United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Triangle Park, NC 27711
July 1994
Air
> EPA
Regulatory Impact Analysis for the
Petroleum Refineries NESHAP
DRAFT
U.S. Environmental/rct-r.Mon Agency
Rq-ior< 5, Library '""'. '
77 V:. ,t J2c;;scfi '/ ;. , i2th Floor
Chic.:-t;o, IL 60-wj'i-j^ 'J
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CONTENTS
Page
TABLES vi
FIGURES vii
ACRONYMS AND ABBREVIATIONS viii
EXECUTIVE SUMMARY ES-1
ES.l PURPOSE AND STATUTORY AUTHORITY ES-1
ES.2 PROPOSED PETROLEUM REFINERY EMISSION STANDARD ES-2
ES.3 NEED FOR REGULATION ES-3
ES.4 CONTROL TECHNIQUES AND REGULATORY ALTERNATIVES . . . ES-4
ES.5 COST ANALYSIS ES-4
ES.6 ECONOMIC IMPACTS AND SOCIAL COSTS ES-6
ES.7 QUALITATIVE ASSESSMENT OF BENEFITS OF EMISSION
REDUCTIONS ES-8
ES.8 QUANTITATIVE ASSESSMENT OF BENEFITS ES-8
ES.9 COMPARISON OF BENEFITS TO COSTS ES-10
1.0 INTRODUCTION 1
1.1 PURPOSE 1
1.2 LEGAL HISTORY AND STATUTORY AUTHORITY 2
2.0 PROPOSED PETROLEUM REFINERIES EMISSION STANDARD IN BRIEF ... 5
2.1 THE EMISSION STANDARD IN BRIEF 5
2.1.1 Applicability of the Petroleum Refinery NESHAP 6
2.1.2 Miscellaneous Process Vent Provisions 6
2.1.3 Storage Vessel Provisions 7
2.1.4 Wastewater Provisions 8
2.1.5 Equipment Leak Provisions 8
2.1.6 Recordkeeping and Reporting Provisions 9
2.1.7 Emission Averaging 9
3.0 NEED FOR REGULATION 11
3.1 MARKET FAILURE 11
3.1.1 Air Pollution as an Externality 12
3.1.2 Natural Monopoly 12
3.1.3 Inadequate Information 13
3.2 INSUFFICIENT POLITICAL AND JUDICIAL FORCES 13
3.3 ENVIRONMENTAL FACTORS WHICH NECESSITATE REGULATION .... 14
3.3.1 Air Emission Characterization - 14
3.3.2 Harmful Effects of HAPs 15
3.4 CONSEQUENCES OF REGULATORY ACTION 17
3.4.1 Conseauences if EPA's Emission Reduction Objectives are Met 7"
3.4.2 Consequences if EPA's Emission Reduction Objectives are Not .Met . '20
111
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CONTENTS (continued)
Page
4.0 CONTROL TECHNIQUES AND REGULATORY ALTERNATIVES 23
4.1 CONTROL TECHNIQUES 24
4.1.1 Combustion Technology 24
4.1.2 Product Recovery Devices 36
4.1.3 Leak Detection and Repair 52
4.1.4 Internal Floating Roofs 62
4.2 DESCRIPTION OF MACT AND SUMMARY OF REGULATORY
ALTERNATIVES 65
4.2.1 Miscellaneous Process Vents 66
4.2.2 Storage Vessels 66
4.2.3 Wastewater Streams 67
4.2.4 Equipment Leaks 68
4.2.5 Summary of Alternatives 69
4.3 NO ADDITIONAL EPA REGULATION 69
4.3.1 Judicial System 69
4.3.2 State and Local Action 71
4.4 ROLE OF COST EFFECTIVENESS IN CHOOSING AMONG REGULATORY
ALTERNATIVES 71
4.5 ECONOMIC INCENTIVES: SUBSIDIES, FEES, AND MARKETABLE
PERMITS 72
5.0 COST ANALYSIS AND EMISSION REDUCTION 75
5.1 APPROACH FOR ESTIMATING REGULATORY COMPLIANCE COSTS ... 75
5.1.2 Calculations for Existing Sources 77
5.1.3 Calculations for New Sources 84
5.2 TOTAL COMPLIANCE COST ESTIMATES, REDUCTIONS, AND COST
EFFECTIVENESS 87
5.3 MONITORING, RECORDKEEPING, AND REPORTING COSTS 91
6.0 ECONOMIC IMPACTS AND SOCIAL COSTS 97
6.1 PROFILE OF THE PETROLEUM REFINING INDUSTRY 98
6.1.1 Profile of Affected Facilities 99
6.1.2 Market Structure 102
6.1.3 Market Supply 106
6.1.4 Market Demand Characteristics 107
6.1.5 Market Outlook Ill
6.2 MARKET MODEL 114
6.2.1 Market Supply and Demand 114
6.2.2 Market Supply Shift 115
6.2.3 Impact of Supply Shift on Market Price and Quantity 119
6.2.4 Trade Impacts 119
6.2.5 Changes in Economic Welfare , 120
6.2.6 Labor Market and Energy Market Impacts 123
6.2.7 Baseline Inputs 124
6.2.8 Price Elasticities of Demand and Suoolv 124
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CONTENTS (continued)
Page
6.3 CAPITAL AVAILABILITY ANALYSIS 127
6.4 LIMITATIONS OF THE ECONOMIC MODEL 131
6.5 PRIMARY IMPACT, CAPITAL AVAILABILITY ANALYSIS, AND
SECONDARY IMPACT RESULTS 133
6.5.1 Estimates of Primary Impacts 133
6.5.2 Capital Availability Analysis 136
6.5.3 Labor Market Impacts and Energy Market Impacts 137
6.5.4 Foreign Trade Impacts 139
6.5.5 Regional Impacts 140
6.6 SUMMARY 140
6.7 POTENTIAL SMALL BUSINESS IMPACTS 142
6.7.1 Introduction 142
6.7.2 Methodology 142
6.7.3 Categorization of Small Businesses 143
6.7.4 Small Business Impacts 143
6.8 SOCIAL COSTS OF REGULATION 144
6.8.1 Social Cost Estimates 144
7.0 QUALITATIVE ASSESSMENT OF BENEFITS OF EMISSION REDUCTIONS . 149
7.1 IDENTIFICATION OF POTENTIAL BENEFIT CATEGORIES 149
7.2 QUALITATIVE DESCRIPTION OF AIR RELATED BENEFITS 150
7.2.1 Benefits of Decreasing HAP Emissions 150
7.2.2 Benefits of Reduced VOC Emissions 153
8.0 QUANTITATIVE ASSESSMENT OF BENEFITS 159
8.1 METHODOLOGY FOR DEVELOPMENT OF BENEFIT ESTIMATES 159
8.1.1 Benefits of Reduced Cancer Risk Associated with HAP Reductions . 160
8.1.2 Quantitative Benefits of VOC Reduction 167
9.0 COMPARISON OF BENEFITS TO COSTS 177
9.1 COMPARISON OF ANNUAL BENEFITS AND COSTS 177
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TABLES
Page
ES-1 SUMMARY OF TOTAL COSTS IN THE FIFTH YEAR FOR THE
PETROLEUM REFINING INDUSTRY REGULATION ES-5
ES-2 ANNUAL SOCIAL COST ESTIMATES FOR THE PETROLEUM REFINING
REGULATION ES-7
ES-3 VOC EMISSION REDUCTIONS BY EMISSION POINT ES-9
ES-4 BENEFIT PER MEGAGRAM VALUES FOR VOC REDUCTIONS ES-10
ES-5 COMPARISON OF ANNUAL BENEFITS TO COSTS FOR THE NATIONAL
PETROLEUM REFINING INDUSTRY REGULATION ES-11
ES-6 VOC INCREMENTAL COST-EFFECTIVENESS OF PETROLEUM
REFINING REGULATION ES-11
3-1 NATIONAL BASELINE VOC AND HAP EMISSIONS BY EMISSION POINT 15
3-2 BASELINE SPECIATED HAP EMISSIONS FROM EQUIPMENT LEAKS . . 16
3-3 NATIONAL CONTROL COST IMPACTS OF PREFERRED ALTERNATIVE
IN THE FIFTH YEAR 19
4-1 SUMMARY OF REGULATORY ALTERNATIVES BY EMISSION POINT ... 70
5-1 SUMMARY OF TOTAL COSTS IN THE FIFTH YEAR FOR THE
PETROLEUM REFINING NESHAP 88
5-2 CONTROL OPTIONS AND IMPACTS BY EMISSION POINT 89
5-3 COST, HAP EMISSION REDUCTION, AND COST EFFECTIVENESS BY
ALTERNATIVE 90
5-4 COST, VOC EMISSION REDUCTION, AND COST EFFECTIVENESS BY
ALTERNATIVE 90
5-5 MISCELLANEOUS PROCESS VENTS — MONITORING,
RECORDKEEPING, AND REPORTING REQUIREMENTS FOR
COMPLYING WITH 98 WEIGHT-PERCENT REDUCTION OF TOTAL
ORGANIC HAP EMISSIONS OR A LIMIT OF 20 PARTS PER MILLION BY
VOLUME 93
6-1 ESTIMATES OF PRICE ELASTICITY OF DEMAND 125
6-2 SUMMARY OF PRIMARY IMPACTS 135
6-3 ANALYSIS OF FINANCIAL RATIOS 137
6-4 SUMMARY OF SECONDARY REGULATORY IMPACTS 138
6-5 FOREIGN TRADE (NET EXPORTS) IMPACTS 141
6-6 ANNUAL SOCIAL COST ESTIMATES FOR THE PETROLEUM REFINING
REGULATION 145
7-1 POTENTIAL HEALTH AND WELFARE EFFECTS ASSOCIATED WITH
EXPOSURE TO HAZARDOUS AIR POLLUTANTS 151
8-1 HAP EMISSIONS AT PETROLEUM REFINERIES 160
8-2 SOURCES OF UNCERTAINTY IN CANCER RISK ASSESSMENT 163
8-3 UNCERTAINTIES IN BENEFIT ANALYSIS 163
8-4 UNIT RISK FACTORS FOR CARCINOGENIC HAPS 164
8-5 MAXIMUM INDIVIDUAL RISK AND ANNUAL CANCER INCIDENCE OF
CARCINOGENIC HAPs 165
8-6 RFCS AND NUMBER OF INDIVIDUALS EXPOSED AT OR ABOVE RFC
BY HAP 166
8-7 VOC EMISSION REDUCTIONS BY EMISSION POINT 171
8-8 BENEFITS OF VOC REDUCTIONS BY REGULATORY ALTERNATIVE . 172
VI
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8-9 VOC INCREMENTAL COST-EFFECTIVENESS OF PETROLEUM
REFINING REGULATION 174
9-1 COMPARISON OF ANNUAL BENEFITS TO COSTS FOR THE NATIONAL
PETROLEUM REFINING INDUSTRY REGULATION 179
FIGURES
Page
6-1 ILLUSTRATION OF POST-NESHAP MODEL 118
VTl
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ACRONYMS AND ABBREVIATIONS
API
ASM
bbl
bbl/d
BCA
BWON
CAA
C/E
CERA
DOC
DOE/EIA
EIA
EPA
FCCU
HAP
HEM
HON
IARC
kPa
LDAR
LEL
LPGs
1pm
MACT
MIR
MRR
MTBE
Mg
NAAQS
NESHAP
NSPS
NOX
OGJ
OMB
PADD
ppmv
RACT
RFA
RfC
RIA
SIC
SIP
SO2
SOCMI
URF
VOC
American Petroleum Institute
Annual Survey of Manufactures
One barrel; equal to 42 gallons
barrels per day
Benefit Cost Analysis
Benzene Waste Operations NESHAP (NESHAP is defined below)
Clean Air Act Amendments of 1990
cost effectiveness
Cambridge Energy Research Associates
Department of Commerce
Department of Energy/Energy Information Administration
economic impact analysis
Environmental Protection Agency
fluidized catalytic cracking unit
Hazardous Air Pollutant
Human Exposure Model
Hazardous Organic NESHAP (NESHAP is defined below)
International Agency for Research on Cancer
kilopascal
leak detection and repair
lower explosive limit
Liquefied Petroleum Gases
liter per minute
Maximum Achievable Control Technology
maximum individual risk
monitoring, recordkeeping, and reporting
Methyl tertiary butyl ether
Megagram
National Ambient Air Quality Standard
National Emission Standard for Hazardous Air Pollutants
New Source Performance Standard
nitrogen oxide
Oil and Gas Journal
Office of Management and Budget
Petroleum Administration for Defense Districts
parts per million by volume
Reasonably Available Control Technology
Regulatory Flexibility Act; also Regulatory Flexibility Analysis
reference-dose concentration
Regulatory Impact Analysis
Standard Industrial Classification
State Implementation Plan
sulfur dioxide
Synthetic Organic Chemical Manufacturing industry
unit risk factor
volatile organic compound
Vlll
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EXECUTIVE SUMMARY
ES.l PURPOSE AND STATUTORY AUTHORITY
This report analyzes the regulatory impacts of the Petroleum Refinery National
Emission Standard for Hazardous Air Pollutants (NESHAP), which is being promulgated
under Section 112 of the Clean Air Act Amendments of 1990 (CAA). This emission
standard would regulate the emissions of certain hazardous air pollutants (HAPs) from
petroleum refineries. The petroleum refineries industry group includes any facility
engaged in the production of motor gasoline, naphthas, kerosene, jet fuels, distillate fuel
oils, residual fuel oils, lubricants, or other products made from crude oil or unfinished
petroleum derivatives. This report analyzes the impact that regulatory action is likely to
have on the petroleum refining industry, and on society as a whole.
The President issued Executive Order 12866 on October 4, 1993, which requires EPA
to prepare RIAs for all "significant" regulatory actions. EPA has determined that the
petroleum refinery NESHAP is a "significant" rule because it will have an annual effect
on the economy of more than $100 million, and is therefore subject to the requirements of
Executive Order 12866. This report satisfies the requirements of the executive order. In
addition to a mandatory assessment of benefits and costs, E.O. 12866 specifies that EPA,
to the extent allowed by the CAA and court orders, demonstrate (1) that the benefits of
the NESHAP regulation will outweigh the costs and (2) that the maximum level of net
benefits (including potential economic, environmental, public health and safety and other
advantages; distnbutive impacts; and equity) will be reached. EPA has chosen two
regulatory options to be evaluated in this RIA. For each of the two options, benefits and
costs are quantified to the greatest extent allowed by available data.
ES-1
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The petroleum refinery NESHAP would require sources to achieve emission limits
reflecting the application of the maximum achievable control technology (MACT),
consistent with sections 112(d) and 112(h) of the CAA. Section 112 of the CAA provides a
list of 189 HAPs and directs the EPA to develop rules to control HAP emissions. For the
Petroleum Refinery NESHAP, EPA chose regulatory options based on control options on
an emission point basis. An emission point is defined as a point within a refinery which
emits one or more HAPs. The emission points to be regulated under the source category
for this standard are: equipment leaks, storage vessels, miscellaneous process vents, and
waste water collection and treatment systems.
ES.2 PROPOSED PETROLEUM REFINERY EMISSION STANDARD
The proposed rule, the Petroleum Refinery NESHAP, would require sources to
achieve emission limits reflecting the application of MACT. The definition of source in
the proposed standard is "the collection of emission points in HAP-emitting petroleum
refining processes within the source category." The source comprises all miscellaneous
process vents, storage vessels, wastewater collection and treatment systems, and
equipment leaks associated with petroleum refining process units that are located at a
single plant site covering a contiguous area under common control. The definition of
source is an important element of this NESHAP because it describes the specific grouping
of emission points within the source category to which each standard applies. The rule is
made up of seven different subjects: applicability, definitions, and general standards;
miscellaneous process vent provisions; storage vessel provisions; wastewater provisions;
equipment leak provisions; recordkeeping and reporting provisions; and emissions
averaging. The proposed rule outlines the chosen option for controlling HAP emissions
from each of the four emission points within a refinery source, given existing control
technology.
The applicability of the rule refers to the definition of the source within the petroleum
refinery source category. The emission standard applies to petroleum refining process
units that are part of a major source as defined in Section 112 of the CAA. EPA's initial
source category list (57 FR 31576, July 16, 1992), required by section 112(c) of the Act,
identifies categories of sources for which NESHAP are to be established. Two categories
of sources are listed in the initial source category list for petroleum refineries:
ES-2
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(1) catalytic cracking (fluid and other) units, catalytic reforming units, and sulfur plant
units and (2) other sources not distinctly listed. Based on an EPA review of information
on petroleum refineries during development of the proposed standards, it was determined
that some of the emissions points from the two listed categories of sources have similar
characteristics and can be controlled by the same control techniques. EPA determined
that it is most effective to regulate these emission points in a single regulation.
Data analyses conducted in developing the MACT floor for miscellaneous process vents
determined that combustion controls can achieve 98 percent organic HAP reduction or an
outlet organic HAP concentration of 20 ppmv or less for all vent streams. The storage
vessel provision specifies the control systems which represent the MACT floor to be
applied to storage vessels. The wastewater provisions of this rule are based on the
benzene waste operations NESHAP (BWON), which controls 75 percent of the benzene in
refinery wastewater. The wastewater streams subject to this rule include water, raw
material, intermediate product, by-product, co-product, or waste material that contains
HAPs and is discharged into an individual drain system. The equipment leak provisions
of the proposed rule are based on the negotiated equipment leak regulation included in
the Hazardous Organics NESHAP (HON) (40 CFR 63 subpart H).
The rule specifies the necessary recordkeeping and reporting requirements to verify
compliance with the MACT floor for each of the four emission points. EPA is also
proposing that emission averaging be allowed among existing miscellaneous process vents,
*
storage tanks, and wastewater streams within a refinery. Under emission averaging, a
system of emission "credits" and "debits" would be used to determine whether the source
is achieving the required emission reductions. If emissions averaging is accepted as part
of the standard, the rule would contain specific equations and procedures for calculating
credits and debits.
ES.3 NEED FOR REGULATION
One of the concerns about potential threats to human health and the environment
from petroleum refineries is the emission of HAPs. Health risks from emissions of HAPs
into the air include increases in oancer incidences and ocher toxic effects. The U.o. Office
of Management and Budget (OMB) directs regulatory agencies to demonstrate the need
ES-3
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for an economically significant rule. The RIA must show that a market failure exists and
that it cannot be resolved by measures other than Federal regulation. Externality is one
type of market failure. HAP emissions represent an externality in that refinery operation
imposes costs on others outside of the marketplace. In the case of this type of negative
externality, the market price of goods and services does not reflect the costs borne by
receptors of the HAPs generated in the refining process. With the NESHAP in effect, the
amount that refiners must incur to refine petroleum products will more closely
approximate the full social costs of production. The necessity for a uniform national
standard is based on the determination that air pollution crosses jurisdictional lines, and
uniform national standards, unlike potentially piecemeal local standards, will be more
efficient to both industry and government.
ES.4 CONTROL TECHNIQUES AND REGULATORY ALTERNATIVES
The proposed regulation would require a broad range of control techniques as options
for compliance with the standard. Combustion technology, internal floating roofs, and
product recovery devices, including internal floating roofs and vapor recovery tanks, are
all part of the technology requirements for the Petroleum Refinery NESHAP. In addition,
leak detection and repair (LDAR) programs will be used to control equipment leaks.
Based on the determination of the MACT floor for each of the four emission points,
EPA developed two regulatory alternatives. Alternative 1 is a hybrid option, referred to
as the preferred alternative, which incorporates MACT floor level control for wastewater
collection and treatment systems, storage vessels, and miscellaneous process vents, and
an option above the floor for equipment leaks. Alternative 2 includes control levels above
the floor for equipment leaks and storage vessels.
ES.5 COST ANALYSIS
The annualized compliance costs by emission point are shown in Table ES-1 for the
preferred alternative (Alternative 1) and the more stringent alternative (Alternative 2).
The total national cost of Alternative 1 in the fifth year is $81 million, compared with a
cost of $97 million for Alternative 2. The difference between the two alternatives are the
ES-4
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Annual Fifth Year Costs (1000$/yr
(1992 Dollars)
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increased costs associated with more stringent control techniques for equipment leaks and
storage vessels. In addition to provisions for the installation of control equipment, the
proposed regulation includes provisions for monitoring, recordkeeping, and reporting
(MRR). EPA estimates that the total annual cost for refineries to comply with the MRR
requirements is $30 million. The MRR requirements are outlined separately in the
proposed regulation for each emission point.
ES.6 ECONOMIC IMPACTS AND SOCIAL COSTS
An economic impact analysis (ELA) was conducted to evaluate the effect of increased
compliance costs for emission control equipment on the domestic petroleum refining
market. The partial equilibrium model used in the ELA utilized the costs for Alternative
1 which were presented in'Table ES-1 to estimate primary market impacts including
increases in price of refined petroleum products, decreases in output levels, changes in the
value of domestic shipments, and possible refinery closures. Estimated secondary effects
include labor market adjustments, energy input market changes, and foreign trade effects.
Welfare changes for consumers, producers, and society at large or the social costs of the
proposed emission controls were also evaluated. The estimated market changes from the
proposed emission controls were relatively small.
The social costs of regulation incorporate costs borne by society for pollution
abatement. The social costs reflect the opportunity cost or economic cost of resources used
in emission control. Consumers, producers, and all of society bear the costs of pollution
controls in the form of higher prices, lower quantities produced, and possible tax revenues
that may be gained or lost. The annual social cost estimates for the preferred alternative
and the more stringent alternative are shown in Table ES-2. The social costs are used
later in the RIA to conduct a benefit cost analysis.
ES-6
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TABLE ES-2. ANNUAL SOCIAL COST ESTIMATES FOR THE PETROLEUM
REFINING REGULATION
(Millions of 1992 dollars)
Social Cost Category Net Costs1
Surplus Losses for Preferred Alternative:
Change in Consumer Surplus $476.19
Change in Producer Surplus $(242.11)
Change in Residual Surplus to Society2 $(101.73)
Total Social Cost of Alternative I3 $132.35
Total Social Cost of Alternative 24 $148.35
NOTES. 'Brackets indicate negative surplus losses or surplus gains.
"Residual surplus loss to society includes adjustments necessary to equate the relevant discount rate to the social
cost of capital and to consider appropriate tax effect adjustments.
Alternative 1 includes floor controls for all emission points except equipment leaks. Option 1 is preferred to the floor
for equipment leaks because it is a less costly option than the floor.
'Alternative 2 includes Option 2 for Equipment Leaks, Option 1 for Storage Tanks, and the Floor for Miscellaneous
process vents. Emission controls at other emission points were not considered. Social costs were calculated by
adding incremental compliance costs for Alternative 2 to the social costs of Alternative 1.
ES-7
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ES.7 QUALITATIVE ASSESSMENT OF BENEFITS OF EMISSION
REDUCTIONS
This RIA presents the results of an examination of the potential health and welfare
benefits associated with air emission reductions projected as a result of implementation of
the petroleum refinery NESHAP. The proposed regulation is expected to reduce
emissions of HAPs emitted from storage tanks, process vents, equipment leaks, and
wastewater emission points at refining sites. Of the HAPs emitted by petroleum
refineries, some areclassified as VOCs, which are ozone precursors. HAP benefits are
presented separately from the benefits associated specifically with VOC emission
reductions.
The predicted emissions of a few HAPs associated with this regulation have been
classified as probable or known human carcinogens. As a result, one of the benefits of the
proposed regulation is a reduction in the risk of cancer mortality. Other benefit
categories include reduced exposure to noncarcinogenic HAPs, and reduced exposure to
VOCs.
Emissions of VOCs have been associated with a variety of health and welfare impacts.
VOC emissions, together with NOX, are precursors to the formation of tropospheric ozone.
Exposure to ambient ozone is most directly responsible for a series of respiratory related
adverse impacts.
ES.8 QUANTITATIVE ASSESSMENT OF BENEFITS
Based on existing data, the benefits associated with reduced HAP and VOC emissions
were quantified. The quantification of dollar benefits for all benefit categories is not
possible at this time because of limitations in both data and available methodologies.
Although an estimate of the total reduction in HAP emissions for various control options
has been developed for this RIA, it has not been possible to identify the speciation of the
HAP emission reductions for each type of emission point. However, an estimate of HAP
speciation for equipment leaks has been made. Using emissions data for equipment leaks
and the Human Exposure Model (HEM), the annual cancer risk caused by HAP emissions
from petroleum refineries was estimated. Generally, this benefit category is calculated as
ES-8
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the difference in estimated annual cancer incidence before and after implementation of
each regulatory alternative. Since the annual cancer incidence associated with baseline
conditions was less than one life per year, the benefits associated with the petroleum
refinery NESHAP were determined to be small. Therefore, these benefits are not
incorporated into this benefit analysis.
The benefits of reduced emissions of VOC from a MACT regulation of petroleum
refineries were quantified using the technique of "benefits transfer." Because there is an
assumption incorporated into a report completed by the Office of Technology Assessment
(OTA) from which benefits transfer values were obtained that no health benefits are
experienced in attainment areas, the VOC emission reductions used in this analysis are
defined in terms of reductions occurring only in non-attainment areas. (Nonattainment
areas are geographical locations in which the Federal ambient air quality standard
(NAAQS) for ozone has been violated.) Table ES-3 presents the VOC emission reductions
for refineries in nonattainment and attainment areas associated with each alternative.
TABLE ES-3. VOC EMISSION REDUCTIONS BY EMISSION POINT
VOC Emission Reductions bv Reeulatorv Alternative (Me/vrf
Emission Point2
Equipment Leaks
Miscellaneous Process Vents
Storage Vessels
Alternative
Nonattainment1
77,535
104,693
3,090
1
Attainment
80,266
55,161
1,408
Alternative
Nonattainment '
81,626
104,693
6,056
2
Attainment
83,471
55,161
2,760
TOTAL REDUCTION BY
ATTAINMENT STATUS
TOTAL REDUCTION BY
ALTERNATIVE
185,318
136,835
192,375
141,392
322,153
333,767
NOTES: 'VOC emission reductions include only those associated with control of the 87 refineries located in ozone
nonattainment areas.
2No further control is assumed for wastewater streams, and therefore, emission reductions associated with this
emission point is zero.
'Emission reduction estimates do not incorporate reductions occurring at new sources.
The benefit transfer ratio range for acute health impacts used in this analysis is
presented in Table ES-4. In order to quantify VOC emission reductions, these ratios were
multiplied by VOC emission reductions from petroleum refineries located in ozone non-
ES-9
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attainment areas. Estimated benefits for VOC reductions are $148.3 million for
Alternative 1 and $153.9 million for Alternative 2.
TABLE ES-4. BENEFIT PER MEGAGRAM VALUES FOR VOC REDUCTIONS
Benefits Transfer Value1 1992 Dollars/Megagram2
Average $800
Range $25 - $1,574
NOTES: 'The benefits transfer value in the table quantifies only the benefits attributable to acute health impacts.
2Values are in first quarter 1992 dollars.
ES.9 COMPARISON OF BENEFITS TO COSTS
Table ES-5 depicts a comparison of the benefits of the alternative proposals to the
compliance and social costs. A comparison of the net benefits for the alternatives and the
incremental difference in net benefits between the alternatives provides an economic basis
for rational environmental policymaking. The benefits exceed costs for each of the
alternatives. Thus, either alternative is viable and warrants consideration. However, a
comparison of the incremental difference in the two alternatives indicates that the
incremental net benefits are negative for Alternative 2. Thus, Alternative 1 provides the
greatest net benefits to society.
Based on the monetary estimates of the benefits associated with the Petroleum
Refinery NESHAP, incremental VOC cost-effectiveness values were calculated. The
results of these calculations are presented in Table ES-6. Alternative 1 can be justified as
a desirable option since the incremental VOC cost-effectiveness of implementing
Alternative 2 is significantly higher.
ES-10
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TABLE ES-5. COMPARISON OF ANNUAL BENEFITS TO COSTS FOR THE
NATIONAL PETROLEUM REFINING INDUSTRY REGULATION
(MILLIONS OF 1992 DOLLARS PER YEAR)
Benefits
Social Costs
Benefits Less Social Costs
Alternative 1
$148.3
$(132.35)
$15.95
Alternative 2
$153.9
$(148.35)2
$5.55
Incremental
Difference1
$5.6
$(16.0)
$(10.4)
NOTES: ( ) represent costs or negative values.
'The incremental difference represents the difference between Alternative 1 and Alternative 2.
'Social costs for Alternative 2 are calculated by adding incremental compliance costs to social costs of Alternative
1.
TABLE ES-6. VOC INCREMENTAL COST-EFFECTIVENESS OF PETROLEUM
REFINING REGULATION
Incremental Cost (Million $ 1992)'
Incremental Emission Reduction (Mg)
Incremental Cost Effectiveness ($/Mg)
Alternative 1
$132.35
185,318
$714/Mg
Alternative 2
$16.0
7,057
$2,267/Mg
NOTES: 'The cost estimates of each alternative reflect the total social cost of emission control.
ES-11
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1.0 INTRODUCTION
The regulation under analysis in this report, which is being promulgated under
Section 112 of the Clean Air Act Amendments of 1990 (CAA), is the Petroleum Refinery
National Emission Standard for Hazardous Air Pollutants (NESHAP). This emission
standard would regulate the emissions of certain hazardous air pollutants (HAPs) from
petroleum refineries. The petroleum refineries industry group includes any facility
engaged in producing motor gasoline, naphthas, kerosene, jet fuels, distillate fuel oils,
residual fuel oils, lubricants, or other products made from crude oil or unfinished
petroleum derivatives. This report analyzes the impact that regulatory action is likely to
have on the petroleum refining industry, and on society as a whole. Included in this
chapter is a summary of the purpose of this regulatory impact analysis (RIA), the
statutory history which preceded this regulation, and a description of the content of this
report.
1.1 PURPOSE
The President issued Executive Order 12866 on October 4, 1993. It requires EPA to
prepare RIAs for all "significant" regulatory actions. The criteria set forth in Section I of
the Order for determining whether a regulation is a significant rule are that the rule:
(1) is likely to have an annual effect on the economy of $100 million or more, or adversely
and materially affect a sector of the economy, productivity, competition, jobs, the
environment, public health or safety, or State, local, or tribal governments or
communities; (2) is likely to create a serious inconsistency or otherwise interfere with an
action taken or planned by another agency; (3) is likely to materially alter the budgetary
impact of entitlements, grants, user i'ees, or loan programs or me rx^rrcs anu \;nimauun ->\
recipients thereof; or 14) is likely to raise novel legal or policy issues arising out of" ieijat
1
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mandates, the President's priorities, or the principles set forth in the Executive Order.
EPA has determined that the petroleum refinery NESHAP is a "significant" rule because
it will have an annual effect on the economy of more than $100 million, and is therefore
subject to the requirements of Executive Order 12866.
Along with requiring an assessment of benefits and costs, E.O. 12866 specifies that
EPA, to the extent allowed by the CAA and court orders, demonstrate (1) that the benefits
of the NESHAP regulation will outweigh the costs and (2) that the maximum level of net
benefits (including potential economic, environmental, public health and safety and other
advantages; distributive impacts; and equity) will be reached. EPA has chosen two
regulatory options to be evaluated in this RIA. For each of the two options, benefits and
costs are quantified to the greatest extent allowed by available data. As stipulated in
E.O. 12866, in deciding whether and how to regulate, EPA is required to assess all costs
and benefits of available regulatory alternatives, including the alternative of not
regulating. Accordingly, the cost benefit analysis in this report is measured against the
baseline, which represents industry conditions in the absence of regulation.
1.2 LEGAL HISTORY AND STATUTORY AUTHORITY
The petroleum refinery NESHAP would require sources to achieve emission limits
reflecting the application of the maximum achievable control technology (MACT),
consistent with sections 112(d) and 112(h) of the CAA. This section provides a brief
history of Section 112 of the Act and background regarding the definition of source
categories and emission points for Section 112 standards.
Section 112 of the Act provides a list of 189 HAPs and directs the EPA to develop
rules to control HAP emissions. The CAA requires that the rules be established for
categories of sources of the emissions, rather than being set by pollutant. In addition, the
CAA establishes specific criteria for establishing a minimum level of control and criteria
to be considered in evaluating control options more stringent than the minimum control
level. Assessment and control of any remaining unacceptable health or environmental
risk is to occur 8 years after the rules are promulgated.
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For the subject NESHAP, EPA chose regulatory options based on control options on
an emission point basis. The petroleum refinery NESHAP regulates emissions of all
HAPs emitted from all emission points at both new and existing petroleum refinery
sources. An emission point is defined as a point within a refinery which emits one or
more HAPs. The emission points to be regulated under the source category for this
standard are: equipment leaks, storage vessels, miscellaneous process vents, and
wastewater collection and treatment systems.
1.3 REPORT ORGANIZATION
Chapter 2 presents a summary of the proposed regulation for the Petroleum Refinery
NESHAP. Executive Order 12866 requires EPA to prove that regulation is necessary due
to a compelling public need, such as material failures of private markets to protect or
improve the health and safety of the public, the environment, or the well-being of the
public. In order to satisfy this requirement, Chapter 3 presents the market conditions
which necessitate regulatory action. A characterization of the air emissions associated
with the petroleum refining process, and the significance of the environmental problem
which EPA intends to address through regulation are assessed. An explanation of how
the regulation is consistent with the CAA is also presented.
Chapter 4 identifies the control techniques and regulatory alternatives which were
considered for the standard. EPA's designation of control options reflects the best control
technology available to refineries, given existing technology levels. Chapter 5 presents
the approach for estimating regulatory compliance costs, the quantitative estimates of
each control option under analysis, and the issues and assumptions upon which the
estimates were based. The associated emission reductions and cost effectiveness of the
regulatory options are also presented.
Chapter 6 provides an economic profile of the petroleum refining industry, and
describes the methodology used to estimate the economic effects of a chosen hybrid option
on the industry. Predicted price, output, employment, and closure impacts are presented
as well as a quantification of the social costs of the regulatory option.
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Chapter 7 provides a qualitative description of the benefits associated with the
regulatory action. As explained in this chapter, some benefits are nonquantiflable and
therefore cannot be usefully estimated. Qualitative measures of the air related benefits
associated with a decrease in HAP emissions are presented separately from those
associated with a decrease in volatile organic compound (VOC) emissions. Benefits which
are difficult to quantify, but nevertheless essential to consider, are also identified in this
chapter.
Chapter 8 provides a quantitative assessment of those benefits which were identified
in Chapter 7. The methodology used to arrive at these estimates is outlined and any
limitations are identified. The quantitative estimates of benefits associated with risk
reductions and human health effects are presented separately.
The Executive Order requires EPA to assess both the costs and the benefits of the
intended regulation and, recognizing that some costs and benefits are difficult to quantify,
adopt a regulation only on a determination that the benefits of the regulation justify the
costs. Chapter 9 compares the annualized costs to the annualized benefits for each of the
two regulatory options in this RIA. Economic efficiency is considered within the context
of a welfare analysis, using the social costs of regulation.
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2.0 PROPOSED PETROLEUM REFINERIES EMISSION STANDARD
IN BRIEF
The discussion in this chapter briefly summarizes the requirements of the rule,
without accounting for how the provisions were selected or how emission cutoffs were
determined. The proposed rule, the NESHAP for petroleum refineries, would require
sources to achieve emission limits reflecting the application of MACT, consistent with
sections 112(d) and 112(h) of the CAA. The proposed rule would regulate the emissions of
the organic HAPs identified on the list of 189 HAPs in the CAA at both new and existing
petroleum refinery sources.
The proposed standard defines source as the collection of emission points in
HAP-emitting petroleum refining processes within the source category. The source
comprises all miscellaneous process vents, storage vessels, wastewater streams, and
equipment leaks associated with petroleum refining process units that are located at a
single plant site covering a contiguous area under common control. The definition of
source is an important element of this NESHAP because it describes the specific grouping
of emission points within the source category to which each standard applies.
2.1 THE EMISSION STANDARD IN BRIEF
The rule is made up of seven different subjects: applicability, definitions, and general
standards; miscellaneous process vent provisions; storage vessel provisions; wastewater
provisions; equipment leak provisions; recordkeeping and reporting provisions; and
emissions averaging. Each of these sections is summarized below.
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2.1.1 Applicability of the Petroleum Refinery NESHAP
The applicability of the rule refers to the definition of the source within the petroleum
refinery source category. Petroleum refineries are defined as facilities engaged in
producing motor gasoline, naphthas, kerosene, jet fuels, distillate fuel oils, residual fuel
oils, or other transportation fuels, heating fuels, or lubricants from crude oil or unfinished
petroleum derivatives. The emission standard applies to petroleum refining process units
that are part of a major source as defined in Section 112 of the CAA. EPA's initial source
category list (57 FR 31576, July 16, 1992), required by section 112(c) of the Act, identifies
categories of sources for which NESHAP are to be established. This list includes all
categories of major sources of HAPs known to the EPA at this time, and all area source
categories for which findings of adverse effects warranting regulation have been made.
Two categories of sources are listed in the initial source category list for petroleum
refineries: (1) catalytic cracking (fluid and other) units, catalytic reforming units, and
sulfur plant units and (2) other sources not distinctly listed.
Based on an EPA review of information on petroleum refineries during development
of the proposed standards, it was determined that some of the emissions points from the
two listed categories of sources have similar characteristics and can be controlled by the
same control techniques. In particular, miscellaneous process vents emitting organic
HAPs, storage vessels, wastewater streams, and leaks from equipment in organic HAP
service within catalytic cracking units, catalytic reforming units, and sulfur plant units
are similar to emission points from the other process units at petroleum refineries. EPA
determined that it is most effective to regulate these emission points in a single
regulation. (The EPA intends to amend the source category list when the NESHAP under
analysis is promulgated.) Upon revision, all emission points regulated by the subject
NESHAP will be in a single source category.
2.1.2 Miscellaneous Process Vent Provisions
Miscellaneous process vents are defined to include streams containing greater than
20 parts per million by volume (ppmv) of organic HAP that are continuously or
periodically discharged from petroleum refining process units. This emission point
excludes vents that are routed to the refinery fuel gas system and vents from fluidized
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catalytic cracking unit (FCCU) catalyst regeneration, catalytic reformer catalyst
regeneration, and sulfur plants. The miscellaneous process vent provisions require the
owner or operator of a miscellaneous process vent to reduce emissions of organic HAP by
98 percent or to 20 ppmv of HAP, or to reduce emissions using a flare meeting the
requirements of § 63.11(b) of the NESHAP General Provisions (40 CFR 63 subpart A).
Data analyses conducted in developing the MACT floor for miscellaneous process vents
determined that combustion controls can achieve 98 percent organic HAP reduction or an
outlet organic HAP concentration of 20 ppmv or less for all vent streams.
2.1.3 Storage Vessel Provisions
A storage vessel is defined as a tank or other vessel storing feed or product for a
petroleum refining process unit that contains organic HAPs. The storage vessel
provisions do not apply to the following: (1) vessels permanently attached to motor
vehicles, (2) pressure vessels designed to operate in excess of 204.9 kPa (29.7 psia),
(3) vessels with capacities smaller than 40 m3 (10,500 gal), and (4) wastewater tanks. The
storage provisions define two groups of vessels: Group 1 vessels are vessels with a design
storage capacity and a maximum true vapor pressure above the specified values (see
definitions section); Group 2 vessels are all vessels that are not Group 1 vessels.
The proposed rule specifies the control systems to be applied to each of the two types
of storage vessels. The storage provisions require that one of the following control
systems be applied to Group 1 storage vessels: (1) an internal floating roof with proper
seals; (2) an external floating roof with proper seals; (3) an external floating roof
converted to an internal floating roof with proper seals; or (4) a closed vent system with a
95-percent efficient control device. Details are provided in the proposed rule on the types
of seals required. Vessels at new sources are also required to meet specifications for
fittings. Monitoring and compliance provisions for Group 1 vessels include periodic visual
inspections of vessels and roof seals, as well as internal inspections. No controls or
inspections are required for Group 2 storage vessels.
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2.1.4 Wastewater Provisions
The wastewater provisions of this rule are based on the benzene waste operations
NESHAP (BWON), using benzene as a surrogate for all HAPs from wastewater in
petroleum refineries. EPA research concluded that benzene is a good indicator of the
presence of other HAPs. The wastewater streams subject to this rule include water, raw
material, intermediate product, by-product, co-product, or waste material that contains
HAPs and is discharged into an individual drain system. The wastewater provisions
define two groups of wastewater streams. Group 1 streams are those that contain a
concentration of at least 10 parts per million in water (ppmw) of benzene, have a flow rate
of at least 0.02 liter per minute (1pm), are located at a refinery with a total annual
benzene loading of at least 10 megagrams per year and are not exempt from control
requirements under 40 CFR 61 subpart FF (the BWON). Group 2 streams are
wastewater streams that are not Group 1.
The wastewater provisions of the rule refer to the BWON, which requires owners or
operators of a Group 1 wastewater stream to reduce benzene mass by 99 percent using
suppression followed by steam stripping, biotreatment, or other treatment processes. The
performance tests required for wastewater streams and treatment operations to verify
that the control devices achieve the desired performance are included in the BWON, as
are the monitoring, reporting, and recordkeeping provisions necessary to demonstrate
compliance. No controls or monitoring are required for Group 2 wastewater streams.
2.1.5 Equipment Leak Provisions
The equipment leak standards for the petroleum refinery NESHAP refer to the
negotiated equipment leak regulation included in the Hazardous Organics NESHAP
(HON) (40 CFR 63 subpart H). The standards for the petroleum refinery NESHAP differ
from the HON in the following ways: only one leak definition for pumps in phase III; leak
definition for pumps is equal to or greater than 2,000 ppmv; leak definitions for valves in
phases II and III; monitoring frequencies for valves; connectors are not required to be
monitored, but sources may choose to monitor valves less frequently in exchange for
monitoring of connectors.
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2.1.6 Recordkeeping and Reporting Provisions
The rule requires petroleum refineries to keep records of information necessary to
document compliance for five years and submit the following four types of reports to the
Administrator: (1) an initial notification, (2) a notification of compliance status,
(3) periodic reports, and (4) other reports. There are no requirements for reporting
compliance with wastewater provisions other than the reports already required by the
BWON. The initial notification report must list the petroleum refining process units that
are subject to the rule. The notification of compliance status report contains the
information necessary to demonstrate that compliance has been achieved. Periodic
reports must include information required to be reported under the recordkeeping and
reporting provisions for each emission point. Other reports must be submitted as
required by the provisions for each kind of emission point, including requests for
extensions of time for repair of storage vessels and notifications of storage vessel
inspections.
2.1.7 Emission Averaging
The EPA is proposing that emission averaging be allowed among existing
miscellaneous process vents, storage tanks, and wastewater streams within a refinery.
EPA decided against allowing equipment leaks to be included in emissions averaging
because of the complexity and cost of developing a scheme to include equipment leaks in
emissions averaging and the likelihood of a high compliance determination burden for
both the industry and enforcement agencies. Under emission averaging, a system of
emission "credits" and "debits" would be used to'determine whether the source is
achieving the required emission reductions. An owner or operator who generates an
emission debit must control other emission points to a level more stringent than is
required by the regulation to generate an emission credit. Annual emission credits must
exceed emission debits for a source to be in compliance. The rule would contain specific
equations and procedures for calculating credits and debits.
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presented in Chapter 6.) It is estimated that approximately 192 petroleum refineries
would be required to apply controls by the proposed standards. Throughout this report,
impacts are presented relative to the baseline, which represents the level of control in the
absence of the proposed rule. The estimates include the impacts of applying control to:
(1) existing process units and (2) additional process units that are expected to begin
operation over a 5-year period. Thus, the estimates represent annual impacts occurring
in the fifth year. Based on a review of annual construction projects over the years 1988 to
1992 listed in the Oil and Gas Journal, it was assumed that 34 new process units would
be constructed each year over a 5-year period.
3.4.1.1 Allocation of Resources. There will be improved allocation of resources
associated with petroleum refining. Specifically, more of the costs of the harmful effects
of the refining process will be internalized by the producers. This, in turn, will affect
consumers' purchasing decisions. To the extent these newly-internalized costs are then
passed along to the end users of refined petroleum products, and to the extent that these
end users are free to buy as much or as little of the petroleum products as they wish, they
will purchase less (relative to their purchases of other competing services). If this same
process of internalizing negative externalities occurs throughout the entire petroleum
refining industry, an economically optimal situation is approached. This is the situation
in which the marginal cost of resources devoted to petroleum refining equals the marginal
value of the products to the end users of the products. Although there are uncertainties
in this progression of impacts, in the aggregate and in the long run, the NESHAP will
move society toward this economically optimal situation.
3.4.1.2 Emissions Reductions. The environmental impact of the rule includes the
reduction of HAP and VOC emissions. Under the proposed rule, it is estimated that the
emissions of HAP from refineries would be reduced by 53,000 Mg/yr, and the emissions of
VOC would be reduced by 350,000 Mg/yr. Emission levels of other air pollutants (CO,
NOX, and SO2) were not quantified. It is important to note that the possibility exists for
slight increases above existing emission levels would result from the combustion of fossil
fuel as part of control device operations. Additional emissions of these pollutants would
be attributable to the additional fuel burned to generate energy for operation
of compressors for ducting miscellaneous process vent streams to control devices.
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EPA has devised a system, which was adapted from one developed by the
International Agency for Research on Cancer (IARC), for classifying chemicals based on
the weight-of-evidence.2 Of the HAPs listed in Table 3-2, only benzene is classified as
group A, or a known human carcinogen. This means that there is sufficient evidence to
support that the chemical causes an increased risk of cancer in humans. Benzene is a
concern to the EPA because long term exposure to this chemical has been known to cause
leukemia in humans. While this is the most well known effect, benzene exposure is also
associated with aplastic anemia, multiple myeloma, lymphomas, pancytopenia,
chromosomal breakages, and weakening of bone marrow (53 FR 28504; July 28, 1988).
Cresols and naphthalene are considered to be group C or possible human carcinogens.
For these chemicals, there is either inadequate data or no data on human carcinogenicity,
and there is limited data on animal carcinogenicity. Therefore, while cancer risk is
possible, there is not sufficient evidence to support that these chemicals will cause
increased cancer risks in humans. The remaining HAPs in Table 3-2 are noncarcinogens.
Though they do not cause cancer, they are considered hazardous because of the other
significant adverse health effects with which they are associated.
Emissions of VOC have been associated with a variety of health impacts. VOCs,
together with NOX, are precursors to the formation of tropospheric ozone. It is exposure
to ozone that is responsible for adverse respiratory impacts, including coughing and
difficulty in breathing. Repeated exposure to elevated concentrations of ozone over long
periods of time may also lead to chronic, structural damage to the lungs.
3.4 CONSEQUENCES OF REGULATORY ACTION
This section provides a preliminary assessment of the consequences of the attainment
of EPA emission reduction objectives, and the likely consequences if these objectives are
not met.
3.4.1 Consequences if EPA's Emission Reduction Objectives are Met
This section presents the environmental, cost, and ener-jy use impacts resulting :'rcm
the control of HAP emissions under the proposed rule. (Economic impacts will be
17
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None of these reasons, by itself, provides overriding justification for Federal action in
the case at hand. Collectively, however, the reasons argue against reliance on State and
local action to control HAP emissions from petroleum refineries.
Citizens, as well as EPA, may sue State and local governments to force them to
control HAP emissions from petroleum refineries. Litigation under both the CAA and
RCRA.is possible. However, EPA has not explored ways of improving the judicial route so
that it might serve as a substitute for action under Section 112 of the CAA.
3.3 ENVIRONMENTAL FACTORS WHICH NECESSITATE REGULATION
Regulation of the petroleum refining industry is necessary because of the adverse
health effects caused by human exposure to HAP emissions. This section characterizes
the emissions attributable to petroleum refining and summarizes the adverse health
effects associated with human exposure to HAP emissions.
3.3.1 Air Emission Characterization
The HAP emissions from the emission points that comprise the source in this source
category are all organic HAPs. Therefore, given the source and source category
definitions, the provisions of this NESHAP apply to organic HAPs listed in section 112(b)
of the CAA. HAP emissions from refineries are composed of a few chemicals, including
benzene, toluene, xylenes, ethylbenzene, and hexane. There is a narrower range of
variation in emission stream composition among petroleum refinery emission points than
there is in some other source categories (e.g., Synthetic Organic Chemical Manufacturing
Industry (SOCMI) emission points regulated by the HON). However, the different HAPs
emitted have different toxicities, and there are some variations in the concentrations of
individual HAPs and the emission release characteristics of different emission points.
Baseline emissions from petroleum refineries were estimated using information
published in the Oil and Gas Journal (OGJ) and provided by petroleum refineries in
response to information collection requests and questionnaires sent out under section 114
of the CAA. Table 3-1 presents the baseline HAP and VOC emissions for each of the four
kinds of emission points controlled by this proposed rule. Emission levels of other air
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Because of the wide diversity in the size and number of petroleum refineries, however,
conditions of natural monopoly do not represent a market failure for this industry.
3.1.3 Inadequate Information
The third category "of potential market failure that sometimes is used to justify
government regulation is inadequate information. Some petroleum refineries can reduce
costs by installing air pollution control devices, or reducing leaks. Due to lack of
information, some of these refineries do not install such systems. The NESHAP will
require the collection of information that may give a particular petroleum refiner enough
data to make an informed decisiori on whether or not control devices are the best option.
3.2 INSUFFICIENT POLITICAL AND JUDICIAL FORCES
There are a variety of reasons why many emission sources, in EPA's judgment, should
be subject to reasonably uniform national standards. The principal reasons are:
• Air pollution crosses jurisdictional lines.
• The people who breathe the air pollution travel freely, sometimes coming in
contact with air pollution outside their home jurisdiction.
• Harmful effects of air pollution detract from the nation's health and welfare
regardless of whether the air pollution and harmful effects are localized.
• Uniform national standards, unlike potentially piecemeal local standards, are not
likely to create artificial incentives or artificial disincentives for economic
development in any particular locality.
• One uniform set of requirements and procedures can reduce paperwork and
frustration for firms that must comply with emission regulations across the
country.
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3.1.1 Air Pollution as an Externality
Air pollution is an example of a negative externality. This means that, in the absence
of government regulation, the decisions of generators of air pollution do not fully reflect
the costs associated with that pollution. For a petroleum refiner, air pollution from the
refinery is a product or by-product that can be disposed of cheaply by venting it to the
atmosphere. Left to their own devices, many refiners treat air as a free good and do not
fully "internalize" the damage caused by emissions. This damage is born by society, and
the receptors - the people who are adversely affected by the pollution ~ are not able to
collect compensation to offset their costs. They cannot collect compensation because the
adverse effects, like increased risks of morbidity and mortality, are non-market goods,
that is, goods that are not explicitly and routinely traded in organized free markets.
HAP emissions represent an externality in that refinery operation imposes costs on
others outside of the marketplace. In the case of this type of negative externality, the
market price of goods and services does not reflect the costs, borne by receptors of the
HAPs, generated in the refining process. Government regulation can be used to improve
the situation. For example, the NESHAP will force petroleum refiners to reduce the
quantity of HAPs that they emit. With the NESHAP in effect, the amount that refiners
must incur to refine petroleum products will more closely approximate the full social costs
of production. In the long run, refiners will be forced to increase prices of the petroleum
products sold in order to cover total production costs. Thus, prices will rise, consumers
accordingly will reduce their demand for petroleum products, and as a result, fewer
petroleum products will be provided to the market. The more the costs of pollution are
internalized by the petroleum refiners, the greater the improvement in the way the
market functions.
3.1.2 Natural Monopoly
Natural monopoly exists where a market can be served at lowest cost only if
production is limited to a single producer. The refining industry is characterized by some
of the same attributes which define monopolistic markets, including economies of scale,
and barriers to entry due to the heavy up-front capital needed for refinery construction.
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3.0 NEED FOR REGULATION
One of the concerns about potential threats to human health and the environment
from petroleum refineries is the emission of HAPs. Health risks from emissions of HAPs
into the air include increases in cancer incidences and other toxic effects. This chapter
discusses the need for and consequences of regulating of HAP emissions from petroleum
refineries.
Section 3.1 presents the conditions of market failure which necessitate government
intervention. Section 3.2 identifies the insufficiency of political and judicial forces to
control the release of toxic air pollutants from petroleum refineries. Section 3.3 provides
a characterization of the HAP and VOC emissions from petroleum refineries. These
values represent the baseline against which the emission reductions associated with the
regulatory options will be compared in the cost effectiveness calculations presented in
Chapter 5 of this report. Section 3.3 also provides more detail on the health risks of these
pollutants. Lastly, Section 3.4 identifies the consequences of regulating versus the option
of not regulating.
3.1 MARKET FAILURE
The U.S. Office of Management and Budget (OMB) directs regulatory agencies to
demonstrate the need for a major rule.1 The RIA must show that a market failure exists
and that it cannot be resolved by measures other than Federal regulation. Market
failures are categorized by OMB as externalities, natural monopolies, or inadequate
information. The following paragraphs address the three categories of market failure.
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TABLE 3-2. BASELINE SPECIATED HAP EMISSIONS FROM EQUIPMENT LEAKS
Baseline Emissions
Hazardous Air Pollutant (Mg/yr)
2, 2, 4-Trimethylpentane 5,660
Benzene 1,904
Ethyl Benzene 2,377
Hexane 5,486
Naphthalene 1,539
Toluene 8,049
Xylenes 7,597
Hydrogen Fluoride 2,764
Phenol 1,243
Cresols 603
MTBE 5,840
Hydrogen Chloride 199
Methyl Ethyl Ketone 2,117
TOTAL 45,380
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pollutants (CO, NOX, and SO2) were not quantified. Baseline emissions include emissions
from both new and existing sources. Baseline HAP and VOC emissions take into account
the current estimated level of emissions control, based on questionnaire responses
submitted by refineries, and on related regulations which have already been promulgated.
(These regulations are summarized later in this chapter.) As a result, baseline HAP and
VOC emissions reflect the level of control that would be achieved in the absence of the
proposed rule.
TABLE 3-1. NATIONAL BASELINE VOC AND HAP EMISSIONS BY EMISSION
POINT
Emission Point
Miscellaneous Process Vents
Equipment Leaks
Storage Vessels
Wastewater Collection and Treatment
TOTAL
Baseline
HAP
9,800
52,000
9,300
10,000
81,100
Emissions (Mg/yr)
VOC
190,000
190,000
111,000
10,000
501,000
Given available data, it has not been possible to identify individual HAP emissions for
each type of emission point. Speciated HAP emissions were available only for equipment
leaks. Since HAP emissions from equipment leaks account for nearly 65 percent of total
HAP emissions at petroleum refineries, however, this speciation is valuable for
approximating the minimum level of cancer risk related to refinery emissions. Speciated
HAP emissions for equipment leaks are presented in Table 3-2.
3.3.2 Harmful Effects of HAPs
Exposure to HAPs has been associated with a variety of adverse health effects. Direct
exposure to HAPs can occur through inhalation, soil ingestion, the food chain, and dermal
contact. Only health effects associated with HAP emissions are addressed in these
NESHAPs. Many HAPs are classified as known human carcinogens. Other HAPs have
not been classified as known human carcinogens. Exposure to these pollutants, however,
may still result in adverse health ana welfare impacts to numan populations.
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3.4.1.3 Costs and Benefits. The cost impact of the rule includes the capital cost of
new control equipment, and the associated operation and maintenance cost. Generally,
the cost impact also includes any cost savings generated by reducing the loss of valuable
product in the form of emissions. Under the proposed rule, it is estimated that total
capital costs would be $188 million (first quarter 1992 dollars) and total annual costs
would be $81 million (first quarter 1992 dollars). Table 3-3 presents the capital and
annual cost impact of the regulation for each of the four emission points as well as the
national totals.
TABLE 3-3. NATIONAL CONTROL COST IMPACTS OF PREFERRED ALTERNATIVE
IN THE FIFTH YEAR
Emission Point
Miscellaneous Process Vents
Equipment Leaks
Storage Vessels
Wastewater Collection and Treatment
TOTAL
Total Capital Costs
(Million Dollars)
$ 31.0
$ 130.0
$ 27.0
b
$ 188.0
Total Annual Costs
(Million Dollars)
$ 11.4
$ 65.8
$ 3.8
b
$ 81.0
NOTES: "The MACT level of control is no additional control.
3.4.1.4 Energy Impacts. Increases in energy use were estimated for operating control
equipment that would be required by the proposed standards (compressors for ducting
miscellaneous process vent streams to control devices). The estimated energy use
increase in the fifth year would be 13 million kw-hr/yr of electricity or 10 barrels of oil
equivalent.3
3.4.1.5 State Regulation and New Source Review. State regulatory programs will be
strengthened. Some components of the petroleum refining industry have already been
subject to various Federal, State, and local air pollution control rules. Although these
existing rules will remain in effect, the petroleum refinery NESHAP will provide
comprehensive coverage of the petroleum refinery sources not covered by the existing
rules. Recognition that the NESHAP is effectively reducing emissions will expedite the
State process of reviewing applications for new petroleum refineries and issuing permits
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for their construction and operation. State regulations will also be uniform, and the
disadvantages of the piecemeal approach to emission regulation will be avoided.
3.4.1.6 Other Federal Programs. The regulations which affect the petroleum
refining industry which have already been promulgated include a number of NSPS,
(40 CFR 60): subpart J - Standards of Performance for Petroleum Refineries; subparts K,
Ka, and Kb - various standards of performance for storage vessels for petroleum liquids;
subpart GGG - Standards of Performance for Equipment Leaks of VOC in Petroleum
Refineries, and the Standards of Performance for VOC Emissions from Petroleum
Refinery Wastewater Systems. The regulations that have already been promulgated also
include a number of NESHAPs, (40 CFR 61): subpart J - NESHAP for Equipment Leaks
(Fugitive Emission Sources) of Benzene; subpart Y - NESHAP for Benzene Emissions
from Benzene Storage Vessels; and subpart FF - NESHAP for Benzene Waste Operations
(BWON).
This petroleum refinery NESHAP generally covers refinery processes that produce
petroleum liquids (such as motor gasoline, naphthas, and kerosene) for use as fuels.
Often, products of refinery processes are used to make synthetic organic chemicals other
than fuels. The petroleum refinery NESHAP will not cover chemical manufacturing
process units that are covered under the SOCMI source category, even if these units are
located at a refinery site. A SOCMI chemical manufacturing process unit that is located
at a refinery and produces one or more of the chemicals listed in the HON (40 CFR 63
subpart F, table 1) as a single chemical product or as a mixed chemical used to produce
other chemicals would be considered a SOCMI process and would be subject to the HON
rather than to the petroleum refinery NESHAP.
3.4.2 Consequences if EPA's Emission Reduction Objectives are Not Met
The most obvious consequence of failure to meet EPA's emission reduction objectives
would be emissions reductions and benefits that are not as large as is projected in this
report. However, costs are not likely to be as large either. Whether it is noncompliance
from ignorance or error, or from willful intent, or simply slow compliance due to owners
and/or operators exercising legal delays, poor compliance can save some refineries money.
Unless States respond by allocating more resources into enforcement, then poor
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compliance could bring with it smaller aggregate nationwide control costs. EPA has not
included an allowance for poor compliance in its estimates of emissions reductions, due to
the fact that poor compliance is unlikely. Also, if the emission control devices degraded
rapidly over time or in some other way did not function as expected, there could be a
misallocation of resources. This situation is very unlikely, given that the NESHAP is
based on demonstrated technology.
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REFERENCES
1. U.S. Office of Management and Budget. Regulatory Impact Guidance. Appendix V of
Regulatory Program of the United States Government. April 1, 1991 - March 31,
1992.
2. U.S. Environmental Protection Agency. The Risk Assessment Guidelines of 1986.
Office of Health and Environmental Assessment. Washington, DC. August 1987.
3. U.S. Environmental Protection Agency. National Emission Standards for Hazardous
Air Pollutants for Source Categories: Petroleum Refineries. Proposed Rule and
Notice of Public Hearing. Draft. Section IV. February 1994.
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4.0 CONTROL TECHNIQUES AND REGULATORY ALTERNATIVES
The proposed regulation would require a broad range of control techniques as options
for compliance with the standard. Combustion technology, internal floating roofs, and
product recovery devices, including internal floating roofs and vapor recovery tanks, are
all part of the technology requirements for the Petroleum Refinery NESHAP. Leak
detection and repair (LDAR) programs will be used to control equipment leaks. This
chapter does not attempt to be comprehensive in explaining the technology and
techniques used to control air toxics emissions under this proposed regulation; it does
attempt to survey what technologies and techniques are being used and how effective they
are.
Petroleum refineries differ in the number, combination, and design of their process
units; the production capacities of their refining processes; the type and characteristics of
crude oil they use; and the control equipment they use. Consequently, actual emissions
and characteristics of petroleum refinery facilities vary widely from refinery to refinery.
This diversity affected the approach used to define the MACT floor for existing and new
sources.
This chapter briefly explains the control technologies which are available to refineries
to comply with the proposed regulation. At the end of this chapter, a summary of the two
regulatory alternatives is provided.
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4.1 CONTROL TECHNIQUES
This section presents a summary of the control equipment available for combustion
technology, product recovery devices, LDAR programs, and internal floating roofs. Each
type of control is presented separately.
4.1.1 Combustion Technology
Combustion control devices, unlike noncombustion control devices, alter the chemical
structure of the VOC. Destruction of the VOC by combustion is complete if all VOCs are
converted to CO2 and water. Incomplete combustion results in some of the VOC
remaining unaltered or being converted to other organic compounds such as aldehydes or
acids. If chlorinated or sulfur-containing compounds are present in the mixture, the
products of complete combustion include the acid components HC1 or SO2, respectively, in
addition to water and carbon dioxide. Available combustion technology options include
incinerators, flares, and boilers and process heaters. The process and applicability of each
control type are summarized in the following sections.
4.1.1.1 Incinerators. Incineration is one of the best known methods of industrial gas
waste disposal. It is a method of ultimate disposal, that is, the constituents to be
controlled in the waste gas stream are converted rather than collected. Provided proper
engineering design is used, incineration can eliminate the desired organic chemicals in a
gas stream safely and cleanly.
The heart of an incinerator is a combustion chamber in which the VOC-containing
waste stream is burned. The temperature required for combustion is much higher than
the temperature of the inlet gas, so energy is usually supplied to the incinerator to raise
the waste gas temperature. This is accomplished by adding auxiliary fuel (usually
natural gas).
The amount of auxiliary fuel required can be decreased and energy efficiency
increased by providing heat exchange between the inlet stream and the effluent stream.
The effluent stream containing the products of combustion, along with any inerts that
may nave oeen present in or aaaea to the miet stream, can he usea ~<> preheat Lne
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incoming waste stream, auxiliary air, or both via a "primary", or recuperative, heat
exchanger.
Auxiliary air may be required for combustion if the requisite oxygen is not available
in the inlet gas stream. Most industrial gases that contain VOCs are dilute mixtures of
combustible gases in air. During the air oxidation reactor and distillation processes, the
waste gas stream is deficient in air.
Important in the design and operation of incinerators is the concentration of
combustible gas in the waste gas stream. Having a large amount of excess air (i.e., in
excess of the required stoichiometric amounts) may be costly, but any mixture within the
flammability limits, on either the fuel-rich or fuel-lean side of the stoichiometric mixture,
is considered a fire hazard as a feed stream to the incinerator. Therefore, some waste gas
streams are diluted with air before incineration, even though this requires more fuel in
the incinerator. There are two types of incinerators: thermal and catalytic. While much
of what was discussed above applies to both, there are important differences in their
design and operation.
4.1.1.1.1 Thermal Incinerators. As is true of other combustion control devices,
thermal incinerators operate on the principle that any VOC heated to a high enough
temperature in the presence of sufficient oxygen will be oxidized to CO2 and water. The
theoretical temperature for thermal oxidation depends on the properties of the VOC to be
combusted. There is great variation in theoretical combustion temperatures among
different VOCs.
There are three requirements that must be met for a thermal incinerator to be
considered efficient: 1) a high enough temperature within the combustion chamber to
enable oxidation of the organic compounds to proceed rapidly to completion; 2) enough
turbulence for good mixing of the hot combustion products from the burner, the
combustion air, and the organic compounds; and 3) sufficient residence time for oxidation
to reach completion.
A typical thermal incinerator i-s i refractory-lined chamber containing a burner >r -e<,
of burners at one end. Entering gases are mixed with the process vent streams and the
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inlet air in a premixing chamber. Then the stream of gases passes into the main
combustion chamber. This chamber is designed to allow the mixture enough time at the
required combustion temperature for complete oxidation (usually from 0.3 to 1.0 second).
A heat recovery section is often added to increase energy efficiency. Often, inlet
combustion air is preheated; if this occurs, insurance regulations require the VOC
concentration must be maintained below 25 percent of the lower explosive limit (LED to
minimize the possibility of explosions. Concentrations from 25 to 50 percent are
permitted given continuous monitoring by LEL monitors.
The required level of VOC control of the waste gas that must be achieved within the
time it spends in the thermal combustion chamber dictates the reactor temperature. The
shorter the residence time, the higher the reactor temperature must be. Once the unit is
designed and built, the residence time is not easily changed, so that the required reaction
temperature becomes a function of the particular gaseous species and the desired level of
control. These required combustion reaction temperatures cannot be calculated a priori,
although incinerator vendors can provide guidelines based on their extensive experience.
Predictions of these temperatures are further complicated by the fact that most process
vent streams are mixtures of compounds.
Good mixing is also important, particularly in determining destruction efficiency.
Even though it cannot be measured, mixing is a factor of equal or even greater
importance than other parameters such as temperature. The most feasible and efficient
way to improve the mixing in an incinerator is to adjust it after start-up.
Other parameters affecting thermal incinerator performance are the heat content of
the vent stream, the water content of the stream, and the amount of excess combustion
air (the amount of air above the stoichiometnc air needed for combustion). Combustion of
a vent stream with a heat content less than 1.9 MJ/m3 (52 BTU/scf) usually requires
burning supplemental fuel to maintain the desired combustion temperature.
The maximum achievable VOC destruction efficiency decreases with decreasing inlet
VOC concentration because combustion is slower at lower inlet concentrations. Therefore,
a VOC weight percentage reduction based on the mass rate of VOC exiting the control
device versus the mass rate of VOC entering the device is appropriate for vent streams
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with VOC concentrations above approximately 2,000 ppmv (which corresponds to 1,000
ppmv VOC in the incinerator inlet stream since air dilution is typically 1:1).
Thermal incinerators are technically feasible control devices for most vent streams.
They are not recommended, however, for vent streams with potentially excessive
fluctuations in flow rate (process upsets, for example), and for vent streams containing
halogens. The former case would require a flare (see Section 4.1.1.2) and the latter case
would require additional equipment such as acid gas scrubbers (see Section 4.1.2).
4.1.1.1.2 Types of Thermal Incinerators. The very simplest type of thermal
incinerator is the direct flame incinerator, which is made up of only the combustion
chamber. Energy recovery devices such as a waste gas preheater and a heat exchanger
are not included with this type of incinerator.
A second type of thermal incinerator is the recuperative model. Recuperative
incinerators use the exit (product) gas to preheat the incoming feed stream, combustion
air, or both via a heat exchanger. These heat exchangers can recover up to 70 percent of
the energy (or enthalpy) in the product gas. The two types of heat exchangers commonly
used for this purpose and many others are plate-to-plate and shell-and-tube. Plate-to-
plate exchangers can be built to achieve a variety of efficiencies and offer high efficiency
energy recovery at lower cost than shell-and-tube designs. But when gas temperatures
exceed 520 degrees Celsius, shell-and-tube exchangers usually have lower purchase costs
than plate-to-plate designs. Moreover, shell-and-tube exchangers offer better long-term
structural reliability than plate-to-plate units.
Occasionally it is desired to recover some of the energy added by auxiliary fuel in the
traditional thermal units (but not recovered in preheating the feed stream). Additional
heat exchangers can be added to provide process heat in the form of low pressure steam
or hot water for on-site application. The need for this higher level of energy recovery will
be dependent upon the plant site. The additional heat exchanger is often provided by the
incineration unit vendor.
A third type of thermal incinerator is the regeneracive incinerator. This type of
incinerator uses direct contact heat exchangers constructed of a ceramic material that can
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tolerate the high temperatures needed to achieve ignition of the waste stream. The
concept behind this incinerator type is that the traditional approach to energy recovery in
thermal units still requires a significant amount of auxiliary fuel to be burned in the
combustion chamber when waste gas heating values are too low to sustain the desired
reaction temperature at the moderate preheat temperature employed. Under these
conditions, additional fuel savings can be realized in units with more complete transfer of
exit stream energy. The regenerative incinerator serves this purpose.
In this type of incinerator, the inlet gas first passes through a hot ceramic bed
thereby heating the steam to its ignition temperature. After the hot gases react and
release energy in the combustion chamber, the gases pass through another ceramic bed,
thereby heating it to the levels of the combustion chamber outlet temperature. The
process flows are then switched, now feeding the inlet stream to the hot bed. This cyclic
process affords very high energy recovery (up to 95 percent).
4.1.1.1.3 Catalytic Incinerators. A catalyst promotes oxidation of some VOCs at
a lower temperature than that required for thermal incineration. The catalyst increases
the rate of the chemical reaction without becoming permanently altered itself. Catalysts
typically used for VOC incineration include platinum and palladium. These catalysts
work well for most organic streams, but are not tolerant of compounds containing
halogens such as chlorine and sulfur. Among the catalysts that have been developed that
are effective in the presence of these halogens are chromia/alumina, cobalt oxide, and
copper oxide/manganese oxide. Inert substrates are coated with thin layers of these
materials to provide maximum surface area for contact with the VOC in the vent stream.
Compounds containing elements such as lead, arsenic, and phosphorus should, in general,
be considered poisons for most oxidation catalysts. In addition, particulate matter,
including dissolved minerals in aerosols, can rapidly blind (deactivate) the pores of
catalysts and deactivate them over time. Because essentially all the active surface of the
catalyst is contained in relatively small pores, the particulate matter need not be large to
blind the catalyst.
For optimal operation, the volumetric gas flow rate and the concentration of
combustibles (in this case, VOCs) should be constant. Large fluctuations in the flow rate
will cause the conversion of the VOCs to fluctuate also. Changes in the concentration or
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type of organic compounds in the gas stream can also affect the overall conversion of the
VOC contaminants. Most changes in flow rate, organic concentration, and chemical
composition are generally the result of upsets in the manufacturing process generating
the waste gas stream.
Applicability of catalytic incinerators for control of VOCs is limited by the catalyst
deactivation sensitivity to the characteristics of the inlet gas stream. The vent stream to
be combusted should not contain materials that can poison the catalyst or deposit on and
block the reactive sites on the catalyst surface. In addition, catalytic incinerators are
unable to handle high inlet concentrations of VOC or very high flow rates. Catalytic
incineration is generally useful for concentrations of 50 to 10,000 ppmv, if the total
concentration is less than 25 percent of the LEL and for flow rates of less than 2,820
m3/min (100,000 scfm).
4.1.1.1.4 Types of Catalytic Incinerators. One type of catalytic incinerator is
fixed-bed. Fixed-bed incinerators come in two varieties, depending on the type of catalyst
used: the monolith and packed-bed. The monolith catalyst is the most widespread
method of contacting the VOC-containing stream with the catalyst. In this scheme, the
catalyst is a porous solid block containing parallel, non-intersecting channels aligned in
the direction of the gas flow. Monolith catalysts offer the advantages of minimal attrition
due to thermal expansion/contraction during startup/shutdown and low overall pressure
drop.
A second contacting scheme is a simple packed-bed in which catalyst particles are
supported either in a tube or in shallow trays through which the gases pass. The tray
type arrangement is the more common packed-bed scheme due to the use of pelletized
catalysts. This tray arrangement is preferred because pelletized catalysts can handle
inlet streams containing contaminants such as phosphorus or silicon. The tube
arrangement is not used widely due to its inherently high pressure drop compared with a
monolith, and the breaking of catalyst particles due to thermal expansion when the
confined catalyst bed is heated/cooled during startup/shutdown.
A third contacting pattern betwpen the ,cras and cntrJvst ..s i Hu^i-Vsi. F^mi-M'-'':-
have the advantage of very high mass transfer rates, although the overall pressure
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somewhat higher than for a monolith. Fluid-beds also possess the advantage of high bed-
side heat transfer compared with a normal gas heat transfer coefficient. This higher heat
transfer rate to heat transfer tubes immersed in the bed allows higher heat release rates
per unit volume of gas processed and therefore may allow waste gases with higher
heating values to be processed without exceeding maximum permissible temperatures in
the catalyst bed. The catalyst temperatures depend on the rate of reaction occurring at
the catalyst surface and the rate of heat exchange between the catalyst and imbedded
heat transfer surfaces.
In general, fluid-bed systems are more tolerant of particulates in the gas stream than
fixed-bed or packed-bed systems. This results from the constant abrasion of the fluidized
catalyst pellets, which helps remove these particulates from the exterior of the catalysts
in a continuous manner.
4.1.1.2 Flares. Flaring is an open combustion process in which the oxygen necessary
for combustion is provided by the air around the flame. The organic compounds to be
combusted are piped to a remote, usually elevated, location and burned in an open flame
in the open air using a specially designed burner tip, auxiliary fuel, and sometimes steam
or air to promote mixing for nearly complete (98 percent minimum) destruction of
combustibles. Good combustion in a flare is governed by flame temperature, residence
time of organic species in the combustion zone, turbulent mixing of the organic species to
complete the oxidation reaction, and the amount of oxygen available for free radical
formation. Combustion is complete if all combustibles (i.e., VOCs) are converted to CO.,
and water, while incomplete combustion results in some of the VOCs being unaltered or
converted to other organic compounds such as aldehydes or acids.
Flares are generally categorized in two ways: 1) by the height of the flare tip (i.e.,
ground-level or elevated), and 2) by the method of enhancing mixing at the flare tip (i.e.,
steam-assisted, air-assisted, pressure-assisted, or unassisted). Elevating the flare can
prevent potentially dangerous conditions at ground level where the open flame is located
near a process unit. Further, the products of combustion can be dispersed above working
areas to reduce the effects of noise, heat radiation, smoke, and objectionable odors.
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In most flares, combustion occurs by means of a diffusion flame. A diffusion flame is
one in which air diffuses across the boundary of the fuel/combustion product stream
toward the center of the fuel flow, forming the envelope of a combustible gas mixture
around a core of fuel gas. This mixture, on ignition, establishes a stable flame zone
around the gas core above the burner tip. This inner gas core is heated by diffusion of hot
combustion products from the flame zone.
Cracking can occur with the formation of small hot particles of carbon that give the
flame its characteristic luminosity. If there is an oxygen deficiency and if the carbon
particles are cooled to below their ignition temperature, smoking occurs. In large
diffusion flames, combustion product vortices can form around burning portions of the gas
and shut off the supply of oxygen. This localized instability causes flame flickering, which
can be accompanied by soot formation.
Flares can be dedicated to almost any VOC stream, and can handle fluctuations in
VOC concentration, flow rate, heating value, and inerts content. Flaring is appropriate
for continuous, batch, and variable flow vent stream applications.
Some streams, such as those containing halogenated or sulfur-containing compounds,
are usually not flared because they corrode the flare tip or cause formation of secondary
pollutants (such as acid gases or sulfur dioxide). If these vent types are to be controlled
by combustion, thermal incineration, followed by scrubbing to remove the acid gases, is
the preferred method.
The majority of refineries have existing flare systems designed to relieve emergency
process upsets that might contain large gas volumes. Often, large diameter flares
designed to handle emergency releases are also used to control continuous vent streams
from various process operations. Typically in refineries, many vent streams are combined
in a common gas header to fuel boilers and process heaters. However, excess gases,
fluctuations in flow rate in the fuel gas line, and emergency releases are sometimes sent
to a flare. Five factors affecting flare combustion efficiency are vent gas flammability,
auto-ignition temperature, heat content of the vent stream, density, and flame zone
mixing.
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The flammability limits of the vent stream influence ignition stability and flame
extinction. Flammability limits are the stoichiometric composition limits (maximum and
minimum) of an oxygen-fuel mixture that will burn indefinitely at given conditions of
temperature and pressure without further ignition. In other words, gases must be within
their flammability limits to burn. If these limits are narrow, the interior of the flame
may have insufficient air for the mixture to burn. Fuels, such as hydrogen, with wide
limits of flammability are therefore easier to combust.
The auto-ignition temperature of a vent stream affects combustion because gas
mixtures must be at a sufficient temperature and concentration to burn. A gas with a low
auto-ignition temperature will ignite more easily than a gas with a high auto-ignition
temperature.
The heat content of the vent stream is a measure of the heat available from the
combustion of the VOC in the vent stream. The heat content of the vent stream affects
the flame structure and stability. A gas with a lower heat content produces a cooler flame
that does not favor combustion kinetics and is more easily extinguished. The lower flame
temperature will also reduce buoyant forces, which reduces mixing.
The density of the vent stream also affects the structure and stability of the flame
through the effect on buoyancy and mixing. By design, the velocity in many flares is very
low; therefore, most of the flame structure is developed through buoyant forces as a result
of combustion. Lighter gases therefore tend to burn better. In addition to burner tip
design, the density also affects the minimum purge gas required to prevent flashback,
with lighter gases requiring more purge.
Poor mixing at the flare tip or poor flare maintenance can cause smoking (particulafce
matter release). Vent streams with high carbon-to-hydrogen ratios (> 0.35) have a greater
tendency to smoke and require better mixing to burn smokelessly. For this reason, one
generic steam-to-vent-stream ratio is not appropriate for all vent streams. The steam
required depends on the vent stream carbon-to-hydrogen ratio. A high ratio requires
more steam to prevent a smoking flare.
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The efficiency of a flare in reducing VOC emissions can be variable. For example,
smoking flares are far less efficient than properly operated and maintained flares. Flares
have been shown to have high VOC destruction efficiencies, under proper operating
conditions. Up to 99.7 percent combustion efficiency can be achieved.
4.1.1.2.1 Steam-Assisted Flares. Steam-assisted flares are single burner tips,
elevated above ground level for safety reasons, that burn the vented gas in essentially a
diffusion flame. They reportedly account for the majority of the flames installed and are
the predominant flare type found in refineries. To ensure an adequate air supply and
good mixing, this type of flare system injects steam into the combustion zone to promote
turbulence for mixing and to induce air into the flame.
4.1.1.2.2 Air-Assisted Flares. Air-assisted flares use forced air to provide the
combustion air and the mixing required for smokeless operation. These flares are built
with a spider-shaped burner (with many small gas orifices) located inside but near the top
of a steel cylinder two feet or more in diameter. Combustion air is provided by a fan in
the bottom of the cylinder, and the amount of combustion air can be varied by changing
the fan speed. The primary advantage air-assisted flares provide is that they can be used
without steam.
4.1.1.2.3 Non-Assisted Flares. The non-assisted flare is just a flare tip without
any auxiliary provision for enhancing the mixing of air into its flame. Its use is limited
essentially to gas streams that have a low heat content and a low carbon/hydrogen ratio
that burn readily without producing smoke. These streams require less air for complete
combustion, have lower combustion temperatures that minimize cracking reactions, and
are more resistant to cracking.
4.1.1.2.4 Pressure-Assisted Flares. This type of flare uses vent stream pressure
to promote mixing at the burner tip. If sufficient vent stream pressure is available, these
flares can be applied to streams previously requiring steam or air assist for smokeless
operation. Pressure-assisted flares generally have the burner arrangement at ground
level, and consequently, must be located in a remote area of the plant where there is
plenty of space available. Thev have multiple burner heads that are staged to operate
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based on the quantity of gas being released. The size, design, number, and group
arrangement of the burner heads depend on the vent gas characteristics.
4.1.1.2.5 Enclosed Ground Flares. The burner heads of an enclosed flare are
inside an insulated shell. This shell reduces noise, luminosity, and heat radiation and
provides wind protection. A high nozzle pressure drop is usually adequate to provide the
mixing necessary for smokeless operation and air or steam assist is not required. In this
context, enclosed flares can be considered a special class of pressure-assisted or non-
assisted flares. Enclosed flares are always at ground level.
Enclosed flares generally have less capacity than open flares and are used to combust
continuous, constant flow vent streams, although reliable and efficient operation can be
attained over a wide range of design capacity. Stable combustion can be obtained with
lower heat content vent gases than is possible with open flare designs, probably due to
their isolation from wind effects.
4.1.1.3 Boilers and Process Heaters. Industrial boilers are combustion units that boil
water to produce high and low pressure steam. Industrial boilers can also combust
various vent streams containing VOCs, including vent streams from distillation
operations, reactor processes, and other general operations. The majority of industrial
boilers used in the refining industry are of watertube design, and over half of these
boilers use natural gas as a fuel. In a watertube boiler, hot combustion gases contact the
outside of heat transfer tubes which contain hot water and steam. These tubes are
interconnected by a set of drums that collect and store the heated water and steam.
Energy transfer from the hot flue gases to the water in the furnace watertube and drum
system can be better than 85 percent efficient. Additional energy can be recovered from
the flue gas by preheating combustion air in an air preheater or by preheating incoming
boiler feed water in an economizer unit.
When firing natural gas, forced- or natural-draft burners thoroughly mix the incoming
fuel and combustion air. A VOC-containing vent stream can be added to this mixture or
it can be fed into the boiler through a separate burner. In general, burner design depends
on the characteristics of the fuel - either the combined VOC-containing vent stream and
fuel, or the /ent scream alone < when a separate burner ,s used).
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A process heater is similar to an industrial boiler in that heat liberated by the
combustion of fuels is transferred by radiation and convection to fluids contained in
tubular coils. It is different from an industrial boiler in that process heaters raise the
temperature of process streams instead of producing high temperature steam. Process
heaters are used in many chemical manufacturing operations to drive endothermic
reactions. They are also used as feed preheaters and as reboilers for some distillation
operations. The fuels used in process heaters include natural gas, refinery offgases, and
various grades of fuel oil.
A typical process heater design consists of the burner(s), the firebox, and a row of
tubular coils containing the process fluid. Most heaters also contain a convective section
in which heat is recovered from hot combustion gases by convective heat transfer to the
process fluid.
4.1.1.3.1 Efficiency of Boilers and Process Heaters. Average furnace temperature
and residence time determine the combustion efficiency of boilers and process heaters,
just as they do for incinerators. When a vent gas is injected as a fuel into the flame zone
of a boiler or process heater, the required residence time is reduced because of the
relatively high temperature and turbulence of the flame zone.
Residence time and temperature profiles in boilers and process heaters are
determined by factors such as overall configuration, fuel type, heat input, and excess air
level. A mathematical model developed to estimate furnace residence time and
temperature profiles for a variety of industrial boilers predicts mean furnace residence
times ranging 0.25 to 0.83 second for natural gas-fired watertube boilers that range in
size from 4.4 to 44 MW (15 to 150 x 106 Btu/hr). Boilers with a 44-MW capacity or
greater generally have residence times and operating temperatures that would ensure a
98 percent VOC destruction efficiency. The required temperatures for these size boilers
are at least 1,200 degrees Celsius.
Firebox temperatures for process heaters can show wide variations depending on the
application. Firebox temperatures can range from 400 degrees Celsius for preheaters and
"eboilers to 1,260 decrees Celsius for pyroiysis furnaces. Tescs coniiucieu oy £PA 'Hi
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process heaters using a mixture of benzene offgas and natural gas showed greater than 98
percent destruction efficiency for C, to C6 hydrocarbons.
4.1.1.3.2 Applicability of Boilers and Process Heaters. Both of these devices are
used throughout petroleum refineries to provide steam and heat input essential to the
refining process. Most of these devices possess sufficient size to provide the necessary
temperature and residence time for VOC destruction. Furthermore, boilers and process
heaters have proved effective in destroying compounds that are difficult to combust, such
as PCBs (polychlorinated biphenyls). Boilers and process heaters are thus effective in
reducing VOC emissions from any vent streams that are certain not to reduce the
performance or reliability of the boiler or process heater.
Ducting some vent streams to a boiler or process heater can present potential safety
and operating problems. The varying flow rate and organic content of some vent streams
can lead to explosive mixtures or flame instability within the furnace. In addition, vent
streams with halogenated or sulfur-containing compounds are usually not combusted in
boilers or process heaters due to the possibility of corrosion.
Boilers and process heaters are most applicable where the potential exists for heat
recovery from the combustion of the vent stream. Vent streams with a high enough VOC
concentration and high flow rate can provide enough equivalent heat value to act as a
substitute for fuel that would otherwise be needed. Because boilers and process heaters
cannot tolerate wide fluctuations or interruptions in the fuel supply, they are not widely
used to reduce VOC emissions from batch operations or other noncontinuous vent
streams.
4.1.2 Product Recovery Devices
4.1.2.1 Absorbers. In absorption, a soluble vapor is absorbed from its mixture with
an inert gas by means of a liquid in which the solute gas is more or less soluble. For any
given solvent, solute, and operating conditions, there exists an equilibrium ratio of solute
concentration in the gas mixture to solute concentration in the solvent. The driving force
for mass transfer at a given point in an operating absorber is the difference between the
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concentration of solute in the gas and the equilibrium concentration of solute in the
liquid.
Devices based on absorption principles include spray towers, venturi and wet
impingement scrubbers, acid gas scrubbers, packed columns, and plate columns. Spray
towers have the least effective mass transfer capability due to their high atomization
pressure requirement, and are generally restricted to particulate matter removal and
control of high-solubility gases such as SO2 and NH3 (ammonia). Venturi scrubbers have
a high degree of gas/liquid mixing and provide high particulate matter removal efficiency.
They also require high pressure drops (i.e. high energy requirements) and have relatively
short contact times. Their use is also restricted to high-solubility gases. Acid gas
scrubbers are used with thermal incinerators to remove corrosive combustion products.
Acid gas is formed upon the contact of halogenated or sulfur-containing VOCs with
intense heat during incineration. This gas is quenched to lower its temperature and is
then scrubbed in an absorber. In most cases, the type of absorber used is packed or plate
columns, the two most commonly used absorbers for VOC control.
Packed towers are vertical columns containing inert packing, manufactured from
materials such as porcelain, metal, or plastic, that provides the surface area for contact
between the liquid and gas phases in the absorber. Packed towers are used mainly for
corrosive materials and liquids with tendencies to foam or plug. They are less expensive
than plate columns for small-scale or pilot plant operations where the column diameter is
less than 0.6 m. They are also suitable where the use of plate columns would result in
excessive pressure drops.
Plate columns contain a series of trays on which contact between the gas and liquid
phases in a stepwise fashion. The liquid phase flows down tray to tray as the gas phase
moves up through openings in the tray (usually perforations or bubble caps), passing
through the liquid on the way.
The major design parameters for absorbing any substance are column diameter and
height, system pressure drop, and required liquid flow rate. Deriving these parameters is
accomplished by considering the solubility, viscositv. density, ind concentration of the
VOC m the miet vent stream tail of which depend on column temperature}; the total
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surface area provided by the packing material; and the mass flow rate of the gases to be
treated.
4.1.2.1.1 Absorber Efficiency. Control efficiencies for absorbers can vary widely
depending on the solvent selected, design parameters, and operating practices. Solvents
are chosen for high solubility for the specific VOC and include liquids such as water,
mineral oils, kerosenes, nonvolatile hydrocarbon oils, and aqueous solutions of oxidizing
agents, sodium carbonate, and sodium carbonate. An increase in absorber size (i.e.,
contact surface area) or a decrease in the operating temperature can increase the VOC
removal efficiency of the system for a given solvent and solute. It is sometimes possible to
increase VOC removal efficiency by changing the solvent.
4.1.2.1.2 Applicability. The primary determinant of absorption applicability for
controlling VOC emissions is the availability of a suitable solvent. Water is a suitable
solvent for absorption of organic chemicals with relatively high water solubilities (e.g.,
most alcohols, organic acids, aldehydes, glycols). For organic compounds with low water
solubilities, other solvents (usually organic liquids with low vapor pressures) are used.
Other important factors influencing absorption applicability include absorptive
capacity and strippability of VOC in the solvent. Absorptive capacity is a measure of the
solubility of VOC in the solvent. The solubility limits the total quantity of VOC that
could be absorbed in the system, while strippability describes the ease with which the
VOC can be removed from the solvent. If strippability is low, then absorption is less
viable as a VOC control technique.
The concentration of VOC in the inlet vent stream also determines the applicability of
absorption. Absorption is usually considered only when the VOC concentration is above
200 to 300 ppm. Below these gas-phase concentrations, the rate of mass transfer of VOC
to solvent is decreased enough to make reasonable designs infeasible.
4.1.2.2 Steam Stripping. Steam stripping can be used as initial treatment of a
process wastewater stream to reduce the VOC loading of that steam before it is dent to
the facility-wide wastewater treatment system. There are several components m a steam
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stripping system: a feed tank, heat exchanger, steam stripping column, condenser,
overhead receiver, and a destruction device (if necessary).
Steam stripping involves the fractional distillation of wastewater to remove VOCs.
The basic operating principle of steam stripping is the direct transfer of heat through
contact of steam with wastewater. This heat transfer vaporizes the more volatile organic
compounds. The overhead vapor contains water and organic compounds, and it is
condensed and separated to recover the organic fraction. Recovered organic compounds
are either recycled for reuse in the process or incinerated in an on-site combustion device
for heat recovery.
Steam, stripper systems may be operated in batch or continuous mode. Batch steam
strippers are more prevalent when the wastewater feed is generated by batch processes,
when feed characteristics are highly variable, or when small volumes of wastewater are
generated. They may also be used if wastewater contains relatively high concentrations
of solids, resins, or tars. In batch stripping, wastewater is charged to the receiver, or pot,
and brought to the boiling temperature of the mixture. Solids and other residues
remaining in the bottom of the pot (hence the term "bottoms") at the completion of the
batch are nonvolatile, heavy compounds that are removed for disposal. By varying the
heat input and fraction of the initial charge boiled overhead, a batch stripper can be used
to treat wastewater mixtures with widely varying characteristics.
In contrast to batch strippers, continuous steam strippers are designed to treat
wastewater streams with relatively consistent characteristics. Continuous strippers can
have several stages and achieve greater efficiencies of VOC removal than batch strippers.
Other advantages offered by continuous strippers include more consistent effluent quality,
more automated operation, and lower annual operating costs.
Typically, wastewater steams continuously discharged from process equipment are
usually consistent in composition. A continuous steam stripper system would thus be
indicated for treating the wastewater. However, batch wastewater streams can also be
controlled by continuous steam strippers by incorporating a feed tank with adequate
residence time to provide a consistent outlet composition.
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4.1.2.2.1 Collecting, Conditioning, and Recovery. The controlled sewer system or
hard piping from the point of wastewater generation to the feed tank controls emissions
before steam stripping. The feed tank collects and conditions the wastewater fed to the
steam stripper. If the feed tank is adequately designed, a continuous steam stripper can
treat wastewater generated by some batch processes. In these cases, the feed tank serves
as a buffer between the batch process and the continuous steam stripper. During periods
of no wastewater flow from the batch process, wastewater stored in the feed tank is fed to
the stripper at a relatively constant rate.
Often present in the feed tank are aqueous and organic phases. The feed tank
provides the retention time necessary for these phases to separate. The organic phase is
recycled to the process for recovery of organic compounds or disposed by incineration. The
water phase is fed to the stripper to remove the soluble organic compounds. Solids are
also separated in the stripper feed tank; the separation efficiency depends on the density
of the solids dissolved in the process wastewater. The more dense solids, which settle to
the bottom of the tank, are removed periodically from the feed tank and are usually
landfilled or landfarmed.
After this conditioning of the wastewater, it is pumped through the feed/bottoms heat
exchanger where it is preheated and then pumped into the steam stripping column.
Steam is sparged into the stripper at the bottom of the column, and the wastewater feed
enters at the top. The wastewater flowing down the column contacts the flowing
countercurrently up the column. Both latent and sensible heat is transferred from the
steam to the organic compounds in the wastewater, vaporizing them into the vapor
stream. These constituents flow out the top of the column with any uncondensed steam.
The wastewater effluent leaving the bottom of the stripper is pumped through the
feed/bottoms heat exchanger which heats the feed stream and cools the bottoms before
discharge. After leaving the exchanger, the bottoms stream is usually either routed to an
on-site wastewater treatment plant and discharged to an NPDES-permitted outfall, or
sent to a publicly owned treatment works (POTW).
Recover;/ of both VOCs and water vapors from the gaseous overheads .stream -'r-m h'j
steam stripper is usually accomplished with a condenser. The condensed stream is ted to
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an overhead receiver, and the recovered VOCs are usually either pumped to storage and
recycled to the process unit or combusted for their fuel value in an incinerator, boiler, or
process heater (all discussed earlier in this chapter). If an aqueous phase is generated, it
is returned to the feed tank and recycled through the steam stripper system.
4.1.2.2.2 Efficiency of Control. The degree of contact between the steam and the
wastewater is the primary variable affecting the ability of a steam stripper to remove
VOCs. In turn, this variable is affected by five factors: 1) column dimensions (height and
diameter); 2) the contacting media (packing or trays); and 3) operating parameters such
as the steam-to-feed ratio, column temperature, and wastewater pH.
Control efficiency increases as column height increases since there is greater
opportunity for contact between the steam and the wastewater. The column height is
determined by the number of theoretical stages required to achieve the desired removal
efficiency. The number of theoretical stages is a function of the equilibrium coefficient of
the pollutants and the efficiency of mass transfer in the column, and this number can be
computed by either the McCabe-Thiele graphical method or the Kremser analytical
method.
The column diameter determines the required cross-sectional area for liquid and
vapor flow through the column. The smaller the cross-sectional area, the higher the
superficial gas velocity, which increase turbulence and mixing resulting in high column
•
efficiencies. However, the column cross-sectional area must be sufficient to prevent
flooding from excessive liquid loading or liquid entrainment. This area also affects the
liquid retention time, with higher retention times resulting in higher efficiencies. These
factors have to be weighed in selecting the column diameter and the design velocities.
The contacting media in the column also play an important role in determining the
mass transfer efficiency. Packing or trays are used to provide contact between liquid and
vapor phases. Packing provides for continuous contact while trays provide staged contact.
Trays are usually more effective for wastewater containing dispersed solids because of the
plugging and cleaning problems encountered with packing. Tray towers can also operate
over a wider range of liquid flow rates than packed towers. Packed cowers, on ihe )ther
hand, are often more cost effective to install and operate when treating highly corrosive
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wastewater since corrosion resistant ceramic packing can be used. Also, the pressure
drop through packed towers may be less than through tray towers.
The steam-to-feed ratio required for high removal efficiencies is affected by the
wastewater temperature as it enters the column. If the feed temperature is lower than
the operating temperature at the top of the column, part of the steam is required to heat
the feed. With good column design, sufficient steam flow is provided to heat the feed as
well as volatilize the organic constituents. Any steam in excess of this flow rate helps
carry VOCs out of the top of the column with the overheads stream. Also, increasing the
steam-to-feed ratio will increase the ratio of the vapor to liquid flow through the column,
which increases the stripping of VOCs into the vapor phase.
Two other influences on VOC removal are the column temperature and wastewater
pH. Temperature influences the solubility and equilibrium coefficients of the organic
compounds. pH has an effect on the vapor liquid equilibrium characteristics of VOCs. To
ensure steam stripping is successful, columns are operated at pressures slightly exceeding
atmospheric, and operating temperatures are usually slightly higher than the normal
boiling point of water. Wastewater pH is controlled by adding caustic to the feed.
4.1.2.2.3 Applicability. Steam stripping is most applicable to treating
wastewaters with organic compounds that are highly volatile and have a low solubility in
water. The VOCs that have low volatility tend not to volatilize and thus are not easily
stripped out of the wastewater by the steam. Similarly, VOCs that are very soluble in
water tend to remain in the wastewater and are not easily stripped by steam. Oil, grease,
solids content and pH of wastewater also affect applicability. High oil, grease, and solids
levels can cause operating problems for steam stnppers, and extremes in pH may prove to
be corrosive to equipment. Design or wastewater preconditioning techniques can be used
to mitigate these problems.
4.1.2.3 Carbon Adsorbers. Adsorption is a mass-transfer operation involving
interaction .between gas- or liquid-phase components and solid-phase components. In this
operation, certain components of a gas- or liquid-phase (or adsorbate) are transferred to
the surface of a solid adsorbent. The transfer is accomplished by physical or chemical
adsorption mechanisms. Physical adsorption takes place when intermolecuiar < van der
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Waals) forces attract and hold the gas molecules to the solid surface. Chemisorption
occurs when a chemical bond forms between the gaseous- and solid-phase molecules. A
physically adsorbed molecule can be removed readily from the adsorbent (under suitable
temperature and pressure conditions); the removal of a chemisorbed component is much
more difficult.
Most industrial adsorption systems use activated carbon as the adsorbent. Activated
carbon effectively captures certain organic vapors by physical adsorption. The vapors can
then be released for recovery by regenerating the adsorption bed with steam or nitrogen.
Oxygenated adsorbents such as silica gels or diatomaceous earth exhibit a greater
selectivity for capturing water vapor than organic gases compared to activated carbon.
They thus are of little use for high-moisture vent streams characteristic of some VOC-
containing vent streams.
Among the factors influencing the design of a carbon adsorption system are the
chemical characteristics of the VOC being recovered, the physical properties of the inlet
stream (temperature, pressure, and volumetric flow rate), and the physical properties of
the adsorbent. The mass of VOC that adheres to the adsorbent surface is directly
proportional to the difference in VOC concentration between the gas phase and the solid
surface. In addition, the quantity of VOC adsorbed depends on the adsorbent bed volume,
the surface area of adsorbent available to capture VOC, and the rate of diffusion of VOC
through the gas film at the gas- and solid-phase interface (the mass transfer coefficient).
It should be noted that physical adsorption is an exothermic operation that is most
efficient within a narrow range of temperature and pressure.
4.1.2.3.1 Types of Adsorbers. There are five types of adsorption equipment used
in gas collection: 1) fixed regenerable beds; 2) disposable/rechargeable canisters;
3) traveling bed adsorbers; 4) fluid bed adsorbers; and 5) chromatographic baghouses.
The fixed-bed type is the one most commonly used for control of VOCs, so this section
addresses this type only.
Fixed-bed units can be sized for controlling continuous, VOC-containing streams over
i wide range °f Tow rates, ranging up ro several thousand cubic meters per Tnnutc
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(100,000 scftn). VOC concentrations in streams that can be treated by fixed-bed units can
range from several parts per billion by volume (ppbv) to 10,000 ppmv.
Fixed-bed adsorbers can be operated in two modes: intermittent or continuous. In
intermittent mode, the adsorber removes VOCs for a specified time (called "the adsorption
time"), which corresponds to the time during which the controlled source is emitting
VOCs. In continuous mode, a regenerated carbon bed is always available for adsorption,
so that the controlled source can operate continuously without shutting down. While
continuous operation allows for more adsorption over the same period of time because it
does not need to be shut down, more carbon must be provided. This is necessary since a
bed for desorbing must be provided along with the adsorbing bed in order to recover the
captured VOC from the carbon.
4.1.2.3.2 Control Efficiency. Well designed and operated carbon adsorption
systems can achieve control efficiencies of 95 to 99 percent for a variety of solvents
including ketones such as methyl ethyl ketone and cyclohexanone. The VOC control
efficiency depends on factors such as inlet vent stream characteristics (temperature,
pressure, and velocity), the physical properties of the compounds present in the vent
stream, the physical properties of the adsorbent, and the condition of the regenerated
carbon bed.
The adsorption capacity of the carbon and the resulting outlet concentration are
dependent upon the temperature of the inlet vent stream. High vent stream
temperatures increase the kinetic energy of the gas molecules, causing them to overcome
van der Waals forces and release from the surface of the carbon. At vent stream
temperatures above 38 degrees Celsius, both adsorption capacity and outlet concentration
may be adversely affected.
Increasing vent stream pressure improves VOC removal efficiency. Increased stream
pressure results in higher VOC concentrations in the vapor phase and increased driving
force for mass transfer to the carbon surface. Decreased stream pressure, on the other
hand, is often used to regenerate carbon beds. Reduced pressure in the carbon bed
effectively lowers the concentration of VOCs in the vapor phase, desorbing the VOCs from
che carbon surt'ace to the vapor phase.
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Vent stream velocity entering the carbon bed must be quite low to allow time for
diffusion and adsorption. Typical inlet vent stream velocities range from 15 to 30 meters
per minute (50 to 100 feet per minute). If inlet VOC concentrations are low, the bed area
required for the volume needed usually permits a velocity at the high end of this range.
The required depth of the bed for a given compound is directly proportional to the carbon
granule size and porosity and to the inlet vent stream velocity. For a given carbon type,
bed depth must increase as the vent stream velocity increases. Generally, carbon
adsorber bed depths range from 0.40 to 0.95 meter (1.5 to 3.0 feet). The condition of the
regenerated carbon bed will change with use. After repeated regeneration, the carbon bed
loses activity, resulting in reduced VOC removal efficiency.
4.1.2.3.3 Applicability. Carbon adsorption cannot be used universally for
distillation or process vent streams. It is not recommended under the following
conditions, common with many VOC-containing vent streams: 1) high VOC
concentrations, 2) very high or low molecular weight compounds, 3) mixtures of high and
low boiling point VOCs, and 4) high moisture content.
Absorbing vent streams with VOC concentrations above 10,000 ppmv may result in
excessive temperature rise in the carbon bed due to the accumulated heat of adsorption
resulting from the VOC loading. If flammable vapors are present, insurance company
requirements may limit inlet concentrations to less than 25 percent of the LEL.
The molecular weight of the compounds to be adsorbed should be in the range of 45 to
130 gm/gm-mole for effective adsorption. High molecular weight compounds that are
characterized by low volatility are strongly adsorbed on carbon. The affinity of carbon for
these compounds makes it difficult to remove them during regeneration of the carbon bed.
Conversely, highly volatile materials (i.e., molecular weight less than about 45 gm) do not
adsorb readily on carbon, thus adsorption is not typically used for controlling streams
containing such compounds.
Adsorption systems can be very effective with homogeneous vent streams but much
less so with streams containing a mixture of light and heavy hydrocarbons. The lighter
organic compounds tend to be disnlaced bv the heavier compounds, crreatlv reducing
system efficiency.
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Humidity is not a factor in adsorption at adsorbate concentrations above 1,000 ppmv.
Below this level, however, water vapor competes with VOCs in the vent stream for
adsorption sites on the carbon surface. In these cases, vent stream humidity levels
exceeding 50 percent (relative humidity) are not desirable.
4.1.2.4 Condensers. Condensation is a separation technique in which one or more
volatile components of a vapor mixture are separated from the remaining vapors through
saturation followed by a phase change. The phase change from gas to liquid can be
achieved in two ways: 1) by increasing the system pressure at a given temperature or
2) by lowering the temperature at a constant pressure. The latter method is the more
common to achieve the specified phase change, and it alone is addressed here.
The basic equipment includes a condenser, refrigeration unit(s), and auxiliary
equipment such as a pre-cooler, recovery/storage tank, pump/blower, and piping. The two
most commonly used condenser types are surface condensers and direct contact
condensers. In surface condensers, the coolant fluid does not contact the vent stream;
heat transfer occurs through the tubes or plates in the condenser. As the vapor
condenses, a film forms on the cooled surface and drains away to a collection tank for
storage, reuse, or disposal. Because the coolant from surface condensers does not contact
the vapor stream, it is not contaminated and can be recycled in a closed loop. Surface
condensers also allow for direct recovery of VOCs from the gas stream.
Most refrigerated surface condensers are the shell-and-tube type, which circulates the
coolant fluid on the tube side. The VOCs condense on the outside of the tube (the shell
side). Plate-type heat exchangers are also used as surface condensers in refrigerated
systems. Plate condensers operate under the same principles as the shell-and-tube
systems, for there is no contact between the coolant and vent stream), but the two
streams are separated by thin, flat plates instead of cylindrical tubes.
In contrast to surface condensers, direct contact condensers cool the vapor stream by
spraying a liquid at ambient or lower temperature directly into the vent stream. Spent
coolant containing VOCs from direct contact condensers usually cannot be reused directly.
Additionally, VOCs in the spent coolant cannot be recovered without further processing.
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The combined stream could present a potential waste disposal problem, depending upon
the coolant and the specific VOCs.
A refrigeration unit generates the low-temperature medium necessary for heat
transfer for recovery of VOCs. Typically in refrigerated condenser systems two kinds of
refrigerants are used, primary and secondary. Primary refrigerants such as ammonia and
chlorofluorocarbons (e.g., chlorodifluoromethane) are those that undergo a phase change
from liquid to gas after absorbing heat. Secondary refrigerants, such as brine solutions,
have higher boiling points and thus act only as heat carriers and remain in the liquid
phase.
There are some applications that require auxiliary equipment. If the vent stream
contains water vapor or if the VOC has a high freezing point (e.g., benzene or toluene), ice
or frozen hydrocarbons may form on the condenser tubes or plates. This will reduce the
heat transfer efficiency of the condenser and thereby reduce the removal efficiency.
Formation of ice will also increase the pressure drop across the condenser. In such cases,
a precooler may be used to remove the moisture before the vent stream enters the
condenser. Alternatively, ice can be melted during an intermittent heating cycle by
circulating ambient temperature brine through the condenser or using radiant heating
coils.
It is necessary in some cases to provide a recovery tank for temporary storage of
condensed VOC before its reuse, reprocessing, or transfer to a large storage tank. Pumps
and blowers are typically used to transfer liquid (e.g., coolant and recovered VOC) and gas
streams, respectively, within the system.
4.1.2.4.1 Control Efficiency. The major parameters that affect the removal
efficiency of refrigerated surface condensers designed to control air/VOC mixtures are:
1) Volumetric flow rate of the VOC-containing vent stream; 2) Inlet temperature of the
vent stream; 3) Concentrations of the VOCs in the vent stream; 4) Absolute pressure of
the vent stream; 5) Moisture content of the vent stream; and 6) properties of the VOCs in
the vent stream, such as dew points, heats of condensation, heat capacities, and vapor
nressures.
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Any operator of a condenser should remember that a condenser cannot lower the VOC
concentration to levels below the saturation concentration at the coolant temperature.
Removal efficiencies above 90 percent can be achieved with coolants such as chilled water,
brine solutions, ammonia, or chlorofluorocarbons.
4.1.2.4.2 Applicability. Condensers are widely used as product recovery devices.
They may be used to recover VOCs upstream of other control devices or they may be used
alone for controlling vent streams containing relatively high VOC concentrations (usually
greater than 5,000 ppmv). In these cases, the removal efficiencies of condensers can
range widely, from 50 to 95 percent.
Since the temperature necessary for condensation depends on the properties and
concentration of VOCs in the vent stream, streams having either low VOC concentrations
or more volatile compounds require lower condensation temperatures. Also, depending on
the type of condenser used, disposal of the spent coolant can be a problem. If cross-media
impacts are a concern, surface condensers would be preferable to direct contact
condensers.
Condensers used as emission control devices can process flow rates as high as about
57 m3/min (120,000 scfm). Condensers for vent streams with greater volumetric flow
rates and having high concentrations of noncondensibles will require significantly larger
heat transfer areas.
4.1.2.5 Vapor Collection Systems for Loading Racks. When liquids are transferred
into a transport vessel, vapors in the head space of that vessel can be lost to the
atmosphere. The principal factors affecting emissions from transfer operations are the
vapor pressure of the chemical being transferred. Other factors that influence emissions
from transfer operations include the transfer rate and the purge rate of nitrogen (or other
inert gas) through the vessel during transfer.
The vapor pressure of the chemical being transferred has the greatest influence on
emissions from transfer operations. For pure materials, the vapor pressure gives a
measure of the amount of organic compound lost during transfer. The total potential
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emissions from any transfer is related to the void volume of the transport vessel and the
concentration of the VOC in the head space.
The mode of transfer is also an important factor in determining emissions from
transfer operations. Top splash loading creates the most emissions because it enhances
the agitation of the liquid being transferred, creating a higher concentration of the
compound in the vapor space. With alternate loading techniques, such as submerged fill
or bottom loading, the organic liquid is loaded under the surface of the liquid, which
reduces the amount of agitation and suppresses the generation of excess vapor in the
head space of the transport vessel.
The rate of transfer has a more subtle influence on emissions; its greatest effect is on
air quality. Transfer rate will dictate the short-term emission rate of the compound being
transferred, thereby influencing exposure to the worker or public.
A nitrogen purge is used to reduce the potential for explosion of some chemicals in air
or to keep some chemicals moisture-free. Using an inert gas purge increases the emission
rate of VOC lost to the atmosphere because it creates a turnover rate of gas through the
transport vessel, increasing the total volume of vapor discharged to the atmosphere.
Most vapor collection systems collect the vapors generated during transfer operations
and transport them to either a recovery device for return to the process or a combustion
device for destruction. In vapor balancing systems, vapors generated during transfer
operations are returned directly to the storage facility for the material, and the system
requires no additional controls.
Vapor collection systems consist of piping that captures and transports to a control
device VOCs in the vapor space of transport vessels that are displaced when liquids are
loaded. These systems may use existing piping normally used to transport liquids under
pressure into the transport vessel or piping separate from that for transfer. Collection
systems comprise very few pieces of equipment and minimal piping. The principal piece
of equipment in a collection system is a vacuum pump or blower, used to induce the flow
of vanors from the trnnsnort vessel to the recovery or combustion system.
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Blowers can also be used to remove vapors from the head space of the tank car as
liquid is transferred into the tank car. Standard recovery techniques such as
condensation or refrigeration/condensation systems, or combustion can be applied to the
captured vapors.
Vapor balancing is another means of collecting vapors and reducing emissions from
transfer operations. Vapor balancing is most commonly used where storage facilities are
adjacent to the loading facility. In this collection system, an additional line is connected
from the transport vessel to the storage tank to return any vapor in the transport vessel
displaced by the liquid that is loaded to the vapor space of the storage vessel left by the
transferred liquid. Since this is a direct volumetric change, there are no losses to the
atmosphere.
4.1.2.5.2 Efficiency. The three factors affecting the efficiency of a vapor
collection system are:
1) Operating pressure of the collection system;
2) Volume of piping between the loading arm and the transport vessel; and
3) The efficiency of the ultimate control device.
The first factor influences the efficiency of collection through the VOC concentration
remaining in the line after transfer. The VOC concentration for systems operating at low
pressures or under vacuum is decreased, thus lowering the total amount of VOC in the
piping. This effectively reduces the amount of VOC lost to the atmosphere when
disconnecting transfer lines. The opposite occurs for systems operating at higher
pressures.
The second factor establishes the quantity of VOC not delivered to the transport
vessel and not collected for treatment. Systems that minimize the piping between the
transfer loading arm and the transport vessel are more efficient than those with larger
piping connections, because there is less open piping to the atmosphere. The third factor
is the most important, for it affects the overall efficiency of the collection system and the
control system.
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4.1.2.5.2 Applicability. Applicability of vapor collection systems depends on four
factors:
1) Vapor pressure of the material;
2) Value of the product;
3) Physical layout of the facility; and
4) OSHA considerations.
Materials with vapor pressures greater than atmospheric are stored and loaded under
pressure. Loading under pressure eliminates the losses associated with atmospheric
transfer operations and limits losses to those associated with connections and
disconnections.
For purely economic considerations, expensive products are candidates for more
extensive collection and recovery systems. Further, it is unlikely that combustion
techniques will be used to control emissions of products whose value is high enough to
warrant recovery efforts.
The third factor, physical layout of the facility, is the most important. The shorter
the distance between the vapor balancing system and the storage tank, the fewer meters
of piping required, and the more affordable a vapor balancing system is. Because vapor
balancing is a simple and cost effective control technique for transfer operations, it is
often used in RACT (reasonably available control technology) requirements and has been
used in many instances as a control measure to meet the emission requirements of many
State air toxic regulations.
OSHA limitations on work place exposure to chemicals being transferred are
additional considerations. Some chemical compounds being transferred are more toxic
than others, and thus must be more tightly controlled. Highly toxic or carcinogenic
compounds require stringent control measures such as transferring VOCs under vacuum,
vapor compression, refrigeration, and combustion.
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4.1.3 Leak Detection and Repair
Leak detection and repair (LDAR) programs have been required by EPA for a number
of years. They have been undertaken to reduce emissions due to leaking equipment.
These emissions occur when process fluid (liquid or gaseous) is released through the
sealing mechanisms of equipment in the chemical plant. This section discusses the
sources of equipment leak emissions and control techniques that can be applied to reduce
emissions from equipment leaks, including the applicability of each control technique and
its associated effectiveness in reducing emissions.
Many potential sources of equipment leak emissions exist in a refinery. The following
sources are covered in this section: pumps, compressors, pressure relief devices, open-
ended lines, sampling connections, process valves, connectors, instrumentation systems,
and product accumulator vessels.
The techniques for reducing emissions from equipment leaks are as diverse as the
types of sources. The three major categories for techniques are: 1) equipment
(modifications); 2) closed vent systems; and 3) work practices. The selection of a control
technique and its effectiveness in reducing emissions depends on a number of factors
including: 1) type of equipment; 2) equipment service (gas, light liquid, heavy liquid);
3) process variables influencing equipment selection (temperature, pressure); 4) process
stream composition; and 5) costs.
4.1.3.1 Pumps. Pumps are used widely in the petroleum refining industry for the
movement of organic liquids. Liquids transferred by pump can leak at the point of
contact between the moving shaft and the stationary casing. Consequently, all pumps
require a seal at the point where the shaft penetrates the housing in order to isolate the
pumped fluid from the environment.
Two generic types of seals, packed and mechanical, are used on pumps. Packed seals
can be used on both reciprocating and rotary action (centrifugal) pumps. A packed seal
consists of a cavity (or "stuffing box") in the pump casing filled with packing material that
is compressed with a packing gland to form a seal around the shaft. Coolant is required
r,o remove me rrictionai heat oecween the pacKing ana shaft. The necessary iuuncatu;n ..-
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provided by a coolant that flows between the packing and the shaft. Deterioration of the
packing can result in leakage of the process liquid.
Mechanical seals are limited in application to pumps with rotating shafts. There are
single and double mechanical seals, with many variations to their basic design, but all
have a lapped seal face between a stationary element and a rotating seal ring. In a single
mechanical seal, the faces are held together by the pressure applied by a spring on the
drive and by the pump pressure transmitted through the pumped fluid on the pump end.
An elastomer O-ring seals the rotating face to the shaft. The stationary face is sealed to
the stuffing box with another elastomer O-ring or gasket.
For double mechanical seals, two seals are arranged back-to-back, in tandem, or face
to face. In the back-to-back arrangement, a closed cavity is created between the two
seals. A seal liquid, such as water or seal oil, is circulated through the cavity. This seal
liquid is used to control the temperature in the stuffing box. For the seal to function
properly, the pressure of the seal liquid must be greater than the operating pressure of
the pump. In this manner, any leakage would occur across the seal faces into the process
or the environment.
Double mechanical seals are used in many process applications, but there are some
conditions for which their use is not indicated. Such conditions include service
temperatures above 260 degrees Celsius, and pumps with reciprocating shaft motion.
Further, double mechanical seals cannot be used where the process fluid contains slurries,
polymeric, or undissolved solids.
Another type of pump used in the petroleum refining industry is the seal-less pump.
Seal-less pumps are used primarily in processes where the pumped fluid is hazardous,
highly toxic, or very expensive and where every effort must be made to prevent all
possible leakage of the fluid. Canned-motor, diaphragm, and magnetic drive pumps are
three common types of seal-less pumps.
Canned-motor pumps have interconnected cavity housings, motor rotors, and pump
casings. Because the process liquid is the bearing lubricant, abrasive solids in the nrocess
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lines cannot be tolerated. Canned-motor pumps are widely used for handling organic
solvents, organic heat transfer liquids, and light oils.
Diaphragm pumps contain a flexible diaphragm of metal, rubber, and plastic as the
driving member. The primary advantage of this arrangement is the elimination of all
packing and seals exposed to the process liquid provided the diaphragm's integrity is
maintained. This is important when handling hazardous or toxic liquids. Emissions from
diaphragm pumps can be large, however, if the diaphragm fails. In magnetic-drive
pumps, no seals contact the process fluid. An externally-mounted magnet coupled to the
pump motor drives the impeller in the pump casing.
4.1.3.2 Compressors. Compressors move gas through a process unit in much the
same way that pumps transport liquid. Compressors are typically driven with rotating or
reciprocating shafts. Thus, the sealing mechanisms for compressors are similar to those
for pumps, i.e., packed and mechanical seals. Emissions from this source type may be
reduced by improving the seals' performance or by collecting and controlling the emissions
from the seal. Emissions from mechanical contact seals depend on the type of seal or
control device used and the frequency of seal failure.
Shaft seals for compressors are of several different types: labyrinth, restrictive
carbon rings, mechanical contact, and liquid film. All of these seal types restrict leaks,
although none of them completely eliminates leakage. Compressors can be equipped with
ports in the seal area to evacuate collected gases, which could then be controlled.
A buffer or barrier fluid may be used with these mechanical seals to form a buffer
between the compressed gas and the environment, similar to barrier fluids in pumps.
This system requires a clean, external gas supply that is compatible with the gas being
compressed. Barrier gas can become contaminated and must be disposed of properly, for
example by venting to a control device. Compressors can also be equipped with liquid
film seals. This seal is formed by a film of oil between the rotating shaft and stationary
gland.
4.1.3.3 Agitators. Agitators are used to stir or blend chemicals. As with pumps and
compressors, emissions from agitators can occur at the interlace of' a moving shaft and a
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stationary casing. Emissions from this source type may be reduced by improving the seal
or by collecting and controlling emissions. There are four seal arrangements commonly
used with agitators: packed seals, mechanical seals, hydraulic seals, and lip seals.
Packed seals for agitators are similar in design and application to the packed seals for
pumps.
While mechanical seals are more costly than other seal arrangements, they provide
better leakage rate reduction. Also, the maintenance frequency of properly installed and
maintained mechanical seals is one-half to one-fourth that of packed seals. Mechanical
seals can be designed specifically for high pressure applications (i.e., greater than 1,140
kPa or 165 psia). As with packed seals, the mechanical seals for agitators are similar to
the design and application of mechanical seals for pumps.
The hydraulic seal is the simplest and least-used agitator shaft seal. In this type of
seal, an annular cup attached to the process vessel contains a liquid that contacts an
inverted cup attached to the rotating agitator shaft. The primary advantage of this seal is
that it is a noncontact seal. However, this seal is limited to low temperatures and
pressures and can only handle very small fluctuations. Process chemicals may
contaminate the seal liquid and then be released into the atmosphere as equipment leak
emissions.
Lip seals, which are relatively inexpensive and easy to install, can be used on a top-
entering agitator as a dust or vapor seal. Once the seal has been installed, the agitator
shaft rotates in continuous contact with the lip seal. Emissions can be released through
this seal when it wears excessively or when the operating pressure surpasses the pressure
limitation of the seal.
4.1.3.4 Pressure Relief Devices. Insurance, safety, and engineering codes require that
pressure relief devices or systems be used in applications where the process pressure may
exceed the maximum allowable working pressure of the process equipment. Pressure
relief devices include rupture disks and safety/relief valves. The most common pressure
relief device is a spring-loaded valve designed to open when the operating pressure of a
piece of process equipment exceeds a set pressure. Equipment luak ..-missions from
spring-loaded relief valves may be caused by failure of the valve seat or vaive stem,
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improper reseating after overpressure relief, or process operation near the relief valve set
pressure which may cause the relief valve to frequently open and close or "simmer."
Rupture disks are designed to burst at overpressure to allow the process gas to vent
directly to the atmosphere. Rupture disks allow no emissions as long as the integrity of
the disk is maintained. They must be replaced after each pressure relief episode to
restore the process to an operating pressure condition. Although rupture disks can be
used alone, they are sometimes installed upstream of a relief valve to prevent emissions
through the relief valve stem.
Combinations of rupture disks and relief valves require certain design constraints and
criteria to avoid potential safety hazards. For example, appropriate piping changes must
be made to prevent disk fragments from lodging in damaging the relief valve when
relieving overpressure. A block valve upstream of the rupture disk can be used to isolate
the rupture disk/relief valve combination and permit in-service replacement of the disk
after it bursts. Otherwise, emissions could result through the relief valve.
4.1.3.5 Open-Ended Lines. Emissions from open-ended lines are caused by leakage
through the seat of an upstream valve in the open-ended line. Emissions that occur
through the stem and gland of the valve are not considered "open-ended" emissions and
are addressed in the section on process valves. Emissions from open-ended lines can be
controlled by installing a cap, plug, flange, or second valve to the open end. Control
efficiency of these control measures is assumed to be 100 percent.
4.1.3.6 Sampling Connections. Emissions from sampling connections occur as a
result of purging the sampling line to obtain a representative sample of the process fluid.
These emissions can be reduced by using a closed loop sampling system or disposing of
the purged process fluid in a control device. The closed loop sampling system is designed
to return the purged fluid to the process at a point of lower pressure. Closed loop
sampling is assumed to be 100 percent effective for controlling emissions from a sample
purge. This purged fluid could also be directed to a control device such as an incinerator,
in which case the control efficiency would depend on the efficiency of the incinerator in
removing the VOC.
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4.1.3.7 Process Valves. There are many designs for valves, and most of the designs -
contain a valve stem which operates to restrict or allow fluid flow. Typically, the stem is
sealed by a packing gland or O-ring to prevent leakage of process fluid to the atmosphere.
Emissions from valves occur at the stem or gland area of the valve body when the packing
or O-ring in the valve fails.
Valves that require the stem to move in and out or turn must utilize a packing gland.
A variety of packing materials are suitable for conventional packing glands. The most
common packing materials are the various types of braided asbestos that contain
lubricants; other packing materials include graphite, graphite-impregnated fibers, and
tetrafluorethylene. The choice of packing material depends on the valve application and
configuration. Conventional packing glands can be used over a wide range of operating
temperatures.
Emissions from process valves can be eliminated if the valve stem can be isolated
from the process fluid. There are two types of sealless valves available: diaphragm
valves and sealed bellows valves.
Diaphragm valves isolate the valve stem from the process fluid using a flexible
elastomer or metal diaphragm. The position of the diaphragm is regulated by a plunger,
which is controlled by the stem. Depending on the diaphragm material, this type of valve
can be used at temperatures as high as 205 degrees Celsius and in strong acid service. If
the diaphragm fails, the valve can become a relatively larger source of emissions. In
addition, use at temperatures beyond the operating limits of the material tends to damage
or destroy the diaphragm.
Sealed bellows valves are another alternative leakless design. In this valve type,
metal bellows are welded to the bonnet and disk of the valve, thereby isolating the stem
from the process. These valves can be designed to withstand high temperatures and
pressures and can provide leak-free service at operating conditions beyond the limits of
diaphragm valves. However, they are usually dedicated to highly toxic services and the
nuclear industry.
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The control effectiveness of both diaphragm and sealed bellows valves is essentially
100 percent, although a failure of the diaphragm or bellows could cause temporary
emissions much larger than those from other types of valves.
4.1.3.8 Connectors. Connectors are flanges, threaded fittings, and other fittings used
to join sections of piping and equipment. They are used wherever pipe or other
equipment (such as vessels, pumps, valves, and heat exchangers) require isolation or
removal.
Flanges are bolted, gasket-sealed connectors. Normally, flanges are used for pipes
with diameters of 50 mm or greater and are classified by pressure rating and face type.
The primary cause of flange leakage are poor installation and thermal stress, which
results in the deformation of the seal between the flange faces.
Threaded fittings are made by cutting threads into the outside end of one piece (male)
and the inside end of another piece (female). These male and female parts are then
screwed together like a nut and bolt. Threaded fittings are normally used to connect
piping and equipment having diameters of 50 mm or less. Seals for these fittings are
made by coating the male threads with a sealant before joining it to the female piece.
Emissions from threaded fittings can occur as the sealant ages and eventually cracks.
Leakage can also occur as the result of poor assembly or application of the sealant, and
thermal stress of the piping and fittings.
Emissions from connectors can be controlled by regularly scheduled maintenance.
Potential emissions can be reduced by replacing the gasket or sealant materials. If
connectors are not required for process modification or periodic equipment removal,
emissions from connectors can be eliminated by welding the connectors together.
4.1.3.9 Instrumentation Systems. An instrumentation system is a group of equipment
components used to condition and convey a sample of process fluid to analyzers and
instruments for the purpose of determining process operating conditions (e.g., composition,
pressure, and flow rate). Valves and connectors are the predominant types of equipment
used in instrumentation systems, although other equipment may be included. Emissions
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resulting from the components in the instrumentation system are controlled as they are
for the same component in the process system.
Emissions from equipment leaks may be controlled by installed a closed vent system
around the leaking equipment and venting the emissions to a control device. This method
of control is only applicable to certain equipment types, i.e., pumps, compressors,
agitators, pressure relief valves, and product accumulator vessels. Because of the many
valves, connectors, and open-ended lines typically found in refineries, it is not practical to
use this technique for reducing emissions from all of these potential sources for an entire
process unit. However, a closed vent system can be used to control emissions from a
limited number of components, which could be enclosed and maintained under negative
pressure and vented to a control device.
LDAR methods are used to identify equipment components that are emitting
significant amounts of VOC and to reduce these emissions. The emission reduction
potential for LDAR as a control technique is highly variable and depends on several
factors, the most important of which are the frequency of monitoring and the techniques
used to identify leaks. Repair of leaking components is required only when the equipment
leak emissions reach a set level - the leak detection level. A low leak definition will
initiate repair at lower levels, resulting in a lower overall emission rate.
Leak detection methods include individual component surveys, area (walk-through)
surveys, and fixed point monitors. Individual component surveys form a part of the other
methods.
4.1.3.9.1 Individual Component Survey. Each source of equipment leak
emissions (pump, valve, compressor, etc.) can be checked for VOC leakage by visual.
audible, olfactory, soap bubble, or instrument techniques. Visual methods are good for
locating liquid leaks. A visible leak does not necessarily indicate VOC emissions,
however, because the leaking material may be non-VOC. High-pressure leaks may be
detected by the sound of escaping vapors, and leaks of odorous materials may be detected
by smell.
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Soap spraying on equipment components can be used to survey individual components
in certain applications. If the soap solution forms bubbles or blows away, a leak is
indicated, and vice versa. Disadvantages of this method are that 1) it does not
distinguish leaks of hazardous VOCs from nonhazardous VOCs; 2) it is only
semiquantitative, since it requires the observer to determine subjectively the rate of
leakage based on the behavior of the soap bubbles; and 3) it is limited to sources with
temperatures below 100 degrees Celsius, because the water in the soap solution will
evaporate at temperatures above this figure. This method is also not suited for moving
shafts on pumps or compressors, because the motion of the shaft may interfere with the
motion of the bubbles caused by a leak.
The best method for identifying leaks of VOC from components is using a portable
hydrocarbon detection instrument. Air close to the potential leak site is sampled and
analyzed by a sampling traverse ("monitoring") over the entire are where leaks may occur.
The concentration of hydrocarbons in the sampled air is displayed on the instrument
meter and is a rough indicator of the VOC emission rate from the component. If the
concentration is higher than a specified figure ("action level"), then the leaking component
is marked for repair.
4.1.3.9.2 Area Survey. An area or walk-through survey requires the use of a
portable hydrocarbon detector and a strip chart recorder. The procedure involves carrying
the instrument within one meter of the upwind and downwind sides of process equipment.
The instrument is then used for an individual component survey in a suspected leak area.
The efficiency of this method for locating leaks is not well established. Problems with this
method include the fact that leaks from overhead valves or relief valves will not be-
detected, and the possibility of leaks from adjacent units and adverse meteorological
conditions affecting the results of the walk-through survey. Thus, the area survey is best
for locating only large leaks at small expense.
4.1.3.9.3 Fixed Point Monitors. This method consists of placing several
automatic hydrocarbon sampling and analysis instruments at various locations in the
process unit. If elevated hydrocarbon concentrations are detected, a leaking component is
indicated. Identifying the specific leaking component reauires an individual component
survey. The efficiency of fixed point monitoring is not weil established, out fixed point
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monitoring of VOCs is not as effective as a complete individual component survey. Fixed-
point monitors are expensive, multiple units may be required, and the portable
instrument is also needed to locate the particular leaking component. Calibration and
maintenance costs may be high. Fixed-point monitors are used successfully to detect
emissions of hazardous or toxic substances, and can provide an increased detection
efficiency by selecting a particular compound as the sampling criterion.
4.1.3.9.4 Repair Methods. This section describes repair methods for possible
equipment emission sources in a refinery. These are not intended to be complete repair
procedures.
Many pumps have in-line or parallel spares that can be used while the leaking pump
is being repaired. Leaks from packed seals may be reduced by tightening the packing
gland. With mechanical seals, the pump must be dismantled to repair or replace the
leaking seal. Dismantling pumps can result in spillage of some process fluid. If the seal
leak is small, evaporative emissions of VOC from such spillage may be greater than the
continued leak from the seal. Precautions must be taken to prevent or reduce these
emissions.
Leakage from compressors with packed seals may be reduced by tightening the
packing gland, as described for pumps. Repair of compressors with mechanical seals
requires the compressor be removed from service. Since compressors usually do not have
spares, immediate repair may not be practical or possible without a process unit
shutdown.
Agitators, like pumps and compressors, can leak VOCs at the point where the shaft
penetrates the casing, and seals are required to minimize fugitive emissions. Leaks from
packed seals may be reduced by the repair procedure described for pumps, while repair of
other types of seals require the agitator to be out of service. In this latter case, process
shutdown or isolation of the particular agitator being repaired is required.
Leaking repair valves usually must be removed for repair. To remove the relief valve
without shutting down the process, a block valve mav be required unstream of the -"Hief
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valve. A spare relief valve should be attached while the faulty valve is repaired and
tested.
A rupture disk can be installed upstream from a pressure relief valve to eliminate
leaks until an overpressure release occurs. Once a release occurs, the rupture disk must
be replaced to prevent further leaks. A block valve is required to isolate the rupture disk
for replacement.
Most valves have a packing gland that can be tightened while in service. Although
this procedure should decrease the emissions from the valve, it can actually increase the
emission rate if the packing is old and brittle or has been over-tightened. Some types of
valves have no means of in-service repair and must be isolated from the process and
removed for repair and replacement. Most control valves have a manual bypass loop that
allows them to be isolated and removed. Most block valves cannot be isolated easily,
although temporary changes in process operation may allow isolation in some cases.
In some cases, leaks from connectors can be reduced by replacing the connector
gaskets, but most connectors cannot be isolated to permit gasket replacement. Tightening
of connector bolts also may reduce emissions from connectors. Where connectors are not
required for process modification or periodic equipment removal, emissions from
connectors can be eliminated by welding them.
• 4.1.4 Internal Floating Roofs
Internal floating roofs are commonly used in the petroleum refining industry to
control emissions from fixed-roof storage tanks. As the name implies, it is a roof inside a
tank that floats on the surface of the stored liquid.
The presence of a floating roof (or deck) inside a fixed roof tank significantly reduces
the surface area of exposed liquid. It serves as a physical barrier between the volatile
organic liquid and the air that enters the tank through vents.
Because evaporation is the primary emission mechanism associated with storage
tanks, emissions from floating roof tanks as well as fixed root' tanks vary with the va
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pressure of the stored liquid. Thus, the control efficiency of retrofitting a fixed roof tank
with an internal floating deck depends on the material being stored.
Other factors affecting emissions, and therefore control efficiency, are tank size,
number of turnovers, and the type of deck and seal system selected. Installing an
internal floating roof can reduce emissions by 61 to 98 percent. The relative effectiveness
of one internal floating roof design over another is a function of how well the deck can be
sealed. Probably the most typical internal floating roof design is the noncontact, bolted,
aluminum internal floating roof with a single vapor-mounted wiper seal and uncontrolled
fittings.
Loss of VOCs from internal floating roof tanks occurs in one of four ways:
1) Through the annular rim space around the perimeter of the floating roof (seal
losses),
2) Through the openings in the deck required for various types of fittings (fitting
losses),
3) Through the nonwelded seams formed when joining sections of the deck material
(deck seam losses), and
4) Through evaporation of liquid left on the tank wall following withdrawal of liquid
from the tank (withdrawal loss).
4.1.4.1 Control of Seal Losses. Internal floating roof seal losses can be minimized by
employing liquid-mounted primary seals instead of vapor-mounted seals and/or by
employing secondary wiper seals in addition to primary seals.
Available emissions test data suggest that the location of the seal (i.e., vapor- or
liquid-mounted) and the presence of a secondary seal are the major factors affecting seal
losses. A liquid-mounted primary seal has a lower emissions rate, and thus a higher
control efficiency, than a vapor-mounted seal. A secondary seal, with either a liquid- or a
vapor-mounted primary seal, provides an additional level of control.
The type of seal used plays a less significant role in determining the emissions rate.
The type of seal is important only to the extent that the seal must be suitable for the
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particular application. For instance, an elastomeric wiper seal is commonly employed as
a vapor-mounted primary seal or as a secondary seal for an internal floating roof.
Because of its shape, this seal is not suitable for use as a liquid-mounted primary seal.
Resilient foam seals, on the other hand, can be used as both liquid- and vapor-mounted
seals.
4.1.4.2 Control of Fitting Losses. There are numerous fittings that penetrate or are
attached to an internal floating roof. Among them are access hatches, column wells, roof
legs, sample pipes, ladder wells, vacuum breakers, and automatic gauge float wells.
Fitting losses occur when VOCs leak around these fittings. Fitting losses can be
controlled with gasketing and sealing techniques or by the substitution of fittings that are
designed to leak less.
The effectiveness of fitting controls at reducing the overall emission rate is a function
of the number of fittings of each type employed on a given tank. For example, if using
controlled fittings reduces total fitting loss by 36 percent, and if fitting losses are about 35
percent of the total emissions from a typical internal floating roof tank, then the
controlled fittings reduce the overall emissions by (.36*.35)= .126, or 12.6 percent over a
similar tank without fitting controls. The usual increase in control efficiency achieved by
installing controlled fittings ranges from 0.5 to 1.0 percent.
4.1.4.3 Control of Deck Seam Losses. Deck seam losses are inherent in a number of
floating roof types including internal floating roofs. Any roof constructed of sheets or
•
panels fastened by mechanical fasteners (e.g., bolts) is expected to have deck seam losses.
Deck seam losses are considered to be a function of the length of the seams and not the
type of mechanical fastener or the position of the deck relative to the liquid surface. This
is a conclusion drawn from a 1986 study on two roof types with significantly different
mechanical fasteners and differences in the amount of contact with the liquid surface.
Deck seam losses are controlled by selecting a roof type with vapor-tight deck seams.
The welded deck seams on steel pan roofs are vapor tight. Fiberglass lapped seams of a
glass fiber reinforced polyester roof may be vapor tight as long as there is negligible
permeability of the liquid through the seam lapping materials. Some manufacturers
provide Baskets for bolted metal deck seams.
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Selecting a welded roof (rather than a bolted roof) will eliminate deck seam losses.
For a typical internal roof that has primary seals, secondary seals, and controlled fittings
already, eliminating deck seam losses will raise the control efficiency as much as 1.5
percent.
4.1.4.4 Applicability. The applicability of any storage tank improvement in order to
reduce VOC emissions is dependent upon the characteristics of the particular VOC. Since
floating decks are often constructed primarily of aluminum, they may not be applicable to
tanks storing halogenated compounds, pesticides, or other compounds that are
incompatible with aluminum. Contact between these compounds and an aluminum deck
could corrode the deck and cause product contamination.
In addition, vapor pressures may affect the selection of tank improvements as an
applicable control technology. For chemicals with very low vapor pressure, fixed roof tank
emissions will already be so low that installing an internal floating roof may not
significantly reduce emissions further. For chemicals with vapor pressures up to 65 kPa
(9.4 psia), emission reductions of 95 percent and above are achievable with this
technology. Above this vapor pressure, achievable emission reduction starts to decrease
with increasing vapor pressure. Thus, an internal floating roof may not be indicated for
chemicals with relatively high vapor pressures.1
4.2 DESCRIPTION OF MACT AND SUMMARY OF REGULATORY
ALTERNATIVES
The 'CAA requires that in designating regulatory options, the maximum degree of
reduction in emissions that is deemed achievable shall be subject to a floor, which is
determined differently for new and existing sources. For new sources, the standards must
be set at levels which are not any less stringent than the emission control that is achieved
in practice by the best controlled similar source. For existing sources, the standards may
not be less stringent than the average emission limitation achieved by the best performing
12 percent of existing sources in each category or subcategory of 30 or more sources. In
determining whether the standard should be more stringent than the floor and by how
much. EPA is to consider, amonu other things, the oor,t if -.chuivimr ~nch ,;dcntin
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presented separately in the following sections. The chosen option and any more stringent
options are presented separately for each of the four emission points.
4.2.1 Miscellaneous Process Vents
This section summarizes the MACT floors as they relate to miscellaneous process
vents. EPA used the percentage of miscellaneous process vents that are controlled by
combustion at a refinery to determine which refineries represent the best performing
12 percent of sources for miscellaneous process vents. The average level of control for the
top 12 percent of sources is combustion control of all miscellaneous process vents. Data
analyses conducted in developing previous NSPSs and the HON determined that
combustion controls can achieve 98 percent organic HAP reduction or an outlet organic
HAP concentration of 20 ppmv for all vent streams. This represents the MACT floor level
of control for existing sources. Regulatory options more stringent than the floor were not
investigated for miscellaneous process vents because no available technology that is
generally applicable can achieve a more stringent level of control than the MACT floor.
Therefore, the standard being proposed for miscellaneous process vents at existing sources
is the MACT floor. The new source MACT floor also includes reduction of emissions from
miscellaneous process vents by 98 percent or to a level of 20 ppmv.
4.2.2 Storage Vessels
This section summarizes the MACT floors for storage vessels. The information that
EPA used in determining the floor level of control for existing storage vessels consisted of
the types of storage vessels, vessel capacities, existing controls on vessels, and true vapor
pressures of stored liquids reported by refineries responding to survey questionnaires.
EPA compared the baseline level of control on each storage vessel at each refinery with
the storage vessel control requirements (with the exception of fitting requirements for
floating roof vessels) of subpart Kb of 40 CFR 60. Subpart Kb represents the best control
technology for storage vessels. It requires either floating roofs with specified seals and
fittings or closed vent systems and control devices.
Once the best performing 12 percent were identified, the average true vapor pressure
of the stored liquids being controlled at these refineries was determined. The iVLr
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level of control for existing sources is: vessels with capacities greater than or equal to
177 cubic meters (1,115 barrels or 47,000 gallons) storing liquids with true vapor
pressures greater than or equal to 23 kilopascals (kPa) (3.4 psia) must be controlled to the
requirements of subpart Kb with the exception of the controlled fitting requirements for
floating roof vessels. EPA determined, based on the available data, that an emission
reduction more stringent than the level associated with the floor is not cost effective.
To determine the MACT floor for storage vessels at new sources, EPA reviewed other
State and Federal storage vessel regulations. The MACT floor and an option more
stringent than the floor requiring control of storage vessels with vapor pressures above
0.014 kPa (0.002 psia) (which is the same as option 3 for existing sources) was also
considered. The proposed level of control for new sources is the MACT floor. Vessels with
capacities greater than or equal to 151 m3 (950 barrels or 40,000 gallons) storing liquids
with true vapor pressures greater than or equal to 3.4 kPa (0.5 psia), and vessels with
capacities greater than or equal to 76 m3 (475 barrels or 20,000 gallons) storing liquids
with vapor pressures equal to or greater than 77 kPa (11.1 psia) would be required to
comply with the subpart Kb (including the controlled fitting requirements). The option
more stringent than the floor was not selected because it would result in high costs
relative to HAP emission reductions.
4.2.3 Wastewater Streams
This section summarizes the MACT floors for wastewater streams. The alternative
selected for proposal is the floor level of control (compliance with the Benzene Waste
Operations NESHAP (BWON)). The BWON controls 75 percent of the benzene in refinery
wastewater and 76 percent of the volatile organic HAP in refinery wastewater. The best
performing wastewater control systems are those that are m place to comply with the
BWON. These systems control not only benzene, but also the other organic HAPs in
petroleum refinery wastewater. The BWON controls 75 percent of the benzene in refinery
wastewater nationwide and 76 percent of the volatile organic HAP in refinery wastewater
Benzene is an effective surrogate for indicating the presence of all HAP compounds in
petroleum refinery wastewater because data show that the majority of the total HAP
compound loading in wastewater consists of comnounds *h;it \ro vorv -imilar to bsr'z-^e
in terms of both chemical structure and volatility (from the water phase !.o the air pnase)
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Because the proposed standard for wastewater requires compliance with the existing
BWON, no additional emission reduction, cost, energy, or other environmental or health
impacts are associated with the proposed standard. Based on data provided to the EPA
through the BWON 90-day reports, the EPA determined that the BWON was applicable
to 43 percent of the refineries. No refineries are known to have more stringent controls
than the BWON. Therefore, the MACT floor, or the average of the top performing
12 percent of sources, is control to the BWON level of control.
EPA also considered an alternative level of emission reduction more stringent than
the MACT floor that would be achieved by controlling all wastewater streams with at
least 10 ppmw benzene at any refinery regardless of the size of its annual benzene
loading. This alternative control option was not selected because the additional emission
reduction achieved through further control was not significant, given the associated costs.
The floor alternative was selected as the proposed level of control for new sources. As
with existing sources, the option more stringent than the floor was considered, but was
rejected for new sources for the same reason described above for existing sources.
4.2.4 Equipment Leaks
The section summarizes the MACT floors for equipment leaks. EPA determined that
the average control level of the best-controlled 12 percent of sources, the MACT floor level
of control, is between the level of control required by the petroleum refinery CTG and the
petroleum refinery NSPS. For costing purposes, the petroleum refinery NSPS level of
control was used for the MACT floor option. (This was done because it would have been
difficult to determine the requirements for an option in between the two items.) The
NSPS level of control results in a conservative estimate of the cost associated with the
MACT floor.
Two options above the floor were also considered based on the negotiated rule for
equipment leaks (40 CFR 63, subpart H). Option 1 was the negotiated rule without the
connector provisions, and option 2 was the negotiated rule. The proposed standard is the
negotiated rule without the connector provisions (option 1), with a few exceptions. The
more stringent option, requiring the same connector monitoring as the negotiated niie tor
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all refineries, was not selected due to the small additional emission reductions and high
incremental costs. The negotiated rule for equipment leaks implements the leak detection
and repair program for pumps and valves in three phases, with lower leak definitions in
the later phases. For new sources, EPA proposes to require refinery sources to meet the
same requirements as proposed for existing sources. Because the equipment leak
provisions of the proposed rule are work practice and equipment standards, monitoring,
repairing leaks, and maintaining the required records constitutes compliance with the
rule.2
4.2.5 Summary of Alternatives
Based on the determination of the MACT floor for each of the four emission points,
EPA developed two regulatory alternatives. Alternative 1 is a hybrid option, referred to
as the preferred alternative, which incorporates MACT floor level control for wastewater
streams, storage vessels, and miscellaneous process vents, and an option above the floor
for equipment leaks. Alternative 2 includes control levels above the floor for equipment
leaks and storage vessels. Table 4-1 presents a summary of the options included in this
analysis.
4.3 NO ADDITIONAL EPA REGULATION
E.O. 12866 requires that the rationale for regulation versus no regulation must be
addressed in the decision process. To satisfy this requirement, this section presents the
alternatives to regulation of HAP emissions from petroleum refineries. The alternatives
include reliance on the judicial system for pollution control, or reliance on regulation by
States and localities.
4.3.1 Judicial System
In the absence of governmental regulation, market systems fail to make the
generators of pollution pay for the costs associated with that pollution. For an individual
firm, pollution is an apparently unusable by-product that can be disposed of cheaply by
venting it to the atmosphere. However, in the atmosphere, pollution '.-auses real costs to
others. The fact that producers, consumers, and others whose activities result in air
69
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pollution do not bear the full costs of their actions leads to a divergence between private
costs and social costs. This divergence is considered a market failure, since it results in a
misallocation of society's resources. Too many resources are devoted to the polluting
activity when polluters do not bear the full cost of their actions. Also, if there was no
regulation, the previous regulations would be relied upon as the basis for making judicial
decisions regarding excess emissions.
4.3.2 State and Local Action
The CAA requires each State to develop and implement measures to attain and
maintain EPA's standards. Each State assembles these measures in a document called
the State Implementation Plan (SIP). SIPs must be approved by EPA, and EPA is
empowered to compel revision of plans it believes are inadequate. EPA may assume
enforcement authority over air pollution control programs any State fails to implement.
The standards will become parts of each State's SIP, and enforcement authority will be
delegated to the States. If the EPA were not to promulgate the standards, States would
be responsible for making case-by case MACT decisions under Section 112 (g) and (j)
whenever there is a major modification, or when the date for MACT promulgation has
passed without action on EPA's part.
EPA believes that reliance on State and local action is not a viable substitute for the
standards. This belief holds even if EPA were to step up research and technology transfer
programs to assist State and local governments.
4.4 ROLE OF COST EFFECTIVENESS IN CHOOSING AMONG REGULATORY
ALTERNATIVES
EPA has often used cost effectiveness (C/E) analysis as a guide for selecting among
regulatory alternatives. Regulatory alternatives can sometimes be ranked based on
stringency of control. All else equal, alternatives yielding the same level of control but
higher average C/E (usually control cost per ton of pollutant reduced) could be eliminated
from consideration. Incremental C/E can then be calculated for each step up the
stringency ranking. The selection of a regulatory alternative could then be made by
choosing the most stringent alternative below some agreed upon C/E cutoff. The level of
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such a C/E cutoff would generally depend on the pollutant being controlled and other
factors.
However, since the Petroleum Refinery NESHAP is to be a MACT standard, the role
of C/E analysis for selecting a regulatory alternative for this regulation is somewhat
limited. A MACT floor level of control stringency is required regardless of the C/E at this
control level. At stringency levels beyond the MACT floor, cost effectiveness can be
legally considered, and EPA believes cost-effectiveness of controls is a primary
consideration for evaluating stringency levels beyond the MACT floor. The average cost
effectiveness of the regulation ($/Mg of pollutant removed) is included as part of the cost
analysis in Chapter 5.
4.5 ECONOMIC INCENTIVES: SUBSIDIES, FEES, AND MARKETABLE
PERMITS
Economic incentive strategies, when designed properly, act to harness the
marketplace to work for the environment. In deciding among regulatory options, EPA is
required to consider as options such strategies which influence, rather than dictate,
producer and consumer behavior, in order to achieve environmental goals. Economic
incentive programs make environmental protection of economic interest to producers and
consumers. When feasible, properly designed systems can be employed to- achieve any
environmental goal at the least cost to society.
Several types or categories of economic incentive strategies exist. One broad category
of incentive programs is based of the use of fees or subsidies. Fee programs establish and
collect a fee on emissions, providing a direct economic incentive for emitters to decrease
emissions to the point where the cost of abating emissions equals the fee.! Similarly,
subsidy programs provide a direct incentive for emitters to decrease emissions by
providing subsidy payments for emission reductions beyond some baseline.
A second broad category of economic incentive strategies is based on the concept of
emissions trading. A wide range of variations in emissions trading programs are possible.
The common idea in such programs is to allow sources with low abatement cost
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alternatives to trade or sell emission allowances to sources with higher abatement cost
alternatives so that the cost of meeting a given total level of abatement is minimized.
There are two important constraints regarding the workability of economic incentive
programs. The first constraint concerns the problem of emissions monitoring. Without an
effective emissions monitoring system it is not possible to charge fees or use other
economic incentive strategies. Only the traditional "command and control" approach of
requiring employment of specific control technologies is feasible in this circumstance.
The second problem constraining the potential value of economic incentive strategies
is legal. Various legal restrictions imposed by the CAA limit the applicability of economic
incentive strategies to reduce air pollution.
Legal constraints imposed by Title III of the Act severely limit the usefulness of
economic incentive strategies for reducing HAP emissions. Title III requires the
implementation of MACT. Thus sources have little or no choice as to the type or level of
control they implement except perhaps if going beyond the MACT floor control level. As a
limited economic incentive, it may then be possible to impose, for example, an emissions
fee on residual emissions after the MACT technology is employed to encourage additional
control.
The applicability of economic incentive programs for the petroleum refinery NESHAP
is therefore very limited. However, emissions averaging at the facility level may be
feasible and legal given that each facility is considered an emissions source. This
emissions averaging strategy allows facilities to trade emission reductions across emission
points so as to minimize control costs for any given facility level emission reduction
requirement. Thus, to this extent, an economic incentive strategy may be implemented
for the Petroleum Refinery NESHAP regulation. The analysis of control costs (Chapter 5)
does not incorporate emission averaging. It is recognized that if emissions averaging were
incorporated into the standard, facilities' costs of control should fall. Thus, the costs
calculated could be an overestimate.
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REFERENCES
1. U.S. Environmental Protection Agency. Regulatory Impact Analysis for the National
Emissions Standards for Hazardous Air Pollutants for Source Categories: Organic
Hazardous Air Pollutants from the Synthetic Organic Chemical Manufacturing
Industry and Seven Other Processes. EPA-450/3-92-009. pp. 4-1 to 4-41. December
1992.
2. U.S. Environmental Protection Agency. Office of Air Quality Planning and Standards.
Draft Preamble for the HON. December 1993.
3. U.S. Environmental Protection Agency. Office of Air Quality Planning and Standards.
Draft Preamble for the Petroleum Refinery NESHAP. January 1994.
4. Reference 2.
5. U.S. Environmental Protection Agency. Office of Air Quality Planning and Standards.
Municipal Waste Landfills - Regulatory Impact Analysis. March 1991.
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5.0 COST ANALYSIS AND EMISSION REDUCTION
Section 5.1 of this chapter presents the methodology used to estimate the regulatory
compliance costs for the options which were listed in Table 4-1. Section 5.2 presents total
compliance costs by emission point, the corresponding emission reductions for each
alternative, and discusses the cost effectiveness of controlling each of the four petroleum
refinery emission points. Section 5.4 presents any cost categories not directly associated
with a control technique, including monitoring, reporting, and recordkeeping costs.
5.1 APPROACH FOR ESTIMATING REGULATORY COMPLIANCE COSTS
This section explains the methods used for estimating the emissions associated with
petroleum refineries and the impact associated with controlling existing petroleum
refinery emission sources using various alternative control technologies. These estimates
are used to compare different control alternatives and select the provisions for the
proposed NESHAP for petroleum refineries.
Emissions and control impacts were estimated for each of the four petroleum refinery
emission points: storage vessels, wastewater collection and treatment systems, equipment
leaks, and miscellaneous process vents. The control impact estimates include estimates of
emission reductions, control costs, and where applicable, energy impact. A qualitative
assessment of the possible impact of secondary air pollution, water pollution, or solid
waste generation is also included.
The emissions calculations involved three steps: (1) development of a database
characterizing refineries. (2) develoDment and assignment of ~calinir rncr,orH ">
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of emission point to use for estimating emissions for refineries that provided no data, and
(3) calculation of nationwide emissions and control impacts.
The database included the processes and technology used to produce refinery products
and controls used to reduce emissions. This information came from responses to survey
questionnaires sent out under section 114 of the CAA and information collection requests.
Refineries across the United States responded to the questionnaires and provided control
and process information for process vents, storage vessels, wastewater treatment systems,
and leaking equipment. In addition, information on existing regulations was compiled to
determine the control requirements that apply to petroleum refineries.
Because site-specific data were not available for every refinery, scaling factors
relating refinery process parameters or emissions to the charge capacity of refinery
processes were derived from the available data. Estimates of emissions and control
impacts for refineries for which data were lacking were derived using scaling factors.
Scaling factors could be used because the emission mechanisms and applicable control
technologies are well understood for the kinds of sources to be regulated by the petroleum
refinery NESHAP, and these characteristics are similar from refinery to refinery.
Baseline emissions represent emission levels from petroleum refineries that would
occur in the absence of a refinery MACT standard. Baseline emissions were estimated
using calculation algorithms based on known, previously published, well-established
methods from the process charge capacities of the refineries in the database and the data
reported in the questionnaire responses. The impact of each alternative control level was
estimated using previously developed cost algorithms and control efficiencies for
commonly used control technologies. The control technologies included in the analysis
were chosen because they can achieve emission reductions at least as stringent as the
MACT floor. While the selected control technologies were used as the basis of the control
impacts estimates, the proposed standards are written using formats that would allow use
of other control technologies if the equivalent emission reduction is achieved.
The impact estimates are based on average, representative, or typical emissions and
control requirements for each kind of source. Thus, the estimates do not reflect the
impact thac would be observed at any particular re fine rv. However, they do provide ;i
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reasonable estimate of nationwide emission reductions and represent the range of control
costs that refineries might incur under different regulatory alternatives.
The specific procedures used to estimate baseline emissions and the costs and
emission reductions for the different control alternatives for each kind of emission point
are described separately for new and existing sources.
5.1.2 Calculations for Existing Sources
For existing petroleum refinery sources, baseline emissions and control impacts were
calculated for the four sources for individual refineries and aggregated to determine
nationwide impacts. Some sources were not as well characterized as others. In these
cases, the available information was extrapolated to derive nationwide estimates.
5.1.2.1 Storage Vessels. Emissions and emission reductions from storage vessels are
a function of the volatility of the material stored and the type of storage vessel.
Responses to questionnaires sent to refineries provided information on the volatility and
HAP content of materials stored and the types of vessels used to store materials. Based
on information in the questionnaire responses, factors for storage vessel population and
VOC emissions were developed and used to estimate baseline emissions of HAPs and
VOC, emission reductions at the floor level of control and above, and costs for controlling
emissions to the floor level of control and to levels more stringent than the floor. Thirteen
"major" petroleum liquids were included in this analysis: crude oil, gasoline, naphtha,
asphalt, alkylate, reformate, jet kerosene/kerosene, heavy gas oil, aviation gasoline,
diesel/distillate, jet fuel (#4), residual fuel oil, and slop oil. In a previous analysis using
all available information, these 13 petroleum liquids accounted for more than 80 percent
of the estimated nationwide baseline VOC emissions.
The storage vessel population factors were used to estimate the total number of
vessels at each refinery. The storage vessels reported in the questionnaire responses were
divided into groups based on storage vessel type (e.g., fixed roof), refinery crude capacity
(greater than or less than 150,000 barrels per calendar day (bbls/cd)), and petroleum
liquid stored (e.g., gasoline, naphtha, etc.). The average number of vessels in each ^roup
per barrel of crude capacity at a refinery was the tank population factor. For example,
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the questionnaire responses indicated that the number of internal floating roof vessels
storing gasoline at refineries with crude capacities greater than 150,000 bbls/cd was
1.2 x 10 storage vessels per barrel of crude capacity per day. That is, a refinery of
267,000 barrels per day would have two internal floating roof tanks storing gasoline.
VOC emission factors were calculated for each storage vessel grouping. To calculate
the VOC factor, VOC emissions from the storage vessels reported in the questionnaire
responses were estimated using equations in chapter 12 of AP-42. Where data were
missing or insufficient, default values, developed from information in the questionnaire
responses, were used. Average VOC emission factors at the baseline level of control were
then calculated for each vessel grouping. For example, for internal floating roof vessels
storing gasoline at refineries with crude capacities greater than 150,000 bbls/cd, an
average VOC emission factor of 15,000 Ibs VOC emitted/vessel was calculated.
The number of vessels and the baseline VOC emissions nationwide were estimated in
the following way. The crude capacity of each refinery in the nation, as listed in OGJ,
was multiplied by the population factor for each applicable type of vessel to estimate the
numbers and types of vessels at each refinery. This yielded the nationwide storage vessel
population. The baseline VOC emission factor (Ib VOC emitted/vessel) corresponding to
each vessel type was multiplied by the number of vessels of that type to calculate the
baseline VOC emissions at each refinery. For example, for internal floating roof vessels
storing gasoline at refineries with crude capacities greater than 150,000 bbls/cd the
refinery crude capacity,, times the tank population factor of 1.2 x 10J vessels per barrel,
times the VOC emission factor of 15,000 Ib VOC emitted/vessel yielded the estimated
VOC emissions. Certain petroleum liquids (e.g., asphalt, alkylate, and reformate) are
directly associated with specific process units. If OGJ did not list capacities for these
specific process units, then the vessel population factor corresponding to that process unit
was not applied to that refinery. (For more information, refer to "Summary of Nationwide
Volatile Organic Compound and Hazardous Air Pollutant Emission Estimates from
Petroleum Refineries," in the docket).
Emissions of HAPs were estimated by multiplying the VOC emissions calculated for
each type of material stored by the average HAP weight fraction in the vapor phase of the
material. Average vapor phase BAP weight fractions were calculated from the HAP
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liquid concentrations (obtained from industry questionnaire responses) using Raoult's Law
and the vapor pressure of the individual HAPs.
Emission reductions and costs for control options were estimated using the
extrapolated nationwide storage vessel population. For all control options, factors for
average emission reduction and costs were developed by calculating specific emission
reductions and costs for the 3,400 storage vessels reported in the questionnaire responses.
Average emission reduction and cost factors were then calculated for each storage vessel
group.
An analysis of refinery storage vessels indicated that the MACT floor level of control
for existing sources is an internal floating roof with seals that comply with the NSPS for
and with the hazardous organic NESHAP (HON) storage. Costs were estimated for
equipping existing fixed roof storage vessels with an internal floating roof and seals that
comply with specifications in the storage NSPS (40 CFR 60 subpart Kb) and HON
(40 CFR 63 subpart G). For existing external and internal floating roof vessels, costs
were estimated for installing seals that comply with the proposed HON seal requirements.
The MACT floor level of control for existing floating roof storage vessels does not include
complying with the fitting requirements in the proposed HON.
More stringent controls were not identified for existing fixed roof storage vessels. For
existing external and internal floating roof vessels, the more stringent control alternative
is to comply with the fitting requirements in the proposed HON in addition to the seal
requirements.
The emission reduction assigned to each of the 3,400 storage vessels was calculated as
a function of the emission reductions presented in the EPA publication "NSPS VOC
Emissions from VOL Storage Tanks—Background Information for Proposed Standards".
This document provided the emission reduction (in percent) of various seal and fitting
configurations compared with fixed roof vessels. For example, an internal floating roof
vessel with a liquid mounted primary seal and controlled fittings has an average emission
reduction of 96.2 percent over a similar sized fixed roof vessel. Adding a rim-mounted
secondary seal increases this emission reduction to 96.6 percent. Therefore, the
incremental emission reduction gained by adding the nm mounted secondary seal is
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0.4 percent. The emission reduction applied to each storage vessel was calculated as the
difference between the level of control required by the control option and the baseline
level of control.
The cost equations for converting existing fixed roof vessels to internal floating roof
vessels were taken from the "Control of Volatile Organic Compound Emissions from
Volatile Organic Liquid Storage in Floating and Fixed Roof Tanks" (Draft, July 1992), and
"Internal Instruction Manual for ESD Regulation-Storage Tanks" (January 1993). The
cost equations for adding seals and controlled fittings to existing external and internal
floating roof vessels were also taken from these two documents.
5.1.2.2 Wastewater Collection and Treatment Systems. Emissions and emission
reductions from wastewater collection and treatment systems are both a function of
wastewater stream flow, the HAP compound concentration in the wastewater, and the
volatility of the HAP compounds in the wastewater. Emission reductions are also a
function of the design and operating parameters of the control device.
EPA gathered data for the wastewater stream flow rate and the concentration of
HAPs in petroleum refinery wastewater to develop models of wastewater from process
units found at refineries. Each model process unit was assigned representative values for
the concentration and volatility of the HAPs in its wastewater stream. A ratio of
wastewater stream flow to refinery crude capacity was also developed for each model
process unit and applied to the capacities reported in OGJ for each process unit at each
refinery. (For more information, refer to "Data Summary for Petroleum Refinery
Wastewater," in the docket). Mass loadings of volatile HAP in wastewater were
determined by multiplying volatile HAP concentrations by capacity-based wastewater
stream flow rates for each process unit at each refinery in the nation. The results of prior
EPA analyses developed for the HON were judged to be appropriate to use to estimate the
cumulative mass fraction of HAPs emitted from wastewater collection and treatment
systems.
Uncontrolled emissions were determined by multiplying the mass fraction of HAPs
emitted by the mass loading of volatile HAPs. However, many petroleum refineries
control their wastewater collection and treatment systems in accordance with the BWON.
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(For more information, refer to "The Effectiveness of the BWON in Controlling Volatile
HAP Mass Loading in Petroleum Refinery Wastewater," in the docket). These controls
were credited in the national baseline emissions calculations by applying the applicability
criteria of the BWON (i.e., waste-water streams with flows greater than 0.02 1/min and
benzene concentration of 10 ppmw or greater at a facility with at least 10 Mg/yr total
annual benzene loading in wastes and wastewater) to each refinery and wastewater
stream and by assuming that the control requirements of the BWON (i.e., 99 percent
reduction of benzene) were met for those streams requiring control.
An analysis of existing refinery wastewater collection and treatment systems
indicated that the MACT floor for wastewater is the BWON. (For more information, refer
to ["Maximum Achievable Control Technology Floor for Process Wastewater Streams at
Petroleum Refineries,"] in the docket). Existing refineries are already required to comply
with the BWON, so no emission reductions or costs would be associated with the floor
option for refinery wastewater sources. In considering a control option more stringent
than the BWON, the EPA assessed the effects of lowering the applicability threshold of
the BWON, by eliminating the cutoff of 10 Mg/yr TAB loading in facility wastes and
wastewater. The additional wastewater streams requiring control (those streams with at
least 10 ppmw benzene at refineries with a TAB under the 10 Mg/yr loading criterion)
were assumed to be steam stripped to achieve reductions equivalent to the requirements
of the BWON Ce.g., 99 percent reduction of benzene). The overheads from the steam
stripper were assumed to be sent to a combustion device. (For more information, refer to
["Control Option Above the Floor for Petroleum Refinery Process Wastewater,"] in the
docket). The results of prior EPA analyses were used to estimate the mass fraction of
HAPs removed from a wastewater stream by a steam stripper as well as the costs
associated with the stripper system. (For more information, refer to "Steam Stripper
Removals and Costing for Petroleum Refinery Wastewater," in the docket). The results of
those analyses indicate that the selected steam stripper design and operating parameters
achieve a 95 to 99 percent removal, depending on the volatility of the HAPs in the stream.
5.1.2.3 Equipment Leaks. Emissions and emission reductions from leaking
equipment are a function of the component counts and the control program used to reduce
emissions. The questionnaires were designed to obtain equipment leak information for
18 different refinery process units because the controls required may vary from process
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unit to process unit. The questionnaire responses included information on component
counts, the HAP content of refinery process streams, and the monitoring frequencies and
leak definitions used for leak detection and repair programs for each refinery process unit.
The monitoring frequencies and leak definitions reported for each process unit were
matched to the requirements of existing LDAR programs to determine which control
program was being used to reduce emissions.
Data on equipment leaks were reported by approximately 70 percent of the refineries
in the nation. For those refineries not reporting information, the characteristics of model
process units (for each of the 18 process units of interest) were assigned to the refinery
based on information in OGJ. The model process units were developed as the median
component count of the process units from refineries reporting information in the surveys.
If OGJ data indicated that a refinery contained a specific process unit, then the median
counts for the model representing that process unit was assigned to the refinery. If the
refinery was determined to be in an ozone nonattainment area, the EPA assumed that the
refinery would be controlled to the level of control in the petroleum refinery CTG.
Uncontrolled HAP emissions from each of the 18 different refinery process units were
estimated by multiplying the uncontrolled VOC emissions from each unit by the average
HAP-to-VOC ratio of the streams associated with each unit. Uncontrolled VOC emissions
from leaking equipment were estimated on a process unit basis by multiplying the
component counts for the process unit by VOC emission factors for each equipment
component. The VOC emission factors relate VOC emissions to the type of component
leaking (e.g., pumps, valves, etc.) in units of Ib/hr/component type. The emission factors
used for the impacts analysis were taken from a previous EPA study on leaking refinery
equipment and presented in chapter 9 of AP-42. These emission factors are currently
being reviewed by EPA based on new industry data. The emission estimates may be
revised at promulgation if new factors are developed by EPA based on the new industry
data.
Baseline emissions of HAPs and VOC were estimated by multiplying the uncontrolled
emissions by one minus the control efficiencies associated with each LDAR program
reported by or assigned to each refinery. The "Equipment Leaks Enabling Document' (in
the docKetj provides information on the control efficiencies that may !ie acrnevea tjv
82
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monitoring components under various LDAR programs. (For more information, refer to
"Summary of Nationwide Volatile Organic Compound and Hazardous Air Pollutant
Emission Estimates from Petroleum Refineries," in the docket).
An analysis of existing controls on refinery equipment leaks indicated that the MACT
floor level of control for refinery equipment leaks was the control required by the
Petroleum Refinery NSPS. For more information refer to ["Maximum Achievable Control
Technology Floor for Equipment Leaks at Petroleum Refineries," in the docket]. Two
more stringent control options were also analyzed: (1) compliance with the negotiated
equipment leaks regulation included in the HON, without the monitoring requirements
for connectors, and (2) compliance with the negotiated equipment leaks regulation
included in the HON. Each of these options requires specific leak monitoring frequencies
for components and control devices. Emission reductions for controlling leaking
equipment to the level of control required by the NSPS and the two more stringent
options were calculated from the difference between baseline emissions and the emissions
calculated using the percent reductions associated with the petroleum refinery NSPS and
the HON equipment leaks negotiated rule. Similarly, the cost impact of controlling
leaking equipment to the level required by the NSPS and the two more stringent control
options was calculated from the cost of control devices and labor associated with the
petroleum refinery NSPS and the negotiated rule. The cost methodology was based on
procedures provided in the "Equipment Leaks Enabling Document." (For more
information, refer to ["Costs for the MACT Floor Level of Control and Control Options
Above the Floor for Controlling Emissions from Leaking Refinery Equipment,"] in the
docket).
5.1.2.4 Miscellaneous Process Vents. The miscellaneous process vent group includes
most miscellaneous process vents that emit organic HAPs at refineries other than FCCU
catalyst regeneration vents, catalyst reformer catalyst regeneration vents, and sulfur
plant vents. The baseline HAP emissions from miscellaneous process vents were
estimated by multiplying HAP emission factors by the charge capacities of refinery
processes. Specific HAP emission factors were developed by dividing the HAP emissions
reported in questionnaire responses by the charge capacities of those refineries reporting
the specific HAP. (For further information, refer to "Summarv of Nationwide Volatile
83
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Organic Compound and Hazardous Air Pollutant Emission Estimates from Petroleum
Refineries," in the docket).
The MACT floor level of control for these vents was combustion. EPA has determined
that combustion of emissions can achieve 98 percent organic HAP reduction, so emission
reductions were calculated by applying this percent reduction to emissions from
miscellaneous process vents that are uncontrolled at baseline. The cost for controlling
emissions from miscellaneous vents includes the cost for piping emissions to existing
control devices and an additional compressor for the refinery. EPA assumed that
refineries would already have an existing fuel gas or flare system that could be used to
reduce emissions from miscellaneous process vents. Further information on costing
procedures and specific assumptions is contained in "Costing Methodology for Controlling
Emissions for Miscellaneous Process Vents," in the docket.
5.1.3 Calculations for New Sources
This section explains the methodology used for estimating emissions and control
impacts in the first 5 years after the promulgation of this rule. These costs represent
control of new process units and equipment built within the first 5 years after
promulgation. It should be noted for regulatory purposes, that some of these units and
equipment will be considered "new sources" and others will be considered part of an
"existing source". It is not possible to determine how many new units will fall into each of
these categories; however, controls will be required for the emission points in either case.
Costs for controlling new process units were estimated from the costs calculated for
existing sources and the number of new process units that are expected to be constructed
in the 5-year period after the standard is enacted. The costs for applying control
technologies to existing sources were calculated as previously described. The results are
documented in the four memoranda presenting cost impacts (in the docket). The cost
information was scaled up to account for new emission points that may need to be
controlled in the first 5 years after the petroleum refinery NESHAP has been
promulgated. Reductions of emissions of HAPs and VOC from controlling existing
emission points were also presented in the costing memorandum. The emission reduction
information was scaled up to account for controls on new emission ponies usint^ trie same
84
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methodology that was used to scale up cost data. (For further information, refer to
"Estimation of Annual Costs for New Petroleum Refinery Emission Points in the Fifth
Year After Promulgation," in the docket).
OGJ provided estimates of annual refinery construction projects. This information
was used to determine an average number of process units constructed in a year.
5.1.3.1 Storage Vessels. The MACT floor for storage vessels at new sources is
application of seals and fittings equivalent to those required by 40 CFR 60 subpart Kb
(the NSPS for VOL storage) to storage vessels larger than 151 m3 (947 bbl) with vapor
pressures above 3.5 kPa (0.50 psia). (These seals and fittings are the same as those
required by the HON.) The petroleum refinery NESHAP would result in no costs or
emission reductions for those storage vessels required to comply with subpart Kb (all new
3
vessels with a capacity greater than or equal to 40 m or 250 bbl). This methodology may
overestimate the impact of the regulation in the 5 years after promulgation because, as
previously stated, many vessels constructed in that period may be considered part of
existing sources for regulatory purposes. Because the requirements for existing sources
are equivalent to the NSPS, there will be no costs or emission reductions for existing
storage vessels. Therefore, the fifth year impacts on vessels at new sources would be
lower than the impact estimated here because the number of vessels at new sources is
probably overestimated.
5.1.3.2 Wastewater Collection and Treatment Systems. A MACT floor analysis
performed on wastewater collection and treatment systems indicated that the MACT floor
level of control for wastewater streams at new sources is compliance with the BWON.
Therefore, no costs are anticipated for sources built in the 5 years after promulgation to
reach the MACT floor level of control. The control option more stringent than the floor
that was considered was the same as the option considered for existing sources: assessing
the effects of lowering the applicability threshold of the BWON by eliminating the cutoff
of 10 Mg/yr TAB loading in facility wastes and wastewater.
The average annual number of newly constructed process units that will generate
wastewater is expected to be approximately 34. The distribution of these new units
across refinery processes was based on OGJ data. (For more information, refer co the
85
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docket). Using the same approach for applying controls and estimating costs for new
sources as for existing sources, costs for the newly constructed units were estimated. The
total estimated capital investment for controls by the fifth year (considering 34 new units
per year over the 5-year period) would be approximately $42 million. The total annual
cost to be expended in the fifth year (considering all 170 new units) would be
approximately $18 million per year.
5.1.3.3 Equipment Leaks. OGJ provides annual construction projects in petroleum
refineries and expected dates of completion. This information, for a 5-year period from
1988 to 1992, was used to develop an average count of new construction projects 5 years
after promulgation of the refinery NESHAP. From this information, it was determined
that an average of 34 process units would be built annually. Each of these process units
is expected to require control under the NSPS for refineries. Therefore, the only cost
associated with controlling these units is the extra cost required to go from the NSPS
control requirements (the MACT floor for equipment leaks at new sources) to the two
options more stringent than floor. The two options are the same as for existing sources:
(1) the negotiated regulation for equipment leaks in the HON (40 CFR 63 subpart H)
without the monitoring requirements for connectors and (2) the HON negotiated
regulation.
The average capital investment cost and annual cost of upgrading from the NSPS.to
the HON negotiated regulation without connector monitoring were determined to be
$20,000 and $7,000/yr per process unit, respectively. The average capital investment and
annual cost of upgrading from the NSPS to the HON negotiated regulation were
determined to be $17,000 and $6,200/yr per process unit, respectively. For each option,
the capital investment cost and average annual cost for controlling the 34 process units
constructed each year was calculated by multiplying the average cost per process unit by
the number of new process units.
5.1.3.4 Miscellaneous Process Vents. The MACT floor level of control for
miscellaneous process vents at new sources was determined to be combustion. The
annual cost for controlling emissions from miscellaneous vents consisted the cost for
piping to an existing combustion system (to a flare or to the fuel gas system) and for an
additional compressor for each retinery. The average capital cost for piping for eacn vent
86
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and a compressor for each refinery was determined to be $9,910 and $66,100, respectively,
and the average annual cost of piping for each vent and compressor for each refinery was
determined to be $2,170 and $37,800, respectively.
As previously stated, the average annual number of newly constructed process units
is expected to be 34. The number of miscellaneous vents requiring control was calculated
from the average number of uncontrolled vents per process unit, as presented in the
baseline emissions estimation memorandum (-refer to docket). Based on this information,
one vent for each of the 34 process units is estimated to require control (that is, a total of
34 new vents will require control each year). This number of vents per year was
multiplied by the average cost per vent to estimate national costs for miscellaneous
process vents for process units constructed in the 5 years after promulgation of this rule.
5.2 TOTAL COMPLIANCE COST ESTIMATES, REDUCTIONS, AND COST
EFFECTIVENESS
The annualized compliance costs by emission point are shown in Table 5-1 for the
preferred alternative. The total national cost of Alternative 1 in the fifth year is $81
million, compared with a cost of $97 million for Alternative 2. The difference between the
two alternatives are the increased costs associated with more stringent control techniques
for equipment leaks and storage vessels. Table 5-2 presents the costs, HAP emission
reductions, and cost effectiveness for the control options by emission point. The average
cost effectiveness of the regulation ($/Mg of pollutant removed) is determined by dividing
the annual cost by the annual emission reduction. Table 5-3 presents a summary of the
HAP emission reductions, total cost, and cost effectiveness values for each of the two
regulatory alternatives. The emission reductions associated with each alternative in
Table 5-3 were calculated by summing the HAP emission reductions listed in Table 5-2 for
the control option chosen at each emission point. The annual costs are as reported in
Table 5-1, and the cost effectiveness values were calculated as described above. The
incremental cost effectiveness represents the increase in cost from Alternative 1 to
Alternative 2 divided by the increased HAP emission reduction. Table 5-4 reports similar
information for VOC emissions.
87
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TABLE 5-3. COST, HAP EMISSION REDUCTION, AND COST EFFECTIVENESS BY
ALTERNATIVE
Regulatory Alternative
Alternative 1
Alternative 2
HAP Emissions
(Mg/Yr)
Reduction
53,684
56,444
Cost Effectiveness
($/Mg)
Annual Cost
(Million $, 1992)1
$81.0
$97.0
Average
$1,509
$1,719
Incremental
N/A
$5,797
NOTES. N/A = Not applicable.
'Cost estimates do not include costs associated with monitoring, recordkeeping, and reporting requirements
TABLE 5-4. COST, VOC EMISSION REDUCTION, AND COST EFFECTIVENESS BY
ALTERNATIVE
Regulatory Alternative
Alternative 1
Alternative 2
VOC Emission
Reduction (Mg/Yr)1
322,153
333,767
Annual Cost
(Million $, 1992)2
$81.0
$97.0
Cost Effectiveness
($/Mg)
Average Incremental
$251 N/A
$290 $1,378
NOTES. N/A = Not applicable.
'Emission reduction estimates do not incorporate reductions occurring at new sources.
2Cost estimates do not include the costs associated with monitoring, recordkeeping, and reporting requirements.
90
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5.3 MONITORING, RECORDKEEPING, AND REPORTING COSTS
In addition to provisions for the installation of control equipment, the proposed
regulation includes provisions for MRR. EPA estimates that the total annual cost for
refineries to comply with the MRR requirements is $30 million. After incorporating MRR
costs, the total cost of compliance of Alternative 1 is $111 million, and Alternative 2's
total cost is $127 million. For Alternative 1, the incorporation of MRR costs into total
annual cost results in a cost effectiveness of $345 for each megagram of VOC reduced and
$2,068 for each megagram of HAP reduced. For Alternative 2, the cost effectiveness with
the incorporation of MRR costs is $381 per megagram of VOC reduced and $2,250 per
megagram of HAP reduced. The incremental change from Alternative 1 to Alternative 2
is $1,378 per megagram of VOC reduced and $5,797 per megagram of HAP reduced.
In order to calculate the costs of MRR associated with the petroleum refinery
NESHAP, estimates of hours per item (i.e., a required MRR action), frequency of required
action per year, and number of respondents (i.e., total number of individuals required to
submit compliance reports) were estimated based on the requirements in the proposed
rule for all of the emission points. To compute the costs associated with the burden
estimates, a wage rate of $32 per hour (in 1992 dollars) was assumed. This assumption
was based on an estimate that 85 percent of the labor will be accomplished by technical
personnel (typically by an engineer with a wage rate of $33 per hour), 10 percent will be
completed by a manager (at $49 per hour), and 5 percent by clerical personnel (at $15 per
hour). All of the wage rates include an additional 110 percent for overhead. Costs were
annualized assuming an expected remaining life for affected facilities of 15 years from the
date of promulgation of the subject NESHAP, and using an interest rate of 7 percent.
Compliance requirements vary in terms of frequency. This variance is taken into
account in the annualization of costs. Performance tests to demonstrate compliance with
the control device requirements are required once. Compliance requirements also include
monitoring of operating parameters of control devices and records of work practice and
other inspections. These activities must be reported semiannually. The compliance
requirements that must be met only once are annualized over the time from the year in
which they are to take place to the expected end of facility life.
91
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The MRR requirements are outlined separately in the regulation for each emission
point. The proposed compliance determination provisions for storage vessels include
inspections of vessels and roof seals. If a closed vent system and control device is used for
venting emissions from storage vessels, the owner must establish appropriate monitoring
procedures. For wastewater stream and treatment operations, the MRR requirements are
outlined in the rule for the BWON.
For miscellaneous process vents, the proposed standard specifies the performance
tests, monitoring requirements, and test methods necessary to determine whether a
miscellaneous process vent stream is required to apply control devices and to demonstrate
that the allowed emission levels are achieved when controls are applied. The format of
these requirements, as with the format of the miscellaneous process vent provisions,
depends on the control device selected. The MRR requirements for miscellaneous process
vents are summarized by control device in Table 5-5.
For equipment leaks, because the provisions of the proposed rule are work practice
and equipment standards, monitoring, repairing leaks, and maintaining the required
records constitutes compliance with the rule. The HON equipment leak provisions are
appropriate to determine continuous compliance with the petroleum refinery equipment
leak standards. In summary, these provisions require periodic monitoring with a portable
hydrocarbon detector to determine if equipment is leaking.
92
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96
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6.0 ECONOMIC IMPACTS AND SOCIAL COSTS
The goal of the RIA is to evaluate the potential benefits and costs of specific pollution
control standards on our nation's economy. Potential regulatory benefits relate to reduced
HAP and VOC emissions that have detrimental effects on the health and well-being of
members of society. Social costs associated with the regulation are those costs borne by
consumers and producers of refined petroleum products and by society at large as a result
of the proposed standards. A comparison of the costs and benefits or net benefits (social
benefits less social costs) of alternative control measures serves as a basis for rational and
effective environmental policymaking.
The emission control measures considered in this analysis will require domestic
petroleum refineries to incur increased investment costs for control equipment and the
associated annual operation and maintenance expenses. Increased costs of production
may impact the domestic petroleum refining market in a number of ways. Primary
market impacts resulting from the control measures include increases in the market
equilibrium price for refined petroleum products, decreases in output levels for products
produced and sold nationally, changes in the value of domestic shipments or revenues for
refineries in the industry, and possible plant closures. Predicted changes in the market
equilibrium price and quantity of refined petroleum products produced and sold will result
in additional market modifications or secondary market impacts. The secondary effects
relate to the likely labor market adjustments (job losses), energy input market changes
(decrease in the energy used as an input in the production of petroleum products) and
foreign trade effects (decrease in net exports). Control measures may also have a
detrimental influence on the capital availability and financial position of firms in the
petroleum refining industry. Welfare changes for consumers, producers, and .societ.v at
large or the social costs of the proposed emission controls will also be evaluated.
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Additionally, the Regulatory Flexibility Act (RFA) requires that an assessment be made of
the effect of control measures on small entities.
This chapter will briefly describe the methods used to estimate the primary impacts,
secondary effects, and small business impacts of the emission controls on the petroleum
refining industry. A more detailed description of the methods used in the analysis is
available in the Economic Impact Analysis of the Petroleum Refinery NESHAP (1994). A
profile of the petroleum refining industry, the primary market impacts, capital
availability consequences, secondary market impacts, small business impacts, and social
costs of the control measures will be presented in this chapter.
6.1 PROFILE OF THE PETROLEUM REFINING INDUSTRY
The petroleum industry can be divided into five distinct sectors: (1) exploration,
(2) production, (3) refining, (4) transportation, and (5) marketing. Refining, the process
subject to this NESHAP, is the process which converts crude oil into useful fuels and
other products for consumers and industrial users. The Standard Industrial Classification
(SIC) code for all petroleum refineries is 2911. Although petroleum refineries produce a
diverse slate of products, the five primary output categories are (1) motor gasoline, (2) jet
fuel, (3) residual fuel, (4) distillate fuel, and (5) liquefied petroleum gases (LPGs), which
in total accounted for 93 percent of all domestically refined petroleum products in 1992.
This analysis is concerned only with these five main product categories.
A brief overview of the petroleum refining industry is presented in this section.
Economic and financial data which characterize conditions in the refining industry and
that are likely to influence the economic impacts associated with the implementation of
the alternative NESHAPs are discussed. The information in this section represents the
data inputs to the economic model used in the EIA. More details concerning the industry
are provided in the Economic Impact Analysis of the Petroleum Refinery NESHAP (1994)
and Industry Profile of the Petroleum Refinery NESHAP (1993).
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6.1.1 Profile of Affected Facilities
A brief description of the facilities affected by the proposed emission controls is
presented in this section. The processes and product market characteristics of the
petroleum refining industry are discussed. Refineries subject to the regulations are
identified by geographical location, capacity, and complexity.
6.1.1.1 General Process Description. The refining process transforms crude oil into a
wide range of petroleum products which have a variety of applications. The refining
industry has developed a complex variety of production processes used to transform crude
oil into its various final forms, many of which are already subject to some CAA controls.
There are numerous refinery processes from which HAP emissions occur. Separation
processes (such as atmospheric distillation and vacuum distillation), breakdown processes
(thermal cracking, coking, visbreaking), change processes (catalytic reforming,
isomerization), and buildup processes (alkylation and polymerization) all have the
potential to emit HAPs. HAP emissions may occur through process vents, equipment
leaks, or from evaporation from storage tanks or wastewater streams. The NESHAP will
address emissions from all of these refinery emission points.
6.1.1.2 Product Description and Differentiation. Most petroleum refinery output
consists of motor gasoline and other types of fuel, but some non-fuel uses exist, such as
petrochemical feedstocks, waxes, and lubricants. The output of each refinery is a function
of its crude oil feedstock and its preferred petroleum product slate.
Motor gasoline is defined as a complex mixture of relatively volatile hydrocarbons
that has been blended to form a fuel suitable for use in spark-ignition engines. Residual
fuel oil is a heavy oil which remains after the distillate fuel oils and lighter hydrocarbons
are distilled away in refinery operations. Uses include fuel for steam-powered ships,
commercial and industrial heating, and electricity generation. Distillate fuel oil is a
general classification for one of the petroleum fractions produced in conventional
distillation operations. It is used primarily for space heating, on- and off-highway diesel
engine fuel (including railroad engine fuel and fuel for agricultural machinery), and
electric power generation. Jet fuel is a low freezing point distillate of the kerosene type
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used primarily for turbojet and turboprop aircraft engines. LPGs are defined as ethane,
propane, butane, and isobutane produced at refineries.
Product differentiation is a form of non-price competition used by firms to target or
protect a specific market. The extent to which product differentiation is effective depends
on the nature of the product. The more homogenous the overall industry output, the less
effective differentiation by individual firms becomes. Each of the five petroleum products
in this analysis are by nature quite homogenous — there is little difference between
Exxon premium gasoline and Shell premium gasoline — and, as a result, differentiation
does not play a major role in the competitiveness among petroleum refineries.
6.1.1.3 Distinct Market Characteristics. The markets for refined petroleum products
vary by geographic location. Regional markets may differ due to the quality of crude
supplied or the local product demand. Some smaller refineries which produce only one
product have single, local markets, while larger, more complex refineries have extensive
distribution systems and sell their output in several different regional markets. In
addition, because refineries are the source of non-hydrocarbon pollutants such as
individual HAPs, volatile organic compounds (VOCs), sulfur dioxide (SO2), and nitrogen
oxide (NOX), many Federal, State, and local regulations are already in place in some
locations. Differences in the regional market structure may also result in different
import/export characteristics.
»
The United States is segmented into five regions, called Petroleum Administration for
Defense Districts (PADDs), for which statistics are maintained. PADDs were initiated in
the 1940s for the purpose of dividing the United States into five economically and
geographically distinct regions. Relatively independent markets for petroleum products
exist in each PADD.
In addition to differences in regional markets, each of the five product categories in
this analysis possesses its own individual market segment, satisfying demand among
different end-use sectors. The substitutability of one of the products — motor gasoline,
for example — is not possible with another refinery output, such as jet fuel. Thus, each of
:he products in this analysis is treated as a separate produce with its own .share of the
market. From a refinery standpoint, however, if the production of one refined product
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were to become less costly after regulation, production of this product may increase at the
expense of a product with a more costly refining process.
6.1.1.4 Affected Refineries and Employment. There are currently 192 operable
petroleum refineries in the United States.1 Though refineries differ in capacity and
complexity, almost all refineries have some atmospheric distillation capacity and
additional downstream charge capacity. Most of the employment in the industry exists at
larger refineries. Slightly fewer than 4 percent of refinery employees work in
establishments of fewer than 100 people, and the remaining 96 percent of the labor force
in the industry works at establishments of 100 employees or more.
6.1.1.5 Capacity and Capacity Utilization. Refineries have many different specialties,
targeted product slates, and capabilities. Some refineries produce output only by
processing crude oil through basic atmospheric distillation. These refineries have very
little ability to alter their product yields and are deemed to have low complexity. In
contrast, refineries that have assorted downstream processing units can substantially
improve their control over yields, and thus have a higher level of complexity. Because of
their differences in size and complexity, refineries can be grouped by two main structural
features: (1) atmospheric distillation capacity (which denotes their size) and (2) process
complexity (which characterizes the type of products a refinery is capable of producing).
Capacity utilization rates of petroleum refineries have been rising in recent years,
reaching a high of 92 percent in 1991.2 This indicates that existing refineries are
operating closer to full capacity than in the past, and will have limited opportunity to
enhance production by increasing utilization.
During the past 23 years, the entire domestic refining industry has been affected by
crude oil quantity changes and shifting petroleum demand patterns. A more complex and
flexible refining industry has evolved domestically. Ownership of U.S. refineries has
changed through consolidation and foreign investments. Throughout the 1970s, the
number of U.S. refineries rose rapidly in response to rising demand for petroleum
products. In the early 1980s, the petroleum refining industry entered a period of
restructuring, wnicn continued through 1992. A record number or' U'.S. refineries were
operating in 1981. A decline m petroleum demand in the early 1980s caused many small
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refineries and older, inefficient plants to close. The refinery shutdowns resulted in
improved operating efficiency, which enabled the refinery utilization rate to increase,
despite lower crude oil inputs. Operable capacity has remained relatively constant since
1985, while capacity utilization has risen steadily.
6.1.1.6 Refinery Complexity. Complexity is a measure of the different processes used
in refineries. It can be quantified by relating the complexity of a downstream process
with atmospheric distillation, where atmospheric distillation is assigned the lowest value,
1.0. The level of complexity of a refinery generally correlates to the types of products the
refinery is capable of producing. Higher complexity denotes a greater ability to enhance
or diversify product output, to improve yields of preferred products, or to process lower
quality crude. By defining refinery complexity, it is possible to differentiate among
refineries having similar capacities but different process capabilities. In theory, more
complex refineries are more adaptable to change, and are therefore potentially less
affected by regulation. The complexity of a refinery usually increases as its crude capacity
increases. (Lube plants are the exception to this rule.) Over 50 percent of the operable
capacity (50,000 to 100,000 bbl/d) can be found at refineries with above-average
complexity. Likewise, the smaller refineries are less complex.
6.1.2 Market Structure
The market structure of an industry will influence the magnitude of market impacts
resulting from emission controls. A perfectly competitive market is characterized by many
sellers, no barriers to entry or exit, homogeneous output, and complete information. A
perfectly competitive market is one in which producers have small degrees of market
power and pricing is determined by market forces, rather than by the producers.
Alternatively an industry with monopoly power has more discretion over the market price
charged. Producers in such an industry have greater market power. A profile of the
market structure of the petroleum refining industry is provided in the following sections,
including an assessment of the number of domestic operating refineries, the market
concentration, and the extent of vertical integration, and diversification.
6.1.2.1 Market Concentration. Market concentration is :i measure of the -mtnut )r fV-
largest firms in the industry, expressed as a percentage of total national output. Clarket
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concentration is usually measured for the 4, 8, or 20 largest firms in the industry. A
firm's concentration in a market provides some indication of the firm's size distribution.
For example, on one extreme, a concentration of 100 percent would indicate monopoly
control of the industry by one firm. On the other extreme, concentration of less than 1
percent would indicate the industry was comprised of numerous small firms.
Concentration is measured based on refining capacity. Until recently, the top four firms in
the refining industry have consistently comprised over 30 percent of the market share,
but most market concentration ratios have marginally decreased in recent years.
Market concentration may also be evaluated using the Herfindahl-Hirschman index,
which is defined as the sum of the squared market shares (expressed as a percentage) for
all firms in the industry. If a monopolist existed, with market share equal to 100 percent,
the upper limit of the index (10,000) would be attained. If an infinite number of small
firms existed, the index would equal zero. An industry is considered unconcentrated if the
Herfindahl-Hirschman index is less than 1,000. Ratings are also developed for
moderately concentrated (between 1,000 and 1,800) and highly concentrated (greater than
1,800) industries. The petroleum refining Herfindahl-Hirschman index in recent years
has been less than 500. Thus the refining industry is considered unconcentrated.3
6.1.2.2 Industry Integration and Diversification. Vertical integration exists when the
same firm supplies input for several stages of the production and marketing process.
Firms that operate petroleum refineries are vertically integrated because they are
responsible both for exploration and production of crude oil (which supplies the input for
refineries) and for marketing the finished petroleum products after refining occurs. To
assess the level of vertical integration in the industry, firms are generically classified as
major or independent. Generally speaking, major energy producers are defined as firms
that are vertically integrated. There are currently 20 major energy companies. The crude
capacity of the major, vertically integrated firms represents almost 70 percent of
nationwide production.
For the major oil companies, horizontal integration exists because these firms operate
several refineries which are often distributed around the nation. Seventy-three of the 109
firms in the industry operate onlv one rsfinerv jach.
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firms. The major firms operate several refineries, and the largest, Chevron, operates 13.
Fourteen firms operate four or more refineries each.
Diversification exists when firms produce a wide array of unrelated products. In the
short run, diversification may indirectly benefit firms that engage in petroleum refining,
since the costs of control in petroleum refining may be dispersed over other unaffected
businesses operated by the firm. Over the long term, however, firms will not subsidize
petroleum product production with profit from other operations, but will shut down
unprofitable operations instead. Diversification within the energy industry may mitigate
some of the effects of regulation at least in the short run.
6.1.2.3 Financial Profile. The financial performance of firms in the petroleum
refining industry is particularly relevant to an evaluation of the impact of regulation on
the industry. In order to evaluate the financial condition of the refinery operations of
firms, a sample of the petroleum refining industry's major firms financial operations were
evaluated. Annual reports to stockholders were used as a source of data for the analysis.
While this sample is too small and diverse to be considered representative of the
aggregate industry, the data presented are more recent and more refinery-specific than
American Petroleum Institute data.
The sample of annual report data analyzes refinery-specific data in order to provide a
preliminary assessment of the financial condition of firms in the industry. This 12-firm
sample as a whole operated 59 refineries in 1991, and represented 45.3 percent of the
industry's total refining capacity. Refining capacity in the sample ranges from 165,000
bbl/d to 2,139,000 bbl/d. Over the 5-year period from 1987 to 1991, operating income per
dollar of revenue increased from 1 percent to 4 percent. Capital expenditures increased
steadily, while refined product sales continued a period of decline. The consolidation
taking place in the refining industry is reflected in the decreasing crude oil capacity and
refinery runs.
Refined product margins are a good indicator of overall refinery financial
performance.4 The difference between refined product costs and refined product revenues
is the refined product margin. During the 1980s, refined product margins were affected
by a snift in product siates to gasoline and jet fuels, the decrease in crude oii prices.
104
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fluctuations in demand, and an increase in refinery utilization rates.5 In constant 1982
dollars, the refined product margin fluctuated over this time frame, decreasing between
1985 and 1987 and then increasing significantly in 1988. The fluctuations in the refined
product margins reflect the volatility of the market and the degree to which refineries'
revenues are often subject to significant change over short time -periods. In the early half
of 1990, the margin between overall U.S. refined product prices and crude oil import costs
rose to record levels, given falling crude oil prices and stable gasoline prices.6 After the
invasion of Kuwait, U.S. refined product prices did not keep pace with crude oil prices for
the remainder of the year. This negatively impacted refinery revenues for 1991.
Firms have three sources of funding for the capital necessary to purchase emission
control equipment required by the NESHAP. These sources include (1) internal funds,
(2) borrowed funds, and (3) stock issues. Typically, firms seek a balance between the use
of debt and stock issues for financing investments. Debt-to-equity ratios reflect a measure
of the extent to which the firm has balanced the tax advantages of borrowing with the
financial safety of stockholder financing. Based on information obtained in the annual
reports of the 12 companies in the refinery sample, firms anticipate that internally
generated funds will fund most of their capital expenditures. Other firms recognize the
need to also draw on available credit lines and commercial paper borrowing. Overall,
capital expenditures of refiners have doubled since 1977, although spending peaked in
1982 and has since been in a period of decline.
Planned uses of investment funds by the 12 firms in the financial sample over the
next few years include construction of diesel desulfurization units, expansion of existing
units, and construction of units to manufacture methyl tertiary butyl ether (MTBE) and
oxygenated fuels. In a 1991 study, Cambridge Energy Research Associates (CERA)
surveyed refiners and oxygenate producers to evaluate the ability of the refining industry
to meet CAA provisions.7 Among the firms in the CERA survey, the majors and some
large independents plan to fund their investments primarily or entirely from internally
generated cash flows, while most of the small refineries surveyed are planning on
resorting to the debt market for funds.
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6.1.3 Market Supply
Refiners have increased production of most refined products almost every year since
1984. Historically, motor gasoline has been the product that is supplied in the greatest
quantities to meet increased demand. Most of the other petroleum products show a
modest net increase in supply over the past few years. The lack of significant change in
the yield for most refined petroleum products indicates a relatively stable supply slate,
but significant regulatory costs could force some reshuffling of product yield.
Refinery production of motor gasoline has increased each year, with the exception of
periods of economic recession. Production remained relatively steady from 1988 to 1992.
Distillate fuel oil output peaked at 3.3 million barrels per day in 1977, then fell through
1983. Output has increased slightly almost every year since, reaching 3 million barrels
per day in 1992. Jet fuel production grew during the 1970s and 1980s, and almost
doubled by 1990 before declining to 1.4 million barrels per day in 1992. Residual fuel oil
production generally declined from 1980 through 1985, and was 1 million barrels per day
in 1992, compared to 0.7 million barrels per day in 1970.
6.1.3.1 Supply Determinants. The most important short-run production decision for
an oil refinery is the determination of how much crude oil to allocate for the production of
each of the refinery's products. The production decision depends on the profit each of the
oil products can generate for the firm. Profits, in turn, depend on the productivity of the
oil refinery — its ability to produce each oil product as effectively as possible from a
barrel of crude oil. The quantity of crude oil a refinery will refine depends on the capacity
of the refinery and the cost of production. The marginal costs of production of each
product will determine any future changes in production. Crude oil is the primary
material input to the refining process; as a result, the production of refined products is
vulnerable to fluctuations in the world crude oil market.
In the long run, production decisions are based on the cost of capacity expansion
relative to existing price levels and expected future price levels. A refinery uses different
processing units to turn crude oil into finished products, so when a particular processing
unit reaches capacity, output can be increased onlv by substituting u rnoro pxoensivp
process. Firms will typically utilize sufficient crude oil to fill the appropriate processing
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unit until the price increases substantially. At this point, the firm would calculate
whether the increased price warrants using an additional, more expensive processing
unit.8
6.1.3.2 Exports of Petroleum Products. Some measure of the extent of foreign
competition can be obtained by comparing exports to domestic production. Export levels
and domestic refinery output for the past decade were analyzed. Exports as a percentage
of domestic refinery output steadily increased from 1984 to 1991 and then fell slightly to
5.6 percent in 1992. Distillate oil, residual fuel oil, motor gasoline, and petroleum coke
are exported in the highest volumes. The combined export volumes of these products
represent 75 percent of domestic refinery output shipped overseas.
6.1.4 Market Demand Characteristics
The end-use sectors that contribute to demand for refined petroleum products are
classified in the following four economic sectors: (1) household and commercial, (2)
industrial, (3) transportation, and (4) electric utilities. Petroleum products used as
transportation fuel include motor gasoline, distillate (diesel) fuel, and jet fuel, and
accounted for an estimated 64 percent of all U.S. petroleum demand in 1990. Since
mobile source emissions will be regulated by Title II regulations, this output from
petroleum refineries will be most affected by the CAA. The industrial sector constitutes
the second highest percentage of demand for petroleum products, followed by household
and electric utility demands.
Petroleum is used most widely in the transportation sector. In the household and
commercial sector, light heating oil and propane are used for heating and energy uses,
and compete with natural gas and electricity. Petroleum fuels in the industrial sector
compete with natural gas, coal, and electricity. In the industrial sector, residual and
distillate heating oils are used for boiler and power fuel. In the electric utility sector,
petroleum products supply energy in the form of heavy residual fuel oil and smaller
amounts of bulk light distillate fuel oil.9
In terms of refined products, ihe motor gasoline and jet fuel marKets are .lojociateu
with the transportation sector. The markets for distillate fuel oil are associated with the
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transportation sector (diesel engine fuel as a trucking fuel), household (space heating),
industrial (fuel for commercial burner installations), and electric-utilities (power
generation). The sectors that are sources of demand for residual fuel oil include the
commercial and industrial sectors (heating), utilities (electricity generation), and the
transportation sector (fuel for ships). Nonutility use of residual fuel has been decreasing
due to interfuel substitution in the commercial and industrial sectors. Because LPGs
cover a broad range of gases, demand levels are attributable to various end users.
6.1.4.1 Demand Determinants. The demand for refined petroleum products is
primarily determined by price level, the price of available substitutes, and economic
growth trends. The degree.to which price level influences the quantity of petroleum
products demanded is referred to as the price elasticity of demand, which is explored later
in this report. Prices of refined petroleum products affect the willingness of consumers to
choose petroleum over other fuels, and may ultimately cause a change in consumer
behavior. In the transportation sector, the effect of high gasoline prices on fuel use could
reduce discretionary driving in the short term and, in the long term, result in the
production of more fuel-efficient vehicles.
In the market for jet fuel, demand is primarily determined by a combination of price
concerns and the overall health of the airline industry. In the residential sector, demand
for home heating (distillate) is determined in part by price level, and also by'temperature
levels and climate. Temperature in different areas of the country may determine the
degree to which buildings and houses are insulated. Temperature and insulation are
exogenous factors which will determine heating needs regardless of the price level of fuel.
High prices for home heating oil provide incentive for individuals to conserve by adjusting
thermostats, improving insulation, and by using energy-efficient appliances. In some
cases, higher oil prices also provide incentive for switching to natural gas or electric
heating. (Adjusting thermostats is a short-run response, while changing to more energy-
efficient appliances or fuels are long-run responses.)
In the industrial sector, fuel oil competes with natural gas and coal for the boiler-feed
market. High prices relative to other fuels tend to encourage fuel-switching, especially at
electric utilities and in industrial plants having dual-fired boilers. Generally speaking, in
choosing a boiler for a new plant, management must choose between the higher
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capital/lower operating costs of a coal unit or the lower capital/higher operating costs of a
gas-oil unit. In the utility sector, most new boilers in the early 1980s were coal-fired due
to the impact of legislative action, favorable economic conditions, and long-term assured
supplies of coal.10 Today, because the CAA will require utilities to scrub or use a low-
sulfur fuel, oil will eventually become more competitive with coal as a boiler fuel,
although a significant increase in oil-fired capacity is not expected until 2010."
Demand levels in each of the end-use sectors are also affected by the economic
environment. Periods of economic growth and periods of increased demand for petroleum
products typically occur simultaneously. For example, in an expanding economy, more
fuel is needed to transport new products, to operate new production capacity, and to heat
new homes. Conversely, in periods of low economic growth, demand for petroleum
products decreases.
6.1.4.2 Past and Present Consumption. Total consumption of all types of petroleum
products has fluctuated over the past 20 years, reflecting the volatility of this market.
The consumption level has been sporadic and has shown an overall decline in recent
years. Demand for individual petroleum product types has also fluctuated over this
period. The percentage of total demand is highest for motor gasoline followed by demand
for distillate fuel oil. Over the 23-year period from 1970 to 1992, the demand for residual
fuel oil has decreased by 50 percent, showing the greatest percentage of change over time
of any of the petroleum products. It has also been the only fuel to show a decline in use.
This decrease in residual fuel demand reflects a move in the industry from heavier fuels
toward lighter, more refined versions. This trend is expected to continue into the future
as efforts to control air emissions go into effect.
All other types of fuel show increases in use, with the most growth occurring in the
market for jet fuel. Substantial gains in airplane fuel efficiency in the last two decades,
which have resulted from improved aerodynamic design and a shift toward higher seating
capacities, have been exceeded by even faster growth in passenger miles traveled.12 The
other categories show an average growth rate of approximately 23 percent over this time
period. All major petroleum products registered lower demand in 1991 than in 1990,
except LPGs. This was the first ume since 1980 mat demand for ail major petroieum
products fell simultaneously in the same year. In this case, decreased demand was
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brought on by wanner winter temperatures, an economic slowdown, and higher prices
resulting from the Persian Gulf situation.13
Motor gasoline demand increased from a 1970 low to a high of 7.4 million barrels per
day in 1978. The increase reflected a 31 percent growth in the number of automobiles in
use and a 25 percent growth in vehicle miles traveled. From 1985 to 1992, motor gasoline
use accounted for about 42 percent of all petroleum products consumed.
Changes in demand for distillate fuel oil were similar to motor gasoline in that
consumption reached its lowest and highest levels in 1970 and 1978, respectively.
Between 1985 and 1992, consumption was relatively stable and accounted for about 18
percent of total U.S. petroleum consumption. Residual fuel oil demand, in response to
lower-priced natural gas and other factors, fell 64 percent, from a high in 1977 of 3.1
million barrels per day to 1.1 million barrels per day in 1992.
Between the period from 1970 to 1990, expanding air travel spurred a 57 percent
growth in jet fuel demand. Demand increased from a 1970 low of 1.0 million barrels per
day to 1.5 million barrels per day in 1990.
The variation in U.S. petroleum product demand has been linked to changes in the
prices of petroleum products relative to one another, and relative to other energy sources.
Dramatic petroleum price increases and eventual steep drops were in response to wars,
political upheaval in crude oil producing areas, and supply disruptions during the past
two decades. During this period, the more stable and lower prices of alternative fuels led
consumers to switch from petroleum as their fuel of economic choice.
6.1.4.3 Imports of Refined Petroleum Products. Imports as a percentage of domestic
consumption have fluctuated during the period 1981 through 1992, although in 1992
levels were 10.6 percent, or roughly the same level as in 1981. The import to export ratio
has decreased since 1981, due primarily to steady increases in exports.
6.1.4.4 Pricing. Prices for petroleum products have shown volatility over the time
period from 1978 through 1992. This volatility is mainlv attributable <-o f"he fluctuations
in the global market for crude oil and the inelastic demand for petroleum products.
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Inelastic demand allows refiners to pass crude oil price increases on to consumers. Since
petroleum products are essentially commodity products and are produced by a large
number of refineries, refineries have little ability to differentiate products or their prices.
6.1.5 Market Outlook
Quantitative production, demand, and price projections are available from the
literature. Projections are important to the economic impact analysis since future market
conditions contribute to the potential impacts of the NESHAP which are assessed for the
fifth year after regulation.
6.1.5.1 Supply Outlook (Production and Capacity). The refining industry was
operating near maximum capacity in 1991, with an average annual utilization rate of
approximately 92 percent.14 This is an increase from levels of previous years. In the
market for motor gasoline, for example, production capacity is nearly at full capacity. As
a result, any increases in demand will have to be met by imported products. This will
result in an increase in worldwide competition for gasoline. East Coast refiners,
accounting for more than 90 percent of all unleaded gas imports to the United States, will
be most affected by this increased competition.15 DOC predicts that, although U.S.
refinery output will remain relatively unchanged, net imports of refined petroleum
products are expected to increase by 15 percent.16 DOE predicts net petroleum imports
will rise to at least 10 million bbl/d in 2010, and perhaps as high as 15 million bbl/d from
the 1990 level of 7 million bbl/d as domestic oil production is expected to decline. Imports
are expected to supply between 53 and 69 percent of U.S. petroleum consumption by 2010,
compared with 42 percent in 1990. Refined products will account for much of this
increase because most of the expansion in the world's refinery system is expected to take
place outside the United States.17
Over the next 5 years, the petroleum industry as a whole plans to increase crude oil
distillation capacity by an additional 2 percent, or 272,000 bbl/d, of which 44 percent
would be produced by new facilities/8 (The other 56 percent includes reactivations and
expansions.) The level of added demand will determine if this added capacity is sufficient
to satisfy the market without driving up pnces.
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Companies that operate refineries with greater complexity factors (often the largest
refineries) will presumably be in a more favorable position to make the necessary capital
investments for the transition to cleaner fuels. Such refineries will most likely be those
large enough to benefit from the economies of scale, and with basic downstream
configurations to facilitate compliance with the new regulations. A financial analysis of
major petroleum refineries in the 1980s conducted by DOE concluded that vertically
integrated firms benefitted in a period characterized by increased regulatory activity and
price instability.19 The report found that the larger companies could offset a loss in one
segment with gains in another. (It is important to note, however, that in the long run,
both large and small firms would close refineries which operate at a loss over time.)
In contrast, smaller, independent, and less complex refineries will face higher
marginal compliance costs, and may not find it economical to spend the required
environmental capital. Generally not as flexible as the larger, integrated companies,
these firms operate at greater risk from the effects of market instability. As a result, an
industry which has seen a high level of consolidation in past years will be likely to see
more concentration.20
Overall, the effect of the CAA on individual refineries is dependent upon production
capacity, economies of scale, degree of self-sufficiency, capital cost, and ability of refiners
to "pass through" higher costs to consumers. Predictions of the effect on the aggregate
industry are difficult at this time because of the uncertainty of the ability of some
refineries to develop plans for compliance pending resolution of key issues affecting their
operations. A recent Harvard University study, however, predicted that the promulgation
of environmental regulations was likely to result in the early phase out of older, less
sophisticated facilities, combined with the upgrade and expansion of more efficient,
complex refineries at a faster rate.21
6.1.5.2 Demand Outlook. DOC projects the demand for all petroleum products to rise
slowly and steadily over the next 5 years, with domestic demand for refined products
increasing by 2.1 percent in 1992, assuming an economic recovery and a return to
"normal" weather. DOC's longer term demand prediction is for a steady growth rate of
1 percent through 1996.22'23 Given that two-thirds of petroleum oroduct d<"-nand '.s
attributable to the transportation sector, projected demand growth for motor gasoline will
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have the greatest effect on refiners. Industrial demand for distillate fuel reflects the
strongest projected growth. According to DOE projections, the consumption of diesel fuel
in the transportation sector is expected to grow by over 40 percent between 1990 and
2010.24 Residential and commercial sectors are expected to show a decrease in demand
for petroleum products.
DOE has also projected future levels of demand. Motor gasoline will remain the
leading end use of petroleum products throughout DOE's chosen time frame, dropping off
during 1990 and 1995, and rising again to higher levels by 2010. DOE predicts the
demand for residual oil to rise, level off, and then begin to decline in 2010. Jet fuel and
distillate fuel are both projected to rise steadily through 2010.
6.1.5.3 Price Outlook. Given that the demand for motor gasoline is price inelastic,
the added capital investment that refineries will be required to undertake in the
production of reformulated gasolines is likely to be passed on to consumers in the form of
a price increase. DOC has estimated this price increase to be a 5 to 10 cent-per-gallon
rise in the price of motor gasoline.25 In a recent study undertaken by the National
Petroleum Council, the impacts of air quality regulations on petroleum refineries were
assessed. One of the conclusions of the study was that the costs of controlling air
emissions are likely to be passed along to consumers as increases in the final price of
refined products. (The study offered no quantitative projections, however.)26
m
DOE has projected the domestic prices of petroleum products for 2010. DOE projects
the average price for all petroleum prices to increase at a rate in the range of 0.4 percent
to 2.1 percent annually. These price increases are due to projected increases in both
domestic demand and crude oil prices. DOE also accounted for higher refining and
distribution expenses-in making these projections. The real price of motor gasoline is
projected to rise from $1.17 per gallon in 1990 to between $1.30 and $1.74 in 2010,
depending on the level of world crude oil prices. On-highway diesel fuel is projected to
increase to between $1.27 and $1.69 per gallon, primarily because of the added refinery
costs of desulfurization. The average retail price of residual fuel oil, the least expensive
petroleum product, is projected to be within the range of $25.52 to $40.79 per barrel in
2010.
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If refineries are able to accommodate projected increases in demand, the price level
will remain fairly stable. However, because the price level in this industry is contingent
upon so many factors independent of the industry, any price predictions necessarily have
their limitations. In the long run, therefore, price predictions will need to be modified
with the occurrence of any world events which will affect the supply of crude oil to the
refineries and therefore to the supply of refined petroleum products. Refineries will also
be faced with increasing levels of emission restrictions, escalating their pollution
abatement costs, and consequently, the price of their products.
6.2 MARKET MODEL
A partial equilibrium model is the analytical tool used to estimate the impact of the
proposed NESHAP on the petroleum refining industry. Five refined petroleum products
were modeled. Collectively, these products represent over 90 percent of the refined
petroleum products sold in the nation annually. These products include motor gasoline,
jet fuel, residual fuel oil, distillate fuel oil, and liquified petroleum gases (LPGs). It is
assumed that firms in the petroleum refining industry operate in a perfectly competitive
market. Although the petroleum refinery industry does not meet the strictest definition
of a perfectly competitive industry, perfect competition seems a more applicable
characterization of the market than pure monopoly. The assumption of perfect
competition results in a worst case scenario of model results from the perspective of the
impact of the regulation on the petroleum refinery industry.
•
6.2.1 Market Supply and Demand
The partial equilibrium model approach estimates the baseline market supply and
demand relationship that provides the framework for evaluating market changes likely to
occur from emission controls. The baseline or pre-control petroleum refining market is
defined by a domestic market demand equation, a domestic market supply equation, and
a foreign market supply equation. It is further assumed that the markets will clear or
achieve an equilibrium. The following equations identify the market demand, supply, and
equilibrium conditions for the petroleum refinery industry:
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D =
QD =
QS' =
Q° = QS« + QSf = Q
where:
Q = annual output or quantity of petroleum products purchased and sold in the
United States
QD = quantity of the petroleum products domestically demanded annually
Qsd = quantity of the products produced by domestic suppliers annually
Qsf = quantity of the products produced by foreign suppliers annually
P = price of the petroleum product
e = price elasticity of demand for the product
y = price elasticity of supply for the product
a, p, and p are parameters estimated by the model.
The constants a, P, and p are computed such that the baseline equilibrium price is
normalized to one. The market specification assumes that domestic and foreign supply
elasticities are the same. This assumption was necessary because data were not readily
available to estimate the price elasticity of supply for foreign suppliers.
6.2.2 Market Supply Shift
The domestic supply equation shown above may be solved for the price of the
petroleum product, P, to derive an inverse supply function that will serve as the baseline
supply function for the industry. The inverse domestic supply equation for the industry is
as follows:
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P = «2S7P)T
A rational profit maximizing business firm will seek to increase the price of the
product it sells by an amount that recovers the capital and operation costs of the
regulatory control requirements over the useful life of the emission control equipment.
This relationship is identified in the following equation:
[(C • (?) - (V + £>)] (1 - t) + D _k
S
where:
C = increase in the supply price
Q = output
V = measure of annual operating and maintenance control costs
t = marginal corporate income tax rate
S = capital recovery factor
D = annual depreciation (assumes straight line depreciation)
k = investment cost of emission controls
Thus, the model assumes that individual refineries will seek to increase the product
supply price by an amount (C) that equates the investment costs in control equipment (k)
to the present value of the net revenue stream (revenues less expenditures) related to the
equipment. Solving the equation for the supply price increase (C) yields the following
equation:
^ " D V * D
- 0 Q
Estimates of the annual operation and maintenance control costs and of the
investment cost of emission controls (Vand k, respectively) were obtained from
engineering studies conducted by the engineering contractor for EPA and are based on
first quarter 1992 price levels. The variables depreciation and capital recovery factor, D
and S, respectively, are computed as follows:
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c — H.J- ')
~ [(1 * rf-\]
where r is the discount rate faced by producers and is assumed to be a rate of 10 percent,
and T is the life of the emission control equipment, 10 years for most of the emission
control equipment proposed.
Emission control costs will increase the supply price for each refinery by an amount
equivalent to the per unit cost of the annual recovery of investment costs and annual
operating costs of emission control equipment, or C, (i denotes domestic refinery 1 through
192). The baseline individual refinery cost curves are unknown because production costs
for the individual refineries are unknown. Therefore, an assumption is made that the
refineries with the highest after-tax per unit control costs are marginal in the post-control
market, or that those firms with the highest after tax per unit control costs also have the
highest per unit production costs. This is a worst case scenario model assumption and
may not be the case in reality. Based upon this assumption, the post-control supply
function becomes the following:
±
P = «2*W + C (C,,?,.)
where:
C (C,,q,) = a function that shifts the supply function to reflect control costs
Ct = vertical shift that occurs in the supply curve for the ith refinery to
reflect the increased cost of production in the post-control market
q, = quantity produced by the ith refinery
This industry pre-control and post-control supply and demand is illustrated in Figure 6-1.
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HI
Q
O
LLJ
z
h-
C/3
O
Q_
U_
O
O
I
I
CO
LU
tr
D
g
a.
&
"c
3
a
-------
6.2.3 Impact of Supply Shift on Market Price and Quantity
The impact of the proposed control standards on market equilibrium price and output
are derived by solving for the post- control market equilibrium and comparing the new
equilibrium price and quantity (P, and Q1( respectively) to the pre-control equilibrium (P0
and Q0). The change in value of domestic product is simply the difference in the industry
revenue (Pl * Qt) at the post-control market equilibrium and the revenue (P0 * Q0) at the
pre-control equilibrium.
Those firms that lie on the industry supply curve at price and quantity levels above
the post-control equilibrium (P^Qj) are subject to closure. This assumption is consistent
with the assumption of perfect competition. Firms in a competitive market are price
takers and are unable to sell their products at prices above the market equilibrium.
Predicted primary market impacts become the basis for assessing economic surplus
changes; secondary labor, energy, and foreign trade market impacts; and the capital
availability consequences expected to result from the emission controls.
6.2.4 Trade Impacts
Trade impacts are reported as the change in both the volume and dollar value of net
exports (exports minus imports). It is assumed that exports comprise an equivalent
percentage of domestic production in the pre- and post-control markets. The supply
elasticities in the domestic and foreign markets have also been assumed to be identical.
As the volume of imports rises and the volume of exports falls, the volume of net exports
will decline. However, the dollar value of net exports may rise or fall when demand is
inelastic, as is the case for the petroleum products of interest. The dollar value of imports
will increase since both the price and quantity of imports increase. Alternatively, the
quantity of exports will decline, while the price of the product will increase. Price
increases for products with inelastic demand result in revenue increases for the producer.
Consequently, the dollar value of exports is anticipated to increase. Since the dollar value
of imports and exports rise, the resulting change in the value of net exports will depend
on the magnitude of the changes for imports relative to exports. Tho foil-owing ruricii;:::::
are used to compute the trade impacts:
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I.VIM -(
«?,*' - oft
where:
&Qsr = change in the volume of imports
AV7M = change in the dollar value of imports
&Q/r = change in the volume of exports
= change in the dollar value of exports
= quantity of exports by domestic producers in the pre-control market
The subscripts 1 and 0 refer to the post- and pre-control equilibrium values, respectively.
All other terms have been previously defined.
The change in the quantity of net exports, &NX, is simply the difference between the
change in the volume of exports and the change in volume of imports, or ^Qxsd - z-Q3^ The
reported change in the dollar value of net exports, &.VNX, is the difference between the
equations for change in value of exports and the change in value of imports, or &VX -
6.2.5 Changes in Economic Welfare
Regulatory control requirements will result in changes in the market equilibrium
price and quantity of petroleum products produced and sold. These changes in the
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market equilibrium price and quantity will affect the welfare of consumers of petroleum
products, producers of petroleum products, and society as a whole.
Consumer surplus is a measure of the well-being of consumers of a particular product
and it represents the net benefit (total benefits derived from consuming a good less the
expenditure necessary to purchase the good) associated with consuming a particular
product. Consumers of refined petroleum products will bear a loss in consumer surplus as
a result of proposed emission controls. This loss in consumer surplus (ACS) represents the
amount consumers would have been willing to pay over the pre-control price for
production eliminated and a loss due to the increase in the market price consumers must
pay for the quantity of petroleum products purchased.
The change in consumer surplus includes losses of surplus incurred by foreign
consumers and domestic consumers. Although the change in domestic consumer surplus
is the object of interest, no method is available to distinguish the marginal consumer as
domestic or foreign. Therefore, an assumption is made that the consumer surplus change
is allocable to the foreign and the domestic consumer in the same ratio as the division of
sales between foreign and domestic consumers in the pre-control market. The variable,
&CSd, represents the change in domestic consumer surplus that results from the change in
market equilibrium price and quantity resulting from the imposition of regulatory
controls. While ACS is the change in consumer surplus from the perspective of the world
economy, &CSd is the change in consumer surplus relevant to the domestic economy.
Producer surplus is a measure of well-being of producers in an industry. The change
in producer surplus resulting from emission controls is composed of two elements. The
first element relates to output eliminated as a result of controls. The second element is
associated with the change in price and cost of production for the new market equilibrium
quantity. The total change in producer surplus is the sum of these elements. After-tax
measures of surplus changes are required to estimate the impacts of controls on
producers' welfare. The after-tax surplus change is computed by multiplying the pre-tax
surplus change by a factor of 1 minus the tax rate, (1-t) where t is the marginal tax rate.
Every dollar of after-tax surplus loss represents a complimentary loss in tax revenues of
t/fl-t; dollars.
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Output eliminated as a result of control costs cause producers to suffer a welfare loss
in producer surplus. Refineries remaining in operation after emission controls realize a
welfare gain on each unit of production for the incremental increase in the price and
realize a decrease in welfare per unit for the capital and operating cost of emission
controls. The total change in producer surplus (A PS) is the sum of each individual
change in producer surplus.
Since domestic surplus changes are the object of interest, the welfare gain
experienced by foreign producers due to higher prices is not considered. This procedure
treats higher prices paid for imports as a dead-weight loss in consumer surplus. Higher
prices paid to foreign producers represent simply a transfer of surplus from the United
States to other countries from a world economy perspective, but a welfare loss from the
perspective of the domestic economy.
The changes in economic surplus as measured by the change in consumer and
producer surplus previously discussed must be adjusted to reflect the true change in
social welfare resulting from the emission controls. Adjustments must be made to
consider tax effects and to adjust for the difference between the social discount rate and
the private discount rate. These adjustments result in a number referred to as the
residual surplus to society since these surplus changes do not relate specifically to
consumers or producers of refined petroleum products, but rather reflect losses that must'
be borne by all members of society.
Two adjustments are necessary to adjust changes in economic surplus for tax effects.
The first relates to the per unit control cost (Ct) that reflects after-tax control costs and is
used to predict the post-control market equilibrium. True cost of emission controls must
be measured on a pre-tax basis. A second tax-related adjustment is required because
changes reflect the after-tax welfare impacts of emission control costs on affected
refineries. As noted previously, a one dollar loss in pre-tax surplus imposes an after-tax
burden on the affected refinery of (1-t) dollars. Alternatively, a one dollar loss in after-tax
producer surplus causes a complimentary loss of t/(l-t) dollars in tax revenue.
Economic surplus must also be adjusted because the private and social discount rates
differ. The private discount rate is used to shift the supply-curve of firms in the industry
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since this rate reflects the marginal cost of capital to affected firms. The shift in the
supply curve for the refining industry is used to estimate primary and secondary market
impacts. A private cost of capital of 10 percent is assumed for the analysis.
In contrast, the economic costs of regulation must consider the social cost of capital
rather than the private cost of capital. A social cost of capital of 7 percent is assumed for
the analysis. This rate reflects the social opportunity cost of resources displaced in the
economy by investments required for emission controls. The adjustment for the two tax
effects and the social cost of capital are referred to as the residual change in economic
surplus to society (A/?S).
The total economic costs of the proposed regulations are the sum of the changes in
consumer surplus, producer surplus, and the residual surplus to society. This
relationship is defined by the following equation:
EC =
where EC is the economic cost of the proposed controls and all other variables have been
previously defined.
6.2.6 Labor Market and Energy Market Impacts
Emission control costs will result in a decrease in the market equilibrium quantity of
refined products produced and sold domestically. This reduction in output or production
will directly cause the level of inputs used in production to decrease. Quantification of
the input reduction affecting the labor and energy markets are of particular interest.
Two adjustments in the labor market may result from the emission controls. The
first involves monitoring and maintenance of the emission control equipment that may
cause employment increases. Information necessary to quantify potential employment
increases for monitoring and maintenance of emission controls is not readily available.
Consequently , possible employment increases are not considered in the analysis.
Additionally, job losses may occur as a result of decreases in the level of production for
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firms in the industry. Probable job losses due to the estimated decrease in refined
petroleum output are quantified by multiplying the decrease in industry output by an
industry ratio of employees per unit of production. This quantification of possible job
losses in the refining industry is likely to be overstated due to the omission of potential
job increases for monitoring and maintenance of emission control equipment.
Reduction in the utilization of energy inputs associated with the proposed standard
result from decreases in output in the industry. The expected change in expenditures on
energy by firms in the industry is calculated by multiplying the ratio of baseline energy
expenditure per dollar refined petroleum output by the estimated decrease in annual
output. The quantification of energy input changes reflects energy expenditure decreases
per year occurring as a result of the reduced production of refined petroleum products.
6.2.7 Baseline Inputs
The partial equilibrium model requires, as data inputs, baseline values for variables
and parameters that characterize the petroleum refining market. These data inputs
include the number of domestic refineries in operation in 1992, the annual production per
refinery for 1992, and the relevant control costs per refinery. All monetary values are
based upon 1992 price levels. Specific details concerning the data inputs and the sources
of the data are available in the Economic Impact Analysis of the Petroleum Refinery
NESHAP (1994).
Two data inputs crucial to the estimation of partial equilibrium are the price
elasticity of demand and the price elasticity of supply. The price elasticity of supply and
demand is briefly discussed in the following section.
6.2.8 Price Elasticities of Demand and Supply
Price elasticities of demand and supply are measures of the responsiveness of buyers
and sellers of a product to changes in the market price. Elasticity measures may be
categorized as elastic, unitary elastic, and inelastic to price changes in the market.
Products with elastic price elasticity values are very resnonsive to changes in f.he nnce of
the product ( percent quantity decrease exceeds percent price increase) while products
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with inelastic price elasticity measures are not very responsive to changes in price
(percent quantity decrease is less than percent price increase). Unitary elasticity
measures have equal percent changes in price and quantity. The ultimate increase in
market equilibrium price and decrease in market equilibrium quantity resulting from
emission controls are dependent upon the magnitude of the per unit control costs and
elasticity measures in the market. The relative burden of emission control costs between
consumers and producers will be determined by the comparative magnitudes of the supply
and demand elasticities prevailing in a market, all other factors being equal. The more
inelastic demand is for a product, the larger the share of emission control costs that will
be paid by consumers of the product in the form of higher product prices. Alternatively,
the more inelastic the supply curve, the larger the share of emission control costs that
will be paid by suppliers.
6.2.8.1 Price Elasticity of Demand. The price elasticity of demand represents the
percentage change in the quantity demanded resulting from each 1 percent change in the
price of the product. Petroleum products represent a very important energy source for the
United States. Many studies have been conducted which estimate the price elasticity of
demand for some or all of the petroleum products of interest and numerous published
sources of the price elasticity of demand for petroleum products exist. These elasticity
measures are used in the analysis and are listed in Table 6-1. Sources of these data are
discussed in detail in the Industry Profile for the Petroleum Refinery NESHAP (1993).
TABLE 6-1. ESTIMATES OF PRICE ELASTICITY OF DEMAND
FUEL TYPE
Motor Gasoline
Jet fuel
Residual Fuel Oil
Distillate Fuel Oil
Liquified Petroleum Gas
ELASTICITY
RANGE
-0.55 to -0.8227
-0.1528
-0.61 to -0.7427
-0.50 to -0.9927
-0.60 to -l.O27
MID-POINT
ELASTICITY
-0.69
-0.15
-0.675
-0.745
-0.80
The elasticity estimates for each of the products reflect that each of these products
have inelastic demand. The only exception is the upper end of the range of elasticities for
LPGs that is unitary elastic. As previously stated, regulatory control costs are more likely
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to paid by consumers of products with inelastic demand when compared to elastic
demand, all other things held constant. Price increases for products with inelastic
demand lead to revenue increases for producers of the product. Thus, one can predict
that price increases resulting from implementation of regulatory control costs will lead to
higher revenues for the petroleum refining industry, all other factors held constant. The
market changes resulting from the regulations are based upon the midpoint of the range
of demand elasticities. A sensitivity analysis of this assumption was made using the upper
and lower bounds of the range of elasticities.
6.2.8.2 Price Elasticity of Supply. The price elasticity of supply or own-price
elasticity of supply is a measure of the responsiveness of producers to changes in the price
of a product. The price elasticity of supply indicates the percentage change in the
quantity supplied of a product resulting from each 1 percent change in the price of the
product.
Published sources of the price elasticity of supply using current data were not readily
available. It was determined that the price elasticity of supply should be estimated
econometrically using time series data. Several estimation approaches were considered
and are discussed in detail in the Economic Impact Analysis of the Petroleum Refinery
NESHAP (1994). The approach actually used to estimate the price elasticity of supply
was a time series model of the production function for the petroleum refining industry.
Relevant factors of production in the model included labor, capital, and materials (crude
oil). The econometric results of the production function estimation and efficient market
assumptions were used to derive a price elasticity of supply for the petroleum products of
interest of 1.24. This estimate of the price elasticity of supply for the five petroleum
products reflects that the petroleum refinery industry in the U.S. will increase production
of gasoline, jet fuel, residual fuel oil, distillate fuel oil and LPGS jointly by 1.24 percent
for every 1.0 percent increase in the price of these products. Elasticity measures for the
individual products were not calculated due to statistical modeling problems. Limitations
of the elasticity measure estimate are discussed in detail in the Economic Impact Analysis
and in a limited manner in 6.4 Limitations of the Economic Model.
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6.3 CAPITAL AVAILABILITY ANALYSIS
It is necessary to estimate the impact of the proposed emission controls on the
financial performance of affected petroleum refineries and on the ability of the refineries
to finance the additional capital investment in emission control equipment. Financial
data were not available for the majority of the refineries in the industry. Available data
were obtained only for the largest publicly held petroleum refining companies. For this
reason, the capital availability analysis has been conducted on an industrywide basis.
One measure of financial performance frequently used to assess profitability of a firm
is net income before interest expense as a percentage of firm assets or rate of return on
investment. The pre-control rate of return on investment (roi) is calculated as follows:
roi =
15 • 100
where nt is income before interest payments and a, is total assets. A five-year average is
used to avoid annual fluctuations that may occur in income data. The proposed
regulations potentially could have an effect on income before taxes (n)t for firms in the
industry and on the level of assets for firms in the industry (a,.) Since firm specific data
were unavailable for all of the affected firms, sample financial data collected by the
American Petroleum Institute (API) were used.29 Data from the API study are available
in Industry Profile for the Petroleum Refinery NESHAP. The sample studied by API
represents 71 percent of net income in the industry and 70 percent of total industry
assets. These percentages are considered to estimate changes in the financial ratios and
are necessary to allocate changes in income and assets resulting from emission controls to
the study sample. There is a great diversity among the refineries in the industry;
therefore, individual firm financial performance may vary greatly from the sample
estimate. The post-control return on investment (proi) is calculated as follows:
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proi =
1990 N
£ n. I / 5
V(=1986
(1990
E.
1=1986
•100
where:
proi = the post-control return on investment
A/I = the change in income before interest resulting from implementation of
emission controls for firms in the sample
*k = capital expenditures associated with emission controls.
The equation proi will tend to overstate the impact of the control measure on the rate of
return on investment for the industry over the life of the emission controls. This is true
because net capital investment in emission controls will decline as capital is depreciated.
The ability of affected firms to finance the capital equipment associated with the
emission control is also relevant to the analysis. Numerous financial ratios can be
examined to analyze the ability of a firm to finance capital expenditures. One such
measure is historical profitability measures such as rate of return on investment. The
analysis approach for this measure has been previously described. The bond rating of a
firm is another indication of the credit worthiness of a firm or the ability of a firm to
finance capital expenditures with debt capital. Such data are unavailable for many of the
firms subject to the regulation, and consequently bond ratings are not analyzed. Ability
to pay interest payments is another criterion sometimes used to assess the capability of a
firm to finance capital expenditures. Coverage ratios provide such information. The
interest coverage ratio, or the number of times income (before taxes and interest) will pay
interest expense, is a ratio that provides some information about the ability of a firm to
cover or pay annual interest obligations. The pre-control measure of coverage ratio is as
follows:
ebit.
l 15
i = 1986 interest,
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where:
tc
ebit
interest, =
number of times earnings will pay annual interest charges
earnings before interest payments and taxes
annual interest expense
Post-control coverage ratios may be estimated as follows:
where:
ptc =
1990
ebiti / 5 + A ebit
U =• 1986
1990
interest A / 5 + A interest
V=1986
= estimated change in earnings before interest and taxes of the firm
= anticipated change in interest expense
All other variables have been previously described. The ^interest is calculated by
multiplying the capital expenditures for the proposed controls (tJt) by the assumed private
cost of capital (10 percent). This is generally lower than the overall cost of capital for a
firm. Again the interest coverage ratios of individual petroleum refineries may differ from
the average significantly.
Finally, the degree of debt leverage or debt-equity ratio of a firm is considered in
assessing the ability of a firm to finance capital expenditures. The pre-control debt-equity
ratio is the following:
where:
die =
d =
e =
debt equity ratio
debt capital
equity capital
d/e =
*1990
1990
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Since capital information is less volatile than earnings information, it is appropriate to
use the latest available information for this calculation. If one assumes that the capital
costs of control equipment are financed solely by debt, the debt-equity ratio becomes:
pd/e = £2
where pd/e is the post-control debt-equity ratio assuming that the control equipment
costs are financed solely with debt. Obviously, firms may choose to issue capital stock to
finance the capital expenditure or to finance the investment through internally generated
funds. The assumption that the capital costs are financed solely by debt may be viewed
as a worse case scenario.
The methods used to analyze the capital availability do have some limitations. The
approach matches 1990 debt and equity values with estimated capital expenditures for
control equipment. Average 1986 through 1990 income and asset measures are matched
with changes in income and capital expenditures associated with the control measures.
The control cost changes and income changes reflect 1992 price levels. The financial data
used in the analysis represents the most recent data available. It is inappropriate to
simply index the income, asset, debt, and equity values to 1992 price levels for the
following reasons. Assets, debt, and equity represent embedded values that are not
subject to price level changes except for new additions such as capital expenditures.
Income is volatile and varies from period to period. For this reason, average income
measures are used in the study. The analysis reflects a conservative approach to
analyzing the changes likely in financial ratios for the petroleum industry. Some
decreases the cost of production expected to result from implementation of emission
controls have not been considered. These include labor input and energy input cost
decreases. Annualized compliance costs are overstated from a financial income
perspective since these costs include a component for earnings or return on investment.
In general, the approach followed is a worst case scenario approach that overstates the
negative impact of the proposed emission controls on the financial operations of the
petroleum refining industry..
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6.4 LIMITATIONS OF THE ECONOMIC MODEL
Several qualifications of the model presented must be made. First, the partial
equilibrium model estimated for each of the five petroleum products assumes that a single
homogeneous product is sold in a national market. In the actual market, there may be
some differentiation of the refined petroleum products sold throughout the country and
regional barriers to trade may exist in the petroleum refinery market. Product
differentiation and regional barriers to trade would allow firms in the industry to have
greater market power. Market power enables firms to have more control over the market
price of the product sold and would lessen the impact of emission controls costs on firms
in the industry.
Next, an assumption is made in the model that refineries with the highest per unit
control cost are marginal in the post-control market. Firms with the highest per unit
control costs are assumed to have the highest underlying cost of production. This
assumption was necessary due to lack of available information concerning the cost of
production on an individual refinery basis.
Additionally, a review of the data indicates refineries that are marginal in the post-
control market have per unit control costs that significantly exceed the average. This
may be the result of the engineering method used to assign costs to individual refineries.
Moreover, the cost allocation methodology assigns all of the control costs to the five
petroleum products of interest. These products represent less than one hundred percent
of the refined petroleum products produced domestically.
Finally, some plants may find that the price increase resulting from the regulations
make it profitable to expand production. This would occur if a firm found its post-control
incremental cost to be less that the post-control market price. Expansion by these firms
would result in a smaller decrease in output and increase in price than otherwise would
occur. The foregoing list of qualifications tend to overstate the impacts of the proposed
emission controls on the market equilibrium price and quantity, revenues, and plant
closures.
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Estimates of model results are dependent on the price elasticity measures assumed
for demand and supply. A sensitivity analysis of the price elasticity of demand reflects
minimal changes in the market results with alternative lower and upper bound elasticity
measures. (See the Economic Impact Analysis for the Petroleum Refinery NESHAP for
details.)
The methodology used to estimate the price elasticity of supply also must be qualified.
The elasticity measure does not estimate the supply elasticities for the individual
products or directly consider the interrelationships between products. The assumption
implicit in use of this supply elasticity estimate is that the elasticities of the individual
petroleum products will not differ significantly from the elasticity of the products
combined. This does not seem a totally unreasonable assumption since the same factor
inputs are used to produce each of the petroleum products. The methodology also does not
explicitly consider the cross-price elasticities for the petroleum products. Since these
products are joint products, changes in the price of one product will have an effect on the
quantity supplied of the other products.
The uncertainty of the supply estimate is acknowledged. It is possible to conduct a
sensitivity analysis of the price elasticity supply. Such an analysis would quantify the
impact of this assumption on the reported market results. Given the magnitude of
market impact results, reasonable variations in the price elasticity of supply are unlikely
to alter the model results significantly.
The estimates of the secondary impacts associated with the emission controls are
based on changes predicted by the partial equilibrium model. The limitations previously
described are applicable to primary and secondary economic impacts. As previously
noted, the estimated employment losses do not consider potential employment gains for
operating the emission control equipment. It is important to note that the potential job
losses predicted by the model are only those directly linked to predicted production losses
in the petroleum refining industry. Likewise, the gains or losses in markets indirectly
affected by the regulations, such as substitute product markets, complement products
markets, or in markets that use petroleum products as inputs have not been considered in
this analysis.
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The capital availability analysis also has limitations. Some of these limitations have
been previously noted. Future baseline performance may not resemble past levels.
Future financial performance of the petroleum refining industry will be affected by
market considerations other than emission control measures, and these factors are not
readily estimated. Additionally, the tools used in the analysis are limited in scope and do
not fully describe the financial position of individual firms within the industry but are
more reflective of industry averages. Finally, the approach used to estimate the impact of
the control costs on the financial ratios tends to overstate the effect of emission control
costs on these ratios.
6.5 PRIMARY IMPACT, CAPITAL AVAILABILITY ANALYSIS, AND SECONDARY
IMPACT RESULTS
Estimates of the primary economic impacts, secondary impacts, and capital
availability consequences associated with the chosen option or preferred alternative are
presented. As previously discussed, Alternative 1 requires MACT floor controls on all
emission points other than equipment leaks where Option 1 controls are less costly.
Primary impacts related to control cost associated with Alternative 1 include changes in
the market equilibrium price and output levels, changes in the value of shipments or
revenues to domestic producers, and plant closures. Secondary impacts relate to labor
market, energy market and international trade effects likely to occur as a result of the
emission control requirements. The capital availability analysis assesses the ability of
affected firms to raise capital, and the impacts of control costs on plant profitability.
Finally, there are social costs associated with the incurrence of the emission control costs
of Alternative 1 and for Alternative 2.
6.5.1 Estimates of Primary Impacts
The partial equilibrium model is used to analyze the market outcome of the proposed
regulation. The purchase of emission control equipment will result in an upward vertical
shift in the domestic supply curve for refined petroleum products. The height of the shift
is determined by the after-tax cash flow required to offset the per unit increase m
production costs. Since the control costs vary- for aach of the domestic rcfine-noy. :bc- posr-
control supply curve is segmented, or a step function. Underlying production costs tor
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each refinery are unknown; therefore, a worst case scenario has been assumed. The
plants with the highest control costs per unit of production are assumed to also have the
highest pre-control per unit cost of production. Thus, firms with the highest per unit cost
of emission control are assumed to be marginal in the post-control market.
Foreign supply is assumed to have the same price elasticity of supply as domestic
supply. The United States had a negative trade balance for each of the refined products
in 1992 with the exception of distillate fuel oil that had a slightly positive trade balance of
$1.1 million. Therefore net exports are negative for all products except distillate fuel oil
in the baseline model. Foreign and domestic post-control supply are added together to
form the total post-control market supply. The intersection of this post-control supply
with market demand will determine the new market equilibrium price and quantity.
Post-control domestic output is derived by deducting post-control imports from the post-
control output.
Table 6-2 reveals the primary impacts predicted by the partial equilibrium model for
Alternative 1. The range of anticipated price increases for the five products vary from
$0.03 to $0.14 per barrel produced for residual fuel oil and jet fuel, respectively. The
percentage increases for each product are less than 1 percent and range from 0.26 percent
to 0.53 percent.
Production is expected to decrease by 12.5 million barrels per year for all products, an
overall decrease in domestic production of 0.24 percent. The estimated annual reductions
in production of the individual products range from 0.65 million barrels to 5.67 million
barrels for jet fuel and motor gas, respectively. The production percentage decreases
range from 0.13 percent to 0.58 percent for jet fuel and residual fuel oil, respectively.
Value of domestic shipments or revenues for domestic producers are expected to
increase for the five products approximately $107 million annually. The predicted
changes in revenues for individual products range from an increase of $56 million in
motor gasoline revenues to a decrease in residual fuel revenues of approximately S12
million annually. The percent changes range from an increase of 0.41 percent in jet fuel
to a decrease of 0.26 percent in residual fuel oil revenues. Economic theory predicts that
revenue increases are expected to occur when prices are increased ibr inelastic goous, in
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TABLE 6-2. SUMMARY OF PRIMARY IMPACTS
Estimated Impacts
Refined Product
Price
Increases1
Production
Decreases2
Value of
Domestic
Shipments3
Motor gasoline
Amount
Percentage
Jet fuel
Amount
Percentage
Residual fuel
Amount
Percentage
Distillate fuel
Amount
Percentage
LPGs
Amount
Percentage
TOTAL
$0.09
0.29%
$0.14
0.53%
$0.03
0.24%
$0.08
0.29%
$0.07
0.26%
(5.67)
(0.22%)
(0.65)
(0.13%)
(1.62)
(0.50%)
(2.78)
(0.26%)
(1.80)
(0.25%)
(12.52)
$55.63
0.07%
$53.22
0.41%
($11.92)
( 0.26%)
$8.06
0.03%
$2.42
0.01%
$107.41
NOTES: () indicate decreases.
'Prices are shown in price per barrel ($1992).
2Annual production quantities are shown in millions of barrels.
Values of domestic shipments are shown in millions of 1992 dollars.
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other factors held constant. This phenomenon results from the percentage increase in
price exceeding the percentage decrease in quantity for goods with inelastic demand. All
of the refined petroleum products follow the expected trend except residual fuel oil.
Residual fuel oil has the highest trade deficit of the five products with over 40 percent of
domestic demand being imported. The magnitude of residual fuel oil imports causes a
decrease in domestic residual fuel oil revenues to occur in the post-control market.
It is anticipated that seven refineries may close as a result of the decrease in
production predicted by the model. Those refineries with the highest per unit control
costs are assumed to be marginal in the post-control market. Refineries that have post-
control supply prices that exceed the market equilibrium price are assumed to close. This
assumption is consistent with the perfect competition theory that presumes all firms in
the industry are price takers. Firms with the highest per unit control costs may not have
the highest underlying cost of production. This is a worst case assumption that likely
biases the results to overstate the likely number of plant closures and other adverse
effects of the proposed emission controls.
The estimated primary impacts reported depend on the set of parameters used in the
partial equilibrium model. One of the parameters, the price elasticity of demand,
consisted of a range for four of the five refined products. The midpoint of the range of
elasticities was used to estimate the reported primary and secondary impacts. A
sensitivity analysis of this assumption was conducted. The low and high end of the range
of elasticities are inputs in the sensitivity analysis. In general, the sensitivity analysis
shows that the estimated primary impacts are relatively insensitive to reasonable changes
of price elasticity of demand estimates. Estimates of market impacts with lower elasticity
measures shift relatively more of the burden of the emission controls to consumers in the
form of slightly higher price increases and lower output decreases. Higher elasticity
measures shift more of the burden to producers in the form of slightly lower price
increases and higher output decreases.
6.5.2 Capital Availability Analysis
The capital availability analysis involves examining pre- and post-control values of
selected financial ratios. These ratios include rate of return on investment, times interest
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earned coverage ratio, and the debt-equity ratio. Data were not available to estimate the
ratios for many refineries in the industry. Consequently, these ratios have been analyzed
on an industrywide basis. Since the industrywide ratios represent an average for the
industry, individual firms within the industry may have financial ratios that differ
significantly from the average. Net income was averaged for a five year period (1986
through 1990) to avoid annual fluctuations in income that may occur due to changes in
the business cycle. Debt and equity capital are not subject to annual fluctuations;
therefore, the most recent data available (1990) were used in the analysis.
The financial statistics provide insight regarding firms' ability to raise capital to
finance the investment in emission control equipment. Table 6-3 shows the estimated
impact on financial ratios for the industry.
TABLE 6-3. ANALYSIS OF FINANCIAL RATIOS
Financial Ratios Pre-Control Ratios Post-Control Ratios
Rate of return on investment 5.91% 5.91%
Coverage Ratio (or Times 7.08 7.07
Interest Earned)
Debt-Equity Ratio 62.75% 62.76%
The financial ratios remain virtually unchanged as a result of the proposed emission
controls. The magnitude of the income changes and the capital expenditures necessary
for the emission control measures do not significantly alter the financial position of the
industry. The impact of the standards on individual refineries, however, may vary greatly
from the industry averages used in this analysis.
6.5.3 Labor Market Impacts and Energy Market Impacts
The estimated labor impacts associated with the NESHAP are based on the results of
the partial equilibrium analyses of the five refined oetroleum Troducts ind are mooned
in Table 6-4. The number of workers employed by firms in SIC 2911 is estimated to
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TABLE 6-4. SUMMARY OF SECONDARY REGULATORY IMPACTS
Estimated Impacts
Refined Product Labor Input1 Energy Input2
Motor gasoline
Amount (52) ($5.79)
Percentage (0.22%) (0.22%)
Jet fuel
Amount (6) ($0.52)
Percentage (0.13%) (0.13%)
Residual fuel
Amount (15) ($0.71)
Percentage (0.50%) (0.50%)
Distillate fuel
Amount (25) ($2.27)
Percentage (0.26%) (0.26%)
LPGs
Amount (16) ($1.56)
Percentage (0.25%) (0.25%)
Total five products
Amount (114) ($10.85)
NOTES: ( ) Indicates decreases.
'Indicates estimated reduction in number of jobs.
2Reduction in energy use in millions of 1992 dollars.
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decrease by approximately 114 workers as a result of the proposed emission controls. The
loss in number of workers depends primarily on the estimated reduction in production.
Gains in employment anticipated to result from operation and maintenance of control
equipment have not been included in the analysis due to lack of reliable data. Estimates
of employment losses do not consider potential employment gains in industries that
produce substitute products. Similarly, losses in employment in industries that use
petroleum products as an input or in industries that provide complement goods are not
considered. The changes in employment reflected in this analysis are only direct
employment losses due to reductions in domestic production of refined petroleum
products.
The loss in employment of 114 jobs annually is small relative to the total employment
in the industry. The magnitude of predicted job losses is a direct results of from the
relatively small decrease in production estimated by the model, and by the relatively low
labor intensity in the industry.
The method used to estimate reductions in use of energy inputs relates the energy
expenditures to the level of production. An estimated decrease in energy input use of
nearly $11 million annually is expected for the industry. The individual product energy
use changes are reported in Table 6-4. As production decreases, the amount of energy
input utilized by the refining industry also declines. The changes in energy use do not
reflect the increased energy use associated with operating and maintaining emission
control equipment. Insufficient data were available to consider such changes in energy
costs.
6.5.4 Foreign Trade Impacts
The implementation of the NESHAP will increase the cost of production for domestic
refineries relative to foreign refineries, all other factors being equal. This change in the
relative price of imports will cause domestic imports of refined petroleum products to
increase and domestic exports to decrease. The balance of trade overall for refined
petroleum products is currently negative (imports exceed exports). The NESHAP will
likelv cause the trade deficit; to 'ncroase. Met exports ar3 ;ikoiv "": ie"i'r.e hv 2.V! •mlbo!?
barrels per year. The range of net export decreases vary from 0.21 million barrels to 0.91
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million barrels for LPGs and residual fuel oil, respectively. The related percent decreases
range from 0.54 percent to 40.9 percent for LPGs and distillate fuel oil, respectively. The
large percentage decrease in exports of distillate is the result of the product having a very
small positive trade balance in the pre-control market. The dollar value of the total
decline in net exports is expected to amount to $68.2 million annually. The predicted
changes in the trade balance are reported in Table 6-5.
6.5.5 Regional Impacts
No significant regional impacts are expected from implementation of the NESHAP.
Approximately 7 refineries are estimated to close nationwide. Due to the manner used to
estimate control costs for the individual refinery and the method of allocating the costs to
products, the facilities predicted to close do not necessarily represent the facilities most
likely to close. However, the facilities postulated in the model are dispersed throughout
the United States and are not specific to a particular geographical region. Employment
impacts are directly related to plant closure and production decreases. Employment
impacts are also dispersed throughout the country.
6.6 SUMMARY
The estimated market changes resulting from the proposed emission controls are
relatively small. Predicted price increases and reductions in domestic output are less
than 1 percent for each of the refined products. The value of domestic shipments or
revenues to domestic producers are anticipated to increase for the 5 product categories by
a total of $107 million annually ($1992). Emission controls costs are small relative to the
financial resources of affected producers, and on average, refineries should not find it
difficult to raise the capital necessary' to finance the purchase and installation of emission
controls. Approximately seven refineries may close as a result of the proposed controls.
The estimated secondary economic impacts are also relatively small. Approximately
114 job losses may occur nationwide. Energy input reductions are estimated to be
approximately $11 million annually. A decrease is net exports of 2.3 million barrels
annually in refined products is anticipated to occur. No regional impacts are expected.
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TABLE 6-5. FOREIGN TRADE (NET EXPORTS) IMPACTS
Estimated Impacts
Refined Product
Motor Gasoline
Jet fuel
Residual fuel
Distillate fuel
LPGs
Total
Amount1
(0.43)
(0.23)
(0.91)
(0.48)
(0.21)
(2.26)
Percentage
(0.54%)
(1.41%)
(0.81%)
(40.92%)
(0.54%)
Dollar Value of Net
Export Change2
($21.92)
($8.14)
($16.81)
($12.67)
($8.68)
($68.22)
NOTES: () indicates decreases.
'Millions of barrels.
'Millions of dollars ($1992).
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6.7 POTENTIAL SMALL BUSINESS IMPACTS
6.7.1 Introduction
The RFA requires that special consideration be given to the effects of all proposed
regulations on small business entities. The Act requires that a determination be made as
to whether the subject regulation will have a significant impact on a substantial number
of small entities. A substantial number is considered to be greater than 20 percent of the
small entities identified. The following criteria are provided for assessing whether the
impacts are significant. The impact on small business entities is considered significant
whenever any of the following criteria are met:
1. annual compliance costs (annualized capital, operating, reporting, etc.) increase
as a percentage of cost of production for small entities for the relevant process or
product by more than 5 percent;
2. compliance costs as a percent of sales for small entities are at least 10 percent
higher than compliance costs as a percent of sales for large entities;
3. capital costs of compliance represent a significant portion of capital available to
small entities, considering internal cash flow plus external financing capabilities;
and
4. the requirements of the regulation are likely to result in closure of small entities.
6.7.2 Methodology
Data are not readily available to estimate the small business impacts for two of the
criteria (1 and 3) listed in the previous section. The information necessary to make such
comparisons are generally considered proprietary by small business firms. Consequently,
the analysis will focus on remaining two (2 and 4) criteria of the potential for adverse
impacts. Closure of small businesses and a comparison of the compliance costs as a
percentage of sales for small and large business entities will be examined.
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The closure method of analysis will focus on the number of petroleum refineries
expected to close as a result of the proposed emission controls and the relative size of the
firms at risk. Alternatively, a measure of annual compliance costs as a percentage of
sales will also be considered. The ratio of costs to sales will be compared for small
refineries to the same ratio for all other refineries.
6.7.3 Categorization of Small Businesses
Consistent with Title IV, Section 410 of the CAA, a petroleum refinery is classified as
a small business if it has less than 1,500 employees or has annual production less than
50,000 barrels produced per day. A refinery must also be unaffiliated with another large
business entity. Information necessary to distinguish refinery size by number of
employees was not readily available. However, daily production data were available from
the Oil and Gas Journal, U.S. Refinery Survey (1-1-92). Based upon the production size
criterion, there were 63 operating refineries in 1992 that could be categorized as small
business entities.
6.7.4 Small Business Impacts
The results of the partial equilibrium analysis lead to the conclusion that
approximately seven refineries are at risk of closure. This estimate represents
approximately four percent of the domestic refineries in operation and 11 percent of those
designated to be small businesses. The estimated number of closures is therefore less
than 20 percent of the small refineries. However, it is important to note that the firms
designated in the model as being at the greatest risk for closure were small refineries.
Compliance costs as a percentage of sales were computed both for the small refineries
and for those refineries that are not considered small. The cost to sales ratio for the
small refineries was 0.19 percent of sales while the cost to sales ratio for all other
refineries was 0.08 percent. The differential between these two rates exceeds ten percent,
and consequently, a conclusion is drawn that a significant number of small businesses are
adversely affected by the proposed regulations.
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6.8 SOCIAL COSTS OF REGULATION
The social costs of regulation are those costs borne by society for pollution abatement.
From an economic perspective, the social costs of regulation represent the opportunity
costs of scarce resources utilized for pollution control, or the economic costs. Scarce
resources used in pollution control could alternatively be used by society for purposes
other than emission control. Thus, a social loss or economic cost occurs. Consumers,
producers, and all of society bear the costs of pollution controls. Economic losses to
consumers result from the higher prices paid for goods consumed and the lesser quantity
goods consumed. Producers benefit from a higher price paid by consumers for each unit of
product sold but incur compliance costs for each unit of production. Producers also sell a
smaller quantity of the good after controls are implemented. Finally, it is necessary to
adjust the preceding changes in consumer and producer surplus to reflect the regulation's
cost to society. The change in residual surplus represent tax revenues that may be gained
or lost from the emission controls and the differential in the private cost of capital and
the social cost of capital. The economic costs of regulation (EC) as previously defined
consists of the sum of the change in domestic consumer surplus (&CSd), the change in
producer surplus (APS), and the change in the residual surplus to society (&RS) resulting
from the proposed emission controls.
6.8.1 Social Cost Estimates
The components of the social costs of regulation have been previously discussed.
More details on the exact methodology for calculating for these values are contained in
the Economic Impact for the Petroleum Refinery NESHAP (1994). The economic costs of
Alternatives 1 and 2 of the NESHAP are displayed in Table 6-6. The social costs of
Alternative 1 are estimated from the partial equilibrium model and are divided into
changes in consumer, producer, and residual surplus. The social costs of Alternative 2
are calculated by adding the differential in the compliance costs for the two alternatives
to the social costs of Alternative 1. This approach was used because the partial
equilibrium model results were available only for Alternative 1. This method understates
the social costs of Alternative 2, but it is the most accurate approach possible, given
available data.
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TABLE 6-6. ANNUAL SOCIAL COST ESTIMATES FOR THE PETROLEUM REFINING
REGULATION
(Millions of 1992 dollars)
Social Cost Category Net Costs1
Surplus Costs for Preferred Option:
Change in Consumer Surplus $476.2
Change in Producer Surplus $(242.1)
Change in Residual Surplus to Society2 $(101.7)
Total Social Cost of Alternative I3 $132.4
Total Social Cost of Alternative 24 $148.4
NOTES: 'Brackets indicate negative surplus losses, or surplus gains.
2Residual surplus loss to society includes adjustments necessary to equate the relevant discount rate to the social
cost of capital and to consider appropriate tax effect adjustments.
Alternative 1 includes floor controls for all emission points except equipment leaks. Option 1 is preferred to the floor
for equipment leaks because it is a less costly option than the floor.
4Altemative 2 includes Option 2 for Equipment Leaks, Option 1 for Storage Tanks, and the Floor for Miscellaneous
process vents. Emission controls at other emission points were not considered. Social costs were calculated by
adding incremental compliance costs for Alternative 2 to the social costs of Alternative 1
145
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REFERENCES
1. Robert Beck and Joan Biggs. OGJ 300. Oil & Gas Journal. Vol. 89. No. 39. Tulsa,
OK. September 1991.
2. U.S. Department of Commerce. Petroleum Refining — U.S. Industrial Outlook 1992.
Washington, DC. January 1992.
3. American Petroleum Institute. Market Shares and Individual Company Data for U.S.
Energy Markets, 1950-1989. Discussion Paper #014R. Washington, DC. October
1990.
4. U.S. Department of Energy. The U.S. Petroleum Refining Industry in the 1980's.
DOE/EIA-0536. Energy Information Administration. October 1990.
5. U.S. Department of Energy. Annual Outlook for Oil and Gas. DOE/EIA-0517(91).
Energy Information Administration. Washington, DC. June 1991.
6. U.S. Department of Energy. Performance Profiles of Major Energy Producers, 1990.
DOE/EIA-0206(90). Energy Information Administration. Washington, DC. December
1991.
7. Cambridge Energy Research Associates. The U.S. Refining Industry: Facing the
Challenges of the 1990s. Prepared for U.S. Department of Energy. January 1992.
8. Robert S. Pindyck and Daniel L. Rubinfeld. Microeconomics. MacMillan Publishing
Co. 1989.
9. U.S. Department of Energy. The U.S. Petroleum Industry: Past as Prologue 1970-
1992. DOE/EIA-0572. Energy Information Administration, Office of Oil and Gas.
Washington, DC. September 1993.
10. Bonner & Moore Management Science. Overview of Refining and Fuel Oil
Production. Houston, TX. April 29, 1982.
11. U.S. Department of Energy. Annual Report to Congress. DOE/EIA-0173(91). Energy
Information Administration. Washington, DC. March 1992.
12. Dermot Gately. New York University. Taking Off: The U.S. Demand for Air Travel
and Jet Fuel. The Energy Journal. Vol. 9. No. 4. 1988.
13. U.S. Department of Energy. Petroleum Marketing Annual, 1990. DOE/EIA-0487(90).
Energy Information Administration. Washington, DC. December 1991.
14. Reference 2.
15. U.S. Department of Commerce. Petroleum Refining — U.S. Industrial Outlook 1991.
Washington, DC. January 1991.
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7.0 QUALITATIVE ASSESSMENT OF BENEFITS
OF EMISSION REDUCTIONS
One rationale for environmental regulation is to provide benefits to society by
iproving environmental quality. In this chapter, and the two chapters which follow,
formation is provided on the types and levels of social benefits anticipated from the
itroleum refinery NESHAP. This chapter examines the potential health and welfare
jnefits associated with air emission reductions projected as a result of implementation of
le petroleum refinery NESHAP. The proposed regulation is expected to reduce
nissions of HAPs emitted from storage tanks, process vents, equipment leaks, and
'astewater emission points at refining sites. Of the HAPs emitted by petroleum
jfineries, some are classified as VOCs, which are ozone precursors.
In general, the reduction of HAP emissions resulting from promulgation and
implementation of the petroleum refinery NESHAP will reduce human and environmental
exposure to these pollutants and thus, reduce potential adverse health and welfare effects.
.Tiis chapter provides a general discussion of the various components of total benefits that
nay be gained from a reduction in HAPs through the subject NESHAP. HAP benefits are
Dresented separately from the benefits associated specifically with VOC emission
•eductions.
7.1 IDENTIFICATION OF POTENTIAL BENEFIT CATEGORIES
The benefit categories associated with the emission reductions predicted for this
regulation can be broadly categorized as those benefits which are attributable to reduced
exposure to HAPs. and those attributable to reuucea exposure r,o YGCo. T!:c- 'rv:r;:r'^
emissions of a few HAPs associated with this regulation have been classified as probable
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or known human carcinogens. As a result, one of the benefits of the proposed regulation
is a reduction in the risk of cancer mortality. Other benefit categories include: reduced
exposure to noncarcinogenic HAPs, and reduced exposure to VOCs. In addition to health
impacts occurring as a result of reductions in HAP and VOC emissions, there are welfare
impacts which can also be identified. In general, welfare impacts include effects on creps
and other plant life, materials damage, soiling, and visibility. Each category is discussed
separately in the following section.
7.2 QUALITATIVE DESCRIPTION OF AIR RELATED BENEFITS
A summary of the range of potential physical health and welfare effects categories
that may be associated with HAP emissions and also with concentrations of ozone formed
by VOC HAPs is provided in Table 7-1. As noted in the table, exposure to HAPs can lead
to a variety of acute and chronic health impacts as well as welfare impacts. The health
and welfare benefits of HAP and VOC reductions are presented separately.
7.2.1 Benefits of Decreasing HAP Emissions
Human exposure to HAPs may occur directly through inhalation or indirectly through
ingestion of food or water contaminated by HAPs or through dermal exposure. HAPs may
also enter terrestrial and aquatic ecosystems through atmospheric deposition. HAPs can
be deposited on vegetation and soil through wet or dry deposition. HAPs may also enter
the aquatic environment from the atmosphere via gas exchange between surface water
and the ambient air, wet or dry deposition of particulate HAPs and particles to which
HAPs adsorb, and wet or dry deposition to watersheds with subsequent leaching or runoff
to bodies of water.1 This analysis is focused only on the air quality benefits of HAP
reduction.
7.2.1.1 Health Benefits of Reduction in HAP Emissions. According to baseline
emission estimates, this source category currently emits approximately 81,000 Mg of
HAPs annually. The petroleum refinery NESHAP will regulate several of the 189 air
toxics listed in Section 112(b) of the CAA. Exposure to ambient concentrations of these
pollutants may result in a variety of adverse health effects considering both cancer arm
150
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noncancer endpoints. Many HAPs are classified as known human carcinogens.
Speciation of the HAP emissions at refining sites was available only for equipment leaks.
Of those HAPs (presented in Table 3-2), only benzene and naphthalene are classified as
known human carcinogens, according to an EPA system for classifying chemicals by
cancer risk. This means that there is sufficient evidence to support that exposure to these
two chemicals causes an increased risk of cancer in humans. Benzene is a concern to
EPA because long term exposure to this chemical has been known to cause leukemia in
humans. While this is the most well known effect, benzene exposure is also associated
with aplastic anemia, multiple myeloma, lymphonomas, pancytopenia, chromosomal
breakages, and weakening of bone marrow.13 Therefore, a reduction in human exposure
to benzene and naphthalene could lead to a decrease in cancer risk and ultimately to a
decrease in cancer mortality.
Cresols are considered to be group C or possible human carcinogens. For this HAP,
there is either inadequate data or no data on human carcinogenicity, and there is limited
data on animal carcinogenicity. Therefore, while cancer risk is possible, there is not
sufficient evidence to support that these chemicals will cause increased cancer risks in
humans.
The remaining HAPs emitted by equipment leaks at refining sites are noncarcinogens.
However, exposure to these pollutants may still result in adverse health impacts to
human and non-human populations. Noncancer health effects can be grouped into the
following broad categories: genotoxicity, developmental toxicity, reproductive toxicity,
systemic toxicity, and irritant. Genotoxicity is a broad term that usually refers to a
chemical that has the ability to damage DNA or the chromosomes. Developmental
toxicity refers to adverse effects on a developing organism that may result from exposure
prior to conception, during prenatal development, or postnatally to the time of sexual
maturation. Adverse developmental effects may be detected at any point in the life span
of the organism. Reproductive toxicity refers to the harmful effects of HAP exposure on
fertility, gestation, or offspring, caused by exposure of either parent to a substance.
Systemic toxicity affects a. portion of the body other than the site of entry. Irritant reiers
to any effect which results in irritation of the eves, skin, and respiratory tract.14
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For the HAPs covered by the petroleum refinery NESHAP, evidence on the potential
toxicity of the pollutants varies. Given sufficient exposure conditions, each of these HAPs
has the potential to elicit adverse health or environmental effects in the exposed
populations. It can be expected that emission reductions achieved through the subject
NESHAP will decrease the incidence of these adverse health effects.
7.2.1.2 Welfare Benefits of Reduction in HAP Emissions. The welfare effects of
exposure to HAPs have received less attention from analysts than the health effects.
However, this situation is changing, especially with respect to the effects of toxic
substances on ecosystems. Over the past ten years, ecotoxicologists have started to build
models of ecological systems which focus on interrelationships in function, the dynamics of
stress, and the adaptive potential for recovery. This perspective is reflected in Table 7-1
where the end-points associated with ecosystem functions describe structural attributes
rather than species specific responses to HAP exposure. This is consistent with the
observation that chronic sub-lethal exposures may affect the normal functioning of
individual species in ways that make it less than competitive and therefore more
susceptible to a variety of factors including disease, insect attack, and decreases in
habitat quality.15 All of these factors may contribute to an overall change in the structure
(i.e., composition) and function of the ecosystem.
The adverse, non-human biological effects of HAP emissions include ecosystem and
recreational and commercial fishery impacts. Atmospheric deposition of HAPs directly to
land may affect terrestrial ecosystems. Atmospheric deposition of HAPs also contributes
to adverse aquatic ecosystem effects. This not only has adverse implications for
individual wildlife species and ecosystems as a whole, but also the humans who may
ingest contaminated fish and waterfowl. In general, HAP emission reductions achieved
through the petroleum refinery NESHAP should reduce the associated adverse
environmental impacts.
7.2.2 Benefits of Reduced VOC Emissions
Emissions of VOCs have been associated with a variety of health and welfare impacts.
VOC emissions, together with NOX, are precursors en che formation ->r -,ruut>ap;;e.":.: .,,:,:,,-
It is exposure to ambient ozone that is most directly responsible for a series of respiratory
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related adverse impacts. Consequently, reductions in the emissions of VOCs will also lead
to reductions in the types of health and welfare impacts that are associated with elevated
concentrations of ozone. In this section, the benefits of reducing VOC emissions are
examined in terms of reductions in ozone.
7.2.2.1 Health Benefits of Reduction in VOC Emissions. Human exposure to elevated
concentrations of ozone primarily results in respiratory-related impacts such as coughing
and difficulty in breathing. Eye irritation is another frequently observed effect. These
acute effects are generally short-term and reversible. Nevertheless, a reduction in the
severity or scope of such impacts may have significant economic value.
Recent studies have found that repeated exposure to elevated concentrations of ozone
over long periods of time may also lead to chronic, structural damage to the lungs. *° To
the extent that these findings are verified, the potential scope of benefits related to
reductions in ozone concentrations could be expanded significantly.
Major ozone health effects are: alterations in lung capacity and breathing frequency;
eye, nose and throat irritation; reduced exercise performance; malaise and nausea;
increased sensitivity of airways; aggravation of existing respiratory disease; decreased
sensitivity to respiratory infection; and extrapulmonary effects (central nervous system,
liver, cardiovascular, and reproductive effects).17 In general, it is expected that reductions
in VOCs through the petroleum refinery NESHAP regulation is a mechanism by which
the ambient ozone concentration may be reduced and, in turn, reduce the incidence of the
adverse health effects of ozone exposure. In this section, the benefits of reducing VOC
emissions is examined in terms of reductions in ozone.
7.2.2.2 Welfare Benefits of VOC Reduction. In addition to acute and (possible) chronic
health impacts of ozone exposure, there may also be adverse welfare effects. The
principal welfare impact is related to losses in economic value for certain agricultural
crops and ornamental plants. Over the last decade, a series of field experiments has
demonstrated a positive statistical association between ozone exposure and reductions in
yield as well as visible injury to several economically valuable cash crops, including
soybeans and cotton. Damage to selected timber species has aiso oeen associated \vitr.
exposure to ozone. The observed impacts range from foliar injury to reduced growth rates
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and premature death. Benefits of reduced ozone concentrations include both the value of
avoided losses in commercially valuable timber and aesthetic losses suffered by non-
consumptive users.
155
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REFERENCES
1. U.S. Environmental Protection Agency. Regulatory Impact Analysis for the National
Emissions Standards for Hazardous Air Pollutants for Source Categories: Organic
Hazardous Air Pollutants from the Synthetic Organic Chemical Manufacturing
Industry and Seven Other Processes. Draft Report. Office of Air Quality Planning
and Standards. Research Triangle Park, NC. EPA-450/3-92-009. December 1992.
2. Mathtech, Inc. Benefit Analysis Issues for Section 112 Regulations. Final report
prepared for U.S. Environmental Protection Agency. Office of Air Quality Planning
and Standards. Contract No. 68-D8-0094. Research Triangle Park, NC. May 1992.
3. U.S. Environmental Protection Agency. Cancer Risk from Outdoor Exposure to Air
Toxics. Volume I. EPA-450/l-90-004a. Office of Air Quality Planning and Standards.
Research Triangle Park, NC. September 1990.
4. Graham, John D., D.R. Holtgrave, and M.J. Sawery. "The Potential Health Benefits
of Controlling Hazardous Air Pollutants." In: Health Benefits of Air Pollution
Control: A Discussion. Blodgett, J. (ed). Congressional Research Service report to
Congress. CR589-161. Washington, DC. February 1989.
5. Reference 4.
6. Voorhees, A., B. Hassett, and I. Cote. Analysis of the Potential for Non-Cancer
Health Risks Associated with Exposure to Toxic Air Pollutants. Paper presented at
the 82nd Annual Meeting of the Air and Waste Management Association. 1989.
7. Reference 4.
8. Reference 6.
9. Cote, I., L. Cupitt and B. Hassett. Toxic Air Pollutants and Non-Cancer Health
Risks. Unpublished paper provided by B. Hassett. 1988.
10. NAS. Chlorine and Hydrogen Chloride. National Academy of Sciences, National
Research Council. Chapter 7. 1975.
11. Stern, A. et al. Fundamentals of Air Pollution. Academic Press, New York. 1973.
12. Weinstein, D. and E. Birk. The Effects of Chemicals on the Structure of Terrestrial
Ecosystems: Mechanisms and Patterns of Change. In: Levin, S. et aL (eds). Ecotoxi-
cology: Problems and Approaches. Chapter 7. pp. 181-209. Springer-Verlag, New
York. 1989.
13. Reference 1. p. 3-5.
14. Reference 1. no. 8-4 to 8-5.
156
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REFERENCES (continued)
15. U.S. Environmental Protection Agency. Ecological Exposure and Effects of Airborne
Toxic Chemicals: An Overview. EPA/6003-91/001. Environmental Research
Laboratory. Corvallis, OR. 1991.
16. Reference 4.
17. Reference 1. pp. 8-8 to 8-9.
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8.0 QUANTITATIVE ASSESSMENT OF BENEFITS
This chapter presents quantitative estimates of the possible dollar magnitude of the
benefits identified in the previous chapter. The quantification of dollar benefits for all
benefit categories is not possible at this time because of limitations in both data and
methodology. This chapter presents the methodology which was utilized to obtain
monetary estimates of HAP and VOC emission reductions occurring as a result of the
proposed rule. Limitations of this methodology are also identified. To ensure that an
economically efficient regulatory alternative is chosen, an incremental analysis must be
performed. Therefore, benefits for the two regulatory alternatives are presented.
Potential impacts are evaluated for the proposed regulation and one alternative more
stringent than the proposed regulation.
8.1 METHODOLOGY FOR DEVELOPMENT OF BENEFIT ESTIMATES
Quantification of impacts associated with HAP exposure requires information on the
particular HAP involved. Such data are necessary because different HAP emissions can
lead to different types and degrees of severity of impacts. Table 8-1 identifies HAP
emissions by type for petroleum refineries. Although an estimate of the total reduction in
HAP emissions for various control options has been developed for this RIA, it has not
been possible to identify the speciation of the HAP emission reductions for each type of
emission point. However, an estimate of HAP speciation for equipment leaks has been
made. Since HAP emissions from equipment leaks account for nearly two thirds of total
HAP emissions at petroleum refineries, it is possible to use these data to develop an
approximate lower bound estimate of average cancer risk related to petroleum refinery
emissions.
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TABLE 8-1. HAP EMISSIONS AT PETROLEUM REFINERIES
2,2,4 - Trimethyl Pentane Hydrogen Fluoride
Benzene Phenol
Ethyl Benzene Cresols/Cresylic Acid
Hexane Methyl Tertiary Butyl Ether
Naphthalene Hydrogen Chloride
Toluene Methyl Ethyl Ketone
Xylenes
The potential impacts of reducing HAP emissions can be separated into two health
benefits categories. The first health benefit category evaluated will be the reduction in
annual cancer incidence due to carcinogenic HAP emission reductions. This approach
uses emissions data and the Human Exposure Model (HEM) to estimate the annual
cancer risk caused by HAP emissions from petroleum refineries. Generally, this benefit
category is calculated as the difference in estimated annual cancer incidence before and
after implementation of each regulatory alternative. The benefit category is then
monetized by applying a range of benefit values for each cancer case avoided.
The second category of health benefits expected to result from reduced HAP emissions
is reduced human exposure to noncarcinogenic HAP emissions. For each noncarcinogenic
HAP for which EPA had health benchmark information, EPA performed a baseline
assessment to estimate the number of people exposed to HAPs above health benchmark
levels. The quantified benefits attributable to reducing noncarcinogenic HAP emissions is
the difference in the number of people exposed above health benchmark levels before and
after regulation.
The benefits of controlling VOC emissions are monetized by applying average benefit
per megagram estimates to the total amount of VOC emission reductions calculated for
each of the two regulatory alternatives.
8.1.1 Benefits of Reduced Cancer Risk Associated with HAP Reductions
The proposed MACT for petroleum refineries is expected to reduce *;ne .'mission.-; •:
several HAPs that have been classified as probable or known human carcinogens. As a
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result, one of the benefits of the proposed regulation is a reduction in the risk of cancer
mortality.
A quantitative assessment of these benefits requires two types of data. First, it must
be possible to relate changes in emissions to changes in risk and incidence of cancer. This
involves the completion of a risk assessment. The second type of data required to
estimate the economic benefits of reduced cancer risk is an estimate of society's
willingness to pay to realize this risk reduction. While straightforward in concept, there
are difficulties in the way both types of data are usually developed so that the credibility
of any quantitative estimates must be carefully assessed. The next two sections discuss
the models of cancer risk, and estimates of the value of a statistical life.
8.1.1.1 Models of Cancer Risk. A variety of models have been proposed to formalize
the relationships between emission changes and changes in cancer risk so that predictions
can be made regarding changes in the expected number of lives saved due to a specific
emission reduction scenario. Cancer risk models often express cancer risk in terms of
excess lifetime cancer risks. Lifetime risk is a measure of the probability that an
individual will develop cancer as a result of exposure to an air pollutant over a lifetime of
70 years.1 The basis for developing estimates of this probability is the unit risk factor
(URF). The URF is a quantitative estimate of the carcinogenic potency of a pollutant. It
is often expressed as the probability of contracting cancer from a 70 year lifetime
continuous exposure to a concentration of one microgram per cubic meter (ug/m3) of a
pollutant. The unit risk factors are designed to be conservative. That is, actual risk may
be higher, but it is more likely to be lower. EPA has developed unit risk factors for many
of the HAPs.1 Among the HAPs identified in Table 8-1, only benzene and naphthalene
have been formally classified as known human carcinogens.
To translate lifetime individual risk to annual incidence of excess cancer, it is neces-
sary to combine three pieces of data: the unit risk factor, the (constant) level of concen-
tration to which the population is exposed, and the population count. For example.
benzene, which is classified as a known human carcinogen, has a unit risk factor of 8.3 x
10"fa (jjg/nT3)"1. In a population of 1,000,000 people, each exposed to 5 ug/m3 of benzene for
70 years (a lifetime of constant exposure), the number of excess cancer cases in the
population due to this exposure is estimated to be 41.5 cancer cases over 70 years <5
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ug/m3 x 1,000,000 x 8.3 x 10'6 (fig/m3)"1). On an annual average basis, this is equal to 0.59
excess cases per year in the population.
From the above example calculation, it is clear that each element in the calculation
algorithm may contribute to uncertainty in the final estimate of cancer risk. Table 8-2
summarizes the major sources of uncertainty with the data and methods used in the
standard approach to cancer risk assessment. Additional issues arise in estimating
economic benefits from the risk assessment information. Table 8-3 identifies these issues.
8.1.1.2 Value of a Statistical Life. Economists have used labor market data to
identify the wage-risk tradeoff accepted by workers in high risk occupations and to infer
the implicit value of a statistical life. Multiplication of the value of a statistical life times
the expected number of lives saved due to the reduced cancer risk provides an estimate of
the economic benefits associated with the regulation. Estimates of the value of a
statistical life have been developed by examining the wage-risk tradeoff revealed by
workers accepting jobs with known risks. Viscusi recently completed a survey of over 20
of these studies and recommends an initial range of $3-$7 million (December 1990 dollars)
as an estimate of the statistical value of a life.2
Using this range in an environmental policy analysis requires consideration of several
factors that could bias the transfer of the results. Specifically, adjustments may be
required to account for differences across applications. These differences include:
• Risk perception: Environmental risks are involuntary; job risks may not be.
Cancer risks may be prolonged and involve suffering; job fatalities may be more
immediate in consequence.
• Age: The age of the affected population may affect willingness to pay values.
Life years saved may be a more relevant measure. Discount rates may also be
age-sensitive.
• Income: Income levels of exposed individuals may affect willingness to pay.
Economic theory *vo'ii
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TABLE 8-2. SOURCES OF UNCERTAINTY IN CANCER RISK ASSESSMENT1
Unit risk factors are generally derived from a nonthreshold, multi-stage
model, which is linear at low doses. Available experimental data are often for
high dose exposures so that responses must be extrapolated to the relatively
low doses typically associated with ambient conditions.
Unit risk information is frequently generated from bioassays in which the
potency of a chemical is often determined by the effect of the chemical on non-
human specimens. Transfer of results across species is subject to considerable
uncertainty.
Risk estimates are calculated as if exposed individuals experience a constant
outdoor exposure over a lifetime. This ignores activity patterns of people and
the opportunity for behavioral adjustments.
Estimates of exposure are often conservative. Ambient concentrations are
frequently modeled to reflect the maximum individual risk (MIR) (i.e., highest
concentration location). If all individuals are assumed to be continuously
exposed over a lifetime to the concentration associated with MIR, this will bias
risk estimates upwards.
TABLE 8-3. UNCERTAINTIES IN BENEFIT ANALYSIS
Benefit calculations should reflect the year-by-year change in cancer incidence
following policy implementation. The timing of incidences, including latency
periods, should be expressly considered.
Benefit calculations should reflect changes in concentrations over time related
to economic responses to the regulatory action.
Benefit calculations should reflect any changes to the composition of the
affected population and possible behavioral responses to exposure.
Valuation of cancer incidences should address a variety of issues. These
include: discounting, age distribution, non-voluntary nature of risk, risk
adverseness of general population, probability of fatality, and treatment costs.
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• Baseline risks: The willingness to pay function could be non-linear. Initial risk
levels and the change in risk would become important with non-linearities.
Unfortunately, there is no general consensus on the adjustments that should be made
to account for these possible biases in a direct transfer of values. As a result, this study
makes no adjustments other than to update the values to first quarter 1992 dollars. With
this single change, the value range to be applied to the annual reduction in lives saved is
$3.11-$7.25 million.
8.1.1.3 Quantitative Results. Emissions of benzene and naphthalene were input into
the HEM to conduct a risk and exposure assessment of baseline HAP emissions. One
important input to the HEM was the URF of each pollutant. The URFs are presented in
Table 8-4.
TABLE 8-4. UNIT RISK FACTORS FOR CARCINOGENIC HAPS
HAP URF (x 106)
Benzene 8.3
Naphthalene 4.2
The HEM uses the URFs in Table-8-4, along with other information such as refinery
emissions, to characterize the risk posed to individuals and the population located within
a 50 km radius of each refinery (approximately 83.4 million people).
The maximum individual risk (MIR) and annual cancer incidence for the two HAPs
are presented in Table 8-5. The MIR for each pollutant expresses the increased risk
experienced by the person exposed to the highest predicted concentration of each HAP.
The values in Table 8-5 are for emissions at the baseline only. The annual cancer
incidences are the number of new cancer cases estimated to occur m the exposed
population in a year. As estimated by HEM, the total annual cancer incidence of the 2
HAPs is 0.52 of a statistical life. Because the cancer risk associated with benzene and
haphthalene is [ess than 1, the effect of reduced emissions is expected to he minima!. l\ic
benefits of reducing cancer risk resulting from reduced emissions of carcinogenic HAPs
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could not be monetized since values of annual cancer risk after controls were not
available. However, if it is assumed that the controls required by the proposed rule would
decrease benzene and naphthalene emissions to zero, then a monetary estimate of the
benefit of reducing these two HAPs could be calculated. The benefit of eliminating the
carcinogenic HAP emissions is calculated by multiplying the 0.52 reduction in total
annual cancer risk by the midpoint of the range of values of a statistical life ($3.11 to
$7.25 million) which is $5.2 million. This calculation yields a total monetary benefit of
$2.7 million. This is an overestimation, however, given that the petroleum refinery
NESHAP will not achieve a 100 percent HAP reduction.
TABLE 8-5. MAXIMUM INDIVIDUAL RISK AND ANNUAL CANCER INCIDENCE OF
CARCINOGENIC HAPs
HAP MIR Annual Cancer Incidence
Benzene 1.8 x 10'4 0.37
Naphthalene 6.8 x IP'5 0.15
These monetary values should be interpreted carefully due to uncertainties in the
derivation of annual incidence numbers, the value of life estimates, and the focus on
equipment leak emissions. Because these uncertainties work in both directions, and
remain unquantified, it is not possible to say whether these values are over- or
underestimates of the (unknown) true value of cancer risk reduction. At best, the
numbers should be viewed as a guide to the possible level of benefits that may be
realized.
8.1.1.4 Other Health and Welfare Impacts of HAPs. A quantitative assessment of the
economic benefits related to these impacts requires information on risk relationships,
exposure, and economic value. Unfortunately, such data are generally unavailable.
Therefore, it is currently not possible to conduct a complete quantitative analysis of the
benefits associated with HAP emission reductions.
Several intermediate quantitative assessment approaches have been developed which
can provide partial objective evidence of the positive impact of HAP emission reductions.
One approach examines changes in che population exposed to concentrations of HAPs over
a reference dose level with and without additional controls.3 The reference dose level is
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designed to reflect a concentration level, with a margin of safety, at which no adverse
health impacts would be expected. To complete this calculation, data must be available
on population counts near affected refineries, concentrations of speciated HAPs with and
without additional controls, and a reference dose level for the specific HAP.
Based on toxicity and emission information, an exposure assessment was performed
for hexane, hydrogen chloride, methy|ethyl ketone, and toluene. For noncarcinogens, the
dose-response is expressed in terms of an inhalation reference-dose concentration (RfC).
Using the RfC methodology, a benchmark concentration is calculated below which adverse
effects are not expected to occur. The significance of the RfC benchmark is that exposures
to levels below the RfC are considered "safe" because exposures to concentrations of the
chemical at or below the RfC have not been linked with any observable health effects.
The RfCs of the above mentioned HAPs are presented in Table 8-6. The benefits of
reducing these HAPs could not be monetized because information on reduced exposure is
not available. The omission of this benefit category from the monetized benefits analysis
will lead to an underestimation of the total expected benefits from the proposed
regulation. Significant baseline exposure was not shown to result from these HAPs. so
post-regulation emissions were not analyzed.
TABLE 8-6. RFCS AND NUMBER OF INDIVIDUALS EXPOSED AT OR ABOVE RFC
BY HAP
HAP
Hexane
Hydrogen Chloride
Methyl Ethyl Ketone
Toluene
RfC
0.2 mg/M3
0.07 mg/M3
1 mg/M3
0.4 mg/M3
Individuals Exposed
At or Above RfC
0
1,810
0 "
0
Epidemiological studies which attempt to identify statistical associations between
exposure and observable responses in the population represent another way to quantify
possible risks. However, because of collinearity with other environmental factors, it is
often very difficult to isolate the effects due solely to changes in HAP emissions. For this
reason, sucn statistical functions nave generally not been estimateu.
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At present, most of the model development in the area of estimating the welfare
effects and ecosystem impacts of exposure to HAPs is still conceptual and not amenable to
objective measurement. Therefore, no quantitative estimates of these potential ecosystem
impacts have been made.
8.1.2 Quantitative Benefits ofVOC Reduction
The benefits of reduced emissions of VOC from a MACT regulation of petroleum
refineries will be developed using the technique of "benefits transfer." Benefits transfer
involves the use of benefit values obtained from another study to represent benefits
associated with the current regulatory proposal, with appropriate adjustments. At a
minimum, the adjustments must address the differential impact in the severity of the
regulations as represented, for example, by changes in emissions or concentrations. With
this technique the assumption is made that benefits per ton reduced of a pollutant are
constant. Then, knowledge of a benefit per ton reduced ratio from a prior study, coupled
with information on tons reduced for the regulation under review, will be sufficient to
estimate benefits for the current regulation. NIn effect, extrapolated benefits are developed
on the basis of a constant, average benefit per ton reduced value. ,
In this RIA, an estimate of the benefits per (metric) ton reduced of VOC emissions is
developed from a study conducted for the Office of Technology Assessment.4 The OTA
study examined a variety of acute health impacts related to ozone exposure as well as the
benefits of reduced ozone concentrations for selected agricultural crops. However, chronic
health effects of ozone exposure were not considered. Therefore, all else equal, the
extrapolated estimate of VOC benefits for the MACT regulation should be viewed as a
lower bound estimate.
8.1.2.1 Benefit Transfer Values. Application of the benefit transfer technique
requires information on benefit values and the associated reduction in VOC emissions.
Data on benefits are taken from Table 3-10 of the OTA report. For the present
calculation, the values reported for the 35 percent VOC reduction scenario are used.
Specifically, information from both the epidemiological studies and the clinical studies
reported in the OTA report is used to establish an initial benetit range of 354-53,400
million per year per ton VOC emission reduction.
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The selection of this range of values was influenced by several factors. First, the
results for the 35 percent VOC emission reduction scenario are used because it is easier to
identify the level of emission reductions associated with this scenario in the OTA report.
It should also be noted that this scenario involves a reduction of 35 percent in those
emissions occurring only in non-attainment areas. Although there are expected to be
VOC emission reductions in attainment areas under this scenario, the percentage
reduction in VOC emissions in attainment areas is less than 35 percent. A close reading
of the OTA report indicates that all health impacts are estimated for non-attainment
areas only. Therefore, no benefits are associated with VOC emission reductions in
attainment areas. This may provide additional conservatism to the benefit values since
there is recent evidence that acute health effects may be experienced at ozone
concentrations below the current NAAQS.5
The OTA report calculates acute health impacts based on the results of epidemio-
logical and clinical studies. Both study designs have advantages and disadvantages
relative to one another. Indeed, the OTA report acknowledges that i.t is not possible to
judge which approach is superior.<{Even though the two study designs measure similar
impacts, it is possible to use the results from both design types to form a range of values.
This approach would not involve double-counting and would use more of the available
information. A lower bound value is identified from the epidemiological study design. An
upper bound value is taken from the clinical study design in which all exercisers are
affected. These choices lead to the initial benefit range of $54-$3,400 million per year.
*
The year of dollars for these benefit values is not made clear in the OTA report.
However, a check with the authors of several of the cited references used to develop "will-
ingness-to-pay" values, indicates that the values are in 1984 dollar terms.8 To maintain
consistency with other parts of this RIA, the benefit values are converted to first quarter
1992 dollars by multiplying the 1984 dollars by a factor of 1.335. This factor was
computed from the percentage change in the all item urban CPI index between the
annual index value for 1984 and the geometric mean of index values for the first three
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months of 1992.a The adjusted dollar benefit range in first quarter 1992 dollars is $72-
$4,539 million.
Three further adjustments can be considered for this benefit value range. First, as
noted earlier, benefits can be scaled by the tons of VOC emissions reduced in order to
form a benefit transfer ratio which can be multiplied by the VOC emission reductions for
the petroleum refinery MACT.
Second, the benefit values in the OTA report reflect a level of exposure that corre-
sponds to population densities in non-attainment areas in the early 1980's. Since the cost
analysis is conducted for the fifth year following rule promulgation (i.e., circa 1999), the
benefit analysis should be conformable. There is approximately a twenty year interval
from the period when the estimates used in the OTA report were calculated to the year of
regulatory impact. It is appropriate to scale the OTA benefit values by a factor which
represents the percentage change in population, between 1980 and 1999, in those non-
attainment areas with petroleum refineries. Using data from the 1980 and 1990
Censuses and extrapolating to 1999 under an assumption of a constant growth rate equal
to that observed for the 10 year period, it is estimated that the population scale factor is
19.64 percent. This leads to a revised benefit value range of $86 to $5,430 million.
Third, the passage of time may also affect the willingness to pay value. If real income
grows over time and the income elasticity of environmental quality is positive, then unit
willingness to pay values in 1999 should exceed those implied by the surveys conducted in
the mid-1980's. Using the 1993 Statistical Abstract5, the simple average percentage
change in per capita real income between 1985 and 1992 is 3.3 percent in those areas
most likely to be ozone non-attainment areas. Extrapolating to 1999 under a constant
growth assumption results in an increase of 6.7 percent. Given this relatively small
change and uncertainty about the proper income elasticity measure, no adjustment has
been made to the benefit value range to account for this factor.
JCPI index values were obtained from the 1993 U.S. Statistical Abstract (Table 756) and the
December 1992 issue of the Survey of Current Business.
'"Statistical Abstract, 1993, Table 704.
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8.1.2.2 Emission Reductions. The development of VOC emission reductions
associated with the benefits range described above can be determined directly from the
OTA report. Tables 6-1 and 6-6 of OTA provide the needed information. Total VOC
emissions in 1985 are 25 million tons.0 Of this total, 11 million tons are predicted to
occur in non-attainment cities while 14 million tons of VOC are predicted to be emitted in
ozone attainment areas. For the 35 percent VOC (non-attainment area) emission
reduction scenario, 3.8 million tons of VOC emissions are predicted to be controlled in
1994, while 2.7 million tons will be controlled in attainment areas.
The selection of a "tons reduced" value for the denominator of the benefit transfer
ratio must be consistent with the benefits measure selected for the numerator. As
described earlier, the benefits reflect the annual reduction in acute health impacts
experienced by populations in non-attainment areas that result from a 35 percent
reduction in non-attainment area VOC emissions. Implicitly, there is the assumption that
no health benefits are experienced in attainment areas. Consequently, it seems most
appropriate to define the VOC emission reductions in terms of reductions occurring only
in non-attainment areas. This also implies that the derivation of petroleum refinery
health benefits from VOC emission reductions should consider only those emission
reductions which occur at plants in non-attainment areas. Fortunately, because
individual refineries are identified, it is possible to identify this subset of emission
reductions. A result of this approach is that no acute health benefits are associated with
VOC emission reductions in attainment areas.d Table 8-7 presents the baseline VOC
emissions, and the emission reductions for refineries in nonattainment areas associated
with each alternative.
"The emissions data in OTA do not reflect measured emissions. Rather, they represent
emissions on a typical non-attainment day multiplied by 365. It is not clear from OTA how these
"nonattainment-day-equivalent-annual-emissions" are calculated for attainment regions.
dRecent evidence suggests that some health benefits may occur for VOC emission reductions in
areas near, but below, the current ozone NAAQS.5 As might be expected, the response rate is
lower than that observed at higher ozone concentrations. In addition, economic theory suggests
that the marginal willingness to pay for an incremental improvement in air quality at such levels
•-vould be less than ohe marginal v/iilingness to pay ibr increments as, ... ^i^r.er ;.„••.e> .mo;.-_• .;,
standard. That is, the marginal benefits function is non-linear. Since the benefit transfer ratio
assumes a constant, linear relationship, it seems prudent to limit the benefits transfer calculation
to the non-attainment area data presented in the OTA report.
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TABLE 8-7. VOC EMISSION REDUCTIONS BY EMISSION POINT
VOC Emission Reductions by Regulatory Alternative (Mg/yr)J
Emission Point2
Equipment Leaks
Miscellaneous Process Vents
Storage Vessels
TOTAL REDUCTION BY
ATTAINMENT STATUS
TOTAL REDUCTION BY
ALTERNATIVE
Alternative 1
Nonattainment1
77,535
104,693
3,090
185,318
322,153
Attainment
80,266
55,161
1,408
136,835
Alternative 2
Nonattainment1
81,626
104,693
6,056
192,375
333,767
Attainment
83,471
55,161
2,760
141,392
NOTES. 'VOC emission reductions include only those associated with control of the 87 refineries located in ozone
nonattainment areas.
2No further control is assumed for wastewater streams, and therefore, emission reductions associated with this
emission point are zero.
Emission reduction estimates do not incorporate reductions occurring at new sources.
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One final step is needed prior to forming the benefit transfer ratio. Since VOC
emission reductions for petroleum refineries are stated in megagrams per year (metric
tons per year), it is necessary to convert the OTA emission reductions to equivalent metric
tons. This conversion results in a reduction of 3.45 million metric tons in non-attainment
areas.
8.1.2.3 Benefit Estimates. The benefit transfer ratio range for acute health impacts is
estimated to be $25-$l,574 (first quarter 1992 dollars per metric ton). These values were
obtained by dividing the benefit range values by the reduction in emissions. The average
(mid-point) of the range is $800 per metric ton. These ratios are to be multiplied by VOC
emission reductions from petroleum refineries located in ozone non-attainment areas in
order to estimate the VOC-related acute health benefits of the petroleum refinery MACT.
Table 8-8 summarizes the results of these calculations for the combination of options
selected for the four controlled emission points. In addition, benefits for the next most
stringent option for each emission point type are also reported. Note, the floor option for
each emission point type is statutorily mandated so that, in effect, the floor options
represent the minimal regulatory requirements.
TABLE 8-8. BENEFITS OF VOC REDUCTIONS BY REGULATORY ALTERNATIVE
Benefits (Million Dollars)
Alternative 1 Alternative 2
Average $148.3 $153.9
Range $4.6 - $291.7 $4.8 - $302.8
The benefit values reported above are restricted to acute health impacts associated
with VOC emission reductions. Several qualifications should be noted. First, there is an
implicit assumption of a constant linear relationship between VOC emission reductions
and changes in ozone concentrations in non-attainment areas. One result of this
assumption is that it becomes difficult to justify quantifying benefits for agricultural yield
changes associated with VOC emission reductions. As described in OTA, the VOC/NO^
ratio in rural areas is NOx-limited because of relatively high vegetative VOC emissions.
Consequently, ozone production is less sensitive to changes in man-made ^OC ;miK5i')n:\
Therefore, it seems appropriate to exclude agricultural benefits for the present analysis.
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Also, as noted earlier, there may be other benefit types. Reductions in VOC emissions
which lead to improvements in ozone concentrations may contribute to reductions in
chronic health impacts (e.g. sinusitis, hay fever and reduced damage to certain materials.
such as elastomers).8 However, because of data and methodological concerns, no
quantitative benefit estimates for these possible effect types have been developed for the
present analysis. All else equal, this implies that the calculated benefit per metric ton
range of $25-$l,574 is likely to be conservative.
Although the quantified VOC benefits estimated in this RIA represent one approach
for valuing the benefits of reduced VOC emissions, data limitations prevent a complete
quantification of all categories of benefits attributable to VOC reductions. Since lack of
data prevent all benefit categories from being monetized, a direct comparison of benefits
to costs may not be helpful in determining the desirable regulatory alternative. An
assessment of the incremental cost-effectiveness analysis will represent the cost of the air
emission controls relative to the expected VOC emission reductions attributable to the
- ^trols. Because of the lack of data, this analysis ignores the benefit of HAP emission
reductions. The incremental VOC cost-effectiveness analysis begins with the baseline, or
no control. Alternative 1, which is the basis of the proposed rule, includes controls to
meet MACT floor level controls, and a level of control more stringent than the floor for
equipment leaks.-The annual cost of this control, including equipment costs, MRR costs,
and economic costs, is $132 million annually/ This regulatory alternative is expected to
result in a reduction of VOC emissions of approximately 185,000 Mg annually. Therefore,
the incremental cost-effectiveness, averaged across multiple emission points, of the
requirements of Alternative 1 is approximately $712/Mg. In other words, the average cost
of reducing each Mg required by Alternative 1 is $712.
The next more stringent level of control. Alternative 2, which includes increased
control of equipment leaks and storage vessels, has a total annual cost of $148 million.
This level of control is estimated to achieve an annual VOC emission reduction of
approximately 192,375 Mg. The incremental VOC cost-effectiveness of going from
Alternative 1 to Alternative 2 is approximately $2,300/Mg.
Table 8-9 presents the incremental VOC cost-effectiveness values for each regulatory
alternative discussed in this analysis. Alternative 1 can be justified as a desirable option
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since the incremental VOC cost-effectiveness of implementing Alternative 2 is
significantly higher.
TABLE 8-9. VOC INCREMENTAL COST-EFFECTIVENESS OF PETROLEUM
REFINING REGULATION
Alternative 1 Alternative 2
Incremental Cost (Million S 1992)1 $132.35 $16.0
Incremental Emission Reduction (Mg) 185,318 7,057
Incremental Cost Effectiveness ($/Mg) $712/Mg $2,267/Mg
NOTES: 'The cost estimates of each alternative reflect the total social cost of emission control
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REFERENCES
1. U.S. Environmental Protection Agency. Cancer Risk from Outdoor Exposure to Air
Toxics, Volume I. EPA-450/l-90-004a. Office of Air Quality Planning and Standards.
Research Triangle Park, NC. September 1990.
2. Viscusi, W. Kip. "The Value of Risks to Life and Health." Journal of Economic
Literature, pp. 1912-1946. December 1993.
3 Voorhees, A., B. Hassett, and I. Cote. Analysis of the Potential for Non-Cancer
Health Risks Associated with Exposure to Toxic Air Pollutants. Paper presented at
the 82nd Annual Meeting of the Air and Waste Management Association. 1989.
4. Office of Technology Assessment. Catching Our Breath: Next Steps for Reducing
Urban Ozone. OTA-O-412. Washington, DC. U.S. Government Printing 6ffice. July
1989.
5. Horstman, D., W. McDonnell, L. Folinsbee, S. Abdal-Salaam, and P. Ives. Changes in
Pulmonary Function and Airway Reactivity Due to Prolonged Exposure to Typical
Ambient Ozone (O3) Levels. In: Schneider, T. et aj. (eds.) Atmospheric Ozone
Research and its Policy Implications. Elsevier Science Publishers. Amsterdam.
1989.
6. Horst, R.L., Jr. Personal communication with L. Chestnut. January 26, 1994.
7. Reference 4. p. 107.
8. Portney P. and J. Mullahy. "Urban Air Quality and Chronic Respiratory Disease."
Regional Science and Urban Economics. Vol. 20. p. 407-18. 1990.
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9.0 COMPARISON OF BENEFITS TO COSTS
The goal of the Regulatory Impact Analysis and Benefits Analysis for the Petroleum
Refinery NESHAP is to provide economic and engineering data necessary for effective
environmental policymaking. A comparison of the benefits of alternative air emission
controls with the costs of such controls provides the necessary framework for a reasonable
assessment of the net benefits of the proposed environmental measures.
9.1 COMPARISON OF ANNUAL BENEFITS AND COSTS
The potential health and welfare benefits associated with air emission reductions
relate to expected reductions in emissions of several HAPs and VOCs from storage tanks.
process vents, equipment leaks, and wastewater emission points at refining sites. The
quantification of benefits from emission controls relates to health benefits from reduced
cancer incidence associated with carcinogenic HAPs emitted at petroleum refineries and
the health benefits related to reduced VOCs that translate into reductions in ozone.
Benefits from reducing cancer incidence to zero were quantified for equipment leaks only
in the previous chapter. Because of the uncertainty associated with this estimate, the
benefits of reduced cancer risk are not incorporated in this benefit cost analysis. Other
health and welfare benefits from the controls such as benefits to the ecosystem have not
been quantified due to limitations in data and methodology.
The compliance costs of the alternative emission controls relate to capital costs and
operation and maintenance costs for each of the regulatory alternatives (including MRR
costs) obtained from engineering studies conducted for EPA. These estimates reflect the
engineering; costs of emission controls rather than the economic costs to society. The
compliance cost estimates provide a necessary data input for the economic analysis of the
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cost of the regulatory alternatives to society. The economic effect of imposing compliance
costs on the petroleum refining market and its consumers and producers is obtained from
a partial equilibrium model of the petroleum refining industry. The social costs of the
controls include potential economic costs to consumers of refined petroleum products,
producers of refined petroleum products, and society as a whole. Economic costs are a
better measure of the costs of the air emission control alternative to society because these
costs represent the true costs or opportunity costs to society of resources used for emission
control. Quantifications of the compliance costs and economic costs of the air emission
alternatives are subject to the limitations noted in Section 6.4J^imitations of the Economic
Model. The social costs of Alternative 2 represents the social costs of Alternative 1 plus
the incremental increase in compliance costs for Alternative 2. Social costs were not
estimated independently for Alternative 2 due to limitations in resources. Table 9-1
depicts a comparison of the benefits of the alternative proposals to the compliance and
social costs. A comparison of the net benefits for the alternatives and the incremental
difference in net benefits between the alternatives provides the appropriate comparison.
The benefits exceed costs (both compliance and social) for each of the alternatives.
Thus, either alternative is viable and warrants consideration. However, a comparison of
the incremental difference in the two alternatives indicates that the incremental net
benefits are negative for Alternative 2. Thus, Alternative 1 provides the greatest net
benefits to society.
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TABLE 9-1. COMPARISON OF ANNUAL BENEFITS TO COSTS FOR THE NATIONAL
PETROLEUM REFINING INDUSTRY REGULATION
(MILLIONS OF 1992 DOLLARS PER YEAR)
Benefits
Social Costs
Benefits Less Social Costs
Alternative 1
$148.3
$(132.4)
$16.0
Alternative 2
$153.9
$(148.4)2
$5.5
Incremental
Difference1
$5.6
$(16.0)
$(10.4)
NOTES: ( ) represent costs or negative values.
'The incremental difference represents the difference between Alternative 1 and Alternative 2.
2Social costs for Alternative 2 are calculated by adding incremental compliance costs to social costs of Alternative
1
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7.0 QUALITATIVE ASSESSMENT OF BENEFITS
OF EMISSION REDUCTIONS
One rationale for environmental regulation is to provide benefits to society by
.proving environmental quality. In this chapter, and the two chapters which follow,
brmation is provided on the types and levels of social benefits anticipated from the
troleum refinery NESHAP, This chapter examines the potential health and welfare
rits associated with air emission reductions projected as a result of implementation of
e petroleum refinery NESHAP. The proposed regulation is expected to reduce
lissions of HAPs emitted from storage tanks, process vents, equipment leaks, and
astewater emission points at refining sites. Of the HAPs emitted by petroleum
ifineries, some are classified as VOCs, which are ozone precursors.
In general, the reduction of HAP emissions resulting from promulgation and
nplementation of the petroleum refinery NESHAP will reduce human and environmental
cposure to these pollutants and thus, reduce potential adverse health and welfare effects.
'his chapter provides a general discussion of the various components of total benefits that
lay be gained from a reduction in HAPs through the subject NESHAP. HAP benefits are
resented separately from the benefits associated specifically with VOC emission
eductions.
.1 IDENTIFICATION OF POTENTIAL BENEFIT CATEGORIES
The benefit categories associated with the emission reductions predicted for this
"emulation can be oroaaly categorized as Ariose oenents '.vhich u.re .utrrbutabb ^ -^rjc-jd
exposure to HAPs. and those attributable co reduced exposure to VOCs. The predicted
emissions of a few HAPs associated with this regulation have been classified as probable
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or known human carcinogens. As a result, one of the benefits of the proposed regulation
is a reduction in the risk of cancer mortality. Other benefit categories include: reduced
exposure to noncarcinogenic HAPs, and reduced exposure to VOCs. In addition to health
impacts occurring as a result of reductions in HAP and VOC emissions, there are welfare
impacts which can also be identified. In general, welfare impacts include effects on crops
and other plant life, materials damage, soiling, and visibility. Each category is discussed
separately in the following section.
7.2 QUALITATIVE DESCRIPTION OF AIR RELATED BENEFITS
A summary of the range of potential physical health and welfare effects categories
that may be associated with HAP emissions and also with concentrations of ozone formed
by VOC HAPs is provided in Table 7-1. As noted in the table, exposure to HAPs can lead
to a variety of acute and chronic health impacts as well as welfare impacts. The health
and welfare benefits of HAP and VOC reductions are presented separately.
7.2.1 Benefits of Decreasing HAP Emissions
Human exposure to HAPs may occur directly through inhalation or indirectly through
ingestion of food or water contaminated" by HAPs or through dermal exposure. HAPs may
also enter terrestrial and aquatic ecosystems through atmospheric deposition. HAPs can
be deposited on vegetation and soil through wet or dry deposition. HAPs may also enter
the aquatic environment from the atmosphere via gas exchange between surface water
and th.e ambient air, wet or dry deposition of particulate HAPs and particles to which
HAPs adsorb, and wet or dry deposition to watersheds with subsequent leaching or runoff
to bodies of water/ This analysis is focused only on the air quality benefits of HAP
reduction.
7.2.1.1 Health Benefits of Reduction in HAP Emissions. According to baseline
emission estimates, this source category currently emits approximately 81,000 Mg of
HAPs annually. The petroleum refinery NESHAP will regulate several of the 189 air
toxics listed in Section 112(b) of the CAA. Exposure to ambient concentrations of these
pollutants may result tn a variety of adverse health effects considering botn cancer unc.
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noncancer endpoints. Many HAPs are classified as known human carcinogens.
Speciation of the HAP emissions at refining sites was available only for equipment leaks.
Of those HAPs (presented in Table 3-2), only benzene and naphthalene are classified as
known human carcinogens, according to an EPA system for classifying chemicals by
cancer risk. This means that there is sufficient evidence to support that exposure to these
two chemicals causes an increased risk of cancer in humans. Benzene is a concern to
EPA because long term exposure to this chemical has been known to cause leukemia in
humans. While this is the most well known effect, benzene exposure is also associated
with aplastic anemia, multiple myeloma, lymphonomas, pancytopenia, chromosomal
breakages, and weakening of bone marrow.13 Therefore, a reduction in human exposure
to benzene and naphthalene could lead to a decrease in cancer risk and ultimately to a
decrease in cancer mortality.
Cresols are considered to be group C or possible human carcinogens. For this HAP,
there is either inadequate data or no data on human carcinogenicity, and there is limited
data on animal carcinogenicity. Therefore, while cancer risk is possible, there is not
sufficient evidence to support that these chemicals will cause increased cancer risks in
humans.
The remaining HAPs emitted by equipment leaks at refining sites are noncarcinogens.
However, exposure to these pollutants may still result in adverse health impacts to
human and non-human populations. Noncancer health effects can be grouped into the
following broad categories: genotoxicity, developmental toxicity, reproductive toxicity,
systemic toxicity, and irritant. Genotoxicity is a broad term that usually refers to a
chemical that has the ability to damage DNA or the chromosomes. Developmental
toxicity refers to adverse effects on a developing organism that may result from exposure
prior to conception, during prenatal development, or postnatally to the time of sexual
maturation. Adverse developmental effects may be detected at any point in the life span
of the organism. Reproductive toxicity refers to the harmful effects of HAP exposure on
fertility, gestation, or offspring, caused by exposure of either parent to a substance.
Systemic toxicity affects a portion of the body other than the site of entry. Irritant refers
to any effect which results in irritation of the eyes, skin, and respiratory tract.14
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For the HAPs covered by the petroleum refinery NESHAP, evidence on the potential
toxicity of the pollutants varies. Given sufficient exposure conditions, each of these HAPs
has the potential to elicit adverse health or environmental effects in the exposed
populations. It can be expected that emission reductions achieved through the_subject
NESHAP will decrease the incidence of these adverse health effects.
7.2.1.2 Welfare Benefits of Reduction in HAP Emissions. The welfare effects of
exposure to HAPs have received less attention from analysts than the health effects.
However, this situation is changing, especially with respect to the effects of toxic
substances on ecosystems. Over the past ten years, ecotoxicologists have started to build
models of ecological systems which focus on interrelationships in function, the dynamics of
stress, and the adaptive potential for recovery. This perspective is reflected in Table 7-1
where the end-points associated with ecosystem functions describe structural attributes
rather than species specific responses to HAP exposure. This is consistent with the
observation that chronic sub-lethal exposures may affect the normal functioning of
individual species in ways that make it less than competitive and therefore more
susceptible to a variety of factors including disease, insect attack, and decreases in
habitat quality.15 All of these factors may contribute to an overall change in the structure
(i.e., composition) and function of the ecosystem.
The adverse, non-human biological effects of HAP emissions include ecosystem and
recreational and commercial fishery impacts. Atmospheric deposition of HAPs directly to
land may affect terrestrial ecosystems. Atmospheric deposition of HAPs also contributes
to adverse aquatic ecosystem effects. This not only has adverse implications for
individual wildlife species and ecosystems as a whole, but also the humans who may
ingest contaminated fish and waterfowl. In general, HAP emission reductions achieved
through the petroleum refinery NESHAP should reduce the associated adverse
environmental impacts.
7.2.2 Benefits of Reduced VOC Emissions
Emissions of VOCo have been associated with a variety oc heaich .ind .veuure ^ripuccj.
VOC emissions, together with NOX, are precursors to the formation of troposphenc ozone.
It is exposure to ambient ozone that is most directly responsible for a series of respiratory
-------
related adverse impacts. Consequently, reductions in the emissions of VOCs will also lead
to reductions in the types of health and welfare impacts that are associated with elevated
concentrations of ozone. In this section, the benefits of reducing VOC emissions are
examined in terms of reductions in ozone.
7.2.2.1 Health Benefits of Reduction in VOC Emissions. Human exposure to elevated
concentrations of ozone primarily results in respiratory-related impacts such as coughing
and difficulty in breathing. Eye irritation is another frequently observed effect. These
acute effects are generally short-term and reversible. Nevertheless, a reduction in the
severity or scope of such impacts may have significant economic value.
Recent studies have found that repeated exposure to elevated concentrations of ozone
over long periods of time may also lead to chronic, structural damage to the lungs.'b To
the extent that these findings are verified, the potential scope of benefits related to
reductions in ozone concentrations could be expanded significantly.
Major ozone health effects are: alterations in lung capacity and breathing frequency;
eye, nose and throat irritation; reduced exercise performance; malaise and nausea;
increased sensitivity of airways; aggravation of existing respiratory disease; decreased
sensitivity to respiratory infection; an'd extrapulmonary effects (central nervous system,
liver, cardiovascular, and reproductive effects).17 In general, it is expected that reductions
in VOCs through the petroleum refinery NESHAP regulation is a mechanism by which
the ambient ozone concentration may be reduced and, in turn, reduce the incidence of the
adverse health effects of ozone exposure. In this section, the benefits of reducing VOC
emissions is examined in terms of reductions in ozone.
7.2.2.2 Welfare Benefits of VOC Reduction. In addition to acute and (possible) chronic
health impacts of ozone exposure, there may also be adverse welfare effects. The
principal welfare impact is related to losses in economic value for certain agricultural
crops and ornamental plants. Over the last decade, a series of field experiments has
demonstrated a positive statistical association between ozone exposure and reductions in
yield as well as visible injury to several economically valuable cash crops, including
soybeans and cotton. Damage to selected timber species has also been associated \vuri
exposure to ozone. The observed impacts range from foliar injury to reduced growth rates
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and premature death. Benefits of reduced ozone concentrations include both the value of
avoided losses in commercially valuable timber and aesthetic losses suffered by non-
consumptive users.
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REFERENCES
1. U.S. Environmental Protection Agency. Regulatory Impact Analysis for the National
Emissions Standards for Hazardous Air Pollutants for Source Categories: Organic
Hazardous Air Pollutants from the Synthetic Organic Chemical Manufacturing
Industry and Seven Other Processes. Draft Report. Office of Air Quality Planning
and Standards. Research Triangle Park, NC. EPA-450/3-92-009. December 1992.
2. Mathtech, Inc. Benefit Analysis Issues for Section 112 Regulations. Final report
prepared for U.S. Environmental Protection Agency. Office of Air Quality Planning
and Standards. Contract No. 68-D8-0094. Research Triangle Park, NC. May 1992.
3. U.S. Environmental Protection Agency. Cancer Risk from Outdoor Exposure to Air
Toxics. Volume I. EPA-450/l-90-004a. Office of Air Quality Planning and Standards.
Research Triangle Park, NC. September 1990.
4. Graham, John D., D.R. Holtgrave, and M.J. Sawery. "The Potential Health Benefits
of Controlling Hazardous Air Pollutants." In: Health Benefits of Air Pollution
Control: A Discussion. Blodgett, J. (ed). Congressional Research Service report to
Congress. CR589-161. Washington, DC. February 1989.
5. Reference 4.
6. Voorhees, A., B. Hassett, and I. Cote. Analysis of the Potential for Non-Cancer
Health Risks Associated with Exposure to Toxic Air Pollutants. Paper presented at
the 82nd Annual Meeting of the Air and Waste Management Association. 1989.
7. Reference 4.
8. Reference 6.
9. Cote, I., L. Cupitt and B. Hassett. Toxic Air Pollutants and Non-Cancer Health
Risks. Unpublished paper provided by B. Hassett. 1988.
10. NAS. Chlorine and Hydrogen Chloride. National Academy of Sciences, National
Research Council. Chapter 7. 1975.
11. Stern, A. et al. Fundamentals of Air Pollution. Academic Press, New York. 1973.
12. Weinstein, D. and E. Birk. The Effects of Chemicals on the Structure of Terrestrial
Ecosystems: Mechanisms and Patterns of Change. In: Levin, S. et al. (eds). Ecotoxi-
cology: Problems and Approaches. Chapter 7. pp. 181-209. Springer-Verlag, New
York. 1989.
13. Reference 1. p. 3-5.
14. Reference 1. pp. 8-4 to 8-5.
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REFERENCES (continued)
15. U.S. Environmental Protection Agency. Ecological Exposure and Effects of Airborne
Toxic Chemicals: An Overview. EPA/6003-91/001. Environmental Research
Laboratory. Corvallis, OR. 1991.
16. Reference 4.
17. Reference 1. pp. 8-8 to 8-9.
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8.0 QUANTITATIVE ASSESSMENT OF BENEFITS
This chapter presents quantitative estimates of the possible dollar magnitude of the
benefits identified in the previous chapter. The quantification of dollar benefits for all
benefit categories is not possible at this time because of limitations in b>ojj}_data and
methodology. This chapter presents the methodology which was utilized to obtain
monetary estimates of HAP and VOC emission reductions occurring as a result of the
proposed rule. Limitations of this methodology are also identified. To ensure that an
economically efficient regulatory alternative is chosen, an incremental analysis must be
performed. Therefore, benefits for the two regulatory alternatives are presented.
Potential impacts are evaluated for the proposed regulation and one alternative more
stringent than the proposed regulation.
8.1 METHODOLOGY FOR DEVELOPMENT OF BENEFIT ESTIMATES
Quantification of impacts associated with HAP exposure requires information on the
particular HAP involved. Such data are necessary because different HAP emissions can
lead to different types and degrees of severity of impacts. Table 8-1 identifies HAP
emissions by type for petroleum refineries. Although an estimate of the total reduction in
HAP emissions for various control options has been developed for this RIA, it has not
been possible to identify the speciation of the HAP emission reductions for each type of
emission point. However, an estimate of HAP speciation for equipment leaks has been
made. Since HAP emissions from equipment leaks account for nearly two thirds of total
HAP emissions at petroleum refineries, it is possible to use these data to develop an
approximate lower bound estimate of average cancer risk related co petroieum refiner.'
emissions.
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TABLE 8-1. HAP EMISSIONS AT PETROLEUM REFINERIES
2,2,4 - Trimethyl Pentane Hydrogen Fluoride
Benzene Phenol
Ethyl Benzene Cresols/Cresylic Acid
Hexane Methyl Tertiary Butyl Ether
Naphthalene Hydrogen Chloride
Toluene Methyl Ethyl Ketone
Xylenes
The potential impacts of reducing HAP emissions can be separated into two health
benefits categories. The first health benefit category evaluated will be the reduction in
annual cancer incidence due to carcinogenic HAP emission reductions. This approach
uses emissions data and the Human Exposure Model (HEM) to estimate the annual
cancer risk caused by HAP emissions from petroleum refineries. Generally, this benefit
category is calculated as the difference in estimated annual cancer incidence before and
after implementation of each regulatory alternative. The benefit category is then
monetized by applying a range of benefit values for each cancer case avoided.
The second category of health benefits expected to result from reduced HAP emissions
is reduced human exposure to noncarcinogenic HAP emissions. For each noncarcinogenic
HAP for which EPA had health benchmark information, EPA performed a baseline
assessment to estimate the number of people exposed to HAPs above health benchmark
levels. The quantified benefits attributable to reducing noncarcinogenic HAP emissions io
the difference in the number of people exposed above health benchmark levels before and
after regulation.
The benefits of controlling VOC emissions are monetized by applying average benefit
per megagram estimates to the total amount of VOC emission reductions calculated for
each of the two regulatory alternatives.
8.1.1 Benefits of Reduced Cancer Risk Associated with HAP Reductions
The proposed MACT for petroleum rerinenes is expected to reduce the emissions u
several HAPs that have been classified as probable or known human carcinogens. As a
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result, one of the benefits of the proposed regulation is a reduction in the risk of cancer
mortality.
A quantitative assessment of these benefits requires two types of data. First, it must
be possible to relate changes in emissions to changes in risk and incidence of cancer. This
involves the completion of a risk assessment. The second type of data required to
estimate the economic benefits of reduced cancer risk is an estimate of society's
willingness to pay to realize this risk reduction. While straightforward in concept, there
are difficulties in the way both types of data are usually developed so that the credibility
of any quantitative estimates must be carefully assessed. The next two sections discuss
the models of cancer risk, and estimates of the value of a statistical life.
8.1.1.1 Models of Cancer Risk. A variety of models have been proposed to formalize
the relationships between emission changes and changes in cancer risk so that predictions
can be made regarding changes in the expected number of lives saved due to a specific
emission reduction scenario. Cancer risk models often express cancer risk m terms of
excess lifetime cancer risks. Lifetime risk is a measure of the probability that an
individual will develop cancer as a result of exposure to an air pollutant over a lifetime of
70 years.1 The basis for developing estimates of this probability is the unit risk factor
(URF). The URF is a quantitative estimate of the carcinogenic potency of a pollutant. It
is often expressed as the probability of contracting cancer from a 70 year lifetime
continuous exposure to a concentration of one microgram per cubic meter (jjg/m3) of a
pollutant. The unit risk factors are designed to be conservative. That is, actual risk may
be higher, but it is more likely to be lower. EPA has developed unit risk factors for many
of the HAPs.1 Among the HAPs identified in Table 8-1, only benzene and naphthalene
have been formally classified as known human carcinogens.
To translate lifetime individual risk to annual incidence of excess cancer, it is neces-
sary to combine three pieces of data: the unit risk factor, the (constant) level of concen-
tration to which the population is exposed, and the population count. For example,
benzene, which is classified as a known human carcinogen, has a unit risk factor of 8.3 x
10"6 (ug/m3)"1. In a population of 1,000,000 people, each exposed to 5 ug/ma of benzene for
70 years ia lifetime of constant exposure), the number of excess cancer cases m tne
population due to this exposure is estimated to be 41.5 cancer cases over 70 years t5
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Hg/m3 x 1,000,000 x 8.3 x 10'6 (ug/m3)'1). On an annual average basis, this is equal to 0.59
excess cases per year in the population.
From the above example calculation, it is clear that each element in the calculation
algorithm may contribute to uncertainty in the final estimate of cancer risk. Table 8-2
summarizes the major sources of uncertainty with the data and methods used in the
standard approach to cancer risk assessment. Additional issues arise in estimating
economic benefits from the risk assessment information. Table 8-3 identifies these issues.
8.1.1.2 Value of a Statistical Life. Economists have used labor market data to
identify the wage-risk tradeoff accepted by workers in high risk occupations and to infer
the implicit value of a statistical life. Multiplication of the value of a statistical life times
the expected number of lives saved due to the reduced cancer risk provides an estimate of
the economic benefits associated with the regulation. Estimates of the value of a
statistical life have been developed by examining the wage-risk tradeoff revealed by
workers accepting jobs with known risks. Viscusi recently completed a survey of over 20
of these studies and recommends an initial range of $3-$7 million (December 1990 dollars)
as an estimate of the statistical value of a life.2
Using this range in an environmental policy analysis requires consideration of several
factors that could bias the transfer of the results. Specifically, adjustments may be
required to account for differences across applications. These differences include:
*
• Risk perception: Environmental risks are involuntary; job risks may not be.
Cancer risks may be prolonged and involve suffering; job fatalities may be more
immediate in consequence.
• Age: The age of the affected population may affect willingness to pay values.
Life years saved may be a more relevant measure. Discount rates may also be
age-sensitive.
• Income: Income levels of exposed individuals may affect willingness to pay.
Economic theory would suggest a positive elasticity oetv/een income ana risk
reduction.
162
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TABLE 8-2. SOURCES OF UNCERTAINTY IN CANCER RISK ASSESSMENT'
• Unit risk factors are generally derived from a nonthreshold, multi-stage
model, which is linear at low doses. Available experimental data are often for
high dose exposures so that responses must be extrapolated to the relatively
low doses typically associated with ambient conditions.
• Unit risk information is frequently generated from bioassays in which the
potency of a chemical is often determined by the effect of the chemical on non-
human specimens. Transfer of results across species is subject to considerable
uncertainty.
• Risk estimates are calculated as if exposed individuals experience a constant
outdoor exposure over a lifetime. This ignores activity patterns of people and
the opportunity for behavioral adjustments.
• Estimates of exposure are often conservative. Ambient concentrations are
frequently modeled to reflect the maximum individual risk (MIR) (i.e., highest
concentration location). If all individuals are assumed to be continuously
exposed over a. lifetime to the concentration associated with MIR, this will bias
risk estimates upwards.
TABLE 8-3. UNCERTAINTIES IN BENEFIT ANALYSIS
Benefit calculations should reflect the year-by-year change in cancer incidence
following policy implementation. The timing of incidences, including latency
periods, should be expressly considered.
Benefit calculations should reflect changes in concentrations over time related
to economic responses to the regulatory action.
Benefit calculations should reflect any changes to the composition of the
affected population and possible behavioral responses to exposure.
Valuation of cancer incidences should address a variety of issues. These
include: discounting, age distribution, non-voluntary nature of risk, risk
adverseness of general population, probability of fatality, and treatment costs.
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• Baseline risks: The willingness to pay function could be non-linear. Initial risk
levels and the change in risk would become important with non-linearities.
Unfortunately, there is no general consensus on the adjustments that should be made
to account for these possible biases in a direct transfer of values. As a result, this study
makes no adjustments other than to update the values to first quarter 1992 dollars. With
this single change, the value range to be applied to the annual reduction in lives saved is
S3.11-$7.25 million.
8.1.1.3 Quantitative Results. Emissions of benzene and naphthalene were input into
the HEM to conduct a risk and exposure assessment of baseline HAP emissions. One
important input to the HEM was the URF of each pollutant. The URFs are presented in
Table 8-4.
TABLE 8-4. UNIT RISK FACTORS FOR CARCINOGENIC HAPS
HAP URF (x 10b
Benzene 8.3
Naphthalene 4.2
The HEM uses the URFs in Table 8-4, along with other information such as refinery
emissions, to characterize the risk posed to individuals and the population located within
a 50 km radius of each refinery (approximately 83.4 million people).
The maximum individual risk (MIR) and annual cancer incidence for the two HAPs
are presented in Table 8-5. The MIR for each pollutant expresses the increased risk
experienced by the person exposed to the highest predicted concentration of each HAP.
The values in Table 8-5 are for emissions at the baseline only. The annual cancer
incidences are the number of new cancer cases estimated to occur in the exposed
population in a year. As estimated by HEM, the total annual cancer incidence of the 2
HAPs is 0.52 of a statistical life. Because the cancer risk associated with benzene and
naphthalene is iess than _ me effect of reduced emissions :s expected :o je .niaira:±i. . /
benefits of reducing cancer risk resulting from reduced emissions of carcinogenic HAPs
-------
could not be monetized since values of annual cancer risk after controls were not
available. However, if it is assumed that the controls required by the proposed rule would
decrease benzene and naphthalene emissions to zero, then a monetary estimate of the
benefit of reducing these two HAPs could be calculated. The benefit of eliminating the
carcinogenic HAP emissions is calculated by multiplying the 0.52 reduction in total
annual cancer risk by the midpoint of the range of values of a statistical life ($3.11 to
$7.25 million) which is $5.2 million. This calculation yields a total monetary benefit of
$2.7 million. This is an overestimation, however, given that the petroleum refinery
NESHAP will not achieve a 100 percent HAP reduction.
TABLE 8-5. MAXIMUM INDIVIDUAL RISK AND ANNUAL CANCER INCIDENCE OF
CARCINOGENIC HAPs
HAP MIR Annual Cancer Incidence
Benzene 1.8 x 10'4 0.37
Naphthalene 6.8 x IP'5 0.15
These monetary values should be interpreted carefully due to uncertainties in the
derivation of annual incidence numbers, the value of life estimates, and the focus on
equipment leak emissions. Because these uncertainties work in both directions, and
remain unquantified, it is not possible to say whether these values are over- or
underestimates of the (unknown) true value of cancer risk reduction. At best, the
numbers should be viewed as a guide to the possible level of benefits that may be
realized.
8.1.1.4 Other Health and Welfare Impacts of HAPs. A quantitative assessment of the
economic benefits related ta these impacts requires information on risk relationships,
exposure, and economic value. Unfortunately, such data are generally unavailable.
Therefore, it is currently not possible to conduct a complete quantitative analysis of the
benefits associated with HAP emission reductions.
Several intermediate quantitative assessment approaches have been developed which
can provide partial objective evidence of the positive impact of HAP emission reGucnons.
One approach examines changes in the population exposed to concentrations of HAPs over
a reference dose level with and without additional controls.3 The reference dose level is
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designed to reflect a concentration level, with a margin of safety, at which no adverse
health impacts would be expected. To complete this calculation, data must be available
on population counts near affected refineries, concentrations of speciated HAPs with and
without additional controls, and a reference dose level for the specific HAP.
Based on toxicity and emission information, an exposure assessment was performed
for hexane, hydrogen chloride, methy^ethyl ketone, and toluene. For noncarcmogens, the
dose-response is expressed in terms of an inhalation reference-dose concentration (RfC).
Using the RfC methodology, a benchmark concentration is calculated below which adverse
effects are not expected to occur. The significance of the RfC benchmark is that exposures
to levels below the RfC are considered "safe" because exposures to concentrations of the
chemical at or below the RfC have not been linked with any observable health effects.
The RfCs of the above mentioned HAPs are presented in Table 8-6. The benefits of
reducing these HAPs could not be monetized because information on reduced exposure is
not available. The omission of this benefit category from the monetized benefits analysis
will lead to an underestimation of the total expected benefits from the proposed
regulation. Significant baseline exposure was not shown to result from these HAPs. so
post-regulation emissions were not analyzed.
TABLE 8-6. RFCS AND NUMBER OF INDIVIDUALS EXPOSED AT OR ABOVE RFC
BY HAP
HAP
Hexane
Hydrogen Chloride
Methyl Ethyl Ketone
Toluene
RfC
0.2 mg/M3
0.07 mg/M3
1 mg/M3
0.4 mg/M3
Individuals Exposed
At or Above RfC
0
1,810
0
0
Epidemiological studies which attempt to identify statistical associations between
exposure and observable responses in the population represent another way to quantify
possible risks. However, because of collinearity with other environmental factors, it is
often very difficult to isolate the effects due solely to changes in HAP emissions. For this
reason, such statistical functions have generally not oeen estimated.
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At present, most of the model development in the area of estimating the welfare
effects and ecosystem impacts of exposure to HAps is still conceptual and not amenable to
objective measurement. Therefore, no quantitative estimate-* of these potential ecosystem
impacts have been made.
8.1.2 Quantitative Benefits of VOC Reduction
The benefits of reduced emissions of VOC from a MACT regulation of petroleum
refineries will be developed using the technique of "benefits transfer." Benefits transfer
involves the use of benefit values obtained from another study to represent benefits
associated with the current regulatory proposal, with appropriate adjustments. At a
minimum, the adjustments must address the differential impact in the severity of the
regulations as represented, for example, by changes in emissions or concentrations. With
this technique the assumption is made that benefits per ton reduced of a pollutant are
constant. Then, knowledge of a benefit per ton reduced ratio from a prior study, coupled
with information on tons reduced for the regulation under review, will be sufficient to
estimate benefits for the current regulation. Jn effect, extrapolated benefits are developed
on the basis of a constant, average benefit per ton reduced value.
In this RIA, an estimate of the benefits per (metric) ton reduced of VOC emissions is
developed from a study conducted for the Office of Technology Assessment.4 The OTA
study examined a variety of acute health impacts related to ozone exposure as well as the
benefits of reduced ozone concentrations for selected agricultural crops. However, chronic
health effects of ozone exposure were not considered. Therefore, all else equal, the
extrapolated estimate of VOC benefits for the MACT regulation should be viewed as a
lower bound estimate.
8.1.2.1 Benefit Transfer Values. Application of the benefit transfer technique
requires information on benefit values and the associated reduction in VOC emissions.
Data on benefits are taken from Table 3-10 of the OTA report. For the present
calculation, the values reported for the 35 percent VOC reduction scenario are used.
. Specifically, information from both the epidemiological studies and the clinical studies
reported in the OTA report is used to establish an initial benefit range of $54-$3,400
million per year per ton VOC emission reduction.
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The selection of this range of values was influenced by several factors. First, the
results for the 35 percent VOC emission reduction scenario are used because it is easier to
identify the level of emission reductions associated with this scenario in the OTA report.
It should also be noted that this scenario involves a reduction of 35 percent in those
emissions occurring only in non-attainment areas. Although there are expected to be
VOC emission reductions in attainment areas under this scenario, the percentage
reduction in VOC emissions in attainment areas is less than 35 percent. A close reading
of the OTA report indicates that all health impacts are estimated for non-attainment
areas only. Therefore, no benefits are associated with VOC emission reductions in
attainment areas. This may provide additional conservatism to the benefit values since
there is recent evidence that acute health effects may be experienced at ozone
concentrations below the current NAAQS.5
The OTA report calculates acute health impacts based on the results of epidemio-
logical and clinical studies. Both study designs have advantages and disadvantages
relative to one another. Indeed, the OTA report acknowledges that it is not possible to
judge which approach is superior.^Even though the two study designs measure similar
impacts, it is possible to use the results from both design types to form a range of values. >
This approach would not involve double-counting and would use more of the available
information. A lower bound value is identified from the epidemiological study design. An
upper bound value is taken from the clinical study design in which all exercisers are
affected. These choices lead to the initial benefit range of $54-$3,400 million per year.
The year of dollars for these benefit values is not made clear in the OTA report.
However, a check with the authors of several of the cited references used to develop "will-
ingness-to-pay" values, indicates that the values are in 1984 dollar terms.6 To maintain
consistency with other parts of this RIA, the benefit values are converted to first quarter
1992 dollars by multiplying the 1984 dollars by a factor of 1.335. This factor was
computed from the percentage change in the all item urban CPI index between the
annual index value for 1984 and the geometric mean of index values for the first three
168
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months of 1992.d The adjusted dollar benefit range in first quarter 1992 dollars is $72-
$4,539 million.
Three further adjustments can be considered for this benefit value range. First, as
noted earlier, benefits can be scaled by the tons of VOC emissions reduced in order to
form a benefit transfer ratio which can be multiplied by the VOC emission reductions for
the petroleum refinery MACT.
Second, the benefit values in the OTA report reflect a level of exposure that corre-
sponds to population densities in non-attainment areas in the early 1980's. Since the cost
analysis is conducted for the fifth year following rule promulgation (i.e., circa 1999), the
benefit analysis should be conformable. There is approximately a twenty year interval
from the period when the estimates used in the OTA report were calculated to the year of
regulatory impact. It is appropriate to scale the OTA benefit values by a factor which
represents the percentage change in population, between 1980 and 1999, in those non-
attainment areas with petroleum refineries. Using data from the 1980 and 1990
Censuses and extrapolating to 1999 under an assumption of a constant growth rate equal
to that observed for the 10 year period, it is estimated that the population scale factor is
19.64 percent. This leads to a revised benefit value range of $86 to $5,430 million.
Third, the passage of time may also affect the willingness to pay value. If real income
grows over time and the income elasticity of environmental quality is positive, then unit
willingness to pay values in 1999 should exceed those implied by the surveys conducted in
the mid-1980's. Using the 1993 Statistical Abstract6, the simple average percentage
change in per capita real income between 1985 and 1992 is 3.3 percent in those areas
most likely to be ozone non-attainment areas. Extrapolating to 1999 under a constant
growth assumption results in an increase of 6.7 percent. Given this relatively small
change and uncertainty about the proper income elasticity measure, no adjustment has
been made to the benefit value range to account for this factor.
!CPI index values were obtained from the 1993 U.S. Statistical Abstract (Table 756) and the
December 1992 issue of the Survey of Current Business.
Statistical Abstract, 1993, Table 704.
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8.1.2.2 Emission Reductions. The development of VOC emission reductions
associated with the benefits range described above can he determined directly from the
OTA report. Tables 6-1 and 6-6 of OTA provide the needed information. Total VOC
emissions in 1985 are 25 million tons.c Of this total, 11 million tons are predicted to
occur in non-attainment cities while 14 million tons of VOC are predicted to be emitted in
ozone attainment areas. For the 35 percent VOC (non-attainment area) emission
reduction scenario, 3.8 million tons of VOC emissions are predicted to be controlled in
1994, while 2.7 million tons will be controlled in attainment areas.
The selection of a "tons reduced" value for the denominator of the benefit transfer
ratio must be consistent with the benefits measure selected for the numerator. As
described earlier, the benefits reflect the annual reduction in acute health impacts
experienced by populations in non-attainment areas that result from a 35 percent
reduction in non-attainment area VOC emissions. Implicitly, there is the assumption that
no health benefits are experienced in attainment areas. Consequently, it seems most
appropriate to define the VOC emission reductions in terms of reductions occurring only
in non-attainment areas. This also implies that the derivation of petroleum refinery
health benefits from VOC emission reductions should consider only those emission
reductions which occur at plants in non-attainment areas. Fortunately, because
individual refineries are identified, it is possible to identify this subset of emission
reductions. A result of this approach is that no acute health benefits are associated with
VOC emission reductions in attainment areas.d Table 8-7 presents the baseline VOC
emissions, and the emission reductions for refineries in nonattainment areas associated
with each alternative.
The emissions data in OTA do not reflect measured emissions. Rather, they represent
emissions on a typical non-attainment day multiplied by 365. It is not clear from OTA how these
"nonattainment-day-equivalent-annual-emissions" are calculated for attainment regions.
^Recent evidence suggests that some health benefits may occur for VOC emission reductions in
areas near, but below, the current ozone NAAQS.5 As might be expected, the response rate is
lower than that observed at higher ozone concentrations. In addition, economic theory suggests
that the marginal willingness to pay for an incremental improvement in air quality at such levels
•-vould be less than the marginal 'villingness to pay :br increments at a higher level ibovp the
standard. That is, the marginal benefits function is non-linear. Since the beneiit transfer ratio
assumes a constant, linear relationship, it seems prudent to limit the benefits transfer calculation
to the non-attainment area data presented in the OTA report.
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TABLE 8-7. VOC EMISSION REDUCTIONS BY EMISSION POINT
VOC Emission Reductions by Regulatory Alternative (Mg/yrj!
Emission Point2
Equipment Leaks
Miscellaneous Process Vents
Storage Vessels
TOTAL REDUCTION BY
ATTAINMENT STATUS
TOTAL REDUCTION BY
ALTERNATIVE
Alternative 1
Nonattainment1
77,535
104,693
3,090
185,318
322,153
Attainment
80,266
55,161
1,408
136,835
Alternative 2
Nonattainment1
81,626
104,693
6,056
192,375
333,767
Attainment
83,471
55,161
2,760
141,392
NOTES. 'VOC emission reductions include only those associated with control of the 87 refineries located in ozone
nonattainment areas.
JNo further control is assumed for wastewater streams, and therefore, emission reductions associated with this
emission point are zero.
Emission reduction estimates do not incorporate reductions occurring at new sources.
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One final step is needed prior to forming the benefit transfer ratio. Since VOC
emission reductions for petroleum refineries are stated in megagrams per year (metric
tons per year), it is necessary to convert the OTA emission reductions to equivalent metric
tons. This conversion results in a reduction of 3.45 million metric tons in non-attainment
areas.
8.1.2.3 Benefit Estimates. The benefit transfer ratio range for acute health impacts is
estimated to be $25-$l,574 (first quarter 1992 dollars per metric ton). These values were
obtained by dividing the benefit range values by the reduction in emissions. The average
(mid-point) of the range is $800 per metric ton. These ratios are to be multiplied by VOC
emission reductions from petroleum refineries located in ozone non-attainment areas in
order to estimate the VOC-related acute health benefits of the petroleum refinery MACT.
Table 8-8 summarizes the results of these calculations for the combination of options
selected for the four controlled emission points. In addition, benefits for the next most
stringent option for each emission point type are also reported. Note, the floor option for
each emission point type is statutorily mandated so that, in effect, the floor options
represent the minimal regulatory requirements.
TABLE 8-8. BENEFITS OF VOC REDUCTIONS BY REGULATORY ALTERNATIVE
Benefits (Million Dollars)
Alternative 1 Alternative 2
Average $148.3 $153.9
Range $4.6 - $291.7 $4.8 - $302.8
The benefit values reported above are restricted to acute health impacts associated
with VOC emission reductions. Several qualifications should be noted. First, there is an
implicit assumption of a constant linear relationship between VOC emission reductions
and changes in ozone concentrations in non-attainment areas. One result of this
assumption is that it becomes difficult to justify quantifying benefits for agricultural yield
changes associated with VOC emission reductions. As described in OTA, the VOC/NOX
ratio in rural areas is NOx-limited because of relatively high vegetative VOC emissions.'
Consequently, ozone production is less sensitive to changes in man-made VOC emissions.
Therefore, it seems appropriate to exclude agricultural benefits for the present analysis.
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Also, as noted earlier, there may be other benefit types. Reductions in VOC emissions
which lead to improvements in ozone concentrations may contribute to reductions in
chronic health impacts (e.g., sinusitis, hay fever and reduced damage to certain materials,
such as elastomers).8 However, because of data and methodological concerns, no
quantitative benefit estimates for these possible effect types have been developed for the
present analysis. All else equal, this implies that the calculated benefit per metric ton
range of $25-$l,574 is likely to be conservative.
Although the quantified VOC benefits estimated in this RIA represent one approach
for valuing the benefits of reduced VOC emissions, data limitations prevent a complete
quantification of all categories of benefits attributable to VOC reductions. Since lack of
data prevent all benefit categories from being monetized, a direct comparison of benefits
to costs may not be helpful in determining the desirable regulatory alternative. An
assessment of the incremental cost-effectiveness analysis will represent the cost of the air
emission controls relative to the expected VOC emission reductions attributable to the
- atrols. Because of the lack of data, this analysis ignores the benefit of HAP emission
reductions. The incremental VOC cost-effectiveness analysis begins with the baseline, or
no control. Alternative 1, which is the basis of the proposed rule, includes controls to
meet MACT floor level controls, and a level of control more stringent than the floor for
equipment leaks. --The annual cost of this control, including equipment costs, MRR costs,
and economic costs, is $132 million annuallyy This regulatory alternative is expected to
result in a reduction of VOC emissions of approximately 185,000 Mg annually. Therefore,
the incremental cost-effectiveness, averaged across multiple emission points, of the
requirements of Alternative 1 is approximately $712/Mg. In other words, the average cost
of reducing each Mg required by Alternative 1 is $712.
The next more stringent level of control, Alternative 2, which includes increased
control of equipment leaks and storage vessels, has a total annual cost of $148 million.
This level of control is estimated to achieve an annual VOC emission reduction of
approximately 192,375 Mg. The incremental VOC cost-effectiveness of going from
Alternative 1 to Alternative 2 is approximately $2,300/Mg.
Table 8-9 presents the incremental VOC cost-effectiveness values for each regulatory
alternative discussed in this analysis. Alternative 1 can be justified as a desirable option
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since the incremental VOC cost-effectiveness of implementing Alternative 2 is
significantly higher.
TABLE 8-9. VOC INCREMENTAL COST-EFFECTIVENESS OF PETROLEUM
REFINING REGULATION
Alternative 1 Alternative 2
Incremental Cost (Million S 1992)1 $132.35 $16.0
Incremental Emission Reduction (Mg) 185,318 7,057
Incremental Cost Effectiveness ($/Mg) $712/Mg $2,267/Mg
NOTES. 'The cost estimates of each alternative reflect the total social cost of emission control
174
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REFERENCES
1. U.S. Environmental Protection Agency. Cancer Risk from Outdoor Exposure to Air
Toxics, Volume I. EPA-450/l-90-004a. Office of Air Quality Planning and Standards.
Research Triangle Park, NC. September 1990.
2. Viscusi, W. Kip. "The Value of Risks to Life and Health." Journal of Economic
Literature, pp. 1912-1946. December 1993.
3 Voorhees, A., B. Hassett, and I. Cote. Analysis of the Potential for Non-Cancer
Health Risks Associated with Exposure to Toxic Air Pollutants. Paper presented at
the 82nd Annual Meeting of the Air and Waste Management Association. 1989.
4. Office of Technology Assessment. Catching Our Breath: Next Steps for Reducing
Urban Ozone. OTA-O-412. Washington, DC. U.S. Government Printing Office. July
1989.
5. Horstman, D., W. McDonnell, L. Folinsbee, S. Abdal-Salaam, and P. Ives. Changes m
Pulmonary Function and Airway Reactivity Due to Prolonged Exposure to Typical
Ambient Ozone (O3) Levels. In: Schneider, T. et aj. (eds.) Atmospheric Ozone
Research and its Policy Implications. Elsevier Science Publishers. Amsterdam.
1989.
6. Horst, R.L., Jr. Personal communication with L. Chestnut. January 26, 1994.
7. Reference 4. p. 107.
8. Portney P. and J. Mullahy. "Urban Air Quality and Chronic Respiratory Disease."
Regional Science and Urban Economics. Vol. 20. p. 407-18. 1990.
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9.0 COMPARISON OF BENEFITS TO COSTS
The goal of the Regulatory Impact Analysis and Benefits Analysis for the Petroleum
Refinery NESHAP is to provide economic and engineering data necessary for effective
environmental policymaking. A comparison of the benefits of alternative air emission
controls with the costs of such controls provides the necessary framework for a reasonable
assessment of the net benefits of the proposed environmental measures.
9.1 COMPARISON OF ANNUAL BENEFITS AND COSTS
The potential health and welfare benefits associated with air emission reductions
relate to expected reductions in emissions of several HAPs and VOCs from storage tanks,
process vents, equipment leaks, and wastewater emission points at refining sites. The
quantification of benefits from emission controls relates to health benefits from reduced
cancer incidence associated with carcinogenic HAPs emitted at petroleum refineries and
the health benefits related to reduced VOCs that translate into reductions in ozone.
Benefits from reducing cancer incidence to zero were quantified for equipment leaks only
in the previous chapter. Because of the uncertainty associated with this estimate, the
benefits of reduced cancer risk are not incorporated in this benefit cost analysis. Other
health and welfare benefits from the controls such as benefits to the ecosystem have not
been quantified due to limitations in data and methodology.
The compliance costs of the alternative emission controls relate to capital costs and
operation and maintenance costs for each of the regulatory alternatives (including MRR
costs; ootained from engineering studies conducted for EPA. These estimates reflect tne
engineering costs of emission controls rather than the economic costs to society. The
compliance cost estimates provide a necessary data input for the economic analysis of the
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cost of the regulatory alternatives to society. The economic effect of imposing compliance
costs on the petroleum refining market and its consumers and producers is obtained from
a partial equilibrium model of the petroleum refining industry. The social costs of the
controls include potential economic costs to consumers of refined petroleum products,
producers of refined petroleum products, and society as a whole. Economic costs are a
better measure of the costs of the air emission control alternative to society because these
costs represent the true costs or opportunity costs to society of resources used for emission
control. Quantifications of the compliance costs and economic costs of the air emission
alternatives are subject to the limitations noted in Section 6.4-Limitations of the Economic
Model. The social costs of Alternative 2 represents the social costs of Alternative 1 plus
the incremental increase in compliance costs for Alternative 2. Social costs were not
estimated independently for Alternative 2 due to limitations in resources. Table 9-1
depicts a comparison of the benefits of the alternative proposals to the compliance and
social costs. A comparison of the net benefits for the alternatives and the incremental
difference in net benefits between the alternatives provides the appropriate comparison.
The benefits exceed costs (both compliance and social) for each of the alternatives.
Thus, either alternative is viable and warrants consideration. However, a comparison of
the incremental difference in the two alternatives indicates that the incremental net
1
benefits are negative for Alternative 2. Thus, Alternative 1 provides the greatest net
benefits to society.
178
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TABLE 9-1. COMPARISON OF ANNUAL BENEFITS TO COSTS FOR THE NATIONAL
PETROLEUM REFINING INDUSTRY REGULATION
(MILLIONS OF 1992 DOLLARS PER YEAR)
Benefits
Social Costs
Benefits Less Social Costs
Alternative 1
$148.3
$(132.4)
$16.0
Alternative 2
$153.9
$(148.4)2
$5.5
Incremental
Difference1
$5.6
$(16.0)
$(10.4)
NOTES: ( ) represent costs or negative values.
'The incremental difference represents the difference between Alternative 1 and Alternative 2
'Social costs for Alternative 2 are calculated by adding incremental compliance costs to social costs of Alternative
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TECHNICAL REPORT DATA
(Please read Instructions on reverse before completing)
I. REPORT NO.
EPA-453/D-94-053
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Regulatory Impact Analysis for the Petroleum
Refineries NESHAP
5. REPORT DATE
July 1994
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
U.S. Environmental Protection Agency
Office of Air Quality Planning and
Standards
Emission Standards Division
Research Triangle Park, NC 27711
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-D1-0144
12. SPONSORING AGENCY NAME AND ADDRESS
Director
Office of Air Quality Planning and
Standards
Office of Air and Radiation
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
14. SPONSORING AGENCY CODE
EPA/200/04
15. SUPPLEMENTARY NOTES
16. ABSTRACT
A regulatory impact analysis (RIA) of the industries affected by the
Petroleum Refineries National Emissions Standard for Hazardous Air
Pollutants (NESHAP) was completed in support of this proposal. This
(RIA) was required because the proposal is economically significant
according to Executive Order 12866 (future RIAs will be called economic
assessments).
The industry for which these impacts was computed was the petroleum
refinery industry. Several different impact analyses were included in
total or summarized in different chapters in the document. Those
analyses were: the compliance cost analysis, the economic impact
analysis, and the benefits analysis. Benefits and costs were then
compared and discussed in the document's last chapter.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b. IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Control Costs
Industry Profile
Economic Impacts
Benefits Analysis
Air Pollution control
18. DISTRIBUTION STATEMENT
Release Unlimited
19. SECURITY CLASS (Report)
Unclassified
21. NO. OF PAGES
200
20. SECURITY CLASS (Page)
Unclassified
22. PRICE
EPA Form 2220-1 (Rev. 4-77) PREVIOUS EDITION IS OBSOLETE
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