REGULATORY IMPACT

ANALYSIS FOR THE

PETROLEUM REFINERY

NESHAP

REVISED DRAFT FOR PROMULGATION

Office of Air Quality Planning and Standards

U.S. Environmental Protection Agency

Research Triangle Park, NC 27711

July 1995
ii

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. 
iii

CONTENTS

Page

TABLES . . . . . . . . . . . . . . . . . . . . . . . . . . vi

FIGURES . . . . . . . . . . . . . . . . . . . . . . . . . . vii

ACRONYMS AND ABBREVIATIONS . . . . . . . . . . . . . . . viii

EXECUTIVE SUMMARY . . . . . . . . . . . . . . . . . . . . ES-1

ES.1 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
CONTENTS (continued)

Page

iv

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 . . . . . . . . . . . . . . . . 111

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
CONTENTS (continued)

Page

v

6.3 CAPITAL AVAILABILITY ANALYSIS . . . . . . . . . . 134

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 REDUCTIONS159

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
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FIGURES

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6-1 ILLUSTRATION OF POST-NESHAP MODEL. . . . . . . 125
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ACRONYMS AND ABBREVIATIONS

API American Petroleum Institute

ASM Annual Survey of Manufactures

bbl One barrel; equal to 42 gallons

bbl/d barrels per day

BCA Benefit Cost Analysis

BWON Benzene Waste Operations NESHAP (NESHAP is 

defined below)

CAA Clean Air Act Amendments of 1990

C/E cost effectiveness

CERA Cambridge Energy Research Associates

DOC Department of Commerce

DOE/EIA Department of Energy/Energy Information

Administration

EIA economic impact analysis

EPA Environmental Protection Agency

FCCU fluidized catalytic cracking unit

HAP Hazardous Air Pollutant

HEM Human Exposure Model

HON Hazardous Organic NESHAP (NESHAP is defined

below)

IARC International Agency for Research on Cancer

kPa kilopascal

LDAR leak detection and repair

LEL lower explosive limit

LPGs Liquefied Petroleum Gases

lpm liter per minute

MACT Maximum Achievable Control Technology

MIR maximum individual risk

MRR monitoring, recordkeeping, and reporting

MTBE Methyl tertiary butyl ether

Mg Megagram

NAAQS National Ambient Air Quality Standard

NESHAP National Emission Standard for Hazardous Air

Pollutants

NSPS New Source Performance Standard

NOx nitrogen oxide

OGJ Oil and Gas Journal

OMB Office of Management and Budget

PADD Petroleum Administration for Defense Districts

ppmv parts per million by volume

RACT Reasonably Available Control Technology

RFA Regulatory Flexibility Act; also Regulatory

Flexibility Analysis

RfC reference-dose concentration

RIA Regulatory Impact Analysis 

SIC Standard Industrial Classification

SIP State Implementation Plan

SO2 sulfur dioxide

SOCMI Synthetic Organic Chemical Manufacturing industry

URF unit risk factor

VOC volatile organic compound
ES-1

EXECUTIVE SUMMARY

ES.1 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-2

(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-3

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
ES-4

represent the MACT floor to be applied to storage vessels. The

wastewater provisions of this rule are based on the benzene waste

operations NESHAP (BWON), which controls 75 percent of the

benzene in refinery wastewater. The wastewater streams subject

to this rule include water, raw material, intermediate product,

by-product, co-product, or waste material that contains HAPs and

is discharged into an individual drain system. The equipment

leak provisions of the 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
ES-5

represent an externality in that refinery operation imposes costs

on others outside of the marketplace. In the case of this type

of negative externality, the market price of goods and services

does not reflect the costs borne by receptors of the HAPs

generated in the refining process. With the NESHAP in effect,

the amount that refiners must incur to refine petroleum products

will more closely approximate the full social costs of

production. The necessity for a uniform national standard is

based on the determination that air pollution crosses

jurisdictional lines, and uniform national standards, unlike

potentially piecemeal local standards, will be more efficient to

both industry and government. 

ES.4 CONTROL TECHNIQUES AND REGULATORY ALTERNATIVES

The 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. 
TABLE ES-1. SUMMARY OF TOTAL COSTS IN THE FIFTH YEAR

FOR THE PETROLEUM REFINERIES NESHAP

Capital Costs and Annual Fifth Ye

(1992 Dollars)

Emission Point Option

Total

Capital

Costs

Existing

Sources

New

Construction To

Equipment LeaksMiscellaneousProcess VentsWastewaterSystemsStorage VesselsOtherRecordkeepingand Reporting

FloorOption 1

1

FloorFloor

1

Floor

1

$142,000

$21,000

$ 0

$48,000

$2,000

$69,000$58,000$12,000

$ 0

$8,000

$ 0

$(210)

$370

$ 0$98

$6$5$1

$

TOTAL COST $213,000 

NOTES:

1Alternative 1.
ES-7

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-8

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

$342.86

$(174.32)

$(73.25)

Total Social Cost of Alternative 13 $95.29

NOTES: 1Brackets 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. 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-9

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-10

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 nonattainment 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
ES-11

health benefits from VOC emission reductions were $108.5 million,

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

VOC Emission Reductions by

Regulatory Alternative (Mg/yr)3

Alternative 1

Emission Point2 Nonattainment1 Attainment

Equipment Leaks 56,601 69,052

Miscellaneous

Process Vents

76,426 47,438

Storage Vessels 2,256 1,227

TOTAL REDUCTION

BY ATTAINMENT

STATUS

134,283 117,717

TOTAL REDUCTION

FOR ALTERNATIVE 252,000
ES-12

1VOC 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.

TABLE ES-4. BENEFIT PER MEGAGRAM VALUES FOR VOC REDUCTIONS

Benefits Transfer Value1 1992 Dollars/Megagram2

Average $800

Range $25 - $1,574

1The 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,
ES-13

however. The net benefits to society are $58.1 million annually

from compliance with the standard.
ES-14

TABLE ES-5. COMPARISON OF ANNUAL BENEFITS TO COSTS FOR THE 

PETROLEUM REFINERIES NESHAP

(MILLIONS OF 1992 DOLLARS PER YEAR)

Alternative 1

Benefits $153.40

Social Costs $(95.29)

Benefits Less Social Costs $58.11

( ) represent costs or negative values.
1

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
2

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

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
3

the definition of source categories and emission points for

Section 112 standards.

Section 112 of the Act provides a list of 189 HAPs and directs

the EPA to develop rules to control HAP emissions. The CAA

requires that the rules be established for categories of sources

of the emissions, rather than being set by pollutant. In

addition, the CAA establishes specific criteria for establishing

a minimum level of control and criteria to be considered in

evaluating control options more stringent than the minimum

control level. Assessment and control of any remaining

unacceptable health or environmental risk is to occur 8 years

after the rules are promulgated.

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.
4

Chapter 4 identifies the control techniques and regulatory

alternatives which were considered for the standard. EPA's

designation of control options reflects the best control

technology available to refineries, given existing technology

levels. Chapter 5 presents the approach for estimating

regulatory compliance costs, the quantitative estimates of each

control option under analysis, and the issues and assumptions

upon which the estimates were based. The associated emission

reductions and cost effectiveness of the regulatory options are

also presented.

Chapter 6 provides an economic profile of the petroleum

refining industry, and describes the methodology used to estimate

the economic effects of a chosen hybrid option on the industry. 

Predicted price, output, employment, and closure impacts are

presented as well as a quantification of the social costs of the

regulatory option.

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
5

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.
6
7

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.
8

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, and leaks from equipment in organic

HAP service within catalytic cracking units, catalytic reforming

units, and sulfur plant units are similar to emission points from

the other process units at petroleum refineries. EPA determined

that it is most effective to regulate these emission points in a

single regulation, and all emission points regulated by the

subject NESHAP are in a single source category.

2.1.2 Miscellaneous Process Vent Provisions
9

Miscellaneous process vents include vents from petroleum

refining process units that emit organic HAP's. Vents that are

routed to the refinery fuel gas system are considered to be part

of the process and are not subject 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 lbs/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. 
10

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

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 (l/min) (0.005 gallons per
11

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

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 VV (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 VV 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,
12

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 VV 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

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
13

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

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. 
14
15

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.
16

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
17

Natural monopoly exists where a market can be served at lowest

cost only if production is limited to a single producer. The

refining industry is characterized by some of the same attributes

which define monopolistic markets, including economies of scale,

and barriers to entry due to the heavy up-front capital needed

for refinery construction. 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:

C Air pollution crosses jurisdictional lines.

C The people who breathe the air pollution travel freely,

sometimes coming in contact with air pollution outside

their home jurisdiction.

C Harmful effects of air pollution detract from the nation's

health and welfare regardless of whether the air pollution

and harmful effects are localized.
18

C Uniform national standards, unlike potentially piecemeal

local standards, are not likely to create artificial

incentives or artificial disincentives for economic

development in any particular locality.

C 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
19

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

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 HAP VOC

Miscellaneous Process Vents 10,000 109,000

Equipment Leaks 52,000 189,000

Storage Vessels 9,300 111,000

Wastewater Collection and

Treatment

10,000 10,000

TOTAL 81,300 419,000

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
20

these NESHAPs. Many HAPs are classified as known human

carcinogens. Other HAPs have not been classified as known human

carcinogens. Exposure to these pollutants, however, may still

result in adverse health 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.
21

TABLE 3-2. BASELINE SPECIATED HAP EMISSIONS FROM EQUIPMENT LEAKS

Hazardous Air Pollutant

Baseline

Emissions

(Mg/yr)

2, 2, 4-Trimethylpentane 6,497

Benzene 2,190

Ethylbenzene 2,734

Hexane 6,309

Naphthalene 1,540

Toluene 9,256

Xylenes 8,737

Hydrogen Fluoride 3,178

Phenol 1,429

Cresols 693

MTBE 6,716

Hydrogen Chloride 229

Methyl Ethyl Ketone 2,435

TOTAL 51,943
22

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
23

petroleum refining industry, an economically optimal situation is

approached. This is the situation in which the marginal cost of

resources devoted to petroleum refining equals the marginal value

of the products to the end users of the products. Although there

are uncertainties in this progression of impacts, in the

aggregate and in the long run, the NESHAP will move society

toward this economically optimal situation.

3.4.1.2 Emissions Reductions. The environmental impact of

the rule includes the reduction of HAP and VOC emissions. Under

the 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.
24

TABLE 3-3. NATIONAL CONTROL COST IMPACTS OF PREFERRED

ALTERNATIVE IN THE FIFTH YEAR

Emission Point

Total Capital

Costs

(Million

Dollars)

Total Annual

Costs

(Million

Dollars)

Miscellaneous Process Vents 21.0 12.0

Equipment Leaks 142.0 58.0

Storage Vessels 48.0 8.0

Wastewater Collection and

Treatment

Other recordkeeping 

and reporting

a

2.0

a

1.0

TOTAL 213.0 79.0

NOTES: aThe MACT level of control is no additional control.

3.4.1.4 Energy Impacts. Increases in energy use were

estimated for operating control equipment that would be required

by the 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.
25

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
26

legal delays, poor compliance can save some refineries money. 

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.
27

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.
28
29

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.
30

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 HCl 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
31

may have been present in or added to the inlet stream, can be

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
32

premixing chamber. Then the stream of gases passes into the main

combustion chamber. This chamber is designed to allow the

mixture enough time at the required combustion temperature for

complete oxidation (usually from 0.3 to 1.0 second). A heat

recovery section is often added to increase energy efficiency. 

Often, inlet combustion air is preheated; if this occurs,

insurance regulations require the VOC concentration must be

maintained below 25 percent of the lower explosive limit (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.
33

The maximum achievable VOC destruction efficiency decreases

with decreasing inlet VOC concentration because combustion is

slower at lower inlet concentrations. Therefore, a VOC weight

percentage reduction based on the mass rate of VOC exiting the

control device versus the mass rate of VOC entering the device is

appropriate for vent streams 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 shelland-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.
34

Occasionally it is desired to recover some of the energy added

by auxiliary fuel in the traditional thermal units (but not

recovered in preheating the feed stream). Additional heat

exchangers can be added to provide process heat in the form of

low pressure steam or hot water for on-site application. The

need for this higher level of energy recovery will be dependent

upon the plant site. The additional heat exchanger is often

provided by the incineration unit vendor.

A third type of thermal incinerator is the 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
35

such as chlorine, and sulfur. Among the catalysts that have been

developed that are effective in the presence of these halogens

are chromia/alumina, cobalt oxide, and copper oxide/manganese

oxide. Inert substrates are coated with thin layers of these

materials to provide maximum surface area for contact with the

VOC in the vent stream. Compounds containing elements such as

lead, arsenic, and phosphorus should, in general, be considered

poisons for most oxidation catalysts. In addition, particulate

matter, including dissolved minerals in aerosols, can rapidly

blind (deactivate) the pores of catalysts and deactivate them

over time. Because essentially all the active surface of the

catalyst is contained in relatively small pores, the particulate

matter need not be large to blind the catalyst.

For optimal operation, the volumetric gas flow rate and the

concentration of combustibles (in this case, VOCs) should be

constant. Large fluctuations in the flow rate will cause the

conversion of the VOCs to fluctuate also. Changes in the

concentration or 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
36

in two varieties, depending on the type of catalyst used: the

monolith and packed-bed. The monolith catalyst is the most

widespread method of contacting the VOC-containing stream with

the catalyst. In this scheme, the catalyst is a porous solid

block containing parallel, non-intersecting channels aligned in

the direction of the gas flow. Monolith catalysts offer the

advantages of minimal attrition due to thermal

expansion/contraction during startup/shutdown and low overall

pressure drop.

A second contacting scheme is a simple packed-bed in which

catalyst particles are supported either in a tube or in shallow

trays through which the gases pass. The tray type arrangement is

the more common packed-bed scheme due to the use of pelletized

catalysts. This tray arrangement is preferred because pelletized

catalysts can handle inlet streams containing contaminants such

as phosphorus or silicon. The tube arrangement is not used

widely due to its inherently high pressure drop compared with a

monolith, and the breaking of catalyst particles due to thermal

expansion when the confined catalyst bed is heated/cooled during

startup/shutdown.

A third contacting pattern 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
37

systems. This results from the constant abrasion of the

fluidized catalyst pellets, which helps remove these particulates

from the exterior of the catalysts in a continuous manner.

4.1.1.2 Flares. Flaring is an open combustion process in

which the oxygen necessary for combustion is provided by the air

around the flame. The organic compounds to be combusted are

piped to a remote, usually elevated, location and burned in an

open flame in the open air using a specially designed burner tip,

auxiliary fuel, and sometimes steam or air to promote mixing for

nearly complete (98 percent minimum) destruction of combustibles. 

Good combustion in a flare is governed by flame temperature,

residence time of organic species in the combustion zone,

turbulent mixing of the organic species to complete the oxidation

reaction, and the amount of oxygen available for free radical

formation. Combustion is complete if all combustibles (i.e.,

VOCs) are converted to 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., steamassisted, 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.
38

Cracking can occur with the formation of small hot particles

of carbon that give the flame its characteristic luminosity. If

there is an oxygen deficiency and if the carbon particles are

cooled to below their ignition temperature, smoking occurs. In

large diffusion flames, combustion product vortices can form

around burning portions of the gas and shut off the supply of

oxygen. This localized instability causes flame flickering,

which can be accompanied by soot formation.

Flares can be dedicated to almost any VOC stream, and can

handle fluctuations in VOC concentration, flow rate, heating

value, and inerts content. Flaring is appropriate for

continuous, batch, and variable flow vent stream applications.

Some streams, such as those containing halogenated or sulfurcontaining 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, autoignition 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
39

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 autoignition temperature will ignite more easily than a gas with a

high auto-ignition temperature.

The heat content of the vent stream is a measure of the heat

available from the combustion of the VOC in the vent stream. The

heat content of the vent stream affects the flame structure and

stability. A gas with a lower heat content produces a cooler

flame that does not favor combustion kinetics and is more easily

extinguished. The lower flame temperature will also reduce

buoyant forces, which reduces mixing.

The density of the vent stream also affects the structure and

stability of the flame through the effect on buoyancy and mixing. 

By design, the velocity in many flares is very low; therefore,

most of the flame structure is developed through buoyant forces

as a result of combustion. Lighter gases therefore tend to burn

better. In addition to burner tip design, the density also

affects the minimum purge gas required to prevent flashback, with

lighter gases requiring more purge.

Poor mixing at the flare tip or poor flare maintenance can

cause smoking (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
40

operating conditions. Up to 99.7 percent combustion efficiency

can be achieved.

4.1.1.2.1 Steam-Assisted Flares. Steam-assisted flares are

single burner tips, elevated above ground level for safety

reasons, that burn the vented gas in essentially a diffusion

flame. They reportedly account for the majority of the flames

installed and are the predominant flare type found in refineries. 

To ensure an adequate air supply and good mixing, this type of

flare system injects steam into the combustion zone to promote

turbulence for mixing and to induce air into the flame.

4.1.1.2.2 Air-Assisted Flares. Air-assisted flares use

forced air to provide the combustion air and the mixing required

for smokeless operation. These flares are built with a spidershaped 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
41

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 nonassisted flares. Enclosed flares are always at ground level.

Enclosed flares generally have less capacity than open flares

and are used to combust continuous, constant flow vent streams,

although reliable and efficient operation can be attained over a

wide range of design capacity. Stable combustion can be obtained

with lower heat content vent gases than is possible with open

flare designs, probably due to their isolation from wind effects.

4.1.1.3 Boilers and Process Heaters. Industrial boilers are

combustion units that boil water to produce high and low pressure

steam. Industrial boilers can also combust various vent streams

containing VOCs, including vent streams from distillation

operations, reactor processes, and other general operations. The

majority of industrial boilers used in the refining industry are

of watertube design, and over half of these boilers use natural

gas as a fuel. In a watertube boiler, hot combustion gases

contact the outside of heat transfer tubes which contain hot

water and steam. These tubes are interconnected by a set of

drums that collect and store the heated water and steam. Energy

transfer from the hot flue gases to the water in the furnace

watertube and drum system can be better than 85 percent

efficient. Additional energy can be recovered from the flue gas

by preheating combustion air in an air preheater or by preheating

incoming boiler feed water in an economizer unit.

When firing natural gas, forced- or natural-draft burners

thoroughly mix the incoming fuel and combustion air. A VOCcontaining vent stream can be added to this mixture or it can be

fed into the boiler through a separate burner. In general,
42

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.

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
43

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 C1 to C6 hydrocarbons.

4.1.1.3.2 Applicability of Boilers and Process Heaters. Both

of these devices are used throughout petroleum refineries to

provide steam and heat input essential to the refining process. 

Most of these devices possess sufficient size to provide the

necessary temperature and residence time for VOC destruction. 

Furthermore, boilers and process heaters have proved effective in

destroying compounds that are difficult to combust, such as PCBs

(polychlorinated biphenyls). Boilers and process heaters are

thus effective in reducing VOC emissions from any vent streams

that are certain not to reduce the performance or reliability of

the boiler or process heater.

Ducting some vent streams to a boiler or process heater can

present potential safety and operating problems. The varying

flow rate and organic content of some vent streams can lead to

explosive mixtures or flame instability within the furnace. In

addition, vent streams with halogenated or sulfur-containing

compounds are usually not combusted in boilers or process heaters

due to the possibility of corrosion.

Boilers and process heaters are most applicable where the

potential exists for heat recovery from the combustion of the

vent stream. Vent streams with a high enough VOC concentration

and high flow rate can provide enough equivalent heat value to

act as a substitute for fuel that would otherwise be needed. 

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
44

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

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
45

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

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
46

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

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
47

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, VOCcontaining 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

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
48

methyl ethyl ketone and cyclohexanone. The VOC control

efficiency depends on factors such as inlet vent stream

characteristics (temperature, pressure, and velocity), the

physical properties of the compounds present in the vent stream,

the physical properties of the adsorbent, and the condition of

the regenerated carbon bed.

The adsorption capacity of the carbon and the resulting outlet

concentration are dependent upon the temperature of the inlet

vent stream. High vent stream temperatures increase the kinetic

energy of the gas molecules, causing them to overcome van der

Waals forces and release from the surface of the carbon. At vent

stream temperatures above 38 degrees Celsius, both adsorption

capacity and outlet concentration may be adversely affected.

Increasing vent stream pressure improves VOC removal

efficiency. Increased stream pressure results in higher VOC

concentrations in the vapor phase and increased driving force for

mass transfer to the carbon surface. Decreased stream pressure,

on the other hand, is often used to regenerate carbon beds. 

Reduced pressure in the carbon bed effectively lowers the

concentration of VOCs in the vapor phase, desorbing the VOCs from

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.
49

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 VOCcontaining vent streams: 1) high VOC concentrations, 2) very

high or low molecular weight compounds, 3) mixtures of high and

low boiling point VOCs, and 4) high moisture content.

Absorbing vent streams with VOC concentrations above 10,000

ppmv may result in excessive temperature rise in the carbon bed

due to the accumulated heat of adsorption resulting from the VOC

loading. If flammable vapors are present, insurance company

requirements may limit inlet concentrations to less than 25

percent of the LEL.

The molecular weight of the compounds to be adsorbed should be

in the range of 45 to 130 gm/gm-mole for effective adsorption. 

High molecular weight compounds that are characterized by low

volatility are strongly adsorbed on carbon. The affinity of

carbon for these compounds makes it difficult to remove them

during regeneration of the carbon bed. Conversely, highly

volatile materials (i.e., molecular weight less than about 45 gm)

do not adsorb readily on carbon, thus adsorption is not typically

used for controlling streams containing such compounds.

Adsorption systems can be very effective with homogeneous vent

streams but much less so with streams containing a mixture of

light and heavy hydrocarbons. The lighter organic compounds tend

to be 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
50

achieved in two ways: 1) by increasing the system pressure at a

given temperature or 2) by lowering the temperature at a constant

pressure. The latter method is the more common to achieve the

specified phase change, and it alone is addressed here.

The basic equipment includes a condenser, refrigeration

unit(s), and auxiliary equipment such as a pre-cooler,

recovery/storage tank, pump/blower, and piping. The two most

commonly used condenser types are surface condensers and direct

contact condensers. In surface condensers, the coolant fluid

does not contact the vent stream; heat transfer occurs through

the tubes or plates in the condenser. As the vapor condenses, a

film forms on the cooled surface and drains away to a collection

tank for storage, reuse, or disposal. Because the coolant from

surface condensers does not contact the vapor stream, it is not

contaminated and can be recycled in a closed loop. Surface

condensers also allow for direct recovery of VOCs from the gas

stream.

Most refrigerated surface condensers are the shell-and-tube

type, which circulates the coolant fluid on the tube side. The

VOCs condense on the outside of the tube (the shell side). 

Plate-type heat exchangers are also used as surface condensers in

refrigerated systems. Plate condensers operate under the same

principles as the shell-and-tube systems, for there is no contact

between the coolant and vent stream), but the two streams are

separated by thin, flat plates instead of cylindrical tubes.

In contrast to surface condensers, direct contact condensers

cool the vapor stream by spraying a liquid at ambient or lower

temperature directly into the vent stream. Spent coolant

containing VOCs from direct contact condensers usually cannot be

reused directly. Additionally, VOCs in the spent coolant cannot

be recovered without further processing. 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
51

ammonia and chlorofluorocarbons (e.g., chlorodifluoromethane) are

those that undergo a phase change from liquid to gas after

absorbing heat. Secondary refrigerants, such as brine solutions, 

have higher boiling points and thus act only as heat carriers and

remain in the liquid phase.

There are some applications that require auxiliary equipment. 

If the vent stream contains water vapor or if the VOC has a high

freezing point (e.g., benzene or toluene), ice or frozen

hydrocarbons may form on the condenser tubes or plates. This

will reduce the heat transfer efficiency of the condenser and

thereby reduce the removal efficiency. Formation of ice will

also increase the pressure drop across the condenser. In such

cases, a precooler may be used to remove the moisture before the

vent stream enters the condenser. Alternatively, ice can be

melted during an intermittent heating cycle by circulating

ambient temperature brine through the condenser or using radiant

heating coils.

It is necessary in some cases to provide a recovery tank for

temporary storage of condensed VOC before its reuse,

reprocessing, or transfer to a large storage tank. Pumps and

blowers are typically used to transfer liquid (e.g., coolant and

recovered VOC) and gas streams, respectively, within the system.

4.1.2.4.1 Control Efficiency. The major parameters that

affect the removal efficiency of refrigerated surface condensers

designed to control air/VOC mixtures are: 1) Volumetric flow

rate of the VOC-containing vent stream; 2) Inlet temperature of

the vent stream; 3) Concentrations of the VOCs in the vent

stream; 4) Absolute pressure of the vent stream; 5) Moisture

content of the vent stream; and 6) properties of the VOCs in the

vent stream, such as dew points, heats of condensation, heat

capacities, and vapor 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
52

above 90 percent can be achieved with coolants such as chilled

water, brine solutions, ammonia, or chlorofluorocarbons.

4.1.2.4.2 Applicability. Condensers are widely used as

product recovery devices. They may be used to recover VOCs

upstream of other control devices or they may be used alone for

controlling vent streams containing relatively high VOC

concentrations (usually greater than 5,000 ppmv). In these

cases, the removal efficiencies of condensers can range widely,

from 50 to 95 percent.

Since the temperature necessary for condensation depends on

the properties and concentration of VOCs in the vent stream,

streams having either low VOC concentrations or more volatile

compounds require lower condensation temperatures. Also,

depending on the type of condenser used, disposal of the spent

coolant can be a problem. If cross-media impacts are a concern,

surface condensers would be preferable to direct contact

condensers.

Condensers used as emission control devices can process flow

rates as high as about 57 m3/min (120,000 scfm). Condensers for

vent streams with greater volumetric flow rates and having high

concentrations of noncondensibles will require significantly

larger heat transfer areas.

4.1.3 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,
53

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

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. 
54

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-toback, in tandem, or face to face. In the back-to-back

arrangement, a closed cavity is created between the two seals. A

seal liquid, such as water or seal oil, is circulated through the

cavity. This seal liquid is used to control the temperature in

the stuffing box. For the seal to function properly, the

pressure of the seal liquid must be greater than the operating

pressure of the pump. In this manner, any leakage would occur

across the seal faces into the process or the environment.

Double mechanical seals are used in many process applications,

but there are some conditions for which their use is not

indicated. Such conditions include service temperatures above

260 degrees Celsius, and pumps with reciprocating shaft motion. 

Further, double mechanical seals cannot be used where the process

fluid contains slurries, polymeric, or undissolved solids.

Another type of pump used in the petroleum refining industry

is the seal-less pump. Seal-less pumps are used primarily in

processes where the pumped fluid is hazardous, highly toxic, or

very expensive and where every effort must be made to prevent all

possible leakage of the fluid. Canned-motor, diaphragm, and

magnetic drive pumps are three common types of seal-less pumps.

Canned-motor pumps have interconnected cavity housings, motor

rotors, and pump casings. Because the process liquid is the

bearing lubricant, abrasive solids in the 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
55

contact the process fluid. An externally-mounted magnet coupled

to the pump motor drives the impeller in the pump casing.

4.1.3.2 Compressors. Compressors move gas through a process

unit in much the same way that pumps transport liquid. 

Compressors are typically driven with rotating or reciprocating

shafts. Thus, the sealing mechanisms for compressors are similar

to those for pumps, i.e., packed and mechanical seals. Emissions

from this source type may be reduced by improving the seals'

performance or by collecting and controlling the emissions from

the seal. Emissions from mechanical contact seals depend on the

type of seal or control device used and the frequency of seal

failure.

Shaft seals for compressors are of several different types: 

labyrinth, restrictive carbon rings, mechanical contact, and

liquid film. All of these seal types restrict leaks, although

none of them completely eliminates leakage. Compressors can be

equipped with ports in the seal area to evacuate collected gases,

which could then be controlled.

A buffer or barrier fluid may be used with these mechanical

seals to form a buffer between the compressed gas and the

environment, similar to barrier fluids in pumps. This system

requires a clean, external gas supply that is compatible with the

gas being compressed. Barrier gas can become contaminated and

must be disposed of properly, for example by venting to a control

device. Compressors can also be equipped with liquid film seals. 

This seal is formed by a film of oil between the rotating shaft

and stationary gland.

4.1.3.3 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 springloaded 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
56

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

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
57

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

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
58

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

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,
59

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

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.
60

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

higher than a specified figure ("action level"), then the leaking

component is marked for repair.
61

4.1.3.9.2 Repair Methods. This section describes repair

methods for possible equipment emission sources in a refinery. 

These are not intended to be complete repair procedures.

Many pumps have in-line or parallel spares that can be used

while the leaking pump is being repaired. Leaks from packed

seals may be reduced by tightening the packing gland. With

mechanical seals, the pump must be dismantled to repair or

replace the leaking seal. Dismantling pumps can result in

spillage of some process fluid. If the seal leak is small,

evaporative emissions of VOC from such spillage may be greater

than the continued leak from the seal. Precautions must be taken

to prevent or reduce these emissions.

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 overtightened. Some types of valves have no means of in-service

repair and must be isolated from the process and removed for

repair and replacement. Most control valves have a manual bypass
62

loop that allows them to be isolated and removed. Most block

valves cannot be isolated easily, although temporary changes in

process operation may allow isolation in some cases.

In some cases, leaks from connectors can be reduced by

replacing the connector gaskets, but most connectors cannot be

isolated to permit gasket replacement. Tightening of connector

bolts also may reduce emissions from connectors. Where

connectors are not required for process modification or periodic

equipment removal, emissions from connectors can be eliminated by

welding them.

4.1.4 Internal Floating Roofs

Internal floating roofs are commonly used in the petroleum

refining industry to control emissions from fixed-roof storage

tanks. As the name implies, it is a roof inside a tank that

floats on the surface of the stored liquid.

The presence of a floating roof (or deck) inside a fixed roof

tank significantly reduces the surface area of exposed liquid. 

It serves as a physical barrier between the volatile organic

liquid and the air that enters the tank through vents.

Because evaporation is the primary emission mechanism

associated with storage tanks, emissions from floating roof tanks

as well as fixed 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 vapormounted wiper seal and uncontrolled fittings.
63

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,
64

sample pipes, ladder wells, vacuum breakers, and automatic gauge

float wells. Fitting losses occur when VOCs leak around these

fittings. Fitting losses can be controlled with gasketing and

sealing techniques or by the substitution of fittings that are

designed to leak less.

The effectiveness of fitting controls at reducing the overall

emission rate is a function of the number of fittings of each

type employed on a given tank. For example, if using controlled

fittings reduces total fitting loss by 36 percent, and if fitting

losses are about 35 percent of the total emissions from a typical

internal floating roof tank, then the controlled fittings reduce

the overall emissions by (.36*.35)= .126, or 12.6 percent over a

similar tank without fitting controls. The usual increase in

control efficiency achieved by installing controlled fittings

ranges from 0.5 to 1.0 percent.

4.1.4.3 Control of Deck Seam Losses. Deck seam losses are

inherent in a number of floating roof types including internal

floating roofs. Any roof constructed of sheets or panels

fastened by mechanical fasteners (e.g., bolts) is expected to

have deck seam losses. Deck seam losses are considered to be a

function of the length of the seams and not the type of

mechanical fastener or the position of the deck relative to the

liquid surface. This is a conclusion drawn from a 1986 study on

two roof types with significantly different mechanical fasteners

and differences in the amount of contact with the liquid surface.

Deck seam losses are controlled by selecting a roof type with

vapor-tight deck seams. The welded deck seams on steel pan roofs

are vapor tight. Fiberglass lapped seams of a glass fiber

reinforced polyester roof may be vapor tight as long as there is

negligible permeability of the liquid through the seam lapping

materials. Some manufacturers provide 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,
65

eliminating deck seam losses will raise the control efficiency as

much as 1.5 percent.

4.1.4.4 Applicability. The applicability of any storage tank

improvement in order to reduce VOC emissions is dependent upon

the characteristics of the particular VOC. Since floating decks

are often constructed primarily of aluminum, they may not be

applicable to tanks storing halogenated compounds, pesticides, or

other compounds that are incompatible with aluminum. Contact

between these compounds and an aluminum deck could corrode the

deck and cause product contamination.

In addition, vapor pressures may affect the selection of tank

improvements as an applicable control technology. For chemicals

with very low vapor pressure, fixed roof tank emissions will

already be so low that installing an internal floating roof may

not significantly reduce emissions further. For chemicals with

vapor pressures up to 65 kPa (9.4 psia), emission reductions of

95 percent and above are achievable with this technology. Above

this vapor pressure, achievable emission reduction starts to

decrease with increasing vapor pressure. Thus, an internal

floating roof may not be indicated for chemicals with relatively

high vapor pressures.1

4.2 DESCRIPTION OF MACT AND SUMMARY OF REGULATORY ALTERNATIVES

The CAA requires that in designating regulatory options, the

maximum degree of reduction in emissions that is deemed

achievable shall be subject to a floor, which is determined

differently for new and existing sources. For new sources, the

standards must be set at levels which are not any less stringent

than the emission control that is achieved in practice by the

best controlled similar source. For existing sources, the

standards may not be less stringent than the average emission

limitation achieved by the best performing 12 percent of existing

sources in each category or subcategory of 30 or more sources. 

In determining whether the standard should be more stringent than

the floor and by how much, EPA is to consider, among other
66

things, the cost of achieving such additional emission

reductions. The options for achieving reductions at each

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 lb/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 lb/day (33 kg/day) VOC. Thus, control of

process vents with VOC emissions greater than 72 lb/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.
67

4.2.2 Storage Vessels

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 CFR 60. Subpart Kb represents the best control technology for

storage vessels. It requires either floating roofs with

specified seals and fittings or closed vent systems and control

devices.

Once the best performing 12 percent were identified, the

average true vapor pressure of the stored liquids being

controlled at these refineries was determined. The 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
68

than or equal to 3.4 kPa (0.5 psia), and vessels with capacities

greater than or equal to 76 m3 (475 barrels or 20,000 gallons)

storing liquids with vapor pressures equal to or greater than

77 kPa (11.1 psia) would be required to comply with the

subpart Kb (including the controlled fitting requirements). The

option more stringent than the floor was not selected because it

would result in high costs relative to HAP emission reductions.

4.2.3 Wastewater Streams

This section summarizes the MACT floors 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
69

at any refinery regardless of the size of its annual benzene

loading. This alternative control option was not selected

because the additional emission reduction achieved through

further control was not significant, given the associated costs.

The floor alternative was selected as the 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 VV) 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,
70

and comply with Phase III 5 1/2 years after promulgation. Each

phase has lower leak definitions for pumps and valves.

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 control, or reliance on regulation by States and

localities.

4.3.1 Judicial System

In the absence of governmental regulation, market systems fail

to make the generators of pollution pay for the costs associated

with that pollution. For an individual firm, pollution is an

apparently unusable by-product that can be disposed of cheaply by

venting it to the atmosphere. However, in the atmosphere,

pollution 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
71

polluting activity when polluters do not bear the full cost of

their actions. 
TABLE 4-1. SUMMARY OF REGULATORY ALTERNATIVES BY EMISSION POI

Emission Point Alternative 1 Description of Control OptioEquipmentLeaks

Option 1 Floor = Compliance with the 

refinery NSPS.Option 1 = Compliance with pin 40 CFR part 60 subpart VV Petroleum Refinery NSPS, or with a modified negotiated rfor equipment leaks presenteCFR part 63 subpart H (HON eleaks). 

MiscellaneousVents

MACT Floor Floor = Control of vents wit

emissions greater than 72 lbkg/day). For Group 1 vents 

WastewaterStreams

MACT Floor Floor = Compliance with the 

for Group 1 streams. 

StorageVessels

MACT Floor Floor = Group 1 storage vess

are required to put on one ofollowing control systems: 1internal floating roof (IFR) proper seals; 2) an external roof (EFR) with proper sealsEFR converted to an IFR with seals; or 4) a closed vent sa 95 percent efficient contr
73

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
74

cutoff would generally depend on the pollutant being controlled

and other factors.

However, since the Petroleum Refinery NESHAP is to be a MACT

standard, the role of C/E analysis for selecting a regulatory

alternative for this regulation is somewhat limited. A MACT

floor level of control stringency is required regardless of the

C/E at this control level. At stringency levels beyond the MACT

floor, cost effectiveness can be legally considered, and EPA

believes cost-effectiveness of controls is a primary

consideration for evaluating stringency levels beyond the MACT

floor. The average cost effectiveness of the regulation ($/Mg of

pollutant removed) is included as part of the cost analysis in

Chapter 5.

4.5 ECONOMIC INCENTIVES: SUBSIDIES, FEES, AND MARKETABLE

PERMITS

Economic incentive strategies, when designed properly, act to

harness the marketplace to work for the environment. In deciding

among regulatory options, EPA is required to consider as options

such strategies which influence, rather than dictate, producer

and consumer behavior, in order to achieve environmental goals. 

Economic incentive programs make environmental protection of

economic interest to producers and consumers. When feasible,

properly designed systems can be employed to achieve any

environmental goal at the least cost to society.

Several types or categories of economic incentive strategies

exist. One broad category of incentive programs is based of the

use of fees or subsidies. Fee programs establish and collect a

fee on emissions, providing a direct economic incentive for

emitters to decrease emissions to the point where the cost of

abating emissions equals the fee.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
75

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
76

emissions averaging were incorporated into the standard,

facilities' costs of control should fall. Thus, the costs

calculated could be an overestimate.
77

REFERENCES

1. U.S. Environmental Protection Agency. Regulatory Impact

Analysis for the National Emissions Standards for

Hazardous Air Pollutants for Source Categories: Organic

Hazardous Air Pollutants from the Synthetic Organic

Chemical Manufacturing Industry and Seven Other Processes. 

EPA-450/3-92-009. pp. 4-1 to 4-41. December 1992.

2. U.S. Environmental Protection Agency. Office of Air

Quality Planning and Standards. Draft Preamble for the

HON. December 1993.

3. U.S. Environmental Protection Agency. Office of Air

Quality Planning and Standards. Draft Preamble for the

Petroleum Refinery NESHAP. January 1994.

4. Reference 2.

5. U.S. Environmental Protection Agency. Office of Air

Quality Planning and Standards. Municipal Waste Landfills

- Regulatory Impact Analysis. March 1991.
78
79

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,
80

(2) development and assignment of scaling factors for each kind

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
81

basis of the control impacts estimates, the promulgated standards

are written using formats that would allow use of other control

technologies if the equivalent emission reduction is achieved. 

The impact estimates are based on average, representative, or

typical emissions and control requirements for each kind of

source. Thus, the estimates do not reflect the impact 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,
82

and slop oil. In a previous analysis using all available

information, these 13 petroleum liquids accounted for more than

80 percent of the estimated nationwide baseline VOC emissions. 

The storage vessel population factors were used to estimate

the total number of vessels at each refinery. The storage

vessels reported in the questionnaire responses were divided into

groups based on storage vessel type (e.g., fixed roof), refinery

crude capacity (greater than or less than 150,000 barrels per

calendar day (bbls/cd)), and petroleum liquid stored (e.g.,

gasoline, naphtha, etc.). The average number of vessels in each

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

-5

 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 lbs 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 (lb VOC emitted/vessel)
83

corresponding to each vessel type was multiplied by the number of

vessels of that type to calculate the baseline VOC emissions at

each refinery. For example, for internal floating roof vessels

storing gasoline at refineries with crude capacities greater than

150,000 bbls/cd the refinery crude capacity, times the tank

population factor of 1.2 x 10

-5

 vessels per barrel, times the VOC

emission factor of 15,000 lb 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
84

in the storage NSPS (40 CFR 60 subpart Kb) and HON (40 CFR 63

subpart G). For existing external and internal floating roof

vessels, costs were estimated for installing seals that comply

with the proposed HON seal requirements. The MACT floor level of

control for existing floating roof storage vessels does not

include complying with the fitting requirements in the proposed

HON. 

More stringent controls were not identified for existing fixed

roof storage vessels. For existing external and internal

floating roof vessels, the more stringent control alternative is

to comply with the fitting requirements in the proposed HON in

addition to the seal requirements. 

The emission reduction assigned to each of the 3,400 storage

vessels was calculated as a function of the emission reductions

presented in the EPA publication "NSPS VOC Emissions from VOL

Storage Tanks--Background Information for Proposed Standards". 

This document provided the emission reduction (in percent) of

various seal and fitting configurations compared with fixed roof

vessels. For example, an internal floating roof vessel with a

liquid mounted primary seal and controlled fittings has an

average emission reduction of 96.2 percent over a similar sized

fixed roof vessel. Adding a rim-mounted secondary seal increases

this emission reduction to 96.6 percent. Therefore, the

incremental emission reduction gained by adding the 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 ESD Regulation-Storage Tanks"

(January 1993). The cost equations for adding seals and

controlled fittings to existing external and internal floating

roof vessels were also taken from these two documents. 
85

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

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 l/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
86

and wastewater stream and by assuming that the control

requirements of the BWON (i.e., 99 percent reduction of benzene)

were met for those streams requiring control.

An analysis of existing refinery wastewater collection and

treatment systems indicated that the MACT floor for wastewater is

the BWON. (For more information, refer to ["Maximum Achievable

Control Technology Floor for Process Wastewater Streams at

Petroleum Refineries,"] in the docket). Existing refineries are

already required to comply with the BWON, so no emission

reductions or costs would be associated with the floor option for

refinery wastewater sources. In considering a control option

more stringent than the BWON, the EPA assessed the effects of

lowering the applicability threshold of the BWON, by eliminating

the cutoff of 10 Mg/yr TAB loading in facility wastes and

wastewater. The additional wastewater streams requiring control

(those streams with at least 10 ppmw benzene at refineries with a

TAB under the 10 Mg/yr loading criterion) were assumed to be

steam stripped to achieve reductions equivalent to the

requirements of the BWON (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
87

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

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

lb/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
88

data. The emission estimates may be revised at promulgation if

new factors are developed by EPA based on the new industry data. 

Baseline emissions of HAPs and VOC were estimated by

multiplying the uncontrolled emissions by one minus the control

efficiencies associated with each LDAR program reported by or

assigned to each refinery. The "Equipment Leaks Enabling

Document" (in the 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
89

["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

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
90

some of these units and equipment will be considered "new

sources" and others will be considered part of an "existing

source". It is not possible to determine how many new units will

fall into each of these categories; however, controls will be

required for the emission points in either case. 

Costs for controlling new process units were estimated from

the costs calculated for existing sources and the number of new

process units that are expected to be constructed in the 5-year

period after the standard is enacted. The costs for applying

control technologies to existing sources were calculated as

previously described. The results are documented in the four

memoranda presenting cost impacts (in the docket). The cost

information was scaled up to account for new emission points that

may need to be controlled in the first 5 years after the

petroleum refinery NESHAP has been promulgated. Reductions of

emissions of HAPs and VOC from controlling existing emission

points were also presented in the costing memorandum. The

emission reduction information was scaled up to account for

controls on new emission 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

3

or

250 bbl). This methodology may overestimate the impact of the
91

regulation in the 5 years after promulgation because, as

previously stated, many vessels constructed in that period may be

considered part of existing sources for regulatory purposes. 

Because the requirements for existing sources are equivalent to

the NSPS, there will be no costs or emission reductions for

existing storage vessels. Therefore, the fifth year impacts on

vessels at new sources would be lower than the impact estimated

here because the number of vessels at new sources is probably

overestimated. 

5.1.2.2 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
92

projects 5 years after promulgation of the refinery NESHAP. From

this information, it was determined that an average of 34 process

units would be built annually. Each of these process units is

expected to require control under the NSPS for refineries. 

Therefore, the only cost associated with controlling these units

is the extra cost required to go from the NSPS control

requirements (the MACT floor for equipment leaks at new sources)

to the two options more stringent than floor. The two options

are the same as for existing sources: (1) the negotiated

regulation for equipment leaks in the HON (40 CFR 63 subpart H)

without the monitoring requirements for connectors and (2) the

HON negotiated regulation. 

The average capital investment cost and annual cost of

upgrading from the NSPS to the HON negotiated regulation without

connector monitoring were determined to be $20,000 and $7,000/yr

per process unit, respectively. The average capital investment

and annual cost of upgrading from the NSPS to the HON negotiated

regulation were determined to be $17,000 and $6,200/yr per

process unit, respectively. For each option, the capital

investment cost and average annual cost for controlling the

34 process units constructed each year was calculated by

multiplying the average cost per process unit by the number of

new process units.

5.1.2.4 Miscellaneous Process Vents. The MACT floor level of

control for miscellaneous process vents at new sources was

determined to be combustion. The annual cost for controlling

emissions from miscellaneous vents consisted the cost for piping

to an existing combustion system (to a flare or to the fuel gas

system) and for an additional compressor for each 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
93

miscellaneous vents requiring control was calculated from the

average number of uncontrolled vents per process unit, as

presented in the baseline emissions estimation memorandum (refer

to docket). Based on this information, one vent for each of the

34 process units is estimated to require control (that is, a

total of 34 new vents will require control each year). This

number of vents per year was multiplied by the average cost per

vent to estimate national costs for miscellaneous process vents

for process units constructed in the 5 years after promulgation

of this rule.

5.2 TOTAL COMPLIANCE COST ESTIMATES, REDUCTIONS, AND COST

EFFECTIVENESS

The annualized compliance costs by emission point are shown in

Table 5-1 for the 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.
TABLE 5-1. SUMMARY OF TOTAL ANNUAL COSTS IN THE FIFTH YEAR FOR THE PETROLE

Annual Fifth Year Costs (1000$

(1992 Dollars)

Emission Point Option

Existing

Sources

New

Construction Total Alternat

Equipment LeaksMiscellaneousProcess VentsWastewater SystemsStorage Vessels

FloorOption 1

1

Floor

2

Floor

1

Floor

1

$69,000$59,000$12,000

$ 0

$8,000

$ 0

$(210)

$370

$ 0$98

$69,000$58,790$12,370

$ 0

$8,098

$58,79$11,37

$ 

$8,09

Other Recordkeepingand ReportingTOTAL COST

$1,00

$79,19

NOTES:

1Alternative 1.2EPA did not choose an option above the MACT floor for miscellaneous process vents.3Costs are in 1992 dollars. 
TABLE 5-2. CONTROL OPTIONS AND IMPACTS BY EMISSION POINT

HAP Co

Emission Point

Baseline

HAP

Emissions

(Mg/yr)

Control

Option

EmissionReductio

n

(Mg/yr)

Percent

Emission

Reduction

Annual

Cost

($1,000/

yr)

b

Av

Miscellaneous Process Vents ExistingSources

8,900 Floor* 7,600 85 $11,000 $1,

 New Sources

a 900 Floor* 770 85 $370 $

Storage Vessels ExistingSources

9,000 Floor* 670 7 $3,700 $5,

Option 1 1,300 14 $6,200 $4,Option 2 1,800 20 $8,400 $4,Option 3 2,600 29 $32,000 $12,

 New Sources

a 290 Floor* 4 1.4 $98 $24,

Option 1 14 4.8 $550 $39,

WastewaterSystems ExistingSources

9,200 Floor* 0 N/A 0 

Option 1 7,700 93 $120,000 $15,

 New Sources

a 960 Floor* 0 N/A 0 

Option 1 930 97 $18,000 $20,

Equipment Leaks ExistingSources

50,000 Floor 35,000 69 $69,000 $2,

Option1*

44,000 87 $58,000 $1,

Option 2 46,000 91 $78,000 $1,

 New Sources 1,300 Floor 0 0 0 

Option1*

640 49 $(210) $(

Option 2 760 59 $840 $1,
96

NOTES: aImpacts were estimated for new process units constructed in the 5 years after promulgation. For regulatory purposes, some of these units ma

others may be considered part of an existing source. bThe costs for monitoring, recordkeeping, and reporting (MRR) requirements are not available on an emission point basis. The costs in this tab

maintenance of control equipment only. N/A = Not applicable.Brackets indicate negative values.* = Control option chosen for preferred alternative.
97

TABLE 5-3. COST, HAP EMISSION REDUCTION, AND COST EFFECTIVENESS BY

ALTERNATIVE

HAP

Emissions

(Mg/Yr)

Cost Effectiveness

($/Mg)

Regulatory

Alternative

Reduction

Annual Cost

(Million $,

1992)1

Average Incremental

Alternative 1 48,000 $79.0 $1,645 N/A

NOTES: N/A = Not applicable.

1Cost estimates do include costs associated with monitoring, recordkeeping, and reporting requirements.

TABLE 5-4. COST, VOC EMISSION REDUCTION, AND COST EFFECTIVENESS BY

ALTERNATIVE

Cost Effectiveness

($/Mg)

Regulatory

Alternative

VOC Emission

Reduction

(Mg/Yr)1

Annual Cost

(Million $,

1992)

Average Incremental

Alternative 1 252,000 $79.0 $313 N/A

NOTES: N/A = Not applicable.

1Emission reduction estimates do not incorporate reductions occurring at new sources.
98

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
99

time from the year in which they are to take place to the

expected end of facility life.

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 MRR requirements for

miscellaneous process vents are summarized by control device in

Table 5-5.

For equipment leaks, because the provisions of the proposed

rule are work practice and equipment standards, monitoring,

repairing leaks, and maintaining the required records constitutes

compliance with the rule. The HON equipment leak provisions are

appropriate to determine continuous compliance with the petroleum

refinery equipment leak standards. In summary, these provisions

require periodic monitoring with a portable hydrocarbon detector

to determine if equipment is leaking.
TABLE 5-5. MISCELLANEOUS PROCESS VENTS — MONITORING, RECORDKEEPING, AN

REQUIREMENTS FOR COMPLYING WITH 98 WEIGHT-PERCENT REDUCTION OF TOTAL ORGANI

OR A LIMIT OF 20 PARTS PER MILLION BY VOLUME

Control Device

Parameters to be

Monitored

a Recordkeeping and Reporting Requir

Monitored Parameters

ThermalIncinerator

Fireboxtemperature

b

[63.644(a)(1)(i)]

1. Continuous records

c

2. Record and report the firebox t

averaged over the full period operformance test - NCS

d

3. Record the daily average firebo

for each operating day

e

4. Report all daily average temper

are outside the range establishor operating permit and all opewhen insufficient monitoring dacollected

f - PR

g

CatalyticIncinerator

Temperatureupstream anddownstream of thecatalyst bed[63.644(a)(1)(ii)]

1. Continuous records2. Record and report the upstream 

temperatures and the temperaturacross the catalyst bed averagefull period of the performance 

3. Record the daily average upstre

and temperature difference acrobed for each operating day

e

4. Report all daily average upstre

temperatures that are outside testablished in the NCS or operaPR
TABLE 5-5 (continued).

Control Device

Parameters to be

Monitoreda Recordkeeping and Reporting Requir

Monitored Parameters

5. Report all daily average temper

differences across the catalyst outside the range established ioperating permit - PR

6. Report all operating days when 

monitoring data are collectedf

Boiler orProcess Heaterwith a designheat inputcapacity lessthan44 megawattsand Vent Streamis notintroduced withor as theprimary fuelh,i

Fireboxtemperatureb[63.644(a)(4)]

1. Continuous records2. Record and report the firebox t

averaged over the full period operformance test - NCS

3. Record the daily average firebo

for each operating daye

4. Report all daily average firebo

that are outside the range estaNCS or operating permit and all days when insufficient monitoricollectedf - PR
TABLE 5-5 (continued).

Control Device

Parameters to be

Monitoreda Recordkeeping and Reporting Requir

Monitored Parameters

Flare Presence of a

flame at the pilotlight[63.644(a)(2)]

1. Hourly records of whether the m

continuously operating and whetflame was continuously present hour

2. Record and report the presence 

the pilot light over the full pcompliance determination - NCS

3. Record the times and durations 

when a pilot flame is absent or is not operating

4. Report the times and durations 

when all pilot flames of a flarPRAll Control DevicesPresence odiverted to the atmosphere from device [63.644(c)(1)] or1. Ho

of flwaanwaanea

2. Record and report the times and 

all periods when the vent streathrough a bypass line or the mooperating - PRMonthly inspectiovalves [63.644(c)(2)]1. Recor

monthwere p
Control Device

Parameters to be

Monitoreda Recordkeeping and Reporting Requir

Monitored Parameters

NOTES: aRegulatory citations are listed in brackets.

bMonitor may be installed in the firebox or in the ductwork immediately downstream of the firebox before any substantial heat exchange is c"Continuous records" is defined in §63.641 of this subpart.dNCS = Notification of Compliance Status described in §63.652(e) of this subpart.eThe daily average is the average of all recorded parameter values for the operating day. If all recorded values during an operating day are established in the NCS or operating permit, a statement to this effect can be recorded instead of the daily average.fWhen a period of excess emission is caused by insufficient monitoring data, as described in §63.552(f)(3)(i)(C) of this subpart, the duratio

monitoring data were not collected shall be included in the Periodic Report.

gPR = Periodic Reports described in §63.652(f) of this subpart.hNo monitoring is required for boilers and process heaters with heat input capacities >44 megawatts or for boilers and process heaters whe

introduced with or as the primary fuel. No recordkeeping or reporting associated with monitoring is required for such boilers and process h

iProcess vents that are routed to refinery fuel gas systems are not regulated under this subpart. No monitoring, recordkeeping, or reporting 

process heaters that combust refinery fuel gas.
104
105

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
106

exports). Control measures may also influence the capital

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.
107

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
108

types of fuel, but some non-fuel uses exist, such as

petrochemical feedstocks, waxes, and lubricants. The output of

each refinery is a function of its crude oil feedstock and its

preferred petroleum product slate.

Motor gasoline is defined as a complex mixture of relatively

volatile hydrocarbons that has been blended to form a fuel

suitable for use in spark-ignition engines. Residual fuel oil is

a heavy oil which remains after the distillate fuel oils and

lighter hydrocarbons are distilled away in refinery operations. 

Uses include fuel for steam-powered ships, commercial and

industrial heating, and electricity generation. Distillate fuel

oil is a general classification for one of the petroleum

fractions produced in conventional distillation operations. It

is used primarily for space heating, on- and off-highway diesel

engine fuel (including railroad engine fuel and fuel for

agricultural machinery), and electric power generation. Jet fuel

is a low freezing point distillate of the kerosene type 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
109

their output in several different regional markets. In addition,

because refineries are the source of non-hydrocarbon pollutants

such as individual HAPs, volatile organic compounds (VOCs),

sulfur dioxide (SO2), and nitrogen oxide (NOx), many Federal,

State, and local regulations are already in place in some

locations. Differences in the regional market structure may also

result in different import/export characteristics.

The United States is segmented into five regions, called

Petroleum Administration for Defense Districts (PADDs), for which

statistics are maintained. PADDs were initiated in the 1940s for

the purpose of dividing the United States into five economically

and geographically distinct regions. Relatively independent

markets for petroleum products exist in each PADD. 

In addition to differences in regional markets, each of the

five product categories in this analysis possesses its own

individual market segment, satisfying demand among different enduse 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
110

capabilities. Some refineries produce output only by processing

crude oil through basic atmospheric distillation. These

refineries have very little ability to alter their product yields

and are deemed to have low complexity. In contrast, refineries

that have assorted downstream processing units can substantially

improve their control over yields, and thus have a higher level

of complexity. Because of their differences in size and

complexity, refineries can be grouped by two main structural

features: (1) atmospheric distillation capacity (which denotes

their size) and (2) process complexity (which characterizes the

type of products a refinery is capable of producing).

Capacity utilization rates of petroleum refineries have been

rising in recent years, reaching a high of 92 percent in 1991.2

This indicates that existing refineries are operating closer to

full capacity than in the past, and will have limited opportunity

to enhance production by increasing utilization.

During the past 23 years, the entire domestic refining

industry has been affected by crude oil quantity changes and

shifting petroleum demand patterns. A more complex and flexible

refining industry has evolved domestically. Ownership of U.S.

refineries has changed through consolidation and foreign

investments. Throughout the 1970s, the number of U.S. refineries

rose rapidly in response to rising demand for petroleum products. 

In the early 1980s, the petroleum refining industry entered a

period of restructuring, 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
111

lowest value, 1.0. The level of complexity of a refinery

generally correlates to the types of products the refinery is

capable of producing. Higher complexity denotes a greater

ability to enhance or diversify product output, to improve yields

of preferred products, or to process lower quality crude. By

defining refinery complexity, it is possible to differentiate

among refineries having similar capacities but different process

capabilities. In theory, more complex refineries are more

adaptable to change, and are therefore potentially less affected

by regulation. The complexity of a refinery usually increases as

its crude capacity increases. (Lube plants are the exception to

this rule.) Over 50 percent of the operable capacity (50,000 to

100,000 bbl/d) can be found at refineries with above-average

complexity. Likewise, the smaller refineries are less complex.

6.1.2 Market Structure

The market structure of an industry will influence the

magnitude of market impacts resulting from emission controls. A

perfectly competitive market is characterized by many sellers, no

barriers to entry or exit, homogeneous output, and complete

information. A perfectly competitive market is one in which

producers have small degrees of market power and pricing is

determined by market forces, rather than by the producers.

Alternatively an industry with monopoly power has more discretion

over the market price charged. Producers in such an industry

have greater market power. A profile of the market structure of

the petroleum refining industry is provided in the following

sections, including an assessment of the number of domestic

operating refineries, the market concentration, and the extent of

vertical integration, and diversification.

6.1.2.1 Market Concentration. Market concentration is 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
112

indicate monopoly control of the industry by one firm. On the

other extreme, concentration of less than 1 percent would

indicate the industry was comprised of numerous small firms.

Concentration is measured based on refining capacity. Until

recently, the top four firms in the refining industry have

consistently comprised over 30 percent of the market share, but

most market concentration ratios have marginally decreased in

recent years.

Market concentration may also be evaluated using the

Herfindahl-Hirschman index, which is defined as the sum of the

squared market shares (expressed as a percentage) for all firms

in the industry. If a monopolist existed, with market share

equal to 100 percent, the upper limit of the index (10,000) would

be attained. If an infinite number of small firms existed, the

index would equal zero. An industry is considered unconcentrated

if the Herfindahl-Hirschman index is less than 1,000. Ratings

are also developed for moderately concentrated (between 1,000 and

1,800) and highly concentrated (greater than 1,800) industries. 

The petroleum refining Herfindahl-Hirschman index in recent years

has been less than 500. Thus the refining industry is considered

unconcentrated.3

6.1.2.2 Industry Integration and Diversification. Vertical

integration exists when the same firm supplies input for several

stages of the production and marketing process. Firms that

operate petroleum refineries are vertically integrated because

they are responsible both for exploration and production of crude

oil (which supplies the input for refineries) and for marketing

the finished petroleum products after refining occurs. To assess

the level of vertical integration in the industry, firms are

generically classified as major or independent. Generally

speaking, major energy producers are defined as firms that are

vertically integrated. There are currently 20 major energy

companies. The crude capacity of the major, vertically integrated

firms represents almost 70 percent of nationwide production.

For the major oil companies, horizontal integration exists

because these firms operate several refineries which are often
113

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.

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
114

taking place in the refining industry is reflected in the

decreasing crude oil capacity and refinery runs.

Refined product margins are a good indicator of overall

refinery financial performance.4 The difference between refined

product costs and refined product revenues is the refined product

margin. During the 1980s, refined product margins were affected

by a 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.
115

Planned uses of investment funds by the 12 firms in the

financial sample over the next few years include construction of

diesel desulfurization units, expansion of existing units, and

construction of units to manufacture methyl tertiary butyl ether

(MTBE) and oxygenated fuels. In a 1991 study, Cambridge Energy

Research Associates (CERA) surveyed refiners and oxygenate

producers to evaluate the ability of the refining industry to

meet CAA provisions.7 Among the firms in the CERA survey, the

majors and some large independents plan to fund their investments

primarily or entirely from internally generated cash flows, while

most of the small refineries surveyed are planning on resorting

to the debt market for funds.

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
116

refinery's products. The production decision depends on the

profit each of the oil products can generate for the firm. 

Profits, in turn, depend on the productivity of the oil refinery

— its ability to produce each oil product as effectively as

possible from a barrel of crude oil. The quantity of crude oil a

refinery will refine depends on the capacity of the refinery and

the cost of production. The marginal costs of production of each

product will determine any future changes in production. Crude

oil is the primary material input to the refining process; as a

result, the production of refined products is vulnerable to

fluctuations in the world crude oil market.

In the long run, production decisions are based on the cost of

capacity expansion relative to existing price levels and expected

future price levels. A refinery uses different processing units

to turn crude oil into finished products, so when a particular

processing unit reaches capacity, output can be increased 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
117

used as transportation fuel include motor gasoline, distillate

(diesel) fuel, and jet fuel, and accounted for an estimated 64

percent of all U.S. petroleum demand in 1990. Since mobile

source emissions will be regulated by Title II regulations, this

output from petroleum refineries will be most affected by the

CAA. The industrial sector constitutes the second highest

percentage of demand for petroleum products, followed by

household and electric utility demands.

Petroleum is used most widely in the transportation sector. 

In the household and commercial sector, light heating oil and

propane are used for heating and energy uses, and compete with

natural gas and electricity. Petroleum fuels in the industrial

sector compete with natural gas, coal, and electricity. In the

industrial sector, residual and distillate heating oils are used

for boiler and power fuel. In the electric utility sector,

petroleum products supply energy in the form of heavy residual

fuel oil and smaller amounts of bulk light distillate fuel oil.9

In terms of refined products, 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
118

refined petroleum products affect the willingness of consumers to

choose petroleum over other fuels, and may ultimately cause a

change in consumer behavior. In the transportation sector, the

effect of high gasoline prices on fuel use could reduce

discretionary driving in the short term and, in the long term,

result in the production of more fuel-efficient vehicles.

In the market for jet fuel, demand is primarily determined by

a combination of price concerns and the overall health of the

airline industry. In the residential sector, demand for home

heating (distillate) is determined in part by price level, and

also by temperature levels and climate. Temperature in different

areas of the country may determine the degree to which buildings

and houses are insulated. Temperature and insulation are

exogenous factors which will determine heating needs regardless

of the price level of fuel. High prices for home heating oil

provide incentive for individuals to conserve by adjusting

thermostats, improving insulation, and by using energy-efficient

appliances. In some cases, higher oil prices also provide

incentive for switching to natural gas or electric heating. 

(Adjusting thermostats is a short-run response, while changing to

more energy-efficient appliances or fuels are long-run

responses.)

In the industrial sector, fuel oil competes with natural gas

and coal for the boiler-feed market. High prices relative to

other fuels tend to encourage fuel-switching, especially at

electric utilities and in industrial plants having dual-fired

boilers. Generally speaking, in choosing a boiler for a new

plant, management must choose between the higher 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 longterm 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,
119

although a significant increase in oil-fired capacity is not

expected until 2010.11

Demand levels in each of the end-use sectors are also affected

by the economic environment. Periods of economic growth and

periods of increased demand for petroleum products typically

occur simultaneously. For example, in an expanding economy, more

fuel is needed to transport new products, to operate new

production capacity, and to heat new homes. Conversely, in

periods of low economic growth, demand for petroleum products

decreases.

6.1.4.2 Past and Present Consumption. Total consumption of

all types of petroleum products has fluctuated over the past 20

years, reflecting the volatility of this market. The consumption

level has been sporadic and has shown an overall decline in

recent years. Demand for individual petroleum product types has

also fluctuated over this period. The percentage of total demand

is highest for motor gasoline followed by demand for distillate

fuel oil. Over the 23-year period from 1970 to 1992, the demand

for residual fuel oil has decreased by 50 percent, showing the

greatest percentage of change over time of any of the petroleum

products. It has also been the only fuel to show a decline in

use. This decrease in residual fuel demand reflects a move in

the industry from heavier fuels toward lighter, more refined

versions. This trend is expected to continue into the future as

efforts to control air emissions go into effect.

All other types of fuel show increases in use, with the most

growth occurring in the market for jet fuel. Substantial gains

in airplane fuel efficiency in the last two decades, which have

resulted from improved aerodynamic design and a shift toward

higher seating capacities, have been exceeded by even faster

growth in passenger miles traveled.12 The other categories show

an average growth rate of approximately 23 percent over this time

period. All major petroleum products registered lower demand in

1991 than in 1990, except LPGs. This was the first time since

1980 that demand for all major petroleum products fell

simultaneously in the same year. In this case, decreased demand
120

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

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.
121

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

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
122

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

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
123

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

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
124

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. Onhighway 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
125

industry. Five refined petroleum products were modeled. 

Collectively, these products represent over 90 percent of the

refined petroleum products sold in the nation annually. These

products include motor gasoline, jet fuel, residual fuel oil,

distillate fuel oil, and liquified petroleum gases (LPGs). It is

assumed that firms in the petroleum refining industry operate in

a perfectly competitive market. Although the petroleum refinery

industry does not meet the strictest definition of a perfectly

competitive industry, perfect competition seems a more applicable

characterization of the market than pure monopoly. The

assumption of perfect competition results in a worst case

scenario of model results from the perspective of the impact of

the regulation on the petroleum refinery industry. 

6.2.1 Market Supply and Demand

The partial equilibrium model approach estimates the baseline

market supply and demand relationship that provides the framework

for evaluating market changes likely to occur from emission

controls. The baseline or pre-control petroleum refining market

is defined by a domestic market demand equation, a domestic

market supply equation, and a foreign market supply equation. It

is further assumed that the markets will clear or achieve an

equilibrium. The following equations identify the market demand,

supply, and equilibrium conditions for the petroleum refinery

industry:

where:
126

Q = annual output or quantity of petroleum products

purchased and sold in the United States

Q

D = quantity of the petroleum products domestically

demanded annually

Q

Sd = quantity of the products produced by domestic suppliers

annually

Q

Sf = quantity of the products produced by foreign suppliers

annually

P = price of the petroleum product

, = price elasticity of demand for the product

( = price elasticity of supply for the product

", $, and D are parameters estimated by the model.

The constants ", $, and D are computed such that the baseline

equilibrium price is normalized to one. The market specification

assumes that domestic and foreign supply elasticities are the

same. This assumption was necessary because data were not readily

available to estimate the price elasticity of supply for foreign

suppliers.

6.2.2 Market Supply Shift

The domestic supply equation shown above may be solved for the

price of the petroleum product, P, to derive an inverse supply

function that will serve as the baseline supply function for the

industry. The inverse domestic supply equation for the industry

is as follows:

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:
127

where:

C = increase in the supply price

Q = output

V = measure of annual operating and maintenance control

costs

t = marginal corporate income tax rate

S = capital recovery factor

D = annual depreciation (assumes straight line

depreciation)

k = investment cost of emission controls

Thus, the model assumes that individual refineries will seek to

increase the product supply price by an amount (C) that equates

the investment costs in control equipment (k) to the present

value of the net revenue stream (revenues less expenditures)

related to the equipment. Solving the equation for the supply

price increase (C) yields the following equation:

Estimates of the annual operation and maintenance control

costs and of the investment cost of emission controls (V and k,

respectively) were obtained from engineering studies conducted by

the engineering contractor for EPA and are based on first quarter

1992 price levels. The variables depreciation and capital

recovery factor, D and S, respectively, are computed as follows:
128

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 Ci (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:

where:

C (Ci,qi) = a function that shifts the supply function to

reflect control costs

Ci = vertical shift that occurs in the supply curve for

the ith refinery to reflect the increased cost of

production in the post-control market

qi = quantity produced by the ith refinery

This industry pre-control and post-control supply and demand is

illustrated in Figure 6-1.
129
130

Figure 6-1. 
131

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 postcontrol market equilibrium and comparing the new equilibrium

price and quantity (P1 and Q1, respectively) to the pre-control

equilibrium (P0 and Q0). The change in value of domestic product

is simply the difference in the industry revenue (P1 * Q1) 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 (P1,Q1) 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
132

exports rise, the resulting change in the value of net exports

will depend on the magnitude of the changes for imports relative

to exports. The following functions are used to compute the trade

impacts:

where:

aQ

Sf = change in the volume of imports

aVIM = change in the dollar value of imports

aQx

Sf = change in the volume of exports

aVX = change in the dollar value of exports

Qx

Sd = 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, aNX, is simply the

difference between the change in the volume of exports and the

change in volume of imports, or aQx

Sd - aQ

Sf. The reported change

in the dollar value of net exports, aVNX, is the difference

between the equations for change in value of exports and the

change in value of imports, or aVX - aVIM.
133

6.2.5 Changes in Economic Welfare

Regulatory control requirements will result in changes in the

market equilibrium price and quantity of petroleum products

produced and sold. These changes in the 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 precontrol 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
134

to output eliminated as a result of controls. The second element

is associated with the change in price and cost of production for

the new market equilibrium quantity. The total change in producer

surplus is the sum of these elements. After-tax measures of

surplus changes are required to estimate the impacts of controls

on producers' welfare. The after-tax surplus change is computed

by multiplying the pre-tax surplus change by a factor of 1 minus

the tax rate, (1-t) where t is the marginal tax rate. Every

dollar of after-tax surplus loss represents a complimentary loss

in tax revenues of t/(1-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 not considered. This procedure treats higher prices

paid for imports as a dead-weight loss in consumer surplus. 

Higher prices paid to foreign producers represent simply a

transfer of surplus from the United States to other countries

from a world economy perspective, but a welfare loss from the

perspective of the domestic economy.

The changes in economic surplus as measured by the change in

consumer and producer surplus previously discussed must be

adjusted to reflect the true change in social welfare resulting

from the emission controls. Adjustments must be made to consider

tax effects and to adjust for the difference between the social

discount rate and the private discount rate. These adjustments

result in a number referred to as the residual surplus to society

since these surplus changes do not relate specifically to

consumers or producers of refined petroleum products, but rather

reflect losses that must be borne by all members of society.
135

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

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/(1-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:
136

where EC is the economic cost of the proposed controls and all

other variables have been previously defined.

6.2.6 Labor Market and Energy Market Impacts

Emission control costs will result in a decrease in the market

equilibrium quantity of refined products produced and sold

domestically. This reduction in output or production will

directly cause the level of inputs used in production to

decrease. Quantification of the input reduction affecting the

labor and energy markets are of particular interest.

Two adjustments in the labor market may result from the

emission controls. The first involves monitoring and maintenance

of the emission control equipment that may cause employment

increases. Information necessary to quantify potential

employment increases for monitoring and maintenance of emission

controls is not readily available. Consequently, possible

employment increases are not considered in the analysis. 

Additionally, job losses may occur as a result of decreases in

the level of production for 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
137

The partial equilibrium model requires, as data inputs,

baseline values for variables and parameters that characterize

the petroleum refining market. These data inputs include the

number of domestic refineries in operation in 1992, the annual

production per refinery for 1992, and the relevant control costs

per refinery. All monetary values are based upon 1992 price

levels. Specific details concerning the data inputs and the

sources of the data are available in the Economic Impact Analysis

of the Petroleum Refinery NESHAP (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
138

more inelastic the supply curve, the larger the share of emission

control costs that will be paid by suppliers. 

6.2.8.1 Price Elasticity of Demand. The price elasticity of

demand represents the percentage change in the quantity demanded

resulting from each 1 percent change in the price of the product.

Petroleum products represent a very important energy source for

the United States. Many studies have been conducted which

estimate the price elasticity of demand for some or all of the

petroleum products of interest and numerous published sources of

the price elasticity of demand for petroleum products exist.

These elasticity measures are used in the analysis and are listed

in Table 6-1. Sources of these data are discussed in detail in

the Industry Profile for the Petroleum Refinery NESHAP (1993).

TABLE 6-1. ESTIMATES OF PRICE ELASTICITY OF DEMAND

FUEL TYPE

ELASTICITY

RANGE

MID-POINT

ELASTICITY

Motor Gasoline

Jet fuel

Residual Fuel Oil

Distillate Fuel Oil

Liquified Petroleum Gas

-0.55 to -0.8227

-0.1528

-0.61 to -0.7427

-0.50 to -0.9927

-0.60 to -1.027

 -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.
139

A sensitivity analysis of this assumption was made using the

upper and lower bounds of the range of elasticities.

6.2.8.2 Price Elasticity of Supply. The price elasticity of

supply or own-price elasticity of supply is a measure of the

responsiveness of producers to changes in the price of a product. 

The price elasticity of supply indicates the percentage change in

the quantity supplied of a product resulting from each 1 percent

change in the price of the product.

 Published sources of the price elasticity of supply using

current data were not readily available. It was determined that

the price elasticity of supply should be estimated

econometrically using time series data. Several estimation

approaches were considered and are discussed in detail in the

Economic Impact Analysis of the Petroleum Refinery NESHAP (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
140

petroleum refineries and on the ability of the refineries to

finance the additional capital investment in emission control

equipment. Financial data were not available for the majority of

the refineries in the industry. Available data were obtained

only for the largest publicly held petroleum refining companies. 

For this reason, the capital availability analysis has been

conducted on an industrywide basis.

One measure of financial performance frequently used to assess

profitability of a firm is net income before interest expense as

a percentage of firm assets or rate of return on investment. The

pre-control rate of return on investment (roi) is calculated as

follows:

where ni is income before interest payments and ai 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)i for

firms in the industry and on the level of assets for firms in the

industry (ai.) Since firm specific data were unavailable for all

of the affected firms, sample financial data collected by the

American Petroleum Institute (API) were used.29 Data from the

API study are available in Industry Profile for the Petroleum

Refinery NESHAP. The sample studied by API represents 71 percent

of net income in the industry and 70 percent of total industry

assets. These percentages are considered to estimate changes in

the financial ratios and are necessary to allocate changes in

income and assets resulting from emission controls to the study

sample. There is a great diversity among the refineries in the

industry; therefore, individual firm financial performance may

vary greatly from the sample estimate. The post-control return

on investment (proi) is calculated as follows:
141

where:

proi = the post-control return on investment

an = the change in income before interest resulting from

implementation of emission controls for firms in the

sample

ak = capital expenditures associated with emission

controls.

The equation proi will tend to overstate the impact of the

control measure on the rate of return on investment for the

industry over the life of the emission controls. This is true

because net capital investment in emission controls will decline

as capital is depreciated.

The ability of affected firms to finance the capital equipment

associated with the emission control is also relevant to the

analysis. Numerous financial ratios can be examined to analyze

the ability of a firm to finance capital expenditures. One such

measure is historical profitability measures such as rate of

return on investment. The analysis approach for this measure has

been previously described. The bond rating of a firm is another

indication of the credit worthiness of a firm or the ability of a

firm to finance capital expenditures with debt capital. Such

data are unavailable for many of the firms subject to the

regulation, and consequently bond ratings are not analyzed. 

Ability to pay interest payments is another criterion sometimes

used to assess the capability of a firm to finance capital

expenditures. Coverage ratios provide such information. The

interest coverage ratio, or the number of times income (before

taxes and interest) will pay interest expense, is a ratio that

provides some information about the ability of a firm to cover or
142

pay annual interest obligations. The pre-control measure of

coverage ratio is as follows:

where:

tc = number of times earnings will pay annual interest

charges

ebit = earnings before interest payments and taxes

interesti = annual interest expense

Post-control coverage ratios may be estimated as follows:

where:

aebit = estimated change in earnings before interest and

taxes of the firm

ainteresti = anticipated change in interest expense

All other variables have been previously described. The

ainterest is calculated by multiplying the capital expenditures

for the proposed controls (ak) 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:
143

where:

d/e = debt equity ratio

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:

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
144

expenditures. Income is volatile and varies from period to

period. For this reason, average income measures are used in the

study. The analysis reflects a conservative approach to

analyzing the changes likely in financial ratios for the

petroleum industry. Some decreases the cost of production

expected to result from implementation of emission controls have

not been considered. These include labor input and energy input

cost decreases. Annualized compliance costs are overstated from

a financial income perspective since these costs include a

component for earnings or return on investment. In general, the

approach followed is a 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 postcontrol 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
145

costs that significantly exceed the average. This may be the

result of the engineering method used to assign costs to

individual refineries. Moreover, the cost allocation methodology

assigns all of the control costs to the five petroleum products

of interest. These products represent less than 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
146

consider the cross-price elasticities for the petroleum products. 

Since these products are joint products, changes in the price of

one product will have an effect on the quantity supplied of the

other products.

The uncertainty of the supply estimate is acknowledged. It is

possible to conduct a sensitivity analysis of the price

elasticity supply. Such an analysis would quantify the impact of

this assumption on the reported market results. Given the

magnitude of market impact results, reasonable variations in the

price elasticity of supply are unlikely to alter the model

results significantly. 

The estimates of the secondary impacts associated with the

emission controls are based on changes predicted by the partial

equilibrium model. The limitations previously described are

applicable to primary and secondary economic impacts. As

previously noted, the estimated employment losses do not consider

potential employment gains for operating the emission control

equipment. It is important to note that the potential job losses

predicted by the model are only those directly linked to

predicted production losses in the petroleum refining industry.

Likewise, the gains or losses in markets indirectly affected by

the regulations, such as substitute product markets, complement

products markets, or in markets that use petroleum products as

inputs have not been considered in this analysis. 

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.
147

6.5 PRIMARY IMPACT, CAPITAL AVAILABILITY ANALYSIS, AND 

SECONDARY IMPACT RESULTS

Estimates of the primary economic impacts, secondary impacts,

and capital availability consequences associated with the chosen

option or preferred alternative are presented. As previously

discussed, Alternative 1 requires MACT floor controls on all

emission points other than equipment leaks where 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 postcontrol 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
148

trade balance of $1.1 million. Therefore net exports are

negative for all products except distillate fuel oil in the

baseline model. Foreign and domestic post-control supply are

added together to form the total post-control market supply. The

intersection of this post-control supply with market demand will

determine the new market equilibrium price and quantity. Postcontrol 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 0.24 percent. The estimated annual reductions in production

of the individual products range from 0.65 million barrels to

5.67 million barrels for jet fuel and motor gas, respectively. 

The production percentage decreases range from 0.13 percent to

0.58 percent for jet fuel and residual fuel oil, respectively.

Value of domestic shipments or revenues for domestic producers

are expected to increase for the five products approximately $107

million annually. The predicted changes in revenues for

individual products range from an increase of $56 million in

motor gasoline revenues to a decrease in residual fuel revenues

of approximately $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. 
149

TABLE 6-2. SUMMARY OF PRIMARY IMPACTS

Estimated Impacts

Refined Product

Price

Increases1

Production

Decreases2

Value of

Domestic

Shipments3

Motor gasoline

 Amount

 Percentage

Jet fuel 

 Amount 

 Percentage

Residual fuel 

 Amount 

 Percentage

Distillate fuel 

 Amount 

 Percentage

LPGs

 Amount 

 Percentage

TOTAL

$0.09

 0.29%

$0.14

0.53%

$0.03

0.24%

$0.08

0.29%

$0.07

0.26%

 (5.67)

(0.22%)

(0.65)

(0.13%)

(1.62)

(0.50%)

(2.78)

(0.26%)

(1.80)

(0.25%) 

(12.52)

(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.

3Values of domestic shipments are shown in millions of 1992 dollars.
150

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 Capital Availability Analysis
151

The capital availability analysis involves examining pre- and

post-control values of selected financial ratios. These ratios

include rate of return on investment, times interest earned

coverage ratio, and the debt-equity ratio. Data were not

available to estimate the ratios for many refineries in the

industry. Consequently, these ratios have been analyzed on an

industrywide basis. Since the industrywide ratios represent an

average for the industry, individual firms within the industry

may have financial ratios that differ significantly from the

average. Net income was averaged for a five year period (1986

through 1990) to avoid annual fluctuations in income that may

occur due to changes in the business cycle. Debt and equity

capital are not subject to annual fluctuations; therefore, the

most recent data available (1990) were used in the analysis.

The financial statistics provide insight regarding firms'

ability to raise capital to finance the investment in emission

control equipment. Table 6-3 shows the estimated impact on

financial ratios for the industry.

TABLE 6-3. ANALYSIS OF FINANCIAL RATIOS

 

Financial Ratios Pre-Control Ratios Post-Control Ratios

Rate of return on

investment

5.91% 5.91%

Coverage Ratio (or

Times Interest

Earned)

7.08 7.07

Debt-Equity Ratio 62.75% 62.76%

The financial ratios remain virtually unchanged as a result of

the proposed emission controls. The magnitude of the income

changes and the capital expenditures necessary for the emission

control measures do not significantly alter the financial

position of the industry. The impact of the standards on

individual refineries, however, may vary greatly from the

industry averages used in this analysis.
152

6.5.3 Labor Market Impacts and Energy Market Impacts

The estimated labor impacts associated with the NESHAP are

based on the results of the partial equilibrium analyses of the

five refined 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
153

industry also declines. The changes in energy use do not reflect

the increased energy use associated with operating and

maintaining emission control equipment. Insufficient data were

available to consider such changes in energy costs.
154

TABLE 6-4. SUMMARY OF SECONDARY REGULATORY IMPACTS

Estimated Impacts

Refined Product Labor Input1 Energy Input2

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.

1

Indicates estimated reduction in number of jobs.

2Reduction in energy use in millions of 1992 dollars.
155

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
156

increases and reductions in domestic output are less than 1

percent for each of the refined products. The value of domestic

shipments or revenues to domestic producers are anticipated to

increase for the 5 product categories by a total of $107 million

annually ($1992). Emission controls costs are small relative to

the financial resources of affected producers, and on average,

refineries should not find it difficult to raise the capital

necessary to finance the purchase and installation of emission

controls. 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 Amount1 Percentage

Dollar Value

of Net Export

Change2

Motor Gasoline

Jet fuel

Residual fuel

Distillate fuel

LPGs

Total

(0.43)

(0.23)

(0.91)

(0.48)

(0.21)

(2.26)

(0.54%)

(1.41%)

(0.81%)

(40.92%)

(0.54%)

(1.24%)

($21.92)

($8.14)

($16.81)

($12.67)

($8.68)

($68.22)

NOTES: ( ) indicates decreases.

1Millions of barrels.

2Millions of dollars ($1992).
157

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.
158

6.7.2 Methodology

Data are not readily available to estimate the small business

impacts for two of the criteria (1 and 3) listed in the previous

section. The information necessary to make such comparisons are

generally considered proprietary by small business firms. 

Consequently, the analysis will focus on remaining two (2 and 4)

criteria of the potential for adverse impacts. Closure of small

businesses and a comparison of the compliance costs as a

percentage of sales for small and large business entities will be

examined.

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
159

designated to be small businesses. The estimated number of

closures is therefore less than 20 percent of the small

refineries. However, it is important to note that the firms

designated in the model as being at the greatest risk for closure

were small refineries.

Compliance costs as a percentage of sales were computed both

for the small refineries and for those refineries that are not

considered small. The cost to sales ratio for the small

refineries was 0.19 percent of sales while the cost to sales

ratio for all other refineries was 0.08 percent. The

differential between these two rates exceeds ten percent, and

consequently, a conclusion is drawn that a significant number of

small businesses are adversely affected by the 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
160

of the sum of the change in domestic consumer surplus (aCSd), 

the change in producer surplus (aPS), and the change in the

residual surplus to society (aRS) 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

 

$342.86

$(174.32)

$(73.25)

Total Social Cost of Alternative 13 $95.29

NOTES: 1Brackets 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.
161

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.
162

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-WA78A.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.
163

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

emission 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.

7.1 IDENTIFICATION OF POTENTIAL BENEFIT CATEGORIES
164

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

air, wet or dry deposition of particulate HAPs and particles to
165

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.
166

TABLE 7-1. POTENTIAL HEALTH AND WELFARE EFFECTS ASSOCIATED WITH EXPOSURE POLLUTANTS2

EffectType

Effect Category Effect End-Point Citation

Health Mortality Carcinogenicity

GenotoxicityNon-Cancer lethality

EPA (1990)3, 

(1989)4

Graham et al. Voorhees et a

ChronicMorbidity

NeurotoxicityImmunotoxicityPulmonary function decrementLiver damageGastrointestinal toxicityKidney damageCardiovascular impairmentHematopoietic (Blooddisorders)Reproductive/Developmentaltoxicity

All morbidity obtained from 

al. (1989)7 V

(1989)8, Cote 

(1988)9

Acute Morbidity Pulmonary function decrement

Dermal irritationEye irritation

Welfare Materials

Damage

Corrosion/Deterioration NAS (1975)10
167

Aesthetic Unpleasant odors

Transportation safetyconcerns

Agriculture Yield reductions/Foliar

injury

Stern et al. 

EcosystemStructure

Biomass decreaseSpecies richness declineSpecies diversity declineCommunity size decreaseOrganism lifespan decreaseTrophic web shortening

Weinstein and 
168

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
169

affects a portion of the body other than the site of entry. 

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
170

of these factors may contribute to an overall change in the

structure (i.e., composition) and function of the ecosystem.

The adverse, non-human biological effects of HAP emissions

include ecosystem and recreational and commercial fishery

impacts. Atmospheric deposition of HAPs directly to land may

affect terrestrial ecosystems. Atmospheric deposition of HAPs

also contributes to adverse aquatic ecosystem effects. This not

only has adverse implications for individual wildlife species and

ecosystems as a whole, but also the humans who may ingest

contaminated fish and waterfowl. In general, HAP emission

reductions achieved through the petroleum refinery NESHAP should

reduce the associated adverse environmental impacts.

7.2.2 Benefits of Reduced VOC Emissions

Emissions of VOCs have been associated with a variety of

health and welfare impacts. VOC emissions, together with NOx,

are precursors 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
171

to chronic, structural damage to the lungs.16 To the extent that

these findings are verified, the potential scope of benefits

related to reductions in ozone concentrations could be expanded

significantly.

Major ozone health effects are: alterations in lung capacity

and breathing frequency; eye, nose and throat irritation; reduced

exercise performance; malaise and nausea; increased sensitivity

of airways; aggravation of existing respiratory disease;

decreased sensitivity to respiratory infection; and

extrapulmonary effects (central nervous system, liver,

cardiovascular, and reproductive effects).17 In general, it is

expected that reductions in VOCs through the petroleum refinery

NESHAP regulation is a mechanism by which the ambient ozone

concentration may be reduced and, in turn, reduce the incidence

of the adverse health effects of ozone exposure. In this

section, the benefits of reducing VOC emissions is examined in

terms of reductions in ozone.

7.2.2.2 Welfare Benefits of VOC Reduction. In addition to

acute and 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.
172

REFERENCES

1. U.S. Environmental Protection Agency. Regulatory Impact

Analysis for the National Emissions Standards for

Hazardous Air Pollutants for Source Categories: Organic

Hazardous Air Pollutants from the Synthetic Organic

Chemical Manufacturing Industry and Seven Other Processes. 

Draft Report. Office of Air Quality Planning and

Standards. Research Triangle Park, NC. EPA-450/3-92-009. 

December 1992.

2. Mathtech, Inc. Benefit Analysis Issues for Section 112

Regulations. Final report prepared for U.S. Environmental

Protection Agency. Office of Air Quality Planning and

Standards. Contract No. 68-D8-0094. Research Triangle

Park, NC. May 1992.

3. U.S. Environmental Protection Agency. Cancer Risk from

Outdoor Exposure to Air Toxics. Volume I. EPA-450/1-90-

004a. Office of Air Quality Planning and Standards. 

Research Triangle Park, NC. September 1990.

4. Graham, John D., D.R. Holtgrave, and M.J. Sawery. "The

Potential Health Benefits of Controlling Hazardous Air

Pollutants." In: Health Benefits of Air Pollution

Control: A Discussion. Blodgett, J. (ed). Congressional

Research Service report to Congress. CR589-161. 

Washington, DC. February 1989.

5. Reference 4.

6. Voorhees, A., B. Hassett, and I. Cote. Analysis of the

Potential for Non-Cancer Health Risks Associated with

Exposure to Toxic Air Pollutants. Paper presented at the

82nd Annual Meeting of the Air and Waste Management

Association. 1989.

7. Reference 4.

8. Reference 6.

9. Cote, I., L. Cupitt and B. Hassett. Toxic Air Pollutants

and Non-Cancer Health Risks. Unpublished paper provided

by B. Hassett. 1988.

10. NAS. Chlorine and Hydrogen Chloride. National Academy of

Sciences, National Research Council. Chapter 7. 1975.

11. Stern, A. et al. Fundamentals of Air Pollution. Academic

Press, New York. 1973.

12. Weinstein, D. and E. Birk. The Effects of Chemicals on

the Structure of Terrestrial Ecosystems: Mechanisms and
REFERENCES (continued)

173

Patterns of Change. In: Levin, S. et al. (eds). 

Ecotoxicology: Problems and Approaches. Chapter 7. pp.

181-209. Springer-Verlag, New York. 1989.

13. Reference 1. p. 3-5.

14. Reference 1. pp. 8-4 to 8-5.

15. U.S. Environmental Protection Agency. Ecological Exposure

and Effects of Airborne Toxic Chemicals: An Overview. 

EPA/6003-91/001. Environmental Research Laboratory. 

Corvallis, OR. 1991.

16. Reference 4.

17. Reference 1. pp. 8-8 to 8-9.
174

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
175

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 Phenol

Benzene Cresols/Cresylic Acid

Ethylbenzene Methyl Tertiary Butyl Ether

Hexane Methyl Ethyl Ketone

Naphthalene Toluene

Xylenes
176

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 (:g/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. 
177

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

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 × 10-6 (:g/m3)

-1. In a

population of 1,000,000 people, each exposed to 5 :g/m3 of

benzene for 70 years (a lifetime of constant exposure), the

number of excess cancer cases in the population due to this

exposure is estimated to be 41.5 cancer cases over 70 years (5

:g/m3 × 1,000,000 × 8.3 × 10-6 (:g/m3)

-1). On an annual average

basis, this is equal to 0.59 excess cases per year in the

population.

From the above example calculation, it is clear that each

element in the calculation algorithm may contribute to

uncertainty in the final estimate of cancer risk. Table 8-2

summarizes the major sources of uncertainty with the data and

methods used in the standard approach to cancer risk assessment. 

Additional issues arise in estimating economic benefits from the

risk assessment information. Table 8-3 identifies these issues.

8.1.1.2 Value of a Statistical Life. Economists have used

labor market data to identify the wage-risk tradeoff accepted by

workers in high risk occupations and to infer the implicit value

of reduction in small risks of mortality. This is mathematically

equivalent to valuing a small reduction in risk of mortality per

person over a large number of people (usually one million

people). Multiplication of the value of a statistical life

times the expected number of lives saved due to the reduced

cancer risk provides an estimate of the economic benefits

associated with the regulation. Estimates of the value of a

statistical life have been developed by examining the wage-risk

tradeoff revealed by workers accepting jobs with known risks. 

Viscusi recently completed a survey of over 20 of these studies

and recommends an initial range of $3-$7 million (December 1990

dollars) as an estimate of the statistical value of a life.2
178

Using this range in an environmental policy analysis requires

consideration of several factors that could bias the transfer of

the results. Specifically, adjustments may be required to

account for differences across applications. These differences

include:

C 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.

C 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 agesensitive.

C Income: Income levels of exposed individuals may affect

willingness to pay. Economic theory would suggest a

positive elasticity between income and risk reduction.

C 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.
179

TABLE 8-2. SOURCES OF UNCERTAINTY IN CANCER RISK ASSESSMENT1

C 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.

C 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.

C 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.

C 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.
180

TABLE 8-3. UNCERTAINTIES IN BENEFIT ANALYSIS

C 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.

C Benefit calculations should reflect changes in

concentrations over time related to economic responses to

the regulatory action.

C Benefit calculations should reflect any changes to the

composition of the affected population and possible

behavioral responses to exposure.

C 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.
181

 

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

HAP URF (x 106)

Benzene 8.3

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
182

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 MIR Annual Cancer Incidence

Benzene 1.8 * 10-4 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
183

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. 
184

Table 8-6. RFCS AND NUMBER OF INDIVIDUALS EXPOSED AT OR ABOVE 

RFC BY HAPS

HAP RfC (mg/m3) Individuals Exposed

 At or Above RfC

Hexane 0.2 0

Hydrogen Chloride 0.07 1,810

Methyl Ethyl Ketone 1 0

Toluene 0.4 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 transfer." 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, 
185

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

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 report indicates that all health impacts are estimated for

non-attainment areas only. Therefore, no health benefits are
186

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

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.
187

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

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
188

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

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. 
189

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

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
190

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. 

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 108.48

Range 3.4 - 213.5

Quantified Agricultural Benefits

Average 44.9

Range 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
191

all categories of benefits attributable to VOC reductions. Since

lack of data prevent all benefit categories from being monetized,

a direct comparison of benefits to costs may not be helpful in

determining the desirable regulatory alternative. An assessment

of the incremental cost-effectiveness analysis will represent the

cost of the air 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. 
192

REFERENCES

1. 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.

2. Viscusi, W. Kip. "The Value of Risks to Life and Health." 

Journal of Economic Literature. pp. 1912-1946. December 

1993.

3. Voorhees, A., B. Hassett, and I. Cote. Analysis of the 

Potential for Non-Cancer Health Risks Associated with 

Exposure to Toxic Air Pollutants. Paper presented at the 

82nd Annual Meeting of the Air and Waste Management

Association. 1989.

4. Office of Technology Assessment. Catching Our Breath: 

Next Steps for Reducing Urban Ozone. OTA-O-412. 

Washington, DC. U.S. Government Printing Office.

 July 1989.

 

5. Horstman, D., W. McDonnell, L. Folinsbee, S. Abdal-Salaam,

and P. Ives. Changes 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.

6. Horst, R.L., Jr. Personal communication with L. Chestnut. 

January 26, 1994.

7. Reference 4, p. 107.

8. Portney, P. and J. Mullahy. "Urban Air Quality and 

Chronic Respiratory Disease." Regional Science and Urban 

Economics. Vol. 20. p. 407-18. 1990.
193

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
194

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. 
195

Table 9-1. COMPARISON OF ANNUAL BENEFITS TO COSTS FOR THE 

 

 NATIONAL PETROLEUM REFINING

INDUSTRY 

 NESHAP (MILLIONS OF 1992 $ PER YEAR)

Alternative 1

Benefits $153.4

Social Costs $95.3

Benefits Less

 Social Costs 

$58.1

NOTES: ( ) represent negative values. 
196

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-equivalent-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.