Regulatory Impact Analysis of the Final
Acid Rain Implementation Regulations
Prepared by:
ICF Incorporated
under
EPA Contract 67-DO-0102
Work Assignment 29
Prepared for:
Office of Atmospheric and Indoor Air Programs
Acid Rain Division
U.S. Environmental Protection Agency
October 19, 1992
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EXECUTIVE SUMMARY
1. background
Acid rain (and other forms of wet and dry acid deposition, including snow, fine particulates
and gases) is suspected of causing serious damage in a variety of areas: aquatic and terrestrial
ecosystems, construction and cultural materials (such as metals, wood, paint, and masonry), and public
health. In addition, the gaseous pollutants that promote acid rain have been linked to local ozone
buildup, suspended particulate matter, and reduced visibility. Of the three pollutants that are
generally considered to be most heavily involved in the formation of acid rain. SO-, and NOx arise
almost entirely from power plants and motor vehicles.
After more than a decade of clean air bills and proposals. President Bush signed the Clean
.Air Act (CAA) Amendments of 1990 (P.L. 101-549) into law on November 15. 1990. Title IV of the
Clean Air Act (the acid rain title) set three major goals: (1) a reduction in SO, emissions of 10
million tons per year below 1980 levels by the year 2000: (2) a nationwide cap on SO-, emissions
beginning in the year 2000; and (3) a two million ton reduction in NOx emissions. These goals are
to be met through a two-phased program. In Phase I (beginning in 1995), part of the SO, and NO
reductions are to be achieved through emissions reduction requirements at the largest, highest-
emitting power plants. During Phase II, the S02 and NOx reduction goals are to be reached through
more stringent requirements at virtually all fossil fuel power plants and through other parts of the
CAA amendments.
An important feature of the Acid Rain Program is a system of allowance allocation and
trading. The provisions of Title IV that establish this system represent a significant departure from
the more traditional "command and control" approach to regulation. Command and control
regulations typically set specific emissions standards that must be met on a source-by-source basis.
Under the Acid Rain Program, however, units at sources are not assigned rigid emissions limits.
Instead, each unit is allocated transferable emissions "allowances," each of which permits the holder
to emit one ton of S02. If the number of tons of S02 emitted by a unit exceeds its allocated
allowances, it can still comply with the program by obtaining additional allowances from units whose
emissions are smaller than their allowance allocations. This transferability creates a potential market
for emissions allowances, in which allowances may be bought, sold, auctioned, and banked from year
to year by SO, emitting units or by any party outside of the regulated community. The flexibility
allowed by this system is expected to lower the costs of reducing emissions considerably, since the
emissions reductions at the units with the lowest costs of control will be able to substitute for the
more costly emissions reductions by other units that would otherwise have been required.
The regulations covered by this regulatory impact analysis are
• permitting;
• the allowance system (including conservation and renewable resources, auctions, sales,
and IPP guarantees); and
• emissions monitoring.
ES-1
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These provisions are essential to making the allowance trading program functional and effective.
They ensure that emissions are accurately measured, the program's provisions can be enforced, and
that allowances are generally available, even to those entities that do not receive allowance
allocations. Other provisions enhance the overall goals of the Acid Rain Program bv encouraging
emissions reductions through reductions in electrical generation, the substitution of renewable
resources for fossil fuels, and the inclusion of additional electricity sources.
2. Purpose and Scope of this Report
This regulatory impact analysis (RIA) was developed in response to Executive Order (EO)
12291. which requires Federal Agencies to assess the costs, benefits, and impacts of all "major"
regulations. Under EO 12291. any regulation likely to result in an annual effect on the economv of
$100 million or more is considered a "major" regulation. While the proposed regulations
implementing the allowance allocation and trading system are expected to reduce costs rather than
increase them, the net costs of emission reductions imposed by the statute itself are expected to be
large enough to fit the definition of a major regulation. EPA has therefore decided to treat the
proposed regulations as a major rule for the purposes of EO 12291.
In compliance with EO 12291. this RIA assesses costs, benefits and impacts for the important
provisions of Title IV. Its scope excludes those parts of the program not yet completed: the NOx-
related provisions, and voluntary inclusions of additional sources (opt-in). Also excluded are analvses
of a set of implementation issues (including the question of serialization of allowances: end-of-year
"truing up" periods, and other issues related to permits and monitoring). While no dollar values could
be assigned to these implementation issues, they are discussed in the preamble to the implementation
regulations.
EPA divided its analysis of the Acid Rain Program into two parts. First, EPA analyzed the
effects of the statute in the absence of any implementation regulations. This analysis was performed
by defining and examining the "absent regulations" case, in which a 10 million ton reduction in S02
emissions is mandated by statute, but there are no implementation regulations to establish an acid
rain program that allows for allowance trading, special compliance plans, or application for alternative
monitoring programs. EPA compared this "absent regulations" case to a "pre-Statute" case (in which
no emissions reductions would be required) to show the incremental costs of the SO, reductions
without the implementation regulations.
In the second part of the analysis, EPA examined a "regulatory" case that included both the
SO, reductions and the implementation regulations. By comparing costs under the regulatory case
to those under the absent regulations case, EPA was able to isolate the incremental savings provided
by the regulations. At the same time, by combining the two parts of the analysis. EPA was able to
show the total costs imposed by the Acid Rain Program (the statute and the regulations) as a whole.
3. Industries Affected by the Acid Rain Program
Title IV directly affects utility units providing power to generators that produce electricity
commercially. Most utility units belong to the electric utility industry and are either investor-owned
or publicly-owned, such as the Tennessee Valley Authority. The utility industry currently accounts
for the vast majority of the generation capacity in the U.S. A growing share of generating capacity,
however, is being owned by independent power producers (IPPs) and other entities outside of the
conventionally-defined utility industry.
ES-2
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The characteristics of electric utilities vary widely in terms of institutional and regulatory
arrangements, size, power plant types, fuel consumption, and power supply cost structure. Utilities
are currently highly regulated at both the state and federal levels, but the regulatorv climate is
gradually shifting toward less regulation and more competition.
The electric utility industry is composed of about 3.000 companies. Most of these are
municipallv-owned utilities or rural electric cooperatives, which are generally very small in terms of
electricity generation. A relatively small number of utilities (about 200) are investor-owned; these,
however, account for about three-quarters of the total electricity generated in the U.S. Exhibit ES-1
provides an overview of the electricity generating sector.
Most U.S. electric utilities have monopolies (known as franchises) provided by state or local
authorities and arc the only supplier of electric power within their service territories. In exchange
for the advantages conferred by the franchise, the utility subjects its rates to regulation bv state
authorities. Rates for investor owned utilities are set to allow them to recover all of their costs (so
long as these costs were "prudently incurred") and make limited profits as well.
Phase I of the Acid Rain Program affects units owned by 61 different utilities, with a total
installed capacity of 88,977 megawatts MW; Phase FI affects units owned by 239 different utilities
representing 471,445 MW of capacity. Exhibit ES-2 shows the breakdown of these utilities by size
and type of owner.
Almost 70 percent of the electricity currently generated in the U.S. is produced using coal and
other fossil fuels. The rest is produced using nuclear power, hydropower, or other energy sources
that are not regulated by Title IV. Regional differences in fuel types are substantial: oil and gas
fueled generation serve as the dominant capacity sources in several regions including New England
and the Pacific, while coal is the most important source in other areas including the Midwest. The
regional mix in fuel use has important implications for regional S02 emissions, acid rain control costs,
and electric rate impacts.
A significant amount of electric generation capacity owned and operated by private
developers, rather than by the regulated utilities, has come on line over the last decade. The total
amount of generation from this capacity was about 199,000 MW, or seven percent of total U.S. utility
generation. Plants burning natural gas, coal, and biomass are the most common types of generators
outside of the conventionally-defined utility industry. Projects burning waste products also provide
substantial capacity, as do plants utilizing hydro and wind resources.
In addition to the industries that are regulated under Title IV, a number of other industries
could be affected indirectly. The coal industry is the most important example of an indirectly affected
industry because of the fact that most of the coal industry's output is sold to utilities. Pollution
control equipment manufactures, the bulk transportation industry, and some industries that use large
quantities of electricity, could also be affected indirectly.
ES-3
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EXHIBIT ES-I
U.S. Installed Generating Capacity by Industry Type
(Gigawatts)
1979 1986 1987 1988 !
Total U.S. F.lectnc Utility
Industry
Investor Owned Utilities
Municipals, ('.imperatives.
Federal, and Public Power
.
598
464
134
710 718 724
; :
546 , 553 j 558
164 165 166
j
Total Non-Generating
Industry
18
25
:
30 34 ;
!
Source: "1988 Capacity and Generation of Non-Utility Sources of Energy," Edison Electric Institute. April, i
1990. 1
Note: 1 gigawatt equals 1000 megawatts or 1 million kilowatts. !
4. Costs of the Program
In estimating the effects of the Acid Rain Program, EPA divided costs into two broad
categories: costs related to S02 emissions reductions, and costs related to regulatory implementation.
Costs in these categories were estimated for the absent regulations case compared to the pre-statute
case; for the regulatory case compared to the absent regulations case; and for the regulatory case
compared to the pre-statute case. In addition, each case was estimated under a high and low scenario
representing different assumptions about energy demand growth and other factors that could affect
emissions. The time frame for the analysis of emissions reduction costs is the 18-year period from
1993 through 2010. To cover this period, EPA analyzed four discrete points in time: 1995 (the
beginning of Phase I); 2000 (the beginning of Phase II); 2005; and 2010.
The costs of S02 emissions reductions were estimated with a detailed linear programming
model that computes the utility industry's lowest cost responses to the emissions control requirements
under each case. EPA estimated total costs (that is, the present discounted value of costs over the
18-vear period 1993 through 2010) for both the absent regulations case and the regulatory case. The
total costs of the S02 reductions mandated by the statute were estimated to range from $19.1 to
$30.9 billion without the regulations, compared to only $9.5 to $17.1 billion with the regulations (see
Exhibit ES-3a). Comparing the total costs with and without the regulations showed that a well-
functioning allowance trading system would reduce the costs of the 302 emissions reductions
mandated by the statute by $9.6 to $13.8 billion.
ES-4
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EXHIBIT ES-2
Characterization of Affected Existing L'tility-Owned Units
Phase I
Type of Ownership
# of
Utilities
# of
Units
Phase II
Capacity I # of I # of j Capacity
(GW) Utilities j Units j (GW)
Federal and Public Power
Entities, State and District
Systems
26
13 | 116
.is
Cooperative Systems
15
27 ! 89
SJ)
Investor-Owned Systems
52
216
75
132
1,517
392
.! Municipal Systems
TOTALS
61
261
89
67
239
183
1,905
24
471
Source: National Allowance Data Base Version 1.0 and ICF Analysis of the Clean Air Act Amendment of
IWO.
In addition to the costs of reducing S02 emissions, the implementation regulations would
impose some additional costs. The auctions, direct sales, and IPP written guarantee provisions, which
are intended to aid in the development of an allowance market and ensure the availability of
allowances, would add between two and eight million dollars to the total costs of the regulations
(where, again, the total costs were measured as the discounted present value of costs over the 18-year
period from 1993 through 2010). Operating the conservation and renewable energy program would
cost a total of between $1 and $2 million. The total costs of the allowance tracking system would also
be relatively small, at $4 to $6 million, while the total costs to the regulated community of arranging
allowance transactions could range from $200 to $400 million. The total costs of the continuous
emissions monitoring program was estimated at approximately $2.4 billion. The monitoring costs,
however, are actually lower in the regulatory case than in the absent regulations case. Finally, EPA
estimated the total cost of the permits program to be $68 million.
ES-5
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Exhibit ESoa presents the total cost estimates for the absent regulations case compared to
the pre-statute case, the regulatory case compared to the absent regulations case: and the regulatory
case compared to the pre-statute case. Overall, the acid rain statute (including the implementation
regulations) imposes total costs (measured as the present value of costs from 1993 through 2010) of
between 512.2 and 520.0 billion, while the acid rain regulations provide net savings of between 59.4
and S 1.1.4 billion. Exhibit ESob shows costs and cost savings on an annualized basis.
EXHIBIT ES-3a
INCREMENTAL TOTAL COSTS AND COST SAVINGS
(1993 to 2010, in Millions of 1990 dollars)'1
Costs of SO-,
Reductions without
Implementation
Regulations11
Costs of SO-,
Reductions with
Implementation
Regulations'3
J
Cost Savings J
Provided bv Imple-
mentation
Regulations'1 .j
Cost of SO,
Reductions
$19,100 to $30,900
$9,500 to $17,100
¦1
$9,600 to $13,800
;j
1 Implementation
!|
Allowance System'
• Trans/Tracking
• A/S/IPPG
• Con/Ren Energy
SO
so
so
S204to S406
S2 to S8
SI to S2
-S204 to -S406 ;
-S2 to -SN
-SI to -S2 !
CEMS
S2.512
S2.395
SI 17
Permits
SO
S68
-S6S *
Subtotal:
$2,512
$2,670 to $2,879
-$158 to -$367
Total Costs/Savings
$21,612 to $33,412
$12,170 to $19,979
$9,442 to $13,433
Total costs are present values of costs incurred in each year (with capital costs annualized at 7 percent per year)
discounted to 1992 at 3 percent per year. Annualized costs are computed using the total costs and a discount
rate of 3 percent per year.
Ranges cover EPA Low Scenario and High Scenario.
Includes: Allowance Transactions/Tracking. Auctions/Sales/ [PP Guarantees, and Conservation/Renewable
Energy
ES-6
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EXHIBIT ES-3b
INCREMENTAL ANNUALIZED COSTS AND COST SAVINGS
(1993 to 2010, in Millions of 1990 dollars)a
•
Costs ot" SO-,
"
Costs of SO,
Cost Savincs
Reductions without
Reductions with
Provided by Imple- !
Implementation
Implementation
mentation
Regulations'3
Regulations'3
Regulations'1
Cost of S02
Reductions
S 1,400 to $2,300
$700 to $1,300
$700 to S 1,000
: Implementation
i
Allowance System'
• Trans,Tracking
• A/S/IPPG
SO
SO
so
S 14.8 to S29.5
S0.1 to S0.6
S0.1
-S14.N to -S29.5
-S0.2 to -S0.6 ,
-SO. 1 j
• Con/Ren Energy
CEMS
S 182.6
S 174.1
-S8.5
Permits
SO
S4.9
-S4.9
Subtotal:
$182.6
$194.0 to $209.2
-$11.5 to -$26.6
Total Costs/Savings
$1,583 to $2,483
$894 to $1,509
¦ i
$689 to $973
Annualized costs are computed using the total costs and a discount rate of 3 percent per year. Total costs are
present values of costs incurred in each year (with capital costs annualized at 7 percent per year) discounted to
1992 at 3 percent per year.
Ranges cover EPA Low Scenario and High Scenario.
Includes: Allowance Transactions/Tracking, Auctions/Sales/ IPP Guarantees, and Conservation/Renewable
Energy
ES-7
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5. Impacts of the Acid Rain Program
EPA assessed the effects of the Acid Rain Program from four different perspectives: the
impacts of the costs and cost savings on the regulated community as a whole; on different regions
of the country: on entities outside the regulated community: and on smaller entities.
Nationwide Impacts on the Regulated Community
The annual Acid Rain Program costs, while large in absolute terms, are relatively small
compared to the roughly $200 billion annual costs of generating electricity. As shown in Exhibit
ES-4. the average costs (on a "levelized" basis) of generating electricity rise 0.5 to 0.7 percent
under the absent regulations case for 1995 under the high and low scenarios, respectively.
Average cost impacts for 2000, 2005, and 2010 are greater as a consequence of Phase II. but still
less than two percent of total costs. As with any average, these average cost estimates take into
account utilities with more significant cost impacts (e.g.. as high as ten percent or more in a few
cases) along with many others that are largely unaffected or experience cost reductions under the
absent regulations case.
The regulations provide cost reductions of less than a third of one percent of total
generation costs in Phase I and generally less than one percent in Phase II. Savings of this
magnitude amount to between one-fourth and two-thirds of the costs in the absent regulations
case, depending on the year and the scenario.
The aggregate impact of these cost changes on the financial health (in terms of net
income) of the electric utility industry is likely to be small. Because utility rates are tightly
regulated, cost increases are generally passed through to electricity consumers as price increases.
Costs for pollution control costs in particular have almost always been considered a necessary cost
of power production, and so are especially likely to be passed through. The utilities' margins are
therefore expected to be insulated to a certain extent from both cost increases and decreases.
EXHIBIT ES-4
AVERAGE NATIONWIDE PERCENTAGE CHANGE IN ELECTRICITY COSTS
(percent)
j
COSTS OF ABSENT
REGULATIONS CASE
(incremental to pre-
Statute case)
Low High
Scenario Scenario
COSTS OF
REGULATORY CASE
(incremental to pre-
Statute case)
Low High
Scenario Scenario
COST SAVINGS OF
REGULATORY
CASE
(incremental to absent
regulations case)
Low High
Scenario Scenario
1995 0.5 0.7
0.3 0.4
0.2 0.3
2000 | 1.3 1.9
0.5 0.8
0.8 l.l
2005 | 1.4 1.7
1.0 1.2
0.4 0.5
2010 0.9 1.5
0.4 1.1
0.5 0.4 !
ES-8
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In addition, because utilities are structured as regulated monopolies (as discussed in
Chapter 2), they are protected to a certain extent from losing customers to competitors with lower
rates. However, increasing deregulation of the industry and competition from independent power
and industrial cogeneration and self-generation make this protection somewhat limited in certain
cases. Nonetheless, consumers' responses to levelized average U.S. price increases or decreases in
the range of one-half to one percent may be considered insignificant by the utilities experiencing
these responses. Even higher rate increases on the order of five to ten percent would probablv
not substantially reduce consumer demand.
Cost changes cannot always be passed through entirely, however, because Public Utility
Commissions may disallow portions of the costs if it is determined that they were not prudently
incurred. For this reason, the regulations will reduce the utilities' exposure to potential financial
difficulties by minimizing the increase in their costs. Further, the regulations will tend to reduce
impacts on utilities that arise from lags in the rate-setting process. Because cost increases are not
always quickly translated into price increases, they can sometimes hurt profitability. By reducing
cost impacts, the regulations can minimize the effects of the lags in the rate-setting process.
Regional Impacts
The impacts discussed above are nationwide averages, and do not represent the impacts
faced by utilities in any one state or region. Given the significant differences in fuel mixes across
regions and the differential effects of S02 controls on power plants using different fuels, regional
impacts can be expected to vary widely.
Exhibit ES-5 shows the approximate percentage cost changes over the period 1995
through 2010 under the absent regulations and regulatory cases for the high scenario. The census
regions are listed in order of cost impacts, from lowest to highest. In general, the regions with
the highest cost impacts are those with the most affected coal-fired capacity and greatest required
SO, reductions. While the savings provided by the implementation regulations do not follow
exactly the same pattern, the four regions with the lowest costs do appear to have lower savings.
Similarly, the four regions with the highest cost impacts under the absent regulations case all have
relatively large savings under the regulatory case.
ES-9
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EXHIBIT ES-5
Costs of Absent Regulations and Savings with Regulations as a Percentage of Generation Costsa
(percent)
REGIONb
COSTS
¦
' SAVINGS
PACIFIC
0.2
¦
0.2
¦
NEW ENGLAND
0.5
0.2
LOW COST.
LOW SAVINGS
LOWER SOUTH
ATLANTIC
0.9
0.3
MIDDLE
1.1
03
ATLANTIC
MODERATE COST.
HIGH SAVINGS
MOUNTAIN
1.3
0.8
WEST SOUTH
CENTRAL
1.5
1.1
EAST SOUTH
2.0
0.7
CENTRAL
WEST NORTH
2.1
0.8
HIGH COST,
CENTRAL
HIGH SAVINGS
EAST NORTH
2.3
0.7
CENTRAL
UPPER SOUTH
2.4
0.5
ATLANTIC
Costs and savings were estimated by averaging estimates from 1995. 2000, 2005, and 2010 for the high scenario.
Regions listed in order of lowest costs to highest costs.
Secondary Effects
Title IV's direct effects reach only the nation's electric generation industry. As previously
discussed, however, the utilities are not likely to absorb much of the impact of the Acid Rain
Program. Instead, the impacts are likely to be passed on to other sectors of the economy: electricity
consumers, the coal industry, railroads and other transportation providers, oil and gas producers, and
emissions control manufacturers.
The costs of emissions reductions are likely to be passed on through increased electricity rates.
The increased costs will have very small impacts on the typical consumer: electricity is a minor part
of household budgets, and the changes in electricity bills will be small even in percentage terms.
Consumption will drop marginally as prices rise and consumers respond to avoid some of the
increased costs. Reducing electricity usage will impose real, though small, costs on consumers, as they
spend more to purchase energy-efficient appliances, and make other electricity-saving choices.
The increased electricity rates attributable to acid rain compliance could have more significant
impacts on those industries that are unusually large consumers of electricity, such as steel and
ES-10
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aluminum producers, though even in extreme cases total production costs for these industries will not
rise more than a few percent. Cost savings provided by allowance trading will tend to mitigate
somewhat the negative effects on industrial competitiveness and employment that might occur in the
absent regulations case as a result of electricity rate increases.
Neither the absent regulations case nor the regulatory case is likely to result in a significant
change in total consumption of coal for electricity generation. Considerable changes in the tvpe of
coal consumed may take place, as consumption shifts from high to low sulfur coals. Because the
implementation regulations allow many utilities to choose to avoid scrubbing if they switch to low
sulfur coal, coal production losses in high sulfur regions are likely to be higher in the regulator, case
than in the absent regulations case in 2005 and 2010.
Changes in regional coal production caused by the Acid Rain Program will affect the railroad,
trucking, and barge transportation industries as well as the coal industry. The total volume of rail and
barge shipments of coal is expected to increase under the absent regulations case. The regulations
will mitigate some of the increase in ton-miles hauled. Truck transportation of coal, on the other
hand, is expected to decline.
Some utilities that are currently burning oil are expected to switch to gas in order to reduce
SO-, emissions (the SO? emission rate of natural gas is virtually zero). As a result, gas producers are
likely to experience increased demand (and may receive higher prices) at the expense of oil
producers.
The Acid Rain Program is expected to lead to increased retrofit scrubbing at coal-fired power
plants. The increase in retrofit scrubbing will, in turn, lead to increased revenues tor scrubber
manufacturers, as well as increased revenues for lime/limestone producers whose products are
commonly used in scrubbers. Because there will be less scrubbing under the regulatory case than the
absent regulations case, revenues and employment in the air pollution control industry will not
increase as much in the regulatory case.
Impacts on Small Entities
For purposes of assessing the impacts of the Acid Rain Program on smaller entities, EPA has
adopted the SBA definition that a "small" electric power utility is one that generates a total of less
than 4 billion kilowatt-hours per year. Not all small utilities are affected by the acid rain title of
CAA. Utilities will be unaffected if (1) all of their units are exempt (e.g., units using non-fossil
sources or existing simple gas turbines), or (2) they fall below statutory minimums for electric
generating capacity (i.e., existing capacity below 25 MW). These unaffected utilities were excluded
from the analysis of impacts on small entities; an attachment to this document covers impacts on
utilities with new units under 25 MW capacity.
After excluding utilities exempt from the provisions of CAA. EPA determined that about 105
of the 241 Phase II affected utilities (about 44 percent) are small. (No small utilities are affected
under Phase I). Collectively, affected small utilities accounted for about 5 percent of total 19
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105) of the small utilities are run by municipal governments, while the comparable figure for large
utilities is only four percent (5 out of 132). Smaller utilities are more likely to depend exclusively on
either oil/gas or coal, rather than a combination of oil/gas and coal at different units; verv small
utilities are more dependent on oil and gas as opposed to coal. In addition, emissions from smaller
power plants tend to be relatively costly to control.
To examine the effects on small entities. EPA constructed six model small utilities of varying
fuel type and size to represent most of the small utility population. To allow for differences across
fuel types, two of the model utilities burn coal: two burn oil: and two burn natural gas. The two coal-
lired utilities are relatively "dirty," the two oil-fired utilities have moderate SO-, emissions rates, and
the two gas-fired utilities have virtually no SO-, emissions. EPA projected the most likely responses
of these model utilities under the absent regulations case and the regulatory case, and used results
from the analysis of the industry as a whole to predict the cost impacts of SOi reductions and the
implementation regulations on each model small utility.
EPA concluded that the Acid Rain Program would have very little impact on most small
entities, since they are either gas-fired (and therefore inherently low in emissions) or small enough
to quality to receive relatively large allocations of allowances. Some coal or oil-fired utilities that are
ineligible to receive additional allowances, however, might face substantial increases in their costs (as
high as ten to twenty percent in extreme cases) under the absent regulations case.
The implementation regulations are likely to result in substantial reductions in the costs
imposed by the statute on small entities. As a percentage of the costs under the absent regulations
case, the savings provided by the regulations may be in the range of 25 to 60 percent, which is similar
to the savings for larger utilities. Absolute savings measured in average levelized cents per kwh. on
the other hand, will typically be greater for small utilities (0.13 to 0.68 cents per kwh) than for larger
utilities (0.08 cents per kwh).
Virtually all of the impacts on small businesses are caused by statutory provisions of the Clean
Air Act. EPA is considering regulations that are intended to mitigate some of the burden on small
businesses. For new small utilities (i.e., less than or equal to 25 MW), EPA will grant an exemption
from the requirements of the Acid Rain Program if they can certify that they use very low sulfur fuel
(i.e., less than .05 lbs S02/mmBtu) and that they have a utilization of less than 10 percent. EPA will
do this to minimize the burden on small entities and because the emissions from small entities will
be negligible. The statutory provisions, however, restrict the amount of relief that can be provided.
ES-12
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CHAPTER 1
Introduction
EPA has prepared this Regulatory Impact Analysis (RIA) to accompany the Agency's
proposed regulations tor the implementation of Title IV of the Clean Air Act as amended (42 U.S.C.
7651 ct seq.), which imposes limits on emissions that cause acid rain. The RIA was developed in
accordance with Executive Order (EO) 12291, which requires federal agencies to assess the costs,
benefits, and impacts of all "major" regulations. Under EO 12291, a "major" regulation is defined as
one likely to result in any of the following effects:
• An annual effect on the economy of $ 1 (X) million or more;
• A major increase in prices for consumers:
• A major increase in costs to individual industries, geographic regions,
or federal, state, or local government entities; or
• Significant adverse effects on competition, employment, productivity,
innovation, or on the ability of U.S.-based enterprises to compete with
foreign-based enterprises in domestic or export markets.
If a rule is determined to be major, the issuing agency must prepare an RIA and consider its
results (to the extent permitted by authorizing legislation).
EPA does not anticipate major increases in prices, costs, or other significant adverse effects
due to the proposed regulations for the implementation of Title IV. Instead, EPA expects that the
flexibility provided by proposed regulations would result in a significant reduction in costs to the
economy, when compared to the costs of compliance with statutory emissions control requirements
in the absence of these regulations. Thus. EPA expects the proposed Title IV regulations to have
beneficial rather than harmful effects. Because the expected magnitude of the total costs of the Acid
Rain Program exceed $100 million per year, the proposed regulations are being treated as a major
rule for the purposes of EO 12291.
1.1 ACID RAIN REGULATIONS
1.1.1 History of Acid Rain Problem and Response
The acidification of natural atmospheric precipitation, commonly called "acid rain," is of
concern because of the potential adverse environmental impacts on natural ecosystems (including
aquatic life, wildlife, vegetation, forests, and agriculture), materials (such as metals, wood, paint, and
masonry), and general public health and welfare. In addition, the gaseous pollutants that are
suspected of promoting acid rain are also thought to be linked to certain other atmospheric problems,
such as local ozone buildup, suspended particulate matter, and reduced visibility.
Adverse effects of acid rain were initially observed in the late 1970s. Increasing Congressional
interest led to the passage of the Acid Precipitation Act of 1980 (Title VII of the Energy Security
Act of 1980. P.L. 96-294). This Act established an Interagency Task Force on Acid Precipitation.8
1-1
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which developed and implemented a comprehensive National Acid Precipitation Assessment Program
(NAPAP). This national program was designed to develop and progressively refine the scientific
understanding of the causes and effects of acid rain.
It is generally believed that three main precursor pollutants, sulfur dioxide (SO-,), nitrogen
oxides (NOx), and volatile organic compounds (VOC). are involved in the formation of acid rain.
While only about 40 percent of VOC emissions are of anthropogenic origin, the majority of SO-, and
NOx emissions are anthropogenic. For example, about 25 million tons of SO-, are emitted annually
in the U.S. result from human activity (about 70 percent from electricity generating power plants),
versus less than 500 thousand tons of annual natural SO-, emissions. As for NOx. of 22 million tons
emitted annually in the U.S. only about 3 million tons per year come from natural sources while
about seven million tons come from power plants.
Concern over local environmental conditions led several states to pass legislation during the
1980s requiring curtailments or caps on statewide S02 (and, in some cases. NOx) emissions.
However. Congress and others felt that state laws would only be partially effective in reducing the
impacts of acid rain. Furthermore. Canada became increasingly concerned with acid rain-related
effects on its lakes and other ecosystems, which it attributed in part to sources in the United States.
Because of acid rain's interregional (and international) nature, the debate over acid rain control
moved towards federal acid rain legislation. As a result, during the 1980s, various bills and proposals
for reducing SO-, and NOx emissions were put forth in Congress.
1.1.2 Clean Air Act Amendments of 1990: Summary oF Acid Rain Provisions
After more than a decade of clean air bills and proposals. President Bush signed the Clean
Air Act (CAA) Amendments of 1990 (P.L. 101-549) into law on November 15, 1990. The
Amendments include 11 separate titles that cover nonattainment (e.g.. ozone and carbon monoxide
problems), motor vehicles, air toxics, stratospheric ozone, and acid rain among other air pollution
issues. Title IV, the acid rain title, sets three major goals adopted from the original Administration
proposal: (1) a reduction of S02 emissions of 10 million tons per year below the 1980 level by the
year 2000: (2) approximately a two million ton reduction from the 1980 level of NOx emissions: and
(3) a national cap on SO-, emissions beginning in the year 2000.
In meeting the goals of a 10 million ton S02 reduction, cap on S02 emissions, and two million
ton NOx reduction, a two-phased program was developed. During Phase I (beginning in 1995) part
of the SO? and NOx reductions are to be achieved through emissions reduction requirements at 110
of the largest, highest-emitting power plants. During Phase II. the S02 and NOx reduction goals are
to be reached through more stringent requirements at virtually all fossil fuel utility units.1 The
rationale for this two-phased program was to achieve some reductions promptly while alerting a broad
range of polluters to plan for a more significant reduction by 2000.
Perhaps the most important feature of the acid rain title is the allowance allocation and
trading provisions. These represent a significant departure from more traditional "command and
control" regulation which sets emissions standards that must be met by each individual unit. The
program allocates emission "allowances." which allow utilities to emit tons of SO-, based on a national
target for S02 reductions. Through the transfer of these allowances from one source to another in
A "unit" is an individual fossil-fuel burning device (either a turbine or a boiler) that drives an electrical generator.
By contrast, a power plant consists of one or more units at a single site.
1-2
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a tree market, the targeted reductions can be achieved in the most cost-effective manner. Simply
stated, the rules in this market are as follows:
(1) Each existing "affected" (defined in Table A of the Act for Phase I)
unit is allocated and issued SO-, allowances:
(2) All units, including new units, must have enough allowances each year
to cover actual emissions: and
(3) Allowances may be bought, sold, and banked (saved) from year to
year.
The major acid rain provisions are presented in Exhibit 1-1 and briefly summarized below.
• Phase I SO-, and NOx Requirements - In Phase I (beginning 1/1/1995)
— SO-, emission allowances are tradeable among affected sources
across all states. Sources may also bank emission allowances
and use them in a later year.
— An additional 200,000 tons of allowances are allocated
annually during Phase I to units in Illinois, Indiana and Ohio
(except for the three Department of Energy (DOE) plants:
Clifty Creek, Kyger Creek, Joppa Steam) based on their pro
rata share of Phase I allowances.
— Units affected in Phase I are required to install cost-effective
NOx control technology.
• Phase I Technology Allowances - Eligible Phase I extension units
using qualifying Phase I technology (i.e., 90 percent removal technolo-
gy) receive two-year "extension allowances" during 1995-96, and
additional allowances during 1997-99.
• Phase II SOt and NO.c Requirements - In Phase II (beginning
1/1/2000), almost all fossil fuel utility units that commenced operation
or will commence operation prior to the end of 1995 are provided
emission allowances, generally based on a 1.2 lb S02/mmBtu (or
lower) emission rate.
— S02 emission allowances are tradeable across the U.S. and
may be banked.
— New units coming on-line after December 31, 1992 and prior
to the end of 1995 whose construction did not commence by
December 31, 1990 are allocated emission allowances.
Otherwise they must obtain allowances to offset their emis-
sions.
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EXHIBIT 1-1
Summary of Major Provisions of Acid Rain Title
Phase One
Phase Two
Compliance
Date:
1/1/1995
1/1/2000
SO, Require-
ments
.Allowances according to Table A of
the Clean Air Act.
Most units "affected" except those granted
emission allowances based on a 1.2
Ib/mmBtu SO, rate (or lower). New units
on-line after 1992 and prior to the end of
1995.
NO^ Require-
ments
NO^, controls required at Phase 1
"affected" units.
:i
NO^, controls required at all "attected" |
units. ;j
Allowance Trad- : Interstate trading of SO, allowances;
ing and Banking : allowance banking permitted.
Interstate trading of SO, allowances: allow- ¦
ance banking permitted.
Clean Coal/
Repowering
Financial incentives for clean coal
demonstration projects.
Four-year deferral of requirements.
Phase 1 Exten-
• sion Allowances
for Technology
Extension allowances during 1995-
1996, and additional allowances
1997-1999. Total credits limited to
3.5 million tons allocated on a first-
come-first-served basis.
ii
None
¦\
if
;
Monitoring
Ail Phase I units must be equipped j All Phase II units must be equipped with
with continuous emissions monitors, continuous emissions monitors, and must
and must submit data quarterly. i submit data quarterly.
Permits
EPA will issue permits to own- ; „ . . , .... i
,r ¦ States with approved programs will issue
er/operators of power plants re- ; , c
. r , l. permits to owner/operators of new units
quired to meet Phase I SO-, require- : • . .
, , 1 required to have SO, emission allowances
ments and the NOv reduction re- ! \ . . ,,
* j and existing units 25 MW or greater,
quirements. b b
Auctions, Direct
Sales and IPP
Written Guaran-
tees
EPA will offer limited numbers of 1
i
allowances through annual auctions i A r ,,
... * . . , EPA will offer limited numbers of allowanc-
and direct sales; independent power , . ...
,.,r„ r ! es through annual auctions and direct sales,
producers may qualify for guaran- s
teed access to reserved allowances. |
Conservation
and Renewable
¦ Reserve
1
Up to 300,000 allowances awarded Up to 300,000 allowances awarded to utili- i
to utilities that reduce emissions ties that reduce emissions through energy
through energy conservation or the ! conservation or the use of renewable energy j
use of renewable energy sources. ! sources. |
1-4
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— NOx controls are required.
— Units repowering with "clean coal" technologies are granted
a deferral of up to 4 years of Phase Two requirements during
which they receive extra "non-tradeable" allowances.
In addition to these provisions. Title IV contains provisions for
Monitoring of emissions:
Voluntary inclusions ("elections") of unaffected sources (existing utility
units with less than 25 MW capacity, industrial boilers, and industrial
process sources);
• Extra allowances for energy conservation and renewable energy;
• Sales of allowances through auctions, direct sales, and written
guarantees for new independent power producers (IPPs); and
• Permits and compliance plans.
1.1.3 Types of Costs, Cost Savings, and Benefits Anticipated
The acid rain statute will result in increased costs to those entities regulated under the Act
(i.e.. electric utilities and IPPs). These costs are in the form of (1) higher capital and operating costs
as pollution control equipment is installed to meet the S02 and NOx emissions reduction
requirements, and (2) higher fuel costs as sources shift to more expensive, lower sulfur fuels. In
addition to these direct costs, the statute is likely to result in shifts of production volume,
employment, and income from high sulfur to lower sulfur coal producers, as well as shifts to natural
gas producers, pipelines, and pollution control equipment manufacturers. The statute will also yield
environmental benefits: the mandated reductions in SO? and NOx emissions will result in less acid
rain and sulfate exposure, and better visibility and local air quality.
Under a traditional command-and-control approach to environmental management. Congress,
EPA, or a State regulatory agency would assign pollution control obligations that must be met by
each source. This is generally accomplished by applying uniform emission limits or technology
requirements to all sources that belong to common industrial source categories (e.g., existing coal-fired
power plants). While considerable analysis may be carried out to ensure that it is feasible for the
sources in a given source category to meet the uniform requirements, the application of uniform
standards often results in substantial cost inefficiencies. Allowance trading regulations, and the other
implementation regulations (such as monitoring regulations) that make them possible would serve to
improve efficiency and reduce the costs of compliance while leaving intact the environmental benefits
intended by the statute.
The principle behind emissions allowance trading is straightforward. Instead of mandating
fixed uniform emission reductions from each source, allowance trading permits the aggregate emission
reductions to be achieved from sources in the most economically efficient manner. Thus, those
sources that are relatively inexpensive to control can reduce emissions more than would be required
under uniform standards. The surplus allowances from these extra emission reductions can then be
traded to other sources that are more costly to control, allowing these latter sources to reduce
emissions less than would be otherwise required, while still achieving the same level of aggregate
emission reductions would be achieved.
The implementation regulations are expected to generate additional benefits in the long run
in the form of improved pollution control technology. The ability to sell allowances generated bv
1-5
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emissions control techniques that bring emissions well below targets will create incentives tor research
and development of new, more effective emissions control technologies. In a uniform requirements
approach, utilities that have met their tonnage limits have no incentive to develop the abilitv to make
further emissions reductions. Under the implementation regulations, even those meeting their
tonnage limits have the incentive to develop cost-effective ways to cut emissions still more so thev
can sell more allowances. In the long run. these incentives may result in technological advances that
make even tighter emissions standards feasible.
1.2 SCOPE OF THE REGULATORY IMPACT ANALYSIS
As discussed, the acid rain reduction provisions encompass an array of requirements including
SO-, and NOx reductions, and SO-, allowance trading and tracking. This RIA is limited to a subset
of these provisions. Specifically, the focus of the RIA is to evaluate the effects of a set of four
classes of regulations, termed the 'implementation regulations:"
• S02 allowance system (tracking and trading regulations);
• SO-, monitoring regulations:
• Permits; and
• Auctions, direct sales, and IPP written guarantee regulations.2
Collectively, this set of implementation regulations establishes and implements the allowance
trading system. While the first element in the set provides directly for rules regarding how SO,
emission trades are to be effectuated and recorded by EPA, the other elements are equally important
in that the trading system could not be operated without them. An accurate and reliable system for
monitoring emissions is required to determine how many allowances have been generated or used by
individual units: a permit system ensures national consistency and accountability and makes the
enforcement of the allowance system possible; and a system of auctions and sales offers assurances
that allowance market develops smoothly and equitably. Thus, the implementation regulations must
be viewed as a whole, and the costs and benefits associated with each separate part should be
considered to arise jointly from all of them.
This section describes the factors considered in determining the scope of the regulatory impact
analysis.
1.2.1 Consequences of S02 and NOx Reductions are Not Considered
The central purpose of Title IV of CAA is to achieve significant reductions in SOt and NOx
of ten million and two million tons per year, respectively. Achieving these reductions will entail
significant costs to the economy. Because these emissions reductions are required by the statute
itself, independent of any EPA regulations, less emphasis is placed on the estimation of the costs of
these emissions reductions under the command-and-control regime than would be necessary in the
absence of the regulations. In keeping with the central purpose of EPA's proposed regulations -- to
establish tradeable SO, emissions allowances and facilitate the development of markets for these
EPA's analysis of the auctions, sales, and IPP guarantee programs are contained in a separate document: Economic
Analysis of the Proposed Acid Rain Regulations for Auctions. Direct Sales, and IPP Written Guarantees. Office
of Atmospheric and Indoor Air Programs. Acid Rain Division. U.S. Environmental Protection Agency. April 26.
Wl.
1-6
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allowances -- the focus of the RIA is on the economic effects of the allowance trading system and
the related regulations necessary to the operation of the system.
Neither the costs nor the benefits of reductions in NOx emissions, which are not included in
the allowance trading system, are considered in this analysis.
1.2.2 Consideration of the Costs of the Implementation Regulations
The implementation regulations will bring with them both costs and cost savings. The costs
will be related directly to emissions monitoring, tracking the ownership of allowances, ensuring that
an adequate source of allowances is available, and bringing buyers and sellers of allowances together.
The RIA. therefore, includes sections on the incremental costs of monitoring systems required under
a trading system: the transactions costs (both to EPA and the regulated community) associated with
actual allowance trades: costs of permits; and the costs to EPA and the regulated community of
allowance auctions, direct sales, and allowance guarantees. The analysis attempts in every case to
separate the costs imposed by the regulations themselves from costs that would have been borne
under the statute in the absence of regulations.
L.2.3 Consideration of the Cost Savings of the Implementation Regulations
This RIA also considers the cost savings that will ensue when emissions sources that have high
control costs are able to shift some of the burden of emissions reduction to the sources with low
incremental control costs. The owners of both sources will gain as a result of a trade -- the allowance
buyer will pay less for additional allowances than it would cost to increase its control effort, and the
allowance seller will receive more for each allowance sold than the costs it incurs to generate the
allowance. These cost savings are expected to outweigh the costs associated with implementing the
regulations. Thus, the costs of complying with the statute through the implementation regulations
are lower than the costs of complying with the statute in the absence of the implementation
regulations.
1.2.4 Benefits
The regulations examined in the RIA are not expected to provide environmental benefits.
Rather, they are intended to lower the costs of reaching essentially the same levels of emissions as
required under the statute. For this reason, the RIA does not focus closely on the benefits of
reducing emissions of pollutants related to acid rain. The benefits of reducing acid rain are discussed
qualitatively, however, to provide a point of comparison for the estimates of the total costs of the
regulations combined with the statutory reductions in emissions.
1.2.5 Implementation Options
This analysis assumes that a well-functioning market for allowances will develop. EPA is
exploring a number of implementation issues, however, that will affect how well this market performs.
Two issues are related to the administration of the allowance trading and tracking system: serialization
(i.e., numbering) of allowances; and an end-of-the-year "truing-up" period. Four issues relate to
permits: bonus allowances for Phase I extension; reduced utilization/load shifting in Phase I:
certification of designated representatives; and permit revisions. Finally, five issues involve
monitoring: hourly versus daily data for quarterly reporting; incentive approaches for monitoring
accuracy: incentive approaches for missing da'a: alternatives to SO-,, NOx, and flow monitors for gas
and oil units: and flow monitor requirements. These issues have not been treated in this RIA
1-7
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because of the difficulty of assigning dollar values to them. The advantages and disadvantages of the
options relating to these issues are, however, discussed at length in the preamble to the implementa-
tion regulations.
1.3 ORGANIZATION OF THE REPORT
The remainder of the RIA is divided into five chapters:
Chapter 2 describes the community that would be subject to the regulations. The
chapter investigates the number of firms in the community, firm size distributions,
demand conditions, and recent trends affecting the regulated community.
Chapter 3 outlines the baselines used for the comparisons made in the analysis. In
addition to a review of the time-frame considered in the RIA, this chapter introduces
both pre-statute and absent regulations baselines. In addition, this chapter discusses
issues related to the types of costs analyzed in the report.
Chapter 4 presents and compares the costs under the regulations to costs under the
baseline cases (pre-statute and absent regulations). The chapter also breaks down the
cost of regulatory implementation to both the EPA and the regulated community.
Chapter 5 provides the economic effects of the regulations on utilities and indepen-
dent power producers and then discusses the regional impacts of the regulations. The
chapter emphasizes the potential impacts on small power producers and explores the
potential for mitigating any negative impacts.
Chapter 6 present a qualitative description of the expected environmental benefits of
the statutory reductions in acid-rain-related emissions.
The appendices to the report provides a detailed description of the methodologies and
computations used to develop estimates of costs and cost savings. Finally, the attachment describes
the impacts of continuous emission monitoring system requirements on new small electric power
generating units (i.e., those with a capacity of less than 25 MW).
1-8
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CHAPTER 2
Characterization of the Regulated Community
This chapter provides background information on the industries that will be affected bv Title
IV of the Clean Air Act (CAA) Amendments of 1990. Title IV, designed to control nationwide
emissions of sulfur dioxide and other acid rain precursors, applies to "utility units." which are defined
to include units that serve a generator producing electricity for sale or that did so in 19X5. Entities
owning "utility units" generally belong either to:
• The electric utility industry (which includes investor-owned utilities and
publiclv-owned utility entities such as municipal systems and federal power
entities like the Tennessee Valley Authority). The utility industry currently
accounts for the vast majority of the generation capacity in the U.S. A
substantial portion of this utility capacity is affected either by Phase I or Phase
II of the CAA Amendments: or
• The non-utility generation industry (which includes qualifying facilities (QFs)
under the Public Utility Regulatory Policies Act (PURPA) and other non-
utility power producers called independent power producers (IPPs)). Existing
non-utility generators are largely unaffected by Title IV because they are
mostly exempt under provisions of the Amendments. However, as Exhibits
2-1 and 2-2 indicate, the non-utility sector is building much of the new
generating capacity now under construction and is likely to continue to do so.
Most future non-utility capacity commencing commercial operation on or after
November 15, 1990 is subject to Title IV provisions.
This chapter is divided into two major sections that focus on the two industries respectively.
Each section provides an overview (with definitions) of the industry structure, the economic
regulations that apply to the industry sector, and the impact of Title IV on the industry. In addition,
each section describes the current and projected demands for the industry's output and. therefore,
its potential growth. The section on the electric utility industry also describes the variation in power
costs and potential competition. Background on other affected industries is presented in Appendix
2A.
2.1 THE U.S. ELECTRIC UTILITY INDUSTRY
Companies comprising the U.S. electric utility industry (SIC code 4911) differ significantly in
terms of institutional and regulatory arrangements, size, power plant types, fuel consumption, and
power supply cost structure. These companies are currently highly regulated at both the state and
federal levels, which protects them from open competition. However, the regulatory climate is
gradually changing, with a shift toward less regulation and more competition.
2-1
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EXHIBIT 2-1
U.S. Installed Generating Capacity by Industry Type
(Gigawatts)
j
1979
1986
1987
1988
! '
Total U.S. Hlectrtc Utility !
Industry |
59K
710
718
4-
I
Investor (Owned Utilities ;
464
546
553
55
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2.1.1 Overview of Industry Structure
The electric utility industry is composed of about 3.000 companies. There are four principal
types of utilities:
• Investor Owned Utilities (IOUs) - The approximately 206 IOUs
represent about seven percent of the total number of companies in
the electric utility industry; however, they account for about three-
quarters of the total electricity generated in the U.S. These compa-
nies own a similar share of total generation capacity. Part of this
concentration is explained by the large economies of scale in genera-
tion and transmission of electricity.
• Municipally Owned Utilities - The 1,810 municipally owned electric
utilities are generally very small in terms of generation and sales, and
often own one or no power plants: however, there are some important
exceptions, such as the Los Angeles Department of Water and Power,
the City of San Antonio, and the Jacksonville Electric Authority.
• Rural Electric Cooperatives - Most of the 933 rural electric coopera-
tives. established to help electrify rural areas where transmission and
distribution costs were high, are small and have no generating
capacity. A few cooperatives also have generating capacity, but these
cooperatives are usually owned by smaller distribution-only coopera-
tives. Both types of cooperatives are subsidized by the federal
government.
• Federal Public Power Districts (Including TVA) - Most of the 77
federally owned utilities are primarily involved in flood control;
electricity is a by-product of river flow control. Hence, most of their
capacity is hydroelectric powerplants although there are some notable
exceptions, especially the Tennessee Valley Authority (TVA), which
is the nation's largest consumer of coal. These utilities usually sell
their power wholesale to municipalities and other companies.
2.1.2 Utility Regulation
Most U.S. electric utilities have monopolies (known as franchises) provided by state or local
authorities and are the only supplier of electric power within their service territories. In exchange
for the advantages conferred by the franchise, the utility subjects its rates to regulation by state
authorities and undertakes to serve the public's demand for power.
Rates for IOUs, which operate for profit, are theoretically set to allow them to recover all
of their costs so long as these costs were "prudently incurred." The costs that may be recovered
include non-capital cost items {e.g., fuel, O&M, and administration), and the costs of capital
investments including a reasonable profit (or "rate of return") on invested capital. This rate-making
arrangement is known as "rate of return" or "cost-of-service" regulation.
Although the "cost-of-service" model of rate regulation is straightforward in concept, its
implementation in recent years has been complicated by disputes between utilities and their
2-3
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ratepayers. For instance, substantial amounts of new nuclear and coal capacity came on-line in the
late 1970s and early !9
-------
EXHIBIT 2-3
Characterization of Affected Existing Utility-Owned Units
!
i
Phase 1
Phase II j
1 Type of Ownership
# of
Utilities
# of
Units
Capacity
"
# of
Utilities
# of
Units
Capacity '
<<;wi
1
Federal and Public Power
Entities. State and District
Systems
! '
1
26
9
13
116
32
i
Cooperative Systems
5
15
4
27
89
!
23
i Investor-Owned Systems
52
216
75
132
1.517
392
Municipal Systems
3
4
1
67
183
24 ;
TOTALS
61
261
89
239
1,905
471
!
| Source: National Allowance Data Base Version
1990.
1.0 and K'F Analysis of the Clean Air Act Amendment of
Actual and potential differences in variable generation costs are greatest between regions
relying on oil and gas and regions relying on coal. For example, coal-fueled electricity production
costs in Wyoming and North Dakota are as low as one cent per kilowatt-hour, whereas in Florida,
where oil-fuel generation, at $20 per barrel, constitutes a large share of total capacity, electricity
production costs are about three cents per kilowatt-hour. Oil and gas fueled generation are also the
dominant capacity sources in other regions of the country, including New England, Texas, and the
Pacific. The regional mix in fuel use has important implications for regional S02 emissions, acid rain
control costs, and rate impacts.
2-5
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While utilities currently provide over 95 percent ot' the power generated in the U.S.. thev face
some competition because of alternatives available to their customers, including:
• Self-Generation - Large companies have self-generation or
cogeneration options which may be cheaper than purchasing electricity
from utilities:
• Alternative Fuels - Customers have a choice between gas/oil and
electric:
• Relocation - Customers can relocate to areas of lower power cost: and
• Wholesale Purchases - Large customers, such as municipalities or
other utilities, may switch power purchases to other nearby utilities.
2.1.5 Demand for Industry Output
Electric utility decisions about future capacity additions have been complicated by increasing
uncertainty regarding electricity demand growth. As Exhibit 2-5 indicates, three major sectors
dominate energy demand: residential, commercial, and industrial. Prior to the 1973 OPEC oil price
rise, electricity demand had been steadily growing at very high rates of about 5-7 percent per year
(see Exhibit 2-6). This rate of growth in demand decreased in the mid-1970s. In recent years,
however, electricity demand has begun to increase again at about the rate of GNP. or about 2.5-4.5
percent per year.
Although utilities are monopolies, their customers are still sensitive to rate increases and may
cut back on their demand. With an increase in the competitiveness in electricity generation, large
customers may also be able to respond to increased electricity rates by purchasing power from a utility
other than the franchised utility.
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EXHIBIT 2-4
U.S. ELECTRIC UTILITY GENERATION BY FUEL TYPE
HISTORICAL AND PROJECTED
4000
HYDRO
~ NUCLEAR
pi] OIL AND GAS
COAL
2000
HISTORIC
FORECAST
SOURCE: EIA/Monthly Energy Review 10/89, ICF CEUM Projections
2-7
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EXHIBIT 2-5
U.S. Energy Demand by Sector -1989
Residential
34.4%
Commercial
27.4%
Other 3.6%
Industrial
34.6%
Source; Edison Electric Institute Statistical Yearbook 1980
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EXHIBIT 2-6
U.S. ELECTRIC UTILITY ELECTRICITY
DEMAND GROWTH
s
Actual
%/YEAR 4
1968-1973 1974-1979 1980-1985 1986-1990 1 990-1995 1995-2000 2000-2005
Source: EPA High and Low Base Cass Forecasts. See Chapter 3 for mora detail.
2-9
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2.1.6 Recent Changes Affecting the Industry
Over the last decade, many utilities experienced serious financial problems associated with the
inability to fully recover their costs, especially capital costs. Several factors contributed to these
problems including inflation, higher financing costs, increased costs and cost overruns for new
powerplants. unexpectedly sluggish demand growth, and excess generation capacity. These factors
put a great strain on traditional cost-of-service ratemaking. as utilities realized that the long-held
presumption of being able to recover all prudently incurred costs did not guarantee adequate financial
returns. Many utilities argue that under the present system, cost-of-service regulation means that a
utility earns no more than its regulated rate of return at best, and could earn significantly less under
adverse circumstances. Regulators and other industry observers concede that traditional cost-of-
service regulations do not appear to provide utilities with the correct incentives to lower costs and
be innovative in providing service.
A parallel and distinct development affecting the utility industry was the enactment in 197X
of the Public Utility Regulatory Policies Act (PURPA). PURPA helped open the way for non-utilitv
power producers and cogenerators to supply power to the public by requiring utilities to purchase
cogenerated and other categories of power. PURPA set prices for the power supplied by the non-
utilities at the utilities' "avoided cost," which is the amount of money it would have cost the utility to
have produced the power themselves. The response to PURPA has been large and by 19X8 over
seven percent of U.S. electricity generation was supplied by non-utility producers. The PURPA
experience has. in turn, set the stage for the establishment of an independent power industry, which
is discussed in Section 2.2 below.
Finally, in addition to the Clean Air Act Amendments of 1990, other regulatory initiatives are
likely to affect the industry in the future. For example, heightened concern over global warming may
lead to restrictions on greenhouse gas emissions, which would affect utility investment decisions.
2.2 THE NON-UTILITY GENERATION INDUSTRY1
A significant quantity of electric generation capacity owned and operated by private
developers, rather than by the regulated utilities, has come on line over the last decade. These "non-
utility" generators, which are comprised of two classes of power producers, qualifying facilities (QFs)
and Independent Power Producers (IPPs), have already established themselves as important flayers
in the power generation industry and are likely to play an increased role through the 1990s."
The term "non-utility" industry is used to identity electric generating units that are owned by parties other than
traditional utilities. As discussed in this section, a substantial number of the electric generating units that are part
of the "non-utility" industry could be treated as "utility units" pursuant to the f'AA Amendments of 1990 and subject
to Title [V.
The industry includes plants that produce electricity entirely for on-site use (so-called "self-generators"). New plants,
designed for on-site uses, will likely seek to get certified as UFs under PURPA. to the extent they meet the tests
laid down for certification. This is because, as QFs, they will be legally entitled to receive non-discriminatory back-
up service. There are, however, existing industrial generating plants that do not meet the tests of a OF.
Furthermore, it is possible that some additional capacity of this type may be built by industry. In any event, capacity
dedicated entirely to on-site use in not subject to Title IV.
2-10
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2.2.1 Overview of Industry Structure
The non-utilitv generation industry is a relatively young industry characterized bv a large
number of companies, including many small companies (in terms of revenues and number of
employees). The industry grew steadily in the 1980s and most observers expect this growth to
continue in the 1990s. This industry attracted a large number of companies that have experience in
one or more aspects of the power generation business. The industry now includes equipment
vendors, electric utility subsidiaries, railroad companies, engineering and construction companies, and
developers. A large number of electric utility subsidiaries are also active in developing a range of
new projects.
As Exhibits 2-7 and 2-8 indicate, total non-utility capacity was estimated at about 34.000 \1W
in 1989. The total amount of generation from this capacity was about 199 billion KWH, or seven
percent of total U.S. utility generation. However, electricity sales to the electric utilities account for
about 89 billion KWH or 3.1 percent of total utility generation. The remaining electrical energy
generated by the non-utility industry was used to meet on-site electrical needs.
PURPA created a special class of power producers called "Qualifying Facilities" (QFs). Some
QFs are qualifying cogenerators (QF-Cogenerators) which produce both electricity and useful thermal
energy in the same process. The remaining QFs are qualifying small power producers (QF-SPPs).
which are below a certain size and fueled by renewable energy (including solar, hydropower, wind,
or biomass) or waste fuels such as petroleum coke or used tires.^ QFs sell considerable amounts
of their power to electric utilities.
In recent years, FERC, which is responsible for implementing both PURPA and the FPA. has
allowed power producers that do not meet the tests laid down for QFs to be exempt from cost-of-
service regulation provided that the price they obtain for power sales is "market-based". Such non-QF
power producers are commonly referred to as "independent power producers (IPPs)."4
Cogenerators (QF-Cogenerators): These are facilities which sequentially use energy, usually
producing electric power and some form of useful thermal output such as steam. Thermal output
from a cogenerator must be at least 5 percent of total energy output for the plant to receive QF
status. In addition, oil- or gas-fired cogenerators effectively are required to meet various system
configuration, heat utilization and efficiency standards.
Small Power Producers (QF-SPPV These are facilities which produce less than 80 MW of
electric power primarily through the use of biomass. waste materials, geothermal energy or renewable
resources such as wind, solar and hydroelectric resources. Although many benefits accruing to QFs
are available to all QF-SPPs, the benefits of exemption from cost-of-service regulation under the
FPA. as well as the exemption from PUHCA and certain State regulations were not available until
recently to QF-SPPs that were larger than 30 MW except in cases where they were fueled by biomass
Congress enacted legislation in 1990 that will effectively lift the size limitation for QF-SPPs whose construction
commences during the 1990s.
Note that currently IPPs represent a class of producers approved by FERC on a case-by-case basis. However,
legislative proposals currently being considered both within the Administration and Congress would, by law. create
a class of power producers called "exempt wholesale generators "that would enjoy at least some benefits similar to
those enjoyed by QFs. without having to meet the operating or size constraints applicable to such QFs. Note that
the CAA Amendments do contain a definition of IPP, but that definition is simply for the purpose of identifying
"sirandfathered" IPPs.
2-11
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or geothermal. Legislation enacted in 1990 may effectively remove the size limitation of QF-SPPs
for solar, wind, waste, or geothermal units commencing, construction during a certain time window
in the 1990s and make these QF-SPPs eligible for all benefits open to QF-Cogenerators.
Independent Power Producers (IPPsV. IPPs are a relatively new class of non-utilitv generators
whose purpose is primarily to generate power for sale to utilities (i.e.. at wholesale). In electric
market parlance, an IPP facility is one which, unlike most PURPA-QFs. is subject to rate regulation
under the FPA. but intends to obtain an order from FERC effectively stating that FERC finds the
IPP's rates to be just and reasonable under the FPA. Generally, FERC. in making this finding, will
rely on a showing that the rates are "market-based" rather than cost-based. Therefore, the rates for
IPPs are generally not determined in accordance with traditional rate-based, cost-of-service regulation.
Under the CAA Amendments of 1990. IPP units are specifically defined as facilities which are used
for the generation of electric energy. 80 percent or more of which is sold at wholesale: are non-
recourse project-financed: and do not generate electric energy sold to any affiliate of the facility's
owner or operator which could provide it with allowances. Thus. IPPs as understood in electric
market parlance could also be IPPs under the CAA Amendments of 1990. Note, however, that
certain affiliate entities could be viewed as IPPs in electric market parlance, but not be IPPs under
the CAA Amendments of 1990. Moreover, there is a possibility that the current Congress will enact
legislation as part of the National Energy Strategy (NES) that will define IPPs (or an equivalent such
as exempt wholesale generators (EWG)) more precisely from an electric market perspective.
Fossil Fuels: Fossil fuels are not explicitly defined in the CAA Amendments. The term
usually refers to petroleum, natural gas and coal. However, there is some ambiguity as to whether
certain waste fuels such as bituminous coal wastes, refinery off-gases, or tires will be treated as fossil
fuels for the purpose of the CAA Amendments-1.
The average size of a QF-Cogenerator is about 20 to 30 MW based on electric output. Gas-
fired cogeneration projects, which collectively account for over 50 percent of total QF-Cogeneration
capacity, average about 15 to 25 MW, while coal-based cogenerators average 50 to 70 MW based on
electric output. Some coal and gas-fired QF-Cogenerators, however, are substantially larger than this
average, with capacities exceeding 150 MW. Qualifying Facilities-Small Power Producers tend to be
somewhat smaller than cogenerators, averaging about 5 to 20 MW in size. Note, however, that while
there were 3,517 non-utility projects on line at the end of 1988, the 69 largest projects (over 100
MW) accounted for over 40 percent of the non-utility generation capacity (see Exhibit 2-7).
As Exhibit 2-8 shows, plants burning natural gas, coal, and biomass are the most common
types of non-utility generators, collectively accounting for almost three-fourths of all non-utility
capacity. Projects burning waste products also provide substantial capacity, as do plants utilizing
hydro and wind resources.
2.2.2 Regulation of QFs and IPPs
Under PURPA, QFs enjoy benefits that enable them either to produce their own power for
on-site needs or to sell back to the grid (or both). Specifically.
• If a QF produces power for use on-site (usually by construction of a
cogeneration plant at an industrial site), it is eligible to receive back-
up electric service at non-discriminatory rates.
Note that under FERC's implementation of PURPA, these fuels arc treated as waste materials.
2-12
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If a QF sells electricity to the grid, the utility is obligated to purchase
such power at its avoided cost or at a mutually acceptable negotiated
rate.
Even it" QFs sell their power to the grid, they are not treated like
other utilities. First, unlike traditional utilities. QFs are not subject to
cost-of-service regulation. Second, most QFs are exempt t'rom
PUHCA.
EXHIBIT 2-7
Non-Utility Capacity by Project Size,
by Census Division j
at December 31, 1988
Project Size
] (Megawatts)
Total Number of Total Capacity
Projects
Less than 1.0
2,037
339.1
1.0 to 9.9
868
3,247.2
10.0 to 49.9 ' 455
10,668.0
50.0 to 99.9 1 88
5,988.2
100.0 and over i 69
13,499.4
TOTAL | 3.517
33,741.9
Source: "ll)SS Capacity and Generation of Non-Utility Sources of Energy," Edison Electric Institute. April 1SW0.
2-13
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EXHIBIT 2-8
Non-Utility Capacity by Primary Energy Source, by
Census Division
at December 31, 1988
!| I
- Primary Energy Source ! Total Capacity
Coal
5.602.2
Oil
955.1
Gas
12.486.1
Biomass
6.642.3
Waste
3.155.9
Hydro
1.860.3
Wind
1.893.0
Solar
297.5
Geothermal
624.2
Other
225.2
TOTAL
33,741.9 1
i
Source: "1988 Capacity and Generation of Non-Utility Sources of Energy." F.dison Electric Institute. April 1990.
2.2 J Regulated Segments of the Industry Under the 1990 CAA
Exhibit 2-9 shows the sub-sectors of the IPP and QF market regulated under the CAA
Amendments. QFs currently in commercial operation are not regulated under the Act. IPPs are not
regulated if they have already entered into a power sales agreement with a utility, received a letter
of intent from a utility to enter into a power sales agreement, or won a competitive bid at the time
of the Act's enactment.
All future IPPs and QFs that burn fossil fuels are subject to the Act's provisions. However,
cogenerators with less than 25 MW capacity, or those that sell less than one third of the power they
generate to the grid, are not affected by the CAA Amendments, regardless of the type of fuel they
burn. New renewable energy QFs might create allowances for utilities that purchase their power.
Exhibit 2-10 presents a "representative" estimate of the relative size of different segments that
would be affected by the CAA Amendments. These estimates depend on the fundamentals driving
the electricity market such as load growth, fuel prices, and utility behavior with respect to acquiring
new capacity. The numbers in Exhibit 2-10, therefore, simply place in perspective the relative sizes
2-14
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of the different segments.6 From the perspective of this RIA, the main purchasers of allowances
will be new. coal-fired IPPs and perhaps a subset of waste-fired QF-SPPs if EPA determines they are
affected.
2.2.4 Demand for Industry Outputs
The demand for new QF and IPP capacity will depend largely on electricity market
developments. As Exhibit 2-11 shows, in each of the time periods 19XX-1995 and 1995-2000. between
20 and 43 GW of QF/IPP capacity is projected to be brought on-line.
The ranges for projected QF/IPP additions are heavily dependent on electricity load growth.
The higher levels of new QF/IPP capacity correspond to higher load growth, while the lower levels
are based on lower load growth.
The economics of large QF-cogeneration and IPP projects undertaken to sell power to an
electric utility depend strongly on electric market conditions. As discussed in Section 2.1 on the
electric utility industry, there is uncertainty over the future demand for electricity. On the supply
side, there is some hesitation on the part of electric utilities to commit to building large, rate-based
plants in the face of uncertain demand and a still-evolving regulatory regime. Thus, the proportion
of new electric capacity that will be IPP (as distinct from traditional rate-based) is uncertain. (Exhibit
2-10 provides a perspective on the need for new capacity over the 1990-2000 time frame and the
extent to which IPPs and QFs might contribute to meeting that need. Such estimates are very
dependent on scenario-specific assumptions).
The proportion of IPP and rate-based capacity shown in Exhibit 2-10 represents a rough estimate based on the
limited experience with IPPs.
2-15
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EXHIBIT 2-9
PURPA-QF and IPP Plants Affected by Title IV
Category
Status
Subcategories
Affected? :j
1
1
Existing11
N„ |
i) Burns non-fossil fuel
No
QF-Cogenerators
Future
ii) Sell <25 MW capacity or
less than Vs of total capacity
to grid.
No
iii) All other
Yes
Existinga 1
No
QF-SPP
Future
i) Burns non-fossil fuel
No ;
j
ii) Burns fossil fuelsb
Yes
i
Substantially
1
Committed as of
No
IPP
1 l/15/90c
Future
i) Burns non-fossil fuels
No
ii) Burns fossil fuels
Yes
a Refers to both plants in commercial operation and those for which substantial commit-
ments have been made as of November 15, 1990.
b It is conceivable that certain QF-SPPs that burn fuels treated as "waste fuels" under
I PURPA could be treated as fossil fuel units under the CAA Amendments of 1990.
! Plants burning coal wastes or petroleum coke are examples.
c IPPs in commercial operation as of November 15, 1990 and making substantial sales to
j the grid are subject to Title IV. As a practical matter, the amount of such capacity is
I small.
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EXHIBIT 2-10
Representative Size of the Affected PURPA-QF and IPP Population Relative to the
Total Changes in Capacity1
Estimated 1988 to 2000 Changes in Capacity
(GW)
Segment
Traditional Rate- |
Based Units2 \
IPP
Total
RATE-BASED OR IPP UNITS
Primarily Gas-Fired Simple Cycle
and Combined Cycle Systems
44 to 77
22 to 38
66 to
Coal-Fired Systems (conventional
and tluidized bed)
TOTAL (Rate-Based and IPP
4 to 21
48 to 98
to 12
25 to 50
7 to 33
73 to 148
PURPA QF
Gas-Fired Systems
Coal-Fired Systems
Oil-Fired Systems
Biomass - Resource Recovery
Systems
Biomass -- Wood; Agricultural
Waste-Fired Systems (e.g., anthra-
cite culm, petroleum coke; tires)
Renewables (e.g., hydro, geother-
mal, wind, and solar)
N/A
8.0 to 14
3.0 to 6
0.5 to 0.9
1.3 to 2.4
.8 to 1.5
1.6 to 3.0
1.2 to 2.2
The estimates presented here are properly treated as a "representative" of future circumstances.
They are based upon the EPA's High Base Case and Low Base Case.
The proportion of required new capacity that will get built as IPP capacity somewhat uncertain. It
depends in large part on how regulators behave in the future with respect to cost-recovery, and
how investors perceive such behavior.
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EXHIBIT 2-11
Projected Demand for Non-Utilitv Capacity
Time Period
!
Utility Sales Growth
Required Total New
Electric Capacity
Additions (GW)
Projected QF/IPP
Capacity Additions
(GW)
19X8 to 1995
2.4 to 2.8%
39 to 74
21 to 37
•i
|
1995 to 2000
;
2.1 to 2.8%
50 to 104
20 to 43
2000 to 2005
1.7 to 2.3%
63 to 114
24 to 47 ;
Total 1990 to 2005
152 to 292
65 to 127 j
Source: ICF analysis based upon EPA High Base and Low Base cases.
2.2.5 Future Trends
In the 1980s, state and federal regulators implemented policies designed to encourage
cogeneration. In recent years, however, regulators have shitted their emphasis from "providing
encouragement" to QFs to the "competitive procurement of electric supplies." It is in this context
that IPPs have been approved on a case-by-case basis. In general, regulators at the federal and state
levels have been receptive to the idea of allowing all non-utility suppliers to be essentially free from
cost-of-service regulation, so long as their power sales rates are market-based (as. for instance, when
prices are determined through a competitive bidding process).
These recent trends portend several major developments in the QF/IPP sector:
• It is reasonable to expect that a considerable proportion of future
electric capacity will be IPP capacity, free from cost-of-service
regulation. In addition. Congressional action to remove some of the
regulatory hurdles faced by IPPs {e.g., exemption from PUHCA
jurisdiction) could increase IPP penetration even more.7 In fact, if
the establishment of affiliate IPPs is made easier by reducing their
regulatory burdens, it is conceivable that some utilities may elect not
As noted previously, these IPPs may eventually be called "exempt wholesale generators".
2-18
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to build any new facilities under cost-of-service regulation. Under
such a scenario. IPPs (as a proportion of total builds) could exceed
the Table 2-7 estimates substantially.
PURPA-QFs will likely continue to exist, but will face increasing
competition from IPPs. In some jurisdictions, certain classes of QFs
may be allowed to obtain long-term power sales contracts outside of
competitive bidding. For example, all QFs below some size range may
be made eligible for such treatment.
Measured in terms of market penetration, gas-fired cogeneration
systems have fared well in the PURPA-QF market because of
relatively low capital costs and the availability of attractively priced gas
supplies. There is also a view that the attractiveness of gas-fired
svstems in the 25 to 75 MW range relative to coal systems has made
them more appropriate for many cogeneration applications. Because
IPPs face no size or operational constraints, this option will allow
large coal-fired power projects (which presumably enjoy economies of
scale) to compete with gas-fired cogeneration projects.
• The QF/IPP industry thus far has been made up of a very large
number of firms. Many industry observers expect one or more waves
of consolidation to occur in the 1990s with the more efficient
companies acquiring projects and/or companies that (1) will enhance
their efficiency through even greater economies of scale and scope,
and (2) represent a good "strategic fit."
From the perspective of this RLA. the key issue is what new electricity producing projects will
be affected by the CAA Amendments.
• The new, non-affiliate IPPs (which are the only ones included in the
CAA Amendments definition) and new large QFs are, in general,
going to be purchasers of allowances for their projects. These non-
affiliate IPPs and large QFs would be no different from other
traditional rate-based utility projects from a CAA standpoint except
that the traditional rate-based utilities may be able to use allowances
from their other plants without having to buy them in the market
place. This seeming advantage, however, would be substantially
mitigated if the market for allowances were well-developed and
allowances were freely traded. Furthermore, large QF-Cogenerators
with steam sales from the cogeneration project may be in a position
to take advantage of the "opt-in" provisions of the CAA Amendments.
• While many small QFs (under 25 MW) would not be affected by the
CAA Amendments of 1990 (see Exhibit 2-9), relatively small waste-
fired projects {e.g. coal waste projects) determined to be affected units
would have to purchase allowances (see Exhibit 2-9). The transac-
tions costs associated with making suitable compliance arrangements
for such small projects may be quite high. Thus, this segment may
bear a high burden under the CAA Amendments.
2-19
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CHAPTER 3
Baseline and Cost Methodology Issues
This chapter provides a foundation for the presentation of cost estimates in Chapter 4 bv
covering two issues. The first section of the chapter discusses assumptions used in creating baselines
for assessing the costs of the regulations. The second section describes the types of costs covered
in the analysis, and the degree to which each cost type has been quantified.
3.1 BASELINE ISSUES
This first section of the chapter covers a series of baseline issues. The first of the four
subsections below defines the specific regulatory and nonregulatory cases evaluated and compared
in assessing the impacts of the regulations. The second subsection discusses the time period over
which the baseline and regulatory cases were evaluated. The third subsection discusses the energy
and economic assumptions used in defining two scenarios for emissions growth in the absence of acid
rain regulation, and the final subsection presents the assumptions used in evaluating the effects of
the statute in the absence of regulations.
3.1.1 Cases Examined
This RIA evaluates impacts under a "regulatory case" (which includes the acid rain
implementation regulations described in Chapter 1) relative to two baseline cases: the "pre-statute"
case and the "absent regulations" case. The pre-statute case assumes that no acid rain legislation was
enacted, and that no further controls on S02 emissions will be imposed. The absent regulations case,
in contrast, assumes that Title IV is in effect but that EPA promulgates no regulations for its
implementation. Under the absent regulations case, S02 emissions must be reduced by 10 million
tons, but there are no regulations to establish S02 allowances or an allowance trading system. By
comparing costs under the pre-statute case to costs under the regulatory case, EPA is able to identify
the costs of the statute and the implementation regulations combined. By comparing costs under the
absent regulations case to costs under the regulatory case which permits allowance trading, EPA is
able to measure the cost savings provided by the implementation regulations alone.
Exhibit 3-1 presents a summary description of the pre-statute, absent regulations, and
regulatory cases evaluated in this report. Each case was evaluated under two scenarios: a high
scenario and a low scenario. Thus, six situations (three cases under each scenario) were evaluated
and compared in all.
3-1
-------
I
EXHIBIT 3-1
Pre-Statute, Absent Regulations, and Regulatory Cases Evaluated
Case
Description
Regulatory
Energy/Economic Assumptions
High
Low
Pre-statute
No Acid Rain/
SO-, Reduction
Requirements
No Acid Rain
Regulations
X
X
Absent
Regulations
SO, Reductions
in 1995 and
20(X) and After
Acid Rain Re-
quirements
without
Implementation
Regulations
X
X
Regulatory Case
SO-, Reduction
in 1995 and
2000 and After
With
Implementation
Regulations
X
X
3.1.2 Time Period Examined
All cases were evaluated over the 1995-2010 period with specific forecasts for the 1995. 2000.
2005. and 2010 periods. These time periods were chosen because they are the same as those used
hv EPA for its earlier legislative analyses and provide for an every-five-year snapshot of the incremen-
tal effects of the legislation and regulations. In addition, the specific forecast years correspond closely
to important statutory deadlines under the acid rain title of the Clean Air Act Amendments of 1990
(CAA):
• Phase I requirements begin in 1995:
• Phase II requirements begin in 2000: and
• Phase II "bonus" allowances expire in 2010.
3.1.3 Energy and Economic Assumptions for High and Low Scenarios
To measure the economic impacts of Title IV of CAA, it is necessary to project estimated
levels of utility air emissions in the absence of Title IV during the time period covered by the RIA.
The levels of utility air emissions are expected to depend upon factors such as the electricity demand,
alternative sources of electricity supply, and fuel costs. Because of the extent of uncertainty
surrounding each of these factors, this analysis relies on high and low electricity growth forecasts to
obtain a reasonable range of electric utility air emissions over the next two decades. In constructing
the high and low scenarios, this analysis uses the energy and economic assumptions that were
developed by EPA during the latter half of 1988 to evaluate the cost and economic impacts of the
proposed acid rain regulations.1 The assumptions are documented comprehensively in a May 19
report, although a brief summary is also presented in Exhibit 3-2. Appendices 3A and 3B of this
See 19X9 F.PA Base Case Forecasts, prepared by ICF Resources Inc. tor the U.S. EPA. May 19N9.
3-2
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EXHIBIT 3-2
Major Assumptions for EPA High and Low Base Cases
(Used as the basis for high and low scenarios)
Energy/Economic
Assumption
Time Period
or Category
1989 EPA Base: Reference Case
High
Low
Crude Oil Prices
(19X8 $/bbl)
1995
2000
2005
2010
18.00
22.00
25.00
29.50
25.00
29.00
31.50
34.00
Electricity Demand
Growth
(percent per year)
1988-2000
2001-2010
2.8
2.3
2.0
1.4
Steam Power Plant
Lifetimes
(years)
Coal/Oil/Gas >50 MW
Coal/Oil/Gas <50 MW
Nuclear
65
45
35
55
45
40
Cogeneration
(billions of kilowatt
hours)
1995
2000
2005
2010
175
208
255
313
195
291
382
474
New Non-Fossil
Capacity
(gigawatts)
2005
2010
0
0
9
20
Repowered Coal
Capacity*
(gigawatts)
2000
2005
2010
0
6
10
4
20
38
* Includes 50 percent increase in capacity due to repowering, in addition to currently
planned projects.
report may be referred to for additional information.
In general, the assumptions used in the low scenario result in a lower forecast of emissions
growth than those used in the high scenario. In particular:
• Lower electricity demand results in lower coal power plant utilization
and the construction of fewer new coal plants;
• Shorter fossil steam power plant lifetimes result in earlier retirements
of higher-emitting existing coal units, which are generally replaced by
new lower-emitting gas or scrubbed coal capacity;
-------
• More repowering with clean coal technologies reduces SO? emissions
rates at repowered plants; and
• More non-fossil capacity and cogeneration (which is usually gas-fired)
reduces the amount of higher-emitting coal-fired capacity operated
and built.
The implications of the differences between the high and low scenarios for the costs of the statute
and the regulations arc discussed at greater length in Section 3.2.3 below.
The change in utility/IPP S02 emissions over time is shown in Exhibit 3-3. As shown in that
exhibit, the SO? emission forecasts for the pre-Statute case between the high and low scenarios
diverge considerably over time with a difference of 3.6 million tons. 17.1 versus 20.7 million tons, in
2000. The divergence in the forecasts is due to the difference in the aforementioned energy and
economic assumptions.
3.1.4 Regulatory Assumptions for Cases
As covered in Section 3.1.1. three cases are compared in this report. For two of these, the
pre-statute and regulatory cases, the regulatory framework to be analyzed was relatively clear-cut.
Under the pre-statute case, no federal regulations other than those in the CAA before 1990 were
assumed. S02 is controlled for existing sources on a source-by-source basis through the existing state
implementation plans of the Clean Air Act; newer sources must meet existing new source
performance standards (NSPS); a continuation of existing state acid rain regulations (as in
Massachusetts, New York, Wisconsin, and Minnesota, for example) was assumed as well.
For the absent regulations case, more developed assumptions were required because the
statute does not completely describe in detail how its provisions would be applied in the absence of
any regulations. The absent regulations case was developed using basically the same set of ener-
gy/economic and pollution control cost assumptions as in the pre-statute case (See Exhibit 3-4 and
referenced appendices). The major difference between the absent regulations case and the pre-
statute case is that the pre-statute case leaves out the impacts of acid rain legislation. The absent
regulations case includes the impact of the acid rain requirements as stipulated in Title IV of the
CAA. The assumptions in the absent regulations case are presented in Exhibit 3-5 with a brief
discussion of each provided below:
• S02 Reductions — The same S02 reduction goals and requirements
stipulated under Title IV are assumed under the absent regulations
case.
• NO^ Reductions — No NOx reductions were assumed in the absent
regulations case or the regulatory case. This RLA focuses only on the
impact of S02 reduction requirements and attendant regulations.
3-4
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EXHIBIT 3-3
Pre-Statute Utility S02 Emissions
25
High Case
20
Low Case
(MMTons)
2010
2000
2005
1990
1995
1985
1980
3-5
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EXHIBIT 3-4
Energy and Economic Assumptions
Absent Regulations (.'nse-
lliyh Scenario
Low Scenario
Energy and Economic
Assumptions
EPA High Assumptions (See
Appendix 3A)
EPA Low Assumptions (Sec
Appendix 3A)
Pollution Control Cost Assumptions
Repowering
Same as High (See Appendix
3B)
Same as Low Plus
Accelerated Repowering
(See Appendix 3B)
Scrubbing Costs
Same as High and Low (See Appendix 3B)
Regulatory Assumptions
Acid Rain Statute With No Trading of Allowances or
Reallocation of Tonnage Limits Between Units
Emissions Trading and Banking/SO-, Tonnage Limits-Existing Units —
There would be no trading or banking of SOt emission allowances
under the absent regulations case. Rather each unit would be
required to meet an annual SO, tonnage limit (as set under Title
IV).2
SQt Tonnage Limits-New (Post-1995) Units — For new units that do
not receive any allowances under the Act, a 95 percent removal New
Source Performance Standards (NSPS) was assumed in lieu of the
zero tonnage limit requirement. While a literal reading of the Act
suggests that, in the absence of any implementation regulations, new
units would have to meet a zero emissions target, this requirement
would make it extremely onerous if not impossible for high growth
states and utilities to meet energy demand within Phase II (2000) SO-,
requirements.3 Accordingly, it was assumed by EPA that in the
absence of implementation regulations, some provisions would have
been made for economic growth, while limiting SO? emissions growth
through a more stringent NSPS (e.g.. 95 percent removal in lieu of the
current 70 to 90 percent removal requirement).
Annual tonnage limits under the baseline cases or SO. allowances under the regulatory cases were developed
based on the statutory language of the Act and the National Allowance Data Base, version 1.0.
Note that a zero tonnage limit would eliminate all new fossil fuel fired units (even natural gas emits very low
levels of S(); emissions) making it extremely difficult to meet new growth needs.
3-6
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EXHIBIT 3-5
Absent Regulations Case — Assumptions on Emissions Requirements
Phase I
(1995)
Phase II
(2000)
SO-, Reductions below 19K0 levels
from Utilities and IPPs
(in millions of tons)
3 to 4
S to S.5
NOx Reductions11
None
None
Emission Trading/Banking
None
None
Phase I and II SO-, Tonnage Limits
- Existing Units
Same as Act: Tonnage
Limits in Table A plus
200.000
Additional Tons
Same as Act
Phase II SO-, Tonnage Limits
New (Post- Nov. 15,
1990) Units
....
95cc Removal Assumed in
Lieu of Zero Allowances
Phase I Technology Allowances
None
....
Conservation/Renewables Reserve
None
None
Allowance Auctions: Fixed Price
Sales or Guarantees
None
None
Clean Coal Repowering Phase II
Extension
....
Included
Phase I Minimum Fuel Constraints
Includedb
....
a NOx reduction requirements are not included in the absent regulations or the
regulatory cases developed for this RIA.
h Minimum Fuel Constraints included as part of the permits and compliance plans under
the Act.
Phase I Technology Allowances — None of the 3.5 million ton Phase
I Extension Reserve was assumed to be allocated. This reserve would
provide tor 3.5 million tons of additional allowances to units installing
eligible control technology (90 percent SO-, removal or greater) in
Phase I.
3-7
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Conservation/Renewable Reserve: Auctions and Fixed Price Sales —
Similar to the Phase I Reserve, no conservation and renewables
reserve or auctions and fixed price sales were assumed in the absent
regulations case. Consistent with this treatment, there was no as-
sumed withholding from basic Phase I and II allowances (or tonnage
limits) for either of these reserves or special sales. Similar to the
Phase I extension reserve, emission allowances from either the
auctions of fixed price sales or special reserves would not be allocated
in the absent regulations case because they could not be traded or
banked.
Clean Coal Repowering Phase II Extension — As stipulated in Title
IV, units that repower with clean coal technologies (e.g., fluidized bed
combustion, integrated gasifier combined cycle, etc.) receive a four
year extension until December 31. 2003, during which time they
receive additional emission allowances. Since these extra allowances
apply only to the specific units that repower (and are non-tradeable),
they were assumed to apply in the absent regulations case and were
modeled as increases in the unit level tonnage limits.
Phase I Minimum Fuel Constraints — Under Title IV, Phase I affected
sources are restricted from reducing their utilization below "baseline"
levels (e.g., 1985-87 average fuel consumption) unless it occurs
through conservation or energy efficiency, or the compensating source
of generation becomes an "affected" unit. These minimum fuel
constraints were included in the baseline cases.
3.2 COST ISSUES
This second section of the chapter discusses the cost categories examined in the analysis, the
cost measures used, and the role of the high and low scenarios in dealing with uncertainty.
3.2.1 Types of Costs
Several broad classes of costs are considered to varying degrees in this regulatory analysis: real
resource costs of administration to government; real resource costs of compliance to the regulated
community; transfers between the regulated community and other sectors of society; and lost social
welfare due to reduced output ("dead-weight" losses).
Real resource costs to the government are represented by the cost of additional staff to
process applications or monitor compliance. Real resource costs to the regulated community are
exemplified by the hardware-related costs of scrubbers and continuous emissions monitor systems
(CEMS) added to power plants, costs of reporting and recordkeeping of emission levels, and the
incremental costs of producing and transporting low-sulfur coal compared to high-sulfur coal.
Transfers occur where a loss to one segment of the economy represents a pure gain to
another, and thus do not represent a net loss to the economy. In the context of the Acid Rain
Program, transfers can occur when increased demand for low sulfur coal drives its price up more than
the increase in the average cost of extracting and transporting the coal plus the value of the coal in
3-8
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other uses. In the short run, tor example, there may be a limit to the rate at which coal can he mined
and shipped. The increased demand tor low sulfur coal brought about by the Acid Rain Program
could allow a mine that was already operating at full capacity in the pre-regulation case to charge a
higher price for the same coal even though its average production costs have not changed. In this
case, nothing would change except that the utilities would pay more and themine operator would
receive more: there would be no change in real resource costs. Even in the long run (the time-frame
considered in this analysis) the price of low sulfur coal could be driven up by increased demand if low
sulfur coal resources were limited. Where resource owners receive high returns for the same coal-
bearing land that would have been sold in the pre-statute case at low prices, there is a transfer rather
than a resource cost. Higher coal prices that are a cost to electric utilities would represent a gain
to the owners of coal resources; thus, net costs to society as a whole would not change.
Transfer costs, which are not true costs to society as a whole, have not been considered in
detail in the analysis. A qualitative assessment of the direction and magnitude of transfers is included
in Chapter 4.
The last category of costs is the dead-weight loss, which is an intangible loss in the value of
the economy's production that results from reductions in outputs. The dead-weight loss resulting
from a drop in output is measured as the difference between the true value to consumers of the lost
output and the production cost savings realized when output is reduced. In cases in which changes
in prices are significant, measuring dead-weight losses provides an important measure of the true costs
of forcing consumers to turn to less valuable substitutes. This analysis does not consider dead-weight
losses quantitatively because qualitative analysis shows them to be much smaller than the costs and
cost savings resulting from the statute and the regulations.
In summary, this analysis explicitly provides measurement of the following costs:
• Costs of S02 reductions and emissions monitoring systems imposed by
Title IV of CAA in the absence of implementation regulations by
EPA;
• Cost savings due to the implementation regulations because they
provide flexibility in achieving S02 reduction targets; and
• Costs of the implementation regulations to the federal government
(administrative costs) and the cost to the regulated community of
compliance (net of monitoring costs imposed by the statute).
3.2.2 Cost Measures Presented
Three cost measures are presented in this analysis, including annualized costs, levelized
percent changes in electricity rates, and present values of total costs.
Annualized costs include the annual increases or changes in costs forecast for 1995. 2000,
2005, and 2010. They include fuel, operating, transaction, administrative, and capital costs. For
comparison purposes, incremental capital investments are levelized over the book lifetime of the
equipment (generally, 30 years) and are presented as annualized capital costs.
Levelized percent changes in electricity rates indicate the national and regional percent
change in rates associated with the change in annualized pollution control costs.
3-9
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EXHIBIT 4-7
Monitoring Equipment and Operation and Maintenance Cost Estimates'1
(Thousands of 1990 Dollars)
Fixed Cost
; Capital Equipment
(per unit)
| Base Equipmentand Installation
SX1.4
NOx Monitor (CEMS)
20.6
OVCO-, Monitor (CEMS)
10.8
SO-, Monitor (CEMS)
22.5
i
Flow Monitor
19.7 !
Opacity Monitor (COM)
:
35.7
Data Acquisition System (DAS)
41.5 ;
Customized DAS Software
70.0
Operation and Maintenance
1
Annual Cost
Relative Accuracy Test Audits
15.0
Labor
24.4
Calibration Gases'1
30.0
Other Equipment O&M
9.3
These estimates include the costs of installation, start-up and training, and
certification in addition to the capital cost of the equipment.
Calibration gases are not necessary for units using alternative methods of monitoring SO,
emissions. These units, therefore, will only incur incremental calibration gas costs tor other
CEMS equipment ^$15,000).
The costs to EPA under the regulatory options include the cost to conduct periodic plant
inspections, and to process, review, and evaluate emissions data reports submitted by the utilities.
EPA expects to conduct inspections at 11 plants (roughly 10 percent of the regulated community)
in 1995. six plants (roughly five percent of the regulated community) from 1996 through 1999. and
37 plants (roughly five percent of the regulated community) each year starting in the year 2000. EPA
assumes that a plant inspection will require an average of 60 hours at a cost of $34 per hour."5 In
addition, EPA assumes that an average of 30 minutes will be required to process, review, and evaluate
the quarterly data reports from each of the affected plants.26
EPA estimate.
EPA estimate.
4-20
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The present value of costs indicates the total costs over the entire 1995 to 2010 period, with
costs in later years discounted to allow for the time value of money. For annual pollution control
costs, a real discount rate of 5.4 percent per year is assumed to reflect the value of capital diverted
from productive investments.4 For costs to EPA and for costs to industry that do not displace
productive investments, a lower social discount rate of three percent per year is assumed.
These measures provide a snapshot of costs over several forecast years, as well as the total
cost impacts over the next twenty years.
3.2.3 Uncertainties and Sensitivity Analyses
Some of the major sources of uncertainties in the analysis and their effect on electric
generating costs include the costs and availability of pollution control equipment: net growth in
demand for electricity from fossil fuels plants; and prices of lower sulfur fuels. These sources of
uncertainty are summarized below.
• Pollution Control Equipment Costs and Availability - The costs of
conventional S02 removal equipment (e.g., scrubbers) as well as the
availability and costs of newer low-cost clean coal technologies (CCT)
are uncertain and will have an important effect on the costs of the
Acid Rain Program.
• Electricity Demand Growth/Nuclear Renewables - The growth in the
demand for electricity generation over the next 10 to 20 years is also
uncertain and will depend on economic and demographic factors, as
well as improvements in energy efficiency and conservation. Electrici-
ty generation growth (along with the penetration of renewable or non-
fossil fuel technologies and potential improvements to nuclear power
plant reliability) will in large measure determine the utilization of
existing coal and oil-fired units. It will also affect the rate of construc-
tion of new coal power plants in the future and hence, the amount of
SO, emissions growth which will have to be offset under the acid rain
requirements. Costs will be affected significantly as a result.
• Lower Sulfur Fuel Costs - The forecasted prices and price premiums
between higher and lower sulfur fuels (e.g., high and low sulfur coals,
residual oil, and gas) will directly affect the costs of switching to lower
sulfur fuels under the acid rain regulations.
The range of uncertainties in cost impacts due to the factors described above is captured
through the use of the high and low emissions growth scenarios discussed earlier. The high and low
scenarios also provide a range for the cost savings achieved due to the implementation regulations.
EPA's two-stage discounting procedure suggests the use of a seven percent rate for annualizing capital expenses
to convert them into consumption terms, and then a three percent rate for finding the present value of reduced
consumption (a combination of the annualized capital expenses plus O&M expenses). The use of a discount
rate of 5.4 percent, EPA's estimate of the utility industry's weighted average cost of capital produces present
value estimates that are very similar to the explicit use of the two-stage approach because it is midway between
the three percent rate appropriate for O&M expenses and the seven percent rate for capital.
3-10
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Two areas of uncertainty or sensitivity are not. however, captured by the EPA high and low
scenario assumptions. The first involves the uncertain ability to and cost of switching Eastern
bituminous-only coal fired boilers to switch to Western low-sulfur sub-bituminous coals. The second
involves the potential penetration of low-cost sorbent injection and other retrofit clean coal
technologies. In both cases. EPA has assumed conservatively for purposes of this-RIA that these SO-,
control options would not be available. To the extent these options are available and economically
feasible, the costs of the acid rain regulations would be lower and the cost savings associated with the
implementation regulations would be higher than presented herein.
3-11
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CHAPTER 4
Costs
This chapter presents analyses of the costs of the emissions reductions with and without the
use of transferable allowances and the costs of a variety of regulatory provisions associated with the
implementation of the allowance system. The first section of the chapter discusses the types of costs
incurred hv the regulated community and the changes in the costs attributable to the statute and the
regulations. The following sections address the costs of implementing the statute and the trading
regulations. The first category of implementation costs presented are those related to conducting
allowance trading. The chapter then presents estimates of the costs of allowance auctions, direct
sales, and IPP written guarantees, followed by estimates of the costs of emissions monitoring, permits,
and energy conservation/renewable energy. Where possible, implementation costs in each category
are divided into costs to EPA and costs to the regulated community, and are presented in terms of
annual costs and present value costs discounted to the time of promulgation of the regulations.
This chapter also provides a summary of the total costs of the statute and the regulations,
including both the costs related to emissions reductions and the associated implementation costs.
4.1 COSTS OF S02 REDUCTIONS WITH AND WITHOUT TRADING
EPA estimated the cost changes associated with the statute and the regulations using ICF's
Coal and Electric Utilities Model (CEUM).1 CEUM is a detailed linear programming, engineering-
economic model (see Exhibit 4-1), that contains coal supply, transportation, electric utility demand,
transmission, and non-utility energy demand segments. It is linked with databases and other
supporting models, including a Coal and Utilities Information System (CUIS), which contains data
on all electric utility units.
The model estimates acid rain compliance costs and cost savings by considering the choices
likely to be made at each power plant and across all power plants affected by the regulations. For
every plant, the model calculates the costs of each strategy that could be used to meet a given set of
emissions requirements while meeting the demand for electricity and other utility system operating
constraints. The model determines which of the strategies costs the least, across all the power plant
units within a utility system, and assumes that the operator of a power plant will choose the lowest
cost combination of strategies. The selection of compliance strategies within the model automatically
and simultaneously affects the prices of various types of coal and other fuels and vice versa. The
model then reports total costs by adding up the costs of the strategies that are assumed to be chosen.
CEUM was originally developed in 1975 as the National Coal Model and has been extensively refined and updated
since then. 1CF has used the model as a primary analytic tool in analyses for EPA, other federal agencies, and
private companies for proposed acid rain policy initiatives and bills. The model has also been used in fuel price and
energy market forecasting and planning studies, electric utility integrated capacity planning studies, and environmen-
tal compliance and pollution control technology assessment studies.
4-1
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EXHIBIT 4-1
BASIC CEUM STRUCTURE
Coal Contracts
Coal Production
Electricity Demand
Oil and Gas Prlc##
Coal Supply Curves
Coal Transportation
Non-utility
Coal Demands
Coal Production
Capacity Dats
Coal Raaoures Data
Coal Transportation
Network
Fossil Powerplant
Operation and
Capacity Expansion
Non-fossil Generation
-Nuclear
•Hydroelectric
•Qeothsrmal, Blomass,
Solar, Wind, etc.
FossU Powsrplsnt Dsta
• Envlronmsntal
Standarda
• Production
Efflclsncy
• Design Limitations
•Availability
• New Powsrplant
Construction Costs
4-2
-------
In addition to increases or decreases in fuel costs as a consequence of fuel switching, there
are also capital costs associated with shifts to lower sulfur coals. For example, additional investment
in particulate control equipment may be required to accommodate lower sulfur coals at certain power
plants because of the inherent characteristics of the ash in lower sulfur coals. Also, some coal-fired
power plants receive all of their coal shipments by truck from local mines. Receiving shipments from
more distant coal mines {e.g.. Western low-sulfur mines) may require changes in coal handling
facilities to receive coal bv rail.
Switching to Lower Sulfur Oil or Natural Gas
Power plants burning higher sulfur residual oil may shift to lower sulfur residual oil. distillate,
or natural gas in order to reduce S02 emissions. Lower sulfur oil is more expensive than higher
sulfur oil because of the substantial capital and operating costs incurred by refineries in removing
sulfur from their products. Gas can also be more expensive than oil. depending on market conditions.
In contrast to shifts from high to low sulfur coal, it is unlikely that shifts in oil or gas use by
utilities will have significant effects on relative fuel prices. While the electricity generating sector
consumes more than three quarters of total U.S. coal production, it accounts for less than one-quarter
of natural gas demand in the U.S. and only a very small portion of worldwide oil demand. Thus, the
oil and natural gas markets are unlikely to be affected by the moderate shifts in electric utility de-
mand forecast under acid rain legislation. Some natural gas price increases, however, are likely to
occur as electric utility natural gas demand increases.
Shifts in Power Plant Utilization
More intensive utilization of already low-emitting power plants matched by reduced utilization
of higher-emitting power plants can be a cost-effective S02 reduction strategy in many instances.
This strategy tends to increase the use {i.e.. the capacity factor) of power plants that already have
scrubbers (often using medium or higher sulfur coals) or power plants using lower sulfur coals without
scrubbers.
4.1.2 Cost Impacts
This section presents estimates of the costs associated with changes in S02 emissions under
the statute and the implementation regulations. Three cost comparisons are presented:
• Costs under the absent regulations case as compared to the pre-
statute case:
• Costs under the regulatory case, again compared to the pre-statute
case; and
• Costs under the regulatory case compared to the absent regulations
case.
The last cost comparison shows the incremental cost savings attributable to compliance with
the implementation regulations relative to compliance with the statute by itself.
As discussed in Chapter 3, each cost comparison was made twice, once under the assumptions
of the low scenario and once under the assumptions of the high scenario. The change in annualized
4-4
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cost impacts in three years (1995. 2000. and 2010) are presented and compared for both of these
scenarios. In addition, the present values of costs are presented and discussed. The section also
presents the S02 emission reduction impacts under the various cases and scenarios. More detailed
emission and cost forecasts for these years and 2005 are presented in Appendix 4B.
Annual SO-, Emission Reduction and Cost Impacts
Exhibit 4-2 presents the changes in annual costs and S02 emissions during Phase I (1995) and
Phase II (2000 and 2010).2 The first four columns of figures in the table show costs and emissions
under the absent regulation case and the regulatory case relative to the pre-Statute case. The last
two columns show emissions and costs under the regulatory case relative to the absent regulation
case.
During Phase I (1995), the S02 reductions forecast for the regulatory case are close to those
forecast for the pre-Statute case under both the high and low scenarios. Costs, however, are
significantly lower in the regulatory trading case than under the absent regulations case. The cost
savings provided by the regulations amount to $0.4-0.6 billion, or about a 40 percent reduction in the
costs of the statute. These savings arise when units that have high emissions control costs are allowed
to meet their regulatory obligations by reducing emissions less, or not at all, by purchasing allowances
from units with lower control costs. These compliance cost savings for the difficult-to-control units
more than outweigh the added control costs for additional emissions reductions by units with lower
incremental control costs.
In Phase II (2000), the implementation regulations cut the annual costs of the statute even
more substantially. Costs in the regulatory case are lower than in the absent regulations case by $2.1-
2.8 billion, which is a savings of 60 to 65 percent. This reflects the even greater value of emissions
trading as the reduction requirements become more stringent. Under the absent regulations case,
virtually all power plants must consume very low sulfur coals or scrub to meet the Phase II unit-by-
unit requirements. Emissions trading permits some power plants to overcontrol emissions and sell
the allowances; the allowance purchasers, which have higher incremental control costs, are then able
to reduce their compliance costs substantially. Cost savings from trading in this way represent
improved efficiency in obtaining the same level of emissions reductions. In addition, some of the cost
savings arise because S02 allowances are "banked" from Phase I in the regulatory case and are used
to offset more costly reductions at the beginning of Phase II in 2000.
By 2010, the cost savings provided by the regulations compared to the absent regulations case
are somewhat lower ($1.3-1.4 billion, which is a reduction in costs of 30 to 60 percent). This
reduction occurs because banked SO? allowances are forecast to be used up by 2005 and thus annual
S02 reduction requirements are about 0.1-0.5 million tons lower under the regulatory cases with
trading th^n under the absent regulations case (instead of about 2.1-2.2 million tons lower as in 2000).
Present Value of Costs and Cumulative S02 Reductions
Exhibit 4-3 presents the total cumulative S02 reductions in the electric generating sector as
well as the change in present value of costs. As shown in the figure, the present value of the costs
resulting from the S02 reductions over the 1991 to 2010 period (in 1990 dollars) is estimated to be
Existing units of 25 MW or less of capacity are not covered by the regulations, but new units less than 25 MW are
covered. New units under 25 MW were not. however, considered in this analysis. Discussion of this small number
of units is included in the attachment to this document.
-------
EXHIBIT 4-2
Forecasted S02 Emission Reductions and Annual Cost Impacts On
The Electric Generating Sector
PHASE I (1995) |
Absent Regulations j
Regulatory Case
| Net Change (Trad-
(No Trading) !
With Trading
1 ing-No Trading)
-i : 1
Low
High
|
Low
High
Low
High i
: SO, Emission Reductions (in millions
! of tons helow 19X0 levels)
Electric litilitv/IPP
Other Non-Utility^
TOTAL
-4.2
-1.5
-5.7
-2.5
-1.5
-4.0
-4.2
-1.5
-5.7
|
-2.8
-1.5
-4.3
+ 0.0
+ 0.0
1
-0.3
!
-0.3 :
Changes in Annualized Costs (in
billions of 1990 S)
1.0
1.5
0.6
0.9
-0.4
-0.0 :
i
Phase II (2000)
Absent Regulations
(No Trading)
Regulatory Case
With Trading
Net change (Trad- j
ing-No Trading) i
Low
High
I^ow
High
Low
High
SO, Emission Reductions (in millions
of tons below 1980 levels)
Electric Utility/IPP
Other Non-Utility1
TOTAL
-8.6
-1.5
-1.0.1
-8.1
-1.5
-9.6
-5.7
-1.5
-7.2
-5.7
-7.2
+ 2.9
+ 2»
+ 2.4 |
+ 2.4
Changes in Annualized Costs (in
billions of 1990 S)
3.2
4.9
1.1
2.1
-2.1
-2.8 j
Phase II (2010)
Absent Regulations
(No Trading)
Regulatory Case
With Trading
Net Change (Trad-
ing-No Trading)
Low
High
Low
High
Low
High !
SO, Emission Reductions (in millions
of tons below 1980 levels)
Electric Utility/IPP
Other Non-Utility"1
TOTAL
-9.1
-1.5
-10.6
-8.5
-1.5
-10.0
-8.5
-1.5
-10.0
-8.4
-1.5
-9.9
+0.6
+~
-------
EXHIBIT 4-3
Cumulative S02 Reductions Through 2010
(Below 1980)
125
100
75
50
25
High Case
Low Case
' ft** ~'V ^
/ / ^ / Ay ^ /|V
V * ^
/' <• x* /// >i/f'/s/tto/
'' > i < '£
-"'¦'"iZU'-
/s»
legulatory
Case
Absent
Regulation
Case
<0
HS75
|
250
125 ¦
100
; ,
25 •
WS'-W.
wsw^x-
Absent
Regulation
Case
Present Value Of Costs Through 2010
(Billions of 1990 Dollars)
High Case
Low Case
Absent
Regulation
Case
egulatory
Case
Absent
Regulation
Case
4-7
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only half as great under the regulatory case as under the absent regulations case. In other words, the
implementation regulations allow a 50 percent reduction in the costs of the statute. These savings
reflect the Phase I and Phase II cost savings discussed in the previous section.
Cumulative SO-, reductions are about 10 to 16 million tons or about 10 .to 15 percent lower
in the regulatory cases than in the absent regulations case. This reflects several factors shown below
in Exhibit 4-4.
EXHIBIT 4-4
Comparison of Cumulative S02 Reductions
Cumulative S02 Reductions (million tons) !
(below 1980 levels)
Total Regulatory Case
92-105
No Phase I Extension Allowances
+3.5
No Cap on New Plant Emissions
-3 to -5
No Retirement Credits/Overcontrol
+9 to +18
Total Absent Regulations Case
102-121
First, there is no 3.5 million ton allowance reserve assumed in the absent regulations case
(which is forecasted to be fully allocated to Phase I units with scrubbers in the regulatory case).
Eliminating this reserve increases cumulative S02 reductions. Second, there are no credits for plant
shutdowns or retirements since no trading is permitted and only unit-by-unit limits apply. Thus, when
a unit retires, its emissions tonnage limit cannot be transferred to other power plants as permitted
in the regulatory case. Third, some units are overcontrolled for economic reasons (e.g., gas is used
at units with higher emission limits because it is less costly). These factors are all partially offset by
the fact that no "cap" on new plant emissions is assumed in the absent regulations case.
In sum, however, the present value of costs are reduced by about 50 percent because of
emissions trading, while cumulative S02 reductions are 10-15 percent lower. Further, it should be
stressed that the regulatory case with trading still achieves the 10 million ton S02 reduction goal of
the legislation during Phase II. The "additional" reductions achieved in the absent regulations case
are above and beyond the goal stipulated in the Act.
IMPLEMENTATION COSTS
The next four sections, 4.2, 4.3, 4.4, and 4.5, address the costs of the implementation
regulations. Section 4.2 discusses costs related to conducting allowance trading. Section 4.3 provides
the costs of allowance auctions, direct sales, and IPP written guarantees. Section 4.4 presents the
costs of continuous emissions monitoring and Section 4.5 presents costs of permits. Finally, Section
4-8
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4.6 provides a summary of the total costs of the statute and the regulations including both the costs
related to emissions reduction and the associated implementation.
4.2 COSTS OF ALLOWANCE TRACKING AND TRANSFERS
Costs associated with the use of allowance markets can be separated into administrative costs
and costs to participants. In reviewing the costs, it should be noted (as discussed in Section 4.1) that
the administrative activities responsibile for these cots provide substantial savings as well in that they
make the cost reducitons of the allownace system possible.
4.2.1 Administrative Costs to EPA
Administrative costs to EPA will include costs for developing and maintaining an allowance
tracking system, and costs for executing allowance transfers among allowance accounts.
Allowance Tracking System
Section 403 of the Act requires EPA to establish a system for tracking allowances. This
section estimates the cost to EPA of developing and maintaining an allowance tracking system. The
allowance system regulations set the context for the allowance tracking system, which is currently
being developed by EPA. Because the tracking system development is in a very preliminary stage,
the associated costs contained in this section are presented as preliminary range estimates.
In order to track allowances, the allowance tracking system will need to include information
on: 1) allowance allocations for each affected unit. 2) allowance transfers and deductions for
emissions, 3) allowance holders, and 4) reported emissions from the unit. Also, to allow for the
transfer of future year allowances, the allowance tracking system will contain allowance information
for thirty years into the future. EPA plans to make the information compiled in the allowance
tracking system available to the public by some means of electronic access.
Based on preliminary development, the estimated total cost for developing an operational
allowance tracking system is between $800,000 and $ 1.500.000.3 The annualized cost of develop-
ment. if the system's costs are spread over the 18 years from 1993 through 2010, is between $60,000
and $110,000. Once in place, EPA will incur annual operation and maintenance (O&M) costs for
running an electronic transmission network, system enhancement, general maintenance, and employee
salaries. These O&M costs are estimated to range from $100,000 to $200,000 annually, for a present
value of between $1,335,000 and $2,670,000.4 The total cost for the allowance tracking system, then,
including development and O&M costs, is estimated to range between $2,135,000 and $4,170,000,
with an annualized range of between $160,000 and $310,000.
Allowance Transfer System
The Act requires EPA to receive and record allowance transfers. EPA will perform the
following activities when an allowance transfer notification is submitted: 1) review the transfer
information for completeness and to ensure all requirements are met, 2) record the transfer by
EPA estimate.
EPA estimate.
4-9
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deducting allowances from the transferror and adding them to the transferee. 3) notify both the
transferror and transferee that either the transfer was recorded or whv it was not recorded. The
average estimated burden and cost for EPA to perform these activities for each transfer submission
is tine hour and $34 respectively^.
For the purposes of this analysis. EPA is assuming that about 3.000 allowance transactions
will be made per year starting in 1993 and that each one will require one hour for processing for a
total of 3,000 hours of processing per year.6 At a cost of $34 per hour. 3.0(H) hours per year will
cost about $102,000 annually.7 The present value of $102,000 per year for the 18 years, from 1993
through 2010. discounted at three percent per year to 1992. is approximately Si.400,000.
Total Administrative Costs
Adding the costs of allowance transfers to the costs for establishing and maintaining the
tracking system yields total costs of between $3.5 million and $5.5 million. These estimates equal
between $250,000 and $400,000 on an annual basis.
4.2.2 Participant Costs
Costs associated with participating in an allowance trading market can be divided into two
components: market evaluation costs and transactions costs. First, potential participants must spend
time and/or money to analyze their compliance strategies, evaluate the potential advantages of using
the allowance market, and determine the number of allowances they would wish to buy or sell at
various prices. Second, allowance purchasers will generally incur costs in finding allowance holders
willing to sell the quantity of allowances they need. These costs may take the form of time spent
contacting allowance holders and negotiating deals. These costs are more likely, however, to take
the form of commissions paid to allowance brokers, who will specialize in collecting and analyzing
information on supply and demand for allowances.
Costs to participants are difficult to project. Market evaluation costs are uncertain, depending
in part on the complexity of compliance choices available to various affected entities and on the
amount of effort spent evaluating the available choices. It is impossible to predict whether the
addition of the option of trading allowances would increase or decrease the total costs of evaluating
compliance options, because some, utilities may find that the possibility of complying with emissions
EPA estimate.
Number of affected sources is based on Economic Analysis of Proposed Regulations for Auctions. Direct Sales, and
IPP Written Guarantees, p.5, note 3. The assumption of three transactions per entity is based on EPA judgment
that sources will need to adjust their allowance holding throughout the year as emissions and economic factors
change. Entities are assumed to participate in allowance trading even before they are directly affected in order to
prepare themselves for compliance when they are affected. The estimate of 3,000 transactions per year is based
on an estimate that there will be about 340 entities (240 utilities and 100 IPPs) affected in Phase II. and that each
will make an average of three allowance sales per year (with some making more than three and others fewer than
three), for a total of about 1,000 sales by affected units. In addition to these sales by affected units. EPA is
assuming there will be an additional 2,000 sales by non-affected entities including brokers and other market
participants).
The average total compensation rate of S34 per hour consists of 1991 direct compensation at the Grade 11, Step
3 level plus overhead costs [EPA, "Draft Information Collection Request for Proposed Title V Operating Permits
Regulations," February 12, 1991],
4-10
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standards by purchasing allowances eliminates the need to evaluate more complex technology-bused
compliance strategies.
While transactions costs are more predictable than evaluation costs, transactions costs are still
subject to uncertainty, depending both on the volume of transactions and on the-cost per transaction.
Volumes can be predicted using the ICF Coal and Electric Utilities Model (CEUM) described in
Section 4.1. Costs per transaction will depend heavily on the characteristics of the allowance market.
It the market develops the characteristics of financial or commodities exchanges (i.e.. frequent
transactions, publicly available information on prices and trading volumes) and if deals are not
complicated by public utility commission involvement, then transactions costs should be comparable
to the small commissions charged by stock brokers (as low as 0.25 percent).'s At the other extreme,
if trades are infrequent, advance approval of trades by public utility commissions is required, deals
are complex, and summary price and volume information is kept secret, transactions costs mav be
much higher. An analogy might be drawn to the coal market, a market with differentiated products
and private price information in which commissions have been in the range of one to seven percent
of the value of each deal.
For any given trade, the transactions costs will also depend on the total value of the
allowances exchanged. Because of the economies of scale for larger transactions, brokers generally
charge less per unit for larger transactions. For example, one stock broker charges a commission of
5.2 percent to the buyer in a trade totalling $2,500: 0.8 percent for a trade worth $50,000; and only
0.33 percent for a $250,000 trade.9 For this reason, the smallest participants in the market are likely
to experience considerably higher transactions costs as a percentage of their trades.
Finally, transactions costs will be affected by the amount of market analysis and advice
provided by allowance brokers along with the service of buying or selling allowances. Full-service
stock brokers typically charge higher commissions than discount brokers who handle only transactions.
4.2.3 Assumptions Used to Project Participant Costs
For this analysis, EPA is assuming that a smoothly functioning and efficient market for
allowances will develop (though for the purposes of sensitivity analysis a less efficient market will be
assumed). EPA is, therefore, assuming that the average transactions costs as a percentage of the
value of allowances traded will be comparable to the commissions in existing, efficient financial
markets. On the assumption that a certain amount of brokering will involve market analysis and
advice, EPA is assuming that transactions costs will average 1.5 percent of the value of trades. This
average will be composed of lower costs (as low as 0.1 percent) for the largest trades accompanied
by the least advice, and higher costs (up to five percent or more) for the smallest trades. Average
costs of completed transactions are assumed to include all of the costs of negotiating allowance
transactions, including preliminary negotiations that may not result in trades immediately.
"At Your Service: a Directory of Information for Clients of Vanguard Discount Brokerage Services." The Vanguard
Group. 1989.
Figures quoted are the total for the buyer and the seller, with no market analysis or advice provided, based on
commissions quoted in "At Your Service: a Directory of Information for Clients of Vanguard Discount Mrokerage
Services," The Vanguard Group, 1989.
4-11
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Transactions costs are assumed to he shared equally between buyers and sellers of allowances.1"
For a sensitivity analysis, EPA also examines a case in which the market is much less efficient.
with transactions costs averaging six percent across all trades, with even higher costs for small
_ „
traders.
The total value of trades among allowance users is assumed for this analysis to range between
$1 billion and $2 billion annually.1' There may be additional trades among brokers, speculators,
and other individuals who are outside of the regulated community. The costs of these trades have
not been included in the analysis for three reasons. First, any estimate of the number of transactions
of this type would be highly uncertain. Second, the transactions costs per trade for brokers and other
professional securities traders are likely to be low, given their access to the market and frequent
contacts with potential traders. Finally, brokers and speculators are not part of the regulated
community, and their participation in trades among themselves is voluntary.
4.2.4 Estimated Total Costs
Based on EPA's assumptions of transactions of between $1 billion and $2 billion in annual
allowance trades and transactions costs of 1.5 percent, the annual transactions costs to participants
will range between S15 and $30 million; annual costs to EPA of between $0.25 and $0.4 million raise
1 ^
the nationwide cost to between SI5.25 and $30.4 million annually. The present value of
transactions costs to participants is equal to between $200 million and $400 million: administrative
costs to EPA increase these totals to between $204 and $406 million.14
EPA estimates that transactions costs could be four times as great if the market for allowances
is relatively inefficient and commissions average 6.0 percent rather than 1.5 percent. Annual costs
under these assumptions would range between $60 million and $120 million, amounting to present
values of between $800 and $1,6 billion.1*' The wide difference between the low and high
In theory, the distribution ot" commissions between buyers and sellers depends on their relative price sensitivity. For
example, if buyers and sellers are equally sensitive to price changes, then they will each absorb half of the
commission. On the surface, it may appear that the seller is paying all of the commission, but market forces will
tend to force the price up by one-half of the magnitude of the commission. This price change will shift half of the
transactions cost to the buyers. EPA has not attempted to estimate the relative price sensitivity of buyers and
sellers. Rather, their sensitivities have been assumed to be equal; thus, EPA is assuming that transactions costs are
shared equally between buyers and sellers.
ICF estimate of transaction costs under market conditions similar to those in the coal market, where transactions
costs have ranged between one and ten percent over time, depending on the size and complexity of the trade and
the degree of risk.
Based on model results for interstate trades, scaled up to account for intrastate trades.
This figure is assumed to include S23.500 in EPA administrative costs, which are well within the rounding error of
(he estimated participant costs.
Present value was calculated as of 1992 using a discount rate of three percent per year, and IS years of costs
starting in IW.
Transactions volumes are likely to be closer to the lower end of the range in an inefficient market, because some
trades that would be worth making given a commission rate of 0.25 percent would be unprofitable if commissions
were three percent or 10 percent.
4-12
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transactions cost cases suggests the importance of encouraging the development of an efficient
market.
4.3 COSTS OF AUCTIONS, SALES. AND INDEPENDENT POWER PRODUCER
GUARANTEES
This section summarizes the costs of three programs under the proposed regulations which
are intended to aid in the development of an allowance market and improve access to allowances for
new entrants to the regulated community. These regulations are covered in a separate rulemaking,
hut are summarized here for completeness. These programs and their costs are covered in detail in
a separate document. Economic Analysis of the Proposed Acid Rain Regulations for Auctions. Direct
Sales, and IPP Written Guarantees. As with the administrative costs, the costs associated with these
programs should be reviewed in light of their contribution to the integrity and success of the
allowance system, with the substantial cost reductons it makes possible.
Section 416 of Title IV authorizes the Administrator to reserve allowances to sell through
auctions, direct sale, and Independent Power Producer (IPP) written guarantees. The auctions, direct
sale, and IPP guarantee provisions of Title IV are intended to provide some certainty that units will
have a public source of allowances beyond those allocated initially for existing units. In addition, the
auctions are expected to help signal price information to the allowance market early in the program.
4.3.1 Spot and Advance Auctions
Spot (for emission allowances to be used in the current year) and advance (for emission
allowances to be used in future years) auctions will be held early in each calendar year to allow new
and existing units time to plan for end-of-the-year compliance. In addition to the reserve allowances
withheld specifically for the auction,16 unsold allowances from the direct sales of the previous year
will also be sold in the EPA auction. Other allowance holders will also be permitted to sell
allowances through the EPA auctions; their allowances will be sold after the sale of the allowances
EPA must withhold.
The proceeds from the sale of other allowances will be transferred at the time of the auction
from the purchaser to the seller via EPA. EPA will also handle the transfer of proceeds to the
original holders of the auctioned allowances withheld by EPA. Any unsold allowances will be
returned to the original holders of those allowances.
EPA is required to report publicly on the results of each auction. To provide sufficient
information for market participants to gauge the demand and the price range for allowances, EPA
proposes to report the names of all bidders and their bids (successful and unsuccessful).
4.3.2 Direct Sales
The Clean Air Act as amended establishes a Direct Sales Subaccount of 50.1)00 allowances
to be sold annually for $1,500 each (adjusted for inflation using the 1990 Consumer Price Index).
EPA is required to offer 25,000 allowances every year in advance sales beginning in 1993, and 25.000
"ITie reserves will contain 50,000 allowances for the spot auction and 100.000 allowances for the advance auction
for years 1993 to 1995. 150,000 and 100.000 respectively for years 1996 to 1999, and 100,000 each for years 2000
and beyond.
4-13
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per year in spot sales beginning in 2000. However, the actual quantity of allowances available tor
direct sale will depend on the demand for allowances by the IPP guarantee program participants.
Allowances for the IPP guarantee program will be taken from those set aside for advance sales before
any are taken from the spot sales category: for this reason, the IPP guarantee program is expected
to preempt the direct sale program at least until the year 2000.
Applicants for allowances through the direct sales program will have up to six months from
the time of their application to submit a non-refundable deposit of 50 percent of the total purchase
price after their request to purchase allowances is approved. The remainder of the price will be paid
on or before the last day of the sale period. Because of the high price of allowances in the direct
sales program, EPA does not expect either strong demand for allowances through the direct sale
program, or the submission of non-refundable deposits; rather, purchasers are likely to wait until the
end of the year before submitting applications.
Section 416 of the Act directs EPA to end the direct sale program if during any two
consecutive years, fewer than 20 percent of the allowances (advance or spot) are sold. EPA currently
expects the direct sale program to end two years after it is initiated.
4.3.3 IPP Written Guarantee
Under the IPP written guarantee program. EPA will offer "written guarantees" to certain IPPs
planning to construct new facilities. The IPP written guarantees will provide the IPPs the right to
purchase allowances every year for the useful life of the unit from the Direct Sale Subaccount before
others are allowed to purchase. The IPP written guarantee is intended to provide new IPPs with a
means of demonstrating to their lenders that they will have access to a sufficient number of
allowances to fully operate planned facilities.
To quality for a guarantee, an IPP must meet the definition of an owner or operator of a new
independent power production facility and satisfy several additional requirements. The IPP must
submit written offers to each utility affected under Phase I to purchase the required allowances at
$750 each; record the responses to the offers; and certify on the application that none of the offers
was unconditionally accepted within 180 days. Once a guarantee is awarded, the IPP must submit
periodic statements certifying that the guarantee is still needed.
The aggregate annual cap for allowances reserved through IPP written guarantees will be set
at 50.000. Allowances for the written guarantees will come from the advanced allowance category
of the direct sale schedule first, and then from the spot allowance category.
Exhibit 4-5 summarizes the total costs of the three programs discussed in this report to EPA
and to the participants. Details on these programs and the annual costs used to estimate the present
value costs presented below are contained in Economic Analysis of the Proposed Acid Rain Regula-
tions for Auctions. Direct Sales, and IPP Written Guarantees and The Information Collection
Reuuest for the Acid Rain Program Under the Clean Air Act Amendments Title IV.
4.4 COSTS OF CONTINUOUS EMISSIONS MONITORING SYSTEMS
CAA section 412 requires the use of continuous emissions monitoring systems (CEMS) at
each affected unit's source of emissions. This part of the chapter presents estimates of the costs to
4-14
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EXHIBIT 4-5
Estimated Present Value Costs of the Auction, Direct Sales, and
IPP Written Guarantee Programsa
(Thousands of 1991 dollars)
;
I
! Auction
Direct Sales
IPP Written
Guarantees
j
TOTAL 1
i.
Government Costs
| S297 to 967 |
S21
S92
S410 to 1.0X0
1 ii.
i
Participant Costs
S 1,036 to 6.217 i
| ;
S12
S164
SI.: 12 to 6,393 <
.1
; in.
Total Costs
! S 1,336 to 7.184 i
S33
S256
S 1.625 to 7.473 |j
Costs .ire discounted tor IS years (1W3-2010) to the beginning of l
-------
4.4.2 CEMS Regulatory Options
EPA has analyzed the costs of monitoring in the absence of regulation and under five CEMS
regulatory options. These six cases differ from each other in (1) CEMS and flow monitoring
hardware requirements, (2) acceptable monitoring methods other than CEMS. and (3) data reporting
and record-keeping requirements.
The absent regulations case assumes that no further CEMS regulations are promulgated bv
EPA beyond the statutory requirements included in CAA. section 412. Under the statutory
requirements, all affected units (Phases I and II) must install a S07 CEMS. a NOx CEMS. a
continuous opacity monitor (COM), and a volumetric flow monitor. No other monitoring methods
are allowed, no performance standards are set. and no data reporting is required by law.
In contrast to the absent regulations case, the five regulatory options include operation and
maintenance requirements and additional performance testing requirements. The Relative Accuracy
Test Audit (RATA) is one of the main performance audits that takes place. Option 1 presents the
most stringent regulatory case; Option 2 permits the use of other monitoring methods as an exception
to CEMS; Option 3 exempts retiring plants from all monitoring requirements; Option 4 requires the
use of standardized data reporting and record keeping procedures; and Option 5 combines all of the
regulatory options:17
• Option 1 assumes no pre-approved monitoring methods other than
CEMS. All affected sources are subject to operation and maintenance
requirements and additional performance testing requirements.
• Option 2 is similar to Option 1 except for pre-approved excepted
monitoring methods and COM exemption for gas-fired units and wet-
scrubbed coal-fired units. Option 2 allows units burning oil and units
burning 90 percent or more gas to use methods of monitoring SO?
emissions and volumetric flow other than CEMS.18 These gas- and
oil-fired units are likely to get accurate measures of S02 emissions
using an alternative method of monitoring because fluid fuels are
easily measured using a fuel flow meter and are generally homogenous
in terms of sulfur content. The gas units would also be exempt from
the COM requirement because natural gas is a clean fuel with low
opacity levels. Coal-fired units, if wet-scrubbed, are also exempt from
the COM requirement because wet-scrubbed units emit large amounts
of water vapor, which prevents meaningful measurements of opacity.
All S02 emitters are subject to operation and maintenance require-
ments and additional performance testing requirements.
• Option 3 is similar to Option 1 except that units that retire before
compliance deadline are exempted from all monitoring requirements.
For all options, the regulations provide for case-by-case demonstrations for approval of alternatives, but no pre-
approved excepted monitoring methods unless specified.
Units burning 90 percent or more gas may also be allowed to use monitoring methods other than CEMS for NO,
equivalent to CEMS; however, because NOx generation is site specific, depending upon boiler configuration, any
determination of equivalency for the use of an alternative must be made on a case-by-case basis.
4-16
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Option 3 exempts all affected units retiring before January 1995 from
all monitoring requirements because they will not be emitting SO-,
during the period of compliance. All affected sources are subject to
operation and maintenance requirements and additional performance
testing requirements.
• Option 4 is similar to Option 1 except that it requires the use of EPA
approved, standardized electronic reporting format for the Data
Acquisition Systems (DAS) for reporting and record keeping. A
standardized electronic reporting format is expected to reduce the
costs to industry of reprogramming customized or off-the-shelf
software by about 50 percent. In addition, standardized reporting
could reduce EPA's administrative burden in processing quarterly
emissions reports by about 50 percent.
• Option 5 combines Options I. 2, 3 and 4 including the operation and
maintenance requirements, additional performance testing require-
ments, the use of methods of monitoring S02 and volumetric flow by
gas- and oil-fired units as an exception to CEMS, the exemption of
gas-fired units and wet-scrubbed coal-fired units from the COM
requirement, the exemption of all affected units retiring before
January 1995, and the required use of EPA approved, standardized
electronic reporting format for the Data Acquisition Systems. This
option also assumes that new units below 25 MW would be exempted
from the CEMS requirements and that gas- and oil-fired units with a
capacity factor less than or equal to 10 percent would be allowed to
use alternative methods of monitoring NOx emissions. Option 5
represents the proposed CEMS rule.
Options I, 2, and 3 also require data reporting and record-keeping but without the
standardized electronic reporting format requirement. EPA will require that all affected units
required to install CEMS update or install a DAS to record hourly CEMS and flow monitor data.
Affected units without CEMS must record daily fuel sampling analysis data and install a DAS to
record hourly fuel flow values. All affected units will be required to submit quarterly reports of their
emissions data to EPA. EPA will also require certification and inspection of all data handling
systems.
4.4.3 Assumptions about the Absent Regulations Case and the Regulatory Options
Under the absent regulations case, EPA assumes that all affected generating units would be
required to purchase, install, and maintain CEMS (for S02 and NOx), COM, and flow monitoring
systems if they do not already have one in place.19 The number of affected units and the additional
According to the National Allowance Database (October 1990), there are 2.165 Phase II affected units (1.311 coal-
fired units. 393 oil-fired units, and 461 gas-fired units). EPA assumes that 142 new diesel-fired units would come
online between 1990 and 2000 for a total of 2.307 Phase II affected units. Gas-tired units are defined as units that
burn gas at least 90 percent of the time. Although a single CEM may monitor multiple units, if several affected
units contribute to a single source (i.e., stack), it is assumed for this analysis that a CEM is installed for each
affected unit. This could be an overestimation of the number of monitors needed because some units share a
common stack and a common CEMS.
4-17
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monitoring equipment required for each were determined hv using the National Allowance Database
(October 1990) and Aerometric Information and Retrieval System (AIRS).
Exhibit 4-6 presents the number of affected units and the tvpes of CEMS equipment needed
under the statutory requirements. About 46 percent (1070. out of 2307) of 'all the affected units
would be required to install all monitors while 90 percent (414 out of 461) of the gas-fired units and
87 percent (467 out of 535) of the oil-fired units will be required to install all monitors. In contrast,
only about 14 percent.(189 out'of 1311) of the coal-fired units require all monitors.
Exhibit 4-7 presents the industry average CEMS cost estimates used for this analvsis.-0
Purchase, installation, operation and maintenance cost estimates were provided bv CEMS
manufacturers.21 Under the absent regulations case, absent CEMS performance standards. EPA
assumes that most of the affected units will choose to purchase and install lower cost CEMS. If
affected units arc required to install all monitors, it is expected to cost about $302,200 in capital
expenses and about $78,700 in annual operation and maintenance expenses per unit.
Because section 412 does not specify regular reporting, the absent regulations case assumes
that no additional effort would be required for record keeping beyond what the DAS records.—
For the purposes of this analysis. EPA assumes that the preparation of quarterly reports and
data quality assurance/quality control requirements will require about 160 hours each year (40 hours
each quarter) for each plant.23
Under Option 2. EPA assumes that 461 gas-fired units and 535 oil-fired units would be
allowed to use fuel sampling and analysis and a fuel flow meter instead of an SO-, CEMS and flow
monitor. The gas-fired units would also be exempt from the COM requirement. EPA also assumes
that 10 existing coal-fired units with new wet-scrubbers would benefit from the COM exemption.
Under Option 3. EPA assumes that 118 units will be retired prior to January 1995.24
Engineering costs associated with CEM retrofit are not included in the analysis due to the difficulty in obtaining cost
estimates. These retrofit engineering costs, however, are expected to be similar under the absent regulations case
and the regulatory cases.
These cost estimates are based on data provided by Thermo Environmental Instruments. Inc.: Rosemount
.Analytical, Inc.; and KVB Inc. Fuel flow meter cost estimates are based on data provided by Jacksonville Electric
Authority. Flow monitor cost estimates are based on information provided by KVB. Inc. and Environmental
Measurement Research Corporation. DAS software and operation/maintenance costs are EPA estimates.
In the base case, EPA may submit a data request to the affected unit operators to obtain data as needed or inspect
the data during a plant inspection. However, EPA assumes that no additional administrative time would be
required to keep track of the emissions data.
EPA estimate. There are 110 plants in Phase I, and approximately 730 plants in Phase II.
/Ml estimates of numbers of affected units are from the National Allowance Database. October 1990 (version 1.0).
ICF estimates that, of the retired units. 37 units are coal-fired. 66 oil-fired, and 15 gas-fired. For the purposes of
this analysis, EPA assumes that the distribution of any exempt group is the same as the regulated community as
a whole in terms of the quantities and types of monitoring equipment that are currently in place, i-'or example,
under Option 3. it is assumed that the distribution of retired coal-fired units is the same as the distribution of all
coal-fired units as presented in Exhibit 4-6.
4-18
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EXHIBIT 4-6
Number of Affected Units and Monitoring Equipment Needed*
Coal-Fired Units
Affected Units 1 Monitors Required
:
! Phase I
Phase [I
Base Equip.
NO,
OvCO,
so,
Flow
COM
DAS i
0
1X9
x
X
X
X
X
X
x ;!
ITS
666
X
X
X
X
X
*
-
i 70
346
*
X
.
-
X
*
* _ :i
3
103
*
»
*
*
X , * ¦ j
2
7
X
*
*
.
*
¦i
0
X
X
X
X
*
* 1
256
1311
Subtotal Coal
Oil-Fired Units
Affected Units
Monitors Required !
Phase I
Phase II
Base Equip.
NO,
oyco.
SO,
Flow
COM
DAS 1
(i
467
X
X
X
A
A
X
X j
5
55
X
X
X
A
A
* f
0
2
•
x
*
*
X
X
0
1
*
*
*
m
X
*
*
0
6
*
*
*
A
A
m
* |
0
4
*
*
*
A
A
X
*
5
535
Subtotal Oil ;
Gas-Fired Units
Affected Units
Monitors Required
Phase [
Phase II
Base Equip.
NO,
0,/C0,
SO,
Flow
COM
DAS !
0
414
X
X
X
A
A
E
X
0
16
X
X
X
A
A
*
•
0
1
*
*
*
*
X
E
*
0
1
*
X
*
A
A
*
*
; o
29
*
*
*
A
A
E
*
0
461
Subtotal Gas
! 261
2307
Total All Fuels
* Monitors already present. No additional monitoring equipment required.
X Monitoring equipment required.
A Monitoring methods other than CEMS are available under Options 2 and 5.
E Exemptions from these monitoring requirements are given under Options 2 and 5.
1 EPA estimates based on the National Allowance Database and AIRS. These are conservative
estimates given that some sources with monitors installed do not report to the federal EPA.
4-19
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4.4.4 Costs Incurred by the Regulated Community
The costs to the regulated community under the absent regulations case and the live
regulatory options include costs associated with CEMS. flow monitoring, and data handling hardware,
installation, maintenance, and costs associated with data recording and reporting.
CEMS, Flow Monitoring, and Data Handling Hardware Costs
EXHIBIT 4-8
Estimated Annualized Costs to the Regulated Community
(Millions of L990 Dollars)
Absent
Regulations
(per year)
Option 1
(per yean
Option 2
(per year)
Option 3
(per year)
Option 4
(per year)
:i
Option 5
(per year) i
Monitoring Equipment
Coal-fired Units
I
1993
20.8
23.5
23.5
23.5
23.5
23.5
1094-2010
110.8
125.9
125.9
124.9
125.2
124.1
Oil-fired (J nits
1W3
0.4
0.5
0.4
0.5
0.5
0.4
1994-2010
45.1
58.7
39.7
55.7
56.9
28.8 j
(His-Fired Units
1993
0
0
0
0
0
0
1994-2010
39.0
50.5
41.0
49.8
48.9
26.7
Subtotal
1993
21.2
24.0
23.9
24.0
24.0
2.3.9 '
1994-2010
194.9
235.1
206.6
230.5
231.0
179.6 !
Data Reporting
1993
0
6.6
6.6
6.6
6.6
6.6 j
1994
0
58.1
58.1
58.1
58.1
58.1 1
1995-2010
0
3.9
3.9
3.9
3.9
3.9 j
TOTAL
1993
21.2
30.6
30.5
30.6
30.6
> 30.5
1994
194.9
293.2
264.7
288.6
289.1
237.7
1995-2010
194.9
239.0
210.5
234.4
2.34.9
183.5
The annual costs under each scenario for gas. oil, and coal units and for the regulated
community as a whole are presented in Exhibit.4-8. The'present value of the total hardware costs
4-21
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EXHIBIT 4-9
Estimated Present Value Costs to the Regulated Community for the Time Period 1993-2010a
(Millions of 1990 Dollars)
!
i
j
Absent
Regulation j
Case
Option 1 j
Option 2
Option 3
Option 4
-
Option 5
i Monitoring Equipment
i
Coal-tired Units
1,436 |
1,632 |
1,632
1.619
1,623 ;
1.610 '
Oil-fired Units
577 |
751 j
698
712
728 1
368 :
Gas-Fired Units
499 '
646 i
524
637
626 !
341
j Subtotal
2,512
3,1)29 ;
2.854
2,968
2,977
2.319 ;
Data Reporting
0 j
105 j
105
105
105 I
75 j
TOTAL
2,512 |
3,134 1
2,959
3,073
3,082 J
2,394 !
1 Costs are discounted for 18 years (1993-2010) to the beginning of 1992 at a discount rate of three percent.
to the regulated community are presented in Exhibit 4-9. The average costs per unit are presented
in Exhibit 4-10.
Under the absent regulations case, the present value of the cost of installing a S02 CEMS.
a NOx CEMS, and a flow monitor at all units not presently equipped with these devices will be about
$2,512 million for the period 1993-2010.27 The annualized costs are $21.2 million for 1993 and
$194.9 million each year for 1995-2010. The average cost per unit will be about $81,300 for 1993 and
$90,000 each year for 1995-2010.
Under Option 1, the increase in the costs, attributable to relative accuracy testing audit and
other necessary quality assurance and maintenance procedure expenses, raises the monitoring costs
to the regulated community over the absent regulations case costs. The present value of the costs
to the regulated community will be about 53,134 million for the 1993-2010 period. The annualized
costs are $30.6 million for 1993, $293.2 million for 1994, and $239 million each year for 1995-2010.
The average cost per unit will be about $95,800 for 1993, $130,300 for 1994, and $110,400 each year
for 1995-2010. Option 1 is the most stringent and the most expensive regulatory option examined
for this analysis.
Under Option 2, the costs to the regulated community are reduced from Option 1 through
the use of excepted monitoring methods and COM exemption of gas-fired units and wet-scrubbed
coal-fired units. These cost savings are outweighed, however, by the cost of quality assurance
procedures vital to ensuring accurate, trustworthy emissions data. The present value of the costs to
the regulated community under this option will be about $2,959 million for the 1993-2010 period.
The annualized costs are $30.5 million for 1993, S264.7 million for 1994. and $210.5 million each year
All present value costs are discounted back to the beginning of 1992 at a discount rate of three percent.
4-22
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EXHIBIT 4-10
Average Annual Costs per Unit to the Regulated Community
(Thousands of 1990 Dollars Per Unit)
>
1
Absent
Regulations
(per year)
Option 1
(per year)
Option 2
(per year)
Option J
(per year)
Option 4
(per year)
Option 5
(per year)
i
Monitoring Equipment
i
Coal-tired Units
.i
1
IW
81.3
9 1 9
91.9
91.6
91.9
91.6 ij
! I <-m-2010
j
K4.5
96.0
96.0
95.3
95.5
94.7
-
1 Oil-tired Units
! 1993
X0.7
95.7
97.4
95.7
95.7
77.4 '
1994-2010
114.9
149.3
138.9
141.6
144.8
"3 "> 1
';i
Gas-Fired Units
1993
0
0
0
0
0
o j
1994-2010
84.6
109.6
88.9
108.1
106.2
58.0
AJI Units
1993
81.3
92.0
92.0
91.7
92.0
91.4 !
1994-2010
90.0
108.6
102.3
106.4
106.7
S3.0
Data Reporting
1993
0
3.8
3.8
3.8
3.8
3.8 j
1994
0
21.7
21.7
21.7
21.7
21.7 |
1995-2010
0
1.8
1.8
1.8
1.8
1.8 I
TOTAL
1993
81.3
95.8
95.8
95.5
95.8
95.2
1994
90.0
130.3
124.0
128.1
128.4
104.7
1995-2010
90.0
110.4
104.1
108.2
108.5
84.8
tor 1995-2010. The average cost per unit will be about $95,800 tor 1993, $124,000 for 1994, and
$104,100 each year for 1995-2010.
Under Option 3, the costs to the regulated community are reduced from Option 1 through
the exemption of retiring plants from the CEMS/COM and flow monitor requirements. Again these
cost savings are outweighed by the quality assurance procedure expenses. Overall, the present value
of the costs to the regulated community under this option will be about $3,073 million for the 1993-
2010 period. The annualized costs are about $30.6 million for 1993, $288.6 million for 1994. and
$234.4 million annually for 1995-2010. The average cost per unit will be about $95,500 for 1993.
$128,100 for 1994, and $108,200 each year for 1995-2010.
4-23
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Under Option 4. the lower cost of the DAS with the EPA approved, standardized electronic
reporting format reduces the costs to the regulated community. Overall, the present value of the
costs to the regulated community under this option will be about $2,977 million for the 1993-2010
period. The annualized costs are $30.6 million for 1993. $289.1 million for 1994. and $3,082 million
each year for 1995-2011). The average cost per unit will be about $95,800 for 1993. $128,400 for
1994. and $108,500 each year for 1995-2010.
Under Option 5. the proposed CEMS rule combining all of the elements of Options [-4. the
present value of the costs to the regulated community will be about $2,394 million for the 1993-2010
period. The annualized costs are about $30.5 million for 1993, $237.7 million for 1994. and $183.5
million annually for 1995-2010. The average cost per unit will be about $95,200 for 1993. S 104.700
for 1994. and $84,800 each year for 1995-2010. Option 5 is the least expensive regulatory' option
examined for this analysis.
Mannar Cenificcnion. Data Recording and Reporting Costs
Under the absent regulations case, the affected utilities are not required to report emissions
data to EPA. Thus, there are no costs for monitor certification, data recording or reporting
associated with the absent regulations case."8 The present value of the cost of monitor certifica-
tion. data recording and reporting to the regulated community under each of the regulatory options
is about $105 million for the 1993-2010 period.29 The annual costs are expected to be about $6.6
million for 1993. $58.1 million for 1994. and about $3.9 million each year for 1995-2010. The average
cost per unit will be about $25,200 for the period of 1993-1994, and about $1,800 each year for 1995-
2010. Annual cost estimates are presented in Exhibit 4-8 and the total present value cost estimates
are presented in Exhibit 4-9. The average costs per unit are presented in Exhibit 4-10.
Total Costs to the Regulated Community
The present value of the total costs to the regulated community under the absent regulations
case is about $2,512 million for the period 1993-2010. The present value of the total costs to the
regulated community under each of the regulatory options is about $3,134 million for Option 1,
$3,040 million for Option 2. $3,073 million for Option 3. $3,082 million for Option 4, and $2,626 for
Option 5.
4.4.5 Costs Incurred by EPA
The costs to EPA include the cost of conducting periodic plant inspections and processing
and reviewing emissions data. EPA incurs no inspection and data evaluation costs under the absent
regulations case. Under all regulatory options, the present value of the total cost to EPA of
performing these activities is about $1.0 million for the 1993-2010 period/*0 The annual costs are
expected to be about $5,400 for 1994, $58,200 for 1995. $46,900 each year for 1996-1999, and
$110,200 each year for 2000-2010. The annual costs to EPA are presented in Exhibit 4-11. and the
total present value costs are presented in Exhibit 4-12.
Electronic data collection and tracking costs are included in the CEM and DAS costs.
Costs tor monitor certification are based on EPA's estimates that monitor certification will cost S25.000 per unit,
and a total of 2,307 units.
Based on EPA's estimate that a plant inspection will require an average of 60 hours at a cost of S34 per hour.
Options 4 and 5 include the cost savings of standardized emissions data reporting.
4-24
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EXHIBIT 4-11
Estimated Annual Costs to EPA
(Thousands of 1990 Dollars)
Absent
Regulation
Case
Option I
Option 2
¦
Option 3
Option 4
Option 5
Plant Inspections
i
i
1995
0
22.4
22.4
21.8
22.4
21.8
1996-1999
0
11.2
11.2
10.9
11.2
io.9 :
2000-2010
0
74.4
74.4
74.4
74.4
74.4
Data Review and
Evaluation
1994
0
5.4
5.4
5.4
5.4
5.4 :
1995-2010
35.7
35.7
35.7
35.7
35.7 :
TOTAL
1994
0
5.4
5.4
5.4
5.4
5.4
1995
0
58.2
58.2
57.6
58.2
57.6
1996-1999
0
46.9
46.9
46.7
46.9
46.7
2000-2010
0
110.2
110.2
110.2
110.2
110.2 !
i
EXHIBIT 4-12
Estimated Present Value Costs to EPA for the Time Period 1993-2010a
(Thousands of 1990 Dollars)
Absent
Regulation
Case
Option L
Option 2
Option 3
Option 4
Option 5 |
i
Plant Inspections
0
619
619
617
619
617
Data Review and
Evaluation
0
416
416
416
416
416
TOTAL
0
1,035
1,035
1,033
1,035
1,033
Costs are discounted for 18 years (1993-2010) to the beginning of 1992 at a discount rate of three percent.
4-25
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4.4.6 Total Costs of the CEMS Regulations
Exhibit 4-13 summarizes the total costs associated with the absent regulations case and each
of the three regulatory options examined. Option 5. the proposed rule, otters a savings of about $710
million from the most stringent regulatory case (Option 1). Furthermore, the cost of Option 5 is
about Si 17 lower than the absent regulations case due to the more rational approach to monitoring
sources that likely will have very low emissions, such as retired coal units and gas units with verv low
utilization.
EXHIBIT 4-13
Total Present Value CEMS Costs for the Time Period 1993-20101'
(Millions of 1990 Dollars)
; | j
1 i
Absent
: Regulation 1 Option I
i Case
Option 2
Option 3
Option 4 Option 5
!
. Regulated Community
Cosis
! EPA Costs
2,512
0
3,104
1
2,959
1
3,043
1
I
3,052 2,394
1 : 1 |
TOTAL COSTS
2,512
3,105
2,960
3,044 ; 3,053 : 2,395 j
Costs are discounted for IX years (t'W-2010) lo the beginning of 1992 at a discount rate of three percent.
4.5 COSTS OF PERMITS
This section presents estimates of the labor requirements and costs to (1) federal and state
governments to implement acid rain permit requirements, and (2) owners and operators of sources
that must obtain permits under Title IV of CAA as amended.-1 As with other implementation
activities, the costs of permits should be reviewed in light of the costs savings that a credible permit
program makes possible.
4.5.1 Background
To ensure compliance with Title IV requirements, section 408 requires owners and operators
of affected sources to obtain operating permits from EPA during Phase I and from states in the
continental United States with approved Title V permit programs or from EPA during Phase II.
Permits issued to implement this title will have terms of five years.
As provided in section 408, the permit program is to be implemented in two phases. Under
the first phase. EPA will issue operating permits to owners and operators of power plants that, are
required to meet Phase I S02 and NOx reduction requirements. First phase permits will be effective
January 1, 1995 through December 31, 1999. Under the second phase, states with approved Title V
Because permit fees to be collected from source owners and operators under state permit programs are required
specifically by Title V, and because these fees v»ere addressed< in the Title V Regulator)' Impact Analysis and no
additional fees are required by or would result due to Title IV. examination of permit fees has been excluded from
this analysis.
4-26
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permit programs will issue permits that include acid rain provisions to owners and operators of (1)
sources with new utility units, and (2) sources with existing electric utility units serving generators with
a capacity of greater than 25 MW (i.e.. Phase II affected sources). Second phase permits will he
effective for terms of five years, beginning January 1. 2000. If a state fails to adopt and implement
a permit program approvable under Title V. EPA must issue permits to affected sources in Phase II.
To obtain permits, owners and operators must submit to the permitting authoritv a permit
application for each affected source (i.e.. plant). The contents of the acid rain permit application will
include the following for each affected unit at the source: (1) general information required for a[l
units, and (2) a compliance plan with specific information, as appropriate, to support the use of anv
compliance options for SO-, (e.g., substitutions. Phase I extensions, repowering extensions) or for NO
(i.e.. alternative emission limitations, emissions averaging, or extensions). The general information
will include the identity of the designated representative, source and unit identification, operating
information, emissions monitoring information, and an indication of the compliance strategy or
strategies proposed for units.In addition, a certificate of representation for the designated
representative for the source must precede or accompany the application. The certificate of
representation must state, among other things, that allowances and proceeds of transactions involving
allowances will be held or distributed to the owners of units at the source, either in proportion to
each owner's legal, equitable, or leasehold interest, or by some other contractual entitlement, and that
the designated representative is authorized to fully bind the owners and operators with regard to Acid
Rain Program matters.
The designated representative of the owners and operators of subject power plants must
submit Phase I acid rain permit applications and proposed compliance plans to EPA no later than
February 15. 1993. (Proposals to revise the permit application, proposed compliance plan, and final
permit may be submitted at any time.) EPA must act on the compliance plan within six months of
receipt. Designated representatives of Phase II sources must submit initial acid rain permit
applications and proposed compliance plans to the state permitting authority, with copies to EPA,
by January 1, 1996. States with approved permit programs must issue the permits to sources satisfying
the permit requirements bv December 31. 1997. In states without permit programs approved under
Title V by July 1, 1996, EPA is required by Section 408 to act on the applications and issue permits
by January 1, 1998. The designated representatives of sources that include new electric utility steam
generating units must submit permit applications and proposed compliance plans to the appropriate
permitting authority at least two years before the latter of (1) January 1, 2000, or (2) the date on
which the unit commences operation, unless the new unit shares a common stack with a Phase I
affected unit, is designated as a compensating unit, or was modified on or after enactment to serve
a generator greater than 25 MW. In any of these cases, the designated representative must submit
a permit application for the unit at an earlier date.
4.5.2 Assumptions
The estimates of labor requirements and costs to implement permit programs and obtain
permits under Title IV depend on assumptions regarding participation, source burden, and timing.
[f the owners, operators, and designated representative of a unit plan to comply in timely fashion with the applicable
SO: emission limitations by holding the requisite number of allowances and plan to comply in a timely fashion with
the applicable NOx emissions limitations, a certification to that effect is all that is required. If the owners, operators,
and designated representative of a unit elect to use one or more of the compliance options authorized by the Act.
the following specific information to support use of a proposed option is required: identification of units governed
by the option, and of the designated representatives: notification and reporting requirements: and proposed
emissions limitation and allowance allocation information.
4-27
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Participation
Ot' the 110 sources expected to require permits under the first phase of the acid rain permit
program. S3 sources are expected to require permits covering both SO-, and NO emissions.'1 and
27 are expected to require permits covering only SO-, emissions.'14 Under the second phase. 727
Phase II sources (which include sources under the first phase) are expected to require permits. Four
hundred and thirty (430) of these sources are expected to require permits for both SO-, and NO
emissions.35 and 297 sources are expected to require permits for SO-, only/6 Sources with new
units and some new IPPs will also require permits under the second phase. For the purposes of
projecting permit costs. EPA is estimating that roughly 100 of these projects will require permits.
These projects all are assumed to obtain the needed allowances to start operating in the vear
2000.l7 For sources that are subject to both S07 and NOx emission limitations, this analysis
assumes that one permit will govern all pollutants regulated by the program emitted by a single
source. This analysis assumes that all sources required to obtain acid rain permits under this title are
large sources.39
Source Burden Estimates
Administrative burden costs are expected to be incurred by (1) owners, operators, and
representatives of sources who apply for operating permits: (2) EPA, which must implement a federal
permit program to issue first phase permits to sources, and which will provide oversight of state
permit program implementation, permit issuance, data management, permit compliance, and
enforcement for second phase permits: and (3) state authorities who assist EPA during Phase I
implementation and review applications for and issue second phase permits.
Estimating the burden associated with permits is difficult because the burden to individual
permit applicants of developing an application may vary widely depending upon the method of
compliance chosen. Although all applicants for permits will be required to submit a general acid rain
permit application form for each affected source that covers all affected units at the source, additional
forms would be necessary if one or more compliance options are chosen by the source to meet the
SO-, or NOx emissions limitations for any unit. Rather than trying to predict the number of
applicants that will elect to use various combinations of compliance options for units, this analysis
assumes average overall burden estimates for permits applicants, EPA, and states.
Excludes Phase J plants with all wet bottom/cyclone Phase I units and excludes solely oil and gas plants.
Estimates of the number of sources that will be affected by the acid rain permits program were obtained from the
National Allowance Data Base (version 1.0).
Assumes the January 1, 1997, regulations for nitrogen oxide emissions apply for all other coat boiler-tvpe units, hut
excludes solely oil and gas plants.
Estimates of the number of sources were obtained from the National Allowance Data Base (version 1.0).
EPA estimates that these projects will require about 127,000 allowances per year to emit sulfur dioxide (or about
1.270 annually per project).
Additional sources may elect to be included under the "opt-in" program, and will be required to obtain permits.
These sources have not been included in this analysis because the costs they incur are optional and because they
will be covered under separate regulations.
Large sources are defined as those emitting more than 100 tons per year of any pollutant.
4-28
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The labor burden estimates (per occurrence of a task where appropriate) used in this analysis
tor federal and state governments and permit applicants are the same as those used lor large sources
in the Regulatory Impact .Analysis and Regulatory Flexibility Act Screening Analysis tor Proposed
Title V Operating Permits Regulations.4^ This analysis assumes that any incremental burden
incurred by ( 1) permit applicants tiling applications that include one or moje of the acid rain
compliance options, and (2) permitting authorities reviewing these applications and issuing permits,
is included in these labor burden estimates. Burden estimates per task occurrence are assumed not
to change over the time period of this analysis. In addition, the activities that will be performed and
the burden on sources associated with obtaining a single permit are assumed to be the same under
both the first and second phases of the permit program (although the actual burden on all affected
sources in Phase II may be less since the program, including options, is greatly simplified bv Phase
II and because Phase I sources will be applying for a second time and will have a better understand-
ing of the program and the application procedures).41
Timing of Costs
This analysis covers the period from January 1. 1992, through December 31. 2010. inclusive.
Submission of a designated representative certificate of representation form and a permit application
(along with the proposed compliance plan), application review, and permit issuance are generally
required prior to the effective date of a permit. Although deadlines for submitting permit
applications and issuing initial permits under both Phase I and Phase II exist (see section 4.5.1 above),
the actual timing when (1) applications will be prepared, submitted, and reviewed, and (2) permits
will be issued -- both for initial permit applications and future renewals of Phase II permits -- is
uncertain. Because of this uncertainty and to simplify the analysis, it is assumed that all initial costs
associated directly with obtaining and issuing each permit, which are non-recurring over the life of
a permit, will be incurred at the end of the year the permit becomes effective, beginning in the year
1995 (i.e.. 1995, 2000, 2005, and 2010). Recurring costs will be incurred annually at the end of each
year. (For more precise estimates of the timing of burden and costs to participants and EPA under
the first three years of the acid rain permit program, see the Information Collection Request for
.Allowance Transfers, Energy Conservation and Renewable Energy Allowances, Acid Rain Permits,
and Emissions Reporting Under the Clean Air Act Amendments Title IV.)
Because the first phase of the permit program is federally operated, this analysis assumes that
no state burden will be incurred until the year 2000 (although in actuality states will develop
personnel and procedures for program implementation during the 1992 to 1995 time period, and will
be reviewing Phase II permits beginning in 1996).
4.5.3 Costs Associated with Permit Program Administration
Administrative burden costs to operate the Title IV acid rain permits program are incurred
by EPA alone under the first phase of the permit program and by both EPA and state authorities
that have delegated authority for the permit program under the second phase (beginning January 1,
2000). Administrative costs in this analysis account only for direct costs incurred once permitting
Burden estimates for the Title V Regulatory Impact Analysis were provided by F.PA.
These decreases in burden will be offset by increases in burden for units which were not affected for NOx during
Phase I and which may need to submit their applications for Phase II NO, compliance at a later date than their
general permit applications ;is specified in section 407(f). For sources with such units, the permit will be modified
to include the NOx requirements.
4-29
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authorities begin accepting applications and issuing permits: Indirect costs related to program
development, program monitoring, enforcement, and overhead have not been included because
estimates of the burden and costs associated with these activities are still uncertain.
First Phase
The primary non-recurring tasks performed bv EPA under the first phase of the permit
program will be reviewing permit applications, notifying the public and affected states, and issuing
proposed and final permits. The primary recurring activity performed by EPA under this phase will
be reviewing quarterly and annual compliance certifications. Quarterly compliance certifications,
other than the monitoring reports discussed in that section, will be submitted only lor some units
using a few of the specific compliance options. This burden is. therefore, speculative and is
considered to be very small. Reviewing an initial permit application and issuing a permit is estimated
to take an average of 60 hours. Reviewing certificates of representation is estimated to require one
hour per occurrence. Reviewing quarterly and annual compliance certifications is estimated to take
four hours per occurrence.42 Therefore, the burden to EPA to administer the first phase of the
permit program is estimated to be 65 hours per source the first year and 4 hours annually for
subsequent years for each source. If 110 sources submit certificates of representation, permit
applications and annual compliance certifications, EPA's permitting effort will be about X.470 hours
over five years (6,710 hours will be incurred the first year and 440 hours annually in the subsequent
four years). EPA is also expected to incur costs in training state staff and for state program oversight.
Some of these costs, though related to the second phase of the permit program, will be incurred
during the first phase and are therefore included in the costs of the first phase. EPA estimates that
training will require approximately two FTEs for two to three years; for simplicity, these costs are
shown in Exhibit 4-14 as though they all occur during the first year. Program oversight is estimated
to require roughly 10 FTEs (one in each of the ten EPA regions) for the entire period of the first
and second phase. At 2,080 hours per FTE per year, training and oversight will require a total of
114,400 hours during the first phase. Assuming EPA's hourly rate is about $34 per hour, the total
cost to EPA to administer the first phase of the permit program will be about $4,193,000. EPA's
level of effort and costs under this phase of the permit program are presented in Exhibit 4-14.
Second Phase
Under the second phase of the permit program, states will have primary responsibility for
reviewing initial permit applications and proposed compliance plans, notifying states that are within
50 miles of a source, issuing permits, transmitting copies of proposed permits and final permits to
EPA, and processing permit revisions. These activities will be non-recurring over the 5-year life of
the permits. Reviewing an initial permit application and proposed compliance plan and issuing a
permit is estimated to take on average 60 hours. Notifying EPA and notifying applicable states are
estimated to require two hours per occurrence for a total of four hours per source.43 The primary
recurring activity performed by states under this phase will be reviewing quarterly and annual
compliance certifications. Reviewing quarterly and annual compliance certifications is estimated to
The burden io EPA for processing permit revisions is uncertain and will depend upon the number and nature of
the revisions. Because of the flexible compliance planning options available to sources at the time of permit
application, and because of the flexible revision procedures proposed. EPA estimates the burden to EPA for permit
revisions will be minimized. Permit revisions are optional and the quantity unknown. Therefore, an estimate of
the burden associated with permit revisions had not been included.
The burden to states for processing permit revisions will be less significant on a per source basis than for EPA
during Phase I because the program is greatly simplified. (See the previous footnote.)
4-30
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EXHIBIT 4-14
Administrative Burden and Costs to EPA
Under the First Phase of the Permit Program
Tasks
i
Hours Per Occurrence
Total" Hours"
"Total
Burden
I'otal ;
('osts
"
Initial
Recurring
First Year
.Annually
Subsequent
Years
()ver Five
Years
Over Five
Years'
1. Review certificates of
representation and issue
completeness notices.
1
110
110
$4,000
2. Review permit
application.'notify the
public and affected states,
and issue proposed and
final permit.
.600
6.600
$224,000 !
3. Review annual
compliance certification
4
440
440
o
c
575.000
4. Training State Staff
10,400
10,400
S354.000
5. Oversight of State
Programs
20.800
20.800
104,000
S3.536.000
i
| TOTAL
38,350
21,240
123,310
S4.193.000
Assumes 110 sources are required to obtain permits.
1990 dollars. (Costs have been rounded to the nearest thousand dollars.)
take tour hours per occurrence. Therefore, the burden to states as primary administrators of the
second phase of the permit program is estimated to be 68 hours the first year and 4 hours annually
for subsequent years for each source. If 727 Phase II sources and 100 new power plants submit
permit applications and proposed compliance plans to state permit authorities, the total state effort
will be about 66.987 hours over one 5-year permitting cycle (53,755 hours will be incurred the first
year and 3.308 hours annually in subsequent years). Assuming that state administrative costs are
equivalent to EPA costs (about $34 per hour), the total cost to states over one five-year permitting
cycle are estimated to be about $2,277,000.
In its oversight role under the second phase of the permit program, assuming that all states
will have approved permit programs, EPA will perform the non-recurring task of reviewing proposed
permits issued by states. Reviewing a proposed permit is estimated to take 40 hours. If a total of
827 Phase II sources and new power plants submit permit applications and proposed compliance
plans. EPA's total effort for permit review will be about 33,080 hours.
EPA's oversight of state programs will continue in the second phase, with one FTE in each
of ten regions throughout the phase for a total of 104,000 hours for each five year permit cycle.44
At $34 per hour, the cost of oversight for each five year permit cycle will total $3,536,000. At $34
Preliminary EPA estimate.
4-31
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per hour. EPA's total costs over one five-year permitting cvcle are expected to he about $4.661.000.
In making these estimates. EPA assumes that no states will default.
The burden and costs to states and EPA for one five-year permitting cycle under the second
phase of the permit program are presented in Exhibit 4-15. Based on the assumptions regarding the
time frame of this analysis and a five-vear permit life, burden and costs will be incurred for two full
permitting cycles plus those for the first vear of a third cycle (in the year 2010) during the period of
lhis analysis. Therefore, the total labor burden to states and EPA under this phase is 523.212 hours
over 11 years: the total costs over 11 years are estimated to be about S17.7S9.000.
EXHIBIT 4-15
Administrative Burden and Costs to States and EPA
For a 5-Year Period Under the Second Phase of the Permit Program*1
Tasks
Hours Per Occurrence
Total Hours1'
Total
Burden
Total
Cosis j
Initial
Recurring
I-lrst Year
Annually
Subsequent
Years
Over hive
Years
Over f ive !
Years- j
:i
States:
"i
1. Review certificates of
representation and issue
completeness notices
1
-------
program to states and EPA over the period of this analysis are summarized in Exhibit 4-17. The
aggregate burden to states and EPA is estimated to be 585.324 hours. As shown in Exhibit 4-IS. the
total costs to states and EPA are estimated to be about $21.731,(X)0; the present value of these costs
from 1W5 through 2010 will be about $15,654,000 at a discount rate of three percent.4,1 The
average annualized costs per source to states and EPA are estimated to be about-$7.600 under Phase
I and $1,700 under Phase II.
EXHIBIT 4-16
Summary (>r the Administrative Burden to States and EPA
For the Acid Rain Permit Program
January 1. 1CJ95 through December 31. 2010
(Hours)
Authority
First
Phase;
Second Phase0
(First 5 Years)
Second Phase"
(Second 5 Years)
.
Total'
'
Total
First Year
Total
Subsequent
Four Years
Total
First Year
Total
Subsequent
Four Years
Total
First Year
Total
Subsequent
Four Years j
EPA
38.350
84.960
53.880
83.200
53.880
83.200
451.350
States j
53,755
13.232
53.755
13.232
133.974 1
TOTAL
HOURS
38.350
84,960
107.635
96,432
107,635
96,432
585.324
Assumes 110 sources are required to obtain permits.
Assumes 827 sources (727 Phase II sources and 100 new power plants) are required to obtain permits.
Includes first year burden hours that will be incurred in the year 2010 during the third 5-year cycle under
the second phase of the permit program.
4.5.4 Costs Associated with Program Participation
The primary non-recurring tasks performed by program participants to obtain permits under
either phase of the permit program will be rule interpretation and compliance planning, information
collection and analysis, designation of a representative of the owners and operators of each unit at
a source, and permit application and proposed compliance plan development. Interpreting the rule
and compliance planning is estimated to require 60 hours.46 Collecting and analyzing relevant
information is also expected to require on average 60 hours.47 Designating a representative of the
owners and operators of each unit at a source is estimated to take 50 hours. Assembling the
permit application and developing a proposed compliance plan is estimated to take on average 200
hours.4^ The principal recurring activity performed by program participants will be submitting
EPA assumption. Costs are discounted back to January 1. 1992.
F.PA estimate.
EPA estimate.
EPA estimate.
EPA estimate.
4-33
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EXHIBIT 4-17
Summary of the Costs to States and EPA
For the Acid Rain Permit Program
January 1, 1995 through December 31. 2010
(Thousands of 1990 Dollars)
Authority
First
Phase1
Second Phase'
(First 5 Years)
Second Phase"
(Second 5 Years)
Total'
Total
First Year
Total
Subsequent 1
Four Years j
Total
First Year
Total
Subsequent
Four Years
Total
First Year
Total
Subsequent ,
Four Years !
¦
EPA
1.304
2.889
1.S32
2.829
1.832
2.829
15.347
States
1
1.828
450
1.828
450
6.384 ;
TOTAL
COST
1.304
¦
2.8X9
3.660
3.279
3.660
3.279
21.731 i
Assumes 110 sources are required to obtain permits.
Assumes 827 sources (727 Phase II sources and 100 new power plants) are required to obtain permits.
Includes first year costs that will be incurred in the year 2010 during the third 5-vear cycle under the
second phase of the permit program.
annual compliance certifications. (Some participants may incur an additional burden tor quarterly
reporting associated with the use of certain compliance options; however, this burden is optional,
speculative, and expected to be very small.) Compliance certification is estimated to take 16 hours
annually?0
If 110 sources participate in the permit program during the first phase, the total administrative
burden will be about 66.370 hours over five years. Given the breakdown for each task between
managerial, technical and secretarial hours as presented in the ICR, the cumulative total
administrative cost to all 110 participants over the first phase of the permit program will be about
$2,843,000.
If 827 Phase II sources (including new power plants) participate in the second phase of the
permit program, the total burden to participants will be about 431,720 hours over a five-year
permitting cycle. Given the breakdown for each task between managerial, technical and secretarial
hours as presented in the ICR, the five-year total administrative costs to participants under the
second phase of the permit program will be about $18,183,000. Assuming that two second phase
permitting cycles and the first year of a third cycle will be completed within the time frame covered
by this analysis, total administrative costs to permit program participants under this phase will be
about $43,556,000.
The level of effort and costs to permit program participants are presented in Exhibit 4-18.
The total administrative costs to participants for the 16-year period of this analysis will be about
$46,399,000. In present value costs, the total administrative cost to participants will be about
EPA estimate.
4-34
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EXHIBIT 4-18
Administrative Burden and Costs to Participants
Under the Acid Rain Permit Program
January 1, 1995 through December 31, 2010
Tasks
Hours Per Occurrence
Hours Per Source
Per Permit f^ycle
Total
1 lours
Total
Hurden'
Total CosisJ
Initial
Recurring
First Year
Annually
Subsequent
Years
Phase 1"
Phase Uh
(One Cycle)
1. Select a designated
representative
35
35
11,900
28,945
98,735
$4,713,895
2. I'repare permit applica-
tion
96
96
10,560
79,392
248,736
10,640,926
3. Apply for a reduced
utilization plan
26
26
780
5.850
6.630
294.525
4. Apply for a substitution
plan
8
8
160
1,200
3,760
171,550
5. Apply for a I'hase 1
extension
56
56
896
0
896
¦ 39,792
6. Annual compliance
certification
66
66
66
36,300
272,910
636,702
26,201,242
7. lixcess I-missions
20
0
0
0
0
0
0
8. Permit Revisions
21
21
21
5,775
43,418
101,295
. 4,337.459
TOTAL
NA
NA
NA
NA
66,371
431.715
1.096,754
$46,399,389
Assumes 340 entities (including 230 affected under Phase II bui not under Phase 1) designate a representative. 110 I'hase I units apply lor a permit, oil sourees
apply lor a reduced utilization plan, 20 sources apply lor a substitution plan, and 16 sources apply lor a I'hase I extension, 110 sources submit an annual compliance
certification, no sources have excess emissions because the incentives lor compliance are so great, and 55 sources submit permit revisions.
Assumes 827 sources (727 I'hase II sources and KM) new ll'l's) select a designated representative and apply lor permits. 225 sources apply lor a reduced unli/ation
plan. 150 sources apply lor a substitution plan, 827 sources submit an annual compliance certification, no sources have excess emissions because the incentives lor
compliance are so great, and 414 sourees submit permit revisions.
Fquals to the sum of hours for (I) I'hase I. (2) two full cycles under I'hase II, and (3) the first year of the third cycle of I'hase II (the year 2010).
I WO dollars.
-------
$31,877,000 at a discount rate of three percent.'"11 The average annualized costs per source to
participants are estimated to he about $4,500 under Phase I and $3,200 under Phase II.
The total annualized administrative costs to respondents as well as EPA and states is
summarized in Exhibit 4-19.
EXHIBIT 4-19
TOTAL ANNUALIZED ADMINISTRATIVE COSTS
FOR THE ACID RAIN PERMIT PROGRAM
January 1, 1995 through December 31, 2010
(Thousands of 1990 Dollars)1'
; Authority
First Phase''
Second Phase'
1
(1995-1999)
(2000-2010)
I7 PA
SX54
S 1.025 ;
States
SO
S792 1
Participants
S590
S4.040 i
1
1 TOTAL
S 1.444
S5.1S57 i
Costs rounded to the nearest thousand dollars.
Assumes 110 sources are required to obtain permits.
Assumes X27 sources are required to obtain permits.
4.6 ENERGY CONSERVATION AND RENEWABLE ENERGY
This section presents estimates of the level of effort and costs to utilities and EPA associated
with obtaining and distributing allowances from the Conservation and Renewable Energy Reserve.
4.6.1 Background
Although the principal purpose of Title IV of the Clean Air Act is to reduce acid rain by
requiring reductions in emissions of S02 and NOx, it is also the purpose of this title to encourage
energy conservation and pollution prevention as a long-range strategy for reducing air pollution and
other adverse effects of energy production and use. As an incentive for electric utilities to (1)
implement energy conservation measures and (2) use renewable energy, section 404(f) of Title IV
establishes provisions for qualifying electric utilities to receive allowances for SO-, emissions avoided
through either of these two options. That is, for each ton of S02 emissions avoided by an electric
utility through the use of qualified energy conservation measures or qualified renewable energy, the
EPA assumption. Costs are discounted back to January 1. 1992.
4-36
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utility shall he allocated a single allowanced" Allowances will he allocated on a first-come-first-
served hasis tor energy saved by qualified conservation measures or generated by qualified renewable
energy during the period between January 1. 1992 and December 31. 2000:-^ up to a total of
300.0(H) allowances for all utilities will be allocated from the Conservation and Renewable Energy
Reserve. No allowances will be allocated for energy conservation measures or renewable enersr/ that
were operational before January I. 1992.
To qualify to receive allowances for emissions avoided, an electric utility will have to meet the
following requirements:
~ Costs for the qualified energy conservation measures or qualified
renewable energy are being paid directly by the electric utility or
through purchase from another entity;
~ Emissions of S07 avoided through the use of qualified energy
conservation measures or qualified renewable energy are quantified
according to EPA guidelines; and
~ A least cost energy conservation and electric power plan is being
implemented to the maximum extent practicable/4
In order to receive allowances for emissions avoided, each electric utility must submit to EPA
(or the appropriate state regulatory authority)__an application to receive allowances from the
Conservation and Renewable Energy Reserve." The application must include the following
information:
~ Designation of the qualified energy conservation measures implement-
ed and the qualified renewable energy sources used for purposes of
avoiding emissions during the previous calendar year;
~ Verification of (1) installation of energy conservation measures and
the energy savings attained,"16 and (2) plant operation using renew-
Under Title [V, a qualified energy conservation measure is defined as "a cost effective measure that increases the
efficiency of the use of electricity provided by an electric utility to its customers;" qualified renewable energy is
defined as "energy derived from biomass, solar, geothermal, or wind." Neither is to result in a net increase in SO,
emissions. Illustrative lists of qualified energy conservation measures and renewable electric energy resources will
be provided in EPA's Energy Conservation and Renewable Energy Reserve regulations.
Because allowances will be awarded retrospectively, the earliest date on which applications for allowances will he
accepted is January 1, 1993.
A least-cost energy conservation and electric power plan must (1) contain a long-term resource plan which integrates
demand-side and supply-side resources, (2) allow for public participation in the planning process, and (3) be
approved by the appropriate state regulatory or rate-making authority.
Only state-regulated electric utilities will submit applications for allowances to the state regulatory authority for
review and approval. Electric utilities whose retail rates are not subject to the jurisdiction of a state regulatory
authority will submit their applications directly to EPA for approval.
A certification of energy savings methods and calculations will be included as part of the verification.
4-37
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The model analyzes the effects of allowance trading and banking by including the possibility
of allowance transactions as part of each power plant's strategy. For instance, in addition to various
strategies discussed in the next section that could reduce a power plant's SO, emissions, the plant's
operators could choose to purchase allowances instead. Alternatively, the plant could be equipped
with scrubbers that would more than meet its emissions reduction targets; the extra allowances that
would be generated as a result could either be sold at the market price or banked for future use.
Each of these new strategies has a cost that will depend on the market price for allowances. Again,
the model assumes that the lowest-cost strategies will be chosen across the utility svstem and
calculates total costs by adding up the costs for each plant.
While the model shows clearly that the use of the allowance system can lower the costs of
control substantially on a nationwide basis, it should be noted that both the allowance svstem and the
cost savings it provides depends on the existence of credible mechanisms to ensure that emissions
reductions and allowances are tracked and recorded fairly and accurately. Without these mechanisms,
whose costs are described in sections 4.2. 4.3. 4.4. and 4.5. none of the cost savings shown in the
section would be possible. For this reason, the cost savings described here can be attributed in large
part to the elements of the Acid Rain Program concerning the administration of the allowance
system, the auctions, direct sales and IPP guarantees, permits, and emissions monitoring.
A more detailed discussion of the Coal and Electric Utilities Model is presented in Appendix
4A.
4.1.1 Sulfur Dioxide Reduction Strategies and Their Costs
The increase in costs due to the acid rain title and the cost savings associated with the
implementation regulations depend on the types of S02 reduction strategies likely to be employed
by affected units and the market impacts associated with these strategies. The major types of
reduction strategies and their likely impacts on costs are discussed below.
Installing Pollution Control Equipment
One major strategy for reducing S02 emissions is to install "scrubbers" or pollution control
equipment. Equipment costs are functions of the type of control technology used as well as the SO,
removal efficiency associated with the technology. The installation of pollution control equipment
results in higher capital and operating costs. The use of the equipment also increases fuel costs; the
operation of scrubbers, for example, results in additional steam and electricity requirements.
Switching to Lower Sulfur Coals
Switching to lower sulfur coals reduces S02 emissions, but results in higher costs because
delivered low sulfur coal prices are typically higher than delivered high sulfur coal prices at most
power plants. This is particularly true for many plants located in states in the Midwest where high
sulfur coals are available locally while low sulfur coal supplies must be obtained from outside the
state. Furthermore, increased demand for low sulfur coals will tend to push up prices for all users
of low sulfur coal, as coal that is more expensive to mine is brought into the market to meet the
demand. On the other hand, falling demand for high sulfur coals will tend to push high sulfur coal
prices down as production is concentrated in low-cost mines. Thus, while power plants using large
amounts of lower sulfur coals face increases in their fuel costs, many power plants that plan to use
higher sulfur coals (because they are using or planning to use scrubbers to reduce emissions from
these coals) will probably experience a reduction in their fuel costs.
4-3
-------
able energy and the energy generation attributable to renewable
energy input:57
• Calculations of the number of tons of emissions avoided (and
allowances sought) by implementing conservation measures or using
renewable energy; and
• Demonstration of qualification to receive allowances for emissions
avoided. (The requirements to qualify to receive emissions are listed
above.)
As applications are received by EPA. they will be registered chronologically bv daily postmark.
Within 30 davs of receipt, each application will be reviewed to determine whether it meets all the
necessary criteria to receive allowances from the Conservation and Renewable Energy Reserve.
Utilities with qualitying applications will be allocated allowances until the Reserve is depleted.
If a sufficient number of allowances remain in the Reserve, each utility with a qualitying
application will be allocated the number of allowances for which it applied. In the event that the
number of allowances remaining is less than the amount for which the next qualifying applicant has
applied, the applicant will receive the number of allowances remaining in the Reserve. In the event
that the Reserve becomes over-subscribed by more than one applicant on a single day. the allowances
remaining in the Reserve will be distributed on a pro rata basis to the applicants.
4.6.2 Assumptions
Estimates of the labor burden and costs associated with obtaining and distributing allowances
from the Conservation and Renewable Energy Reserve are based on the assumptions below.
Participation
Predicting the number of utilities that will apply for allowances from the Reserve is difficult.
According to a research project sponsored by the Electric Power Research Institute, about 40 percent
of all electric utilities are expected to implement energy conservation programs before the year
2000.;'x Based on this expectation, as many as 145 electric utilities could file applications for
allowances from the Reserve each year.39 The actual number of utilities that apply for allowances,
however, could vary significantly depending on the marginal value of Reserve allowances to utilities
relative to the application costs to receive allowances. Because of the uncertainty regarding the
number of utilities that will apply for allowances, cost estimates are presented in ranges. For this
analysis, it is assumed that 40 to 125 applications will be submitted per year and that, on average, only
one application for allowances will be submitted by any one utility in a particular year.60
Copies of certified plant operation records showing energy generation, plant size, and hours of operation during the
applicable calendar year are required to verify plant operation using renewable energy.
Electric Power Research Institute (EPRI) CU-6953. Impact of Demand-Side Management on Future Customer
Electricity Demand: An Update. September. 1990.
It'.F estimate which assumes that one application would be submitted per utility for each year allowances from the
Reserve are requested.
EPA estimate.
4-38
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Timing of Costs
This analysis covers the period from January 1. 1992. through December 31. 2010: the last
date on which allowances from the Reserve may be available is January 2. 2010 (determined bv
statute). Because allowances will be awarded retrospectively for energy saved bv qualified
conservation measures or generated by qualified renewable energy after January 1. 1992 (and before
December 31. 2000). the earliest date on which applications for allowances will be accepted is Januarv
1. 1993. This analysis assumes that costs to applicants and EPA associated with obtaining and
distributing allowances will be incurred at the end of the year, beginning in 1993.
The time period over which costs will be incurred depends not only on the number of
applications for allowances that are completed and submitted, but also on the number of allowances
requested per application (which is nearly impossible to predict) or projections of when the Reserve
will be depleted. Based on estimates of the overall annual demand-side affect of conservation on
future electricity demand from 1990 through 2010 provided in the EPRI report.61 the Conservation
and Renewable Energy Reserve will be depleted by the end of the year 2.000. if not sooner/'2
Therefore, this analysis assumes that at the high estimate of 125 applications per year, the Reserve
will be depleted in eight years with each utility on average applying for 300 allowances. At the low
estimate of 40 applications per year, assuming the average number of allowances for which each
utility will apply is the same as under the high estimate (i.e.. about 300), allowances from the Reserve
will be available through the last day of the program on January 2, 2010.
4.6.3 Costs Associated with Program Administration
Exhibit 4-20 depicts the annual burden and costs to EPA associated with distributing
allowances from the Conservation and Renewable Energy Reserve. Tasks that will be performed by
EPA related to the distribution of allowances from the Reserve include the following: (1) register
applications and review applications for completeness: (2) perform substantive reviews of applications
to determine whether all necessary criteria to receive allowances are met; and (3) transfer allowances
from the Reserve or notify applicants of their failure to qualify for allowances from the Reserve.
EPA estimates that registering applications and reviewing applications for completeness will require
about 0.5 hour per application, performing substantive reviews of applications will take 2 hours per
application, and transferring allowances from the Reserve or notifying applicants will take 0.5 hours
per application. Assuming it will take EPA about 3 hours to process each application and transfer
allowances (or notify applicants), the total administrative burden to EPA associated with distributing
allowances from the Reserve will range between 2,160 hours over 18 years and 3.000 hours over eight
years for processing 40 and 125 applications per year, respectively. At a cost of $34 per hour, the
total cost to EPA will range between $73,440 and $102,000. At a discount rate of three percent/^
the present value of these costs will be about $54,000 and $87,000 for processing 40 and 125
applications per year, respectively.
See footnote 65.
IC'F estimate.
EPA assumption. Costs are discounted back to the beginning of 1992.
4-39
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EXHIBIT 4-20
Annual Administrative Burden and Costs to EPA
For Conservation and Renewable Energy Allowances11
Tasks
Burden
Hours
Per
Applica-
tion
Cost Per
Applica-
40 Applications
Per Yearc~
125 Applications
Per YearJ
tion
Total
Burden
(Hours)
Total
Cost0
Total
Burden
(Hours)
Total
Cost0
I. Register application and
review application for
completeness
0.5
$17
20
$680
62.5
$2,125
2. Perform substantive
review of application
2
68
SO
2,720
250
8,500
3. Transfer allowances from
the Reserve or notify
applicants
0.5
17
20
680
62.5
2.125
TOTAL:
3
S102
120
S4.080
375
SI 2,750
Assumes the earliest date on which applications will be submitted is January 1, 1993.
h Based on an average rate of S47 per hour.
Assumes applications will be submitted and processed for 18 years without depleting
the Reserve.
d Assumes applications will be submitted and processed for 8 years, depleting the
Reserve in the year 2000.
1990 dollars.
4.6.4 Costs Associated with Program Participation
Exhibit 4-21 depicts the annual participant burden and costs associated with obtaining
allowances from the Conservation and Renewable Energy Reserve. Each utility applying for
allowances from the Reserve will be required to perform the following tasks: (1) designate energy
conservation measures implemented and renewable energy sources used to avoid emissions: (2) verify
installation of energy conservation measures and plant operation using renewable energy and resulting
benefits; (3) calculate the tons of emissions avoided; and (4) demonstrate qualification to receive
allowances for emissions avoided. Because most states collect information on these activities from
utilities already, the primary burden to utilities will be that associated with assembling and submitting
to EPA the application to receive allowances from the Reserve. Assuming it will take each utility
on average about SO hours to assemble and submit an application to receive allowances from the
Reserve to EPA.64 the total burden to respondents will range between 57.600 hours over 18 years
and 80,000 hours over eight years for assembling and submitting 40 and 125 applications per year,
respectively. The total cost to utilities applying for allowances from the Conservation and Renewable
Energy Reserve will range between $1,717,200 and $2,385,000. At a discount rate of three percent,
the present value of these costs will be about $1,274,000 and $2,032,000 for assembling and submitting
40 and 125 applications per year, respectively.
EPA estimate.
4-40
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EXHIBIT 4-21
Annual Administrative Burden and Costs to Participants
for Conservation and Renewable Energy Allowances"
Tasks ; Burden ; Cost Per 40 Applications 125 .Applicaiit>ns
Hours ; Applica- , Per Yearc Per Ycard
I
i
Per | tton1
Applica- |
tion
Total
Burden
(Hours)
Total Total Total Costc
Cost1"* Burden
(Hours)
Assemble and submit an
application to receive allow-
ances from the Reserve
Managerial
Technical
Secretarial
15 794
25 j 911
40 680
I
600
1,000
1,600
S31,760
36,440
27.200
:
1,875 S99.250 1
3,125 j 113.875
5.000 ! 85.000 !
TOTAL:
•SO $2,385
3,200
$95,400
10.000 1 S298.125 ;
¦Assumes the earliest date on which applications will be submitted is January 1. 1993.
Rased on total hourly compensation of $52.96 for managerial staff; S36.43 for technical staff, and SI7.00
for secretarial staff. These figures were derived by updating the rates developed for the Comprehensive
Assessment Information Rule (CAIR) to June 1991 using the Employment Cost Index (the initial CAIR
rates are from a May 28, 1987 memorandum from Jeff Carnes of Centaur Associates to Brian Muehling
of EPA).
Assumes applications will be submitted and processed for 18 years without depleting
the Reserve.
Assumes applications will be submitted and processed for 8 years, depleting the
Reserve in the year 2000.
1991 dollars.
4.7 SUMMARY OF COSTS
In general, the statute without allowance trading imposes substantial costs tor S02 reductions,
but relatively minor implementation costs. The allowance trading made possible by the implementa-
tion regulations reduces substantially the cost of S02 reductions. The implementation regulations
themselves, however, will result in some costs which will offset the savings from trading. Estimates
of these regulatory costs are summarized first, to allow a clearer comparison of the costs of the
implementation regulations to the costs of the statute and the savings from trading.
Exhibit 4-22 summarizes the costs presented in sections 4.2 through 4.5 of this chapter. As
the table illustrates, the majority of the costs consists of costs associated with allowance transaction
and CEMS. The costs of the auction, direct sale, IPP written guarantee, permit, and energy
conservation and renewable energy programs constitute a small fraction of the total costs.
Exhibit 4-23 places the implementation costs presented above into context by comparing them
to the total costs of the statute and the savings provided by allowance trading.
4-41
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EXHIBIT 4-22
COSTS OF IMPLEMENTATION REGULATIONS
(Millions of 1990 dollars)11
! Low Scenario
High Scenario
Allowance Transactions and
Tracking
$204
$406
Auctions. Sales, and IPP
Written Guarantees
2
•7
'
CEMSh
2.395
2.395
Permits
68
68
Conservation and Renew-
able Energy
1
2
Total Costs
$2,670
;
$2,878
These are present value costs, discounted to 1992 at 3 percent per year: capital costs
annualized at 7 percent per year.
Assumes Option 5 costs.
EXHIBIT 4-23
INCREMENTAL COSTS AND COST SAVINGS
(Billions of 1990 dollars)3
Costs of Absent Reg-
ulation Case (incre-
mental to pre-Statute)5
Costs of Regulatory
Case (incremental to
pre-statute)13
Cost Savings of
Regulatory Case
(incremental to I
absent regulation)5 !
SO, Reductions
$19.1 to $30.9
$9.5 to $17.1
$9.6 to $13.8
Implementation c
$2.5
$2.7 to $2.9
-$0.2 to -$0.4
Total
$21.6 to $33.4
$12.2 to $20.0
$9.4 to $13.4
3 These are present value costs, discounted to 1992 at 3 percent per year; capital costs are
annualized at 7 percent per year.
b Ranges cover EPA Low Scenario and High Scenario.
c Includes transactions costs; costs of auctions, direct sales, and IPP written guarantees: ('EMS
costs; and permit costs.
The center column of Exhibit 4-23 shows the total costs of the statute and the regulations to
he between $12.2 and $20.0 billion, depending on the scenario assumed. Of this total, about $3
billion are costs incurred because of the regulations. Costs in the absence of regulations, by contrast,
would be between $21.6 and $33.4 billion under the low and high scenarios, respectively. The
4-42
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difference in costs between the regulatory and absent regulations cases. $9.4 to SI3.4 billion,
represents the cost savings for SO-, reductions made possible bv the regulations.
The last column of the exhibit shows in detail the incremental savings provided bv the
regulations. The allowance trading regulations allow the regulated community to save a total of
between $9.6 and Sl.l.X billion in achieving the SCK emissions reductions mandated in the statute.
These cost savings are offset to a small extent, between $0.2 and $0.4 billion, by the costs of
implementation (net of-the $2.5 billion cost of CEMS required by the statute itself)- The net savings
provided by the allowance trading regulations still total $9.4 billion in the low scenario, and $13.4
billion in the high scenario.
4-43
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CHAPTER 5
Impacts of Cost Changes
This chapter assesses the effects of the costs and cost savings presented in Chapter 4 from
tour different perspectives. The first section of the chapter evaluates the impacts of the costs and
cost savings attributable to the Acid Rain Program on the regulated community as a whole. The
second section examines regional differences in costs and savings. The third section provides a
qualitative overview of the "secondary" impacts of the Acid Rain Program-that is. the effects on
entities outside the regulated community. The final section examines the differential effects of the
program on smaller entities.
5.1 Impucts on the Regulated Community
This section evaluates the costs identified in Chapter 4 in terms of their impacts on entities
in the regulated community. The impact measures considered in the section include effects on costs,
rates, sales, and net incomes.
5.1.1 Impacts on Regulated Utilities
The annual Acid Rain Program costs of between $1.0 and $5.1 billion and the cost savings
of $0.4 to $2.8 billion, while large in absolute terms, are relatively small compared to the roughly $200
billion annual costs of generating electricity.1 As shown in Exhibit 5-1, the average costs (on a
"levelized" basis) of generating electricity rise 0.5 to 0.7 percent under the absent regulations case for
1995 under the high and low scenarios, respectively.2 - Average cost impacts for 2000. 2005, and
2010 are greater as a consequence of Phase II, but still less than two percent of total costs. As with
any average, these average cost estimates take into account utilities with more significant cost impacts
as high as ten percent or more in a few cases) along with many others that are largely
unaffected or experience cost reductions under the absent regulations case. The highest cost impacts
are likely to be among utilities with fairly small high sulfur coal-fired plants; these cases are discussed
in section 5.4 of this chapter.
The regulations provide cost reductions of less than a third of one percent of total generation
costs in Phase I and generally less than one percent in Phase II. as shown in Exhibit 5-1. Savings of
this magnitude amount to between one-fourth and two-thirds of the costs in the absent regulations
case, depending on the year and the scenario.
See Exhibit 4-2 of Chapter 4.
In addition to cost changes related directly to emissions reductions, costs to utilities include transactions costs (under
the regulator)' case); costs of CEMS; costs of permits: and the costs of participation in auctions, direct sales, and
IPP guarantees. These costs are insignificant compared to the cost impacts of SO; reductions (i.e.. much less than
one tenth of one percent of electricity generation costs).
Levelized cost impacts for a given year reflect changes in fuel and operating costs plus changes in capital costs that
have been spread out over the life of the purchased capital equipment. Actual capital expenditures will be higher
in the early years (and Sower in later years) than suggested by the levelizing procedure.
5-1
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The impacts of these cost changes on the financial health (in terms of net income) of the
utilities is likely to be very small. As discussed in Chapter 2. utility rates are tightly regulated. Cost
increases, so long as they are the result of prudent decisions, are generally passed through to
electricity consumers as price increases. The utilities' margins are thereby insulated to a large decree
from both cost increases and decreases.
EXHIBIT 5-1
AVERAGE NATIONWIDE PERCENTAGE CHANGE IN ELECTRICITY COSTS
(percent)
COST SAVINGS OF i
COSTS OF ABSENT
REGULATIONS CASE
(incremental to pre-
Statute case)
COSTS OF
REGULATORY CASE
(incremental to pre-
Statute case)
REGULATORY
CASE
(incremental to absent i
regulations case)
Low
Scenario
High
Scenario
Low
Scenario
High
Scenario
Low High
Scenario Scenario
1995
0.5
0.7
0.3
0.4
0.2 0.3 |
2000
1.3
1.9
0.5
0.8
0.8 l.l !
2005
1.4
1.7
1.0
1.2
0.4 0.5 ;
2010
0.9
1.5
0.4
1.1
0.5 0.4 j
In addition, because utilities are structured as regulated monopolies (as discussed in Chapter
2). they are generally protected from losing customers to competitors with lower rates. While
customers may reduce their total consumption of electricity in response to price increases (and.
conversely, may increase consumption as prices fall), they tend to be relatively insensitive to price
changes.4 Consumers' responses to price increases or decreases in the range of one-half to one
percent may be considered insignificant by the utilities experiencing these responses.
Cost changes cannot always be passed through entirely, however, because Public Utility
Commissions may disallow portions of the costs if it is determined that they were not prudently
incurred. The regulations will reduce the utilities' exposure to potential financial difficulties by
minimizing the increase in their costs. Further, the regulations will tend to reduce impacts on utilities
that arise from lags in the rate-setting process. Because cost increases are not always quickly
translated into price increases, they can sometimes hurt profitability. By reducing cost impacts, the
regulations can minimize the effects of the lags in the rate-setting process.
Some smaller utilities faced with the need to make capital investments in order to comply with
the Acid Rain Program's requirements may have difficulty arranging financing for the investments.
Capital costs are typically recovered through rate increases over the life of the purchased equipment.
The observation that most customers are insensitive to changes in electricity rates may be changing, given the
increasing deregulation of the industry in the new power generation markets, where there is sometimes considerable
competition from industrial regeneration, self-generation, and independent power producers.
5-2
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However, the capital costs associated with SO-, controls are relatively small compared to the total
capital spending and cash flow in the utility sector, capital-related problems are likelv to he relatively
uncommon. To the extent that there are problems with capital availability, however, the flexibility
afforded by the regulations should make a positive contribution. Bv purchasing allowances rather
than emissions control equipment, a utility can avoid or delay a large investment.
5.1.2 Impacts on Independent Power Producers
The impacts of the statute and the regulations on IPPs are very difficult to predict in a
quantitative manner. As discussed in Chapter 3. the statute makes no provision for anv emissions by
IPPs or other new units (except for units brought on line by the end of 1995). Rather than make
the unrealistic assumption that new (post-1995) plants would be held to zero emissions in the absence
of implementation regulations. EPA assumed for the purposes of the absent regulations case that
IPPs would be allowed to enter the industry, but would be held to a strict emissions limit. Because
the estimates of the cost changes for IPPs would be very sensitive to the specific emissions limit
assumed in the absent regulations case (c.#.. if the emissions limit for IPPs were set equal to the
existing new source performance standard, the statute would appear to have no impact on IPPs at
all), EPA has not attempted to analyze IPP costs and savings quantitatively.
Qualitatively, the absent regulations case appears to create serious uncertainties for IPPs and
in the extreme could mean the elimination of all new fossil fuel fired IPPs. The regulatory case, on
the other hand, offers IPPs the opportunity to enter the industry through the purchase of allowances.
In addition, the IPP guarantee program (as well as the auctions and direct sales programs) are likely
to reduce the costs and impacts of the Acid Rain Program still further.
5.2 Distribution of Impacts by Region
The impacts discussed in the previous section are nationwide averages, and do not represent
the impacts faced by utilities in any one state or region. Given the significant differences in fuel
mixes across regions and the differential effects of SO-, controls on power plants using different fuels,
regional impacts can be expected to vary widely.
Regional differences in impacts, measured in terms of percentage changes in the cost of
electricity generation, are shown in Exhibits 5-2a and 5-2b. Exhibit 5-2a shows cost increases by
census region under the absent regulations case in the low and high scenarios (as described in
Chapter 3). (The areas covered by the ten census regions are shown in Exhibit 5-3.) Costs for each
of the four years analyzed in the RIA are presented in separate columns. Exhibit 5-2b presents the
cost savings provided by the implementation regulations.
Under the high scenario, changes in costs in 1995 range from 0.0 percent in the Pacific region
up to 1.5 percent in the East North Central. In general, this reflects the location of Phase I-affected
power plants: there are no affected units in the Pacific region, for example, and proportionately the
most affected capacity in the East North Central region. Cost savings in 1995 are as low as a
negative 0.4 percent in the Upper South Atlantic region — in other words, costs are temporarily
higher with the implementation regulations in that region and at that time as a result of capital
investments made during Phase I under the regulations - these investments pay off in later years,
resulting in net savings to the region. Savings in 1995 range as high as 1.3 percent in the West South
Central.
5-3
-------
Percentage impacts also vary widely within each region from one point in time to the next,
generally reflecting the increasing reductions requirements between Phase I and Phase II. In the
West North Central region, for instance, under the high scenario, costs rise from 0.9 percent in 1995
to Vi percent in 2000 before declining somewhat. In general, the regional cost and cost savings
mirror the pattern of national costs over time discussed above. In Phase 1(1995). the resiional
percentage increase in costs in the absent regulations case and the cost savings in the regulatory case
are the lowest, reflecting the relatively moderate level of emissions reductions required in 1995. In
Phase II (2000 - 2010), the cost impacts and cost savings are generally higher, reflecting the more
significant emissions reduction requirements in the later years.
An important underlying pattern in these results appears if the variations over time are
removed by averaging the percentage changes in costs over the entire forecast period (1995 - 2010).
Exhibit 5-4 shows the approximate percentage cost changes over the period 1995 through 2010 under
the absent regulations and regulatory cases for the high scenario. The census regions are listed in
order of cost impacts, from lowest to highest. In general, the regions with the highest cost impacts
are those with the most affected coal capacity and greatest required SO-, reductions. While the
savings provided by the implementation regulations do not follow exactly the same pattern, the four
regions with the lowest costs do appear to have lower savings. Similarly, the four regions with the
highest cost impacts under the absent regulations case all have relatively large savings under the
regulatory case.
Exhibit 5-5 shows that the group of regions with the highest costs under the absent
regulations case form a relatively cohesive geographic unit. The map also shows that the four high
cost regions (the West North Central. East North Central, East South Central, and Upper South
Atlantic—heavily shaded) are clustered around the upper Midwest. The four regions with low costs
and generally lower savings under the regulatory case (the Pacific, Middle Atlantic. Lower South
Atlantic, and New England regions-lightly shaded) are found in the periphery. Two regions with
moderately high costs and high savings (the Mountain and West South Central regions) lie between
the periphery and the center.
The high cost area of Exhibit 5-5 corresponds roughly to the region of greatest dependence
on medium-to-high sulfur coal for electricity generation. In addition, these regions are generally
required by the statute to achieve the greatest degrees of S02 reductions in absolute and percentage
terms. It is not surprising that the rigid S02 limits of the absent regulations case would impose the
greatest costs on this midwestern region. In addition, the greater flexibility allowed under the
regulations (including both emissions trading and banking of extra technology allowances) can be
expected to allow significant savings to this same group.
Trading programs can generate considerable profits for affected units or sources whose
emissions are already low (in some cases below their allowance allocations), because of their ability
to generate and sell allowances in the high cost area of Exhibit 5-5.
5-4
-------
EXHIBIT 5-2a
PERCENTAGE CHANGE IN ELECTRICITY COSTS
FOR ABSENT REGULATIONS CASE INCREMENTAL TO PRE-STATUTE CASE
(percent)
1
1995
2000
2005
¦ i
2010 :
-
Low2
Highb
Lowa
Highb
Low^1
Highb
Lowa
High11 ;
NEW ENGLAND
0.2
0.1
0.4
0.7
0.2
0.8
0.1
0.5 !
| MIDDLE
| ATLANTIC
0.3
0.3
1.0
1.S
0.5
1.6
0.1
1.2 ;
UPPER SOUTH
ATLANTIC
0.8
0.7
3.0
4.4
2.5
3.1
1.2
2.2 '
|
LOWER SOUTH
ATLANTIC
0.2
0.4
0.8
1.4
2.0
1.1
0.4
0.9
EAST NORTH
CENTRAL
1.2
1.5
2.1
2.5
2.1
2.5
2.0
3.1 '
EAST SOUTH
CENTRAL
0.8
1.0
2.6
3.3
2.7
2.4
1.0
2.0
WEST NORTH
CENTRAL
0.8
0.9
2.1
3.1
2.9
2.5
2.4
2.7 j
WEST SOUTH
CENTRAL
0.0
1.3
0.5
1.2
0.4
1.9
0.4 1.1 !
MOUNTAIN
-0.3
0.1
1.4
1.6
2.6
2.0
1.3 1.8
PACIFIC
0.0
0.0
0.2
0.1
0.1
0.3
0.3
0.3 |
TOTAL U.S.C
0.5
0.7
1.3 1.9
1.4
1.7
0.9
1.5
Low refers Low Scenario.
High refers to High Scenario.
Total U.S. is an average across regions, weighted by electricity consumption.
5-5
-------
EXHIBIT 5-2b
PERCENTAGE COST SAVINGS OF REGULATORY CASE
INCREMENTAL TO ABSENT REGULATIONS CASE
(percent)
-
1995
2000
2005
2010
,
i
Lowa
Highb
Low;1
Highb
Lowa
Highb
Low'
High11
NEW ENGLAND
0.2
0.2
0.5
0.3
0.5
a,
0.3
0.1 ;
MIDDLE
ATLANTIC
0.0
0.0
0.7
0.9
-0.2
0.3
-0.1
0.2
i UPPER SOUTH
1 ATLANTIC
-0.3
-0.4
1.8
2.6
0.4
0.5
0.2
0.2
LOWER SOUTH
ATLANTIC
0.3
0.3
0.6
0.5
0.4
0.2
0.5
0.2 '
;
EAST NORTH
CENTRAL
0.2
0.3
1.1
..9
0.6
0.5
0.8
0.9
EAST SOUTH
CENTRAL
0.6
0.5
1.5
1.5
0.7
0.7
0.4
0.4
WEST NORTH
CENTRAL
0.7
0.5
1.1
1.1
0.9
0.8
1.2
0.8
WEST SOUTH
CENTRAL
-0.1
1.3
0.5
1.1
0.5
1.1
0.4
0.4
MOUNTAIN
-0.1
0.0
1.2
1.0
1.4
1.5
1.1
0.9
PACIFIC
0.0
0.0
0.2
0.2
0.2
0.2
0.3
0.2
TOTAL U.S.b
0.2
0.3
0.8
1.1
0.4
0.5
0.5
0.4
Low refers Low Scenario.
High refers to High Scenario.
Total U.S. is an average across regions, weighted by electricity consumption.
5-6
-------
EXHIBIT 5-3
U.S. CENSUS REGIONS
-------
EXHIBIT 5-4
Costs of Absent Regulations and Savings with Regulations from 1995 through 2010 as a
Percentage of (feneration Costs11
(percent)
REGION11
COSTS
SAVINGS
j
PACIFIC
0.2
j
NEW ENGLAND
0.5
0.2
LOW COST.
LOW SAVINGS
LOWER SOUTH
ATLANTIC
0.9
¦
0.3
MIDDLE
ATLANTIC
1.1
1
0.3
J
MODERATE COST,
HIGH SAVINGS
MOUNTAIN
1.3
0.8
WEST SOUTH
CENTRAL
1.5
1-1
EAST SOUTH
CENTRAL
2.0
0.7
HIGH COST,
WEST NORTH
CENTRAL
2.1
0.8
HIGH SAVINGS
EAST NORTH
CENTRAL
2.3
0.7 |
UPPER SOUTH
ATLANTIC
2.4
0.5
Costs and savings were estimated by averaging estimates from 1995, 2000. 2005, and 2010 for the high scenario.
Regions listed in order of lowest costs to highest costs.
5.3 Secondary Effects
Title IV's direct effects reach only the nations electric utilities and IPPs. As discussed in
section 5.1. however, the utilities are not likely to absorb much of the impacts of the Acid Rain
Program. Instead, the impacts are likely to be passed on to other sectors of the economy: electricity
consumers, the coal industry, railroads and other transportation providers, oil and pas producers, and
emissions control manufacturers.
Although the other sectors have not been analyzed in detail in this analysis, EPA. has
attempted to identify the sectors that will experience the most significant secondary impacts, and
made qualitative assessments of the nature and direction of the effects.
5.3.1 Impacts on Electricity Users
As discussed, the costs of emissions reductions are likely to be passed on through increases
in electricity rates. The increased costs will have very' small impacts on the typical consumer:
5-8
-------
electricity is a minor part of household budgets, and the changes in electricity bills will be small even
in percentage terms. Consumption will drop marginally as prices rise, as consumers respond to avoid
some of the increased costs. Reducing electricity usage, though, will impose real costs on consumers.
-------
EXHIBIT 5-5
REGIONAL IMPACTS
REGIONS WITH HIGH COMPLIANCE COSTS TEND TO HAVE HIGH SAVINGS
WITH IMPLEMENTATION REGULATIONS
NEW
PACIFIC
JuS'tf ««*>'
SOUTH
CENTRAL
High costs and high savings
fill] Moderate costs and high savi
Low costs and low savings
-------
Regional shifts in coal mining employment would also be mitigated by retrofit scrubbing. As
a result, employment losses in high sulfur regions are likely to be somewhat less in the absent
regulations case (ir. which there is more retrofit scrubbing) than in the regulator/ case in 2005 and
2010.
5.3.3 Transportation Impacts
Changes in regional coal-production caused bv the Acid Rain Program will affect the railroad
industry as well as the coal industry. The total volume of rail shipments of coal (measured in ton-
miles) is expected to increase under the absent regulations case. This is because manv eastern power
plants currently rely largely on coal from mines in their own region. .As these power plants switch
to lower sulfur coals, from Centra! and Southern Appalachia and the West, coal must be hauled
greater distances. Railroads heavily involved in the high sulfur transportation market will experience
decreased shipment demands, while railroads positioned to haul low sulfur coals will experience
increased shipment demands.
Increased retrofit scrubbing will mitigate some of the increase in ton-miles hauled because
scrubbed sources will continue to rely on less expensive regional coals. As a result, ton-mile increases
are expected to be smaller in the absent regulation case than in the regulatory case in 2005 and 2010.
Barge transportation, like rail transportation, is expected to increase as a result of the Acid
Rain Program. For example, there will be increased shipments of western coal moved by barge on
the Great Lakes to Michigan. Wisconsin. Illinois, and Indiana. Truck transportation of coal, on the
other hand, is expected to decline. This is because truck transportation is generally only economical
for short hauls (i.e.. to power plants that rely on local high sulfur coals). Therefore, as more power
plants switch to low sulfur coals they will rely more heavily on rail and barge transportation.
5.3.4 Impacts on Oil and Gas Use
Some utilities that are currently burning oil are expected to switch to gas in order to reduce
SOt emissions (the S02 emission rate of natural gas is virtually zero). Many of these sources are
currently "oil/gas fungible" (i.e., are able to switch quickly and easily between oil and gas) and have
access to gas pipelines. Others (e.g., some sources in New England, New York and Florida) have
limited pipeline access or face regional pipeline capacity limitations in the near term and would thus
incur additional costs to switch from residual oil to natural gas. As a result, gas producers are likely
to experience increased demand (and may receive higher prices) at the expense of oil producers.
After 2000 under the high scenario, gas utilization is expected to be somewhat higher in the
regulatory case than in the absent regulations case because oil/gas steam sources in some regions may
find it profitable to over-control (i.e., reduce emissions below target levels) and sell or use the
resulting allowances elsewhere.
5.3.5 Impacts on Manufacturers of Emissions Control Equipment
The Acid Rain Program will lead to increased retrofit scrubbing at coal-fired power plants.
The increase in retrofit scrubbing will, in turn, lead to increased revenues for scrubber manufacturers,
as well as increased revenues for lime/limestone producers (lime/limestone are common catalvtic
reagents used in wet scrubbing systems). This could also lead to increased employment in the air
pollution equipment industry.
5-11
-------
As mentioned earlier, more retrofit scrubbing is expected in the absent regulations case than
in the regulatory case. This is because many sources cannot easilv switch to low sulfur coais because
( 1) they are not easily accessible by rail. (2) they are "minemouth" plants (i.e.. located very near a coai
mine and receiving their coal by truck or conveyer) or (.i) thev have boiler designs that arc not
compatible with eastern low sulfur coals.'1
5.4 Impacts on Small Entities
This section provides an assessment of the differential effects of the regulations on small
entities. The first subsection presents a description of the federal requirements for a small entitv
analysis. The next subsection provides a definition of a small entity for the purposes of this report
and a characterization of the population of small entities. The third subsection presents estimates
of the costs and savings under the absent regulations case and the regulatory case for six model
utilities that, taken together, represent the most important characteristics of the small utility
population. The fourth subsection discusses the potential differences between the impacts on small
utilities that are owned by municipalities and other small utilities. Finally, the fifth subsection
summarizes the conclusions of the small entity analysis.
5.4.1 Requirements for a Small Entity Analysis
Under the Regulatory Flexibility Act (RFA), EPA is required to analyze the impacts of
proposed regulations to determine whether they will cause a significant impact on a substantial
number of small entities.0 Because the RFA does not provide concrete definitions of "small entitv."
"significant impact," or "substantial number." EPA has established guidelines setting the standards to
be used in evaluating impacts on small businesses.7 The guidelines specify that size definitions set
by the U.S. Small Business Administration (SBA) should be used as the initial determination of a
"small entity," but that EPA can use an alternative definition if it better captures the point at which
entities are adversely affected simply because of their size. The guidelines further specify that a
"substantial number" can be either a large fraction of the affected population of small entities or a
large number of small entities. Finally, the guidelines set four criteria for determining whether
impacts will be significant:
• Annual compliance costs increase total cost of production for small businesses by
more than 5 percent:
• Compliance costs as a percentage of sales for small businesses are at least ten percent
higher than compliance costs as a percentage of sales for large businesses:
• Capital costs of compliance represent a significant portion of capital available to small
businesses; or
For example, wet bottom and cyclone boilers require low ash fusion temperature coals and there are few low sulfur
coals with these characteristics in the East.
5 USC 601.
U.S. Environmental Protection Agency, Memorandum to Assistant Administrators. "Compliance with the Regulatory
Flexibility Act." EPA Office of Policy, Planning and Evaluation, 1984 (no date).
5-12
-------
• The requirements of the regulations are likely to result in closures of small businesses.
The net effect of the regulations will be to reduce the cost of meeting the objectives of CAA.
and small entities are likely to be the primary beneficiaries of the costs reduction. However, an
assessment of the impact of compliance with the implementation regulations compared to compliance
with the statute bv itself is included.
5.4.2 Definition of Small Entity
For purposes of this analysis. EPA has adopted the SBA definition that a "small" electric
power utility is one that generates a total of less than 4 billion kilowatt-hours per year.'s Not all
small utilities are affected by the acid rain title of CAA. Utilities will be unaffected if (1) all of their
units are exempt (e.g.. units using non-fossil sources or existing simple gas turbines), or (2) they fall
below statutory minimums for electric generating capacity (existing units smaller than 25 \1W).
After excluding utilities exempt from the provisions of CAA. EPA has determined that about
105 of the 241 Phase II affected utilities (about 44 percent) are small.9 10 Collectively, affected
small utilities accounted for about 5 percent of total 1988 electricity generation by affected utilities
(i.e.. about 119 billion kilowatt-hours of electric power generation during 1988).
Characteristics of Small Utilities
Small utilities differ from large utilities in several important respects: (1) ownership; (2)
generation mix; and (3) cost of achieving emissions reductions. Exhibit 5-6 shows the ownership
patterns of all Phase II affected utilities, disaggregated by size. As shown in the exhibit, it is more
common for small utilities to be operated by municipal governments than is the case for larger
utilities; 60 percent (63 out of 105) of the small utilities whose generation is shown in Exhibit 5-6 are
run by municipal governments, while the comparable figure for large utilities is only four percent (5
out of 132). Municipal governments operating their own small utilities are likely to administer small
cities as well; thus, an analysis that examines the effects of the acid rain regulations on small utilities
also serves as an examination of the effects on small affected municipalities.11
This section treats utilities as the unit of analysis, rather than individual power plants or
individual generating units within power plants. The reason for concentrating on utilities is that they
are separate financial entities, while power plants and generating units are owned (generally) by
utilities. As a practical matter, smaller utilities tend to have only one power plant, and the analysis
assumes that all units owned by a given utility will be affected by the regulations. To some extent.
13 C'FR 121.
In making this determination, EPA counted all individual operating companies that operate at least one affected
unit. Because some of the operating companies are owned by one or more large utilities, the actual number of
affected utilities and affected small utilities will both be smaller. Four affected utilities could not be characterized
because their generation rates are unknown.
None of the Phase I affected utilities are considered small.
The assumption that small municipal utilities serve small municipalities is based on the fact that more than 60
percent (38 out of 63) of small municipal utilities are in cities with populations of less than 50.000. Countv and City
Data Rook. U.S. Bureau of the Census. 1988.
5-13
-------
this assumption could overstate the impact of the program, since utilities with some unaffected
generating units will face proportionately smaller changes in their costs.
EXHIBIT 5-6
OWNERSHIP CHARACTERISTICS OF AFFECTED PHASE II OPERATING UTILITIES,
BY SIZE CATEGORY
(number of utilities)
1988 Generation
(billion kilowatt-hours per year)
Large Utilities Small Utilities'1
Ownership
More
than 20
10 to 20
4 to 10
1 to 4
0.5 to 1
Less
than 0.5
Total" ;
Investor
35
29
41
19
1
5
130
Co-op
0
2
12
9
2
1
26
Municipal
1
1
1
3
15
2
46
68
I Federal
2
3
2
1
2
13
|
! Total
38
35
59
45
6
54
237
Small utilities are defined by the Small Business Administration as utilities generating less than 4 billion kwh.vr.
n Total does not include two investor-owned, one co-op, and one municipal utility for which generation rates are
unknown.
Source: National Allowance Data Base Version 1.0 and ICF Analysis of the Clean Air Act Amendments of 1990.
Exhibit 5-7 shows the types of fossil fuels used by utilities with different generation rates. As
seen in the exhibit, smaller utilities are more likely to depend exclusively on either oil/gas or coal,
rather than a combination of oil/gas and coal at different units. In addition, very small utilities are
more dependent on oil and gas as opposed to coal.
A preliminary review of publicly available data and information on unit characteristics suggests
that, all other things being equal, emissions from smaller power plants tend to be relatively costly to
control. In other words, it is generally more expensive per kilowatt-hour (kwh) of electricity
generated for a small plant to reach a given emissions target than for a large plant to reach the same
target. This is believed to be true for several reasons. First, relative to larger units, smaller units
typically require more fuel (measured in Btu) per kwh produced. Consequently, their costs of
switching to higher priced, lower sulfur fuels will generally be higher per kwh produced than for
larger units, even if they are able to switch to a lower sulfur fuel without any other cost. Second,
smaller units are at a relative disadvantage if capital improvements are needed in order to allow the
use of lower sulfur fuels. Smaller units cannot achieve the same "economies of scale" as larger units
and thus incur higher capital costs per unit kwh. Also, because smaller units tend to be older than
larger units, their shorter remaining useful lifetime over which to depreciate capital costs contributes
to a higher cost per kwh produced. Third, designing equipment for smaller units that is comparable
to equipment used at larger units is frequently more difficult, because smaller units generally have
less space available for adding equipment.
5-14
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EXHIBIT 5-7
FUEL USE CHARACTERISTICS BY UTILITY SIZE
ton
UtilMaa Using Coal Only
roo* -i
OJ 9.2 g.03
I
I
I
UtflMH iMng Om/OI Only
io.o* -
ao»
f
iu> -
0.08
l««l
5-15
-------
5.4.3 Estimation of Impacts of Statute and Implementation Regulations
This section presents analyses of how the total costs of the statute and the implementation
regulations vary with utility sizes, fuel tvpes, and ownership tvpes. The costs due to the effects under
the absent regulations case are compared to the effects under the regulatory case. Costs under the
absent regulations case include the costs of SO-, emissions reductions and the installation of basic
CEMS. Estimated costs under the regulatory case include SO-, emissions control costs as reduced
by emissions trading and banking, plus the costs of transactions, additional CEMS monitoring
requirements (including data reporting), and permits. Results are based on the high scenario in the
year 2000. which is believed to provide a reasonable basis for evaluating maximum potential impacts
of the regulations on small entities.
In examining effects on small entities. EPA constructed six model small utilities of varying fuel
type and size to represent most of the small utility population. It was important to include model
utilities using different fuel types because the cost of controlling SO-, emissions for coal plants is
different from the cost for oil or gas plants, and different allowance allocations are made depending
on fuel type. There were also two factors considered in choosing model utilities of varying sizes.
First, relatively smaller utilities would tend to experience greater impacts if they were subject to the
same statutory provisions as relatively larger utilities. Second, it was necessary to include utilities of
all sizes because the statute contains provisions which grant additional allowances to a subgroup of
small utilities—those with high emissions rates, no power plants larger than 75 MW. and total fossil
steam generating capacity below 250 MW. It was necessary to differentiate among utilities that were
affected by these provisions and those that were not.12
To allow for the effects of utility size, EPA developed two sizes of model plants by first
dividing the universe of small entities into four size groups; each group contains one-fourth of the
affected small entities. EPA identified characteristics of the plants at the points dividing the size
groups (i.e.. the utilities that were greater in size than 25, 50 and 75 percent of all small utilities,
termed the lower quartile, median, and upper quartiles respectively). EPA then developed model
plants that corresponded to the plants at the lower quartile and median points. EPA determined that
utilities at the median were generally on the borderline of meeting the statutory requirements that
provide additional allowances. Consequently, utilities at the median are about the smallest that are
subject to the same level of stringency as large plants and are. therefore, likely to incur the largest
impacts. Utilities at the lower quartile will be typical of the smaller utilities potentially eligible for
additional allowances. The smallest existing units covered by the regulations are 25 MW. but new
units less than 25 MW are also covered under some options. Under Option 5. units less than 25 MW
will not be required to have CEMS and permits. Impacts on those units less than 25 MW are
considered briefly in an attachment to this document.
To allow for differences across fuel types, two of the model utilities burn coal; two burn oil;
and two burn natural gas. The two coal-fired utilities are relatively "dirty." with pre-statute emissions
rates of S02 of about 5 lbs/mmBtu. The two oil-fired utilities have emissions rates of SO, of about
1.5 lbs/mmBtu. whereas the two gas-fired utilities have virtually no SO? emissions. The larger coal-
tired utility has total (year 2000) generation of about 2.1 bkwh/yr (billion kwhs per year), which is
about half SBA's current definition of a small utility and about 5 times as great as the median of all
More detail on these provisions, and on the number of utilities affected by them, is provided in Appendix 5.
5-16
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small utilities in 1988.1 The larger gas-tired utility has a total generation rate of about 1.3 bkwh/vr.
The larger oil-fired utility has a total generation rate of about 0.5 bkwh/vr. Each of the three smallest
model utilities have generation rates of about 0.! bkwh/vr. In the case of the larger oil and coal
utilities, their total capacitv exceeds 250 MW. Hence, thev must effectively reduce their emissions
to 1.2 lbs/mmBtu based on their baseline fuel consumption. The larger oil and coal utilities are worst
case examples because all of their units are assumed to be affected, and have to reduce emissions
significantly at high unit costs. In contrast, the smaller coal and oil utilities have total capacitv less
than 250 MW and hence receive allowances equal to their current emissions levels (that is. their
baseline times their current emissions rate) and are not forecast to experience any utilization
increases in the future. Accordingly, they do not need to reduce their emissions.
.Another important regulatory distinction relates to gas units of differing utilization patterns.
As discussed in Chapter 4. gas and oil units used ten percent of the time or less (that is. "peaking"
units) are permitted to use monitoring methods other than CEMS that will cut monitoring costs
substantially. The model utilities assumed for this analysis concentrated on non-peaking units, since
they are both more common and more likely to incur significant costs. In reviewing the results,
however, it should be kept in mind that impacts for some small oil- and gas-fired units will be
substantially lower than those presented here.
Results of Model Utility Cost Impact Analysis
Exhibit 5-8 shows the cost of the regulations in millions of dollars per year. Cost categories
examined include the costs of SO, reductions; transactions costs associated with buying and selling
allowances: costs of CEMS; and permit-related costs. Costs for the auctions, sales, IPP guarantees,
and conservation and renewables are not included, as these are voluntary programs with minimal costs
to participants.
Costs of SO-, reductions are the incremental costs of acid rain controls, relative to the pre-
Statute case, under the absent regulations and regulatory cases. Costs for the model utilities were
estimated using the results of the CEUMl-i and additional calculations to adapt the model's results
to the model utilities that were constructed. The assumed responses of the utilities under the absent
regulations case and the regulatory case are shown in Exhibit 5-9. Allowance trading and banking
lead to cost savings (or no change) relative to the absent regulations case for each model utility; for
the small oil utility and the two gas utilities, the allowance trading and banking system leads to net
savings relative to the pre-Statute case.
EPA has not made precise estimates of the costs of allowance transactions to individual small
utilities. Instead, impacts have been estimated on the basis of relative values of transactions costs and
volumes and the cost savings from trading and banking. A small utility's transaction costs per
allowance traded are assumed to be four times higher than the industry average.15 Transaction
Generation rates are not strictly comparable, however, because the generation rate in 2000 incorporates estimates
of utility growth.
IC'Fs Coal and Electric Utilities Model (C'EUM) is a detailed linear programming, engineering-economic model that
contains a coal supply segment, a transportation segment, an electric utility demand sector, transmission, and non-
utility energy demand segments and is linked with databases and other supporting models. 'ITiis model is the
primary analytic tool used by K'F in analyses for EPA. other federal agencies, and private companies for proposed
acid rain policy initiatives and bills.
See Appendix 4A.
5-17
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costs tor the industry as a whole are assumed to he three percent of the savinns realized through
allowance trading.16 If the per-unit transaction costs for small entities are four times as great as
lor the industry as a whole, then transactions costs equal twelve percent (that is. four times three
percent) of the savings from trading and banking. The costs shown in Exhibit 5-N reflect a twelve
percent transactions cost. (This is likely to be an overestimate for the largest small utilities, as their
allowance transactions may be about as large as the average industry-wide transaction. If so. their
transactions cost might be no higher than the industry average.) The auctions, direct sales, and IPP
written guarantee program should help keep transactions down for small entities, as they are expected
to aid in the development of a well-functioning market.
EXHIBIT 5-8
ESTIMATED COST OF THE ACID RAIN PROGRAM TO MODEL SMALL UTILITIES
Cost
(Millions of Dollars)
! Model I'tility
Case
SO, Reduc-
Transactions
CEMS
Permits
Total
tions
j Coal (more than 250
Absent regulations
23.510
0.055
0.0(H)
23.571
j MVV capacity)
Regulatory
7.2%
1.946
0.109
0.003
''.355 j
i
Difference
-16.220
1.946
0.055
0.003
-14.216 i
Coal (less ihan 250
Absent regulations
0.000
0.055
0.000
0.055 i
MW capacity)
Regulatory
0.000
0.000
0.109
0.003
0.113 |
Difference
0.000
0.000
0.055
0.003
0.058 :
()il (more than 250
Absent regulations
2.655
0.055
0.000
2.710
MW capacity)
Regulatory
1.845
0.097
0.125
0.003
2.070
Difference
-0.810
0.097
0.070
0.003
-0.639 i
Oil (less than 250
Absent regulations
0.000
0.055
0.000
0.055 I
1 MW capacity)
Regulatory
-0.062
0.007
0.125
0.003
(1.074 !
Difference
-0.062
0.007
0.070
0.003
0.019
(las (more than 250
Absent regulations
0.000
0.055
0.000
'
0.055 1
MW capacity)
Regulatory
-0.066
0.008
0.104
0.003
0.049 |
i
Difference
-0.066
0.008
0.049
0.003
-0.006 J
Gas (less than 250
Absent regulations
0.055
0.000
0.055 !
MW capacity)
Regulatory
-0.007
0.001
0.104
0.003
0.101 j
Difference
-0.007
0.001
0.049
0.003
0.047 !
Source: 1CF analysis.
All units are iissumed to have capacity factors greater than ten percent.
The absent regulations case assumes costs for purchasing CEMS but no costs for data
reporting. The cost of CEMS in the regulatory case assumes a variant Option 5. which is the
F.xhibit 4-22 shows the high estimate of transactions costs to be S400 million, while Exhibit 4-23 shows the high
estimate of savings from trading to be S13.8 billion. The transactions costs as a percentage of savings, then, are
equal to S0.4 billion/Si3.8 billion or about three percent.
5-18
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proposed option.17 It includes annual costs of S1.K00 per source (based on Exhibit 4-10 on page 4-
24) tor data reporting in Phase II. Costs of permits are based on the total annualized Phase II costs
to participants ($2,646,000) divided by the total number ot'sources (827) that are required to obtain
permits (see Exhibit 4-19 on page 4-37).
EXHIBIT 5-9
ASSUMED RESPONSES OF MODEL UTILITIES
Model Utility
Absent Regulations Case
Regulatory Case
COAL
: above 250 MW
!
Scrubs all units
Switches to low-sulfur coal and
buys allowances
i
below 250 MW
(No response)
(No response)
i OIL
above 250 MW
j
Switches to gas
Buys allowances
below 250 MW
(No response)
Sells allowances
GAS
!
! above 250 MW
(No response)
May sell a few allowances
j below 250 MW j
(No response)
May sell a few allowances
Source: IC'F analysis of cost-effective responses.
The three smallest model utilities are worse off under the regulatory case than under the
absent-regulations case. The increase in costs is moderately small (less than $60,000 per year) and
is due largely to the additional CEMS requirements.
Exhibit 5-10 shows the results in mills (tenths of a cent) per kwh for small utilities compared
to the industry as a whole. Although reliable electricity generation costs for the model utilities in the
pre-statute case were not available, the results can be compared to the average price of electricity
of roughly 60 mills/kwh.18 For four model facilities (the two gas-fired facilities and the smaller coal
and oil facilities) cost increases under the absent-regulations case are less than 1 mill/kwh. which is
comparable to the overall cost to all utilities. This increase represents about one percent of the
average price of electricity, and should cause minimal impacts. The difference in costs for these four
facilities under the regulatory case are minimal as well.
For the larger coal and oil-fired model utilities, though, impacts in the absent regulations case
are serious -- 5 to 11 mills/kwh, which is about ten to twenty percent of the approximately 60
mills/kwh value of the electricity generated. These utilities are helped significantly more by the
implementation regulations than the industry average. After transactions costs, the trading provisions
reduce the costs of S02 reductions to the larger model coal-fired utility by about 6.8 mills/kwh. The
The regulatory case does not fully reflect CEMS cost savings now incorporated into Option 5. and overstates CEMS
costs by about 10 percent for gas-fired units and 25 percent for oil-fired units. The overall thrust of the results are
not affected by these differences in cost estimates.
Edison Electric Institute Statistical Yearbook.
5-19
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overall savings ot the regulatory case is roughly 60 percent ol the costs under the absent regulations
case. For the larger oil-tired utiiitv. the net cost savings of the trading provisions is about 1.2
mill.kwh: overall, the regulatory case is 25 percent less costlv than the absent regulations case.
LXIIIBIT 5-10
INCREASE IN ELECTRICITY GENERATION COSTS TO MODEL SMALL I TILITIES
AND THE NATIONAL AGGREGATE FOR ALL UTILITIES -- YEAR 2000. HIGH SCENARIO
('osts
,mills per kwh)
Model Utility
('asc
Reductions
Transactions
CIIMS
Permits
Total
Coai (more than 250
Absent regulations
! 1.187
0.000
0.026
0.(100
1 1.213
MVV capacity)
Regulatory
>.471
0.926
0.052
0.002
4.45 1
Difference
-7.716
0.926
0.026
0.002
-6. "63
Coal (less than 25(1
Absent regulations
0.00(1
0.000
0.391
0.0(10
0."91
MW capacity)
Regulatory
0.000
0.000
0.782
0.023 :
0.805
Difference
0.000
0.000
0.391
0.023
0.414
Oil (more than 250
Absent regulations
5.057
0.000
0.104
0.000
. 1 6 1
MW capacity)
Regulatory
3.5 14
0.185
0.238
0.006
3.944 :
Difference
-1.543
0.185
0.134
0.006 ;
-1.218
Oil (less than 250
Absent regulations
0.000
0.000
0.421
0.000 I
0.421 .
MW capacity)
Regulatory
-0.477
0.057
0.961
0.025 :
0.566
Difference
-0.477
0.057
0.541
0.025 .
0.146 :
Gas (more than 250
Absent regulations
0.000
0.000
0.041
0.000 :
0.041
MW capacity)
Regulatory
-0.044
0.006
0.077
0.002 ;
0.036 i
Difference
-0.049
0.006
0.037
0.002 |
-0.004
Gas (less than 250
Absent regulations
0.0(H)
0.000
0.405
0.000 ,
,
0.405 1
MW capacity)
Regulatory
-0.049
0.006
0.770
0.024 ¦
0.751 |
Difference
-0.049
0.006
0.365
0.024 :
0.346 !
National aggregate'1
Absent regulations
1.388
0.000
0.056
0.000 ;
1.444 :
Regulatory
0.587
0.009
0.061
0.001
0.65,S |
Difference
-0.801
0.009
0.005
0.001
-0.786 i
National aggregate is estimated by dividing total cost by total generation.
Source: ICF analysis.
/Ml units arc assumed to have capacity factors greater than ten percent.
Even after the reductions in cost provided by the implementation regulations the impact on
small coal- and oil-fired utilities is still significant. The regulatory cost to the larger coal-fired model
utility of 4.5 mills/lcwh represents more than seven percent of the 60 mills/kwh value of the electricity
produced, whereas the regulatory cost to the larger oil-fired model utility of 3.9 mills/lcwh represents
less than 7 percent of the value of the electricity produced. About 36, or one-third of the 105
affected small utilities, could face impacts of up to this magnitude, although as noted the larger coal
and oil model utilities represent worst case examples. The other two-thirds have regulatory impacts
that are comparable to or less than the impacts on all utilities as a group. EPA believes that bv
implementing the trading provisions, it has provided all relief available under the statute to help the
most affected small utilities. Costs of the CEMS and permit provisions represent a minor part of the
overall cost to these utilities.
5-20
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5.4.4 Impacts on Small Municipal Utilities
Exhibit 5-6 showed the strong association between small utilities and municipal ownership:
almost all municipal utilities (63 of 68) are small, and a majority of small utilities (63 of 105) are
municipal. Because of the large number of municipallv-owned small utilities, it is important to
consider whether the impacts of the Acid Rain Program will differ according to the ownership of the
utilities.
The impacts of the Acid Rain Program could potentially differ between municipallv-owned
and investor-owned utilities for two reasons: if the same cost changes could have different impacts
depending on the financial structure of the owners; or if the mix of sizes and types of power plants
owned by municipalities is different than the mix owned by investors.
Of these two potential reasons for differing effects on municipallv-owned utilities. EPA has
considered only the second in detail. EPA has no reason to expect that the Acid Rain Program will
affect power plant costs differently solely on the financial structure of the owner. The fact that
municipallv-owned utilities rely more heavily on borrowed capital (as opposed to equity capital) than
do investor-owned utilities is not seen as likely to change the impacts of cost differences; if anything,
the use of tax-exempt municipal bonds as a financing mechanism may provide municipallv-owned
utilities with a minor cost advantage. Combined with the lack of a profit incentive for municipallv
owned utilities, the net cost under the regulatory case to the consumer may well be smaller for
municipally-owned utilities as compared to investor-owned utilities.
Because the size and fuel type of a utility has a significant impact on the costs of compliance,
however, it is important to consider the mix of power plants owned by municipal utilities compared
to investor-owned utilities and co-operatives. Exhibit 5-11 shows a breakdown of small affected
utilities by capacity and fuel type for federally owned, investor-owned, municipally owned, and co-
operative-owned utilities. Capacities are divided into those above and those below 250 MW, because
those below 250 MW with substantial emissions are more likely to be eligible to receive additional
allowances.19 Fuel types are divided into coal, oil. and gas.
The power plants most affected under the absent-regulations case are likely to be those at
utilities with capacities above 250 MW that burn coal or oil. As seen in the exhibit, a relatively small
fraction of municipally-owned utilities (9 of 63. or 14 percent) fall into these categories. By contrast,
most small investor-owned utilities (16 of 25. or 64 percent) fall into the categories likely to be most
affected. Co-operatives are similar to investor-owned utilities in that a large fraction (8 of 12, or 67
percent) burn coal and have capacities greater than 250 MW. Thus, relatively few municipal utilities
are likely to be seriously affected in the absent-regulations case, or to gain significantly under the
regulatory case.20
As seen in Appendix 5 A. about 58 of the 66 utilities with less than 250 MW of fossil steam generating capacity are
granted additional allowances, 17 because they meet statutory criteria of having an emissions rate of more than 1.2
lb/mmBtu and no individual unit greater than 75 MW capacity, and 41 because they have an emissions rate less than
1.2 Ib/mmBtu.
Impacts on municipal utilities with new small generating units, given the exception for certain new units under 25
MW. are discussed separately in a brief attachment to this document.
5-21
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EXHIBIT 5-11
FUEL USED AT SMALL UTILITIES BY TYPE OF OWNERSHIP
j
Less than 250 MW Ca-
More than 250 MW Ca-
1
1
paciiv
parity
1
i
Fuel
Percentaiie
Percentaue
Ownership
Type
Niimber
(of ownership)
N umber
(of ownership)
Total
Co-operative
Coal
3
25%
8
67%
1
11
Gas
1
8%
0
0%
1 :
Federal
Coal
1
20%
2
40%
3
Oil
2
40%
0
0%
i
1 Investor
Coal
4
16%
14
56%
IS
'
Gas
0
0%
2
8%
2 i
Oil
3
12%
2
8%
5
Municipal
Coal
25
40%
8
13%
/O !
Gas
20
32%
2
3%
22 1
Oil
7
11%
1
2%
8
Total
66
39
:
105 !
Source: ICF analysis.
5.4.5 Conclusions Regarding Small Entities
In conclusion, virtually all of the impacts on small businesses are caused by statutory
provisions of CAA. Although EPA is considering regulations that are intended to mitigate some of
the burden on small businesses (see the brief attachment to this document), the statutory provisions
restrict the amount of relief that can be given. EPA's regulatory flexibility analysis is summarized in
the following observations.
• The implementation regulations are likely to result in substantial
reductions in the costs imposed by the statute on small entities. As
a percentage of the costs under the absent regulations case, the
savings provided by the regulations may be similar to the savings for
larger utilities. Absolute savings measured in mills per kwh, on the
other hand, will typically be greater for those small utilities that face
significant costs than for larger utilities.
• Among small entities, most of the savings provided by the regulations
will be concentrated among those utilities experiencing the largest cost
increases under the absent regulations case: relatively larger small
utilities burning coal and, to a lesser degree, oil.
5-22
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• The auctions, direct sales, and IPP written guarantee programs are
likely to have net positive impacts on small entities.
• The proposed CEMS regulations (Option 5) will impose dispropor-
tionate costs on small entities because thev require the same equip-
ment at all facilities regardless of size. The proposed regulations,
however, would allow the use of monitoring methods other than
CEMS .for gas-fired units. This will mitigate the disproportionate
impacts to some degree, because small utility plants are more likely to
bum gas. Further mitigation of impacts for new small units is
discussed in a brief attachment to this document.
• Permit regulations will impose greater costs per kwh on the smallest
oil and coal utilities than on other utilities. The permit costs are
mandated by the statute, and are thus not imposed by EPA.
• A relatively small percentage of affected municipally-owned utilities
- no more than 14 percent - will face significant cost increases as a
result of the Acid Rain Program.
5-23
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CHAPTER 6
Benefits of S02 Reductions
This chapter describes the benefits that are expected to result from the SO-, reductions that
would result under the acid rain program. Where possible, the beneficial effects have been expressed
quantitatively: however, none of the effects have been expressed in terms of dollar values.
The five sections of this chapter discuss five areas in which acid rain is known or suspected
to cause damage: Acid levels in surface water; visibility; human health; forests; and materials. Each
section also discusses the extent to which the 10 million ton per year reduction in SO-, emissions
mandated bv Title IV may be able to reduce these damages.
6.1 Acidification of Surface Water
A principal effect of acid rain (or more accurately, acidic deposition, which includes acid rain,
snow, and fog, as well as gases and particulates) is increased acidity of lakes and streams.
Based on measurements taken under the National Surface Water Survey, it is estimated that
four percent of the lakes in the United States larger than 10 acres and eight percent of streams are
currently acidic.1 These percentages represent hundreds of lakes and thousands of miles of streams.
Acidic lakes and streams are even more prevalent in Canada than in the United States. The
Canadian government reports that more than 14,000 lakes in Southeastern Canada are acidic due to
acid deposition.2 In addition, there are many more surface water bodies which become temporarily
acidic at times of high acidic deposition capacity to neutralize acid, threatening biological life such
as fish. Including these bodies triples the number of lakes and streams seriously affected by
acidification.
SO? emissions have been identified as a principal cause of acid rain, which is estimated to be
responsible for three-fourths of lake acidification and half of stream acidification.3 Thus, significant
reductions in S02 emissions can be expected to reduce the problem of surface water acidification.
For example, analyses of the Adirondack region, which is particularly affected by acid deposition,
showed that a 50 percent reduction in sulfate (a transformation product of S02) deposition would
reduce the number of acidic lakes from the current level of 14 percent to 3 percent over a period
of years in that area.4 Other areas that would benefit from reduced S02 emissions include lakes and
streams in New England, the Mid-Atlantic Highlands and Coastal Plain, the upper Midwest, the
Southeastern Highlands, and Florida.3
National Acid Precipitation Assessment Program (NAPAP). Integrated Assessment External Review Draft.
August 1990.
"U.S. - C-anada Air Quality Agreement Progress Report", March. 1992.
See footnote 1.
See footnote 1.
NAPAP Integrated Assessment, 1990.
6-1
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Most acidified surface waters are unable to support fish or plant life. While there are species
(yellow perch, for example) that are resistant to acid and can live in some acidic waters, sensitive
species such as brook trout have been wiped out in many areas. The degradation of these habitats
has many harmful effects, in reduced value to sport fishers as well as in the more intangible area of
reduced biodiversity and the value our society attaches to ensuring that the nat.ural environment can
support wildlife. Acid sensitive species occur in all major groups of aquatic organisms including algae,
zooplankton. invertebrates, fish and amphibians. Thus, bv reducing SOt emissions, the Acid Rain
Program is predicted to provide the benefits, such as a rich and diverse population of aquatic species,
associated with restored capacity of surface water to support life by reducing acidic deposition and
thereby reducing surface water acidification. The further and future acidification of surface waters,
both due to chronic and episodic acidification, will also be substantially reduced in manv areas bv
significant reductions in acid deposition.
6.2 Reductions in Visibility
Another important impact of SO, emissions is reduced visibility. Visibility degradation
manifests itself as haze, which is particularly common in the eastern part of the United States. The
link between increased levels of sulfate in the air and visibility reduction is firmly established in the
scientific literature, and increased sulfate levels have, in turn, been found to be directly related to SOt
emissions. Sulfates account for more than half of the visibility problem in the East and about a
fourth of the problem in the West.6
Because a large part of the visibility degradation is caused by S02 emissions, reduced
emissions translate almost immediately into improved visibility. The ten million ton reduction in SOt
emissions mandated by Title IV is projected to increase visibility by about 30 percent in the eastern
part of the United States.7
The increased visibility that would be provided by the S02 reductions in the acid rain program
create two major types of benefits: increased safety and improved aesthetics. Increased safety may
be manifested in terms of reduced accident rates for aircraft and motor vehicles. Improved aesthetics,
particularly in national parks and other scenic vistas, are highly valued by the public. Improved
visibility will affect national parks including the Great Smokey and Shenandoah Mountains in the
east. Visitors to the parks and wilderness areas will benefit from improved visual range and increased
ability to see form, texture and color in a view.
6.3 Effects on Human Health
S02 emissions, and especially air concentrations of acid sulfate aerosols, have been implicated
by a growing body of evidence from epidemiological studies and laboratory studies of humans and
animals as responsible for a variety of human health effects. Some studies directly relate acid aerosols
to breathing problems in asthmatics, children, and other sensitive subpopulations. Acute exposures
may result in wheezing, coughing and shortness of breath. Other studies implicate the effect of
long-term exposure to acid aerosols on the development of chronic lung disease. Sulfate
concentrations have been shown by one study to be associated with an increase in hospital admissions
See footnote I.
See footnote 1.
6-2
-------
tor respiratory ailments, and several researchers have suggested that sulfates are responsible tor an
excess in mortality*
A number of inherent uncertainties exist in some of the analyses concerning the effects of
SO-, on human health, especially with regard to the association between sulfates and excess mortalitv.
Consequently, definitive statements concerning the amounts and types of health effects caused bvSO-,
are limited. Nevertheless, the consistent findings across several studies and indications of ongoing
health studies support the belief, that a reduction in SO-, will result in a significant — and. for some
health effects, immediate — reduction in adverse human health effects.
6.4 Effects on Forests
Acid deposition appears to be a major contributor to damage to high elevation spruce trees
that populate the Appalachian Mountains and other mountain ranges in the eastern part of the
United States. This damage is manifested by a loss of foliage, which can lead to a reduction in tree
populations in high elevation areas and. in turn, an increase in erosion and other adverse effects.
Acid deposition also is a concern for forest soils. As acidic compounds moves through the
soil, they can strip away vital plant nutrients and thus pose a threat to future forest productivity.
Furthermore, as the acidity of the soils increases and the capacity of the soil to absorb acidic
deposition decreases, acidic water begins to pass through to surface waters, thus increasing the
adverse effects to aquatic organisms (discussed in Section 6.1) and to an entire watershed area.
A reduction of S02 emissions is expected to not only result in an elimination of damage to
foliage and soil, but to allow for the recovery of previously damaged tree populations. Constant or
increased emissions, on the other hand, are expected to result in increased foliage damage and an
increase in soil acidity.
6.5 Damage to Materials
Through the use of controlled experiments that imitate current conditions, acidic deposition
has been shown to corrode certain commercially important coatings, such as paint, and a variety of
structural materials, such as those used in items ranging from statues to buildings.9 Many public
monuments and other cultural objects are constructed of some of the most susceptible of these
materials. Furthermore, the areas in the U.S. having the largest number of cultural materials coincide
with the regions of highest acidic depostion. These cultural resources include historic buildings,
monuments, statues and gravemarkers. Recent data also indicate that acid deposition may damage
automobile paint often resulting in car owners or dealerships repainting the damaged surfaces.
Secondary benefits (e.g., reduced soiling) will accrue through reduction in particulate matter (PM).
which will occur when S02 emissions are reduced. A reduction in S02 emissions would also likely
extend the life (including functionality and appearance) of many of these materials and structures,
resulting in economic benefits associated with reduced damage and need for extensive maintenance
or repair.
See footnote 1.
See footnote 1.
-------
APPENDIX 3B
EPA Pollution Control
Cost Assumptions
-------
Scrubber Costs
Scrubber cost assumptions for the RIA analysis were the same as those used in EPA 1989-90
acid rain analyses, including the Administration bill analysis in 1989^ and the previously cued Senate
and House bill analyses.3-' The scrubber cost assumptions were based on EPRI/Stearns-Rogers cost
assumptions as interpreted by RCG/Hagler, Bailly, Inc. (Several key assumptions were made: (1)
a contingency factor of 15 percent was used, (2) one spare module was assumed, and (3) scrubbers
were assumed to be designed with no reheat in contrast to assumptions in the 1987 EPA Base Case.)
The cost assumptions for a new powerplant meeting NSPS-Da requirements resulting from this
assessment are presented in Table III-B-1.
The net effect of these assessments was that wet scrubbing was assumed to be employed at
all unplanned new powerplants, because wet scrubbing cost estimates were lower than dry scrubbine
costs estimates.
For the House and Senate bill analyses and this RIA analysis, three further sets of scrubber
costs assumptions were used:
• Retrofits. Retrofit scrubber costs assumed that 90 percent S02
removal (using wet scrubber technology) would be the most cost-
effective scrubbing option. These cost assumptions for a "base"
generic installation were developed using the same methodology and
sources as described above, and are presented in Table HI-B-2. In
addition, aU retrofit scrubber installations were then applied "retrofit
factors" to reflect the relative ease or difficulty of installing scrubbers
at various existing sites. These cost add-ons range from 10 to 100
percent of the "base" scrubber capital cost, and from 7.5 to 75
percent of the "base" fixed O&M cost
• 95 Percent Removal at New Plants. Under Title IV, most sources
built after enactment must obtain emission allowances from "affect-
ed" sources in Phase IL Over time, the marginal cost of obtaining
allowances for new plants would increase very significantly, to the
point where increased S02 removal from new sources (beyond New
Source Performance Standards, subpart Da requirements) would be
economic and desirable. For this analysis, new coal plants were given
the option to install scrubbers to achieve 95 percent S02 removal in
the trading cases and were required to achieve 95 percent S02
removal in the no-trading cases. To achieve 95 percent S02 removaC
it was conservatively assumed (after discussion with architectural/
engineering firms) that current, conventional NSPS-Da wet scrubbing
alone would be insufficient, and that adipic acid injection or a
modified/refined scrubbing system would be required. To account for
these added costs, capital costs were increased by S30/lcw and variable
O&M costs by 0.2 mill/kwh over 90 percent wet scrubber removal cost
levels for a very high sulfur coal, or total levelized costs of about 0.7-
y See Economic Analysis of Title V (Acid Rain Provisions) of the Administration's Proposed
Clean Air Act Amendments (H.R.3030/S.1490), September 1989.
V Op cit p. 3-2.
-------
0.8 mills/kwh. (For a low sulfur coai. the costs were assumed to be
about 0.4 mills/lcwh.) These estimates are likely to be conservative,
and compare to industry total cost estimates of about 0.3-0.5 mills/kwh
for incorporating an adipic acid system into conventional scrubbing
designs. These resulting costs are presented in Table III-B-3.
-------
EXHIBIT 3B-1
Wet Scrubber Costs For New Utility Powerplants
Meeting NSPS Subpart Da Regulations
Sulfur Level
Verjr
t Low
Law |
Low
Medium
Medium
High
Medium
High
Very 1
High |
Capital Costs
(early '86 S/kw)
108.00
110.00
110.00
124.00
133.00
145.00
154.00
Fixed O&M Costs
(early '86 S/lcw-yr)
4.92
4.98
5.00
5.45
5.74
6.11
639
Variable O&M
Costs (early *86
mills/kwh)
0.25
032
0.46
0.69
0.92
136
j
1.80
Energy Penalty
(%)
150
2.50
150
150
150
150
150
Capacity Penalty
(%)
110
110
110
110
110
110
110
Reliability Penalty
(%)
2.70
170
170
170
170
170
. 170
Annual Emission
Rate
(lbs. SO^/mmBtu)
0.22
0.29
0.48
0.48
0.48
0.60
0.80 :
Satflff Lml
Lbs. SO^/uBta
Very Low Sulfur Less than 0.80
Low Sulfur 0.80-1.06
Low-Medium Sulfur 1.09-1.66
Medium Sulfur 1.67-2-50
High-Medium Sulfur 2.51-333
High Sulfur 3.54-5.00
Very High Sulfur More than 5.00
NOTE: EPA estimates except for reliability penalty, which is based on earlier EPRI estimates. j
More recent scrubber availability data suggests that these reliability estimates may be I
conservatively high.
-------
EXHIBIT 3B-2
"Base" Wet Scrubber Costs For Retrofit Installations* ,
Suiftar Level !
Very
Low
Low ! | Medttnn
i Medium 1
High S Hlah Very j
Mediam 1 High i
Capital Costs
(early '86 S/kw)
125.00
i
119.00
128.00 | 133.00 j 138.00 148.00 i 156.00 |
Fixed 04tM Costs
(early '86 S/kw-yr)
5.46
5.48
5.56
5.82
5.88
6.18 i 6.46 j
Variable O&M
Costs (early '86
milis/kwh)
0.26
0.34
0.49
0.71
0.93
i
137 | 1.81
Energy Penalty
(%)
150
2.50
150
150
150
150
150
Capacity Penalty
(%)
110
110
110
110
110
110
110
Reliability Penalty
(*)
2.70
2.70
170
170
170
170
170
Annual Emission
Rate
(lbs. SO^mmBtu)
0.06
0.11
0.17
0.25
033
0J0
0.67
Sulfur Level Lbs. SOj/sunBti
Very Low Sulfur Less than 0.80
Low Sulfur 0.80-1.08
Low-Medium Sulfur 1.09-1.66
Medium Sulfur 1.67-2-50
High-Medium Sulfur 2-51-333
High Sulfur 3.54-5.00
Very High Sulfur More than 5.00
* Does Q2J include "retrofit factors" (cost add-ons to reflect relative ease or difficulty i
of iMfiling scrubbers at existing sites).
NOTE; EPA estimates except for reliability penalty, which is based on earlier EPRI estimates. \
More recent scrubber availability data suggests that these reliability estimates may be |
conservatively high.
-------
EXHIBIT 3B-3
Wet Scrubber Costs For New Utility Powerplants
Achieving 95 Percent Removal with Adipic Acid j
! i
;
'
Sulfur Lewi
Very
Low
Low
Low
Medium
Medium
High
Medina
High
Very '
High i
Capital Costs
(eariy '86 S/kw)
139.00
142.00
148.00
158.00
164.00
178.00
!
187.00 j
!
Fixed O&M Costs
(eariy '86 S/kw-yr)
5.38
5.48
5.56
5.72
5.90
6.18
6.47 i
Variable O&M
Costs (eariy '86
mills/lcwh)
0.29
038
0-54
0.79
1.04
1.54
104 :
Energy Penalty
(%)
150
2.50
2.50
150
150
150
150 !
Capacity Penalty
(%)
110
2.10
110
110
110
110
110
Reliability Penalty
(%)
2.70
170
170
170
170
170
170
Annual Emission
Rate
(lbs. SOymmBtu)
0.04
0.05
0.06
0.13
0.17
025
I
0.33
SaMkr Lant Lb«. SOj/—Bti
Very Low Sulfur Lea than 0.80
Low Sulfur 0JXM.06
Low-Medium Sulfur 1.09-1.66
Medium Sulfur 1.67-2JO
High-Medium Sulfur 2-51-3J 3
High Sulfur 3.54-5.00
Very High Sulfur More than 5.00
NOTE; EPA estimates except for reliability penalty, which is based on earlier EPRI estimates.
More recent scrubber availability data suggests that these reliability estimates may be
conservatively high.
-------
Repowering
The amount of repowering in the future, with or without acid rain legislation, is very
uncertain. Accordingly, EPA assumed for the 1989 Base Case analysis that utilities would undertake
a small to significant amount of repowering at certain existing coal-fired- units. Repowering (using
a "generic clean coal" technology) was assumed at EPA's direction to have much greater market
penetration in the Low Base Case than in the High Base Case. Repowering candidates were assumed
to include only those unscrubbed SIP coal units greater than 75 megawatts and less than 400
megawatts, since current evidence suggests that repowering technologies may be uneconomic or
technically infeasible at very small or very large units. Units were assumed to become part of the
candidate pool upon reaching 35 years of age beginning in 2000 (with only units built before 1950
assumed to be too old to repower).
In the Low Base Case, it was assumed a total of one third of all such candidates would
repower by 2010 with lower percentages (five percent by 2000 and 20 percent by 2005) assumed in
earlier yean. In the High Base Case, much lower market penetration was assumed with only 10
percent of candidate units repowering by 2010 (five percent by 2005 and no repowering in 2000).
Under this RIA analysis of Title IV, as well as earlier Senate and House bill analyses, no
additional repowering was assumed to result under the High Cases, but about 6 gigawatts of
repowering candidates assumed to repower between 2005-2010 in the Low Base Case were assumed
to repower earlier in 2004 under the Low Cases in order to take advantage of the proposals'
repowering incentives.
In the assumed first year of repowering in both the High and Low Cases, units between "5
and 150 Mw and built before 1960 were generally selected for repowering. In later years, units up
to 400 Mw and those built in the late 1960s and early 1970s were assumed to be selected for
repowering. Smaller units were assumed to be selected first because utilities would wish to develop
their design and construction expertise in simpler, leu expensive settings. Older units were selected
first because they are generally smaller and because many utilities would tend to repower units as they
reached the end of their useful lives (assuming no major refurbishment). Repowered units were
selected regionally so as to roughly reflect the proportional distribution of available candidate
capacity. Future utility regional capacity requirements were taken into account in selecting the
repowered units. Capacity was only selected to the extent new capacity was needed in the region to
meet reserve margin requirements.
The capacity of repowered units under the cases analyzed is presented in Table III-B-4. Note
that capacity affected by these repowering assumptions are in addition to those units which have
already repowered (e.g^ TVA's Shawnee 10. NSP's Black Dog 4, MDlTs Heskett 2, Colorado-Ute s
Nucla 4) or have firm plans to repower (AEP's Tidd and Sporn projects, SPS's Nichols 3). Together,
these units total roughly 1 gigawatt of capacity, in contrast to about 38 gigawatts of repowered
capacity that results by 2010 from the repowering assumptions of the Low Case.^
The cost and performance characteristics of future repowering candidates is also very
uncertain. The assumed cost and performance characteristics of the repowering technology are
discussed below, and are generally representative of a fluidized bed combustion (FBC) technology.
3/
In addition, other projects (using other emissions control technologies which do not increase
capacity) that were approved for funding in DOE's Gean Coal Technology development
program (through Round II) were also included in this Base Case analysis.
-------
• Capacity at those units that were selected for repowering was assumed
to increase by 50 percent upon repowering, DOE assumes that
atmospheric FBC (AFBC) repowering would lead to a 15 percent
increase in capacity, pressurized FBC (PFBC) repowering would lead
to a 30-50 percent capacity increase, and integrated gasifier combined
cycle (IGCC) repowering would lead to a 150 percent increase in
capacity.^ The 50 percent capacity increase assumption was thus
chosen as a reasonable average capacity gain for repowering projects
to reflect a "representative* repowering technology, weighted heavily
towards FBC technology for a typical installation (given the current
relatively advanced state of FBC development, demonstration, and
economic refinement). This 50 percent average capacity gain
assumption is in agreement with EFRI's current assumptions.
• A heat rate of 9500 Btwkwh was assumed for all repowering projects.
This is in rough accord with EPRI TAG estimates for the candidate
repowering technologies (9000 Btu/kwh for PFBC and IGCC 10000
Btu/kwh for AFBC).^
• Capital costs (for units assumed to repower earlier under the Senate
and House Low cases) were assumed to equal S794/kw (in 1988 I).
This assumption is in approximate accord with previous preliminary
ICF analyses, which indicated that the economics of repowering with
PFBC versus building new coal capacity under the earlier Adminis-
tration proposal would break even at roughly $800/kw (is 1988 S).
• O&M cost estimates for the generic repowering projects were also
derived using EPRI TAG information (see PFBC combined cycles).
Assuming the use of a four percent sulfur bituminous coal, Sxed
O&M costs were assumed to be 538.60/kw-yr, while variable O&M
costs were assumed to equal 5.5 milis/kwh (costs in early 1986 $).
• A minimum capacity (turndown) of 50 percent was assumed for
repowered units also in line with EPRI's assessment of PFBC
technology.
• Additionally, it was further assumed that repowering would not affect
a unit's availability (forced and scheduled outage rates were assumed
not to improve).
• Pmktinrai rates were assumed to meet current NSPS requirements for
S02 and TSP. NO, rates from repowered projects were assumed to
equal 03 lbs. NOx per million Btu.
- America's Clean Coal Commitment. U.S. Department of Energy, Office of Fossil Energy,
February 1987.
5/ TAG - Technical Assessment Guide, Volume I: Electricity Supply - 1986. Electric Power
Research Institute (EPRI p. 4463-SR), December 1986.
-------
EXHIBIT 3B-4
Repowered Coal Capacity* |
(gigawatts) j
Low Cues |
High Cases
Base
BascUatf
Regit latonr
2000
0
4
4
2005
6
20
29
2010
10
38
38
* Includes SO percent increase in capacity due to rcpowering.
-------
APPENDIX 4A
Overview of ICF's Coal and Electric
Utilities Model (CEUM)
-------
APPENDIX 4A
ICFs Coal and Electric Utilities Model (CEUM)
The complexity of the coal and electric utility industries in the United States poses difficult
challenges for strategic planners, market analysts, and policymakers. Numerous uncertainties
regarding changing economic trends and future government policies increase the difficulties of
forecasting future market conditions. Because of interactions between these two closeiy-coupled
industries, attempts to analyze either one in isolation are necessarily incomplete. Yet the complex
characteristics of these industries often strain the limits of traditional analytic methods.
Both the coal and electric utility industries face rapidly changing markets. Recent years have
brought about dramatic changes in the growth of electricity demand, price of alternative fuels, cost
of nuclear plant construction, and much more. Market conditions have swung broadly from
undercapacity to overcapacity. The markets continue in a state of transition, and the importance of
understanding the timing and magnitude of such changes is great.
Further, both industries are heavily influenced by a wide-range of government policies and
regulations. Government regulation affects nearly every aspect of each of these industries including
environmental protection, miner health and safety, transportation, taxation, price regulation, and
ratemaking. The implications of possible policy changes are substantial and government and industry
planners place great value on understanding these effects.
To address the full range of these considerations, ICF Incorporated has developed a system
of models and databases for analyzing the coal and electric utility industries in an integrated manner.
At the core of this system of models and data bases is ICFs Coal and Electric Utilities Model
(CEUM). The CEUM system is a set of interrelated models, data bases, and report writers which
beyond CEUM consists of mine costing models, numerous data bases including the Coal and Utility
Information System (CUIS), coal reserve data, coal transportation networks, and much more.
The CEUM system of models is the product of over ten years of research, development, and
intensive analysis of the coal and electric utility markets. The "roots" of the system go back to the
early and mid-1970s when, for the Federal Energy Administration, ICF pioneered the development
of coal supply concepts and models to link the coal and electric utility markets. Over several years
and hundreds of analyses for scores of clients, these models and data bases have grown and evolved
to meet the ever-changing needs of the marketplace.
Over the last several years, these models have been used individually or in tandem for EPA
for a wide variety of analytical fronts. The most common purpose has been the analysis of the
impacts of alternative environmental regulations on utility emission, costs, fuel consumption, coal
production and compliance choices as well as the effects of alternative existing and new control
technologies on these measures.
4A-1
-------
CEUM SYSTEM OVERVIEW
ICFs CEUM system is composed of a number of interrelated models and data bases. The
components of the system are structured to operate in either a stand-alone environment or as part
of a broader analytic system.
Components of the CEUM System
The centerpiece of the CEUM system of models is ICFs Coal and Electric Utilities Model
(CEUM). CEUM, perhaps the best-known component of this system, serves as the integrating tool
which links together all the other models and data bases. The CEUM forecasts key attributes of both
the coal and electric utility industries. For the coal industry, forecasts are made of coal consumption
by type of user, production by region and method of mining, mine-mouth prices by type of coal,
transportation patterns, and delivered prices. For the electric utility industry, forecasts can be made
of generation, capacity expansion, capacity utilization, fuel use, generation costs, capital investment
requirements, air emissions and solid wastes. For other coal consuming sectors, forecasts are made
of coal consumption, sourcing, quality, and price.
As the integrating component of this modelling system, CEUM is closely linked with the other
models and data bases that form the complete CEUM modeling system. Frequently, many of these
models are run jointly with CEUM either as a pre-processor or as a post-processor. Alternatively,
many of these models and data bases can be used in a stand-alone environment to address specific
analytic problems. These other components include the following:
• The Coal and Utility Information System (CTJIS) is a powerful data
base management system containing detailed information on every
electric generation unit, both present and planned The CUIS
develops the electric utility data inputs of CEUM, and can also be
used independently as a market analysis tool. Moreover, this system
is used in disaggregating the forecasts from CEUM to develop
estimates of individual utility, powerplant, and generating unit impacts.
• The Reserve Allocation and Coal Mine Costing Models estimate
costs, productivity, and minimum selling prices for different types of
mines in different supply regions. Together with data bases on coal
reserves and coal mining capacity, these models develop the coal
supply functions used in CEUM. As stand-alone models, they can be
used to analyze the effects of alternative mining plans and financial
conditions, and can be used in evaluating the relative profitability of
different mining operations.
• Numerous other models and data bases serve within the CEUM
system primarily as front-end processors to CEUM or the other
models described above. Although typically not used in a stand-alone
mode, these other models and data bases represent important and
powerful components of the entire system, and include the following:
— coal mining capacity data base.
— coal reserves data base.
— coal transportation networks.
-------
electricity demand forecasting model,
load curve forecasting model,
coal contract data base,
industrial boiler model,
process heat model,
coking coal demand model,
world coal model.
System Capabilities
Collectively, the models and data bases comprising the CEUM system provide the analyst with
a set of tools which can be used to analyze or address a number of different economic, policy or other
questions regarding the fuel and electric utility industries.
These capabilities are best illustrated by identifying some of the analyses which have been
performed with these models:
* Air Emissions. How will growth in coal consumption affect future air
emissions? What are the environmental effects of powerplant life
extension? What are the costs and coal market impacts of Title IV of
the Gean Air Amendments? How would changes in emissions
standards for new industrial boilers affect the use of coal versus
alternative fuels? How will EPA's "Tall Stack" regulations affect
utility costs, emissions, and fuel use?
* Power Generation Technologies. What is the market outlook for
different technologies for power generation and pollution control?
How would acid rain mitigation program affect the attractiveness of
dry scrubbing or LIMB technologies? What are the prospects for
combined cycle units vis-a-vis conventional coal-fired technology?
* Inter-Regional Transmission Potential. Where do current opportuni-
ties exist for increased interregional transmission of electricity between
regions? What are the avoided costs of providing power from one
region and displacing power generation in another. What are the
impacts of electricity imports from Canada?
* Regional Coal Development Where and to what extent will coal
production continue to grow? What are the impacts on coal produc-
tion and mining employment associated with sulfur dioxide control
programs? How might changes in Federal coal leasing policies or
state severance taxes affect the demand for western coal?
* Coal Prices. How and when will coal prices change as the markets
move from an overcapacity situation to a balanced market? How will
this vary with different economic outlooks and/or policy changes? Can
changes in mining technologies and labor productivity offset the cost
impacts of resource depletion? How wall changes in coal prices affect
coal reserve values?
4A-3
-------
• Coal Transportation. How will growing demand for coal change
transportation patterns? What are the impacts of the Staggers' Rail
Act and resulting ICC regulations on regional coal production
patterns? How might individual railroads fare under alternative acid
rain mitigation strategies? How would a network of coal slurry
pipeline affect, revenues and regional coal production?
• Fuel Price and Availability. What are the impacts of changing oil and
gas prices on the coal markets? How will electricity rates change as
overcapacity in the coal markets is worked off? What are the
financial and economic impacts of converting powerplants from oil and
gas to coal?
• Tax Policy. How would changes in the percentage depletion
allowance affect regional and national coal production? How would
changes in investment tax credits affect electricity rates? How would
limits on state severance taxes affect coal production patterns in
western states?
System Attributes
The CEUM system of models and data bases has been developed with the objective of
helping government policy-makers and private sector decision-makers solve real-world problems.
Each component of the system was designed from its inception to incorporate and display the level
of detail necessary to address problems in a realistic manner.
The models incorporate a very high degree of resolution. This resolution is important in
accurately assessing complex questions. Experience has shown that smaller and simpler models, while
providing computational speed and programming efficiency, often are not capable of addressing
complex questions at a level of detail meaningful to analysts. For example, in assessing the costs and
economics of emission reduction compliance strategies for individual powerplants, it is important to
have the resolution and flexibility to assess the impact of plant specific retrofit scrubbing costs, fuel
switching constraints and changes in utilization in meeting overall state or plant specific reduction
targets.
As a result of these types of issues and questions the models of the CEUM system have been
structured to provide a very fine level of detail. For example, CEUM has forty different coal supply
regions each with up to fifty types of coal, and fifty demand regions each with six consuming sectors.
In each demand region, there are over thirty different types or categories of powerplants which can
be modelled in the electric utility sector. Over twenty of these are coal, wit most coal powerplants
categorized individually. The coal transportation network used in CEUM has over two thousand
routes connecting the various types of movements from coal supply origin to final consumer end-use
destination. The coal mine costing models reflect over one hundred different mining configurations,
each which can be adapted to reflect different state taxation policies, union affiliation, and other
variables.
A high degree of resolution provided by these models has value only if it can be understood
and reviewed. To this end, the CEUM system has been developed as a system of "structural"
models incorporating well-known engineering and financial relationships. Unlike econometric
approaches, the CEUM models are not based upon abstract concepts and statistical fits, but instead
4A-4
-------
express the engineering (technical and economic) relationships of the overall coal and electric utility
markets important to the investment and operating decisions within each market. I'sine these
relationships, the CEUM system of models attempt to replicate the normative decisions made within
the coal and electric utility industries. The structural approach of the models allow the reasonable-
ness and impact of each data input and assumption to be evaluated directly. The analyst is not forced
to rely solely upon a series of indirect statistical measures.
The models "solve" using criteria which replicate real-world decision making. Each of the
CEUM models follow decision rules consistent with rational decision-making. Generally, this implies
a cost minimization model in which each decision maker (e.g., electric utility) is trying to minimize
their own costs while competing in the market place with others who are trying to do likewise.
Constraints can be placed upon this cost minimization framework to reflect the realities at hand,
planned capacity underway, environmental regulations, technological limitations, long-term
contracting, regulatory practices, and many other factors which decision-makers must consider.
Because the models have such a high degree of resolution, the data inputs required are often
quite large. ICF has developed an extensive set of data bases linked closely with every aspect of the
coal and electric utility market. In a number of instances, these data bases were developed using
publicly available data as the original source with extensive updating and refinements of this
information over time. However, often it has necessitated the development of original data collection
and management efforts, where public data was either absent or unreliable. For example, in ICFs
Coal and Utility Information System (CUIS) certain powerplant characteristics (e.g., capacities, plant
types) were based on DOE-EIA's Inventory of Powerplants1 and Generating Unit Reference File
(GURF). However, virtually all other data elements or revisions to the DOE data over time reflect
numerous surveys of the industry in order to collect and maintain detailed statistics on every
powerplant unit in the nation. The coal reserve data base goes well beyond government published
statistics, and incorporates hundreds of documents which are missing or incompletely used in
published compilations. Prior to 1980, coal reserve characterizations were based mostly on the
Demonstrated Reserve Base (DRB).2 However, since that time, reserve characterizations and data
have been largely based on detailed analyses of region and state specific reserved conducted by ICF
as well as other information obtained from states and coal companies.
Despite these data collection efforts and maximum use of publicly available sources, gaps
remain in the available data. Out of necessity, all models must forecast with imperfect information.
The structural approach employed by the CEUM system of models require that gaps in knowledge
be acknowledged explicitly since each data element or economic relationship also must be specified
explicitly. It forces the analyst to evaluate key issues and permits an understanding of the relative
importance of incomplete information. Over time, as more precise information becomes known, it
can be readily incorporated into the models.
The CEUM system provides a great deal of flexibility in the types of issues that can be
analyzed and the relevant timeframes over which they can be addressed. The structure and content
of all of the models and databases have evolved substantially since their initial conception, reflecting
improvements in analytic approaches and adaptations to changing market conditions. As future
markets and analytic needs change, the CEUM system will similarly change. The models also have
capabilities of addressing a wide range of forecast periods. Near-term analyses (e.g., 1987) are
See DOE/EIA-0095 (81) Inventory of Powerplants in the United States. 1961 Annual September, 1982.
See Bureau of Mines Demonstrated Reserve Base 1975.
-------
characterized by substantial constraints on capacity additions, fuel supply, and fuel contracts. Cher
time (e.g., 1990 to 2000), the constraints on capital stock and other factors become less binding,
thereby increasing the options available to decision makers. In the very long-term (e.g.. 2010 and
beyond), new technologies can be postulated and evaluated. The models in the CEUM system have
been used to address issues spanning all of these timeframes.
-------
EXHIBIT 4A-I
Map of Coal Supply Regions
Lucira
Mid* tit
*««rta«n
APPtiMAJ
S«vtA«r«
*U3
Mortharn Apptliohli
PennaytYanla. Central (PC)
Pemayivanla, Weal (PW)
Ohio (OH)
Maryland (MO)
Waal Virginia, North (MO)
Mldweat
niinaia (1U
Indiana (IN)
Kentucky, Waat (KW)
High * Law guitar Gael Bhmvh
Qiilf
Texaa (TX)
I ni mi ana (UK)
Arfcanaaa SouttVMIaalaalppI (AS)
Central Waat
Iowa (IA)
Mlaoourt (MO)
Kanaae (KS)
Artranaaa, North (AN)
Oklahoma (OK)
Cintrai Apptfachia
Waal Virginia. South (WS)
Virginia (VA)
Kartudiy, Eaal (KE)
(™)
Southern Appalaehla
Alabama (AC)
Eaatam Northern Great Ptalna
North Dakota (NO)
(Montana, Eaal (ME)
Wat em Northern Great Plalna
Montana. Powder River (MP)
Montana, Waat (MW)
Wyoming, Powder River (WP)
Roddee
Wyoming, Green Rker (WG)
Colorado, Green River (CG)
Colorado, Denver (CO)
Colorado. Raton (CR)
Colorado, Uinta (CU)
Colorado, San Juan (CS)
Utah, Central (UC)
Utah, South (US)
New Mexico, Raton (NR)
Southweet
New Mexico. San Juan (NS)
Arizona (AZ)
North* eat
Waahmgton (WA)
Alaaka
Alaaka (AK)
4A-7
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Electricity Demand Regions in CEUM
/ o
CEUM
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APPENDIX 2A
Background on Other Industries
Affected by the Acid Rain Title
-------
APPENDIX 2A
Background on Other Industries Affected by the Acid Rain Title
COAL INDUSTRY
The U.S. coal industry is closely linked to the U.S. electric power industry; over 78 percent of total
coal production in 1989 (766 out of 981 million tons) was supplied to electric powerplants. Over the
last three decades coal production has increased about 125 percent in response to powerplant
demand. Continued growth in coal production is expected over the next few years as existing coal-
fired utility plants are more highly utilized. After 2000, the potential for growth will be determined
primarily by the amount of new coal-fired generating capacity.
U.S. coal production is also consumed by (1) non-electric industrial boilers and process plants (77
million tons in 1989); (2) the U.S. steel industry for the production of coke, a feedstock to
steelmaking (40 million tons); and (3) net exports to foreign powerplants and steelmakers (98 million
tons).
Coal is a very heterogenous material composed of the fossilized remains of plants and animals and
other minerals. The two most important differences between coals are:
• Coal Rank/Energy Content1 - Coal falls into one of four categories established by
the geochemical community:
(1) high energy content bituminous,2 accounting for over two-thirds of the
coal mined in the U.S. in 1989;
(2) medium to low energy sub-bituminous, accounting for about 24 percent
of 1989 production;
(3) low energy lignite, accounting for about nine percent of production; and
(4) very high energy anthracite, accounting for less than one percent of
production.
• Sulfur Content - Coal sulfur content varies considerably. The U.S.
reserves of bituminous coal include both low- and high-sulfur coals.
Reserves of sub-bituminous coals are mostly low-sulfur coals, and
lignite coals are mostly medium-sulfur coaL
U.S. coal production primarily occurs in several regions with significant differences in coal
quality between the various regions (listed below). Thus, regulations favoring one type of coal (e.g.,
low-sulfur coal) can shift the regional distribution of coal output:
While coal rank correlates with energy content, the classification by rank reflects other geochemical factors as well.
Energy content is measured in BTU per ton; in 1989 the average heat content of all coal mined in the U.S. was
21.8 million BTU per too.
2A-1
-------
Geographic Area
Northern Appaiachia
Central and Southern Appaiachia
Midwest
Lignite Regions of Texas
and the Dakotas
Powder River Basin
Other West
Sulfur Content
medium to high
low to medium
mostly high
low
low
Tons ( 1989t
164 million
.296 million
134 million
83 million
188 million
116 million
There are a large number of coal-mining companies, including some very large multi-regional
companies, such as Peabody Coal, and a large number of small companies, especially in Appaiachia.
The top 15 producers accounted for more than 45 percent of the coal produced in 1989. The top
five producers, their production, and market share are shown below:
Producer
Production (mmtonst Market Share
Region
Peabody Holding Group 86.7
Consolidation Coal Company 53.5
AMAX Coal Industries Inc. 38.4
ARCO Coal Company 31.1
Texas Utilities Mining Company 29.9
8.9%
Midwest/NatL
5.5
Appaiachia
3.9
PRB/Natl.
3.2
PRB
3.1
Texas
The number of active coal mines in the U.S. producing at least 10,000 torn annually fell in
1989 to 2,821 mines from a 1988 level of 2,915. About 51 percent of these mines are underground
mines and the rest are surface mines. Some differences between surface and underground mines
include:
Location - Most of the underground production is located in the East,
while surface mines tend to predominate in the Western region;
Productivity • Surface mines have higher productivity than under-
ground mines, due to the fact that surface mining enjoys greater
economies of scale, thus, requires fewer workers. Also advancements
in mining technology, such as the longwail mining system, have further
increased productivity for surface mines; and
Size - Surface mines are generally larger and higher producing than
underground mines. Several surface mines produced more than 10
million tons per year. The average surface mine produced 419
thousand tons in 1989, compared with an average of 275 thousand
tons for underground mines.
2A-2
-------
The F.O.B. mine price of coal varies by region, type of mining, and quality. On average.
Western coal is cheaper than Appalachian or Interior coal because it is more efficiently mined and
has a lower heat content.
OTHER FOSSIL FUEL PRODUCERS
Crude oil and natural gas are also important fueis for the electric utility industry, but much
less important than coal; in 1989, oil-powered plants accounted for only 6 percent of total electric
generation, and natural gas-powered plants, only 9 percent. In recent years, the share of oil and gas
generation capacity has decreased, while coal and nuclear capacity has increased, in response to the
rising oil and gas prices of the 1970s. Most recently, lower oil and gas prices and a reluctance to
build capital-intensive coal and nuclear plants have caused many to expect a resurgence in utility oil
and gas usage.
Oil and gas usage by utilities is a very small share of total U.S. usage of these fuels. In 1989,
the total U.S. natural gas consumption was about 19 trillion cubic feet; utilities accounted for only
about 15 percent of natural gas consumption. Oil consumption was 17 million barrels per day,
accounting for 42 percent of total U.S. energy consumption, but utilities usage of oil by electric
utilities accounted for only about 4 percent of total oil consumption.
U.S. crude oil production was 7.63 million barrels per day in 1989 (produced by 603,000 oil
wells), and crude oil imports were 5.81 million barrels per day. The U.S. and non-U.S. oil markets
are highly integrated due to relatively low transportation costs, and many of the nation's largest oil
companies are involved in production. Also, many other small companies are involved. Oil moves
from the producing well to the refinery where it is refined into various petroleum products, which
are then shipped to the end-user markets. The U.S. oil market can be characterized as highly
competitive.
The U.S. is a leading producer and consumer of natural gas; however, the U.S. natural gas
industry is much less integrated with the rest of the world than the oil industry because of the far
greater transportation costs for natural gas. In 1989,261,000 producing gas wells produced 17 trillion
cubic feet of natural gas in the U.S. Natural gas is produced at the wellhead, gathered and processed,
and then transmitted to distribution companies, who supply it to the end-use customer. The gas
market consists of many localized markets. Pipelines provide an efficient means to transport the gas
to the markets. The pipelines deliver the gas to Local Distribution Companies (LDCs), who receive
the gas at "citygates" and distribute it to the consumers. Generally, LDCs are granted franchise rights
by the state authorities to serve specific communities, and are subject to rate regulation by these
authorities. End-use consists primarily of gas consumption equipment such as a furnace, a home
stove or water heater, an industrial boiler or oven, or an electric utility turbine.
POLLUTION CONTROL EQUIPMENT/SCRUBBERS
The provisions of the 1990 Qean Air Act Acid Rain Amendments create new potential
markets for pollution control equipment such as "scrubbers" (devices installed at powerplants to
remove sulfur dioxide from powerplant flue gases) and equipment controlling the formation of
nitrogen oxides. There are several types of scrubber technologies:
2A-3
-------
• Wet Scrubbers - Utilities generally use limestone or lime slurries to
wash the flue gas and produce a wet waste product. There are about
60 million kilowatts of scrubbed coal-fired capacity in the U.S. out of
about 300 million kilowatts total.
• Dry Scrubbers - To a much lesser extent, utilities use dry scrubbers
which use lime, sodium, or other powders to wash the flue gas and
produce dry waste products. This technology is generally used only
for low-sulfur coal applications.
• Reusable Product Scrubbers - These systems create sulfur and sulfuric
acid waste streams. Only a very few of these systems exist in the U.S.
Since scrubbers were first installed at utility full-scale operations in the early 1970s, five firms
have accounted for a vast majority of utility scrubber sales:
(1) Asea/Brown-Boveri (Combustion Engineering) - 29 percent;
(2) GE Environmental Services - 22 percent;
(3) Babcock and Wilcox • 15 percent;
(4) Research Cottrell - 15 percent; and
(5) Joy - 9 percent.
Ten other firms have accounted for about 10 percent of utility sales.
The DOE Gean Coal Program is a $5 billion joint effort of the federal government and
private sector to encourage the rapid development of new technologies for sulfur dioxide and
particulate matter emissions control and the repowering of powerplants. The program structure
includes five solicitations or "rounds" for projects; Round m is currently underway, and solicitations
have been requested for Round IV. This program involves many companies, some experienced in
the scrubber industry and some newcomers, and a vast range of new technologies, such as sorbent
injection, coal gasification, nitrogen oxide controls, and fluidized bed combustion.
2A-4
-------
APPENDIX 3A
EPA Base Case Assumptions
-------
dki aii.l:!) uask cask assumptions
ELECTRIC UTILITY ENERGY DEMAND
o Electricity Orowih Rate
(% Per Year)
1989 EPA Base:
llifh Case
1990 = 2 8
1995 = 2.8
2000 - 2.8
2005 = 2 3
2010 - 2.3
1989 EPA Base:
Low Case
1990 = 2.4
1995 = 2.1
2000 = 1.7
2005 «= 1.4
2010 = 14
1988-2000 = 2.8
2001-2010 = 2.3
1988 2000 = 2.0
2000 2010 = 1 4
o Total U.S. Nuclear Capacity (gw)
1995 = 104
2000 = 104
2005 = 102
2010 = 77
1995 = 104
2000 = 104
2005 = 104
2010 = 102
o Nuclear Capacity Factors (%)
1995 = 70
2000 = 71
2005 = 66
2010 = 67
1995 = 70
2000 = 71
2005 = 66
2010 = 68
o Utility Capital Costs
(Early 1986 S/Kw)
Coal = 900 1010
Turbine = 275-315
Comb. Cycle = 510-590
Scrubbers, Wei - 108-154
Coal = 900 1010
Turbine = 275-315
Comb. Cycle = 510-590
Scrubbers. Wet = 108 154
o Generation O&M
(Early-1986 S/kw-year)
o Power Plant Lifetime (Years)
Coal = 12.20 19.50
Combined Cycle = 9.70-11.10
Turbine = 3.70 - 4.30
Coal/Oil/Gas Sleam 65 yrs.
45 years if <50 Mw
Coal = 12.20 19.50
Combined Cycle = 9.70 -11.10
Turbine = 3.70 4 30
Coal/Oil/Gas Steam 55 yrs.
45 years if <50 Mw
Nucleai 35 years
Turbine 20 years
Nuclear <1(1 years
Turhinc 20 years
-------
DETAILED BASIC CASE ASSUMITIONS
1989 EPA Base:
High Case
ELECTRIC UTIU'l'Y ENERGY DEMAND (continued)
o Repowciiiig/Kcfuihishment
Assumptions
) Coal Piiwcrplaiii Heal Rales
Rcpowcred Capacity (includes 50%
increase from repowering)
2000
2005
2010
0
6 gw
10 gw
All other coal
capacity refurbishes
at 30 years of age.
0.25% per year increase
over current levels.
After refurbishment heal
rales are improved
(decreased) by five per-
cent from previous fore-
cast levels.
Minimum Turndown Rates
Canadian Powei Imports
(billions of kwhrs)
Coal 35%
Oil/Gas Steam 20%
1995
2000
2(105
2010
64
76
75
75
Cogcncratiou
(billions of kwhrs)
1995
2000
2005
2010
175
208
255
313
1989 EPA Base:
Ia)w Case
Repowercd Capacity (includes 50%
increase from repowciing)
2000: 4 gw
2005: 20 gw
2010: 38 gw
Ail other coal
capacity refurbishes
at 30 years of age.
0.25% per year increase
over current levels.
After refurbishment heal
rates are improved
(decreased) by five per-
cent from previous fore-
cast levels.
Coal 35%
Oil/Gas Steam 20%
1995 = 64
2000 = 76
2005 = 75
2010 = 75
1995 = 195
2000 = 291
2005 = 382
2010 = 474
-------
I)IIAIUJ) BASK CASE ASSUMPTIONS
FINANCIAL PAKAMETERS
o Tax Depreciation Life (years)
Retrofit Pollution Control
Others
o Real Discount Rates
(% Per Year)
o Real Capital Charge Rates
Coal/Nuclear/Combined Cycle
New Scrubbers/Paniculate Equip
Combust ion Turbines
Retrofit Scrubbers
o Book Life (ycais)
Coal/Nuclcar/Combincd Cycle
Combustion Turbine
Pollution Control-Retrofit
Pollution Control New
o Input Year Dollars
o Output Year Dollars
o Escalation Input to Output
Dollars
o Indus!rial/Kctail Coal Use
(millions of tons)
1989 EPA Base:
Hieh Case
1989 EPA Base:
Low Case
IS
IS
15
IS
Coal Mine ¦ 6.00% Coal Mine = 6.00%
Utility - 5.38% Utility = 538%
9.4%
9.4%
11.5%
9.4%
9.4%
9.4%
11.5%
9.4%
30
20
30
30
30
20
30
30
Early 1986
Mid 1988
1.073
Early 1986
Mkl 1988
1.073
1995 = 90
20110 = 95
2005 = 97
2010 = 100
1995 = 90
2000 = 95
2**»5 = 97
2010 = ItN)
-------
DETAILED IIASK CASE ASSUMPTIONS
NON-UTILITY COAL DEMAND
o Coal Eiporis (millions of Ions)
-- Sleam Coal
-- Metallurgical Coal Exports
o Domestic Metallurgical Coal Use
(millions of ions)
o Synthetics
(Coal Input in millions of tons)
COAL SUPPLY
o Coal Transportation Rates
Rail
liuik, Ihiigc
1989 EPA Base:
High Case
1989 EPA Base:
Low Case
1995 = 30
2000 = 36
2005 = 35
2010 ¦ 37
1995 = 45
2000 = 35
2005 * 30
2010 = 31
1995 - 30
2000 = 36
2005 = 35
2010 = 37
1995 = 45
2000 = 35
2005 = 30
2010 = 31
1995 = 32
2000 = 30
2005 = 29
2010 « 27
1995 = 32
2000 = 30
2005 = 29
2010 = 27
1995 = 6
2000 a 6
2005 - 6
2010 » 6
1995 = 6
2000 = 6
2005 = 6
2010 = 6
Long-run marginal costs
based on engineering
analysis.
Based oil full cosis.
Long run marginal cosls
based on engineering
analysis.
Itabcd on lull cosis.
-------
DKTAII.IlI) BASK CASE ASSUMPTIONS
1989 EPA Base:
High Case
1989 EPA Base:
Low Case
COAL SUPPLY (continued)
o Mining Costs
(% Annual Real Escalation)
OTHER GOVERNMENTAL REGULATIONS
o Federal Leasing Policy
o Air Pollution Regulations
Capital = 0.0%
Labor = 2.0%
Materials « 0.0%
Gross Labor Productivity:
Deep 1988 ¦= 7.0%
1989 = 5.0%
1990 = 4.0%
1991-on = 3.0%
Surface = 2.0%
Capital Productivity
Deep = 0.0%
Surface » 1.5%
Enough
Up-to-date reassessment
of federal and slate
rules, including pro-
posed changes In SIPs,
state acid rain pro-
grams and proposed
federal tall slacks
regulations. Large
industrial boilers
must scrub by 1995.
Capital = 0.0%
Labor = 2.0%
Materials = 0.0%
Gross Labor Productivity:
Deep 1988 = 7.0%
1989 = 5.0%
1990 = 40%
1991 on = 30%
Surface = 2.0%
Capital Productivity
Deep = 0.0%
Surface = 1.5%
Enough
Up-to-date reassessment
of federal and state
rules, including pro-
posed changes in SIPs,
state acid rain pro-
grams and proposed
federal tall slacks
regulations. Large
industrial boilers
must scrub by 1995.
-------
DELIVERED OIL PRODUCT PRirrc j nn
PRICES and DELIVERS GAS PRICES
.1995
-2Q00 2005
Sisfe toL Sh Low hI^TT =-°'W --
rufii LOW Hi£ii I^W_ Low
(1988J/bbl) l8'°° :5*°° 1 2100 2900 I 25-00 31.50 | 29.50 34.00
Census Rggion/Prndurr
(1988S/mmbtu)
New England
Gas
Distillate
1.0% Residual
2.8% Residual
Middle Atlantic
Gas
Distillate Zl J« | Is | I'4' 4'75 I 4-95
1.09& Residual 3„ 4 27 J? ^ f «
2.8% Residual 2.60 ^ 71 in*
South Atlantic
Distillate IT? ! 4-«
3.55
3.85
1 4.10
4.40
4.19
5.45
! 4.91
6.17
3.11
4.29
| 3.77
4.94
2.62
3.74
! 3.26
4.39
3.55
3.85
I 4.10
4.40
4.17
5.42
1 4.88
6.14
3.09
4.27
( 3.75
4.92
160
3.73
I 3.24
4.37
4.45
4.75
I 4.95
5.15
5.45
6.62
1 6.26
"07
4.24
5.32
I 4.99
5.74
3.72
4.76
| 4.44
5.16
3J5
3.85
1 4.10
4.40 |
4.15
5.40
I 4.86
6.12 i
3.02
4.19
I 3.68
4.85 1
2.52
3.65
I 3.16
1
4.29 I
2.8% Residual 252 in* .
3.63
East North Central
Distillate ! !!S ! 4«
3.50
3.80
1 4.05
435
4.05
5.29
I 4.76
6.00
3.18
4.36
i 3.84
5.01
169
3.82
1 3.33
4.46
1.0% Residual ^ JS ^ ' "?
18* Residual 2.69 3.82 | 3.33 4^ | 179
East South Central
2?*.,. | 4.jo 4.40 I 445
JSKS - 3 ! i£ S3 13
Rorfu^ 175 3.99 I 3.45 4.«9 | 3.96
West North Central
{T^ua, ^ ™ M
^ £2 £ J* i»5 <£ !«
3.55
335
I 4.10
4.40
4.13
5.38
! 4.85
6.10
3.24
4.53
I 3.96
5.25
175
3.99
I 3.45
4.69
3.75
4.05
I 430
4.60
3.96
5.20
| 4.67
5.91
3.12
4.29
I 3.78
4.95
2.62
3.75
I 3.27
4.39
6.59
1 6.23
7.04
5.30
i 4.97
5.72
4.74
1 4.42
5.15
4.75
| 4.95
5.15
6J7
| 6.21
7.02
533
| 4.89
5.64
4.67
| 4.35
5.07
4.70
| 4.90
5.10
6.45
| 6.09
6.89
539
I 5.06
5.81
4.84
| 4.51
5.24
4.75
| 4.95
5.15
6.55
j 6.19
6.99
5.67
| 5.30
6.13
5.11
| 4.76
5.55
4.95
| 5.15
5.35
635
| 6.00
6.80
533
I 5.00
5.75
4.77
| 4.45
5.17
indu^aovfo~~^„X '™miptaie earn. CMS price shown hete.n do m
P 'nCreaM due ro 'naOTa'ttl ««r «« "«»«>* m ita
(2) oiT^h^S1"?®* '"T for L0% Md i8* Raii Actual sulfur level of residual
oil used in specific states and modelled in the base use van**
-------
1995
2000
2005
2010
Eisil hm. Um Iqsl Hist Ls*l Hi^h io*_
West South Central
Gas
Distillate
1.0% Residual
2.8% Residual
2.85
3.45
| 3.50
4.00
1 3.95
4.35
j 4.55
4.-5
3.94
5.18
i 4.65
5.89
1 5,18
6.33
| 5.98
6.73
2.S7
4.03
i 3.52
4.68
I 3.99
5.06
i 4.73
5.47
2.37
3.49
| 3.0t
4.13
1 3.47
4.50
t 4.18
4.90
Mountain
Gas
3.35
3.65
| 3.90
4.20
( 4.25
4.55
' 4.75
4.95
Distillate
3.88
5.12
I 4.59
5.83
| 5.12
6.27
I 5.92
6.17
1.0% Residual
3.09
4.27
I 3.75
4.92
| 4.22
5.30
! 4.97
5."2
2.8% Residual
2.60
3.73
1 3.24
4.37
1 3.70
4.74
j 4.42
5.15
Pacific
Gas
3.75
4.05
1 4.30
4.60
| 4.65
4.95
I 5.15
5.35
Distillate
3.94
5.18
( 4.65
5.89
| 5.18
6.33
I 5.98
6.78
1.0% Residual
2-97
4.13
| 3.62
4.78
| 4.08
5.16
I 4.83
5.S7
2.8% Residual
2.47
3.59
| 3.11
4.22
| 3-57
4.60
I 4.28
4.99
-------
A PPFNDTY 4R
£%JL A UdllJLJmJX. *tAJ
Detailed Forecasts
-------
SXHIItT A«1
SULFUR 510X161 FOMCASTS
AISCMT 1E9UL*T!CM 4*0 teSUUTQRr
HIGH uses
(IN HI LUOIS OF TOMS)
CHANGS CMAMCC
F*OM FROM
»ti-ST*ruTE 9tt-sT*njTr
Pf Abaam Pf»- Absant
Statuta R««uittion **9ul«orv sututi Regulation Regulatory
Cat* Cass Caaa Cam Cata cue
Ility SQ2 laiaaiana
1991
1995
1995
2000
2000
2000
:*» 111ona et torn)
_
—
—
——
37-Caeterri states
Cost
•1.*§
SIP
13.fl
•1.35
14.47
•8.94
-r.se
MS*
2.1ft
.07
.0*
2.30
-.15
.00
MVS
.07
.00
.00
.15
-.04
-.05
TOTAt COM.
iCTI
-Of
•Oi
ifTfl
-cw
-T1S
OIL/GAS
1.33
.04
.93
1.12
-.80
-*.19
TOTAL 37-CASTIM STATM
if3?
-or
¦rrr
lOS
-Of
-731
11-western statas
Coal
SIP
.44
.00
.00
.44
-.10
-.04
NSM
.10
.00
.00
.20
-.03
.00
mm
.01
.00
.00
.14
-.08
-.05
total coal
"735
IX
-TUB
"31
-m.
OIL/SAS
.03
.00
.00
.03
-.03
-.03
TOTAL 11 -WiSTIRM STATU
~rm
"TUB
~nr
United StatM
Cost
SIP
U.3B
-1.3*
•1.45
15.10
•S.9*
-7.35
NSPS
2.3*
.07
.04
2.50
-.is
.00
ansps
.01
.00
.00
.29
-.13
-.10
TOTAL COAL
iOT
•oi
•OB
lO»
*9.8
•7TXJ
OIL/OAS
t.3»
.OS
1.IS
-.12
-.22
TOTAL UNITCO STATU
1«7!1
-Of
-1757
lOS
-ifTTB
•rxr
MTI: ratals say not adfl due to
-------
Utility SQ2 EaiMiona
(*»11 ions at torn)
37-tMtarn StatM
Coal
Sir
NSM
MUM
TOTAL COM.
OIL/OAS
TOTAL IMASrCM STATU
11-MMtam SUtM
NSM
mn
TOTAL COAL
0SU8AS
TOTAL 11-WIT«m STATIS
United States
Coal
SIP
•tn
AMM
TOTAL COAL
OIL/OAS
TOTAL UilTB STATIS
EXHtllT A-1
SUlfUB DIOXIDE FORECASTS
ABSENT REGULATION ANO (ESUUTOKT
*tC* CASES
(IN MILLIONS OF TONS)
CHAKCE CXANGt
cR0M FtOH
ME-STATUTE ME-STATUTf
Prt- AM«1t P<-*- AbMTt
Statutt l«9ulacian Regulatory statut* l««uiation ••fulatory
Cm* Case CaM CaM CaM CaM
2005 2005 2005 2010 2010 2010
14.49
-9.08
-8.96
14.42
•9.41
-9.11
2.32
*,19
- .09
2.1*
*.1*
*.11
.93
*.53
-.54
2.44
*1.51
-1.51
lOJ
-OB
-CST
iO?
-iTTTI
-lO¥
1.1?
-ill
-.n
.84
-.37
-.«1
19TTT
-iOJ
•tOS
iCB
-lOI
-iO?
.41
-.09
-.04
.40
•M
-.05
.21
-.(S
.00
.it
-.04
.00
.24
-.16
-.10
.33
-.23
-.14
—
-TB
**.01
.00
*.00
.08
.00
-m
•rs
"^9
15.10
-9.17
*9.02
14.82
-9.58
-9.14
2.51
-.23
-.09
2.35
-.If
-.15
1.17
-.69
-.44
2.77
-1.71
-1.43
109
-lOI
•O?
lOI
-1 TXf
-lO*
i.if
-.12
-.72
.85
-.37
-.12
109
-itrsf
-18TX?
25771
-lOE
-1T77S
NOT!: Totals aay net add due te indapandv* rauidina.
-------
EXNUIT a-2
'MfCAsrs
*«6»t tesuLATim ahq *eajLATc*r
HIGH OtSCS
(IN OtMUS)
CHC?" '-»**<*
. Wf'Snjri
§" 7sT '£•"" £r •z:—
'»W 19P5 1999 2000 2^0
37 Easttrn Stitn
COM.
totai
irw TUT rBT lOJ
11 Mwtim
COAl
Of
Total u.s.
TO
2000
LOt tULfU 3 „ „
SBSS.'SSSi Is -S :s »' •» '-2
-«« 5:8 .,:3 ,3 - J
~n
**.«* , 1A M
m-moim su.n* « •& 2 2.57 ..43 . ,<
HICN-MCD(UM &M.FUR 'S "*2? *•08 .74 ja 'ff
mi014 «u na ¦« -.01 03 •*' .27
.00 .00 :g ;g -g .«
TTW ¦» .00
~n»
COAL
low su.na , M __
SUtn* ;¦» "X -51 6.30 3.41 , M
"!GM-««DU* SXHM 1'S "tJ -JJ 4.04 ,1J 2*2
HlfiM SJLfUi *" }-g -g .07 3.00 .*2
J.M -1.47 .>75 4 |S - .g
T0TAl irrr —m —
^ ^ i?u rjr
-------
IXM1IIT A-2
mi coHSMPtim f«icAsts
AKCHT KCSUUTSQH *10 tiOUUtORr
«IGH CASIS
CI* QUAOS)
CHANOI CHANOI
nm
f*l*StATVJtl ?tf •STATUTf
piff« j^tn n*t Absent
Statuta (adulation laautatary statuta tabulation Ha«ula»ry
C«m Caa« C«m CaM Caa« Caa*
2005 ZOOS 2001 2010 2010 2010
37 taatam State* """"" """" "™"~
LOU ttJUR
lOW'MDlUM SULFUR
hign'MBiun mm
niw una
4.83
4.17
5.93
4.0S
2.7*
.03
•1.1*
*1.71
3.32
.15
-1.27
•2.20
5.11
4.41
7.0*
7.M
2,3
.a
-.47
*2.11
3.M
.54
*.74
-3.21
TOTAL
iOT
TO
TO
2or
TO
11 waatam Statac
mi,
low mina
L0H*MB!lff M.KR
*ta»-«ua» sulfur
hi on sulk*
3.30
.82
.43
.00
-.3*
.51
-.20
.00
-.32
.so
-.17
.00
3.85
.a
.64
.00
-.30
•.41
.00
*.55
.72
-.1*
.00
TOTAL
TO
=T8J
.W
or
TO
TO
Total U.S.
iou aiLfUi
LOW-NOllM XJLFUB
Him-MBit* an.**
HtfiN MAS
S.13
4.f»
*.sr
4.M
2.3*
.54
*1,34
•1.71
3.00
M
*1.44
•2.20
9.4*
5.44
T,m
7.M
1.fJ
1.14
*.90
*2.51
3.11
1.2«
*.»1
•1.21
TOTAL
2TO
TO
"If
3TO
TO
TO
-------
EXHIBIT 4-3
JSAL M00UC7J0* AMO SHtPWEHT *t*ECASTS
aisekt regulation ano »iguutoit
MICH CASES
(IN MILLIONS 3f TQMS)
CHANCE CKANCC
'(ON
9«E-STATUTE Mi-STATUTE
Pr#.
Afisant
fra»
Statuta Regulation *tgulat§ry Statute
•adulation ftaouW
Cam
Cat*
Caaa
Caaa
Caaa
Caaa
1995
1995
1995
2000
2000
2000
COAL PWOOCTIOM
—_
-mmmm
m^rtmkiui XPfSuottA
ISA.
0.
Iff.
-51.
-31.
CENTRAL AGALACTIA
261.
29.
21.
280.
68.
59.
SOUTKCRM AWAUCHIA
a.
1,
1.
22.
1.
3.
MIDUKSr
13*.
•38.
-20.
149.
•67.
•6*.
MM?
420.
4.
0.
491.
38.
30.
TOTAL COM. II6IQM
182T
TT
-j-
inr
—j-
COAL TRAMWTATIQH
JFirytrmn m jiy
51.
-1.
0.
ii.
2A.
12.
-------
EXHIBIT A-3
COAL PRODUCT ION ANO SHIPMENT 'OftECASTS
ABSENT REGULATION ANO «OJUTC*Y
HIGH CASES
(!N MILLIONS OF- TOMS)
CHANGE
?RCN
PRE-STATUTE
CHANGE
PRE-STATUTE
Pr*.
Atwant
P ra-
AbMnt
StAtUta
Radiation **9ulatory Statuta Raoulatfon tagula
Cam
Caaa
Caaa
cist
Cam
Caaa
2009
2009
2005
2010
2010
2010
COAL PfCOUCTION
HOt T HUM APPALACN1A
239.
•51.
•52.
290.
•45.
-41.
CENTRAL A^ALACHIA
317.
77.
96.
324.
108.
140.
SOUTHUN AFfAUCIItA
29.
-3.
•2.
35.
•6.
•5.
MtOUKtT
181.
•41.
•76.
30*.
•101.
•129.
WIST
542.
26.
30.
675.
27.
38.
TOTAL COAL KfSlOM
1ST
TH
iXJ?T
t:
COAL TIAMMRTATtQN
-------
MtV ENGLANO
NIOOLS ATLANTIC
I#** S. ATLANTIC
ion S. ATLANTIC
CAST N. CSNTML
EA8T S. CZNTRAi
MIST H. CENTRAL
WIST S. CUTML
NOUlTAtl
Metric
TOTAL U.S.
EXHIBIT A-4
CHANGE IN ANNUALIZED NET
UTILITY COSTS IT REGION 1/
(MILLIONS OP 1990 0QLLAJIS)
CHANGS
PRQH
ASSENT
REGULATION
change change
HON F*0N
PIE- ASSENT
STATUTE REGULATION
CHANGE CHANGE CHANGE
F«CN FROM CDQM
»IS- ASSENT PIE-
STATUTE REGULATION STATUTE
CHANGE CHANGE
FROM c«QM
ABSENT B«f-
iequlatson statute
HIGH
HIGH
MI6M
HIGH
HIGH
HIGH
HUH
HIGH
IBS.
REG.
IIS.
RES.
ISO.
REG.
REG.
'EG.
CASE
CASS
CASS
riff
CASf
CASE
CASE
1995
1993
2000
2000
2009
2005
2010
2910
__
—
—
—
__
-20
• 11
•49
42
-11
114
•18
73
-4
94
•m
123
•111
444
•90
436
47
141
-3*1
231
•83
411
-32
349
-89
a
•210
M8
•82
402
•127
3*1
-102
4*t
-819
280
-242
933
-474
1141
'79
79
-291
3U
-141
574
-104
393
•83
Si
-184
344
•142
308
-144
39*
-sr
1
-347
40
•400
273
•173
30*
0
20
-1*1
90
-280
102
-11*
191
0
0
•71
•a
•107
0
-74
41
(MS)
874
(2,822)
2,0*8
(1,6W
3.42*
(1,4*6)
3,471
V lnel«dt» «n pHe# increesee <«• «•• JwntH InerwM), but dam not fnctutfa easts of Mtfiar
9UMT Mctort.
•a* prlect for
-------
EXHIBIT 4*5
0CRCEMT CMAMC !* EL«CT«!CITY MTIS IAXCD OH
MNUA112E0 COSTS <1.1., lEVfLSOD IASIS) 1/
<*>€»CMT)
CMANOC
CHANS!
cxami
CHAIKB
CXAMtil
CHA*«|
CKAHGf
:**»«
«<*
r*m
f*M
r*m
r*m
FICM
AISCNT
n«-
ASSMT
AISIMT
»«•
*tSi*T
S«f-
KCQUUTIM
STAWI tCOUUTlOi
STATUTE MOUUTIQi
statuti
tiouurioN
STATUTI
,
WIS*
HIS*
HtCN
N!M
M!W
mm
MIS*
HIGH
III.
*(6.
«f«.
III.
•19.
118.
ICS.
8€S.
r»Tf
CASI
cut
CAM
CAM
ast
CAS C
1 m
!W
2000
2000
290S
2009
2010
2010
*W IN6UND
•0.1
•0.1
•0.4
0.*
¦0.1
O.S
•0.0
3.2
RfOOU ATLANTIC
•0.0
0.3
•O.t
0.9
•0.2
1.0
•0.2
0.1
vmi S. ATLANTIC
0.4
1.1
-2.4
1.4
•O.f
2.1
•0.2
1.0
lOUU S. ATLANTIC
•0.3
0.1
•0.3
O.S
•0.1
0.*
•0.2
0.4
BAST N. CSNTIAL
•o.a
t,1
•1.«
0.*
•0.1
1.9
•0.9
2.1
IAST S. entlAL
¦0.4
0.4
•1.3
1.3
•0.1
1.4
-0.3
1.2
MST M. CSimUL
•0,1
0.1
•1.0
1.1
•0.*
1.4
•0.7
1.6
WIST S. CINTMAl
*1.3
0.0
•1.1
0.1
~0.4
0.3
•0.2
0.6
MOUiTAia
0.0
0.1
•0.4
0.3
•0.*
0.3
-0.4
•3.4
Metric
0.0
0.0
•1.4
•O.I
•0.1
0.0
0.1
0.3
TOTAt U.S.
•0.3
0.4
•1.1
o.«
*0.4
0.9
•0.3
0.9
V Catculatad m follawt
"irtMivt taduction cmm Amatltad tost •
?r*
1914 Avefaee
flactr
-------
EXHIIIT *-6
HIS* CASE 1995
REGULATORY CASt RELATlVt TO "AISCMt kftJUUkTtQN" CASt
TOTAL
AffiCTIO
-
ALL0UA8H
ALLOUAILt
source
CASt
CASt
CASt ELECTRICITY
SOJ
¦ANKZB
S02
S02
«T
TRADING I
:o»u uta
TOTAL
RATE
EMtSStONS
ALLOWANCES
EMISSIONS
Emissions
TRAOtS
COSTS
COSTS
COSTS
INCREASES
ST ATE/RESION
(MTONS)
(MTOM)
(ttTOHS)
(HTQMS)
(ATOM)
(SMI)
(SW)
(Ml)
(X)
¦••••••••••tail
¦aaaaaaaaa
nuuuu aaaaaaasas
MMUlttl a
utMtsaa a
laaaaaaaa i
¦mnm a
aaaaaaaa aaaaaaaaaaa
NEW ENGLANO
32
0
32
26
(6)
(1>
(20)
(20)
•0.2
NIOOLE ATLANTIC
706
(108)
m
643
86
11
(15)
(4)
•0.3
UfKi S. ATLANTIC
637
(151)
486
108
22
3
44
47
0.4
lOUtR S. ATUNTtC
715
(6)
m
447
(261)
(S3)
(55)
(89)
•0.3
EAST N. CXNTtAi
2,29?
(600)
1,658
1,601
(17)
(7)
(95)
(102)
•0.2
EAST S. CENTRAL
990
tm
874
829
(44)
(6)
(73)
(79)
•0.4
WIST K. CENTRAL
402
0
402
261
34
(118)
(83)
•a.s
WfST S. CfiTIM.
0
0
9
0
0
0
(337)
(337)
•i.S
NQWTAIH
0
9
0
0
0
0
0
0
0.0
?AClfIC
0
0
0
0
0
0
0
0
ERR
TOTAt U.S.
1,099
(943)
4,757
4,718
0
0
(6*8)
(668)
-0.3
MOTI: Total* mtf not «tf *» ta IndqHnMnt rawriinf.
1/ "lankad AtlaMKM" r«flwt wtanafw atlMancM antf **»*•*¦ oriMlan r«*ct<«* tarm-atad ty Mum 1
tacftnoiofy In 1991.
-------
EXKU1T A-7
*im casc 2qoo v
MOUUTOIT CAM tfLATlVf TO "AiSMT HIQUUTION" CASI
TOTAL amictib
ALLCMAILK
EMISSIONS
allowable
soma
case
CASC
CASC Et£CT*rc:'T
$02
CSCS1TS I
$02
$02
Ntt
TKAOIM CONKIANCS
TOTAL
»ATE
EMISSIONS
ftAJUCIW
EMISSIONS
EMISSIONS
tkaois
costs
COSTS
COSTS
:«Ct€AS6S
StATC/ICfilOH
(MTQNS)
(HT0HS)
(NTQNS)
(NT0NS)
(HT0NS)
(SW)
(SW)
(tmj
C%>
atniinuuw*
innHM*
nnunw
MiimiN
imtSMtM 1
www
wnm i
mnum lumui miaaiiin
NCW CMfiUUB
m
0
294
429
131
SI
(107)
(49)
• c.»
"I0OLI AfUMTIC
934
194
1,130
1,354
424
111
(507)
(326)
UWM i. ATLANTIC
741
334
1,042
1,130
41
20
(312)
(341)
' Z -•»
IIMK* S. ATLMttC
1,417
11
1,421
1,477
249
104
(314)
(210)
•3.5
EAST H. CXMtlAL
2,324
1,344
3,664
2,313
(1,00)
(441)
(351)
CI193
••.s
EAST S. CSNTRAL
1,09*
140
1,254
1,421
171
73
(344)
(293)
.J
WIST H. CS1TRAI.
924
0
924
1,14«
224
91
(279)
(184)
•* .3
WIST S. CSMTRAl
1,033
0
1,033
990
(84)
(34)
(312)
(347)
-< .1
MQUttAlH
424
0
m
575
(49)
<21)
(141)
(161)
. 9
PAClftC
1*0
0
140
104
(34)
(15)
(54)
(71)
* , <*
TOTAL U.S.
9,534
2,042
11,371
11,57*
0
0
(2,122)
(2,122)
•1.1
NOTt: Total* aay
net add due
te fndapand
ant rohMlni
1/ •AilMatolt SQ2 iitMlm* include ntra rwtramfarratoU etleweee for unit* npamrim 1001.
aim, "Wnim Credits ft lai*
-------
SXHliiT A-8
«(SH CASE 2005
sfGuurotr case «unvi to -awmt «fauun<*» case
total
amicteo
ALL0UA81C
soma
CASE
CASt
case electricity
502
sea
HIT
r*M ;«c i
:3#uance
total
lATf
MISSIONS
EMISSIONS
TSAOIS
COSTS
COSTS
COSTS
:nc*eas«s
STATC/tCGfQN
(MTQNSJ
(KTQNS)
(NTQNS)
(WO
(SMI)
(SMI)
(X)
immmmmmmmammmmm
tmmmmmmmma
¦aaaaaaaaa i
lactntu s
laaaaaaaa :
lUSMMH ¦
•nm« aaaaaaaaaaa
NEW ENGLAND
"285
144
(139)
(17)
72
(13)
•0.1
K 1001.1 A Tt AIITiC
917
887
(29)
(18)
(91)
(111)
•0.2
UWII I. ATUHTtC
no
m
251
117
(242)
CSS)
¦0.5
10UCI S. ATUUIT1C
1,410
1,430
19
12
(95)
(82)
•0.1
EAST N. CEMTVAt
2,240
2,111"
<144)
<90)
(152)
(242)
•0.5
EAST S. CENTRAL
1,073
1,198
125
78
(223)
(145)
•0.5
WEST It. CENTRAL
91S
941
29
18
(140)
<142)
•0.6
Ufir S. CENTRAL
1.0S
m
(80)
(SO)
<151)
(400)
•0.4
MOUNTAIN
622
427
6
4
(2*4)
(280)
•0.8
PACIFIC
140
102
(38)
(24)
(85)
(107)
•0.1
total u.s.
9,391
9,m
0
0
<1,410)
<1,410)
•0,4
HOT I: Totals a* not m» *« to tn*»an*nt rwntitm.
-------
EXHIBIT A-9
HIGH CAM 2010
RlGUUTOif CjkSi I1LAT1V1 TO "MtINT »6QUUTtM- CASS
TOT At AMECTEO
AU0WMH.1
SOURCf
CASE
CASS
CASE ELECTtlCITT
S02
502
HIT
TRAOlNG COMPllANCf
TOT At
MTS
CMtSSlCKS
EMISSION*
TRACES
COSTS
COSTS
COSTS
IMCtEASCS
STATE/CtGlON
(HTOMS)
CHTQNS}
(HTOMSJ
(MM)
(Ml)
(X)
mmmmrnammmm
mmmmmmmmmm
¦aaaaaaaa a
laaaaaaaa i
¦••aaawn *
•nam •
anmanaa
»w ctKsuun
274
229
£45)
(23)
5
(18)
•0.0
NICOLE ATUWTtC
891
«9»
5
3
(93)
(90)
*0.2
UW€« S. ATUNTIC
raft
829
103
53
(89)
<32>
•0.2
taucit s. ATuunc
1,321
1,10ft
(21!)
(111)
(1ft>
(12?)
•0.2
EAST a. CMTRAi.
2,111
2,019
an
-------
EXMISIT A-10
HtCM CASE 1W V
regulatory case relative ro pre-Statute case
TOTAL *F^ECTEO
allcuasle
auowasle
SOURCE
CASE
CASE
CASE
Ei-ECTRtCITT
SQ2
SANKEO
SQ2
$02
MET
TRACING 1
COMPLIANCE
TOTAL
?ATE
EMISSIONS ALLOWANCES
EMISSIONS
EMISSIONS
TRACES
COSTS
COSTS
COSTS
INCREASES
STATE/REGION
(MTONS)
(MTONS)
(MTONS)
(MTONS)
(MTONS)
(SMI)
(SMI)
(SMI)
(X)
tiuuiuumi
tstnassat
•asaaaaaaa niisifliii
ititntns
aiuuisa «
naann i
saaaaaasaa
l«S*fl«f«
autatsiitt
NEW ENGLANO
32
0
32
26
<6)
(1)
(10)
(11 )
*
MIOOLE ATLANTIC
706
<108)
598
683
86
11
83
94
•:.'j
UPHR S. ATLANTIC
637
(151)
486
508
22
3
138
141
• •
IOUE* S. ATLANTIC
715
(*)
709
447
(261)
(35)
58
23
0•
EAST N. CtNTtAl
2,257
(600)
1,658
1,601
(57)
(7)
475
T •
EAST S. ONTRAl
950
-------
EXHIBIT A-11
MICH CASC 2000 >/
ItGUUTOtY USX RELATIVE TO WI-STATUTE CASC
TOTAL
AMECTE0
Ai.L0U*Ct.E
EMISSIONS
AL5.0MA8LE
SOURCE
CASE
' 'CASC
CASE
electricity
SQ2
CREDITS &
502
soz
NET
trading caeuAMa
total
BATE
EMISStOIS
SANK INC
inissiois
EMISSIONS
TRADES
COSTS
COSTS
COSTS
INCREASES
STATI/REGIOH
(XT CHS)
(HTQHS)
(MTQUSi
(MTQNS)
(NTQMS)
(INI)
(SM>
(SW1
(X)
••nimiMuM
s*s*iitaa«
•¦*«¦¦¦¦**
•
II
It
•
•
II
•
H
•
II
¦MWIMI «
mmmmmwmm i
inmuu ¦
••¦¦••¦¦sax
NIV ENSLA40
294
0
294
429
115
58
4
42
0.4
MIQOLi ATLAHTJC
m
m
1,130
1,55ft
42«
1S1
142
123
0.9
on i. atlahtic
74*
234
1,042
1,130
a
20
231
251
' .6
L0WM S. ATLANTIC
t,4i r
11
1,421
1,677
249
10*
242
348
3.3
EAST M. CMTML
2,324
1,344
3,64*
2,543
(1,045)
(441)
741
280
0.6
EA1T S. CSHTIAL
1,096
1*0
1,25*
1.42S
172
71
275
344
1.5
WIT H, CENTRAL
924
0
924
1,141
224
9»
249
344
1.8
UMT S. CfMTMi
1,333
0
1,033
950
(84)
(34)
n
40
Q.I
MOUHTAtH
624
0
424
571
(49)
(21)
119
98
0.3
PACIMC
140
0
140
104
(3*)
(15)
(10)
(25!
I *0.5
TOTAL U.S.
9,534
2,042
11,571
11,571
0
0
2,061
2,048
0.8
writ Tocala trn
net add *»
to indapand
•nt rounding
»
V "AltOMatoU KS lafMlona" inelu* wtra non-tranafarribU aUawaneM far unit* rip—r»w> by 2003.
•IM, "fafMfom Cradlta I tmrnim* ««t*»ian iUmmm, mt
"bmkmdP ¦Maaiena raA*t1ona uh« in 2000.
-------
sXHUIT *-12
mich cast 2009
«£GUUTQ«T ass MUTiVf T0 MW-STAfUTE CASl
TOTUt
AMfCTRJ
imaimiiMii
XCU ENGUNO
* I DO IE ATLANTIC
JP«* S. ATUHTIC
1.0UER S. ATLANTIC
EAST «. CEMTtAL
EAST S. CENTtAl
MEST N. CENTtAL
WtST S. CENTRAL
mcumtaim
PACIFIC
TOTAL U.S.
AlLOUULE
SOUtCX
CASE
CASE
CASE
IlECTHCm
SOI
S02
MIT
TRACING :
:3»uance
'QTAl.
(ATI
ehissioks
EMISSIONS
TIAOCS
COSTS
COSTS
COSTS
!NCIEASES
(«T0»J>
(*to*s)
-------
exhibit A-13
high CASC 2010
REOULATOtY CASC RELATIVE TO PRE-STATUTE CASE
TOTAL
AMECTED
ALLOWABLE
SOURCE
CASE
CASE
CASC
ELECTRICITY
S02
S02
NET
TRADING CCMPlIANCC
TOTAL
RATE
EMISSIONS
EMISSIONS
TRADES
COSTS
COSTS
COSTS
INCREASES
STATE/REGION
(MTONS)
(MTONS)
(MTONS)
(SMI)
(SMI)
(SMI)
(X)
KlWfMWM
laacaaaiaa
mutatai
ttaanaas assuaaaa aai
•aaaaaaa
faaaaaa
¦ n m m ¦* aaal
NEW ENGLANO
zn
229
(45)
(23)
96
73
0.2
HtOOLE ATLANTIC
893
898
5
3
403
406
0.8
UPPER S. ATLANTIC
726
829
103
S3
296
349
1.8
LOWER S. ATLANTIC
1,321
1,106
(215)
(111)
472
361
0.4
EAST N. CENTRAL
2,111
2,089
(21)
(11)
1,172
1,161
2.1
EAST S. CENTRAL
1,060
1,189
123
64
331
399
1.2
WtST N. CENTRAL
892
967
115
59
337
396
1.6
WEST S. CENTRAL
1,001
917
(84)
(43)
390
306
0.4
MOUNTAIN
549
631
42
22
169
191
0.4
PACIFIC
123
99
(23)
(12)
53
41
-0.0
TOTAL U.S.
a,950
8,950
<0)
(0)
3,67t
3,671
0.9
M0T1: Totals aay not add Am to (ndapandant routing.
-------
EXHIBIT 9-1
sr.r.n zzoxzzi f:r£cas:s
ASSZS: UIATIIK A.Nj sIGulATSSY
low CASES
:s z~ ::ss;
:hasgs
now
PRE-STATUTE
?ri- Afcsent
Statute Stgy.atu
vi-lity SC2 Emissions
¦H,llisns of Tens)
7 Eastern States
Coal
SIP
HSPS
ASSFS
Total Coal
Oil/Gas
;tai 37 Eastern States
.as*
1995
13.38
2. 39
a. 36
".5.53
0.46
IS. 99
.as*
¦55'
-3 32
-C . 03
-3 35
3.33
-3 35
Raguia^cry
Case
•.m
-3 35
:• 32
30
-3 . 33
-3 33
-3.33
CHASGE
FROM
PRE-STATUTE
ta- Absent
state Regulation K.«g ulat:rv
-ase
23CO
13 70
2.20
0 08
16 .00
3 43
36 . 40
-ase
Z300
91
-0 U
3 oi
-3 01
3 30
-3,01
• 4J«
2333
-5 2k
2:
-3 *2
-5 23
*. 1 Western States
Coal
SIP
HSPS
ANSPS
Total Coal
Oil/Gas
Total 11 Western States
3.44 -C.30
0.20 3 30
0.01 3.33
0.65 -0.00
0.01 0.30
0.66 -0.00
-¦3.00 0.k3
0.00 0.20
0.00 0.01
-0.00 0 5t
0.00 0.03
-0.00 0.68
-0.10 -0,03
-0.03 0.00
-0.00 0.30
-0.13 -3 33
-3.03 3 33
-0.16 -3 33
United States
Coal
SIP
HSPS
ANSPS
Total Coal
Oil/Sas
Total United State*
13.82 -3.32
2.29 -0.03
0,07 0,01
16.18 -3.35
0.46 0.00
16.6* -3.35
-3.35 14.14
0.02 2.42
-0.00 0,09
-3.33 16.64
-0.00 0.43
-3.33 17.07
-3.01 -5.27
-3.14 0.03
0.01 0.00
-8.15 -5.23
-0.08 -0.02
-3.23 -5.26
-------
EXHIEIT 3-1
sr.?'.-?. :::x:ze -crecasts
assent r£31'la::oh an: ;x3v'la:cf.y
LOW CASES
*:n «x'»l:chs cf rcssi
CHANGE
r RCM
?s£-sTArvr:
.'iiiuy S02 Emiaaiona
MClicna of tons)
?ra- Ais»r.t
Statuta
C»t» Cis«
2305
Ragulatery
In*
izzi
CHA.SGE
rHOM
fre-sta::
Prt- Afcjar.t
Statuta Kajulaii:
Casa
2010
. 43»
Z;i:
Case
2-12
37 Eastaro Statas
Ccai
s:p 13-03
NSPS 2.20
AMSFS 3.33
total Ccal 15.56
OU/Gas 0.33
rital 3? Eaatarn Stataa IS.89
49
•7 81
-0.06
-7. 37
C3
•; 02
-a 34
09
-3.03
-7 12
11.85
2.00
C 73
14 .66
0.25
14.91
: 07
-7 05
-3.06
"7 U
¦¦} *<¦
¦' 06
-6.59
11 Wastarr. Stataa
Coal
SIP 0.39 -3 10 -3.0« 0.38 -0.08 -3 02
USPS 0.21 -0.04 -0.01 0.20 -3.04 0 M
AN5PS 0.13 -C 03 -0,04 0.18 -1.33 -0 li
Total Coal 0.73 -0.16 -0.08 0.75 -0.16 -0 06
Oi1/Gaa 0.02 -0.01 -0.00 0.01 *0.01 -0.00
Total 11 Mastam Stataa 0.75 -0.18 -C 09 0.76 -3 16 -0 06
'."r.itad Stataa
Coal
SIP
HSPS
ASS PS
Total Coal
Oil/Oaa
Total Unitad Stataa
13.42 -7.79
2.*1 -0.14
0.*6 -0.04
16.29 -7.97
0.35 -0.08
16.6* -8.06
-7.07 12.22
-0.03 2.28
-0.38 0.90
-7,17 15.41
-0.03 0.26
-7.20 15.67
-7.09 -6 52
-0.15 -0 02
3.03 -0.04
-7.20 -6.S?
-0.07 -0.06
-7.27 -6.65
-------
EXHIBIT 3-2
FUEL :OMSUWTIO« FORECASTS
ASSENT IEGUUTIO« ANO REOUUTCKY
LOU CASES
(IN QUAOS)
change
f ROM
PRE-STATUTE
CHANGE
nw
PRE-STATUTE
37 Eastarn Stataa
Pre- Abaant P^a- Abaant
statuta Ragulatien Ragulatory statuta Ra«ulat
-------
iXHJiit i-2
5ufi consult i qh
AISENT 8ECUUTIOK **0 8EGUUT0HT
LOU CASES
!!H 3UA0S)
CHANCE CHANGE
c*» MOM
P«f-STATUTS SHE*STATUTE
37 futtm ttim
Pre- Abaant Absent
Statute l*9ulation ••fulatory statute Regulation Re«ulatory
C«m Cms Casa caaa Caa«
1005 ZOOS ZOOS 2010 2010 2010
tow urn*
3.SO
1.41
1.04
3.99
.89
.40
lOU-MCSlW SULPUI
3.12
-.11
.01
3.14
-.10
-.12
HICM-ME01UH SULFUR
5.15
•2.28
*1.77
4.97
-1.70
-1.22
high win*
4.20
-1.M
-1.91
4.91
•2.01
-2.19
TOTAL
13TS
'T7&5
•rn
iTO
•CTJ
WW9
*r»
11 weetern States
iou uu
2.14
1.2]
1.02
2.74
1.27
1.19
UM*MBtUH SU.Wt
.77
.40
.74
.79
.91
.91
HISM-MCSiUM SULK*
.2ft
.77
.•1
• 2ft
.17
.87
NI6N SULK*
.00
.09
.13
.00
.10
.12
TOTAL
m
ra
m
CTT
Total U.S.
COM.
low suina
5.9*
2.84
2.0ft
4.73
2.14
1.79
10U-MCDIIM IM.ru>
3.a»
.49
.75
4.34
.81
.81
H16N-M01UH SULFVJi
3,41
-1.51
-.9*
5.24
-.84
•.a
HtON SUM
4.20
-1.77
*1.79
4.91
•1.91
-2.07
TOTAL
ifTB
TB
2TT2T
"H
"HI
-------
gXHtliT 1-3
COAL PWDUCTIOl A NO SHtPWMT fOUICASTJ
AISCMT PECULATION ANO »SGULATQ»Y
low cash
< IN NIUIONS Of- TONS)
CHANG! CHANGS
FtOM c;cm
P«i-STATUTE f»»t-ST*TUT£
Prw AbMnt Prt« *ba«nt
Stiiuti tabulation fttfulatory Statuta *a«uiation ttfuLatory
COAL MWOUCTlOi
NCRTNfttt APfALAGHA
CENTRAL APMLACNIA
SCUTHUH AWALACIIIA
NIOWKST
WSST
TOTAL COM. ICQ10M
COAL TXAMWTATI 91
wifTii» au. wmt
Caa«
C»M
Cat*
c«»
Case
Caa«
1995
\m
19W
2000
2000
2000
m.
2.
1.
191,
•S1.
-12.
230.
2S.
17.
254.
75.
39.
a.
1,
0.
21.
3.
1.
tit.
-43.
•22.
140.
¦64.
*59.
411.
1.
*5.
424.
11.
11.
wc
^TT
155TT
-rr
a.
*1.
*2.
11.
19.
6.
-------
exhibit i-j
coal production *mo SHIP**? FORECASTS
ASSENT REGULATION ANO RE&ILATORf
.OH USES
CIM MILLIONS Of TONS}
CHANGC CHANG!
FROM FROM
PRE-STATUTE 9*6*STATUTE
COAL PRODUCTION
NORTHERN APPAtAC*IA
CENTRAL AP»ALACHU
SOUTHERN APPALACMIA
Mtowcst
WEST
TOTAL COAL REGIONS
COAL TRANSPORTATION
wgfTtik akt Tfl IAst
Pr#-
AMant
Prt-
Asunt
Statute Ra«ulat*an Rwlatory Statute
Refutation Raoula
Cas«
Cut
cat*
Caaa
C«M
Caae
2005
2005
2005
2010
2010
2010
—
—
——
—
__
—
20#.
•4»,
-32.
220.
•45.
•32.
262.
74.
64.
250.
106.
94.
24.
-1.
-1.
27.
•4.
•5.
155.
•54.
•IS.
1W.
-71.
•75.
444.
32.
26.
522.
21.
20.
tUT
"H7
-7T
1257T
"X
-r
a.
15.
8.
a.
J.
4.
-------
EXHttlT 1-4
CHANGE IN 4MNUAUZIC MKT
UTILITY COSTS It tEQiOM V
(MI.UOIIS Of 1990 OOtUUS)
CHAMSC
CXANCC
CHAN6C
CHANGE
CHANG!
CHANGE
change
CxANC
FROM
fW
*»OI
W(K
ftot
-*»<*
«»<*
ASSENT
Ml-
aismt
WW-
A1SENT
Ptfi-
A«SE»T
»«e-
RESUIATIOK
ST*?yT|
•ESULATIOI
STATUTE (EQUUTiOM
STiTutl
«ISUIATI«
STATUTE
tow
LOU
LOW
LOW
tow
LOW
tow
i.0W
RCfi.
*E6.
US.
¦IS.
IK.
*18.
RES.
ft(G.
CASf
CAS!
CASS
CASC
CASE
CASE
1995
\m
2000
2000
2009
2005
2010
2010
—
—
—»
WW ENGLAND
-12
2
•60
•16
•61
•33
-64
¦29
MOOU ATLANTIC
•5
96
-2S3
110
6i
267
U
69
umi S. ATLANTIC
36
136
•226
11?
•54
291
•25
139
LOWSR t. ATUWTIC
-102
•*1
-205
76
*130
571
-186
•55
EAST N. CZMTIAL
•90
m
•435
*01
•229
m
•315
521
IA*T 1. dHTML
-91
36
•2*2
200
-in
m
•79
135
«tT «. CSNTIAL
-106
If
•171
1S2
•149
ns
-209
217
1
UKST 1. CUTRAi
28
23
*157
9
•114
•35
•133
NOUITAIN
16
•11
•17*
28
-229
201
•190
2ft
PAcirtc
0
1
•66
-7
•61
•23
•100
• 17
TOTAL U.S.
(335)
624
(2,061)
1,111
(1,156)
2,567
(1.279)
1,008
1/ IneludM tM price tncraau* (m 9«t I—niH inerMM), but 4ms not ineludt cast* of Mgf*f gat price* fei-
stliar Metora.
-------
EXNill.T |»5
P€»Cl*T CHM6C 1M fUCIIICITT MfiS IASCS 1/
MCE*T>
CMMSf
nm
HiSMI
ICOJUTtOM
CHANGE CHMGC
MOM *90*
HI- ASSENT
stATuri Mayun<*
CHAM6I CMAMGI
**W »**
?»!• asm
statute icajuna*
CHAM6C CXAMGI CH MGe
t*m nm nm
«!• M|-
STATUTE tCOUUttCH StJktUtt
MCU EMUMO
utmt MUttitie
uwa t. ATUMTte
10UX t. ATUVTtC
EAST I. CSHTIAL
EAST t. CfVTIAL
uftr a. central
UCXT «. CENTRAL
MOWTAiN
PACIFIC
TOTAL U.I.
LOU
tow
LOW
L0H
10w
LOW
low
icw
tie.
•ES.
*««.
ttfi.
tea.
iu.
•CO.
IIS.
CAtf
CASE
CASE
CAM
CAM
CA St
CASE
1991
1995
2000
2000
xxii
2001
2010
2310
——
—
—
—
—
—
—
-O.J
9.0
•o.t
-0.2
•o.t
-0.1
•0.4
•0.4
•0.0
0.3
•o.a
0.1
0.2
O.S
0.1
0.2
O.J
1.1
•i.i
1.1
•0.4
t.J
•0.2
1.1
-9.1
*0.1
•0.*
0.2
•0.4
1.*
•0.1
•0.1
•O.t
0.*
-1.0
1.0
•O.S
1.4
•0.1
1.2
•o.s
9.3
•i.J
O.f
•0.*
1.«
-O.J
0.4
-0.»
0.1
•1.0
0.1
•o.t
Uf
•1.1
1.1
8.1
0.1
•0.5
0.0
-0.*
•O.t
•0.1
0.0
o.t
-0.1
-o.»
0.1
•0.*
0.f
•0.4
0.1
0.0
0.0
0.0
0.0
•0.4
-0.1
•O.T
•0.1
-0.1
0.2
-o.»
0.3
•0.5
1.1
•O.S
0.4
1/ Calculated m foilawt
"ttfaafan tarfuetfw Omm imnlUwl CMt ~
>r*-statute Amalitafl CMt
IffStat* feneration after Oiatfifeutian Loaaaa
•MBA
t nV
Elactrtetty tatae
-------
ismiit a-*
LOW CAM 1995 •/
tcouutoit CAM ICUftVf TO "AtSlMf *fflUUTIO** UJI
torn iMicta
ALL0WUU
AUOUAIlf
SOWCI
-
CAM
CASI
CAS! 1
es.sct*!c: rr
SOI
SANKIt)
$02
S02
«T
tiaoiik aam.ma
T0T*|.
«ATf
EMISSIONS
CilOlTf
EMISSIONS
EMISSIONS
tlASCl
casts
COSTS
COSTJ
tMCIfASEI
STJkTf/tfGiOB
CMTOM)
CXTOMS)
CXtQMf)
(Mtoas)
-------
EXHIBIT 1-7
1* CASE 2000 V
REGULATOR CASE RELATIVE TO "USUI? UOLtUTIOM" CAM
TOTAL AMtCTtO
AU0UA6LE EMISSIONS AL10MA8LI SOMCI CAM USi ^M eiECTRICITT
S02 CIEOITS 4 S02 SOJ HIT TRAOING C0NPL1ANCE 'STAC «ATE
EMISSIONS IANKING EMISSIONS EMISSIONS TRACES COSTS COSTS COSTS INCREASES
STATE/REGION ("TONS) (MTONS) (MTQNS) (MTONS) (MTONS) (SMN) (UO«) (It*) (X)
luaaiaitaisiaa :aaaiaaa«« ainaaMH innutia iMunaM uuiaaaa «Maa«ag« aaaaaaaata aseaiatat taaaaaaisaa
NEW ENGLANO
292
0
292
206
(86)
(17)
<43)
(60)
. 2
MI00LE ATLANTIC
1,033
155
i.iaa
1,»7
199
39
(292)
(253)
UPPER S. ATLANTIC
791
267
1,059
1,094
35
7
(233)
(226)
LCMI S. ATLANTIC
1,507
9
1,516
1.626
110
22
(227)
(205)
* j
EAST N. CENTRAL
2.49a
1,07?
3,573
2.667
(906)
(iao)
(235)
(435)
. <
EAST S. CENTRAL
1,121
12S
1,249
1.575
326
65
(347)
(282)
. i
MIST N. CENTRAL
976
0
976
1.446
491
97
(276)
(178)
. ~
MIST S. CENTRAL
1,027
0
1,027
971
(56)
(11)
(146)
(157)
•0
MOUNTAIN
6ia
0
6ia
539
<79)
(16)
(164)
(179)
• C
PACIFIC
139
0
139
104
(36)
<7)
(59)
(66)
*
TOTAL U.S.
10,009
1.434
11.637
11,636
0
<0)
(2.040)
(2,041)
•0
MOTS: Totals aay not add duo to Indopanrtwit routine.
1/ "Allomblo S02 tofulm1 tnetudo astro non-trwvforraMo oUoMncao for unit* ripawartnp by 2009.
aim, -Cataaiara Crodtta I Sarfclna" rofiact aitmtan ailc
"bankatf* aataaiflna roductiono ua«d In 2000.
-------
gXHIttT l-«
10U CASC im
liauUkTQtT uu HUT IVI to »*ISf»f HffiUUlftON" au
TOTAL
fffCTO
UlOrtSLI
souiec
CASt
C*H
CAS« EUCTIICITT
SQ2
SQ2
KIT
TIAOIMfi CCMPLIANCI
total
un
EMISSIONS
EMISSIONS
rtAfiCS
COSTS
COSTS
COSTS
tKCIEASM
sT*ti/tioian
(M70NS)
(NTCXS)
CMTQNS)
(SW)
(SW)
(SW)
(X)
IIMIIIIOIIIII
ttstiatafi
i»»»>u >
!••••¦••• 1
iiKUilia i
1
1
1
!
•
mtnaa i
laaamMam
NEW EMSLUO
2S3
. 203
(80)
<32)
(»)
(41)
¦0.9
miooli atuntic
910
1,013
143
57
11
4i
<3.2
UP*f« S. ATLANTIC
ru
m
129
51
(105)
-0.4
lOWKt S. ATLANTIC
1,394
1,254
(138)
(55)
(75)
(130)
-0.4
EAST a. CiMTtAi
2.249
2.091
(154)
(41)
(149)
(221)
*0.1
EAST S. CSNTtAL
1,04*
1,114
1«1
74
(20S)
(133)
*0.4
*ST t. CIITMt
904
911
11
20
(1if)
(14f)
*0.«
WIS? S. CflTML
1,027
911
(49)
cm
<1«S)
(114)
*0.4
MOUNTAIN
611
341
($7)
(22)
(283)
(229)
-0.9
Heme
139
102
(37)
(13)
(*«)
(43)
*0.4
TOTAL U.S.
9,327
9,32*
0
(0)
(1,119)
(1,114)
•0.1
MOH; Totaii mr not add dua to inMpMMt routine.
-------
IMIItT 1«9
10U CAS* 2010
KOULATOrr ZASt ICUT1V1 TO >IUUt KfflUUTiai" CASI
TOT At
M*ICT©
AUSUAKJ
souta
CAM
CASI
CASI SlICtltCtTY
102
sod
KIT
TIMING COWUAMCS
total
RATI
EMISSIONS
IMISIIOM
TRAMS
COSTS
COSTS
COSTS
INCSCASIS
$tAT«/»I8iai
(NTQM1
(RT0M)
(KTQMS)
(MM)
(*•)
(SW<)
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(190)
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102
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(190)
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514
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5
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715
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709
490
(218)
(22)
(19)
(41 >
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(400)
1,41*
1.978
(80)
(8)
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403
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23
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0
0
0
0
0
0
(21)
(21)
PACIFIC
0
0
0
0
0
0
1
TOTAL U.S.
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4,197
4,79»
0
0
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-------
LOW CASI 2000
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STATE/tCGIOM
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COSTS
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283
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(1)
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910
1,053
143
57
219
247
9.8
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734
44*
129
51
240
291
2.3
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1,258
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624
571
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2,099
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139
102
(37)
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(10)
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9,327
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1,230
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-------
ATTACHMENT
Impacts of Regulation
of New Small Utility Units
Under the Acid Rain Program
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I. INTRODUCTION
ICF has conducted a preliminary analysis of the savings to utilities resulting from an
exception tor utility units with a capacity of 25 megawatts (MW) or less. The savings to utilities
of an exception for small units are estimated at approximately S2 million in the. first year.
Because additional small units would be purchased each year, the annual savings would increase
hv about the same amount each year.
Under the Clean Air Act Amendments of 1990. utility generating units of 25 MW or less
capacity are exempt from all statutory requirements if they were built before November 15. 1990
(the date of enactment of the statute). TTie statute does not specify whether new units will be
exempt. Under proposed regulations, a utility operating a new unit of any size would be subject
to all requirements, including the requirements to (1) install a continuous emission monitoring
system (CEMS) and (2) hold allowances equal to its SO? emissions. A proposed exception to
these requirements for units using very-low-sulfur fuel that were used infrequently would reduce
costs per unit significantly. EPA received numerous comments questioning the need for
monitoring requirements for small units. Commenters have requested that EPA provide relief to
utilities purchasing new small units.
EPA has decided to grant an exception to the CEMS requirements and associated
allowance and permit requirements for new units of 25 MW or less capacity that (1) are fueled
with very-low-sulfur fuel (i.e., natural gas or very-low-sulfur diesel fuel) and (2) are used ten
percent of the time or less. Owners and operators of such units seeking to qualify for the
exception would be required to certify their use of very-low-sulfur fuel, but would not be required
to hold allowances for their S02 emissions.
2. ANALYTICAL APPROACH
For this preliminary estimate of the savings to the utility industry from an exception for
small units, ICF has examined several issues: (1) the number of new small units that may be
purchased by utilities each year; (2) the savings per unit of a small unit exception; and (3)
potential incentives to use two smaller units under 25 MW instead of one larger unit over 25
MW. The analysis also considered the extent to which the benefits of an exception will accrue to
municipal utilities and other small utilities.
3. THE NUMBER OF NEW SMALL UNITS THAT MAY BE PURCHASED BY UTILITIES
EACH YEAR
According to utility projections reported to the Energy Information Administration in
1988, utilities were planning 28 small units for 1989.1 While the number of planned units for
later years decreased, with only nine units planned for 1990 and zero to three units planned each
year thereafter, data for these years are less reliable because utilities do not need to plan far in
advance in order to install a small unit. Many small units, notably diesel or dual-fuel generators,
are purchased off-the-shelf rather than constructed on-site. Because utilities may generally
purchase and install these units and receive permit approval in a short period of time, there is
often no need for them to plan for a small unit years in advance. This analysis uses the 28 small
1 Based on Form EIA-860 Annual Electric Generator Report for 1988.
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units planned for 1989 as the estimated number of small units that would be ordered by utilities
each year.
Of the 28 units planned for 1989. the utilities planning the units expected to burn liquid
fuels in IS of the units, natural gas in nine of the units, and coal in one unit. Of the liquid-
burning units. 16 were expected to be fueled with number 2 oil. (equivalent to diesel fuel), and
two were expected to be fueled with number 6 oil. Any of these units could instead burn very-
low-sulfur diesel oil. which costs somewhat more than higher-sulfur oil. The coal unit could not
burn very-low-sulfur fuel without a capital investment for conversion: it is assumed in this
preliminary analysis that such a conversion would not be economical. Therefore, it is assumed
that 27 units per year could potentially quality for a small unit exception.
4. THE SAVINGS TO UTILITIES FROM A SMALL UNIT EXCEPTION
A small unit exception yields savings to utilities that purchase new small units, because the
utilities are not required to (1) install a CEMS on the unit. (2) obtain a permit for the unit, or (3)
purchase allowances for the unit's SO, emissions. An exception results in additional costs for the
purchase of verv-low-sulfur fuel, except when (1) the utility would have used natural gas. a
qualifying fuel, in the absence of an exception, or (2) the utility would have used very-low-sulfur
diesel fuel in the absence of an exception, because higher sulfur diesel fuel was locally
unavailable.
The annualized costs per unit for a CEMS are substantial. EPA has estimated the total
annual capital and operating costs of a CEMS on a diesel unit at $73,(X)0 (in 1990 dollars).
Annual costs for a CEMS for a gas turbine have been estimated at $58,000, but in this
preliminary analysis of the savings for all small units, savings are estimated using the CEMS cost
for a diesel unit. Annual data reporting costs in Phase II are estimated to be about $ 1.800 per
unit."
The costs of allowances for a 25 MW unit in the absence of an exception depends on the
amount of time the units are in use. Utilities use small units to generate peaking power during
times of peak demand, such as hot summer afternoons when many air conditioners are in use. In
this analysis it was assumed that a typical small unit is operated 200 hours per year. A new 25
MW diesel unit operated for 200 hours per year would produce an estimated ten tons of SO, per
year."1 The owner or operator of such a unit would need to purchase ten allowances each year.
Allowance prices are uncertain; in the only publicly reported trades to date, allowance prices have
been in the S250 to $400 range. Even at a price of $500 each, ten allowances would cost $5,000.
At a maximum, small utilities could purchase ten allowances each year through the direct sales
program at a cost of $1,500 each for a total of $15,000: this may be considered an overestimate of
" U.S. EPA Acid Rain Division, Regulatory Impact Analysis of the Final Acid Rain Implementation
Regulations. U.S. EPA Acid Rain Division, October 1992, p. 4-23.
* Based on a fuel sulfur content of 0.4 percent by weight, a heat rate of 10,000 Btu/kWh, and an
emissions factor of 1.7 grams of S02 per kWh. This sulfur content is conservatively high. By October
1993. diesel fuel for motor vehicles may contain only 0.05 percent sulfur by weight; petroleum marketers in
some areas may choose not to sell higher-sulfur diesel fuel for any purpose after that date.
Attachment - 2
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allowance costs per unit. The annualized permitting costs per source in Phase II have been
estimated at S3.200.4
When small unit exceptions are available, utilities incur extra costs to purchase verv-low-
sulfur fuel (tor those units that would otherwise have used higher-sultur fuel)-. . To quality tor the
small unit exception, a small unit must burn fuel with a sulfur content no greater than 0.05
pounds per million Btu (i.e.. natural gas or very-low-sulfur diesel). The Clean Air Act requires
that motor vehicle diesel fuel sold after October 1, 1993 may not contain sulfur in excess of 0.05
percent by weight. A small unit using such very-low-sulfur diesel fuel would qualify for the
exemption. Based on previous studies. EPA estimates that such fuel may cost as much as cwo
cents per gallon more than conventional diesel fuel, if both grades are available in a geographic
region. This estimate is believed, however, to represent a maximum value of the differential cost
of fuel to utilities. In some less-populated regions, such as the Midwest, the cost of providing
separate distribution channels for conventional diesel and very-low-sulfur diesel may exceed the
cost of manufacturing all diesel to meet the 0.05 percent sulfur specification. Because
conventional, higher sulfur diesel may be unavailable in these regions, utilities would incur no
incremental costs to use the very-low-sulfur diesel. Based on an incremental cost of 2 cents per
gallon, the use of very-low-sulfur fuel would increase the annual costs for a utility operating a 25
MW unit for 200 hours per year by an estimated $9,000.
This preliminary analysis of the savings from a small unit exception considers only the
CEMS costs, because (1) the avoided costs of CEMS far outweigh the avoided costs for
allowances and permits, and the incremental costs under an exception for very-low-sulfur fuel, and
(2) the additional costs for very-low-sulfur fuel tend to balance out the avoided costs for
allowances and permits.
Assuming that a small unit exception allows utilities to avoid CEMS costs on 27 small
units in the first year, and that annual CEMS costs are $73,000, the annual savings for utilities for
units purchased in the first year would be approximately $2.0 million. Each year, assuming that
utilities continue to purchase 27 new units that qualify for the exception, the annual savings to
utilities would rise by about the same amount.
5. POTENTIAL INCENTIVES TO USE TWO SMALL UNITS INSTEAD OF ONE
LARGER UNIT
A utility deciding what size generating unit to purchase will encounter decreasing capital
costs per MW capacity as the size of the generator increases, due to economies of scale. If a
CEMS is not required for new units of 25 MW or less capacity, however, the cost per MW
capacity for units of 25 MW will be lower than the cost per MW capacity for units slightly larger
than 25 MW.5
4 U.S. EPA Acid Rain Division, Regulatory Impact Analysis of the Final Acid Rain Implementation
Regulations. U.S. EPA Acid Rain Division, October 1992, p. 4-36.
5 For generators using diesel oil, this cost savings and the savings in avoided operating costs for
CEMS will be slightly offset by the higher cost of low-sulfur diesel fuel, as required under the CEMS
exception. However, because so little fuel is used in a peaking unit, the capital cost savings will dominate
Attachment - 3
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The exception for units of 25 MW or less could thus provide an incentive to limit new
small units to this size. A utility considering installing a single 40 MW unit, for example, might
have an incentive to install two 20 MW units instead. This decision will turn on whether the
annual CEMS. permit, and allowance savings exceed the higher annualized capital costs of
"splitting" a larger unit in halt" (and losing some economies of .scale). The balance between
regulatory compliance costs and the economies of scale will depend, in turn, on the magnitude of
the scale economies in constructing small electrical generating units.
To assess the relative importance of regulatory compliance costs for units above 25 MW
and higher capital costs per kW for smaller units. ICF estimated the costs for gas turbine units
ranging up to 50 MW (excluding costs of land and buildings) using the following cost equation:
Cost=$542 . 3 *(Size(MW) ) °'7
The exponent in the equation expresses the degree to which there are economies of scale in
manufacture of the units. The exponent of 0.7 indicates minimal scale economies in the
manufacture of gas turbines: the cost per kW capacity drops approximately three percent as the
size of the unit increases by ten percent. The exponent value of 0.7 for gas turbines is based on
previous EPA analyses of gas turbine costs.6 This analysis does not consider relative heat rates,
fuel costs, and operating costs. Because of the limited annual operating time for small units, such
costs are likely to be relatively minor relative to the capital costs.
On the basis of this preliminary analysis, ICF concluded that the only units likely to be
split in order to take advantage of the small unit exception would be those just slightly larger than
25 MW. A utility planning a 26 MW gas turbine, for example, may have an economic incentive to
instead purchase one 25 MW unit and one one-megawatt unit. Units in a range slightly larger
than 25 MW would account for a small percentage of all new small generating units. The
emissions consequences of this small shift in unit sizes would be minimal, given the small size of
the units affected, their generally low utilization rates, and the fact that they would be required to
use fuel with an extremely low sulfur content in order to qualify for the exception.
6. DISTRIBUTION OF SAVINGS TO SMALL UTILITIES
Small municipal utilities own a large number of small units.7 This preliminary analysis
assumes that many of the new small units purchased by utilities would be purchased by municipal
utilities, to replace small units being retired. Thus, the cost savings from a small unit exception
are expected to accrue largely to municipal utility companies.
in the firm's decision.
6 EPA Office of Air Quality Planning and Standards, "Air Emissions from Municipal Solid Waste
Landfills -- Background Information for Proposed Standards and Emissions Guidelines,'' EPA-450/3-90-
01 la. May 30, 1991.
7 ICF analysis of 1988 Energy Information Administration data from Form ELA-860.
Attachment - 4*
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7. CONCLUSIONS
From the Foregoing analysis, several conclusions fallow:
• The savings to utilities ot" an exception tor small units are estimated at
approximately $2 million in the first year. Because additional small units would he
purchased each year, the annual savings would increase by about the same amount
each yeiar.
• Relatively few new small units are likely to be purchased each year.
• Regulations that require full CEMS far new small units would achieve the
monitoring of very low amounts of annual emissions, especially where verv-low-
sulfur fuel is used.
• .An exception for small units would distort a utility's choice of unit size only in a
small number of cases.
Attachment - 5
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