 and the City of Tacoma v. Washington (1994), the

Supreme Court ruled that States may establish minimum stream flows for

hydroelectric project under the Clean Water Act. Prior to this decision, the Federal

Energy Regulatory Commission had relatively exclusive authority over hydropower

projects under the Federal Power Act of 1920. This decision is expected to have a

significant effect on hydroelectric projects that are facing licensing renewal.

a

In many air districts in California, BACT means LAER (i.e., the most stringent emission limitation achieved in practice for a class or

category of source). The primary difference between LAER and BACT (Federal definition) is that LAER does not require the consideration

of environmental, energy, or economic impacts, whereas BACT does. BACT and LAER determinations do not require use of a specific

technology.

AQMD = Air Quality Management District. BACT = Best available control technology.

BARCT = Best available retrofit control technology. LAER = Least achievable emissions rate.

NMFS = National Marine Fisheries Service. NOx = Nitrogen oxides.

NSR = New source review. RACT = Reasonably available control technology.

RECLAIM = Regional clean air incentives market. SCR = Selective catalytic reduction.

SOx = Sulfur oxides. SO2 = Sulfur dioxide.

Source: Reproduced from California Energy Commission, Draft Final 1994 Energy Report (Sacramento, CA, July 1995), pp. 3-26 and

3-27.

in 1990. This legislation imposes—both on the CEC

(California Public Resource Code section 25000.1) and

the CPUC (Public Utilities Code section 701.1)—the

requirement to calculate the cost-effectiveness of energy

resources, including conservation and load management

options, by attaching a value for any costs and benefits

to the environment including air quality.191

In its next submission, the 1992 Electricity Report, the

CEC grappled further with the question of emissions

valuation estimates. The CEC directed the utilities to

use estimates derived from the revealed preference (or

control costs) and the damage function approach (Table

13).192 According to the CEC, both these methods

internalize environmental externalities in evaluating

electricity resources. The values for control costs are

invariably higher than those for the damage function

approach (except PM10). However, the CEC states that

differences between the values are not large enough to

affect longrun planning decisions; their only effect is in

the timing of a new resource addition. In addition, the

intent to encourage low-emission emitting or renewable

191In its Decision 91-06-022, the CPUC determined that since emissions from power plants lead to environmental impacts that impose

measurable costs on society, utilities should account for these emissions when they evaluate long-term purchases of power. For short-term

purchases (5 years or less), however, externality values do not need to be considered. The reason given by the CPUC is that it would

ease the transition to using externality values and help cushion any rate impacts that might result from incorporating externalities in

evaluating long-term purchases. 192These approaches have been discussed in Chapter 3. For additional CEC comments, see California Energy Commission, 1992

Electricity Report (Sacramento, CA, January 1993), pp. 47-65.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 59
Table 13. Comparison of Residual Emission Reduction Values for 1992

(1989 Real Dollars per Ton per Year)

Air Basin or District Valuing Methoda b NOx SOx ROG PM10 COc

South Coast Damage Functions 14,483 7,425 6,911 47,620 3

Control Costs 26,400 19,800 18,900 5,700 9,300

Ventura County Damage Functions 1,647 1,500 286 4,108 0

Control Costs 16,500 6,200 21,100 1,800 Attainment

Bay Area Damage Functions 7,345 3,482 90 24,398 1

Control Costs 10,400 8,900 10,200 2,600 2,200

San Diego Damage Functions 5,559 2,676 98 14,228 1

Control Costs 18,300 3,600 17,500 1,000 1,100

San Joaquin Valley Damage Functions 6,473 1,500 3,711 3,762 0

Control Costs 9,100 17,800 9,100 5,200 3,200

Sacramento Valley Damage Functions 6,089 1,500 4,129 2,178 0

Control Costs 9,100 9,600 9,100 2,800 5,000

North Coast Damage Functions 791 1,500 467 551 0

Control Costs 6,000 3,000 3,500 900 Attainment

North Central Coast Damage Functions 1,959 1,500 803 2,867 0

Control Costs 9,100 3,000 9,100 900 Attainment

South Central Coast Damage Functions 1,647 1,500 286 4,108 0

Control Costs 9,100 3,000 9,100 900 Attainment

Southeast Desert Damage Functions 439 1,500 157 680 0

Control Costs 6,000 19,700 3,500 5,700 2,900

Districts which are attainment

for O3 but not for PM10 Control Costs 6,000 3,000 3,500 900 Attainment

a

The damage function values shown above are estimates of the external or social costs of residual air emissions. In ER 92, such costs

are based on an evaluation of the damages resulting from the residual emissions remaining after rules and control strategies are

implemented to attain ambient air quality standards. Thus, the values assume successful implementation of a local air district’s air quality

management plan over time, with attainment of ambient air quality standards occurring by the year required.

The Energy Commission’s analysis of future electricity generation options in ER 92 includes both the internal private costs and benefits

of power plant generation and, responding to Section 25000.1(c), the external social costs and benefits of power plant generation. The

Energy Commission’s purpose in adopting damage-function air emissions values is to estimate the external costs of air emissions based

on the marginal social benefit of reducing residual power plant emissions remaining after rules and regulations are implemented along the

path to attainment of ambient air quality standards. Therefore, for the South Coast AQMD, for example, the Energy Commission examined

the social benefit of reductions in power plant air pollutants, assuming full implementation of all control strategies and control costs on

power plants in accordance with the South Coast AQMD’s rules, regulations, and the 1991 Air Quality Management Plan (AQMP), which

sets forth the emission reductions required for attainment of air quality standards.

While the Energy Commission recognizes that the South Coast AQMD does not agree with the use of damage-function methodology to

evaluate a single emissions source or the resulting values from the methodology, the Commission nevertheless adopts these values to

allow finalization of ER 92 resource decisions and recognizes that these values need to be refined for future decisions. b

Damage function values and control cost values were escalated at different rates.

c

CO damage function values were rounded to the nearest dollar.

AQMD = Air Quality Management District. CEC = California Energy Commission.

CO = Carbon monoxide. NOx = Nitrogen oxides.

O3 = Ozone. PM10 = Particulate matter less than 10 microns in diameter.

ROG = Reactive organic gases. SOx = Sulfur oxides.

Note: ER 92 stands for 1992 Electricity Report.

Source: Reproduced from California Energy Commission, 1992 Electricity Report (Sacramento, CA, January 1993), p. 55.

60 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
technologies is not enhanced by using either set of

values.

According to the CEC, the ineffectiveness of using

externality values could be handled better if there

existed a market mechanism to price residual emissions.

Legislative enactments (California Assembly Bills 2198

and 1090) required that resource acquisition explicitly

recognize the environmental and fuel-diversity values

of renewable energy resources. Based on that legislation

and the fact that no such market currently exists for

residual emissions, the CEC’s recommendations, as

reported in the 1992 Electricity Report, include:

• Low-emitting technologies and renewables have a

role to play in reducing emission levels.

• A set-aside for renewables is warranted for a

portion of any new capacity.

• Development of an emissions trading program

was considered to be the most effective way to

include the value of pollution costs in society’s

decisions.

• Pending the development of a market for emissions trading, residual emission values would

continue to be estimated, applied, and included in

resource planning decisions.

• The CEC should investigate scientific problems

associated with the valuation of externalities.

• An analysis of the socially least-cost options

should include all other segments of the economy

besides power generation.

• Other environmental externalities (pertaining to

land and water, for example) should also be considered in due course.

The cost effectiveness of energy resources is determined

by including a value for any costs and benefits to the

environment including air quality. The State environmental laws have also started the application of market

principles in regulations that affect power plants as

well other large sources. As a result, large new sources

of air emissions fall within the scope of New Source

Review (NSR) regulation, which requires that the emissions they produce be offset through the purchases of

emission reductions from other existing sources.193

State regulatory authorities noted that electricity generation in other States causes pollution that crosses

State boundaries. Thus the State considered these emissions too. The Commission directed (in Decision 91-06-

022) that the utilities’ base case analysis assign a

uniform value to residual emissions, regardless of

where they occurred, based on the marginal cost of

emission control. However, in a subsequent decision,

the CPUC shifted from uniform to nonuniform residual

emissions valuation and stated that the base case

should value emissions depending on where those

emissions were generated.194 Emissions in nonattainment areas would be valued using the marginal cost of

control, but emissions in attainment areas would use

values adopted by the Nevada Public Service Commission. The CPUC directed Pacific Gas and Electric to use

a combination of the South Coast Air Quality Management District’s (SCAQMD) values and values from the

Pace (1990) study.195

Legislative enactments in California also require that

resource acquisition explicitly recognize environmental

and fuel diversity of renewable energy resources.196

Thus, the CEC directed and the CPUC decided to set

aside a portion of generating capacity for renewable

resources in the recent bid solicitation. All technologies

were allowed to bid against renewable “Identified

Deferrable Resources,” but at least half the capacity was

to be awarded to bidders using renewable energy

sources.197

193Air emissions and impacts of power plants built before the mid-1970s are controlled through local Air Quality Management District

retrofit regulations and other local regulations. However, plants built between the mid-1970s and the mid-1980s were subject to less

restrictive environmental controls. Problem areas, therefore, remain. 194California Public Utilities Commission, Interim Opinion, Resource Plan Phase: Bidding for New Generation Resources. Decision 92-04-045

with respect to Docket No. I.89-07-004 (filed July 6, 1989). 195Pace University Center for Environmental Legal Studies, Environmental Costs of Electricity (Oceana Publications, Inc., New York, NY,

1990). 196California Assembly Bills 2198 and 1090. 197In 1985, the CPUC adopted the concept of using utilities’ resource plans as the basis for setting longrun avoided costs. Cost-effective

resource additions identified in a utility’s resource plan could be deferred (or avoided by qualifying facilities) and the longrun avoided

cost prices paid to these qualifying facilities could be based on the cost of the generation resource that was deferred. These resources

came to be known as “Identified Deferrable Resources” or IDRs. See California Public Utilities Commission, Biennial Resource Plan Update:

A Primer (San Francisco, CA, October, 1993), p. 4.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 61
Alternative Approaches to Treatment of

Externalities

In recent testimony before the CEC, the Commission

Staff stated that the overall impact of externality considerations had not been significant.198 With a view to

overcoming the prevailing shortcomings in using externality values, the CEC Staff recommended consideration of the following five alternatives:199

a. Improved damage assessment and translation

b. Multi-attribute tradeoff analysis

c. Environmental performance standards

d. Marketable permit programs

e. Emission taxes and surcharges.

Of the above alternatives, the first two require improvements or refinements in current practices.200 The

third offers the possibility of developing a flexible

policy for implementation.201 The last two approaches

are market-oriented. Among these alternatives, the CEC

Staff prefer market-based options such as permits and

surcharges. However, they suggest that second-best

measures such as standards are appropriate interim

measures.202

The electric utilities in the State point out that not all

emissions are attributable to them and that a significant

share comes from other sources not subject to regulation. As an example, Pacific Gas and Electric (PG&E)

indicated that electric utilities emit only 3 percent of

Statewide NOx emissions. With improvements in technology, utility NOx emissions have declined further and

are expected to be about 1 percent by the year 2002.203

The utility argued that any further attempt to reduce

utilities’ NOx emissions would be inefficient.204

Some participants at a workshop convened by the CEC

stated that the air quality standards in California would

continue to improve as a result of air quality regulations requiring cleaner electricity generation. In their

view, establishment of market-oriented systems might

offer a better approach than internalization. Based on

these considerations, the “benefits of substantial additional attention to internalizing remaining electric utility

emissions may not be worth the associated cost.”205

The CEC Staff recognize the range of problems associated with internalizing externalities. Plans for the future

include a reexamination and improvement of the implementation procedures while continuing to recommend

minimizing social cost as an appropriate goal even as

the industry structure changes. The possibility that

moving to a more competitive structure in the electric

power industry will limit the means of energy regulatory agencies to internalize externalities has also been

noted. As a result, the CEC Staff has called for the

Legislature to establish a collaborative task force to

examine externalities in a restructured electricity industry.

Externality Values Adopted by California

Externality values for five major air pollutants associated with electricity generation were established in

California (Table 14).206 These values are based on the

estimates of the marginal cost of the best available

control technology. The externality values differ among

regions in the State depending on whether a given

region is in attainment with the required air quality

198California Energy Commission, Staff Testimony on Internalizing Externalities, Docket No. 93-ER-94 (Sacramento, CA, October 20, 1994). 199California Energy Commission, Staff Testimony on Internalizing Externalities, Docket No. 93-ER-94 (Sacramento, CA, October 20, 1994). 200The first two methods have been discussed in Chapter 3. 201For additional details on this approach, see The National Regulatory Research Institute, Public Utility Treatment of Environmental

Externalities (Columbus, OH, June 1994). 202Oak Ridge National Laboratory, The Effects of Considering Externalities on Electric Utilities’ Mix of Resources: Case Studies of Massachusetts,

Wisconsin, and California (Oak Ridge, TN, July 1995). 203Rebuttal Testimony submitted by Pacific Gas and Electric Company on November 3, 1994, regarding the Preparation of the 1994

Electricity Report (Docket No. 93-ER-94), to the California Energy Commission, Sacramento, CA. 204San Diego Gas & Electric argued for considering externalities in the siting process, not in the planning process, so as to allow

competition to be unfettered. However, CEC Staff cautioned against confusing externalities with environmental impacts, and it was

unclear to CEC how externalities would be addressed in siting. 205California Energy Commission, Staff Testimony on Internalizing Externalities, Docket No. 93-ER-94 (Sacramento, CA, October 20, 1994). 206Note that residual emissions remain after an electric generation plant has met all applicable air quality requirements and that these

residual emissions continue to impose a cost on society. A reduction in the level of residual emissions provides a net benefit to society.

62 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
Table 14. Externality Values for California

(1992 Dollars/Ton Emission)

Pollutant

Southern

California Edison

San Diego Gas &

Electric

Pacific Gas &

Electric

Areas in

Attainment

NOx .................... 31,448 31,448 9,120 7,467

SOx .................... 23,490 23,490 4,486 1,720

PM10 ................... 6,804 6,804 2,624 4,608

ROG . . . . . . . . . . . . . . . . . . . 22,462 22,462 4,236 1,301

CO2 .................... 9 9 9 9

NOx = Nitrogen oxides.

SOx = Sulfur oxides.

PM10 = Particulate matter less than 10 microns in diameter.

ROG = Reactive organic gases.

CO2 = Carbon dioxide.

Source: Oak Ridge National Laboratory, The Effects of Considering Externalities on Electric Utilities’ Mix of Resources: Case

Studies of Massachusetts, Wisconsin, and California (Oak Ridge, TN, July 1995).

standards. Inclusion of carbon dioxide value hinges on

perceptions of the need to control future risks of

regulation.

It may be noted that the CEC offers guidance on the

values to be used in each Biennial Update.207 In the

1992 Electricity Report and the Draft Final 1994 Electricity

Report, the damage function approach was used as the

appropriate methodology for estimating values of

residual pollutant emissions from power plants.208 In

recent testimony, the CEC Staff recommended residual

emission values for use in the forthcoming 1994

Electricity Report.209 In addition, the CEC provides

information on values to use for out-of-State residual

emissions. Note that the CEC’s recommendations are

not binding. The CPUC, therefore, makes its own determination. Comparison of externality values in Tables 12

and 13 shows differences in the valuations of the CEC

and the CPUC.

The Integrated Resource Planning Process

and the Biennial Resource Planning in

California

In July 1989, the CPUC designated the Biennial

Resource Plan Update (BRPU) as the forum in which it

would address issues related to longrun avoided cost

and resource planning and acquisition.210 The BRPU

has three main goals:211

• To identify the total need for new generation

capacity for each of the three participating electric

utilities in the State, i.e., Southern California

Edison, San Diego Gas and Electric, and Pacific

Gas and Electric

• To quantify the capacity that qualified facilities

(QFs) may potentially supply

207The Biennial Resource Planning requires the utilities in California to submit plans every 2 years identifying the need for new

generation capacity within the prevailing regulatory framework in the State. See California Public Utilities Commission, Biennial Resource

Plan Update: A Primer (San Francisco, CA, October 1993). 208The Air Quality Valuation Model (AQVM) developed by the CEC is used to assist in developing appropriate values. The AQVM

uses the damage function method to calculate the damage associated with residual air emissions in various locations/regions. The model

requires two inputs, the geographical area of interest and the energy technology to be evaluated. The first determines baseline air quality,

and the second determines several characteristics like emission factors, stack height, exit temperature, and velocity. The AQVM also uses

the Environmental Protection Agency’s Empirical Kinetic Modeling Approach (EKMA) for ozone modeling. See California Energy

Commission, The Air Quality Valuation Model (Sacramento, CA, April 1994). 209California Energy Commission, Valuing Residual Pollutant Emissions, Docket No. 93-ER-94, July 27, 1994. 210California Public Utilities Commission, Biennial Resource Plan Update: A Primer (San Francisco, CA, October 1993), p. 3. 211California Public Utilities Commission, Biennial Resource Plan Update: A Primer (San Francisco, CA, October 1993), p. 3.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 63
• To establish reasonable prices and terms for

energy and capacity from the QFs.

The starting point for each BRPU cycle is the release of

the Electricity Report by the CEC. The Electricity Report,

released biennially, contains resource plans responsive

to the State’s longrun electricity policy.212 On the basis

of the CEC’s demand and supply assumptions, the

investor-owned utilities submit resource plans to the

CPUC. In making their submissions, the utilities ensure

that they meet CPUC’s cost-effectiveness test stipulations.213

The next step is for the CPUC is to hold hearings permitting interested parties to present their comments

and suggest alternatives. At the conclusion of the

hearings, the CPUC makes a determination of the total

resource needs for each utility. At the same time, the

CPUC makes a distinction between deferrable and nondeferrable resource needs.214 The CPUC’s decision

also specifies a certain amount of capacity and corresponding benchmark prices to be offered for possible

deferral through bidding by qualifying facilities.

The final step involves the utilities’ bid solicitation and

the QF auction process.215 The utilities issue a

“Request for Bids” detailing the particulars of the

identifiable deferrable resources and the availability of

longterm standard offer contracts based on the capacity

and the fixed and variable cost of the avoidable resource(s).216 From the date of the release of the CEC’s

Report, length of an average cycle is about 3 years

(Figure 3). The procedural steps are discussed next.

Environmental externality considerations are included

in the QF purchases as a part of the contract modification. Since the emissions from an identifiable

deferred resource (IDR) are known, they can be easily

estimated. Based on these estimates, the QFs receive

“adder” or “subtractor” payments (at the time of acquisition) based on the net difference in emissions between

the QF and the IDR. Emission costs from all new resources, whether utility resources or QF resources, are

calculated by multiplying the emissions values by the

amount of residual emissions. The position of the CEC

and the CPUC is that new coal-fired plants have no

role in resource plans in California at this time.217

In addition to a consideration of the environmental

impacts of new resources on air emissions, the CPUC

also requires that a specific portion of future generating

capacity be set aside for renewable resources.218 The

amount of capacity to be set aside is decided on a

utility-by-utility basis as a function of the diversity in

the utility’s existing resources. Benchmark prices for

renewable set-asides are established by the cost of the

212The 1992 Electricity Report, for example, addressed the following major issues in its discussion of the State’s resource needs:

incorporation of environmental concerns in resource planning, problems with State’s resource planning and acquisition process, potential

changes in long-term trends in electricity demand, natural gas supply and price risks, future role of energy efficiency, potential benefits

of advanced and noncommercial generation options, the future role of renewable technologies, and the effects of changes in transmission

system regulation on longrun electricity planning. Refer California Energy Commission, The Electricity Report, 1992 (Sacramento, CA,

January 1993), p. 2. 213The cost-effective test methodology adopted by the CPUC is known as the Iterative Cost-Effective Methodology (ICEM). The ICEM

is used to identify the type, size, and timing of the utility’s most cost-effective resource addition in relation to its overall system cost.

California Public Utilities Commission, Biennial Resource Plan Update: A Primer (San Francisco, CA, October 1993), p. 4. 214Deferrable resources include baseload or intermediate load resources that appear in the first 8 years of the planning horizon. The

time period represents the leadtime necessary for utility power plants. Nondeferrable resources consist of peaking units, short-run

capacity, demand-side management resources, committed resources, and others. See California Public Utilities Commission, Biennial Resource

Plan Update: A Primer (San Francisco, CA, October 1993), p. 4. 215In the early 1980s, the CPUC implemented provisions of sales (implicit in the PURPA legislation) via a series of four preapproved

power purchase contracts called “Standard Offers.” The Standard Offers 1, 2, and 3 are shortrun in terms of which the QFs receive prices

based on utilities’ existing generation resources. Interim Standard Offer 4 is longrun in which prices are based on the costs of new

generation resources that the utility avoids by the QF purchase. These procedures for pricing QF purchases led to an oversubscription

of purchases from QFs in the 1980s. With a view to correct and modify this situation, the CPUC formulated what is now called the Final

Standard Offer 4 or FSO4. The FSO4 represents a shift toward a market-oriented policy. 216Utilities’ resource plans are used as the basis for setting longrun “avoided costs.” The QFs’ initial attempt is to make an offer at

a price which is equal to or lower than the utilities’ avoided costs. Provisions also exist for a second price auction where the QFs compete

on the basis of price. In this approach, the incentive for a QF is to quote its own marginal cost rather than the avoided cost of the utility

even though it may receive a market clearing price which may be higher than its own marginal cost. For additional details see California

Public Utilities Commission, Biennial Resource Plan Update: A Primer (San Francisco, CA, October 1993), p. 5. 217Oak Ridge National Laboratory, The Effects of Considering Externalities on Electric Utilities’ Mix of Resources: Case Studies of Massachusetts,

Wisconsin, and California (Oak Ridge, TN, July 1995). 218This requirement has been mandated by Assembly Bill 1090 passed by the California Legislature in 1991. The requirement to set

aside a portion of the capacity for renewables will remain in force until such time that electrical generating methodology valuing

environmental and diversity costs and benefits is completed.

64 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
California Energy

Commission’s

Electricity Report

1990

Investor-Owned Utilities

File Resource Plans

California Public

Utility Commission

Adopts Resource

Plan D.92-04-045

Final Standard

Offer 4 Approved

D.92-12-021/

D.93-03-020

April 1992 December 1992-

March 1993

Investor-Owned Utilities

Issue Requests For Bids

August 1993

October 1990 August 1991

Figure 3. Biennial Resource Plan Update: Timing of Significant Events

Source: Adapted from California Public Utilities Commission, Biennial Resource Plan Update: A Primer (San Francisco, CA, October

1993).

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 65
IDRs and are subject to the requirement that the winning QF’s total cost should be lower than cost of the

IDR.219

Pacific Gas and Electric’s

Considerations of Externalities

in its Resource Planning

Pacific Gas and Electric’s 1994 Integrated

Resource Plan

The electric resource plan submitted in 1994 by Pacific

Gas and Electric (PG&E) has the following three main

ingredients:

• Demand-side management will continue to be the

cornerstone of PG&E’s resource planning during

the 1990s.

• Economic upgrades, license extensions, and environmental retrofits at PG&E’s existing facilities

will be undertaken to permit an efficient use and

maintenance of existing resources.

• Flexible new contracts in the wholesale market

will be undertaken so that the entry of “exempt

wholesale generators” as envisaged in the Energy

Policy Act of 1992 can be accommodated.

PG&E is the nation’s largest investor-owned utility,

serving nearly 13 million customers. Its diverse mix of

plants includes nuclear, natural gas, hydroelectric and

pumped storage, and geothermal power plants. Taken

together, these plants account for nearly 15,000 MW of

summer and winter capability. In addition, nonutility

generators contribute about 2,850 MW of on-peak

dependable capacity using cogeneration, wind, solar,

and biomass.

Output from the utility’s above facilities supplemented

by inter-utility purchases/imports enabled PG&E to

meet its planning area load of 88,000 gigawatthours in

1993.220 Table 15 shows the percentage breakdown of

electricity sources for 1993 and projections for the year

2004.

PG&E projects that for the next 10 years, demand-side

management programs will be the primary providers of

additional capacity to meet the system load. Starting in

2002, the utility will require purchases of wholesale

generation: 320 MW in 2002, growing to 1,340 MW by

2004.

Based on the above considerations, PG&E’s most likely

forecast shows need for new supply-side resources of

Table 15. Sources of Electric Energy for Pacific Gas and Electric (PG&E)

(Percent)

Sources Actual 1993 Projected 2004

Purchases From Current or Committed Qualifying Facilities . . . . . . . . . . . . . . 25 22

New Wholesale Purchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . NA 3.5

PG&E Fossil (Natural Gas) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 20

Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 14

PG&E Hydro . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 12

Government Hydro . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 11

Geothermal ................................................ 7 3

Imports (Primarily From the Northwest) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 11

New Demand-Side Management Programs ......................... NA 3.5

NA = Not applicable.

Note: PG&E has hundreds of contracts with qualifying facilities. Qualifying facilities use cogeneration, wind, solar, and biomass.

Source: Pacific Gas and Electric Company, 1994 Electric Resource Plan (San Francisco, CA, 1994).

219For additional conditions regulating these requirements, see California Public Utilities Commission, Biennial Resource Plan Update:

A Primer (San Francisco, CA, October 1993), p. 7. 220The data have been abstracted from PG&E’s 1994 Electric Resource Plan submitted to the CPUC.

66 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
about 320 MW in 2002, increasing steadily to about

3,700 MW by 2010.221 For the years 1993 and 2004, the

impact of these resource changes on sources of electricity can be seen in Table 15.

Impact of Externality Considerations on

Pacific Gas and Electric’s Resource Mix

The Pacific Gas and Electric (PG&E) company used a

specific set of values (Table 16) to assess the impact of

the externality values on its mix of resources. These

values were used in the utility’s most recent resource

planning submission to the CPUC and were based on

the values provided by the CEC in the Draft Final 1994

Electricity Report.

Inclusion of externality values accelerates the shift from

new combustion turbine units to combined cycle units

(Table 17).222 Other than this timing shift, there are no

other changes in resource acquisition plan or in the mix

of resources to be acquired. In particular, the externalities values have no impact on the amount of nonfossil and demand-side resources because they are not

options that the utility considers in its analysis.223

The existing resource mix of the PG&E may be a part

of the reason why there is a lack of impact on resource

acquisition even when externalities are internalized.

Current externality considerations apply primarily to

residual air emissions. In 1993, more than 90 percent of

PG&E’s fossil-fueled generation used natural gas.

Internalizing externality values is not likely to take

away the advantages of natural gas as a clean fuel.

Furthermore, the prevailing low gas prices preclude

other technologies with lower emissions from being

cost-effective.224 In any case, these considerations do

not affect PG&E’s acquisition plans.

Concluding Remarks on the Impact of

Internalization Efforts on Resource

Acquisition in California225

The CEC Staff recently provided an assessment of the

status of internalization efforts in California with

specific reference to impacts on actual procurement and

operations decisions by the utilities.226 While recognizing that the “efforts to identify externalities, estimate

their damages or benefits have continued and improved

over time, the record of applying the damage function

Table 16. Externality Values Used by Pacific Gas and Electric Based on Values Estimated by the California

Energy Commission for the 1994 Biennial Update

(1996 Dollars/Ton Emission)

Pollutant

San Francisco

Air Basin

South Central

Coast Air Basin

North Central

Coast Air Basin

Out-of-State

Northwest

Nitrogen Oxides ................. 7,000 1,676 1,018 292

Sulfur Oxides ................... 15,660 4,060 2,640 298

Particulate Matter Less Than 10 Microns 23,760 6,920 7,020 556

Reactive Organic Gases . . . . . . . . . . . 204 44 34 0

Carbon Dioxide .................. 9.82 9.82 9.82 9.82

Source: Oak Ridge National Laboratory, The Effects of Considering Externalities on Electric Utilities’ Mix of Resources: Case

Studies of Massachusetts, Wisconsin, and California (Oak Ridge, TN, July 1995).

221Note that the utility used the Iterative Cost-Effectiveness Methodology (ICEM) model to develop a least-cost plan. The utility

presented a base case plan and an alternative case using residual emission externality values. The utility then applied a three-step

uncertainty analysis to both plans before deciding that the base plan was its preferred plan. The uncertainty analysis used ranges of load

growth and fuel prices. 222Due to modeling limitations, PG&E considered only NOx, PM10, and CO2 externalities in the numerical analysis. 223Since PG&E assumed that all new resources would be gas units, the externality values had little effect on the mix of resources (i.e.,

they only effected a more rapid shift from combustion turbine units to combined cycle units). 224There are problems in controlling emissions attributable to QFs or to out-of-State purchases. 225As defined by the CEC, internalization connotes “policies, such as emission taxes or permit markets, that affect the cost of activities

producing externalities as to equate the marginal social cost of the activity with the marginal social benefit.” California Energy

Commission, Staff Testimony on Internalizing Externalities, Docket No. 93-ER-94, September 15, 1994. 226California Energy Commission, Staff Testimony on Internalizing Externalities, Docket No. 93-ER-94 (September 15, 1994, and October

20, 1994).

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 67
Table 17. Pacific Gas and Electric’s Analysis of the Effects of Externality Values on Resource Additions

Year

Spot

Purchases

(megawatts)

BPA Exchange

(megawatts)

Additions WITHOUT

Consideration of Externalities

Additions WITH Consideration

of Externalities

101.5 MW

Combustion

Turbine

Units

215 MW

Combined

Cycle Units

Total MW

Added

101.5 MW

Turbine

215 MW

Combined

Cycle Units

Total MW

Added

1994 ........ 0 0 0 0 0 0 0 0

1995 . . . . . . . . 200 300 0 0 500 0 0 500

1996 . . . . . . . . 200 300 0 0 500 0 0 500

1997 . . . . . . . . 200 300 0 0 500 0 0 500

1998 . . . . . . . . 200 300 0 0 500 0 0 500

1999 . . . . . . . . 200 300 0 0 500 0 0 500

2000 . . . . . . . . 200 300 0 0 500 0 0 500

2001 . . . . . . . . 200 300 0 0 500 0 0 500

2002 . . . . . . . . 200 300 0 0 500 0 0 500

2003 . . . . . . . . 200 300 5 0 1,008 3 2 1,235

2004 . . . . . . . . 200 300 12 0 1,718 10 2 1,945

2005 . . . . . . . . 200 300 17 1 2,441 11 4 2,477

2006 . . . . . . . . 200 300 17 4 3,086 11 7 3,122

2007 . . . . . . . . 200 300 17 5 3,301 11 8 3,337

2008 . . . . . . . . 200 300 17 7 3,731 11 10 3,767

2009 . . . . . . . . 200 300 17 9 4,161 11 12 4,197

2010 . . . . . . . . 200 300 17 10 4,376 11 13 4,412

2011 . . . . . . . . 200 300 17 13 5,021 11 16 5,057

2012 ........ 200 300 17 16 5,666 11 19 5,702

BPA = Bonneville Power Authority.

Source: Pacific Gas and Electric, 1994 Electric Resource Plan, submitted to the California Public Utility Commission.

methodology and results to electricity system procurement and operations decisions is at best problematic.

The uncertainties involved in the analysis of externalities combined with inherent difficulties of regulatory coordination and scope have been found to limit

the translation of identified social benefits of accounting

for externalities from system planning results through

procurement decisions into operational reality.”227 In

other words, incorporating externality values in the

resource selection process had only a small or negligible impact on actual procurement and operation

decisions as developed by the investor-owned utilities

and/or approved by the CPUC.

The Staff’s discussion of the above results does not take

into account factors like the lack of supply-side capacity

requirements by the investor-owned utilities or the

decline in natural gas prices but focuses on problems of

regulatory scope in the State. First, coordination difficulties between the electricity resource planning

process (initiated by the CEC) and the utility capacity

procurement process (controlled by the CPUC) are

identified as inhibiting achievement of planned goals.

Limited authority enjoyed by the planning and

procurement regulators, i.e., the CEC and the CPUC,

precludes coordination with other State regulatory

agencies and out-of-State authorities. Second, the current planning process does not take into account externalities from other energy sectors. Third, the differential

treatment of externalities in the regulatory process encourages short-term acquisition of resources from the

spot market or the nonutility generators which are not

227California Energy Commission, Staff Testimony on Internalizing Externalities, Docket No. 93-ER-94 (October 20, 1994), p. 2.

68 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
subject to the same externality considerations. Finally,

there are uncertainties involved in developing estimates

of the value of reducing externalities from power plant

residual emissions.

The CEC Staff recognized that the problems of coordination and uncertainty are not easy to eliminate even

though some improvements may be possible. Procedures to translate planning-oriented benefits (from

internalization of externalities) into reality should be reexamined and improved. The Staff also recommended

that the CEC request the State legislature to enact

changes that would permit internalization of externalities even as the industry structure changes.

It should also be noted that the acquisition of resources

under the current Biennial Update has been suspended

due to litigation. The Federal Energy Regulatory

Commission (FERC) overturned CPUC’s procurement

process in February 1995 on the grounds that it had

violated the Public Utility Regulatory Policies Act of

1978 in calculating avoided costs for the Biennial

Resource Plan Update by failing to take into account all

resources available to the State’s utilities and by

allowing only QFs to bid. CPUC considered whether to

take FERC to court to resolve the issue. Southern California Edison had also been litigating against the

auction process for some time. In response to these

pressures, the CPUC declared in July 1995 that the

auction process implicit in the Biennial Resource Plan

Update was annulled.228

These developments, however, do not affect the general

conclusion about California’s experience. Overall, California’s decision on the use of externality values has

not had any effect on the mix of resources to date.

Furthermore, with industry restructuring afoot, the

attention of CPUC and the industry is directed at

reducing private costs, without any consideration of

externalities. On this issue, the CEC and the CPCU may

differ.

228Electric Power Alert, July 19, 1995, p. 8.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 69
7. Externalities in a Changing Industry Environment

The 2 decades from the early 1970s to the early 1990s

witnessed a phenomenal growth in delineating the environmental impacts of electricity generation. Studies

detailing the various approaches to handling and quantifying environmental costs of electricity proliferated.229 More recent studies attempt to encapsulate the

totality of environmental impacts stemming from the

current modes of energy production and consumption

activities.230 In addition, growing national and international environmental concerns (attributable to energy

consumption) have brought about a nexus between environmental and energy issues.

Although the adverse environmental impacts of energy

consumption in general and electricity generation in

particular have been duly recognized, there is still no

consensus on methodological approaches to be used in

quantifying environmental costs. Agreement concerning

the incorporation or internalization of the adverse environmental impacts of electricity generation in marketpricing calculations is rather limited in its scope and

applicability.

Externality Considerations Within the

Integrated Resource Planning Framework

Federal and State regulations, taken together, govern

the environmental aspects of electricity generation in

the United States. Most Federal regulations mandate

requirements that need to be met within a specified

timeframe. Capital, operating, and maintenance costs of

meeting federally mandated environmental standards

are thus internalized and reflected in the rates customers pay for the electricity they buy.

The Appendix summarizes the States’ activities with

respect to handling externalities. Note that more than

half the States currently require that environmental

externalities be considered in some form or the other.

However, some States still have no plans to incorporate

externalities in their rulemaking procedures. In short,

the treatment of externalities at State levels is asymmetrical ranging from environmental zeal to inertia or

benign neglect.

Of the States requiring utilities to consider externalities

quantitatively, only seven—California, Massachusetts,

Minnesota, Nevada, New York, Oregon, and Wisconsin

—specify monetary values by emission (Table 18).231

The States that form the subject of this study—Massachusetts, Wisconsin, and California—were selected

from the group of seven States that have specific

monetary values for externalities. Apart from being in

the vanguard of incorporating monetized externality

values, the choice of these States reflects a regional

diversity.

In each of the above three States, the externality values

were used within the framework of the integrated resource planning process. Externality values, as specified

for designated emissions or pollutants, are required to

be applied in the utilities’ evaluation of procured

energy and demand-side resources as well as any new

capacity requirements. Thus, the externality values were

factored in (assuming them to be a resource cost) in

selecting future resource options within the integrated

resource planning process. Incorporating externalities

within the integrated resource planning process could

affect two basic types of utility decisions: resource

planning decisions and system operation decisions (Figure 4). Resource planning decisions include: building

new plants or purchasing power from nonutility generators; undertaking life-extension/repowering; and

postponing the need for new capacity by implementing

demand-side management programs. System operation

decisions are those that involve the order in which the

utilities commit units and dispatch them to meet load.

“Adders” could be applied to more polluting units,

permitting the functioning of what is called an

229For an excellent overview of the recent relevant studies, see U.S. Congress, Office of Technology Assessment, Studies of the

Environmental Costs of Electricity, OTA-ETI-134 (Washington, DC: U.S. Government Printing Office, September 1994). 230Oak Ridge National Laboratory and Resources for the Future, U.S.-EC Fuel Cycle Study: Background Document to the Approaches and

Issues, ORNL/M-2500 (Oak Ridge, TN, November 1992). 231Massachusetts will not be able to incorporate externality values as a result of the decision by the State’s Supreme Court on December

22, 1994. See Chapter 4 for more information.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 71
Table 18. Externality Values for Different Pollutants, by State

(1992 Dollars/Ton)

State

Pollutant

SO2 NOx

TSP or

PM10 VOCs CO2 CO

California .............. 4,486 9,120 4,608 4,236 9 NVS

Massachusettsa ......... 1,700 7,200 4,400 5,900 24 960

Minnesota . . . . . . . . . . . . . 150 850 1,274 1,190 9.8 NVS

Nevada ............... 1,716 7,480 4,598 1,012 24 1,012

New York .............. 1,437 1,897 333 NVS 1 NVS

Oregon ................ 0 3,500 3,000 NVS 25 NVS

Wisconsin .............. NVS NVS NVS NVS 15 NVS

a

Massachusetts will not be able to incorporate externality values due to a decision by the State’s Supreme Court on December

22, 1994.

CO2 = Carbon dioxide. CO = Carbon monoxide.

NOx = Nitrogen oxides. PM10 = Particulate matter less than 10 microns in diameter.

SO2 = Sulfur dioxide. TSP = Total suspended particulates.

NVS = No value stipulated. VOC = Volatile organic compounds.

Notes: Not all pollutants are included in this table. For example, methane and nitrous oxide are not included. Median values

are given if the State has a range of values.

Source: Oak Ridge National Laboratory, The Effects of Considering Externalities on Electric Utilities’ Mix of Resources: Case

Studies of Massachusetts, Wisconsin, and California (Oak Ridge, TN, July 1995).

“environmental dispatch.” Adoption of environmental

dispatch may, however, bring about other changes for

which the industry may not be fully prepared.232

The Impact of Incorporating Externalities on

the Resource Mix of Utilities

The analyses presented in the preceding three chapters

show that even though each of the States required

incorporation of externality values in planning for

resources, the valuations and the emphasis varied

significantly. Wisconsin, for example, focused exclusively on greenhouse gas emissions. Massachusetts and

California had varying values for residual emissions in

addition to values for some or all greenhouse gas

emissions.233 In seeking the incorporation of externalities, the States concentrated on directing the resource selection process within their own geographic

areas. Prescribed externality values were used for

purposes of making a comparative assessment of resources to be acquired to meet future needs of the

regulated utilities.234

Incorporation of externalities in the three States had

little impact on the resource selection process in a

conventional sense. With a continuing softness in the

price of fossil fuels since the early 1980s, combined

with advances in technology, natural gas emerged as

the fuel of choice in most resource selections determined by considerations of cost effectiveness.235

Accordingly, where the alternative modes of generation

did not show a cost advantage, no perceptible impact

on the mix of resources is observable. In addition:

232For example, if “adders” are to be levied on old coal units, the results may be to change the dispatch order, resulting in cycling rather

than a baseload operation, lower capacity factor, and reduced emissions. See Research Triangle Institute, Accounting for Externality Costs

in Electric Utility Planning in Wisconsin (Research Triangle Park, NC, November 1991), p. 2-4. 233Note that the revised integrated resource planning in Massachusetts no longer requires the consideration of externalities. In

California, the current restructuring debate is critical. 234California incorporated considerations for purchases from out-of-State as well. 235The annual average wellhead price for natural gas declined from a 1983 peak of $2.97 per thousand feet to a 15-year low of $1.39

per thousand feet in 1991. Prices recovered somewhat over the next 2 years, reaching $1.59 per thousand cubic feet in 1993. Per barrel

crude oil refiner acquisition costs declined from $44.66 in 1981 to $13.21 in 1993. Finally, delivered coal prices to the electric utilities

declined from a high of $41.66 per short ton in 1982 to $23.06 per short ton in 1993. Note: all prices are expressed in constant 1987 dollars.

Energy Information Administration, Annual Energy Review 1993, DOE/EIA-0384(93) (Washington, DC, July 1994).

72 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
Environmental

Externalities

Unit

Commitment

Power

Purchases

Unit and DSM

Dispatch

Order

Resource

Planning

Decisions

Unit Life

Extension

or Retirement

SupplySide

Resources

DemandSide

Resources

System

Operation

Decisions

New

Generation and

Transmission

Resources

Figure 4. Utility Decisions That Could Be Affected by Considering Environmental Externalities

DSM = Demand-side management.

Source: Research Triangle Institute, Accounting for Externality Costs in Electric Utility Planning in Wisconsin, RTI Project No. 354-5198-

01.DR (Research Triangle Park, NC, November 1991), p. 2-2.

• No renewable energy technology was selected as

a result of calculations using the prescribed externality values in any of the three States.184

• Resources becoming available as a result of implementation of demand-side management initiatives

were largely unaffected by externality considerations.185

• Shifts in timing of certain natural gas plants

coming online could be viewed as an impact.186

Two other recent studies reach similar conclusions.187

A study undertaken by the Oak Ridge National Laboratory states that “no renewable energy project has

been selected with externalities as the deciding

factor.”188 A report by the General Accounting Office

184Penetration of renewables in electricity generation (in the past) is attributable to special programs such as Federally legislated

requirements or State set-aside programs. The passage of the Public Utility Regulatory Policies Act of 1978 was another contributory

factor in pushing the entry of renewables in electricity generation. See General Accounting Office, Considering Externalities in Selecting

Fuel Sources, GAO/RCED-95-187 (Washington, DC, May 1995). 185Pacific Gas and Electric estimated a possible 5-percent increase in DSM activity when externality values were considered. Oak Ridge

National Laboratory, The Effects of Considering Externalities on Electric Utilities’ Mix of Resources: Case Studies of Massachusetts, Wisconsin,

and California (Oak Ridge, TN, July 1995). 186The California Energy Commission makes a similar point by stating that “including residual emissions values accelerates the time

when new resources become cost-effective and beneficial to society. The acceleration is generally modest.” See California Energy

Commission, Draft Final 1994 Electricity Report (Sacramento, CA, June 1995), p. 3-35. 187General Accounting Office, Electricity Supply: Consideration of Environmental Costs in Selecting Fuel Sources, GAO/RCED-95-187

(Washington, DC, May 1995), and Oak Ridge National Laboratory, The Impact of Environmental Externality Requirements on Renewable Energy

(Oak Ridge, TN, December 1994). 188Oak Ridge National Laboratory, The Impact of Environmental Externality Requirements on Renewable Energy (Oak Ridge, TN, December

1994).

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 73
goes even further by stating that the consideration of

externalities has not influenced the selection or acquisition of renewable energy or any other type of

energy for electricity production. Reasons for the ineffective impact of incorporating externalities include:

• Requirements for additional supply-side resources

are still years away with respect to the resource

acquisition plans of all three investor-owned

utilities analyzed in this report.

• A continuing decline in the price of fossil fuels

tends to offset the cost-effectiveness of other

generating options even when externality values

are incorporated.

• Technological improvements and mandated emission controls with respect to fossil-fuel technologies may also contribute to restricting the

operational impact of externality considerations.

• Investor-owned electric utilities lack adequate

experience with emerging renewable energy technologies (other than hydropower) like solar, wind,

and others.241

• Interjurisdictional issues make it difficult for

utilities that operate in several States to choose

renewable energy projects when the renewable

technologies do not have a clear cost advantage.

• The level of externality values may not be high

enough to mitigate cost advantages enjoyed by

conventional technologies.

• There is an absence of enabling legislation to

permit State regulatory authorities to enforce

incorporation of externalities (as in the case of

Massachusetts where litigation now precludes

consideration of externalities).

Note should also be taken that utilities may differ in

their interpretation of the decisions by the State

regulatory authorities. For example, New England Electric in Massachusetts applied externalities to its “Green

RFP” while the externality values used in the resource

planning analysis were included only to provide

information, not as a means of possibly altering the

utility’s resource mix. This point is, however, no longer

relevant since the Massachusetts Supreme Court

invalidated decisions of the MDPU with respect to

incorporating externality values.

Externalities in a Changing Industry

Environment

The domestic electric power industry has been undergoing changes, imperceptibly perhaps, since the mid1970s. Oil price hikes, construction cost escalations, and

higher-than-required excess capacity levels all contributed to the changes in one form or another.

Regulatory changes initiated by the Public Utility

Regulatory Policies Act (PURPA) of 1978 accelerated industry changes. By permitting the entry of nonutility

generators into the field of power generation, PURPA

launched a process that facilitated penetration into the

power generation monopoly enjoyed by the vertically

integrated utilities. Subsequent enactment of the Energy

Policy Act of 1992 has quickened the pace of transition

and potential restructuring to a level (by fostering

competition in the industry) that could not possibly be

envisioned a few years earlier.242

Some State regulatory authorities have already initiated

industry restructuring proceedings. For example, the

California Public Utility Commission issued an order to

institute investigation and rulemaking with respect to

restructuring California’s electricity industry in

1994.243 Massachusetts initiated a similar proceeding

earlier this year.244

A likely consequence of the restructuring would be the

erosion of vertically integrated electric utilities with a

significant dispersion of generation activities implicit in

the unbundling of services concept.245 With availability

241An additional problem is that not all renewables can generate electricity continually. 242Provisions of the Energy Policy Act of 1992 (EPACT) spur competition by creating a new category of power producers, called exempt

wholesale generators. EPACT also requires all utilities that own transmission facilities to grant nondiscriminatory access to transmission

grid and empowers the Federal Energy Regulatory Commission to ensure that utilities do provide this access. 243California Public Utilities Commission, Order Instituting Rulemaking and Order Instituting Investigation, R.94-04-031 and I.94-04-032,

April 20, 1994. 244Massachusetts Department of Public Utilities, Notice of Enquiry and Order Seeking Comments on Electricity Restructuring, D.P.U. 95-30,

February 10, 1995. 245The report does not discuss other consequences or ramifications of industry restructuring. It is, however, worthwhile noting that

there will be significant changes to the ways in which the industry is regulated in the future.

74 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
of transmission access, the customers are expected to

have the freedom to go to a supplier of their choice

based on considerations of price and service.246

A dispersion of generation activities may imply fundamental changes in the exercise of regulatory oversight in the future. Some of the existing regulations

may need to be modified, and some new guidelines

may still be necessary. In this environment, State

regulatory authorities may no longer be in a position to

exercise control on acquisition of supply-side resources

within the framework of what is now called the “integrated resource planning” process. The capability of

States to enforce a consideration and incorporation of

externalities—in the current mode—may no longer be

feasible.

The California Energy Commission (CEC) acknowledges the potential impact of industry restructuring in

many areas. The CEC, however, maintains that changes

in the ownership of generating facilities (through sale

or divestiture by the utilities) should not cause an

increase in environmental damages and that future environmental regulations should be based on technology

and performance rather than on ownership. Another recommendation is to increase the application of marketoriented internalization methods while continuing to

use existing tools as new and changed methods are developed.247 In Massachusetts, ongoing proceedings of

the Electric Industry Restructuring Roundtable recognize

the need toward environmental improvement based on

retirements, replacements, controls, or offsets. The

stated objective, however, is to find out “new innovative means to meet long-term environmental

goals.”248 Additional details have not become available.

As restructuring progresses, issues other than environmental externalities may become more critical for the

States’ regulatory authorities. Issues connected with

divestiture of the generation facilities, the handling of

stranded investments, and transmission access and its

pricing are possibly going to occupy the center stage in

the near future. State regulatory authorities’ primary

concern will be to ensure reliability of services at

reasonable prices for power. The possibility that environmental considerations by the States may thus be

placed on the backburner is, therefore, not unlikely.

Even where the States manage to remain proactive in

the handling of externalities, the impact scenario based

on recent experience is far from encouraging. In addition, the State regulatory authorities can operate only

within the State boundaries, whereas the environmental

impacts of electricity generation inflict transboundary

damages. Finally, energetic pursuit of handling externalities could, in theory, raise electricity prices higher

than those prevailing in neighboring States (if they do

not pursue a similar approach). The economic consequences of this disparity may imply that States may

be reluctant to lose their competitiveness advantage.

Yet, the future may be less bleak than envisaged in the

preceding paragraph. Innovative options for effectively

treating externalities could still be found within an

industry structure that may not be vertically integrated.

For example, a nonbypassable wires charge could be

used to fund energy efficiency investment by the local

distributing company or to include other similar

elements like externalities. It may also be possible to

impose a higher cost on power purchases from “clean”

sources.

A review of the recent State proceedings and other

forums (such as the Electricity Forum sponsored by

DOE and the National Association of Regulatory Utility

Commissioners) indicates that there is considerable

support for addressing “potentially strandable benefits”

such as environmental protection, energy efficiency,

and renewable energy. There is interest in explicitly

designing environmental and other public interest

considerations into the electric industry framework as

is evident from the proceedings in Massachusetts and

California. As a result, it may be difficult to predict the

future of externality considerations in State settings.

246Vertically integrated electric utilities currently provide bundled services to their customers who treat and pay for electricity as a

single, homogenous product. Their tariff structure bundles the cost of generation, transmission, distribution, and other ancillary services.

Industry restructuring (in the future) may necessitate unbundling, implying a realignment of traditional assets currently included in the

ratebase along functional lines. Realignment of assets may be through sale, segregation, divestiture, changes in corporate ownership or

a shifting of assets outside the ratebase. Asset realignment may, therefore, lead to specific services being charged separately. 247California Energy Commission, Draft Final 1994 Electricity Report (Sacramento, CA, June 1995). 248Report by Eric Van Loon, Senior Mediator, Electric Industry Restructuring Roundtable, submitted to the Massachusetts Department of

Public Utilities on July 17, 1995. D.P.U. 95-30.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 75
Appendix

Summary of State

Public Utility

Commissions’ Activities

Regarding Externalities
Table A1. Summary of State Public Utility Commissions’ Activities Regarding Externalities

State Status

Approach to Incorporating

Externalities Rationale Where is it going?

Alabama None Alabama does not require the

inclusion of externalities in the

Integrated Resource Planning

(IRP) process.

There is no rule requiring

that externalities be

considered. Utilities

generally address

environmental concerns

through regulatory

compliance.

There are no plans to require

that externalities be

considered in the IRP

process.

Alaska None In a recent case, the Commission

affected an Order which states

that, absent direction from the

Legislature, the Commission will

decline further consideration of

environmental externalities in that

case.

Given the legal uncertainties

and the policy deviations

inherent in consideration of

environmental externalities,

the Commission believes

that the question of whether

environmental externalities

can be considered by the

Commission should be

addressed by the

Legislature.

The Order is being appealed

to the State Supreme Court.

Arizona Developing A 1992 Task Force report

recommends that utilities

determine quantitative estimates

of externalities where possible,

preferably based on damages

and expressed as costs per unit

of emission or per kWh, or

develop multi-attribute

assessments where monetization

is not reliable or not applicable.

The Task Force report also states

that utilizing offsets is appropriate

to the extent that they would not

have otherwise occurred.

Environmental externalities

are to be included as part of

the total societal costs of

meeting demand for electric

energy services.

The Commission ordered staff

to begin developing rules to

incorporate the Task Force

recommendations in the

resource planning rules. A

subsequent working group

has recommended which

externalities the rules should

apply to. Workshops and

hearings on the rule

amendments were to be held

in 1994.

Arkansas Awareness IRP guidelines include

quantifiable avoided externality

costs. While these guidelines

provide guidance to utilities, no

rule is in effect that requires them

to include externalities in their

resource planning.

There are no plans to

incorporate externalities in any

rulemaking.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 79
Table A1. Summary of State Public Utility Commission’s Activities Regarding Externalities (Continued)

State Status

Approach to Incorporating

Externalities Rationale Where is it going?

California Operational California requires that utilities

consider quantitative estimates of

externalities. Values are as

follows: for Southern California

Edison and San Diego Gas &

Electric - $31,448/ton NOx,

$23,490/ton SOx, $6,804/ton

PM10, $22,462/ton ROG, $9/ton

CO2; for Pacific Gas & Electric -

$9,120/ton NOx, $4,486/ton SOx,

$2,624/ton PM10, $4,236/ton

ROG, and $9/ton CO2; for

attainment areas- $7,467/ton NOx,

$1,720/ton SOx, $4,608/ton PM10,

$1,301/ton ROG, and $9/ton CO2.

All values are in 1992 $. Offsets

approved by the air quality district

may be used.

Externality values are based

on estimates of the marginal

cost of the best available

control technology. Different

externality values are

applied depending on

whether the area is in

attainment, and depending

on the service territory.

The California Energy

Commission (CEC) also

provides guidance on values

to use for emissions

experienced in-State and

out-of-State. The CEC’s

recommendations are not

binding.

The most significant

development is the

Commission’s recent Order to

institute investigation and

rulemaking on a restructuring

of California’s electric services

industry. The purpose of the

proposal is to lower the cost

of electric service in an

increasingly competitive

economic environment. The

proposal calls for “retail

wheeling” or “direct access” in

which customers have the

option of shopping around for

the best deal. They would

pay the local utility a retail

wheeling rate for transmission

and distribution services, and

buy unbundled electricity

generation service from any

supplier. Under the proposal,

environmental quality remains

an important goal, but the

proposal does not discuss the

role of addressing externalities

as a means of meeting those

goals. Extensive hearings are

being held on this proposal.

Colorado Operational Colorado requires qualitative, but

not quantitative, consideration of

externalities in utilities’ IRPs. The

General Assembly has also

instructed that when the

Commission considers

environmental factors, it should

also consider economic factors in

its decisions.

Utilities are required to

address externalities in their

IRPs because Colorado is

“not persuaded that mere

compliance with existing

environmental laws is

equivalent to an absence of

any externalities.” The

Order states, however, that

methods for quantification

are highly complex and

speculative, and that given

the current state of

knowledge, it is premature to

monetize externalities.

The Commission is unlikely to

require quantification of

externalities. In addition to its

concern for the environment,

the General Assembly is also

concerned about economic

factors and the health of the

State’s coal mining industry.

80 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
Table A1. Summary of State Public Utility Commission’s Activities Regarding Externalities (Continued)

State Status

Approach to Incorporating

Externalities Rationale Where is it going?

Connecticut Operational The Department recently issued

its final report on the matter to the

Legislature. In that report, the

Department requires that, for all

factors requiring internalization as

a result of the Department’s sixstep screening process, utilities

use tradeoff analysis. This

analysis compares the costs of

control under alternative

scenarios with the quantified

impacts of controls. This method

was based on the Analysis Group

for Regional Electricity

Alternatives’ (AGREA) approach,

developed at the Massachusetts

Institute of Technology. This

approach uses graphs of

compliance costs and emissions

for different pollutants and for

different technology options.

The Department requires

that, where possible,

externalities be quantified by

weight or other nonmonetary

measures. In its final report,

the Department concluded

that the use of monetized

adders is highly subjective

and is not appropriate.

In the future, utilities are

expected to use the tradeoff

analysis approach that the

Department has adopted for

any factor that requires

internalization as determined

by the Department’s

screening process.

Delaware Operational A Delaware Order requires

qualitative, but not quantitative,

consideration. Utilities must report

how they consider and treat

externalities in their IRPs.

This Order is in agreement

with the Hearing Examiner’s

recommendation. The

Commission has a public

interest obligation to

consider environmental

factors.

There are no plans to re-open

the matter, although the

Hearing Examiner has

indicated that a

reconsideration might be

made.

District of

Columbia

Awareness DC requires that “noneconomic

factors are to be incorporated into

the resource screening process

but consideration of externalities

is not formally ordered at this

point.”

No change is anticipated at

this time.

Florida None Florida Power Plant Siting Board

appointed a task force to draw up

legislation based on the

Department of Environmental

Protection’s recent report. The

report states that externalities

should be considered qualitatively

in the power plant licensing

process (i.e. on the choice of

power plant). The Florida

Legislature did not enact the

legislation.

According to Florida’s

Department of

Environmental Protection,

use of quantitative values for

environmental externalities is

not practical now because

there is no consensus that

any set of values is accurate

or wholly defensible.

The Florida Public Service

Commission itself is not

formally considering the issue.

There are no dockets or

rulemaking underway.

Georgia Operational Georgia requires quantification

where possible and qualitative

considerations in cases where

quantification is not possible.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 81
Table A1. Summary of State Public Utility Commission’s Activities Regarding Externalities (Continued)

State Status

Approach to Incorporating

Externalities Rationale Where is it going?

Hawaii Operational Hawaii requires quantitative

consideration, if possible. If not,

then externalities must be

considered qualitatively.

Specified as part of Hawaii’s

IRP framework.

The current Order is the first

that requires consideration of

environmental externalities.

Companies have been filing

their IRPs. Hearings have

been concluded on two cases,

but no decision or order has

been issued yet on either one.

Idaho Awareness Idaho’s Least-Cost Planning

Order does not have a formal

requirement regarding

externalities. Some statements in

the Order suggest the desirability

of hydro enhancements, but there

are no generic statements about

such a preference.

No quantitative consideration

is expected soon.

Illinois Operational A statutory requirement

necessitates qualitative and, if

possible, quantitative

consideration.

One of the goals of public

utility regulation is

environmental quality.

A rulemaking case is pending

on how the Commission is to

treat externalities, with

hearings in the Spring of

1994. Two proposals are

under consideration: (a)

monetary adders for five

specific emissions; and (b)

cost of control for least-cost

system-wide control of

regulated emissions.

Indiana None Indiana does not require

consideration.

Indiana is still in the process

of developing resource

planning guidelines.

There are no plans to include

requirements regarding

externalities as part of the

forthcoming IRP rules.

Iowa Operational Iowa applies percent adders of 10

percent to avoided capacity and

energy costs for electric utilities

and 7.5 percent to avoided

capacity and energy costs for gas

utilities.

The calculations are part of

an energy efficiency plan

analysis in the State

(essentially an IRP).

No change is anticipated.

Kansas Developing The commission has proposed

IRP rules that require quantitative

consideration to the extent

feasible. Where externalities are

not readily monetized, the

proposal is that the utility consider

them on a qualitative basis.

Hearings are being held on

the proposed IRP rules and a

final rule is expected soon.

Kentucky Awareness Kentucky does not require

consideration.

There is no mention of

externalities in Kentucky’s

IRP regulations.

Kentucky is monitoring

developments in other States

and elsewhere.

Louisiana None Louisiana does not require

consideration.

Externalities are not an issue

in the State.

No change is anticipated.

82 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
Table A1. Summary of State Public Utility Commission’s Activities Regarding Externalities (Continued)

State Status

Approach to Incorporating

Externalities Rationale Where is it going?

Maine Developing Maine does not require

consideration, and is not actively

developing requirements. A

legislative initiative, however,

requires the Commission and

other State agencies to jointly

investigate the externalities of

energy production and

consumption.

As part of the 2-year study

required by the Legislature,

the PUC and other State

agencies are considering

existing regulations, other

States’ actions, and methods

of quantifying externalities.

Maryland Awareness Maryland does not have an Order

that mandates the use of

externality values. However,

there are conservation

collaboratives that develop

avoided costs to value demandside management, based on the

system resources of the utility. In

developing avoided costs,

externalities associated with SO2

and NOx are considered both

quantitatively and qualitatively.

Other externalities are considered

qualitatively. A 10-percent adder

was recently used in one utility’s

demand-side management

collaborative.

Utilities are increasingly

concerned about the impacts

of conservation programs on

rates. These concerns are

making it increasingly difficult

to negotiate on environmental

concerns.

Massachusetts Operational Massachusetts’ decision requires

quantitative consideration of

externalities based on numbers

the Commission adopted. The

values are as follows: $1,700/ton

SOx, $7,200/ton NOx, $5,900/ton

VOCs, $960/ton CO, $24/ton

carbon dioxide, $4,400/ton TSP,

$240/ton CH4, and $4,400/ton

N2O. These values are in 1992$

and are based on control costs.

Offsets will also be allowed where

applicable. Utilities may use

different numbers if they can

demonstrate that the methodology

used is as good as or better than

the methodology used to

determine the numbers above.

Utility resource decisions

have a significant and lasting

impact on the environment,

and therefore, it is

appropriate for

environmental and utility

regulators to establish

policies so that

environmental and economic

objectives can be satisfied at

least cost to society.

The Decision is under appeal

before the Supreme Judicial

Court of Massachusetts.

Michigan Awareness There is no explicit statutory

requirement on externalities.

Utilities assess the risk that

externalities will need to be

internalized at some point in the

life of the plant.

Any direct requirement

would be challenged by

industry interests within the

State.

No change is anticipated.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 83
Table A1. Summary of State Public Utility Commission’s Activities Regarding Externalities (Continued)

State Status

Approach to Incorporating

Externalities Rationale Where is it going?

Minnesota Operational Minnesota issued an Order that

sets “interim” values as follows:

SO2 0 - $300/ton

NOx $68.80 - $1,640/ton

VOCs $1,180 - $1,200/ton

TSP $166.60 - $2,380/ton

CO2 $5.99 - $13.60/ton

The values were determined

by the Public Utilities

Commission, taking into

account the comments from

all interested parties. The

low end of the range for SO2

assumed all costs to be

internalized; the high end for

SO2 was based on current

market price of emissions

allowances. The values for

NOx, VOCs, TSP, and CO2

are based on the

recommendations of the

Department of Public

Services. The low end of

the ranges are generally

based on a study conducted

by the Bonneville Power

Administration (BPA), while

the Pace study is the

primary basis for the high

end.

The Order on the interim

values was just made in

March 1994. Final values are

to be decided later.

Mississippi Awareness Mississippi does not require

consideration.

The issue may possibly arise

when Mississippi Power &

Light’s IRP is taken up again.

Missouri Operational Missouri has an IRP Rule that

requires utilities to assess the risk

that externalities will need to be

internalized at some point in the

life of the plant. The analysis

involves a three-step process

that: (1) lists the pollutants that

have some prospect of more

stringent regulation in the future;

(2) considers at least two levels

of control and their subjective

probabilities; and (3) computes

the cost of the expected (i.e.,

average) mitigation.

Some sort of quantitative

analysis seems necessary

since decisions will have an

impact on rates. However,

the legislative mandate is

not clear whether the

Commission has the

authority to require direct

consideration of externalities.

Also, the Commission

considers the valuation of

externalities to be highly

uncertain given the state of

the art and the great

variation among States

across the country.

The Public Service

Commission is beginning to

implement the process and

the first of five utilities has

filed.

Montana Developing Montana has IRP guidelines

(though no order) for utilities to

assess externalities and to

account for them in their leastcost plans. The guidelines call

for a range of estimates and their

uncertainty, and for a

consideration of the uncertainty

and risk of future environmental

regulations.

The Commission focuses on

the integration of

externalities when comparing

options for resource

acquisition.

In a recent cost of service and

rate design docket, the

Commission is scoping out

the prospect of integrating

externalities into the pricing of

electric power.

Nebraska None Nebraska does not regulate

electric utilities.

Nebraska is a public utility

State. There are no

investor-owned utilities.

84 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
Table A1. Summary of State Public Utility Commission’s Activities Regarding Externalities (Continued)

State Status

Approach to Incorporating

Externalities Rationale Where is it going?

Nevada Operational Nevada has a Rule that requires

quantitative consideration of

externalities. The values are as

follows: $1,716/ton SOx,

$7,480/ton NOx, $1,298/ton

VOCs, $1,012/ton CO, $24/ton

CO2, $4,598/ton TSP, $4,598

PM10, $242/ton CH4, and

$4,554/ton N2O. These values

are in 1992$, based on the 1990$

control-cost values given in the

Rule. Utilities can use other

values if they provide adequate

justification.

The quantitative values were

developed through a process

that involved a series of

public workshops. The

1990$ values in the Rule are

as follows: $1,560/ton SOx,

$6,800/ton NOx, $1,180/ton

VOCs, $920/ton CO, $22/ton

CO2, $4,180/ton TSP,

$4,180 PM10, $220/ton CH4,

and $4,140/ton N2O.

No changes are anticipated at

this time. The docket was

reopened, but is closed

without any changes affecting

environmental considerations.

New Hampshire Operational While New Hampshire does not

explicitly require consideration of

externalities, a recent Order

requires utilities to do a risk

avoidance analysis that takes into

account the risk of more stringent

environmental regulations (and

their subsequent costs).

The Commission is opposed

to monetizing environmental

impacts.

A group was formed among

regulators in New Hampshire,

Massachusetts, and Rhode

Island to try to reach a

regional consensus on how to

address externalities. The

group was unable to reach a

consensus. For now, the

Commission is focusing on

the use of risk avoidance

analysis to justify any

premium above avoided cost.

New Jersey Operational A 2 cents/kWh (1991$) credit is

given to demand-side

management (DSM) projects to

reflect the reduction in

externalities associated with

electric power.

Part of the evaluation criteria

for projects on the supply

side are location and

environmental benefits. On

the demand side, the

rationale for the DSM credit

is the environmental benefit

of energy conservation, as

compared to supply-side

resources.

Except for the DSM credit,

other aspects are in a state of

flux while the State works on

developing its IRP process.

New Mexico Developing The Commission has issued a

Notice of Proposed Rulemaking

with respect to IRPs. The Notice

refers to qualitative assessments

of externalities.

The next step is to have

hearings on the Notice of

Proposed Rulemaking.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 85
Table A1. Summary of State Public Utility Commission’s Activities Regarding Externalities (Continued)

State Status

Approach to Incorporating

Externalities Rationale Where is it going?

New York Operational New York requires quantitative

consideration based on values

developed using control costs.

Programs that promote energy

conservation are credited with 1.4

cents/kWh. Following is the

derivation of the maximum 1.4

cents/kWh credit:

SO2 0.250

NOx 0.550

CO2 0.100

Particulates 0.005

Water impacts 0.100

Land impacts 0.400

Total 1.405

These values represent the

externalities attributed to each of

the six sources of externalities,

that are associated with a new

coal plant that meets New Source

Performance Standards (NSPS).

Programs aimed at peak clipping

are credited with 0.9 cents/kWh,

and programs aimed at load

shifting are credited with 0.04

cents/kWh. These latter values

are based on residual

environmental impacts of the

resource relative to those of the

NSPS coal plant.

State legislation requires that

the State energy plan give

due regard to environmental

impacts. To estimate

externalities, values based

on the costs of control can

be developed in a more

straightforward way than

damage-cost estimates.

The new State energy plan

recommends a new set of

values (levelized, nominal

1992$ per ton):

SO2 $1,367

NOx $6,524

CO2 $8.6

PM $3,642

VOC $4,400

Air toxics $164,000

CO $423

The State Public Service

Commission may consider

this recommendation in the

near future. Also, a study is

being conducted to develop a

modeling system to calculate

site-specific externality values.

These values would be based

on estimates of damages,

rather than costs of control.

North Carolina Operational North Carolina requires qualitative

consideration.

When demand and supply

options have equivalent

costs and reliability, the

more benign resource will

produce greater societal

benefits.

The Commission has taken

no further action beyond

requiring qualitative

consideration.

North Dakota None North Dakota does not require

consideration.

The issue has not been

considered.

The issue is unlikely to be

considered by the State.

Ohio Operational Ohio requires utilities to use the

value of under-utilization on a

cents/kWh basis. For SO2, the

value of 0.04 cents/kWh is a

benchmark, with acceptable

values being in the range 0.03-

0.05 cents/kWh.

Following the Clean Air Act

Amendments, the

Commission considered the

constituents addressed in

the Act, and decided that it

was financially prudent not

to require utilities to do their

own research but rather wait

for other reliable quantitative

values to be developed. The

value of 0.04 cents/kWh for

SO2 is based on the U. S.

Environmental Protection

Agency’s estimate.

The Commission is waiting for

the development of other

reliable quantitative values for

the other constituents

addressed in the Clean Air

Act Amendments.

86 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
Table A1. Summary of State Public Utility Commission’s Activities Regarding Externalities (Continued)

State Status

Approach to Incorporating

Externalities Rationale Where is it going?

Oklahoma Awareness Oklahoma does not require

consideration.

Oklahoma is at an early

stage in developing an

Integrated Resource Plan.

There is a Notice of Inquiry

calling for comments on the

shape of an Integrated

Resource Planning (IRP) rule,

and there was a technical

conference in the Fall of

1994.

Oregon Operational Oregon has an Order that

requires utilities to perform

sensitivity analyses using the

following range of values —

NOx: $2,000 - $5,000/ton TSP:

$2,000 - $4,000/ton CO2: $10 -

$40/ton. Utilities may also present

the results of other approaches.

If a utility chooses to rely on

another approach to incorporate

external effects, then it must

explain why the approach is

superior to the use of adders in

the ranges listed above.

The Commission developed

the ranges of values based

on information presented by

the various parties involved.

No change is anticipated.

Pennsylvania Awareness Pennsylvania does not require

consideration of externalities.

The Commission may require

Integrated Resource Plans

(IRPs) to include externalities

in the future.

Rhode Island None The Rhode Island Commission

has not formally considered

incorporation of externalities in

evaluating new resources, and

has not accepted externalities

values on either the demand or

supply side.

Commission staff

participated in a regional

study aimed at coordinating

environmental externality

policies in New England, but

no regional consensus was

reached.

The regional task force is

continuing, with a focus now

on coordinating among the

States in such areas as Clean

Air Act compliance.

South Carolina Awareness South Carolina does not require

formal consideration. The utilities

are voluntarily considering them

qualitatively.

The Commission does not

presently require

consideration but is monitoring

developments regarding the

externality issue.

South Dakota Awareness South Dakota does not require

consideration.

The Commission is focusing

on other priorities relating to

the Energy Policy Act of

1992, and has not

considered the whole IRP

process yet.

The Commission will decide

on the Integrated Resource

Planning (IRP) process and

then decide on the externality

issue.

Tennessee None Tennessee does not regulate

electric utilities.

Texas Operational Texas Rule states that in its

Notice of Intent which sets forth

its resource planning, a utility

must consider external costs and

benefits. While the rule does not

explicitly stipulate quantification,

utilities have generally quantified

to the extent that they can.

Recently, a judge ruled that

qualitative treatment is

insufficient.

Following the general

guidelines of a 1983 statute

on public utility regulation,

the Commission believes it

needs to consider

environmental integrity when

licensing plants.

IRP rulemaking is ongoing. If

this IRP rule goes into effect,

then the existing rule will be

subsumed under the IRP rule.

The proposed rule includes

explicit consideration of at

least the six most commonly

considered air emissions.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 87
Table A1. Summary of State Public Utility Commission’s Activities Regarding Externalities (Continued)

State Status

Approach to Incorporating

Externalities Rationale Where is it going?

Utah Operational Utah’s Public Service

Commission has promulgated IRP

standards and guidelines that

require consideration of

externalities. Air emissions for

each resource considered in the

IRP must be quantified in terms

of pounds, tons, etc. The

standards require a risk mitigation

analysis, based on a range of

monetary values for the

emissions, and mitigation

strategies in the utilities’ 2-year

action plans.

“Prudent business planning

must evaluate environmental

risks and uncertainties.”

No change is anticipated at

this time.

Vermont Operational When computing avoided cost,

Vermont requires 5-percent

adders to reflect external costs in

(all conventional) supply-side

resources. For demand-side

resources, costs are decreased

by 10 percent to reflect the

comparative risk benefit of

demand-side management (DSM)

measures relative to supply side.

An Order calls on the use of

adders to reflect the external

costs of producing and

delivering electricity to endusers.

The Public Service Board is in

the midst of a litigated

proceeding which is

considering different

environmental costs among all

resource options (supply,

demand, and transmission

and distribution).

Virginia Awareness While Virginia has used a 15-

percent adder in the past, in a

recent demand-side management

review, the Commission rejected

quantification.

The Commission considers

that it has an obligation to

consider environmental

impacts, but that further

study is needed before a

policy on quantifying

externalities can be

developed.

The Commission feels that it

should get direction on the

issue from the General

Assembly or Congress before

adopting a comprehensive

policy toward externalities.

Washington Operational Washington requires

consideration of externalities in

requests for proposals. A specific

cost adder has been adopted.

The Commission gives a 10-

percent credit for conservation

programs compared to supply

options.

The 10-percent credit is

based on Northwest Power

Planning Council guidelines.

No change is anticipated.

West Virginia None West Virginia does not require

consideration.

In regulating utilities, the

Commission must balance

the economic and other

interests of the State.

No requirement for

consideration is anticipated in

the future.

88 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
Table A1. Summary of State Public Utility Commission’s Activities Regarding Externalities (Continued)

State Status

Approach to Incorporating

Externalities Rationale Where is it going?

Wisconsin Operational Wisconsin requires quantitative

and qualitative consideration. No

specific methodology has been

given; that is left to the individual

utilities. Utilities must also reflect

the risk that “greenhouse gases”

will be regulated in the future

using the numbers developed by

the Commission. They are as

follows: $15 per ton of CO2; $150

per ton of CH4 (methane); and

$2,700 per ton of N2O. The

Commission also accepts the use

of offsets.

The Commission does not

feel that the Legislature

intended to prohibit the

Commission from accounting

for externalities.

Wyoming None Wyoming requires that utilities

take all demonstrated costs into

account in their IRPs. Wyoming

does not require explicit

consideration of externalities as

these have not been

demonstrated for the State of

Wyoming.

Wyoming considers that it

already has very stringent

environmental laws that

internalize all externalities of

any significance or

consequence.

No change is anticipated.

The “Status” categories that define each State’s position on incorporating externalities in their regulatory requirements are defined

as follows: •Operational means that the State has an order, rule, statute, or other legal decision that requires utilities to explicitly

consider externalities in terms of monetary values, percentage adders, or on a qualitative basis; or to explicitly assess the risks of

more stringent environmental regulation in the future (i.e., that externalities will have to be internalized in the future). •Developing

means that the State is assessing the possibility of requiring utilities to consider externalities in their IRPs, or in some similar

process. Thus, States in the midst of rulemaking, hearings, task forces, or other deliberations are in this category. •Awareness

means that the State has no requirement for utilities to consider externalities and that it is not developing possible requirements,

but that it has guidelines or that there is a reasonable possibility of considering requirements in the future. •None means that the

State does not have a requirement (possibly having considered and rejected such a requirement), is not formally assessing the need

for a requirement (or for an analysis of the risk of more stringent environmental regulations in the future), and is unlikely to take

any of these actions in the foreseeable future. Based on this classification, the number of States in each category is O: 23 States;

D: 5 States; A: 12 States; N: 11 States.

CO = carbon monoxide; CO2 = carbon dioxide; CEC = California Energy Commission; CH4 = methane; DSM = demand-side

management; IRP = integrated resource planning/plan; NOx = nitrogen oxide; N2O = nitrous oxide; PM10 = particulate matter less

than 10 microns in diameter; PUC = public utility commission; NSPS = new source performance standards; ROG = reactive organic

gases; SO2 = sulfur dioxide; SOx = sulfur oxide; TSP = total suspended particulates; VOCs = volatile organic compounds.

Notes: This table was compiled by Russell Lee and Todd Stevenson of the Oak Ridge National Laboratory from discussions with

State public utility commission (PUC) staff and review of PUC documents, supplemented with information from the Electric Power

Research Institute’s EPRINET database, Environmental Externalities News. The table was completed in early 1994. Subsequent

changes are, therefore, not reflected in the above table. For example, the Massachusetts Supreme Judicial Court determined the

designation of monetary values by the Massachusetts Department of Public Utilities to be beyond the range of its statutory authority.

Accordingly, the electric utilities in Massachusetts are no longer required to incorporate externality values in their resource planning.

Avoided externalities—social costs not incurred because the producer has taken some action to mitigate them. Attainment—in

compliance with National Ambient Air Quality Standards or comparable State standards. Avoided capacity costs—quantification

of avoided externalities due to increased technological efficiency or demand-side management, which has relieved the need to build

additional capacity (thereby creating an increase in externalities). Offsets—programs designed to reduce the net increases in

emissions by offsetting increases from one source by decreasing or by sequestering emissions from another source. Adder—a

hypothetical cost added to electricity production costs, or subtracted from DSM programs, to represent an externality. The value

of an adder is based on a percentage of the production cost.

Source: Oak Ridge National Laboratory, “The Impact of Environmental Externality Requirements on Renewable Energy” (Oak

Ridge, TN, December 1994).

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 89
Glossary
Glossary

Note: Many of the environmental definitions contained in this glossary were excerpted with permission from the

Guide to Environmental Issues, published by the U.S. Environmental Protection Agency.

Abatement: Reducing the degree or intensity of, or

eliminating, pollution.

Acid Rain: Also called acid precipitation or acid

deposition, acid rain is precipitation containing harmful

amounts of nitric and sulfuric acids formed primarily

by nitrogen oxides and sulfur oxides released into the

atmosphere when fossil fuels are burned. It can be wet

precipitation (rain, snow, or fog) or dry precipitation

(absorbed gaseous and particulate matter, aerosol particles or dust). Acid rain has a pH below 5.6. Normal

rain has a pH of about 5.6, which is slightly acidic. The

term pH is a measure of acidity or alkalinity and

ranges from 0 to 14. A pH measurement of 7 is regarded as neutral. Measurements below 7 indicate

increased acidity, while those above indicate increased

alkalinity.

Adders: Environmental adders are estimates of the

monetary value of damage imposed upon society by

each additional ton of a particular pollutant. In theory,

when these values are added to the direct cost of

resources under planning consideration, resources with

the lowest total social cost can be identified.

Air Quality Standards: The level of selected pollutants

set by law that may not be exceeded in outside air.

Used to determine the amount of pollutants that may

be emitted by industry.

Allowance: An authorization for the holder to emit a

specified amount of a pollutant into the atmosphere as

set forth in the Clean Air Act Amendments, i.e. one SO2

allowance permits one ton of SO2 emissions.

Alternative Fuels: Refers to requirements for replacing

conventional fuels with alternative, less polluting fuels,

established both by State governments and by the 1990

Clean Air Act Amendments.

Ambient Air: Any unconfined portion of the atmosphere; open air; outside surrounding air.

Avoided Costs: The incremental costs of energy

and/or capacity, except for the purchase from a qualifying facility, that a utility would incur in the

generation of the energy or its purchase from another

source.

Beneficiation: The dressing or processing of ores for

the purpose of (1) regulating the size of a desired

product, (2) removing unwanted constituents, and

(3) improving the quality, purity, or assay grade of a

desired product.

Biodiversity: Refers to the variety and variability

among living organisms and the ecological complexes

in which they occur. Diversity can be defined as the

number of different items and their relative frequencies.

For biological diversity, these items are organized at

many levels, ranging from complete ecosystems to the

biochemical structures that are the molecular basis of

heredity. Thus, the term encompasses different ecosystems, species, and genes.

Btu (British Thermal Unit): A standard unit for

measuring the quantity of heat energy equal to the

quantity of heat required to raise the temperature of

one pound of water by one degree Fahrenheit.

Chlorofluorocarbons (CFCs): A family of chemicals

commonly used in air conditioners and refrigerators as

coolants and also as solvents and aerosol propellants.

CFCs drift into the upper atmosphere where their

chlorine components destroy ozone. CFCs are thought

to be a major cause of the ozone hole over Antarctica.

Climate Change: Potentially disruptive changes to the

Earth’s climate caused by rising absorption of the sun’s

heat. The sun’s heat is captured within the Earth’s

atmosphere by so-called “greenhouse gases,” such as

water vapor, carbon dioxide, methane, and nitrous

oxide. Atmospheric concentrations of these gases are

rising due to human activities, including combustion of

fossil fuels and deforestation.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 93
Coal: A black or brownish-black solid combustible

substance formed by the partial decomposition of

vegetable matter without access to air.

Command and Control: The command and control

approach attempts to control pollution by means of

regulatory instruments. With the command and control

approach, polluters are required to comply with certain

regulations.

Conservation: Preserving and renewing natural resources to assure their highest economic or social

benefit over the longest period of time. Clean rivers and

lakes, wilderness areas, a diverse wildlife population,

healthy soil, and clean air are natural resources worth

conserving for future generations.

Cost-Benefit Analysis: As an economic tool for project

evaluation or investment appraisal, cost-benefit analysis

is used to quantify and compare the costs and benefits

of alternative ways of achieving the same objectives.

Cost Effectiveness: This term refers to providing a

given service or good with least cost.

Cradle-to-Grave or Manifest System: A procedure in

which hazardous wastes are identified as they are

produced and are followed through further treatment,

transportation, and disposal by a series of permanent

linkable, descriptive documents.

Criteria: Descriptive factors taken into account by EPA

in setting standards for pollutants. For example, water

quality criteria describe the concentration of pollutants

that most fish can be exposed to for an hour without

showing acute effects.

Damage Function Approach: A step-by-step approach

to valuing environmental damages, starting from

emissions, to concentrations, to impacts, to damage.

Damages: Following legal terminology, damages are

the monetized value of detrimental impacts which

accrue to society from the activities of producers and

consumers. A related term, benefit, refers to the monetary value of positive impacts.

Demand: The functional relationship between the price

and the quantity of a good demanded by the buyer.

Demand (Electric): The rate at which electric energy is

delivered to or by a system, part of a system, or piece

of equipment, at a given instant or averaged over any

designated period of time.

Demand-Side Management (DSM): The planning,

implementation, and monitoring of utility activities

designed to encourage consumers to modify patterns of

electricity usage, including the timing and level of

electricity demand. It refers only to energy and loadshape modifying activities that are undertaken in

response to utility-administered programs. It does not

refer to energy and load-shape changes arising from the

normal operation of the marketplace or from government-mandated energy-efficiency standards. DSM

covers the complete range of load-shape objectives,

including strategic conservation and load management,

as well as strategic load growth.

Dielectric Fluid: A fluid that can sustain an electric

field. Because of its ability to permit the passage of the

lines of force of an electrostatic field without conducting the current, it is used in transformers,

capacitors, and between adjacent wires in a cable.

Discharge: The release of any waste into the environment from a point source. Usually refers to the release

of a liquid waste into a body of water through an outlet

such as a pipe, but also refers to air emissions.

Disposal: The discharge, deposit, injection, dumping,

spilling, leaking, or placing of any solid waste or

hazardous waste into the environment (land, surface

water, ground water, and air).

Ecosystem: The interacting synergism of all living

organisms in a particular environment; every plant,

insect, aquatic animal, bird, or land species that forms

a complex web of interdependency. An action taken at

any level in the food chain, use of a pesticide for

example, has a potential domino effect on every other

occupant of that system.

Economic Efficiency: An optimum allocation of

resources met when the price of a good equals its

marginal cost. Externalities, public goods, monopoly, or

decreasing cost production may undermine economic

efficiency.

Effluent: Waste water, treated or untreated, that flows

out of a treatment plant, sewer, or industrial outfall.

Generally refers to wastes discharged into surface

waters.

Electric Power Industry: The privately, publicly,

Federally, and cooperatively owned electric utilities of

the United States taken as a whole. This includes all

electric systems serving the public: regulated investorowned electric utility companies; Federal power

94 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
projects; State, municipal, and other government-owned

systems, including electric public utility districts; electric cooperatives, including generation and transmission

entities. Excluded from this definition are the special

purpose electric facilities or systems that do not offer

service to the public.

Electric Utility: A corporation, person, agency, authority, or other legal entity or instrumentality that

owns and/or operates facilities within the U.S., its

territories, or Puerto Rico for the generation, transmission, distribution, or sale of electric energy primarily

for use by the public and files forms listed in the Code

of Federal Regulations, Title 18, Part 141. Facilities that

qualify as cogenerators or small power producers under

the Public Utility Regulatory Policies Act (PURPA) are

not considered electric utilities.

Emission: The release or discharge of a substance into

the environment; generally refers to the release of gases

or particulates into the air.

Emissions Trading: With an emissions trading system,

a regulatory agency specifies an overall level of pollution that will be tolerated—a cap—and then uses

allowances to develop a market to allocate the pollution

among sources of pollution under that cap. Emissions

permits or allowances become the currency of the market, as pollution sources are free to buy, sell, or

otherwise trade permits based on their own marginal

costs of control and the price of the permits. In no case

can the total emissions exceed the cap.

Environment: The sum of all external conditions

affecting the life, development, and survival of an

organism.

Environmental Assessment (EA): A preliminary, written, environmental analysis required by the National

Environmental Policy Act to determine whether a

Federal activity, such as building airports or highways,

would significantly affect the environment.

Environmental Impact Statement (EIS): A document

prepared by or for the Environmental Protection

Agency which identifies and analyzes, in detail,

environmental impacts of a proposed action. As a tool

for decision-making, the EIS describes positive and

negative effects and lists alternatives for an undertaking, such as development of a wilderness area.

Factor Mobility: Factor mobility refers to the ease (or

the lack of it) with which inputs or resources used in

the process of production, i.e., land, labor, and capital,

can be moved among competing uses.

Federal Power Facility: A utility that is either owned

or financed by the Federal Government.

Flue Gas Desulfurization: The removal of sulfur

oxides from the combustion gases of a boiler plant

before discharge to the atmosphere. Chemicals, such as

lime, are used as the scrubbing media.

Fossil Fuel: Any naturally occurring organic fuel, such

as petroleum, coal, and natural gas.

Fuel Cycle: The series of physical and chemical processes and activities that are required to generate

electricity from a specific fuel or resource.

Fuel Switching: A precombustion process whereby a

low-sulfur coal is used in place of a higher sulfur coal

in a power plant to reduce sulfur dioxide emissions.

Gas Turbine: A gas turbine consists typically of an

axial-flow air compressor and one or more combustion

chambers, where liquid or gaseous fuel is burned and

the hot gases are passed to the turbine and where the

hot gases expand to drive the generator and are then

used to run the compressor.

Generating Unit: Any combination of physically connected generator(s), reactor(s), boiler(s), combustion

turbine(s), or other prime mover(s) operated together to

produce electric power.

Generation: The process of producing electric energy

by transforming other forms of energy; also, the

amount of electric energy produced, expressed in

watthours (Wh).

Gigawatt: One billion watts.

Global Warming: The scientific hypothesis which

states that the earth’s temperature is rising as a result

of the increasing concentration of certain gases, known

as greenhouse gases, in the atmosphere, trapping heat

that would otherwise radiate into space.

Greenhouse Effect: A popular term used to describe

the roles of water vapor, carbon dioxide, and other

trace gases in keeping the Earth’s surface warmer than

it would be otherwise. These radiatively active gases

are relatively transparent to incoming shortwave

radiation, but are relatively opaque to outgoing

longwave radiation. The latter radiation, which would

otherwise escape to space, is trapped by these gases

within the lower levels of the atmosphere. The subsequent reradiation of some of the energy back to the

Earth maintains surface temperatures higher than they

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 95
would be if the gases were absent. There is concern that

increasing concentrations of greenhouse gases, including carbon dioxide, methane, and manmade chlorofluorocarbons, may enhance the greenhouse effect and

cause global warming.

Greenhouse gases: Those gases, such as water vapor,

carbon dioxide, tropospheric ozone, nitrous oxide, and

methane, that are transparent to solar radiation but

opaque to longwave radiation. Their action is similar to

that of glass in a greenhouse.

Gross National Product (GNP): The market value, in

monetary terms, of goods and services produced by

labor and property supplied by the residents of a

nation, within a specified period of time.

Hazardous Substance: (1) Any material that poses a

threat to human health and/or the environment.

Typical hazardous substances are toxic, corrosive,

ignitable, explosive, or chemically reactive. (2) Any

substance designated by EPA to be reported if a

designated quantity of the substance is spilled in the

waters of the United States or if otherwise released into

the environment.

Hazardous Waste: By-products of society that can pose

a substantial or potential hazard to human health or the

environment when improperly managed. Possesses at

least one of four characteristics (ignitability, corrosivity,

reactivity, or toxicity), or appears on special EPA lists.

Impact: This term is taken from the phrase, environmental impact statement, meaning the physical or

socioeconomic effect of some activity. Examples of

physical impacts are changes in crop yields, human

health, and recreation resources. Examples of socioeconomic impacts are changes in aesthetics, noise

nuisance, and employment conditions.

Integrated Resource Planning: In the case of an

electric utility, a planning and selection process for new

energy resources that evaluates the full range of

alternatives, including new generating capacity, power

purchases, energy conservation and efficiency, cogeneration and district heating and cooling applications,

and renewable energy resources, in order to provide

adequate and reliable service to its electrical customers

at the lowest system cost. Often used interchangeably

with least-cost planning.

Internalizing Externalities: This expression means to

create social conditions where the damages (or benefits)

from production and consumption are taken into

account by those who produce these effects. These

social conditions can be created by government regulation, a tort system, bargaining between private parties,

or other policy and institutional arrangements. Benefits

and damages can exist even when all externalities have

been internalized.

Investor-Owned Utility (IOU): A class of utility that

is investor owned and organized as a tax paying

business, usually financed by the sales of securities in

the capital market.

Kilowatt: One thousand watts.

Kilowatthour: One thousand watthours.

Least-Cost Planning: See Integrated Resource Planning.

Load Management: Efforts to change electricity

demand to reduce cost; includes actions by consumers,

utilities, or public agencies to reduce, shift, or increase

demand at selected times.

Manifest System: Tracking of hazardous waste from

“cradle to grave” (generation through disposal), with

accompanying documents known as “manifests.” See

Cradle-to-Grave.

Marginal: Pertaining to the last unit, i.e., the marginal

cost of an output is the increase in the total production

cost of the output caused by producing the last unit of

the output.

Marginal Benefit: The cost of damage avoided by

reducing one additional unit of pollutant.

Marginal Cost: The cost of reducing one additional

unit of pollutant.

Market Pricing Approach: The market approach to

internalizing externalities attempts to put price tags on

externalities directly in the marketplace, therefore

causing the prices for products or services to reflect

their full social costs. Market approaches that are

discussed in the report include emissions trading, taxes,

fees, liability, and subsidies.

Maximum Social Welfare: An allocation of resources

that cannot be improved; that is, no one can be made

better off without someone being made worse off. It

can only be determined with the distribution of income

taken as given.

Megawatt (MW): One million watts.

Megawatthour (MWh): One million watthours.

96 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies
National Ambient Air Quality Standards (NAAQS):

Maximum air pollutant standards that EPA set under

the Clean Air Act for attainment by each State. The

standards were to be achieved by 1975, along with State

implementation plans to control industrial sources in

each State.

Natural Gas: A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in porous geological formations beneath the earth’s surface, often in

association with petroleum. The principal constituent is

methane.

Non-Attainment: Refers to areas of the United States

that have not met air standards for human health by

deadlines set in the Clean Air Act.

Nuclear Reactor: An apparatus in which the nuclear

fission chain can be initiated, maintained, and controlled so that energy is released at a specific rate. The

reactor includes fissionable material (fuel), such as

uranium or plutonium; fertile material; moderating

material (unless it is a fast reactor); a heavy-walled

pressure vessel; shielding to protect personnel; provision for heat removal; and control elements and

instrumentation.

Operating Capability: The available capability of a

generating unit excluding any limitations such as environmental, legal, or regulatory restrictions, extensive

modifications or repairs, or being in a mothballed state.

Oxidant: A substance containing oxygen that reacts

chemically with other materials to produce new substances. Oxidants are the primary ingredients in smog.

Ozone: Three molecule oxygen compound (O3) found

in two layers of the earth’s atmosphere. One layer of

beneficial ozone occurs at 7 to 18 miles above the

surface and shields the earth from ultraviolet light.

Several holes in this protective layer have been documented by scientists. Ozone also concentrates at the

surface as a result of reactions between by-products of

fossil-fuel combustion and sunlight, having harmful

health effects.

Ozone Depletion: The depletion of the earth’s stratospheric ozone layer, which protects life on earth from

radiation. The use of synthetic chlorofluorocarbons

(CFCs) is the principal cause of ozone depletion.

Particulates: Solid particles, such as ash, released in

exhaust gases at fossil-fuel plants during the combustion process.

Perfect Competition: The condition where the actions

of any single buyer or seller have no effect on the price

of a product in the market. It requires a large number

of buyers and sellers.

Permit: A legal document issued by State and/or

Federal authorities containing a detailed description of

the proposed activity and operating procedures as well

as appropriate requirements and regulations. The permitting process includes provisions for public comment.

Petroleum: A mixture of hydrocarbons existing in the

liquid state found in natural underground reservoirs,

often associated with gas. Petroleum includes fuel oil

No. 2, No. 4, No. 5, and No. 6; topped crude; kerosene;

and jet fuel.

Petroleum (Crude Oil): A naturally occurring, oily,

flammable liquid composed principally of hydrocarbons. Crude oil is occasionally found in springs or

pools but usually is drilled from wells beneath the

earth’s surface.

Pollution: Any substances in water, soil, or air that

degrade the natural quality of the environment, offend

the senses of sight, taste, and smell, and cause a health

hazard. The usefulness of the natural resource is

usually impaired by the presence of pollutants and contaminants.

Polychlorinated Biphenyls (PCBs): A group of toxic,

persistent chemicals used in electrical transformers and

capacitors for insulating purposes, and in gas pipeline

systems as a lubricant. The sale and new use of PCBs

were banned by law in 1979.

Private Costs: Costs that are reflected in the market

price and borne by the producers or consumers of a

product or service.

Production Function: A mathematical relationship

between the output of a firm (or the economy) and the

inputs used to produce that output. The relationship

can be so written that constant, increasing, or decreasing returns to scale can be exhibited.

Public Utility: An enterprise providing essential public

services, such as electric, gas, telephone, water and

sewer, under legally established monopoly conditions.

Qualifying Facility (QF): A cogeneration or small

power production facility that meets certain ownership,

operating, and efficiency criteria established by the

Federal Energy Regulatory Commission (FERC) pursuant to the Public Utility Regulatory Policies Act.

Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies 97
Rate of Return: The ratio of net operating income

earned by a utility calculated as a percentage of its rate

base.

Release: Any spilling, leaking, pumping, pouring,

emitting, emptying, discharging, injecting, escaping,

leaching, dumping, or disposing into the environment

of a hazardous or toxic chemical, or extremely hazardous substance.

Renewables: An energy source that is regenerative or

virtually inexhaustible. Typical examples are wind,

geothermal, and water power.

Residual Emissions: Emissions containing pollutants

which remain after compliance with all existing

regulations.

Siting: Choosing a location for a facility.

Smog: Air pollution associated with oxidants.

Social or Societal Cost: The term social cost is often

used interchangeably with the cost of externalities, but

actually refers to the sum of private costs and the costs

of externalities.

Solid Waste: Any solid, semi-solid, liquid, or contained gaseous materials discarded from industrial,

commercial, mining, or agricultural operations, and

from community activities. Solid waste includes garbage, construction debris, commercial refuse, sludge

from water supply or waste treatment plants or air pollution control facilities, and other discarded materials.

Spent Nuclear Fuel: Fuel that has been withdrawn

from a nuclear reactor following irradiation, the constituent elements of which have not been separated by

reprocessing.

Steam-Electric Plant: A plant in which the prime

mover is a steam turbine. The steam used to drive the

turbine is produced in a boiler where fossil fuels are

burned.

Stranded Assets/Costs/Investment: Investment with a

cost recovery schedule that was initially approved by

regulatory action that subsequent regulatory action has

rendered not practically recoverable.

Subsidies: Financial incentives that are employed to

ensure the fulfillment of an environmental policy

objective. Subsidies considered in this report are

government financial support for capital investment in

pollution control equipment or less polluting processes.

Indirect subsidies, such as financial support for research

and development related to pollution control, are not

discussed in this report.

Technology Standards: Technology standards for pollution control can take various forms. These may

include prescriptive technology requirements for certain

pollution control measures; the prescription that best

available technologies for pollution control have to be

used; or specification of a minimum energy efficiency

standard for residential appliances, industrial equipment, plants, buildings, or automobiles. Technology

standards are often set on the basis of what can be

done with available technology. The government

specifies the equipment that must be used to control

pollution. The only pollution permitted is that remaining after sources have installed the prescribed

pollution control equipment.

Toxic Substance: A chemical or mixture that can cause

illness, death, disease, or birth defects. The quantities

and exposures necessary to cause these effects can vary

widely. Many toxic substances are pollutants and

contaminants in the environment.

Transboundary Effects: Transboundary effects occur

when a source of pollution is within a separate government jurisdictional boundary from the one in which the

impact of the pollution is incurred (for example, when

winds carry SO2 emissions from U.S. factories into

Canada where the pollution is deposited as acid rain).

Since the benefits of controlling transboundary pollution occur outside the government jurisdictional

boundary, there is little incentive for the government

jurisdiction to regulate transboundary pollution.

Utility: Investor-owned companies and public agencies

engaged in the generation, transmission, or distribution

of electric power for public use. Public agencies include

municipal electric utilities, Federal power projects, rural

electrification, cooperatives, power districts, and State

power authorities and projects.

98 Energy Information Administration/ Electricity Generation and Environmental Externalities: Case Studies