This report is issued by the Emission Standards Division of
the Office of Air Quality Planning and Standards, U.S.
Environmental Protection Agency. It presents technical data.
IX
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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-4
ES.4 CONTROL TECHNIQUES AND REGULATORY ALTERNATIVES . ES-5
ES.5 COST ANALYSIS ES-5
ES.6 ECONOMIC IMPACTS AND SOCIAL COSTS ES-7
ES.7 QUALITATIVE ASSESSMENT OF BENEFITS OF EMISSION
REDUCTIONS ES-9
ES.8 QUANTITATIVE ASSESSMENT OF BENEFITS ES-9
ES.9 COMPARISON OF BENEFITS TO COSTS ES-12
1.0 INTRODUCTION 1
1.1 PURPOSE ..... 1
1.2 LEGAL HISTORY AND STATUTORY AUTHORITY 2
1.3 REPORT ORGANIZATION 3
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 9
2.1.6 Marine Vessel Loading and Unloading, Bulk
Gasoline Terminal Breakout Station Storage
Vessels, and Bulk Gasoline Terminal Loading Rack
Provisions ' 10
2.1.7 Recordkeeping and Reporting Provisions .... 10
2.1.8 Emission Averaging 10
3 .0 NEED FOR REGULATION . , 13
3 .1 MARKET FAILURE 13
3.1.1 Air Pollution as an Externality 14
3.1.2 Natural Monopoly 14
3.1.3 Inadequate Information 15
3.2 INSUFFICIENT POLITICAL AND JUDICIAL FORCES .... 15
3.3 ENVIRONMENTAL FACTORS WHICH NECESSITATE REGULATION 16
3.3.1 Air Emission Characterization 16
3.3.2 Harmful Effects of HAPs 17
3.4 CONSEQUENCES OF REGULATORY ACTION 20
3.4.1 Consequences if EPA's Emission Reduction
Objectives are Met 20
iii
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CONTENTS (continued)
Page
3.4.2 Consequences if EPA's Emission Reduction
Objectives are Not Met 23
4.0 CONTROL TECHNIQUES AND REGULATORY ALTERNATIVES 27
4.1 CONTROL TECHNIQUES . -. 28
4.1.1 Combustion Technology 28
4.1.2 Product Recovery Devices . . . 41
4.1.3 Leak Detection and Repair 50
4.1.4 Internal Floating Roofs 59
4.2 DESCRIPTION OF MACT AND SUMMARY OF REGULATORY
ALTERNATIVES 62
4.2.1 Miscellaneous Process Vents 63
4.2.2 Storage Vessels . . 64
4.2.3 Wastewater Streams 65
4.2.4 Equipment Leaks 66
4.2.5 Summary of Alternatives 67
4.3 NO ADDITIONAL EPA REGULATION 67
4.3.1 Judicial System 67
4.3.2 State and Local Action 70
4.4 ROLE OF COST EFFECTIVENESS IN CHOOSING AMONG
REGULATORY ALTERNATIVES 70
4.5 ECONOMIC INCENTIVES: SUBSIDIES, FEES, AND
MARKETABLE PERMITS 71
5.0 COST ANALYSIS AND EMISSION REDUCTION 75
5.1 APPROACH FOR ESTIMATING REGULATORY COMPLIANCE COSTS 75
5.1.1 Calculations for Existing Sources 77
5.1.2 Calculations for New Sources 85
5.2 TOTAL COMPLIANCE COST ESTIMATES, REDUCTIONS, AND
COST EFFECTIVENESS 89
5.3 MONITORING, RECORDKEEPING, AND REPORTING COSTS . . 94
6.0 ECONOMIC IMPACTS AND SOCIAL COSTS 101
6.1 PROFILE OF THE PETROLEUM REFINING INDUSTRY 102
6.1,1 Profile of Affected Facilities 103
6.1.2 Market Structure 107
6.1.3 Market Supply Ill
6.1.4 Market Demand Characteristics 112
6.1.5 Market Outlook 117
6.2 MARKET MODEL 120
6.2.1 Market Supply and Demand 121
6.2.2 Market Supply Shift 122
6.2.3 Impact of Supply Shift on Market Price and
Quantity 126
6.2.4 Trade Impacts 126
6.2.5 Changes in Economic Welfare 128
6.2.6 Labor Market and Energy Market Impacts 131
6.2.7 Baseline Inputs . . . 131
6.2.8 Price Elasticities of Demand and Supply .... 132
6.3 CAPITAL AVAILABILITY ANALYSIS . . . 134
IV
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CONTENTS (continued)
Page
6/4 LIMITATIONS OF THE ECONOMIC MODEL 139
6.5 PRIMARY IMPACT, CAPITAL AVAILABILITY ANALYSIS, AND
.SECONDARY IMPACT RESULTS 141
6.5.1 Estimates of Primary Impacts 142
6.5.2 Capital Availability Analysis 145
6.5.3 Labor Market Impacts and Energy Market Impacts . 146
6.5.4 Foreign Trade Impacts 150
6.5.5 Regional Impacts 150
6.6 SUMMARY . 150
6.7 POTENTIAL SMALL BUSINESS IMPACTS . 152
6.7.1 Introduction 152
6.7.2 Methodology 153
6.7.3 Categorization of Small Businesses 153
6.7.4 Small Business Impacts 153
6.8 SOCIAL COSTS OF REGULATION 154
6.8.1 Social Cost Estimates 155
7.0 QUALITATIVE ASSESSMENT OF BENEFITS OF EMISSION REDUCTIONS 159
7.1 IDENTIFICATION OF POTENTIAL BENEFIT CATEGORIES . . 160
7.2 QUALITATIVE DESCRIPTION OF AIR RELATED BENEFITS . . 160
7.2.1 Benefits of Decreasing HAP Emissions 160
7.2.2 Benefits of Reduced VOC Emissions ........ 166
8.0 QUANTITATIVE ASSESSMENT OF BENEFITS 170
8.1 METHODOLOGY FOR DEVELOPMENT OF BENEFIT ESTIMATES . 170
8.1.1 Benefits of Reduced Cancer Risk Associated with
HAP Reductions 171
8.1.2 Quantitative Benefits of VOC Reduction 180
9.0 COMPARISON OF BENEFITS TO COSTS 189
9.1 COMPARISON OF ANNUAL BENEFITS AND COSTS ! 189
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TABLES
Page
ES-1 SUMMARY OF'TOTAL COSTS IN THE FIFTH YEAR FOR THE
PETROLEUM REFINING INDUSTRY REGULATION ES-6
ES-2 ANNUAL SOCIAL COST ESTIMATES FOR THE PETROLEUM REFINING
REGULATION ES-8
ES-3 VOC EMISSION REDUCTIONS BY EMISSION POINT ES-11
ES-4 BENEFIT PER MEGAGRAM VALUES FOR VOC REDUCTIONS . . . ES-12
ES-5 COMPARISON OF ANNUAL BENEFITS TO COSTS FOR THE NATIONAL
PETROLEUM REFINING INDUSTRY REGULATION ES-13
3-1 NATIONAL BASELINE VOC AND HAP EMISSIONS BY EMISSION
POINT 17
3-2 BASELINE SPECIATED HAP EMISSIONS FROM EQUIPMENT
LEAKS 19
3-3 NATIONAL CONTROL COST IMPACTS OF PREFERRED
ALTERNATIVE IN THE FIFTH YEAR 22
4-1 SUMMARY OF REGULATORY ALTERNATIVES BY EMISSION POINT 69
5-1 SUMMARY OF TOTAL COSTS IN THE FIFTH YEAR FOR THE
PETROLEUM REFINING NESHAP 90
5-2 CONTROL OPTIONS AND IMPACTS BY EMISSION POINT ... 91
5-3 COST, HAP EMISSION REDUCTION, AND COST EFFECTIVENESS
BY ALTERNATIVE 93
5-4 COST, VOC EMISSION REDUCTION, AND COST EFFECTIVENESS
BY ALTERNATIVE 93
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 96
6-1 ESTIMATES OF PRICE ELASTICITY OF DEMAND 133
6-2 SUMMARY OF PRIMARY IMPACTS 144
6-3 ANALYSIS OF FINANCIAL RATIOS •. . . 146
6-4 SUMMARY OF SECONDARY REGULATORY IMPACTS ...... 149
6-5 FOREIGN TRADE (NET EXPORTS) IMPACTS 151
6-6 ANNUAL SOCIAL COST ESTIMATES FOR THE PETROLEUM
REFINING REGULATION 155
7-1 POTENTIAL HEALTH AND WELFARE EFFECTS ASSOCIATED WITH
EXPOSURE TO HAZARDOUS AIR POLLUTANTS 162
8-1 HAP EMISSIONS AT PETROLEUM REFINERIES 171
8-2 SOURCES OF UNCERTAINTY IN CANCER RISK ASSESSMENT . 175
8-3 UNCERTAINTIES IN BENEFIT ANALYSIS 176
8-4 UNIT RISK FACTORS FOR CARCINOGENIC HAPS 177
8-5 . MAXIMUM INDIVIDUAL RISK AND ANNUAL CANCER INCIDENCE
OF CARCINOGENIC HAPs 178
8-6 RFCS AND NUMBER OF INDIVIDUALS EXPOSED AT OR ABOVE
RFC BY HAP 180
QUANTIFIED BENEFITS FOR VOC EMISSION REDUCTIONS . .
8-7 BY REGULATORY ALTERNATIVE . 186
9-1 COMPARISON OF ANNUAL BENEFITS TO COSTS FOR THE
NATIONAL PETROLEUM REFINING INDUSTRY NESHAP .... 191
VI
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6-1
FIGURES
ILLUSTRATION OF POST-NESHAP MODEL.
Page
. 125
VI1
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ACRONYMS AND ABBREVIATIONS
API
ASM
bbl
bbl/d
BCA
BWON
CAA
C/E
. CERA
DOC
DOE/EIA
Administration
EIA
EPA
FCCU
HAP
HEM
HON
below)
IARC
kPa
LDAR
LEL
LPGs
1pm
MACT
MIR
MRR
MTBE
Mg
NAAQS
NESHAP
Pollutants
NSPS
NOX
OGJ
OMB
PADD
ppmv
RACT
RFA
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
economic impact analysis
Environmental Protection Agency
fluidized catalytic cracking unit
Hazardous Air Pollutant
Human Exposure Model
Hazardous Organic NESHAP (NESHAP is defined
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
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
RfC reference-dose concentration
RIA ' Regulatory Impact Analysis
SIC Standard Industrial Classification
SIP State Implementation Plan
SO2
SOCMI
URF
VOC
sulfur dioxide
Synthetic Organic Chemical Manufacturing industry
unit risk factor
volatile organic compound
viii
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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 (or economic assessments) for
all "significant" regulatory actions. At proposal, EPA
determined that the petroleum refinery NESHAP is a "significant"
rule because it had an estimated annual cost on the economy of
more than $100 million, and is therefore subject to the
requirements of Executive Order 12866. As shown later in the
report, that cost is now less than $100 million, but it has been
decided that due to the level of interest in the results of the
analyses that make up this report that revising the RIA for
promulgation was necessary. 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
ES-1
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(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 to focus on one regulatory option, the
chosen regulatory alternative (referred to as "Alternative 1")
and calculated the compliance costs, economic impacts, and
benefits from implementing that alternative to the greatest
extent possible.
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 wastewater collection and treatment systems.
ES.2 PROMULGATED PETROLEUM REFINERY EMISSION STANDARD
The promulgated 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
ES-2
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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 promulgated 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: (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.
EPA intends to amend the source category list to define the
processes and emission points regulated in this rule as one
source category. Catalyst regeneration vents, catalytic cracking
units, catalytic reforming units, and vents from sulfur recovery
plants are being defined as the second source category.
Data analyses conducted in developing the MACT floor for
miscellaneous process vents determined that 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
ES-3
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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 promulgated rule are based on the
Petroleum Refinery NSPS Equipment Leak provisions, as well as 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 allowing emission
averaging 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. With emissions averaging as part of the
standard, the rule contains 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 cancer incidences, genotoxicity, neurotoxicity,
liver damage, cardiovascular impairment, and other toxic effects.
In addition to threats to human health, there are also
detrimental effects on human welfare, such reduced-agricultural
crop yields and reduced ecosystem diversity and activity. The
U.S. Office of Management and Budget (OMB) directs regulatory
agencies to demonstrate the need 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
ES-4
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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 promulgated regulation requires 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 a single regulatory
alternative, Alternative 1. It is a hybrid option, that
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. Cost
and emission data were unavailable to compare this alternative
with a second alternative to examine the incremental costs and
benefits of going to another alternative.
ES.5 COST ANALYSIS
The annualized compliance costs by emission point are shown in
Table ES-1 for the chosen alternative. The total national cost
of Alternative 1 in the fifth year is $79 million.
ES-5
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In addition to provisions for the installation of control
equipment, the promulgated regulation includes requirements for
monitoring, recordkeeping, and reporting (MRR). EPA estimates
that the total annual cost for refineries to comply with the MRR
requirements is $20 million, an amount included in the compliance
cost estimate of $79 million. The MRR requirements are outlined
separately in the promulgated regulation for each emission point.
ES.6 ECONOMIC IMPACTS AND SOCIAL COSTS
An economic impact analysis (EIA) 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 EIA 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 emission controls were also evaluated. The
estimated market changes from the use of these 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 Alternative 1 is
shown in Table ES-2. The social costs are used later in the RIA
to conduct a benefit cost analysis, for the proper costs to
compare benefits with are the social costs, since the benefits
are to society as a whole. As seen in Table ES-2, the social
costs are $95 million annually, $16 million higher than the
compliance costs alone.
ES-7
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TABLE ES-2.
ANNUAL SOCIAL COST ESTIMATES FOR THE PETROLEUM
REFINERIES NESHAP
Social Cost Category
Net Costs1
(millions of 1992
dollars)
Surplus Losses for Preferred
Alternative:
Change in Consumer Surplus
Change in Producer Surplus
Change in Residual Surplus to
Society2
Total Social Cost of Alternative
$342.86
$(174.32)
$(73.25)
$95.29
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. The social costs was calculated by
reducing the social costs for the chosen alternative (Alternative 1) at proposal minus
the reduction in annual engineering cost estimates between proposal and promulgation, and assuming the
same percentage change in the social costs.
ES-8
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ES.7 QUALITATIVE ASSESSMENT OF BENEFITS OF EMISSION REDUCTIONS
This RIA presents the results of an examination of the health
and welfare benefits associated with air emission reductions
projected as a result of implementation of the petroleum refinery
NESHAP. The promulgated 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 are
classified 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
Benefits were quantified from VOC emission reduction for two
categories, reduced acute health effects in ozone nonattainment
areas and increased agricultural crop yields nationwide. The
quantification of dollar benefits for all benefit categories is
not possible at this time because of limitations in both data and
available methodologies, but the monetized benefits quantified
exceed the costs of the rule.' Since the dollar benefits could
not quantified for all benefit categories (including acute health
effects in ozone attainment areas and chronic health effects
nationwide), the resulting monetized benefits estimate is an
underestimate.
ES-9
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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 the difference in estimated annual
cancer incidence before and after implementation of each
regulatory alternative. The annual cancer incidence associated
with this rule was less than one statistical life per year.
EPA's risk assessment indicates that over 4.5 million people
exposed to refinery emissions have an individual risk greater
than 1 in 1 million from exposure to benzene, a known human
carcinogen.
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, an assumption that is conservative, the VOC emission
reductions used in this analysis for computing health benefits
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 Alternative 1, the chosen alternative.
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 for these impacts, the ratios
were multiplied by VOC emission reductions from petroleum
refineries located in ozone non-attainment areas. Estimated
health benefits from VOC emission reductions were $108.5 million,
ES-10
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the midpoint of a range from $3.4 - $213.5 million. Benefits
from increase in agricultural yields from decreased ozone
concentrations due to VOC emission reductions, calculated for
attainment and nonattainment areas, were estimated at $44.9
million, the midpoint of a range from $30.3 - $59.5 million. The
resulting total annual benefits were $153.4 million, again a
midpoint, this time of a range from $33.7 - $273.0 million.
TABLE ES-3. VOC EMISSION REDUCTIONS BY EMISSION POINT
Emission Point2
VOC Emission Reductions by
Regulatory Alternative (Mg/yr)3
Alternative 1
Nonattainment1 Attainment
Equipment Leaks
Miscellaneous
Process Vents
Storage Vessels
TOTAL REDUCTION
BY ATTAINMENT
STATUS
TOTAL REDUCTION
FOR ALTERNATIVE
56,601
76,426
2,256
69,052
47,438
1,227
134,283 . 117,717
252,000
•'•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.
3Emission reduction estimates do not incorporate
reductions occurring at new sources.
ES-11
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TABLE ES-4. BENEFIT PER MEGAGRAM VALUES FOR VOC REDUCTIONS
Benefits Transfer Value1
1992 Dollars/Megagram2
Average
Range
$800
$25 - $1,574
benefits transfer value in the table quantifies only the
benefits attributable to reduced acute health impacts in ozone
nonattainment areas.
2Values are in first quarter 1992 dollars.
ES.9 COMPARISON OF BENEFITS TO COSTS
Table ES-5 depicts a comparison of the benefits of
implementing the chosen regulatory alternative only to the
compliance and social costs. Data for calculating the benefits
for a second alternative were not available, thus the Agency was
unable to 'examine the incremental benefits and incremental costs
of going to a second alternative and determine if maximum net
benefits are approached with the chosen alternative. There are
positive net benefits from control at the chosen alternative,
however. The net benefits to society are $58.1 million annually
from compliance with the standard.
ES-12
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TABLE ES-5.
COMPARISON OF ANNUAL BENEFITS TO COSTS FOR THE
PETROLEUM REFINERIES NESHAP
(MILLIONS OF 1992 DOLLARS PER YEAR)
Alternative 1
Benefits
Social Costs
Benefits Less Social Costs
$153.40
$(95.29)
$58.11
( ) represent costs or negative values.
ES-13
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ES-14
J
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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 1 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 fees, or loan
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programs or the rights and obligation of recipients thereof; or
(4) is likely to raise novel legal or policy issues arising out
of legal mandates, the President's priorities, or the principles
set forth in the Executive Order. At proposal, EPA 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. While the NESHAP is no longer a
"significant" rule due to the annual effect on the economy now
estimated to be less than $100 million, the RIA has been revised
and a final version will be available at promulgation.
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 a single
regulatory option for evaluation in this RIA. 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 and societal 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
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requires that the rules be established for categories of sources
of the emissions, rather than being set by pollutant. In
addition, the CAR 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.
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 promulgated 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
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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.
Chapter 7 provides a qualitative description of the benefits
associated with the regulatory action. As explained in this
chapter, some benefits are nonquantifiable 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 PROMULGATED 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 promulgated 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 promulgated 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 final 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 promulgated 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, arid 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, and all emission points regulated by the
subject NESHAP are in a single source category.
2.1.2 Miscellaneous Process Vent Provisions
Miscellaneous process vents include vents from petroleum
refining process units that emit organic HAP's. Vents that are
6
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routed to the refinery fuel gas system are considered to be part
of the process and are not subj ect to the standard. The
miscellaneous process vent provisions define two groups of vents.
Group 1 process vents are those with VOC emissions greater than
or equal to 33 kilograms per day (kg/day) (72 Ibs/day) at
existing sources. Group 2 vents are vents with emissions below
this level.
The miscellaneous process vent provisions for new and existing
sources require the owner or operator of a Group 1 miscellaneous
process vent to control vents using a flare, boiler, process
heater, or 98 percent control device. No controls or monitoring
are required for those vents already in Group 2. The process
vent provisions are the same for both new and existing petroleum
refinery sources.
2.1.3 Storage Vessel Provisions
The storage vessel provisions define two groups of vessels:
Group 1 vessels are vessels with a design storage capacity and a
maximum true vapor pressure above the values specified in the
regulation. Group 2 vessels,are all storage vessels that are not
Group 1 vessels. The storage provisions require that one of the
following control systems be applied to Group 1 storage vessels:
(1) An internal floating roof (IFR) with proper seals; (2) an
external floating roof (EFR) with proper seals; (3) an EFR
converted to an IFR with proper seals; or (4) a closed vent
system with a 95 percent efficient control device. The storage
provisions give details on the type of seals required.
Monitoring and compliance provisions for Group 1 vessels include
periodic external visual inspections of vessels and roof.seals,
as well as less frequent internal inspections. If a closed vent
system and control device is used for venting emissions from
Group 1 storage vessels, the owner or operator must establish
appropriate monitoring procedures. No controls or inspections
are required for Group 2 storage vessels.
For existing sources, the final rule requires that fixed roof
tanks with capacities greater than or equal to 177 cubic meters
(m3) (1,115 barrels or 47,000 gallons) that store liquids with
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vapor pressures greater than 10.2 kilopascals (kPa) (1.5 pounds
per square inch absolute (psia)) comply fully with the rule
within 3 years. 'Owners or operators of IFR or EFR tanks are
allowed to defer upgrading of their seals to meet the NESHAP
requirements until the next scheduled inspection and maintenance
activity or within 10 years, whichever comes first. For new
sources, the final rule requires that vessels with capacities
greater than or equal to 151 m3 (950 barrels or 40,000 gallons),
with vapor pressures equal to or greater than 3.4 kPa (0,5 psia),
and vessels with capacities equal to or greater than 76 m3 (475
barrels or 20,000 gallons) storing liquids with vapor pressures
equal to or greater than 77 kPa (11.1 psia} comply with the level
of control required by 40 CFR part 63 subpart G (including the
controlled fitting requirements).
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 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). In general, streams are not exempt from 40 CFR part
61 subpart FF if they contain a concentration of at least 10
parts per million by weight (ppmw) benzene, and have a flow rate
of at least 0.02 liters per minute (1/min) (0.005 gallons per
minutes (gal/min)). Group 2 streams are wastewater streams that
are not Group 1.
The wastewater provisions of the final rule refer to the BWON
for both new and existing sources, which requires owners or
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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. Vents from stream
strippers and other waste management or treatment units are
required to be controlled by a control device achieving 95
percent emissions reduction or 20 ppmv at the outlet of the
control device. The performance tests, monitoring, reporting,
and recordkeeping provisions required to demonstrate compliance
are included in the BWON. 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
allow owners and operators of existing sources to choose between
complying with equipment leaks provisions in 40 CFR part 60
subpart W (Petroleum Refinery NSPS Equipment Leaks Standard) or-
complying with a modified negotiatied regulation for equipment
leaks presented in 40 CFR part 63 subpart H (HON equipment
leaks). The differences in the refinery equipment leak
requirements and the HON equipment leak provisions are in the
leak definitions and connector monitoring provisions.
Under either of the two options, existing refineries subject
to the rule will be required to implement a Leak Detection and
Repair (LDAR) program with the same leak definitions (10,000 ppm)
and frequencies as specified in 40 CFR part 60 subpart W within
3 years after promulgation of the petroleum refineries NESHAP.
Refineries that choose to comply with the modified negotiated
regulation would implement the Phase II leak definitions and
frequencies at the end of the fourth year after promulgation, .and
comply with Phase III requirements 5 1/2 years after
promulgation. Phase III has lower leak definitions, but allows
less frequent monitoring for good performers. Although the
modified negotiated regulation is not required in the final rule,
the EPA believes that it would provide greater emission
reductions and, in many cases, would be more cost effective than
40 CFR part 60 subpart W and could even provide cost savings.
Cost savings would occur because it would reduce equipment leak
product loss, and facilities with a low percent of leaking valves
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would be able to monitor less frequently, thereby reducing
monitoring costs.
New sources must comply at startup with the modified
negotiated regulation; pumps and valves at new sources must be in
compliance with the Phase II requirements at startup rather than
Phase I. This is consistent with the negotiated rule (40 CFR
part 63 subpart H).
2.1.6 Marine Vessel Loading and Unloading, Bulk Gasoline
Terminal or Pipeline Breakout Station Storage
Vessels, and Bulk Gasoline Terminal Loading Rack
Provisions
The final refineries NESHAP requires marine vessel loading and
unloading operations at refineries to comply with the marine
loading NESHAP (40 CFR part 63 subpart Y) unless they are
included in an emissions average. Bulk gasoline terminal or
pipeline breakout station storage vessel and equipment leaks, and
bulk gasoline terminal loading racks at refineries are required
to comply with the gasoline distribution NESHAP (40 CFR part 63
subpart R) unless they are included in an emissions average
(equipment leaks cannot be included in an emissions average).
2.1.7 Recordkeeping and Reporting Provisions
The final rule requires petroleum refineries subject to 40 CFR
part 63 subpart CC maintain required records for a period of at
least 5 years. The final rule required that the following three-
types of reports be submitted: (1) a Notification of Compliance
Status, (2) periodic reports, and (3) other reports.
2.1.8 Emission Averaging
The EPA is allowing emission averaging among existing
miscellaneous process vents, refining storage vessels, and
wastewater streams, marine vessel loading and unloading
operations, bulk gasoline terminals or pipeline breakout station
storage vessels and bulk gasoline terminal loading -racks within a
10
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refinery. New sources are not allowed to use emissions
averaging. Under emission averaging, a system of emission
"credits" and "debits" would be used to determine whether the
source is achieving the required emission reductions.
11
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12
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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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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
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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. 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 decision 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
15
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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.
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 promulgated rule. Emission levels of other
air pollutants (CO, NOX, and SO2) were not quantified. Baseline
16
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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. promulgated rule.
TABLE 3-1.
NATIONAL BASELINE VOC AND HAP EMISSIONS BY EMISSION
POINT
Baseline Emissions (Mg/yr)
Emission Point
Miscellaneous Process Vents
Equipment Leaks
Storage Vessels
Wastewater Collection and
Treatment
TOTAL
HAP
10,000
52,000
9,300
10,000
81,300
VOC
109,000
189,000
111,000
10,000
419,000
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.
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
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result in adverse health and welfare impacts to human
populations.
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 is considered to be a group C or a possible human
carcinogen. For this chemical,.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 this
chemical 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. These other adverse health effects
are listed in Chapter 8 of this RIA.
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.
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TABLE 3-2. BASELINE SPECIATED HAP EMISSIONS FROM EQUIPMENT LEAKS
Hazardous Air Pollutant
2, 2, 4-Tritnethylpentane
Benzene
Ethylbenzene
Hexane
Naphthalene
Toluene
Xylenes
Hydrogen Fluoride
Phenol
Cresols
MTBE
Hydrogen Chloride
Methyl Ethyl Ketone
TOTAL
Baseline
Emissions
(Mg/yr)
6,497
2,190
2,734
6,309
1,540
9,256
8,737
3,178
1,429
693
6,716
229
2,435
51,943
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3.4 CONSEQUENCES OF REGULATORY ACTION
This section provides an 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 energy use
impacts resulting from the control of HAP emissions under the
promulgated rule. (Economic impacts will be presented in Chapter
6.) It is estimated that approximately 173 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
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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 promulgated rule, it is estimated that the emissions of HAP
from refineries would be reduced by 48,000 Mg/yr, and the
emissions of VOC would be reduced by 252,000 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 for CO, NOX,~
and SO2 may result from the combustion of fossil fuel as part of
additional control device operations refineries undertake to meet
the requirements of this NESHAP. 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.
3.4.1.3 Costs and Benefits. The cost impact of the rule
includes the capital cost of new control equipment, the
associated operation and maintenance cost, and the cost of
monitoring, recordkeeping, and reporting. Generally, the cost
impact also includes any cost savings generated by reducing the
loss of valuable product in the form of emissions.. Under the
promulgated rule, it is estimated that total capital costs would
be $213 million (first quarter 1992 dollars) and total annual
costs would be $79 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.
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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 Capital
Costs
(Million
Dollars)
21.0
142.0
48.0
a
Total Annual
Costs
(Million
Dollars)
12.0
58.0
,8.0
a
Other recordkeeping
and reporting
TOTAL
2.0
213.0
1.0
79.0
NOTES: 'The MACT level of control is no addftionaF control.
3.4.1.4 Energy Impacts. Increases in energy use were
estimated for operating control equipment that would be required
by the promulgated standards (compressors for ducting
miscellaneous process vent streams to control devices). The
estimated energy use increase in the fifth year would be
48 million kw-hr/yr of electricity or 77.5 thousand 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 for their construction
and operation. State regulations will also be uniform, and the
disadvantages of the piecemeal approach to emission regulation
will be avoided.
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3.4.1.6 Other Federal Programs. The regulations which
affect the petroleum refining industry that 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.
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Unless States respond by allocating more resources into
enforcement, then poor 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 promulgated 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
promulgated 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 promulgated
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 have been present in or added to the inlet stream, can be
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used to preheat the 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.
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 is a refractory-lined chamber
containing a burner or set of burners at one end. Entering gases
are mixed with the process vent streams and the inlet air in a
premixing chamber. Then the stream of gases passes into the main
combustion chamber. This chamber is designed to allow the
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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 (LEL) 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 stoichiometric 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
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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 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
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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 regenerative'
incinerator. This type of incinerator uses direct contact heat
exchangers constructed of a ceramic material that can 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
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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 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
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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 between the gas and catalyst is a
fluid-bed. Fluid-beds have the advantage of very high mass
transfer rates, although the overall pressure drop is 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,
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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 CO2 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.
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
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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.
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
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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 (particulate 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.
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-Assis ted 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
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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. They have multiple burner heads that are staged
to operate 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
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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 vent
stream alone (when a separate burner is used).
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.
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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 reboilers
to 1,260 degrees Celsius for pyrolysis furnaces. Tests conducted
by EPA on process heaters using a mixture of benzene offgas and
natural gas showed greater than 98 percent destruction efficiency
for Cx 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
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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.
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 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
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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 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, viscosity, density, and concentration
of the VOC in the inlet vent stream (all of which depend on
column temperature); the total 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
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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 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 intermolecular (van der
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
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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 a wide range of flow rates, ranging up to
several thousand cubic meters per minute (100,000 scfm). VOC
concentrations in streams that can be treated by fixed-bed units
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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
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concentration of VOCs in the vapor phase, desorbing the VOCs from
the carbon surface to the vapor phase.
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.
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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 displaced by the heavier compounds, greatly reducing 'system
efficiency.
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
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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. The combined stream
creates a wastewater with potential for air emissions.
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.
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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 yapor pressures.
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.
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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, systems process valves, connectors, and
instrumentation systems.
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
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around the shaft. Coolant is required to remove the frictional
heat between the packing and shaft. The necessary lubrication is
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.
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Canned-motor pumps have interconnected cavity housings, motor
rotors, and pump casings. Because the process liquid is the
bearing lubricant, abrasive solids in the process 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.
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This seal is formed by a film of oil between the rotating shaft
and stationary gland.
4.1.3.3. 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
leak emissions from spring-loaded relief valves may be caused by
failure of the valve seat or valve stem, 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.
4.1.3.4 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
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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.
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
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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.
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
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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
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
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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.
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
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higher than a specified figure ("action level"), then the leaking
component is marked for repair.
4.1.3.9.2 fiepair 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.
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 may be required upstream of the relief 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
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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 r'oof tanks
as well as fixed roof tanks vary with the vapor 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.
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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
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
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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 se'am 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 gaskets for bolted metal
deck seams.
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.
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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, yapor 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.^
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, among other
things, the cost of achieving such additional emission
reductions. The options for achieving reductions at each
62
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emission point are 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 and chosen
alternatives as they relate to miscellaneous process vents and
how -they were arrived at. The EPA evaluated the current level of
control for miscellaneous process vents in eight State and two
air districts that contain the majority of refineries and were
expected to have the most stringent regulations. Of the
refineries in the U.S., the 12 percent that are subject to the
most stringent regulations are located in three States. In these
three States, miscellaneous process vents emitting greater than.
15 to 100 Ib/day (6.8 to 44.4 kg/day) of VOC are required to be ~
controlled. The median applicability cutoff level for the 12
percent of U.S. refineries subject to the most stringent
regulations is 72 Ib/day (33 kg/day) VOC. Thus, control of
process vents with VOC emissions greater than 72 Ib/day is the
MACT floor level of control for existing sources and is the
standard for miscellaneous process vents. The primary organic
HAPs at refineries are also VOC. Additionally, a VOC-based
applicability criteria is most reflective of the current level of
control required for miscellaneous process vents as the majority
of State regulations are expressed in terms of VOC. Therefore,
the EPA has adopted this emission level in the final rule to
distinguish Group 1 from Group 2 vents. Group 1 vents, those
that emit over 33 kg/day, must be controlled, whereas Group 2
vents, representing all other vents, are not required to apply
controls under the final rule. The applicability limit is
determined as gases exit from process unit equipment and not
downstream from an emission control device. The new source MACT
floor also includes reduction of emissions from miscellaneous
process vents with the same cut-off.
4.2.2 Storage Vessels
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This section summarizes the MACT floors and chosen
alternatives 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 CPR 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 MACT floor
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)
(1.5 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 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)
64
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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 and chosen
alternatives for wastewater streams. The alternative selected 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 in place to comply
with the BWON. These systems control not only benzene, but also-
the other organic HAPs in petroleum 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 compounds that are very similar to benzene in terms
of both chemical structure and volatility (from the water phase
to the air phase).
Because the final 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 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
65
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because the additional emission reduction achieved through
further control was not significant, given the associated costs.
The floor alternative was selected as the promulgated 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 and chosen alternatives
for equipment leaks. The Petroleum Refinery 'NSPS requirements
(40 CFR part 60 subpart W) is the MACT floor for existing
sources. In the final rule, EPA is providing each existing
refinery with a choice of complying with either: 1) The
Petroleum Refinery NSPS equipment leak requirements mentioned
above or 2) a modified verison of the negotiated rule (40 CFR
part 63 subpart H). The modified negotiated regulation is the
same as what was contained in the proposed petroleum refinery
NESHAP, except that the compliance dates have been extended.
Although not required in the final rule, the EPA promotes use of
the modified negotiated rule option because it is believed to
provide considerable product, emissions, and cost savings to a
refinery.
Under either option, existing refineries will be required to
implement an LDAR program with the same leak definitions (10,000
ppm) and the same leak frequencies as contained in the NSPS by 3
years after promulgation. A refinery may opt to remain at this
level of control and do the monitoring, recordkeeping, and
reporting specified in the NSPS. This option allows refineries
that are familiar with the Petroleum Refinery NSPS to continue to
implement that standard without needing to change their
procedures.
Alternatively, a refinery may choose to comply with Phase I of
the negotiated rule (10,000 ppm leak definition) 3 years after
promulgation, comply with Phase II 4 years after promulgation,
and comply with Phase III 5 1/2 years after promulgation. Each
phase has lower leak definitions for pumps and valves.
66
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For new sources, EPA requires refinery sources to meet the
same requirements as for existing sources.
4.2.5 Summary of Alternatives
Based on the determination of the MACT floor for each of the
four emission points, EPA selected a regulatory alternative.
Alternative 1, the regulatory alternative selected, incorporates
MACT floor level control for wastewater streams, storage vessels,
and miscellaneous process vents, and the floor for equipment
leaks. Table 4-1 presents a summary of the alternative examined
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 controller 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 causes real costs to others. The fact that producers,
consumers, and others whose activities result in air 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.
67
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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 the Agency to establish emission standards,
and if EPA fails to do this, the burden falls on the States to
develop and implement measures to attain and maintain such
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) 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 such a C/E
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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:
PERMITS
SUBSIDIES, FEES, AND MARKETABLE
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.3 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
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variations in emissions trading programs are possible. The
common idea in such programs is to allow sources with low
abatement cost 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,
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facilities' costs of control should fall. Thus, the costs
calculated could be an overestimate.
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REFERENCES
4.
5.
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.
U.S. Environmental Protection Agency. Office of Air
Quality Planning and Standards. Draft Preamble for the
HON. December 1993.
U.S. Environmental Protection Agency. Office of Air
Quality Planning and Standards. Draft Preamble for the
Petroleum Refinery NESHAP. January 1994.
Reference 2.
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 option 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) development and assignment of scaling factors for each kind
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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 promulgated standards
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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 that would
be observed at any particular refinery. However, they do provide
a 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.
5.1.1 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.
5.1.1.1 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
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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
group per barrel of crude capacity at a refinery was the tank
population factor. For example, 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 ,
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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 10"5 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 HAP weight fractions were calculated from the
HAP 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
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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 rim mounted
secondary seal is 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 BSD 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.
5.1.1.2 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
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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.
(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., wastewater 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.
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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 (e.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.
5.1.1.3 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 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
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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
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Document" (in the docket) provides information on the control
efficiencies that may be achieved by 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).
5.1.1.4 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
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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 "Summary of Nationwide Volatile
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.
5.1.2 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
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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 points using the same 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.
5.1.2.1 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 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
overe s t imat ed.
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5.1.2.2 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 to the 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.
5.1.2.3 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)
87
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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.
5.1.2.4 Miscellaneous Process Vents. The MA.CT 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 refinery. The
average capital cost for piping for each vent 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.
88
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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 chosen alternative. The total national cost of
Alternative 1 in the fifth year is $79 million. Table 5-2
presents the costs, HAP emission reductions, and cost
effectiveness for the control options by emission point. The
average cost effectiveness of the regulation ($/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 the chosen regulatory alternatives. The emission reductions
associated with the alternatives 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.
89
-------
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TABLE 5-3. COST, HAP EMISSION REDUCTION, AND COST EFFECTIVENESS BY
ALTERNATIVE
Regulatory,
Alternative
Alternative 1
HAP
Emissions
(Mg/Yr)
Annual Cost
Reduction (Million $,
1992)1
48,000 $79.0
Cost Effectiveness
($/Mg)
Average Incremental
$1,645 N/A
NOTES: N/A = Not applicable.
estimates do include costs associated with monitoring, recordkeeping, and reporting requirements.
TABLE 5-4. COST, VOC EMISSION REDUCTION, AND COST EFFECTIVENESS BY
ALTERNATIVE
Regulatory
Alternative
VOC Emission
Reduction
(Mg/Yr)1
Annual Cost
(Million $,
1992)
Cost Effectiveness
($/Mg)
Average Incremental
Alternative 1
252,000
$79.0
$313
N/A
NOTES: N/A = Not applicable.
Emission reduction estimates do not incorporate reductions occurring at new sources.
93
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5.3 MONITORING, RECORDKEEPING, AND REPORTING COSTS
In addition to provisions for the installation of control
equipment, the promulgated regulation includes provisions for
MRR. EPA estimates that the total annual cost for refineries to
comply with the MRR requirements is $20 million. After
incorporating MRR costs, the total cost of compliance of
Alternative 1 is $79 million. For Alternative 1, the
incorporation of MRR costs into total annual cost results in an
average cost effectiveness of $313 for each megagram of VOC
reduced and $1,645 for each 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 $34 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.
94
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The MRR requirements are outlined separately in the regulation
for each emission point. The 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 promulgated 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 MRS. 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.
95
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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 one valuable criterion 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. This report will examine primary market impacts
resulting from the control measures including changes in the
market equilibrium price for refined petroleum products, output
levels for products produced and sold nationally, value of
domestic shipments or revenues for refineries in the industry,
and plant operations. 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 (employment effects), energy input market
changes (changes in the energy used as an input in the production
of petroleum products) and foreign trade effects (change in net
exports). Control measures may also influence the capital
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availability and financial position of firms in the petroleum
refining industry. Welfare changes for consumers, producers, and
society at large or the social costs of the proposed emission
controls will also be evaluated. 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 (1995). 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.
It should be noted that the economic impact analysis reflects
the compliance costs from the proposal. Thus the actual impacts
are smaller than estimated here, though only by a minor amount.
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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 (1995) and Industry Profile of the
Petroleum Refinery NESHAP (1993).
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
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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 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 one company's premium gasoline and another's — 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 •
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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 the products in this
analysis is treated as a separate product with its own share of
the market. From a refinery standpoint, however, if the
production of one refined product 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 were 192
operable petroleum refineries in the United States as of January
1, 1992.-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
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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, which continued through 1992. A record
number of U.S. refineries were operating in 1981. A decline in
petroleum demand in the early 1980s caused many small 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
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no
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,
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 a
measure of the output of the largest firms in the industry,
expressed as a percentage of total national output. Market
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
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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 only one refinery each. These are the
smaller independent firms. The major firms operate several
refineries, and the largest, Chevron, operates 13. Fourteen
firms operate four or more refineries each.
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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
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by a shift in product slates to gasoline and jet fuels, the
decrease in crude oil prices, 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
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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.
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
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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 only by
substituting a more expensive process. Firms will typically
utilize sufficient crude oil to fill the appropriate processing
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.
112
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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, the motor gasoline and jet fuel
markets are associated with the transportation sector. The
markets for distillate fuel oil are associated with the
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
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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 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 2010.1:L
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.
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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 time since
1980 that demand for all major petroleum products fell
simultaneously in the same year. In this case, decreased demand
was brought on by warmer 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
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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 mainly attributable to the fluctuations in the
global market for crude oil and the inelastic demand for
petroleum products. 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
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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.18 (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 prices.
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
' 117
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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. The'U.S. Department of Commerce
(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
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product demand is attributable to the transportation sector,
projected demand growth for motor gasoline will 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
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-
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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.
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 final 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
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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:
QD - «Pe
Q" =
QS' = pP*
QD = Qd + Qf =
where:
Q
0° =
sd
QS
p =
e =
Y =
Oi, ft,
annual output or quantity of petroleum products
purchased and sold in the United States
quantity of the petroleum products domestically
demanded annually
quantity of the products produced by domestic
suppliers annually
quantity of the products produced by foreign
suppliers annually
price of the petroleum product
price elasticity of demand for the product
price elasticity of supply for the product
and p are parameters estimated by the model.
The constants a, /3, 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
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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 :
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 • Q) - (V + D)] (1 - t) * D ^k
S
where:
C
Q
V
t
S
D
increase in the supply price
output
measure of annual operating and maintenance control
costs
marginal corporate income tax .rate
capital recovery factor
annual depreciation (assumes straight line
depreciation)
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:
Estimates of the annual operation and maintenance control
costs and of the investment cost of emission controls (V and k,
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c =
~ D
v + D
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:
S-
[(1 + r)M]
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 an assumption that likely
causes overestimates of impacts and may not be the case in
reality. Based upon this assumption, the post-control supply
function becomes the following:
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where:
C (C£,g.£) = a function that shifts the supply function to
reflect control costs
C± « 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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01
a
o
5
a_
03
01
i
u_
O
CD
UJ
DC
i
UL
a
a
125
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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 Q-L, respectively) to the pre-control
equilibrium (P0 and Q0) . The change in value of domestic product
is simply the difference in the industry revenue (Px * Q]_) 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-L,Q-L) 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
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will depend on the magnitude of the changes for imports relative
to exports. The following functions are used to compute the trade
impacts:
- (P0
where:
AVJM
change in the volume of imports
change in the dollar value of imports
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 AQxsd - AQsf. 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 AVX - AVJM.
6.2.5 Changes in Economic Welfare
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Regulatory control requirements will result in changes in the
market equilibrium price and quantity of petroleum products
produced and sold. These changes in the 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, ACSd, 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, ACSd 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
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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/(l-t) dollars.
Output eliminated as a result of control costs cause producers
to suffer a welfare loss in producer surplus. Refineries
operating in the post-control market 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 riot 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 (Ci) that reflects after-tax control costs and is
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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 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 (ARS).
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
APS
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
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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 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 final 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
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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 (1995) .
Two data inputs crucial to the estimation of partial
equilibrium are the price elasticity of demand and the price
elasticity of supply. The price elasticities of supply and
•demand are 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
responsive to changes in the price of the product (percent
quantity decrease exceeds percent price increase) while products
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
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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 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.
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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
curr'ent 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 (1995).
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.
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
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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 n± 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)± 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 (pro!) is calculated as follows:
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proi =
1990
£ n>
(=1986
1990
£ «•! /5 + *
i-1986
•100
where:
prod.
the post-control return on investment
the change in income before interest resulting from
implementation of emission controls for firms in the
sample
capital expenditures associated with emission
controls.
The equation pro! 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
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pay annual interest obligations. The pre-control measure of
coverage ratio is as follows:
6 interest^ I
where:
tc = number of times earnings will pay annual interest
charges
ebit = earnings before interest payments and taxes
inter est^ = annual interest expense
Post-control coverage ratios may be estimated as follows:
ptc =
1990
i = 1986
ebitt I 5 + A ebit
T-^ I
2J interest,. / 5 + A interest
{'=1986 )
where:
AeJbit
Ainteresti
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 (A^C) 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:
d/e = debt equity ratio
137
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die =
1990
d = debt capital
e » equity capital
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:
pdle =
d1990
1990
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 conservative
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
138
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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 scenario that overstates the negative
impact of the emission controls on the financial operations of
the petroleum refining industry.
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
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of interest. These products represent less than 100 percent (to
be exact, 93 percent) of the refined petroleum products produced
domestically. It is not possible to assign compliance costs to
every petroleum product due to the lack of data on certain
products produced in low quantity, so a decision was made to
assign all the costs to the five products produced in the
greatest quantity.
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.-
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 (1995) 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.
140
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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.
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
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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 a choice of
controls allowed refineries is 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.
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 in production costs. Since the
control costs vary for each of the domestic refineries, the post-
control supply curve is segmented, or'a step function.
Underlying production costs for 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
142
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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 price increase for each product is
less than 1 percent and they 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 0.2,4 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 $12 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 for inelastic goods, all 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.
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TABLE 6-2. SUMMARY OF PRIMARY IMPACTS
Estimated Impacts
Refined Product
Price
Increases3
Production
Decreases2
Value of
Domestic,
Shipments-
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)
(0.24%)
$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.
1Prices 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.
144
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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 between 0 and 7 refineries are at risk
of closure as a result of the decrease in production predicted by
the .model, with the actual number likely being closer to 0 than
7. 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 an assumption that likely overstates the
the likely number of plant closures and other adverse effects of
the 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 Capi tal Availabili ty Analysis
The capital availability analysis involves examining pre- and
post-control values of selected financial ratios. These ratios
145
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include rate of return on investment, times interest 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
Rate of return on
investment
Coverage Ratio (or
Times Interest
Earned)
Debt-Eouitv Ratio
Pre-Control Ratios Post-Control Ratios
5.91%
7.08
62.75%
5.91%
7.07
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
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The estimated labor impacts associated with the NESHAP are
based on the results of the partial equilibrium analyses of the
five refined petroleum products and are reported in Table 6-4.
The number of workers employed by firms in SIC 2911 is estimated
to decrease by approximately 0 to 114 workers as a result of the
proposed emission controls, using the assumptions made in the
economic analysis with regard to the behavior of per-unit cost.
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 and
from additional monitoring, recordkeeping, and reporting
requirements have not been included in the analysis are not
considered in the labor impact estimate. 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 annually is relatively low compared to
the total employment in the industry (a 0.16 percent loss at
most). 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. If the gains from employment could have been
considered in the analysis, then the predicted loss in employment
would be less.
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
147
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maintaining emission control equipment. Insufficient data were
available to consider such changes in energy costs.
148
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TABLE 6-4. SUMMARY OF SECONDARY REGULATORY IMPACTS
Estimated Impacts
Refined Product
Labor Input1
Energy Input'
Motor gasoline
Amount
Percentage
Jet fuel
Amount
Percentage
Residual fuel
Amount
Percentage
Distillate fuel
Amount
Percentage
LPGs
Amount
Percentage
Total five products
Amount
(52)
(0.22%)
(6)
(0.13%)
(15)
(0.50%)
(25)
(0.26%)
(16)
(0.25%)
(0-114)
(0-0.16%)
($5.79)
(0.22%)
($0.52)
(0.13%)
($0.71)
(0.50%)
($2.27)
(0.26%)
($1.56)
(0.25%)
(0-$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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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
likely cause the trade deficit to increase. Net exports are
likely to decline by 2.3 million barrels per year, a 1.2 percent
decline. The range of net export decreases vary from 0.21
million barrels to 0.91 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. Between 0 and 7 refineries are
estimated to close nationwide, with the point estimate likely
closer to 0 than 7. 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
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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. The economic analysis estimates that between 0 and 7
refineries may close as a result of the emission controls, with
the point estimate of the range likely being closer to 0 than 7.
As to the estimated secondary economic impacts, between 0 and
114 job losses may occur nationwide, given the effects on labor
that are considered in the analysis. Energy input reductions are
estimated to be approximately $11 million annually. A decrease
in net exports of 2.3 million barrels, a decrease of 1.24
percent, annually in refined products is anticipated to occur.
No regional impacts are expected.
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%)
(l.-41%)
(0.81%)
(40.92%)
(0.54%)
(1.24%)
Dollar Value
of Net Export
Change^
($21.92)
($8.14)
. ($16.81)
($12.67)
($8.68)
($68.22)
NOTES: {) indicates decreases.
1 Millions of barrels.
Millions of dollars ($1992).
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6.7 POTENTIAL SMALL BUSINESS IMPACTS
6.7.1 Introduction
The Regulatory Flexibility Act (RFA) of 1980 and EPA
Guidelines for Regulatory Flexibility Analyses (1992) require
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; the Guidelines require that a final Regulatory
Flexibility Analysis be done if any impact on small entities
occurs. The analysis used four criteria provided in the original
Federal Guidelines for Regulatory Flexibility Analyses (1982). A
substantial number is considered to be greater than 20 percent of
the small entities identified. The following criteria are
provided for assessing whether 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.
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6.7.2 Me thodology
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.
The closure method of analysis will focus on the number of
petroleum refineries expected to close as a result of the
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 firm 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 firm must also be unaffiliated with
another large business entity to be classified as small.
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 between 0 and 7 refineries are at risk of
closure, with the actual number likely closer to 0 than 7. The
upper end of the 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
153
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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 promulgated
regulations.
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 (ACSd) ,
the change in producer surplus (APS), and the change in the
154
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residual surplus to society (&.RS) resulting from the 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 (1995). The economic costs of
Alternative 1 (the set of chosen alternatives) 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.
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
Change in Producer Surplus
Change in Residual Surplus to Society2
Total Social Cost of Alternative I3
$342.86
$(174.32)
$ (73.25)
$95.29
NOTES: 1 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.
3Alternative 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.
155
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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.
156
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15. U.S. Department of Commerce. Petroleum Refining — U.S.
Industrial Outlook 1991. Washington, DC. January 1991.
16. Reference 2.
17. U.S. Department of Energy. Annual Energy Outlook, 1992.
DOE/EIA-0383(92). Energy Information Administration.
Washington, DC. January 1992.
18. Reference 15. .
19 . Reference 4.
20. Reference 2.
21. Henry Lee and Ranjit Lamech. The Impact of Clean Air Act
Amendments on U.S. Energy Security. Harvard University.
Energy 93-01. Cambridge, MA. 1993.
22. Reference 2.
23. Reference 15.
24. Reference 17.
25. Reference 15.
26. National Petroleum Council. Estimated Expenditures by
Petroleum Refineries to Meet New Regulatory Initiatives
Air Quality. For presentation at the 86th Annual Air &
Waste Management Association Meeting. Denver, CO. 93-WA-
78A.03. June 13-18, 1993.
27. U.S. Department of Energy, Short-term Energy Outlook, Vol.
II. DOE/EIA-0202/42. Energy Information
Administration.Washington, DC. August 1980.
28. Robert S. Pindyck and Daniel L. Rubinfeld. Microeconomics.
MacMillan Publishing Company. 1989.
29. American Petroleum Institute. Financial Trends for Leading
U.S. Oil Companies 1968-1990. Discussion Paper #017R.
Washington, DC. October, 1991.
157
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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 improving environmental quality. In this
chapter, and the two chapters which follow, information is
provided on the types and levels of social benefits anticipated -
from the petroleum refinery NESHAP. This chapter examines the
potential health and welfare benefits associated with air emis-
sion reductions projected as a result of implementation of the
petroleum refinery NESHAP. The final 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 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.
This chapter provides a general discussion of the various
components of total benefits that may be gained from a reduction
in HAPs through the subject NESHAP. HAP benefits are presented
separately from the benefits associated specifically with VOC
emission reductions.
159
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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 reduced exposure to VOCs. 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. 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 the ambient
160
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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 and noncancer
endpoints.
161
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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 is 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
this chemical 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
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 these HAPs, there are limited data on animal
carcinogenicity, but no data on human carcinogenicity. Data are
currently inadequate to quantitatively estimate possible cancer
risks associated with cresol exposure.
The remaining HAPs emitted by equipment leaks at refining
sites have not been shown to cause cancer. 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 irritation. 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.
164
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Irritation, for the purpose of this document, refers to any
effect which results in irritation of the eyes, skin, and
respiratory tract.14
There are particular noncancer effects in humans associated
with exposure to several of these HAPs. Brief exposure to HCl
can cause ulceration of the respiratory tract; brief exposure to
phenol can cause mortality; and brief exposure to HF can cause
severe respiratory damage, n-hexane can cause polyneuropathy
(muscle weakness, numbness), and naphthalene's noncancer effects
include cataracts and anemia in humans.
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.
165
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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 to the formation of tropospheric 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.16 To the extent that
these findings are verified, the potential scope of benefits
166
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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 chronic health impacts of ozone exposure, there are
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 with exposure to ozone. The observed impacts
range from foliar injury to reduced growth rates 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.
167
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REFERENCES
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12,
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.
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.
U.S. Environmental Protection Agency. Cancer Risk from
Outdoor Exposure to Air Toxics. Volume I. EPA-450/1-90-
004a. Office of Air Quality Planning and Standards.
Research Triangle Park, NC. September 1990.
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.
Reference 4.
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.
Reference 4.
Reference 6.
Cote, I., L. Cupitt and B. Hassett. Toxic Air Pollutants
and Non-Cancer Health Risks. Unpublished paper provided
by B. Hassett. 1988.
NAS. Chlorine and Hydrogen Chloride. National Academy of
Sciences, National Research Council. Chapter 7. 1975.
Stern, A. et al.
Press, New York.
Fundamentals of Air Pollution. Academic
1973.
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). Eco-
168
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REFERENCES (continued)
13.
14.
15.
16.
17.
•5no "•"« ?roblems and Approaches. Chapter 7 r>™
-209. Springer-Verlag, New York. 1989 PP'
Reference i. p. 3-5.
Reference 1. pp. 8-4 to 8-5
Reference 4.
Reference 1. pp. 8-8 to 8-9.
169
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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 promulgated regulation and one
alternative more stringent than that.
8.1 METHODOLOGY FOR DEVELOPMENT OF BENEFIT ESTIMATE
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 the specific HAPs emitted by 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 estimate specific 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 estimate of cancer risk related to
petroleum refinery emissions.
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
170
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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 the emissions of several HAPs that have been classified as
probable or known human carcinogens. As a result, one of the
benefits of the final regulation is a reduction in the risk of
cancer mortality.
TABLE 8-1. HAP EMISSIONS AT PETROLEUM REFINERIES
2,2,4 - Trimethyl Pentane
Benzene
Ethylbenzene
Hexane
Naphthalene
Xylenes
Phenol
Cresols/Cresylic Acid
Methyl Tertiary Butyl Ether
Methyl Ethyl Ketone
Toluene
171
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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 risk.
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 A 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 (/xg/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 HAPs. 1 Among the HAPs
identified in Table 8-1, only benzene has a quantitative URFs.
In addition, benzene is a known human carcinogen, as there are
several studies linking benzene exposure to cancer in humans.
Cresols are considered possible human carcinogens based on animal
experiments.
To translate lifetime individual risk to annual incidence of
excess cancer, it is necessary to combine three pieces of data:
the unit risk factor, the (constant) level of concentration to
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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 1
-------
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 between income and risk reduction.
• 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.
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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 animals.
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.
• For carcinogens as well as other toxicants, there is a
great deal of individual variability in sensitivity to
adverse effects. In some cases, the suceptibility of an
individual's reaction to a toxic pollutant may be an order
of magnitude of greater than another's. This increaes the
uncertainty of cancer risk estimates at both the
individual and population level.
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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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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 from reduced
cancer mortality for this standard is $3-7 million.
8.1.1.3 Quantitative Results. Emissions of benzene 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 (benzene only, in this case). Benzene's
URF is presented in Table 8-4.
Table 8-4. UNIT RISK FACTORS FOR CARCINOGENIC HAPS
IHAP
Benzene
URF (x 106)
8.3 1
The HEM uses the URF 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).
Runs using the HEM showed that 4.5 million people exposed to
refinery HAP emissions within a 50 km radius of refineries have
an individual risk greater than 1 * 10'6. If the risk from any
source in a source category is greater than that, then the source
category must be listed on the list of source categories in
section 112(b) of the Clean Air Act.
The maximum- individual risk (MIR) and annual cancer incidence
for benzene are presented in Table 8-5. The MIR 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 baseline only. The annual cancer incidence is
the number of new cancer cases estimated to occur in the exposed
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population in a year. As estimated in the HEM, the total annual
cancer incidence of the HAP is 0.33 of a statistical life. The
benefits of reducing cancer risk resulting from reduced emissions
of carcinogenic HAP 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 promulgated rule would
decrease benzene emissions to zero, then a monetary estimate of
the benefit of reducing this HAP could be calculated. The
benefit of eliminating the carcinogenic HAP emissions is
calculated by multiplying the 0.33 reduction in total annual
cancer risk by the midpoint of the range of values of a
statistical life ($3-$7 million), which is $5 million. This
calculation yields a total monetary benefit of $1.50 million.
This is biased upwards, however, because 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
Benzene
MIR
1.8 * 10'4
Annual Cancer Incidence
0.33
These monetary values should be interpreted carefully due to
uncertainties in the derivation of annual incidence numbers, the
value of statistical life estimates, and the focus on equipment
leak emissions. Because these uncertainties, it is not possible
to say whether these values are over- or under- estimates of the
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
and economic value. Unfortunately, such data are generally
unavailable. Therefore, it is currently not possible to conduct
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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 of the
positive impact of HAP emission reductions. 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 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, methyl
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 promulgated regulation. Only baseline exposure was
analyzed.
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Table 8-6.
RFCS AND NUMBER OF INDIVIDUALS EXPOSED AT OR ABOVE
RFC BY HAPS
HAP
Hexane
Hydrogen Chloride
Methyl Ethyl Ketone
Toluene
RfC (mg/m3)
0.2
0.07
1
0.4
Individuals Exposed
At or Above RfC
0
1,810
0
0
Epidemiological studies that 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 been estimated.
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 impact 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 largely
using the technique of "benefits transf-er." Benefits transfer
involves the use of benefit values obtained from another study to
represent benefits associated with the promulgated rule, with
appropriate adjustments. At a minimum, the adjustments must
address the differential impact in the severity of the regulation
as represented, for example, by changes in emissions or
concentrations. With this technique, the assumption is made that
benefits per ton of emission reduction 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
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final regulation. In 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
(megagram) 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 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 per year per ton VOC emission reduction.
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 nonattainment 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
non
report indicates that all health impacts are estimated for
-attainment areas only. Therefore, no health benefits are
associated with VOC emission reductions in attainment areas,
according to the report. This may provide additional
conservatism to the benefit values since there is recent evidence
181
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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 epidemiological 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 per ton VOC emission reduction.
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 "willingness-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 months of 1992.a The adjusted
dollar range in first quarter 1992 dollars is $72-4,539 per ton
VOC emission reduction.
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 that 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 corresponds to population densities in
nonattainment areas in the early 1980's. Since the cost analysis
is conducted for the fifth year following rule promulgation (the
year 2000), the benefit analysis should be conformable. There is
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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 that represents the percentage change in
population, between 1980 and 1999, in those nonattainment areas
with petroleum refineries as of 1995. 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 it 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 Abstract,b 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 nonattainment 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.
It should be noted that even though the population of those in
ozone nonattainment areas has fallen since the early 1980's,-VOC
emissions'as precursors to ozone formation have fallen also.
Thus, any adjustment to the benefit transfer ratio used in this
analysis must take into account the reduction in emissions as
well as any changes in air quality that have occurred since the
time of the data used in the OTA report. It is uncertain whether
the benefit transfer ratio would change significantly with such
adjustments.
8.1.2.2 Agricultural Yield Estimates. In addition to
valuing acute health effects, the OTA report also attempted to
value the effect that reduced VOC emissions would have on the
yield of crops. Ozone levels currently found in rural areas are
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linked with reduced growth rates and yields of crops such as
soybeans and oats. Lower VOC concentrations are expected to
reduce ambient ozone concentrations, which in turn will increase
crop yields. This category of benefits is primarily true for
areas, mostly rural, in ozone attainment that have refineries in
relative proximity, but it also applies in nonattainment areas as
well. The report estimated that an annual reduction of
approximately 11 million Mg of VOC would result in total annual
agricultural benefits ranging from $1.4 billion to $27 billion
while an annual reduction of approximately 5.7 million Mg of VOC
would result in total annual agricultural benefits of
approximately $77 million to $1.4 billion. These benefits
translate into an average benefit value per Mg of VOC emission
reduction of approximately $120 to $236 (first quarter 1992
dollars). To calculate the monetized benefits from improved
agricultural yields, a point estimate of $178 per Mg was used and
applied to both attainment and nonattainment VOC emission
reductions'.
8.1.2.3 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 the report 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 nonattainment cities while
14 million tons of VOC are predicted to be emitted in ozone
attainment areas. For the 35 percent VOC (nonattainment 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 nonattainment areas that result
from a 35 percent reduction in nonattainment area VOC emissions.
Implicitly, there is the assumption, derived from the OTA study,
that no health benefits occur in attainment areas. This also
184
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implies that the derivation of petroleum refinery health benefits
from VOC emission reductions should consider only those emission
reductions that occur at refineries in nonattainment 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 impacts are
associated with VOC emission reductions in attainment areas.d
Table ES-3 in the executive summary presents the baseline VOC
emissions, and the emission reductions for refineries in
nonattainment areas associated with each alternative.
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 nonattainment areas.
8.1.2.4 Benefit Estimates. The benefit transfer ratio range
for acute health impacts is estimated to be $25-1,574 (first
quarter 1992 dollars per megagram or 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 megagram. These ratios are to be multiplied by VOC
emission reductions.from petroleum refineries located in ozone
nonattainment area in order to estimate the VOC-related acute
health benefits of the petroleum refinery MACT. Also among the
benefits estimates is the estimate of benefits from increased
agricultural yields from reduced ozone concentrations, occurring
due to VOC emission reductions. Table 8-7 summarizes the results
of these calculations for the combination of options selected for
the four controlled emission points. Note, the floor option
for-each emission point type is statutorily mandated so that, in
effect, the floor options represent the minimum regulatory
requirements.
185
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Table 8-7.
QUANTIFIED BENEFITS OF VOC REDUCTIONS BY REGULATORY
ALTERNATIVE AND BENEFIT CATEGORY
(millions of 1992 dollars)
Alternative 1
Quantified Acute Health Benefits
Average
Range
Quantified Agricultural Benefits
Average
Range
108.48
3.4 - 213.5
44.9
30.3 - 59.5
Several qualifications should be noted in interpreted the
benefits values above. First, there is an implicit assumption of
a constant linear relationship between VOC emission reductions
and changes in ozone concentrations in nonattainment areas.
Second, as noted earlier, there may be other benefit types.
Reductions in VOC emissions that 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
benefits per metric ton are 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
186
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cost of the air emissions controls relative to the expected VOC
emission reductions attributable to the controls. 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, the set
of alternatives in the promulgated 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 $94 million annually. This regulatory
alternative is expected to result in a reduction of VOC emissions
of approximately 134,283 Mg annually in nonattainment areas.
Therefore, the incremental cost-effectiveness from baseline,
averaged across multiple emission points for nonattainment areas,
for alternative 1 is approximately $714/Mg. In other words, the
average cost of reducing each Mg required by alternative 1 is
$714.
187
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REFERENCES
7,
8
U.S. Environmental Protection Agency. Cancer Risk from
Outdoor Exposure to Air Toxics, Volume I. EPA-450/1-90-
004a. Office of Air Quality Planning and Standards.
Research Triangle Park, NC. September 1990.
Viscusi, W. Kip. "The Value of Risks to Life and Health."
Journal of Economic Literature, pp. 1912-1946. December
1993.
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.
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.
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 al (eds.)
Atmospheric Ozone Research and its Policy Implications.
Elsevier Science Publications. Amsterdam. 1989.
Horst, R.L., Jr. Personal communication with L. Chestnut.
January 26, 1994.
Reference 4, p. 107.
Portney, P. and J. Mullahy. "Urban Air Quality and
Chronic Respiratory Disease." Regional Science and Urban
Economics. Vol. 20. p. 407-18. 1990.
188
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9.0 COMPARISON OF BENEFITS TO COSTS
The goal of the RIA (or Economic Assessment) for the Petroleum
Refinery NESHAP is to provide economic and some engineering data
necessary for effective environmental policy making. 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 resources.
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 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 ecosystem benefits
have not been quantified due to limitations in data and
methodology.
The compliance costs of the regulatory alternatives are taken
from the capital costs and operating and maintenance costs for
each alternative (including MRR costs) obtained from the cost
analysis done by EPA. These estimates reflect engineering costs
of emission controls, not the economic costs to society. The
compliance costs estimates are a necessary input to the economic
analysis using the costs of the regulatory alternatives to
society. The economic effect of imposing compliance costs on the
petroleum refining markets and its consumers and producers is
obtained from a partial equilibrium model of the petroleum
189
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refining industry. The social costs of the controls include
potential economic costs to consumers of refined petroleum
products, producers of such 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 these
costs associated with the regulatory alternatives are subject to
the limitations noted in Section 6.4, Limitations of the Economic
Model.
Costs, both engineering (compliance) and social, for other
alternatives other than the chosen ones are not available here
due to limitations in resources and data. Table 9-1 depicts a
comparison of the benefits of the chosen alternative to the
social costs. There is an annual net benefit of $58.1 million
estimated from compliance with the promulgated standard, thus
providing some evidence of the desirability of the alternative.
A comparison of the net benefits for the alternative and the
incremental difference in net benefits between it and other
alternatives would be a way to determine if net benefits were at
least approaching a maximum. Due to cost information not being
available, this comparison cannot be drawn. According to the
analyses conducted for this RIA, the standard should provide net
benefits to society.
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Table 9-1. COMPARISON OF ANNUAL BENEFITS TO COSTS FOR THE
NATIONAL PETROLEUM REFINING INDUSTRY
NESHAP (MILLIONS OF 1992 $ PER YEAR)
Benefits
Social Costs
Benefits Less
Social Costs
Alternative
1
$153.4
$95.3
$58.1
NOTES:
( ) represent negative values.
191
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r
a.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.
b. Statistical Abstract, 1993, Table 704.
c. The emissions data in OTA do not reflect measured emissions.
Rather, they represent emissions on a typical nonattainment day
multiplied by 365. It is not clear from the OTA report how these
"nonattainment-day-eguivalent-annual emissions" are calculated
for attainment regions.
d. 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
increments at a higher level above the 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 benefit transfer calculation to the
nonattainment area data presented in the OTA report.
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TECHNICAL REPORT DATA
(Please read Instructions on reverse before completing)
1. REPORT NO.
EPA-452/R-95-004
2.
4. TITLE AND SUBTITLE
Regulatory Impact Analysis for the Petroleum
Refineries NESHAP
7. AUTHOR(S)
9. PERFORMING ORGANIZATION NAME AND ADDRESS
U.S. Environmental Protection Agency
Office of Air Quality Planning and
Standards
Air Quality Strategies and Standards
Division
Research Triangle Park, NC 27711
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
3. RECIPIENT'S ACCESSION NO.
5. REPORT DATE
August 1995
6. PERFORMING ORGANIZATION CODE
8. PERFORMING ORGANIZATION REPORT NO.
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
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 regulation. This
(RIA) was required because the proposal is economically significant
according to Executive Order 12866.
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
a. DESCRIPTORS
Control Costs
Industry Profile
Economic Impacts
Benefits Analysis
18. DISTRIBUTION STATEMENT
Release Unlimited
b. IDENTIFIERS/OPEN ENDED TERMS c. COSATI Field/Group
Air Pollution control
19. SECURITY CLASS (Report) 21. NO. OF PAGES
Unclassified 203
20. SECURITY CLASS (Page) 22. PRICE
Unclassified
EPA Form 2220-1 (Rev. 4-77) PREVIOUS EDITION IS OBSOLETE
-------
-------
TECHNICAL REPORT DATA
(Please read Instructions on reverse before completing)
i. REPORT NO.
EPA-453/R-95-OOY
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Impact Analysis for the Petroleum
Refineries NESHAP
5. REPORT DATE
August 1995
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
Air Quality Strategies and Standards
Division
Research Triangle Park, NC 27711
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
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
_ An economic analysis of the industries affected by the Petroleum
Refineries National Emissions Standard for Hazardous Air Pollutants
(NESHAP) was completed in support of this standard. The industry for
which economic impacts was computed was the petroleum refinery industry.
Affected refineries must reduce HAP emissions by the level of
control required in the standard. Several types of economic impacts
among them product price changes, output changes, job impacts, and
effects on foreign trade, were computed for the selected regulatory
alternative.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b. IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Control Costs
Industry Profile
Economic Impacts
Air Pollution control
8. DISTRIBUTION STATEMENT
Release Unlimited
19. SECURITY CLASS (Report)
Unclassified
21. NO. OF PAGES
150
20. SECURITY CLASS (Page)
Unclassified
22. PRICE
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