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 1995ii

This report is issued by the Emission Standards Div ision of the Office of Air Quality Planning and Standards, U .S. Environmental Protection Agency. It presents techn ical data.iii CONTENTS

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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 . E S-2 ES.3 NEED FOR REGULATION . . . . . . . . . . . . . . ES-4 ES.4 CONTROL TECHNIQUES AND REGULATORY ALTERNATIVES E S-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 STANDAR D 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 REGULATI ON 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 . . . . . . . . . . . . . . . 20CONTENTS (continued)

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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 CO STS 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 . . . 132CONTENTS (continued)

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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 . 1 60 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 . . . . . . . . . 17 0 8.1 METHODOLOGY FOR DEVELOPMENT OF BENEFIT ESTIMATES 170 8.1.1 Benefits of Reduced Cancer Risk Associated wit h 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 . . . . . 189vi TABLES
Page ES-1 SUMMARY OF TOTAL COSTS IN THE FIFTH YEAR FOR TH E 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 EMISS ION

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 P OINT 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 EFFECTIVE NESS

BY ALTERNATIVE . . . . . . . . . . . . . . . . . 93 5-4 COST, VOC EMISSION REDUCTION, AND COST EFFECTIVE NESS

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 INCIDE NCE

OF CARCINOGENIC HAPs . . . . . . . . . . . . . . 178 8-6 RFCS AND NUMBER OF INDIVIDUALS EXPOSED AT OR ABO VE

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 . . . 191vii FIGURES
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6-1 ILLUSTRATION OF POST-NESHAP MODEL. . . . . . . 125viii 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 NO x 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 SO 2 sulfur dioxide SOCMI Synthetic Organic Chemical Manufacturing indus try URF unit risk factor VOC volatile organic compoundES-1 EXECUTIVE SUMMARY

ES.1 PURPOSE AND STATUTORY AUTHORITY

This report analyzes the regulatory impacts of the Petroleum Refinery National Emission Standard for Hazardous A ir Pollutants (NESHAP), which is being promulgated under Section 112 of the Clean Air Act Amendments of 1990 (CAA). This emiss ion standard would regulate the emissions of certain hazardous a ir pollutants (HAPs) from petroleum refineries. The petroleum re fineries industry group includes any facility engaged in the production of motor gasoline, naphthas, kerosene, jet fuels, dist illate fuel oils, residual fuel oils, lubricants, or other prod ucts made from crude oil or unfinished petroleum derivatives. Thi s report analyzes the impact that regulatory action is likel y to have on the petroleum refining industry, and on society as a whole.
The President issued Executive Order 12866 on Octob er 4, 1993, which requires EPA to prepare RIAs (or economic ass essments) 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 la ter in the report, that cost is now less than $100 million, bu t it has been
decided that due to the level of interest in the re sults 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 t o a mandatory assessment of benefits and costs, E.O. 12866 specif ies that EPA, to the extent allowed by the CAA and court orders, demonstrateES-2

(1) that the benefits of the NESHAP regulation will outweigh the costs and (2) that the maximum level of net benefit s (including potential economic, environmental, public health an d 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 "Alte rnative 1") and calculated the compliance costs, economic impac ts, 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 m aximum achievable control technology (MACT), consistent wi th 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 Refine ry NESHAP, EPA chose regulatory options based on control options o n an emission point basis. An emission point is defined as a poi nt within a refinery which emits one or more HAPs. The emissio n points to be regulated under the source category for this standa rd are: equipment leaks, storage vessels, miscellaneous pro cess 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 reflecti ng the application of MACT. The definition of source in t he proposed standard is "the collection of emission points in H AP-emitting petroleum refining processes within the source cate gory." The source comprises all miscellaneous process vents, s torage vessels, wastewater collection and treatment system s, 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 sourc e is an important element of this NESHAP because it describ es the specific grouping of emission points within the sou rce categoryES-3

to which each standard applies. The rule is made u p of seven different subjects: applicability, definitions, an d general standards; miscellaneous process vent provisions; s torage vessel provisions; wastewater provisions; equipment leak p rovisions; recordkeeping and reporting provisions; and emissio ns 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 categor y. The emission standard applies to petroleum refining pro cess units that are part of a major source as defined in Secti on 112 of the CAA. EPA's initial source category list (57 FR 315 76, July 16, 1992), required by section 112(c) of the A ct, identifies categories of sources for which NESHAP are to be es tablished. Two categories of sources are listed in the initial source category list for petroleum refineries: (1) cataly tic cracking (fluid and other) units, catalytic reforming units, and sulfur plant units and (2) other sources not distinctly li sted. Based on an EPA review of information on petroleum refine ries during development of the proposed standards, it was deter mined that some of the emissions points from the two listed ca tegories of
sources have similar characteristics and can be con trolled by the same control techniques. EPA determined that it is most effective to regulate these emission points in a si ngle regulation. EPA intends to amend the source category list to de fine the processes and emission points regulated in this rul e as one source category. Catalyst regeneration vents, cata lytic cracking units, catalytic reforming units, and vents from su lfur recovery plants are being defined as the second source categ ory. Data analyses conducted in developing the MACT floo r for miscellaneous process vents determined that controls can achieve 98 percent organic HAP reduction or an outlet organ ic HAP concentration of 20 ppmv or less for all vent strea ms. The storage vessel provision specifies the control systems whichES-4

represent the MACT floor to be applied to storage v essels. The
wastewater provisions of this rule are based on the benzene wa ste operations NESHAP (BWON), which controls 75 percent of the benzene in refinery wastewater. The wastewater str eams subject to this rule include water, raw material, intermedi ate product, by-product, co-product, or waste material that cont ains HAPs and is discharged into an individual drain system. The equipment
leakprovisions of the promulgated rule are based on th e Petroleum Refinery NSPS Equipment Leak provisions, as well as the negotiated equipment leak regulation included in th e Hazardous Organics NESHAP (HON) (40 CFR 63 subpart H). The rule specifies the necessary recordkeeping and reporting requirements to verify compliance with the MACT flo or for each of the four emission points. EPA is also allowing emi ssion averaging among existing miscellaneous process vent s, storage tanks, and wastewater streams within a refinery. U nder emission averaging, a system of emission "credits" and "debi ts" would be used to determine whether the source is achieving t he required emission reductions. With emissions averaging as p art 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 huma n health and the environment from petroleum refineries is th e emission of
HAPs. Health risks from emissions of HAPs into the air include increases in cancer incidences, genotoxicity, neuro toxicity, liver damage, cardiovascular impairment, and other toxic effects. In addition to threats to human health, there are a lso detrimental effects on human welfare, such reduced agricultural crop yields and reduced ecosystem diversity and act ivity. The U.S. Office of Management and Budget (OMB) directs regulatory agencies to demonstrate the need for an economicall y significant
rule. The RIA must show that a market failure exis ts and that it cannot be resolved by measures other than Federal r egulation. Externality is one type of market failure. HAP emi ssionsES-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 th e HAPs generated in the refining process. With the NESHAP in effect, the amount that refiners must incur to refine petro leum products will more closely approximate the full social costs of production. The necessity for a uniform national s tandard is based on the determination that air pollution cross es jurisdictional lines, and uniform national standard s, 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 o f control techniques as options for compliance with the stand ard. Combustion technology, internal floating roofs, andproduct recovery devices, including internal floating roofs and vapor recovery tanks, are all part of the technology requ irements for the Petroleum Refinery NESHAP. In addition, leak d etection and repair (LDAR) programs will be used to control equi pment leaks.
Based on the determination of the MACT floor for ea ch of the four emission points, EPA developed a single regula tory alternative, Alternative 1. It is a hybrid option, that incorporates MACT floor level control for wastewate r collection and treatment systems, storage vessels, and miscell aneous 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 incrementa l costs and benefits of going to another alternative.

ES.5 COST ANALYSIS The annualized compliance costs by emission point a re shown in
Table ES-1 for the chosen alternative. The total n ational cost of Alternative 1 in the fifth year is $79 million.TABLE ES-1. SUMMARY OF TOTAL COSTS IN THE FIFTH YEARFOR THE PETROLEUM REFINERIES NESHAPCapital Costs and Annual Fifth Year Costs (1000$/yr)(1992 Dollars)Emission Point OptionTotalCapitalCostsExistingSourcesNewConstruction TotalAlternative1Equipment LeaksMiscellaneousProcess VentsWastewaterSystemsStorage VesselsOtherRecordkeepingand ReportingFloorOption 11FloorFloor1Floor1$142,000$21,000$ 0$48,000$2,000$69,000$58,000$12,000$ 0$8,000$ 0$(210)$370$ 0$98$69,000$57,790$12,370$ 0$8,098$57,790$12,370$ 0$8,098$1,000TOTAL COST $213,000$79,190NOTES:1Alternative 1.ES-7

In addition to provisions for the installation of c ontrol equipment, the promulgated regulation includes requ irements for monitoring, recordkeeping, and reporting (MRR). EP A 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 e mission point.

ES.6 ECONOMIC IMPACTS AND SOCIAL COSTS An economic impact analysis (EIA) was conducted to evaluate the effect of increased compliance costs for emissi on control equipment on the domestic petroleum refining market . The partial equilibrium model used in the EIA utilized the cost s 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, cha nges in the value of domestic shipments, and possible refinery closures. Estimated secondary effects include labor market ad justments, energy input market changes, and foreign trade effe cts. Welfare changes for consumers, producers, and society at la rge or the
social costs of the emission controls were also eva luated. The estimated market changes from the use of these emis sion controls were relatively small. The social costs of regulation incorporate costs bo rne by society for pollution abatement. The social costs reflect the opportunity cost or economic cost of resources usedin 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 Alte rnative 1 is
shown in Table ES-2. The social costs are used lat er in the RIA to conduct a benefit cost analysis, for the proper costs to compare benefits with are the social costs, since t he 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 P ETROLEUM REFINERIES NESHAP

Social Cost Category Net Costs 1 (millions of 1992 dollars)

Surplus Losses for Preferred Alternative:
Change in Consumer Surplus Change in Producer Surplus Change in Residual Surplus to Society 2 $342.86 $(174.32) $(73.25)

Total Social Cost of Alternative 1 3 $95.29

NOTES: 1 Brackets indicate negative surplus losses or surplu s gains.

2 Residual surplus loss to society includes adjustmen ts necessary to equate the relevant discount rate t o the social cost of capital and to consider appropriate tax effect a djustments. 3 Alternative 1 includes floor controls for all emiss ion points except equipment leaks. Option 1 is pre ferred 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 alternativ e (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 r eductions projected as a result of implementation of the petr oleum refinery NESHAP. The promulgated regulation is expected to reduce emissions of HAPs emitted from storage tanks, proce ss 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. HA P benefits are presented separately from the benefits associated s pecifically
with VOC emission reductions. The predicted emissions of a few HAPs associated wi th this regulation have been classified as probable or know n human carcinogens. As a result, one of the benefits of t he proposed regulation is a reduction in the risk of cancer mor tality. Other benefit categories include reduced exposure to nonc arcinogenic HAPs, and reduced exposure to VOCs.
Emissions of VOCs have been associated with a varie ty of health and welfare impacts. VOC emissions, togethe r with NO
x , are precursors to the formation of tropospheric ozo ne. 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 reductio n for two categories, reduced acute health effects in ozone n onattainment areas and increased agricultural crop yields nation wide. The quantification of dollar benefits for all benefit c ategories 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 ben efits could not quantified for all benefit categories (includin g acute health
effects in ozone attainment areas and chronic healt h effects nationwide), the resulting monetized benefits estim ate 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 Hu man Exposure Model (HEM), the annual cancer risk caused by HAP e missions from petroleum refineries was estimated. Generally, thi s benefit category is calculated as the difference in estimat ed annual cancer incidence before and after implementation of each regulatory alternative. The annual cancer incidenc e associated with this rule was less than one statistical life p er year. EPA's risk assessment indicates that over 4.5 milli on people exposed to refinery emissions have an individual ri sk greater than 1 in 1 million from exposure to benzene, a kno wn human carcinogen.
The benefits of reduced emissions of VOC from a MAC T 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 value s 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 heal th benefits are defined in terms of reductions occurring only i n nonattainment areas. (Nonattainment areas are geograph ical locations in which the Federal ambient air quality standard ( NAAQS) for ozone has been violated.) Table ES-3 presents the V OC emission
reductions for refineries in nonattainment and atta inment areas associated Alternative 1, the chosen alternative.

The benefit transfer ratio range for acute health i mpacts used in this analysis is presented in Table ES-4. In or der to quantify VOC emission reductions for these impacts, the ratios were multiplied by VOC emission reductions from pet roleum
refineries located in ozone non-attainment areas. EstimatedES-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 decreasedozone concentrations due to VOC emission reductions, calc ulated 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 PO INT

VOC Emission Reductions by Regulatory Alternative (Mg/yr) 3

Alternative 1
Emission Point 2 Nonattainment 1 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 252,000ES-12 1 VOC emission reductions include only those associated with control of the 87 refineries locate d in ozone nonattainment areas. 2 No further control is assumed for wastewater streams, and therefore, emission reductions associated with this emission point is zero. 3 Emission reduction estimates do not incorporate reductions occurring at new sources.

TABLE ES-4. BENEFIT PER MEGAGRAM VALUES FOR VOC RE DUCTIONS

Benefits Transfer Value 1 1992 Dollars/Megagram 2

Average $800 Range $25 - $1,574

1 The benefits transfer value in the table quantifies only the benefits attributable to reduced acute health impac ts in ozone
nonattainment areas.

2 Values 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 t he Agency was
unable to examine the incremental benefits and incr emental costs of going to a second alternative and determine if m aximum net benefits are approached with the chosen alternative . There are positive net benefits from control at the chosen al ternative,ES-13

however. The net benefits to society are $58.1 mil lion 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 Emis sion Standard for Hazardous Air Pollutants (NESHAP). This emissi on standard would regulate the emissions of certain hazardous a ir pollutants (HAPs) from petroleum refineries. The petroleum re fineries industry group includes any facility engaged in pro ducing motor gasoline, naphthas, kerosene, jet fuels, distillate fuel oils, residual fuel oils, lubricants, or other products m ade from crude oil or unfinished petroleum derivatives. This repo rt analyzes the impact that regulatory action is likely to have on the petroleum refining industry, and on society as a wh ole. 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 thi s report.

1.1 PURPOSE
The President issued Executive Order 12866 on Octob er 4, 1993. It requires EPA to prepare RIAs for all "significan t" regulatory
actions. The criteria set forth in Section 1 of th e Order for determining whether a regulation is a significant r ule are that the rule: (1) is likely to have an annual effect o n the economy of $100 million or more, or adversely and materiall y affect a sector of the economy, productivity, competition, j obs, the environment, public health or safety, or State, loc al, or tribal governments or communities; (2) is likely to create a serious2

inconsistency or otherwise interfere with an action taken or planned by another agency; (3) is likely to materia lly 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 t he principles set forth in the Executive Order. At proposal, EPAdetermined that the petroleum refinery NESHAP is a "significan t" rule
because it will have an annual effect on the econom y of more than $100 million, and is therefore subject to the requi rements of Executive Order 12866. While the NESHAP is no long er 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 promulgati on. 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, envi ronmental, public health and safety and other advantages; dist ributive impacts; and equity) will be reached. EPA has chos en a single regulatory option for evaluation in this RIA. Bene fits and costs are quantified to the greatest extent allowed by av ailable data. As stipulated in E.O. 12866, in deciding whether an d how to regulate, EPA is required to assess all costs and b enefits of available regulatory alternatives, including the al ternative of not regulating. Accordingly, the cost benefit anal ysis in this report is measured against the baseline, which repr esents 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 m aximum achievable control technology (MACT), consistent wi th sections 112(d) and 112(h) of the CAA. This sectio n provides a brief history of Section 112 of the Act and backgro und regarding3

the definition of source categories and emission po ints 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 categori es of sources of the emissions, rather than being set by pollutan t. In addition, the CAA establishes specific criteria for establishing
a minimum level of control and criteria to be consi dered in evaluating control options more stringent than the minimum control level. Assessment and control of any remai ning unacceptable health or environmental risk is to occ ur 8 years after the rules are promulgated. For the subject NESHAP, EPA chose regulatory option s based on control options on an emission point basis. The pe troleum refinery NESHAP regulates emissions of all HAPs emi tted from all emission points at both new and existing petroleum refinery sources. An emission point is defined as a point w ithin a refinery which emits one or more HAPs. The emissio n points to be regulated under the source category for this standa rd are: equipment leaks, storage vessels, miscellaneous pro cess vents, and wastewater collection and treatment systems.

1.3 REPORT ORGANIZATION Chapter 2 presents a summary of the promulgated reg ulation for the Petroleum Refinery NESHAP. Executive Order 128 66 requires EPA to prove that regulation is necessary due to a compelling public need, such as material failures of private m arkets to protect or improve the health and safety of the pub lic, the environment, or the well-being of the public. In o rder to satisfy this requirement, Chapter 3 presents the ma rket conditions which necessitate regulatory action. A
characterization of the air emissions associated wi th 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 reg ulatory
alternatives which were considered for the standard . EPA's designation of control options reflects the best co ntrol technology available to refineries, given existing technology levels. Chapter 5 presents the approach for estima ting regulatory compliance costs, the quantitative estim ates of each control option under analysis, and the issues and a ssumptions upon which the estimates were based. The associate d emission reductions and cost effectiveness of the regulatory options are also presented. Chapter 6 provides an economic profile of the petro leum refining industry, and describes the methodology us ed to estimate the economic effects of a chosen hybrid option on t he 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 explaine d in this chapter, some benefits are nonquantifiable and ther efore cannot be usefully estimated. Qualitative measures of the air related
benefits associated with a decrease in HAP emission s are presented separately from those associated with a d ecrease in volatile organic compound (VOC) emissions. Benefit s which are difficult to quantify, but nevertheless essential t o consider, are also identified in this chapter. Chapter 8 provides a quantitative assessment of tho se benefits which were identified in Chapter 7. The methodolog y used to arrive at these estimates is outlined and any limit ations are identified. The quantitative estimates of benefits associated with risk reductions and human health effects are p resented separately. The Executive Order requires EPA to assess both the costs and the benefits of the intended regulation and, recogn izing that some costs and benefits are difficult to quantify, adopt a regulation only on a determination that the benefit s of the regulation justify the costs. Chapter 9 compares t he annualized5

costs to the annualized benefits for each of the tw o regulatory options in this RIA. Economic efficiency is consid ered within the context of a welfare analysis, using the social costs of regulation.67

2.0 PROMULGATED PETROLEUM REFINERIES EMISSION STAN DARD
IN BRIEF The discussion in this chapter briefly summarizes t he requirements of the rule, without accounting for ho w the provisions were selected or how emission cutoffs we re determined. The promulgated rule, the NESHAP for petroleum refi neries, would require sources to achieve emission limits reflecti ng the application of MACT, consistent with sections 112(d ) and 112(h) of the CAA. The promulgated rule would regulate th e 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 sourceas the collection of emission points in HAP-emitting petroleum refining processes within the source category. The source comprises a ll miscellaneous process vents, storage vessels, waste water streams, and equipment leaks associated with petroleum refin ing process units that are located at a single plant site cover ing a contiguous area under common control. The definiti on of source is an important element of this NESHAP because it d escribes the specific grouping of emission points within the sou rce 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; recordkeepin g and reporting provisions; and emissions averaging. Eac h 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 categor y. Petroleum refineries are defined as facilities engaged in pro ducing 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 petroleu m derivatives. The emission standard applies to petroleum refining process units that are part of a major source as defined in Secti on 112 of the CAA. EPA's initial source category list (57 FR 315 76, July 16, 1992), required by section 112(c) of the A ct, identifies categories of sources for which NESHAP are to be es tablished. This list includes all categories of major sources of HAPs known to the EPA at this time, and all area source catego ries for which findings of adverse effects warranting regulation h ave been made. Two categories of sources are listed in the initial source category list for petroleum refineries: (1) cataly tic cracking (fluid and other) units, catalytic reforming units, and sulfur plant units and (2) other sources not distinctly li sted. Based on an EPA review of information on petroleumrefineries during development of the promulgated standards, it was determined that some of the emissions points from t he two listed categories of sources have similar characteristics and can be controlled by the same control techniques. In part icular, miscellaneous process vents emitting organic HAPs, storage vessels, wastewater streams, and leaks from equipme nt in organic HAP service within catalytic cracking units, cataly tic reforming units, and sulfur plant units are similar to emissi on points from the other process units at petroleum refineries. E PA determined that it is most effective to regulate these emissio n points in a single regulation, and all emission points regulate d by the subject NESHAP are in a single source category.

2.1.2 Miscellaneous Process Vent Provisions9

Miscellaneous process vents include vents from petr oleum refining process units that emit organic HAP's. Ve nts that are routed to the refinery fuel gas system are consider ed to be part of the process and are not subject to the standard. The miscellaneous process vent provisions define two gr oups of vents. Group 1 process vents are those with VOC emissions greater than or equal to 33 kilograms per day (kg/day) (72 lbs/d ay) at existing sources. Group 2 vents are vents with emi ssions below
this level. The miscellaneous process vent provisions for new a nd 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. T he process vent provisions are the same for both new and exist ing 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 c apacity and a maximum true vapor pressure above the values specif ied in the regulation. Group 2 vessels are all storage vessel s that are not Group 1 vessels. The storage provisions require th at one of the following control systems be applied to Group 1 sto rage vessels: (1) An internal floating roof (IFR) with proper se als; (2) an external floating roof (EFR) with proper seals; (3) an EFR converted to an IFR with proper seals; or (4) a clo sed vent system with a 95 percent efficient control device. The storage provisions give details on the type of seals requir ed. Monitoring and compliance provisions for Group 1 ve ssels include periodic external visual inspections of vessels androof seals, as well as less frequent internal inspections. If a closed vent system and control device is used for venting emiss ions 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 (m 3 ) (1,115 barrels or 47,000 gallons) that store liqu ids 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 t he NESHAP requirements until the next scheduled inspection an d 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 m 3 (950 barrels or 40,000 gallons), with vapor pressures equal to or greater than 3.4 k Pa (0.5 psia), and vessels with capacities equal to or greater tha n 76 m 3 (475 barrels or 20,000 gallons) storing liquids with vap or 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 (in cluding 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 benze ne as a surrogate for all HAPs from wastewater in petroleumrefineries. EPA research concluded that benzene is a good indic ator of the presence of other HAPs. The wastewater streams sub ject to this rule include water, raw material, intermediate prod uct, by-product, co-product, or waste material that cont ains 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 wi th a total annual benzene loading of at least 10 megagrams per year and are not exempt from control requirements under 40 CFR 6 1 subpart FF (the BWON). In general, streams are not exempt fro m 40 CFR part 61 subpart FF if they contain a concentration of at least 10 parts per million by weight (ppmw) benzene, and hav e a flow rate of at least 0.02 liters per minute (l/min) (0.005 g allons per11

minutes (gal/min)). Group 2 streams are wastewater streams that are not Group 1. The wastewater provisions of the final rule refer t o the BWON for both new and existing sources, which requires o wners or operators of a Group 1 wastewater stream to reduce benzene mass by 99 percent using suppression followed by steam s tripping, biotreatment, or other treatment processes. Vents from stream strippers and other waste management or treatment u nits are required to be controlled by a control device achie ving 95 percent emissions reduction or 20 ppmv at the outle t of the control device. The performance tests, monitoring, reporting, and recordkeeping provisions required to demonstrat e compliance
are included in the BWON. No controls or monitorin g are required for Group 2 wastewater streams.
2.1.5 Equipment Leak Provisions The equipment leak standards for the petroleum refi nery NESHAP allow owners and operators of existing sources to c hoose between complying with equipment leaks provisions in 40 CFRpart 60 subpart VV (Petroleum Refinery NSPS Equipment Leaks Standard) or complying with a modified negotiatied regulation fo r equipment leaks presented in 40 CFR part 63 subpart H (HON eq uipment leaks). The differences in the refinery equipment leak requirements and the HON equipment leak provisions are in the leak definitions and connector monitoring provision s. Under either of the two options, existing refinerie s subject to the rule will be required to implement a Leak De tection and Repair (LDAR) program with the same leak definition s (10,000 ppm) and frequencies as specified in 40 CFR part 60 subp art VV within 3 years after promulgation of the petroleum refiner ies NESHAP. Refineries that choose to comply with the modified negotiated regulation would implement the Phase II leak defini tions and frequencies at the end of the fourth year after pro mulgation, and comply with Phase III requirements 5 1/2 years afte r promulgation. Phase III has lower leak definitions , but allows less frequent monitoring for good performers. Alth ough the modified negotiated regulation is not required in t he final rule,12

the EPA believes that it would provide greater emis sion reductions and, in many cases, would be more cost e ffective than 40 CFR part 60 subpart VV and could even provide co st savings. Cost savings would occur because it would reduce eq uipment leak product loss, and facilities with a low percent of leaking valves would be able to monitor less frequently, thereby r educing monitoring costs. New sources must comply at startup with the modifie d negotiated regulation; pumps and valves at new sour ces must be in compliance with the Phase II requirements at startu p rather than Phase I. This is consistent with the negotiated ru le (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 t he marine loading NESHAP (40 CFR part 63 subpart Y) unless th ey are included in an emissions average. Bulk gasoline te rminal or pipeline breakout station storage vessel and equipm ent 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 subjec t to 40 CFR part 63 subpart CC maintain required records for a period of at least 5 years. The final rule required that the f ollowing three types of reports be submitted: (1) a Notification of Compliance Status, (2) periodic reports, and (3) other reports

.

2.1.8 Emission Averaging13

The EPA is allowing emission averaging among existi ng miscellaneous process vents, refining storage vesse ls, and wastewater streams, marine vessel loading and unloa ding operations, bulk gasoline terminals or pipeline bre akout station storage vessels and bulk gasoline terminal loading racks within a refinery. New sources are not allowed to use emiss ions averaging. Under emission averaging, a system of e mission
"credits" and "debits" would be used to determine w hether the source is achieving the required emission reduction s.1415 3.0 NEED FOR REGULATION

One of the concerns about potential threats to huma n health and the environment from petroleum refineries is th e emission of
HAPs. Health risks from emissions of HAPs into the air include
increases in cancer incidences and other toxic effe cts. This chapter discusses the need for and consequences of regulating of HAP emissions from petroleum refineries. Section 3.1 presents the conditions of market failu re which necessitate government intervention. Section 3.2 i dentifies the insufficiency of political and judicial forces to c ontrol the release of toxic air pollutants from petroleum refi neries. 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 asso ciated 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 th ese pollutants. Lastly, Section 3.4 identifies the con sequences of regulating versus the option of not regulating.

3.1 MARKET FAILURE The U.S. Office of Management and Budget (OMB) dire cts regulatory agencies to demonstrate the need for a m ajor rule. 1
The RIA must show that a market failure exists and that it cannot be resolved by measures other than Federal regulati on. 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 externali ty. This means that, in the absence of government regulation , the decisions of generators of air pollution do not ful ly reflect the costs associated with that pollution. For a petrol eum refiner, air pollution from the refinery is a product or by- product that can be disposed of cheaply by venting it to the atm osphere. Left to their own devices, many refiners treat air as a free good and do not fully "internalize" the damage caused by emi ssions. 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 co llect compensation because the adverse effects, like incr eased risks of morbidity and mortality, are non-market goods, that is, goods that are not explicitly and routinely traded in org anized free
markets. HAP emissions represent an externality in that refi nery operation imposes costs on others outside of the ma rketplace. In the case of this type of negative externality, the market price of goods and services does not reflect the costs, b orne by receptors of the HAPs, generated in the refining pr ocess. Government regulation can be used to improve the si tuation. For example, the NESHAP will force petroleum refiners t o reduce the quantity of HAPs that they emit. With the NESHAP i n effect, the amount that refiners must incur to refine petroleumproducts will more closely approximate the full social costs of p roduction. In the long run, refiners will be forced to increase p rices of the petroleum products sold in order to cover total pro duction costs. Thus, prices will rise, consumers accordingly will reduce their demand for petroleum products, and as a result, few er petroleum products will be provided to the market. The more the costs of pollution are internalized by the petroleum refiner s, the greater the improvement in the way the market functions.

3.1.2 Natural Monopoly17

Natural monopoly exists where a market can be serve d at lowest cost only if production is limited to a single prod ucer. The refining industry is characterized by some of the s ame attributes which define monopolistic markets, including econom ies of scale, and barriers to entry due to the heavy up-front cap ital needed for refinery construction. Because of the wide div ersity in the size and number of petroleum refineries, however, c onditions 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 inadequ ate information. Some petroleum refineries can reduce costs by installing air pollution control devices, or reduci ng leaks. Due to lack of information, some of these refineries do not install such systems. The NESHAP will require the collecti on of information that may give a particular petroleum re finer 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 so urces, in EPA's judgment, should be subject to reasonably uni form national standards. The principal reasons are:

C Air pollution crosses jurisdictional lines.

C The people who breathe the air pollution travel fre ely, sometimes coming in contact with air pollution outs ide their home jurisdiction.

C Harmful effects of air pollution detract from the n ation's health and welfare regardless of whether the air po llution
and harmful effects are localized.18

C Uniform national standards, unlike potentially piec emeal local standards, are not likely to create artificia l
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 compl y with emission regulations across the country.

3.3 ENVIRONMENTAL FACTORS WHICH NECESSITATE REGULATI ON Regulation of the petroleum refining industry is ne cessary because of the adverse health effects caused by hum an exposure to HAP emissions. This section characterizes the emis sions attributable to petroleum refining and summarizes t he adverse health effects associated with human exposure to HA P 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, t he provisions of this NESHAP apply to organic HAPs listed in sect ion 112(b) of the CAA. HAP emissions from refineries are compose d of a few chemicals, including benzene, toluene, xylenes, eth ylbenzene, and hexane. There is a narrower range of variation in emission stream composition among petroleum refinery emissio n points than there is in some other source categories (e.g., Syn thetic Organic Chemical Manufacturing Industry (SOCMI) emission po ints regulated by the HON). However, the different HAPs emitted h ave different toxicities, and there are some variations in the co ncentrations
of individual HAPs and the emission release charact eristics of different emission points. Baseline emissions from petroleum refineries were e stimated using information published in the Oil and Gas Journal (OGJ) and provided by petroleum refineries in response to inf ormation collection requests and questionnaires sent out und er section 114 of the CAA. Table 3-1 presents the baseline HAP an d VOC19

emissions for each of the four kinds of emission po ints controlled by this promulgated rule. Emission leve ls of other air pollutants (CO, NO
x , and SO 2 ) were not quantified. Baseline
emissions include emissions from both new and exist ing sources.
Baseline HAP and VOC emissions take into account th e current estimated level of emissions control, based on ques tionnaire responses submitted by refineries, and on related r egulations which have already been promulgated. (These regula tions are summarized later in this chapter.) As a result, ba seline HAP and
VOC emissions reflect the level of control that wou ld 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 i dentify individual HAP emissions for each type of emission point. Speciated HAP emissions were available only for equ ipment leaks. Since HAP emissions from equipment leaks account fo r nearly 65 percent of total HAP emissions at petroleum refiner ies, however, this speciation is valuable for approximating the m inimum level of cancer risk related to refinery emissions. Spec iated HAP emissions for equipment leaks are presented in Tabl e 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 der mal contact.
Health effects associated with HAP emissions are ad dressed in20

these NESHAPs. Many HAPs are classified as known h uman carcinogens. Other HAPs have not been classified a s known human carcinogens. Exposure to these pollutants, however , may still result in adverse health and welfare impacts to hum an populations. EPA has devised a system, which was adapted from on e developed by the International Agency for Research on Cancer (IARC), for classifying chemicals based on the weight-of-eviden ce. 2 Of the HAPs listed in Table 3-2, only benzene is classifie d as group A, or a known human carcinogen. This means that there is sufficient evidence to support that the chemical causes an inc reased risk of
cancer in humans. Benzene is a concern to the EPA because long term exposure to this chemical has been known to ca use leukemia
in humans. While this is the most well known effec t, benzene exposure is also associated with aplastic anemia, m ultiple myeloma, lymphomas, pancytopenia, chromosomal break ages, and weakening of bone marrow (53 FR 28504; July 28, 198 8). Cresols is considered to be a group C or a possible human carcinogen. For this chemical, there is either ina dequate data or no data on human carcinogenicity, and there is l imited data on animal carcinogenicity. Therefore, while cancer ri sk is possible, there is not sufficient evidence to suppo rt that this
chemical will cause increased cancer risks in human s. The remaining HAPs in Table 3-2 are noncarcinogens. Though they do not cause cancer, they are considere d hazardous because of the other significant adverse health eff ects with which they are associated. These other adverse hea lth effects are listed in Chapter 8 of this RIA.
Emissions of VOC have been associated with a variet y of health impacts. VOCs, together with NO
x , are precursors to the formation of tropospheric ozone. It is exposure to ozone that is responsible for adverse respiratory impacts, includ ing coughing and difficulty in breathing. Repeated exposure to elevated concentrations of ozone over long periods of time m ay also lead to chronic, structural damage to the lungs.21

TABLE 3-2. BASELINE SPECIATED HAP EMISSIONS FROM E QUIPMENT 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 51,94322

3.4 CONSEQUENCES OF REGULATORY ACTION This section provides an assessment of the conseque nces of the attainment of EPA emission reduction objectives, an d 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 presen ted in Chapter 6.) It is estimated that approximately 173 petrole um refineries would be required to apply controls by the proposedstandards. Throughout this report, impacts are presented relat ive to the baseline, which represents the level of control in the absence of the proposed rule. The estimates include the impac ts of applying control to: (1) existing process units and (2) add itional process units that are expected to begin operation over a 5-year period. Thus, the estimates represent annual impac ts occurring in the fifth year. Based on a review of annual con struction 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 r efining. Specifically, more of the costs of the harmful effe cts of the refining process will be internalized by the produc ers. This, in turn, will affect consumers' purchasing decisions. To the extent these newly-internalized costs are then passed alon g to the end users of refined petroleum products, and to the ext ent that these end users are free to buy as much or as little of t he petroleum products as they wish, they will purchase less (rel ative to their purchases of other competing services). If this sa me process of internalizing negative externalities occurs through out the entire23

petroleum refining industry, an economically optima l situation is approached. This is the situation in which the mar ginal 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, i n 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 emis sions. Under the promulgated rule, it is estimated that the emis sions of HAP from refineries would be reduced by 48,000 Mg/yr, a nd the emissions of VOC would be reduced by 252,000 Mg/yr. Emission levels of other air pollutants (CO, NO
x , and SO 2 ) were not quantified. It is important to note that the possi bility exists for slight increases above existing emission levels for CO, NO
x , and SO 2 may result from the combustion of fossil fuel as p art of additional control device operations refineries und ertake to meet the requirements of this NESHAP. Additional emissi ons of these pollutants would be attributable to the additional fuel burned to generate energy for operation of compressors for du cting miscellaneous process vent streams to control devic es.

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. Generall y, 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 capita l costs would be $213 million (first quarter 1992 dollars) and to tal annual costs would be $79 million (first quarter 1992 doll ars). Table 3-3 presents the capital and annual cost impa ct 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 PREFER RED

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 woul d be required by the promulgated standards (compressors for ducti ng miscellaneous process vent streams to control devic es). The estimated energy use increase in the fifth year wou ld be 48 million kw-hr/yr of electricity or 77.5 thousandbarrels 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 subje ct to various Federal, State, and local air pollution control rul es. Although these existing rules will remain in effect, the pet roleum refinery NESHAP will provide comprehensive coverage of the petroleum refinery sources not covered by the exist ing rules. Recognition that the NESHAP is effectively reducing emissions will expedite the State process of reviewing applic ations for new petroleum refineries and issuing permits for their construction and operation. State regulations will also be unif orm, 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 al ready 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 vesse ls for petroleum liquids; subpart GGG

% Standards of Performance for Equipment Leaks of VOC in Petroleum Refineries, andthe Standards
of Performance for VOC Emissions from Petroleum Ref inery Wastewater Systems. The regulations that have alre ady been promulgated also include a number of NESHAPs, (40 C FR 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 ref inery processes that produce petroleum liquids (such as m otor gasoline, naphthas, and kerosene) for use as fuels. Often, p roducts of refinery processes are used to make synthetic organ ic chemicals other than fuels. The petroleum refinery NESHAP wi ll not cover chemical manufacturing process units that are cover ed under the SOCMI source category, even if these units are loca ted at a refinery site. A SOCMI chemical manufacturing proc ess unit that is located at a refinery and produces one or more o f the chemicals listed in the HON (40 CFR 63 subpart F, t able 1) as a single chemical product or as a mixed chemical usedto produce other chemicals would be considered a SOCMI process and would be subject to the HON rather than to the petroleum ref inery 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 repor t. However, costs are not likely to be as large either. Whethe r it is noncompliance from ignorance or error, or from will ful intent, or simply slow compliance due to owners and/or operato rs exercising26

legal delays, poor compliance can save some refiner ies 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 in cluded an allowance for poor compliance in its estimates of e missions reductions, due to the fact that poor compliance is unlikely. Also, if the emission control devices degraded rapi dly over time or in some other way did not function as expected, there could be
a misallocation of resources. This situation is ve ry unlikely, given that the NESHAP is based on demonstrated tech nology.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 A ssessment Guidelines of 1986. Office of Health and Environme ntal Assessment. Washington, DC. August 1987.
3. U.S. Environmental Protection Agency. National E mission Standards for Hazardous Air Pollutants for Source Categories: Petroleum Refineries. Proposed Rule a nd Notice of Public Hearing. Draft. Section IV. Feb ruary 1994.2829

4.0 CONTROL TECHNIQUES AND REGULATORY ALTERNATIVES

The promulgated regulation would require a broad ra nge of control techniques as options for compliance with t he standard. Combustion technology, internal floating roofs, andproduct recovery devices, including internal floating roofs and vapor recovery tanks, are all part of the technology requ irements 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 w hat technologies and techniques are being used and how effective they

are. Petroleum refineries differ in the number, combinat ion, and design of their process units; the production capac ities of their refining processes; the type and characteristics of crude oil they use; and the control equipment they use. Cons equently, actual emissions and characteristics of petroleum r efinery 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 technolog ies which are available to refineries to comply with the prom ulgated 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 equi pment available for combustion technology, product recove ry devices, LDAR programs, and internal floating roofs. Each t ype of control is presented separately.
4.1.1 Combustion Technology Combustion control devices, unlike noncombustion co ntrol devices, alter the chemical structure of the VOC. Destruction of the VOC by combustion is complete if all VOCs are c onverted to
CO 2 and water. Incomplete combustion results in some of the VOC remaining unaltered or being converted to other org anic compounds such as aldehydes or acids. If chlorinated or sulf ur-containing compounds are present in the mixture, the products of complete combustion include the acid components HCl or SO 2 , respectively,
in addition to water and carbon dioxide. Available combustion technology options include incinerators, flares, an d 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 coll ected. Provided proper engineering design is used, inciner ation can eliminate the desired organic chemicals in a gas st ream 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 accomp lished by adding auxiliary fuel (usually natural gas). The amount of auxiliary fuel required can be decrea sed and energy efficiency increased by providing heat excha nge between
the inlet stream and the effluent stream. The effl uent stream containing the products of combustion, along with a ny inerts that31

may have been present in or added to the inlet stre am, can be used to preheat the incoming waste stream, auxiliar y 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. M ost industrial gases that contain VOCs are dilute mixtures of comb ustible gases
in air. Important in the design and operation of incinerato rs is the concentration of combustible gas in the waste gas s tream. Having a large amount of excess air (i.e., in excess of th e required stoichiometric amounts) may be costly, but any mixt ure within the flammability limits, on either the fuel-rich or fue l-lean side of the stoichiometric mixture, is considered a fire ha zard as a feed stream to the incinerator. Therefore, some waste g as streams are diluted with air before incineration, even though t his requires more fuel in the incinerator. There are two types of incinerators: thermal and catalytic. While much o f what was discussed above applies to both, there are importan t differences in their design and operation.
4.1.1.1.1 Thermal Incinerators . As is true of other combustion control devices, thermal incinerators op erate on the principle that any VOC heated to a high enough temp erature in the presence of sufficient oxygen will be oxidized to C O 2 and water. The theoretical temperature for thermal oxidation d epends on the properties of the VOC to be combusted. There is gr eat variation in theoretical combustion temperatures among differ ent 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 complet ion; 2) enough turbulence for good mixing of the hot combustion pr oducts from the burner, the combustion air, and the organic compounds; and 3)
sufficient residence time for oxidation to reach co mpletion. A typical thermal incinerator is a refractory-linedchamber containing a burner or set of burners at one end. Entering gases are mixed with the process vent streams and the inl et air in a32

premixing chamber. Then the stream of gases passes into the main combustion chamber. This chamber is designed to al low the mixture enough time at the required combustion temp erature 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 o ccurs, insurance regulations require the VOC concentration must be maintained below 25 percent of the lower explosive limit (LEL) to minimize the possibility of explosions. Concentrat ions from 25 to 50 percent are permitted given continuous monito ring by LEL
monitors. The required level of VOC control of the waste gas that must be achieved within the time it spends in the therma l combustion chamber dictates the reactor temperature. The shor ter 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 experie nce. Predictions of these temperatures are further compl icated by the fact that most process vent streams are mixtures of compounds. Good mixing is also important, particularly in dete rmining destruction efficiency. Even though it cannot be m easured, mixing is a factor of equal or even greater importa nce than other parameters such as temperature. The most feasible and efficient way to improve the mixing in an incinerator is to a djust it after start-up. Other parameters affecting thermal incinerator perf ormance are the heat content of the vent stream, the water cont ent of the stream, and the amount of excess combustion air (th e amount of
air above the stoichiometric air needed for combust ion).
Combustion of a vent stream with a heat content les s than 1.9 MJ/m 3 (52 BTU/scf) usually requires burning supplemental fuel to maintain the desired combustion temperature.33

The maximum achievable VOC destruction efficiency d ecreases with decreasing inlet VOC concentration because com bustion 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 concentration s above approximately 2,000 ppmv (which corresponds to 1,00 0 ppmv VOC in
the incinerator inlet stream since air dilution is typically 1:1). Thermal incinerators are technically feasible contr ol devices for most vent streams. They are not recommended, h owever, for vent streams with potentially excessive fluctuation s in flow rate (process upsets, for example), and for vent streams containing halogens. The former case would require a flare (s ee Section 4.1.1.2) and the latter case would require addition al 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 combustio n chamber. Energy recovery devices such as a waste gas preheat er and a heat exchanger are not included with this type of incine rator. A second type of thermal incinerator is the recuper ative model. Recuperative incinerators use the exit (pro duct) gas to preheat the incoming feed stream, combustion air, o r 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 pur pose and many others are plate-to-plate and shell-and-tube. Plat e-to-plate exchangers can be built to achieve a variety of eff iciencies and offer high efficiency energy recovery at lower cost than shelland-tube designs. But when gas temperatures exceed520 degrees Celsius, shell-and-tube exchangers usually have low er purchase costs than plate-to-plate designs. Moreover, shell -and-tube exchangers offer better long-term structural reliab ility than plate-to-plate units.34

Occasionally it is desired to recover some of the e nergy added by auxiliary fuel in the traditional thermal units (but not recovered in preheating the feed stream). Addition al heat exchangers can be added to provide process heat in the form of low pressure steam or hot water for on-site applica tion. 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 regenera tive incinerator. This type of incinerator uses direct contact heat exchangers constructed of a ceramic material that c an tolerate the high temperatures needed to achieve ignition of the waste stream. The concept behind this incinerator type i s 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 value s are too low to sustain the desired reaction temperature at the moderate preheat temperature employed. Under these conditio ns, additional fuel savings can be realized in units with more complete transfer of exit stream energy. The regenerative incinerato r serves this

purpose. In this type of incinerator, the inlet gas first pa sses through a hot ceramic bed thereby heating the steamto its ignition temperature. After the hot gases react an d release energy in the combustion chamber, the gases pass th rough another ceramic bed, thereby heating it to the levels of th e 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 t he rate of the chemical reaction without becoming permanently alte red itself. Catalysts typically used for VOC incineration inclu de platinum and palladium. These catalysts work well for most organic streams, but are not tolerant of compounds containi ng halogens35

such as chlorine, and sulfur. Among the catalysts that have been developed that are effective in the presence of the se halogens are chromia/alumina, cobalt oxide, and copper oxide /manganese oxide. Inert substrates are coated with thin layer s of these materials to provide maximum surface area for conta ct with the VOC in the vent stream. Compounds containing eleme nts such as lead, arsenic, and phosphorus should, in general, b e considered poisons for most oxidation catalysts. In addition, particulate matter, including dissolved minerals in aerosols, c an rapidly blind (deactivate) the pores of catalysts and deact ivate them over time. Because essentially all the active surf ace of the catalyst is contained in relatively small pores, th e 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 g as stream can also affect the overall conversion of the VOC conta minants. Most changes in flow rate, organic concentration, and ch emical composition are generally the result of upsets in t he manufacturing process generating the waste gas stre am. 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 poi son the catalyst or deposit on and block the reactive sites on the catalyst surface. In addition, catalytic incinerat ors 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 c oncentration is less than 25 percent of the LEL and for flow rat es of less than 2,820 m 3 /min (100,000 scfm).

4.1.1.1.4 Types of Catalytic Incinerators . One type of catalytic incinerator is fixed-bed. Fixed-bed inci nerators come36

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 po rous solid block containing parallel, non-intersecting channel s 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 l ow overall pressure drop. A second contacting scheme is a simple packed-bed i n which catalyst particles are supported either in a tube o r 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 beca use pelletized catalysts can handle inlet streams containing conta minants 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 du e to thermal expansion when the confined catalyst bed is heated/ cooled during startup/shutdown. A third contacting pattern between the gas and cata lyst is a fluid-bed. Fluid-beds have the advantage of very h igh mass transfer rates, although the overall pressure drop is somewhat higher than for a monolith. Fluid-beds also posses s the advantage of high bed-side heat transfer compared w ith a normal gas heat transfer coefficient. This higher heat tr ansfer rate to heat transfer tubes immersed in the bed allows high er 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 tra nsfer
surfaces. In general, fluid-bed systems are more tolerant of particulates in the gas stream than fixed-bed or pa cked-bed37

systems. This results from the constant abrasion o f the fluidized catalyst pellets, which helps remove thes e 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 provid ed by the air around the flame. The organic compounds to be comb usted are piped to a remote, usually elevated, location and b urned in an open flame in the open air using a specially design ed burner tip, auxiliary fuel, and sometimes steam or air to promo te 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 fr ee radical formation. Combustion is complete if all combustib les (i.e., VOCs) are converted to CO 2 and water, while incomplete combustion results in some of the VOCs being unaltered or conv erted to other organic compounds such as aldehydes or acids. Flares are generally categorized in two ways: 1) b y the height of the flare tip (i.e., ground-level or elev ated), and 2) by the method of enhancing mixing at the flare tip (i.e., steamassisted, air-assisted, pressure-assisted, or unass isted). Elevating the flare can prevent potentially dangero us conditions at ground level where the open flame is located nea r a process unit. Further, the products of combustion can be d ispersed above working areas to reduce the effects of noise, heat radiation, smoke, and objectionable odors. In most flares, combustion occurs by means of a dif fusion
flame. A diffusion flame is one in which air diffu ses across the boundary of the fuel/combustion product stream towa rd the center of the fuel flow, forming the envelope of a combust ible gas mixture around a core of fuel gas. This mixture, o n ignition, establishes a stable flame zone around the gas core above the burner tip. This inner gas core is heated by diffu sion 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 lu minosity. If there is an oxygen deficiency and if the carbon par ticles 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 fl ickering, which can be accompanied by soot formation. Flares can be dedicated to almost any VOC stream, a nd can handle fluctuations in VOC concentration, flow rate , heating value, and inerts content. Flaring is appropriate for continuous, batch, and variable flow vent stream ap plications. Some streams, such as those containing halogenated or sulfurcontaining compounds, are usually not flared becaus e they corrode the flare tip or cause formation of secondary pollu tants (such as acid gases or sulfur dioxide). If these vent types are to be controlled by combustion, thermal incineration, fol lowed by scrubbing to remove the acid gases, is the preferre d method. The majority of refineries have existing flare syst ems designed to relieve emergency process upsets that m ight contain large gas volumes. Often, large diameter flares de signed to handle emergency releases are also used to control continuous vent streams from various process operations. Typi cally in refineries, many vent streams are combined in a common gas header to fuel boilers and process heaters. However, exce ss gases, fluctuations in flow rate in the fuel gas line, andemergency releases are sometimes sent to a flare. Five facto rs affecting flare combustion efficiency are vent gas flammabili ty, autoignition temperature, heat content of the vent stre am, density, and flame zone mixing. The flammability limits of the vent stream influenc e ignition stability and flame extinction. Flammability limit s are the stoichiometric composition limits (maximum and mini mum) of an oxygen-fuel mixture that will burn indefinitely at given conditions of temperature and pressure without furt her ignition. In other words, gases must be within their flammabi lity limits to39

burn. If these limits are narrow, the interior of the flame may
have insufficient air for the mixture to burn. Fue ls, such as hydrogen, with wide limits of flammability are ther efore easier
to combust. The auto-ignition temperature of a vent stream affe cts combustion because gas mixtures must be at a suffic ient 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 ven t stream. The
heat content of the vent stream affects the flame s tructure and stability. A gas with a lower heat content produce s a cooler
flame that does not favor combustion kinetics and i s more easily extinguished. The lower flame temperature will als o reduce buoyant forces, which reduces mixing. The density of the vent stream also affects the str ucture and stability of the flame through the effect on buoyan cy and mixing. By design, the velocity in many flares is very low; therefore, most of the flame structure is developed through bu oyant forces as a result of combustion. Lighter gases therefore tend to burn better. In addition to burner tip design, the dens ity also affects the minimum purge gas required to prevent f lashback, with lighter gases requiring more purge. Poor mixing at the flare tip or poor flare maintena nce can cause smoking (particulate matter release). Vent s treams with high carbon-to-hydrogen ratios (> 0.35) have a grea ter tendency to smoke and require better mixing to burn smokeles sly. For this reason, one generic steam-to-vent-stream ratio is n ot appropriate for all vent streams. The steam required depends o n the vent stream carbon-to-hydrogen ratio. A high ratio requ ires 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. Flar es have been shown to have high VOC destruction efficiencies, un der proper40

operating conditions. Up to 99.7 percent combustio n 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, t his type of flare system injects steam into the combustion zone to promote turbulence for mixing and to induce air into the fl ame. 4.1.1.2.2 Air-Assisted Flares . Air-assisted flares use forced air to provide the combustion air and the mi xing required for smokeless operation. These flares are built wi th a spidershaped burner (with many small gas orifices) locate d inside but near the top of a steel cylinder two feet or more i n diameter. Combustion air is provided by a fan in the bottom o f the cylinder, and the amount of combustion air can be v aried by changing the fan speed. The primary advantage air- assisted flares provide is that they can be used without ste am. 4.1.1.2.3 Non-Assisted Flares . The non-assisted flare is just a flare tip without any auxiliary provision fo r enhancing the mixing of air into its flame. Its use is limit ed essentially to gas streams that have a low heat content and a l ow carbon/hydrogen ratio that burn readily without pro ducing smoke. These streams require less air for complete combust ion, have lower combustion temperatures that minimize crackin g 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 burne r tip. If sufficient vent stream pressure is available, these flares can be applied to streams previously requiring steam or ai r assist for smokeless operation. Pressure-assisted flares gene rally have the burner arrangement at ground level, and consequentl y, must be located in a remote area of the plant where there i s plenty of space available. They have multiple burner heads t hat are staged to operate based on the quantity of gas being relea sed. The41

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 operatio n and air or steam assist is not required. In this context, enc losed flares can be considered a special class of pressure-assis ted or nonassisted flares. Enclosed flares are always at gro und level. Enclosed flares generally have less capacity than o pen flares and are used to combust continuous, constant flow v ent streams, although reliable and efficient operation can be at tained over a wide range of design capacity. Stable combustion c an be obtained with lower heat content vent gases than is possible with open flare designs, probably due to their isolation fromwind effects.
4.1.1.3 Boilers and Process Heaters . Industrial boilers are combustion units that boil water to produce high an d low pressure
steam. Industrial boilers can also combust various vent streams containing VOCs, including vent streams from distil lation operations, reactor processes, and other general op erations. 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 combusti on gases contact the outside of heat transfer tubes which co ntain hot water and steam. These tubes are interconnected by a set of
drums that collect and store the heated water and s team. Energy transfer from the hot flue gases to the water in th e furnace watertube and drum system can be better than 85 per cent efficient. Additional energy can be recovered fromthe 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 b urners 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, o r 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 transf erred by
radiation and convection to fluids contained in tub ular coils. It is different from an industrial boiler in that p rocess heaters raise the temperature of process streams instead of producing high temperature steam. Process heaters are used i n many chemical manufacturing operations to drive endother mic reactions. They are also used as feed preheaters and as reboil ers 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 bur ner(s), the firebox, and a row of tubular coils containing the process fluid.
Most heaters also contain a convective section in w hich heat is recovered from hot combustion gases by convective h eat transfer to the process fluid.
4.1.1.3.1 Efficiency of Boilers and Process Heaters . Average furnace temperature and residence time determine th e combustion efficiency of boilers and process heaters, just as they do for incinerators. When a vent gas is injected as a fue l into the flame zone of a boiler or process heater, the requi red residence time is reduced because of the relatively high temp erature and
turbulence of the flame zone. Residence time and temperature profiles in boilers and process heaters are determined by factors such as overall c onfiguration, fuel type, heat input, and excess air level. A mat hematical model developed to estimate furnace residence time and temperature profiles for a variety of industrial bo ilers predicts mean furnace residence times ranging 0.25 to 0.83 s econd for natural gas-fired watertube boilers that range in s ize from 4.4 to 44 MW (15 to 150 x 10 6 Btu/hr). Boilers with a 44-MW capacity or greater generally have residence times and opera ting temperatures that would ensure a 98 percent VOC des truction43

efficiency. The required temperatures for these si ze boilers are at least 1,200 degrees Celsius. Firebox temperatures for process heaters can show w ide variations depending on the application. Firebox t emperatures can range from 400 degrees Celsius for preheaters a nd reboilers to 1,260 degrees Celsius for pyrolysis furnaces. T ests conducted by EPA on process heaters using a mixture of benzen e offgas and natural gas showed greater than 98 percent destruct ion efficiency
for C 1 to C 6 hydrocarbons.
4.1.1.3.2 Applicability of Boilers and Process Heaters . Both of these devices are used throughout petroleum refi neries to provide steam and heat input essential to the refin ing process. Most of these devices possess sufficient size to pr ovide the necessary temperature and residence time for VOC de struction. Furthermore, boilers and process heaters have prove d effective in destroying compounds that are difficult to combust, such as PCBs (polychlorinated biphenyls). Boilers and process h eaters are thus effective in reducing VOC emissions from any v ent streams that are certain not to reduce the performance or r eliability of the boiler or process heater. Ducting some vent streams to a boiler or process he ater can present potential safety and operating problems. T he 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-c ontaining compounds are usually not combusted in boilers or p rocess heaters due to the possibility of corrosion. Boilers and process heaters are most applicable whe re the potential exists for heat recovery from the combust ion of the vent stream. Vent streams with a high enough VOC c oncentration and high flow rate can provide enough equivalent he at value to
act as a substitute for fuel that would otherwise b e 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 mean s of a liquid44

in which the solute gas is more or less soluble. F or any given solvent, solute, and operating conditions, there ex ists an equilibrium ratio of solute concentration in the ga s mixture to solute concentration in the solvent. The driving f orce for mass transfer at a given point in an operating absorber is the
difference between the concentration of solute in t he gas and the equilibrium concentration of solute in the liquid. Devices based on absorption principles include spra y towers, venturi and wet impingement scrubbers, acid gas scr ubbers, packed columns, and plate columns. Spray towers have the least effective mass transfer capability due to their hig h atomization pressure requirement, and are generally restricted to particulate matter removal and control of high-solubility gases such as SO 2 and NH 3 (ammonia). Venturi scrubbers have a high degree o f gas/liquid mixing and provide high particulate matt er removal efficiency. They also require high pressure drops (i.e. high energy requirements) and have relatively short cont act times. Their use is also restricted to high-solubility gas es. Acid gas
scrubbers are used with thermal incinerators to rem ove corrosive combustion products. Acid gas is formed upon the c ontact of halogenated or sulfur-containing VOCs with intense heat during incineration. This gas is quenched to lower its te mperature and is then scrubbed in an absorber. In most cases, th e type of absorber used is packed or plate columns, the two m ost commonly
used absorbers for VOC control. Packed towers are vertical columns containing inert packing, manufactured from materials such as porcelain, meta l, or plastic, that provides the surface area for contact between the liquid and gas phases in the absorber. Packed towers are usedmainly for corrosive materials and liquids with tendencies to foam or plug. They are also suitable where the use of plate colum ns would result in excessive pressure drops. Plate columns contain a series of trays on which co ntact between the gas and liquid phases in a stepwise fas hion. The liquid phase flows down tray to tray as the gas pha se moves up45

through openings in the tray (usually perforations or bubble caps), passing through the liquid on the way. The major design parameters for absorbing any subst ance are column diameter and height, system pressure drop, a nd required liquid flow rate. Deriving these parameters is acc omplished by considering the solubility, viscosity, density, andconcentration of the VOC in the inlet vent stream (all of which d epend on column temperature); the total surface area provide d by the packing material; and the mass flow rate of the gas es 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. Solven ts are chosen for high solubility for the specific VOC and includ e liquids such as water, mineral oils, kerosenes, nonvolatile hydr ocarbon oils, and aqueous solutions of oxidizing agents, sodium c arbonate, and sodium carbonate. An increase in absorber size (i. e., contact surface area) or a decrease in the operating temper ature can increase the VOC removal efficiency of the system f or a given solvent and solute. It is sometimes possible to in crease VOC removal efficiency by changing the solvent.
4.1.2.1.2 Applicability . The primary determinant of absorption applicability for controlling VOC emissi ons is the availability of a suitable solvent. Water is a sui table solvent for absorption of organic chemicals with relatively high water solubilities (e.g., most alcohols, organic acids, a ldehydes, glycols). For organic compounds with low water sol ubilities, other solvents (usually organic liquids with low va por pressures)
are used. Other important factors influencing absorption appl icability include absorptive capacity and strippability of VO C in the solvent. Absorptive capacity is a measure of the s olubility of VOC in the solvent. The solubility limits the tota l quantity of VOC that could be absorbed in the system, while str ippability
describes the ease with which the VOC can be remove d from the46

solvent. If strippability is low, then absorption is less viable as a VOC control technique.
The concentration of VOC in the inlet vent stream a lso determines the applicability of absorption. Absorp tion 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 liq uid-phase components and solid-phase components. In this ope ration, certain components of a gas- or liquid-phase (or ad sorbate) are
transferred to the surface of a solid adsorbent. T he transfer is accomplished by physical or chemical adsorption mec hanisms. 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 bondforms between the gaseous- and solid-phase molecules. A physical ly 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 ca rbon as the adsorbent. Activated carbon effectively captures c ertain organic vapors by physical adsorption. The vapors can then be released for recovery by regenerating the adsorption bed wit h steam or nitrogen. Oxygenated adsorbents such as silica gel s or diatomaceous earth exhibit a greater selectivity fo r capturing water vapor than organic gases compared to activate d 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 carbo n adsorption system are the chemical characteristics of the VOC being recovered, the physical properties of the inl et 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 propor tional to the47

difference in VOC concentration between the gas pha se and the solid surface. In addition, the quantity of VOC ad sorbed depends on the adsorbent bed volume, the surface area of ad sorbent available to capture VOC, and the rate of diffusion of VOC through the gas film at the gas- and solid-phase in terface (the mass transfer coefficient). It should be noted tha t 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) fi xed regenerable beds; 2) disposable/rechargeable canist ers; 3) traveling bed adsorbers; 4) fluid bed adsorbers; and 5) chromatographic baghouses. The fixed-bed type is t he one most commonly used for control of VOCs, so this section addresses this type only. Fixed-bed units can be sized for controlling contin uous, VOCcontaining streams over a wide range of flow rates, ranging up to several thousand cubic meters per minute (100,000 s cfm). VOC concentrations in streams that can be treated by fi xed-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 adso rption time"), which corresponds to the time during which the cont rolled source is emitting VOCs. In continuous mode, a regenerate d carbon bed is always available for adsorption, so that the con trolled source can operate continuously without shutting down. Wh ile continuous operation allows for more adsorption over the same period of time because it does not need to be shut down, more carb on must be provided. This is necessary since a bed for desorb ing must be provided along with the adsorbing bed in order to r ecover the captured VOC from the carbon.
4.1.2.3.2 Control Efficiency . Well designed and operated carbon adsorption systems can achieve control effic iencies of 95 to 99 percent for a variety of solvents including k etones such as48

methyl ethyl ketone and cyclohexanone. The VOC con trol efficiency depends on factors such as inlet vent st ream characteristics (temperature, pressure, and velocit y), the physical properties of the compounds present in the vent stream, the physical properties of the adsorbent, and the c ondition of the regenerated carbon bed. The adsorption capacity of the carbon and the resul ting outlet concentration are dependent upon the temperature of the inlet vent stream. High vent stream temperatures increas e the kinetic energy of the gas molecules, causing them to overco me van der
Waals forces and release from the surface of the ca rbon. At vent stream temperatures above 38 degrees Celsius, both adsorption capacity and outlet concentration may be adversely affected. Increasing vent stream pressure improves VOC remova l efficiency. Increased stream pressure results in h igher VOC concentrations in the vapor phase and increased dri ving force for
mass transfer to the carbon surface. Decreased str eam pressure, on the other hand, is often used to regenerate carb on beds. Reduced pressure in the carbon bed effectively lowe rs 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 b e quite low to allow time for diffusion and adsorption. Typica l inlet vent stream velocities range from 15 to 30 meters per mi nute (50 to 100 feet per minute). If inlet VOC concentrations are low, the bed area required for the volume needed usually per mits a velocity at the high end of this range. The requir ed depth of the bed for a given compound is directly proportion al to the carbon granule size and porosity and to the inlet v ent stream velocity. For a given carbon type, bed depth must increase as the vent stream velocity increases. Generally, car bon 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 a ctivity, resulting in reduced VOC removal efficiency.49

4.1.2.3.3 Applicability . Carbon adsorption cannot be used universally for distillation or process vent stream s. It is not recommended under the following conditions, common with many VOCcontaining vent streams: 1) high VOC concentration s, 2) very high or low molecular weight compounds, 3) mixtures of high and low boiling point VOCs, and 4) high moisture conten t. Absorbing vent streams with VOC concentrations abov e 10,000 ppmv may result in excessive temperature rise in th e carbon bed due to the accumulated heat of adsorption resulting from the VOC loading. If flammable vapors are present, insuranc e company requirements may limit inlet concentrations to less than 25 percent of the LEL. The molecular weight of the compounds to be adsorbe d should be in the range of 45 to 130 gm/gm-mole for effective adsorption. High molecular weight compounds that are characteri zed by low volatility are strongly adsorbed on carbon. The af finity of carbon for these compounds makes it difficult to re move them during regeneration of the carbon bed. Conversely, highly volatile materials (i.e., molecular weight less tha n about 45 gm) do not adsorb readily on carbon, thus adsorption is not typically used for controlling streams containing such compou nds. Adsorption systems can be very effective with homog eneous 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 r educing 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 f or adsorption sites on the carbon surface. In these cases, vent stream humidity levels exceeding 50 percent (relative humi dity) 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 saturat ion followed by a phase change. The phase change from gas to li quid can be50

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 h ere. The basic equipment includes a condenser, refrigera tion unit(s), and auxiliary equipment such as a pre-cool er, recovery/storage tank, pump/blower, and piping. Th e two most commonly used condenser types are surface condenser s and direct contact condensers. In surface condensers, the coo lant fluid does not contact the vent stream; heat transfer occ urs 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 strea m, it is not contaminated and can be recycled in a closed loop. Surface condensers also allow for direct recovery of VOCs f rom the gas
stream. Most refrigerated surface condensers are the shell- and-tube type, which circulates the coolant fluid on the tub e 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 und er the same principles as the shell-and-tube systems, for there is no contact between the coolant and vent stream), but the two s treams are separated by thin, flat plates instead of cylindric al tubes. In contrast to surface condensers, direct contact c ondensers cool the vapor stream by spraying a liquid at ambie nt or lower temperature directly into the vent stream. Spent c oolant containing VOCs from direct contact condensers usua lly cannot be reused directly. Additionally, VOCs in the spent c oolant cannot be recovered without further processing. The combi ned stream creates a wastewater with potential for air emissio ns. A refrigeration unit generates the low-temperature medium necessary for heat transfer for recovery of VOCs. Typically in refrigerated condenser systems two kinds of refrige rants are used, primary and secondary. Primary refrigerants such as51

ammonia and chlorofluorocarbons (e.g., chlorodifluo romethane) are those that undergo a phase change from liquid to ga s after absorbing heat. Secondary refrigerants, such as br ine solutions, have higher boiling points and thus act only as hea t 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 V OC has a high freezing point (e.g., benzene or toluene), ice or f rozen hydrocarbons may form on the condenser tubes or pla tes. This will reduce the heat transfer efficiency of the con denser and thereby reduce the removal efficiency. Formation o f ice will also increase the pressure drop across the condense r. In such cases, a precooler may be used to remove the moistu re before the vent stream enters the condenser. Alternatively, i ce can be melted during an intermittent heating cycle by circ ulating 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, withi n the system.

4.1.2.4.1 Control Efficiency . The major parameters that affect the removal efficiency of refrigerated surfa ce condensers designed to control air/VOC mixtures are: 1) Volum etric flow rate of the VOC-containing vent stream; 2) Inlet te mperature of the vent stream; 3) Concentrations of the VOCs in t he vent stream; 4) Absolute pressure of the vent stream; 5) Moisture content of the vent stream; and 6) properties of th e VOCs in the vent stream, such as dew points, heats of condensat ion, 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 efficiencies52

above 90 percent can be achieved with coolants such as chilled water, brine solutions, ammonia, or chlorofluorocar bons.
4.1.2.4.2 Applicability . Condensers are widely used as product recovery devices. They may be used to reco ver VOCs upstream of other control devices or they may be us ed 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 r ange widely, from 50 to 95 percent. Since the temperature necessary for condensation de pends on the properties and concentration of VOCs in the ven t stream, streams having either low VOC concentrations or mor e volatile compounds require lower condensation temperatures. Also, depending on the type of condenser used, disposal o f the spent coolant can be a problem. If cross-media impacts a re a concern, surface condensers would be preferable to direct co ntact
condensers. Condensers used as emission control devices can pro cess flow rates as high as about 57 m 3 /min (120,000 scfm). Condensers for vent streams with greater volumetric flow rates andhaving high concentrations of noncondensibles will require sign ificantly 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 under taken to reduce emissions due to leaking equipment. These e missions occur when process fluid (liquid or gaseous) is released through the sealing mechanisms of equipment in the chemical pla nt. This section discusses the sources of equipment leak emi ssions and control techniques that can be applied to reduce em issions from equipment leaks, including the applicability of eac h control technique and its associated effectiveness in reduc ing emissions. Many potential sources of equipment leak emissions exist in a refinery. The following sources are covered in thi s section: pumps, compressors, pressure relief devices, open-e nded lines,53

sampling connections, systems process valves, conne ctors, and instrumentation systems. The techniques for reducing emissions from equipmen t leaks are as diverse as the types of sources. The three majo r 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 emissio ns depends on a number of factors including: 1) type of equipmen t; 2) equipment service (gas, light liquid, heavy liquid) ; 3) process variables influencing equipment selection (temperat ure, pressure); 4) process stream composition; and 5) co sts.

4.1.3.1 Pumps . Pumps are used widely in the petroleum refining industry for the movement of organic liqui ds. Liquids transferred by pump can leak at the point of contac t between the moving shaft and the stationary casing. Consequent ly, all pumps require a seal at the point where the shaft penetra tes the housing in order to isolate the pumped fluid from t he
environment. Two generic types of seals, packed and mechanical, are used on pumps. Packed seals can be used on both reciprocat ing 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 th e frictional heat between the packing and shaft. The necessary lubrication is provided by a coolant that flows between the packin g and the shaft. Deterioration of the packing can result in leakage of the process liquid. Mechanical seals are limited in application to pump s with rotating shafts. There are single and double mecha nical seals, with many variations to their basic design, but all have a lapped seal face between a stationary element and a rotati ng seal ring. In a single mechanical seal, the faces are held tog ether by the pressure applied by a spring on the drive and by th e pump pressure transmitted through the pumped fluid on th e 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-b ack arrangement, a closed cavity is created between the two seals. A seal liquid, such as water or seal oil, is circulat ed through the cavity. This seal liquid is used to control the te mperature in the stuffing box. For the seal to function properl y, the pressure of the seal liquid must be greater than th e operating pressure of the pump. In this manner, any leakage would occur across the seal faces into the process or the envir onment. Double mechanical seals are used in many process ap plications,
but there are some conditions for which their use i s not indicated. Such conditions include service tempera tures above 260 degrees Celsius, and pumps with reciprocating s haft motion. Further, double mechanical seals cannot be used whe re 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 pr imarily in processes where the pumped fluid is hazardous, high ly toxic, or very expensive and where every effort must be made to prevent all possible leakage of the fluid. Canned-motor, diaph ragm, and magnetic drive pumps are three common types of seal -less pumps. Canned-motor pumps have interconnected cavity housi ngs, motor rotors, and pump casings. Because the process liqu id is the bearing lubricant, abrasive solids in the process l ines cannot be tolerated. Canned-motor pumps are widely used for handling organic solvents, organic heat transfer liquids, an d light oils. Diaphragm pumps contain a flexible diaphragm of met al, rubber, and plastic as the driving member. The primary adv antage of this arrangement is the elimination of all packing and s eals exposed to the process liquid provided the diaphragm's inte grity is maintained. This is important when handling hazard ous or toxic liquids. Emissions from diaphragm pumps can be lar ge, however, if the diaphragm fails. In magnetic-drive pumps, n o seals55

contact the process fluid. An externally-mounted m agnet coupled to the pump motor drives the impeller in the pump c asing.
4.1.3.2 Compressors . Compressors move gas through a process unit in much the same way that pumps transport liqu id. Compressors are typically driven with rotating or r eciprocating shafts. Thus, the sealing mechanisms for compresso rs are similar to those for pumps, i.e., packed and mechanical sea ls. Emissions from this source type may be reduced by improving t he seals' performance or by collecting and controlling the em issions from
the seal. Emissions from mechanical contact seals depend on the type of seal or control device used and the frequen cy of seal
failure. Shaft seals for compressors are of several differen t types: labyrinth, restrictive carbon rings, mechanical con tact, and liquid film. All of these seal types restrict leak s, although none of them completely eliminates leakage. Compre ssors can be equipped with ports in the seal area to evacuate co llected gases,
which could then be controlled. A buffer or barrier fluid may be used with these me chanical seals to form a buffer between the compressed gas a nd the environment, similar to barrier fluids in pumps. T his system requires a clean, external gas supply that is compa tible with the gas being compressed. Barrier gas can become conta minated and must be disposed of properly, for example by ventin g to a control device. Compressors can also be equipped with liqu id film seals. This seal is formed by a film of oil between the ro tating shaft and stationary gland.
4.1.3.3 Pressure Relief Devices . Insurance, safety, and engineering codes require that pressure relief devi ces or systems be used in applications where the process pressure may exceed the maximum allowable working pressure of the process e quipment. Pressure relief devices include rupture disks and s afety/relief valves. The most common pressure relief device is a springloaded valve designed to open when the operating pr essure of a piece of process equipment exceeds a set pressure. Equipment leak emissions from spring-loaded relief valves may be caused by56

failure of the valve seat or valve stem, improper r eseating after overpressure relief, or process operation near the relief valve set pressure which may cause the relief valve to fr equently 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 o f the disk is maintained. They must be replaced after each press ure relief episode to restore the process to an operating pres sure condition. Although rupture disks can be used alon e, they are sometimes installed upstream of a relief valve to p revent emissions through the relief valve stem. Combinations of rupture disks and relief valves req uire certain design constraints and criteria to avoid po tential safety hazards. For example, appropriate piping changes m ust be made to prevent disk fragments from lodging in damaging the relief valve when relieving overpressure. A block valve upstrea m of the rupture disk can be used to isolate the rupture dis k/relief valve combination and permit in-service replacement of th e disk after it bursts. Otherwise, emissions could result throu gh the relief
valve.
4.1.3.4 Open-Ended Lines . Emissions from open-ended lines are caused by leakage through the seat of an upstre am 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. Em issions from open-ended lines can be controlled by installing a cap, plug, flange, or second valve to the open end. Control e fficiency 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 sampli ng 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 contr ol device. The closed loop sampling system is designed to retu rn the purged fluid to the process at a point of lower pressure. Closed loop57

sampling is assumed to be 100 percent effective for controlling emissions from a sample purge. This purged fluid c ould also be
directed to a control device such as an incinerator , in which case the control efficiency would depend on the eff iciency 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 proce ss fluid to the atmosphere. Emissions from valves occur at the stem or gland area of the valve body when the packing or O-ring i n the valve
fails. Valves that require the stem to move in and out or turn must utilize a packing gland. A variety of packing mate rials 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 applicatio n and configuration. Conventional packing glands can be u sed 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 andsealed
bellows valves. Diaphragm valves isolate the valve stem from the pr ocess fluid using a flexible elastomer or metal diaphragm. The position of the diaphragm is regulated by a plunger, which is c ontrolled by the stem. Depending on the diaphragm material, thi s type of valve can be used at temperatures as high as 205 de grees 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 leakl ess design. In this valve type, metal bellows are welded to the bonnet and58

disk of the valve, thereby isolating the stem from the process. These valves can be designed to withstand high temp eratures and pressures and can provide leak-free service at oper ating 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 sea led bellows valves is essentially 100 percent, although a failu re of the diaphragm or bellows could cause temporary emission s 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 eq uipment (such as vessels, pumps, valves, and heat exchangers) req uire isolation
or removal. Flanges are bolted, gasket-sealed connectors. Nor mally, flanges are used for pipes with diameters of 50 mm or greater and are classified by pressure rating and face type. T he primary cause of flange leakage are poor installation and t hermal stress,
which results in the deformation of the seal betwee n the flange
faces. Threaded fittings are made by cutting threads into the outside end of one piece (male) and the inside end of anoth er piece (female). These male and female parts are then scr ewed together like a nut and bolt. Threaded fittings are normall y used to connect piping and equipment having diameters of 50 mm or less. Seals for these fittings are made by coating the ma le threads with a sealant before joining it to the female piec e. Emissions from threaded fittings can occur as the sealant age s and eventually cracks. Leakage can also occur as the r esult of poor assembly or application of the sealant, and thermal stress of the piping and fittings. Emissions from connectors can be controlled by regu larly
scheduled maintenance. Potential emissions can be reduced by replacing the gasket or sealant materials. If conn ectors are not required for process modification or periodic equip ment removal,59

emissions from connectors can be eliminated by weld ing the connectors together.
4.1.3.9 Instrumentation Systems . An instrumentation system is a group of equipment components used to conditio n and convey a sample of process fluid to analyzers and instrument s 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 instrume ntation systems, although other equipment may be included. Emissions resulting from the components in the instrumentatio n system are controlled as they are for the same component in th e process system. Emissions from equipment leaks may be controlled by installed a closed vent system around the leaking equipment a nd venting the
emissions to a control device. This method of cont rol is only applicable to certain equipment types, i.e., pumps, compressors, agitators, pressure relief valves, and product accu mulator vessels. Because of the many valves, connectors, a nd open-ended lines typically found in refineries, it is not prac tical to use this technique for reducing emissions from all of t hese potential sources for an entire process unit. However, a clo sed vent system can be used to control emissions from a limi ted 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 compone nts that are emitting significant amounts of VOC and to redu ce these emissions. The emission reduction potential for LD AR as a control technique is highly variable and depends on several factors, the most important of which are the freque ncy of monitoring and the techniques used to identify leak s. Repair of leaking components is required only when the equipm ent leak
emissions reach a set level

% the leak detection level. A low leak definition will initiate repair at lower level s, resulting
in a lower overall emission rate.60

Leak detection methods include individual component surveys, area (walk-through) surveys, and fixed point monito rs. Individual component surveys form a part of the oth er 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, olfacto ry, soap bubble, or instrument techniques. Visual methods a re good for locating liquid leaks. A visible leak does not nec essarily indicate VOC emissions, however, because the leakin g 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 t o survey individual components in certain applications. If the soap solution forms bubbles or blows away, a leak is ind icated, and vice versa. Disadvantages of this method are that 1) it does not distinguish leaks of hazardous VOCs from nonhazardo us VOCs; 2) it is only semiquantitative, since it requires the obs erver to determine subjectively the rate of leakage based on the behavior of the soap bubbles; and 3) it is limited to source s 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 in terfere with the motion of the bubbles caused by a leak. The best method for identifying leaks of VOC from c omponents is using a portable hydrocarbon detection instrumen t. Air close to the potential leak site is sampled and analyzed by a sampling traverse ("monitoring") over the entire are where l eaks may occur. The concentration of hydrocarbons in the sa mpled air is displayed on the instrument meter and is a rough in dicator of the VOC emission rate from the component. If the conce ntration is higher than a specified figure ("action level"), th en 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 proced ures. Many pumps have in-line or parallel spares that can be used while the leaking pump is being repaired. Leaks fr om packed seals may be reduced by tightening the packing glan d. With mechanical seals, the pump must be dismantled to re pair or replace the leaking seal. Dismantling pumps can re sult in spillage of some process fluid. If the seal leak i s 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 VOC s at the point where the shaft penetrates the casing, an d seals are required to minimize fugitive emissions. Leaks fro m packed seals may be reduced by the repair procedure described fo r 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 r epair. To remove the relief valve without shutting down the p rocess, a block valve may be required upstream of the relief valve. A spare relief valve should be attached while the fau lty valve is repaired and tested. A rupture disk can be installed upstream from a pre ssure relief valve to eliminate leaks until an overpressu re release occurs. Once a release occurs, the rupture disk mu st be replaced to prevent further leaks. A block valve is require d to isolate the rupture disk for replacement. Most valves have a packing gland that can be tighte ned while in service. Although this procedure should decreas e 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 i n-service repair and must be isolated from the process and re moved for repair and replacement. Most control valves have a manual bypass62

loop that allows them to be isolated and removed. Most block valves cannot be isolated easily, although temporar y 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 connector s cannot be isolated to permit gasket replacement. Tightening of connector bolts also may reduce emissions from connectors. W here connectors are not required for process modificatio n 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 pe troleum refining industry to control emissions from fixed-r oof 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 expo sed liquid. It serves as a physical barrier between the volatil e organic liquid and the air that enters the tank through ven ts. Because evaporation is the primary emission mechani sm associated with storage tanks, emissions from float ing roof tanks as well as fixed roof tanks vary with the vapor pre ssure of the stored liquid. Thus, the control efficiency of ret rofitting a fixed roof tank with an internal floating deck depe nds on the material being stored. Other factors affecting emissions, and therefore co ntrol efficiency, are tank size, number of turnovers, andthe type of deck and seal system selected. Installing an inter nal 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 n oncontact, bolted, aluminum internal floating roof with a sing le vapormounted wiper seal and uncontrolled fittings.63

Loss of VOCs from internal floating roof tanks occu rs in one of four ways: 1) Through the annular rim space around the perimete r of the floating roof (seal losses), 2) Through the openings in the deck required for var ious types of fittings (fitting losses), 3) Through the nonwelded seams formed when joining s ections of the deck material (deck seam losses), and 4) Through evaporation of liquid left on the tank wa ll following withdrawal of liquid from the tank (withd rawal loss).

4.1.4.1 Control of Seal Losses . Internal floating roof seal losses can be minimized by employing liquid-mountedprimary 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 loca tion of the seal (i.e., vapor- or liquid-mounted) and the prese nce of a secondary seal are the major factors affecting seal losses. A liquid-mounted primary seal has a lower emissions r ate, and thus a higher control efficiency, than a vapor-mounted s eal. A secondary seal, with either a liquid- or a vapor-mo unted 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 f or the particular application. For instance, an elastomer ic wiper seal is commonly employed as a vapor-mounted primary sea l or as a secondary seal for an internal floating roof. Beca use of its shape, this seal is not suitable for use as a liqui d-mounted primary seal. Resilient foam seals, on the other h and, 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 inter nal floating roof. Among them are access hatches, column wells, roof legs,64

sample pipes, ladder wells, vacuum breakers, and au tomatic gauge float wells. Fitting losses occur when VOCs leak a round these fittings. Fitting losses can be controlled with ga sketing and sealing techniques or by the substitution of fittin gs that are designed to leak less. The effectiveness of fitting controls at reducing t he overall
emission rate is a function of the number of fittin gs of each type employed on a given tank. For example, if usi ng 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 fi ttings reduce the overall emissions by (.36*.35)= .126, or 12.6 p ercent over a similar tank without fitting controls. The usual i ncrease in control efficiency achieved by installing controlle d 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 includi ng internal floating roofs. Any roof constructed of sheets or panels fastened by mechanical fasteners (e.g., bolts) is e xpected to
have deck seam losses. Deck seam losses are consid ered to be a function of the length of the seams and not the typ e of mechanical fastener or the position of the deck rel ative to the liquid surface. This is a conclusion drawn from a 1986 study on two roof types with significantly different mechani cal fasteners
and differences in the amount of contact with the l iquid surface. Deck seam losses are controlled by selecting a roof type with vapor-tight deck seams. The welded deck seams on s teel pan roofs are vapor tight. Fiberglass lapped seams of a glas s fiber reinforced polyester roof may be vapor tight as lon g as there is negligible permeability of the liquid through the s eam 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 fitt ings 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 dep endent upon the characteristics of the particular VOC. Since f loating decks are often constructed primarily of aluminum, they m ay 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 selecti on of tank improvements as an applicable control technology. For chemicals with very low vapor pressure, fixed roof tank emiss ions will already be so low that installing an internal float ing roof may not significantly reduce emissions further. For ch emicals with vapor pressures up to 65 kPa (9.4 psia), emission r eductions of 95 percent and above are achievable with this techn ology. 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 wi th relatively high vapor pressures. 1

4.2 DESCRIPTION OF MACT AND SUMMARY OF REGULATORY AL TERNATIVES

The CAA requires that in designating regulatory opt ions, the maximum degree of reduction in emissions that is de emed achievable shall be subject to a floor, which is de termined differently for new and existing sources. For new sources, the standards must be set at levels which are not any l ess stringent than the emission control that is achieved in pract ice by the best controlled similar source. For existing sourc es, the standards may not be less stringent than the averag e emission limitation achieved by the best performing 12 perce nt of existing sources in each category or subcategory of 30 or mo re sources. In determining whether the standard should be more stringent than the floor and by how much, EPA is to consider, amon g other66

things, the cost of achieving such additional emiss ion reductions. The options for achieving reductions a t each emission point are presented separately in the foll owing 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 proces s vents and how they were arrived at. The EPA evaluated the cur rent level of control for miscellaneous process vents in eight St ate and two air districts that contain the majority of refineri es and were expected to have the most stringent regulations. Of the refineries in the U.S., the 12 percent that are sub ject to the most stringent regulations are located in three Sta tes. 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 re quired to be controlled. The median applicability cutoff level for the 12 percent of U.S. refineries subject to the most stri ngent 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 an d is the standard for miscellaneous process vents. The pri mary organic HAPs at refineries are also VOC. Additionally, a V OC-based applicability criteria is most reflective of the cu rrent 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 fina l rule to distinguish Group 1 from Group 2 vents. Group 1 ve nts, those that emit over 33 kg/day, must be controlled, where as Group 2 vents, representing all other vents, are not requir ed to apply controls under the final rule. The applicability l imit is determined as gases exit from process unit equipmen t and not
downstream from an emission control device. The ne w source MACT floor also includes reduction of emissions from mis cellaneous 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 exist ing 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 l evel of control on each storage vessel at each refinery wit h 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 b eing
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 meter s (1,115 barrels or 47,000 gallons) storing liquids w ith true vapor pressures greater than or equal to 23 kilopascals ( kPa) (1.5 psia) must be controlled to the requirements o f subpart Kb with the exception of the controlled fitting requir ements for floating roof vessels. EPA determined, based on th e available data, that an emission reduction more stringent tha n 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 stora ge vessel regulations. The MACT floor and an option more str ingent than the floor requiring control of storage vessels with vapor pressures above 0.014 kPa (0.002 psia) (which is th e 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 m 3 (950 barrels or 40,000 gallons) storing liquids with true vapor pre ssures greater68

than or equal to 3.4 kPa (0.5 psia), and vessels wi th capacities greater than or equal to 76 m 3 (475 barrels or 20,000 gallons) storing liquids with vapor pressures equal to or gr eater than 77 kPa (11.1 psia) would be required to comply with the subpart Kb (including the controlled fitting requir ements). The option more stringent than the floor was not select ed 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 alternati ve selected is the floor level of control (compliance with the Ben zene Waste Operations NESHAP (BWON)). The BWON controls 75 pe rcent of the benzene in refinery wastewater and 76 percent of th e volatile organic HAP in refinery wastewater. The best perfo rming wastewater control systems are those that are in pl ace to comply with the BWON. These systems control not only benz ene, but also the other organic HAPs in petroleum refinery wastew ater. Benzene is an effective surrogate for indicating the presen ce of all HAP compounds in petroleum refinery wastewater because data show that the majority of the total HAP compound loading in w astewater consists of compounds that are very similar to benz ene 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 redu ction, cost, energy, or other environmental or health impacts ar e associated with the standard. Based on data provided to the E PA through the BWON 90-day reports, the EPA determined that the BW ON was applicable to 43 percent of the refineries. No ref ineries are known to have more stringent controls than the BWON . Therefore, the MACT floor, or the average of the top performin g 12 percent of sources, is control to the BWON level of control

. EPA also considered an alternative level of emissio n reduction more stringent than the MACT floor that would be ac hieved by controlling all wastewater streams with at least 10 ppmw benzene69

at any refinery regardless of the size of its annua l benzene loading. This alternative control option was not s elected
because the additional emission reduction achieved through further control was not significant, given the asso ciated costs. The floor alternative was selected as the promulgat ed level of control for new sources. As with existing sources, the option more stringent than the floor was considered, but w as 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 a lternatives for equipment leaks. The Petroleum Refinery NSPS r equirements (40 CFR part 60 subpart VV) is the MACT floor for e xisting 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 r ule (40 CFR part 63 subpart H). The modified negotiated regula tion is the same as what was contained in the proposed petroleu m refinery NESHAP, except that the compliance dates have been extended. Although not required in the final rule, the EPA pr omotes use of the modified negotiated rule option because it is b elieved to provide considerable product, emissions, and cost s avings to a refinery. Under either option, existing refineries will be re quired to implement an LDAR program with the same leak defini tions (10,000 ppm) and the same leak frequencies as contained in the NSPS by 3 years after promulgation. A refinery may opt to re main at this level of control and do the monitoring, recordkeepi ng, and reporting specified in the NSPS. This option allow s refineries that are familiar with the Petroleum Refinery NSPS to continue to implement that standard without needing to change t heir 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 pr omulgation,70

and comply with Phase III 5 1/2 years after promulg ation. Each phase has lower leak definitions for pumps and valv es. For new sources, EPA requires refinery sources to m eet the same requirements as for existing sources.

4.2.5 Summary of Alternatives
Based on the determination of the MACT floor for ea ch of the four emission points, EPA selected a regulatory alt ernative. Alternative 1, the regulatory alternative selected, incorporates MACT floor level control for wastewater streams, st orage vessels, and miscellaneous process vents, and the floor for equipment leaks. Table 4-1 presents a summary of the altern ative examined in this analysis.

4.3 NO ADDITIONAL EPA REGULATION E.O. 12866 requires that the rationale for regulati on versus no regulation must be addressed in the decision pro cess. To satisfy this requirement, this section presents the alternatives to regulation of HAP emissions from petroleum refin eries. The alternatives include reliance on the judicial syste m for pollution control, or reliance on regulation by Sta tes and
localities.

4.3.1 Judicial System In the absence of governmental regulation, market s ystems fail to make the generators of pollution pay for the cos ts associated with that pollution. For an individual firm, pollu tion is an apparently unusable by-product that can be disposedof cheaply by venting it to the atmosphere. However, in the atmo sphere, pollution causes real costs to others. The fact th at producers, consumers, and others whose activities result in ai r pollution do
not bear the full costs of their actions leads to a divergence between private costs and social costs. This diver gence is considered a market failure, since it results in a misallocation of society's resources. Too many resources are devo ted to the71

polluting activity when polluters do not bear the f ull cost of
their actions.TABLE 4-1. SUMMARY OF REGULATORY ALTERNATIVES BY EMISSION POINTEmission Point Alternative 1 Description of Control OptionEquipmentLeaksOption 1 Floor = Compliance with the petroleumrefinery NSPS.Option 1 = Compliance with provisionsin 40 CFR part 60 subpart VV of thePetroleum Refinery NSPS, or complyingwith a modified negotiated regulationfor equipment leaks presented in 40CFR part 63 subpart H (HON equipmentleaks).MiscellaneousVentsMACT Floor Floor = Control of vents with VOCemissions greater than 72 lb/day (33kg/day). For Group 1 vents only.WastewaterStreamsMACT Floor Floor = Compliance with the BWON, onlyfor Group 1 streams.StorageVesselsMACT Floor Floor = Group 1 storage vessels onlyare required to put on one of thefollowing control systems: 1) aninternal floating roof (IFR) withproper seals; 2) an external floatingroof (EFR) with proper seals; 3) anEFR converted to an IFR with properseals; or 4) a closed vent system witha 95 percent efficient control device.73

Also, if there was no regulation, the previous regu lations would be relied upon as the basis for making judicial dec isions regarding excess emissions.

4.3.2 State and Local Action The CAA requires the Agency to establish emission s tandards, and if EPA fails to do this, the burden falls on th e States to develop and implement measures to attain and mainta in such
standards. Each State assembles these measures in a document called the State Implementation Plan (SIP). SIPs m ust be approved by EPA, and EPA is empowered to compel rev ision of plans it believes are inadequate. EPA may assume enforce ment 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 Stat es. If the EPA were not to promulgate the standards, States wo uld 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 actio n is not a
viable substitute for the standards. This belief ho lds even if EPA were to step up research and technology transfe r programs to assist State and local governments.

4.4 ROLE OF COST EFFECTIVENESS IN CHOOSING AMONG REG ULATORY ALTERNATIVES

EPA has often used cost effectiveness (C/E) analysi s as a guide for selecting among regulatory alternatives. Regulatory
alternatives can sometimes be ranked based on strin gency of control. All else equal, alternatives yielding the same level of control but higher average C/E (usually control cos t per ton of pollutant reduced) could be eliminated from conside ration. Incremental C/E can then be calculated for each ste p up the stringency ranking. The selection of a regulatory alternative could then be made by choosing the most stringent a lternative below some agreed upon C/E cutoff. The level of su ch a C/E74

cutoff would generally depend on the pollutant bein g 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 regar dless of the C/E at this control level. At stringency levels be yond the MACT floor, cost effectiveness can be legally considered , and EPA believes cost-effectiveness of controls is a primar y consideration for evaluating stringency levels beyo nd the MACT floor. The average cost effectiveness of the regul ation ($/Mg of pollutant removed) is included as part of the cost analysis in Chapter 5.

4.5 ECONOMIC INCENTIVES: SUBSIDIES, FEES, AND MARKE TABLE PERMITS

Economic incentive strategies, when designed proper ly, act to harness the marketplace to work for the environment . In deciding among regulatory options, EPA is required to consid er as options such strategies which influence, rather than dictat e, producer and consumer behavior, in order to achieve environm ental goals. Economic incentive programs make environmental prot ection of economic interest to producers and consumers. When feasible, properly designed systems can be employed to achiev e any environmental goal at the least cost to society. Several types or categories of economic incentive s trategies exist. One broad category of incentive programs is based of the use of fees or subsidies. Fee programs establish a nd collect a fee on emissions, providing a direct economic incen tive for emitters to decrease emissions to the point where t he 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 strat egies is based on the concept of emissions trading. A wide range of75

variations in emissions trading programs are possib le. The common idea in such programs is to allow sources wi th low
abatement cost alternatives to trade or sell emissi on 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 w orkability of economic incentive programs. The first constrai nt concerns the problem of emissions monitoring. Without an ef fective emissions monitoring system it is not possible to c harge fees or use other economic incentive strategies. Only the traditional "command and control" approach of requiring employm ent of specific control technologies is feasible in this c ircumstance. The second problem constraining the potential value of economic incentive strategies is legal. Various le gal restrictions imposed by the CAA limit the applicabi lity of economic incentive strategies to reduce air polluti on. Legal constraints imposed by Title III of the Act s everely limit the usefulness of economic incentive strategi es for reducing HAP emissions. Title III requires the imp lementation of
MACT. Thus sources have little or no choice as to the type or level of control they implement except perhaps if g oing beyond
the MACT floor control level. As a limited economi c 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 fo r the petroleum refinery NESHAP is therefore very limited . However, emissions averaging at the facility level may be fe asible and legal given that each facility is considered an emi ssions 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 inc entive strategy may be implemented for the Petroleum Refin ery NESHAP regulation. The analysis of control costs (Chapter 5) does not incorporate emission averaging. It is recognized t hat if76

emissions averaging were incorporated into the stan dard, facilities' costs of control should fall. Thus, th e 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: Or ganic Hazardous Air Pollutants from the Synthetic Organic Chemical Manufacturing Industry and Seven Other Pro cesses. 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 Lan dfills - Regulatory Impact Analysis. March 1991.7879 5.0 COST ANALYSIS AND EMISSION REDUCTION

Section 5.1 of this chapter presents the methodolog y used to estimate the regulatory compliance costs for the op tion listed in Table 4-1. Section 5.2 presents total compliance c osts by emission point, the corresponding emission reductio ns for each alternative, and discusses the cost effectiveness o f controlling each of the four petroleum refinery emission points . Section 5.4 presents any cost categories not directly associate d with a control technique, including monitoring, reporting, and recordkeeping costs.

5.1 APPROACH FOR ESTIMATING REGULATORY COMPLIANCE CO STS This section explains the methods used for estimati ng the emissions associated with petroleum refineries and the impact associated with controlling existing petroleum refi nery emission sources using various alternative control technolog ies. These estimates are used to compare different control alt ernatives and select the provisions for the proposed NESHAP for p etroleum
refineries. Emissions and control impacts were estimated for ea ch of the four petroleum refinery emission points: storage v essels, wastewater collection and treatment systems, equipm ent leaks, and miscellaneous process vents. The control impact es timates include estimates of emission reductions, control c osts, and where applicable, energy impact. A qualitative ass essment of the possible impact of secondary air pollution, water p ollution, or solid waste generation is also included. The emissions calculations involved three steps: (1) development of a database characterizing refine ries,80

(2) development and assignment of scaling factors f or each kind of emission point to use for estimating emissions f or refineries that provided no data, and (3) calculation of natio nwide emissions and control impacts. The database included the processes and technology used to produce refinery products and controls used to redu ce emissions. This information came from responses to survey ques tionnaires
sent out under section 114 of the CAA and informati on collection requests. Refineries across the United States resp onded to the questionnaires and provided control and process inf ormation for process vents, storage vessels, wastewater treatmen t systems, and leaking equipment. In addition, information on exi sting regulations was compiled to determine the control r equirements that apply to petroleum refineries. Because site-specific data were not available for e very refinery, scaling factors relating refinery process parameters or emissions to the charge capacity of refinery proces ses were derived from the available data. Estimates of emis sions and control impacts for refineries for which data were lacking were derived using scaling factors. Scaling factors cou ld be used because the emission mechanisms and applicable cont rol technologies are well understood for the kinds of s ources to be regulated by the petroleum refinery NESHAP, and the se characteristics are similar from refinery to refine ry. Baseline emissions represent emission levels from p etroleum
refineries that would occur in the absence of a ref inery MACT standard. Baseline emissions were estimated using calculation algorithms based on known, previously published, we ll-established methods from the process charge capacities of the r efineries in the database and the data reported in the questionn aire responses. The impact of each alternative control level was estimated using previously developed cost algorithm s and control efficiencies for commonly used control technologies . The control technologies included in the analysis were chosen b ecause they can achieve emission reductions at least as stringe nt as the MACT floor. While the selected control technologies wer e used as the81

basis of the control impacts estimates, the promulg ated standards are written using formats that would allow use of o ther control technologies if the equivalent emission reduction i s achieved. The impact estimates are based on average, represen tative, or typical emissions and control requirements for each kind of source. Thus, the estimates do not reflect the imp act that would be observed at any particular refinery. However, t hey do provide
a reasonable estimate of nationwide emission reduct ions and represent the range of control costs that refinerie s might incur under different regulatory alternatives. The specific procedures used to estimate baseline e missions
and the costs and emission reductions for the diffe rent control alternatives for each kind of emission point are de scribed separately for new and existing sources.
5.1.1 Calculations for Existing Sources For existing petroleum refinery sources, baseline e missions and control impacts were calculated for the four so urces for individual refineries and aggregated to determine n ationwide impacts. Some sources were not as well characteriz ed as others. In these cases, the available information was extra polated to
derive nationwide estimates.
5.1.1.1 Storage Vessels . Emissions and emission reductions from storage vessels are a function of the volatili ty of the material stored and the type of storage vessel. Re sponses to questionnaires sent to refineries provided informat ion on the volatility and HAP content of materials stored and the types of
vessels used to store materials. Based on informat ion in the questionnaire responses, factors for storage vessel population and VOC emissions were developed and used to estima te baseline emissions of HAPs and VOC, emission reductions at t he floor level of control and above, and costs for controlling emi ssions to the floor level of control and to levels more stringent than the floor. Thirteen "major" petroleum liquids were inc luded in this analysis: crude oil, gasoline, naphtha, asphalt, a lkylate, reformate, jet kerosene/kerosene, heavy gas oil, av iation gasoline, diesel/distillate, jet fuel (#4), residua l fuel oil,82

and slop oil. In a previous analysis using all ava ilable information, these 13 petroleum liquids accounted f or 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 wer e divided into groups based on storage vessel type (e.g., fixed ro of), refinery crude capacity (greater than or less than 150,000 b arrels per calendar day (bbls/cd)), and petroleum liquid store d (e.g., gasoline, naphtha, etc.). The average number of ve ssels in each group per barrel of crude capacity at a refinery wa s the tank population factor. For example, the questionnaire responses indicated that the number of internal floating roof vessels storing gasoline at refineries with crude capacitie s 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 stora ge vessel grouping. To calculate the VOC factor, VOC emissio ns from the storage vessels reported in the questionnaire respo nses were estimated using equations in chapter 12 of AP-42. Where data were missing or insufficient, default values, devel oped from information in the questionnaire responses, were us ed. Average
VOC emission factors at the baseline level of contr ol were then calculated for each vessel grouping. For example, for internal floating roof vessels storing gasoline at refinerie s with crude capacities greater than 150,000 bbls/cd, an average VOC emission factor of 15,000 lbs VOC emitted/vessel was calcula ted.
The number of vessels and the baseline VOC emission s nationwide were estimated in the following way. Th e crude capacity of each refinery in the nation, as listed in OGJ, was multiplied by the population factor for each applic able type of vessel to estimate the numbers and types of vessels at each refinery. This yielded the nationwide storage vess el population. The baseline VOC emission factor (lb VOC emitted/ve ssel)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 capacitie s 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 yie lded the estimated VOC emissions. Certain petroleum liquids (e.g., asphalt, alkylate, and reformate) are directly asso ciated with specific process units. If OGJ did not list capaci ties 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 Polluta nt Emission Estimates from Petroleum Refineries," in the docket ). Emissions of HAPs were estimated by multiplying the VOC emissions calculated for each type of material stor ed by the average HAP weight fraction in the vapor phase of t he material. Average vapor phase HAP weight fractions were calcu lated from the HAP liquid concentrations (obtained from industry q uestionnaire responses) using Raoult's Law and the vapor pressur e of the
individual HAPs. Emission reductions and costs for control options w ere estimated using the extrapolated nationwide storage vessel population. For all control options, factors for a verage emission reduction and costs were developed by calc ulating specific emission reductions and costs for the 3,40 0 storage vessels reported in the questionnaire responses. A verage emission reduction and cost factors were then calcu lated for each storage vessel group. An analysis of refinery storage vessels indicated t hat 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 w ith an internal floating roof and seals that comply with s pecifications84

in the storage NSPS (40 CFR 60 subpart Kb) and HON (40 CFR 63 subpart G). For existing external and internal flo ating 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 exi sting fixed roof storage vessels. For existing external and in ternal floating roof vessels, the more stringent control a lternative is to comply with the fitting requirements in the prop osed HON in addition to the seal requirements. The emission reduction assigned to each of the 3,40 0 storage
vessels was calculated as a function of the emissio n reductions presented in the EPA publication "NSPS VOC Emission s from VOL Storage Tanks--Background Information for Proposed Standards". This document provided the emission reduction (in p ercent) of various seal and fitting configurations compared wi th fixed roof vessels. For example, an internal floating roof ve ssel with a liquid mounted primary seal and controlled fittings has an average emission reduction of 96.2 percent over a s imilar 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 reduct ion applied to each storage vessel was calculated as the differenc e between the level of control required by the control option andthe baseline
level of control. The cost equations for converting existing fixed ro of vessels to internal floating roof vessels were taken from t he "Control of Volatile Organic Compound Emissions from Volatile O rganic Liquid Storage in Floating and Fixed Roof Tanks" (Draft, J uly 1992), and "Internal Instruction Manual for ESD Regulation-Sto rage Tanks" (January 1993). The cost equations for adding seal s and controlled fittings to existing external and intern al floating
roof vessels were also taken from these two documen ts.85

5.1.1.2 Wastewater Collection and Treatment Systems

. Emissions and emission reductions from wastewater c ollection and treatment systems are both a function of wastewater stream flow, the HAP compound concentration in the wastewater, a nd the volatility of the HAP compounds in the wastewater. Emission reductions are also a function of the design and op erating parameters of the control device. EPA gathered data for the wastewater stream flow ra te and the concentration of HAPs in petroleum refinery wastewa ter to develop models of wastewater from process units found at re fineries. 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 refin ery 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 determi ned 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 a nalyses developed for the HON were judged to be appropriate to use to estimate the cumulative mass fraction of HAPs emitt ed from wastewater collection and treatment systems. Uncontrolled emissions were determined by multiplyi ng the mass fraction of HAPs emitted by the mass loading of vol atile HAPs. However, many petroleum refineries control their wa stewater 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 c redited in the national baseline emissions calculations by applyin g the applicability criteria of the BWON (i.e., wastewate r streams with flows greater than 0.02 l/min and benzene concentra tion of 10 ppmw or greater at a facility with at least 10 M g/yr total annual benzene loading in wastes and wastewater) to each refinery86

and wastewater stream and by assuming that the cont rol requirements of the BWON (i.e., 99 percent reductio n of benzene) were met for those streams requiring control.

An analysis of existing refinery wastewater collect ion and treatment systems indicated that the MACT floor for wastewater is the BWON. (For more information, refer to ["Maximu m Achievable Control Technology Floor for Process Wastewater Str eams at Petroleum Refineries,"] in the docket). Existing r efineries are already required to comply with the BWON, so no emi ssion
reductions or costs would be associated with the fl oor option for refinery wastewater sources. In considering a cont rol option more stringent than the BWON, the EPA assessed the effects of lowering the applicability threshold of the BWON, b y eliminating the cutoff of 10 Mg/yr TAB loading in facility wast es and wastewater. The additional wastewater streams requ iring control (those streams with at least 10 ppmw benzene at ref ineries with a TAB under the 10 Mg/yr loading criterion) were assu med to be steam stripped to achieve reductions equivalent to the requirements of the BWON (e.g., 99 percent reductio n 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 Proce ss Wastewater,"] in the docket). The results of prior EPA analyses
were used to estimate the mass fraction of HAPs rem oved from a wastewater stream by a steam stripper as well as th e costs associated with the stripper system. (For more inf ormation, refer to "Steam Stripper Removals and Costing for P etroleum 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 rem oval, depending on the volatility of the HAPs in the stre am. 5.1.1.3 Equipment Leaks . Emissions and emission reductions from leaking equipment are a function of the compon ent counts and the control program used to reduce emissions. The questionnaires were designed to obtain equipment leak information for87

18 different refinery process units because the con trols required may vary from process unit to process unit. The qu estionnaire responses included information on component counts, the HAP content of refinery process streams, and the monito ring frequencies and leak definitions used for leak dete ction 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 p rograms to determine which control program was being used to r educe
emissions. Data on equipment leaks were reported by approximat ely 70 percent of the refineries in the nation. For th ose refineries not reporting information, the characteristics of m odel process units (for each of the 18 process units of interest ) were assigned to the refinery based on information in OG J. The model process units were developed as the median componen t count of the process units from refineries reporting information in the surveys. If OGJ data indicated that a refinery con tained a specific process unit, then the median counts for t he model representing that process unit was assigned to the refinery. If the refinery was determined to be in an ozone nonat tainment area, the EPA assumed that the refinery would be controll ed to the level of control in the petroleum refinery CTG.
Uncontrolled HAP emissions from each of the 18 diff erent refinery process units were estimated by multiplyin g the uncontrolled VOC emissions from each unit by the av erage HAP-to-VOC ratio of the streams associated with eac h unit. Uncontrolled VOC emissions from leaking equipment w ere estimated on a process unit basis by multiplying the componen t counts for the process unit by VOC emission factors for each e quipment component. The VOC emission factors relate VOC emi ssions to the type of component leaking (e.g., pumps, valves, etc .) in units of lb/hr/component type. The emission factors used fo r the impacts analysis were taken from a previous EPA study on le aking refinery equipment and presented in chapter 9 of AP-42. The se emission factors are currently being reviewed by EPA based o n new industry88

data. The emission estimates may be revised at pro mulgation if new factors are developed by EPA based on the new i ndustry data.
Baseline emissions of HAPs and VOC were estimated b y multiplying the uncontrolled emissions by one minus the control efficiencies associated with each LDAR program repo rted by or assigned to each refinery. The "Equipment Leaks En abling Document" (in the docket) provides information on t he control efficiencies that may be achieved by monitoring components under various LDAR programs. (For more information, refe r to "Summary of Nationwide Volatile Organic Compound and Hazardo us Air
Pollutant Emission Estimates from Petroleum Refiner ies," in the docket). An analysis of existing controls on refinery equipm ent leaks
indicated that the MACT floor level of control for refinery equipment leaks was the control required by the Pet roleum Refinery NSPS. For more information refer to ["Max imum Achievable Control Technology Floor for Equipment L eaks at Petroleum Refineries," in the docket]. Two more st ringent control options were also analyzed: (1) compliance with the negotiated equipment leaks regulation included in t he HON, without the monitoring requirements for connectors, and (2) compliance with the negotiated equipment leaks regulation included in the HON. Each of these options require s specific leak monitoring frequencies for components and cont rol devices. Emission reductions for controlling leaking equipme nt to the level of control required by the NSPS and the two m ore stringent options were calculated from the difference between baseline emissions and the emissions calculated using the pe rcent reductions associated with the petroleum refinery N SPS and the HON equipment leaks negotiated rule. Similarly, th e cost impact of controlling leaking equipment to the level requi red by the NSPS and the two more stringent control options was calculated
from the cost of control devices and labor associat ed with the petroleum refinery NSPS and the negotiated rule. T he cost methodology was based on procedures provided in the "Equipment Leaks Enabling Document." (For more information, r efer to89

["Costs for the MACT Floor Level of Control and Con trol Options Above the Floor for Controlling Emissions from Leak ing Refinery Equipment,"] in the docket).
5.1.1.4 Miscellaneous Process Vents . The miscellaneous process vent group includes most miscellaneous proc ess vents that emit organic HAPs at refineries other than FCCU cat alyst regeneration vents, catalyst reformer catalyst rege neration vents, and sulfur plant vents. The baseline HAP em issions from miscellaneous process vents were estimated by multi plying HAP emission factors by the charge capacities of refine ry processes. Specific HAP emission factors were developed by div iding the HAP emissions reported in questionnaire responses by th e charge capacities of those refineries reporting the specif ic HAP. (For further information, refer to "Summary of Nationwid e Volatile Organic Compound and Hazardous Air Pollutant Emissi on 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 emissi on reductions were calculated by applying this percent reduction to emissions from miscellaneous process vents that are uncontrol led at baseline. The cost for controlling emissions from miscellaneous vents includes the cost for piping emissions to exi sting control devices and an additional compressor for the refine ry. EPA assumed that refineries would already have an exist ing fuel gas or flare system that could be used to reduce emissi ons from miscellaneous process vents. Further information o n costing procedures and specific assumptions is contained in "Costing Methodology for Controlling Emissions for Miscellan eous Process Vents," in the docket.
5.1.2 Calculations for New Sources This section explains the methodology used for esti mating emissions and control impacts in the first 5 years after the promulgation of this rule. These costs represent c ontrol of new process units and equipment built within the first 5 years after promulgation. It should be noted for regulatory pu rposes, that90

some of these units and equipment will be considere d "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, contro ls will be required for the emission points in either case. Costs for controlling new process units were estima ted from the costs calculated for existing sources and the n umber of new process units that are expected to be constructed i n the 5-year period after the standard is enacted. The costs fo r applying control technologies to existing sources were calcu lated as previously described. The results are documented i n the four memoranda presenting cost impacts (in the docket). The cost information was scaled up to account for new emissi on points that may need to be controlled in the first 5 years afte r the petroleum refinery NESHAP has been promulgated. Re ductions of emissions of HAPs and VOC from controlling existing emission points were also presented in the costing memorandu m. The emission reduction information was scaled up to acc ount for controls on new emission points using the same meth odology that was used to scale up cost data. (For further infor mation, refer
to "Estimation of Annual Costs for New Petroleum Re finery Emission Points in the Fifth Year After Promulgatio n," in the docket). OGJ provided estimates of annual refinery construct ion projects. This information was used to determine a n 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 fo r VOL storage) to storage vessels larger than 151 m 3 (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 pe troleum refinery NESHAP would result in no costs or emissio n reductions for those storage vessels required to comply with s ubpart Kb (all new vessels with a capacity greater than or equal t o 40 m 3 or 250 bbl). This methodology may overestimate the impact of the91

regulation in the 5 years after promulgation becaus e, 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 e quivalent to the NSPS, there will be no costs or emission reduct ions for existing storage vessels. Therefore, the fifth yea r impacts on vessels at new sources would be lower than the impa ct estimated
here because the number of vessels at new sources i s probably
overestimated.
5.1.2.2 Wastewater Collection and Treatment Systems . A MACT floor analysis performed on wastewater collection a nd treatment systems indicated that the MACT floor level of cont rol for wastewater streams at new sources is compliance wit h the BWON. Therefore, no costs are anticipated for sources bui lt in the 5 years after promulgation to reach the MACT floor level of control. The control option more stringent than th e floor that was considered was the same as the option considere d for existing sources: assessing the effects of lowering the app licability 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 proc ess units that will generate wastewater is expected to be app roximately 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 e stimating costs for new sources as for existing sources, cost s 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) wouldbe approximately $42 million. The total annual cost t o be expended in the fifth year (considering all 170 new units) w ould 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 c onstruction92

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 proce ss units is expected to require control under the NSPS for refi neries. Therefore, the only cost associated with controllin g these units is the extra cost required to go from the NSPS cont rol 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 nego tiated regulation for equipment leaks in the HON (40 CFR 6 3 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 regul ation without connector monitoring were determined to be $20,000 and $7,000/yr per process unit, respectively. The average capita l investment and annual cost of upgrading from the NSPS to the H ON negotiated regulation were determined to be $17,000 and $6,200 /yr per process unit, respectively. For each option, the c apital investment cost and average annual cost for control ling the 34 process units constructed each year was calculat ed by multiplying the average cost per process unit by th e number of new process units.
5.1.2.4 Miscellaneous Process Vents . The MACT floor level of control for miscellaneous process vents at new sour ces was determined to be combustion. The annual cost for c ontrolling
emissions from miscellaneous vents consisted the co st for piping to an existing combustion system (to a flare or to the fuel gas system) and for an additional compressor for each r efinery. 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. Th e number of93

miscellaneous vents requiring control was calculate d from the average number of uncontrolled vents per process un it, as presented in the baseline emissions estimation memo randum (refer to docket). Based on this information, one vent fo r each of the 34 process units is estimated to require control (t hat is, a total of 34 new vents will require control each yea r). This number of vents per year was multiplied by the aver age cost per vent to estimate national costs for miscellaneous p rocess 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 a re shown in
Table 5-1 for the chosen alternative. The total na tional cost of Alternative 1 in the fifth year is $79 million. Ta ble 5-2 presents the costs, HAP emission reductions, and co st effectiveness for the control options by emission p oint. The average cost effectiveness of the regulation ($/Mg of pollutant removed) is determined by dividing the annual cost by the annual emission reduction. Table 5-3 presents a summary o f the HAP emission reductions, total cost, and cost effective ness values for the chosen regulatory alternatives. The emissi on 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 effectiv eness values
were calculated as described above. The incrementa l cost effectiveness represents the increase in cost from Alternative 1 to Alternative 2 divided by the increased HAP emiss ion reduction. Table 5-4 reports similar information for VOC emiss ions.TABLE 5-1. SUMMARY OF TOTAL ANNUAL COSTS IN THE FIFTH YEAR FOR THE PETROLEUM REFINING NESHAPAnnual Fifth Year Costs (1000$/yr)3(1992 Dollars)Emission Point OptionExistingSourcesNewConstruction Total Alternative 1Equipment LeaksMiscellaneousProcess VentsWastewater SystemsStorage VesselsFloorOption 11Floor2Floor1Floor1$69,000$59,000$12,000$ 0$8,000$ 0$(210)$370$ 0$98$69,000$58,790$12,370$ 0$8,098$58,790$11,370$ 0$8,098Other Recordkeepingand ReportingTOTAL COST$1,000$79,190NOTES:1Alternative 1.2EPA did not choose an option above the MACT floor for miscellaneous process vents.3Costs are in 1992 dollars.TABLE 5-2. CONTROL OPTIONS AND IMPACTS BY EMISSIONPOINTHAP Cost Effectiveness($/Mg HAP)Emission PointBaselineHAPEmissions(Mg/yr)ControlOptionEmissionReduction(Mg/yr)PercentEmissionReductionAnnualCost($1,000/yr)bAverage IncrementalMiscellaneous Process VentsExistingSources8,900 Floor* 7,600 85 $11,000 $1,500 N/ANew Sourcesa900 Floor* 770 85 $370 $480 N/AStorage VesselsExistingSources9,000 Floor* 670 7 $3,700 $5,500 N/AOption 1 1,300 14 $6,200 $4,800 $4,000Option 2 1,800 20 $8,400 $4,700 $4,400Option 3 2,600 29 $32,000 $12,000 $30,000New Sourcesa290 Floor* 4 1.4 $98 $24,000 N/AOption 1 14 4.8 $550 $39,000 $45,000WastewaterSystemsExistingSources9,200 Floor* 0 N/A 0 N/A N/AOption 1 7,700 93 $120,000 $15,000 $15,000New Sourcesa960 Floor* 0 N/A 0 N/A N/AOption 1 930 97 $18,000 $20,000 $20,000Equipment LeaksExistingSources50,000 Floor 35,000 69 $69,000 $2,000 N/AOption1*44,000 87 $58,000 $1,500 $(330)Option 2 46,000 91 $78,000 $1,700 $6,000New Sources 1,300 Floor 0 0 0 0 0Option1*640 49 $(210) $(330) $(330)Option 2 760 59 $840 $1,100 $8,30096NOTES:aImpacts were estimated for new process units constructed in the 5 years after promulgation. For regulatory purposes, some of these units may be considered new sources whileothers 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 table reflectcosts for operation andmaintenance 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.

1 Cost estimates do include costs associated with mon itoring, 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. 1 Emission reduction estimates do not incorporate red uctions occurring at new sources.98

5.3 MONITORING, RECORDKEEPING, AND REPORTING COST S In addition to provisions for the installation of c ontrol equipment, the promulgated regulation includes prov isions for
MRR. EPA estimates that the total annual cost for refineries to comply with the MRR requirements is $20 million. A fter incorporating MRR costs, the total cost of complian ce of Alternative 1 is $79 million. For Alternative 1, t he incorporation of MRR costs into total annual cost r esults in an average cost effectiveness of $313 for each megagra m of VOC reduced and $1,645 for each megagram of HAP reduced

. In order to calculate the costs of MRR associated w ith the petroleum refinery NESHAP, estimates of hours per i tem (i.e., a required MRR action), frequency of required action per year, and number of respondents (i.e., total number of indivi duals required to submit compliance reports) were estimated based on the requirements in the proposed rule for all of the em ission points. To compute the costs associated with the burden est imates, 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 (typica lly by an engineer with a wage rate of $33 per hour), 10 perc ent will be completed by a manager (at $49 per hour), and 5 per cent by clerical personnel (at $15 per hour). All of the w age rates include an additional 110 percent for overhead. Co sts were annualized assuming an expected remaining life for affected facilities of 15 years from the date of promulgatio n of the subject NESHAP, and using an interest rate of 7 per cent. Compliance requirements vary in terms of frequency. This
variance is taken into account in the annualization of costs. Performance tests to demonstrate compliance with th e control device requirements are required once. Compliance requirements also include monitoring of operating parameters of control devices and records of work practice and other insp ections. These activities must be reported semiannually. Th e compliance requirements that must be met only once are annuali zed over the99

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 determinat ion 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 m ust establish appropriate monitoring procedures. For wastewater stream and treatment operations, the MRR requirements are outl ined in the
rule for the BWON. For miscellaneous process vents, the promulgated st andard specifies the performance tests, monitoring require ments, and test methods necessary to determine whether a misce llaneous process vent stream is required to apply control de vices and to
demonstrate that the allowed emission levels are ac hieved when controls are applied. The format of these requirem ents, as with the format of the miscellaneous process vent provis ions, depends on the control device selected. The MRR requiremen ts for miscellaneous process vents are summarized by contr ol device in
Table 5-5. For equipment leaks, because the provisions of the proposed rule are work practice and equipment standards, mon itoring, repairing leaks, and maintaining the required recor ds constitutes compliance with the rule. The HON equipment leak p rovisions are appropriate to determine continuous compliance with the petroleum refinery equipment leak standards. In summary, the se provisions require periodic monitoring with a portable hydroca rbon detector to determine if equipment is leaking.TABLE 5-5. MISCELLANEOUS PROCESS VENTS — MONITORING, RECORDKEEPING, AND REPORTINGREQUIREMENTS FOR COMPLYING WITH 98 WEIGHT-PERCENT REDUCTION OF TOTAL ORGANIC HAP EMISSIONSOR A LIMIT OF 20 PARTS PER MILLION BY VOLUMEControl DeviceParameters to beMonitoredaRecordkeeping and Reporting Requirements forMonitored ParametersThermalIncineratorFireboxtemperatureb[63.644(a)(1)(i)]1. Continuous recordsc2. Record and report the firebox temperatureaveraged over the full period of theperformance test - NCSd3. Record the daily average firebox temperaturefor each operating daye4. Report all daily average temperatures thatare outside the range established in the NCSor operating permit and all operating dayswhen insufficient monitoring data arecollectedf- PRgCatalyticIncineratorTemperatureupstream anddownstream of thecatalyst bed[63.644(a)(1)(ii)]1. Continuous records2. Record and report the upstream and downstreamtemperatures and the temperature differenceacross the catalyst bed averaged over thefull period of the performance test - NCS3. Record the daily average upstream temperatureand temperature difference across catalystbed for each operating daye4. Report all daily average upstreamtemperatures that are outside the rangeestablished in the NCS or operating permit -PRTABLE 5-5 (continued).Control DeviceParameters to beMonitoredaRecordkeeping and Reporting Requirements forMonitored Parameters5. Report all daily average temperaturedifferences across the catalyst bed that areoutside the range established in the NCS oroperating permit - PR6. Report all operating days when insufficientmonitoring data are collectedfBoiler orProcess Heaterwith a designheat inputcapacity lessthan44 megawattsand Vent Streamis notintroduced withor as theprimary fuelh,iFireboxtemperatureb[63.644(a)(4)]1. Continuous records2. Record and report the firebox temperatureaveraged over the full period of theperformance test - NCS3. Record the daily average firebox temperaturefor each operating daye4. Report all daily average firebox temperaturesthat are outside the range established in theNCS or operating permit and all operatingdays when insufficient monitoring data arecollectedf- PRTABLE 5-5 (continued).Control DeviceParameters to beMonitoredaRecordkeeping and Reporting Requirements forMonitored ParametersFlare Presence of aflame at the pilotlight[63.644(a)(2)]1. Hourly records of whether the monitor wascontinuously operating and whether the pilotflame was continuously present during eachhour2. Record and report the presence of a flame atthe pilot light over the full period of thecompliance determination - NCS3. Record the times and durations of all periodswhen a pilot flame is absent or the monitoris not operating4. Report the times and durations of all periodswhen all pilot flames of a flare are absent -PRAll Control DevicesPresence of flowdiverted to the atmosphere from the controldevice [63.644(c)(1)] or1. Hourly recordsof whether theflow indicatorwas operatingand whether flowwas detected atany time duringeach hour.2. Record and report the times and durations ofall periods when the vent stream is divertedthrough a bypass line or the monitor is notoperating - PRMonthly inspections of sealedvalves [63.644(c)(2)]1. Records thatmonthly inspectionswere performedControl DeviceParameters to beMonitoredaRecordkeeping and Reporting Requirements forMonitored ParametersNOTES: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 encountered.c"Continuous records" is defined in §63.641 of thissubpart.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 within the rangeestablished in the NCS or operating permit, a statement to this effect can be recorded instead of thedaily 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 duration of the period whenmonitoring 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 where the vent stream isintroduced with or as the primary fuel. No recordkeeping or reporting associated with monitoring is required for such boilers and process heaters.iProcess vents that are routed to refinery fuel gassystems are not regulated under this subpart. No monitoring, recordkeeping, or reporting is requiredfor boilers andprocess heaters that combust refinery fuel gas.104105 6.0 ECONOMIC IMPACTS AND SOCIAL COSTS

The goal of the RIA is to evaluate the potential be nefits and costs of specific pollution control standards on ou r nation's economy. Potential regulatory benefits relate to r educed HAP and
VOC emissions that have detrimental effects on the health and well-being of members of society. Social costs ass ociated with the regulation are those costs borne by consumers a nd producers of refined petroleum products and by society at lar ge as a result of the proposed standards. A comparison of the cost s 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 an alysis will require domestic petroleum refineries to incur incr eased investment costs for control equipment and the asso ciated annual operation and maintenance expenses. Increased cost s of production may impact the domestic petroleum refini ng market in a number of ways. This report will examine primary m arket impacts resulting from the control measures including chang es in the market equilibrium price for refined petroleum prod ucts, output levels for products produced and sold nationally, v alue of domestic shipments or revenues for refineries in th e industry, and plant operations. Predicted changes in the mark et equilibrium price and quantity of refined petroleum products pr oduced and
sold will result in additional market modifications or secondary market impacts. The secondary effects relate to th e likely labor market adjustments (employment effects), energy inp ut market changes (changes in the energy used as an input in the production of petroleum products) and foreign trade effects (c hange in net106

exports). Control measures may also influence the capital availability and financial position of firms in the petroleum refining industry. Welfare changes for consumers, p roducers, and society at large or the social costs of the propose d emission controls will also be evaluated. Additionally, the Regulatory Flexibility Act (RFA) requires that an assessment b e 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, an d small business impacts of the emission controls on the pe troleum refining industry. A more detailed description of t he 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 imp acts, capital availability consequences, secondary market impacts , small business impacts, and social costs of the control m easures will be presented in this chapter.

6.1 PROFILE OF THE PETROLEUM REFINING INDUSTRY

The petroleum industry can be divided into five dis tinct sectors: (1) exploration, (2) production, (3) refi ning, (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 i ndustrial users. The Standard Industrial Classification (SIC ) code for all petroleum refineries is 2911. Although petroleum r efineries produce a diverse slate of products, the five prima ry output categories are (1) motor gasoline, (2) jet fuel, (3 ) residual fuel, (4) distillate fuel, and (5) liquefied petrol eum gases (LPGs), which in total accounted for 93 percent of all domestically refined petroleum products in 1992. T his analysis is concerned only with these five main product cate gories. It should be noted that the economic impact analysi s reflects the compliance costs from the proposal. Thus the a ctual impacts are smaller than estimated here, though only by a m inor 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 an d that are likely to influence the economic impacts associatedwith the implementation of the alternative NESHAPs are discu ssed. The information in this section represents the data inp uts to the
economic model used in the EIA. More details conce rning 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 t he proposed emission controls is presented in this section. Th e processes and product market characteristics of the petroleumrefining 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 petroleumproducts 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, m any of which are already subject to some CAA controls. There are numerous refinery processes from which HA P 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, equipmen t leaks, or from evaporation from storage tanks or wastewater s treams. The
NESHAP will address emissions from all of these ref inery emission points.
6.1.1.2 Product Description and Differentiation . Most petroleum refinery output consists of motor gasolin e and other108

types of fuel, but some non-fuel uses exist, such a s petrochemical feedstocks, waxes, and lubricants. T he output of each refinery is a function of its crude oil feedst ock and its preferred petroleum product slate. Motor gasoline is defined as a complex mixture of r elatively volatile hydrocarbons that has been blended to forma fuel suitable for use in spark-ignition engines. Residu al 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, commerci al and industrial heating, and electricity generation. Di stillate fuel oil is a general classification for one of the petr oleum fractions produced in conventional distillation ope rations. It is used primarily for space heating, on- and off-hi ghway diesel engine fuel (including railroad engine fuel and fue l for agricultural machinery), and electric power generat ion. Jet fuel is a low freezing point distillate of the kerosene type used primarily for turbojet and turboprop aircraft engin es. LPGs are defined as ethane, propane, butane, and isobutane p roduced at
refineries. Product differentiation is a form of non-price comp etition used by firms to target or protect a specific marke t. The extent to which product differentiation is effective depen ds on the nature of the product. The more homogenous the ove rall industry output, the less effective differentiation by indiv idual firms becomes. Each of the five petroleum products in th is analysis are by nature quite homogenous — there is little di fference 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 locat ion. Regional markets may differ due to the quality of crude supp lied or the local product demand. Some smaller refineries whic h produce only one product have single, local markets, while large r, more complex refineries have extensive distribution syst ems and sell109

their output in several different regional markets. In addition, because refineries are the source of non-hydrocarbo n pollutants such as individual HAPs, volatile organic compounds (VOCs), sulfur dioxide (SO 2 ), and nitrogen oxide (NO
x ), many Federal, State, and local regulations are already in place i n some locations. Differences in the regional market stru cture may also result in different import/export characteristics. The United States is segmented into five regions, c alled Petroleum Administration for Defense Districts (PAD Ds), 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 in dependent markets for petroleum products exist in each PADD. In addition to differences in regional markets, eac h 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 pr oducts — motor gasoline, for example — is not possible with anothe r refinery output, such as jet fuel. Thus, each of the produc ts in this analysis is treated as a separate product with its own share of the market. From a refinery standpoint, however, i f the production of one refined product were to become le ss costly after regulation, production of this product may in crease at the expense of a product with a more costly refining pr ocess. 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 complexi ty, almost all refineries have some atmospheric distill ation capacity and additional downstream charge capacity. Most of the employment in the industry exists at larger refiner ies. Slightly fewer than 4 percent of refinery employees work in establishments of fewer than 100 people, and the remaining 96 perc ent 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 , and110

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 siz e and complexity, refineries can be grouped by two main s tructural features: (1) atmospheric distillation capacity (w hich denotes their size) and (2) process complexity (which chara cterizes 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 perce nt in 1991. 2 This indicates that existing refineries are operati ng closer to full capacity than in the past, and will have limit ed opportunity to enhance production by increasing utilization. During the past 23 years, the entire domestic refin ing industry has been affected by crude oil quantity ch anges and shifting petroleum demand patterns. A more complex and flexible refining industry has evolved domestically. Owners hip of U.S. refineries has changed through consolidation and fo reign investments. Throughout the 1970s, the number of U .S. refineries rose rapidly in response to rising demand for petro leum products. In the early 1980s, the petroleum refining industry entered a period of restructuring, which continued through 19 92. A record number of U.S. refineries were operating in 1981. A decline in petroleum demand in the early 1980s caused many sma ll refineries and older, inefficient plants to close. The refine ry shutdowns resulted in improved operating efficiency, which en abled the refinery utilization rate to increase, despite lowe r crude oil inputs. Operable capacity has remained relatively c onstant 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 wit h atmospheric distillation, where atmospheric distillation is ass igned the111

lowest value, 1.0. The level of complexity of a re finery generally correlates to the types of products the r efinery 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 dif ferentiate among refineries having similar capacities but diff erent process capabilities. In theory, more complex refineries a re 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 capacit y (50,000 to 100,000 bbl/d) can be found at refineries with abov e-average complexity. Likewise, the smaller refineries are l ess 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 ma ny 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 pr icing is determined by market forces, rather than by the pro ducers. Alternatively an industry with monopoly power has m ore discretion over the market price charged. Producers in such a n 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, andthe 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 i ndustry, 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 distrib ution. For example, on one extreme, a concentration of 100 per cent would112

indicate monopoly control of the industry by one fi rm. On the other extreme, concentration of less than 1 percent would indicate the industry was comprised of numerous sma ll firms. Concentration is measured based on refining capacit y. Until recently, the top four firms in the refining indust ry have consistently comprised over 30 percent of the marke t share, but most market concentration ratios have marginally de creased in recent years. Market concentration may also be evaluated using th e Herfindahl-Hirschman index, which is defined as the sum of the squared market shares (expressed as a percentage) f or all firms in the industry. If a monopolist existed, with mar ket 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 1,00 0. Ratings are also developed for moderately concentrated (bet ween 1,000 and 1,800) and highly concentrated (greater than 1,800) industries. The petroleum refining Herfindahl-Hirschman index i n 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 inpu t for several stages of the production and marketing process. Fi rms that operate petroleum refineries are vertically integra ted because they are responsible both for exploration and produ ction of crude oil (which supplies the input for refineries) and f or marketing the finished petroleum products after refining occu rs. 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 fir ms that are vertically integrated. There are currently 20 majo r energy companies. The crude capacity of the major, vertica lly integrated firms represents almost 70 percent of nationwide pr oduction. For the major oil companies, horizontal integration exists because these firms operate several refineries whic h are often113

distributed around the nation. Seventy-three of th e 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 ar ray of unrelated products. In the short run, diversificat ion may indirectly benefit firms that engage in petroleum r efining, since the costs of control in petroleum refining may be d ispersed over other unaffected businesses operated by the firm. Over the long term, however, firms will not subsidize petroleum p roduct production with profit from other operations, but w ill shut down unprofitable operations instead. Diversification w ithin 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 particu larly relevant to an evaluation of the impact of regulation on the industry. In
order to evaluate the financial condition of the re finery operations of firms, a sample of the petroleum refi ning industry's major firms financial operations were ev aluated. Annual reports to stockholders were used as a sourc e of data for the analysis. While this sample is too small and d iverse to be considered representative of the aggregate industry , the data presented are more recent and more refinery-specifi c than
American Petroleum Institute data. The sample of annual report data analyzes refinery- specific data in order to provide a preliminary assessment o f the financial condition of firms in the industry. This 12-firm sample as a whole operated 59 refineries in 1991, a nd represented 45.3 percent of the industry's total refining capac ity. 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, o perating income per dollar of revenue increased from 1 perce nt to 4 percent. Capital expenditures increased steadily, while refined product sales continued a period of decline. The c onsolidation114

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 ove rall refinery financial performance. 4 The difference between refined product costs and refined product revenues is the r efined product margin. During the 1980s, refined product margins were affected by a shift in product slates to gasoline and jet fu els, the decrease in crude oil prices, fluctuations in deman d, 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 in creasing significantly in 1988. The fluctuations in the ref ined product margins reflect the volatility of the market and th e degree to which refineries' revenues are often subject to sig nificant 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 c rude oil prices and stable gasoline prices. 6 After the invasion of Kuwait, U.S. refined product prices did not keep pa ce with crude oil prices for the remainder of the year. This neg atively 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) borr owed funds, and (3) stock issues. Typically, firms seek a bala nce between the use of debt and stock issues for financing inve stments. Debt-to-equity ratios reflect a measure of the exte nt to which the firm has balanced the tax advantages of borrowi ng with the financial safety of stockholder financing. Based o n information obtained in the annual reports of the 12 companies in the refinery sample, firms anticipate that internally g enerated funds will fund most of their capital expenditures. Othe r firms recognize the need to also draw on available credit lines and commercial paper borrowing. Overall, capital expen ditures of refiners have doubled since 1977, although spendin g 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 co nstruction of diesel desulfurization units, expansion of existing units, and construction of units to manufacture methyl tertiar y butyl ether (MTBE) and oxygenated fuels. In a 1991 study, Camb ridge Energy Research Associates (CERA) surveyed refiners and ox ygenate producers to evaluate the ability of the refining i ndustry to meet CAA provisions. 7 Among the firms in the CERA survey, the majors and some large independents plan to fund the ir investments primarily or entirely from internally generated cas h 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 q uantities to meet increased demand. Most of the other petroleumproducts show a modest net increase in supply over the past few y ears. The lack of significant change in the yield for most re fined petroleum products indicates a relatively stable su pply slate, but significant regulatory costs could force some r eshuffling of product yield. Refinery production of motor gasoline has increasedeach year, with the exception of periods of economic recession . Production remained relatively steady from 1988 to 1992. Dist illate fuel oil output peaked at 3.3 million barrels per day in 1977, then fell through 1983. Output has increased slightly a lmost every year since, reaching 3 million barrels per day in 1 992. Jet fuel production grew during the 1970s and 1980s, and alm ost doubled by 1990 before declining to 1.4 million barrels per da y in 1992. Residual fuel oil production generally declined fro m 1980 through 1985, and was 1 million barrels per day in 1992, co mpared 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 dete rmination of how much crude oil to allocate for the production o f each of the116

refinery's products. The production decision depen ds on the profit each of the oil products can generate for th e firm. Profits, in turn, depend on the productivity of the oil refinery — its ability to produce each oil product as effect ively 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 prod uction of each product will determine any future changes in produc tion. Crude oil is the primary material input to the refining p rocess; as a result, the production of refined products is vulne rable 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 level s and expected future price levels. A refinery uses different pro cessing units to turn crude oil into finished products, so when a particular processing unit reaches capacity, output can be inc reased only by substituting a more expensive process. Firms will typically utilize sufficient crude oil to fill the appropriat e processing unit until the price increases substantially. At t his point, the firm would calculate whether the increased price wa rrants 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 co mparing 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 inc reased 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 comb ined export volumes of these products represent 75 percent of d omestic refinery output shipped overseas.
6.1.4 Market Demand Characteristics
The end-use sectors that contribute to demand for r efined petroleum products are classified in the following four economic sectors: (1) household and commercial, (2) industr ial, (3) transportation, and (4) electric utilities. Petrol eum products117

used as transportation fuel include motor gasoline, distillate (diesel) fuel, and jet fuel, and accounted for an e stimated 64 percent of all U.S. petroleum demand in 1990. Sinc e mobile source emissions will be regulated by Title II regu lations, this output from petroleum refineries will be most affec ted by the
CAA. The industrial sector constitutes the second highest percentage of demand for petroleum products, follow ed by household and electric utility demands. Petroleum is used most widely in the transportation sector. In the household and commercial sector, light heati ng oil and propane are used for heating and energy uses, and c ompete with natural gas and electricity. Petroleum fuels in th e industrial sector compete with natural gas, coal, and electric ity. 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 hea vy residual fuel oil and smaller amounts of bulk light distilla te fuel oil. 9 In terms of refined products, the motor gasoline an d jet fuel markets are associated with the transportation sect or. The
markets for distillate fuel oil are associated with the transportation sector (diesel engine fuel as a truc king fuel), household (space heating), industrial (fuel for commercial burner installations), and electric utilities (power gener ation). The
sectors that are sources of demand for residual fue l oil include the commercial and industrial sectors (heating), ut ilities (electricity generation), and the transportation se ctor (fuel for ships). Nonutility use of residual fuel has been d ecreasing due
to interfuel substitution in the commercial and ind ustrial 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 o f118

refined petroleum products affect the willingness o f consumers to choose petroleum over other fuels, and may ultimate ly cause a change in consumer behavior. In the transportation sector, the effect of high gasoline prices on fuel use could re duce discretionary driving in the short term and, in the long term, result in the production of more fuel-efficient veh icles. In the market for jet fuel, demand is primarily det ermined by a combination of price concerns and the overall hea lth of the airline industry. In the residential sector, deman d for home heating (distillate) is determined in part by price level, and also by temperature levels and climate. Temperatur e in different areas of the country may determine the degree to wh ich buildings and houses are insulated. Temperature and insulati on are exogenous factors which will determine heating need s regardless of the price level of fuel. High prices for home h eating oil provide incentive for individuals to conserve by ad justing thermostats, improving insulation, and by using ene rgy-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, whi le changing to more energy-efficient appliances or fuels are long- run responses.) In the industrial sector, fuel oil competes with na tural gas and coal for the boiler-feed market. High prices r elative to other fuels tend to encourage fuel-switching, espec ially 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 ca pital/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 condition s, 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 b oiler fuel,119

although a significant increase in oil-fired capaci ty is not expected until 2010. 11
Demand levels in each of the end-use sectors are al so affected by the economic environment. Periods of economic g rowth 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 operat e new production capacity, and to heat new homes. Conver sely, in periods of low economic growth, demand for petroleu m 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. T he consumption level has been sporadic and has shown an overall de cline in recent years. Demand for individual petroleum prod uct types has also fluctuated over this period. The percentage o f total demand is highest for motor gasoline followed by demand fo r distillate fuel oil. Over the 23-year period from 1970 to 199 2, the demand for residual fuel oil has decreased by 50 percent, showing the greatest percentage of change over time of any of t he petroleum products. It has also been the only fuel to show a decline in
use. This decrease in residual fuel demand reflect s a move in the industry from heavier fuels toward lighter, mor e 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. Subst antial gains in airplane fuel efficiency in the last two decades , which have resulted from improved aerodynamic design and a shi ft toward higher seating capacities, have been exceeded by ev en 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 lo wer demand in 1991 than in 1990, except LPGs. This was the first time since 1980 that demand for all major petroleum products f ell simultaneously in the same year. In this case, dec reased demand120

was brought on by warmer winter temperatures, an ec onomic slowdown, and higher prices resulting from the Pers ian 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 198 5 to 1992, motor gasoline use accounted for about 42 percent o f all petroleum products consumed. Changes in demand for distillate fuel oil were simi lar to motor gasoline in that consumption reached its lowe st and highest levels in 1970 and 1978, respectively. Between 198 5 and 1992, consumption was relatively stable and accounted for about 18 percent of total U.S. petroleum consumption. Resid ual fuel oil demand, in response to lower-priced natural gas andother factors, fell 64 percent, from a high in 1977 of 3. 1 million barrels per day to 1.1 million barrels per day in 1 992. Between the period from 1970 to 1990, expanding air travel spurred a 57 percent growth in jet fuel demand. De mand 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 rela tive to one another, and relative to other energy sources. Dra matic petroleum price increases and eventual steep drops were in response to wars, political upheaval in crude oil p roducing areas, and supply disruptions during the past two d ecades. During this period, the more stable and lower price s of alternative fuels led consumers to switch from petr oleum 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 w ere 10.6 percent, or roughly the same level as in 1981. The import to export ratio has decreased since 1981, due primaril y 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 1 992. This volatility is mainly attributable to the fluctuatio ns in the global market for crude oil and the inelastic deman d for petroleum products. Inelastic demand allows refine rs to pass crude oil price increases on to consumers. Since p etroleum 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 projecti ons are available from the literature. Projections are imp ortant to the economic impact analysis since future market condit ions contribute to the potential impacts of the NESHAP w hich are assessed for the fifth year after regulation.
6.1.5.1 Supply Outlook (Production and Capacity) . The refining industry was operating near maximum capaci ty in 1991, with an average annual utilization rate of approxim ately 92 percent. 14 This is an increase from levels of previous years

. In the market for motor gasoline, for example, prod uction 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 pe rcent 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 unchang ed, net imports of refined petroleum products are expected to increase by 15 percent. 16 DOE predicts net petroleum imports will rise to a t 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 dom estic oil production is expected to decline. Imports are exp ected to supply between 53 and 69 percent of U.S. petroleum consumption by 2010, compared with 42 percent in 1990. Refined pr oducts will
account for much of this increase because most of t he expansion122

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 a dditional 2 percent, or 272,000 bbl/d, of which 44 percent woul d 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 s atisfy the market without driving up prices. Companies that operate refineries with greater comp lexity factors (often the largest refineries) will presuma bly be in a more favorable position to make the necessary capit al investments
for the transition to cleaner fuels. Such refineri es will most likely be those large enough to benefit from the ec onomies of scale, and with basic downstream configurations to facilitate compliance with the new regulations. A financial a nalysis of major petroleum refineries in the 1980s conducted b y DOE concluded that vertically integrated firms benefitt ed 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, b oth 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 capi tal. Generally not as flexible as the larger, integratedcompanies, these firms operate at greater risk from the effect s of market instability. As a result, an industry which has se en a high level of consolidation in past years will be likely to see more concentration. 20 Overall, the effect of the CAA on individual refine ries is dependent upon production capacity, economies of sc ale, degree of self-sufficiency, capital cost, and ability of refi ners to "pass through" higher costs to consumers. Predictions of the effect on123

the aggregate industry are difficult at this time b ecause of the uncertainty of the ability of some refineries to de velop plans for compliance pending resolution of key issues aff ecting their operations. A recent Harvard University study, how ever, predicted that the promulgation of environmental re gulations was likely to result in the early phase out of older, l ess sophisticated facilities, combined with the upgrade and expansion of more efficient, complex refineries at a faster r ate. 21
6.1.5.2 Demand Outlook . The U.S. Department of Commerce (DOC) projects the demand for all petroleum product s to rise slowly and steadily over the next 5 years, with dom estic demand for refined products increasing by 2.1 percent in 1 992, assuming an economic recovery and a return to "normal" weath er. DOC's longer term demand prediction is for a steady growt h rate of 1 percent through 1996. 22, 23 Given that two-thirds of petroleum product demand is attributable to the transportatio n sector, projected demand growth for motor gasoline will hav e the greatest
effect on refiners. Industrial demand for distilla te 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 betwe en 1990 and
2010. 24 Residential and commercial sectors are expected t o show a decrease in demand for petroleum products. DOE has also projected future levels of demand. Mo tor gasoline will remain the leading end use of petrole um products throughout DOE's chosen time frame, dropping off du ring 1990 and 1995, and rising again to higher levels by 2010. D OE 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 inv estment that refineries will be required to undertake in the pro duction of reformulated gasolines is likely to be passed on to consumers in the form of a price increase. DOC has estimated th is price increase to be a 5 to 10 cent-per-gallon rise in th e price of124

motor gasoline. 25 In a recent study undertaken by the National Petroleum Council, the impacts of air quality regul ations on petroleum refineries were assessed. One of the con clusions of the study was that the costs of controlling air emi ssions are likely to be passed along to consumers as increases in the final price of refined products. (The study offered no q uantitative projections, however.) 26 DOE has projected the domestic prices of petroleum products for 2010. DOE projects the average price for all p etroleum prices to increase at a rate in the range of 0.4 pe rcent to 2.1 percent annually. These price increases are due to projected increases in both domestic demand and crude oil pri ces. DOE also accounted for higher refining and distribution expe nses 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 bet ween $1.27 and $1.69 per gallon, primarily because of the added re finery costs of desulfurization. The average retail price of re sidual fuel oil, the least expensive petroleum product, is proj ected to be within the range of $25.52 to $40.79 per barrel in 2010. If refineries are able to accommodate projected inc reases in demand, the price level will remain fairly stable. However, because the price level in this industry is conting ent upon so many factors independent of the industry, any price predictions necessarily have their limitations. In the long ru n, therefore, price predictions will need to be modified with the occurrence of any world events which will affect the supply of cr ude oil to the refineries and therefore to the supply of refined p etroleum products. Refineries will also be faced with incre asing levels of emission restrictions, escalating their pollutio n abatement costs, and consequently, the price of their product s.

6.2 MARKET MODEL A partial equilibrium model is the analytical tool used to estimate the impact of the final NESHAP on the petr oleum refining125

industry. Five refined petroleum products were mod eled. Collectively, these products represent over 90 perc ent of the refined petroleum products sold in the nation annua lly. 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 indust ry operate in a perfectly competitive market. Although the petro leum refinery industry does not meet the strictest definition of a perfectly competitive industry, perfect competition seems a m ore applicable characterization of the market than pure monopoly. The assumption of perfect competition results in a wors t case scenario of model results from the perspective of t he impact of the regulation on the petroleum refinery industry.
6.2.1 Market Supply and Demand The partial equilibrium model approach estimates th e 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 ref ining 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 a chieve an equilibrium. The following equations identify the market demand, supply, and equilibrium conditions for the petroleu m 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 supp liers annually Q Sf = quantity of the products produced by foreign suppl iers 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 elasticiti es are the same. This assumption was necessary because data we re not readily available to estimate the price elasticity of suppl y for foreign suppliers.
6.2.2 Market Supply Shift The domestic supply equation shown above may be sol ved for the price of the petroleum product, P , to derive an inverse supply function that will serve as the baseline supply fun ction for the industry. The inverse domestic supply equation for the industry
is as follows:

A rational profit maximizing business firm will see k to increase the price of the product it sells by an am ount that recovers the capital and operation costs of the reg ulatory control requirements over the useful life of the em ission control equipment. This relationship is identified in the f ollowing equation:127

where:
C = increase in the supply price Q = output
V = measure of annual operating and maintenance contro l
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 expe nditures) related to the equipment. Solving the equation for the supply price increase ( C) yields the following equation:

Estimates of the annual operation and maintenance c ontrol
costs and of the investment cost of emission contro ls ( V and k, respectively) were obtained from engineering studie s conducted by the engineering contractor for EPA and are based on first quarter 1992 price levels. The variables depreciation and capital recovery factor, Dand S , respectively, are computed as follows:128

where r

is the discount rate faced by producers and is ass umed to be a rate of 10 percent, and T is the life of the emission control equipment, 10 years for most of the emissio n control equipment proposed. Emission control costs will increase the supply pri ce for each refinery by an amount equivalent to the per unit co st of the annual recovery of investment costs and annual oper ating costs of emission control equipment, or C i ( 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 cont rol 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 t hat likely causes overestimates of impacts and may not be the case in reality. Based upon this assumption, the post-contr ol supply function becomes the following:

where:
C ( C i , q

i ) = a function that shifts the supply function to
reflect control costs
C i = vertical shift that occurs in the supply curve for

the i th refinery to reflect the increased cost of production in the post-control market

q i = quantity produced by the i th refinery

This industry pre-control and post-control supply a nd demand is illustrated in Figure 6-1.129130 Figure 6-1.131

6.2.3 Impact of Supply Shift on Market Price and Quantity The impact of the proposed control standards on mar ket equilibrium price and output are derived by solving for the postcontrol market equilibrium and comparing the new eq uilibrium price and quantity (P 1 and Q 1 , respectively) to the pre-control equilibrium (P 0 and Q 0 ). The change in value of domestic product is simply the difference in the industry revenue (P 1 * Q 1 ) at the post-control market equilibrium and the revenue (P 0 * Q 0 ) at the pre-control equilibrium. Those firms that lie on the industry supply curve a t price and quantity levels above the post-control equilibrium (P 1 ,Q 1 ) are subject to closure. This assumption is consistent with the assumption of perfect competition. Firms in a comp etitive market are price takers and are unable to sell their produ cts at prices above the market equilibrium. Predicted primary market impacts become the basis f or assessing economic surplus changes; secondary labor , energy, and foreign trade market impacts; and the capital avail ability consequences expected to result from the emission c ontrols.
6.2.4 Trade Impacts Trade impacts are reported as the change in both th e volume and dollar value of net exports (exports minus impo rts). It is assumed that exports comprise an equivalent percent age of domestic production in the pre- and post-control ma rkets. The supply elasticities in the domestic and foreign mar kets have also been assumed to be identical. As the volume of imp orts rises and the volume of exports falls, the volume of net expo rts will decline. However, the dollar value of net exports m ay rise or fall when demand is inelastic, as is the case for t he petroleum products of interest. The dollar value of imports w ill increase since both the price and quantity of imports increa se. Alternatively, the quantity of exports will decline , while the price of the product will increase. Price increase s for products
with inelastic demand result in revenue increases f or the producer. Consequently, the dollar value of exports is anticipated to increase. Since the dollar value of imports and132

exports rise, the resulting change in the value of net exports will depend on the magnitude of the changes for imp orts relative to exports. The following functions are used to compute the trade impacts:

where:

a Q Sf = change in the volume of imports

a VIM = change in the dollar value of imports

a Qx Sf = change in the volume of exports

a VX = 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-c ontrol equilibrium values, respectively. All other terms have been previously defined. The change in the quantity of net exports, a NX , is simply the difference between the change in the volume of expo rts and the change in volume of imports, or a Qx Sd - a Q Sf . The reported change in the dollar value of net exports, a VNX , is the difference between the equations for change in value of export s and the change in value of imports, or a VX - a VIM

.133

6.2.5 Changes in Economic Welfare

Regulatory control requirements will result in chan ges in the market equilibrium price and quantity of petroleum products produced and sold. These changes in the market equ ilibrium price and quantity will affect the welfare of consumers o f petroleum products, producers of petroleum products, and soci ety as a
whole. Consumer surplus is a measure of the well-being of consumers of a particular product and it represents the net b enefit (total benefits derived from consuming a good less the exp enditure necessary to purchase the good) associated with con suming a particular product. Consumers of refined petroleumproducts will bear a loss in consumer surplus as a result of prop osed emission controls. This loss in consumer surplus ( a CS ) represents the amount consumers would have been willing to pay ove r 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 s urplus incurred by foreign consumers and domestic consumer s. Although the change in domestic consumer surplus is the obje ct of interest, no method is available to distinguish the marginal consumer as domestic or foreign. Therefore, an assu mption is made that the consumer surplus change is allocable to th e foreign and
the domestic consumer in the same ratio as the divi sion of sales between foreign and domestic consumers in the pre-c ontrol market. The variable, a CS d , represents the change in domestic consumer surplus that results from the change in market equi librium price and quantity resulting from the imposition of regul atory controls. While a CSis the change in consumer surplus from the perspective of the world economy, a CS d is the change in consumer surplus relevant to the domestic economy. Producer surplus is a measure of well-being of prod ucers in an industry. The change in producer surplus resulting from emission controls is composed of two elements. The first ele ment relates134

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 chan ge in producer surplus is the sum of these elements. After-tax me asures of surplus changes are required to estimate the impact s of controls on producers' welfare. The after-tax surplus chang e is computed by multiplying the pre-tax surplus change by a fact or of 1 minus the tax rate, (1-t) where t is the marginal tax rat e. Every dollar of after-tax surplus loss represents a compl imentary loss in tax revenues of t/(1-t) dollars. Output eliminated as a result of control costs caus e producers to suffer a welfare loss in producer surplus. Refin eries operating in the post-control market realize a welf are gain on each unit of production for the incremental increas e in the price and realize a decrease in welfare per unit for the capital and operating cost of emission controls. The total cha nge in producer surplus ( a PS ) is the sum of each individual change in producer surplus. Since domestic surplus changes are the object of in terest, the welfare gain experienced by foreign producers due t o higher prices is not considered. This procedure treats hi gher prices paid for imports as a dead-weight loss in consumer surplus. Higher prices paid to foreign producers represent s imply a transfer of surplus from the United States to other countries from a world economy perspective, but a welfare los s 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 welfa re resulting from the emission controls. Adjustments must be ma de to consider tax effects and to adjust for the difference betwee n the social discount rate and the private discount rate. These adjustments result in a number referred to as the residual surp lus to society since these surplus changes do not relate specifica lly to consumers or producers of refined petroleum product s, 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 p er 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 c hanges reflect the after-tax welfare impacts of emission control c osts on affected refineries. As noted previously, a one do llar loss in pre-tax surplus imposes an after-tax burden on the affected refinery of (1-t) dollars. Alternatively, a one do llar loss in after-tax producer surplus causes a complimentary l oss 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 affec ted firms. The shift in the supply curve for the refining indu stry is used to estimate primary and secondary market impacts. Aprivate cost of capital of 10 percent is assumed for the analysi s. 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 opportu nity cost of resources displaced in the economy by investments r equired for emission controls. The adjustment for the two tax effects and the social cost of capital are referred to as the r esidual change in economic surplus to society ( a RS ). The total economic costs of the proposed regulation s are the sum of the changes in consumer surplus, producer su rplus, 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 a nd sold domestically. This reduction in output or producti on will directly cause the level of inputs used in producti on to decrease. Quantification of the input reduction af fecting the labor and energy markets are of particular interest

. Two adjustments in the labor market may result fromthe emission controls. The first involves monitoring a nd maintenance of the emission control equipment that may cause employment increases. Information necessary to quantify poten tial employment increases for monitoring and maintenance of emission controls is not readily available. Consequently, p ossible employment increases are not considered in the anal ysis. 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 pet roleum output are quantified by multiplying the decrease in indus try output by an industry ratio of employees per unit of producti on. This quantification of possible job losses in the refini ng industry is likely to be overstated due to the omission of pote ntial job increases for monitoring and maintenance of emissio n control equipment. Reduction in the utilization of energy inputs assoc iated with the final standard result from decreases in output in the industry. The expected change in expenditures on e nergy by firms in the industry is calculated by multiplying the ra tio of baseline energy expenditure per dollar refined petr oleum output by the estimated decrease in annual output. The qu antification of energy input changes reflects energy expenditure decreases per year occurring as a result of the reduced productio n of refined petroleum products.
6.2.7 Baseline Inputs137

The partial equilibrium model requires, as data inp uts, baseline values for variables and parameters that c haracterize the petroleum refining market. These data inputs i nclude 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 1 992 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 partia l equilibrium are the price elasticity of demand and the price elasticity of supply. The price elasticities of su pply and demand are briefly discussed in the following secti on. 6.2.8 Price Elasticities of Demand and Supply Price elasticities of demand and supply are measure s of the responsiveness of buyers and sellers of a product t o changes in the market price. Elasticity measures may be categ orized as elastic, unitary elastic, and inelastic to price ch anges in the market. Products with elastic price elasticity val ues 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 ve ry responsive to changes in price (percent quantity decrease is l ess than percent price increase). Unitary elasticity measur es have equal percent changes in price and quantity. The ultimate increase in market equilibrium price and decrease in market equ ilibrium quantity resulting from emission controls are depen dent upon the magnitude of the per unit control costs and elastic ity measures
in the market. The relative burden of emission con trol costs between consumers and producers will be determined by the comparative magnitudes of the supply and demand ela sticities prevailing in a market, all other factors being equ al. The more inelastic demand is for a product, the larger the s hare of emission control costs that will be paid by consume rs of the product in the form of higher product prices. Alte rnatively, the138

more inelastic the supply curve, the larger the sha re 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 quan tity demanded resulting from each 1 percent change in the price o f the product. Petroleum products represent a very important energ y source for the United States. Many studies have been conductedwhich estimate the price elasticity of demand for some or all of the petroleum products of interest and numerous publish ed sources of the price elasticity of demand for petroleum produc ts exist. These elasticity measures are used in the analysis and are listed
in Table 6-1. Sources of these data are discussed i n 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 -0.82 27 -0.15 28 -0.61 to -0.74 27 -0.50 to -0.99 27 -0.60 to -1.0 27 -0.69 -0.15 -0.675 -0.745 -0.80

The elasticity estimates for each of the products r eflect that each of these products have inelastic demand. The only exception is the upper end of the range of elasticities for L PGs that is unitary elastic. As previously stated, regulatory c ontrol costs are more likely to paid by consumers of products wi th inelastic demand when compared to elastic demand, all other t hings held constant. Price increases for products with inelas tic demand lead to revenue increases for producers of the prod uct. Thus, one can predict that price increases resulting from implementation of regulatory control costs will lea d to higher revenues for the petroleum refining industry, all o ther factors held constant. The market changes resulting from t he 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 measu re of the responsiveness of producers to changes in the price of a product. The price elasticity of supply indicates the percen tage change in the quantity supplied of a product resulting from e ach 1 percent change in the price of the product. Published sources of the price elasticity of suppl y using current data were not readily available. It was de termined that the price elasticity of supply should be estimated econometrically using time series data. Several est imation approaches were considered and are discussed in det ail in the Economic Impact Analysis of the Petroleum Refinery NESHAP (1995). The approach actually used to estimate the price el asticity of supply was a time series model of the production fu nction for the petroleum refining industry. Relevant factors of p roduction in the model included labor, capital, and materials (c rude 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 supp ly for the five petroleum products reflects that the petroleumrefinery industry in the U.S. will increase production of ga soline, jet fuel, residual fuel oil, distillate fuel oil and LP GS jointly by 1.24 percent for every 1.0 percent increase in the price of these products. Elasticity measures for the individual pr oducts 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 propo sed emission controls on the financial performance of a ffected140

petroleum refineries and on the ability of the refi neries to finance the additional capital investment in emissi on control equipment. Financial data were not available for t he majority of the refineries in the industry. Available data wer e obtained only for the largest publicly held petroleum refini ng companies. For this reason, the capital availability analysis has been conducted on an industrywide basis. One measure of financial performance frequently use d to assess profitability of a firm is net income before intere st expense as a percentage of firm assets or rate of return on in vestment. The pre-control rate of return on investment ( roi ) is calculated as
follows:

where n i is income before interest payments and a i is total assets. A five-year average is used to avoid annua l fluctuations that may occur in income data. The proposed regula tions potentially could have an effect on income before t axes ( n) i for firms in the industry and on the level of assets fo r firms in the industry ( a i .) Since firm specific data were unavailable for a ll of the affected firms, sample financial data collec ted 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 tot al industry assets. These percentages are considered to estima te 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 refin eries in the industry; therefore, individual firm financial perf ormance may vary greatly from the sample estimate. The post-co ntrol return on investment ( proi ) is calculated as follows:141

where: proi = the post-control return on investment

a n = the change in income before interest resulting fro m

implementation of emission controls for firms in th e sample

a k = capital expenditures associated with emission

controls.

The equation proi will tend to overstate the impact of the
control measure on the rate of return on investment for the industry over the life of the emission controls. T his is true because net capital investment in emission controls will decline as capital is depreciated. The ability of affected firms to finance the capita l equipment
associated with the emission control is also releva nt to the analysis. Numerous financial ratios can be examine d to analyze the ability of a firm to finance capital expenditur es. One such measure is historical profitability measures such a s rate of return on investment. The analysis approach for th is measure has been previously described. The bond rating of a fi rm is another
indication of the credit worthiness of a firm or th e ability of a firm to finance capital expenditures with debt capi tal. Such data are unavailable for many of the firms subject to the regulation, and consequently bond ratings are not a nalyzed. Ability to pay interest payments is another criteri on sometimes used to assess the capability of a firm to finance capital expenditures. Coverage ratios provide such informa tion. The interest coverage ratio, or the number of times inc ome (before taxes and interest) will pay interest expense, is a ratio that provides some information about the ability of a fi rm to cover or142

pay annual interest obligations. The pre-control m easure of coverage ratio is as follows:

where:
tc = number of times earnings will pay annual interest

charges
ebit = earnings before interest payments and taxes
interest i = annual interest expense

Post-control coverage ratios may be estimated as fo llows:

where:

a ebit = estimated change in earnings before interest and

taxes of the firm

a interest i = anticipated change in interest expense

All other variables have been previously described. The

a interest is calculated by multiplying the capital expenditu res for the proposed controls ( a k ) 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 cov erage 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 fi rm 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 ear nings information, it is appropriate to use the latest av ailable
information for this calculation. If one assumes t hat the capital costs of control equipment are financed sol ely by debt, the debt-equity ratio becomes:

where pd/eis the post-control debt-equity ratio assuming tha t the control equipment costs are financed solely wit h debt. Obviously, firms may choose to issue capital stock to finance the capital expenditure or to finance the investment th rough internally generated funds. The assumption that th e capital costs are financed solely by debt may be viewed as a conservative
scenario. The methods used to analyze the capital availabilit y do have some limitations. The approach matches 1990 debt a nd equity values with estimated capital expenditures for cont rol equipment. Average 1986 through 1990 income and asset measures are matched with changes in income and capital expenditures ass ociated with the control measures. The control cost changes andincome changes reflect 1992 price levels. The financial d ata used in the analysis represents the most recent data availa ble. It is inappropriate to simply index the income, asset, de bt, and equity values to 1992 price levels for the following reaso ns. Assets, debt, and equity represent embedded values that are not subject to price level changes except for new additions suc h as capital144

expenditures. Income is volatile and varies from p eriod to period. For this reason, average income measures a re used in the study. The analysis reflects a conservative approa ch to analyzing the changes likely in financial ratios fo r the petroleum industry. Some decreases the cost of pro duction expected to result from implementation of emission controls have not been considered. These include labor input andenergy input cost decreases. Annualized compliance costs are ov erstated from a financial income perspective since these costs in clude 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 op erations 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 homog eneous product
is sold in a national market. In the actual market , there may be some differentiation of the refined petroleum produ cts sold throughout the country and regional barriers to tra de may exist in the petroleum refinery market. Product differen tiation and regional barriers to trade would allow firms in the industry to have greater market power. Market power enables fi rms to have more control over the market price of the product s old and would lessen the impact of emission controls costs on fir ms in the industry. Next, an assumption is made in the model that refin eries with the highest per unit control cost are marginal in t he postcontrol market. Firms with the highest per unit co ntrol costs are assumed to have the highest underlying cost of production. This assumption was necessary due to lack of availa ble information concerning the cost of production on an individual refinery basis. Additionally, a review of the data indicates refine ries that are marginal in the post-control market have per un it control145

costs that significantly exceed the average. This may be the result of the engineering method used to assign cos ts to individual refineries. Moreover, the cost allocati on methodology assigns all of the control costs to the five petrol eum products of interest. These products represent less than 10 0 percent (to be exact, 93 percent) of the refined petroleum prod ucts produced domestically. It is not possible to assign complia nce costs to every petroleum product due to the lack of data on certain products produced in low quantity, so a decision wa s made to assign all the costs to the five products produced in the greatest quantity. Finally, some plants may find that the price increa se resulting from the regulations make it profitable t o expand production. This would occur if a firm found its p ost-control incremental cost to be less that the post-control m arket price. Expansion by these firms would result in a smaller decrease in output and increase in price than otherwise would o ccur. The foregoing list of qualifications tend to overstate the impacts of the proposed emission controls on the market equili brium price and quantity, revenues, and plant closures. Estimates of model results are dependent on the pri ce 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 lowe r 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 elastici ty of supply also must be qualified. The elasticity meas ure does not estimate the supply elasticities for the individual products or directly consider the interrelationships between pr oducts. The assumption implicit in use of this supply elasticit y estimate is that the elasticities of the individual petroleum p roducts will not differ significantly from the elasticity of the products combined. This does not seem a totally unreasonabl e assumption since the same factor inputs are used to produce ea ch of the petroleum products. The methodology also does not e xplicitly146

consider the cross-price elasticities for the petro leum products. Since these products are joint products, changes in the price of one product will have an effect on the quantity sup plied of the other products. The uncertainty of the supply estimate is acknowled ged. It is possible to conduct a sensitivity analysis of the p rice elasticity supply. Such an analysis would quantify the impact of this assumption on the reported market results. Gi ven the magnitude of market impact results, reasonable vari ations in the price elasticity of supply are unlikely to alter th e model results significantly. The estimates of the secondary impacts associated w ith the emission controls are based on changes predicted by the partial equilibrium model. The limitations previously desc ribed are applicable to primary and secondary economic impact s. As previously noted, the estimated employment losses d o not consider potential employment gains for operating the emissi on control equipment. It is important to note that the potenti al job losses predicted by the model are only those directly link ed to predicted production losses in the petroleum refini ng 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 limitati ons. Some of these limitations have been previously noted. F uture baseline performance may not resemble past levels. Future f inancial performance of the petroleum refining industry will be affected by market considerations other than emission contr ol measures, and these factors are not readily estimated. Addit ionally, the tools used in the analysis are limited in scope anddo not fully describe the financial position of individual firms within the industry but are more reflective of industry averag es. Finally, the approach used to estimate the impact of the con trol 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, seconda ry impacts, and capital availability consequences associated wi th the chosen option or preferred alternative are presented. As previously discussed, Alternative 1 requires MACT floor contro ls on all emission points other than equipment leaks where a choice of controls allowed refineries is less costly. Primar y 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 do mestic producers, and plant closures. Secondary impacts re late to labor market, energy market and international trade effec ts likely to occur as a result of the emission control requireme nts. 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 th e market outcome of the proposed regulation. The purchase o f emission control equipment will result in an upward vertical shift in the domestic supply curve for refined petroleum product s. The height of the shift is determined by the after-tax cash fl ow required to offset the per unit increase in production costs. Since the control costs vary for each of the domestic refiner ies, the postcontrol supply curve is segmented, or a step functi on. Underlying production costs for each refinery are u nknown; therefore, a worst case scenario has been assumed. The plants with the highest control costs per unit of producti on are assumed to also have the highest pre-control per unit cost of production. Thus, firms with the highest per unit cost of emiss ion control are assumed to be marginal in the post-control mark et. Foreign supply is assumed to have the same price el asticity of supply as domestic supply. The United States had a negative trade balance for each of the refined products in 1 992 with the exception of distillate fuel oil that had a slightl y positive148

trade balance of $1.1 million. Therefore net expor ts are negative for all products except distillate fuel oi l in the baseline model. Foreign and domestic post-control supply are added together to form the total post-control marke t supply. The intersection of this post-control supply with marke t demand will determine the new market equilibrium price and quan tity. Postcontrol domestic output is derived by deducting pos t-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 f uel, respectively. The percentage price increase for ea ch product is less than 1 percent and they range from 0.26 percen t to 0.53 percent. Production is expected to decrease by 12.5 million barrels per year for all products, an overall decrease in domes tic production of 0.24 percent. The estimated annual reductions i n production of the individual products range from 0.65 million barrels to 5.67 million barrels for jet fuel and motor gas, re spectively. The production percentage decreases range from 0.13 percent to 0.58 percent for jet fuel and residual fuel oil, re spectively. Value of domestic shipments or revenues for domesti c producers are expected to increase for the five products appr oximately $107 million annually. The predicted changes in revenue s for individual products range from an increase of $56 m illion in motor gasoline revenues to a decrease in residual f uel revenues of approximately $12 million annually. The percent changes range from an increase of 0.41 percent in jet fuel to a d ecrease of 0.26 percent in residual fuel oil revenues. Econom ic theory predicts that revenue increases are expected to occ ur when prices are increased for inelastic goods, all other factor s held constant. This phenomenon results from the percent age increase in price exceeding the percentage decrease in quant ity for goods with inelastic demand. All of the refined petroleumproducts follow the expected trend except residual fuel oil.149 TABLE 6-2. SUMMARY OF PRIMARY IMPACTS

Estimated Impacts

Refined Product Price Increases 1 Production

Decreases 2 Value of

Domestic Shipments 3 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.

1 Prices are shown in price per barrel ($1992). 2 Annual production quantities are shown in millions of barrels. 3 Values 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 be ing 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 a re at risk of closure as a result of the decrease in productio n predicted by the model, with the actual number likely being clos er to 0 than 7. Those refineries with the highest per unit cont rol costs are assumed to be marginal in the post-control market. Refineries that have post-control supply prices that exceed th e 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 und erlying cost of production. This is an assumption that likely o verstates the the likely number of plant closures and other adver se effects of
the emission controls. The estimated primary impacts reported depend on th e set of parameters used in the partial equilibrium model. One of the parameters, the price elasticity of demand, consist ed of a range for four of the five refined products. The midpoin t of the range of elasticities was used to estimate the reported p rimary and secondary impacts. A sensitivity analysis of this assumption was conducted. The low and high end of the range of el asticities are inputs in the sensitivity analysis. In general, th e sensitivity analysis shows that the estimated primary impacts a re relatively insensitive to reasonable changes of price elastici ty 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 highe r price increases and lower output decreases. Higher elast icity measures shift more of the burden to producers in the form o f slightly lower price increases and higher output decreases.
6.5.2 Capital Availability Analysis151

The capital availability analysis involves examinin g pre- and post-control values of selected financial ratios. These ratios include rate of return on investment, times interes t earned coverage ratio, and the debt-equity ratio. Data we re not available to estimate the ratios for many refinerie s in the industry. Consequently, these ratios have been ana lyzed on an industrywide basis. Since the industrywide ratios represent an average for the industry, individual firms within t he industry may have financial ratios that differ significantly from the average. Net income was averaged for a five year p eriod (1986 through 1990) to avoid annual fluctuations in incom e that may occur due to changes in the business cycle. Debt a nd equity capital are not subject to annual fluctuations; the refore, 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 i mpact on financial ratios for the industry.

TABLE 6-3. ANALYSIS OF FINANCIAL RATIOS

Financial Ratios Pre-Control Ratios Post-Control Rati os
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 t he income changes and the capital expenditures necessary for the emission control measures do not significantly alter the fin ancial position of the industry. The impact of the standa rds on individual refineries, however, may vary greatly fr om 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 NES HAP are based on the results of the partial equilibrium ana lyses 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 m ade in the economic analysis with regard to the behavior of pe r-unit cost. The loss in number of workers depends primarily on the estimated reduction in production. Gains in employment antici pated to result from operation and maintenance of control eq uipment and from additional monitoring, recordkeeping, and repo rting requirements have not been included in the analysis are not considered in the labor impact estimate. Estimate s of employment losses do not consider potential employm ent gains in industries that produce substitute products. Simil arly, losses in employment in industries that use petroleum prod ucts as an input or in industries that provide complement good s 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 c ompared to the total employment in the industry (a 0.16 percen t 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 intensit y 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 en ergy inputs relates the energy expenditures to the level of pro duction. An estimated decrease in energy input use of nearly $1 1 million annually is expected for the industry. The individ ual product energy use changes are reported in Table 6-4. As p roduction decreases, the amount of energy input utilized by t he refining153

industry also declines. The changes in energy use do not reflect the increased energy use associated with operating and maintaining emission control equipment. Insufficie nt data were available to consider such changes in energy costs.154

TABLE 6-4. SUMMARY OF SECONDARY REGULATORY IMPACTS

Estimated Impacts Refined Product Labor Input 1 Energy Input 2 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. 2 Reduction 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 fore ign refineries, all other factors being equal. This ch ange in the relative price of imports will cause domestic impor ts 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 N ESHAP will likely cause the trade deficit to increase. Net ex ports are likely to decline by 2.3 million barrels per year, a 1.2 percent decline. The range of net export decreases vary fr om 0.21
million barrels to 0.91 million barrels for LPGs an d residual fuel oil, respectively. The related percent decrea ses range from 0.54 percent to 40.9 percent for LPGs and distillat e fuel oil, respectively. The large percentage decrease in exp orts of distillate is the result of the product having a ve ry small positive trade balance in the pre-control market. The dollar value of the total decline in net exports is expect ed to amount to $68.2 million annually. The predicted changes i n 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 refi neries are estimated to close nationwide, with the point estim ate likely
closer to 0 than 7. Due to the manner used to est imate 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 t o a particular geographical region. Employment impacts are direct ly 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 pro posed emission controls are relatively small. Predicted price156

increases and reductions in domestic output are les s than 1 percent for each of the refined products. The valu e of domestic shipments or revenues to domestic producers are ant icipated to increase for the 5 product categories by a total of $107 million annually ($1992). Emission controls costs are smal l relative to the financial resources of affected producers, and on average, refineries should not find it difficult to raise th e capital necessary to finance the purchase and installation of emission controls. The economic analysis estimates that bet ween 0 and 7 refineries may close as a result of the emission co ntrols, with the point estimate of the range likely being closer to 0 than 7. As to the estimated secondary economic impacts, bet ween 0 and 114 job losses may occur nationwide, given the effe cts on labor that are considered in the analysis. Energy input r eductions are estimated to be approximately $11 million annually. A decrease in net exports of 2.3 million barrels, a decrease o f 1.24 percent, annually in refined products is anticipate d to occur. No regional impacts are expected.

TABLE 6-5. FOREIGN TRADE (NET EXPORTS) IMPACTS

Estimated Impacts

Refined Product Amount 1 Percentage Dollar Value of Net Export Change 2

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.

1 Millions of barrels. 2 Millions of dollars ($1992).157

6.7 POTENTIAL SMALL BUSINESS IMPACTS

6.7.1 Introduction The Regulatory Flexibility Act (RFA) of 1980 and EP A Guidelines for Regulatory Flexibility Analyses (199 2) require that special consideration be given to the effects of all proposed regulations on small business entities. T he Act requires that a determination be made as to whether the subject regulation will have a significant impact on a subs tantial number of small entities; the Guidelines require that a fi nal Regulatory Flexibility Analysis be done if anyimpact on small entities occurs. The analysis used four criteria provided in the original Federal Guidelines for Regulatory Flexibility Analy ses (1982). A substantial number is considered to be greater than 20 percent of the small entities identified. The following crite ria are provided for assessing whether impacts are signific ant. The impact on small business entities is considered sig nificant whenever any of the following criteria are met:

1. annual compliance costs (annualized capital, oper ating, reporting, etc.) increase as a percentage of cost o f production for small entities for the relevant proc ess 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 cost s as a percent of sales for large entities;

3. capital costs of compliance represent a significa nt portion of capital available to small entities, considering internal cash flow plus external financ ing 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 smal l business impacts for two of the criteria (1 and 3) listed in the previous section. The information necessary to make such co mparisons 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. Clo sure of small businesses and a comparison of the compliance costs as a percentage of sales for small and large business en tities will be
examined. The closure method of analysis will focus on the nu mber of petroleum refineries expected to close as a result of the
emission controls and the relative size of the firm s at risk. Alternatively, a measure of annual compliance costs as a percentage of sales will also be considered. The r atio of costs to sales will be compared for small refineries to t he 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 unaf filiated with another large business entity to be classified as s mall. Information necessary to distinguish refinery size by number of employees was not readily available. However, dail y production
data were available from the Oil and Gas Journal, U.S. Refinery Survey (1-1-92). Based upon the production size criterio n, 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 lea d to the
conclusion that between 0 and 7 refineries are at r isk 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 perc ent of those159

designated to be small businesses. The estimated n umber of closures is therefore less than 20 percent of the s mall refineries. However, it is important to note that the firms designated in the model as being at the greatest ri sk for closure
were small refineries. Compliance costs as a percentage of sales were comp uted both
for the small refineries and for those refineries t hat 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. T he differential between these two rates exceeds ten pe rcent, and consequently, a conclusion is drawn that a signific ant number of small businesses are adversely affected by the prom ulgated regulations.

6.8 SOCIAL COSTS OF REGULATION The social costs of regulation are those costs born e by society for pollution abatement. From an economic perspective, the social costs of regulation represent the opport unity 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 occu rs. Consumers, producers, and all of society bear the c osts of pollution controls. Economic losses to consumers r esult from the higher prices paid for goods consumed and the lesse r quantity goods consumed. Producers benefit from a higher pr ice paid by consumers for each unit of product sold but incur c ompliance 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 con sumer and producer surplus to reflect the regulation's cost t o society. The change in residual surplus represent tax revenu es that may be gained or lost from the emission controls and the d ifferential in the private cost of capital and the social cost of capital. The economic costs of regulation ( EC ) as previously defined consists160

of the sum of the change in domestic consumer surpl us ( a CS d ), the change in producer surplus ( a PS ), and the change in the residual surplus to society ( a RS ) resulting from the emission
controls.
6.8.1 Social Cost Estimates The components of the social costs of regulation ha ve been previously discussed. More details on the exact me thodology 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 e stimated 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 PE TROLEUM REFINING REGULATION (Millions of 1992 dollars)

Social Cost Category Net Costs 1
Surplus Costs for Preferred Option: Change in Consumer Surplus Change in Producer Surplus Change in Residual Surplus to Society 2 $342.86 $(174.32) $(73.25)

Total Social Cost of Alternative 1 3 $95.29

NOTES: 1 Brackets indicate negative surplus losses, or surpl us gains.

2 Residual surplus loss to society includes adjustme nts necessary to equate the relevant discount rate to the social cost of capital and to consider appropriate tax effect a djustments. 3 Alternative 1 includes floor controls for all emiss ion points except equipment leaks. Option 1 is pre ferred 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, 19 50- 1989. Discussion Paper #014R. Washington, DC. Oc tober 1990.
4. U.S. Department of Energy. The U.S. Petroleum Re fining Industry in the 1980's. DOE/EIA-0536. Energy Info rmation Administration. October 1990.
5. U.S. Department of Energy. Annual Outlook for Oi l 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. Decem ber 1991.
7. Cambridge Energy Research Associates. The U.S. R efining Industry: Facing the Challenges of the 1990s. Pre pared 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 In dustry: 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, 1 982.
11. U.S. Department of Energy. Annual Report to Con gress. DOE/EIA-0173(91). Energy Information Administratio n. Washington, DC. March 1992.
12. Dermot Gately. New York University. Taking Off : The U.S. Demand for Air Travel and Jet Fuel. The Energ y 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 Outloo k, 1992. DOE/EIA-0383(92). Energy Information Administratio n. Washington, DC. January 1992.

18. Reference 15.

19. Reference 4.

20. Reference 2.
21. Henry Lee and Ranjit Lamech. The Impact of Clea n Air Act Amendments on U.S. Energy Security. Harvard Univer sity. Energy 93-01. Cambridge, MA. 1993.

22. Reference 2.

23. Reference 15.

24. Reference 17.

25. Reference 15.
26. National Petroleum Council. Estimated Expenditu res by Petroleum Refineries to Meet New Regulatory Initiat ives Air Quality. For presentation at the 86th Annual A ir & Waste Management Association Meeting. Denver, CO. 93-WA78A.03. June 13-18, 1993.
27. U.S. Department of Energy, Short-term Energy Out look, Vol. II. DOE/EIA-0202/42. Energy Information Administration.Washington, DC. August 1980.
28. Robert S. Pindyck and Daniel L. Rubinfeld. Micro economics. MacMillan Publishing Company. 1989.

29. American Petroleum Institute. Financial Trends for Leading U.S. Oil Companies 1968-1990. Discussion Paper #01 7R. Washington, DC. October, 1991.163 

### 7.0 QUALITATIVE ASSESSMENT OF BENEFITS

OF EMISSION REDUCTIONS

One rationale for environmental regulation is to pr ovide benefits to society by improving environmental qual ity. In this chapter, and the two chapters which follow, informa tion is provided on the types and levels of social benefits anticipated from the petroleum refinery NESHAP. This chapter e xamines the potential health and welfare benefits associated wi th air emission reductions projected as a result of implem entation of the petroleum refinery NESHAP. The final regulatio n is expected to reduce emissions of HAPs emitted from storage ta nks, process vents, equipment leaks, and wastewater emission poi nts at refining sites. Of the HAPs emitted by petroleum r efineries, some are classified as VOCs, which are ozone precur sors. In general, the reduction of HAP emissions resultin g from promulgation and implementation of the petroleum re finery NESHAP will reduce human and environmental exposure to the se pollutants and thus, reduce potential adverse health and welfa re effects. This chapter provides a general discussion of the v arious components of total benefits that may be gained fro m a reduction in HAPs through the subject NESHAP. HAP benefits a re presented separately from the benefits associated specificall y with VOC
emission reductions.

7.1 IDENTIFICATION OF POTENTIAL BENEFIT CATEGORIES164

The benefit categories associated with the emission reductions predicted for this regulation can be broadly catego rized as those benefits which are attributable to reduced exposure to HAPs, and those attributable to reduced exposure to VOCs. Th e predicted emissions of a few HAPs associated with this regula tion 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 catego ries include: reduced exposure to noncarcinogenic HAPs, and reduc ed exposure to VOCs. In addition to health impacts occurring as a result of reductions in HAP and VOC emissions, there are welf are impacts which can also be identified. In general, welfare impacts include effects on crops and other plant life, mate rials damage, soiling, and visibility. Each category is discusse d 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 w ith HAP
emissions and also with concentrations of ozone for med by VOC HAPs is provided in Table 7-1. As noted in the tab le, 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 i nhalation or indirectly through ingestion of food or water co ntaminated by HAPs or through dermal exposure. HAPs may also ent er terrestrial and aquatic ecosystems through atmospheric depositi on. HAPs can be deposited on vegetation and soil through wet or dry deposition. HAPs may also enter the aquatic enviro nment from the atmosphere via gas exchange between surface water a nd the ambient air, wet or dry deposition of particulate HAPs and particles to165

which HAPs adsorb, and wet or dry deposition to wat ersheds 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 sour ce category currently emits approximately 81,000 Mg of HAPs ann ually. The petroleum refinery NESHAP will regulate several of the 189 air toxics listed in Section 112(b) of the CAA. Exposu re to ambient concentrations of these pollutants may result in a variety of adverse health effects considering both cancer and noncancer endpoints.166TABLE 7-1. POTENTIAL HEALTH AND WELFARE EFFECTS ASSOCIATED WITH EXPOSURE TO HAZARDOUS AIRPOLLUTANTS2EffectTypeEffect Category Effect End-Point CitationHealth Mortality CarcinogenicityGenotoxicityNon-Cancer lethalityEPA (1990)3, Graham etal.(1989)4Graham etal. (1989)5Voorhees etal. (1989)6ChronicMorbidityNeurotoxicityImmunotoxicityPulmonary function decrementLiver damageGastrointestinal toxicityKidney damageCardiovascular impairmentHematopoietic (Blooddisorders)Reproductive/DevelopmentaltoxicityAll morbidity end-pointsobtained from Graham etal. (1989)7Voorhees etal.(1989)8, Cote etal.(1988)9Acute Morbidity Pulmonary function decrementDermal irritationEye irritationWelfare MaterialsDamageCorrosion/Deterioration NAS (1975)10167Aesthetic Unpleasant odorsTransportation safetyconcernsAgriculture Yield reductions/FoliarinjuryStern etal. (1973)11EcosystemStructureBiomass decreaseSpecies richness declineSpecies diversity declineCommunity size decreaseOrganism lifespan decreaseTrophic web shorteningWeinstein and Birk (1989)12168

Many HAPs are classified as known human carcinogens . Speciation of the HAP emissions at refining sites was availabl e only for equipment leaks. Of those HAPs (presented in Table 3-2), only benzene is classified as known human carcinogens, a ccording to an EPA system for classifying chemicals by cancer risk . This means that there is sufficient evidence to support that e xposure to this chemical causes an increased risk of cancer in humans. Benzene is a concern to EPA because long term expos ure 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 benze ne could lead to a decrease in cancer risk and ultimat ely to a decrease in cancer mortality. Cresols are considered to be group C or possible hu man carcinogens. For these HAPs, there are limited dat a on animal carcinogenicity, but no data on human carcinogenici ty. Data are currently inadequate to quantitatively estimate pos sible cancer risks associated with cresol exposure. The remaining HAPs emitted by equipment leaks at re fining
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: genot oxicity, developmental toxicity, reproductive toxicity, syst emic 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 adve rse effects on a developing organism that may result from exposure prior to conception, during prenatal development, or postnat ally to the time of sexual maturation. Adverse developmental e ffects may be detected at any point in the life span of the organ ism. Reproductive toxicity refers to the harmful effects of HAP exposure on fertility, gestation, or offspring, cau sed by exposure of either parent to a substance. Systemic toxicity169

affects a portion of the body other than the site o f entry. Irritation, for the purpose of this document, refer s to any effect which results in irritation of the eyes, ski n, and respiratory tract. 14 There are particular noncancer effects in humans as sociated with exposure to several of these HAPs. Brief expo sure to HCl can cause ulceration of the respiratory tract; brie f exposure to phenol can cause mortality; and brief exposure to H F can cause severe respiratory damage. n-hexane can cause poly neuropathy (muscle weakness, numbness), and naphthalene's nonc ancer effects
include cataracts and anemia in humans. For the HAPs covered by the petroleum refinery NESH AP, evidence on the potential toxicity of the pollutant s 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 e mission 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 l ess attention from analysts than the health effects. However, th is 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 ec ological systems which focus on interrelationships in functi on, the dynamics of stress, and the adaptive potential for recovery. This perspective is reflected in Table 7-1 where th e end-points associated with ecosystem functions describe struct ural attributes rather than species specific responses t o HAP exposure. This is consistent with the observation that chronic sub-lethal exposures may affect the normal function ing of individual species in ways that make it less than c ompetitive and therefore more susceptible to a variety of factors including disease, insect attack, and decreases in habitat qu ality. 15 All170

of these factors may contribute to an overall chang e in the structure (i.e., composition) and function of the e cosystem. The adverse, non-human biological effects of HAP em issions include ecosystem and recreational and commercial f ishery impacts. Atmospheric deposition of HAPs directly t o land may affect terrestrial ecosystems. Atmospheric deposit ion of HAPs also contributes to adverse aquatic ecosystem effec ts. This not only has adverse implications for individual wildli fe species and ecosystems as a whole, but also the humans who may ingest contaminated fish and waterfowl. In general, HAP e mission 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 varie ty of health and welfare impacts. VOC emissions, togethe r with NO
x , are precursors to the formation of tropospheric ozo ne. It is exposure to ambient ozone that is most directly res ponsible for a series of respiratory related adverse impacts. Con sequently,
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 sec tion, 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 primar ily results in respiratory-related impacts such as coughing and di fficulty in breathing. Eye irritation is another frequently ob served effect. These acute effects are generally short-term and re versible. 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 m ay also lead171

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 couldbe expanded significantly. Major ozone health effects are: alterations in lun g capacity and breathing frequency; eye, nose and throat irrit ation; reduced exercise performance; malaise and nausea; increasedsensitivity of airways; aggravation of existing respiratory dis ease; decreased sensitivity to respiratory infection; and extrapulmonary effects (central nervous system, liv er, cardiovascular, and reproductive effects). 17 In general, it is expected that reductions in VOCs through the petrol eum refinery NESHAP regulation is a mechanism by which the ambie nt ozone concentration may be reduced and, in turn, reduce t he incidence of the adverse health effects of ozone exposure. I n 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 imp act is related to losses in economic value for certain agricultura l 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 w ell as visible injury to several economically valuable cash crops, including soybeans and cotton. Damage to selected timber spe cies has also been associated with exposure to ozone. The observ ed impacts range from foliar injury to reduced growth rates an d premature
death. Benefits of reduced ozone concentrations in clude both the value of avoided losses in commercially valuable ti mber 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: Or ganic Hazardous Air Pollutants from the Synthetic Organic Chemical Manufacturing Industry and Seven Other Pro cesses. 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 Secti on 112 Regulations. Final report prepared for U.S. Enviro nmental Protection Agency. Office of Air Quality Planning and Standards. Contract No. 68-D8-0094. Research Tria ngle Park, NC. May 1992.
3. U.S. Environmental Protection Agency. Cancer Ris k 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). Congre ssional 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 wi th Exposure to Toxic Air Pollutants. Paper presented at the 82 ndAnnual 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 Po llutants and Non-Cancer Health Risks. Unpublished paper pro vided by B. Hassett. 1988.
10. NAS. Chlorine and Hydrogen Chloride. National Academy of Sciences, National Research Council. Chapter 7. 1 975.
11. Stern, A. et al . Fundamentals of Air Pollution. Academic Press, New York. 1973.
12. Weinstein, D. and E. Birk. The Effects of Chemi cals on the Structure of Terrestrial Ecosystems: Mechanism s andREFERENCES (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. Ecologica l Exposure and Effects of Airborne Toxic Chemicals: An Overvi ew. 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 t he methodology which was utilized to obtain monetary estimates of HAP and VOC emission reductions occurring as a result of the pr oposed rule. Limitations of this methodology are also identified . To ensure that an economically efficient regulatory alternati ve is chosen, an incremental analysis must be performed. Therefo re, benefits for the two regulatory alternatives are presented. Potential impacts are evaluated for the promulgated regulatio n and one alternative more stringent than that.

8.1 METHODOLOGY FOR DEVELOPMENT OF BENEFIT ESTIMATE Quantification of impacts associated with HAP expos ure requires information on the particular HAP involved . Such data are necessary because different HAP emissions can l ead to different types and degrees of severity of impacts. Table 8-1 identifies the specific HAPs emitted by petroleum r efineries. 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 estim ate of HAP speciation for equipment leaks has been made. Sinc e HAP emissions from equipment leaks account for nearly t wo thirds of total HAP emissions at petroleum refineries, it is possible to use these data to develop an estimate of cancer ris k 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 reductio ns. This175

approach uses emissions data and the Human Exposure Model (HEM) to estimate the annual cancer risk caused by HAP em issions from petroleum refineries. Generally, this benefit cate gory is
calculated as the difference in estimated annual ca ncer 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 noncarcino genic HAP for which EPA had health benchmark information, EPA per formed a baseline assessment to estimate the number of peopl e exposed to HAPs above health benchmark levels. The quantifiedbenefits attributable to reducing noncarcinogenic HAP emissi ons is the difference in the number of people exposed above he alth benchmark levels before and after regulation. The benefits o f controlling VOC emissions are monetized by applying average ben efit per Megagram estimates to the total amount of VOC emiss ion reductions calculated for each of the two regulatory alternati ves.

8.1.1 Benefits of Reduced Cancer Risk Associated with HAP Reductions

The proposed MACT for petroleum refineries is expec ted 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 Xylenes176

A quantitative assessment of these benefits require s two types of data. First, it must be possible to relate chan ges in emissions to changes in risk and incidence of cance r. 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 conc ept, there are difficulties in the way both types of data are usua lly developed so that the credibility of any quantitative estimat es must be carefully assessed. The next two sections discuss the models of cancer risk, and estimates of the value of a statis tical life.

8.1.1.1 Models of Cancer Risk . A variety of models have been proposed to formalize the relationships between emi ssion changes and changes in cancer risk so that predictions can be made regarding changes in the expected number of lives s aved due to a specific emission reduction scenario. Cancer risk models often express cancer risk in terms of excess lifetime can cer risk. Lifetime risk is a measure of the probability that an individual will develop cancer as a result of exposure to an a ir 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 o f a pollutant. It is often expressed as the probability of contrac ting cancer from a 70 year lifetime continuous exposure to a co ncentration of one microgram per cubic meter ( : g/m 3 ) 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 low er. EPA has developed unit risk factors for many HAPs. 1 Among the HAPs identified in Table 8-1, only benzene has a quantit ative URFs. In addition, benzene is a known human carcinogen, a s there are several studies linking benzene exposure to cancer in humans. Cresols are considered possible human carcinogens b ased on animal experiments.177

To translate lifetime individual risk to annual inc idence of excess cancer, it is necessary to combine three pie ces of data: the unit risk factor, the (constant) level of conce ntration to which the population is exposed, and the population count. For example, benzene, which is classified as a known hu man carcinogen, has a unit risk factor of 8.3 × 10 -6 ( : g/m 3 ) -1 . In a population of 1,000,000 people, each exposed to 5 : g/m 3 of benzene for 70 years (a lifetime of constant exposu re), 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/m 3 × 1,000,000 × 8.3 × 10 -6 ( : g/m 3 ) -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 tha t 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 th e data and methods used in the standard approach to cancer ris k assessment. Additional issues arise in estimating economic bene fits 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 tradeof f accepted by workers in high risk occupations and to infer the i mplicit 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 m illion people). Multiplication of the value of a statis tical life times the expected number of lives saved due to the reduced cancer risk provides an estimate of the economic be nefits associated with the regulation. Estimates of the v alue of a statistical life have been developed by examining t he wage-risk tradeoff revealed by workers accepting jobs with kn own risks. Viscusi recently completed a survey of over 20 of t hese studies and recommends an initial range of $3-$7 million (D ecember 1990 dollars) as an estimate of the statistical value of a life. 2178

Using this range in an environmental policy analysi s requires
consideration of several factors that could bias th e transfer of the results. Specifically, adjustments may be requ ired to account for differences across applications. These differences
include:

C Risk perception: Environmental risks are involunta ry; job risks may not be. Cancer risks may be prolonged an d involve suffering; job fatalities may be more immed iate in

consequence.

C Age: The age of the affected population may affect willingness to pay values. Life years saved may be a morerelevant measure. Discount rates may also be agesensitive.

C Income: Income levels of exposed individuals may a ffect willingness to pay. Economic theory would suggest a positive elasticity between income and risk reducti on.

C Baseline risks: The willingness to pay function co uld 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 A SSESSMENT 1

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 h igh dose exposures so that responses must be extrapolat ed 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 oft en 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 individ uals experience a constant outdoor exposure over a lifet ime. This ignores activity patterns of people and the opportunity for behavioral adjustments.

C For carcinogens as well as other toxicants, there i s 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 a n order of magnitude of greater than another's. This incre aes 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-yea r change in cancer incidence following policy implementation. The timing of incidences, includin g latency periods, should be expressly considered.

C Benefit calculations should reflect changes in concentrations over time related to economic respon ses 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 var iety of issues. These include: discounting, age distribut ion, non-voluntary nature of risk, risk adverseness of g eneral population, probability of fatality, and treatment costs.181

Unfortunately, there is no general consensus on the adjustments that should be made to account for thes e possible biases in a direct transfer of values. As a result, this study makes no adjustments other than to update the value s to first quarter 1992 dollars. With this single change, the value range to be applied to the annual reduction in lives save d 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 a ssessment 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 10 6 )

Benzene 8.3

The HEM uses the URF in Table 8-4, along with other information such as refinery emissions, to characte rize the risk posed to individuals and the population located wit hin a 50 km radius of each refinery (approximately 83.4 million people). Runs using the HEM showed that 4.5 million people e xposed to refinery HAP emissions within a 50 km radius of ref ineries have an individual risk greater than 1 * 10 -6 . If the risk from any source in a source category is greater than that, t hen the source category must be listed on the list of source categ ories 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 ex presses 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 i n the exposed182

population in a year. As estimated in the HEM, the total annual
cancer incidence of the HAP is 0.33 of a statistica l life. The benefits of reducing cancer risk resulting from red uced emissions of carcinogenic HAP could not be monetized since va lues of annual
cancer risk after controls were not available. How ever, if it is assumed that the controls required by the promulgat ed rule would decrease benzene emissions to zero, then a monetary estimate of the benefit of reducing this HAP could be calculate d. The benefit of eliminating the carcinogenic HAP emissio ns is calculated by multiplying the 0.33 reduction in tot al annual cancer risk by the midpoint of the range of values of a statistical life ($3-$7 million), which is $5 milli on. This calculation yields a total monetary benefit of $1.5 0 million. This is biased upwards, however, because the petrol eum refinery NESHAP will not achieve a 100 percent HAP reduction

.

Table 8-5. MAXIMUM INDIVIDUAL RISK AND ANNUAL CANC ER INCIDENCE OF CARCINOGENIC HAPs

HAP MIR Annual Cancer Incidence

Benzene 1.8 * 10 -4 0.33

These monetary values should be interpreted careful ly 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- est imates of the true value of cancer risk reduction. At best, the numbers should be viewed as a guide to the possible level of benef its that may
be realized.
8.1.1.4 Other Health and Welfare Impacts of HAPs . A quantitative assessment of the economic benefits re lated to these impacts requires information on risk relationships, exposure, and and economic value. Unfortunately, such data are g enerally unavailable. Therefore, it is currently not possib le to conduct183

a complete quantitative analysis of the benefits as sociated with
HAP emission reductions. Several intermediate quantitative assessment approa ches have been developed which can provide partial objective of the positive impact of HAP emission reductions. One ap proach examines changes in the population exposed to conce ntrations of
HAPs over a reference dose level with and without a dditional
controls. 3 The reference dose level is designed to reflect a concentration level, with a margin of safety, at wh ich no adverse health impacts would be expected. To complete this calculation, data must be available on population counts near af fected refineries, concentrations of speciated HAPs with a nd without additional controls, and a reference dose level for the specific
HAP. Based on toxicity and emission information, an expo sure assessment was performed for hexane, hydrogen chlor ide, methyl ethyl ketone, and toluene. For noncarcinogens, the dose-response is expressed in terms of an inhalation reference-do se concentration (RfC). Using the RfC methodology, a benchmark
concentration is calculated below which adverse eff ects are not expected to occur. The significance of the RfC ben chmark is that exposures to levels below the RfC are considered "s afe" because exposures to concentrations of the chemical at or b elow the RfC have not been linked with any observable health eff ects. The RfCs of the above mentioned HAPs are presented in T able 8-6. The benefits of reducing these HAPs could not be moneti zed because information on reduced exposure is not available. The omission of this benefit category from the monetized benefit s analysis will lead to an underestimation of the total expect ed benefits from the promulgated regulation. Only baseline exp osure was analyzed.184

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

RFC BY HAPS

HAP RfC (mg/m 3 ) 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 st atistical associations between exposure and observable respon ses in the population represent another way to quantify possib le risks. However, because of collinearity with other environ mental factors, it is often very difficult to isolate the effects due solely to changes in HAP emissions. For this reaso n, such statistical functions have generally not been estim ated. At present, most of the model development in the ar ea of estimating the welfare effects and ecosystem impact s of exposure to HAPs is still conceptual and not amenable to obj ective 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 MAC T regulation of petroleum refineries will be develope d largely using the technique of "benefits transfer." Benefi ts transfer
involves the use of benefit values obtained from an other study to represent benefits associated with the promulgated rule, with appropriate adjustments. At a minimum, the adjustm ents must address the differential impact in the severity of the regulation as represented, for example, by changes in emission s or concentrations. With this technique, the assumptio n 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 re gulation 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 fr om a study conducted for the Office of Technology Assessment. 4 The OTA study examined a variety of acute health impacts re lated to ozone exposure as well as the benefits of reduced ozone c oncentrations for selected crops. However, chronic health effect s 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 ben efits are taken from Table 3-10 of the OTA report. For the p resent calculation, the values reported for the 35 percent VOC reduction scenario are used. Specifically, information from both the epidemiological studies and the clinical studies re ported 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 influence d by several factors. First, the results for the 35 pe rcent VOC emission reduction scenario are used because it is easier to identify the level of emission reductions associate d with this scenario in the OTA report. It should also be note d that this scenario involves a reduction of 35 percent in thos e emissions occurring only in nonattainment areas. Although th ere are expected to be VOC emission reductions in attainmen t areas under this scenario, the percentage reduction in VOC emis sions in attainment areas is less than 35 percent. A close reading of the OTA report indicates that all health impacts are es timated for non-attainment areas only. Therefore, no health be nefits are186

associated with VOC emission reductions in attainme nt areas, according to the report. This may provide addition al
conservatism to the benefit values since there is r ecent evidence that acute health effects may be experienced at ozo ne concentrations below the current NAAQS. 5 The OTA report calculates acute health impacts base d on the results of epidemiological and clinical studies. B oth 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 po ssible to use the results from both design types to form a range of values. This approach would not involve double-counting andwould use
more of the available information. A lower bound v alue is identified from the epidemiological study design. An upper bound value is taken from the clinical study design in wh ich all
exercisers are affected. These choices lead to the initial benefit range of $54-3,400 per ton VOC emission red uction. The year of dollars for these benefit values is not made clear in the OTA report. However, a check with the autho rs of several of the cited references used to develop "willingnes s-to-pay" values, indicates that the values are in 1984 dolla r 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 CP I index between the annual index value for 1984 and the geo metric 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 thi s 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 em ission reductions for the petroleum refinery MACT.187

Second, the benefit values in the OTA report reflec t a level of exposure that corresponds to population densitie s in nonattainment areas in the early 1980's. Since the cost analysis is conducted for the fifth year following rule prom ulgation (the year 2000), the benefit analysis should be conforma ble. There is approximately a twenty year interval from the perio d 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 c hange in population, between 1980 and 1999, in those nonatta inment areas with petroleum refineries as of 1995. Using data f rom the 1980 and 1990 Censuses and extrapolating to 1999 under a n assumption of a constant growth rate equal to that observed fo r the 10 year period, it it estimated that the population scale f actor is 19.64 percent. This leads to a revised benefit value ran ge of $86 to $5,430 million. Third, the passage of time may also affect the will ingness to pay value. If real income grows over time and the income elasticity of environmental quality is positive, th en unit willingness to pay values in 1999 should exceed tho se implied by the surveys conducted in the mid-1980's. Using the 1993 Statistical Abstract, bthe 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 a reas. Extrapolating to 1999 under a constant growth assumption results in an increase of 6.7 percent. Given this relative ly small change and uncertainty about the proper income elas ticity 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 earl y 1980's, VOC emissions as precursors to ozone formation have fal len also. Thus, any adjustment to the benefit transfer ratio used in this analysis must take into account the reduction in em issions as well as any changes in air quality that have occurr ed since the time of the data used in the OTA report. It is unc ertain whether188

the benefit transfer ratio would change significant ly with such adjustments.
8.1.2.2 Agricultural Yield Estimates . In addition to valuing acute health effects, the OTA report also a ttempted to
value the effect that reduced VOC emissions would h ave on the yield of crops. Ozone levels currently found in ru ral areas are linked with reduced growth rates and yields of crop s such as soybeans and oats. Lower VOC concentrations are ex pected to reduce ambient ozone concentrations, which in turn will increase crop yields. This category of benefits is primaril y true for areas, mostly rural, in ozone attainment that have refineries in relative proximity, but it also applies in nonattai nment areas as well. The report estimated that an annual reductio n 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 mill ion Mg of VOC would result in total annual agricultural benefits of approximately $77 million to $1.4 billion. These b enefits translate into an average benefit value per Mg of V OC emission reduction of approximately $120 to $236 (first quar ter 1992 dollars). To calculate the monetized benefits fromimproved agricultural yields, a point estimate of $178 per M g was used and applied to both attainment and nonattainment VOC em ission
reductions.
8.1.2.3 Emission Reductions . The development of VOC emission reductions associated with the benefits range descr ibed above can be determined directly from the OTA report. Tables 6-1 and 6-6 of the report provide the needed information. Tota l VOC
emissions in 1985 are 25 million tons. c Of this total, 11 million tons are predicted to occur in nonattainmen t cities while 14 million tons of VOC are predicted to be emitted in ozone attainment areas. For the 35 percent VOC (nonattai nment area) emission reduction scenario, 3.8 million tons of VO C emissions are predicted to be controlled in 1994, while 2.7 m illion tons
will be controlled in attainment areas.189

The selection of a "tons reduced" value for the den ominator of
the benefit transfer ratio must be consistent with the benefits
measure selected for the numerator. As described e arlier, the
benefits reflect the annual reduction in acute heal th impacts experienced by populations in nonattainment areas t hat result from a 35 percent reduction in nonattainment area V OC emissions. Implicitly, there is the assumption, derived from t he OTA study,
that no health benefits occur in attainment areas. This also implies that the derivation of petroleum refinery h ealth benefits from VOC emission reductions should consider only t hose emission
reductions that occur at refineries in nonattainmen t areas. Fortunately, because individual refineries are iden tified, it is possible to identify this subset of emission reduct ions. A result of this approach is that no acute health imp acts are associated with VOC emission reductions in attainme nt areas. d Table ES-3 in the executive summary presents the ba seline VOC emissions, and the emission reductions for refineri es in
nonattainment areas associated with each alternativ e. One final step is needed prior to forming the benef it transfer ratio. Since VOC emission reductions for petroleumrefineries are stated in megagrams per year (metric tons per y ear), it is necessary to convert the OTA emission reductions to equivalent
metric tons. This conversion results in a reductio n 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 $25-1,5 74 (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 multipli ed by VOC emission reductions from petroleum refineries locat ed in ozone
nonattainment area in order to estimate the VOC-rel ated acute health benefits of the petroleum refinery MACT. Al so among the
benefits estimates is the estimate of benefits fromincreased agricultural yields from reduced ozone concentratio ns, occurring
due to VOC emission reductions. Table 8-7 summariz es the results190

of these calculations for the combination of option s selected for the four controlled emission points. Note, the f loor option for each emission point type is statutorily mandate d so that, in effect, the floor options represent the minimum reg ulatory requirements.

Table 8-7. QUANTIFIED BENEFITS OF VOC REDUCTIONS B Y 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 interpret ed 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 nonattainmen t areas. Second, as noted earlier, there may be other benefi t types. Reductions in VOC emissions that lead to improvemen ts in ozone concentrations may contribute to reductions in chro nic health impacts (e.g., sinusitis, hay fever and reduced dam age to certain materials, such as elastomers). 8 However, because of data and methodological concerns, no quantitative benefit es timates for these possible effect types have been developed for the present analysis. All else equal, this implies that the ca lculated benefits per metric ton are likely to be conservati ve. Although the quantified VOC benefits estimated in t his RIA represent one approach for valuing the benefits of reduced VOC emissions, data limitations prevent a complete quan tification of191

all categories of benefits attributable to VOC redu ctions. Since lack of data prevent all benefit categories from be ing 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. Alternati ve 1, the set of alternatives in the promulgated rule, includes c ontrols to meet MACT floor level controls, and a level of cont rol more stringent than the floor for equipment leaks. Th e annual cost of this control, including equipment costs, MRR cos ts, and economic costs, is $94 million annually. This regu latory alternative is expected to result in a reduction of VOC emissions of approximately 134,283 Mg annually in nonattainme nt areas. Therefore, the incremental cost-effectiveness from baseline, averaged across multiple emission points for nonatt ainment areas, for alternative 1 is approximately $714/Mg. In oth er words, the average cost of reducing each Mg required by altern ative 1 is $714.192

REFERENCES

1. U.S. Environmental Protection Agency. Cancer Ris k 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. De cember 1993.
3. Voorhees, A., B. Hassett, and I. Cote. Analysis of the Potential for Non-Cancer Health Risks Associated wi th 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 Br eath: 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. Abda l-Salaam, and P. Ives. Changes in Pulmonary Function and Air way Reactivity Due to Prolonged Exposure to Typical Amb ient Ozone (O 3 ) Levels. In: Schneider, T. et al (eds.) Atmospheric Ozone Research and its Policy Implicati ons. 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 a nd Chronic Respiratory Disease." Regional Science andUrban Economics. Vol. 20. p. 407-18. 1990.193 9.0 COMPARISON OF BENEFITS TO COSTS

The goal of the RIA (or Economic Assessment) for th e Petroleum Refinery NESHAP is to provide economic and some eng ineering data necessary for effective environmental policy making . A comparison of the benefits of alternative air emiss ion controls with the costs of such controls provides the necess ary 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 associate d with air emission reductions relate to expected reductions i n emissions of several HAPs and VOCs from storage tanks, process v ents, equipment leaks, and wastewater emission points at refining sites. The quantification of benefits from emissio n controls
relates to health benefits from reduced cancer inci dence associated with carcinogenic HAPs emitted at petrol eum refineries
and the health benefits related to VOCs that transl ate into reductions in ozone. Benefits from reducing cancer incidence to zero were quantified for equipment leaks only in th e previous chapter. Because of the uncertainty associated wit h this estimate, the benefits of reduced cancer risk are n ot incorporated in this benefit cost analysis. Other health and welfare benefits from the controls such as ecosyste m 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 maintenanc e costs for each alternative (including MRR costs) obtained fro m the cost analysis done by EPA. These estimates reflect engi neering costs of emission controls, not the economic costs to soc iety. The compliance costs estimates are a necessary input to the economic analysis using the costs of the regulatory alternat ives to society. The economic effect of imposing complianc e costs on the petroleum refining markets and its consumers and pr oducers is obtained from a partial equilibrium model of the pe troleum194

refining industry. The social costs of the control s include potential economic costs to consumers of refined pe troleum products, producers of such products, and society a s a whole.
Economic costs are a better measure of the costs of the air emission control alternative to society because the se costs represent the true costs or opportunity costs to so ciety of resources used for emission control. Quantificatio ns of these costs associated with the regulatory alternatives a re subject to the limitations noted in Section 6.4, Limitations o f the Economic
Model. Costs, both engineering (compliance) and social, fo r other
alternatives other than the chosen ones are not ava ilable here
due to limitations in resources and data. Table 9- 1 depicts a comparison of the benefits of the chosen alternativ e to the social costs. There is an annual net benefit of $5 8.1 million estimated from compliance with the promulgated stan dard, thus providing some evidence of the desirability of the alternative. A comparison of the net benefits for the alternativ e and the
incremental difference in net benefits between it a nd other alternatives would be a way to determine if net ben efits were at least approaching a maximum. Due to cost informati on not being available, this comparison cannot be drawn. Accord ing to the analyses conducted for this RIA, the standard shou ld 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 Bu siness.
b. Statistical Abstract, 1993, Table 704.

c. The emissions data in OTA do not reflect measure d emissions. Rather, they represent emissions on a typical nonattainment day multipliedby 365. It is not clear from the OTA report how these "nonattainment-day-equivalent-annu al emissions" are calculated for attainment regions. d. Recent evidence suggests that some health benefi ts may occur for VOC emission reductions in areas near, but below, the current oz one NAAQS. 5As might be expected, the response rate is lower than that observed at higher ozone concentrations. In addition, economic theory suggests that the marginal willingn ess 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.