Mechanical seals can be designed specifically for high pressure applications ( i. e., greater than 1,140 kPa or 165 psia). As with packed seals, the mechanical seals for agitators are similar to the design and application of mechanical seals for pumps.

The hydraulic seal is the simplest and least used agitator shaft seal. In this type of seal, an annular cup attached to the process vessel contains a liquid that contacts an inverted cup attached to the rotating agitator shaft. The primary advantage of this seal is that it is a noncontact seal. However, this seal 54 is limited to low temperatures and pressures and can only handle very small fluctuations. Process chemicals may contaminate the seal liquid and then be released into the atmosphere as equipment leak emissions.

Lip seals, which are relatively inexpensive and easy to install, can be used on a top entering agitator as a dust or vapor seal. Once the seal has been installed, the agitator shaft rotates in continuous contact with the lip seal. Emissions can be released through this seal when it wears excessively or when the operating pressure surpasses the pressure limitation of the seal.

<IP_ADDRESS> Pressure Relief Devices. Insurance, safety, and engineering codes require that pressure relief devices or systems be used in applications where the process pressure may exceed the maximum allowable working pressure of the process equipment.

Pressure relief devices include rupture disks and safety/ relief valves. The most common pressure relief device is a springloaded valve designed to open when the operating pressure of a piece of process equipment exceeds a set pressure. Equipment leak emissions from spring loaded relief valves may be caused by failure of the valve seat or valve stem, improper reseating after overpressure relief, or process operation near the relief valve set pressure which may cause the relief valve to frequently open and close or " simmer."

Rupture disks are designed to burst at overpressure to allow the process gas to vent directly to the atmosphere. Rupture disks allow no emissions as long as the integrity of the disk is maintained. They must be replaced after each pressure relief episode to restore the process to an operating pressure condition. Although rupture disks can be used alone, they are sometimes installed upstream of a relief valve to prevent emissions through the relief valve stem.

Combinations of rupture disks and relief valves require certain design constraints and criteria to avoid potential safety hazards. For example, appropriate piping changes must be made to prevent disk fragments from lodging in damaging the relief valve when relieving overpressure. A block valve upstream of the 55 rupture disk can be used to isolate the rupture disk/ relief valve combination and permit in service replacement of the disk after it bursts. Otherwise, emissions could result through the relief valve.

<IP_ADDRESS> Open Ended Lines. Emissions from open ended lines are caused by leakage through the seat of an upstream valve in the open ended line. Emissions that occur through the stem and gland of the valve are not considered " open ended" emissions and are addressed in the section on process valves. Emissions from open ended lines can be controlled by installing a cap, plug,

flange, or second valve to the open end. Control efficiency of these control measures is assumed to be 100 percent.

<IP_ADDRESS> Sampling Connections. Emissions from sampling connections occur as a result of purging the sampling line to obtain a representative sample of the process fluid. These emissions can be reduced by using a closed loop sampling system or disposing of the purged process fluid in a control device.

The closed loop sampling system is designed to return the purged fluid to the process at a point of lower pressure. Closed loop sampling is assumed to be 100 percent effective for controlling emissions from a sample purge. This purged fluid could also be directed to a control device such as an incinerator, in which case the control efficiency would depend on the efficiency of the incinerator in removing the VOC.

<IP_ADDRESS> Process Valves. There are many designs for valves,

and most of the designs contain a valve stem which operates to restrict or allow fluid flow. Typically, the stem is sealed by a packing gland or O ring to prevent leakage of process fluid to the atmosphere. Emissions from valves occur at the stem or gland area of the valve body when the packing or O ring in the valve fails.

Valves that require the stem to move in and out or turn must utilize a packing gland. A variety of packing materials are suitable for conventional packing glands. The most common packing materials are the various types of braided asbestos that contain lubricants; other packing materials include graphite,

graphite impregnated fibers, and tetrafluorethylene. The choice 56 of packing material depends on the valve application and configuration. Conventional packing glands can be used over a wide range of operating temperatures.

Emissions from process valves can be eliminated if the valve stem can be isolated from the process fluid. There are two types of sealless valves available: diaphragm valves and sealed bellows valves.

Diaphragm valves isolate the valve stem from the process fluid using a flexible elastomer or metal diaphragm. The position of the diaphragm is regulated by a plunger, which is controlled by the stem. Depending on the diaphragm material, this type of valve can be used at temperatures as high as 205 degrees Celsius and in strong acid service. If the diaphragm fails, the valve can become a relatively larger source of emissions. In addition,

use at temperatures beyond the operating limits of the material tends to damage or destroy the diaphragm.

Sealed bellows valves are another alternative leakless design.

In this valve type, metal bellows are welded to the bonnet and disk of the valve, thereby isolating the stem from the process.

These valves can be designed to withstand high temperatures and pressures and can provide leak free service at operating conditions beyond the limits of diaphragm valves. However, they are usually dedicated to highly toxic services and the nuclear industry.

The control effectiveness of both diaphragm and sealed bellows valves is essentially 100 percent, although a failure of the diaphragm or bellows could cause temporary emissions much larger than those from other types of valves.

<IP_ADDRESS> Connectors. Connectors are flanges, threaded fittings, and other fittings used to join sections of piping and equipment. They are used wherever pipe or other equipment ( such as vessels, pumps, valves, and heat exchangers) require isolation or removal.

Flanges are bolted, gasket sealed connectors. Normally,

flanges are used for pipes with diameters of 50 mm or greater and are classified by pressure rating and face type. The primary cause of flange leakage are poor installation and thermal stress, 57 which results in the deformation of the seal between the flange faces.

Threaded fittings are made by cutting threads into the outside end of one piece ( male) and the inside end of another piece ( female). These male and female parts are then screwed together like a nut and bolt. Threaded fittings are normally used to connect piping and equipment having diameters of 50 mm or less.

Seals for these fittings are made by coating the male threads with a sealant before joining it to the female piece. Emissions from threaded fittings can occur as the sealant ages and eventually cracks. Leakage can also occur as the result of poor assembly or application of the sealant, and thermal stress of the piping and fittings.

Emissions from connectors can be controlled by regularly scheduled maintenance. Potential emissions can be reduced by replacing the gasket or sealant materials. If connectors are not required for process modification or periodic equipment removal,

emissions from connectors can be eliminated by welding the connectors together.

<IP_ADDRESS> Instrumentation Systems. An instrumentation system is a group of equipment components used to condition and convey a sample of process fluid to analyzers and instruments for the purpose of determining process operating conditions ( e. g.,

composition, pressure, and flow rate). Valves and connectors are the predominant types of equipment used in instrumentation systems, although other equipment may be included. Emissions resulting from the components in the instrumentation system are controlled as they are for the same component in the process system.

Emissions from equipment leaks may be controlled by installed a closed vent system around the leaking equipment and venting the emissions to a control device. This method of control is only applicable to certain equipment types, i. e., pumps, compressors,

agitators, pressure relief valves, and product accumulator vessels. Because of the many valves, connectors, and open ended lines typically found in refineries, it is not practical to use this technique for reducing emissions from all of these potential 58 sources for an entire process unit. However, a closed vent system can be used to control emissions from a limited number of components, which could be enclosed and maintained under negative pressure and vented to a control device.

LDAR methods are used to identify equipment components that are emitting significant amounts of VOC and to reduce these emissions. The emission reduction potential for LDAR as a control technique is highly variable and depends on several factors, the most important of which are the frequency of monitoring and the techniques used to identify leaks. Repair of leaking components is required only when the equipment leak emissions reach a set level

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

Leak detection methods include individual component surveys,

area ( walk through) surveys, and fixed point monitors.

Individual component surveys form a part of the other methods.

<IP_ADDRESS>.1 Individual Component Survey. Each source of equipment leak emissions ( pump, valve, compressor, etc.) can be checked for VOC leakage by visual, audible, olfactory, soap bubble, or instrument techniques. Visual methods are good for locating liquid leaks. A visible leak does not necessarily indicate VOC emissions, however, because the leaking material may be non VOC. High pressure leaks may be detected by the sound of escaping vapors, and leaks of odorous materials may be detected by smell.

Soap spraying on equipment components can be used to survey individual components in certain applications. If the soap solution forms bubbles or blows away, a leak is indicated, and vice versa. Disadvantages of this method are that 1) it does not distinguish leaks of hazardous VOCs from nonhazardous VOCs; 2) it is only semiquantitative, since it requires the observer to determine subjectively the rate of leakage based on the behavior of the soap bubbles; and 3) it is limited to sources with temperatures below 100 degrees Celsius, because the water in the soap solution will evaporate at temperatures above this figure.

This method is also not suited for moving shafts on pumps or 59 compressors, because the motion of the shaft may interfere with the motion of the bubbles caused by a leak.

The best method for identifying leaks of VOC from components is using a portable hydrocarbon detection instrument. Air close to the potential leak site is sampled and analyzed by a sampling traverse (" monitoring") over the entire are where leaks may occur. The concentration of hydrocarbons in the sampled air is displayed on the instrument meter and is a rough indicator of the VOC emission rate from the component. If the concentration is higher than a specified figure (" action level"), then the leaking component is marked for repair.

<IP_ADDRESS>.2 Area Survey. An area or walk through survey requires the use of a portable hydrocarbon detector and a strip chart recorder. The procedure involves carrying the instrument within one meter of the upwind and downwind sides of process equipment. The instrument is then used for an individual component survey in a suspected leak area. The efficiency of this method for locating leaks is not well established. Problems with this method include the fact that leaks from overhead valves or relief valves will not be detected, and the possibility of leaks from adjacent units and adverse meteorological conditions affecting the results of the walk through survey. Thus, the area survey is best for locating only large leaks at small expense.

<IP_ADDRESS>.3 Fixed Point Monitors. This method consists of placing several automatic hydrocarbon sampling and analysis instruments at various locations in the process unit. If elevated hydrocarbon concentrations are detected, a leaking component is indicated. Identifying the specific leaking component requires an individual component survey. The efficiency of fixed point monitoring is not well established, but fixed point monitoring of VOCs is not as effective as a complete individual component survey. Fixed point monitors are expensive,

multiple units may be required, and the portable instrument is also needed to locate the particular leaking component.

Calibration and maintenance costs may be high. Fixed point monitors are used successfully to detect emissions of hazardous or toxic substances, and can provide an increased detection 60 efficiency by selecting a particular compound as the sampling criterion.

<IP_ADDRESS>.4 Repair Methods. This section describes repair methods for possible equipment emission sources in a refinery.

These are not intended to be complete repair procedures.

Many pumps have in line or parallel spares that can be used while the leaking pump is being repaired. Leaks from packed seals may be reduced by tightening the packing gland. With mechanical seals, the pump must be dismantled to repair or replace the leaking seal. Dismantling pumps can result in spillage of some process fluid. If the seal leak is small,

evaporative emissions of VOC from such spillage may be greater than the continued leak from the seal. Precautions must be taken to prevent or reduce these emissions.

Leakage from compressors with packed seals may be reduced by tightening the packing gland, as described for pumps. Repair of compressors with mechanical seals requires the compressor be removed from service. Since compressors usually do not have spares, immediate repair may not be practical or possible without a process unit shutdown.

Agitators, like pumps and compressors, can leak VOCs at the point where the shaft penetrates the casing, and seals are required to minimize fugitive emissions. Leaks from packed seals may be reduced by the repair procedure described for pumps, while repair of other types of seals require the agitator to be out of service. In this latter case, process shutdown or isolation of the particular agitator being repaired is required.

Leaking repair valves usually must be removed for repair. To remove the relief valve without shutting down the process, a block valve may be required upstream of the relief valve. A spare relief valve should be attached while the faulty valve is repaired and tested.

A rupture disk can be installed upstream from a pressure relief valve to eliminate leaks until an overpressure release occurs. Once a release occurs, the rupture disk must be replaced to prevent further leaks. A block valve is required to isolate the rupture disk for replacement. 61 Most valves have a packing gland that can be tightened while in service. Although this procedure should decrease the emissions from the valve, it can actually increase the emission rate if the packing is old and brittle or has been overtightened Some types of valves have no means of in service repair and must be isolated from the process and removed for repair and replacement. Most control valves have a manual bypass loop that allows them to be isolated and removed. Most block valves cannot be isolated easily, although temporary changes in process operation may allow isolation in some cases.

In some cases, leaks from connectors can be reduced by replacing the connector gaskets, but most connectors cannot be isolated to permit gasket replacement. Tightening of connector bolts also may reduce emissions from connectors. Where connectors are not required for process modification or periodic equipment removal, emissions from connectors can be eliminated by welding them.

4.1.4 Internal Floating Roofs Internal floating roofs are commonly used in the petroleum refining industry to control emissions from fixed roof storage tanks. As the name implies, it is a roof inside a tank that floats on the surface of the stored liquid.

The presence of a floating roof ( or deck) inside a fixed roof tank significantly reduces the surface area of exposed liquid.

It serves as a physical barrier between the volatile organic liquid and the air that enters the tank through vents.

Because evaporation is the primary emission mechanism associated with storage tanks, emissions from floating roof tanks as well as fixed roof tanks vary with the vapor pressure of the stored liquid. Thus, the control efficiency of retrofitting a fixed roof tank with an internal floating deck depends on the material being stored.

Other factors affecting emissions, and therefore control efficiency, are tank size, number of turnovers, and the type of deck and seal system selected. Installing an internal floating roof can reduce emissions by 61 to 98 percent. The relative 62 effectiveness of one internal floating roof design over another is a function of how well the deck can be sealed. Probably the most typical internal floating roof design is the noncontact,

bolted, aluminum internal floating roof with a single vapormounted wiper seal and uncontrolled fittings.

Loss of VOCs from internal floating roof tanks occurs in one of four ways:

1) Through the annular rim space around the perimeter of the floating roof ( seal losses),

2) Through the openings in the deck required for various types of fittings ( fitting losses),

3) Through the nonwelded seams formed when joining sections of the deck material ( deck seam losses), and 4) Through evaporation of liquid left on the tank wall following withdrawal of liquid from the tank ( withdrawal loss).

<IP_ADDRESS> Control of Seal Losses. Internal floating roof seal losses can be minimized by employing liquid mounted primary seals instead of vapor mounted seals and/ or by employing secondary wiper seals in addition to primary seals.

Available emissions test data suggest that the location of the seal ( i. e., vapor or liquid mounted) and the presence of a secondary seal are the major factors affecting seal losses. A liquid mounted primary seal has a lower emissions rate, and thus a higher control efficiency, than a vapor mounted seal. A secondary seal, with either a liquid or a vapor mounted primary seal, provides an additional level of control.

The type of seal used plays a less significant role in determining the emissions rate. The type of seal is important only to the extent that the seal must be suitable for the particular application. For instance, an elastomeric wiper seal is commonly employed as a vapor mounted primary seal or as a secondary seal for an internal floating roof. Because of its shape, this seal is not suitable for use as a liquid mounted primary seal. Resilient foam seals, on the other hand, can be used as both liquid and vapor mounted seals. 63 <IP_ADDRESS> Control of Fitting Losses. There are numerous fittings that penetrate or are attached to an internal floating roof. Among them are access hatches, column wells, roof legs,

sample pipes, ladder wells, vacuum breakers, and automatic gauge float wells. Fitting losses occur when VOCs leak around these fittings. Fitting losses can be controlled with gasketing and sealing techniques or by the substitution of fittings that are designed to leak less.

The effectiveness of fitting controls at reducing the overall emission rate is a function of the number of fittings of each type employed on a given tank. For example, if using controlled fittings reduces total fitting loss by 36 percent, and if fitting losses are about 35 percent of the total emissions from a typical internal floating roof tank, then the controlled fittings reduce the overall emissions by (. 36*. 35)= .126, or 12.6 percent over a similar tank without fitting controls. The usual increase in control efficiency achieved by installing controlled fittings ranges from 0.5 to 1.0 percent.

<IP_ADDRESS> Control of Deck Seam Losses. Deck seam losses are inherent in a number of floating roof types including internal floating roofs. Any roof constructed of sheets or panels fastened by mechanical fasteners ( e. g., bolts) is expected to have deck seam losses. Deck seam losses are considered to be a function of the length of the seams and not the type of mechanical fastener or the position of the deck relative to the liquid surface. This is a conclusion drawn from a 1986 study on two roof types with significantly different mechanical fasteners and differences in the amount of contact with the liquid surface.

Deck seam losses are controlled by selecting a roof type with vapor tight deck seams. The welded deck seams on steel pan roofs are vapor tight. Fiberglass lapped seams of a glass fiber reinforced polyester roof may be vapor tight as long as there is negligible permeability of the liquid through the seam lapping materials. Some manufacturers provide gaskets for bolted metal deck seams.

Selecting a welded roof ( rather than a bolted roof) will eliminate deck seam losses. For a typical internal roof that has 64 primary seals, secondary seals, and controlled fittings already,

eliminating deck seam losses will raise the control efficiency as much as 1.5 percent.

<IP_ADDRESS> Applicability. The applicability of any storage tank improvement in order to reduce VOC emissions is dependent upon the characteristics of the particular VOC. Since floating decks are often constructed primarily of aluminum, they may not be applicable to tanks storing halogenated compounds, pesticides, or other compounds that are incompatible with aluminum. Contact between these compounds and an aluminum deck could corrode the deck and cause product contamination.

In addition, vapor pressures may affect the selection of tank improvements as an applicable control technology. For chemicals with very low vapor pressure, fixed roof tank emissions will already be so low that installing an internal floating roof may not significantly reduce emissions further. For chemicals with vapor pressures up to 65 kPa ( 9.4 psia), emission reductions of 95 percent and above are achievable with this technology. Above this vapor pressure, achievable emission reduction starts to decrease with increasing vapor pressure. Thus, an internal floating roof may not be indicated for chemicals with relatively high vapor pressures. 1 4.2 DESCRIPTION OF MACT AND SUMMARY OF REGULATORY ALTERNATIVES The CAA requires that in designating regulatory options, the maximum degree of reduction in emissions that is deemed achievable shall be subject to a floor, which is determined differently for new and existing sources. For new sources, the standards must be set at levels which are not any less stringent than the emission control that is achieved in practice by the best controlled similar source. For existing sources, the standards may not be less stringent than the average emission limitation achieved by the best performing 12 percent of existing sources in each category or subcategory of 30 or more sources.

In determining whether the standard should be more stringent than the floor and by how much, EPA is to consider, among other 65 things, the cost of achieving such additional emission reductions. The options for achieving reductions at each emission point are presented separately in the following sections. The chosen option and any more stringent options are presented separately for each of the four emission points.

4.2.1 Miscellaneous Process Vents This section summarizes the MACT floors and chosen alternatives as they relate to miscellaneous process vents and how they were arrived at. The EPA evaluated the current level of control for miscellaneous process vents in eight State and two air districts that contain the majority of refineries and were expected to have the most stringent regulations. Of the refineries in the U. S., the 12 percent that are subject to the most stringent regulations are located in three States. In these three States, miscellaneous process vents emitting greater than 15 to 100 lb/ day ( 6.8 to 44.4 kg/ day) of VOC are required to be controlled. The median applicability cutoff level for the 12 percent of U. S. refineries subject to the most stringent regulations is 72 lb/ day ( 33 kg/ day) VOC. Thus, control of process vents with VOC emissions greater than 72 lb/ day is the MACT floor level of control for existing sources and is the standard for miscellaneous process vents. The primary organic HAPs at refineries are also VOC. Additionally, a VOC based applicability criteria is most reflective of the current level of control required for miscellaneous process vents as the majority of State regulations are expressed in terms of VOC. Therefore,

the EPA has adopted this emission level in the final rule to distinguish Group 1 from Group 2 vents. Group 1 vents, those that emit over 33 kg/ day, must be controlled, whereas Group 2 vents, representing all other vents, are not required to apply controls under the final rule. The applicability limit is determined as gases exit from process unit equipment and not downstream from an emission control device. The new source MACT floor also includes reduction of emissions from miscellaneous process vents with the same cut off. 66 4.2.2 Storage Vessels This section summarizes the MACT floors and chosen alternatives for storage vessels. The information that EPA used in determining the floor level of control for existing storage vessels consisted of the types of storage vessels, vessel capacities, existing controls on vessels, and true vapor pressures of stored liquids reported by refineries responding to survey questionnaires. EPA compared the baseline level of control on each storage vessel at each refinery with the storage vessel control requirements ( with the exception of fitting requirements for floating roof vessels) of subpart Kb of 40 CFR 60. Subpart Kb represents the best control technology for storage vessels. It requires either floating roofs with specified seals and fittings or closed vent systems and control devices.

Once the best performing 12 percent were identified, the average true vapor pressure of the stored liquids being controlled at these refineries was determined. The MACT floor level of control for existing sources is: vessels with capacities greater than or equal to 177 cubic meters ( 1,115 barrels or 47,000 gallons) storing liquids with true vapor pressures greater than or equal to 23 kilopascals ( kPa)

( 3.4 psia) must be controlled to the requirements of subpart Kb with the exception of the controlled fitting requirements for floating roof vessels. EPA determined, based on the available data, that an emission reduction more stringent than the level associated with the floor is not cost effective.

To determine the MACT floor for storage vessels at new sources, EPA reviewed other State and Federal storage vessel regulations. The MACT floor and an option more stringent than the floor requiring control of storage vessels with vapor pressures above 0.014 kPa ( 0.002 psia) ( which is the same as option 3 for existing sources) was also considered. The level of control for new sources is the MACT floor. Vessels with capacities greater than or equal to 151 m3 ( 950 barrels or 40,000 gallons) storing liquids with true vapor pressures greater than or equal to 3.4 kPa ( 0.5 psia), and vessels with capacities 67 greater than or equal to 76 m3 ( 475 barrels or 20,000 gallons)

storing liquids with vapor pressures equal to or greater than 77 kPa ( 11.1 psia) would be required to comply with the subpart Kb ( including the controlled fitting requirements). The option more stringent than the floor was not selected because it would result in high costs relative to HAP emission reductions.

4.2.3 Wastewater Streams This section summarizes the MACT floors and chosen alternatives for wastewater streams. The alternative selected is the floor level of control ( compliance with the Benzene Waste Operations NESHAP ( BWON)). The BWON controls 75 percent of the benzene in refinery wastewater and 76 percent of the volatile organic HAP in refinery wastewater. The best performing wastewater control systems are those that are in place to comply with the BWON. These systems control not only benzene, but also the other organic HAPs in petroleum refinery wastewater. The BWON controls 75 percent of the benzene in refinery wastewater nationwide and 76 percent of the volatile organic HAP in refinery wastewater. Benzene is an effective surrogate for indicating the presence of all HAP compounds in petroleum refinery wastewater because data show that the majority of the total HAP compound loading in wastewater consists of compounds that are very similar to benzene in terms of both chemical structure and volatility ( from the water phase to the air phase).

Because the final standard for wastewater requires compliance with the existing BWON, no additional emission reduction, cost,

energy, or other environmental or health impacts are associated with the standard. Based on data provided to the EPA through the BWON 90 day reports, the EPA determined that the BWON was applicable to 43 percent of the refineries. No refineries are known to have more stringent controls than the BWON. Therefore,

the MACT floor, or the average of the top performing 12 percent of sources, is control to the BWON level of control.

EPA also considered an alternative level of emission reduction more stringent than the MACT floor that would be achieved by controlling all wastewater streams with at least 10 ppmw benzene 68 at any refinery regardless of the size of its annual benzene loading. This alternative control option was not selected because the additional emission reduction achieved through further control was not significant, given the associated costs.

The floor alternative was selected as the promulgated level of control for new sources. As with existing sources, the option more stringent than the floor was considered, but was rejected for new sources for the same reason described above for existing sources.

4.2.4 Equipment Leaks The section summarizes the MACT floors and chosen alternatives for equipment leaks. The Petroleum Refinery NSPS requirements ( 40 CFR part 60 subpart VV) is the MACT floor for existing sources. In the final rule, EPA is providing each existing refinery with a choice of complying with either: 1) The Petroleum Refinery NSPS equipment leak requirements mentioned above or 2) a modified verison of the negotiated rule ( 40 CFR part 63 subpart H). The modified negotiated regulation is the same as what was contained in the proposed petroleum refinery NESHAP, except that the compliance dates have been extended.

Although not required in the final rule, the EPA promotes use of the modified negotiated rule option because it is believed to provide considerable product, emissions, and cost savings to a refinery.

Under either option, existing refineries will be required to implement an LDAR program with the same leak definitions ( 10,000 ppm) and the same leak frequencies as contained in the NSPS by 3 years after promulgation. A refinery may opt to remain at this level of control and do the monitoring, recordkeeping, and reporting specified in the NSPS. This option allows refineries that are familiar with the Petroleum Refinery NSPS to continue to implement that standard without needing to change their procedures.

Alternatively, a refinery may choose to comply with Phase I of the negotiated rule ( 10,000 ppm leak definition) 3 years after promulgation, comply with Phase II 4 years after promulgation, 69 and comply with Phase III 5 1/ 2 years after promulgation. Each phase has lower leak definitions for pumps and valves.

For new sources, EPA requires refinery sources to meet the same requirements as for existing sources.

4.2.5 Summary of Alternatives Based on the determination of the MACT floor for each of the four emission points, EPA selected a regulatory alternative.

Alternative 1, the regulatory alternative selected, incorporates MACT floor level control for wastewater streams, storage vessels,

and miscellaneous process vents, and the floor for equipment leaks. Table 4 1 presents a summary of the alternative examined in this analysis.

4.3 NO ADDITIONAL EPA REGULATION E. O. 12866 requires that the rationale for regulation versus no regulation must be addressed in the decision process. To satisfy this requirement, this section presents the alternatives to regulation of HAP emissions from petroleum refineries. The alternatives include reliance on the judicial system for pollution control, or reliance on regulation by States and localities.

4.3.1 Judicial System In the absence of governmental regulation, market systems fail to make the generators of pollution pay for the costs associated with that pollution. For an individual firm, pollution is an apparently unusable by product that can be disposed of cheaply by venting it to the atmosphere. However, in the atmosphere,

pollution causes real costs to others. The fact that producers,

consumers, and others whose activities result in air pollution do not bear the full costs of their actions leads to a divergence between private costs and social costs. This divergence is considered a market failure, since it results in a misallocation of society's resources. Too many resources are devoted to the polluting activity when polluters do not bear the full cost of their actions. TABLE 4 1. SUMMARY OF REGULATORY ALTERNATIVES BY EMISSION POINT Emission Point Alternati ve 1 Description of Control Option Equipment Leaks Option 1 Floor = Compliance with the petroleum refinery NSPS. Option 1 = Compliance with provisions in 40 CFR part 60 subpart VV of the Petroleum Refinery NSPS, or complying with a modified negotiated regulation for equipment leaks presented in 40 CFR part 63 subpart H ( HON equipment leaks).

Miscellaneous Vents MACT Floor Floor = Control to 20 ppmv of organic HAP or 98 percent reduction of HAP, or to reduce emissions using a flare meeting the requirements of section 63.11( b) of the NESHAP General Provisions ( 40 CFR part 63 subpart A), for Group 1 vents only.

Wastewater Streams MACT Floor Floor = Compliance with the BWON, only for Group 1 streams.

Storage Vessels MACT Floor Floor = Group 1 storage vessels only are required to put on one of the following control systems: 1) an internal floating roof ( IFR) with proper seals; 2) an external floating roof ( EFR)

with proper seals; 3) an EFR converted to an IFR with proper seals; or 4) a closed vent system with a 95 percent efficient control device. 71 Also, if there was no regulation, the previous regulations would be relied upon as the basis for making judicial decisions regarding excess emissions.

4.3.2 State and Local Action The CAA requires each State to develop and implement measures to attain and maintain EPA's standards. Each State assembles these measures in a document called the State Implementation Plan ( SIP). SIPs must be approved by EPA, and EPA is empowered to compel revision of plans it believes are inadequate. EPA may assume enforcement authority over air pollution control programs any State fails to implement. The standards will become parts of each State's SIP, and enforcement authority will be delegated to the States. If the EPA were not to promulgate the standards,

States would be responsible for making case by case MACT decisions under Section 112 ( g) and ( j) whenever there is a major modification, or when the date for MACT promulgation has passed without action on EPA's part.

EPA believes that reliance on State and local action is not a viable substitute for the standards. This belief holds even if EPA were to step up research and technology transfer programs to assist State and local governments.

4.4 ROLE OF COST EFFECTIVENESS IN CHOOSING AMONG REGULATORY ALTERNATIVES EPA has often used cost effectiveness ( C/ E) analysis as a guide for selecting among regulatory alternatives. Regulatory alternatives can sometimes be ranked based on stringency of control. All else equal, alternatives yielding the same level of control but higher average C/ E ( usually control cost per ton of pollutant reduced) could be eliminated from consideration.

Incremental C/ E can then be calculated for each step up the stringency ranking. The selection of a regulatory alternative could then be made by choosing the most stringent alternative below some agreed upon C/ E cutoff. The level of such a C/ E 72 cutoff would generally depend on the pollutant being controlled and other factors.

However, since the Petroleum Refinery NESHAP is to be a MACT standard, the role of C/ E analysis for selecting a regulatory alternative for this regulation is somewhat limited. A MACT floor level of control stringency is required regardless of the C/ E at this control level. At stringency levels beyond the MACT floor, cost effectiveness can be legally considered, and EPA believes cost effectiveness of controls is a primary consideration for evaluating stringency levels beyond the MACT floor. The average cost effectiveness of the regulation ($/ Mg of pollutant removed) is included as part of the cost analysis in Chapter 5.

4.5 ECONOMIC INCENTIVES: SUBSIDIES, FEES, AND MARKETABLE PERMITS Economic incentive strategies, when designed properly, act to harness the marketplace to work for the environment. In deciding among regulatory options, EPA is required to consider as options such strategies which influence, rather than dictate, producer and consumer behavior, in order to achieve environmental goals.

Economic incentive programs make environmental protection of economic interest to producers and consumers. When feasible,

properly designed systems can be employed to achieve any environmental goal at the least cost to society.

Several types or categories of economic incentive strategies exist. One broad category of incentive programs is based of the use of fees or subsidies. Fee programs establish and collect a fee on emissions, providing a direct economic incentive for emitters to decrease emissions to the point where the cost of abating emissions equals the fee. 3 Similarly, subsidy programs provide a direct incentive for emitters to decrease emissions by providing subsidy payments for emission reductions beyond some baseline.

A second broad category of economic incentive strategies is based on the concept of emissions trading. A wide range of 73 variations in emissions trading programs are possible. The common idea in such programs is to allow sources with low abatement cost alternatives to trade or sell emission allowances to sources with higher abatement cost alternatives so that the cost of meeting a given total level of abatement is minimized.

There are two important constraints regarding the workability of economic incentive programs. The first constraint concerns the problem of emissions monitoring. Without an effective emissions monitoring system it is not possible to charge fees or use other economic incentive strategies. Only the traditional " command and control" approach of requiring employment of specific control technologies is feasible in this circumstance.

The second problem constraining the potential value of economic incentive strategies is legal. Various legal restrictions imposed by the CAA limit the applicability of economic incentive strategies to reduce air pollution.

Legal constraints imposed by Title III of the Act severely limit the usefulness of economic incentive strategies for reducing HAP emissions. Title III requires the implementation of MACT. Thus sources have little or no choice as to the type or level of control they implement except perhaps if going beyond the MACT floor control level. As a limited economic incentive,

it may then be possible to impose, for example, an emissions fee on residual emissions after the MACT technology is employed to encourage additional control.

The applicability of economic incentive programs for the petroleum refinery NESHAP is therefore very limited. However,

emissions averaging at the facility level may be feasible and legal given that each facility is considered an emissions source.

This emissions averaging strategy allows facilities to trade emission reductions across emission points so as to minimize control costs for any given facility level emission reduction requirement. Thus, to this extent, an economic incentive strategy may be implemented for the Petroleum Refinery NESHAP regulation. The analysis of control costs ( Chapter 5) does not incorporate emission averaging. It is recognized that if emissions averaging were incorporated into the standard, 74 facilities' costs of control should fall. Thus, the costs calculated could be an overestimate. 75 REFERENCES 1. U. S. Environmental Protection Agency. Regulatory Impact Analysis for the National Emissions Standards for Hazardous Air Pollutants for Source Categories: Organic Hazardous Air Pollutants from the Synthetic Organic Chemical Manufacturing Industry and Seven Other Processes. EPA 450/ 3 92 009. pp. 4 1 to 4 41. December 1992.

2. U. S. Environmental Protection Agency. Office of Air Quality Planning and Standards. Draft Preamble for the HON. December 1993.

3. U. S. Environmental Protection Agency. Office of Air Quality Planning and Standards. Draft Preamble for the Petroleum Refinery NESHAP. January 1994.

4. Reference 2.

5. U. S. Environmental Protection Agency. Office of Air Quality Planning and Standards. Municipal Waste Landfills  Regulatory Impact Analysis. March 1991. 76 77 5.0 COST ANALYSIS AND EMISSION REDUCTION Section 5.1 of this chapter presents the methodology used to estimate the regulatory compliance costs for the option listed in Table 4 1. Section 5.2 presents total compliance costs by emission point, the corresponding emission reductions for each alternative, and discusses the cost effectiveness of controlling each of the four petroleum refinery emission points. Section 5.4 presents any cost categories not directly associated with a control technique, including monitoring, reporting, and recordkeeping costs.

5.1 APPROACH FOR ESTIMATING REGULATORY COMPLIANCE COSTS This section explains the methods used for estimating the emissions associated with petroleum refineries and the impact associated with controlling existing petroleum refinery emission sources using various alternative control technologies. These estimates are used to compare different control alternatives and select the provisions for the proposed NESHAP for petroleum refineries.

Emissions and control impacts were estimated for each of the four petroleum refinery emission points: storage vessels,

wastewater collection and treatment systems, equipment leaks, and miscellaneous process vents. The control impact estimates include estimates of emission reductions, control costs, and where applicable, energy impact. A qualitative assessment of the possible impact of secondary air pollution, water pollution, or solid waste generation is also included.

The emissions calculations involved three steps:

( 1) development of a database characterizing refineries,

( 2) development and assignment of scaling factors for each kind 78 of emission point to use for estimating emissions for refineries that provided no data, and ( 3) calculation of nationwide emissions and control impacts.

The database included the processes and technology used to produce refinery products and controls used to reduce emissions.

This information came from responses to survey questionnaires sent out under section 114 of the CAA and information collection requests. Refineries across the United States responded to the questionnaires and provided control and process information for process vents, storage vessels, wastewater treatment systems, and leaking equipment. In addition, information on existing regulations was compiled to determine the control requirements that apply to petroleum refineries.

Because site specific data were not available for every refinery, scaling factors relating refinery process parameters or emissions to the charge capacity of refinery processes were derived from the available data. Estimates of emissions and control impacts for refineries for which data were lacking were derived using scaling factors. Scaling factors could be used because the emission mechanisms and applicable control technologies are well understood for the kinds of sources to be regulated by the petroleum refinery NESHAP, and these characteristics are similar from refinery to refinery.

Baseline emissions represent emission levels from petroleum refineries that would occur in the absence of a refinery MACT standard. Baseline emissions were estimated using calculation algorithms based on known, previously published, well established methods from the process charge capacities of the refineries in the database and the data reported in the questionnaire responses. The impact of each alternative control level was estimated using previously developed cost algorithms and control efficiencies for commonly used control technologies. The control technologies included in the analysis were chosen because they can achieve emission reductions at least as stringent as the MACT floor. While the selected control technologies were used as the basis of the control impacts estimates, the promulgated standards 79 are written using formats that would allow use of other control technologies if the equivalent emission reduction is achieved.

The impact estimates are based on average, representative, or typical emissions and control requirements for each kind of source. Thus, the estimates do not reflect the impact that would be observed at any particular refinery. However, they do provide a reasonable estimate of nationwide emission reductions and represent the range of control costs that refineries might incur under different regulatory alternatives.

The specific procedures used to estimate baseline emissions and the costs and emission reductions for the different control alternatives for each kind of emission point are described separately for new and existing sources.

5.1.2 Calculations for Existing Sources For existing petroleum refinery sources, baseline emissions and control impacts were calculated for the four sources for individual refineries and aggregated to determine nationwide impacts. Some sources were not as well characterized as others.

In these cases, the available information was extrapolated to derive nationwide estimates.

<IP_ADDRESS> Storage Vessels. Emissions and emission reductions from storage vessels are a function of the volatility of the material stored and the type of storage vessel. Responses to questionnaires sent to refineries provided information on the volatility and HAP content of materials stored and the types of vessels used to store materials. Based on information in the questionnaire responses, factors for storage vessel population and VOC emissions were developed and used to estimate baseline emissions of HAPs and VOC, emission reductions at the floor level of control and above, and costs for controlling emissions to the floor level of control and to levels more stringent than the floor. Thirteen " major" petroleum liquids were included in this analysis: crude oil, gasoline, naphtha, asphalt, alkylate,

reformate, jet kerosene/ kerosene, heavy gas oil, aviation gasoline, diesel/ distillate, jet fuel (# 4), residual fuel oil,

and slop oil. In a previous analysis using all available 80 information, these 13 petroleum liquids accounted for more than 80 percent of the estimated nationwide baseline VOC emissions.

The storage vessel population factors were used to estimate the total number of vessels at each refinery. The storage vessels reported in the questionnaire responses were divided into groups based on storage vessel type ( e. g., fixed roof), refinery crude capacity ( greater than or less than 150,000 barrels per calendar day ( bbls/ cd)), and petroleum liquid stored ( e. g.,

gasoline, naphtha, etc.). The average number of vessels in each group per barrel of crude capacity at a refinery was the tank population factor. For example, the questionnaire responses indicated that the number of internal floating roof vessels storing gasoline at refineries with crude capacities greater than 150,000 bbls/ cd was 1.2 x 10  5 storage vessels per barrel of crude capacity per day. That is, a refinery of 267,000 barrels per day would have two internal floating roof tanks storing gasoline.

VOC emission factors were calculated for each storage vessel grouping. To calculate the VOC factor, VOC emissions from the storage vessels reported in the questionnaire responses were estimated using equations in chapter 12 of AP 42. Where data were missing or insufficient, default values, developed from information in the questionnaire responses, were used. Average VOC emission factors at the baseline level of control were then calculated for each vessel grouping. For example, for internal floating roof vessels storing gasoline at refineries with crude capacities greater than 150,000 bbls/ cd, an average VOC emission factor of 15,000 lbs VOC emitted/ vessel was calculated.

The number of vessels and the baseline VOC emissions nationwide were estimated in the following way. The crude capacity of each refinery in the nation, as listed in OGJ, was multiplied by the population factor for each applicable type of vessel to estimate the numbers and types of vessels at each refinery. This yielded the nationwide storage vessel population.

The baseline VOC emission factor ( lb VOC emitted/ vessel)

corresponding to each vessel type was multiplied by the number of vessels of that type to calculate the baseline VOC emissions at 81 each refinery. For example, for internal floating roof vessels storing gasoline at refineries with crude capacities greater than 150,000 bbls/ cd the refinery crude capacity, times the tank population factor of 1.2 x 10  5 vessels per barrel, times the VOC emission factor of 15,000 lb VOC emitted/ vessel yielded the estimated VOC emissions. Certain petroleum liquids ( e. g.,

asphalt, alkylate, and reformate) are directly associated with specific process units. If OGJ did not list capacities for these specific process units, then the vessel population factor corresponding to that process unit was not applied to that refinery. ( For more information, refer to " Summary of Nationwide Volatile Organic Compound and Hazardous Air Pollutant Emission Estimates from Petroleum Refineries," in the docket).

Emissions of HAPs were estimated by multiplying the VOC emissions calculated for each type of material stored by the average HAP weight fraction in the vapor phase of the material.

Average vapor phase HAP weight fractions were calculated from the HAP liquid concentrations ( obtained from industry questionnaire responses) using Raoult's Law and the vapor pressure of the individual HAPs.

Emission reductions and costs for control options were estimated using the extrapolated nationwide storage vessel population. For all control options, factors for average emission reduction and costs were developed by calculating specific emission reductions and costs for the 3,400 storage vessels reported in the questionnaire responses. Average emission reduction and cost factors were then calculated for each storage vessel group.

An analysis of refinery storage vessels indicated that the MACT floor level of control for existing sources is an internal floating roof with seals that comply with the NSPS for and with the hazardous organic NESHAP ( HON) storage. Costs were estimated for equipping existing fixed roof storage vessels with an internal floating roof and seals that comply with specifications in the storage NSPS ( 40 CFR 60 subpart Kb) and HON ( 40 CFR 63 subpart G). For existing external and internal floating roof vessels, costs were estimated for installing seals that comply with the proposed HON seal requirements. The MACT floor level of 82 control for existing floating roof storage vessels does not include complying with the fitting requirements in the proposed HON.

More stringent controls were not identified for existing fixed roof storage vessels. For existing external and internal floating roof vessels, the more stringent control alternative is to comply with the fitting requirements in the proposed HON in addition to the seal requirements.

The emission reduction assigned to each of the 3,400 storage vessels was calculated as a function of the emission reductions presented in the EPA publication " NSPS VOC Emissions from VOL Storage Tanks Background Information for Proposed Standards".

This document provided the emission reduction ( in percent) of various seal and fitting configurations compared with fixed roof vessels. For example, an internal floating roof vessel with a liquid mounted primary seal and controlled fittings has an average emission reduction of 96.2 percent over a similar sized fixed roof vessel. Adding a rim mounted secondary seal increases this emission reduction to 96.6 percent. Therefore, the incremental emission reduction gained by adding the rim mounted secondary seal is 0.4 percent. The emission reduction applied to each storage vessel was calculated as the difference between the level of control required by the control option and the baseline level of control.

The cost equations for converting existing fixed roof vessels to internal floating roof vessels were taken from the " Control of Volatile Organic Compound Emissions from Volatile Organic Liquid Storage in Floating and Fixed Roof Tanks" ( Draft, July 1992), and " Internal Instruction Manual for ESD Regulation Storage Tanks"

( January 1993). The cost equations for adding seals and controlled fittings to existing external and internal floating roof vessels were also taken from these two documents.

<IP_ADDRESS> Wastewater Collection and Treatment Systems.

Emissions and emission reductions from wastewater collection and treatment systems are both a function of wastewater stream flow,

the HAP compound concentration in the wastewater, and the volatility of the HAP compounds in the wastewater. Emission 83 reductions are also a function of the design and operating parameters of the control device.

EPA gathered data for the wastewater stream flow rate and the concentration of HAPs in petroleum refinery wastewater to develop models of wastewater from process units found at refineries.

Each model process unit was assigned representative values for the concentration and volatility of the HAPs in its wastewater stream. A ratio of wastewater stream flow to refinery crude capacity was also developed for each model process unit and applied to the capacities reported in OGJ for each process unit at each refinery. ( For more information, refer to " Data Summary for Petroleum Refinery Wastewater," in the docket). Mass loadings of volatile HAP in wastewater were determined by multiplying volatile HAP concentrations by capacity based wastewater stream flow rates for each process unit at each refinery in the nation. The results of prior EPA analyses developed for the HON were judged to be appropriate to use to estimate the cumulative mass fraction of HAPs emitted from wastewater collection and treatment systems.

Uncontrolled emissions were determined by multiplying the mass fraction of HAPs emitted by the mass loading of volatile HAPs.

However, many petroleum refineries control their wastewater collection and treatment systems in accordance with the BWON.

( For more information, refer to " The Effectiveness of the BWON in Controlling Volatile HAP Mass Loading in Petroleum Refinery Wastewater," in the docket). These controls were credited in the national baseline emissions calculations by applying the applicability criteria of the BWON ( i. e., wastewater streams with flows greater than 0.02 l/ min and benzene concentration of 10 ppmw or greater at a facility with at least 10 Mg/ yr total annual benzene loading in wastes and wastewater) to each refinery and wastewater stream and by assuming that the control requirements of the BWON ( i. e., 99 percent reduction of benzene)

were met for those streams requiring control.

An analysis of existing refinery wastewater collection and treatment systems indicated that the MACT floor for wastewater is 84 the BWON. ( For more information, refer to [" Maximum Achievable Control Technology Floor for Process Wastewater Streams at Petroleum Refineries,"] in the docket). Existing refineries are already required to comply with the BWON, so no emission reductions or costs would be associated with the floor option for refinery wastewater sources. In considering a control option more stringent than the BWON, the EPA assessed the effects of lowering the applicability threshold of the BWON, by eliminating the cutoff of 10 Mg/ yr TAB loading in facility wastes and wastewater. The additional wastewater streams requiring control ( those streams with at least 10 ppmw benzene at refineries with a TAB under the 10 Mg/ yr loading criterion) were assumed to be steam stripped to achieve reductions equivalent to the requirements of the BWON ( e. g., 99 percent reduction of benzene).

The overheads from the steam stripper were assumed to be sent to a combustion device. ( For more information, refer to [" Control Option Above the Floor for Petroleum Refinery Process Wastewater,"] in the docket). The results of prior EPA analyses were used to estimate the mass fraction of HAPs removed from a wastewater stream by a steam stripper as well as the costs associated with the stripper system. ( For more information,

refer to " Steam Stripper Removals and Costing for Petroleum Refinery Wastewater," in the docket). The results of those analyses indicate that the selected steam stripper design and operating parameters achieve a 95 to 99 percent removal,

depending on the volatility of the HAPs in the stream.

<IP_ADDRESS> Equipment Leaks. Emissions and emission reductions from leaking equipment are a function of the component counts and the control program used to reduce emissions. The questionnaires were designed to obtain equipment leak information for 18 different refinery process units because the controls required may vary from process unit to process unit. The questionnaire responses included information on component counts, the HAP content of refinery process streams, and the monitoring frequencies and leak definitions used for leak detection and repair programs for each refinery process unit. The monitoring frequencies and leak definitions reported for each process unit 85 were matched to the requirements of existing LDAR programs to determine which control program was being used to reduce emissions.

Data on equipment leaks were reported by approximately 70 percent of the refineries in the nation. For those refineries not reporting information, the characteristics of model process units ( for each of the 18 process units of interest) were assigned to the refinery based on information in OGJ. The model process units were developed as the median component count of the process units from refineries reporting information in the surveys. If OGJ data indicated that a refinery contained a specific process unit, then the median counts for the model representing that process unit was assigned to the refinery. If the refinery was determined to be in an ozone nonattainment area,

the EPA assumed that the refinery would be controlled to the level of control in the petroleum refinery CTG.

Uncontrolled HAP emissions from each of the 18 different refinery process units were estimated by multiplying the uncontrolled VOC emissions from each unit by the average HAP to VOC ratio of the streams associated with each unit.

Uncontrolled VOC emissions from leaking equipment were estimated on a process unit basis by multiplying the component counts for the process unit by VOC emission factors for each equipment component. The VOC emission factors relate VOC emissions to the type of component leaking ( e. g., pumps, valves, etc.) in units of lb/ hr/ component type. The emission factors used for the impacts analysis were taken from a previous EPA study on leaking refinery equipment and presented in chapter 9 of AP 42. These emission factors are currently being reviewed by EPA based on new industry data. The emission estimates may be revised at promulgation if new factors are developed by EPA based on the new industry data.

Baseline emissions of HAPs and VOC were estimated by multiplying the uncontrolled emissions by one minus the control efficiencies associated with each LDAR program reported by or assigned to each refinery. The " Equipment Leaks Enabling Document" ( in the docket) provides information on the control efficiencies that may be achieved by monitoring components under 86 various LDAR programs. ( For more information, refer to " Summary of Nationwide Volatile Organic Compound and Hazardous Air Pollutant Emission Estimates from Petroleum Refineries," in the docket).

An analysis of existing controls on refinery equipment leaks indicated that the MACT floor level of control for refinery equipment leaks was the control required by the Petroleum Refinery NSPS. For more information refer to [" Maximum Achievable Control Technology Floor for Equipment Leaks at Petroleum Refineries," in the docket]. Two more stringent control options were also analyzed: ( 1) compliance with the negotiated equipment leaks regulation included in the HON,

without the monitoring requirements for connectors, and ( 2) compliance with the negotiated equipment leaks regulation included in the HON. Each of these options requires specific leak monitoring frequencies for components and control devices.

Emission reductions for controlling leaking equipment to the level of control required by the NSPS and the two more stringent options were calculated from the difference between baseline emissions and the emissions calculated using the percent reductions associated with the petroleum refinery NSPS and the HON equipment leaks negotiated rule. Similarly, the cost impact of controlling leaking equipment to the level required by the NSPS and the two more stringent control options was calculated from the cost of control devices and labor associated with the petroleum refinery NSPS and the negotiated rule. The cost methodology was based on procedures provided in the " Equipment Leaks Enabling Document." ( For more information, refer to [" Costs for the MACT Floor Level of Control and Control Options Above the Floor for Controlling Emissions from Leaking Refinery Equipment,"] in the docket).

<IP_ADDRESS> Miscellaneous Process Vents. The miscellaneous process vent group includes most miscellaneous process vents that emit organic HAPs at refineries other than FCCU catalyst regeneration vents, catalyst reformer catalyst regeneration vents, and sulfur plant vents. The baseline HAP emissions from miscellaneous process vents were estimated by multiplying HAP 87 emission factors by the charge capacities of refinery processes.

Specific HAP emission factors were developed by dividing the HAP emissions reported in questionnaire responses by the charge capacities of those refineries reporting the specific HAP. ( For further information, refer to " Summary of Nationwide Volatile Organic Compound and Hazardous Air Pollutant Emission Estimates from Petroleum Refineries," in the docket).

The MACT floor level of control for these vents was combustion. EPA has determined that combustion of emissions can achieve 98 percent organic HAP reduction, so emission reductions were calculated by applying this percent reduction to emissions from miscellaneous process vents that are uncontrolled at baseline. The cost for controlling emissions from miscellaneous vents includes the cost for piping emissions to existing control devices and an additional compressor for the refinery. EPA assumed that refineries would already have an existing fuel gas or flare system that could be used to reduce emissions from miscellaneous process vents. Further information on costing procedures and specific assumptions is contained in " Costing Methodology for Controlling Emissions for Miscellaneous Process Vents," in the docket.

5.1.3 Calculations for New Sources This section explains the methodology used for estimating emissions and control impacts in the first 5 years after the promulgation of this rule. These costs represent control of new process units and equipment built within the first 5 years after promulgation. It should be noted for regulatory purposes, that some of these units and equipment will be considered " new sources" and others will be considered part of an " existing source". It is not possible to determine how many new units will fall into each of these categories; however, controls will be required for the emission points in either case.

Costs for controlling new process units were estimated from the costs calculated for existing sources and the number of new process units that are expected to be constructed in the 5 year period after the standard is enacted. The costs for applying control technologies to existing sources were calculated as 88 previously described. The results are documented in the four memoranda presenting cost impacts ( in the docket). The cost information was scaled up to account for new emission points that may need to be controlled in the first 5 years after the petroleum refinery NESHAP has been promulgated. Reductions of emissions of HAPs and VOC from controlling existing emission points were also presented in the costing memorandum. The emission reduction information was scaled up to account for controls on new emission points using the same methodology that was used to scale up cost data. ( For further information, refer to " Estimation of Annual Costs for New Petroleum Refinery Emission Points in the Fifth Year After Promulgation," in the docket).

OGJ provided estimates of annual refinery construction projects. This information was used to determine an average number of process units constructed in a year.

<IP_ADDRESS> Storage Vessels. The MACT floor for storage vessels at new sources is application of seals and fittings equivalent to those required by 40 CFR 60 subpart Kb ( the NSPS for VOL storage)

to storage vessels larger than 151 m3 ( 947 bbl) with vapor pressures above 3.5 kPa ( 0.50 psia). ( These seals and fittings are the same as those required by the HON.) The petroleum refinery NESHAP would result in no costs or emission reductions for those storage vessels required to comply with subpart Kb ( all new vessels with a capacity greater than or equal to 40 m 3 or 250 bbl). This methodology may overestimate the impact of the regulation in the 5 years after promulgation because, as previously stated, many vessels constructed in that period may be considered part of existing sources for regulatory purposes.

Because the requirements for existing sources are equivalent to the NSPS, there will be no costs or emission reductions for existing storage vessels. Therefore, the fifth year impacts on vessels at new sources would be lower than the impact estimated here because the number of vessels at new sources is probably overestimated.

<IP_ADDRESS> Wastewater Collection and Treatment Systems. A MACT floor analysis performed on wastewater collection and treatment 89 systems indicated that the MACT floor level of control for wastewater streams at new sources is compliance with the BWON.

Therefore, no costs are anticipated for sources built in the 5 years after promulgation to reach the MACT floor level of control. The control option more stringent than the floor that was considered was the same as the option considered for existing sources: assessing the effects of lowering the applicability threshold of the BWON by eliminating the cutoff of 10 Mg/ yr TAB loading in facility wastes and wastewater.

The average annual number of newly constructed process units that will generate wastewater is expected to be approximately 34.

The distribution of these new units across refinery processes was based on OGJ data. ( For more information, refer to the docket).

Using the same approach for applying controls and estimating costs for new sources as for existing sources, costs for the newly constructed units were estimated. The total estimated capital investment for controls by the fifth year ( considering 34 new units per year over the 5 year period) would be approximately $ 42 million. The total annual cost to be expended in the fifth year ( considering all 170 new units) would be approximately $ 18 million per year.

<IP_ADDRESS> Equipment Leaks. OGJ provides annual construction projects in petroleum refineries and expected dates of completion. This information, for a 5 year period from 1988 to 1992, was used to develop an average count of new construction projects 5 years after promulgation of the refinery NESHAP. From this information, it was determined that an average of 34 process units would be built annually. Each of these process units is expected to require control under the NSPS for refineries.

Therefore, the only cost associated with controlling these units is the extra cost required to go from the NSPS control requirements ( the MACT floor for equipment leaks at new sources)

to the two options more stringent than floor. The two options are the same as for existing sources: ( 1) the negotiated regulation for equipment leaks in the HON ( 40 CFR 63 subpart H)

without the monitoring requirements for connectors and ( 2) the HON negotiated regulation. 90 The average capital investment cost and annual cost of upgrading from the NSPS to the HON negotiated regulation without connector monitoring were determined to be $ 20,000 and $ 7,000/ yr per process unit, respectively. The average capital investment and annual cost of upgrading from the NSPS to the HON negotiated regulation were determined to be $ 17,000 and $ 6,200/ yr per process unit, respectively. For each option, the capital investment cost and average annual cost for controlling the 34 process units constructed each year was calculated by multiplying the average cost per process unit by the number of new process units.

<IP_ADDRESS> Miscellaneous Process Vents. The MACT floor level of control for miscellaneous process vents at new sources was determined to be combustion. The annual cost for controlling emissions from miscellaneous vents consisted the cost for piping to an existing combustion system ( to a flare or to the fuel gas system) and for an additional compressor for each refinery. The average capital cost for piping for each vent and a compressor for each refinery was determined to be $ 9,910 and $ 66,100,

respectively, and the average annual cost of piping for each vent and compressor for each refinery was determined to be $ 2,170 and $ 37,800, respectively.

As previously stated, the average annual number of newly constructed process units is expected to be 34. The number of miscellaneous vents requiring control was calculated from the average number of uncontrolled vents per process unit, as presented in the baseline emissions estimation memorandum ( refer to docket). Based on this information, one vent for each of the 34 process units is estimated to require control ( that is, a total of 34 new vents will require control each year). This number of vents per year was multiplied by the average cost per vent to estimate national costs for miscellaneous process vents for process units constructed in the 5 years after promulgation of this rule.

5.2 TOTAL COMPLIANCE COST ESTIMATES, REDUCTIONS, AND COST EFFECTIVENESS 91 The annualized compliance costs by emission point are shown in Table 5 1 for the chosen alternative. The total national cost of Alternative 1 in the fifth year is $ 79 million. Table 5 2 presents the costs, HAP emission reductions, and cost effectiveness for the control options by emission point. The average cost effectiveness of the regulation ($/ Mg of pollutant removed) is determined by dividing the annual cost by the annual emission reduction. Table 5 3 presents a summary of the HAP emission reductions, total cost, and cost effectiveness values for the chosen regulatory alternatives. The emission reductions associated with the alternatives in Table 5 3 were calculated by summing the HAP emission reductions listed in Table 5 2 for the control option chosen at each emission point. The annual costs are as reported in Table 5 1, and the cost effectiveness values were calculated as described above. The incremental cost effectiveness represents the increase in cost from Alternative 1 to Alternative 2 divided by the increased HAP emission reduction.

Table 5 4 reports similar information for VOC emissions. TABLE 5 1. SUMMARY OF TOTAL ANNUAL COSTS IN THE FIFTH YEAR FOR THE PETROLEUM REFINING NESHAP Annual Fifth Year Costs ( 1000$/ yr) 3 ( 1992 Dollars)

Emission Point Option Existing Sources New Construction Total Alternative 1 Equipment Leaks Miscellaneous Process Vents Wastewater Systems Storage Vessels Floor Option 11 Floor2 Floor1 Floor1 $ 69,000 $ 58,000 $ 12,000 $ 0 $ 8,000 $ 0 $( 210)

$ 370 $ 0 $ 98 $ 69,000 $ 57,790 $ 12,370 $ 0 $ 8,098 $ 65,790 $ 11,370 $ 0 $ 3,798 Other Recordkeeping and Reporting TOTAL COST $ 1,000 $ 79,190 NOTES: 1Alternative 1.

2EPA did not choose an option above the MACT floor for miscellaneous process vents.

3Costs are in 1992 dollars. TABLE 5 2. CONTROL OPTIONS AND IMPACTS BY EMISSION POINT HAP Cost Effectiveness ($/ Mg HAP)

Emission Point Baseline HAP Emissions ( Mg/ yr) Control Option Emission Reductio n ( Mg/ yr) Percent Emission Reduction Annual Cost ($ 1,000/

yr) b Average Incrementa l Miscellaneous Process Vents Existing Sources 8,900 Floor* 7,600 85 $ 11,000 $ 1,500 N/ A New Sourcesa 900 Floor* 770 85 $ 370 $ 480 N/ A Storage Vessels Existing Sources 9,000 Floor* 670 7 $ 3,700 $ 5,500 N/ A Option 1 1,300 14 $ 6,200 $ 4,800 $ 4,000 Option 2 1,800 20 $ 8,400 $ 4,700 $ 4,400 Option 3 2,600 29 $ 32,000 $ 12,000 $ 30,000 New Sourcesa 290 Floor* 4 1.4 $ 98 $ 24,000 N/ A Option 1 14 4.8 $ 550 $ 39,000 $ 45,000 Wastewater Systems Existing Sources 9,200 Floor* 0 N/ A 0 N/ A N/ A Option 1 7,700 93 $ 120,000 $ 15,000 $ 15,000 New Sourcesa 960 Floor* 0 N/ A 0 N/ A N/ A Option 1 930 97 $ 18,000 $ 20,000 $ 20,000 Equipment Leaks Existing Sources 50,000 Floor 35,000 69 $ 69,000 $ 2,000 N/ A Option 1* 44,000 87 $ 58,000 $ 1,500 $( 330)

Option 2 46,000 91 $ 78,000 $ 1,700 $ 6,000 New Sources 1,300 Floor 0 0 0 0 0 Option 1* 640 49 $( 210) $( 330) $( 330)

Option 2 760 59 $ 840 $ 1,100 $ 8,300 94 NOTES: 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 while others may be considered part of an existing source.

bThe costs for monitoring, recordkeeping, and reporting ( MRR) requirements are not available on an emission point basis. The costs in this table reflect costs for operation and maintenance of control equipment only.

N/ A = Not applicable.

Brackets indicate negative values.

* = Control option chosen for preferred alternative. 95 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 Averag e Increment al Alternative 1 48,000 $ 79.0 $ 1,645 N/ A NOTES: N/ A = Not applicable. 1Cost estimates do include costs associated with monitoring, recordkeeping, and reporting requirements.

TABLE 5 4. COST, VOC EMISSION REDUCTION, AND COST EFFECTIVENESS BY ALTERNATIVE Cost Effectiveness VOC Emission Annual Cost ($/ Mg) Regulatory Alternative Reduction ( Mg/ Yr) 1 ( Million $, 1992) 2 Averag e Increment al Alternative 1 252,000 $ 79.0 $ 313 N/ A NOTES: N/ A = Not applicable. 1Emission reduction estimates do not incorporate reductions occurring at new sources. 96 5.3 MONITORING, RECORDKEEPING, AND REPORTING COSTS In addition to provisions for the installation of control equipment, the promulgated regulation includes provisions for MRR. EPA estimates that the total annual cost for refineries to comply with the MRR requirements is $ 21 million. After incorporating MRR costs, the total cost of compliance of Alternative 1 is $ 79 million. For Alternative 1, the incorporation of MRR costs into total annual cost results in an average cost effectiveness of $ 313 for each megagram of VOC reduced and $ 1,645 for each megagram of HAP reduced.

In order to calculate the costs of MRR associated with the petroleum refinery NESHAP, estimates of hours per item ( i. e., a required MRR action), frequency of required action per year, and number of respondents ( i. e., total number of individuals required to submit compliance reports) were estimated based on the requirements in the proposed rule for all of the emission points.

To compute the costs associated with the burden estimates, a wage rate of $ 32 per hour ( in 1992 dollars) was assumed. This assumption was based on an estimate that 85 percent of the labor will be accomplished by technical personnel ( typically by an engineer with a wage rate of $ 33 per hour), 10 percent will be completed by a manager ( at $ 49 per hour), and 5 percent by clerical personnel ( at $ 15 per hour). All of the wage rates include an additional 110 percent for overhead. Costs were annualized assuming an expected remaining life for affected facilities of 15 years from the date of promulgation of the subject NESHAP, and using an interest rate of 7 percent.

Compliance requirements vary in terms of frequency. This variance is taken into account in the annualization of costs.

Performance tests to demonstrate compliance with the control device requirements are required once. Compliance requirements also include monitoring of operating parameters of control devices and records of work practice and other inspections.

These activities must be reported semiannually. The compliance requirements that must be met only once are annualized over the time from the year in which they are to take place to the expected end of facility life. 97 The MRR requirements are outlined separately in the regulation for each emission point. The compliance determination provisions for storage vessels include inspections of vessels and roof seals. If a closed vent system and control device is used for venting emissions from storage vessels, the owner must establish appropriate monitoring procedures. For wastewater stream and treatment operations, the MRR requirements are outlined in the rule for the BWON.

For miscellaneous process vents, the promulgated standard specifies the performance tests, monitoring requirements, and test methods necessary to determine whether a miscellaneous process vent stream is required to apply control devices and to demonstrate that the allowed emission levels are achieved when controls are applied. The format of these requirements, as with the format of the miscellaneous process vent provisions, depends on the control device selected. The MRR requirements for miscellaneous process vents are summarized by control device in Table 5 5.

For equipment leaks, because the provisions of the proposed rule are work practice and equipment standards, monitoring,

repairing leaks, and maintaining the required records constitutes compliance with the rule. The HON equipment leak provisions are appropriate to determine continuous compliance with the petroleum refinery equipment leak standards. In summary, these provisions require periodic monitoring with a portable hydrocarbon detector to determine if equipment is leaking. TABLE 5 5. MISCELLANEOUS PROCESS VENTS C 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 Control Device Parameters to be Monitoreda Recordkeeping and Reporting Requirements for Monitored Parameters Thermal Incinerator Firebox temperatureb [ 63.644( a)( 1)( i)] 1. Continuous recordsc 2. Record and report the firebox temperature averaged over the full period of the performance test  NCSd 3. Record the daily average firebox temperature for each operating daye 4. Report all daily average temperatures that are outside the range established in the NCS or operating permit and all operating days when insufficient monitoring data are collectedf  PRg Catalytic Incinerator Temperature upstream and downstream of the catalyst bed [ 63.644( a)( 1)( ii)] 1. Continuous records 2. Record and report the upstream and downstream temperatures and the temperature difference across the catalyst bed averaged over the full period of the performance test  NCS 3. Record the daily average upstream temperature and temperature difference across catalyst bed for each operating daye 4. Report all daily average upstream temperatures that are outside the range established in the NCS or operating permit

PR TABLE 5 5 ( continued).

Control Device Parameters to be Monitoreda Recordkeeping and Reporting Requirements for Monitored Parameters 5. Report all daily average temperature differences across the catalyst bed that are outside the range established in the NCS or operating permit  PR 6. Report all operating days when insufficient monitoring data are collectedf Boiler or Process Heater with a design heat input capacity less than 44 megawatts and Vent Stream is not introduced with or as the primary fuelh, i Firebox temperatureb [ 63.644( a)( 4)] 1. Continuous records 2. Record and report the firebox temperature averaged over the full period of the performance test  NCS 3. Record the daily average firebox temperature for each operating daye 4. Report all daily average firebox temperatures that are outside the range established in the NCS or operating permit and all operating days when insufficient monitoring data are collectedf  PR TABLE 5 5 ( continued).

Control Device Parameters to be Monitoreda Recordkeeping and Reporting Requirements for Monitored Parameters Flare Presence of a flame at the pilot light [ 63.644( a)( 2)] 1. Hourly records of whether the monitor was continuously operating and whether the pilot flame was continuously present during each hour 2. Record and report the presence of a flame at the pilot light over the full period of the compliance determination  NCS 3. Record the times and durations of all periods when a pilot flame is absent or the monitor is not operating 4. Report the times and durations of all periods when all pilot flames of a flare are absent

PRAll Control DevicesPresence of flow diverted to the atmosphere from the control device [ 63.644( c)( 1)] or1. Hourly records of whether the flow indicator was operating and whether flow was detected at any time during each hour.

2. Record and report the times and durations of all periods when the vent stream is diverted through a bypass line or the monitor is not operating  PRMonthly inspections of sealed valves [ 63.644( c)( 2)] 1. Records that monthly inspections were performed 2. Record and report all monthly inspections Control Device Parameters to be Monitoreda Recordkeeping and Reporting Requirements for Monitored Parameters NOTES: aRegulatory citations are listed in brackets.

bMonitor may be installed in the firebox or in the ductwork immediately downstream of the firebox before any substantial heat exchange is encountered.

c" Continuous records" is defined in § 63.641 of this subpart.

dNCS = Notification of Compliance Status described in § 63.652( e) of this subpart.

eThe daily average is the average of all recorded parameter values for the operating day. If all recorded values during an operating day are within the range established in the NCS or operating permit, a statement to this effect can be recorded instead of the daily average.

fWhen a period of excess emission is caused by insufficient monitoring data, as described in § 63.552( f)( 3)( i)( C) of this subpart, the duration of the period when monitoring data were not collected shall be included in the Periodic Report.

gPR = Periodic Reports described in § 63.652( f) of this subpart.

hNo monitoring is required for boilers and process heaters with heat input capacities > 44 megawatts or for boilers and process heaters where the vent stream is introduced 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 gas systems are not regulated under this subpart. No monitoring, recordkeeping, or reporting is required for boilers and process heaters that combust refinery fuel gas. 102 103 6.0 ECONOMIC IMPACTS AND SOCIAL COSTS The goal of the RIA is to evaluate the potential benefits and costs of specific pollution control standards on our nation's economy. Potential regulatory benefits relate to reduced HAP and VOC emissions that have detrimental effects on the health and well being of members of society. Social costs associated with the regulation are those costs borne by consumers and producers of refined petroleum products and by society at large as a result of the proposed standards. A comparison of the costs and benefits or net benefits ( social benefits less social costs) of alternative control measures serves as a basis for rational and effective environmental policymaking.

The emission control measures considered in this analysis will require domestic petroleum refineries to incur increased investment costs for control equipment and the associated annual operation and maintenance expenses. Increased costs of production may impact the domestic petroleum refining market in a number of ways. Primary market impacts resulting from the control measures include increases in the market equilibrium price for refined petroleum products, decreases in output levels for products produced and sold nationally, changes in the value of domestic shipments or revenues for refineries in the industry,

and possible plant closures. Predicted changes in the market equilibrium price and quantity of refined petroleum products produced and sold will result in additional market modifications or secondary market impacts. The secondary effects relate to the likely labor market adjustments ( job losses), energy input market changes ( decrease in the energy used as an input in the production of petroleum products) and foreign trade effects ( decrease in net exports). Control measures may also have a 104 detrimental influence on the capital availability and financial position of firms in the petroleum refining industry. Welfare changes for consumers, producers, and society at large or the social costs of the proposed emission controls will also be evaluated. Additionally, the Regulatory Flexibility Act ( RFA)

requires that an assessment be made of the effect of control measures on small entities.

This chapter will briefly describe the methods used to estimate the primary impacts, secondary effects, and small business impacts of the emission controls on the petroleum refining industry. A more detailed description of the methods used in the analysis is available in the Economic Impact Analysis of the Petroleum Refinery NESHAP ( 1994). A profile of the petroleum refining industry, the primary market impacts, capital availability consequences, secondary market impacts, small business impacts, and social costs of the control measures will be presented in this chapter.

6.1 PROFILE OF THE PETROLEUM REFINING INDUSTRY The petroleum industry can be divided into five distinct sectors: ( 1) exploration, ( 2) production, ( 3) refining, ( 4)

transportation, and ( 5) marketing. Refining, the process subject to this NESHAP, is the process which converts crude oil into useful fuels and other products for consumers and industrial users. The Standard Industrial Classification ( SIC) code for all petroleum refineries is 2911. Although petroleum refineries produce a diverse slate of products, the five primary output categories are ( 1) motor gasoline, ( 2) jet fuel, ( 3) residual fuel, ( 4) distillate fuel, and ( 5) liquefied petroleum gases ( LPGs), which in total accounted for 93 percent of all domestically refined petroleum products in 1992. This analysis is concerned only with these five main product categories.

It should be noted that the economic impact analysis reflects the compliance costs from the proposal. Thus the actual impacts are smaller than estimated here, though only by a minor amount. 105 A brief overview of the petroleum refining industry is presented in this section. Economic and financial data which characterize conditions in the refining industry and that are likely to influence the economic impacts associated with the implementation of the alternative NESHAPs are discussed. The information in this section represents the data inputs to the economic model used in the EIA. More details concerning the industry are provided in the Economic Impact Analysis of the Petroleum Refinery NESHAP ( 1995) and Industry Profile of the Petroleum Refinery NESHAP ( 1993).

6.1.1 Profile of Affected Facilities A brief description of the facilities affected by the proposed emission controls is presented in this section. The processes and product market characteristics of the petroleum refining industry are discussed. Refineries subject to the regulations are identified by geographical location, capacity, and complexity.

<IP_ADDRESS> General Process Description. The refining process transforms crude oil into a wide range of petroleum products which have a variety of applications. The refining industry has developed a complex variety of production processes used to transform crude oil into its various final forms, many of which are already subject to some CAA controls.

There are numerous refinery processes from which HAP emissions occur. Separation processes ( such as atmospheric distillation and vacuum distillation), breakdown processes ( thermal cracking,

coking, visbreaking), change processes ( catalytic reforming,

isomerization), and buildup processes ( alkylation and polymerization) all have the potential to emit HAPs. HAP emissions may occur through process vents, equipment leaks, or from evaporation from storage tanks or wastewater streams. The NESHAP will address emissions from all of these refinery emission points.

<IP_ADDRESS> Product Description and Differentiation. Most petroleum refinery output consists of motor gasoline and other types of fuel, but some non fuel uses exist, such as 106 petrochemical feedstocks, waxes, and lubricants. The output of each refinery is a function of its crude oil feedstock and its preferred petroleum product slate.

Motor gasoline is defined as a complex mixture of relatively volatile hydrocarbons that has been blended to form a fuel suitable for use in spark ignition engines. Residual fuel oil is a heavy oil which remains after the distillate fuel oils and lighter hydrocarbons are distilled away in refinery operations.

Uses include fuel for steam powered ships, commercial and industrial heating, and electricity generation. Distillate fuel oil is a general classification for one of the petroleum fractions produced in conventional distillation operations. It is used primarily for space heating, on and off highway diesel engine fuel ( including railroad engine fuel and fuel for agricultural machinery), and electric power generation. Jet fuel is a low freezing point distillate of the kerosene type used primarily for turbojet and turboprop aircraft engines. LPGs are defined as ethane, propane, butane, and isobutane produced at refineries.

Product differentiation is a form of non price competition used by firms to target or protect a specific market. The extent to which product differentiation is effective depends on the nature of the product. The more homogenous the overall industry output, the less effective differentiation by individual firms becomes. Each of the five petroleum products in this analysis are by nature quite homogenous C there is little difference between Exxon premium gasoline and Shell premium gasoline C and,

as a result, differentiation does not play a major role in the competitiveness among petroleum refineries.

<IP_ADDRESS> Distinct Market Characteristics. The markets for refined petroleum products vary by geographic location. Regional markets may differ due to the quality of crude supplied or the local product demand. Some smaller refineries which produce only one product have single, local markets, while larger, more complex refineries have extensive distribution systems and sell their output in several different regional markets. In addition, 107 because refineries are the source of non hydrocarbon 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 in some locations. Differences in the regional market structure may also result in different import/ export characteristics.

The United States is segmented into five regions, called Petroleum Administration for Defense Districts ( PADDs), for which statistics are maintained. PADDs were initiated in the 1940s for the purpose of dividing the United States into five economically and geographically distinct regions. Relatively independent markets for petroleum products exist in each PADD.

In addition to differences in regional markets, each of the five product categories in this analysis possesses its own individual market segment, satisfying demand among different enduse sectors. The substitutability of one of the products C motor gasoline, for example C is not possible with another refinery output, such as jet fuel. Thus, each of the products in this analysis is treated as a separate product with its own share of the market. From a refinery standpoint, however, if the production of one refined product were to become less costly after regulation, production of this product may increase at the expense of a product with a more costly refining process.

<IP_ADDRESS> Affected Refineries and Employment. There are currently 192 operable petroleum refineries in the United States. 1 Though refineries differ in capacity and complexity,

almost all refineries have some atmospheric distillation capacity and additional downstream charge capacity. Most of the employment in the industry exists at larger refineries. Slightly fewer than 4 percent of refinery employees work in establishments of fewer than 100 people, and the remaining 96 percent of the labor force in the industry works at establishments of 100 employees or more.

<IP_ADDRESS> Capacity and Capacity Utilization. Refineries have many different specialties, targeted product slates, and capabilities. Some refineries produce output only by processing crude oil through basic atmospheric distillation. These 108 refineries have very little ability to alter their product yields and are deemed to have low complexity. In contrast, refineries that have assorted downstream processing units can substantially improve their control over yields, and thus have a higher level of complexity. Because of their differences in size and complexity, refineries can be grouped by two main structural features: ( 1) atmospheric distillation capacity ( which denotes their size) and ( 2) process complexity ( which characterizes the type of products a refinery is capable of producing).

Capacity utilization rates of petroleum refineries have been rising in recent years, reaching a high of 92 percent in 1991.2 This indicates that existing refineries are operating closer to full capacity than in the past, and will have limited opportunity to enhance production by increasing utilization.

During the past 23 years, the entire domestic refining industry has been affected by crude oil quantity changes and shifting petroleum demand patterns. A more complex and flexible refining industry has evolved domestically. Ownership of U. S.

refineries has changed through consolidation and foreign investments. Throughout the 1970s, the number of U. S. refineries rose rapidly in response to rising demand for petroleum products.

In the early 1980s, the petroleum refining industry entered a period of restructuring, which continued through 1992. A record number of U. S. refineries were operating in 1981. A decline in petroleum demand in the early 1980s caused many small refineries and older, inefficient plants to close. The refinery shutdowns resulted in improved operating efficiency, which enabled the refinery utilization rate to increase, despite lower crude oil inputs. Operable capacity has remained relatively constant since 1985, while capacity utilization has risen steadily.

<IP_ADDRESS> Refinery Complexity. Complexity is a measure of the different processes used in refineries. It can be quantified by relating the complexity of a downstream process with atmospheric distillation, where atmospheric distillation is assigned the lowest value, 1.0. The level of complexity of a refinery generally correlates to the types of products the refinery is capable of producing. Higher complexity denotes a greater 109 ability to enhance or diversify product output, to improve yields of preferred products, or to process lower quality crude. By defining refinery complexity, it is possible to differentiate among refineries having similar capacities but different process capabilities. In theory, more complex refineries are more adaptable to change, and are therefore potentially less affected by regulation. The complexity of a refinery usually increases as its crude capacity increases. ( Lube plants are the exception to this rule.) Over 50 percent of the operable capacity ( 50,000 to 100,000 bbl/ d) can be found at refineries with above average complexity. Likewise, the smaller refineries are less complex.

6.1.2 Market Structure The market structure of an industry will influence the magnitude of market impacts resulting from emission controls. A perfectly competitive market is characterized by many sellers, no barriers to entry or exit, homogeneous output, and complete information. A perfectly competitive market is one in which producers have small degrees of market power and pricing is determined by market forces, rather than by the producers.

Alternatively an industry with monopoly power has more discretion over the market price charged. Producers in such an industry have greater market power. A profile of the market structure of the petroleum refining industry is provided in the following sections, including an assessment of the number of domestic operating refineries, the market concentration, and the extent of vertical integration, and diversification.

<IP_ADDRESS> Market Concentration. Market concentration is a measure of the output of the largest firms in the industry,

expressed as a percentage of total national output. Market concentration is usually measured for the 4, 8, or 20 largest firms in the industry. A firm's concentration in a market provides some indication of the firm's size distribution. For example, on one extreme, a concentration of 100 percent would indicate monopoly control of the industry by one firm. On the other extreme, concentration of less than 1 percent would indicate the industry was comprised of numerous small firms.

Concentration is measured based on refining capacity. Until 110 recently, the top four firms in the refining industry have consistently comprised over 30 percent of the market share, but most market concentration ratios have marginally decreased in recent years.

Market concentration may also be evaluated using the Herfindahl Hirschman index, which is defined as the sum of the squared market shares ( expressed as a percentage) for all firms in the industry. If a monopolist existed, with market share equal to 100 percent, the upper limit of the index ( 10,000) would be attained. If an infinite number of small firms existed, the index would equal zero. An industry is considered unconcentrated if the Herfindahl Hirschman index is less than 1,000. Ratings are also developed for moderately concentrated ( between 1,000 and 1,800) and highly concentrated ( greater than 1,800) industries.

The petroleum refining Herfindahl Hirschman index in recent years has been less than 500. Thus the refining industry is considered unconcentrated. 3 <IP_ADDRESS> Industry Integration and Diversification. Vertical integration exists when the same firm supplies input for several stages of the production and marketing process. Firms that operate petroleum refineries are vertically integrated because they are responsible both for exploration and production of crude oil ( which supplies the input for refineries) and for marketing the finished petroleum products after refining occurs. To assess the level of vertical integration in the industry, firms are generically classified as major or independent. Generally speaking, major energy producers are defined as firms that are vertically integrated. There are currently 20 major energy companies. The crude capacity of the major, vertically integrated firms represents almost 70 percent of nationwide production.

For the major oil companies, horizontal integration exists because these firms operate several refineries which are often distributed around the nation. Seventy three of the 109 firms in the industry operate only one refinery each. These are the smaller independent firms. The major firms operate several refineries, and the largest, Chevron, operates 13. Fourteen firms operate four or more refineries each. 111 Diversification exists when firms produce a wide array of unrelated products. In the short run, diversification may indirectly benefit firms that engage in petroleum refining, since the costs of control in petroleum refining may be dispersed over other unaffected businesses operated by the firm. Over the long term, however, firms will not subsidize petroleum product production with profit from other operations, but will shut down unprofitable operations instead. Diversification within the energy industry may mitigate some of the effects of regulation at least in the short run.

<IP_ADDRESS> Financial Profile. The financial performance of firms in the petroleum refining industry is particularly relevant to an evaluation of the impact of regulation on the industry. In order to evaluate the financial condition of the refinery operations of firms, a sample of the petroleum refining industry's major firms financial operations were evaluated.

Annual reports to stockholders were used as a source of data for the analysis. While this sample is too small and diverse to be considered representative of the aggregate industry, the data presented are more recent and more refinery specific than American Petroleum Institute data.

The sample of annual report data analyzes refinery specific data in order to provide a preliminary assessment of the financial condition of firms in the industry. This 12 firm sample as a whole operated 59 refineries in 1991, and represented 45.3 percent of the industry's total refining capacity. Refining capacity in the sample ranges from 165,000 bbl/ d to 2,139,000 bbl/ d. Over the 5 year period from 1987 to 1991, operating income per dollar of revenue increased from 1 percent to 4 percent. Capital expenditures increased steadily, while refined product sales continued a period of decline. The consolidation taking place in the refining industry is reflected in the decreasing crude oil capacity and refinery runs.

Refined product margins are a good indicator of overall refinery financial performance. 4 The difference between refined product costs and refined product revenues is the refined product margin. During the 1980s, refined product margins were affected 112 by a shift in product slates to gasoline and jet fuels, the decrease in crude oil prices, fluctuations in demand, and an increase in refinery utilization rates. 5 In constant 1982 dollars, the refined product margin fluctuated over this time frame, decreasing between 1985 and 1987 and then increasing significantly in 1988. The fluctuations in the refined product margins reflect the volatility of the market and the degree to which refineries' revenues are often subject to significant change over short time periods. In the early half of 1990, the margin between overall U. S. refined product prices and crude oil import costs rose to record levels, given falling crude oil prices and stable gasoline prices. 6 After the invasion of Kuwait, U. S. refined product prices did not keep pace with crude oil prices for the remainder of the year. This negatively impacted refinery revenues for 1991.

Firms have three sources of funding for the capital necessary to purchase emission control equipment required by the NESHAP.

These sources include ( 1) internal funds, ( 2) borrowed funds,

and ( 3) stock issues. Typically, firms seek a balance between the use of debt and stock issues for financing investments.

Debt to equity ratios reflect a measure of the extent to which the firm has balanced the tax advantages of borrowing with the financial safety of stockholder financing. Based on information obtained in the annual reports of the 12 companies in the refinery sample, firms anticipate that internally generated funds will fund most of their capital expenditures. Other firms recognize the need to also draw on available credit lines and commercial paper borrowing. Overall, capital expenditures of refiners have doubled since 1977, although spending peaked in 1982 and has since been in a period of decline.

Planned uses of investment funds by the 12 firms in the financial sample over the next few years include construction of diesel desulfurization units, expansion of existing units, and construction of units to manufacture methyl tertiary butyl ether ( MTBE) and oxygenated fuels. In a 1991 study, Cambridge Energy Research Associates ( CERA) surveyed refiners and oxygenate producers to evaluate the ability of the refining industry to 113 meet CAA provisions. 7 Among the firms in the CERA survey, the majors and some large independents plan to fund their investments primarily or entirely from internally generated cash flows, while most of the small refineries surveyed are planning on resorting to the debt market for funds.

6.1.3 Market Supply Refiners have increased production of most refined products almost every year since 1984. Historically, motor gasoline has been the product that is supplied in the greatest quantities to meet increased demand. Most of the other petroleum products show a modest net increase in supply over the past few years. The lack of significant change in the yield for most refined petroleum products indicates a relatively stable supply slate,

but significant regulatory costs could force some reshuffling of product yield.

Refinery production of motor gasoline has increased each year,

with the exception of periods of economic recession. Production remained relatively steady from 1988 to 1992. Distillate fuel oil output peaked at 3.3 million barrels per day in 1977, then fell through 1983. Output has increased slightly almost every year since, reaching 3 million barrels per day in 1992. Jet fuel production grew during the 1970s and 1980s, and almost doubled by 1990 before declining to 1.4 million barrels per day in 1992.

Residual fuel oil production generally declined from 1980 through 1985, and was 1 million barrels per day in 1992, compared to 0.7 million barrels per day in 1970.

<IP_ADDRESS> Supply Determinants. The most important short run production decision for an oil refinery is the determination of how much crude oil to allocate for the production of each of the refinery's products. The production decision depends on the profit each of the oil products can generate for the firm.

Profits, in turn, depend on the productivity of the oil refinery C its ability to produce each oil product as effectively as possible from a barrel of crude oil. The quantity of crude oil a refinery will refine depends on the capacity of the refinery and the cost of production. The marginal costs of production of each product will determine any future changes in production. Crude 114 oil is the primary material input to the refining process; as a result, the production of refined products is vulnerable to fluctuations in the world crude oil market.

In the long run, production decisions are based on the cost of capacity expansion relative to existing price levels and expected future price levels. A refinery uses different processing units to turn crude oil into finished products, so when a particular processing unit reaches capacity, output can be increased only by substituting a more expensive process. Firms will typically utilize sufficient crude oil to fill the appropriate processing unit until the price increases substantially. At this point, the firm would calculate whether the increased price warrants using an additional, more expensive processing unit. 8 <IP_ADDRESS> Exports of Petroleum Products. Some measure of the extent of foreign competition can be obtained by comparing exports to domestic production. Export levels and domestic refinery output for the past decade were analyzed. Exports as a percentage of domestic refinery output steadily increased from 1984 to 1991 and then fell slightly to 5.6 percent in 1992.

Distillate oil, residual fuel oil, motor gasoline, and petroleum coke are exported in the highest volumes. The combined export volumes of these products represent 75 percent of domestic refinery output shipped overseas.

6.1.4 Market Demand Characteristics The end use sectors that contribute to demand for refined petroleum products are classified in the following four economic sectors: ( 1) household and commercial, ( 2) industrial, ( 3)

transportation, and ( 4) electric utilities. Petroleum products used as transportation fuel include motor gasoline, distillate ( diesel) fuel, and jet fuel, and accounted for an estimated 64 percent of all U. S. petroleum demand in 1990. Since mobile source emissions will be regulated by Title II regulations, this output from petroleum refineries will be most affected by the CAA. The industrial sector constitutes the second highest percentage of demand for petroleum products, followed by household and electric utility demands. 115 Petroleum is used most widely in the transportation sector.

In the household and commercial sector, light heating oil and propane are used for heating and energy uses, and compete with natural gas and electricity. Petroleum fuels in the industrial sector compete with natural gas, coal, and electricity. In the industrial sector, residual and distillate heating oils are used for boiler and power fuel. In the electric utility sector,

petroleum products supply energy in the form of heavy residual fuel oil and smaller amounts of bulk light distillate fuel oil. 9 In terms of refined products, the motor gasoline and jet fuel markets are associated with the transportation sector. The markets for distillate fuel oil are associated with the transportation sector ( diesel engine fuel as a trucking fuel),

household ( space heating), industrial ( fuel for commercial burner installations), and electric utilities ( power generation). The sectors that are sources of demand for residual fuel oil include the commercial and industrial sectors ( heating), utilities ( electricity generation), and the transportation sector ( fuel for ships). Nonutility use of residual fuel has been decreasing due to interfuel substitution in the commercial and industrial sectors. Because LPGs cover a broad range of gases, demand levels are attributable to various end users.

<IP_ADDRESS> Demand Determinants. The demand for refined petroleum products is primarily determined by price level, the price of available substitutes, and economic growth trends. The degree to which price level influences the quantity of petroleum products demanded is referred to as the price elasticity of demand, which is explored later in this report. Prices of refined petroleum products affect the willingness of consumers to choose petroleum over other fuels, and may ultimately cause a change in consumer behavior. In the transportation sector, the effect of high gasoline prices on fuel use could reduce discretionary driving in the short term and, in the long term,

result in the production of more fuel efficient vehicles.

In the market for jet fuel, demand is primarily determined by a combination of price concerns and the overall health of the airline industry. In the residential sector, demand for home 116 heating ( distillate) is determined in part by price level, and also by temperature levels and climate. Temperature in different areas of the country may determine the degree to which buildings and houses are insulated. Temperature and insulation are exogenous factors which will determine heating needs regardless of the price level of fuel. High prices for home heating oil provide incentive for individuals to conserve by adjusting thermostats, improving insulation, and by using energy efficient appliances. In some cases, higher oil prices also provide incentive for switching to natural gas or electric heating.

( Adjusting thermostats is a short run response, while changing to more energy efficient appliances or fuels are long run responses.)

In the industrial sector, fuel oil competes with natural gas and coal for the boiler feed market. High prices relative to other fuels tend to encourage fuel switching, especially at electric utilities and in industrial plants having dual fired boilers. Generally speaking, in choosing a boiler for a new plant, management must choose between the higher capital/ lower operating costs of a coal unit or the lower capital/ higher operating costs of a gas oil unit. In the utility sector, most new boilers in the early 1980s were coal fired due to the impact of legislative action, favorable economic conditions, and longterm assured supplies of coal. 10 Today, because the CAA will require utilities to scrub or use a low sulfur fuel, oil will eventually become more competitive with coal as a boiler fuel,

although a significant increase in oil fired capacity is not expected until 2010.11 Demand levels in each of the end use sectors are also affected by the economic environment. Periods of economic growth and periods of increased demand for petroleum products typically occur simultaneously. For example, in an expanding economy, more fuel is needed to transport new products, to operate new production capacity, and to heat new homes. Conversely, in periods of low economic growth, demand for petroleum products decreases. 117 <IP_ADDRESS> Past and Present Consumption. Total consumption of all types of petroleum products has fluctuated over the past 20 years, reflecting the volatility of this market. The consumption level has been sporadic and has shown an overall decline in recent years. Demand for individual petroleum product types has also fluctuated over this period. The percentage of total demand is highest for motor gasoline followed by demand for distillate fuel oil. Over the 23 year period from 1970 to 1992, the demand for residual fuel oil has decreased by 50 percent, showing the greatest percentage of change over time of any of the petroleum products. It has also been the only fuel to show a decline in use. This decrease in residual fuel demand reflects a move in the industry from heavier fuels toward lighter, more refined versions. This trend is expected to continue into the future as efforts to control air emissions go into effect.

All other types of fuel show increases in use, with the most growth occurring in the market for jet fuel. Substantial gains in airplane fuel efficiency in the last two decades, which have resulted from improved aerodynamic design and a shift toward higher seating capacities, have been exceeded by even faster growth in passenger miles traveled. 12 The other categories show an average growth rate of approximately 23 percent over this time period. All major petroleum products registered lower demand in 1991 than in 1990, except LPGs. This was the first time since 1980 that demand for all major petroleum products fell simultaneously in the same year. In this case, decreased demand was brought on by warmer winter temperatures, an economic slowdown, and higher prices resulting from the Persian Gulf situation. 13 Motor gasoline demand increased from a 1970 low to a high of 7.4 million barrels per day in 1978. The increase reflected a 31 percent growth in the number of automobiles in use and a 25 percent growth in vehicle miles traveled. From 1985 to 1992,

motor gasoline use accounted for about 42 percent of all petroleum products consumed.

Changes in demand for distillate fuel oil were similar to motor gasoline in that consumption reached its lowest and highest 118 levels in 1970 and 1978, respectively. Between 1985 and 1992,

consumption was relatively stable and accounted for about 18 percent of total U. S. petroleum consumption. Residual fuel oil demand, in response to lower priced natural gas and other factors, fell 64 percent, from a high in 1977 of 3.1 million barrels per day to 1.1 million barrels per day in 1992.

Between the period from 1970 to 1990, expanding air travel spurred a 57 percent growth in jet fuel demand. Demand increased from a 1970 low of 1.0 million barrels per day to 1.5 million barrels per day in 1990.

The variation in U. S. petroleum product demand has been linked to changes in the prices of petroleum products relative to one another, and relative to other energy sources. Dramatic petroleum price increases and eventual steep drops were in response to wars, political upheaval in crude oil producing areas, and supply disruptions during the past two decades.

During this period, the more stable and lower prices of alternative fuels led consumers to switch from petroleum as their fuel of economic choice.

<IP_ADDRESS> Imports of Refined Petroleum Products. Imports as a percentage of domestic consumption have fluctuated during the period 1981 through 1992, although in 1992 levels were 10.6 percent, or roughly the same level as in 1981. The import to export ratio has decreased since 1981, due primarily to steady increases in exports.

<IP_ADDRESS> Pricing. Prices for petroleum products have shown volatility over the time period from 1978 through 1992. This volatility is mainly attributable to the fluctuations in the global market for crude oil and the inelastic demand for petroleum products. Inelastic demand allows refiners to pass crude oil price increases on to consumers. Since petroleum products are essentially commodity products and are produced by a large number of refineries, refineries have little ability to differentiate products or their prices.

6.1.5 Market Outlook Quantitative production, demand, and price projections are available from the literature. Projections are important to the 119 economic impact analysis since future market conditions contribute to the potential impacts of the NESHAP which are assessed for the fifth year after regulation.

<IP_ADDRESS> Supply Outlook ( Production and Capacity). The refining industry was operating near maximum capacity in 1991,

with an average annual utilization rate of approximately 92 percent. 14 This is an increase from levels of previous years.

In the market for motor gasoline, for example, production capacity is nearly at full capacity. As a result, any increases in demand will have to be met by imported products. This will result in an increase in worldwide competition for gasoline.

East Coast refiners, accounting for more than 90 percent of all unleaded gas imports to the United States, will be most affected by this increased competition. 15 DOC predicts that, although U. S. refinery output will remain relatively unchanged, net imports of refined petroleum products are expected to increase by 15 percent. 16 DOE predicts net petroleum imports will rise to at least 10 million bbl/ d in 2010, and perhaps as high as 15 million bbl/ d from the 1990 level of 7 million bbl/ d as domestic oil production is expected to decline. Imports are expected to supply between 53 and 69 percent of U. S. petroleum consumption by 2010, compared with 42 percent in 1990. Refined products will account for much of this increase because most of the expansion in the world's refinery system is expected to take place outside the United States. 17 Over the next 5 years, the petroleum industry as a whole plans to increase crude oil distillation capacity by an additional 2 percent, or 272,000 bbl/ d, of which 44 percent would be produced by new facilities. 18 ( The other 56 percent includes reactivations and expansions.) The level of added demand will determine if this added capacity is sufficient to satisfy the market without driving up prices.

Companies that operate refineries with greater complexity factors ( often the largest refineries) will presumably be in a more favorable position to make the necessary capital investments for the transition to cleaner fuels. Such refineries will most likely be those large enough to benefit from the economies of 120 scale, and with basic downstream configurations to facilitate compliance with the new regulations. A financial analysis of major petroleum refineries in the 1980s conducted by DOE concluded that vertically integrated firms benefitted in a period characterized by increased regulatory activity and price instability. 19 The report found that the larger companies could offset a loss in one segment with gains in another. ( It is important to note, however, that in the long run, both large and small firms would close refineries which operate at a loss over time.)

In contrast, smaller, independent, and less complex refineries will face higher marginal compliance costs, and may not find it economical to spend the required environmental capital.

Generally not as flexible as the larger, integrated companies,

these firms operate at greater risk from the effects of market instability. As a result, an industry which has seen a high level of consolidation in past years will be likely to see more concentration. 20 Overall, the effect of the CAA on individual refineries is dependent upon production capacity, economies of scale, degree of self sufficiency, capital cost, and ability of refiners to " pass through" higher costs to consumers. Predictions of the effect on the aggregate industry are difficult at this time because of the uncertainty of the ability of some refineries to develop plans for compliance pending resolution of key issues affecting their operations. A recent Harvard University study, however,

predicted that the promulgation of environmental regulations was likely to result in the early phase out of older, less sophisticated facilities, combined with the upgrade and expansion of more efficient, complex refineries at a faster rate. 21 <IP_ADDRESS> Demand Outlook. DOC projects the demand for all petroleum products to rise slowly and steadily over the next 5 years, with domestic demand for refined products increasing by 2.1 percent in 1992, assuming an economic recovery and a return to " normal" weather. DOC's longer term demand prediction is for a steady growth rate of 1 percent through 1996.22, 23 Given that two thirds of petroleum product demand is attributable to the 121 transportation sector, projected demand growth for motor gasoline will have the greatest effect on refiners. Industrial demand for distillate fuel reflects the strongest projected growth.

According to DOE projections, the consumption of diesel fuel in the transportation sector is expected to grow by over 40 percent between 1990 and 2010.24 Residential and commercial sectors are expected to show a decrease in demand for petroleum products.

DOE has also projected future levels of demand. Motor gasoline will remain the leading end use of petroleum products throughout DOE's chosen time frame, dropping off during 1990 and 1995, and rising again to higher levels by 2010. DOE predicts the demand for residual oil to rise, level off, and then begin to decline in 2010. Jet fuel and distillate fuel are both projected to rise steadily through 2010.

<IP_ADDRESS> Price Outlook. Given that the demand for motor gasoline is price inelastic, the added capital investment that refineries will be required to undertake in the production of reformulated gasolines is likely to be passed on to consumers in the form of a price increase. DOC has estimated this price increase to be a 5 to 10 cent per gallon rise in the price of motor gasoline. 25 In a recent study undertaken by the National Petroleum Council, the impacts of air quality regulations on petroleum refineries were assessed. One of the conclusions of the study was that the costs of controlling air emissions are likely to be passed along to consumers as increases in the final price of refined products. ( The study offered no quantitative projections, however.) 26 DOE has projected the domestic prices of petroleum products for 2010. DOE projects the average price for all petroleum prices to increase at a rate in the range of 0.4 percent to 2.1 percent annually. These price increases are due to projected increases in both domestic demand and crude oil prices. DOE also accounted for higher refining and distribution expenses in making these projections. The real price of motor gasoline is projected to rise from $ 1.17 per gallon in 1990 to between $ 1.30 and $ 1.74 in 2010, depending on the level of world crude oil prices.

Onhighway diesel fuel is projected to increase to between $ 1.27 and 122 $ 1.69 per gallon, primarily because of the added refinery costs of desulfurization. The average retail price of residual fuel oil, the least expensive petroleum product, is projected to be within the range of $ 25.52 to $ 40.79 per barrel in 2010.

If refineries are able to accommodate projected increases in demand, the price level will remain fairly stable. However,

because the price level in this industry is contingent upon so many factors independent of the industry, any price predictions necessarily have their limitations. In the long run, therefore,