United states
Environmental Protection
Agency
Radiation
(6204J)
EPA430-R-94-001
February 1994
Energy Efficiency and
Renewable Energy
Opportunities from Title IV of the Clean Air Act

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,— wrt. , V. • u • ..
This handbook was prepared jointly by the US Environmental
Protection Agency and ICF Incorporated under contract # 68-
D3-0005. Contributing authors from EPA were Lloyd Wright,
Jennifer Selber, and Joe Kruger. Important inputs to this
handbook were also provided by Steven Brick, Steven Kihm,
Jerry Mendi, and David Schoengold of MSB Energy Associ-
ates; Michael Marvin of the American Wind Energy Associa-
tion; Rick Morgan of EPA; Manuel Patino of EUA Cogenex
Corporation; and Lynn Sutcliffe of Sycom Enterprises.

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ENERGY EFFICIENCY AND RENEWABLE ENERGY:

        Opportunities from Title IV of the Clean Air Act
                  ACID RAIN DIVISION
          US ENVIRONMENTAL PROTECTION AGENCY
                   FEBRUARY 1994

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Table of Contents
List of Tables and Figures . ii
Executive Sumrnaiy iii
Introduction 1
Part 1: The Acid Raid Program 5
A. Overview of the Acid Rain Program 6
B. The Allowance Trading Market 7
C. Environmental Benefits 8
Part 11: The Incentives: Clean Air Act Opportunities 13
A. Avoided Emissions 14
B. Conservation and Renewable Energy Reserve 17
C. Reduced Utilization 23
Part III: Efficiency and Renewable Energy in SO 2 Compliance Strategies 29
A. SO 2 Emissions and Resource Type 30
B. Avoided Emissions 33
C. Conservation and Renewable Energy Reserve 41
D. Reduced Utilization 43
Part IV: Efficiency and Renewable Energy Cost-Effectiveness 47
A. Avoided Costs 48
B. Demand-Side Efficiency Programs 51
C. Supply-Side Efficiency Programs 54
D. Renewable Energy Projects 56
E. Bidding 58
F. System Dispatch 59
Part V: Beyond SO 2 : Other Pollutants 65
A. Applying the Concepts to Other Pollutants 67
B. Externalities 68
C. Using Efficiency and Renewable Energy to Reduce Regulatory Risk .. 71
Conclusion 75
Endnotes 79
Appendix A: Production-Simulation Modelling 81
Appendix B: Conservation and Renewable Energy Reserve Application Form... . 85

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TABLE OF CONTENTS
List of Tables and Figures
Table I-i Projected Allowance Prices 9
Table 111-1 Emissions Impacts of DSM Programs 37
Table 111-2 Reserve Allowances of Utility B 42
Table 111-3 Reserve Allowances of Utility D 43
Table IV- 1 Avoided Costs for Utility A 50
Table IV-2 Avoided Costs for Utilities A, B, and C 51
Table IV-3 Effect of Avoided SO 2 Emission Costs on DSM Cost-Effectiveness . . . 53
Table IV-4 Effect of Avoided SO 2 Emission Costs on IPP Profitability 59
Table IV-5 Effect of Renewable Energy Resource on Dispatch Order 66
Table V-i Environmental Externality Values 71
Table V-2 Effect of Externalities on Avoided Costs 72
Figure II- 1 Reserve Application Procedures 19
Figure JV-i Avoided Costs and Program Participation 55

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Executive Summary
The 1990 Clean Air Act Amend-
ments provide a significant opportunity
for energy efficiency and renewable
energy to play a cost-effective role in an
electric utility’s resource mix. Through
an innovative system of tradeable emis-
sion allowances, Title l v of the Act calls
for a 10 million ton reduction in nation-
al SO 2 emissions. To encourage pollu-
tion prevention, Title 1V includes three
incentives to promote the use of efficien-
cy and renewable energy.
The Incentives
The three incentives to encourage
efficiency and renewable energy are:
1. Avoided emissions;
2. Conservation and Renewable
Energy Reserve; arid
3. The Reduced Utilization provision.
Avoided emissions is perhaps the
most lucrative of the three incentives;
each ton of SO 2 avoided through effi-
ciency and/or renewable energy saves
one emission allowance. Thus, the
avoided emissions incentive allows a
utility to save emission allowances at
the utility’s own rate of emissions.
Furthermore, the avoided emissions
incentive is quite simple to implement;
no reporting, applications or verification
are required.
The Conservation and Renewable
Energy Reserve is a special bonus pool
of 300,000 allowances set aside to re-
ward new initiatives in demand-side
efficiency and renewable energy. For
every 500 MWh of energy saved through
demand-side efficiency or generated
through renewable energy, a utility
earns one allowance from the Reserve.
A utility is eligible for Reserve allowanc-
es from January 1, 1992 until the utility
enters the Acid Rain Program.
Reduced utilization of an affected
unit is one compliance option. During
Phase I, though, a utility may not re-
duce generation below its baseline
merely by shifting generation to non-
affected units, unless such shifts are
offset by efficiency or renewable energy.
Thus, efficiency and renewable energy
resources can help avoid the loss of
emission allowances and the imposition
of other penalties.
In general, the value of these
incentives will be the number of allow-
ances generated or saved multiplied by
the market price of an SO 2 emission
allowance.
SO 2 Compliance Strategies
Efficiency and renewable energy
can be cost-effective components to an
integrated compliance strategy. Effi-
ciency and renewable energy can play a
significant role by:
U Complementing or offsetting the
use of other compliance strategies
such as fuel-switching;
U Delaying the use of expensive
alternative strategies such as
scrubbing;

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iv EXECUTIVE SUMMARY
L i Helping to avoid penalties asso-
ciated with noncompliance; and
Li Increasing revenues through the
sale of extra allowances.
The usefulness of the three incentives
on SO 2 compliance depends upon each
utility’s own circumstances. Utilities
that currently emit high levels of SO 2
can benefit significantly from the incen-
tives. However, even utilities already in
compliance can benefit from the reve-
nues generated by extra allowances.
Resource Cost- Effectiveness
Because emission allowances
place an economic value on SO 2 emis-
sions, a utility’s avoided costs will
change as a result of Title IV. In turn,
increases in avoided costs due to avoid-
ed SO 2 costs will increase:
Li The number of efficiency mea-
sures and renewable energy op-
tions that are cost-effective;
Li The penetration of efficiency pro-
grams and the size of renewable
energy projects; and
Li The project economics for energy-
service companies and indepen-
dent power producers.
Thus, program design and screening
procedures for demand-side efficiency
programs, supply-side efficiency pro-
grams, and renewable energy projects
should incorporate avoided SO 2 costs.
Likewise, bidding and dispatch process-
es should include these costs.
Beyond SO 2
Efficiency and renewable energy
not only help utilities avoid SO 2 emis-
sions but other pollutants as well, in-
cluding NOx, C0 2 , toxics, and
particulates. The methodologies for
incorporating SO 2 costs into compliance
planning and resource cost-effectiveness
can apply to other pollutants as trading
markets emerge. In some regions,
where ground-level ozone is a problem,
trading systems for NOx are being devel-
oped.
Even when a pollutant is not
presently regulated, it may be cost-effec-
tive to consider the pollutant when for-
mulating SO 2 strategies. The addition
of expensive control technologies for
each pollutant can be considerably more
costly than addressing all pollutants
simultaneously through efficiency and
renewable energy. Thus, efficiency and
renewable energy resources can help a
utility minimize the risk of future envi-
ronmental regulations.
Integrated Resource
Planning
The market-based benefits of the
Clean Air Act incentives are ideal inputs
for integrated resource planning. By
incorporating these benefits into the
planning process the true economic
competitiveness of energy efficiency and
renewable energy is more fully realized.

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Introduction
The Clean Air Act Amendments of 1990 have given
energy efficiency and renewable energy resources an
added quantifiable value. The purpose of this handbook
is to assist in quant fyirtg the incentives from Title IV of
the Clean Air Act.
- Photo courtesij of U.S. House of Representatives

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21 I NTRODUCTION
Energy efficiency and renewable
energy are valued resources in meeting
future energy demands. The Clean Air
Act Amendments of 1990 increased the
attractiveness of these resources
through an innovative system of trade-
able emission allowances. This hand-
book quantifies the added value energy
efficiency and renewable energy bring to
an electric utility based upon the incen-
tives in Title 1V of the Clean Air Act.
Clean Air Act Goals and
Incentives
When the United States Congress
embarked upon the Clean Air Act
Amendments, several goals were para-
mount. The primary goals for Title 1V,
the Acid Rain Program, are:
Achieve significant environmental
benefits by reducing emissions of
sulfur dioxide and nitrogen oxide;
Reduce these emissions at the
lowest cost to society: and
Encourage pollution prevention
through efficiency and renewable
energy.
The resulting legislation called for
a 10 million ton emission reduction in
sulfur dioxide and a 2 million ton reduc-
tion in nitrogen oxides.’ To promote
pollution prevention the program in-
cludes three incentives for energy effi-
ciency and renewable energy. These
three incentives are:
1. Allowance savings from avoided
emissions;
2. Bonus allowances from the Con-
servation and Renewable Energy
Reserve: and
3. Generation shifts away from high
emitting plants by use of the Re-
duced Utilization provision.
Handbook Contents and
Structure
This handbook will describe how
each of the three incentives work and
the potential impact on environmental
compliance strategies and resource
cost-effectiveness. The varying implica-
tions for demand-side management,
supply-side efficiency improvements.
and renewable energy technologies are
addressed.
The essentials of quantifying
Clean Air Act benefits are presented
through examples and step-by-step
work sheets. The examples are based
upon real data from utilities with differ-
ing Clean Air Act compliance needs.
The data requirements and calculation
methodologies are illustrated through
these examples.
The handbook is organized into
five parts. Part I provides an overview of
Title 1V and tradeable emission allow-
ances. Part II describes each of the
three incentives for energy efficiency
and renewable energy in detail. Part III
explains the impact of the incentives on
SO 2 compliance strategies. Part IV
explains the impact of the incentives on
other applications affecting energy effi-
ciency and renewable energy, including
program design and screening, bidding,
and dispatch. Part V applies these
methodologies to pollutants other than
SO 2 .

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INTRODUCTION 3
Handbook Goals
This handbook will assist in tin-
derstanding the relationship between
the Clean Air Act and the cost-effective-
ness of energy efficiency and renewable
energy. A number of groups will find
this information pertinent, including:
Utility regulators;
Utility environmental compliance
planners;
Utility resource planners:
Energy efficiency manufacturers
and service providers;
Renewable energy manufacturers
and developers:
Consultants;
Environmental organizations; and
Through the market-based allow-
ance trading system of the Clean Air
Act, reductions in SO 2 emissions have a
real value to electric utilities. Allowance
trading provides the incentive for utili-
ties to pursue energy efficiency and
renewable energy technologies, and to
minimize costs by doing so.
The extent to which the Clean Air
Act incentives affect the financial out-
look of energy efficiency arid renewable
energy will depend upon each utility’s
own circumstances. However, all utili-
ties should seriously consider these
opportunities. The real, quantifiable
value of the Clean Air Act incentives can
be key to maximizing a utility’s overall
cost-effectiveness in serving its custom-
ers and protecting the environment.
Consumer advocacy groups.

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Part
I
The Acid Rain Program
Using market-based mechanisms to achieve
environmental goals is becoming increasingly common.
The market trading of SO 2 emission allowances, as
provided by the Clean Air Act, serves to benefit energy
efficiency and renewable energy.

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6 1 OVERvIEW OF THE ACID RAIN PROGRAM
A. Overview of the Acid
Rain Program
Through Title I V of the Clean Air
Act Amendments, Congress established
the Acid Rain Program. The program
seeks to significantly reduce emissions of
SO 2 and NOR, the primary causes of acid
rain. To achieve this goal at the lowest
cost to society, the program employs an
innovative market-based approach for
controlling emissions. In addition, the
program encourages pollution prevention
through efficiency and renewable energy.
Title IV sets as its primary goal the
reduction of armual SO 2 emissions by 10
million tons below the 1980 level. These
reductions will be achieved over two
phases. Phase I begins in 1995 and
affects 110 mostly coal-burning electric
utility plants located in 21 eastern and
midwestern states. Phase II, which be-
girls in the year 2000, tightens the Phase
I limits and expands the scope of the
program to include most electric utility
plants over 25 MW.
The Acid Rain Program creates a
new tradeable commodity, the SO 2
emission allowance. Each allowance
represents an authorization to emit one
ton of SO 2 (i.e., a unit that emits 5,000
tons of SO 2 must hold at least 5,000
allowances that are usable that year).
Each affected source is allocated a spe-
cific number of allowances for Phase I
arid Phase II based on past emissions
rates and utilization. 2 Once allocated,
allowances may be bought, sold, traded,
or banked for use in future years. At the
end of each compliance year, a utility
must retire one allowance for each ton of
SO 2 emitted in the preceding year. Hold-
ing an insufficient amount of allowances
can result in a $2,000 per ton fee for
non-compliance.
The tradeable allowance system
will help utilities achieve SO 2 reductions
at the lowest possible cost by allowing the
utilities to choose the most cost-effective
compliance strategy. Compliance strat-
egies can include purchasing allowances
from other utilities, switching to lower-
sulfur fuels, installing scrubbers, and/or
implementing efficiency and renewable
energy resources. The utility decides
which compliance strategies best meets
its needs.
Energy efficiency measures and
renewable energy generation can be an
important part of a compliance plan for
several reasons. Efficiency and renew-
able energy resources not only create
allowances for the utility through the
Conservation and Renewable Energy
Reserve, but they also avoid emissions for
which the utility would otherwise need to
surrender allowances.
The following table defines some
terms commonly used to evaluate the role
of efficiency and renewable energy in
meeting Title IV requirements.
This part discusses the following topics:
A. Overview of EPA’s Acid Rain Program
B. The Allowance Trading Market
C. Environmental Benefits

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PART I: THE ACID RAIN PROGRAM 17
B. The Allowance
Trading Market
I. Overview
A key factor in evaluating the im-
pact of the Clean Air Act incentives will
be the market price of an emission al-
lowance. The allowance price will deter-
mine the degree to which efficiency and
renewable energy resources add value to
the utility.
The allowance price is of impor-
tance to utilities in a variety of compli-
ance situations. For utilities that are
still in the process of formulating com-
pliance strategies, allowance price as-
sumptions are critical to determining
the relative cost-effectiveness of each
compliance option. The cost-effective-
ness of efficiency and renewable energy
versus the other options will vary de-
pending upon the market price. For
utilities already holding excess allow-
ances due to other compliance actions,
the allowance price will indicate the
additional revenue that may be gained
from efficiency and renewable energy.
For utilities considering purchasing
allowances as a compliance strategy, the
market price will directly determine
compliance costs.
2. Market Estimates
Each year EPA holds an auction
and direct sale of a small portion of
allowances (2.8 percent) reserved from
the total allowance allocation. The auc-
tions are intended to help signal price
SO 2 Allowance Terminology
Earned Allowance:
Allowance gained by utility through the Conservation and Renewable Energy
Reserve.
Saved Allowance:
Allowance that utility is not required to surrender to EPA, due to avoiding the
emission of one ton of SO 2 at an affected unit. Avoided emissions and Reduced
Utilization result in saved allowances.
Allowance Balance:
Cumulative balance of allowances in a utility’s allowance account, which can
be thought of as a savings account. Positive annual balances will be added
(deposited) to the account; negative annual balances will be subtracted
(withdrawn). Also called allowance reserve margin.
Banked Allowances:
Unsurrendered and unsold allowances held by a utility in excess of compliance
requirements.

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THE ALLOWANCE TRADI
information to the market early in the
program and to provide a public source
of allowances for new utilities that are
not allocated allowances. Utilities, envi-
ronmental groups, allowance brokers
can participate in the EPA auctions.
The initial auctions are being adminis-
tered by the Chicago Board of Trade.
The 1993 EPA auction yielded the
first recorded values for the allowances.
Prices for allowances for use beginning
in 1995 ranged from $131 to $450 with
an average of $156 per allowance. Pric-
es for allowances for use beginning in
2000 ranged from $122 to $310 with an
average of $136 per allowance.
However, these initial results may
not represent actual market values.
First, EPA did not set a minimum price
on the allowances. Thus, the resulting
price did not necessarily represent the
value at which allowance holders are
willing to sell. Second, allowance trad-
ing is a relatively new instrument; mar-
ket activity and expertise in this area
will continue to evolve. Third, the auc-
tion sales were paid in 1993 dollars
while the allowances are for use starting
in 1995 and 2000. Thus, the auction
results represent the net present value
of some higher future allowance price.
Price signals are entering the
market through other means as well.
Several private trades have taken place,
although the details of these trades are
not always made public by the partici-
pants. Several brokerage firms and
trading exchanges are offering such
services as on-line trades, SO 2 futures
trading, and private auctions. Specialty
consulting firms are also offering price
information services. As actual compli-
NG MARKET
ance dates near, a more certain allow-
ance market should develop.
A recent report issued by the
Electric Power Research Institute (EPRI)
indicates that allowance prices could
rise from $250 per allowance in 1995 to
$480 per allowance in 2007. These
values are in 1992 dollars. EPRI’s pro-
jections are based upon research of
likely utility compliance actions.
Table I-i summarizes EPRI’s findings for
the expected allowance price as well as
the estimated price floor and ceiling.
3. Handbook Assumptions
Unless otherwise stated, the ex-
amples presented in this Handbook are
based upon a conservative allowance
price of $200 per allowance or the $250
EPRI estimate for 1995 allowances.
While these examples often demonstrate
the substantial financial benefits of
efficiency and renewable energy, these
benefits will be even greater at a higher
allowance price. The cost-effectiveness
of efficiency and renewable energy re-
sources will increase as the cost of emit-
ting SO 2 increases.
C. Environmental Benefits
1. The Effects of Acid Rain
Acid rain and the emissions that
cause it damage waters and forests,
endanger animal species, accelerate the
decay of buildings and monuments, and
impair public health. Acid rain has
been the primary cause of the acidifica-
tion of 1,350 streams in the Mid-Allan-
tic highlands, 90% of the streams in the
New Jersey Pine Barrens, and a large
number of lakes in the Adirondacks.
The Canadian government estimates

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PART I: THE ACID RAIN PROGRAM 9
1995
2000
2003
2007
Estimated
Floor
190
250
250
200
Expected
Price
250
340
400
480
Estimated
Ceiling
320
430
510
650
that 14,000 lakes in eastern Canada are
acidic. In many sensitive lakes and
streams acidification has completely
eradicated fish species, leaving these
water bodies barren of life. If acidic
deposition levels were to remain con-
stant over the next 50 years, the acidifi-
cation rate of lakes in the Adirondacks
is expected to rise by 50 percent or
more.
Acid rain also degrades forests,
particularly high-elevation spruce trees
that populate the Appalachian Moun-
tains, by increasing the spruce’s vulner-
ability to winter injury. This deteriora-
tion of forests affects important natural
areas such as the Shenandoah and
Great Smoky Mountain National Parks.
Furthermore, long- term contamination
of the sensitive soils is likely to have
already occurred. Acid rain moves
through soils, stripping away vital plant
nutrients through chemical reactions,
and thus poses a threat to future forest
growth.
Sulfur dioxide emissions in the
atmosphere are responsible for over
50% of the visibility reduction in the
eastern part of the United States. The
resulting haze from sulfur dioxide emis-
sions has impaired enjoyment of many
national parks across the country, in-
cluding such parks as the Grand Can-
yon and Shenandoah. Acid rain also
corrodes metals, stone, and paint re-
sulting in the deterioration of precious
cultural materials, such as statues and
monuments. Dry deposition of acidic
compounds can also dirty buildings and
other structures. The maintenance and
repair costs associated with acid rain
are extremely high. Given the large
number of buildings affected by acidic
deposition, even a small impact on
maintenance costs translates into a very
large savings to society.
Finally, recent studies have point-
ed to increased health risks from partic-
ulate matter, which includes sulfates
and other pollutants emitted during the
combustion of fossil fuels. A recent
study by Harvard University’s School of
Table I-i
Projected Allowance Pricesa
a
Source. EPRI
In 1992 dollars/ton paid in the year indicated. The expected price is a market clearing price
that assumes the continued operation of most fossil fuel units.

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10 ENVIRONMENTAL BENEFITS
Public Health linked these emissions to
higher mortality rates. Preliminary
results of another Harvard University
study of 24 North American cities
showed a strong statistical association
between decreased lung function in
children and long-term exposures to
ambient acidic aerosols. EPA is in the
process of evaluating the need for tight-
er regulations on emissions of particu-
late matter.
Based on concerns about the
\rariolis effects of acid rain on humans.
animals and the environment, Congress
mandated aggressive SO 2 reductions
under the Clean Air Act Amendments.
The Acid Rain Program promises to
confer great benefits on human health
and the environment. The 10 million-
ton reduction in SO 2 emissions should
significantly decrease acidification of
water bodies and forest soils and allow
many of these systems time to recover.
Visibility is expected to increase by 30%
or more in the eastern United States,
and the lifespans of buildings and mon-
uments should improve. Finally, the
SO 2 reductions will make the air health-
ier to breathe.
2. Environmental Benefits
from the Clean Air Act
Incentives
Energy efficiency and renewable
energy can play a crucial role in SO 2
emissions reductions. Pollution preven-
tion through efficiency and renewable
energy helps combat not only acid rain,
but other environmental harms as well,
including global warming and urban
smog. In addition to SO 2 , efficiency and
renewable energy resoi irces help prevent
emissions of CO 2 , NOR, toxics, and
particulates. These resources also avoid
the production of ash and scrubber
sludge.
The environmental benefits from
just one of the Title l v incentives, the
Conservation and Renewable Energy
Reserve, are substantial. The 300,000
allowances in the Reserve represent a
conversion of 150 billion kWh to effi-
ciency or renewable energy. The follow-
ing graphic illustrates the net pollution
displaced by the implementation of the
Reserve.
Photo courtesy of U.S. flepL of Intenor
Implementation of the Reserve displaces:
885 Million
lbs of SO,
825 Million
lbs of NO,
225 Billion
lbs of CO 2
Based upon national average emissions rates for each pollutant

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PART I: THE ACID RAIN PROGRAM 11
The CO 2 reductions from the Re-
serve are equivalent to taking 21 million
cars off the road each year or the plant-
ing of 43.5 million acres of trees. These
reductions are based upon national
averages for each pollutant’s emissions
rate. 4 The actual amount of emissions
offset will depend upon each utility’s
marginal rate of emissions.
The emissions offset in the illus-
tration above is only a small portion of
the total emissions avoided by the Title
TV incentives. The environmental bene-
fits of efficiency and renewable energy
persist as long as these resources func-
tion. Through the use of efficiency and
renewable energy resources, electric
utilities are able to demonstrate concern
for the environment and project a posi-
tive image to the community at large.

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Part II
The Incentives:
Clean Air Act Opportunities
The number of allowances that can be gained from
avoided emissions, the Reserve, and Reduced Utilization
will vary with each utility’s unique circumstances.
However, each utility should calculate the value the
Clean Air Act incentives add to efficiency and renewable
energy resources.
Photo courtesy of Ed Linton

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14 AVOIDED EMISSIONS
A. Avoided Emissions
1. Overview
Each time a utility emits a ton of
SO 2 , the utility has expended an emis-
sion allowance. Given the market value
of each emission allowance, the utility
has thus also expended a financial re-
source. Simply avoiding the emission of
SO 2 through efficiency and renewable
energy is perhaps the most lucrative of
the Title IV incentives.
Each ton of SO 2 avoided through
the use of energy efficiency and renew-
able energy means one less allowance
must be surrendered to comply with
Title IV. Both demand-side and supply-
side efficiency programs will create val-
ue for the utility through avoided emis-
sions. Any energy generation type that
reduces SO 2 emissions will likewise
support avoided emissions. The avoided
transmission and distribution losses
associated with an efficiency and/or
renewable energy program will also
benefit the utility.
The result is an allowance that
can be used for current compliance.
“banked” for future use, or sold. The
utility saves these allowances at the
average emission rate of the utility’s
units affected by Title IV. For utilities
currently emitting high rates of SO 2 ,
avoided emissions can thus be particu-
larly valuable.
This part describes the three Clean Air Act incen-
tives to encourage energy efficiency and renew-
able energy; data needs are identified and work
sheets are provided to help the analyst determine
each incentive s added value. The three incen-
tives from Title IV of the Clean Air Act are:
A. Avoided Emissions
B. Conservation and Renewable Energy
Reserve
C. Reduced Utilization
Each ton of SO 2 avoided...
Offset /
Generation
“/l\”
Increases revenues

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PART II: THE INCENTIVES 15
2. Eligibility
Avoided emissions are relevant
during both Phase I and Phase II. To
save allowances, the avoided emissions
must occur at units affected by Title lv.
During Phase II, virtually all fossil-fu-
eled units are affected. Thus, avoided
emissions may be particularly beneficial
after Phase II begins on January 1,
2000.
3. Verification/Application
Procedures
Avoiding emissions through effi-
ciency and renewable energy is the sim-
plest of the incentives to implement.
The utility achieves the benefits of
avoided emissions automatically. No
forms or applications need to be submit-
ted to EPA or any other governmental
entity. No verification is required to
prove the efficiency or renewable energy
resource is in place. The lack of paper-
work further enhances the cost-effec-
tiveness of this incentive. The indirect
and overhead costs normally associated
with regulatory requirements are avoid-
ed.
The benefits from avoided emis-
sions reach far beyond Clean Air Act
compliance. For utilities that are al-
ready in compliance, the extra allowanc-
es can be sold to further lower overall
costs. Thus, avoided emissions are an
easy way to not only save a substantial
number allowances but to minimize
utility costs as well.
4. Evaluating the Impact of
Avoided Emissions
To understand the potential im-
pact of avoided emissions the utility
should model its system with and with-
out the efficiency and renewable energy
programs in place. “Production-simula-
tion’ t models are useful for this purpose.
Production-simulation models simulate
system operation to determine energy
production costs, dispatch order, gener-
ation and total emissions. Different
system specifications are modeled and
compared to yield estimates of avoided
emissions.
Examples of commercially avail-
able production-simulation models in-
clude ENPRO© and PROMOD©. Appen-
dix A includes information on the neces-
sary input data and procedures for
using a production-simulation model.
The following work sheet leads
the analyst through the steps needed to
assess the value of avoiding SO 2 emis-
sions through efficiency and renewable
energy. Complete the following steps for
each year the utility has units affected
by Title IV. Phase I units are affected
from January 1, 1995 forward. Phase II
units, which include most fossil-fired
units, are affected from January 1, 2000
forward.

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STEP 1:
JAVOIDED EMISSIONS
Work Sheet No. 1
Evaluating the Impact of Avoided Emissions
STEP 2:
Identify planned or potential efficiency and renew-
able energy programs and quantify program ef-
fects on peak demand (MW) and energy (MWh).
Tons
STEP 3:
Run production-simulation model with and without
the efficiency and/or renewable energy programs in
place. Determine the level of SO 2 emissions for each
scenario.
2a. Estimated tons of SO 2 without efficien-
cy/renewable program(s)
2b. Estimated tons of SO 2 with efficien-
cy/renewable program(s)
The model will also allow determination of produc-
tion costs, total and unit-by-unit generation levels
(MWh). and peak demand (MW). These data are
useful to ensure that the outputs are reasonable
and to assist the analyst in understanding model
runs.
STEP 4:
Determine the avoided emissions due to the effi-
ciency and renewable energy programs. Subtract
the result in 2b from the result in 2a. This difference
in tons represents the allowances saved by avoid-
ed emissions.
Multiply the number of allowances saved in step 3
by the market value for emission allowances. This
result is the value added by the avoided emissions
incentive.
Allowances
k
Tons
Tons

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PART II: THE INCENTIVES 17
B. Conservation and
Renewable Energy
Reserve
1. Overview
The Reserve is a special bonus
pooi of 300,000 allowances that Con-
gress set aside to award utilities under-
taking new initiatives in efficiency and
renewable energy. For every 500 MWh
of energy saved through demand-side
efficiency or generated through renew-
able energy, a utility earns one allow-
ance from the Reserve. Reserve allow-
ances may be used for current compli-
ance, banked for future use, or sold.
A utility can apply for Reserve
allowances for efficiency measures and
renewable energy generation brought
into operation on or after January 1,
1992. Energy efficiency measures may
be installed under a program that exist-
ed before January 1, 1992 as long as
the measures themselves were installed
after this date. Efficiency programs are
restricted to demand-side programs
only; supply-side efficiency measures
cannot be claimed for Reserve credit.
Renewable energy programs qualifying
for the Reserve include biomass, geo-
thermal. solar, and wind energy re-
sources. Transmission and distribution
losses avoided by the programs may
also be credited with Reserve allowanc-
es.
The Reserve is an incentive for
utilities to set up efficiency measures
and renewable generation years before
compliance deadlines. Phase I utilities
may earn Reserve allowances from Jan-
uary 1, 1992 until these utilities enter
the Acid Rain Program on January 1,
1995. Phase II utilities may earn Re-
serve allowances from January 1, 1992
until these utilities enter the Acid Rain
Program on January 1, 2000. Thus, the
Reserve encourages utilities to get a
head start on meeting the Acid Rain
Program’s emissions standards.
2. Eligibility Requirements
To qualify for the Reserve the
applicant must meet the following re-
quirements (also see 40 CFR 73.81 and
73.82):
/ Applicant must sell electricity
(utility or independent power
producer).
/ Applicant or applicant’s holding
company must own or operate. in
whole or in part, a Phase I or
Phase H unit.
/ Applicant must be subject to a
least cost plan or planning pro-
cess that is approved or accepted
by the applicant’s ratemaking
entity. The least cost plan or
planning process must meet the
following requirements: (1) public
participation; (2) evaluation of a
full range of resource options: (3)
treatment of supply-side and
demand-side resources on a con-
sistent and integrated basis; (4)
accounting for system operation
and risk factors; and (5) imple-
mentation of least-cost resources.
/ Investor-owned utilities applying
for credit from efficiency pro-
grams must be subject to a rate
making process that provides for
net income neutrality. This
means the utility’s rate making

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_! J CONSERVATION AND
entity adjusts the utility’s electric
rate for lost sales due to the effi-
ciency program. Applications for
net income neutrality must be
certified by the Department of
Energy.
3. Verification
To receive the Reserve allowances,
the applicant must be able to verii r to
EPA that the efficiency savings or re-
newable energy generation did occur.
Renewable energy generation is verified
simply by submitting plant records of
net energy generation.
For demand-side efficiency pro-
grams, utilities follow one of two verifi-
cation paths. If a utility is state-rate
regulated and the rate making entity
uses a performance-based rate adjust-
ment, then the utility submits verifica-
tion to the state for approval. Otherwise
the utility must submit verification to
EPA and is encouraged to use EPA’s
Conservation Venfication Protocols 5 as a
guide to good and accurate verification.
Instructions and forms for these Proto-
cols are found in the User’s Guide to the
Conservation Venfication Protocols. 6
4. Application Procedures
Figure Il-i outlines the Reserve
application procedures. To apply for
Reserve allowances, the applicant must
submit a “Conservation/Renewable
Energy Reserve” form to EPA. This
application is a simple two page form. A
copy of this form is included in Appen-
dix B, along with the relevant instruc-
tions.
If the applicant is applying for
allowances based upon an efficiency
RENEWABLE ENERGY RESERVE
program and is an investor-owned utili-
ty, the utility must also be certified for
“net-income neutrality” by the Depart-
ment of Energy. 7
5. Evaluating the Impact of
the Reserve
Estimating the impact of the Re-
serve allowances is a simple process.
The rate at which the allowances are
earned is fixed at one allowance for
every 500 MWh of qualified efficiency
savings or renewable energy generation.
The primary data needs to estimate the
Reserve’s impact are:
J The amount of savings from qual-
ified demand-side efficiency mea-
sures and the amount of genera-
tion from qualified renewable
energy programs; and
The market value for an SO 2
emission allowance.
In addition to determining the
value of planned efficiency and renew-
able energy programs, the analyst
should also examine the impact of ex-
panded efforts. The added value given
by the Reserve may mean a more ag-
gressive program is the most cost-effec-
tive. The Reserve allowances may also
change the timing of such programs.
The following work sheet leads
the analyst through the steps necessary
to assess the value of the Reserve allow-
ances. Complete the following steps for
each year the utility is eligible for the
Reserve. Phase I utilities are eligible
from January 1, 1992 until January 1,
1995. Phase II utilities are eligible from
January 1, 1992 until January 1, 2000.

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PART II: THE INCENTIVES
Figure 11-1
Reserve Application Procedures
1.
Utility
Complete verification documenta-
tion
Apply for net income neutrality with
DOE (only if investor-owned)
Complete Reserve application
II
2.
Ratemaking Entity
Reviews/certifies Reserve application
D Certifies verification documentation
(only if you are state rate-regulated
with performance-based rate adjust-
ments)
U
3. EPA
Certifies verification documentation
(only if ratemaking entity does not)
Li Approves/disapproves Reserve
application
See 40 CFR 73.82(c)

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20 CONSERVATION AND RENEWABLE ENERGY RESERVE
UTILITY PROFILE
City of Austin, Texas
The City of Austin is one of a growing number of municipalities where the generation
and conservation of Electrical Energy are managed by separate departments within municipal
government. The Electric Utility Department provides Generation and billing services, while the
Environmental and Conservation Services Department (ECSD) provides Conservation and
Energy Services to the citizens of Austin.
The Environmental and Conservation Services Department provides 14 individual
programs to commercial and residential customers, and has provided the Electric Utility
Department with more than 200 MW of generation capacity deferred since 1982. This
represents a reduction of 11% in system capacity requirements.
ESCD’s programs are designed primarily to promote maximum efficiency in Austin’s
energy and environmental resources. Current programs include: residential loan and rebate
programs, the “Energy Star” and “Green Builder new home rating programs, commercial and
municipal energy programs, multi-family programs, a home weatherization program for low-
income, elderly and disabled customers, and an air conditioning rebate program. ECSD is
considering refrigerator disposal, residential lighting, and commercial duct repair programs.
The current Demand-Side Management Program forecast for the City of Austin estimates a
savings of 270 MW and 1267 GWh during the ned Iwenty years (capacity savings include a
system reserve margin of 20%).
As a result of current programs, the City is forecasting substantial emission reductions.
ECSD has developed a sophisticated model based on the EPA’s ISCLT model which predicts
the dispersion, fall, absorption, and decomposition rates of several pollutants. Analyses with
this model indicate that at the current level of commitment to DSM. the City will reduce the
emission of CO 2 by 27,000 tons, SO 2 by 20 tons, Nox by 54 tons, CO by 13 tons, and Total
Suspended Parficulates by 2 tons (all values are yearly incremental savings). Environmental
benefits computed by the model are monetized at the local, long-range and global levels,
with savings of at least 520.5M for each 510M invested in conservation.
ECSD also counts economic impacts due to DSM in its cost-effectiveness criteria. As a
result, a projected investment (by the City) of $1 OM per year will generate a net economic
benefit of $3. 7M per year and the creation of 137 jobs.
The Electric Utility Department has made a signiticant investment in renewable energy
resources, particularly solar voltaic systems. One such project is the 300 KW (alternating
current) generating facility at the Decker Power Plant. Analysis of the first year’s operation
determined that reliability exceeded 99%, a yearly capacity factor of 22%, but a summer on-
peak capacity factor of 55%. The yearly cost savings attributed to fuel were $7800, which

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r ici II: IH INC N1IVES I 1
translates to SO.02 per kWh. The plant,
dedicated on December 5. 1988 has
been operating at or near design con-
ditions since that date.
Based on the sustainable DSM pro-
grams which were implemented in 1992,
the City of Austin received 18 SO 2 emis-
sion allowances from the Conservation
and Renewable Energy Reserve. Austin
was the first municipal utility to receive
Reserve allowances from the EPA.
Austin Photovottaic System

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STEP 1:
STEP 2:
22 CONSERVATION AND RENEWABLE ENERGY RESERVE
Work Sheet No. 2
Evaluating the Impact of the Reserve
Determine if the applicant qualifies for Reserve allowances.
Note the eligibility requirements listed above (or see 40 CFR
73.81 and 73.82), If the applicant and its programs qualify.
proceed to step 2.
STEP 3:
Determine the total amount of system-wide savings
(MWh) from qualified demand-side efficiency programs
and the total generation (MWh) from qualified renewable
energy generation. Add these two values together.
Note That the demand-side efficiency measures and renew-
able energy generation must have become operational on
or after January 1, 1992 to qualify, and must be verified.
MWh
STEP 4:
Divide the result in step 2 by 500 MWh/allowance. This
result is the number of allowances to be received from
the Reserve.
Multiply the number of Reserve allowances earned in step
3 by the market value for emission allowances. This result
is the value added by demand-side efficiency measures
and renewable energy generation from the Reserve.
Repeat steps 1 - 4 for each year the applicant is eligible for
the Reserve.
Allowances
$

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C. Reduced Utilization 8
PART II: THE INCENTIVES 23
1. Overview
The Reduced Utilization provision
prevents anticipated Phase I emission
reductions from being eroded if genera-
tion is shifted away from a Phase I plant
to unaffected SO 2 emitting facilities.
Such load shifting would result in in-
creased emissions at Phase II plants or
unregulated sources.
The Reduced Utilization provision
requires utilities either to specify the
unit or units which will provide the
compensating generation (and make
them affected Phase I units) or to sur-
render allowances for shifting genera-
tion below its Phase I units’ 1985-87
baseline. The allowances are surren-
dered at the average emission rate of the
system’s Phase II units. 9
However, the provision also al-
lows energy effIciency and renewable
energy to offset these shifts and thus
avoid the loss of allowances. To avoid
surrendering allowances, the utility
may:
1. Shift to a sulfur-free genera-
tor; 10
2. Offset with demand-side efficiency
measures; or
3. Offset with supply-side efficiency
measures.
Efficiency and renewable energy
resources permit utilities to reduce the
usage of Phase I plants without the
requirement to designate a compensat-
ing unit or to give up additional allow-
nee.s -
A further advantage of using effi-
ciency or renewable energy in Reduced
Utilization is the flexibility of where the
measure or generation occurs. Offset-
ting energy efficiency measures may
come from anywhere within the utility
system. Offsetting renewable energy
generation may even be purchased from
outside of the utility system. Thus, a
Phase I unit may be credited with the
savings or generation from a source far
from the unit itself.
2. Eligibility Requirements
The Reduced Utilization provision
is applicable only to electric utilities
with Phase I-affected units. Unlike the
Conservation and Renewable Energy Re-
serve, utilities may use both demand-
side measures and supply-side (i.e.,
power generation, transmission. or dis-
tribution) efficiency measures. Utilities
Reduced Utilization provision prevents utilities from
shifting generation bdow the system’s Phase I baseline.
Generation
Shift - - -
t i n 1 __
Phase I Unit Non-Phase I Units
Unless load shifts are offset by efficiency or renewable
energy.

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241 REDUCED UTILIZATION
may receive credit for efficiency mea-
sures installed as early as January 1,
1988, as long as the utility verifies that
the savings persist during the period of
1995- 1999.
3. Verification
Annual verification of energy sav-
ings or renewable energy generation is
required to receive credit under the
Reduced Utilization provision. The
renewable energy generation may be
verified with plant records of net energy
generation. Demand-side and supply-
side energy efficiency measures may be
verified by following appropriate verifica-
tion procedures. These verification
procedures may be those prescribed by
the utility’s ratemaking entity or the
procedures outlined in EPA’s Conserva-
tion Verification Protocols. 1
4. Application Procedures
A Reduced Utilization plan must
be filed with EPA by November 1 of the
year in which reduced utilization oc-
curs. An initial estimate of energy con-
servation savings must be filed in the
annual compliance certification report
by March 1 of the following year. The
unit’s designated representative must
submit the verification results as part of
a confirmation report by July 1 of each
year.
Thus, the first possible verifica-
tions would take place in the first six
months of 1996 for energy savings that
occur in 1995, following submittal of a
Reduced Utilization plan by November
1995. The EPA Administrator may
grant, however, for good cause shown,
an extension of the time to file the con-
firmation report.
Unlike the Reserve program, a
utility using the Reduced Utilization
provision does not have to meet the
least-cost planning or net income neu-
trality requirements. Since the utility is
saving its own allowances, the utility is
not limited to the amount of efficiency
savings or renewable energy generation
for which it may receive credit.
5. Evaluating the Impact of
Reduced Utilization
The following work sheet leads
the analyst through the steps necessary
to assess the value of efficiency and
renewable energy from the Reduced
Utilization provision. This work sheet
provides only an estimate; the actual
value is determined retrospectively by
the procedures in 40 CFR 72.91 and
72.92. The primary data needs to eval-
uate the impact of the Reduced Utiliza-
tion provision are:
J Average baseline heat input
(rnmBtu) from 1985-87 for all
Phase I units.
J Heat rates (fuel input/generation
output in Btu/kWh) for all Phase
I units.
System average SO 2 emission rate
of all Phase II units.
J Average SO 2 emission rate of all
off-system purchases.
MWh savings from qualified ener-
gy efficiency or MWh generation
from renewable energy sources in
each year of Phase I. Measures
must have been installed on or
after January 1, 1988.
J Market price of allowances.

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PART II: THE INCENTIVES
Work Sheet No. 3
Evaluating the Impact of Reduced Utilization
Potential Number of Allowances Surrendered
STEP 1:
STEP 2:
Determine if the utility system’s aggregated Phase I units
are expected to operate below their 1985-87 baseline,
and, if so, how far below (mmBtu) 12 If the Phase I units
are not expected to operate below baseline, Reduced
Utilization does not apply. If the Phase I units are expected to operate below
baseline in any year, continue to step 2.
mmBtu
STEP 3:
Determine the utility’s average emission rate for electricity
not generated at Phase I units (lbs of S0 2 /mmBtu). For
the portion of non-Phase I generation from within the
utility’s system. determine the average emission rate for
the system’s Phase Il units. For the portion of non-Phase I generation from
outside of the utility’s system, find the average emission rate for the utility’s
NERO region (listed in 40 CFR Part 72.92). Calculate the weighted-average
emission rate from these two values.
lbs/mmBtu
Determine the potential number of allowances to be surrendered due to
reduced utilization by multiplying the result from step 1 by
the result from step 2. Divide result by 2000 to convert
pounds of SO 2 to tons. The tons of SO 2 represent the
number of allowances the utility would surrender without
energy efficiency and/or sulfur-free generation.
Allowances
Potential Number of Allowances Saved by Energy Efficiency and
Sulfur-Free Generation
STEP 4:
Determine the total amount of system-wide savings (kWh)
cy and the total system-wide generation (kWh) from
sulfur-free sources. Add these two values together. Note
that the energy efficiency measure(s) must have become
operational after December 31, 1987 to qualify, and must
be verified.
from energy efficien-
kWh
(continued on next page)

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STEP 5:
26 REDUCED UTILIZATION
Work Sheet No. 3 (cont’d)
Evaluating the Impact of Reduced Utilization
STEP 6:
STEP 7:
Determine the weighted-average heat rate (Btu/kWh) for
the Phase I unit(s) that have been operated below the
1985-87 baseline. 13 The weighting is based upon the
percentage each unit is below the baseline.
Converl the total kWhs in step 4 to an equivalent heat
value (Btu) by multiplying the result from step 4 by the
result from step 5. Divide the result by 1 6 to convert Btu
to mmBtu.
Determine the potential number of allowances saved by
energy efficiency and sulfur-free generation by multiply-
ing the result from step 6 by the result from step 2. Divide
result by 2000 to convert pounds of SO 2 to tons. The tons
of SO 2 represent the potential number of allowances saved.
Value Added by Energy Efficiency and Sulfur-Free
Generation
STEP 8:
STEP 9:
Apply the allowances saved in step 7 toward offsethng
the allowances surrendered in step 3. Apply these allow-
ances until all the surrendered allowances in step 3 are
offset or the available allowances in step 7 are used up.
Multiply the number of allowances offset in step 8 by the
market value for emission allowances. This result is the
value added by energy efficiency and sulfur-free genera-
tion from the Reduced Utilization provision. Repeat steps
1 - 9 for each year 1995 through 1999.
Btu/kWh
mmBtu
Allowances
Allowances
$

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PART II: THE INCENTIVES
Basics of the Clean Air Act Incentives for
Energy Efficiency and Renewable Energy
Avoided
Reserve
Reduced
Emissions
Allowances
Utilization
Who May Apply? Anyone Can Owner/Operator of Owner/Operator
Benefit; Any Affected of Phase I
No Application Utility or IPP Affected Units
Utilities Must Have a No Yes No
Least-Cost Plan and
Net Income Neutrality?
What Type of Demand-and Demand-Side Demand-and
Measures? Supply-Side Efficiency; Supply-Side
Efficiency; Renewable Energy Efficiency;
Renewable Energy Renewable Energy
At What Rate are Utility’s Own Rate 500 MWh = 1 Average emission
Allowances of Emissions Allowance rate of the system’s
Earned/Saved? Phase II units
How Many Allowances No limit 300,000 Total No Limit
Are Available?
When Are Utilities
Eligible?
Phase I From 1995 on From 1992 until 1995 From 1992 until 2000
Phase II From 2000 on From 1992 until 2000 Not eligible

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Timeline for the Incentives
January 1, 1995
January 1, 1992 (Phase I Begins)
January 1, 2000
(Phase II Begins)
Conservation and Re-
newable Energy
Reserve begins
Avoided emissions
incentive begins for
Phase I utilities
1 Avoided emissions
available to all
affected utilities
Reserve no longer
available to Phase I
utilities
Reduced utilization
provision begins
L Reserve no longer
available to Phase Il
utilities
E J Reduced utilization
provision ends
m
C
C)
rn
C
-4
I-
-4
0
z
1992 I 1993 [ 1994 I
19951
1996 I 11997 I [ 1998 I I 1999 I
2000 I ••

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Part III
Efficiency and Renewable Energy in
SO 2 Compliance Strategies
To meet SO 2 emission requirements of Title 1V electric
utilities may choose from a range of compliance options.
Efficiency arid renewable energy can be a cost-effective
component to an integrated compliance strategy.
Photo courtesy of Kramer Junction Company

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30 SO 2 EMISSIONS AND RESOURCE TYPE
The market-based nature of Title
IV of the Clean Air Act gives utilities a
range of options for meeting compliance
needs. Efficiency and renewable energy
can play a significant role in this pro-
cess by:
J Complementing or offsetting the
use of other compliance strategies
such as fuel-switching,
Delaying the use of expensive
alternative strategies such as
scrubbing,
J Helping to avoid penalties asso-
ciated with noncompliance, and
Increasing revenues through the
sale of extra allowances.
As the examples below illustrate,
the potential usefulness of the three
Clean Air Act incentives varies depend-
ing on each utility’s own unique circum-
stances. The existing plant mix, emis-
sions levels, and operating costs all
affect the financial impact of the incen-
tives. This chapter discusses and illus-
trates the application of the three Clean
Air Act incentives to encourage the use
of efficiency and renewable energy. 14
A. SO 2 Emissions and
Resource Type
Specific efficiency and renewable
energy technologies differ in terms of
resource availability and the type and
amount of pollutants being offset. The
level of emissions that can be avoided
will also differ by utility. Each existing
fossil fuel plant will have different emis-
sions characteristics. In the case of
load management programs, the
amount of emissions avoided also de-
pends upon the characteristics of the
plants to which generation is trans-
ferred.
Efficiency and renewable energy
technologies generally fall into three
load-type categories: base-load, inter-
mediate-load, and load management.
This part discusses the how the three incentives
affect SO 2 compliance strategies.
A. SO 2 Emissions and Resource Type
B. Avoided Emissions
C. Conservation and Renewable Energy
Reserve
D. Reduced Utilization

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PART Ill: EFFICIENCY AND RENEWABLE ENERGY IN 31
so 2 CO M P11 A N CE STRATEGIES
1. Base-Load Generation
Base-load technologies or pro-
grams reduce demand during both on-
and off-peak periods. rpical demand-
side base-load technologies include
refrigeration, water heating and exit
lights. Supply-side base-load efficiency
technologies include amorphous core
transformers and base-load power plant
efficiency improvement programs. Geo-
thermal resources and biomass-flred
steam generation are examples of re-
newable energy technologies that can
operate as base-load units.
The emissions avoided due to
base-load technologies are those emis-
sions associated with the generation
that is on the margin at any given time
throughout the day when the technology
is operating. The generation unit on the
margin depends on the utility’s specific
plant mix. During off-peak periods, the
emissions that will be avoided due to
the efficiency or renewable energy tech-
nologies are likely to be those of the
base-load plants.
2. Intermediate-Load
Generation
In contrast to base-load technolo-
gies and programs, intermediate-load
technologies and programs reduce de-
mand during on-peak periods only,
when energy costs are highest. While
base-load programs are meant to reduce
demand 24 hours per day, intermediate-
load programs generally reduce demand
during an 8 to 16 hour period depend-
ing on the size and length of system
peak.
Commercial lighting programs
and air conditioning and heating pro-
grams are some examples of typical
intermediate-load demand-side pro-
grams. Wind and solar energy technolo-
gies are examples of intermediate-load
renewable resources.
Emission reductions from inter-
mediate-load units are those reductions
associated with the plants on the mar-
gin during intermediate and peak peri-
ods. Peaking plants are high-fuel, low
capital cost plants such as oil and gas-
fired combined-cycle plants or combus-
tion turbines. Such plants emit consid-
erably less SO 2 than coal-fired plants.
Thus, reduced generation at these
plants will not lower SO 2 emissions as
dramatically as reductions at coal-fired
units.
3. Load Management
Load management technologies
and programs shift demand from on-
peak periods with high energy costs, to
off-peak periods with lower costs. Un-
like base- and intermediate-load pro-
grams, which focus on reducing energy
use (MWh), load management programs
focus on shifting demand (MW). Load
management programs generally save
little energy and sometimes actually
increase energy use.
Load management programs also
can result in increased emissions (see
“Contrary Effects” box). The increased
emissions can occur when generation is
shifted from a clean peak period unit
(e.g., wind energy resource) to a higher
emitting off-peak unit (e.g., a base-load
coal-fired unit).

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EMISSIONS AND RESOURCE TYPE
Contrary Effects of Load Management Programs
Certain types of demand-side management programs, load management and off-peak
promotional programs. may actuafly result in increased emissions rather than avoided
emissions. Load management programs trim peak usage and sometimes transfer that
usage to off-peak periods, If the generation source being used at the oft-peak time
(e.g. , a coal unit without a scrubber) emits greater emissions per unit of generation than
the peaking unit, this “contrary impact” can occur. Off-peak promotional programs
virtually guarantee increased emissions since the purpose of these off-peak programs is
to increase the utilization of existing plants in an effort to minimize rates.
Parametric modeling of Utility A. the 6.000 MW mid-and high-suffur coal-using utility.
illustrates these two effects. The load management program actually results in in-
creased emissions that require the surrender of additional allowances. This utility pos-
sesses a large allowance reserve margin due to having scrubbed a large Phase I unit
and received bonus allowances through the scrubber bonus allowance lottery.
Therefore, for Utility A, the load management program represents a loss of potential
revenue from the sales of extra allowances. For a utility without an allowance reserve, a
load management program would require the purchase of additional allowances or the
use of another compliance strategy to counteract the emissions impacts of the
program.
The contrary emissions impact of this utility’s hypothetical load management program
dilutes the impact of the utility’s demand-side management programs as a whale. The
emissions avoided by the three programs in aggregate (the refrigerator, commercial
lighting, and load management program) are reduced as a result of the load manage-
ment program.
As expected, the off-peak promotion program resulted in increased emissions. By 2010,
this program required the surrender of almost 38,000 allowances more than the no DSM”
scenario. For utilities without excess allowances a promotional program could require
the purchase of additional allowances or reliance on alternative compliance strategies.

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PART III: EFFICIENCY AND RENEWABLE ENERGY IN 33
so 2 Co M P11 A N CE STRATEGIES
B. Avoided Emissions
Each ton of SO 2 avoided through
the use of efficiency and renewable
energy means one less allowance must
be surrendered to comply with the
Clean Air Act. The result is an allow-
ance that can be used for current com-
pliance, banked for future use, or sold.
As described in Part I, avoided emis-
sions is the simplest of the three incen-
tives to implement -- no reporting, ap-
plications or verification are required.
The effectiveness and simplicity of
avoided emissions makes this incentive
a potentially major contributor to a
utility’s Clean Air Act compliance strate-
gy. The actual impact of an avoided
emissions strategy depends upon the
unique character of the utility system.
Avoided emissions save the utility al-
lowances at the utility’s own rate of
emissions. Thus, utilities that currently
emit high levels of SO 2 can benefit sig-
nificantly from avoided emissions.
Depending upon the utility’s Title
IV compliance status, these avoided
emissions may complement compliance
strategies such as fuel switching, or add
to the utility revenues through the sale
of allowances. All utilities should calcu-
late the avoided emissions benefits of
efficiency and renewable energy for each
utility’s own circumstances.

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34IAVOIDED EMISSIONS
UTILITY PROFILE
Northern States Power Company
Northern States Power (NSP), headquartered in Minneapolis, Minn., is a national
leader in utilizing efficiency and renewable energy resources. As early as 1980, NSP
explored the feasibility of harnessing wind to produce electricity. Demand-side manage-
ment at NSP began with appliance rebates in 1982 and has grown steadily since then.
Wind Energy Commitment
After extensive research and analysis, NSP last year signed a power purchase
arrangement with U.S. Windpower Corporation of Oakland, Calitornia. Under terms of the
arrangement, U.S. Windpower will construct, own and operate the Buffalo Ridge
Windplant on a site owned by NSP near Lake Benton in southwestern Minnesota. The
Buffalo Ridge site provides ideal weather and geographic conditions for operating a
reliable and cost-effective wind plant.
The first stage of the wind
energy project will be a 25-
megawatt power purchase ar-
rangement. This initial commitment is
scheduled to be on-line by May 1,
1994. Additionally, NSP has commit-
ted to a total of 100 megawatts of
wind-derived energy by 1998, and
plans to use a competitive bid pro-
cess to achieve the additional 75
megawatts.
At an output of 25 megawatts, the Buffalo Ridge Windplant will generate enough
electricity to power approximately 10,000 to 15,000 homes each year. NSP and its
customvers will enjoy the benefits of avoided SO 2 emissions, and NSP could earn bonus
allowances from the Conservation and Renewable Energy Reserve. Likewise, NSP esti-
mates that for every kilowatt-hour of fossil fuel generation offset by wind energy, beiween
1-2 pounds of carbon dioxide will be kept out of the atmosphere.
N5P Test Windplant in Holland. Minnesota
(continued)

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PART III: EFFICIENCY AND RENEWABLE ENERGY IN 35
S 02 Co M Pit A N CE S TRAT E G I ES
Innovative DSM Programs
NSP has set a goal to reduce ,000 MW of system coincident demand by 1995 and
1,700 MW by 2000. By the end of 1992, NSP had reduced coincident demand by
643 MW - nearly 60 percent of the 1995 goal. The number of DSM programs has in-
creased dramatically, from 25 in 1989 to more than oO programs in 1994.
Three programs represent the core of NSP’s DSM effort: a commercial and
industrial Lighting Efficiency Program, a load control program called Saver’s SwitchSM, and
an interruptible rate program called Peak- and Energy-Controlled Rates. The Lighting
Efficiency Program achieved 20 MW of demand reduction in 1992, considerably aided by
the Energy Financing Program, which disbursed almost $5 million in low-interest loans for
energy-efficient equipment.
One of NSP’s long term goals is to increase DSM efforts by improving existing
programs and adding new programs aimed at conservation and load management. For
example, in 1993 NSP added a preventative maintenance incentive to commercial and
industrial programs for chiller, rooftop, and refrigeration efficiency. Cleaning and check-
ing this equipment on a regular basis can improve energy efficiency by 10 to 20 percent.
Also in 1993, NSP became the first US utility to offer a specific rebate program to
business customers who convert existing chillers from chlorofluorocarbon (CFC) refrigerant
to non-CFC refrigerants. Additionally, NSP is upgrading the lighting in its own facilities
through participation in EPA’s Green Lights Program.

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36 AVOIDED EMISSIONS
1. Avoided Emissions and
Demand-side Efficiency
Utilities already committed to a
compliance strategy based upon scrub-
bing or fuel switching may be sufficient-
ly placed to meet Title IV requirements.
However, avoided emissions through
efficiency and renewable energy can still
benefit the utility. The extra allowances
generated by the avoided emissions can
be sold on the allowance market and
thus increase utility revenues.
The “no DSM” case resulted in the high-
est emissions level at more than 3.5
million tons of SO 2 . Of the three indi-
vidual programs, the high efficiency
refrigerator program achieved the greatest
emission reductions. Refrigerator pro-
grains reduce generation around the
clock and thus lessen the usage of higher
emitting coal-fired units. The load man-
agement program resulted in more einis-
sions than even the “no DSM” scenario.
For an explanation of this effect, see the
“Contrary Effects box.
Given the utility’s strategy to scrub dur-
ing Phase I, implementation of the three
demand-side programs will create addi-
tional allowances that the utility may
bank or sell. The demand-side programs
will increase allowance holdings by al-
most 143,000 by 2010. The allowances
saved by the demand-side programs may
allow the utility to consider less expen-
sive compliance options for Phase II.
These options might include supply- or
demand-side efficiency programs, renew-
able energy, and/or fuel switching.
If utility A continues with plans to scrub
a unit during Phase II, the utility would
not need the allowances saved by the
demand-side programs for compliance
purposes. However, the allowances
would still have value in terms of added
revenue. For example, if the utility sold
the nearly 143,000 additional allowances
“created” by DSM at $200 each, it would
generate nearly $29,000,000 in added
revenue.
Example:
Utility with Excess Allowances
Utility A is a mid-sized (6,000 MW) utility
that relies heavily on medium- and high-
sulfur coal. The utility’s CAAA compli-
ance strategy is to scrub one plant during
Phase I and one plant during Phase H.
Consequently, this utility projects a large
allowance reserve margin during both
Phase I and Phase H.
Three typical demand-side efficiency pro-
grams are modeled: A refrigerator pro-
gram representing a base-load program, a
commercial lighting program representing
an intermediate-load program, and a
peak-load program representing load
management. Together the programs are
expected to reduce Utility A’s peak load
by five percent, an impact typical of
moderately aggressive demand-side effi-
ciency programs.
The programs are modelled
parametrically to capture interactive
effects. The steps to parametric analysis
and production-simulation modeling are
discussed further in Appendix A. The
results of the modeling effort are summa-
rized in Table 111-1.
(antthucd)

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PART Ill: EFFiCIENCY AND RENEWABLE ENERGY iN
SO 2 COMPLIANCE STRATEGIES
Table Ill-i
Emissions Impacts of DSM Programs
Cumulative SO 2
Emissions
(tons)
Emissions
Savings
Allowance
Balance
(Allowances)
‘No DSM Scenario 3,546,100 0% 1,990,700
System with Refrigerator Program 3,435,700 3% 2,101,100
System with Commercial Lighting 3,480,400 2% 2,056,500
Program
System with Load Management 3,573,900 -1% 1,963,000
Program
System with Refrigerator, 3,403,200 4% 2,133,700
Lighting, and Load Management
Programs

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38 AVOIDED EMISSIONS
The following example illustrates
how demand-side management pro-
grams can allow a utility to defer the
use of other Clean Air Act compliance
strategies.
Example:
Deferring Compliance Strategies
Utility C. a large (28,000 MW) utility for
which medium-sulfur coal is the primary
fuel, has 28 Phase I affected units, and
approximately 80 Phase LI-affected units.
The company’s Phase I compliance strat-
egy is to switch fuels at Phase I-affected
units. This strategy will reduce emis-
sions considerably below the number of
allocated allowances.
In Phase II, however, the utility’s annual
SO 2 emissions will be greater than the
annual allowance allocation. During
Phase II the utility plans to use allow-
ances banked during Phase I to remain in
compliance. Once the allowance reserve
margin is depleted, the company intends
to purchase allowances to remain in
compliance.
Two scenarios are modeled to illustrate
the effects of DSM on Utility C’s compli-
ance costs. The first scenario contains
no DSM, and the second scenario as-
sumes that the utility implements ag-
gressive demand-side programs.
The DSM programs include residential,
commercial, and industrial programs for
new and existing facilities. These pro-
grams cover a wide range of technologies,
including building envelope, heating,
ventilating, air conditioning equipment,
lighting, motors, water heating, and load
control programs. In 1993 about 80 MW
of DSM will be in place. DSM progrmns
are ramped up quickly, reaching a maxi-
mum of nearly 4,000 MW in the year
2001. From 2001 to 2010, the last year
modeled, the nearly 4,000 MW of DSM
represents approximately 14 percent of
the utility’s total system capacity.
The DSM programs affect the utility’s
emissions by varying degrees over time.
For example, in 1999, the final year of
Phase I, the demand-side efficiency pro-
grams earn approximately 20,000 allow-
ances more than the amount the utility
would have earned without DSM. During
Phase II, that amount increases to over
50,000 allowances in the year 2001.
Cumulatively, by 2007, this utility would
save over 300,000 allowances through
the DSM programs. In the absence of the
demand-side programs, the utility would
need to purchase nearly 165,000 addi-
tional allowances or change its compli-
ance strategy. Conversely, with the DSM
programs the utility would possess over
130,000 extra allowances. Thus. DSM
could defer for almost two years the need
for this utility to purchase additional al-
lowances or otherwise alter compliance
strategies.
(continued)

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PART III: EFFICIENCY AND RENEWABLE ENERGY IN 39
SO 2 COMPLIANCE STRATEG I ES
2. Avoided Emissions and
Supply-Side Efficiency
Like demand-side efficiency pro-
grams, supply-side efficiency programs
can also avoid SO 2 emissions. And like
demand-side efficiency programs, the
amount of avoided emissions will de-
pend upon the characteristics of the
specific program and the emission char-
actenstics of the plant that is being
avoided.
To calculate the avoided emis-
sions from a supply-side efficiency pro-
gram, the system with and without the
efficiency program are modeled using a
production-simulation model. in some
instances, such as boiler efficiency im-
provements, the analyst may only need
to adjust the plant heat rates assumed
in the model.
3. Avoided Emissions and
Renewable Energy
Like energy efficiency technolo-
gies, renewable energy resources vary in
the emissions avoided depending upon
the characteristics of both the technolo-
gy and the utility system. Some renew-
able energy resources, such as geother-
mal and biomass generation, can be dis-
patched in the same manner as tradi-
tional generation technologies. These
resources are likely to be operated as
base-load or intermediate-load units.
Although solar and wind energy
technologies are by nature intermittent,
the availability of these resources can
often be predicted with a high degree of
certainty. Moreover, technologies are
under development to cost-effectively
store the energy generated from inter-
and distribution losses are approximately
seven percent: transformer losses ac-
count for approximately 25 percent of the
total transmission and distribution loss-
es. The total savings potential, assuming
replacement of all transfonners. is ap-
proximately 0.6 percent of system genera-
lion.
If Utility B adopts a transformer replace-
ment program. with a target of replacing
one-fourth of all transformers by the year
2000, the utility would realize approxi-
mately 60 GWh per year in energy sav-
ings. These energy savings avoid approx-
Imately 165 tons of SO 2 per year.
Such supply-side efficiency improvements
can play an important role in a utility’s
overall energy efficiency strategy and will
yield benefits relative to Clean Air Act
compliance. The utility also benefits from
the reduced energy, transmission and
distribution costs.
Example:
Amorphous Core Transformers
Amorphous core transformers improve
efficiency by decreasing core losses.
Amorphous metal cores can reduce core
losses by 60-70 percent compared to
conventional silicon steel core transform-
ers. Since core losses constitute approxi-
mately 50 percent of the total losses from
transformers, replacement of convention-
al transformers with amorphous core
transformers can reduce total transform-
er losses by approxnnately one-third.
Amorphous core transformers increase
efficiency during all time periods and are
thus considered a base-load efficiency
option.
Assume that Utility B institutes a pro-
gram to replace conventional transform-
ers with amorphous core transformers
across its system. Total transmission
(continued)

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40 AVOIDED EMISSIONS
mittent resources. Solar and wind ener-
gy technologies are now generally con-
sidered to be intermediate-load units.
Generating electricity from sulfur-
free renewable energy technologies can
displace equivalent generation from
sulfur-emitting sources, thus avoiding
SO 2 emissions. Emissions are avoided
at the emission rate of the sulfur-emit-
ting unit, which can be significantly
higher than the rate allowances are
earned under the Reserve. Consequent-
ly, utilities that have implemented or
are planning to implement renewable
energy projects should incorporate
avoided emission benefits into compli-
ance planning.
Utilities with high-sulfur units
capable of being displaced by renewable
energy generation stand to gain the
most from renewable energy technolo-
gies. However, as the following example
shows, even utilities with low-sulfur
units can find that additional renewable
energy generation may lead to the least-
cost compliance strategy.
Utility B plans to add wind energy Ca-
pacity in several years throughout Phas-
es I and II. Specifically, the utility plans
to add 25 MW of wind energy in 1995, 25
more MW in 1997 and a final 50 MW in
2000, for a total of 100 MW installed
capacity by 2000.
Utility B has one affected Phase I unit
and 20 affected Phase II units. Well in
advance of passage of the Clean Air Act
Amendments, Utility B implemented a
S0 2 -reduction strategy that included
fuel-switching and scrubbing. Conse-
quently, all Utility B units already have
emission rates that meet Phase 11 require-
ments. By reducing SO 2 prior to imple-
mentation of Phases I and II of the Clean
Air Act, this utility will possess a large
allowance reserve margin.
The implementation of these levels of
wind energy would result in the utility’s
saving over 3,300 allowances, i.e.,
avoiding over 3,300 tons of SO 2 emis-
sions compared to a “no wind energy”
scenario by the year 2010. The avoided
emissions due to wind power generation
are not concentrated in any single unit or
units, but are distributed relatively evenly
among Utility B’s Phase II units, which
are all low-sulfur units. The 3,300 allow-
ances saved due to Utility B’s wind ener-
gy plans would be three percent of the
cumulative allowance balance for the “no
wind energy’ scenario. If retained by
Utility B, these allowances would add to
the existing allowance reserve margin. If
the additional allowances due to the
implementation of wind energy were sold
at $200 per allowance, the value of the
avoided emissions would be about
$660,000 (or $1.2 million at $350 per
allowance).
Again, these results are for a relatively
“clean” utility. If the utility had a higher
SO 2 emission rate, the benefits would be
even greater.
Example:
Wind Energy and Avoided Emissions
Utility B, a 7,000 MW utility, provides an
example of the potential effect of wind
energy on avoided emissions. Wind ener-
gy can be thought of as an intermediate-
load technology with a typical capacity
factor of approximately 0.3, depending on
the specific technology used, site charac-
teristics and wind profile.
(cxntinued)

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PART III: EFFICIENCY AND RENEWABLE ENERGY IN
SO 2 COMPLIANCE STRATEGIES
141
C. Conservation and
Renewable Energy
Reserve
The bonus allowances from the
Conservation and Renewable Energy
Reserve increase the attractiveness of
demand-side efficiency and renewable
energy resources as SO 2 compliance
strategies. Since the Reserve allowances
are earned before a utility actually en-
ters the Acid Rain Program, the Reserve
is an early way to earn a return on effi-
ciency and renewable energy invest-
ments. Once the utility enters the Acid
Rain Program, the measures or genera-
tion installed continue to benefit
through avoided emissions and/or the
Reduced Utilization provision. Thus,
each of the Title IV incentives are com-
plementary in supporting efficiency and
renewable energy as SO 2 compliance
strategies.
1. Reserve Allowances and
Earning Potential
The number of allowances a utili-
ty will earn from the Reserve depends
upon two factors: (1) the size of the
utility’s efficiency and/or renewable
energy program, and (2) the number of
years the utility is eligible. Phase I
utilities may earn Reserve allowances
for demand-side measures or renewable
generation during a three year period
from January 1, 1992 until January 1,
1995. Phase II utilities may earn Re-
serve allowances during an eight year
period from January 1, 1992 until Jan-
uary 1, 2000.
A Phase Il-affected utility that
began full-scale, aggressive conservation
and/or renewable energy programs in
1992 possesses the greatest opportunity
to benefit from the Reserve. However,
the bonus allowances from the Reserve
can affect the role of efficiency and re-
newable energy for all utilities and inde-
pendent power producers affected by
Title IV of the Clean Air Act. In many
instances the role of the Reserve allow-
ances will be to allow the sale or bank-
ing of excess allowances.
Example:
Reserve Allowances for a
Phase I Utility
Utility B, a 7.000 M\V utility, has one
affected unit in Phase I, and is therefore
only eligible to gain Reserve allowances
from 1992 until 1995. Despite being
eligible for Reserve allowances for oniy a
three-year period, Utility B has in place a
relatively aggressive package of DSM
programs as part of its base plan. As-
surning that Utility B achieves and veri-
fies the projected energy savings, and
meets net income neutrality and least-
cost planning requirements. the utility
will gain a signifIcant number of Reserve
allowances.
Table 111-2 summarizes Utility B’s poten-
tiai for gaining Reserve allowances
through DSM. Note that the DSM sav-
ings from one year continues to add to
the total of a following year. provided the
measure is still in place. Based upon
Utility B’s projected programs. the utility
will earn a total of 2,150 allowances from
the Reserve. Since Utility B is already in
compliance with both Phase I and
Phase II requirements. the utility does
not need the Reserve allowances for Title
IV compliance. At a market value of
$250 per allowance, Utility B would earn
$537,500 from the sale of the 2,150 bo-
ntis allowances ($725,500 if market price
is $350 per allowance).

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42 CONSERVATION AND RENEWABLE ENERGY RESERVE
Year
Savings (GWh)
Allowances
1992
159
318
1993
349
698
1994
567
1,134
2. Reserve Allowances and
Compliance Flexibility
The examples illustrate the bene-
fits of Reserve allowances for utilities
that will have allowances in excess of
SO 2 emissions from affected units in
Phase I and Phase II. The excess allow-
ances generated in the examples can be
sold or banked for future use. The
excess allowances give both Utility B
and Utility D an added reserve margin
for ensuring compliance with Title IV.
Reserve allowances can also in-
crease compliance flexibility and timing.
While the benefits from the Reserve
alone are not likely to completely alter
SO 2 compliance strategies, the Reserve
allowances can help delay more costly
strategies such as scrubbing.
Table 111-2
Reserve Allowances of Utility B
Total
1,075
2,150
Example:
Reserve Allowances for a Utility
With only Phase II Units
Utility D has no units affected in Phase I
and is therefore eligible to gain Reserve
allowances from 1992 until 2000. Utility
D is allocated approximately 100,000
allowances annually in Phase II, and
pians to use less than this number to
comply. Therefore, any allowances
gained through the Reserve can be either
sold or banked.
Utility D has modest plans for DSM and
expects to achieve its first savings from
energy efficiency programs in 1994. As
Table 111-3 illustrates, Utility D’s projected
programs will earn the utility 10,970
allowances through the Reserve. This
result assumes that the programs are
implemented as planned, savings are
verified and accepted as valid by EPA,
and the utility meets net income neutrali-
ty and least-cost planning requirements.
At a market value of $250 per allowance,
Utility D would earn $2,742,500 from the
sale of the 10,970 bonus allowances
($3,839,500 if market price is $350 per
allowance).

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PART IU: EFF1C ENCY AND RENEWABLE ENERGY IN
SO 2 COMPLIANCE STRATEGiES
Year
Savings (GWh)
Allowances
1992
0
0
1993
0
0
1994
114
228
1995
391
782
1996
778
1,556
1997
1,132
2,264
1998
1,413
2,826
1999
1,657
3,314
D. Reduced Utilization
The Reduced Utilization provision
allows utilities to reduce operation of
affected units during Phase I as a
means of compliance. However, to pre-
vent utilities from circumventing Phase I
requirements by shifting generation
from affected units to non-affected
units, utilities that reduce utilization
below their 1985-87 baselines must
identif y a compensating unit or surren-
der allowances unless one of the follow-
ing compensating actions are taken:
1. Shift to a suiftir-free generator;
2. Offset with demand-side efficiency
measures; or
3. Offset with supply-side efficiency
measures.
The Reduced Utilization provision is
only invoked if a unit’s generation drops
below its 1985-87 baseline and is only
applicable to electric utilities with units
affected by Title IV during Phase I.
1. Reduced Utilization and
Phase I Compliance
Reduced Utilization achieved
through demand-side efficiency, supply-
side efficiency, or sulfur-free renewable
energy is a potential strategy for meet-
ing Phase I compliance requirements.
The avoidance of costs associated with
efficiency and renewable energy should
be considered in the evaluation of the
cost-effectiveness of these resources.
Table 111-3
Reserve Allowances of Utility D
Total
5,485
10,970

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44 REDUCED UTILIZATION
Example:
Reduced Utilization in
Phase I Compliance
Utility B’s only Phase I-affected unit is
currently in compliance with Clean Air
Act requirements due to early switching
to low-sulfur fuel. Alternatively, Utility B
could have used the Reduced Utilization
provisions to comply with Phase I re-
quirements.
If Utility B simply shifted the generation
of the utility’s Phase I unit to other units
(most of which would be Phase II units),
the utility would have to identify a coin-
pensating unit or surrender allowances.
The allowances are surrendered at the
average emission rate of the system’s
Phase II units. However, since Utility B
can attribute the reduced utilization to
compensating amounts of DSM, the utili-
ty would avoid bringing a Phase II unit
into Phase I or surrendering these allow-
ances.
Utility B is planning to implement
enough demand-side efficiency to offset
the entire generation of the affected
Phase I unit. Whereas the baseline gen-
eration of Utility B’s Phase I unit is about
300 QWH, the projected savings from the
utility’s demand-side efficiency programs
range from 1,250 GWFI in 1995 to 2,500
GWH in 1999 for measures operational
since January 1, 1988. Thus, the pro-
jected energy savings are greater than
baseline generation, and Utility B could
theoretically reduce the generation of the
Phase I unit to zero without surrendering
allowances.
in this case, the value of the compensat-
ing DSM is equal to the baseline heat
input of the Phase I unit times the aver-
age SO 2 emission rate of Utility B’s Phase
II units. This amount equals 915 tons of
SO 2 for each year, 1995-1999. Utility B
thus avoids surrendering 915 allowances
each year from 1995 through 1999, the
eligibility period for Reduced Utilization.
In total, 4,575 allowances are saved
(continued)
during this period. At a market price of
$250 per allowance, the utility has saved
$1.14 million (at $350 per allowance, the
utility saves $1.60 millionL
In this case, Reduced Utilization provides
the means for meeting Utility B’s Phase I
requirements. The utility is planning to
implement enough efficiency and renew-
able energy programs to offset the pro-
duction of the Phase I unit even without
consideration of Clean Air Act require-
ments.

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PART III: EFFICIENCY AND RENEWABLE ENERGY IN 45
S 02 Co M P11 AN CE STRATEGIES
2. Relevant Circumstances
for Reduced Utilization
Reduced utilization is an attrac-
tive strategy for utilities with units af-
fected in Phase I that have relatively
large demand-side efficiency, supply-
side efficiency, and/or renewable energy
programs either in place or planned.
Since the savings or generation attribut-
able to measures installed anytime after
January 1988 are eligible, utilities with
mature, long-running programs are
likely to save the most allowances.
Reduced Utilization is most appli-
cable to older, less-efficient units with
relatively high operating costs. Reduc-
ing utilization of a newer, efficient base-
load unit with lower production costs is
less likely. The allowance benefits may
not be enough to offset these low pro-
duction costs.
The use of Reduced Utilization
also depends upon whether the utility
offsets enough Phase I generation to
cause the Phase I unit to drop below
baseline. If the efficiency and renewable
energy programs do not cause the unit’s
generation to drop below the 1985-87
baseline, then Reduced Utilization does
not apply. However, emissions would
still be avoided and allowances saved,
but “avoided emissions” would be the
applicable incentive.
3. Reduced Utilization and the
Reserve: Complementary
A strategy incorporating both Re-
duced Utilization and the Reserve can
be particularly beneficial. The same de-
mand-side efficiency and renewable
energy measures that earned bonus
allowances from the Reserve up until
1995 may save allowances for a Phase I
utility under the Reduced Utilization
provisions from 1995 through 1999. In
fact, Reduced Utilization may yield even
greater benefits than the Reserve:
Li Eligibility requirements for Re-
duced Utilization are less strict
than for the Reserve. Unlike the
Reserve, a utility using the Re-
duced Utilization provision does
not have to meet the least-cost
planning or net income neutrality
requirements.
Li Unlike the Reserve, which has a
limited pooi of bonus allowances
to be awarded, Reduced Utiliza-
tion has no limit as to how many
allowances may be saved.
Li While the Reserve awards bonus
allowances only for demand-side
efficiency and renewable energy
programs, the Reduced Utilization
opportunity exists for supply-side
efficiency programs as well.
Li The Reserve allowances are based
on a set formula of 1 allowance
for every 500 MWh of energy
savings or renewable energy gen-
eration. No set formula exists for
Reduced Utilization. Reduced
Utilization generates allowances
based upon the average emission
rate of the system’s Phase II
units.
Li To qualify for the Reserve, effi-
ciency and renewable energy
projects must have been installed
on or after January 1, 1992.
Measures installed on or after
January 1, 1988 qualify for Re-
duced Utilization.

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46 REDUCED UTILIZATION
Example:
Reserve and Reduced
Utilization Allowances
Allowances earned through the Reserve
were compared with allowances saved via
Reduced Utilization for Utility B. The util-
ity is able to earn 2,150 allowances from
the Reserve, based on the formula of one
allowance for every 500 MWh. The utility
saves 915 allowances per year from the
Reduced Utilization provision. This an-
nual savings of 915 allowances is based
upon 300,000 MWh of efficiency savings
(one allowance for every 327 MWh).
The saved allowances for Utility B due to
Reduced Utilization are based on a sys-
tem average SO 2 emission rate for all
Phase II units. Utility B’s average Phase
II emission rate of 0.55 lb/mmBtu re-
flects a reliance on low-sulfur coal.
Utilities with higher Phase II emission
rates would save a greater number of
allowances per kilowatt-hour saved. For
example, if the average emission rate of
Utility B’s Phase II units was 2.5
lbs/mmBtu, Utility B would save 4,138
allowances. In this case, one allowance
is saved for every 71 MWh of efficiency
savings or renewable energy generation.

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Part IV
Efficiency and Renewable
Energy Cost-Effectiveness
Avoided SO 2 emission costs alter the economics of
conventional utility generation. The cost-effectiveness of
efficiency and renewable energy in program design and
screening, bidding, and system dispatch are all
improved by the Title IV incentives.
Photo courU’sq of Osram Sylvania Inc.

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48 AVOIDED COSTS
The Clean Air Act will increase
the attractiveness of resources that do
not emit SO 2 . The economic value of
these alternate energy resources is mea-
sured primarily by the costs of conven-
tional supplies that are avoided. The
previous section described how the
Clean Air Act incentives affect SO 2 com-
pliance strategies. This section exam-
ines how the Clean Air Act affects utility
planning and the overall cost-effective-
ness of efficiency and renewable energy
projects.
Avoided cost values are critical to
the resource selection process. The
utility first develops a base-load forecast
to determine the long-term need for
additional energy resources. The utility
then develops a base supply plan, to
meet the electricity requirements of the
base forecast. Such base supply plans
most often employ traditional supply
resources. The costs avoided by not
implementing the base supply plan is
compared to the cost of other resource
options such as efficiency and renew-
able energy. Resources costing less
than the avoided cost of the base supply
resources should be implemented.
Part IV shows how the costs of
avoided SO 2 emissions will alter overall
avoided cost. The added SO 2 costs
incurred by traditional resources will
improve the cost-effectiveness of effi-
ciency and renewable energy options.
A. Avoided Costs
Efficiency and renewable energy
resources reduce the need for new fos-
sil-fuel facilities, the amount new and
existing plants operate, and the amount
of pollutants emitted. For these rea-
sons, efficiency and renewable energy
resources may avoid many of the costs
associated with a base supply plan.
Efficiency and renewable energy are the
preferable resource options if the costs
avoided by these resources are greater
than the costs of their implementation.
Because emission allowances
place an economic value on SO 2 emis-
sions, a utility’s avoided costs will
change as a result of Clean Air Act com-
pliance strategies. In turn, increases in
avoided costs can increase the amount
of efficiency and renewable energy re-
sources that are cost-effective.
This part discusses the impact of the Title IV incen-
fives on calculating avoided costs and the impli-
cations of an increased avoided cost on utility
planning, bidding, and dispatch.
A. Avoided Costs
B. Demand-side Management Programs
C. Supply-side Efficiency Programs
D. Renewable Energy Projects
E. Bidding
F. System Dispatch

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PART IV: EFFICIENCY AND RENEWABLE
ENERGY COST-EFFECTIVENESS
I
1. Calculating Avoided Costs
Avoided costs are derived from a
comparison of the cost of building and
operating a utility system with and
without alternate energy resources.
Avoided costs can be broken into com-
ponents of energy and capacity. The
avoided cost of SO 2 emission allowances
is a cost which should be incorporated
into current avoided cost of energy cal-
culations.
Methods of calculating avoided
costs vary. A detailed discussion of
avoided cost methodologies is beyond
the scope of this Handbook. The follow-
ing discussion and examples will focus
upon the avoided costs of SO 2 emis-
sions.
The avoided cost of SO 2 emis-
sions can be calculated by multiplying
the annual difference iii SO 2 emissions
by the market value of an emission
allowance. A more complete calculation
is actually more complicated. The ana-
lyst must also account for inflationary
effects as well as determine the net
present value of the cost stream.
2. Avoided Cost and
Resource Characteristics
Avoided energy, capacity arid SO 2
costs vary for different efficiency and
renewable energy options. For pro-
grams offsetting base-load generation,
the avoided cost per kWh may be less
than for intermediate-load options.
Although the base-load energy efficiency
resource saves more energy, some of
that energy is saved during off-peak
periods when production costs are low-
Load management may reduce
system energy and capacity costs, but
increase system SO 2 emission costs.
Likewise off-peak promotion programs
often result in increased energy and SO 2
emission costs (See ‘Contrary Effects’
box in Part Ill).
3. Avoided Costs and Utility
Characteristics
The avoided costs associated with
efficiency and renewable energy resourc-
es vary depending upon utility circum-
stances. In reality, utilities will imple-
ment bundled programs, combinations
of multiple base-load, intermediate-load
and load management options. Such
program combinations which help to
maximize the cost-effectiveness of effi-
ciency and renewable energy programs
alter the aggregate avoided cost value.
A utility’s avoided costs of energy
also vary due to generating plant char-
acteristics such as fuel type. A utility
using peaking units with costly fuels at
the margin will have higher avoided
energy costs than a utility using more
coal plants. Relying less on coal plants
also reduces °2 emissions at the mar-
gin. Avoided costs must be calculated
for each utility’s own specific circum-
stances.
The avoided cost of SO 2 emis-
sions, as represented in the above ex-
ample, is not the primary contributor to
total avoided costs. Although efficiency
and renewable energy resources can
help to reduce emissions and aid com-
pliance with the Clean Air Act, the pri-
mary effect of efficiency and renewable
energy resources on avoided costs ap-
pears to be avoiding the construction
er.

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50 AVOIDED COSTS
Base Load,
Intermediate
Aggre-
Wind
Refrigerator
Program
Load, Commer-
cial Lighting
Load
Managementa
gate
DSM
Energy
Project
Off Peak
Promotionb
(cords/kWh)
(c.nts/lWh)
($/kW)
(cents/kWh)
(cents/kWh)
(cents/kWh)
Avoided Cost
3.62
3.78
40.2
4.08
3.68
3.88
of Energy
Avoided Cost
.56
.93
46.2
1.05
.99
NA
of Capacity
AvoidedSO 2
.15
.15
-1.5
.14
.15
.16
Emission Cost
4.33
4.85
84.9
5.28
4.81
4.05
Table IV - 1
Avoided Costs for Utility A
Total Avoided
Costs
a The avoided costs tot load management are expressed In dollars per kW of load shifted. because load management, as
modeled, does not save energy, the cost value cannot be expressed as a cost per energy avoided.
b The off-peak promotion numbers are not avoided costs, rather They are Incremental costs (an increase In the cost per kWh for
each addItional kWh),
Example:
Effect of Efficiency and Renewable
Energy on Avoided Costs
The avoided costs of energy, capacity and
SO 2 emissions were calculated for five hypo-
thetical load shapes for Utility A. This para-
metric analysis illustrates the avoided costs
associated with a base-load energy efficien-
cy resource, an intermediate-load energy
efficiency resource, a peak-load control
program. a renewable energy option. and an
off-peak promotion program. The first three
options are also combined into an aggregate
demand-side management program.
Table IV- 1 shows the avoided costs of ener-
gy, capacity and SO 2 emissions correspond-
ing to the parametric analysis.The results in
Table IV- 1 are based on a conservative
emission allowance value of 2OO per allow-
ance. The impact of avoided SO 2 emission
costs will be greater at a higher emission
allowance price.
As expected, the avoided cost of the base-
load refrigerator program is less than the
(con ti.rwed)
avoided cost of the intermediate load com-
mercial lighting program. Part of the sav-
ings from the base-load program occurs
during off-peak periods when production
costs are lower. The load management
program actually increased SO 2 emission
costs due to increased generation during
off-peak periods.
The results for the base- and intermediate-
load range energy efficiency resources
would also represent the results for renew-
able energy resources with similar effects on
utility load shape. For example, a paper
company installing a wood-waste boiler and
cogenerator may reduce the company’s elec-
tricity purchases from the utility around the
clock. Thus, the wood-waste project would
have the same effect on avoided costs as
installing a base-load efficiency resource.
Similarly, an independent power producer
may install a photovoltaic system to sell
energy to the utility during on-peak periods.
The photovoltaic system would reduce exist-
ing loads much as would installing an inter-
mediate-load efficiency resource.

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PART IV: EFFICIENCY AND RENEWABLE
ENERGY COST - EFFECTIVENESS
I 51
Utility A,
Utility B,
Utility B,
Utility C,
Demand-Side
Demand-Side
Wind Energy
Demand-Side
Resources
Resources
Resource
Resources
(cents/kWh)
(cents/kWh)
(cents/kWh)
(cents/kWh)
Avoided Cost of
4.08
5.00
3,02
2.39
Energy
Avoided Cost of
1.05
2.25
2.27
1 .60
Capacity
Avoided SO 2
.14
.04
.04
.06
Emission Cost
Total Avoided
5.28
7.29
5.32
4.05
and operation of costly generating Ca-
pacity.
Nonetheless, SO 2 emissions pose
real costs to utilities, and real benefits
accrue from avoiding SO 2 emissions.
These costs and benefits must be con-
sidered when selecting among ener r
resource options. The avoided cost of
SO 2 emissions must be included in the
total avoided costs when screening.
analyzing and implementing resource
options.
The following sections, using
selected examples typical of utility re-
source planning and implementation,
illustrates how avoided SO 2 emissions
costs can affect ener r resource plans.
B. Demand-Side Efficiency
Programs
1. Overview
Avoided SO 2 emission costs can
affect demand-side efficiency programs
by increasing:
Table IV-2
Avoided Costs for Utilities A, B, and C
Cost
Example:
Avoided Costs at Different Utilities
The avoided costs for three different utilities
are given in Table IV-2. This table illus-
trates how avoided costs can vaiy with
utility circumstances.
The Utility A values represent the avoided
costs from the three hypothetical programs,
a base-load refrigerator program, an inter-
mediate-load commercial lighting program,
and a load management program. Avoided
costs for Utility B are given for both the
utility’s planned demand-side efficiency and
wind energy programs. The Utility C values
represent the avoided cost from the utility’s
planned demand-side efficiency programs.
The avoided costs of energy vary with the
utility because the types and fuels of gener-
ating plants are different. Utility B uses
peaking units with costly fuels at the mar-
gin whereas Utility C uses more coal plants.
This greater use of coal plants means higher
SO 2 emissions at the margin, which also
explains why the avoided SO 2 emission
costs are higher for Utility C.

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521 DEMAND-SIDE EFFICIENCY PROGRAMS
L1 The number of energy efficiency
measures that are cost-effective
and should be implemented,
The number of customers partici-
pating, and
LI The overall energy saved.
Thus, avoided SO 2 emission costs
should be an integral part of demand-
side resource program design and
screening. Demand-side management
programs are typically developed and
implemented in the following stages:
1. Potential energy efficiency mea-
sures are identified and the sav-
ings potentials are estimated.
2. The potential energy efficiency
measures are screened to deter-
mine cost-effectiveness using
avoided cost values.
3. Measures that pass the economic
screening are bundled into pro-
grams for implementation. Avoid-
ed costs are used to help set the
customer incentive levels.
4. The bundled programs are
screened to ensure cost-effective-
ness is maintained when program
administrative costs and interac-
tive effects between measures are
considered. The use of avoided
costs in screening the bundled
programs is similar in concept
and method to screening indi-
vidual efficiency measures.
5. Programs are implemented, moni-
tored and refined as necessary.
The economic screen in stage 2
compares the cost of each measure to
the avoided cost of the supply resource
being offset. An energy efficiency mea-
sure is cost-effective when the savings
(avoided costs times energy saved) is
greater than the measure’s cost.
2. Impact on DSM Program
Screening
Avoided costs affect the scope of
energy efficiency measures being con-
sidered. An increase in avoided costs
would have the effect of increasing the
Example:
Cost-Effectiveness of DSM Measures
Consider a hypothetical situation of a
utility evaluating three different energy
efficiency measures. The benefit-cost
ratio is calculated both with and without
the avoided SO 2 emission costs being
considered. In this example, the benefits
of the DSM measures stein from the
avoided emissions incentive. If the utility
also took advantage of the Reserve
and/or Reduced Utilization provision, the
impact on the avoided costs would be
even greater.
Table IV-3 illustrates the impact of avoid-
ed SO 2 emission costs on different DSM
measures. Measure no. 1 was already
cost-effective before the inclusion of the
avoided emission costs and became more
cost-effective with these costs. Measure
no. 2 was just below the cost-effective-
ness threshold without SO 2 emission
costs, and then becomes cost-effective
with the SO 2 emission costs.
Measure no. 3 was not cost-effective be-
fore or after the inclusion of the avoided
SO 2 emission cost. Thus, the impact of
the avoided SO 2 emission costs depends
upon both the nature of the DSM mea-
sure and the utility.

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PART IV: EFFICIENCY AND RENEWABLE
ENERGY COST-EFFECTIVENESS
I
Measure No.
No.1 No.
2 No.3
number of measures that are considered
cost-effective and suitable for inclusion
in one or more demand-side programs.
In some instances, adding the avoided
cost of SO 2 emissions will result in
additional measures being cost-effective.
The effect of the avoided SO 2 emission
cost is very spec flc to each utility.
3. Impact on Customer
Participation and Savings
Measures that pass the economic
screening are bundled into programs
designed to implement those measures.
Avoided costs are used in the design of
the programs to help set the customer
incentive levels needed to achieve suffi-
cient customer participation. The cus-
tomer incentives and program adminis-
trative costs will decrease some of the
savings in avoided costs.
The customer incentives need to
be high enough to achieve savings, but
when combined with program adminis-
trative costs, less than the avoided cost.
The added avoided SO 2 emission cost
mczyjust fy a higher customer incentive,
and thus can increase customer partici-
pation.
The mechanism for program de-
livery can affect the impact of the avoid-
ed SO 2 emission costs on customer
incentives. Delivery mechanism options
include rebates, shared savings, and the
use of energy service companies.
If the mechanism is utility-admin-
istered rebates, small additions to the
avoided cost may not greatly affect the
levels of customer incentives. Program
designers may choose a value signifi-
cantly below the full avoided cost based
on experience or judgement. Program
designers also tend to pick round num-
bers (e.g., a $50 rebate rather than a
$48.50 or $51.50 rebate) for simplicity
and marketing reasons.
Table IV-3
Effect of Avoided 502 Emissions Costs on
DSM Cost- Effectiveness
Present Value of Avoided Energy ($)
Present Value of Avoided Capacity (5)
65.00
Beneffi-Cost Ratio w/o SO 2 Costs
8 50
10.00
Present Value of Avoided SO 2 (5)
129.00
1.50
1.25
Benefft Cost Ratio wiTh SO 2 Costs
32.00
.99
2.50
.67
.50
1.30
5.00
1.02
.69

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DEMAND-SiDE EFFICIEN
If the mechanism is shared sav-
ings with the customer, the costs avoid-
ed by the DSM programs are shared
between the customer using the device
and the utility. For example, the cus-
tomer may receive 50 percent of the
avoided cost for allowing the utility to
install the DSM measure. Under a
shared savings arrangement, even small
additions to the avoided cost will be
passed on to the customer. Thus, the
avoided SO 2 emission costs would be
incrementally added to customer incen-
tive levels.
If the mechanism is purchasing
the savings from third-party, energy
service companies (ESCOs), the utility
will contract with the ESCO to improve
the efficiency of customer energy use.
The customer may or may not receive
additional incentives based on avoided
SO 2 emission costs. However, the SO 2
avoided emission costs can help extend
the scope of the ESCO’s efforts to in-
clude additional measures and/or par-
ticipants.
CY PROGRAMS
C. Supply-Side Efficiency
Programs
1. OveMew
Supply-side efficiency refers to
any efficiency improvements made on
the utility’s side of the meter. Supply-
side efficiency improvements can in-
clude transmission and distflbution
programs such as amorphous core
transformer improvements, in-plant
programs that improve plant heat rate,
and utility in-house efficiency programs
such as lighting, heating, and cooling.
Amorphous core transformers re-
duce standby energy and capacity loss-
es, resulting in more electric power
reaching the customer for the same
amount of heat input to the power
plants. Improving power plant heat
rates means that the power plant pro-
duces more electricity for a given
amount of heat input to the power
plant. Utility in-house programs reduce
the utility’s consumptive use of electrici-
ty by using more efficient end-use tech-
nologies. In each of these cases, less
heat input is required to deliver the
same amount of electricity to the cus-
tomer. Thus, both total heat input and
total emissions are reduced as a result
of supply-side efficiency improvements.
2. Impact of Supply-side
Programs on Cost-
Effectiveness
Supply-side efficiency measures
are considered through a similar pro-
cess as that for demand-side measures.
Avoided costs are used to determine the
cost-effectiveness of the various
Example:
Participation in DSM Programs
The previous example illustrated how the
avoided SO 2 emission cost can increase
the number of measures passing the
cost-effectiveness screen. However, the
avoided SO 2 emission cost also can influ-
ence the optimum number of program
participants. The present value of the
avoided SO 2 indicates the additional
resources available to increase incentives
or other delivery mechanisms.
Figure IV- 1 Illustrates how the avoided
SO 2 emission costs can increase:
1. The number of program partici-
pants, and
2. The amount of energy savings.

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PART IV:
EFFICIENCY AND RENEWABLE
ENERGY COST-EFFECTIVENESS
Avoided Costs
Figure IV- 1
and Program Participation
DSM Measure No. 1
Without SO 2 Costs
11,000 Participants
2,200 MWh saved/yr
Without SO 2 Costs
DSM Measure No. 2
With SO 2 Costs
II
H
_ —
12,000 Participants
2,400 MWh saved/yr
With SO 2 Costs
0 Participants
0 MWh saved/yr
5,000 Participants
250 MWh saved/yr
I
r

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56 SUPPLY-SIDE EFFICIENCY PROGRAMS
supply-side efficiency measures being
considered. A higher avoided cost will
increase the number of supply-side
measures considered to be cost-effec-
tive.
Supply-side efficiency measures
can avoid the surrender of allowances
under the avoided emissions incentive
and the Reduced Utilization provision.
However, these measures do not qualify
for earning bonus allowances from the
Reserve. Like demand-side efficiency
measures and renewable energy pro-
jects, supply-side efficiency measures
can avoid SO 2 emissions by offsetting
generation from sulfur-emitting sources.
The avoided SO 2 emission costs can
make supply-side measures that are
already cost effective to be more so.
Likewise, measures that were not previ-
ously viable may now become cost-effec-
tive.
D. Renewable Energy
Projects
1. Overview
Avoided SO 2 emission costs can
affect renewable energy projects by
increasing:
The number of renewable energy
resource options that are cost-
effective,
L1 The size of the projects, and
LI The payments for purchased
power and improving the project
economics for independent power
producers.
In an integrated resource plan-
ning context, screening and selecting
renewable energy resources follow much
the same pattern as demand-side man-
agement programs. Utilities must devel-
op and implement plans to serve energy
needs. Renewable energy options must
be examined and compared to other
resource options for overall cost-effec-
tiveness. Avoided SO 2 emission costs
must be included to capture the full
avoided cost of the renewable energy
resource.
Renewable energy resources are
typically developed in the following stag-
es.
1. Potential renewable energy re-
sources are identified and the
energy production potentials are
estimated.
2. The potential renewable resources
are screened to determine cost-
effectiveness using avoided cost
values. The economic screen
compares the cost of each option
to the avoided cost of supply
being replaced.
3. Options that pass the economic
screening are implemented either
by the utility or a non-utility
generator.
Renewable resource options may
be developed by the utility or through
non-utility generators who then sell the
power to the utility. The utility’s avoid-
ed costs are a major determinant to the
buyback rate for non-utility generators.
Power purchases under PURPA (Public
Utility Regulatory Policies Act) are
priced at the avoided costs of the pur-
chasing utility. Customer-owned renew-
able energy projects are also possible.
Such self-generation may offset the

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AND RENEWABLE
PART IV: EFFICIENCY
ENERGY CO ST - EFFECTIVENESS
I
customer’s own energy use or be sold
back to the utility grid. 16
2. Impact on Project Size and
Screening
Avoided costs affect both the
number of renewable energy options
passing the economic screening process
and the optimum size of the project. As
with energy efficiency resources, the
inclusion of the avoided SO 2 emission
cost may change the viability of projects
which were previously not cost-effective.
Those projects already cost-effective will
become even more so.
From the utility perspective, the
inclusion of avoided SO 2 emission cost
may be sufficient to select a renewable
energy option. With utility-owned re-
sources the utility directly receives the
cost and SO 2 emissions benefits.
The utility may also accept renew-
able energy project proposals offered by
independent power producers. In this
case, avoided costs can help determine
the terms of the purchase agreement.
The buyback rate will increase with the
addition of avoided SO 2 emission costs.
The increased buyback rate will improve
the project viability for the independent
power producer, and may induce addi-
tional and/or larger project proposals.
3. Impact on Independent
Power Producers
Avoided SO 2 emission costs may
have a significant impact on indepen-
dent power producers. These non-utili-
ty generators are competing to build
and operate electric generating facilities
at costs lower than the electric utility’s
conventional generation. The utility’s
buyback rate for an independent power
Example:
Utility Renewable Energy Project
Renewable energy resources are increas-
ingly becoming components of utility bulk
generation. In other instances, renew-
able energy resources are the most cost-
effective options for specific applications.
One such application is the use of modu-
lar renewable energy systems for remote
locations. Such systems avoid the costly
construction of distribution lines over
long distances.
For example, a potential customer locates
miles away from the nearest utility power
supply. When evaluating the customer’s
options for electricity, the utility calcu-
lates that in addition to the utility’s nor-
ma! avoided costs of 6.5 cents per kWh
(including 0.1 cents per kWh for avoided
SO 2 emission costs), the cost of the ser-
vice extension would be 4.1 cents per
kWh.
The total avoided cost for that customer
would be 10.6 cents per kWh, which is
the same as the estimated cost of a solar
photovoltaic system with storage and
inverters constructed on-site and not
connected to the utility network. The
utility and customer both opt for the pho-
tovoltaic system.
producer depends on the utility’s avoid-
ed costs.
Photo courtesy or roe Solar
Energy Industry Association

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581 RENEWABLE ENERGY PROJECTS
The income received by the inde-
pendent power producer must cover the
amortization of the power generating
plant and operating and maintenance
expenses as well as provide a margin of
profit. As illustrated below, a small
increase in buyback rates can result in
a large increase in the independent
power producer’s profit margin. Since
profit is what remains after all expenses
are paid, even a small increase in
buyback rates can greatly increase prof-
its for a project with set expenses.
The improved profitability will at-
tract more independent power produc-
ers to submit proposals as well as en-
courage those already making proposals
to increase the number and size of pro-
jects. The size of proposed projects is
often limited by the availability of fi-
nancing and capital. Higher buyback
rates will enhance profitability and will
improve the ability of independent pow-
er producers to raise capital needed for
expanded project proposals.
Thus, including avoided SO 2
emission costs can lead to increases in
the size and number of renewable ener-
gy projects offered by independent pow-
er producers.
E. Bidding
1. Overview
Bidding is the mechanism by
which a utility can acquire supply and
demand-side resources in a competitive
fashion. Avoided SO 2 emission costs
may affect the bidding process and
increase the number and scope of com-
petitive bids for energy efficiency and
renewable energy resources.
The utility’s procurement process
may be limited to supply-side or de-
mand-side projects, or may be an open
“all-source” bidding request. Often a
utility will publish its avoided cost as a
target for potential bidders. By knowing
the utility’s avoided costs, a bidder can
determine if the project is sufficiently
competitive to proceed with the often
costly process of developing a proposal.
Generally, a utility receives sealed
proposals from project developers and
selects projects based on cost and other
criteria. A contract between the utility
and the successful bidder(s) must then
be negotiated. Once terms are set, the
project is implemented.
2. Impact of Avoided SO
Emission Costs on Bidci ng
Inclusion of avoided SO 2 emis-
sions costs can affect the bidding pro-
cess in at least three ways. First, avoid-
ed costs may be published prior to the
Example:
Effect of SO 2 on Profitability
Consider an independent power producer
proposing a project with the expenses
and power sales shown in Table IV-4.
Assume that the utility buyback rate for
purchased power was at the avoided cost
for Utility A described in Table IV-2.
The estimated revenue from the project is
greater if buyback rates include the
avoided SO 2 emission cost. However,
because the costs of production remain
unchanged, the profits increase at an
even greater rate. In this example, a 3
percent increase in the avoided costs (due
to avoided SO 2 ) results in a 12 percent
increase in profits for the independent
power producer (IPP).

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PART IV: EFFICIENCY AND RENEWABLE
ENERGY COST-EFFECTIVENESS
I
solicitation of bids for resource projects.
Increasing the avoided cost should re-
suit in a greater number of competitive
bids being submitted, as more projects
become competitive with the utility base
plan.
Second, avoided costs will also af-
fect the evaluation of bids. The full
value of avoiding utility supply capacity
should be considered in bid evaluation.
Thus, when the utility is reviewing bids,
the utility should include the avoided
SO 2 emission cost in the cost criteria.
Other criteria may include risk and
reliability factors and other environmen-
tal impacts.
Third, avoided costs will affect the
actual negotiation of the contract for the
resource. Avoided costs will be part of
the overall balancing of interests be-
tween economic factors, risk, reliability,
and environmental factors. These costs
may also be part of an indexed payment
strategy, or as a re-opener clause to a
fixed payment strategy. To the extent
that avoided costs enter the negotia-
tions, the inclusion of avoided SO 2
emission costs can result in increased
payments to the bidder.
F. System Dispatch
1. Overview
Dispatch refers to the selection
process by which generating units are
chosen to serve electrical loads at a
particular time. The electrical loads are
not constant throughout the day; loads
usually fall to a low during the late
night or early morning hours, and in-
crease to a maximum during the after-
noon hours when customers are most
active.
As loads increase during the day,
the utility must increase the output of
generating units already on-line, or
bring additional units on-line, to serve
the loads. When loads decrease, the
utility must reduce the level of genera-
tion by taking units off-line and/or
backing down the level of output from
units already on-line.
Table IV-4
Effect of Avoided SO 2 Emission Costs on IPP Profitability
Annual Costs:
Amortization of Capital:
O&M Expenses:
Annual Sales:
$5,100,000
$3,200,000
211,000,000 kWh
Buyback rate (S/kWh)
Revenue (5)
Without SO 2 Costs
Profit (5)
.0513
With SO 2 Costs
10,833,000
.0528
2,559,000
11,150,000
2,876,000

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_ ]SYSTEM DISPATCH
Major Components of a Resource Bid
Ufihity requests for proposals for energy resources con be quite detailed and
complicated. Some utilities provide forms to prospective bidders as part of the
request for proposals. These forms require summary information describing the
project, schedules, and other attachments. Some utilities even require that the
bidders complete a project evaluation work sheet in which bidders score their
proposals in accordance with a set of instructions
The major categories of information that could be included in a resource bid
and/or bid evaluation are:
Project description, including resource type. size, fuel type, dote of avail-
ability. and life of the offered resource.
Li Energy and capacity offered. by time of day, season, and year
Price bid, including capacity and energy charges. escalation rates, cost
indices, and proposed payment schedule.
En ,1ronmental emission levels and of her effects calculated both for the
project and net of utilfty plant emissions being offset.
i Technical feos.ibilily and risk assessment, including maturity of technology,
operating experience of the bidder, completeness of engineering design.
progress toward securing needed licenses and permits, and proposed
quality control
Li Economic viability of proposer and project. including capital structure,
security of financing, public acceptance of project. and years unttl
project breaks even,
Project persistence, Including maintenance practice, fuel secunty, and
proposer experience.
Li System compatibility, including dispatchobility, fuel diversity, appropriate-
ness of size, and location.
Li Estimate of The avoided costs of utility supply, including avoided SO 2
emission costs and perhaps avoided costs of external impacts.
Li Estimate of benefit cost ratio.

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PART IV: EFFICIENCY AND RENEWABLE
ENERGY COST-EFFECTIVENESS
61
Utilities dispatch generating units
according to economic dispatch to mini-
mize the operating cost of the utilities’
systems. Plants with lower fuel and
variable operating and maintenance
costs per kWh are brought on-line and
loaded to full output before units with
higher operating costs. Generating
units with low fuel costs, low heat rates
(less heat input per kWh output), and
low variable operating and maintenance
costs tend to be called upon sooner.
loaded more heavily, and taken off-line
later than other units. Fixed costs (e.g..
the cost of building the generating unit)
are sunk costs -- incurred whether the
unit is called upon to operate or not --
and do not enter into the dispatch deci-
sion.
Until recently, SO 2 emissions
were considered externalities, costs that
are imposed upon others but for which
a business does not pay. Thus, SO 2
emission rates were not considered in
economic dispatch. However, the cre-
ation of the SO 2 allowance market tin-
der the Clean Air Act Amendments has
added the cost of SO 2 allowances to the
costs directly incurred by the utility.
Analysts developing or evaluating
utility plans must be careful to include
the cost of SO allowances in the eco-
nomic dispatch of the utility system be-
ing modeled. Failure to include allow-
ance costs in the dispatch model can
result in higher emissions, higher com-
pliance costs, and higher operating
costs.
2. Impact of SO 2 Emission
Allowances on Dispatch
Consider a utility that needs
additional allowances to meet compli-
ance requirements. The utility could
reduce SO 2 emissions at an existing
plant by fliel switching. scrubbing, pur-
chasing excess allowances at market
cost, or employing efficiency and renew-
able ener . In either case, the utility
will face a cost in meeting allowance
obligations.
Conversely, the allowances the
utility expends through the dispatch of
the utilitys system dispatch have a
value. By including the market value of
an allowance in the economic dispatch
algorithm, generating units would be dis-
patched to minimize (he combined cost of
fuel, variable operating and mainte-
ncunce, and SO 2 allowances. SO 2 costs
would be included in economic dispatch
for each unit at the time the unit be-
comes siibject to Title IV.
A utility with excess allowances is
not facing increased system operating
costs. However, a market exists to sell
allowances. This market gives the utili-
tv an opportunity to reduce operating
costs by selling excess SO 2 allowances.
Again, including the market value of an
allowance in the economic dispatch
algorithm will appropriately dispatch
units to minimize overall utility prodiuc-
tion costs.
In both examples. the costs of
SO 2 allowances are real costs, or real
opportunities for reducing costs. faced
by utilities. The SO 2 allowance market
has established a cost for the SO 2 emit-
ted which is every bit as real as the fuel
cost for the plant. The utility needs to
acquire the allowance just as it needs to
purchase fuel.
The allowance concept distin-
guishes SO 2 from other regulated and

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62 SYSTEM DISPATCH
unregulated pollutants. Other regulated
pollutants are regulated solely on the
basis of emission rates, meaning that
more tons of pollutant can be released
as more plants are built. (The exception
is for plants that are being built in non-
attainment areas where offsets for the
emissions would be required.) Unlike
other regulated pollutants, and all un-
regulated pollutants, the limits on total
SO 2 emitted creates a market value for
SO 2 .
3. Impact on Dispatchable
Renewable Energy
Resources
The ability to dispatch energy re-
sources allows the utilities to increase
or decrease electrical supply to loads
demanded by customers. Conventional
fossil-fired utility generation is
dispatchable; the utility has control of
the resource’s availability. The utility
has flexibility to choose which plants
serve the load. The utility can use that
flexibility to respond to varying condi-
tions such as power plant outages, the
amount of power demanded, transmis-
sion network constraints, and environ-
mental regulations on plant operation.
Some forms of alternate resources
do not give the utility the ability to dis-
patch. Sometimes this condition is a
function of the physical process used to
produce electricity; solar and wind erier-
gy systems are examples. However, the
availability of these resources can often
be predicted with a high degree of cer-
tainty. Storage technologies are being
developed to cost-effectively store the
energy generated from these resources.
In general, though, solar and wind ener-
gy resources are not considered
dispatchable.
Many forms of renewable energy
are dispatchable. Biomass systems in
which wood, plant, or other organic
material can be stockpiled until convert-
ed to electricity are dispatchable. Geo-
thermal systems in which steam can be
withdrawn as needed are dispatchable.
Hydro electric systems in which stored
water is the primary energy source are
also dispatchable. In such instances,
the avoided SO 2 emission costs should
be considered in the dispatch of these
resources. Including the avoided SO 2
emission costs will act to increase the
use of dispatchable renewable energy
resources.
Example:
The Failure to Include
SO 2 in Dispatch
Consider the effect of failing to include
SO 2 allowance costs in the dispatch algo-
rithm for Utility A, the moderately-sized
high-sulfur-coal-burning utility. In this
hypothetical situation, the utility failed to
add the market price of $200 per allow-
ance for SO 2 emissions to each unit’s fuel
and operating costs when dispatching.
This hypothetical situation is compared
to one in which the utility applied a cost
of $200 per SO 2 allowance to each unit’s
SO 2 emissions.
SO 2 emissions are substantially higher
when SO 2 emission costs are not includ-
ed in the dispatch algorithm. Including
SO 2 emission costs in dispatch resulted
in the emission of almost 300,000 fewer
tons of SO 2 over the 15 year period be-
ginning in 1995. By comparing operating
cost differences between the two cases,
one finds that this SO 2 reduction was
accomplished at an average cost of $43
per ton.

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PART IV: EFFICIENCY AND RENEWABLE
ENERGY COST - EFFECTIVENESS
The following example illustrates
that dispatchable renewable resources
can displace conventional generation to
reduce SO 2 emissions.
Example:
Utility-Owned Geothermal Unit
Assume that a utility builds a 200 MW geo-
thermal unit at a capital cost of 5.0 cents
per kWh and an 80 percent capacity factor.
Because there is no fuel cost, overall operat-
ing and maintenance costs are an addition-
al 1.0 cents per kWh. Other coal-fired units
on the utility’s system have operating costs
(including avoided SO 2 emission costs of 0.1
cents per kWh) ranging from 2.1 cents to
2.9 cents per kWh. Because the cost to
l)uild generating units is a sunk cost, it
does not enter into the dispatching deci-
sions.
The coal-tired units follow in the same dis-
patch order as prior to the addition of the
geothermal unit. The units at the bottom of
the loading order (last to be dispatched) are
displaced by the geothermal unit. 302
emissions from those units are avoided to
the extent that unit energy output is de-
creased by the new geothermal unit.
Table IV-5 summarizes these results.
63
Photo courtesy of the
Icelandic Tourist Bureau

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JSYSTEM DISPATCH
Table IV-5
Effect of Renewable Energy Resource on Dispatch Order
Before
Geothermal 1
After
Geothermal 1
Dispatch
Priority
Variable 0&M
and Fuel
(Cents/kWh)
502
Emissions
(Tons)
Dispatch
Priority
Variable 0&M
and Fuel
(Cents/kWh)
SO 2
Emissions
(Tons)
Geothermal
1
N.A.
N.A.
N.A.
1
1.0
0
Coal 1
1
2.1
3500
2
2.1
3500
CoaI2
2
2.15
4000
3
2.15
3950
Coal 3
3
2.4
2500
4
2.4
1100
Coal 4
4
2.9
1500
5
2.9
300
Total SO 2 11500 Total SO 2 8850

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Part V
Beyond SO 2 : Other Pollutants
t 1 jjtctency ancL renewabLe energy not onLy tleLp uttLtties
avoid SO 2 emissions but other pollutants as well,
including NOx, GO 2 , toxics, and particulates. Efficiency
and renewable energy resources can provide a cost-
effective strategy against the risk offuture
environmental regulation.
Photo courtesy of Wood fin Camp

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66 PART V: BEYOND $02: OTHER POLLUTANTS
Sulfur dioxide is not the only
pollutant of concern stemming from
electric utility operation. Electric utili-
ties also emit nitrogen oxides, carbon
dioxide, toxics, and particulates as well
as produce ash and scrubber sludge.
Not all of these pollutants are applicable
to tradeable emission programs; nor are
all of these pollutants even currently
regulated. However, the consideration
of these pollutants when formulating
SO 2 strategies may still be a cost-effec-
tive course of action. The following
table indicates the approximate share of
national emissions from electric utilities:
Pollutant
S
hare of National
Emissions by
Electric Utilities
(‘Q
2
A( ’)O/
L 7IO
CO 2
35%
NOx
32%
Particulates
5%
The Clean Air Act includes re-
strictions on most major air pollutants
emitted by electric utilities. In addition
to the SO 2 emission allowance system,
Title IV of 1990 Clean Air Act Amend-
ments also established new regulations
for nitrogen oxides (NOx) emitted from
utilities. Title III of the Act contains
provisions for the study of utility emis-
sions of airborne mercury and other
toxics. Title I of the Act addresses a
range of pollutants such as SO 2 , NOx,
and particulates from the perspective of
ambient air standards.
Carbon dioxide (C0 2 ) is not a
regulated pollutant. However, CO 2 is a
major focus of several international
efforts to reduce greenhouse gas emis-
sions. The Climate Change Treaty as
signed by the United States during the
1991 Earth Summit in Rio de Janeiro is
one such instrument. On Earth Day
1993 President Clinton reaffirmed the
United States’ commitment to meeting
the Climate Change Treaty. This com-
mitment includes stabilizing greenhouse
gases at 1990 levels by the year 2000.
To support this effort, the U.S. has
developed “The Climate Change Action
Plan,” a program of 50 actions designed
to reduce greenhouse gas emissions
across all sectors.
The procedures and issues dis-
cussed in this Handbook are relevant to
these other pollutants in several ways.
First, if emission trading systems or
other economic incentive programs are
This part discusses the following topics:
A, Applying the Handbook’s concepts to
other pollutants
B. Considering the impact of
externalities on avoided costs
C. Using efficiency and renewable ener-
gy as a pollution prevention strategy
to minimize risks

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PART V: BEYOND SO
developed for other pollutants, analo-
gous calculations for compliance costs
and resource cost-effectiveness will
apply. Second, States that develop
monetary values for environmental
externalities may find some of these
calculations and procedures useful.
Finally, to calculate the full benefits of
energy efficiency and renewable energy
as pollution reduction strategies, utili-
ties and regulators should consider how
these technologies can reduce multiple
emissions. One important consideration
is the use of these technologies to hedge
the cost risks of possible future environ-
mental regulations.
A. Applying the Concepts
to Other Pollutants
As with SO 2 , efficiency and re-
newable energy resources help avoid
NOx, CO 2 and other emissions simply
by reducing a utility system’s generation
from fossil fuel sources. If economic
incentive programs are developed for
these other pollutants, the concepts
introduced in this Handbook may prove
useful.
Reduction of ambient nitrogen
oxide emissions may be the next compli-
ance area in which energy efficiency and
renewable energy can play a role. NOx
is an important precursor of tropospher-
ic ozone (urban smog) a pollutant that
affects dozens of cities and towns in the
United States. Under Title I of the Act,
regions that exceed national ambient air
quality standards (NAAQS) must take
actions to reduce their emissions.
These “non-attainment” regions are
classified as either extreme, severe,
serious, moderate, or marginal depend-
ing upon the degree of the problem.
2: OTHER POLLUTANTS 67
Compliance dates range from 1993 to
2010 based on the non-attainment
status.
The Clean Air Act Amendments of
1990 encourage the use of market-
based economic incentive programs in
areas of the country that exceed nation-
al ambient air quality standards
(NAAQS). In several parts of the coun-
try, regulators are developing these
types of programs to control NOx emis-
sions. Most notably, the South Coast
Air Quality Management District in
Southern California will launch NOx
and SOx emissions trading systems in
early 1994. The South Coast region is
classified as an extreme non-attainment
area for ozone and its NOx program will
cover approximately 390 facilities. Each
facility will receive an annual allocation
of tradable emissions credits similar to
Acid Rain allowances. The number of
annual credits allocated to utilities will
be reduced over time so that by 2003
there will be an overall reduction of 75
percent.’ 7
Title I NOx trading is also under
consideration in Massachusetts and
several other States that make up the
Northeast Ozone Transport region. In
addition, State and regional govern-
ments are exploring the use of NOx
trading to address non-attainment areas
in Illinois and Houston, Texas.
As noted in the case of SO 2 emis-
sion trading, the associated emission
costs for these programs will affect the
avoided costs of fossil-fired generation.
In turn, increased avoided costs for
fossil-fired generation will improve the
viability of efficiency and renewable
energy resources in project design and
screening, bidding, and dispatch.

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68 EXTERNALITIES
B. Externalities
1. Overview
A number of states have begun to
consider the environmental costs of
emissions through “environmental
externalities.” These externality values
are incorporated into the traditional
benefit-cost analysis and used in inte-
grated resource planning.
Some states have placed a specif-
ic monetary value on a given pollutant
(in terms of $f ton or similar units). In
other instances, states have adopted a
more general “adder” to the costs of
conventional fossil and/or nuclear gen-
eration technologies (typically a ‘per-
centage” credit or debit added to the
estimated costs of a new unit).
Table V-i summarizes the values given
to eight common air pollutants by three
jurisdictions that have attempted to
quantify the emission impacts.
2. Impact on Cost-
Effectiveness
Like avoided SO 2 emission costs,
environmental externality values im-
prove the cost-effectiveness of efficiency
and renewable energy resources relative
to conventional fossil fuel and nuclear
technologies. Externality values effec-
tively increase a utility’s avoided costs
for conventional energy generation tech-
nologies. Consequently, more efficiency
and renewable energy technologies may
be cost-effectively added to the utility’s
resource portfolio.
Higher avoided costs caused by
the incorporation of the costs of one or
more emissions now considered
externalities could affect the utility
planning process in a variety of ways.
These impacts would parallel those
discussed for SO 2 ; these impacts in-
clude resource screening, program de-
sign, bidding, and dispatch.
In addition to improved cost-effec-
tiveness, externality values can also
affect incentive levels and customer
participation. With the higher avoided
cost, the utility would be able to offer
more attractive incentives to improve
program penetration.
3. Impact on System Dispatch
Historically, system dispatch has
been conducted on a strictly economic
basis; dispatch has included only costs
directly incurred by the utility. As such,
environmental impacts associated with
power plant emissions generally have
not been factored into dispatching deci-
sions, unless environmental regulations
constrain the availability of certain gen-
erating units to produce electricity.
Some analysts have argued that power
plant emissions create a burden on and
cost to the rest of society, and that utili-
ties can reduce these societal costs by
including an emission cost in their dis-
patch methods.
Example:
Externalities Add to Avoided Costs
Table V-2 illustrates the effect of includ-
ing the externality values approved by the
Massachusetts DPU on an example
utility’s avoided costs.
In this example, a total of 4.29 cents
would be added to the utility’s avoided
costs to account for the eight identified
externalities.

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PART V: BEYOND SO 2 : OTHER POLLUTANTS 69
Massachusetts
Nevada
California
(Docket 89-239)
(Docket 89-752)
(PUC)
Pollutant 1989 5/ton
1990 S/ton
1990 S/ton
The environmental dispatch meth-
od thus adds emission rates to the fac-
tors considered in economic dispatch
algorithms (fuel costs, heat rates and
variable operating and maintenance
costs) to determine the priority in which
generating units are loaded. Environ-
mental dispatch is a means of incorpo-
rating external environmental costs into
dispatching decisions.
Using an environmental dispatch
scenario, an analyst could determine a
pollutant’s effect on the dispatching of
generating units. In other words, the
analyst could see the impact on emis-
sion levels from dispatching generating
units as though these pollutants had a
direct cost to the utility. The direct cost
for purposes of the dispatching study
could be an assumed price of a pollu-
tion allowance if a market existed, or it
could be based on perceived environ-
mental harm to society.
Table V-i
Environmental Externality Values
Nitrogen Oxides
(NO)
$6,500
Sulfur Oxides (SO)
Volatile Organic
Compounds
$6,800
$1,500
$5,300
$13,060
Total Suspended
Particulates
$1,560
$1 ,180
$4,000
$12,960
Carbon Monoxide
(CO)
$3,660
$4,180
$860
Carbon Dioxide
(C0 2 )
$8,780
$920
Methane (CH 4 )
$22
NA
Nftrous Oxide (N 2 0)
$22
$220
$3960
$8
$220
$4,140
NA
NA

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70 USING EFFICiENCY AND RENEWABLE ENERGY
TO REDUCE REGULATORY RISK
Mass DP
Pollutant (1989
U Value
$/ton)
System Marginal Emis-
sions (Ib/MWh) Cents/kWh (1991)
Table V-2
Effect of Externalities on Avoided Costs
N0
sox
S6,500
VOC
SL500
5.1
TSP
$5,300
10.6
Co
$4,000
1.66
0
002
0.80
$860
0.3
CH 4
0.00
$22
0
N 2 0
0.06
$220
1,620
0.00
$3,960
0
1.78
0
0.00
0.00
Example:
Environmental Dispatch with NO
Consider assigning costs to the NO
emissions of Utility A and dispatching the
system taking those costs into account.
To determine the effect of NO emission
costs on unit dispatch, a range of NO
emission costs from $1 .000 per ton
avoided to $10,000 per ton avoided was
analyzed using a production-simulation
model. At $1,000/ton, over the 15 year
period of analysis, NO emissions de-
crease by 57,500 tons at an average cost
of $380 per ton due to environmental
dispatch. At $10,000/ton, over the 15
year period of analysis. NO emissions
decrease by 107,700 tons at an average
cost of $990 per ton due to environmen-
tal dispatch.
In both the high- and low-cost NO sce-
narios, environmental dispatch resulted
in decreases in both NO and SO 2 emis-
sions. However, SO 2 emission levels
became more unstable and rose as NO
prices became larger and began to domi-
nate the dispatch. This illustrates that
pollutant control strategies should be
developed in an integrated manner so
that gains made in the control of one are
not unexpectedly lost when the focus
changes to control another.
Although this example is done for NON, it
Is applicable for any pollutant for which
an allowance market does not exist, i.e..
any unregulated pollutant or any einis-
sion-rate-regulated pollutant. If another
pollutant were to be used, the appropri-
ate emission rate for each generating unit
and the appropriate ‘allowance” value
would have to be substituted in the pro-
duction-simulation model.
(continued)

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PART V: BEYOND SO 2 : OTHER POLLUTANTS
C. Using Efficiency and
Renewable Energy to
Reduce Regulatory Risk
Conventional compliance options
such as scrubbing and fuel switching
often address pollutants in isolation.
For instance, scrubbing technologies
that capture SO 2 emissions may not
reduce other pollutants such as NOx.
Such technologies may even increase
the output of other pollutants. 18 Sepa-
rate control technologies may be re-
quired for each pollutant.
Conversely, efficiency and renew-
able energy technologies will reduce or
avoid virtually all pollutants. When
developing compliance options, the
regulatory costs should be considered
on an integrated basis. A pollution
prevention strategy may be particularly
useful for hedging the risks of possible
future environmental requirements.
Efficiency and renewable energy tech-
nologies may be part of a voluntary ‘no
regrets” strategy against changes in
existing regulations or the development
of new legislation for presenfly uncon-
trolled pollutants.
The voluntary reduction of CO 2
and other greenhouse gases is the cor-
nerstone of the recently announced U.S.
Climate Change Action Plan. One com-
ponent of the plan, ‘The Climate Chal-
lenge,” is a program in which electric
utilities are voluntarily committing to
CO 2 reductions. The success of such
voluntary stabilization efforts will be
reviewed every two years by an action
plan task force. Further, the Action
Plan directs an interagency task force to
explore longer term strategies to address
CO 2 beyond the year 2000. Depending
upon the success of the voluntary ac-
tions and the strategies for longer term
actions, other greenhouse gas actions
are possible. Efficiency and renewable
energy help utilities prepare for any
contingency.

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72 USING EFFICIENCY AND RENEWABLE ENERGY
TO REDUCE REGULATORY RISK
UTILITY PROFILE
New England Electric System
Since its first programs were launched in 1987, New England Electric System (NEES)
companies continually to establish new environmental initiatives that reflect a commit-
ment to providing electric service in an environmentally sustainable way. The NEES
companies have developed a broad mix of energy efficiency and renewable energy
efforts, and boast one of the country’s largest demand-side management programs
(DSM), relative to its size.
The NEES companies have initiated efficiency programs that will save as much
energy as produced by a large fossil-fuel generating unit. Residential DSM programs
include appliance recycling, electric space heat conversions, energy efficient home
construction, lighting retrofits and more. NEES’ commercial and industrial DSM programs
promote efficient design and construction practices.
In collaboration with the Conservation Law
Foundation, NEES developed NEESPLAN 4, a plan that
reaffirms energy efficiency and renewable energy
investment as environmentally responsible initiatives
and key components to minimize customer costs and
reduce future environmental risks. In 1992 NEES gener-
ating subsidiary New England Power Company an-
nounced that it will purchase 36,000 kilowatts of elec-
tricity from seven renewable energy plants. Projects
include the company’s first major windpower project,
as well as landfill methane, municipal solid waste,
waste heat to generate electricity. The projects are
estimated to reduce greenhouse gas emissions by over
500,000 tons (carbon dioxide equivalents) per year and
will reduce smog precursor emissions by over 4o0 tons per year. These renewable
initiatives will help NEES reach its goal of reducing net emissions of carbon dioxide and
other greenhouse gases by 20% from 1990 levels by the year 2000, and stabilizing at that
reduced level in the post-2000 period.
NEES also works internationally to offset greenhouse gases. One pilot project
involves working with a Malaysian timber harvesting firm to improve its harvesting practic-
es so that more unharvested trees survive, leaving more of the forest intact. This project is
expected to economically offset 300,000 to 600,000 tons of carbon dioxide.
NEES Appliance Recycling Prcgrorn

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PART V: BEYOND SO 2 : OTHER POLLUTANTS 73
NEES’ efforts take on special importance as New England faces stringent emission
reduction requirements under the Clean Air Act amendments. These environmental
investments will help NEES position itself to comply, not only with requirements flowing from
the 1992 Earth Summit agreement to stabilize greenhouse gas emissions, but with EPA’s
Clean Air Act regulations including the Acid Rain Program. Two NEES companies,
Massachusetts Electric and Granite State Electric, were already awarded 103 bonus SO 2
allowances from the Conservation and Renewable Energy Reserve. The companies were
rewarded for their efficiency efforts and a landfill methane renewable energy project.
Based on current estimates of future DSM energy savings and renewable energy addi-
tions, the NEES companies expect to be eligible for a total of 14,000 allowances from the
Reserve through 1999.
In addition to global and national opportunities for investment in pollution preven-
tion, there are local prospects as well. For example, NEES plans to participate in the new
Massachusetts Emission Reduction Credit (ERC) banking and trading program. The
ground-breaking ERC program allows inventoried sources of NOx, VOCs and CO in
Massachusetts to earn bankable and tradeable credits by reducing emissions before or
below regulatory requirements. Potentially credit-earning activities include utility DSM and
renewable energy.

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Conclusion
The market-based benefits of the Clean Air Act
incentives are ideal inputs for integrated resource
planning. By incorporating these benefits into the
planning process the true economic competitiveness of
energy efficiency and renewable energy is more fully
realized.
Photo courtesy of U.S. Department of Interior

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76 CONCLUSION
This Handbook described the un-
precedented opportunities offered by the
Clean Air Act Amendments of 1990 for
utilities to use energy efficiency and
renewable energy programs in their air
pollution compliance strategies. In
addition to the built-in incentive of sav-
ing allowances through avoided emis-
sions, the Clean Air Act provides two
other special incentives--the Conser-
vation and Renewable Energy Reserve
and Reduced Utilization.
Two Ways to Consider the
Benefits
As discussed in this Handbook,
the link between energy efficiency and
renewable energy and acid rain compli-
ance for electric utilities is important for
two reasons. First, these technologies
can be part of a least cost compliance
strategy. For some utilities, efficiency
and renewable energy may complement
other compliance options such as fuel
switching, co-firing with natural gas, or
allowance trading. Ultimately, utilities
should explore the synergies between all
compliance options to find the least-cost
portfolio.
Second, the SO 2 reduction bene-
fits of efficiency and renewable energy
can make these energy resources more
cost effective and can even turn non-
cost effective programs into viable ones.
The quantifiable costs of generating SO 2
feed directly into electricity planning
mechanisms such as cost effectiveness
tests, program design, bidding schemes,
and buyback rates. Even in States
where the inclusion of environmental
externalities in resource planning deci-
sions is controversial, the inclusion of
the market-based costs of SO 2 emis-
sions in resource decisions should be
acceptable to State regulators.
Beyond SO 2
The methodologies outlined in
this handbook may be easily adapted to
calculate the quantities and impacts of
emissions other than SO 2 . In some
areas of the country, avoided NOx emis-
sions may soon provide an additional
market-based incentive for energy effi-
ciency and renewable energy. In addi-
tion, States with externality values may
use the method outlined in the Hand-
book to calculate the avoided emissions
of additional pollutants.
Integrated Resource
Planning is the Key
Integrated Resource Planning
(IRP) provides an ideal mechanism for
utilities and state regulators to develop
and evaluate acid rain compliance strat-
egies. Even where the value of saved or
earned allowances has only a modest
effect on the cost effectiveness of renew-
able energy or energy efficiency resourc-
es, compliance planning should incorpo-
rate many of the same qualitative vari-
ables necessary for good resource plan-
ning. Factors such as diversity and
modularity of technology and the con-
sideration of risk are as important for
compliance planning as they are for
resource planning. These factors, which
may have a big impact onftaure costs
faced by a utility and its ratepayers,
often favor the use of energy efficiency
and renewable energy.
Finally, the extent to which utili-
ties receive the emission reduction ben-
efits of energy efficiency and renewable

-------
energy will depend upon the policies of
state regulators toward these technolo-
gies. Special bonus allowances for ener-
gy conservation and renewable energy
are available only to utilities that have
implemented least cost integrated re-
source planning. In addition bonus
allowances for energy efficiency pro-
grams only will be awarded to utilities
whose state regulators have taken mea-
sures to make conservation profitable.
These eligibility requirements do not
apply to utilities seeking to save allow-
ances through avoided emissions. How-
ever, utilities in States that lack these
regulatory reforms are not likely to pur-
sue energy efficiency and renewable
energy resources and to benefit from
their emission reductions.
CONCLUSION 77

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Endnotes
1. These reductions are relative to 1980 emission levels. The reductions will he achieved incrementally
beginning in 1995 and reaching targeted levels by 2010.
2. Units affected by Phase I are allocated allowances equal to the average of the 1985-87 heat input
multiplied by a 2.5 lbs S0 2 /mmBtu emissions rate. Phase II allocations are derived from this baseline
times a 1.2 lb S0 2 /mmBtu.
3. Electric Power Research Institute, Integrated Analtjsis of Fuel. Technology and Emission Allowance
Markets: Electric Utility Responses to the Clean Air Act Amendments of 1990, Report no. TR- 102510,
August 1993. P. 1-20.
4. National average emission factors - 1990 (per kWh sold)
Percent of CO 2 NOx SO 2
Fuel type Generation ( lb/kWh) ( lb/kWh) ( lb/kWh )
Coal 53% 2.4 0.0088 0.017
Fuel Oil 4% 2.0 0.0042 0.0 12
Gas 9% 1.3 0.0046 0
Other 34% 0 0 0
National Average 1.5 0. 0055 0.0099
* SO 2 emission rate for coal is an average of the 1990 value of 0.022 lb/kWh and a
projected 2000 value of 0.0 12 lb/kWh.
5. US EPA, Conservation VerifIcation Protocols, Document no. EPA 430/8/B-92-002, March 1993. Also,
California public Utility Commission, Protocols and Proced ures for the Verffication qf Costs. Benpfits. and
Shareholder Earnings from Demand-Side Management Programs, October 29, 1992. Also, New Jersey
Board of Regulatory Commissioners, Measurement Protocol for Commercial. Industrial and Residential
Facilities, April 28, 1993.
6. US EPA, The User’s Guide to the Conservation Verification Protocols, Document No. EPA 430-B-93-002,
April 1993.
7. Net income neutrality applications should be sent to: U.S. Department of Energy. EE- 14, 1000
Independence Ave., SW, Washington, DC 20585.
8. On November 18, 1993 EPA proposed some revisions to the Reduced Utilization requirement. These
revisions are expected to be finalized in the spring of 1994. For more information see 58 FocI. Rep.
60950, November 18, 1993.
9. If the utility shifted a portion of the generation to sources outside of the utility’s system, then
allowances for that portion must be surrendered at the average emission rate for the NERC region.
10. In general, sulfur-free generation includes renewable energy resources. However, in certain cases,
such as some forms of geothermal and biomass production, the resource may not quali1 r as sulfur-free
generation. This distinction between renewable energy generation and sulfur-free generation only applies
to the Reduced Utilization provision.

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__ ,9j ENDNOTES
11. U.S. Environmental Protection Agency, Conservation VerifIcation Protocols, EPA 430-8-B-92-002,
March 1993 and The User’s Guide to the Conservation Verification Protocols, EPA 430-B--93-002, April
1993.
12. This determination is made after adjusting for any system-wide sales declines and any shifts to
compensating units.
13. This weighted-average heat rate is only an approximation. The Reduced Utilization provision
actually requires the kWhs from energy efficiency and sulfur-free generation to be converted by the heat
rate of a specffic Phase I unit. Thus, in order to maximize the benefits of energy efficiency and sulfur-free
generation, the utility would assign these resources to the Phase I unit with the greatest heat rate.
14. Also see: Alliance to Save Energy, Impacts of Demand-Side Management Programs on the Environ-
ment, June 1993, Washington, DC.
15. If the utility shifted a portion of the generation to sources outside of the utility’s system, then
allowances for that portion must be surrendered at the average emission rate for the NERC region.
16. Because retail rates are often higher than the avoided costs, customers who self-generate can benefit
more by offsetting their own energy use. The avoided SO 2 emission cost may not be relevant if the
renewable generation is only for the customer’s own use. However, customer self-generation projects will
often combine self-use with the sale of excess power to the utility grid. For these combined-purpose
projects, utility avoided costs may affect project viability and project size.
17. For a complete description of the RECLAIM program, see RECLAIM, Development Report and
Proposed Rules, Volume I, October 1993.
18. The increased energy demand for the control technology may increase the net emissions of other
gases such as CO 2 .

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Appendix A
Production-Simulation Modelling
Data Needed for Typical
Production-Simulation Model
I Monthly load shapes
I Annual peak and energy forecast
/ General and fuel escalation rates
/ Existing plant data: emissions, heat rates, capacity, fuel types, etc
/ Data on expected plant additions
/ Annual changes to system (retirements, etc.)
/ Seasonal capacity variations
/ Purchases and sales data
/ Scrubber data
/ Cost of emissions ($/lb)
/ Assignment of hours to time-of-use periods

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_ . JAPPENDIX A
Steps in a Parametric Analysis
Parametric analysis can be a useful tool in situations in which either the utility does not
have efficiency and renewable energy programs already planned, or the analyst
wishes to evaluate how changes in program load shapes or energy and capacity
impacts would affect the levels of emissions that are avoided.
STEP U
Determine type of program(s) to model. The analyst might choose to model a
typical complement of efficiency or renewable energy programs that includes
some base-load, intermediate-load, and peak-reduction components. The
analyst could also model individual programs of special interest, e.g., off-peak
promotion, to determine their emissions impacts.
STEP 2:
Determine the level of capacity saved or generated. For example, a moder-
ately aggressive DSM scenario for the near-term time horizon might be expect-
ed to decrease peak load by about ve percent. Larger and smaller decre-
ments can be used. Individual technologies or programs should be assigned a
proportion of the savings.
STEP 3:
Develop a load shape reflecting the capacity and energy savings for each
demand-side and renewable energy program. The load shape of the program
depends on the characteristics of the technology included. Base, intermediate,
and peak-reducing or generating technologies each possess their own unique
load shape. Input to production-simulation model.
For each supply-side efficiency program, determine the change in heat rate
expected as a result. Input changes to production-simulation model.

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APPENDIX A 83
Publicly Available Data Sources for Production-Simulation
Modeling
a Energy Information Administration, U.S. Department of Energy, Form EIA-
767, Steam-Electric Plant Operation and Design Report’.
Projected Fuel Consumption
Plant Configuration
Boiler Information
Air Emission Standards and Design Parameters
Plant Information
Fuel Type and Consumption
Generator Information
Flue Gas Desulfurization Information
J Office of Energy Emergency Operations. U.S. Department of Energy,
Form IE-411.
Capacity Purchases and Sales
Existing Generation Capacity
Future Generating Capacity Installations, Changes, and Removals
Actual and Estimated Net Energy and Peak Demand
Federal Energy Regulatory Commission, FERC Form No. 1: Annual Report
of Major Electric Utilities, Licensees, and Others.
Plant Statistics (e.g. heat rate, net generation)
a Electric Power Research Institute, TAGTM Technical Assistance Guide: Elec-
tricity Supply
General Plant Performance Data
General Economic Factors
j Edison Electric Institute
Load Data

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Appendix B
Conservation and Renewable Energy
Reserve Application Form

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Acid Rain Program
&EPA Instructions for
Conservation/Renewables Reserve Form
(40 CFR Part 73.80, 73.81, and 73.82)
The Energy Conservation and Renewable Energy Reserve Program provides a 300,000 allowance reserve for
utilities employing qualified energy conservation measures or renewable energy generation. To apply for
allowances from the Reserve, you must submit the Conservation/Renewables Reserve form.
EPA will accept submissions each July 1 following the year for which you are claiming energy savings or
generation, beginning on July 1, 1993. Forms received before July 1 will be deemed to be received on July 1.
EPA will accept Conservation/Renewables Reserve forms until it has allocated all 300,000 allowances or until the
year 2010, when the Reserve will be terminated.
EPA will render a decision whether submissions meet the specified requirements within 120 days of receipt.
If the applicant is a state rate-regulated, investor-owned utility and is undertaking conservation measures for the
purpose of receiving Reserve allowances, EPA ‘s approval will be conditional upon certification of net income
neutrality by the Secretary of the U.S. Department of Energy. For a complete description of the Conservation and
Renewable Energy Reserve allowance program mandated by Sections 404 (f) and (g) of the Clean Air Act
Amendments, see 40 CFR Part 73.
Type or complete the form using black ink. If you need more space, add pages in the appropriate format or
photocopy the pertinent page. When you have completed the form, indicate the page order and total number of
pages 1 of 4, 2 of 4, etc.) on each page in the spaces provided at the top right hand corner of the page.
STEP 1 Enter the name of the electric utility that is applying for the reserve allowances and list the state(s) in
which the utility operates.
STEP 2 List the name and phone number of the person(s) EPA should contact for clarification.
STEP 3 To qualify for reserve allowances, the applicant, any subsidiary of the applicant, or any subsidiary of the
applicant’s holding company, must own or operate, in whole or in part, an affected unit. You need to
list only one affected unit.
STEP 4 Applicants subject to the ratemaking jurisdiction of a State regulatory authority must use the verification
methodology approved by such authority provided that the ratemaking entity uses performance-based
rate adjustments (see 40 CFR 73.82(c)(1)).
All other applicants must submit documentation to EPA to verify savings; these applicants may use the
EPA Conservation Verification Protocol. These applicants must submit the documentation with this form.
STEP 5 At “Type of measure or program,” enter a descriptive name associated with the energy conservation
measure or program. If a group of measures are combined for monitoring purposes, you may enter the
overall name of the program. For instance, a group of energy savings measures you undertake in office
buildings may be termed “Building Retrofit.” For individual measures, use the terms given at 40 CFR part
73, Appendix A(1), if appropriate. You also may list a conservation measure not appearing in Appendix
A, provided it meets the requirements of 40 CFR 73.81 (a). List these measures using an appropriate
term.
If you are using industrial waste gases as a conservation method, include documentation to illustrate that
the use of such gases does not result in a net increase of sulfur dioxide emissions.
“Savings year” refers to the year for which you are claiming saving for the particular group of
installations. For instance, if in 1997 you are applying for credit based upon conservation achieved in
1995, the savings year is 1995. You may claim multiple years of savings for a measure, but should list
each year separately. You must have installed measures on or after January 1, 1992, to receive credit.
“Number of Installations” is the number of sites or devices installed with the conservation measure. This
value represents the total number of installations in operation during the savings year.
Total the energy savings from each conservation method, including those listed on additional pages, in
the “Total” box on the right hand side of the form.

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Page 2 Conservation/Renewables Reserve Form Instructions
STEP 6 This step converts the megawatt hours of generation saved to the tons of sulfur dioxide emissions
avoided due to conservation measures, as follows:
Tons of SO 2 = Step 5 Total (MWh) x 4 (lbsIMWh ) = Step 5 Total (MWh) X .002i i n
Avoided 2000 (lbs/ton) !L MWh
Round to the nearest tenth of a ton.
STEP 7 “Type of generation” refers to the renewable energy technology you employ. Use the terms listed at 40
CFR part 73, Appendix A, if such terms are appropriate. Eligible types of generation are: biomass (i.e.,
combustible energy-producing materials from biological sources, which include wood, plant residues,
biological wastes, landfill gas, energy crops and eligible components of municipal solid waste), solar,
geothermal and wind resources. You may list a type of renewable energy generation not appearing in
Appendix A, provided it meets the requirements of 40 CFR 73.81(c). List such measures using an
appropriate term.
At “Plant Name,” identify the plant at which the renewable energy generation took place. Use the plant
name from NADB or other appropriate name.
“Generation year” refers to the year for which you are claiming renewable energy generation. For
instance, if in 1997 you are applying for credit based upon generation achieved in 1995, then the
generation year is 1995. You may claim multiple years of generation, but should list each year
separately. You must have initiated the generation on or after January 1, 1992 to receive credit.
Total the renewable energy generation from each qualified method, including those listed on additional
pages, in the “Total” box provided on the right hand side of the form.
For hybrid renewable energy systems, the amount of generation is the MWh that can be attributed to the
qualified renewable energy measure. Include documentation showing the hybrid system’s total
generation, the heat input and heat rate attributed to the non-renewable portion of the generation, and
the calculations you used to determine the amount of qualified renewable energy generation.
Step 8 Include copies of pertinent plant operation records that substantiate the amount of renewable energy
generation claimed.
Step 9 This step converts the megawatt hours of renewable energy generation to the tons of sulfur dioxide
emissions avoided, as follows:
Tons of SO 2 = Step 7 Total (MWh) x 4 (Ibs/MWh ) = Step 7 Total (MWh) X . 002 j
Avoided 2000 (lbs/ton) MWh
Round to the nearest tenth of a ton.
STEP 10 This step sums the tons of sulfur dioxide emissions avoided from qualified conservation methods and
renewable energy generation. One allowance will be allocated for each ton of sulfur dioxide emissions
avoided due to these practices within the period of applicability (January 1, 1992, to the date on which
any unit owned or operated by the applicant becomes a Phase I or Phase II unit.) Allowances will not
be allocated for savings to be accrued in future years.
STEP 11 You must identify the allowance tracking account(s) to which the allowances from Step 10 are to be
distributed. Allowances may be distributed to one central account or to the accounts of individual units.
The subsequent transfer of Reserve allowances follows the same procedures as other allowances, as
specified in 40 CFR Part 73.
For approved applications, allowances from the Reserve will be transferred into the applicant’s allowance
tracking system account(s) beginning in 1995, provided that a sufficient number of allowances remain
in the Reserve. If less than a sufficient number of allowances remain, the allowances will be
proportionally distributed to the accounts.

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Conservation/Renewables Reserve Form Instructions Page 3
STEP 12 The entity with ratemaking authority for the utility must review the application. As the Step 12
certification states, the ratemaking entity for the utility must be able to certify that the least-cost plan
or least-cost planning process meets the following requirements of 40 CFR 73.82(a)(4)-(7):
• Provides an opportunity for public notice and comment.
• Evaluates the full range of existing and incremental resources in order to meet expected future
demand at lowest system cost.
• Treats demand-side resources and supply-side resources on a consistent and integrated basis.
• Takes into account necessary features for system operation such as diversity, reliability,
dispatchability, and other factors of risk.
• Is being implemented by the applicant to the maximum extent practicable.
• Is consistent with the energy conservation measures adopted and the renewable energy generated.
Further, the applicant must demonstrate that the qualified energy conservation measures adopted and
qualified renewable energy generated are consistent with the least-cost plan or least-cost planning
process.
The ratemaking entity also must be able to certify that measures not included in Appendix A of Part 73
meet the following requirements of 40 CFR 73.81 (a)(2) and (c)(2):
• The measures must be consistent with an applicable least-cost planning process.
• The measures must be implemented pursuant to approval by the utility regulatory authority.
• A qualified conservation measure must be a cost-effective demand-side measure that increases the
efficiency of the customer’s use of electricity (as measured in accordance 40 CFR 73.82(c)) without
increasing the use by the customer of any fuel other than qualified renewable energy, industrial
waste heat or industrial waste gases.
• A qualified renewable energy measure must be derived from biomass (j . ., combustible energy-
producing materials from biological sources, which include wood, plant residue, biological wastes,
landfill gas, energy crops, and eligible components of municipal solid waste), solar, geothermal, or
wind resources.
STEP 13 The certifications arise from the regulatory requirements.
Only a utility may qualify for the Reserve (40 CFR 73.82(a)(1 )).
If your application indudes an energy conservation measure and the utility is investor-owned, you must
provide the necessary information to enable the U.S. Secretary of Energy to certify that the State
regiiatory authority has established rates and charges that ensure net income neutrality (40 CFR
73.82(a)(9)). You must submit this information to the Department of Energy directly and not through
EPA.
Consistent with 40 CFR 73.82(a)(3), you must certify that the utility “is paying in whole or in part for
one or more qualified energy conservation measures or qualified renewable energy generation (that
became operational during the period of applicability) either directly or through payment to another
person that purchases the qualified energy conservation measure ci qualified renewable energy
generation.
Measures that are installed before January 1, 1992, or after one of the utility’s units becomes a Phase
I or Phase II unit do not qualify for the Reserve bonuses (40 CFR 73.80(b)).
Independent power producers that sell qualified energy generation to another utility must submit
documents to indicate the energy was purchased according to the purchasing utility’s least cost planning
process (40 CFR 73.82(a)(8)).
Enter the name of the individual who will act as the certifying official for the Utility.

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Page 4 Conservation/Renewables Reserve Form Instructions
Submission Instructions
To obtain allowances from the Conservation and Renewable Energy Reserve, you must submit this application to
the following address:
U.S. ENVIRONMENTAL PROTECTION AGENCY
ACID RAIN DIVISION, 6204J
ATTN: CONSERVATION AND RENEWABLE ENERGY RESERVE
401 M STREET, SW
WASHINGTON, DC 20460
Paperwoik Bwden Estimate
The burden on the public for collecting and reporting of information under this request is estimated at 78 hours. Send
comments regarding this collection of information, including suggestions for reducing the burden, to: Chief, Information Policy
Branch (PM-223), U.S. Environmental Protection Agency, 401 M Street, SW, Washington, D.C. 20460; and to: Paperwork
Reduction Project (OMB#2060-0258), Office of Information and Regulatory Affairs, Office of Management and Budget,
Washington, D.C. 20503. Do not send your forms to these addresses; see submission instructions, above.

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9EPA
STEP I
Identify the applicant
STEP 2
Enter information for the
person completing this form
STEP 3
Identify any affected unit
owned or operated by the
applicant by plant name
from NADB and allowance
tracking system account ID#
United States
Environmental Protection Agency
Acid Rain Program
0MB No. 2060-0258
Expires 1-31-96
ENERGY CONSERVATION MEASURES AND VERIFICATION
STEP 4
Mark the appropriate box
STEP 5
Enter the requested
information for each type of
conservation measure
employed. Total the
savings and round to the
nearest MWh. If more
space is needed, add pages
in the appropriate format
STEP 6
Convert total from Step 5
to tons of sulfur dioxide
emissions avoided by
multiplying Step 5 total by
.002 tonslMWh. Round to
the nearest tenth of a ton
RENEWABLE ENERGY GENERATION
STEP 7
Enter the requested
information for each type of
renewable energy
generation measure
employed. Total the
generation and round to the
nearest MWI . If more
space is needed, add pages
in the appropriate format
STEP 8
Mark box and attach
documentation
STEP 9
Convert the total from Step
7 to tons of sulfur dioxide
emissions avoided by
multiplying Step 7 total by
.002 tons/MWh. Round to
the nearest tenth of a ton
Verification of conservation measures performed by
L I I State U.S. EPA (Attach documentation verifying energy savings)
I tons 1
Savings Number of
Year Installations
Generation Energy Generation
Year (MWh)
Conservation/Renewables Reserve
For more information, see instructions and refer to 40 CFR 73.80, 73.81 and 73.82
This submission is: LII New [ I] Revised
Page
Page 1
of [ 11
Utility Name
State(s)
Name
Phone
Plant Name
ATS Account ID#
Type of Measure or Program
Energy Savings
(MWh)
I to:1
TOTAL
I I
Type of Generation
Plant Name
LII I have attached documentation to verify the amount of renewable energy generation
TOTAL
EPA Form 7610-10 (1-93)

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TOTAL RESERVE ALLOWANCES
Utility Name (from Step 1)
Conservation - Page 2
Page LI of LIII
STEP 10
Add together the Step 6
and Step 9 entries; round
result to the nearest ton
and convert tons to
allowances (1 ton = 1
allowance)
STEP 11
Identify the allowance
tracking account(s) and the
number of earned reserve
allowances to be allocated
to each account. The total
must equal the number
entered at Step 10
STEP 12
Submit application to
the appropriate
ratemaking entity for
approval
CERTIFICATION BY CERTIFYING OFFICIAL FOR THE UTILITY
STEP 13
Read the certifications
and sign and date (see
instructions)
I certify that the following requirements have been met:
(1) Applicant is a utility as defined in 40 CFR 72.2.
(2) If the applicant is an investor-owned utility submitting an application based on an energy conservation
measure, The Department of Energy has certified the fulfillment of the net income neutrality requirement, or
such certification is pending.
(3) Applicant has met requirements for payment of conservation measures in 40 CFR 73.82(a)(3).
(4) The qualified energy conservation or renewable energy generation measures are installed and operational
on or after January 1, 1992. and before the date on which any Unit owned or operated by the applicant
becomes a Phase I or Phase II unit.
(5) If the applicant is an independent power producer and sells qualified renewable energy generation to
another utility, the generation was sold pursuant to the purchasing utility’s least cost plan. Applicant has
submitted supporting documentation.
I certify under penalty of law that I have personally examined, and am familiar with, the statements and
information submitted in this document and all its attachments. Based on my inquiry of those individuals
with primary responsibility for obtaining the information, I certify that the statements and information are to
the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant
penalties for submitting false statements and information or omitting required statements and information,
including the possibility of fine or imprisonment.
allowances
Allowance Tracking System Account Number
Allowances
CERTIFICATION BY RATEMAKING ENTITY
TOTAL
I certify, as the appropriate representative of the applicant’s ratemaking entity, that the applicant’s least cost
plan or least cost planning process meets the requirements of 40 CFR 73.82(a)(4), (5), (6) and (7), and
if the applicant is claiming savings for a conservation or renewable energy measure not listed in Appendix A
of 40 CFR Part 73, the measure meets the criteria of 40 CFR 73.81(a)(2) or 40 CFR 73.81(c)(2).
If the ratemaking entity performs verification (Step 4 is marked “State”), I also certify that the verification
procedures meet the ratemaking entity’s requirements and the information and calculations contained in this
form are correct and accurate.
Name of Certifying Official
Phone
Name of Regulatory Body
Signature
Date
Name of Certif ng Official Title
Signature Date
EPA Form 7610-10 (1-93)

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