# Regulatory Impact Analysis for the Petroleum Refineries NSPSEPA-452/R-08-002 April 2008

Regulatory Impact Analysis for the Petroleum Refineries NSPS

Prepared By: RTI International 3040 Cornwallis Road Research Triangle Park, NC 27709

Prepared for: U.S. Environmental Protection Agency Office of Air Quality Planning and Standards (OAQPS) HEID, ABCG (MD-C439-02) Research Triangle Park, NC 27711

Contract No. EP-D-06-003 Task Order No. 37

U.S. Environmental Protection Agency Office of Air Quality Planning and Standards HEID, ABCG (MD-C439-02) Research Triangle Park, NC 27711iii CONTENTS

Section Page

1 Executive Summary ...................................................................................................... 1-1

2 Introduction ................................................................................................................ ... 2-1

2.1 Introduction .......................................................................................................... 2-1

2.2 Reason for Today’s Action: Market Failu re or Other Social Purpose ................. 2-2
2.2.1 Externality, Common Property Reso urce, and Public Good ................... 2-2
2.2.2 Market Power ........................................................................................... 2-2
2.2.3 Inadequate or Asymmetric Information ................................................... 2-3
2.2.4 Other Social Purposes .............................................................................. 2-3

2.3 References ............................................................................................................ 2-4

3 Industry Profile ............................................................................................................ . 3-1

3.1 Introduction .......................................................................................................... 3-1

3.2 The Supply Side ................................................................................................... 3-1
3.2.1 Production Process, Inputs, and Outputs ................................................. 3-2
3.2.2 Emissions and Controls in Petroleum Refining ....................................... 3-9
3.2.3 Costs of Production ................................................................................ 3-10

3.3 The Demand Side ............................................................................................... 3-11
3.3.1 Product Characteristics .......................................................................... 3-12
3.3.2 Uses and Consumers .............................................................................. 3-13
3.3.3 Substitution Possibilities in Consumption ............................................. 3-15

3.4 Industry Organization ........................................................................................ 3-15
3.4.1 Market Structure .................................................................................... 3-15
3.4.2 Characteristics of U.S. Petrol eum Refineries and Petroleum Refining Companies ............................................................................... 3-19

3.5 Markets .............................................................................................................. 3-24
3.5.1 U.S. Petroleum Consumption ................................................................ 3-24
3.5.2 U.S. Petroleum Production .................................................................... 3-28iv 3.5.3 International Trade ................................................................................. 3-29
3.5.4 Market Prices ......................................................................................... 3-31
3.5.5 Profitability of Petroleum Refineries ..................................................... 3-32
3.5.6 Industry Trends ...................................................................................... 3-33

3.6 References .......................................................................................................... 3-36

Appendix A: Parent Company Information for Petroleum Refineries ............................. A-1

4 NSPS Regulatory Options, Costs and Emission Reductions from Complying with the NSPS ............................................................................................................... 4 -1

4.1 Background Information on the Setting of NSPS ................................................ 4-1

4.2 Summary of the Final NSPS a nd Changes Since Proposal.................................. 4-2
4.2.1 Final Amendments to the NSPS .............................................................. 4-2
4.2.2 Final Requirements for New FCCU and New FCU ................................ 4-3
4.2.3 Final Requirements for New Sulfur Recovery Plants (SRP) ................... 4-5
4.2.4 Final Requirements for New Fuel Gas Combustion Devices .................. 4-7
4.2.5 Final Work Practice Standards ................................................................. 4-8
4.2.6 Modification and Reconstr uction Provisions ......................................... 4-10

4.3 Model Facility, Source Projecti ons, and Cost Assumptions .............................. 4-10
4.3.1 FCCUs.................................................................................................... 4-11
4.3.2 Fluid Coking Units (FCU) ..................................................................... 4-13

4.4 Emissions Estimation by Unit Type .................................................................. 4-13
4.4.1 FCCUs.................................................................................................... 4-14
4.4.2 FCUs ...................................................................................................... 4-15

4.5 Control Technologies in Analysis ...................................................................... 4-16

4.6 Cost Analysis for Control Options ..................................................................... 4-18

4.7 Summary of Cost, Environmental, Energy, and Economic Impacts ................. 4-19
4.7.1 Secondary Impacts ................................................................................. 4-20

4.8 Limitations and Uncertainties Associat ed with the Cost Analyses ................... 4-22

4.9 References .......................................................................................................... 4-24v Appendix B: Summary of Significant Comments and Responses, and Rationales for NSPS Emission Limits ........................................................................... B-1

5 Economic Impact Analysis: Methods and Results ........................................................ 5-1

5.1 Market Model ....................................................................................................... 5-1

5.2 Model Baseline .................................................................................................... 5-1

5.3 Model Parameters ................................................................................................ 5-2

5.4 Results .................................................................................................................. 5-3

5.5 Executive Order 13211 (Energy Effects) ............................................................. 5-5

5.6 Limitations ........................................................................................................... 5-5

5.7 References ............................................................................................................ 5-6

6 Small Business Analysis ............................................................................................... 6-1

6.1 Data and Methods for Flexibility Analysis .......................................................... 6-1

6.2 Results of Small Business Analysis ..................................................................... 6-2

7 Human Health Benefits of Emissions Reductions ........................................................ 7-1

7.1 Calculation of Human H ealth Benefits ................................................................ 7-1

7.2 Characterization of Uncertainty in the Benefits Estimates ................................ 7-11

7.3 Updating the Benefits Data Underlyi ng the Benefit-per-Ton Estimates ........... 7-12

7.4 Comparison of Benefits and Costs ..................................................................... 7-12

7.5 References .......................................................................................................... 7-13

Appendix C: Overview of Ec onomic Model Equations ....................................................C-1vi LIST OF TABLES

Number Page

3-1 Types and Characteristics of Raw Material s used in Petroleum Refineries ................. 3-8 3-2 Major Refinery Product Categories .............................................................................. 3-8 3-3 Labor, Material, and Capital Expend itures for Petroleum Refineries (NAICS 324110) ......................................................................................................... 3-11 3-4 Costs of Materials Used in Pe troleum Refining Industry ........................................... 3-12 3-5 Major Refinery Products ............................................................................................. 3-14 3-6 Market Concentration Measures of the Petroleum Refi ning Industry: 1985 to 2003 ............................................................................................................... 3- 18 3-7 Number of Petroleum Refi neries, by State ................................................................. 3-20 3-8 Full Production Capacity U tilization Rates for Petrol eum Refineries ........................ 3-21 3-9 Characteristics of Small Businesses in the Petroleum Refi ning Industry ................... 3-25 3-10 Total Petroleum Products Supplied (m illions of barrels per year) ............................. 3-28 3-11 U.S. Refinery and Blender Net Producti on (millions of barrels per year) .................. 3-29 3-12 Value of Product Shipments of the Petroleum Refining Industry .............................. 3-30 3-13 Imports of Major Petroleum Products (millions of barrels per year) .......................... 3-30 3-14 Exports of Major Petroleum Products (millions of barrels per year) .......................... 3-31 3-15 Average Price of Major Petroleum Produc ts Sold to End Users (cents per gallon) ....................................................................................................................... .. 3-31 3-16 Producer Price Index Industry Data: 1995 to 2006 ..................................................... 3-32 3-17 Mean Ratios of Profit before Taxes as a Percentage of Net Sales for Petroleum Refiners, Sorted by Value of Assets ........................................................................... 3-32 3-18 Net Profit Margins for Publicly Owned, Small Petroleum Refiners: 2006 ................ 3-33 3-19 Forecasted Average Price of Major Petr oleum Products Sold to End Users in 2005 Currency (cents per gallon) ................................................................................ 3-34 3-20 Total Petroleum Products Supplied (m illions of barrels per year) ............................. 3-34 3-21 Selected Refinery Constr uction Projects: 2008–2011 ................................................ 3-35 3-22 Full Production Capacity U tilization Rates for Petroleum Refineries ........................ 3-36 4-1 Model Facility Descriptions ........................................................................................ 4-12 4-2 Emissions for Fuel Gas Combustion Devices ............................................................. 4-16 4-3 National Incremental Emission Reductions and Cost Impacts for Petroleum Refinery Units Subject to Final Stan dards Under 40 CFR Part 60, Subpart Ja (Fifth Year After Proposal) a ........................................................................................ 4-21 5-1 Baseline Market Data: 2012 .......................................................................................... 5-2 5-2 Estimates of Price Elasticity of Demand and Supply ................................................... 5-3 5-3 Summary of Intermediate Run Economic Impacts by Petroleum Product: 2012 ......... 5-4vii 6-1 Characteristics of Small Businesses in the Petroleum Refi ning Industry ..................... 6-2 7-1 General Summary of Range of Benefits Estimates for Selected Options in the Final NSPS a ................................................................................................................... 7-3 7-2 Summary of Monetized Benefits for Sel ected Options at 3% Discount Rate in 2012 (millions of 2006$) .............................................................................................. 7-5 7-3 Summary of Monetized Benefits for Sel ected Options at 7% Discount Rate in 2012 (millions of 2006$) .............................................................................................. 7-6 7-4 Estimated Range of Monetized Benefits in 2012 for All Options of New Process Units (thousands of 2006$) a .......................................................................................... 7-7 7-5 Estimated Range of Monetized Bene fits in 2012 for All Options of Modified/Reconstructed Pro cess Units (thousands of 2006$) a ..................................... 7-9viii LIST OF FIGURES

Number Page

3-1 Outline of the Refining Process .................................................................................... 3-3 3-2 Desalting Process .......................................................................................................... 3- 3 3-3 Atmospheric Distillation Process .................................................................................. 3-4 3-4 Vacuum Distillation Process ......................................................................................... 3-5 3-5 Petroleum Refinery Expenditures ............................................................................... 3-10 3-6 Employment Distribution of Companies Owning Petroleum Refine ries (N=49) ....... 3-22 3-7 Average Revenue of Companies Owni ng Petroleum Refineries by Employment (N=49) ........................................................................................................................ . 3-22 3-8 Revenue Distribution of Companies Owni ng Petroleum Refineries (N=49) ............. 3-23 3-9 Total Petroleum Products Supplied (millions of barrels per year) ............................. 3-28 7-1 Monetized Benefits for Selected Opti ons for Final Petrol eum Refineries NSPS at 3% Discount Rate by PM 2.5 Precursor Emitted in 2012 a .......................................... 7-4 7-2 Range of Estimated Net Benefits for Selected Options for Final Petroleum Refineries NSPS a ........................................................................................................ 7-131-1 SECTION 1
EXECUTIVE SUMMARY

EPA has characterized the fac ilities and companies potentia lly affected by the NSPS by examining existing refineries and the companies th at own them. EPA project s that new refineries and processes will be similar to existing ones, and that the companies owning new sources will also be similar to the companies owning exis ting refineries. EPA has collected data on 150 existing refineries, owned by 58 companies. Of th e affected parent comp anies, twenty-five are
identified as small entities based on the Small Bu siness Administration size standard criteria for NAICS 324110, for they employ 1,500 or fewer employees.

EPA estimates that complying with the fi nal NSPS will have an annualized cost of approximately $31 million per year (2006 dollars) in the fifth year after proposal. Using these costs, EPA estimates that the NSPS will have li mited impacts on the market for motor gasoline.
Based on sales data obtained for the affected small entities, EPA estimates that, due to the expected annualized cost savings, that the N SPS will not result in a SISNOSE (a significant economic impacts for a substantia l number of small entities).

The final petroleum refineries NSPS is consider ed subject to the requirements of Circular A-4 because EPA expects that the sum of benefits and costs are potentially $1 billion or higher.
EPA’s estimate of the benefits of the NSPS, based on information from the PM 2.5 expert elicitation study released in October, 2006, is a range from $220 million to $1.9 billion (2006 dollars) in the fifth year after proposal. EPA believes that the benefits are likely to exceed the costs by a substantial margin under this rulemaki ng even when taking into account uncertainties
in the cost and benefit estimates.2-1 SECTION 2
INTRODUCTION

The U.S. Environmental Protection Agency’s (EPA’s) Office of Air Quality Planning and Standards (OAQPS) is currently revising the existi ng Subpart J New Source Performance Standards (NSPS) for petroleum refineries. In a ddition, the Agency is adding a Subpart Ja that provides new requirements, including new emissions limits for new fluid catalytic cracking units (FCCUs), new fluid coking units, and new flares. This final regulation include emissions limits for new and modified/reconstructed sources, and these limits are set for sulfur dioxide (SO 2 ), nitrogen oxides (NO x ), coarse particulate matter (PM 10 ), volatile organic compounds (VOC), and other pollutants. This regulatory impact analysis (RIA), prepared in re sponse to requirements under Executive Order 12866, presents the results of analyses undertak en in support of this final rule including compliance costs, benefits, economic impacts, and impacts to small businesses.

2.1 Introduction
The petroleum refining industry comprises esta blishments primarily engaged in refining crude petroleum into refined petroleum. Exam ples of refined petroleum products include gasoline, kerosene, asphalt, lubricants, solvents , and a variety of othe r products. Petroleum refining falls under the North American Indus trial Classification System (NAICS) 324110.

This RIA is organized as follows:

 Section 1: Executive Summary,

 Section 2: Introduction,

 Section 3 and an Appendix A: Profile of the Petroleum Refinery Industry,

 Section 4: NSPS Regulatory Alternatives, and Costs and Emission Reductions From Complying with the NSPS, and an Appendix B: Summary of Significant Comments and Responses, And Rationales for NSPS Emission Limits

 Section 5: Economic Impacts of the NSPS,

 Section 6: Potential Impacts on Small Businesses,

 Section 7: Benefits of the NSPS,

 Appendix C: Alternative Calc ulation of Welfare Impacts Considering Cost Savings, and

 Appendix D: Overview of Economic Model Equations2-2 2.2 Reason for Today’s Action: Market Failure or Other Social Purpose
The petroleum refinery NSPS is of sufficient im pact to be considered as falling under the requirements of Circular A-4, an addendum to the existing requirements for Executive Order 12866 (OMB, 2003). This final regulation is bein g issued in response to a court-ordered settlement between U.S. EPA and various par ties requiring review of the existing NSPS.

As discussed in Circular A-4, among the reas ons a regulation such as this one may also
be issued is to address market failure. The major types of ma rket failure include: externality, market power, and inadequate or asymmetric information. Correcti ng market failures is a reason for regulation, but it is not the only reason. Other possible justif ications include improving the functioning of government, rem oving distributional unfairness, or promoting privacy and personal freedom.

2.2.1 Externality, Common Property Resource, and Public Good
An externality occurs when one party’s acti ons impose uncompensated benefits or costs on another party. Environmental problems are a cl assic case of external ity. For example, the smoke from a factory may adversel y affect the health of local residents while soiling the property in nearby neighborhoods. If bargaining were costle ss and all property rights were well defined, people would eliminate externalities through bargaining without the need for government regulation. From this perspective, externalities ar ise from high transactions costs and/or poorly defined property rights that prevent people fr om reaching efficient outcomes through market
transactions.

Resources that may become congested or ove rused, such as fisheries or the broadcast spectrum, represent common property resources. “Public goods,” such as defense or basic scientific research, are goods where provision of the good to some individuals cannot occur without providing the same level of benef its free of charge to other individuals.

2.2.2 Market Power
Firms exercise market power when they redu ce output below what would be offered in a competitive industry in order to obtain highe r prices. They may exercise market power collectively or unilaterally. Govern ment action can be a source of market power, such as when regulatory actions exclude low-co st imports. Generally, regulations that increase market power
for selected entities should be avoided. Howe ver, there are some circumstances in which government may choose to validate a monopoly. If a market can be served at lowest cost only when production is limited to a single producer B local gas and el ectricity distri bution services, for example B a natural monopoly is said to exist. In such cases, the government may choose to2-3 approve the monopoly and to regula te its prices and/or producti on decisions. Nevertheless, you should keep in mind that technological advances often affect economies of scale. This can, in turn, transform what was once considered a na tural monopoly into a market where competition
can flourish.

2.2.3 Inadequate or Asymmetric Information
Market failures may also result from inad equate or asymmetric information. Because information, like other goods, is costly to produ ce and disseminate, your evaluation will need to do more than demonstrate the possible existence of incomplete or asymmetric information. Even though the market may supply less than the full amount of information, the amount it does supply may be reasonably adequate and theref ore not require governme nt regulation. Sellers have an incentive to provide information th rough advertising that can increase sales by highlighting distinctive characte ristics of their products. Buyers may also obtain reasonably adequate information about product characteris tics through other channels, such as a seller offering a warranty or a thir d party providing information.

Even when adequate information is availabl e, people can make mistakes by processing it poorly. Poor information-processing often occurs in cases of low probability, high-consequence events, but it is not limited to such situati ons. For instance, people sometimes rely on mental rules-of-thumb that produce errors. If they have a clear mental image of an incident which makes it cognitively “available,” they might overstate th e probability that it will occur. Individuals sometimes process information in a biased ma nner, by being too optimistic or pessimistic, without taking sufficient account of the fact that the outcome is exceedingly unlikely to occur. When mistakes in information processing o ccur, markets may overreact. When it is timeconsuming or costly for consumers to evaluate complex information about products or services (e.g., medical therapies), they may expect governme nt to ensure that minimum quality standards are met. However, the mere possibility of poor information processing is not enough to justify regulation. If you think there is a problem of information processi ng that needs to be addressed, it should be carefully documented.

2.2.4 Other Social Purposes
There are justifications for regulations in addition to correcting market failures. A regulation may be appropriate when you have a clearly identified measure that can make government operate more efficiently. In a ddition, Congress establishes some regulatory programs to redistribute resource s to select groups. Such regulations should be examined to ensure that they are bo th effective and cost-eff ective. Congress also aut horizes some regulations2-4 to prohibit discrimination that conflicts with generally accepted norms within our society. Rulemaking may also be appropr iate to protect privacy, permit more personal freedom or promote other democratic aspirations.

2.3 References U.S. Office of Management and Budget. Circular A-4, September 17, 2003. Found on the Internet at <http://www.whitehouse. gov/omb/circulars/a004/a-4.pdf>.3-1 SECTION 3
INDUSTRY PROFILE

3.1 Introduction
The U.S. Environmental Protection Agency’s (EPA’s) Office of Air Quality Planning and Standards (OAQPS) is currently revising th e existing Subpart J New Source Performance Standards (NSPS) for petroleum refineries. In a ddition, the Agency is adding a Subpart Ja that provides new requirements, including new em issions limits for new and modified and reconstructed fluid catalytic cracking units (FCCUs), new fluid coking units, new process heaters, and new flares. These st andards include emissions limits for reductions of sulfur dioxide (SO 2 ), nitrogen oxides (NO x ), coarse particulate matter (PM 10 ), volatile organic compounds, (VOC) and other pollutants. This industry prof ile of the petroleum re fining industry provides information that will support subsequent regu latory impact analyses (RIAs) and economic impact analyses (EIAs) that will asse ss the impacts of these standards.

At its core, the petroleum refining industry comprises establishments primarily engaged in refining crude petroleum into finished petroleum products. Examples of these petroleum products include gasoline, kero sene, asphalt, lubricants, a nd solvents, among others.

Firms engaged in petroleum refining are ca tegorized under the Nort h American Industry Classification System (NAICS) code 324110. In 2006, 149 establishments owned by 56 parent companies were refining petroleum in the continental United States . That same year, the petroleum refining industry shipped products valu ed at over $489 billion (U.S. Department of Commerce, Bureau of the Census, 2007).

This industry profile report is organized as follows. Section 3.2 provides a detailed description of the inputs, outputs, and proce sses involved in petroleum refining. Section 3.3 describes the applications and users of finish ed petroleum products. Section 3.4 discusses the organization of the industry and provides faci lity- and company-level data. In addition, small businesses are reported separately for use in ev aluating the impact on small business to meet the requirements of the Small Business Regulat ory Enforcement and Fairness Act (SBREFA). Section 3.5 contains market-level data on pri ces and quantities and discusses trends and projections for the industry.

3.2 The Supply Side
Estimating the economic impacts of any re gulation on the petroleum refining industry requires a good understanding of how finished petroleum products are produced (the “supply3-2 side” of finished petroleum pr oduct markets). This section desc ribes the production process used to manufacture these products as well as the inputs, outputs, and by-products involved. The
section concludes with a desc ription of costs involved w ith the production process.

3.2.1 Production Process, Inputs, and Outputs
Petroleum pumped directly out of the ground, kn own as crude oil, is a complex mixture of hydrocarbons (chemical compounds that consis t solely of hydrogen a nd carbon) and various impurities such as salt. To manufacture the vari ety of petroleum products recognized in every day life, this tar-like mixture mu st be refined and processed over several stages. This section describes the typical stages involved in this process as well as th e inputs and outputs.

3.2.1.1 The Production Process
The process of refining crude oi l into useful petroleum products can be separated into two phases and a number of supporting operations. These phases are descri bed in detail in the following section. In the first phase, crude oil is desalted and then separated into its various hydrocarbon components (known as “fractions”). These fractions include gasoline, kerosene, naphtha, and other products (EPA, 1995).

In the second phase, the distilled fractions ar e converted into petroleum products (such as gasoline and kerosene) using three different types of downstream processes: combining, breaking, and reshaping (EPA, 1995). An outline of the refining process is presented in Figure 3-1.

Desalting. Before separation into fractions, crud e oil is treated to remove salts, suspended solids, and other impurities that c ould clog or corrode the downstream equipment. This process, known as “desalting,” is typically d one by first heating the crude oil, mixing it with process water, and depositing it into a gravity se ttler tank. Gradually, the sa lts present in the oil will be dissolved into the process water (EPA, 1995). After this takes place, the process water is separated from the oil by adding demulsifier chem icals (a process known as chemical separation) and/or by applying an electric fiel d to concentrate the suspended water globules at the bottom of the settler tank (a proces s known as electrostatic se paration). The effluent water is then removed
from the tank and sent to the refinery wastewater treatment fa cilities (EPA, 1995). This process is illustrated in Figure 3-2.

Atmospheric Distillation. The desalted crude oil is then heated in a furnace to 750°F and
fed into a vertical distillation column at atmo spheric pressure. After entering the tower, the lighter fractions flash into vapor and travels up the tower. This leav es only the heaviest fractions3-3 Figure 3-1. Outline of the Refining Process
Source: U.S. Department of Labor, Occupational Safety and Health Administration (OSHA). 2003. OSHA

Technical Manual, Section IV: Chapter 2, Petroleum Refining Processes. TED 01-00-015. Washington, DC: U.S. DOL. Available at <http://www.osha.gov/dts/osta/otm/otm_iv/otm_iv_2.html>. As obtained on October 23, 2006.

Figure 3-2. Desalting Process
Source: U.S. Department of Labor, Occupational Safety and Health Administration (OSHA). 2003. OSHA

Technical Manual, Section IV: Chapter 2, Petroleum Refining Processes. TED 01-00-015. Washington, DC: U.S. DOL. Available at <http://www.osha.gov/dts/osta/otm/otm_iv/otm_iv_2.html>. As obtained on October 23, 2006.3-4 (which have a much higher boiling point) at the bottom of the tower. These fractions include heavy fuel oil and asphalt residue (EPA, 1995).

As the hot vapor rises, its temperature is gr adually reduced. Lighter fractions condense onto trays located at successively higher portions of the tower. For example, motor gasoline will condense at higher portion of the tower than kerose ne because it condenses at lower temperatures. This process is illustrated in Figure 3-3. As thes e fractions condense, they will be drawn off their respective trays and potentially se nt downstream for further pro cessing (OSHA, 2003; EPA, 1995).

Figure 3-3. Atmospheric Distillation Process
Source: U.S. Department of Labor, Occupational Safety and Health Administration (OSHA). 2003. OSHA

Technical Manual, Section IV: Chapter 2, Petroleum Refining Processes. TED 01-00-015. Washington, DC: U.S. DOL. Available at <http://www.osha.gov/dts/osta/otm/otm_iv/otm_iv_2.html>. As obtained on October 23, 2006.

Vacuum Distillation. The atmospheric distillation to wer cannot distil the heaviest fractions (those at the bottom of the tower) w ithout cracking under requis ite heat and pressure. So these fractions are separated using a process called vacuum distillation. This process takes place in one or more vacuum distillation towers and is similar to the atmospheric distillation process, except very low pressures are used to increase volatization and separation. A typical first-phase vacuum tower may produce gas oils or lubricating-oil base stocks (EPA, 1995). This process is illustrated in Figure 3-4.

Downstream Processing. To produce the petroleum products desired by the market place, most fractions must be further refine d after distillation or “downstream.” These3-5 Figure 3-4. Vacuum Distillation Process
Source: U.S. Department of Labor, Occupational Safety and Health Administration (OSHA). 2003. OSHA

Technical Manual, Section IV: Chapter 2, Petroleum Refining Processes. TED 01-00-015. Washington, DC: U.S. DOL. Available at <http://www.osha.gov/dts/osta/otm/otm_iv/otm_iv_2.html>. As obtained on October 23, 2006.

downstream processes change the molecular stru cture of the hydrocarbon molecules by breaking them into smaller molecules, joining them to form larger molecules, or shaping them into higher quality molecules (EPA, 1995).

Downstream processes include thermal cracking, coking, cata lytic cracking, catalytic hydrocracking, hydrotreating, alkylation, isomeri zation, polymerization, catalytic reforming, solvent extraction, merox, dewaxing, propane de asphalting and other operations (EPA, 1995).

3.2.1.2 Supporting Operations
In addition to the processes described above, there are other refinery operations that do not directly involve the production of hydrocarbon fu els, but serve in a su pporting role. Some of the major supporting operations ar e described in this section.

Wastewater Treatment. Petroleum refining operations pr oduce a variety of wastewaters including process water (w ater used in process operations li ke desalting), cooling water (water used for cooling that does not come into direct contact with the oil), and surface water runoff (resulting from spills to the surf ace or leaks in the equipment that have collected in drains).3-6 Wastewater typically contai ns a variety of contamin ants (such as hydrocarbons, suspended solids, phenols, ammonia, sulfides, an d other compounds) and must be treated before it is recycled back into refini ng operations or discharged. Petrol eum refineries typically utilize two stages of wastewater treatment. In primary wastewater treatments, oil and solids present in the wastewater are removed. After this is comple ted, wastewater can be di scharged to a publicly owned treatment facility or under go secondary treatment before being discharged directly to surface water. In secondary treatment, microorgani sms are used to dissolve oil and other organic pollutants that are pres ent in the wastewater (EPA, 1995; OSHA, 2003).

Gas Treatment and Sulfur Recovery. Petroleum refinery operati ons such as coking and catalytic cracking emit gases with a high concen tration of hydrogen sulfide mixed with light refinery fuel gases (such as methane and ethane). Sulfur must be removed from these gases in order to comply with Clean Air Act’s SO x emission limits and to recover saleable elemental
sulfur.

Sulfur is recovered by first separating the fu el gases from the hydrogen sulfide gas. Once this is done, elemental sulfur is removed from the hydrogen sulfide gas using a recovery system known as the Claus Process. In this process, hydrogen sulfide is burned under controlled conditions producing sulfur dioxide. A bauxite catalyst is then us ed to react w ith the sulfur dioxide and the unburned hydrogen sulfide to pr oduce elemental sulfur. However, the Claus process only removed 90% of the hydrogen sulfide present in the gas stre am, so other processes must be used to recover the remaining sulfur (EPA, 1995).

Additive Production. A variety of chemicals are a dded to petroleum products to improve their quality or add speci al characteristics. For example, ethers have been added to gasoline to increase octane levels an d reduce CO emissions since the 1970s.

The most common ether additives being used today are methyl tertiary butyl ether (MTBE), and tertiary amyl methyl ether (TAME) . Larger refineries tend to manufacture these additives themselves by reacting isobutylene (a by -product of several refinery processes) with methanol (OSHA, 2003).

Heat Exchangers, Coolers, and Process Heaters. Petroleum refineri es require very high temperatures to perform ma ny of their refining processes. To achieve these temperatures,
refineries use fired heaters fueled by refinery or natural gas, distil late, and residual oils. This heat is managed through heat exchanges, where are composed of bundles of pipes, tubes, plate coils,3-7 and other equipment that surround heating or c ooling water, steam, or oil. Heat exchanges
facilitate the indirect transfer of heat as needed (OSHA, 2003).

Pressure Release and Flare Systems. As liquids and gases e xpand and contract through the refining process, pressure must be activel y managed to avoid accid ent. Pressure-relief systems enable the safe handling of liquids and gases that that are rel eased by pressure-relieving devices and blow-downs. According to the OSHA Technical Manual, “pressure relief is an automatic, planned release when operating pressure reaches a predetermined level. A blow-down normally refers to the intentional release of ma terial, such as blow-downs from process unit startups, furnace blow-downs, shutdowns , and emergencies” (OSHA, 2003).

Blending. Blending is the final operation in petrol eum refining. It is the physical mixture of a number of different liquid hydrocarbons to produce final petroleu m products that have desired characteristics. For example, additives such as ethers can be blended with motor gasoline to boost performance and reduce emissions. Produc ts can be blended in-line through a manifold system, or batch blended in tanks and vessels (OSHA, 2003).

3.2.1.3 Inputs
The inputs in the production pro cess of petroleum products incl ude general inputs such as labor, capital, and water. The i nputs specific to this industry ar e crude oil and the variety of chemicals used in producing petroleum products. Th ese two specific inputs are discussed below.

Crude Oil. Contrary to popular conception, crud e oils are complex, heterogeneous mixtures. Crude oils contain many different hydr ocarbon compounds that vary in appearance and composition from one oil field to another. An “average” crude oil contai ns about 84% carbon; 14% hydrogen; and less than 2% sulfur, nitr ogen, oxygen, metals, and salts (OSHA, 2003).

In 2004, the petroleum refining industry used 5.6 billion barrels of crude oil in the production of finished petr oleum products (EIA, 2005). 1

Common Refinery Chemicals. In addition to crude oil, a variety of chemicals are used in the production of petroleum products. The sp ecific chemicals used will depend on specific characteristics of the product in question. Tabl e 3-1 lists the most common chemicals used by petroleum refineries, their character istics, and their applications.

1 A barrel is a unit of volume that is equal to 42 U.S. gallons.3-8 Table 3-1. Types and Characteri stics of Raw Materials used in Petroleum Refineries

Type Description Crude Oil Heterogeneous mixture of different hydrocarbon compounds. Oxygenates Substances which, when added to ga soline, increase the amount of oxygen in that gasoline blend. Ethanol, methyl tertiary butyl ether (MTBE), ethyl tertiary butyl ether (ETBE), and methanol are common oxygenates. Caustics Caustics are added to desalting water to neutralize acids and reduce corrosion. They are also added to desalted crude in order to reduce the amount of corrosive chlorides in the tower overheads. They are used in some refinery treating processes to remove contaminants from hydrocarbon streams. Leaded Gasoline Additives Tetraethyl lead (TEL) and te tramethyl lead (TML) are additives formerly used to improve gasoline octane ratings but are no longer in common use except in aviation gasoline Sulfuric Acid and Hydrofluoric Acid Sulfuric acid and hydrofluoric acid are us ed primarily as catalysts in alkylation processes. Sulfuric acid is also used in some treatment processes.
Source: U.S. Department of Labor, Occupational Safety and Health Administration (OSHA). 2003. OSHA

Technical Manual, Section IV: Chapter 2, Petroleum Refining Processes. TED 01-00-015. Washington, DC: U.S. DOL. Available at <http://www.osha.gov/dts/osta/otm/otm_iv/otm_iv_2.html>. As obtained on October 23, 2006.

In 2004, the petroleum refining industry used 581 million barrels of natural gas liquids and other liquids in the production of fi nished petroleum products (EIA, 2005).

3.2.1.4 Types of Product Outputs
The petroleum refining industry produces a num ber of products that tend to fall into one of three categories: fuels, finished nonfue l products, and feedstock for the petrochemical industry. Table 3-2 briefly describes these produ ct categories. A more detailed discussion of petroleum fuel products can be found in Section 3.3.

Table 3-2. Major Refinery Product Categories

Product Category Description Fuels Finished Petroleum produ cts that are capable of rel easing energy. These products power equipment such as automobiles, jets, and ships. Typical petroleum fuel products include gasoline, jet fuel, and residual fuel oil. Finished nonfuel products Petroleum products that are not used for powering machines or equipment. These products typically include asphalt, lubric ants (such as motor oil and industrial greases), and solvents (such as benzene, toluene, and xylene). Feedstock Many products derived from crude oil refining, such as ethylene, propylene, butylene, and isobutylene, are primarily intended for use as petrochemical feedstock in the production of plastics, synthetic fibers, synthetic rubbers, and other products.
Source: U.S. Department of Labor, Occupational Safety and Health Administration (OSHA). 2003. OSHA

Technical Manual, Section IV: Chapter 2, Petroleum Refining Processes. TED 01-00-015. Washington, DC: U.S. DOL. Available at <http://www.osha.gov/dts/osta/otm/otm_iv/otm_iv_2.html>. As obtained on October 23, 2006.3-9 3.2.2 Emissions and Controls in Petroleum Refining
Petroleum refining leads to emissions of me tals; spent acids; numerous toxic organic compounds; and gaseous pollutants, including carbon monoxide (CO), sulfur oxides, (SO x ), nitrogen oxides (NO x ), particulates, ammonia (NH 3 ), hydrogen sulfide (H 2 S), and volatile organic compounds (VOCs).

3.2.2.1 Gaseous and VOC Emissions
As previously mentioned, CO, SO x , NO x , NH 3 , and H 2 S emissions are produced along with petroleum products. Sources of these emissi ons from refineries include fugitive emissions
of the volatile constituents in crude oil and its fractions, emissions from the burning of fuels in process heaters, and emissions from the various refinery processes themselves.

Fugitive emissions occur as a result of leaks throughout the refinery. Although individual leaks may be small, the sum of all leaks can result in a lot of hazardous emissions. These emissions can be reduced by purchasing leak-r esistant equipment a nd maintaining an ongoing leak detection and repa ir program (EPA, 1995).

The numerous process heaters used in refineries to heat process streams or to generate steam (boilers) for heating or other uses can be potential sources of SO x , NO x , CO, and hydrocarbons emissions. Emissions are low when process heaters are operating properly and using clean fuels such as refinery fuel gas, fuel oil, or natural gas. However, if combustion is not complete, or the heaters are fueled using fuel pitch or residuals, emissions can be significant (EPA, 1995).

The majority of gas streams exiting each re finery process contain varying amounts of refinery fuel gas, H 2 S, and NH 3 . These streams are directed to the gas treatment and sulfur recovery units described in the pr evious section. Here, refinery fu el gas and sulfur are recovered using a variety of processes. These processes create emissions of their own, which normally
contain H 2 S, SO x , and NO x gases (EPA, 1995).

Emissions can also be created by the periodic regeneration of catalysts that are used in downstream processes. These proce sses generate streams that may contain relatively high levels of CO, particulates, and VOCs. Ho wever, these emissions are treate d before being discharged to the atmosphere. First, the emissions are pro cessed through a CO boiler to burn CO and any VOCs, and then through an electros tatic precipitator or cyclone sepa rator to remove particulates (EPA, 1995).3-10 3.2.2.2 Wastewater and Other Wastes
Petroleum refining operations produce a variet y of wastewaters including process water (water used in process operations like desalting), cooling water (w ater used for cooling that does not come into direct contact with the oil), and surface water runoff (resulting from spills to the surface or leaks in the equipment that have coll ected in drains). This wastewater typically contains a variety of contaminants (such as hydrocarbons, suspended solids, phenols, NH 3 , sulfides, and other compounds) and is treated in on-si te facilities before being recycled back into the production process or discharged.

Other wastes include forms of sludges, spent process catalysts, filter clay, and incinerator
ash. These wastes are controlled through a variety of methods in cluding incineration, land filling, and neutralization, among other treatment methods (EPA, 1995).

3.2.3 Costs of Production
Between 1995 and 2006, expenditures on input materi als accounted for the largest cost to petroleum refineries—amounting to 94% of total expenses (Figur e 3-5). These material costs
included the cost of all raw mate rials, containers, scrap, and supp lies used in produc tion or repair during the year, as well as the cost of all electricity and fuel consumed.

Payroll

3% Materials

94% Total Capital 3% Average Percentage (1995–2006)

Figure 3-5. Petroleum Refinery Expenditures

Labor and capital accounted for the remaini ng expenses faced by petroleum refiners. Capital expenditures include permanent additions a nd alterations to facilities and machinery and equipment used for expanding plant capacity or replacing existing machinery. A detailed3-11 breakdown of how much petroleum refiners sp ent on each of these factors of production over this 11-year period is provided in Table 3-3. A more exhaustive assessment of the costs of materials used in petroleum refi ning is provided in Table 3-4.

Table 3-3. Labor, Material, and Capital Expenditures for Petroleum Refineries (NAICS 324110)

Payroll ($millions) Materials ($millions) Total Capital ($millions) Year Reported 2005 Reported 2005 Reported 2005 1995 3,791 4,603 112,532 136,633 5,937 7,209 1996 3,738 4,435 132,880 157,658 5,265 6,247 1997 3,885 4,595 127,555 150,865 4,244 5,020 1998 3,695 4,415 92,212 110,187 4,169 4,982 1999 3,983 4,682 114,131 134,146 3,943 4,635 2000 3,992 4,509 180,568 203,967 4,685 5,292 2001 4,233 4,743 158,733 177,838 6,817 7,638 2002 4,386 4,947 166,368 187,646 5,152 5,811 2003 4,752 5,227 185,369 203,893 6,828 7,510 2004 5,340 5,635 251,467 265,369 6,601 6,966 2005 5,796 5,796 345,207 345,207 10,525 10,525 2006 5,984 5,751 396,980 381,546 11,175 10,741
Note: Adjusted for inflation using the producer price index industry for total manufacturing industries (Table 5-6). Sources: U.S. Department of Commerce, Bureau of the Census. 2007. 2006 Annual Survey of Manufactures.

Obtained through American Fact Finder Database <http ://factfinder.census.gov/home/saff/main.html?_lang=en>. U.S. Department of Commerce, Bureau of the Census. 2006. 2005 Annual Survey of Manufacture s. M05(AS)-1.

Washington, DC: Government Printing Office. Available at <http://www.census.gov/prod/2006pubs/ am0531gs1.pdf>. As obtained on October 23, 2007. U.S. Department of Commerce, Bureau of the Census. 2003a. 2001 Annual Survey of Manufacture s. M01(AS)-1.

Washington, DC: Government Printing Office. Available at <http://www.census.gov/prod/2003pubs/ m01as-1.pdf>. As obtained on October 23, 2006. U.S. Department of Commerce, Bureau of the Census. 2001. 1999 Annual Survey of Manufacture s. M99(AS)-1

(RV). Washington, DC: Government Printing Office. Available at <http://www.census.gov/prod/2001pubs/ m99-as1.pdf>. As obtained on October 23, 2006. U.S. Department of Commerce, Bureau of the Census. 1998. 1996 Annual Survey of Manufacture s. M96(AS)-1

(RV). Washington, DC: Government Printing Office. Available at <http://www.census.gov/prod/3/98pubs/ m96-as1.pdf>. As obtained on October 23, 2006. U.S. Department of Commerce, Bureau of the Census. 1997. 1995 Annual Survey of Manufacture s. M95(AS)-1.

Washington, DC: Government Printing Office. Available at <http://www.census.gov/prod/2/manmin/ asm/m95as1.pdf>. As obtained on October 23, 2006.

3.3 The Demand Side
Estimating the economic impact the regulat ion will have on the petroleum refining industry also requires characteri zing various aspects of the demand for finished petroleum products. This section describes th e characteristics of finished pe troleum products, their uses and consumers, and possible substitutes.3-12 Table 3-4. Costs of Materials Used in Petroleum Refining Industry

2002 1997

Material Delivered Cost ($10 6 ) Percentage of Material Costs Delivered Cost ($10 6 ) Percentage of Material Costs Petroleum Refineries NAICS 324110 Total materials 157,415,200 100.0% 118,682,535 100.0% Domestic crude petroleum, including lease

condensate 63,157,497 40.1% 47,220,759 39.8%

Foreign crude petroleu m, including lease

condensate 69,102,574 43.9% 48,172,988 40.6%

Foreign unfinished oils (received from

foreign countries for further processing) 2,297,967 1.5% 2,373,376 2.0%

Ethane (C2) (80% purity or more) D D Propane (C3) (80% purity or more) 118,257 0.1% 269,928 0.2% Butane (C4) (80% purity or more) 1,925,738 1.2% 1,567,875 1.3% Gas mixtures (C2, C3, C4) 1,843,708 1.2% 952,009 0.8% Isopentane and natural gasoline 810,530 0.5% 1,381,100 1.2% Other natural gas liquids, including plant

condensate 455,442 0.3% 1,427,123 1.2%

Toluene and xylene (100% basis) 159,563 0.1% N Additives (including antioxidants,

antiknock compounds, and inhibitors) 40,842 0.0% 262,228 0.2%

Other additives (including soaps and

detergents) 709 0.0% 200,005 0.2%

Animal and vegetable oils D D Chemical catalytic preparations D 647,040 0.5% Sodium hydroxide (caustic soda) (100%

NaOH) 129,324 0.1% 41,741 0.0%

Sulfuric acid, excluding spent (100%

H 2 SO 4 ) 189,912 0.1% 56,514 0.0%

Metal containers 9,450 0.0% 60,531 0.1% Plastics containers D N Paper and paperboard containers D 18,404 0.0% Cost of materials r eceived from petroleum

refineries and lube manufacturers 8,980,758 5.7% 4,981,370 4.2%

All other materials and components, parts,

containers, and supplies 5,722,580 3.6% 4,233,383 3.6%

Materials, ingredients, containers, and

supplies, nsk 576,175 0.4% 4,779,890 4.0%

Source: U.S. Department of Commerce, Bureau of the Census. 2004. 2002 Economic Census, Industry Series—

Shipbuilding and Repair . Washington, DC: Government Printing Office. Available at <http://www.census.gov/ prod/ec02/ec0231i324110.pdf>. As obtained on October 23, 2006.

3.3.1 Product Characteristics
Petroleum refining firms produce a variety of di fferent products. The characteristics these products possess largely depend on their intended use. For example, the gasoline fueling our3-13 automobiles has different characteristics than the oil lubricating the car’s engine. However, as discussed in Section 3.1.4, finish ed petroleum products can be categorized into three broad groups based on their inte nded uses (EIA, 1999a):

 fuels —petroleum products that are capable of releasing energy such as motor gasoline

 nonfuel products —petroleum products that are not used for powering machines or equipment such as solvents and lubricating oils

 petrochemical feedstocks —petroleum products that are used as a raw material in the production of plastics, synthe tic rubber, and other goods
A list of selected products from each of these groups is presented in Table 3-5 along with a description of each product’s char acteristics and primary uses.

3.3.2 Uses and Consumers
Finished petroleum products are rarely consum ed as final goods in themselves. Instead, they are used as primary inputs in the creation of a vast number of other goods and services. For example, goods created from petroleum products incl ude fertilizers, pestic ides, paints, thinners, cleaning fluids, refrigerants, and synthetic fi bers (EPA, 1995). Similarly, fuels made from petroleum are used to run vehicles and industria l machinery and generate heat and electrical power. As a result, the demand for many finish ed petroleum products is derived from the demand for the goods and services they are used to create.

The principal end users of petroleum products can be separated into five sectors:

 Residential sector—private homes and residences

 Industrial sector—manufactur ing, construction, mining, agri cultural, and forestry establishments

 Transportation sector—private and pub lic vehicles that move people and commodities such as automobiles, ships, and aircraft

 Commercial sector—nonmanufacturing or nontransportation business establishments such as hotels, restaurants, retail stores , religious and nonprofit organizations, as well federal, state, and local government institutions

 Electric utility sector—priva tely and publicly owned esta blishments that generate, transmit, distribute, or se ll electricity (primarily) to the public; nonutility power producers are not included in this sector3-14 Table 3-5. Major Refinery Products

Product Description Fuels Gasoline A blend of refined hydrocarbons, motor gasoline ranks first in usage among petroleum products. It is primarily used to fuel automobiles and lightweight trucks as well as boats, recreational vehicles, lawn mowers, and other equipment. Other forms of gasoline include Aviation gasoline, which is used to power small planes. Kerosene Kerosene is a refined middle-distillate petroleum product that finds considerable use as a jet fuel. Kerosene is also used in wate r heaters, as a cooking fuel, and in lamps. Liquefied petroleum gas (LPG) LPG consists principally of propane (C 3 H 8 ) and butane (C 4 H 10 ). It is primarily used as a fuel in domestic heating, cooking, and farming operations. Distillate fuel oil Distillate fuel oil includes diesel oil, heating oils, and industrial oils. It is used to power diesel engines in buses, trucks, trains, automobiles, as well as other machinery. Residual fuels Residual fuels are the fuels distilled from the heavier oils that remain after atmospheric distillation, they find their primary use generating electricity in electric utilities. However, residual fuels can also be used as fuel for ships, industrial boiler fuel, and commercial heating fuel. Petroleum coke Coke is a high carbon residue that is the final product of thermal decomposition in the condensation process in cracking. Coke can be used as a low-ash solid fuel for power plants. Finished Nonfuel Products Coke In addition to use as a fuel, petroleum coke can be used a raw material for many carbon and graphite products such as furnace electrodes and liners. Asphalt Asphalt, used for roads and roofing mate rials, must be inert to most chemicals and weather conditions. Lubricants Lubricants are the result of a special re fining process that produce lubricating oil base stocks, which are mixed with various additives. Petroleum lubricating products include spindle oil, cylinder oil, motor oil, and industrial greases. Solvents A solvent is a fluid that dissolves a solid, liquid, or gas into a solution. Petroleum based solvents, such as Benzyme, are used top manufacture detergent and synthetic fibers. Other solvents include toluene and xylene. Feedstock Ethylene Ethylene is the simplest alkene and has the chemical formula C 2 H 4 . It is the most produced organic compound in the world and it is used in the production of many products. For example, one of ethylene’s derivatives is ethylene oxide, which is a primary raw material in the production of detergents. Propylene Propylene is an organic compoun d with the chemical formula C 3 H 6 . It is primarily used the production of polypropylene, which is used in the production of food packaging, ropes, and textiles.
Sources: U.S. Department of Labor, Occupational Safety and Health Administration (OSHA). 2003. OSHA

Technical Manual, Section IV: Chapter 2, Petroleum Refining Processes. TED 01-00-015. Washington, DC: U.S. DOL. Available at <http://www.osha.gov/dts/osta/otm/otm_iv/otm_iv_2.html>. As obtained on October 23, 2006. U.S. Department of Energy, Energy Information Administration (EIA). 1999.

Of these end users, the transportation sector consumes the largest share of petroleum products, accounting for 67% of total consump tion in 2005 (EIA, 2006a). In fact, petroleum products like motor gasoline, distillate fuel, and jet fuel provide virtually all of the energy consumed in the transportation sector (EIA, 1999a).3-15 Of the three petroleum product categories, end-users primarily consume fuel. Fuel products account for 9 out of 10 barrels of petrol eum used in the United States (EIA, 1999a). In 2005, motor gasoline alone accounted for 49% of de mand for finished petroleum products (EIA, 2006a).

3.3.3 Substitution Possibilities in Consumption
A major influence on the demand for finished petroleum products is the availability of substitutes. In some sectors, like the transpor tation sector, it is currently difficult to switch quickly from one fuel to another without costly and irreversible equipm ent changes, but other sectors can switch relatively qui ckly and easily (EIA, 1999a).

For example, equipment at large manufacturing plants often can use either residual fuel oil or natural gas. Often coal and natural gas can be easily substituted for residual fuel oil at electricity utilities. As a result, we would expect demand in these industries to be more sensitive to price (in the short run) th an in others (EIA, 1999a).

However, over time, demand for petroleum products could become more elastic. For example, automobile users could purchase more fu el-efficient vehicles or relocate to areas that would allow them to make fewer trips. Technolog ical advances could al so create new products that compete with petroleum products that curren tly have no substitutes. An example of such a technological advance would be the invention of ethanol (an alcohol pr oduced from biomass), which can substitute for gasoline in spark-ignition motor vehicles (EIA, 1999a).

3.4 Industry Organization
This section examines the organization of th e U.S. petroleum refining industry, including market structure, firm characteristics, plant location, and capacity util ization. Understanding the industry’s organization helps determine how it wi ll be affected by new emissions standards.

3.4.1 Market Structure

Market structure characterizes the leve l and type of competition among petroleum refining companies and determines their power to influence market prices for their products. For example, if an industry is perfectly competitiv e, then individual producers cannot raise their prices above the marginal cost of production without lo sing market share to their competitors. Understanding pricing behavior in the petroleum refining indust ry is crucial for performing subsequent EIAs.3-16 According to basic microeconomic theor y, perfectly competitive industries are characterized by unrestricted entry and exit of firm s, large numbers of firms, and undifferentiated (homogenous) products being sol d. Conversely, imperfectly comp etitive industries or markets are characterized by barriers to entry and exit, a smaller number of firms, and differentiated products (resulting from either differences in pr oduct attributes or brand name recognition of products). This section considers whether the pe troleum refining industry is competitive based
on these three factors.

3.4.1.1 Barriers to Entry
Firms wanting to enter the petroleum refi ning industry may face at least two major barriers to entry. First, according to a 2004 Federal Trade Commission staff study, there are significant economies of scale in petroleum refine ry operations. This means that costs per unit fall as a refinery produces more finished petrol eum products. As a result, new firms that must produce at relatively low levels will face higher av erage costs than firms that are established and produce at higher levels, which will make it more difficult for these new firms to compete (Nicholson, 2005). This is known as a technical barrier to entry.

Second, legal barriers could also make it di fficult for new firms to enter the petroleum refining industry. The most common example of a legal barrier to entry is patents—intellectual property rights, granted by the gove rnment, that give exclusive m onopoly to an inventor over his invention for a limited time period. In the pe troleum refining industry, firms rely heavily on process patents to appropriate re turns from their innovations. As a result, firms seeking to enter the petroleum refining industry must develop pro cesses that respect the novelty requirements of these patents, which could poten tially make entry more difficult for new firms (Langinier, 2004). A second example of a legal barrier would be envi ronmental regulations that apply only to new entrants or new pollution sources. Such regulatio ns would raise the operating costs of new firms without affecting the operating costs of existing ones. As a result, new firms may be less competitive.

Although neither of these barrie rs are impossible for new entrants to overcome, they can
make it more difficult for new firms to enter the market for manufactured petroleum products. As a result, existing petroleum refiners could potentia lly raise their prices above competitive levels with less worry about new firms entering the market to compete away their customers with lower prices. It was not possible during this analysis to quantify how si gnificant these barriers would be for new entrants or what effect they would have on market prices. However, existing firms3-17 would still face competition from each other. In an unconcentrated industry, competition among existing firms would work to keep prices at competitive levels.

3.4.1.2 Measures of Industry Concentration
Economists often use a variety of measures to assess the concentration of a given industry. Common measures include four-fir m concentration ratios (CR4), eight-firm concentration ratios (CR8), and Herfindahl -Hirschmann indexes (HHI). The CR4s and CR8s measure the percentage of sales accounted for by the top four and eight firms in the industry. The HHIs are the sums of the squared market shares of firms in the industry. These measures of industry concentrated are repor ted for the petroleum refini ng industry (NAICS 324110) in Table 3-6 for selected years between 1985 and 2003.

Between 1990 and 2000, the HHI rose from 437 to 611, which indicates an increase in
market concentration over time. This increase is partially due to merger activity during this time period. Between 1990 and 2000, over 2,600 mergers o ccurred across the petroleum industry; 13% of these mergers occurred in the industry’ s refining and marketing segments (GAO, 2007).

Unfortunately, there is no objective criterion for determining market structure based on
the values of these concentration ratios. Howe ver, accepted criteria have been established for determining market structure based on the HHIs for use in horizontal merger analyses (U.S. Department of Justice and the Federal Trade Commission, 1992). Accordin g to these criteria, industries with HHIs below 1,000 are considered unconcentrated (i.e., more competitive); industries with HHIs between 1,000 and 1,800 are c onsidered moderately concentrated (i.e., moderately competitive); and indus tries with higher HHIs are cons idered heavily concentrated. Based on this criterion, the petrol eum refining industry continues to be unconcentrated even after an increase in merger activity.

A more rigorous examination of market c oncentration was conducted in a 2004 Federal Trade Commission (FTC) staff study. This study exp licitly accounted for the fact that a refinery in one geographic region may not exert competitiv e pressure on a refinery in another region if transportation costs are high. This was done by comparing HHIs across Petroleum Administration for Defense Districts (PADDs). PADDs separate the United States into five geographic regions or districts. They were initially created duri ng World War II to help manage the allocation of fuels during wart ime. However, they have remained in use as a convenient way of organizing petroleum ma rket information (FTC, 2004).3-18 Table 3-6. Market Concentration Measures of the Petroleum Refining Industry: 1985 to 2003

Measure 1985 1990 1996 2000 2001 2002 2003 Herfindahl-Hirschmann Index (HHI) 493 437 412 611 686 743 728 Four-firm concentration ratio (CR4) 34.4 31.4 27.3 40.2 42.5 45.4 44.4 Eight-firm concentration ratio (CR8) 54.6 52.2 48.4 61.6 67.2 70.0 69.4

Source: Federal Trade Commission (FTC). 2004. “The Petroleum Industry: Mergers, Structural Change, and

Antitrust Enforcement.” Available at <http://www.ftc.gov/opa/2004/08/oilme rgersrpt.shtm>. As obtained on February 6, 2007.

This study concluded that these geographi c markets were not highly concentrated. PADDs I, II, and III (East Coast, Midwest, and Gulf Coast) were sufficiently connected that they exerted a competitive influence on each other. The HHI for these combined regions was 789 in 2003, indicating a low concentration level. Conc entration in PADD IV (Rocky Mountains) was also low in 2003, with an HHI of 944. PADD V gr adually grew more concentrated in the 1990s after a series of significant refinery mergers. By 2003, the region’s HHI was 1,246, indicating a growth to a moderate level of concentration (FTC, 2004).

3.4.1.3 Product Differentiation
Another way firms can influence market pr ices for their product is through product differentiation. By differentiating one’s product and using marketi ng to establish brand loyalty, manufacturers can raise their prices above margin al cost without losing market share to their competitors.

While we saw in Section 3.3 that there are a wide variety of petr oleum products with many different uses, individual petroleum pr oducts are by nature quite homogenous. For example, there is little difference between premium motor gasoline produced at different refineries (Mathtech, 1997). As a result, the ro le of product differentia tion is probably quite small for many finished petroleum products. Howeve r, there are examples of relatively small refining businesses producing spec ialty products for small niche markets. As a result, there may be some instances where product differentiat ion is important for price determination.

3.4.1.4 Competition among Firms in the Petroleum Refining Industry
Overall, the petroleum industr y is characterized as produci ng largely generic products for sale in relatively unconcentrated markets. A lthough it is not possible to quantify how much barriers to entry and other fact ors will affect competition among firms, it seems unlikely that3-19 individual petroleum refiners w ould be able to significantly infl uence market prices given the
current structure of the market.

3.4.2 Characteristics of U.S. Petroleum Refi neries and Petroleum Refining Companies
A petroleum refinery is a facility where labo r and capital are used to convert material inputs (such as crude oil and other materials) in to finished petroleum products. Companies that own these facilities are legal bus iness entities that conduct transact ions and make decisions that affect the facility. The terms “facility,” “establ ishment,” and “refinery” are synonymous in this study and refer to the physical location where products are manufactured. Likewise, the terms “company” and “firm” are used interchangeably to refer to the legal business entity that owns one or more facilities. This section presents in formation on refineries, such as their location and capacity utilization, as well as financial data for the companies that own these refineries.

3.4.2.1 Geographic Distribution of U.S. Petroleum Refineries
There are approximately 149 petroleum refineri es operating in the United States, spread across 33 states. The number of petroleum refineries located in each of these states is listed in
Table 3-7. This table illustrate s that a significant portion of pe troleum refineries are located along the Gulf of Mexico region. The leading petr oleum refining states are Texas, California,
and Louisiana.

3.4.2.2 Capacity Utilization
Capacity utilization indicates how well current refineries meet demand. One measure of capacity utilization is cap acity utilization rates. A capacity utilization rate is the ratio of actual production volumes to full-capacity production vo lumes. For example, if an industry is producing as much output as possible without adding new floor space for equipment, the capacity utilization rate would be 100 percent. On the othe r hand, if under the same constraints the industry were only producing 75 percent of its maximum po ssible output, the capacity utilization rate would be 75 percen t. On an industry-basis, capacity utilization is highly variable from year to year depending on economic condi tions. It is also variable on a company-bycompany basis depending not only on economic conditions, but also on company’s strategic position in its particular industry. While some pl ants may have idle production lines or empty floor space, others need a dditional space or capacity.

Table 3-8 lists the capacity ut ilization rates for petroleum refineries from 2000 to 2006. It is interesting to note the signifi cant drop in capacity u tilization in 2005. This would seem counter
intuitive since there does not a ppear to be evidence that dema nd for petroleum products is not dropping. To understand why this might be the case, one must first realize that the capacity3-20 Table 3-7. Number of Petrol eum Refineries, by State

State Number of Petroleum Refineries Alabama 4 Alaska 6 Arkansas 2 California 21 Colorado 2 Delaware 1 Georgia 1 Hawaii 2 Illinois 4 Indiana 2 Kansas 3 Kentucky 2 Louisiana 18 Michigan 1 Minnesota 2 Mississippi 4 Montana 4 Nevada 1 New Jersey 6 New Mexico 3 North Dakota 1 Ohio 4 Oklahoma 5 Oregon 1 Pennsylvania 5 Tennessee 1 Texas 25 Utah 5 Virginia 1 Washington 5 West Virginia 1 Wisconsin 1 Wyoming 5 Total 149
Source: U.S. Department of Energy, Energy Information Administration (EIA). 2006b. “Refinery Capacity Report

2006.” Available at <http://www.eia.doe.gov/oil_gas/ petroleum/data_publications/refinery_capacity_data/ refcapacity.html>. As obtained on October 23, 2006.

utilization ratio in petroleum i ndustry represents the utilization of the at mospheric crude oil
distillation units.

This is calculated for the petroleum industr y by dividing the gross input to atmospheric crude oil distillation units (all i nputs involved in atmospheric crude oil distillation, such as crude oil) by the industry’s operational capacity.

In 2004, operational capacity increased fr om 16,974,000 barrels per calendar day to 17,196,000 barrels per calendar day. However, gr oss inputs fell from 15,783,000 barrels per3-21 Table 3-8. Full Production Capacity Util ization Rates for Petroleum Refineries

Year Petroleum Refineries Capacity Utilization Rates (NAICS 324110) Gross Input to Atmospheric Crude Oil Distillation Units (1,000s of barrels per day) Operational Capacity (1,000s of barrels per day) 2000 92.6 15,299 16,525 2001 92.6 15,352 16,582 2002 90.7 15,180 16,744 2003 92.6 15,508 16,748 2004 93.0 15,783 16,974 2005 90.6 15,578 17,196 2006 89.7 15,602 17,385
Source: U.S. Department of Energy, Energy Informati on Administration (EIA). 2007a. “Refinery Utilization and

Capacity.” Available at <http://tonto.eia.doe.gov/dnav/pet/ pet_pnp_unc_dcu_nus_m.htm>. As obtained on January, 2007.

calendar day in 2004 to 15,578,000 in 2005. This indicates that capacity utilization sagged due to a drop in production inputs. In 2006, gross inputs grew 0.15% to 15,602,000 barrels per day. However, since operational capacity gr ew much faster (from 17,196,000 to 17,385,000 or 1.00%), capacity utilization rates for the industry continued to fall.

3.4.2.3 Characteristics of Small Businesse s Owning U.S. Petroleum Refineries
According to the Small Business Administ ration (SBA), a small business in the petroleum refining industry is defined for govern ment procurement purposes as having 1,500 or fewer employees and an Operable Atmospheric Cr ude Oil Distillation capac ity of no more than 125,000 barrels per calendar day total (SBA, 2008). We applied this definition in defining a small business refiner in our proposal RIA. Howeve r, as part of a response to a comment made on the proposal, we define a small business only as having 1,500 or fewer employees.

As of January 2006, there were 149 petroleum refineries operating in the continental United States with a cumulative capacity of processing over 17 million barrels of crude per calendar day (EIA, 2006c). RTI identified 56 parent companies owning refineries in the United States and was able to collect employment and sales data for 49 (88%) of them.

The distribution of employment across compan ies is illustrated in Figure 3-6. As this figure shows, 25 companies (53% of the 49 tota l) employee fewer than 1,500 workers and would be considered small businesses. These firms earned an average of $1.04 billion of revenue per year, while firms employing more than 1,500 employees earned an average of $84.2 billion of revenue per year (Figure 3-7). A distribution of the number of fi rms earning different levels of revenue is presente d in Figure 3-8.3-22 0% 10% 20% 30% 40% 50% 60%

<100 100-250 250-500 500-1000 1000- 1500 >1500Share of Firms (%)

Figure 3-6. Employment Distribut ion of Companies Owning Petroleum Refineries (N=49)

Sources: Dun & Bradstreet. 2007a. 2007 D&B Million Dolla r Directory. Pennsylvania: Dun & Bradstreet Inc.

Dun & Bradstreet Small Business Solutions. Small Business Database. Available at <http://smallbusiness.dnb.com/default.asp?bhcd2=1107465546>. Gale Research Inc. 2007. Ward’s Business Directory of U.S. Private and Public Companies. Detroit: Gale Research.
Hoovers. 2007. Free Content, Co mpany Information. Available at <http://www.hoovers.com/free/>.

$0 $20,000 $40,000 $60,000 $80,000 $100,000

<100 100-250 250-500 500-1000 1000- 1500 >1500Average Revenue ($millions)

Figure 3-7. Average Revenue of Companies Ow ning Petroleum Refineries by Employment (N=49)
Sources: Dun & Bradstreet. 2007. 2007 D&B Million Dollar Directory. Pennsylvania: Dun & Bradstreet Inc.

Dun & Bradstreet Small Business Solutions. Small Business Database. Available at <http://smallbusiness.dnb.com/default.asp?bhcd2=1107465546>. Gale Research Inc. 2007. Ward’s Business Directory of U S Private and Public Companies. Detroit: Gale Research.
Hoovers. 2007. Free Content, Co mpany Information. Available at <http://www.hoovers.com/free/>.3-23 0% 10% 20% 30% 40% 50% 60% 70%

<$5 $5-$10 $10-$50 $50- $100 $100- $500 $500- $1000 >$1000Share of Firms (%)

Figure 3-8. Revenue Distribution of Compan ies Owning Petroleum Refineries (N=49)
Sources: Dun & Bradstreet. 2007. 2007 D&B Million Dollar Directory. Pennsylvania: Dun & Bradstreet Inc.

Dun & Bradstreet Small Business Solutions. Small Business Database. Available at <http://smallbusiness.dnb.com/default.asp?bhcd2=1107465546>. Gale Research Inc. 2007. Ward’s Business Directory of U S Private and Public Companies. Detroit: Gale Research.
Hoovers. 2007. Free Content, Co mpany Information. Available at <http://www.hoovers.com/free/>.

Employment, crude capacity, and location inform ation are provided in Table 3-9 for each of companies employing 1,500 employees or less. Similar information can be found for all 56 companies owning petroleum refineries in Appendix A.

In Section 3.4.2.1, we discussed how petroleu m refining operations are characterized by economies of scale—that the cost per unit falls as a refinery produces more finished petroleum products. This means that smaller petroleum refi ners face higher per unit costs than larger refining operations because they produce fewer petroleum products. As a result, some smaller firms have sought to overcome their compe titive disadvantage by locating close to productconsuming areas to lower transportation cost s and serving niche pr oduct markets (FTC, 2004).

A good example of a firm locating close to prospective customers is Countrymark Cooperative, Inc., which was started in the 1930s for the express purpose of providing farmers in Indiana with a consistent supply of fuels, lu bricants, and other products. A good example of a firm producing niche products is Calumet Lubricants, which focuses on developing and manufacturing naphtheni c specialty oils.

However, recent developments are making thes e factors less important for success in the industry. For example, the entry of new product pi pelines is eroding the locational advantage of smaller refineries (FTC, 2004). Th is trend can possibly be illust rated by the fact that most3-24 refineries owned by small businesses tend to be lo cated in relatively rural areas (see Table 3-9). The median population density of counties occupied by small refineries is 94 people per square mile. This could suggest that refineries do not rely on the population surrounding them to support their refining operations.

To obtain a better sense of wh ere the customers of these small refiners are located, RTI spoke with representatives from four different companies. Three of these representatives indicated that they primarily serve customers outsi de their local areas. In particular, two of these businesses were primarily fuel prod ucers that used pipelines to de liver their product to customers up to 300 miles away.

Capacity information for the 29 refineries owned by small businesses also suggests that fewer small businesses are focusing on developing specialty products or serving local customers as major parts of their business plan. For exam ple, in 2006 these 29 refineries had a collective crude refining capacity of 778,920 barrels per calendar day or 857,155 barrels per stream day (EIA, 2006c). Approximately 21% of this total capacity was devoted to producing specialty products or more locally focused products such as aromatics, asphalt, l ubricants, and petroleum coke. The remaining 79% was used to produce ga soline, kerosene, diesel fuel, and liquefied petroleum gases. As discussed in Section 3.4.1.3, fuel products tend to be quite homogenous (gasoline from one refinery is not very different from gasoline from another refinery), and they are also normally transported by pipeline.

3.5 Markets
This section provides data on the volume of petroleum products produced and consumed in the United States, the quantit y of products imported and expor ted, and the average prices of major petroleum products. The section concludes with a discussion of future trends for the petroleum refining industry.

3.5.1 U.S. Petroleum Consumption
Figure 3-9 illustrates the amount of petr oleum products supplied between 2000 and 2006 (measured in millions of barrels of oil). These data represent the approximate consumption of petroleum products because it measures the di sappearance of these products from primary sources (i.e., refineries, natu ral gas processing plants, blendi ng plants, pipelines, and bulk terminals).3-25Table 3-9. Characteristics of Small Businesses in the Petroleum Refining IndustryParent CompanyParentCompanyTypeCumulativeCrudeCapacity(bbl/cd)ParentCompanySales($Millions)ParentCompanyEmployment (#)Facility Name Facility CityFacilityStateFacilityCountyCounty IDFacilityCountyPopulationDensity(2000)AGE Refining &ManufacturingPrivate 12,200 287 52AGE Refining &ManufacturingSan Antonio TX Bexar CountyTXBexarCounty1,117American RefiningGroupPrivate 10,000 350 310AmericanRefining GroupBradford PAMcKeanCountyPAMcKeanCounty47Arabian AmericanDevelopment CoPublic 0 80 118South HamptonResources Inc.Silsbee TXHardinCountyTXHardinCounty54Calcasieu RefiningCo.Private 30,000 638 51CalcasieuRefining Co.Lake Charles LACalcasieuParishLACalcasieuParish171Calumet SpecialtyProductsPublic 63,320 1,641 350Calumet SpecialtyProductsShreveport LA Caddo ParishLACaddoParish286Calumet SpecialtyProductsCotton Valley LA Caddo ParishLACaddoParish286Calumet SpecialtyProductsPrinceton LA Caddo ParishLACaddoParish286CountrymarkCooperative, Inc.Private 23,000 87 300CountrymarkCooperative, Inc.Mt. Vernon IN Posey CountyINPoseyCounty66Cross Oil &Refining Co. Inc.Private 7,200 49 110Cross Oil &Refining Co. Inc.Smackover ARUnionCountyARUnionCounty44CVR Energy Inc. Public 112,000 3,038 577CoffeyvilleResources LLCCoffeyville KSMontgomeryCountyKSMontgomeryCounty56Foreland RefiningCo.Private 2,000 56 100Foreland RefiningCo.Tonopah/EagleSpringsNV Nye County NVNye County 2Frontier Oil Corp Private 153,000 4,000 727Frontier Oil &Refining Co.Cheyenne WYLaramieCountyWYLaramieCounty30Frontier Oil Corp El Dorado KSButlerCountyKSButlerCounty42Gary-Williams Co Private 54,000 97 200WynnewoodRefining Co.Wynnewood OKGarvinCountyOKGarvinCounty34(Continued)3-26Table 3-9. Characteristics of Small Businesses inthe Petroleum Refining Industry (continued)Parent CompanyParentCompanyTypeCumulativeCrudeCapacity(bbl/cd)ParentCompanySales($Millions)ParentCompanyEmployment (#)Facility Name Facility CityFacilityStateFacilityCountyFacilityCountyPopulationDensity(2000)Goodway RefiningLLCPrivate 4,100 3 18Goodway RefiningLLCAtmore ALEscambiaCounty41Greka Integrated Inc Private 9,500 22 145 Greka Integrated Inc Santa Maria CASanta BarbaraCounty146Gulf AtlanticOperations LLCPrivate 16,700 9 32Gulf AtlanticOperations LLCMobile Bay AL Mobile County 324Holly Corp. Public 99,700 4,023 859 Holly Corp. Woods Cross UT Davis County 785Navajo Refining Co. Artesia NM Eddy County 12Hunt Refining Co. Private 45,500 4,871 1,100 Hunt Refining Co. Tuscaloosa ALTuscaloosaCounty125Hunt SouthlandRefiningLumberton MS Lamar County 79Hunt SouthlandRefiningSandersville MS Lamar County 79Lion Oil Co. Private 70,000 247 425 Lion Oil Co. El Dorado AR Union County 44Pelican Refining Co.LLCPrivate 0 29 62Pelican Refining Co.LLCLake Charles LACalcasieuParish171Placid Refining Inc. Private 56,000 1,400 200 Placid Refining Inc. Port Allen LAWest BatonRouge Parish113San Joaquin RefiningCo., Inc.Private 15,000 288 20San Joaquin RefiningCo., Inc.Bakersfield CA Kern County 81Somerset Oil Inc Private 5,500 55 150Somerset RefineryInc.Somerset KY Pulaski County 85Trigeant Ltd. Private 0 5 50 TrigeantLtd. Corpus Christi TX Nueces County 375(Continued)3-27Table 3-9. Characteristics of Small Businesses inthe Petroleum Refining Industry (continued)Parent CompanyParentCompanyTypeCumulativeCrudeCapacity(bbl/cd)ParentCompanySales($Millions)ParentCompanyEmployment (#)Facility Name Facility CityFacilityStateFacilityCountyFacilityCountyPopulationDensity(2000)Western Refining, Inc. Public 212,200 4,200 416Western Refining,Inc.El Paso TX El Paso County 671Giant Refining Co. Yorktown VA York County 533Giant Refining Co. Bloomfield NMSan JuanCounty21Giant Refining Co. Gallup NMMcKinleyCounty14World Oil Corp Private 8,500 277 475 Lunday-Thagard Co. South Gate CALos AngelesCounty2,344Wyoming Refining Co. Private 12,500 340 107Wyoming RefiningCo.Newcastle WY Weston County 3Total2,128,860 59,738 12,688Sources: Dun & Bradstreet. 2007.2007 D&B Million Dollar Directory. Pennsylvania: Dun & Bradstreet Inc.Dun & Bradstreet Small Business Solutions. Small Business Database. Available at <http://smallbusiness.dnb.com/default.asp?bhcd2=1107465546>.Gale Research Inc. 2007. Ward’s Business Directory of U.S. Private and Public Companies. Detroit: Gale Research.Hoovers. 2007. Free Content,Company Information. Available at <http://www.hoovers.com/free/>. As obtained on April 11, 2007.U.S. Department of Commerce, Bureau of the Census. 2000. “Population Density by County: Census 2000 Summary File 1 (SF 1) 100-Percent Data.”Available through American Fact Finder <http://factfinder.census.gov/home/saff/main.html?_lang=en>. As obtained on February 21,2008.3-28 Between 2000 and 2004, U.S. consumption of petroleum products increased by 5%. Consumption grew steadily from 2001 and 2004 befo re leveling off and slightly declining in 2006 (Figure 3-9). This reduced growth was primarily the result of less jet fuel and residual fuel being consumed in recent years (Table 3-10).

6,800 7,000 7,200 7,400 7,600 7,800

2000 2001 2002 2003 2004 2005 2006

Figure 3-9. Total Petroleum Products Supplied (millions of barrels per year)

Table 3-10. Total Petroleum Products Supplied (millions of barrels per year)

Year Motor Gasoline Jet Fuel Distillate Fuel Oil Residual Fuel Oil Liquefied Petroleum

Gases Other Products Total 2000 3,101 631 1,362 333 816 967 7,211 2001 3,143 604 1,404 296 746 978 7,172 2002 3,229 591 1,378 255 789 969 7,213 2003 3,261 576 1,433 282 757 1,003 7,312 2004 3,333 597 1,485 316 780 1,076 7,588 2005 3,343 613 1,503 336 741 1,057 7,593 2006 3,377 596 1,522 251 749 1,055 7,551
Source: U.S. Department of Energy, Energy Information Administration (EIA). 1996–2007 . “Petroleum Supply

Annuals, Volume 1.” Available at <http://www.eia.doe.gov/oil_gas/petroleum/data_publications/petroleum_ supply_annual/psa_volume1/psa_volume1.html>. As obtained on October 31, 2007.

3.5.2 U.S. Petroleum Production
Table 3-11 reports the number of barrels of major petroleu m products produced in the United States between 2000 and 2006. U.S. producti on of petroleum products at refineries and blenders grew steadily between 1995 and 2003. However, production declined by 0.35% in3-29 Table 3-11. U.S. Refinery and Blender Net Pr oduction (millions of barrels per year)

Year Motor Gasoline Jet Fuel Distillate Fuel Oil Residual Fuel Oil Liquefied Petroleum

Gases Other Products Total 2000 2,910 588 1,310 255 258 990 6,311 2001 2,928 558 1,349 263 243 968 6,309 2002 2,987 553 1,311 219 245 990 6,305 2003 2,991 543 1,353 241 240 1,014 6,383 2004 3,025 566 1,396 240 236 1,057 6,520 2005 3,036 564 1,443 229 209 1,015 6,497 2006 3,053 541 1,475 232 229 1,032 6,561
Source: U.S. Department of Energy, Energy Information Administration (EIA). 1996–2007. “Petroleum Supply

Annuals, Volume 1.” Available at <http://www.eia.doe.gov/oil_gas/petroleum/data_publications/petroleum_ supply_annual/psa_volume1/psa_volume1.html>. As obtained on October 31, 2007.

2005. This drop was possibly the result of damage in flicted by two hurricanes (Hurricane Katrina and Hurricane Rita) on the U.S. Gulf Coast—the location of many U.S. petroleum refineries (Section 3.4.2). According to the American Petrol eum Institute, approximately 30% of the U.S. refining industry was shut down as a result of the damage (API, 2006). In 2006, production of petroleum products rebounded, increasing 1% over 2004 levels. Additional production data are presented in Table 3-12, which reports the valu e of shipments of products produced by the petroleum refining indus try between 1997 and 2006.

3.5.3 International Trade
International trade is a growing component of the U.S. Petroleum refining industry. This
trend is demonstrated in Ta bles 3-13 and 3-14. Between 1995 and 2006, imports and exports of petroleum products increased by more than 50 %. While imports of most major petroleum products grew at approximately the same rate , the growth of petroleum product exports was driven largely by residual fuel oil and other petroleum products.

However, the United States remains a net importer of petroleum products. In 2006, the United States imported nearly three times more petroleum products than it exported. These imported petroleum products accounted for 17% of total petroleum products consumed that year (1,310 millions of barrels per year/7, 551 millions of barrels per year).3-30 Table 3-12. Value of Product Shipments of the Petroleum Refining Industry

Year Millions of $Reported Millions of $2005 1997 152,756 180,671 1998 114,439 136,746 1999 140,084 164,651 2000 210,187 237,425 2001 195,898 219,476 2002 186,761 210,647 2003 216,764 238,425 2004 290,280 306,328 2005 419,063 419,063 2006 489,051 470,037
Note: Numbers were adjusted for inflation using producer price index industry data for Total Manufacturing Industries (Table 5-6). Sources: U.S. Department of Commerce, Bureau of the Census. 2007. 2006 Annual Survey of Manufactures.

Obtained through American Fact Finder Database <http ://factfinder.census.gov/home/saff/main.html?_lang=en>. U.S. Department of Commerce, Bureau of the Census. 2003b. 2001 Annual Survey of Manufactures. M01(AS)-2.

Washington, DC: Government Printing Office. Available at <http://www.census.gov/prod/2003pubs/ m01as-2.pdf>. As obtained on March 4, 2008.
Table 3-13. Imports of Major Petroleum Pr oducts (millions of barrels per year)

Year Motor Gasoline Jet Fuel Distillate Fuel Oil Residual Fuel Oil Liquefied Petroleum

Gases Other Products Total 1995 97 35 71 68 53 262 586 1996 123 40 84 91 61 322 721 1997 113 33 83 71 62 345 707 1998 114 45 77 101 71 324 731 1999 139 47 91 86 66 344 774 2000 156 59 108 129 79 343 874 2001 166 54 126 108 75 400 928 2002 182 39 98 91 67 396 872 2003 189 40 122 119 82 397 949 2004 182 47 119 156 96 520 1,119 2005 220 69 120 193 120 587 1,310 2006 173 68 133 128 121 687 1,310
Source: U.S. Department of Energy, Energy Information Administration (EIA).1996–2007. “Petroleum Supply

Annuals, Volume 1.” Available at <http://www.eia.doe.gov/oil_gas/petroleum/data_publications/petroleum_ supply_annual/psa_volume1/psa_volume1.html>. As obtained on October 31, 2007.3-31 Table 3-14. Exports of Major Petroleum Pr oducts (millions of barrels per year)

Year Motor Gasoline Jet Fuel Distillate Fuel Oil Residual Fuel Oil Liquefied Petroleum

Gases Other Products Total 1995 38 8 67 49 21 128 312 1996 38 17 70 37 19 138 319 1997 50 13 56 44 18 147 327 1998 46 9 45 50 15 139 305 1999 40 11 59 47 18 124 300 2000 53 12 63 51 27 157 362 2001 48 10 44 70 16 159 347 2002 45 3 41 65 24 177 356 2003 46 7 39 72 20 186 370 2004 45 15 40 75 16 183 374 2005 49 19 51 92 19 183 414 2006 52 15 79 103 21 203 472 Source: U.S. Department of Energy, Energy Information Administration (EIA). 1996–2007. “Petroleum Supply

Annuals, Volume 1.” Available at <http://www.eia.doe.gov/oil_gas/petroleum/data_publications/petroleum_ supply_annual/psa_volume1/psa_volume1.html>. As obtained on October 31, 2007.

3.5.4 Market Prices
The average nominal prices of major petroleu m products sold to e nd users are provided for selected years in Table 3-15. 2 As these data illustrate, nomin al prices rose substantially between 2004 and 2006. In particular, the price of motor gasoline rose 48% over this 2-year period.

Table 3-15. Average Price of Major Petroleum Products Sold to End Users (cents per gallon)

Product 1995 2000 2002 2004 2005 2006 Motor gasoline 76.5 110.6 94.7 143.5 182.9 212.8 No. 1 distillate fuel 62 98.8 82.8 126.2 183.2 213.7 No. 2 distillate fuel 56 93.4 75.9 123.5 177.7 209.1 Jet fuel 54 89.9 72.1 120.7 173.5 199.8 Residual fuel oil 39.2 60.2 56.9 73.9 104.8 121.8

Note: Prices do not include taxes. Source: U.S. Department of Energy, Energy Information Administration (EIA). 2007b. “Refiner Petroleum Product

Prices by Sales Type.” Available at <http://tonto.eia.doe.gov/ dnav/pet/pet_pri_refoth_dcu_nus_m.htm>. As obtained on January 11, 2008.

The nominal prices domestic petroleum refiners receive for their products have also been rising much faster than prices received by other U.S. manufacturer s. This trend is demonstrated in Table 3-16 by comparing the producer price index (PPI) for the petr oleum refining industry

2 Sales to end users are those made directly to the consum er of the product. This includ es bulk consumers, such as agriculture, industry, and utilities, as well as residential and commercial consumers.3-32 Table 3-16. Producer Price Index Industry Data: 1995 to 2006

Petroleum Refining (NAICS 32411) Total Manufacturing Industries

Year PPI Annual Percentage Change in PPI PPI Annual Percentage Change in PPI 1995 74.5 3% 124.2 3% 1996 85.3 14% 127.1 2% 1997 83.1

− 3% 127.5 0% 1998 62.3

− 25% 126.2

− 1% 1999 73.6 18% 128.3 2% 2000 111.6 52% 133.5 4% 2001 103.1 –8% 134.6 1% 2002 96.3

− 7% 133.7

− 1% 2003 121.2 26% 137.1 3% 2004 151.5 25% 142.9 4% 2005 205.3 36% 150.8 6% 2006 241.0 17% 156.9 4%
Source: U.S. Bureau of Labor Statistics (BLS). 2007. “Pro ducer Price Index Industry Data: Customizable Industry

Data Tables.” Available at <http://www.bls.g ov/ppi/>. As obtained on October 11, 2007.

against the index for all manu facturing industries. Between 1995 and 2006, prices received by petroleum refineries for their products rose by 223%, while prices received by all manufacturing firms rose by 26%. The vast majority of this grow th in prices has been experienced in the years
after 2002.

3.5.5 Profitability of Petroleum Refineries
Estimates of the mean profit (before taxes) to net sales ratios for petroleum refiners are reported in Table 3-17 for the 2006–2007 fiscal year. These ratios were calculated by Risk Management Associates by dividing net income into revenues for 44 firms in the petroleum refining industry. They are broken down base d on the value of assets owned by the reporting
firms.

Table 3-17. Mean Ratios of Profit before Taxes as a Percentage of Net Sales for Petroleum Refiners, Sorted by Value of Assets

Fiscal Year Total Number of Statements 0 to 500,000 500,000 to 2 Million 2 Million to 10 Million 10 Million to 50 Million 50 Million to 100 Million 100 Million to 250 Million All Firms 4/1/2006– 3/31/2007 44 — — 4.6 6.5 — — 6.7

Source: Risk Management Association (RMA). 2008. Annual Statement Studies 2007-2008. Pennsylvania: RMA,

Inc.

As these ratios demonstrate, firms that report ed a greater value of a ssets also received a greater return on sales. For example, firms with assets valued between $10 and $50 million3-33 received a 6.5% average return on net sales, wh ile firms with assets valued between $2 and $10 million only received a 4.6% average return. The average return on sales for the entire industry
was 6.7%.

Obtaining profitability information specifically for small petroleum refining companies can be difficult as most of these firms are privat ely owned. However, five of the small, domestic petroleum refining firms identified in S ection 3.4.2.3 are publicly owned companies—the Arabian American Development Co., CVR Energy Inc., Calumet Specialty Products Partners, L.P., Holly Corporation, Western Refining, Inc. Pr ofit ratios were calculated for these companies using data obtained from their publicly avai lable 2006 income statements. These ratios are presented for in Table 3-18.

Table 3-18. Net Profit Margins for Publicly Owned, Small Petroleum Refiners: 2006

Company Net Income ($millions) Total Revenue ($millions) Net Profit Margin (%) Arabian American Development Co. 7.9 98.5 8.0% Calumet Specialty Products Partners 93.9 1,641.0 5.7% CVR Energy Inc. 191.6 3,037.6 6.3% Holly Corporation 266.6 4,023.2 6.6% Western Refining, Inc. 204.8 4,199.5 4.9%
Sources: Arabian American Developm ent Co. April 6, 2007. 10K for year ended December 31, 2006. EDGAR

Database. Available at <http://www.sec.gov/Archive s/edgar/data/7039/000095013407007709/0000950134-07- 007709-index.htm>. Calumet Specialty Products Partners. February 23 , 2007. 10K for year ende d December 31, 2006. EDGAR

Database. Available at <http://www.sec.gov/Archives/edgar/data/1340122/000095013407003992/ h43776e10vk.htm>. CVR Energy Inc. 2006. Google Finance. Available at <http://finance.google.com /finance?q=NYSE:CVI>. As obtained on February 28, 2008. Holly Corporation. March 1, 2007. 10K for year ended December 31, 2006. EDGAR Database. Available at <http://www.sec.gov/Archives/edgar/data/480 39/000095013407004555/d44106e10vk.htm>. Western Refining, Inc. March 8, 2007. 10K for year ended December 31, 2006. EDGAR Database. Available at <http://www.sec.gov/Archives/edgar/data/133 9048/000095013407005096/h44360e10vk.htm>.
3.5.6 Industry Trends
The Energy Information Administration’s (EIA’s) 2007 Annual Energy Outlook provides forecasts of average petroleum prices, petrol eum product consumption, and petroleum refining capacity utilization to th e year 2030. Trends in these variable s are affected by many factors that are difficult to predict, such as energy prices, U.S. economic growth, advances in technologies, changes in weather patterns, and future public po licy decisions. As a result, the EIA evaluated a wide variety of cases based on different assump tions of how these factors will behave in the future. This section focuses on the EIA’s “reference case” forecasts, which assume that current3-34 policies affecting the energy sector will re main unchanged throughout the projection period (EIA, 2007c).

According to the 2007 Annual Energy Outlook’s reference forecast, world oil prices (defined as the average price of low-sulfur, light crude oil) are expected to fall significantly over the next 10 years as the amount of oil supplie d by non-OPEC and OPEC countries increases. Since crude oil is the primary i nput in petroleum refining, a dec line in its pri ce would likewise represent a decline in production co sts of petroleum refiners. As a result, the prices of petroleum products sold to end users are expected to de cline over the same period (Table 3-19). These lower prices will, in turn, encourage more pe troleum products to be consumed (Table 3-20). Between 2007 and 2015, the prices of major pe troleum products are expected to fall approximately 20% to 25%, while consumption of those products is ex pected to rise by 9%.

Table 3-19. Forecasted Average Price of Major Petroleum Products Sold to End Users in 2005 Currency (cents per gallon)

Product 2007 2008 2009 2010 2011 2012 2013 2014 2015 Motor gasoline 257.4 241.3 227.3 217.3 209.2 204.7 201.1 195.2 194.9 Jet fuel 175.4 158.3 152.0 147.2 140.0 135.8 135.5 132.9 133.5 Distillate fuel 253.8 236.6 224.1 215.9 205.0 197.2 194.7 190.3 191.0 Residual fuel oil 123.5 125.8 120.6 113.9 107.7 102.8 96.6 95.9 98.0 LPGs 257.4 241.3 227.3 217.3 209.2 204.7 201.1 195.2 194.9
Source: U.S. Department of Energy, Energy Information Administration (EIA). 2007c. “Annual Energy Outlook.”

Available at <http://www.eia.doe.gov/oiaf/archive/aeo07/pd f/0383(2007).pdf>. As obtained on January 21, 2007.

Table 3-20. Total Petroleum Products Supplied (millions of barrels per year)

Year Motor Gasoline Jet Fuel Distillate Fuel Oil Residual Fuel Oil Liquefied Petroleum

Gases Other Products Total 2007 3,388 622 1,600 275 819 940 7,643 2008 3,407 646 1,613 278 824 953 7,721 2009 3,446 675 1,631 281 815 955 7,804 2010 3,479 713 1,654 287 809 937 7,879 2011 3,520 728 1,682 289 811 961 7,990 2012 3,563 739 1,710 294 812 958 8,076 2013 3,610 749 1,735 303 812 967 8,177 2014 3,663 758 1,755 306 814 953 8,249 2015 3,716 766 1,774 300 815 970 8,341
Source: U.S. Department of Energy, Energy Information Administration (EIA). 2007c. “Annual Energy Outlook.”

Available at <http://www.eia.doe.gov/oiaf/archive/aeo07/pd f/0383(2007).pdf>. As obtained on January 21, 2007.

Operational capacity of U.S. petroleum refine ries is also expected to grow for the foreseeable future. The expansion of dozens of petroleum refineries has already been announced (Reuters, 2007). The Oil & Gas Journal’s 2008 Worldwide Construction Update survey alone3-35 catalogued over 40 refining construc tion projects that have been announced in the United States. Table 3-21 lists selected refinery construction projects. The project s listed include two refinery expansion projects and six new processes (d istillation units, delayed cokers, and mild hydrocrackers).

Table 3-21. Selected Refinery Construction Projects: 2008–2011

Company and Location Project Projected Added Capacity (barrels per day) Expected Completion
Cenex Harvest States, Laurel, MT New delayed coker unit N/A 2008
Frontier Oil Corp, El Dorado, KS New crude distillation unit 15,000 2008
New vacuum distillation unit 15,000 2008
Holly Corp, Woods Cross, UT New Mild hydrocracker 15,000 2008 Artesia, NM New Mild hydrocrackert 15,000 2008
Motiva Enterprises LLC, Port Arthur, TX Refinery expansion 325,000 2010
Placid Refining Inc. New crude distillation unit 25,000 2010
Sinclair Oil Corp, Tulsa, OK Refinery expansion 45,000 2011

Source: Oil and Gas Journal . April 7, 2008.Worldwide Construction Update.

In particular, several U.S. refineries are plan ning projects to expand their ability to handle cheaper and lower-quality vari eties of crude oil (known as “heavy crudes”). For example, ConocoPhillips will be expanding its capacity to handle heavy crude oils at its refinery in Billings, Montana, to 46,000 barrels per day (Reuters, 2007).

In addition to these expansions, two entire ly new refineries could potentially be constructed within the next 5 years. The first is the Arizona Clean Fuel s Refinery in Phoenix. This facility will cost $3 billion to construct and will be capable of producing 6 million gallons of gasoline, diesel, and jet fuel per day (A rizona Clean Fuels, 2007). Second, a proposal to construct the MHA Nation Clean Fuels Refinery in North Dakota is being reviewed. If constructed, this facili ty will be capable of producing 15,000 ba rrels of fuel per day (EPA, 2006).

Overall, the EIA forecasts that U.S. operati onal capacity will increa se by a total of 2% between 2007 and 2015 (Table 3-22). However, since consumption of petroleum products is projected to grow much more quick ly, the rate of capacity utiliza tion is projected to average 90% during this period.3-36 Table 3-22. Full Production Capacity Util ization Rates for Petroleum Refineries

Year Petroleum Refineries Capacity Utilization Rates (NAICS 324110) Gross Input to Atmospheric Crude Oil Distillation Units (1,000s of barrels per day) Operational Capacity (1,000s of barrels per day) 2007 88.8% 15,630 17,597 2008 88.1% 15,587 17,684 2009 88.6% 15,712 17,737 2010 89.1% 15,879 17,822 2011 89.9% 16,055 17,852 2012 90.9% 16,267 17,897 2013 91.4% 16,378 17,914 2014 91.6% 16,433 17,940 2015 92.2% 16,628 18,031
Source: U.S. Department of Energy, Energy Information Administration (EIA). 2007c. “Annual Energy Outlook.”

Available at <http://www.eia.doe.gov/oiaf/archive/aeo07/pd f/0383(2007).pdf>. As obtained on January 21, 2007.

3.6 References American Petroleum Institute (API). 2006. “FYI on Refineries: Operating at Record Levels.” Available at <http://new.api.org/aboutoilgas/sectors/refining/upload/ FYI_Refineries.pdf>. As obtained on October 31, 2006.

Arizona Clean Fuels. 2007. Comp any Home Page. Available at <http://www.arizonacleanfuels.com/>. As obtained on February 5, 2007.

Arabian American Development Co. April 6, 2007. 10K for year ended December 31, 2006. EDGAR Database. Available at <htt p://www.sec.gov/Archives/edgar/data/ 7039/000095013407007709/0000950134-07-007709-index.htm>.

Calumet Specialty Products Partners. Febr uary 23, 2007. 10K for year ended December 31, 2006. EDGAR Database. Available at <htt p://www.sec.gov/Archives/edgar/data/ 1340122/000095013407003992/h43776e10vk.htm>.

CVR Energy Inc. 2006. Google Finance. Available at <http://finance.google.com/finance?q=NYSE:CVI>. As obtained on February 28, 2008.

Dun & Bradstreet Small Business Solutions. Small Business Database. Available at <http://smallbusiness.dnb.com /default.asp?bhcd2=1107465546>.

Dun & Bradstreet. 2007. 2007 D&B Million Dollar Directory . Pennsylvania: Dun & Bradstreet Inc.
Federal Trade Commission (FTC). 2004. “The Petrol eum Industry: Mergers, Structural Change, and Antitrust Enforcement.” Availabl e at <http://www.ft c.gov/opa/2004/08/ oilmergersrpt.shtm>. As obtained on February 6, 2007.

Gale Research Inc. 2007. Ward’s Business Direct ory of U.S. Private and Public Companies. Detroit: Gale Research.3-37 General Accounting Office (FTC). 2007. “Energy Markets: Factors That Influence Gasoline Prices.” Available at <http://www.gao.gov/ new.items/d07902t.pdf>. As obtained on February 6, 2007.

Holly Corporation. March 1, 2007. 10K for year ended December 31, 2006. EDGAR Database. Available at <http://www.sec.gov/Archives/edgar/data/48039/000095013407004555/ d44106e10vk.htm>.

Hoovers. 2007. Free Content, Company Information. Available at <http://www.hoovers.com/free/>. As obtained on April 11, 2007.

Langinier, Corrine. 2004. “Are Patent s Strategic Barriers to Entry?” Journal of Economics and Business 56:349-361.

MathTech, Inc. 1997. “Industry Profile for the Pe troleum Refinery NESHAP.” Available at <http://www.epa.gov/ttnecas1/regdata/ IPs/Petroleum%20Refinery%20 (Sulfur%20Recovery%20Units,%20Catalytic% 20Crackin.pdf>. As obtained on October 31, 2006.

Nicholson, Walter. 2005. Microeconomic Theory: Basic Principles and Extensions . Mason, OH: South-Western Publishing.

Oil and Gas Journal. April 7, 2008.W orldwide Construction Update..

Risk Management Association (RMA). 2008. Annual Statement Studies 2007-2008. Pennsylvania: RMA, Inc.

Reuters. July 19, 2007. “U.S. Refinery Expansion Plans.” Available at <http://uk.reuters.com/ article/oilRpt/idUKN1997 46120070719>. As obtained on February 5, 2007.

Small Business Administration. 2006. Table of Sm all Business Size Standards. Available at <http://www.sba.gov/idc/groups/public/documents/sba_homepage/serv_table_pdf>. As obtained on November 30, 2006.

U.S. Bureau of Labor Statistics (BLS). 2007. “Pr oducer Price Index Industry Data: Customizable Industry Data Tables.” Available at <http ://www.bls.gov/ppi/>. As obtained on October 11, 2007.

U.S. Department of Commerce, Bureau of the Census. 1997. 1995 Annual Survey of Manufacture s. M95(AS)-1. Washington, DC: Governme nt Printing Office. Available at <http://www.census.gov/prod/2/manmin/asm/m95as1.pdf>. As obtained on October 23, 2006.

U.S. Department of Commerce, Bureau of the Census. 1998. 1996 Annual Survey of Manufacture s. M96(AS)-1 (RV). Washington, DC : Government Printing Office. Available at <http://www.census.gov/prod/3/98pubs/m96-as1.pdf>. As obtained on October 23, 2006.3-38 U.S. Department of Commerce, Bureau of the Census. 2000. “Population Density by County: Census 2000 Summary File 1 (SF 1) 100-Per cent Data”. Available through American Fact Finder <http://fac tfinder.census.gov/home/saff/main.html?_lang=en>. As obtained on February 21, 2008.

U.S. Department of Commerce, Bureau of the Census. 2001. 1999 Annual Survey of Manufacture s. M99(AS)-1 (RV). Washington, DC : Government Printing Office. Available at <http://www.census.gov/prod/2001pubs/m99-as1.pdf>. As obtained on October 23, 2006.

U.S. Department of Commerce, Bureau of the Census. 2003a. 2001 Annual Survey of Manufacture s. M01(AS)-1. Washington, DC: Governme nt Printing Office. Available at <http://www.census.gov/prod/2003pubs/m01as-1.pdf>. As obtained on October 23, 2006.

U.S. Department of Commerce, Bureau of the Census. 2003b. 2001 Annual Survey of Manufactures . M01(AS)-2. Washington, DC: Governme nt Printing Office. Available at <http://www.census.gov/prod/2003pubs/m01as-2.pdf. As obtained on March 4, 2008.

U.S. Department of Commerce, Bureau of the Census. 2004. 2002 Economic Census, Industry Series—Petroleum Refineries . Washington, DC: Government Printing Office. Available at <http://www.census.gov/prod/ec02/ec0231i 324110.pdf>. As obtained on October 23, 2006.

U.S. Department of Commerce, Bureau of the Census. 2006. 2005 Annual Survey of Manufacture s. M05(AS)-1. Washington, DC: Governme nt Printing Office. Available at <http://www.census.gov/prod/2005pubs/am043 1gs1.pdf>. As obtained on October 23, 2006.

U.S. Department of Commerce, Bureau of the Census. 2007. 2006 Annual Survey of Manufactures. Obtained through Am erican Fact Finder Database <http://factfinder.census.gov/home/saff/main.html?_lang=en>.

U.S. Department of Energy, Energy Informa tion Administration (EIA ). 1996–2007. “Petroleum Supply Annuals, Volume 1.” Availabl e at <http://www.eia.doe.gov/oil_gas/ petroleum/data_publications/petro leum_supply_annual/psa_volume1/psa_ volume1.html>. As obtained on October 31, 2007.

U.S. Department of Energy, Energy Informati on Administration (EIA). 2006a. “A Primer on Gasoline Prices.” Available at <http ://www.eia.doe.gov/bookshelf/brochures/ gasolinepricesprimer/printerversion. pdf>. As obtained on October 31, 2007.

U.S. Department of Energy, Energy Information Administration (EIA). 1999a. “Petroleum: An Energy Profile 1999.” DOE/EIA-0545(99). Avai lable at <http://tonto.eia.doe.gov/ FTPROOT/petroleum/054599.pdf>. As obtained on October 23, 2006.3-39 U.S. Department of Energy, Energy Informa tion Administration (E IA). 2006b. “Refinery Capacity Report 2006.” Available at <h ttp://www.eia.doe.gov/oil_gas/petroleum/ data_publications/refinery_capacity_data/ref capacity.html/>. As obtained on October 23, 2006.

U.S. Department of Energy, Energy Informati on Administration (EIA). 2006c. “Petroleum Supply Annual 2005, Volume 1.” Available at <http://www.eia.doe.gov/pub/oil_gas/ petroleum/data_publications/petroleum_s upply_annual/psa_volume1 /historical/2005/psa _volume1_2005.html>. As obt ained on October 31, 2007.

U.S. Department of Energy, Energy Informa tion Administration (EIA ). 2007a. “Refinery Utilization and Capacity.” Available at <http://tonto.eia.doe.gov/dnav/pet/ pet_pnp_unc_dcu_nus_m.htm>. As obtained on January 7, 2008.

U.S. Department of Energy, Energy Informa tion Administration (E IA). 2007b. “Refiner Petroleum Product Prices by Sales Type.” Available at <http://tonto.eia.doe.gov/ dnav/pet/pet_pri_refoth_dcu_nus_m.htm >. As obtained on January 11, 2008.

U.S. Department of Energy, Energy Informati on Administration (EIA). 2007c. “Annual Energy Outlook.” Available at <http://www.eia.doe .gov/oiaf/archive/ae o07/pdf/0383(2007).pdf>. As obtained on January 21, 2007.

U.S. Department of Justice and the Fede ral Trade Commission. 1992. Horizontal Merger Guidelines. Available at <http://www.ftc .gov/bc/docs/horizmer.htm>. As obtained on October 28, 2006.

U.S. Department of Labor, Occupational Sa fety and Health Administration (OSHA). 2003. OSHA Technical Manual, Section IV: Chapte r 2, Petroleum Refining Processes. TED 01- 00-015. Washington, DC: U.S. DOL. Availa ble at <http://www.osha.gov/dts/osta/ otm/otm_iv/otm_iv_2.html>. As obtained on October 23, 2006.

U.S. Environmental Protection Agency. 1995. “EPA Office of Compliance Sector Notebook Project: Profile of the Petroleum Refi ning Industry.” EPA/310- R-95-013. Washington, DC: U.S. EPA. Available at <http://www.epa.gov/compliance/resources/ publications/assistance/ sectors/notebooks/petrefsn.pdf>. As obtained on October 23, 2006.

U.S. Environmental Protection Agency. 2006. “P roposed MHA Nation Clean Fuels Refinery.” Available at <http://www.epa.gov/Region8/co mpliance/nepa/refinerydeis.html>. As obtained on February 6, 2007.

Western Refining, Inc. March 8, 2007. 10K for year ended December 31, 2006. EDGAR Database. Available at <http://www. sec.gov/Archives/edgar/data/1339048/000095 013407005096/h44360e10vk.htm>.A-1 APPENDIX A:
PARENT COMPANY INFORMATION FOR PETROLEUM REFINERIESA-2Appendix A. Parent Company Information for Petroleum RefineriesaFacility Name City StateCapacity(bbl/cd)ForeignorDomesticSales($million) EmploymentCompanyType(Private orPublic orSubsidiary)OwningCompanyOwningCompanyTypeSales($million) Employment (#) SourceYear ofDataAGE Refining &Manufacturing San Antonio TX 12,200 D 287 52 Private D&B UnknownAlon USA Energy Inc. Big Spring TX 67,000 F SubsidiaryAlon Israel OilCompany LTD Private NA NAAmerican RefiningGroup Bradford PA 10,000 D 350 310 Private D&B UnknownBig West of CA Bakersfield CA 66,000 D Subsidiary Flying J Inc Private 11,350 16,300 Hoovers 2007Big West Oil Co. Salt Lake City UT 29,400 D Subsidiary Flying J Inc Private 11,350 16,300 Hoovers 2007BP Whiting IN 410,000 F SubsidiaryBP PLC Public 274,316 97,000 Hoovers 2007BP Texas City TX 437,000 F Subsidiary BP PLC Public 274,316 97,000 Hoovers 2007BP Prudhoe Bay AK 12,500 F SubsidiaryBP PLC Public 274,316 97,000 Hoovers 2007BP Carson CA 260,000 F SubsidiaryBP PLC Public 274,316 97,000 Hoovers 2007BP Ferndale WA 225,000 F SubsidiaryBP PLC Public 274,316 97,000 Hoovers 2007BP Toledo OH 131,000 F SubsidiaryBP PLC Public 274,316 97,000 Hoovers 2007Calcasieu Refining Co. Lake Charles LA 30,000D 638 51 Private D&B UnknownCalumet SpecialtyProducts Shreveport LA 42,000 D 1,641 350 Public Hoovers 2006Calumet SpecialtyProducts Cotton Valley LA 13,020 D 1,641350 Public Hoovers 2006Calumet SpecialtyProducts Princeton LA 8,300 D 1,641 350 Public Hoovers 2006Cenex Harvest States Laurel MT 55,000 D 11,900 6,370 PublicChevron USA Inc. Perth Amboy NJ 80,000 D SubsidiaryChevronCorporation Public 210,118 62,500 Hoovers 2006Chevron USA Inc. Salt Lake City UT 45,000 D SubsidiaryChevronCorporation Public 210,118 62,500 Hoovers 2006Chevron USA Inc. Portland OR D SubsidiaryChevronCorporation Public 210,118 62,500 Hoovers 2006Chevron USA Inc. Pascagoula MS 330,000 D SubsidiaryChevronCorporation Public 210,118 62,500 Hoovers 2006(continued)A-3Appendix A. Parent Company Informationfor Petroleum Refineries (continued)Facility Name City StateCapacity(bbl/cd)ForeignorDomesticSales($million) EmploymentCompanyType(Private orPublic orSubsidiary)OwningCompanyOwningCompanyTypeSales($million)Employment(#) SourceYear ofDataChevron USA Inc. El Segundo CA 260,000 D SubsidiaryChevronCorporation Public 210,118 62,500 Hoovers 2006Chevron USA Inc. Richmond CA 242,901 D SubsidiaryChevronCorporation Public 210,118 62,500 Hoovers 2006Chevron USA Inc.Honolulu (Barber'sPoint) HI 54,000 D SubsidiaryChevronCorporation Public 210,118 62,500 Hoovers 2006Citgo Corpus Christi TX 156,000 F SubsidiaryPetróleos deVenezuela S.A.(PDVSA)GovernmentOwned NA 49,180 Hoovers 2004Citgo AsphaltRefining Co. Paulsboro NJ 32,000 F SubsidiaryPetróleos deVenezuela S.A.(PDVSA)GovernmentOwned NA 49,180 Hoovers 2004Citgo Petroleum Savannah GA 28,000 F SubsidiaryPetróleos deVenezuela S.A.(PDVSA)GovernmentOwned NA 49,180 Hoovers 2004Citgo PetroleumCorp. Lake Charles LA 429,500 F SubsidiaryPetróleos deVenezuela S.A.(PDVSA)GovernmentOwned NA 49,180 Hoovers 2004CoffeyvilleResources LLC Coffeyville KS 112,000 D 3,038 577 PublicCVR EnergyInc. Hoovers 2006ConocoPhillips Westlake LA 239,400 D 188,52338,400 Public Hoovers 2006ConocoPhillips Ponca City OK 194,000 D 188,523 38,400 Public Hoovers 2006ConocoPhillips Billings MT 58,000 D 188,52338,400 Public Hoovers 2006ConocoPhillips Borger TX 146,000 D 188,52338,400 Public Hoovers 2006ConocoPhillips Sweeny TX 247,000 D 188,523 38,400 Public Hoovers 2006ConocoPhillips Ferndale WA96,000 D 188,523 38,400 Public Hoovers 2006ConocoPhillips Linden NJ 238,000 D 188,523 38,400 Public Hoovers 2006ConocoPhillips Wood River IL 306,000 D 188,52338,400 Public Hoovers 2006ConocoPhillipsLA -Carson/Wilmington CA 139,000 D 188,523 38,400Public Hoovers 2006(continued)A-4Appendix A. Parent Company Informationfor Petroleum Refineries (continued)Facility Name City StateCapacity(bbl/cd)ForeignorDomesticSales($million) EmploymentCompanyType(Private orPublic orSubsidiary)OwningCompanyOwningCompanyTypeSales($million)Employment(#) SourceYear ofDataConocoPhillips SF - Rodeo CA 76,000 D 188,52338,400 Public Hoovers 2006ConocoPhillipsArroyo Grande(Santa Maria) CA 44,200 D 188,523 38,400Public Hoovers 2006ConocoPhillips Belle Chasse LA 247,000 D 188,523 38,400 Public Hoovers 2006ConocoPhillipsTrainer (MarcusHook) PA 185,000 D 188,523 38,400 Public Hoovers 2006ConocoPhillips Kuparuk AK 14,000 D 188,523 38,400 Public Hoovers 2006CountrymarkCooperative, Inc. Mt. Vernon IN 23,000 D 87 300 PrivateCross Oil & RefiningCo. Inc. Smackover AR 7,200 D 49 110 PrivateDelek Refining Ltd Tyler TX 58,000 F SubsidiaryDelek GroupLTD Public 6,237 2,803 Hoovers 2006Edgington Oil Co. Long Beach CA 26,000 F SubsidiaryAlon Israel OilCompany LTD Private NA NAErgon Refining Inc. Vicksburg MS 23,000 DSubsidiary Ergon, Inc. Private 1,300 2,300Ergon-West VirginiaInc. Newell (Congo) WV 20,000 D Subsidiary Ergon, Inc. Private 1,300 2,300ExxonMobil Corp. Baton Rouge LA 501,000 D 377,635 82,100 Public Hoovers 2006ExxonMobil Corp. Billings MT 60,000 D 377,63582,100 Public Hoovers 2006ExxonMobil Corp. Joliet IL 238,500 D 377,635 82,100 Public Hoovers 2006ExxonMobil Corp. Beaumont TX 348,500 D 377,635 82,100 Public Hoovers 2006ExxonMobil Corp. Torrance CA 149,500 D 377,635 82,100 Public Hoovers 2006ExxonMobil Corp. Chalmette LA 188,160 D 377,635 82,100 Public Hoovers 2006ExxonMobil Oil Corp Baytown TX 562,500 D SubsidiaryExxonMobilCorp. Public 377,635 82,100 Hoovers 2006Flint Hills Resources Corpus Christi TX 288,126 D SubsidiaryKoch IndustriesInc Private 51,500 85,000Flint Hills Resources North Pole AK 210,000 D SubsidiaryKoch IndustriesInc Private 51,500 85,000(continued)A-5Appendix A. Parent Company Informationfor Petroleum Refineries (continued)Facility Name City StateCapacity(bbl/cd)ForeignorDomesticSales($million) EmploymentCompanyType(Private orPublic orSubsidiary)OwningCompanyOwningCompanyTypeSales($million)Employment(#) SourceYear ofDataFlint Hills Resources Rosemount MN 279,300 D SubsidiaryKoch IndustriesInc Private 51,500 85,000Foreland Refining Co.Tonopah/EagleSprings NV 2,000 D 56 100 Private D&B UnknownFrontier Oil & RefiningCo. Cheyenne WY 47,000 D Subsidiary Frontier Oil Corp Private 4,000 727Frontier Oil Corp El Dorado KS 106,000 D 4,000 727 PrivateGiant Refining Co. Yorktown VA 58,600 D SubsidiaryWestern Refining,Inc. Private 4,200 416 Hoovers 2006Giant Refining Co. Bloomfield NM 16,800 D SubsidiaryWestern Refining,Inc. Private 4,200 416 Hoovers 2006Giant Refining Co. Gallup NM 20,800 D SubsidiaryWestern Refining,Inc. Private 4,200 416 Hoovers 2006Goodway Refining LLC Atmore AL 4,100 D 3 18 Private D&B UnknownGreka Integrated Inc Santa Maria CA 9,500 D 22 145 PrivateGulf AtlanticOperations LLC Mobile Bay AL 16,700 D 9 32 Private D&B UnknownHess Corporation Port Reading NJ D 23,200 11,610 PublicHolly Corp. Woods Cross UT 24,700 D 4,023 859 Public Hoovers 2006Hunt Refining Co. Tuscaloosa AL 34,500 D 4,871 1,100 Private Ward's 2007Hunt SouthlandRefining Lumberton MS D SubsidiaryHunt RefiningCo. Private 4,871 1,100 Ward's 2007Hunt SouthlandRefining Sandersville MS 11,000 D SubsidiaryHunt RefiningCo. Private 4,871 1,100 Ward's 2007Kern Oil & RefiningCo. Bakersfield CA 26,000 D NA NA PrivateLion Oil Co. El Dorado AR 70,000 D 247 425 PrivateLittle America RefiningCo.Evansville(Casper) WY 24,500 D SubsidiarySinclairCompanies Private 5,500 7,000Lunday-Thagard Co. South Gate CA 8,500 D Subsidiary World Oil Corp Private 277 475 Hoovers 2007(continued)A-6Appendix A. Parent Company Informationfor Petroleum Refineries (continued)Facility Name City StateCapacity(bbl/cd)ForeignorDomesticSales($million) EmploymentCompanyType(Private orPublic orSubsidiary)OwningCompanyOwningCompanyTypeSales($million)Employment(#) SourceYearofDataLyondell-CitgoRefining Co. Houston TX 270,200 D SubsidiaryLyondellChemical Co Public 18,600 10,880Marathon PetroleumCo. LLC Robinson IL 192,000 D SubsidiaryMarathon OilCorp Public 65,449 28,195 Hoovers 2006Marathon PetroleumCo. LLC Catlettsburg KY 222,000 D SubsidiaryMarathon OilCorp Public 65,449 28,195 Hoovers 2006Marathon PetroleumCo. LLC Detroit MI 100,000 D SubsidiaryMarathon OilCorp Public 65,449 28,195 Hoovers 2006Marathon PetroleumCo. LLC Canton OH 73,000 D SubsidiaryMarathon OilCorp Public 65,449 28,195 Hoovers 2006Marathon PetroleumCo. LLC St. Paul Park MN 70,000 D SubsidiaryMarathon OilCorp Public 65,449 28,195 Hoovers 2006Marathon PetroleumCo. LLC Texas City TX 72,000 D SubsidiaryMarathon OilCorp Public 65,449 28,195 Hoovers 2006Marathon PetroleumCo. LLC Garyville LA 245,000 D SubsidiaryMarathon OilCorp Public 65,449 28,195 Hoovers 2006Montana Refining Co. Great Falls MT 8,200 F SubsidiaryConnacher Oiland Gas Limited Public NA NAMotiva Enterprises Norco LA 226,500 D 32,100 2,700 PrivateMotiva Enterprises Port Arthur TX 285,000 D 32,100 2,700 PrivateMotiva Enterprises Convent LA 235,000 D 32,100 2,700 PrivateMurphy Oil USA Inc. Superior WI 34,300 D Subsidiary Murphy Oil Corp Public 14,307 7,296 Hoovers 2006Murphy Oil USA Inc. Meraux LA 120,000 D Subsidiary Murphy Oil Corp Public 14,307 7,296 Hoovers 2006National CooperativeRefinery Association McPherson KS 81,200 D SubsidiaryCenex HarvestStates Public 11,900 6,370Navajo Refining Co. Artesia NM 75,000 D Subsidiary Holly Corp. Public 4,023 859 Hoovers 2006Paramount PetroleumCorp. Paramount CA 50,000 F SubsidiaryAlon Israel OilCompany LTD Private NA NAPasadena RefiningSystems Inc. Pasadena TX 100,000 F SubsidiaryPetroleoBrasileiro, S.A.GovernmentOwned 72,347 62,266 Hoovers 2006(continued)A-7Appendix A. Parent Company Informationfor Petroleum Refineries (continued)Facility Name City StateCapacity(bbl/cd)Foreign orDomesticSales($million) EmploymentCompanyType(Private orPublic orSubsidiary)OwningCompanyOwningCompanyTypeSales($million)Employment(#) SourceYear ofDataPDV Midwest Refining Lemont IL 167,000 F SubsidiaryPetróleos deVenezuela S.A.(PDVSA)GovernmentOwned NA NAPelican Refining Co.LLC Lake Charles LA D 29 62 PrivatePetro Star Inc. North Pole AK 17,000 D SubsidiaryArctic SlopeRegional Corp Private 1,500 5,743Petro Star Inc. Valdez AK 48,000 D SubsidiaryArctic SlopeRegional Corp Private 1,500 5,743Placid Refining Inc. Port Allen LA 56,000 D 1,400 200 PrivateSan Joaquin RefiningCo., Inc. Bakersfield CA 15,000 D 288 20 PrivateShell Chemical LP St. Rose LA 55,000 F SubsidiaryRoyal DutchShell, PLC Public 312,323 108,000 Hoovers 2006Shell Chemical LP Saraland AL 80,000 F SubsidiaryRoyal DutchShell, PLC Public 312,323 108,000 Hoovers 2006Shell Oil Products US Anacortes WA 145,000 F SubsidiaryRoyal DutchShell, PLC Public 312,323 108,000 Hoovers 2006Shell Oil Products US Martinez CA 155,600 F SubsidiaryRoyal DutchShell, PLC Public 312,323 108,000 Hoovers 2006Shell Oil Products US Wilmington CA 98,500 F SubsidiaryRoyal DutchShell, PLC Public 312,323 108,000 Hoovers 2006Shell Oil Products US -Deer Park RefiningLimited Partnership Deer Park TX 333,700 F SubsidiaryRoyal DutchShell, PLC Public 312,323 108,000 Hoovers 2006Silver Eagle RefiningInc. Evanston WY 3,000 D NA NA PrivateSilver Eagle RefiningInc. Woods Cross UT 10,250 D NA NA PrivateSinclair Oil Corp. Tulsa OK 70,300 D SubsidiarySinclairCompanies Private 5,500 7,000(continued)A-8Appendix A. Parent Company Informationfor Petroleum Refineries (continued)Facility Name City StateCapacity(bbl/cd)ForeignorDomesticSales($million) EmploymentCompanyType(Private orPublic orSubsidiary)OwningCompanyOwningCompanyTypeSales($million) Employment (#) SourceYear ofDataSinclair Oil Corp. Sinclair WY 66,000 D SubsidiarySinclairCompanies Private 5,500 7,000Somerset Refinery Inc. Somerset KY 5,500 DSubsidiary Somerset Oil Inc Private 55 150South HamptonResources Inc. Silsbee TX D SubsidiaryArabianAmericanDevelopment Co Public 80 118Suncor Energy Commerce City CO 62,000 F SubsidiarySuncor EnergyInc Public 13,583 5,152 Hoovers 2006Suncor Energy Denver CO 32,000 F SubsidiarySuncor EnergyInc Public 13,583 5,152 Hoovers 2006Sunoco, Inc. Westville NJ 145,000 D 38,71514,000 Public Hoovers 2006Sunoco, Inc. Marcus Hook PA 175,000 D 38,71514,000 Public Hoovers 2006Sunoco, Inc. Toledo OH 160,000 D 38,715 14,000 Public Hoovers 2006Sunoco, Inc. Tulsa OK 85,000 D 38,715 14,000 Public Hoovers 2006Sunoco, Inc.Phil. (Girard Pt &Pt Breeze) PA 335,000 D 38,715 14,000 Public Hoovers 2006Ten By Inc. Oxnard CA 2,800 NA NATesoro Mandan ND 58,000 D SubsidiaryTesoro Corp Public 18,104 3,950 Hoovers 2006Tesoro Salt Lake City UT 58,000 D Subsidiary Tesoro Corp Public 18,104 3,950 Hoovers 2006Tesoro Anacortes WA 120,000 D Subsidiary Tesoro Corp Public 18,104 3,950 Hoovers 2006Tesoro Golden Eagle CA 166,000 D Subsidiary Tesoro Corp Public 18,104 3,950 Hoovers 2006Tesoro Kapolei HI 93,500 D SubsidiaryTesoro Corp Public 18,104 3,950 Hoovers 2006Tesoro Kenai AK 72,000 D SubsidiaryTesoro Corp Public 18,104 3,950 Hoovers 2006Total SA Port Arthur TX 232,000 F 175,189 95,070 Public Hoovers 2005Trigeant Ltd. Corpus Christi TX D 5 50 Private D&B UnknownUnited Refining Co. Warren PA 65,000 D SubsidiaryRed Apple GroupInc Private 4,200 7,000US Oil & Refining Co. Tacoma WA 37,850 NA NAValero Energy Corpus Christi TX 142,000 D 91,833 21,836 Public Hoovers 2006(continued)A-9Appendix A. Parent Company Informationfor Petroleum Refineries (continued)Facility Name City StateCapacity(bbl/cd)ForeignorDomesticSales($million) EmploymentCompanyType(Private orPublic orSubsidiary)OwningCompanyOwningCompanyTypeSales($million) Employment (#) SourceYear ofDataValero Energy Houston TX 83,000 D 91,833 21,836 Public Hoovers 2006Valero Energy Texas City TX 213,750 D 91,833 21,836 Public Hoovers 2006Valero Energy Krotz Springs LA 80,000 D 91,833 21,836 Public Hoovers 2006Valero Energy Benicia CA 144,000 D 91,833 21,836 Public Hoovers 2006Valero Energy Wilmington CA 6,200 D 91,83321,836 Public Hoovers 2006Valero Energy Norco LA 185,003 D 91,833 21,836 Public Hoovers 2006Valero Energy Delaware City DE 181,500 D 91,83321,836 Public Hoovers 2006Valero Energy Lima OH 146,900 D 91,833 21,836 Public Hoovers 2006Valero Energy Memphis TN 180,000 D 91,833 21,836 Public Hoovers 2006Valero Energy Three Rivers TX 90,000 D 91,833 21,836 Public Hoovers 2006Valero Energy Sunray TX 158,327 D 91,833 21,836 Public Hoovers 2006Valero Energy Ardmore OK 83,640 D 91,833 21,836 Public Hoovers 2006Valero Energy Wilmington CA 80,887 D 91,83321,836 Public Hoovers 2006Valero Energy Paulsboro NJ 160,000 D 91,83321,836 Public Hoovers 2006Valero Energy Port Arthur TX 260,000 D 91,833 21,836 Public Hoovers 2006Western Refining, Inc. El Paso TX 116,000 D4,200 416 Public Hoovers 2006Wynnewood RefiningCo. Wynnewood OK 54,000 D 97 200 SubsidiaryGary-WilliamsCo PrivateNote: All data were collected from the 2007 D&B Million Dollar Direction unless noted other wise. Data collected from the 2006D&B Small Business Databaseare indicated using “D&B” in the source column. Data collected from Ward’s BusinessDirectory are identified using “Ward’s” inthe source column.aThese data are shown with the permission of D&B.Sources: Dun & Bradstreet. 2007.2007 D&B Million Dollar Directory. Pennsylvania: Dun & Bradstreet Inc.Dun & Bradstreet Small Business Solutions. Small Business Database. Available at <http://smallbusiness.dnb.com/default.asp?bhcd2=1107465546>.Gale Research Inc. 2007. Ward’s Business Directory ofU S Private and Public Companies. Detroit: Gale Research.Hoovers. 2007. Free Content,Company Information. Available at <http://www.hoovers.com/free/>. As obtained on April 11, 2007.4-1 SECTION 4 NSPS REGULATORY OPTIONS, COSTS AND EMISSION REDUCTIONS FROM
COMPLYING WITH THE NSPS

This section of the RIA provide s descriptions of the regulator y options considered in the developing of this final NSPS, and also the co sts and emission reductions estimated for each option. An appendix to this se ction (Appendix B) provides deta ils on the rationale behind the choice of each option that is included in this NSPS.

4.1 Background Information on the Setting of NSPS
New source performance standards (NSPS) implement CAA section 111(b) and are issued for categories of sources which cause, or contribute significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare. The primary purpose of the NSPS is to attain and maintain ambient air qua lity by ensuring that the best demonstrated emission control technologies are installed as the indus trial infrastructure is modernized. Since 1970, the NSPS have been successful in achieving long-term emissions reductions in numerous industries by assuring cost-effectiv e controls are installed on ne w, reconstructed, or modified

sources.

Section 111 of the CAA requires that NSPS reflect the applica tion of the best system of emission reductions which (taking into consid eration the cost of ach ieving such emission reductions, any non-air quality health and enviro nmental impact and energy requirements) the Administrator determines has been adequately de monstrated. This level of control is commonly referred to as best demonstrated technology (BDT).

Section 111(b)(1)(B) of the CAA requires EPA to periodically revi ew and revise the standards of performance, as necessary, to reflect improvements in methods for reducing emissions. As a result of our periodic review of the NSPS for petroleum refineries (40 CFR part 60, subpart J), we proposed amendments to the cu rrent standards of performance and separate standards of performance for new process uni ts (72 FR 27278, May 14, 2007). In response to several requests, we extended the 60-day co mment period from July 13, 2007, to August 27, 2007 (72 FR 35375, June 28, 2007). We also issued a notice of data availability (72 FR 69175, December 7, 2007) (NODA) to notify the public that additional information had been added to the docket; the NODA also extended the public comm ent period on the proposed rule to January 7, 2008. We received a total of 38 comments from refineries, industry trade associations, and consultants; State and local en vironmental and public health agencies; environmental groups; and members of the public during the extended comment period and 8 additional comments on4-2 the NODA. These final rules reflect our full consid eration of all of the comments we received. Detailed responses to the comments are co ntained in the Response to Comments document
which is included in the docket for this rulemaking.

4.2 Summary of the Final NSPS and Changes Since Proposal
We are promulgating several amendments to provisions in the existing NSPS in 40 CFR part 60, subpart J. Many of these amendments are technical clarifications and corrections that are
also included in the final standa rds in 40 CFR part 60, subpart Ja. For example, we are revising the definition of “fuel gas” to indicate that vapors collected and combusted to comply with
certain wastewater and marine vessel loadi ng provisions are not considered fuel gas. Consequently, these vapors are exem pt from the sulfur dioxide (SO 2 ) treatment standard in 40 CFR 60.104(a)(1) and are not required to be m onitored. In a related amendment, we are clarifying that monitoring is not required for fu el gases that are identi fied as inherently low
sulfur or demonstrated to cont ain a low sulfur content. We ar e also revising the coke burn-off equation to account for oxygen (O 2 )-enriched air streams. Other amendments include
clarification of definitions and correction of grammati cal and typographical errors.

The final standards in 40 CFR part 60, subpa rt Ja include emission limits for fluid catalytic cracking units (FCCU), fl uid coking units (FCU), sulfur r ecovery plants (SRP), and fuel gas combustion devices. Subpart Ja also in cludes work practice standards for minimizing emissions of volatile organic compounds (VOC) from flares and SO 2 emissions from fuel gas combustion devices and for reducing emissions of VOC from delayed coking units. Only those affected facilities that begin construction, modification, or reconstruction after May 14, 2007 will be affected by the standards in 40 CFR part 60, subpart Ja. Units for which construction, modification, or reconstruction began on or befo re May 14, 2007 must continue to comply with the applicable standards under the current NSPS in 40 CFR part 60, subpart J, as amended.

4.2.1 Final Amendments to the NSPS
As proposed, we are amending the definition of “fuel gas” to specifically exclude vapors that are collected and combusted in an air pollu tion control device installed to comply with a specified wastewater or marine vessel loadi ng emissions standard. The thermal combustion
control devices themselves are still considered to be affected fuel gas co mbustion devices if they combust other gases that meet the definition of fuel gas, and all auxiliary fuel gas fired to these devices are subject to the fuel gas limit; however , continuous monitoring is not required for the vapors collected from wastewater or marine vessel loading operati ons that are being incinerated4-3 because these gases are not considered to be fu el gases under the definition of “fuel gas” in subpart J.

We are also exempting certain fuel gas streams from all continuous monitoring requirements. Monitoring is currently not requir ed for combustion in a flare of process upset gases or flaring of gases from relief valve leakage or emergency malfunctions. Additionally, monitoring is not required for inhe rently low sulfur fuel gas str eams. These streams include pilot gas flames, gas streams that meet commercial-gr ade product specifications with a sulfur content of 30 parts per million by volume (ppmv) or less, fuel gases produced by process units that are intolerant to sulfur contamination, and fuel gas streams that an owner or operator can demonstrate are inherently low-sulfur. Owner s and operators are required to document the exemption for which each fuel gas stream applies and ensure that the stream remains qualified for that exemption.

We proposed to amend the definition of “C laus sulfur recovery plant” in 40 CFR 60.101(i) to clarify that the SRP ma y consist of multiple units and that primary sulfur pits are considered part of the Claus SRP based on a recen t applicability determination. However, due to concerns regarding retroactive non-compliance, we are not amendi ng this definition in the final amendments for subpart J. Similarly, we proposed revisions to the subpa rt J definitions of “oxidation control system” and “reduction co ntrol system” in 40 CFR 60.101(j) and 40 CFR 60.101(k), respectively, to clarify that these systems were intended to recycl e the sulfur back to the Claus SRP. The proposed amendments need lessly limit the types of tail gas treatment systems that can be used; therefore, we ar e not amending these definitions in the final amendments for subpart J.

4.2.2 Final Requirements fo r New FCCU and New FCU
The final standards for new fluid catalytic cracking units include emission limits for particulate matter (PM), SO 2 , nitrogen oxides (NO x ), and carbon monoxide (CO). The final standards include no universal opac ity limit because the opacity lim it in subpart J is intended to ensure compliance with the PM limit. Subpart Ja requires that sources us e direct PM monitoring, bag leak detection systems, or parameter monitori ng (along with annual emission tests) to ensure compliance with the PM limit. A provision for a s ite-specific opacity oper ating limit is provided for units that meet the PM emission limits using a cyclone.

For PM emissions from new FCCU and new FCU, we proposed a PM limit of 0.5 pounds (lb)/1,000 lb coke burnoff in the regenerator or (if a PM continuous emission monitoring system (CEMS) is used), 0.020 grains per dry standard cubic feet (gr/dscf ) corrected to 0% excess air.4-4 We have revised the final PM standards to establis h separate limits for mo dified or reconstructed FCCU (1 lb/1,000 lb coke burn or 0.040 gr/dsc f corrected to 0% excess air) and newly constructed FCCU (0.5 lb/1,000 lb coke burn or 0.020 gr/dscf corrected to 0% excess air). The final PM limit for new, modified, or recons tructed FCU is 1 lb/ 1,000 lb coke burn or 0.040 gr/dscf corrected to 0% excess air).

Initial compliance with the PM emission limits for FCCU and FCU is determined using EPA Method 5, 5B or 5F (40 CFR part 60, appendix A) instead of being restricted to only EPA Method 5 as previously proposed. Procedures for computing the PM emission rate using the total PM concentration, effluent gas fl ow rate, and coke burn-off rate are the same as in 40 CFR part 60, subpart J, as amended. To demonstrate ongoi ng compliance, an owner or operator must monitor PM emission control device operating parameters and conduct annual PM performance tests, use a PM CEMS, or operate bag l eak detection systems and conduct annual PM performance tests. A new alterna tive allows refineries with wet scrubbers as PM control devices to use the approved alternativ e in 40 CFR 63.1573(a) for determ ining exhaust gas flow rate instead of a continuous parameter monitoring syst em (CPMS). An alternative to the requirements for monitoring the pressure drop from wet scrubbe rs that are equipped with jet ejectors or atomizing spray nozzles is to conduct a daily check of the air or water pre ssure to the nozzles and record the results of each inspec tion. The final rule also includes procedures for establishing an alternative opacity operating limit for refiners that use continuous op acity monitoring systems (COMS); this alternative is allowed only for units that choose to comply with the PM limit using cyclones. If operating parameters are used to demonstrate ongoing compliance, the owner or operator must monitor the same parameters dur ing the initial performa nce test, and develop operating parameter limits for the applicable para meters. The operating limits must be based on the three-run average of the values for the app licable parameters measured over the three test runs. If ongoing compliance is demonstrated us ing a PM CEMS, the CEMS must meet the conditions in Performance Specification 11 ( 40 CFR part 60, appendix B) and the quality assurance (QA) procedures in Procedure 2, 40 CFR part 60, appendix F. The relative response audits must be conducted annually (in lieu of an nual performance tests for units not employing a PM CEMS) and response correlation audits must be conducted once every 5 years.

For NO x emissions from affected FCCU and FCU, we proposed a limit of 80 ppmv based on a 7-day rolling average (dry basis corrected to 0% excess air) and co -proposed having no limit for FCU. We are adopting the 80 ppmv NO x emission limits for FCCU and FCU as proposed. Initial compliance with the 80 ppmv emission limit is demonstrated by conducting a performance
evaluation of the CEMS in accordance with Performance Specification 2 in 40 CFR part 60,4-5 appendix B, with Method 7 (40 CFR part 60, appendix A) as the reference method. Ongoing compliance with these emission limits is determined using the CEMS to measure NO x emissions as discharged to the atmosphere, averaged over 7-day periods.

No changes have been made to the proposed SO 2 emission limits for affected FCCU and
FCU. The final SO 2 emission limits are to maintain SO 2 emissions to the atmosphere less than or equal to 50 ppmv on a 7–day rolling average basi s, and less than or equal to 25 ppmv on a 365-day rolling average basis (both limits corrected to 0% moisture and 0% excess air). Initial compliance with the final SO 2 emission limits is demonstrated by conducting a performance
evaluation of the SO 2 CEMS in accordance with Performa nce Specification 2 in 40 CFR part 60, appendix B with Method 6, 6A, or 6C of 40 CF R part 60, appendix A as the reference method. Ongoing compliance with both SO 2 emission limits is determined using the CEMS to measure
SO 2 emissions as discharged to the atmosphere , averaged over the 7-day and 365-day averaging periods.

No changes have been made since proposal to the CO limits. The final CO emission limit for affected fluid catalytic cracking units a nd FCU is 500 ppmv (1-hour average, dry at 0% excess air). Initial compliance with this em ission limit is demonstrated by conducting a performance evaluation for the CEMS in acco rdance with Performance Specification 4 in 40 CFR part 60, appendix B, with Method 10 or 10A in 40 CFR part 60, appendix A as the reference method. For Method 10, the integrated sampling technique is to be used. Ongoing compliance with this emission limit is determined on an hourly basis using the CEMS to measure CO emissions as discharged to the atmosphere. An exemption from monitoring may be requested
for an FCCU or FCU if the ow ner or operator can demonstrate that “average CO emissions” are less than 50 ppmv (dry basis). This limit and the compliance procedures are the same as in the existing NSPS for FCCU. As proposed, units th at are exempted from the CO monitoring requirements must comply with contro l device operating parameter limits.

4.2.3 Final Requirements for New Sulfur Recovery Plants (SRP)
For new, modified, and reconstructed SRP w ith a capacity greater than 20 long tons per day (LTD), we proposed a limit of 250 ppmv total sulfur (combined SO 2 and reduced sulfur compounds) as SO 2 (dry basis at 0% excess air determin ed on a 12-hour rolling average basis). The refinery could comply with the limit for each process train or release point or with a flow rate weighted average of 250 ppmv for all releas e points. For affected SR P with a capacity less than 20 LTD, we proposed a mass emissions limit for total sulfur equal to 1 weight percent or less of sulfur recovered (determined hour ly on a 12-hour rolling average basis).4-6 In this final rule, we are adop ting the current limits in subpa rt J (which include separate emission limits for oxidative and reductive systems) for affected SRP with a capacity greater than 20 LTD. For these affected SRP, the final li mits for SRP having an oxidation control system or a reduction control system followed by in cineration is 250 ppmv (dry basis) of SO 2 at 0%
excess air. For an affected SRP with a reducti on control system not followed by incineration, the final limit is 300 ppmv of reduced sulfur compounds and 10 ppmv of hydrogen sulfide (H 2 S), each calculated as ppm SO 2 by volume (dry basis) at 0% excess air. If the SRP consists of multiple process trains or release points, the limits apply to each process train or release points.
A new alternative allows refineries to use a corr elation to calculate thei r effective emission limit for Claus SRP that use oxygen enrichment in the Claus burner. For an affected SRP with a capacity of 20 LTD or less, the sulf ur recovery efficiency standard is based on a sulfur recovery efficiency of 99%. However, due to the difficulti es associated with on-going monitoring of SRP recovery efficiency, in this final rule, we ar e promulgating concentration limits that correlate with a sulfur recovery efficien cy of 99%. For a Claus unit with an oxidative control system or any small SRP followed by an incinerator the em ission limit is 2,500 ppmv (dry basis) of SO 2 at 0% excess air. For all other small SRP, th e emission limit is 3,000 ppmv reduced sulfur compound and 100 ppmv H 2 S, each calculated as ppm SO 2 by volume (dry basis) at 0% excess air. A similar correlation is provided for small Claus SRP that use oxygen enrichment, similar to that provided for large SRP. The standards for small SRP apply to all release points from the SRP combined (note that secondary sulfur storage units are not c onsidered part of the SRP). We are not promulgating the H 2 S limit of 10 ppmv (dry basis, at 0% excess air determined on a 12- hour rolling average basis) or related operating limits that we re included in §60.102a(e) and (f) of the proposed rule.

Initial compliance with the emission limit for large SRP (capacity greater than 20 LTD) is demonstrated by conducting a performance evaluation for the SO 2 CEMS in accordance with either Performance Specification 2 (40 CFR part 60, appendix B) for SRP with oxidation control systems or reduction control systems followed by incineration or Performance Specification 5 (40 CFR part 60, appendix B) for SRP with reduction control systems not followed by
incineration.

Ongoing compliance with the SO 2 limits for large SRP is determined using an SO 2 CEMS (for oxidative or reductive systems followed by incineration) or a CEMS that uses an air
or O 2 dilution and oxidation system to convert the reduced sulfur to SO 2 and then measures the
total resultant SO 2 concentration (for re ductive systems not followed by incineration). An O 24-7 monitor is also required for conve rting the measured combined SO 2 concentration to the
concentration at 0% O 2
.
Initial and ongoing compliance re quirements for small SRPs are the same as for large
SRPs.

4.2.4 Final Requirements for New Fu el Gas Combustion Devices
In the subpart Ja proposal, we divided fuel gas combustion units into two separate affected sources: “process heater s” and “other fuel gas combustion devices.” In response to comments, we have eliminated the proposed defi nition of “other fuel gas combustion devices”
and revised the standards to either refer to fu el gas combustion devices, which include process heaters, or to refer specifically to process heaters. This revisi on makes the definition of “fuel gas combustion devices” consistent with subpart J. We have also added a definition of “flare.”

We proposed a primary sulfur oxides emission limit for fuel gas combustion devices of 20 ppmv or less SO 2 (dry at 0% excess air) on a 3-hour rolling average basis and 8 ppmv or less on a 365-day rolling average basis. We also proposed an alternative limit of 160 ppmv H 2 S or, in the case of coker-derived fuel gas, for total re duced sulfur (TRS) on a 3-hour rolling average basis and 60 ppmv or less on a 365-day rolling average basis. We are promulgating the 20 ppmv and 8 ppmv limits for SO 2 as proposed. We are also promulga ting the alternative limit, except that the limits are expressed and measured as H 2 S in all cases. The alternative H 2 S limit is 162 ppmv or less in the fuel gas on a 3-hour rolling average basis and 60 ppmv or less in the fuel gas on a 365-day rolling average basis. The final rule does not include an alternative TRS limit for
SO 2
.
Initial compliance with the 20 ppmv SO 2 limit or the 162 ppmv H 2 S concentration limits is demonstrated by conducting a performance evaluation for the CEMS. The performance
evaluation for an SO 2 CEMS is conducted in accordance wi th Performance Specification 2 in 40 CFR part 60, appendix B. The performance evaluation for an H 2 S CEMS is conducted in accordance with Performance Specification 7 in 40 CFR part 60, appendix B. Ongoing compliance with the sulfur oxides emission limits is determined using the applicable CEMS to
measure either SO 2 in the exhaust gas to the atmosphere or H 2 S in the fuel gas, averaged over the 3-hour and 365-day averaging periods.

Similar to clarifications for 40 CFR part 60, subpart J, the definition of “fuel gas” includes exemptions for vapors collected and combusted in an air pollution control device installed to comply with specified wastewater or marine vessel loading provisions. We are also4-8 streamlining the process for an owner or operato r to demonstrate that a fuel gas stream not explicitly exempted from continuous monitoring is inherently low sulfur.

For new, modified, or reconstructed process heaters with a rated cap acity greater than 20 million British thermal units per hour (MMBtu/hr), we proposed a NO x limit of 80 ppmv (dry basis, corrected to 0% excess air) on a 24-hour rolling average basis. The final NO x emission limit for affected process heaters is 40 ppmv on a 24-hour rolling averag e basis (dry at 0% excess air) for process heaters greater than 40 MMBtu/hr. For process heaters greater than 100 MMBtu/hr capacity, initial compliance with th e 40 ppmv emission limit is demonstrated by conducting a performance evaluation of th e CEMS in accordance with Performance Specification 2 in 40 CFR part 60, appendix B. For process heaters between 40 MMBtu/hr and 100 MMBtu/hr capacity, initial co mpliance is demonstrated us ing EPA Method 7. For process heaters greater than 100 MMBtu/hr capacity, ong oing compliance with this emission limit is determined using the CEMS to measure NO x emissions as discharged to the atmosphere, averaged over 24-hour periods. For process heaters between 40 MMBtu/hr and 100 MMBtu/hr capacity, ongoing compliance with this emission lim it is determined using biennial performance

tests.

4.2.5 Final Work Practice Standards
We proposed three work pract ice standards to reduce SO 2 , VOC, and NO x emissions from flares and from startup, shutdown, a nd malfunction events and to reduce VOC and SO 2 emissions from delayed coking units. We also co -proposed to require only one of these work practice standards: the requireme nt to depressure delayed coki ng units. This proposed standard required new delayed coking units to depressure to 5 pounds per square inch gauge (psig) during reactor vessel depressuring and vent the exhaust gases to the fuel gas system.

We are promulgating a work practice standa rd for delayed coking units and modified requirements to reduce emissions from flares. The final work practice standard for delayed cokers requires affected delayed coking units to depressure to 5 pounds per square inch gauge (psig) during reactor vessel depressuring. We are requiring the exhaust gases to be vented to the fuel gas system as proposed or to a flare.

To reduce SO 2 emissions from the combustion of sour fuel gases, the final rule requires refineries to conduct a root cause analysis of any emissions limit exceedance or process start-up, shutdown, upset, or malfunction that causes a discharge into the atmosphere, either directly or indirectly, from any fuel gas combustion unit subj ect to the provisions of subpart Ja that exceeds4-9 500 pounds per day (lb/day) of SO 2 . Recordkeeping and reporting requirements apply in the event of such a discharge.

We are not promulgating the proposed defini tion of “fuel gas producing unit” and the proposed requirement for “no routine flaring.” Instead, we are prom ulgating the following requirements: (1) flare fuel gas flow rate monitori ng; (2) a flare fuel gas flow rate limit; and (3) a flare management plan. Affected flares cannot exceed 250,000 standard cubic feet per day (scfd) on a 30-day rolling average basis. In cases where the flow exceeds this value, this would require installation of a flare ga s recovery system or other methods to reduce flaring from the affected flare. A provision is provided for an exclus ion from the flow limitation for times when the refinery can demonstrate that th e refinery produces more fuel gas than it needs to fuel the refinery combustion devices (i.e., it is fuel gas rich) or that the flow is due to an upset or malfunction, provided the refinery follows proce dures outlined in the flare management plan. The flare management plan should address pot ential causes of fuel gas imbalances (i.e. , excess fuel gas) and records to be maintained to document these periods. To demonstrate compliance with the flow limitations, flow rate monitors mu st be installed and operated. As described in 40 CFR 60.103a(a), the flare management plan must include a diagram illustrating all connections to each affected flare, identification of the flow rate monitoring device and a detailed description of the manufacturer’s specifications regardi ng quality assurance pro cedures, procedures to maintain to minimize flaring during planned star t-up and shut down events, and procedures for implementing root cause analysis when daily flow to the flare exceeds 500,000 scfd. The root cause analysis procedures should address th e evaluation of potential causes of upsets or
malfunctions and records to be maintained to document the cau se of the upset or malfunction.
Excess emission events for the flow rate lim it of 250,000 scfd and the result of root cause analysis must be reported in the semi-annual compliance reports.

Because affected flares are also affected fuel gas combustion devices, the root cause analysis for SO 2 emissions exceeding 500 lbs/day also applies to flares. However, compliance with the 500 lb/day root cause analysis will also require conti nuous monitoring of total reduced sulfur of all gases flared. Although all fuel gas combustion devices are required to comply with
continuous H 2 S monitoring of fuel gas, flares routin ely accept gases from upsets, malfunctions and startup and shutdown events, and H 2 S or sulfur monitoring is not specifically required for these gases. In subpart Ja, we explicitly require TRS monitoring to ensure that the 500 lb/day
SO 2 trigger is accurately measured. We also note th at for affected flares, the RCA trigger is 500 lbs/day, not 500 lbs/day in exce ss of an emissions limit.4-10 4.2.6 Modification and Reconstruction Provisions
Existing affected facilities that commence modification or reconstruction after May 14, 2007, are subject to the final standards in 40 CF R part 60, subpart Ja. A modification is any physical or operational change to an existing affected facility which results in an increase in the emission rate to the atmosphere of any polluta nt to which a standard applies (see 40 CFR 60.14). Changes to an existing affected f acility that do not result in an in crease in the emission rate, as well as certain changes that have been exem pted under the General Provisions (see 40 CFR 60.14(e)), are not considered modifications.

In response to comments regarding the work practice standards for flares and fuel gas producing units, we re-evaluated th e work practice standards and ha ve decided to define a flare as the affected source rather than a fuel gas producing unit. The intermittent operation of a flare
makes it difficult to use the criteria of 40 CF R 60.14 to determine when a flare is modified; therefore, we have specified in th e final rule the criteria that de fine a modification to a flare. A flare is considered to be modified if: (1) any piping from a refinery process unit or fuel gas system is newly connected to the flare or (2) th e flare is physically modi fied to increase flow capacity .

Special provisions are included for NO x emissions from certain existing process heaters
that were modified or reconstruc ted between proposal and promulgati on of this final rule in order to avoid the retroactive applic ation of the more stringent NO x emissions limit in the final rule. Existing process heaters with a rated capaci ty of greater than 40 MMBtu/hr for which
modification or reconstruction commenced afte r May 14, 2007, and on or before the date of publication of this final rule in the Federal Register are subject to the same NO x emission limit as proposed (80 ppmv, dry basis co rrected to 0% excess air on a 24-hour rolling average basis).

Petroleum refinery process units are subjec t to the final standards in 40 CFR part 60, subpart Ja if they meet the criteria under the reconstruction provisions, regardless of changes in emission rate. Reconstruction means the replacement of components of an existing facility such that (1) the fixed capital cost of the new components exceeds 50% of the fixed capital cost that would be required to cons truct a comparable entirely new facility; and (2) it is technologically and economically feasible to meet th e applicable standards (40 CFR 60.15).

4.3 Model Facility, Source Project ions, and Cost Assumptions
EPA developed control options for this final to limit emissions of particulate matter, sulfur dioxide, nitrous oxides and volatile or ganic compounds from new and modified processes at petroleum refineries, includi ng FCCUs, SRUs, cokers, and process heaters. EPA has estimated4-11 the costs of complying with the final NSPS unde r each of the options, using a model facility approach. During the 5-year period of analysis (or the analysis of impacts in the fifth year after proposal), EPA assumes the industry will invest in enough new processes to be equivalent to an average of three new refineries per year, or a to tal of 15 new refineries. Further, the new sources are assumed to be 40% new processes or faciliti es and 60% modified or reconstructed facilities

or processes.

Table 4-1 illustrates the assumptions used to characterize the model facilities and processes upon which the costs of complying with the rule ar e based. More details follow on these assumptions.

To project the number of new, reconstructed, and modified process uni ts over the next 5 years, we used many of the same assumptions as in the analysis for subpart GGG, including the average number of process units at a refinery (Parrish, Randall, and Coburn, 2006). That analysis
assumes that there are 0.8 FCCUs and 0.4 coking units per refinery and that 15 refineries’ worth of process units become subject (i .e., are either new, reconstruc ted, or modified) over the 5 years following proposal. We also assumed that 40% of the FCCUs are new and 60% are reconstructed
or modified.

4.3.1 FCCUs

We identified four scenarios to characterize FCCUs, one for new process units and three for reconstructed and modified process units. In th is analysis, currently refers to the situation prior to new NSPS requirements and baseline refers to the requirements if no new standards are implemented(in most cases, baseline is compliance with subpart J).

1. New (baseline = comply with subpart J) 2. Currently subject to subpar t J (baseline = cont inue to comply with subpart J) 3. Currently subject to consent decree (basel ine = continue to comply with consent decree requirements, assuming these are equal to or more stringent than subpart J) 4. Currently subject to MACT (bas eline = comply with subpart J)
We assumed that the currently existing process units that are reconstr ucted or modified are broken down into Scenarios 2, 3, and 4 as follows:

 10% are subject to MACT and not subpart J (Scenario #4).4-12 Table 4-1. Model Facility Descriptions

Model Facility Description It ems Included in the Costs Number Facilities New facility/major new expansion  FCCU PM, SO 2 , and NO x controls

 11 new process heaters with NO x controls

 New fuel gas combustion device

 Implement work practice standards a 2

New FCCU  FCCU PM, SO 2 , and NO x controls

 2 new process heaters with NO x controls

 Modified/reconstructed fuel gas combustion device

 Implement work practice standards b 1

New processes  2 process heaters with NO x controls

 Modified/reconstructed fuel gas combustion device

 Implement work practice standards b 6

Small business with new processes  SRU tail gas treatment

 3 process heaters with retrofit NO x controls

 Modified/reconstructed fuel gas combustion device

 Implement work practice standards b 1

Multi-process and FCCU revamp  FCCU PM, SO 2 , and NO x retrofit controls

 9 new process heaters with NO x controls

 Modified/reconstructed fuel gas combustion device

 Implement work practice standards a 3

Multi-process and FCCU revamp (no delayed coker unit [DCU])  FCCU PM, SO 2 , and NO x controls

 9 new process heaters with NO x controls

 Modified/reconstructed fuel gas combustion device

 Implement work practice standards b 2

FCCU revamp  FCCU PM, SO 2 , and NO x controls

 2 process heaters with retrofit NOx controls

 Modified/reconstructed fuel gas combustion device

 Implement work practice standards b 4

Fluid coking unit revamp  FCCU PM, SO 2 , and NO x controls

 7 new process heaters with NO x controls

 Modified/reconstructed fuel gas combustion device

 Implement work practice standards b 1

Modified processes  3 process heaters with retrofit NO x controls

 Modified/reconstructed fuel gas combustion device

 Implement work practice standards b 8

Small business with modified processes  SRU tail gas treatment

 3 process heaters with retrofit NO x controls

 Modified/reconstructed fuel gas combustion device

 Implement work practice standards b 1

a Work practice standards include: fuel gas recovery for fuel gas producing units; flare minimization plan for

planned start-up and shutdown; sulfur shedding plan; root-cause analysis; and delayed coking depressurization gas
recovery.
b All of the work practices a bove except delayed coking depressurization gas recovery.4-13  76.5% are units subject to a consent decr ee (Scenario #3). For purposes of this analysis, average consent decree requiremen ts are assumed to be 1.0 kg PM/Mg coke burn (using Method 5B or 5F), 50 ppmv SO 2 over a 7-day average, and 25 ppmv SO 2 over a 365-day average.

 The remaining 13.5% are subject to subpart J (Scenario #2).
The assumptions outlined above tran slate into the following values:

 12 total new, reconstructed, or modified FCCUs (multiply estimate of 0.8 FCCU per refinery by 15 refineries’ worth of process units)

 4.8 FCCUs are new

 7.2 FCCUs are reconstructed or modified

– 1 is currently subject to subpart J

– 5.5 are currently subject to consent decree

– 0.7 are currently subject to MACT only

4.3.2 Fluid Coking Units (FCU)
We assumed that there will be six new, rec onstructed, or modified coking units over the next 5 years. Based on industry trends, we anticip ate that five of these will be delayed coking units and only one will be a fluid coking unit. 1 We assumed that the si ngle fluid coking unit will become subject through modificatio n or reconstruction rather than new construction. At baseline, this fluid coking unit would comply with subpart J, which includes no requirements for coking
units.

We assumed that 30 refineries will construct, reconstruc t, or modify a fuel gas combustion device over the next 5 y ears. This estimate is based in part on the assumed average numbers of process units at a refinery from th e analysis for subpart GGG (Parrish, Randall, and Coburn, 2006). Industry representatives have in dicated that most fuel gas systems are centralized. Therefore, the entire system that includes the new, reconstructed, or modified combustion device will essentially have to meet subpart Ja standards in order for the new or reconstructed fuel gas combustion de vice to comply with subpart Ja.

4.4 Emissions Estimation by Unit Type
For both FCCUs and fluid coking units, PM and SO 2 controls were evaluated together
because a wet scrubber installed to reduce PM will also achieve SO 2 reductions. The other
control device considered for FCCUs was an el ectrostatic precipitator (ESP) for PM reduction and catalyst additives for SO 2 emission reduction. This option is not technically feasible for a

1 10–26 meeting minutes.4-14 fluid coking unit; therefore, the analysis for th e one affected fluid coking unit assumed a wet
scrubber as the control device.

4.4.1 FCCUs
We assumed a model FCCU size of 50,000 barrels (bbl) per day. This model FCCU also has a volumetric flow rate of 140,000 dry standard cubic feet per minute (dscfm) and a coke burn-off rate of 800,000 pounds (lb) per da y. It operates at 95% of capacity.

In order to determine emission reductions beyond subpart J for each option, we first estimated emissions attributed to meeting subpart J. Based on industry tre nds and control device capabilities, we assumed that 35% of the FCCUs would meet s ubpart J with a wet scrubber and 65% would meet subpart J using an ESP and catal yst additives. We assumed the basic model wet scrubber could meet the subpart J PM limit with an 80% control efficiency and would average about 25 ppmv SO 2 . The model ESP also had a control efficiency of 80% for PM. For SO 2 , we calculated that the 9.8 kg/Mg coke burn is equi valent to about 265 ppmv.

We estimated emissions of PM as the total of filterable PM that is less than 10 micrometers ( μ m) in diameter (PM 10 ), filterable PM that is less than 2.5 ( μ m) in diameter (PM 2.5 ), and condensable PM. At baseline, an F CCU meeting subpart J with a wet scrubber would emit 236 tons PM per year and an ESP w ould emit 305 tons PM per year. (A wet scrubber has a lower operating temperature than an ESP, which provides improved removal of
condensable PM and results in lower PM emissi ons.) Based on the assumptions described above,
we estimated baseline PM emissions for the 12 FCCUs at 3,370 tons per year (1,350 tons per year from new FCCUs and 2,020 tons per year fr om reconstructed and modified FCCUs). For this model FCCU, we estimated emissions of SO 2 as 1,540 tons per year for catalyst additives meeting 265 ppmv and 145 tons per year for we t scrubbers and catalyst additives meeting 25 ppmv. Based on the assumptions descri bed above, we estimated baseline SO 2 emissions for the 12 FCCUs at 9,600 tons per year (5,050 tons per year from new FCCUs and 4,560 tons per year from reconstructed and modified FCCUs).

To determine the emissions for each option, we assumed that the ratio of ESPs to wet scrubbers chosen for new FCCUs would change depending on the particular emission limits being considered. For example, as the SO 2 limit tightens, a wet scrubber becomes more costeffective compared to the catalyst additives. On the other hand, we have no data to support an assumption that wet scrubbers could achieve th e Option 5 PM limit of 0.15 kg/Mg coke burn, so we assumed that for Option 5, all FCCUs woul d be controlled with an ESP and catalyst additives. In addition to these considerations, we considered for reconstructed and modified4-15 FCCUs with an existing control device whether cost-effectivene ss or technical limitations for each option would drive an operato r to change the control device. For example, for Option 5, all
wet scrubbers would be removed in favor of ESPs that can meet the lower PM limit.

For each of the five options, we again estimated PM emissions as a total of filterable
PM 10 and PM 2.5 and condensable PM. The total values vary for each option and for the specific
control device chosen. In addition to the SO 2 emissions described for baseline, we estimated emissions of 290 tons per year for catalyst additi ves meeting 50 ppmv. We also assumed that wet scrubbers designed to meet 0.5 kg PM/Mg coke burn would achieve 12.5 ppmv SO 2 , which we calculated to be equivale nt to 73 tons per year.

4.4.2 FCUs
We assumed a model fluid coking unit size of 40,000 bbl/day. This model coking unit also has a volumetric flow rate of 200,000 dscfm. At baseline, there are no requirements for fluid coking units, so there are no emissi on reductions for either PM or SO 2 . For Option 1, we
assumed that a basic wet scrubber would be c hosen. We estimated em ission reductions of 1,710 tons PM per year (based on 84% efficiency) and 20,600 tons SO 2 per year (based on estimates of 94% efficiency and uncontrolled SO 2 emissions of 3.0 lb/bbl). 2 For Option 2, we assumed that an
enhanced wet scrubber would be chosen to m eet the emission limits. We estimated emission reductions of 1,970 tons PM per year (based on 97% efficiency) and 21,200 tons SO 2 per year (also based on an estimate of 97% efficiency).

We assumed that an average amine treatment system for fuel gas combustion devices would have an average gas flow rate of 10,000 standard cubic feet per minute (scfm). We developed this model system based on informa tion from various sources (Polasek, Bullin, and Donnelly, 1982; Fedich, Woerner, and Chitnis, 2004; Voltz, Corley, and Fedich, 2004). Based on this flow rate and an emission limit of 20 ppmv, one system would emit 0.27 pounds (lbs) of SO 2 per minute (min), or 70 tons per year (tons/y r). Nationwide (i.e., for 30 systems), the total emissions are 2,100 tons per year. The emissions from one system, nationwide emissions, and
the reduction from the baseline for each of the three options are shown in Table 4-2.

2 Valero submittal (test report specifically).4-16 Table 4-2. Emissions for Fuel Gas Combustion Devices

Option Emissions from One System Nationwide Emissions (tons SO 2 /yr) Reduction from Baseline (tons SO 2 /yr) (lb SO 2 /min) (tons SO 2 /yr) 1 0.13 35 1,050 1,050 2 0.10 26 786 1,310 3 0.07 17 524 1,570

4.5 Control Technologies in Analysis
The following NO x control techniques were included in the cost analysis for the control options:

 Flue Gas Recirculation. Flue gas recirculation (FGR) uses flue gas as an inert material to reduce flame temperatures. In a typical flue gas recirculation system, flue gas is collected from the heater or stack and returned to the burner via a duct and blower. The addition of flue gas with th e combustion air reduces the oxygen content of the inlet air stream to the burner. Th e lower oxygen level in the combustion zone reduces flame temperatures, which in turn reduces NO x emissions. The normal NO x control efficiency range for FGR is 30% to 50%. When coupled with low-NO x burners (LNB) the control effi ciency increases to 50%–72%.

 Low-NO x Burners. Low-NO x burner (LNB) technology utilizes advanced burner design to reduce NO x formation through the restriction of oxygen, flame temperature, and/or residence time. The two general types of low NO x burners are staged fuel and staged air burners. Staged fuel LNBs ar e particularly well-suited for boilers and process heaters burning process and natural gas, which generate higher thermal NO x . The estimated NO x control efficiency for LNBs wh ere applied to petroleum refining fuel burning equipment is generally around 40%.

 Ultra-low NO x Burners. Ultra-low NO x burners (ULNBs) may incorporate a variety of techniques including induced flue gas re circulation (IFGR), steam injection, or a combination of techniques. These burner s combine the benefits of flue gas recirculation and low-NO x burner control technologies. Ra ther than a system of fans and blowers (like FGR), the burner is designed to recirc ulate hot, oxygen-depleted flue gas from the flame or firebox back in to the combustion zone. This leads to a reduction in the average oxygen concentra tion in the flame without reducing the flame temperature below temperatures nece ssary for optimal combustion efficiency. The estimated NO x control efficiency for ULNBs in high temperature applications is 50%. Newer designs have yielded effici encies of between 75% and 85%. When coupled with selective cataly tic reduction, efficiencies in the range of 85% to 97% can be obtained.

 Controlling Excess Oxygen in Complete Combustion FCCU Catalyst Regenerators. Most of the previous control opti ons are specific to process heaters and carbon monoxide (CO) boilers. However, controlling the oxygen concentration in4-17 the FCCU regenerator exhaust at approxima tely 0.5% has been seen to reduce NO x concentrations by 20% to 40% as compared to NO x concentrations when the regenerator exhaust oxygen c oncentration is between 1% and 2%. As such, complete combustion FCCU regenerators with activ e excess oxygen controls are expected to have similar performance as partial com bustion FCCUs followed by CO boilers that use low-NO x burners or flue gas recirculation.

 Selective Non-Catalytic Reduction. In the selective non-catal ytic reduction (SNCR) process, urea or ammonia-based chemicals ar e injected into the flue gas stream to convert nitric oxide ( NO) to nitrogen gas (N 2 ) and water. Without the participation of a catalyst, the reaction require s a high temperature range to obtain activation energy. The optimum operating temperature for SNCR is 1,600°F to 2,100°F. At temperatures above 2,000°F, NO x control efficiency decr eases rapidly. The normal NO x control efficiency range for SNCR is 50% to 70%. SNCR systems are usually lower in capital cost than SCR systems fo r the same application. One advantage of this technology is the fact that no liqu id or solid waste is generated. SNCR technology has been applied to CO boilers, process h eaters and boile rs in the petroleum refining sector where control effi ciencies are consistent with the range mentioned above.

 LoTOx TM Technology. The LoTOx TM process (i.e., low-temperature oxidation) is a patented technology that uses ozone to oxidize NO x to nitric pentoxide and other higher order nitrogen oxides, all of which are water soluble and easily removed from exhaust gas in a wet scrubber. The system operates optimally at temperatures below 300°F. Thus, ozone is injected after scrubbe r inlet quench nozzles and before the first level of scrubbing nozzles. Outlet NO x emission levels have been reduced to less than 20 parts per million by volume (ppmv), and of ten as low as 10 ppmv, when inlet NO x concentrations ranged from 50 to 200 ppmv (an 80% to 90% reduction efficiency)

.

 Selective Catalytic Reduction. Selective catalytic reduction (SCR) is a postcombustion NO x control technology in which ammonia (NH 3 ) is injected into the post-combustion gas stream in the presence of a catalyst. A cata lyst bed containing metals in the platinum family is used to lower the activation energy required for NO x decomposition. The reaction of NH 3 and NO x is favored by the presence of excess oxygen. The NH 3 oxidation to NO x increases with increasing temperature. The normal NO x control efficiency range for SCR is 70% to 90%. There are at least three SCRs currently in-use at re fineries to control FCCU NO x emissions.

 Combination System. Combination systems have used combustion controls followed by SCR or SNCR technology in order to reduce costs of NO x removal from a flue gas. For example, LNB has been combin ed with SNCR technology to minimize the capital and operating cost for NO x removal as well as improve the control efficiency.

 Catalyst Additives. An additional NO x emission control option specific for the FCCU is the use of catalyst additive, such as X-NO x and DENOX (from GraceDavison; Bruhin et al., 2003). Non-platinum combustion prom oter additives appear to achieve a 30% to 50% emission reduction. Additional catalyst additives have had limited success at further reducing the NO x emissions from the FCCU, and the results of these other additives have been quite varied.4-18 Not all of these control technologi es are applicable to all units. For exampl e, use of catalyst additives is applicable only to FCCUs, while the use of low-NO x burners are not applicable to complete combustion FCCU catalyst regenerators . For each source type, costs for four control scenarios were developed in 2005 dollars; the control scenario s ranged between 35% and 95%
NO x emission reduction efficiencies. As the baseline emissions of different FCCUs can span a fairly significant range of outlet NO x concentrations, representative baseline concentrations were assigned a weighting factor to simu late the distribution of baseline NO x emissions. For each representative baseline NO x concentration, the control scenar io needed to achieve a given emission limit was assigned to the fraction of FCCUs represented by th at concentration. The overall costs for a given scenario were then calcul ated based on the weighting attributed to that
uncontrolled NO x concentration range. Although this ba sic approach was used for each NO x emission source type, the specific costing methodol ogies for each of the three types of sources are presented in separate sections to clearly identify the differen ces in the costs developed for the
different sources.

For SO 2 and VOC, and PM control technologies, please refer to the technical memoranda in the public docket for this rulemaking.

4.6 Cost Analysis for Control Options
EPA examined control options for individual re finery processes as well as work practice options affecting the refinery as a whole. This section describes these control options and the estimated costs of implementing them.

The costs presented in this section are calculated based on the control cost methodology presented in the EPA (2002) Air Pollution C ontrol Cost Manual prepared by the U.S. Environmental Protection Agency. 3 This methodology sets out a procedure by which capital and annualized costs are defined and estimated, and this procedure is often used to estimate the costs of rulemakings such as this one. The capital cost s presented in this sect ion are annualized using a 7% interest rate, a rate that is consistent with the guidance provided in the Office of Management and Budget’s (OMB’s) (2003) Circular A-4. 4 Equipment lives for the control technologies employed in this analysis can vary gr eatly (usually from 10 to 25 years).

Four sources of information were consider ed in reviewing the appropriateness of the current NSPS requirements for new sources: (1) sour ce test data from recently installed control systems; (2) applicable Stat e and local regulations; (3) co ntrol vendor emission control

3 Available on the Internet at http://epa.gov/ttn/catc/ products.html#cccinfo

. 4 Available on the Internet at http://www.whitehouse.gov/omb/circulars/a004/a-4.pdf

.4-19 guarantees; and (4) consent decrees . (A significant number of refi neries, representing over 80% of the national refining capacity, are subject to consent decrees that limit the emissions from subpart J process units.) In addition, we recei ved a total of 46 comments during the public comment periods associated with the proposed rule and NODA. These comments were received from refineries, industry trade a ssociations, and consultants; st ate and local environmental and public health agencies; environmental groups; and members of the public. In response to these public comments, most of the cost and emission reduction impact estimates were recalculated, resulting in several changes to the final amen dments and new standards. A summary of the remainder of the comments received during the comment period and responses thereto can be
found in the docket for the final amendments and new standards (Doc ket ID No. EPA–OAR– HQ–2007–0011). The docket also contains further details on all the analyses summarized in the responses below.

Once we identified potential emission limits for various process units, we evaluated each limit in conjunction with contro l technology, costs, and emission reductions to determine the Best Demonstrated Technology (BDT) for each process unit. In responding to the public comments, we re-evaluated the costs and cost -effectiveness of the c ontrol options and reevaluated our BDT determinations. In our BDT dete rminations, we took all relevant factors into account, including cost considerations, which ar e generally consistent with other Agency decisions. It is important to note that, due to the different health effects associated with different pollutants, the acceptable cost-effectiveness of a control option is pollutant dependent. These pollutant-specific factors were consid ered in our BDT determinations.

The cost methodology incorporates the calcu lation of annualized costs and emission reductions associated with each of the options presented. Cost-effectiveness is the annualized cost of control divided by the annual em ission reductions achieved. Incremental costeffectiveness refers to the difference in annuali zed cost from one option to the next divided by
the difference in emission reductions from one option to the next. For NSPS regulations, as mentioned earlier in this chapter, the sta ndard metric for expressing costs and emission reductions is the impact on all affected facilities in the fifth year after proposal. Details of the
calculations can be found in the public docket.

4.7 Summary of Cost, Environmenta l, Energy, and Economic Impacts
We are presenting estimates of the impacts for the final requirements of subpart Ja that change the performance standards: the emission li mits for fluid catalytic cracking units, sulfur recovery plants, fluid coking units, fuel gas com bustion devices, and process heaters, as well as4-20 the work practice standards for flares and dela yed coking units. The cost, environmental, and economic impacts presented in this section are expressed as incr emental differences between the impacts of petroleum refining process units comply ing with the final subpa rt Ja and the current NSPS requirements of subpart J (i.e., baseline). The impacts are presented for petroleum refining process units that commence cons truction, reconstruction, or modification over the next 5 years.

In order to determine the incremental costs a nd emission reductions of this final rule, we first estimated baseline impacts. For new sources , baseline costs and emission reductions were estimated for complying with subpart J; incrementa l impacts for subpart Ja were estimated as the costs to comply with subpart J subtracted from th e costs to comply with final subpart Ja. Sources
that are modified or reconstructed over the ne xt 5 years must comply with subpart J in the absence of final subpart Ja. We assumed that prior to reconstruction or modification, these sources will either be subject to a consent decree (equivalent to more than 80% of the industry by capacity), complying with subpart J or equivale nt limits, and/or complying with 40 CFR part 63, subpart UUU (MACT II). Baseline costs and emissi on reductions were estimated as the effort needed to comply with subpart J from one of those three starting points. The costs and emission reductions to comply with final subpart Ja were estimated from those starting points as well. When considering and selecting emission limits for the final rule, we evaluated the costeffectiveness of each option for new sources separa tely from reconstructed and modified sources. In most cases, our selections for each process unit and pollutant were consistent for modified and
reconstructed units and new units. In this se ction, we are presenting our costs and emission
reductions for the overall rule. We estimate that the final amendments for new and modified and reconstructed sources toge ther will reduce emissions of PM by 1,300 tons/yr, SO 2 by 17,000 tons/yr, NO x by 11,000 tons/yr, and VOC by 1,400 tons/y r from the baseline. The estimated increase in annual cost, including annualized capital costs, is $31,000,000 (2006 dollars). The estimated nationwide 5-year incremental emissions reductions and cost impacts for the final
standards are summarized in Table 4-3. A summar y of the impacts by all options considered in the course of preparing the final NSPS, for new and for modified and r econstructed sources, is available in Appendix B.

4.7.1 Secondary Impacts
Indirect or secondary air quality impacts of th is final rule will result from the increased electricity usage associated with the operation of control devices. Assuming that plants will purchase electricity from a power plant, we estimate that the final standards will increase secondary emissions of criteria pollutants, including PM, SO 2 , NO x , and CO from power plants.4-21 Table 4-3. National Incremental Emission Re ductions and Cost Impacts for Petroleum Refinery Units Subject to Final Standards Under 40 CFR Part 60, Subpart Ja (Fifth Year After Proposal) a

Process Unit Total Capital

Cost ($1,000) Total Annual

Cost ($1,000/yr) Annual Emission Reductions (tons PM/yr) Annual Emission Reductions (tons SO 2 /yr) Annual Emission Reductions (tons NO x /yr) Annual Emission Reductions (tons VOC/yr) CostEffectiveness ($/ton) FCCU 8,500 6,400 240 4,300 2,600 890 FCU 14,000 4,000 1,000 5,900 660 530 SRP 1,700 730 420 1,700 Fuel gas combustion devices 34,000 12,000 5,200 2,300

Process heaters 23,000 12,000 7,500 1,600 Flaring 40,000

− 6,600 80 5 206

− 23,000 Delayed coking units 17,000 1,600 440 25 3,400

Sulfur pits 8,300 1,000 300 3,400 Total 150,000 30,700 1,300 17,000 11,000 1,400 1,070

a All costs are in 2006 dollars.

For new, modified or reconstruc ted sources, this final rule will increase secondary PM emissions by 56 Megagrams per year (Mg/yr ) (62 tons/yr); secondary SO 2 emissions by about 1,400 Mg/yr (1,500 tons/yr); secondary NO x emissions by about 530 Mg/yr (580 tons/yr).

As explained earlier, we expect that affected facilities will control emissions from fluid catalytic cracking units by installing and operating ESP or wet ga s scrubbers. We also expect that
the emissions from the affected FCU will be co ntrolled with a wet scrubber. For these process units, we estimated solid waste impacts for both types of control devices and water impacts for wet gas scrubbers. In addition, the controls needed by small sulfur recovery plants will generate condensate. We project that this final rule will generate 1.6 billion gallons of water per year for the 5 years following proposal. We also estimate th at this final rule wi ll generate 2,200 Mg/yr (2,400 tons/yr) of solid waste over those 5 years.

Energy impacts as defined in this preamble s ection consist of the electricity and steam needed to operate control devices and other eq uipment that would be required under the final rule. Our estimate of the increased energy dema nd includes the electricit y needed to produce the required amounts of steam as well as direct electri city demand. We project that this final rule will increase overall energy demand by about 41 0 gigawatt-hours per year (1,400 billion British4-22 thermal units per year). An analysis of energy impacts that accounts for reactions in affected
markets to the costs of this final rule can be found in the section on Executive Order 13211 found
later in this RIA.

4.8 Limitations and Uncertainties Associated with the Cost Analyses

Limitations and uncertainties associated with the cost analyses presented above are presented here.

1. Assumptions behind the cost savings estimat ed for this NSPS. These annualized cost savings are driven by the rec overy of natural gas associat ed with the minimization of flaring. The calculation presumes that al l refiners owning new and modified or reconstructed that must comply with the NSPS will be able to accomplish this, particularly since they are estimated to r eceive a return on their investment. However, opportunity costs may exist to make such an investment more financially difficult than we may expect. Smaller refiners may have less capital available to them than larger refiners, and may find the investment in necessary capital and development of a flare gas minimization plan more challengi ng than larger refine rs. In addition, there may be varying abilities among refiners to develop such minimization plans with their current labor force due to tightness in labor markets, though such difficulties could be remedied beyond the short run. Finally, many re finers have a minimum rate of return that must be met before an investment to expand capacity, or for other reasons, is carried out. For example, the Ad Hoc Coalit ion of Small Business Refineries asserted in a comment on the proposed petroleum refi neries NSPS that an acceptable rate of return of well above 10% se rved as a minimum for inve stment purposes at their refineries. 5 It also should be noted, however, th at the natural gas price that underlies the estimate of cost savings is $7/Mcf (1,000 cubic feet), which is the average natural gas price in 2006, the base year for the cost analysis. Current spot prices for natural gas exceed $10/Mcf, and there is potential fo r further increases in such natural gas prices to as high as $20/Mcf in the future by some estimates. 6 An increase in natural gas price may lead to additional incentive for refiners to engage in flare gas minimization. 2. Effect of consent decrees on overall impact estimates. As mentioned in the preamble for this final NSPS, the estimates of impact s in this RIA are based on a baseline that includes consent decrees reached by the U.S. Department of Justice (DOJ) as part of the Refinery Enforcement Initiative with refi ners representing 77% of U.S. refinery capacity. Consent decrees continue to take place, however. For example, Holly Oil and Refining Co. in Woods Cross, UT, just entered into a consent decree this month with the U.S. DOJ to reduce emissions of SO 2 , NO x , and VOC from their refinery. With this act, refiners representing 87% of U.S refinery capacity are now under a

5 Comments by Ad Hoc Coalition of Small Business Refi ners to U.S. EPA, August 27, 2007. Comments on Proposed subpart Ja Rule: Standards for New, Modified, and Reconstructed Process Units at Petroleum Refineries. 72 FR 27178. p. 6.
6 Wall Street Journal, April 18, 2008. “Surge in Natural Gas Price Stoked by New Global Trade.”4-23 consent decree. 7 As more refiners are covered by consent decrees, the impacts associated with this NSPS will be less. 3. New source bias. An NSPS is an example of what is known as a “vintage differentiated regulation (VDR), ” which is a term often used to describe regulations that are fixed with respect to the date of entry of regulated units, with later vintages facing more stringent standa rds. Often, units produced before a given date are exempted or “grandfathered” from regulati on. Reasons that are given for their being commonly applied in regulatory policy is that it is more efficient and cost-effective to control a given amount of pollution at a ne w plant as compared to retrofitting an existing plant. Also, there may be greater equity in not changing environmental regulations for facilities that have alre ady been built, and instead focus on only new facilities. However, there may be incentive for existing firms to desire implementation of VDRs, for these can be us ed to erect entry ba rriers to restrict competition and protect rents created by ex isting command-and-control standards. Thus, there are efficiency and equity consid erations inherent in the setting of an NSPS like this one for the petroleum refineri es industry, as well as potential concerns about it being a possible barrier to en try, though this depends on the degree of stringency in the NSPS. This NSPS may create economic inefficiency by discouraging technological innovation and investment/modernization among regulated sources. Insofar as refiners that manage to avoid triggering NSPS will be rewarded, while those that do invest/moderni ze in capacity expansi ons may trigger it, the rule will impose efficiency losses on the economy that are not captured well by the economic impact model used in the RIA All of these considerations could affect the actual estimates of imp acts associated with this NSPS; it may become more difficult to build new and modified and r econstructed process units (cost savings notwithstanding), while existing units and refi ners may receive an advantage in terms of some protection against en try of new firms and proce ss units. Overall efficiency from a social welfare standpoi nt may also be affected. 4. Projections of new and modi fied and reconstructed source s. We project that during the 5-year period of analysis, EPA assume s the industry will invest in enough new processes to be equivalent to an average of three new refineries per year, or a total of 15 new refineries. Further, the new sources are assumed to be 40% new processes or facilities and 60% modified or reconstructed facilities or processes. Our baseline estimates of emissions and process units, a nd thus our incremental analysis options that are applied to these baseline estima tes, depend strongly on these estimates. Many of these estimates are taken from industry trade journals (e.g., Oil and Gas Journal ). The certainty of these estimates is only as high as that of the e xperts’ capabilities that prepare these estimates.

7 Quoted from the U.S. EPA Web site for the Refinery Enforcement Initiative at http://www.epa.gov/complia nce/resources/cases/civil/caa/oil/index.html.4-24 4.9 References Bruhin et al., 2003

Fedich, R.B., A.C. Woerner, and G.K. Chitnis. May 2004. Selective H 2 S Removal. Hydrocarbon Engineering , Vol. 9, No. 5, pp. 89-92.

Parrish, K., D. Randall, a nd J. Coburn. October 30, 2006. Data and Assumptions used in the Equipment Leaks Cost Analysis for Petroleum Refineries . Memorandum to Karen Rackley, EPA/SPPD. Docket It em No. EPA-HQ-OAR-2006-0699-0034.

Polasek, J.C., J.A. Bullin, and S.T. Donnelly. 1982. Alternative Flow Schemes to Reduce Capital and Operating Costs of Amine Sweetening Units. Proceedings of the 1982 AIChE Spring National Meeting , New York, NY: American Institute of Chemical Engineers.

Stavins, Robert N. “The Effects of Vint age-Differentiated Envi ronmental Regulation.” Resources for the Future, Discussion Paper 05-12, March 2005. Available at <http://www.rff.org/Docume nts/RFF-DP-05-12.pdf>.

Voltz, B.L., J.D. Corley, and R.B. Fedich. N ovember 2004. Benefits of a TGCU Amine Solvent Changeover. Sour Oil & Gas Advanced Technology 2004 International Conference.B-1 APPENDIX B:
SUMMARY OF SIGNIFICANT COMMENTS AND RESPONSES, AND RATIONALES
FOR NSPS EMISSION LIMITS

Below is a summary of the public comments and our responses to them organized by source type and pollutant controlled. Within this appendix is the rationale for the emission limits included in the final NSPS for each source type and pollutant.

B.1 PM Limits for Fluid Catalytic Cracking Units

Comment : Several commenters opposed the pro posed tightening of the FCCU PM
standards relative to s ubpart J and the concurrent change in PM monitoring methods. Some commenters supported the co-proposal to keep the 1 kilogram per Megagram (kg/Mg) PM emission limit based on Method 5B and/or 5F; other commenters either did not oppose or supported the 0.5 kg/Mg emission limit for new “gra ssroots” units, provided EPA demonstrates
it is cost-effective and that the limit is based on EPA Method 5B or 5F.

Several commenters suggested that the cost s in Table 11 of the proposal preamble are significantly underestimated. Comm enters contended that the si ngle “model plant” approach used in EPA’s cost analysis does not realistically consider important factor s such as the inherent sulfur content of the feed, partial-burn versus full-burn regeneration, FCCU /regenerator size, and sources that are already well-controlled due to ot her regulations. Commenters asserted that the purchased equipment costs escalated from es timates that are 20 to 30 years old are underestimated. Several commenters provided estim ates of costs and emission reductions for several actual projects, which they stated indicate that EPA’s costs are significantly underestimated and that the proposed standards are much less cost-effective than presented by
EPA.

Response : In response to these comments, we have revised our analysis to consider each unique existing FCCU in the United States. By do ing so, we fully account for plant size, partialburn versus full-burn regenerati on, existing control configurati on, and specific consent decree requirements. (Details on the spec ific revisions to the analysis can be found in the docket.) With a revised analysis, we were able to more direct ly assess the impacts of process modifications or reconstruction of existing e quipment. We also assessed the effects of PM and SO 2 standards separately in this analysis.

In our revised analysis, we considered thre e options for PM: (1) maintain the existing subpart J standard of 1.0 kg/Mg of coke burn-o ff (filterable PM as measured by Method 5B orB-2 5F); (2) 0.5 kg/Mg of coke burn-off (filterable PM as measured by Method 5B or 5F); and (3) 0.5 kg/Mg of coke burn-off (PM as measured by Method 5). Similar to the analysis for the proposed standards, costs and emission reducti ons for each option were estimated as the increment between complying with subpart J and subpart Ja. We note that none of the available data suggest that a 0.5 kg/Mg coke burn emission limit that includes both filterable and condensable PM (as measured using EPA Method 202) is achievable in pract ice, so we disagree with the comments suggesting this level is appropriate to consider as an option for a total PM limit in this rulemaking.

Option 1 includes the same emissions and requirements for PM as the current 40 CFR part 60, subpart J, so we do not expect an incr emental difference in costs or emission reductions. The PM limit in Option 2 is the same numerical li mit that was proposed in subpart Ja, but the PM emissions are determined using Methods 5B and 5F. These test methods are commonly used for
PM tests of FCCU and are the met hods that were used to generate a majority of the test data we reviewed. Option 3 is a limit of 0.5 kg/Mg coke burn using Method 5 and is the performance level that was proposed for subpart Ja. The imp acts of these three options for new FCCU are presented in Table B-1; the impacts for modified and reconstructed FCCU are presented in Table
B-2.

Table B-1. National Fifth Year Impacts of Options for PM Limits Considered for New Fluid Catalytic Cracking Units Subj ect to 40 CFR Part 60, Subpart Ja a

Option Capital Cost ($1,000) Total Annual Cost ($1,000/yr) Emission Reduction (tons PM/yr) Cost-Effectiveness ($/ton) Overall Incremental 1 0 0 0 N/A N/A 2 3,600 1,100 240 5,600 5,600 3 7,100 1,700 300 6,700 11,000

a PM cost-effectiveness calculated for PM-fin e, assuming 83.3% of the PM is PM-fine.
Table B-2. National Fifth Year Impacts of Options for PM Limits Considered for Reconstructed and Modified Fluid Cata lytic Cracking Units Subject to 40 CFR Part 60, Subpart Ja a

Option Capital Cost ($1,000) Total Annual Cost ($1,000/yr) Emission Reduction (tons PM/yr) Cost-Effectiveness ($/ton) Overall Incremental 1 0 0 0 N/A N/A 2 75,000 12,000 690 21,000 21,000 3 100,000 15,000 810 23,000 37,000

a PM cost-effectiveness calculated for PM-fin e, assuming 83.3% of the PM is PM-fine.

The available data and impacts for the opti ons considered suggest that BDT for new
FCCU is different than BDT for modified a nd reconstructed FCCU. Fo r new FCCU, the optionB-3 and incremental costs for Options 1 and 2 are reasonable compared to the emission reduction achieved. The incremental cost between Opti on 2 and Option 3 of $11,000 per ton PM-fine would generally be considered r easonable, but there are uncertain ties in the achievability of Option 3. Although there were few test data point s using Method 5-equivale nt test methods, we concluded at proposal that both electrostatic precipitators and wet scrubbers can achieve this level of PM emissions. However, the data supporti ng Option 3 are not extens ive, and it is unclear
at this time whether a limit of 0.5 kg/Mg of coke burn as measured by Method 5 could be met by all configurations of FCCU. In addition, we prefer to develop a single perf ormance standard that
considers all condensable PM rather than im plementing phased standards targeting different fractions of condensable PM. We agree with th e commenters that Met hod 202 appears to have bias and reproducibility issues when applied to the FCCU vent. We note that the Agency is working to improve Method 202, and when it achieves consistent and accura te results for FCCU, the Agency will consider the best way to im plement Method 202 for reduction of condensable PM from petroleum refinery FCCU. Therefore, we conclude that Op tion 2, control of PM emissions (as measured by Methods 5B and 5F) to 0.5 kg/Mg of coke burn or less, is BDT for newly constructed FCCU. This option achieves PM emission reductions of 240 tons per year (tons/yr) from a baseline of 910 tons/y r at a cost of $5,600 per ton of PM.

For modified and reconstructed FCCU, the ove rall cost for Option 1 was reasonable, but
neither the overall costs nor the incremental co sts were reasonable for Options 2 and 3. These costs support the suggestion that for FCCU curre ntly complying with subpart J or a consent decree, the costs to achieve further emission reductions are not reasonable. Therefore, we conclude that control of PM emissions (as m easured by Methods 5B and 5F) to 1.0 kg/Mg of
coke burn or less is BDT for reconstructed and modified FCCU.

B.2 SO 2 Limits for Fluid Catalytic Cracking Units

Comment : Several commenters supported the co-pr oposal for modified and reconstructed FCCU to meet subpart J and not the 25 pp mv 365-day rolling average limit for SO 2 . Commenters provided data to suggest that the re trofits of existing sources are not cost effective, particularly if catalyst additives cannot be used. The current subpart J includes three compliance options: (1) if using an add-on control device, reduce SO 2 emissions by at least 90% or to less than 50 ppmv, (2) if not using an add-on control device, li mit sulfur oxides emissions (calculated as SO 2 ) to no more than 9.8 kg/Mg of coke burn-off, or (3) process in the fluid catal ytic cracking unit fresh
feed that has a total sulfur content no greater than 0.30% by weight. Several commenters objected to the elimination of the additional co mpliance options in the existing subpart J for subpart Ja because: (1) there ar e no data to show that the SO 2 limits proposed in subpart Ja areB-4 BDT for all FCCU regenerator c onfigurations; (2) the three options are already established as BDT and, therefore, the CAA requires that EPA ma ke them available; and (3) the substantial
cost and other burdens for a reconstructed or m odified FCCU already complying with one of the alternative options in subpart J to change to daily Method 8 mon itoring or to install CEMS were not addressed in the proposal.

Response : We completely revised our impacts analysis to evaluate SO 2 standards for every existing FCCU that may become subj ect to subpart Ja through modification or
reconstruction. We did not have access to the inhe rent sulfur content of the feed for each FCCU,
so SO 2 emissions are still estimated using average emi ssion factors relevant to the type of control device used for FCCU not subject to consent decr ee requirements. Nonethel ess, we significantly revised the impact analysis to fully account fo r FCCU-specific throughput, existing controls, and consent decree requirements. (Details on the specif ic revisions to the analysis can be found in Docket ID No.) We evaluated tw o options: (1) current subpart J, including all three compliance options; and (2) 50 ppmv SO 2 on a 7-day average and 25 ppmv on a 365-day average. Data are
not available on which to base a more stringent control level.

Option 1 includes the same emissions and requi rements as the current standard (40 CFR part 60, subpart J), so we do not expect an incr emental difference in costs or emission reductions. Based on information provided by vendors and da ta submitted by petroleum refiners, Option 2 can be met with catalyst additives or a wet sc rubber. Of 38 FCCU currently subject to a 50/25 ppmv SO 2 limit through consent decrees, 26 used wet sc rubbers and 12 used catalyst additives or other (unspecified) techniques. Given the numbe r of FCCU currently m eeting the 50/25 ppmv
SO 2 emission limit, we conclude that this limit is technically feasible.

The data in the record suggest that all systems with wet scrubbers can meet the 50/25 ppmv SO 2 emission limit. We believe that the owner or operator of an existing FCCU that does not already have a wet scrubber and is modified or reconstructed su ch that it becomes subject to subpart Ja can use catalyst additives to meet the 50/25 ppmv SO 2 emission limit. Therefore, the cost of Option 2 is calculated using catalyst ad ditives as the method facilities choose for meeting the standard. The impacts of these op tions are presented in Table B-3.B-5 Table B-3. National Fifth Year Impacts of Options for SO 2 Limits Considered for New, Reconstructed, and Modified Fluid Ca talytic Cracking Units Subject to 40 CFR Part 60, Subpart Ja

Option Capital Cost ($1,000) Total Annual Cost ($1,000/yr) Emission Reduction (tons SO 2 /yr) Cost-Effectiveness ($/ton) Overall Incremental 1 0 0 0 N/A N/A 2 0 3,000 4,400 700 700

Based on the data we reviewed to select th e options and the estimated impacts of those options, we conclude that Option 2, control of SO 2 emissions to 25 ppmv or less averaged over 365 days and 50 ppmv or less averag ed over 7 days, is technically feasible and cost-effective for new, reconstructed, and modified fluid catalytic cracking units. This option has no capital cost
and achieves SO 2 emission reductions of 4,400 tons/yr from a baseline of 5,900 tons/yr at a cost of $700 per ton of SO 2 . Therefore, we concl ude that control of SO 2 emissions to 25 ppmv or less averaged over 365 days and 50 ppmv or less averaged over 7 days is BDT for new, reconstructed, or modified fl uid catalytic cracking units.

B.3 NO x Limit for Fluid Catalytic Cracking Units

Comment : Several commenters stated that they would support a NO x limit of 80 ppmv for new sources only, provided a corrected impact an alysis considers the different characteristics
of FCCU and demons trates that the NO x limit for new sources is truly cost-effective. Commenters supported the co-proposal for modified and reconstructed FCCU to meet subpart J and not be subject to a NO x emission limit. A few commenters provided cost da ta showing the
cost of NO x controls is high for modified and reconstr ucted units due to the high cost and space needed for add-on controls. A large number of ex isting FCCU in the U.S. are covered by consent decrees, so significant NO x reductions have already been (o r will soon be) achieved, and an
additional incremental reduction to 20 or 40 ppmv over a 365-day aver age are not widely
demonstrated and would not be cost-effective.

One commenter stated that selective noncatal ytic reduction (SNCR), selective catalytic reduction (SCR), and catalyst additi ves have not been demonstrat ed over significant periods of operational life. Commenters also cited environmental side-effect s, such as the generation of ammonia compounds that contribute to condensab le PM emissions, as a reason not to require these types of controls. Technologies like flue gas recirculation or advanced burner design are typically only cost-effective for new units and ma y be technically infeasible for existing FCCU.B-6 If a limit is necessary for modified or r econstructed FCCU, one commenter suggested that recent catalyst additive trials suppor t an emission limit of approximately 150 ppmv on a 7-day rolling average; this limit would only be achievable if a 24-hour CO averaging time was provided since lowering NO x tends to increase CO emissions in FCCU. The commenter noted that this limit is equivalent to the 0.15 pounds per million British thermal units (lb/MMBtu)
standard for reconstructed and modified heaters and boilers in NSPS subpart Db.

Other commenters supported the inclusion of a NO x limit for FCCU and opposed the coproposal of no NO x standard for modified and reconstr ucted FCCU. The commenters disagreed with the feasibility and cost analyses for modi fied and reconstructed FCCU and stated that
FCCU under a consent decree are ach ieving lower levels that are demonstrated and achievable and therefore BDT. Given the significant hazards to human health and the environment posed by
NO x emissions, the commenters recommended limits of 20 ppmv over a 365-day rolling average and 40 ppmv over a 7-day rolling average for all FCCU. The commenters noted that these limits have been successfully achieved under consent decrees and they are technically feasible on new
units at reasonable costs without additional controls.

The commenters recommendi ng more stringent NO x limits for FCCU stated that 80 ppmv does not represent an adequate level of control given the evolution of em erging technologies. In addition, a BDT of 80 ppmv on 7-day rolling averag e does not look “toward what may be fairly projected for the regulated future” as require d by Portland Cement I (486 F. 2d 375 at 384 (D.C. Cir. 1973)) and other court decisions.

Response : As shown by the disparate comment s received, many commenters suggest
lower NO x emission limits are achievable, while ot her commenters do not believe the proposed
NO x emission limits are cost-effective. While we do acknowledge that lower NO x emission limits are technically achievable , the incremental cost of achieving these lower limits was high when we evaluated options for the proposed standa rds. Therefore, we concluded at proposal that 20 or 40 ppmv NO x limits were not BDT. In our BDT assessment, we evaluated the various
methods to meet alternative NO x limits as BDT rather than id entifying one tec hnology. One of the reasons for this is that each technology ha s its own advantages and limitations. While nonplatinum oxidation promoters and advanced oxidation controls do not achieve the same reduction
in NO x emissions as add-on control devices such as SCR, they do so without any significant secondary impacts. As discussed in the preamble to the proposed standards and noted by several commenters, the injection of ammonia, whether to enhance electrostatic precipitator performance
or to reduce NO x emissions (as with SCR and SNCR), in creases the condensable PM emissions from the unit, and SCR also have spent catalyst disposal issues. As such, the added NO xB-7 reduction of SCR and SNCR must be balanced with these secondary impacts. Part of the basis for selecting control methods to achieve an 80 ppmv NO x emission limit as BDT included both cost and secondary impacts. This approach is necessary when conducting our BDT analysis, thus ensuring the best overall environmental be nefit from the subpart Ja standards.

To ensure that we addressed the commenters’ concerns, we re-evaluated the impacts for
FCCU NO x controls. We also collected a dditional data from continuous NO x monitoring systems for a variety of FCCU NO x control systems. These data sugg est that as refiners gain more experience with the NO x control systems (including catal yst additive improvements), NO x control performance has improved over the past y ear or two. These data suggest that 80 ppmv and, for some control systems, 20 ppmv are tech nically achievable. Therefore, we evaluated
three outlet NO x emission level options as part of th e BDT determination: (1) 150 ppmv; (2) 80 ppmv; and (3) 20 ppmv. Each NO x concentration is averaged ove r 7 days. To estimate impacts for Option 1, we assumed that some units have current NO x emissions below 150 ppmv, and all
other units can meet this leve l with combustion controls (e.g. , limiting excess O 2 or using nonplatinum catalyst combustion promoters and other NO x -reducing catalyst additives in a complete combustion catalyst regenerato r or a combination of NO x -reducing combustion promoters and catalyst additives with low-NO x burners (LNB) in a CO boiler after a partial combustion catalyst regenerator). Data collected from FCCU complying with consent decrees show that Option 2 can also be met using combustion controls; therefor e, we estimated impacts for Option 2 using a similar method as Option 1. The main difference is that a larger numbe r of FCCU must use
combustion controls to meet the emissi on limit (i.e., the FCCU with current NO x emissions between 150 and 80 ppmv would not need contro ls under Option 1 but would need controls under Option 2). Option 3 is the leve l at which we expect all units to install more costly control technology such as LoTOx TM or SCR. The estimated fifth-year emission reductions and costs for each option for new FCCU are summarized in Table B-4; the impacts for modified and
reconstructed FCCU are summarized in Table B-5.

Table B-4. National Fifth Year Impacts of Options for NO x Limits Considered for New Fluid Catalytic Cracking Units Subj ect to 40 CFR Part 60, Subpart Ja

Option Capital Cost ($1,000) Total Annual Cost ($1,000/yr) Emission Reduction (tons NO x /yr) Cost-Effectiveness ($/ton) Overall Incremental 1 860 320 370 880 880 2 1,200 640 860 750 650 3 12,000 3,600 1,400 2,600 5,800B-8 Table B-5. National Fifth Year Impacts of Options for NO x Limits Considered for Modified and Reconstructed Fluid Cata lytic Cracking Units Subject to 40 CFR Part 60, Subpart Ja

Option Capital Cost ($1,000) Total Annual Cost ($1,000/yr) Emission Reduction (tons NO x /yr) Cost-Effectiveness ($/ton) Overall Incremental 1 2,800 1,000 860 1,200 1,200 2 3,700 1,600 1,800 920 660 3 45,000 11,000 3,200 3,600 6,800

Options 1 and 2 provide cost-effective NO x control with limited or no secondary impacts. The costs of Option 1 and Option 2 are commensurate with the emission reductions for new
FCCU as well as modified and reconstructed FCCU. Option 3 would impose compliance costs
that are not warranted for the emissions reducti ons that would be achieved, as shown by the incremental cost-effectiveness values between Option 2 and Option 3.

In evaluating these options, we also considered the secondary impacts. In addition to the direct PM impacts of SNCR and SCR, SCR and LoTOx TM units require additional electrical consumption. The increased energy consumpti on for Option 3 is 40,000 MW-hr/yr for new, modified, and reconstructed units. We also evaluated the secondary PM, CO 2 , SO 2 , and NO x emission impacts of the additional electrical consumption for Option 3. Based on the energy impacts, Option 3 will generate secondary emissions of PM, SO 2 , NO x and CO 2 of 6, 150, 57, and 37,400 tons/yr, respectively.

Based on the impacts shown in Table B-4 a nd Table B-5, and taking secondary impacts into account, we conclude that BDT is Option 2, a NO x emission limit of 80 ppmv, for all affected FCCU. For new FCCU, this option achieves NO x emission reductions of 860 tons/yr from a baseline of 1,500 tons/yr at a cost of $750 per ton of NO x . For modified and reconstructed FCCU, this option achieves NO x emission reductions of 1,800 tons/yr from a baseline of 3,600 tons/yr at a cost of $920 per ton of NO x .
B.4 PM and SO 2 Limits for Fluid Coking Units

Comment : Several commenters stated that EPA’s proposed standards for FCU under subpart Ja are inappropriate a nd not cost-effective. Commenters asserted that based on the significant differences between FCU and FCCU operations, a separate BDT determination is needed for FCCU and FCU. An FCU has higher pa rticulate loading; a heavier feedstock that typically contains a higher concen tration of sulfur, increasing the SO 2 and sulfur trioxide (SO 3 ) emissions; and a wider range of feedstocks with c onsiderable variability in the nitrogen content.B-9 The commenters noted that the impacts an alysis performed for the FCU has shortcomings similar to those in the impacts analys is for FCCU (e.g., the analysis did not properly
consider the additional costs a nd technical difficulties of mee ting the proposed emission limits for modified or reconstructed sources, existi ng units are already controlled). One commenter provided site-specific engineering cost estimates to indicate that the PM controls are much less cost-effective (i.e., more expensive on a cost pe r ton basis) than EPA estimates. The commenter requested that EPA consider instances when wastewater limitations require regenerative wet scrubbers and amend the impact estimates acco rdingly. One commenter stated that a newly installed regenerative wet scrubbe r system on an existing FCU could not meet the proposed Ja
PM standards.

Response : As described in the preamble to the proposed standards, we assumed that one of the larger existing FCU will become a modified or reconstructed source in the next 5 years. The two larger FCU in the United States are both subject to consent decr ees: one has installed
controls and the other is in the process of installing contro ls. The remaining two FCU are significantly smaller than the original model FCU; therefore, a new analysis was conducted using
a smaller model FCU indicative of the size of th e two remaining FCUs that are not subject to consent decree requirements. In our new analysis , we also assumed this FCU has approximately one-half the sulfur content as the larger FCU for which we have data, based on information received regarding the variability in sulfur content across differe nt FCU in the public comments.

In addition to revising our impact analysis, we also collected additional source test data from the one FCU operating a newly installed we t scrubber system to better characterize the control system’s performance. At proposal, we had one FCU source test, which suggested that
the FCU wet scrubber could meet a PM limit of 0.5 kg/Mg coke burn. However, following proposal, we received an additional performance te st for this same FCU wet scrubber with an emission rate between 0.5 and 1.0 kg/Mg coke burn. There was no indication of unusual performance during either of these two tests, so we conclude that these tests demonstrate the variability of the emission source and control syst em. Based on the available data, therefore, we conclude that an appropriate PM performance leve l to consider for a BDT analysis is 1.0 kg/Mg coke burn using EPA Method 5B for a FCU with a wet scrubber. We also conclude that the PM emission limit initially proposed for FCU had not b een adequately demonstrated as an emission limit with which one must comply at all times.

Using our revised model FCU and based on the additional source test data, we reevaluated BDT for PM and SO 2 emissions from FCU based on two options: (1) no new standards, or current subpart J; and (2) a PM limit of 1.0 kg/Mg coke burn (as measured usingB-10 Methods 5B and 5F), a short-term SO 2 limit of 50 ppmv averaged over 7 days, and a long-term
SO 2 limit of 25 ppmv averaged over 365 days. Un like the FCCU, catalyst additives cannot be
used in a FCU to reduce SO 2 , so a wet scrubber is the most likely technology (and the one demonstrated technology) that woul d be used to meet the PM and SO 2 limits of Option 2. Therefore, we estimated costs for an enhan ced wet scrubber to meet both the PM and SO 2 limits. The resulting emission reductions and costs for both of the options are shown in Table B-6.

Table B-6. National Fifth Year Impacts of Options for PM and SO 2 Limits Considered for Fluid Coking Units Subject to 40 CFR Part 60, Subpart Ja

Option Capital Cost ($1,000) Total Annual Cost ($1,000/yr) Emission Reduction (tons PM/yr) Emission Reduction (tons SO 2 /yr) Cost-Effectiveness ($/ton PM and SO 2 ) 1 0 0 0 0 N/A 2 10,000 3,200 1,000 5,900 460 2a 100,000 18,600 1,000 5,900 2,700

One commenter indicated that we should c onsider the costs of a regenerative wet scrubber. This type of system is not needed in most applications, however, in the event such a system were needed, we estimated the cost of a regenerative wet scrubber to meet Option 2. The results of this analysis are also provided in Ta ble B-6 as Option 2a. As seen in Table B-6, even under the most conservative assumptions th e costs associated with the PM and SO 2 emission
reductions are reasonable.

Based on the available technology and the cost s presented in Table B-6 , we conclude that BDT is Option 2, which requires technology that reduces PM emissions to 1.0 kg/Mg of
coke burn and reduces SO 2 emissions to 50 ppmv averaged over 7 days and 25 ppmv averaged over 365 days. This option achieves PM emission re ductions of 1,000 tons/yr from a baseline of 1,100 tons/yr and SO 2 emission reductions of 5,900 tons/yr from a baseline of 6,100 tons/yr at a cost of $460 per ton of PM and SO 2 combined.

B.5 NO x Limit for Fluid Coking Units

Comment : A number of commenters opposed the co-proposal of no NO x standard for FCU, and some disagreed with EPA’s 80 ppmv NO x limit for FCU. These commenters recommended limits of 20 ppmv as a 365-day ro lling average and 40 ppmv as a 7-day rolling average for FCU, as has been successfully ach ieved under consent decrees. The commenters
noted that these limits are achievable on new units without additional controls.B-11 One commenter supported the co-proposal that no new NO x standard be established for
FCU.

Response : Similar to the revised analysis for PM and SO 2 impacts, we re-evaluated BDT
for the FCU NO x controls assuming a smaller FCU will be modified or reconstructed. We evaluated three options: (1) no new standards, wh ich is the current subpa rt J; (2) outlet NO x concentration of 80 ppmv; and (3) outlet NO x concentration of 20 ppmv. Similar to the analysis
for FCCU NO x and depending on the baseline emissions for the FCU, we anticipate that Option 2 can be met using combustion controls and Option 3 will require add-on control technology. The results of this analysis are shown in Table B-7.

Table B-7. National Fifth Year Impacts of Options for NO x Limits Considered for Fluid Coking Units Subject to 40 CFR Part 60, Subpart Ja

Option Capital Cost ($1,000) Total Annual Cost ($1,000/yr) Emission Reduction (tons NO x /yr) Cost-Effectiveness ($/ton)

Overall Incremental 1 0 0 0 N/A N/A 2 3,700 850 660 1,300 1,300 3 6,000 1,300 750 1,700 5,000

The costs for Option 1 and Option 2 are comm ensurate with the emission reductions, but the incremental impacts for Option 3 are not reasonable, as shown in Table B-7. Option 3 achieves an additional 90 tons per year NO x reduction, but the incrementa l costs of achieving this reduction is $5,000 per ton of NO x removed. The cost of achieving this 12% additional emission reduction nearly triples the total annualized cost of operating the controls. Based on these projected impacts, we support our original de termination that BDT is Option 2, or technology
needed to meet an outlet NO x concentration of 80 ppmv or less. This option achieves NO x emission reductions of 660 tons/yr from a baselin e of 800 tons/yr at a cost of $1,300 per ton of
NO x .
B.6 SO 2 Limit for Small Sulfur Recovery Plants (SRP)

Comment : One commenter stated that no new re quirements should be added for SRP less
than 20 LTD because the controls are not cost-e ffective. The commenter provided data on tail gas treatment projects but noted that these costs ar e for larger SRP, and controls for smaller SRP
will be less cost-effective. Several commenters noted that if EPA does establish standards for smaller SRP, the monitoring and compliance eval uation methods for the 99% control standard are not clearly specified in the rule and could create difficulties in documenting compliance for small Claus plants. Therefore, the small SRP sh ould be allowed to comp ly with the 250 ppm SO 2B-12 emission limit provided to large SRP. One comment er suggested that non-Cl aus units should be subject to a 95% recovery efficiency standard.

Response : To ensure that we addressed the commenters’ concerns regarding costeffectiveness, we re-evaluated the impacts fo r small SRP. We adjusted our cost estimated upward based on capital costs pr ovided by industry representa tives. We evaluated three SO 2 control options as part of the BDT determ ination for SRP less than 20 LTD: (1) no new standards, or current subpart J; (2) 99% sulfur recovery; and (3) 99.9% sulf ur recovery. As noted in the preamble to the proposed stan dards, 95% sulfur recovery is eq uivalent to the efficiency of a two-stage Claus unit without cont rols. Also as noted in the pr eamble to the proposed standards (section V.D), the 99% and 99.9% recovery levels are achievable for SRP of all sizes by various types of SRP or tail gas treatments.

The estimated fifth-year emission reductions and costs for new SRP are summarized in Table B-8; the impacts for modified and recons tructed SRP are summarized in Table B-9. These values reflect the impacts only for SRP smaller than 20 LTD; there are no additional cost impacts for larger Claus units because th ey would already have to comply with the existing standards in subpart J.

Table B-8. National Fifth Year Impacts of Options for SO 2 Limits Considered for New Small Sulfur Recovery Plants Subject to 40 CFR Part 60, Subpart Ja

Option Capital Cost ($1,000) Total Annual Cost ($1,000/yr) Emission Reduction (tons SO 2 /yr) Cost-Effectiveness ($/ton) Overall Incremental 1 0 0 0 N/A N/A 2 130 63 42 1,500 1,500 3 590 230 52 4,500 18,000

Table B-9. National Fifth Year Impacts of Options for SO 2 Limits Considered for Modified and Reconstructed Small Sulfu r Recovery Plants Subject to 40 CFR Part 60, Subpart Ja

Option Capital Cost ($1,000) Total Annual Cost ($1,000/yr) Emission Reduction (tons SO 2 /yr) Cost-Effectiveness ($/ton) Overall Incremental 1 0 0 0 N/A N/A 2 1,600 670 380 1,800 1,800 3 7,800 2,600 470 5,700 23,000

The costs for Option 1 and Option 2 are reas onable considering th e emission reductions achieved, but the incremental impacts shown in Table B-8 and Table B-9 for Option 3 areB-13 beyond the costs that the Agency believes are re asonable for these small units to achieve an additional 90 tons per year of SO 2 emissions. The additional equipment needed to achieve these reductions quadruples the capital costs. Ba sed on these projected impacts and available performance data, we support our original determ ination that BDT is Option 2, or 99% sulfur recovery. For new SRP, this option achieves SO 2 emission reductions of 42 tons/yr from a baseline of 150 tons/yr at a cost of $1,500 per ton of SO 2 . For modified and reconstructed SRP, this option achieves SO 2 emission reductions of 380 tons/y r from a baseline of 1,400 tons/yr at a cost of $1,800 per ton of SO 2 . We note that we are also revising the format of the standard in response to public comments in terms of sulfur outlet concentrations. Based on the targeted recovery efficiency of 99%, the emission li mit for small SRU is either 2,500 ppmv SO 2 or 3,000 ppmv reduced sulfur co mpounds and 100 ppmv of H 2 S, both of which are determined on a dry basis, corrected to 0% O 2
.
B.7 NO x Limit for Process Heaters

Comment : Several commenters stated that the 80 ppmv NO x limit for process heaters is not stringent enough. Considering recent settleme nt negotiations and regulation development,
NO x emissions reductions well below 80 ppmv can be achieved cost effectively. The
commenters stated that NO x emissions of less than 40 ppmv at 0% O 2 are achievable with combustion modifications such as LNB, ultra low-NO x burners (ULNB), and flue gas recirculation technologies; post-combustion controls such as SCR, SNCR, and LoTOx TM achieve
NO x reductions an order of magnitude below those from combustion modifications. The commenters noted that Bay Ar ea Air Quality Management Di strict (BAAQMD) Regulation 9, Rule 10, requires process heaters to meet a 0.033 lb/MMBtu NO x limit (roughly 32 ppmv NO x at 0% oxygen). One commenter stated that 30 ppmv has been demonstrated under consent decrees to be an achievable level and ample technology ex ists. The commenters also noted that 7 to 10 ppmv NO x limits (at 3% oxygen) have been achieved in practice. One commenter stated that NSPS subparts J and Ja should impose NO x emission limits on all fuel gas combustion devices that are at least as stringent as the most stri ngent consent decree. Some consent decrees require next generation ULNB designed to achieve NO x emissions rates of 0.012 to 0.020 lb/MMBtu (12 to 20 ppmv NO x at 0% oxygen). Commenters recomme nding more stringent requirements suggested limits ranging from 7 ppmv NO x (at 3% oxygen) to 30 ppmv for new process heaters fueled by refinery fuel gas.

Other commenters stated that alternative monitoring options should be provided to small fuel gas combustion units due to the high costs of CEMS relative to the emissions from the small units. One commenter suggested an exemption fro m the fuel gas monitoring requirements forB-14 process heaters less than 50 MMB tu/hr. Another commenter recommended an exemption from the fuel gas monitoring requirements for proce ss heaters less than 40 MMBtu/hr as used by South Coast Air Quality Mana gement District (SCAQMD).

Response : We revisited the BDT determina tion based on the public comments and revised the methodology used to calculate the cost and emission reduction impacts for the proposed standards. We evaluate d three options as part of th e BDT determination. Each option consists of a potential NO x emission limit and applicability ba sed on process heater size. These differ slightly from the proposal options base d on commenter suggestions. Option 1 would limit
NO x emissions to 80 ppmv or less for all proc ess heaters with a capacity greater than 20 MMBtu/hr (the proposed standards). Option 2 would limit NO x emissions to 40 ppmv or less for all process heaters with a capacity greater than 40 MMBtu/hr. This option is similar to many
consent decrees that set an emission li mit of 0.040 lb/MMBtu (roughly 40 ppmv NO x at 0% oxygen) for process heaters greater th an 40 MMBtu/hr. Option 3 would limit NO x emissions to 20 ppmv or less for all process heaters with a cap acity greater than 40 MMBtu/hr. In each option,
the NO x concentration is based on a 24-hour rolling average.

The estimated fifth-year emission reductions and costs for each option for new process heaters are summarized in Table B-10; impacts for modified and recons tructed process heaters are summarized in Table B-11. Similar to the pr oposal analysis, we considered LNB, ULNB, flue gas recirculation, SCR, SNCR, and LoTOx TM as feasible technolog ies. We believe that nearly all process heaters at refineries that wi ll become subject to subpart Ja can meet Option 1 or Option 2 using combustion controls (LNB or UL NB). Most process heat ers would need to use more efficient control technologies, such as LoTOx TM or SCR, to meet the NO x concentration limit in Option 3. Options 2 and 3 include a mini mum 40 MMBtu/hr size threshold because the
incremental cost-effectiveness for NO x control options for the proposed standard of 80 ppmv for

Table B-10. National Fifth Year Impacts of Options for NO x Limits Considered for New Process Heaters Subject to 40 CFR Part 60, Subpart Ja

Option Capital Cost ($1,000) Total Annual Cost ($1,000/yr) Emission Reduction (tons NO x /yr) Cost-Effectiveness ($/ton) Overall Incremental 1 9,000 7,300 4,800 1,500 1,500 2 9,000 7,500 5,200 1,400 500 3 110,000 30,000 5,900 5,100 37,000B-15 Table B-11. National Fifth Year Impacts of Options for NO x Limits Considered for Modified and Reconstructed Process Heaters Subject to 40 CFR Part 60, Subpart Ja

Option Capital Cost ($1,000) Total Annual Cost ($1,000/yr) Emission Reduction (tons NO x /yr) Cost-Effectiveness ($/ton) Overall Incremental 1 12,000 4,000 2,100 1,900 1,900 2 14,000 4,300 2,200 1,900 2,100 3 64,000 15,000 2,500 5,900 39,000

units with smaller capacities rang ed from $3,500/ton to $4,100/ton of NO x reduced, which was
determined not to be reasonable for these small heaters, which would primarily be located at
small refineries.

Based on the impacts in Tables B-10 a nd B-11, the costs of Options 1 and 2 are reasonable compared to the emission reductions. The incremental cost between Options 2 and 3 of almost $40,000/ton of NO x is not commensurate with the additional 1,000 tons of emission
reduction achieved for new and modified or recons tructed process heaters. Moreover, the capital costs of Option 3 are about $150 million greater th an the capital costs for Option 2, which are only $23 million. Therefore, we conclude that BDT for process heaters greater than 40 MMBtu/hr is technology that achieves an outlet NO x concentration of 40 ppmv or less, or Option 2. For new process heaters, this option achieves NO x emission reductions of 5,200 tons/yr from a baseline of 7,500 tons/yr at a cost of $1,400 per ton of NO x . For modified and reconstructed process heater s, this option achieves NO x emission reductions of 2,200 tons/yr from a baseline of 3,200 tons/yr at a cost of $1,900 per ton of NO x . Although we agree that lower
NO x concentrations are achievable, we determined that the incremental cost to achieve these
lower NO x concentrations was not reasonable.

B.8 Fuel Gas Combustion Devices

Comment : Several commenters contended that the proposed standards for fuel gas combustion devices were not stringent enough; EP A should ensure that the best demonstrated emission control technologies are installed as the industry is moderni zed. Given the significant hazards to human health and the environment posed by SO 2 emissions, the commenters suggested that the 365-day average limits should be 40 ppmv TRS and 5 ppmv SO 2 . The commenters also recommended that EPA tighten the 3-hour concentration limit to 100 ppmv TRS. On the other hand, another commente r contended that although amine treatment applications for product gases can achieve H 2 S concentrations of 1 to 5 ppmv, a tighter standard is not BDT for refinery fuel gas.B-16 Several commenters objected to the addition of the 60 ppmv H 2 S and 8 ppmv SO 2 limits (365-day rolling average) in the proposed subpart Ja standards for fuel gas combustion devices because they are infeasible and/or not co st-effective. According to commenters, EPA erroneously assumed that the additional reductio ns could be achieved with existing equipment. Although this may be true in some cases, some refineries would need to add additional amine adsorber/regenerator capacity and some may also need to add additional sulfur recovery capacity (e.g., an additional Claus train and tail gas treatment unit). One commenter requested an exemption be provided for refineries that cannot meet the tighter long-te rm standard by simply increasing their amine circulation rates. One commenter stated that there will be little
incremental environmental benefit from the l ong-term limit, and it unnecessarily penalizes refineries that designed their amine systems to tr eat to levels near the proposed annual standard. The commenters provided cost data for exampl es of projects requiring new amine adsorption units to show that the proposed standards are not cost-effective.

A number of commenters particularly oppos ed the proposed revision to include TRS limits for fuel gas produced from coking units or a ny fuel gas mixed with fu el gas produced from coking units. One commenter noted that some State and local agencies have specific TRS standards, but these requirements were not based on a BDT assessment. According to commenters, EPA has included no technical basis for the achievability of the TRS fuel gas standard or explanation of why control of TRS is limited to fuel gas generated by coking units. The commenters recommended that EPA postpone a doption of a TRS limit until it has gathered and evaluated adequate data to c onclude that the limit is technically feasible and cost effective.

Commenters stated that EPA did not address the cost-effect iveness and no n-air quality impacts of the TRS standards and did not define BDT for the removal of TRS. One commenter
stated that without an established de minimis level, an entire fuel gas system could be subject to the TRS limits if any amount of coker gas enters the fuel gas system. Amine scrubbing systems
are selective to H 2 S and are not suitable to other TRS co mpounds such as mercaptans, according
to the commenters. The non-H 2 S TRS compounds are not amenable to amine treating and there is no technology readily in-place at refineries for reducing non-H 2 S TRS compounds. Therefore, removing these other TRS compounds would re quire significant capital outlay for new equipment, costs that were not considered in the impacts analysis, according to the commenters.

One commenter provided an example of a trea tment system installed to meet a facilitywide fuel gas total sulfur sta ndard of 40 ppmv; the commenter es timated the capital cost of the entire system to be $150-million. The commenter also indicated that low-BTU gas from flexicoking units would need to be specially trea ted at a capital cost of $61 million to achieve aB-17 total sulfur content of less than 150 ppmv, and the treatment would increase energy consumption, resulting in increases in NO x , CO, and CO 2 emissions. Another commenter provided an order-ofmagnitude engineering estimate of $50-million to treat TRS down to 45 ppmv (long-term average). Based on one commenter’s experience with a new fuel ga s treating facility, non-acidic TRS cannot be treated down to the proposed leve ls utilizing Merox-amine treatment. A costeffective solution could be natural gas blending at the affected combustion device; however, this option has the negative effect of reducing the production of refi nery fuel gas and therefore reducing the refinery’s capacity for making gasoline.

Several commenters stated that the orig inal BDT determination was based on amine scrubbing of H 2 S and not on SO 2 ; the SO 2 standard was simply a compliance option that was
calculated to be e quivalent to the H 2 S concentration limit at 0% exce ss air. They also asserted
that EPA cannot use the SO 2 option as a basis for the TRS standard because the SO 2 option is not BDT. On the other hand, one commenter requested that EPA clarify the fuel gas standards in subpart J to expressly indicate that the 20 ppm SO 2 limit is a valid complian ce option (instead of including it only in the monitoring section). According to the commenter, focus has been on H 2 S
due to the structure of the requirements of subpart J, and pe rmits rarely require that combustion sources demonstrate compliance with the 20 ppmv SO 2 limit. The commenter stated that refiners clearly should be allowed to comply w ith the broader, more comprehensive SO 2 limit.

A few commenters noted that, as H 2 S is part of TRS, the TRS standard is even more stringent than the H 2 S standard. One commenter recommende d that no change in the fuel gas
standards be made or that the standards focus on H 2 S only with an alternative emission limit for
SO 2 . One commenter stated that EPA developed the 160 ppmv H 2 S standard to be more stringent than the 20 ppmv SO 2 standard specifically because H 2 S did not represent all of the sulfur in the fuel gas. Commenters stated that using an F-factor approach (Method 19, 40 CFR part 60, appendix A), the TRS limit that is equivalent to the 20 ppmv SO 2 emission limit is 260 ppmv and the TRS limit that is equivalent to the 8 ppmv SO 2 emission limit is 104 ppmv.

Response : We initially assumed that fuel gas generated by the coking unit was mixed with other fuel gases that were mostly H 2 S and that increasing the amine circulation rate would
result in additional H 2 S removal that could be used to meet the proposed standard. However, based on a review of the available data, non-H 2 S sulfur content in coker fuel gas may be 300 to 500 ppmv. At these levels, specif ic treatment to reduce these ot her sulfur compounds would be needed. As indicated by one commenter, a plant- wide total sulfur limit of 40 ppmv has been achieved in practice in at least one refinery using a treatment tr ain consisting of a Merox system, sponge oil absorbers, MEA absorbers, and caustic wash towers. Therefore, total sulfur fuel gasB-18 treatment methods are demonstr ated. We evaluated the cost of this treatment based on information provided in the public comments.

Based on the public comments a nd additional data, we revisited the BDT determination and assessed three options for increasing SO 2 control of fuel gas combustion units: (1) 20 ppmv
SO 2 or 162 ppmv H 2 S averaged over 3 hours; (2) Option 1 plus 8 ppmv SO 2 or 60 ppmv H 2 S averaged over 365 days; and (3) a compliance option of 162 ppmv TRS averaged over 3 hours and 60 ppmv TRS averaged over 365 days for fuel gas combustion devices combusting fuel gas generated by a coking unit and Option 2 for combustion devices combusting fuel gas not generated by a coking unit. Option 1 includes the same limits that are in subpart J, so we do not expect any additional costs or emission reductions. To address the commenters’ concerns, we revised our proposal analysis to include an assumption that 10% of the affected facilities would have to add additional amine capacity to achieve Option 2. We assumed that a separate treatment
train that can treat TRS would be required to meet Option 3. The es timated fifth-year impacts of each of these options for new fuel gas combus tion devices are presented in Table B-12; the impacts for modified and reconstructed fuel gas combustion devices are pr esented in Table B-13.

Table B-12. National Fifth Year Impacts of Options for SO 2 Limits Considered for New Fuel Gas Combustion Devices Subject to 40 CFR Part 60, Subpart Ja

Option Capital Cost ($1,000) Total Annual Cost ($1,000/yr) Emission Reduction (tons SO 2 /yr) Cost-Effectiveness ($/ton) Overall Incremental 1 0 0 0 N/A N/A 2 1,200 770 520 1,500 1,500 3 100,000 13,000 930 14,000 31,000

Table B-13. National Fifth Year Impacts of Options for SO 2 Limits Considered for Modified and Reconstructed Fuel Gas Combustion Devices Subject to 40 CFR Part 60, Subpart Ja

Option Capital Cost ($1,000) Total Annual Cost ($1,000/yr) Emission Reduction (tons SO 2 /yr) Cost-Effectiveness ($/ton) Overall Incremental 1 0 0 0 N/A N/A 2 33,000 11,000 4,700 2,400 2,400 3 1,700,000 200,000 9,100 22,000 42,000

Overall costs for Options 1 and 2 are reas onable compared to the emission reduction achieved for new, modified and reconstructed fu el gas combustion devices. We further evaluated
the incremental costs and reductions between the three options and found that they were reasonable for Options 1 and 2, while the increm ental cost for Option 3 is not. While Option 3B-19 provides significant additional SO 2 emission reductions, the additional capital cost of $1.7 billion is highly significant and coul d pose a significant barrier to future refinery upgrades and expansions. Based on these impacts and consid eration of current operating practices, we
conclude that BDT is use of technology that reduces the emi ssions from affected fuel gas combustion units to 20 ppmv SO 2 or 162 ppmv H 2 S averaged over 3 hours and 8 ppmv SO 2 or 60 ppmv H 2 S averaged over 365 days, or Option 2. For new fuel gas combustion devices, this option achieves SO 2 emission reductions of 520 tons/yr from a baseline of 1,200 tons/yr at a cost of $1,500 per ton of SO 2 . For modified and reconstructed fu el gas combustion devices, this option achieves SO 2 emission reductions of 4,700 tons/yr from a baseline of 12,000 tons/yr at a cost of $2,400 per ton of SO 2
.
We note that although we have determined that Option 3 is not BDT and we will not limit
the amount of SO 2 emissions from combustion of sulfur compounds other than H 2 S in subpart Ja, we plan to continue to work with the industry to understand the magnitude of these SO 2 emissions and to identify technologies that can be cost effectively applied to reduce the
emissions. We have learned thr ough this process that the SO 2 emissions from combustion of TRS in coker gas are generally not reflected in emission inventories and we plan to explore this issue in greater detail in the future to determine where SO 2 emissions are underestimated and the best way to correct the inventories.

B.9 Flaring of Refinery Fuel Gas

Comment : Several commenters supported the pr oposed work practice standards to eliminate routine flaring and develop start up, shutdown, and malfunction (SSM) plans; the commenters opposed the co-proposal of no standards. One commenter supported the
determination that elimination of routine flar ing is BDT, citing reductions in hydrocarbon, NO x , SO 2 , and CO 2 emissions. One commenter stated that bo th subparts J and Ja should explicitly require that flaring be used onl y as a last resort in unusual ci rcumstances, such as emergencies
and not on a routine basis. Commenters asserted that monitoring on an ongoing basis is needed to verify that no flaring of nonexempt gases o ccurs. Commenters stated that subpart Ja should also require refiners to instal l a flare gas recovery system, a lthough such requirements should not preclude monitoring requirements. One commenter stated that the NSPS should require a SSM plan to eliminate venting or flaring during such planned start-up, shutdown, and maintenance activities and explicitly prohibi t venting or flaring during th ese planned activities; proper operation and maintenance practices should completely eliminat e the need to use flares during
these activities. One commenter noted that those re fineries that have eval uated their startup and shutdown procedures to reduce or eliminate direct venting or fl aring during planned startup andB-20 shutdown events have demonstrated the best t echnology; therefore, thei r actions represent BDT and should be adopted in the NSPS. The comme nters also supported co nducting a root cause analysis (RCA) in the event of flaring a nd other venting releases of 500 lb/day SO 2
.
A number of commenters genera lly supported the intent to re duce flaring and the idea of SSM plans to address flaring during planned startups and sh utdowns (one commenter also included combustion of high sulfur-containi ng fuel gases during a malfunction), flare minimization plans, and RCA for flare events in excess of 500 lb/day. However, they opposed the work practice standard for elimination of rout ine flaring and the propose d creation of fuel gas producing units for subpart Ja. The commenters st ated that the definiti on of “fuel gas producing unit” is overly broad, making it difficult to de termine what constitutes a modification or reconstruction, and the proposed work practice standard for these units is infeasible, unnecessary, and not cost-effectiv e. Facility operators and re gulators would have difficulty discerning if a flaring event was caused by an affected fuel gas producing unit or a unit not subject to the standard. One comm enter indicated that there is no de minimis level by which units that produce insignificant quantities of fuel gas can be excluded fr om the extensive work practice
standards.

Commenters recommended that the affected s ource be the flare, which is already subject to the standard as a fuel gas combustion device. The commenters suggested that for each affected flare, the facility would develop a written Flar e Management Plan designed to minimize flaring of fuel gas during all periods of operation. This plan, along with the RCA, would ensure that all flaring events with potential excess emissions will be minimized. One commenter noted that EPA could require a flare management plan for any flare tied to a fuel gas system that has an affected fuel gas combustion device as a better alternative to “fuel ga s producing units.” One commenter noted that an exemption from th e notification requirements for modified or reconstructed units could be provided as an incen tive for early adoption of the flare management plan; another commenter suggested that regula tory incentives such as exemptions from monitoring and developing flare minimization plan s should be provided for facilities that have installed fuel gas recovery systems. One commente r supported this type of requirement for flares currently subject to s ubpart J, assuming a minimum of 9 months is provided for plan development and implementation. On the other ha nd, one commenter noted that the definitions of the affected facility under s ubparts J and Ja are different and recommended that the distinction be made stronger so that it is clear that existi ng process unit facilities are “grandfathered” and exempt from the flaring minimization standards.B-21 One commenter suggested that the work practic es language should be cl arified to indicate that routing offgas to the flare gas system woul d be acceptable if the system was equipped with a flare gas recovery system. The pr ohibition should be specific to the flare itself as some flare gas systems are equipped with recovery compressors, the use of which should be encouraged rather than discouraged.

Commenters stressed the need for flares as safety devices; any flare minimization program must not interfere with the ability of th e refinery owner or operator to use flares for safety reasons. The commenters stated that “r outine” flaring cannot be adequately defined in practice; therefore, restrictions on “routine” flari ng will lead to unsafe operations in attempts to
avoid enforcement actions. The commenters re quested that EPA include language in the regulation, consistent with the preamble discu ssion, that: “Nothing in th is rule should be construed to compromise refinery operations and practices with regard to safety.”

One commenter indicated that the proposed work practice standards for “no routine flaring” interfere with flare minimization plans implemented in response to consent decrees. The proposed work practice standard could be interp reted as prohibiting flaring during start-up and shutdown, and EPA has not determined this to be BDT. The commenter stated that the BAAQMD analysis applies to eliminating flaring duri ng normal operation [similar to proposed §60.103a(b)], not during start-up and shutdown as in proposed §60.103a(a). The commenter provided cost estimates for one re finery to install a recovery sy stem to eliminate flaring during start-up and shutdowns; the costs ranged from $200,000 to $800,000 per ton of VOC reduced and higher for other criteria pollutants. Therefore, §60.103a(a) should clearly exclude start-up and shutdown gases.

A few commenters provided overall project costs for flare gas recovery projects indicating the annual costs are hi gher than those in the analysis supporting the proposed work practice. One commenter stated that EPA underestim ated the cost of fuel gas recovery systems and, given the uncertainty in emission reductions, contended that fuel gas recovery systems are
not cost-effective within the NSPS context.

A number of commenters provided an alte rnative to EPA’s proposed work practice standards. The suggestions included a 500 lb/day SO 2 standard tied with a flare management plan as an alternative compliance option (to the H 2 S concentration limit) for flares. The
commenters recommended that this alternative compliance option be provi ded in both subparts J
and Ja and noted that it could be used as an in centive for the flare management plan to cover all flares. One commenter also noted that these requi rements should be applicable to flares thatB-22 receive process gas, fuel gas, or process upset gas; they should not be applicable to flares used solely as an air pollution contro l device, such as a flare used exclusively to control emissions from a gasoline loading rack. Another commenter cl arified that if the refinery elects to comply with this alternative for any flar e, all flares at the refinery wo uld need a flare management plan.
The commenter noted that EPA coul d choose to set the 500 lb/day SO 2 limit as a total for all flares for which the alternative compliance option is chosen (i.e., if the alternative compliance option is selected for two flares at a refiner y, the total emissions from both flares would be limited to 500 lb/day).

Response : Although commenters suggested that certai n provisions be made applicable to facilities subject to subpart J, the following provisions are only app licable to facilities subject to subpart Ja as CAA section 111 provides that ne w requirements apply only to new sources. We considered these comments and agree that the st andards are much more straight-forward when the affected facility is defined as the flare. Therefore, we ha ve eliminated “fuel gas producing units” as an affected facility in this final rule, and we specifically define a flare as a subset of fuel gas combustion device, which is an affected fac ility in this final rule. A “flare” means “an openflame combustion device used for burning off unwanted gas or flammable gas and liquids. The flare is defined to include the burner, ignite r, flame arrestors, knockout pots, and piping and header systems.”

There are three general work practice standards that we re proposed for “fuel gas producing units,” which may be su mmarized as follows: (1) the “ no routine flaring” requirement; (2) flare minimization plan for start-up, shutdown, and malfunction events; and (3) a root-cause analysis for SO 2 releases exceeding 500 lb/day (which wa s proposed for all affected facilities). The “no routine flaring” work practice was not intended to prohibit flar ing during SSM events; the provisions were intended to apply only dur ing normal operating conditions. We agree with the commenter that suggested that nothing in th is rule should be c onstrued to compromise refinery operations and practices w ith regard to safety. We also specifically rejected a prohibition on flaring for planned start-up a nd shutdown events. We agree with the commenters that noted
that numerous refineries have demonstrated th at flare minimization du ring planned start-up and shutdown activities can greatly re duce flaring during these events . We do believe, however, that a complete elimination of flaring during these events is very site-s pecific and although it is reported to have been achieved at a limited numb er of refineries, we do not have information to suggest that it has been adequa tely demonstrated for universal application. As “no routine flaring” is difficult to define in practice, we have re-evaluated BDT using more specific options.B-23 Option 1 is no additional standards for flares. In Option 2, any routin e emissions event or any process start-up, shutdown, upset or malfunction that causes a discharge into the atmosphere in excess of 500 pounds per day of SO 2 from an affected fuel gas combustion devices would require a root cause analysis to be performed. This approach is similar to what is included in most consent decrees. We are also including a re quirement for continuous monitoring of TRS for all gases flared (including those from upsets, startups, shutdowns, and malfunction events), in order to accurately measure SO 2 emissions from affected flar es. Option 3 includes: (1) the SO 2 root cause analysis in Option 2; (2) a limit on th e flare flow rate of 250,000 scfd; and (3) a flare management plan for each flare affected facili ty. The flow limit of 250,000 scfd is based on our cost analysis that indicates that for typical gas st reams in quantities above this limit, the value of recovered fuel completely offsets the costs of installing and operating recovery systems. Many refineries have implemented flare gas recove ry to reduce energy needs and save money. The flare management plan must: (1) include a diag ram illustrating all connections to each affected flare; (2) identify the flow rate monitoring device and a detailed descrip tion of manufacturer’s specifications regarding quality assurance procedures; (3) include standard operating procedures for planned start-ups and shutdowns of refinery process units that vent to the flare (such as staging of process shutdowns) to minimize flari ng during these events; (4) include procedures for a root cause analysis of any process upset or eq uipment malfunction that causes a discharge to the flare in excess of 500,000 scfd; and (5) include an evaluation of potentia l causes of fuel gas imbalances (i.e. , excess fuel gas), upsets or malfuncti ons and procedures to minimize their occurrence and records to be maintained to document periods of excess fuel gas. Excess emission events for the flow rate limit of 250,000 scfd and the result of root cause analysis must be reported in the semi-annual compliance reports.

Option 4 is identical to Option 3 except that flaring is limite d to 50,000 scfd. This level is
estimated to be a baseline level that accounts for the flow requirement needed to maintain safe operations of the flare (i.e., flow of sweep ga s and compressor cycle gas). For both Option 3 and Option 4, the limit on the flare flow rate does not apply during malf unctions and unplanned startups and shutdowns. The flow rate limits in Options 3 and 4 were developed as surrogate VOC, SO 2 , and NO x emission limits; the limits are based on 30-day rolling average flow rate
values.

It is anticipated that a flare gas recovery sy stem will be used to comply with Options 3 and 4 when a flare is currently used on a contin uous basis, and the recovered flare gas offsets natural gas purchases. The cost-effectiveness of the flare gas recovery system is primarily dependent on the quantity of gas that the syst em can recover. Many refineries have alreadyB-24 implemented similar work practices through co nsent decrees and local rules (BAAQMD and SCAQMD), and these requirements have had a dem onstrated reduction in flaring events. Flare gas recovery will reduce SO 2 , NO x and VOC emissions. However, if a refinery produces more fuel gas than the refinery needs to power its equi pment, there is no place the refinery can use the recovered fuel gas and there is no additional natural gas purchases to offset. In these cases, flare gas recovery is not considered technically feasib le because the excess fuel gas will have to be flared. Therefore, we have included specific pr ovision within the flare management plan to address instances of excess fuel gas. For peri ods when the refinery owner or operator can demonstrate, through records of natural gas purchas es or other means as described in their flare minimization plan, that the refinery is fuel gas rich, compliance with the flow limit is demonstrated by implementing the procedures described in the flare management plan.

Impacts for each of the four options are base d on estimates of current flaring quantities and include the root cause analysis, flare manage ment plan, and flare gas recovery systems when needed. The impacts for each option for new flar es are presented in Table B-14; impacts for
modified and reconstructed flares are presented in Table B-15.

Table B-14. National Fifth Year Impacts of Options for Work Practices Considered for New Flaring Devices Subject to 40 CFR Part 60, Subpart Ja

Option Capital Cost ($1,000) Total Annual Cost ($1,000/yr) Emission Reduction (tons SO 2 /yr) Emission Reduction (tons NO x /yr) Emission Reduction (tons VOC/yr) Cost-Effectiveness ($/ton)

Overall Incremental 1 0 0 0 0 0 N/A N/A 2 0 23 15 0 0 1,600 1,600 3 8,800 (1,300) 16 1 41 (23,000) (31,000) 4 15,000 (840) 16 1 52 (12,000) 43,000

Table B-15. National Fifth Year Impacts of Options for Work Practices Considered for Modified and Reconstructed Flaring Devices Subject to 40 CFR Part 60, Subpart Ja

Option Capital Cost ($1,000) Total Annual Cost ($1,000/yr) Emission Reduction (tons SO 2 /yr) Emission Reduction (tons NO x /yr) Emission Reduction (tons VOC/yr) Cost-Effectiveness ($/ton)

Overall Incremental 1 0 0 0 0 0 N/A N/A 2 0 92 59 0 0 1,600 1,600 3 35,000 (5,300) 64 4 165 (23,000) (31,000) 4 59,000 (3,300) 66 6 207 (12,000) 43,000B-25 Based on these impacts and consideration of t echnically feasible operating practices, we conclude that BDT is Option 3. Option 3 includes a set of work practice standards that include root cause analysis for a discharge into the atmosphere in excess of 500 pounds per day of SO 2 (over the allowable emissions limit) from a fuel gas combustion device of sulfur recovery plant or in excess of 500,000 scfd flow from the flare. It also includes a flare management plan. Finally, fuel flow to the flare is limited to 250,000 scfd. To support implementation of these requirements, monitoring and reporting of the flow rate and sulfur content is required. For new flaring devices, this option achieves SO 2 emission reductions of 16 tons/yr from a baseline of 32 tons/yr, NO x emission reductions of 1 t on/yr from a baseline of 2 tons/yr, and VOC emission reductions of 41 tons/yr from a baseline of 67 tons/yr with a net fuel savings of $23,000 per ton
of combined SO 2 , NO x , and VOC. For modified and reconstr ucted flaring devices, this option
achieves SO 2 emission reductions of 64 tons/yr from a baseline of 129 tons/yr, NO x emission reductions of 4 tons/yr from a baseline of 7 tons/y r, and VOC emission reductions of 165 tons/yr from a baseline of 266 tons/y r with a net fuel savings of $23,000 per ton of combined SO 2 , NO x , and VOC.

B.10 Delayed Coking Units

Comment : Several commenters supported the propos al that requires delayed coking units to depressure the coke drums to the fuel ga s system down to 5 psig. One commenter supported venting the delayed coker gas to a flare or to the atmosphere at pressures less than 5 psig; at pressures greater than 5 psig, th e commenter suggested that the rule should only prohibit gases from being sent to a flare and allow any other disposition. That is, the commenter stated that
EPA should not restrict the dis position of the coker depressuri zation gas to only the fuel gas system.

One commenter supported inclusion of a coke drum pressure limit above which the coke drum exhaust gases must be sent to a recovery sy stem, disagreed that it is technically infeasible to divert emissions for recovery at pressures below 5 psig, and urged EPA to require venting until the pressure drops below 2 psig. The comm enter recently issued a permit including the 2 psig level, and although the modification has no t been completed, the commenter believes the requirement is technically feasible.

A number of commenters objected to the fi nding that BDT is to depressure delayed coking units to the fuel gas system down to 5 psig. Commenters provided examples of coking units whose current mode of opera tions (e.g., set points or timed cycl es) may divert to a flare or the atmosphere at pressures of approximately 10 to 20 psig and that it would not be cost-effectiveB-26 to modify these units to comply with the proposed work practice standard. One commenter supported the premise that it is cost-effective for delayed coking di scharge to be routed to fuel gas blowdown, but depressurization down to 5 psig may not be feas ible with existing equipment; the commenter recommended that the work practi ce simply require a closed blow down system following procedures described in the facility’s SSM plan. At a minimum, an alternative is needed for existing units that w ould require capital expenditure to meet the 5 psig proposal. One commenter stated that compresso rs cannot recover blowdown syst em gases at pressures below the fuel gas recovery compresso r suction pressure. The minimum pressure at which a suction compressor can operate depends on the design of the coking unit and the blowdown management system. Because there is uncertainty surrounding the available emission information, the costs are not minimal in most cases, and the emissions are difficult to measure, the commenter stated
that EPA cannot determine that c ontrols on coker vents is BDT.

Response : Based on the public comments, we re-evaluated BDT for delayed coking units. We considered three options: (1 ) depressurization down to 15 psig ; (2) depressurization down to 5 psig; and (3) depressurization down to 2 psig. We assumed that the baseline is, on average, depressurization down to 15 psig and then venting to the atmos phere. Therefore, there are no impacts for Option 1. Impacts for Options 2 and 3 were estimated based on the baseline conditions, the size of typical c oke drums, and cost informati on provided in public comments. We also collected emissions test data to suppor t and verify the projecte d emissions and emission reductions. The impacts for each option for new delayed coking units are presented in Table B-16; impacts for modified and reconstructed de layed coking units are pr esented in Table B-17.

Table B-16. National Fifth Year Impacts of Options for Work Practices Considered for New Delayed Coking Units Subject to 40 CFR Part 60, Subpart Ja

Option Capital Cost ($1,000) Total Annual Cost ($1,000/yr) Emission Reduction (tons SO 2 /yr) Emission Reduction (tons VOC/yr) Cost-Effectiveness ($/ton)

Overall Incremental 1 0 0 0 0 N/A N/A 2 2,400 230 170 10 1,200 1,200 3 24,000 2,300 230 13 9,500 37,000B-27 Table B-17. National Fifth Year Impacts of Options for Work Practices Considered for Modified and Reconstructed Delayed Co king Units Subject to 40 CFR Part 60, Subpart Ja

Option Capital Cost ($1,000) Total Annual Cost ($1,000/yr) Emission Reduction (tons SO 2 /yr) Emission Reduction (tons VOC/yr) Cost-Effectiveness ($/ton)

Overall Incremental 1 0 0 0 0 N/A N/A 2 14,000 1,400 260 15 4,900 4,900 3 54,000 5,100 340 19 14,000 45,000

Based on these impacts and consideration of t echnically feasible operating practices, we confirmed our conclusion at proposal that BDT is depressurization down to 5 psig, or Option 2. For new delayed coking units, this option achieves SO 2 emission reductions of 170 tons/yr from a baseline of 520 tons/yr and VOC emission reduc tions of 10 tons/yr from a baseline of 29 tons/yr at a cost of $1,200 per ton of combined SO 2 and VOC. For modified and reconstructed delayed coking units, this option achieves SO 2 emission reductions of 260 tons/yr from a baseline of 780 tons/yr and VOC em ission reductions of 15 tons/yr from a baseline of 44 tons/yr at a cost of $4,900 per ton of combined SO 2 and VOC. Although Option 3 has been established in one refiner’s permit, this level of depressu rization has not been demo nstrated in practice. Additionally, the difference in the quantity of gas released when the set point is 2 psig rather than 5 psig is relatively small, 80 tons of SO 2 and 4 tons of VOC, and the resulting incremental costeffectiveness from Option 2 to Option 3 is about $40,000/ton, which is much greater. Therefore, Option 3, or depressurization dow n to 2 psig, is not BDT.

B.11 Summary of Results for New Sources and Modified and Reconstructed Sources
Below in Table B-18 is a summary of result s for the analyses done above for options applied to new sources. Tabl e B-19 contains a similar su mmary for the modified and
reconstructed sources.B-28Table B-18. National Incremental EmissionReductions and Cost Impacts for Options Applied to New Petroleum RefineryUnits Subject to Final Standards Under 40 CFR Part 60, Subpart Ja (Fifth Year After Proposal)ProcessUnitPollutantControlled OptionTotalCapitalCost($1,000)TotalAnnual Cost($1,000/yr)AnnualEmissionReductions(tons PM/yr)AnnualEmissionReductions(tons SO2/yr)AnnualEmissionReductions(tons NOx/yr)AnnualEmissionReductions(tonsVOC/yr)AnnualCostEffectiveness($/ton)IncrementalAnnual CostEffectiveness($/ton)FCCU PM 1 (baseline)2a3,600 1,100 235 5,600 5,6003 7,100 1,700 300 6,700 10,900SO21 (baseline)2a0 1,400 1,993 700 700NOx1 900 300 368 900 9002a1,200 600 859 700 6003 12,200 3,600 1,382 2,600 5,800Small SRP SO21 (baseline)2a100 100 42 1,500 1,5003 600 200 52 4,500 17,700Fuel gascombustiondevicesSO21 (baseline)2a1,200 800 524 1,500 1,5003 100,200 13,200 926 14,300 31,000ProcessheatersNOx1 9,000 7,300 4,841 1,500 1,5002a9,000 7,500 5,237 1,400 1,4003 110,700 30,100 5,853 5,100 36,700(continued)B-29Table B-18. National Incremental EmissionReductions and Cost Impacts for Options Applied to New Petroleum RefineryUnits Subject to Final Standards Under 40 CFR Part 60,Subpart Ja (Fifth Year After Proposal) (continued)Process UnitPollutantControlled OptionTotalCapitalCost($1,000)TotalAnnual Cost($1,000/yr)AnnualEmissionReductions(tons PM/yr)AnnualEmissionReductions(tons SO2/yr)AnnualEmissionReductions(tons NOx/yr)AnnualEmissionReductions(tonsVOC/yr)AnnualCostEffectiveness($/ton)IncrementalAnnual CostEffectiveness($/ton)Flare gasminimizationSO2,VOC 1 (baseline)2 0 23 15 0 0 1,600 1,6003a8,800−1,300 16 1 41−23,000−31,0004 15,000−840 16 1 52−12,000 43,000Delayedcoking unitsSO2,VOC 12a2,400 200 174 10 1,200 1,2003 24,000 2,300 227 13 9,500 36,900Sulfur pits SO212a700 100 30 2900 2,9003 1,300 200 31 5,600 114,000aDenotes selected option. All costs are in 2006 dollars. 83.3% of the PM emissions are PM2.5.B-30Table B-19. National Incremental EmissionReductions and Cost Impacts for OptionsApplied to Modified and ReconstructedPetroleum Refinery Units Subject to Final StandardsUnder 40 CFR part 60, subpart Ja (Fifth Year AfterProposal)ProcessUnitPollutantControlled OptionTotalCapital Cost($1,000)TotalAnnual Cost($1,000/yr)AnnualEmissionReductions(tons PM/yr)AnnualEmissionReductions(tons SO2/yr)AnnualEmissionReductions(tons NOx/yr)AnnualEmissionReductions(tonsVOC/yr)AnnualCostEffectiveness($/ton)IncrementalAnnualCostEffectiveness($/ton)FCCU PM 1 (baseline)a2 75,200 11,900 690 20,700 20,7003 101,100 15,500 808 23,000 36,500SO21 (baseline)2a0 1,600 2,400 700 700NOx 1 2,800 1,000 856 1,200 9002a3,700 1,600 1,784 900 7003 44,800 11,500 3,234 3,600 6,800FCU PM, SO21 (baseline)2a10,400 3,200 1,000 5,900 500 500NOx 1 (baseline)2 800 200 410 400 4003a3700 900 657 1,300 2,7004 6,000 1,300 745 1,700 5,000Small SRP SO21 (baseline)2a1,600 700 381 1,800 1,8003 7,800 2,600 466 5,700 23,000(continued)B-31Table B-19. National Incremental EmissionReductions and Cost Impacts for OptionsApplied to Modified and ReconstructedPetroleum Refinery Units Subject to Final StandardsUnder 40 CFR part 60, subpart Ja (Fifth Year AfterProposal) (continued)Process UnitPollutantControlled OptionTotalCapital Cost($1,000)TotalAnnual Cost($1,000/yr)AnnualEmissionReductions(tons PM/yr)AnnualEmissionReductions(tons SO2/yr)AnnualEmissionReductions(tons NOx/yr)AnnualEmissionReductions(tonsVOC/yr)AnnualCostEffectiveness($/ton)IncrementalAnnual CostEffectiveness($/ton)Fuel gascombustiondevicesSO21 (baseline)2a32,900 11,300 4,700 2,400 2,4003 1,674,000 198,100 9,100 21,700 42,300ProcessheatersNOx 1 11,700 4,000 2,075 1,900 1,9002a14,000 4,300 2,244 1,900 2,1003 64,100 14,800 2,509 5,900 39,400Flare gasminimizationSO2,VOC 1 (baseline)2 0 100 59 0 0 1,600 1,6003a35,000−5,300 64 4 165−23,000−31,0004 59,000−3,300 66 6 207−12,000 43,000Delayedcoking unitsSO2,VOC 12a14,400 1,400 261 15 4,900 4,9003 54,000 5,100 340 19 14,200 45,100Sulfur pits SO212a7,700 900 269 3,500 3,5003 15,300 1,900 275 6,800 138,800aDenotes selected option. All costs are in 2006 dollars. 83.3% of the PM emissions are PM2.5.5-1 SECTION 5
ECONOMIC IMPACT ANALYSIS: METHODS AND RESULTS

The EIA is designed to inform decisi on makers about the potential economic consequences of a regulatory acti on. The analysis consists of es timating the social costs of a regulatory program and the distribution of th ese costs across stakeholders (consumers and producers). As defined in EPA’s (2000) Guidelines for Preparing Economic Analyses, 1 social costs are the value of the goods and services lo st by society resulting from using resources to comply with and implement a regulation and reductions in output.

5.1 Market Model
EPA constructed partial equilibrium models of the national markets for five major petroleum products (motor gasoline, jet fuel, distillate fuel oil, residual fuel oil, and liquefied petroleum gases). 2 These models were used to measur e the economic cons equences of the regulatory program in the intermediate run (when some factors of production are fixed and others are variable). 3 Partial equilibrium models track the effect s of regulatory action in a single market, while ignoring interactions with other markets.

Each of the 5 intermediate-run market mode ls uses a common analytic expression to
estimate how an increase in th e per-unit (per-gallon) costs of producing a product will impact that product’s price (Berck and Hoffmann, 2002; Fullerton and Metcalfe, 2002). This expression is presented in Equation 5.1. A full description fo r how it is derived and used is provided in Appendix C.

Δ price = Supply Elasticity Supply Elasticity – Demand Elasticity × Per-Gallon Cost (5.1)

This approach follows EPA guidelines fo r analyzing the economic impacts of a regulatory program (EPA, 1999; EPA, 2000).

5.2 Model Baseline
Standard EIA practice compares and contrasts the state of a market with and without a regulatory policy. EPA selected 2012, the fifth year after proposal, as the baseline year for the analysis. Forecasts for the pr ice and consumption of each petroleum product in 2012 were

1 These guidelines are unde r review by the Agency.
2 National market models were selected in order to be consistent with the national-level cost estimates provided by the engineering cost analysis.
3 For a complete discussion of how the intermediate run is defined, please see the OAQPS Economic Analysis Resource Document (EPA, 1999).5-2 collected from the Energy Information Admini stration’s Annual Energy Outlook and reported in Chapter 3 (Tables 3-19 and 3-20). However, these da ta had to be standardized for use in EPA’s
models.

First, the 2007 Annual Energy Outlook reports th e price of petroleum products in terms of 2005 dollars. However, compliance costs were es timated in terms of 2006 dollars. Therefore, to ensure that common units were being used, petroleum product prices were converted to 2006 dollars by dividing the forecasted price in 2012 by the ratio of the Consum er Price Indices (CPI)
in 2006 and 2005.

Second, the 2007 Annual Energy Outlook reports the quantity of petroleum products consumed in terms of barrels, while the price of petroleum products is reported in terms of dollars per gallon. Therefore, to ensure that common units were being used, the number of barrels produced each year was divided by 42 (the number of gallons in a barrel). A summary of
the baseline data used in each of the five market models after these adjustments were made is reported in Table 5-1.

Table 5-1. Baseline Market Data: 2012

Market Motor Gasoline Jet Fuel Distillate Fuel Oil Residual Fuel Oil Liquefied Petroleum

Gases Price ($2006/per gallon) $2.11 $1.40 $2.04 $1.06 $1.55 Quantity (billion gallons/per year) 149.67 31.04 71.83 12.36 34.10

Sources: 2012 Petroleum product price and consumption forecasts: U.S. Depart ment of Energy, Energy Information Administration (EIA). 2007. “Annual Energy Outlook.” Available at <http://www.eia.doe.gov/oiaf/archive/ aeo07/pdf/0383(2007).pdf>. As obtained on January 21, 2007.

2005 and 2006 Consumer Price Indices: U.S. Department of Energy, Energy Information Administration (EIA). 2008. “Short-Term Energy Outlo ok: Real Petroleum Prices.” Available at <http://www.eia.doe.gov/emeu/ steo/pub/fsheets/real_prices.html>. As obtained on April 21, 2008.

5.3 Model Parameters
An essential component of partial equilib rium models are supply and demand price elasticities. These elasticities measure the resp onsiveness of producers and consumers to prices changes and determine how the social costs of a regulatory program are distributed between the two groups of stakeholders. Economic theory sugge sts consumers will bear a higher share of the economic welfare losses if the supply of a petrol eum product is more responsive to price changes than is the demand for that product. A summ ary of the estimates of demand and supply elasticities used in this analys is is provided in Table 5-2.5-3 Table 5-2. Estimates of Price El asticity of Demand and Supply

Market Motor Gasoline Jet Fuel Distillate Fuel Oil Residual Fuel Oil Liquefied Petroleum

Gases Demand elasticity

− 0.69

− 0.15

− 0.75

− 0.68

− 0.8 Supply elasticity 1.24 1.24 1.24 1.24 1.24

Sources: U.S. Environmenta l Protection Agency. 1995. Economic Impact Analysis for Petroleum Refineries

NESHAP. EPA-452/R-95-003, Final Report. Washington DC: Government Printing Office.

5.4 Results
Chapter 4 reports that the estimated change in total annualized costs resulting from the regulatory program is approximately $31 million (measured in 2006 dollars). According to the 2007 Annual Energy Outlook, the forecasted consump tion of all petroleum products in 2012 is
8.08 billion barrels or 339.25 bill ion gallons. Assuming that the production processes of all petroleum products are equally affected, this re gulatory program is e xpected to result in a $0.000091 per-gallon increase in the cost of pr oducing petroleum products ($31 million / 339.25 billion gallons).

Based on EPA’s partial equilibrium analysis , the costs induced by this regulatory program do not have a significant impact on market-lev el prices or quantities. The results of this analysis are summarized in Table 5-3. As this table shows, prices for each of the 5 products rise by less than 1 penny (0.003%–0.006%) and the quantity of each petroleum product produced declines. Motor gasoline and distillate fuel face the largest absolute quantity reductions (2.8 and 1.4 million gallons, respectively, or 0.002%), while re sidual fuel oil sees the largest proportional decline in production (0.004%).

As a result of higher prices, consumers of petroleum products see a decline in surplus. For example, consumers of motor gasoline lose $8.78 million of surplus. In addition, producers also receive a smaller surplus as a result of higher production costs. In the case of motor gasoline, producers lose $4.89 million. Total surp lus losses for consumers and producers of motor gasoline are estimated to be $13.67 million. The total annualized loss in surplus for all 5 markets analyzed, which is an estimate of the social cost of this NSPS, is $27.30 million or slightly less than the total annualized compliance cost in these markets.5-4Table 5-3. Summary of Intermediate Run Economic Impacts by Petroleum Product: 2012Motor Gasoline Jet Fuel Distillate Fuel Oil Residual Fuel OilLiquefied PetroleumGasesChange in price 0.003% 0.006% 0.003% 0.006% 0.004%Less than a penny pergallonLess than a penny pergallonLess than a penny pergallonLess than a penny pergallonLess than a penny pergallonChange in quantity−0.002%−0.001%−0.002%−0.004%−0.003%(−2.8 million gallons peryear)(−0.2 million gallons peryear)(−1.4 million gallons peryear)(−0.4 million gallons peryear)(−0.9 million gallons peryear)Welfare Impacts($million)Welfare Impacts($million)Welfare Impacts($million)Welfare Impacts($million)Welfare Impacts($million)Change in consumer surplus−$8.78−$2.53−$4.10−$0.73−$1.89Change in producer surplus−$4.89−$0.31−$2.46−$0.40−$1.22Change in total surplus−$13.67−$2.83−$6.56−$1.13−$3.115-5 In addition to the loss in surplus for consum ers and producers of these 5 major petroleum products, an additional $3.7 million in costs will affect markets fo r petroleum products that were not explicitly modeled in this analysis. These in clude markets for asphalt, lubricants, road oil, petroleum coke and others.

5.5 Executive Order 13211 (Energy Effects)
This rule is not a “significant energy action” as defined in Executive Order 13211, “Actions Concerning Regulations That Significantly Affect En ergy Supply, Distribution, or Use” (66 FR 28355 [May 22, 2001]) because it is not likely to have a significant adverse effect on the supply, distribution, or use of ener gy. We prepared an analysis of the impacts on energy markets as part of our economic impact analysis for t oday’s action. Our analysis shows that there is a reduction in output of the five petroleum products included in th is analysis of between 0.2 and 2.8 million gallons, or a decrease in output of less than 0.01%, in the fifth year after proposal of this action. In addition, our analysis shows that pr ices increase less than 0.001% in the fifth year after proposal of this action for all petroleum pr oducts analyzed. Given such a small increase in domestic prices, no significant increase in our dependence on foreign energy supplies should take place. Finally, today’s action will have no adverse effect on crude oil supply, coal production, electricity production, and energy distribution. Base d on the findings from the analysis of impacts on energy markets, we concl ude that today’s action is not a “significant energy action” as defined in Executive Order 13211. For more information on this analysis, please refer to the economic impact analys is shown earlier in this chapter.

5.6 Limitations

The results of economic should be viewed w ith the following limitations in mind. First, the models used are based on the assumption of a national competitive market, which may influence the findings because the markets for petroleum products such as motor gasoline are regional. Regional price and qua ntity impacts could be differe nt from the average impacts reported in this analysis if local market stru ctures, production costs, or demand conditions are substantially different from those used in this analysis. Second, the models use a market supply function and analyze supply behavior at or ne ar a single market baseline equilibrium using a supply elasticity parameter. Therefore, they do not address facility-level impacts such as closures or changes in employment. Alt hough developing a facili ty-level model could potentially provide these outputs, this type of model requires su bstantial amounts of detailed data for individual
facilities and a level of effort beyond the scope of this analysis. As a result, EPA conducted a cost-to-sales ratio analysis to assess impacts on firms, specifically small firms (see Section 6).5-6 5.7 References Berck, P., and S. Hoffmann. 2002. “Assessing the Employment Impacts.” Environmental and Resource Economics 22:133–156.

Fullerton, D., and G. Metcalf. 2002. “Tax Inciden ce.” In A. Auerbach and M. Feldstein, eds., Handbook of Public Economics , Vol. 4. Amsterdam: Elsevier.

U.S. Department of Energy, Energy Informa tion Administration (EIA). 2007. “Annual Energy Outlook.” Available at <http://www.eia.doe .gov/oiaf/archive/ae o07/pdf/0383(2007).pdf>. As obtained on January 21, 2007.

U.S. Department of Energy, Energy Informa tion Administration (EIA). 2008. “Short-Term Energy Outlook: Real Petroleum Prices.” Available at <http://www.eia.doe.gov/emeu/ steo/pub/fsheets/real_prices.html >. As obtained on April 21, 2008.

U.S. Environmental Protection Agency (EPA). 1995. Economic Impact Analysis for Petroleum Refineries NESHAP. EPA-452/R-95-003, Final Report. Washington DC: Government Printing Office.

U.S. Environmental Protection Agency (EPA). 1999. OAQPS Economic Analysis Resource Document . Research Triangle Park, NC: EPA. Available at <http://www.epa.gov/ttn/ecas/ econdata/6807-305.pdf>.

U.S. Environmental Protection Agency (EPA). September 2000. Guidelines for Preparing Economic Analyses . EPA 240-R-00-003. Washington, DC: EPA. Available at <http://yosemite.epa.gov/ee/epa/eed.nsf/webpages/Guidelines.html>.6-1 SECTION 6
SMALL BUSINESS ANALYSIS

The Regulatory Flexibility Act (RFA) gene rally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a signifi cant economic impact on a substantial number of
small entities. 1 This section begins by describing the da ta and methods used for performing this small business analysis and end by repor ting the results of the analysis.

6.1 Data and Methods for Flexibility Analysis
The impact of the rule on small businesses is assessed using the ratio of compliance costs
to the annual revenue of the ul timate parent company. This is know n as the cost-to-sales ratio or CSR and it can be computed using the following equation:

j n

i TR

TACC CSR 

# ∑

= (6.1)

where

TACC = total annual compliance costs,
i = indexes the number of affect ed plants owned by company j, n = number of affected plants, and TRj = total annual revenue of a representative ultimate parent company j in each industry

If the CSR is less than 1%, then the regulat ory program is considered to not have a significant impact on the parent company in ques tion. This approach assumes affected firms absorb the control costs, rather than pass them onto consumers in the form of higher prices.

In Chapter 3, 25 small companies owning pe troleum refineries classified as small according. As previously discussed, small busine sses in the petroleum refining industry (NAICS code 324100) are defined for the purposes of this rule as having 1,500 or fewer employees. 2

1 Small entities include small businesses, small organizations, and small governmental jurisdictions.
2 Refer to http://www.sba.gov/idc/groups/public/docum ents/sba_homepage/serv_sstd_tablepdf.pdf for more information on SBA small bu siness size standards.6-2 Table 6-1 duplicates sales employment data for these 25 small companies originally reported in Chapter 3.

Table 6-1. Characteristics of Small Busine sses in the Petroleum Refining Industry

Facility Name Refineries (#) Parent Company Sales

($Millions) Parent Company Employment (#) AGE Refining & Manufacturing 1 287 52 American Refining Group 1 350 310 Arabian American Development Co 1 80 118 Calcasieu Refining Co. 1 638 51 Calumet Specialty Products 3 1,641 350 Countrymark Cooperative, Inc. 1 87 300 Cross Oil & Refining Co. Inc. 1 49 110 CVR Energy Inc. 1 3,038 577 Foreland Refining Co. 1 56 100 Frontier Oil Corp 2 4,000 727 Gary-Williams Co 1 97 200 Goodway Refining LLC 1 3 18 Greka Integrated Inc 1 22 145 Gulf Atlantic Operations LLC 1 9 32 Holly Corp. 2 4,023 859 Hunt Refining Co. 3 4,871 1,100 Lion Oil Co. 1 247 425 Pelican Refining Co. LLC 1 29 62 Placid Refining Inc. 1 1,400 200 San Joaquin Refining Co., Inc. 1 288 20 Somerset Oil Inc 1 55 150 Trigeant Ltd. 1 5 50 Western Refining, Inc. 4 4,200 416 World Oil Corp 1 277.3 475 Wyoming Refining Co. 1 340 107
We note here, that we inadvertently used a different small business size standard for small refiners in the proposed

NSPS. The small business analysis for the final rulema king incorporates the correct SBA small business size standard of 1,500 employees per ultimate parent refiner. Th e effect of this correction on the affected small refiner universe is an increase of one small firm. There is no effect on our determination of no significant economic impact on a substantial number of small entities (to be shown later) as a result of this correction.
6.2 Results of Small Business Analysis
As described in Chapter 4, the EPA estimates that small businesses will invest in two new or modified process units during the five-year period of analysis. Investing in thes e process units would require the small businesses to incur an average $1.5 million per facility in annualized compliance cost and earn an average $0.6 million per facility in cost savings as a result of the final NSPS—a net total annualized complia nce cost of $910 thousand per facility.6-3 Literature on the petroleum refining industry was examined to identify and characterize small firms likely to be affected by the rule, The Oil & Gas Journal’s 2008 Worldwide Construction Update survey catalogued over 40 refining construction proj ects that have been announced in the United States. Among the co mpanies announcing construction projects, 3 three were identified by EPA as small businesses—Fron tier Oil Corp, Holly Corp, and Placid Refining
Inc. EPA therefore estimates that three small busi nesses will invest in ne w or modified process units during the five-year period of analysis.

As indicated in Table 6-1, each of these companies earned over $1 billion in revenue in the base year for this analysis (2006). Assuming that these three small businesses (out of 25 total small businesses identified by EPA) are representative of the small businesses that will invest in new or modified process units over the five year period of analysis, their cost to sales ratios would be less than 1%. As a result, the final N SPS is not expected to have a significant impact on small companies.

After considering the economic impact of t oday’s action on small entities, I certify that this action will not have a significant economic im pact on a substantial number of small entities. Of the affected entities, none ar e estimated to incur annualized comp liance cost over 1% of sales.

Although this proposed action would not ha ve a significant economic impact on any small entities, EPA nonetheless ha s tried to reduce the impact of this action on small entities by incorporating specific standards for small sulfur recovery plants and streamlining procedures for exempting inherently low-sulfur fuel gases fr om continuous monitoring. In addition, EPA has updated this small business analysis to incorporate capacity data for small refiners provided in a comment by the Ad Hoc Coalition of Small Business Refiners.

3 Construction projects included in the Oil & Gas Journal’s analysis include new, expanded, and upgraded
processes.7-1 SECTION 7
HUMAN HEALTH BENEFITS OF EMISSIONS REDUCTIONS

7.1 Calculation of Human Health Benefits

In order to estimate the human health benef its of reducing emissions from refineries through this final rulemaking, EPA used the benefits transfer a pproach and methodology described in EPA’s benefits analysis the Technical Support Document (TSD) 1 accompanying the recent National Ambient Air Qualit y Standards (NAAQS) for Ozone. 2 In that RIA, EPA applied a benefits transfer approach to estimate the PM 2.5 co-benefits resulting from reductions in
emissions of NO x ; EPA is adapting that method to estimate the health benefits for the projected
emission reductions of PM 2.5 precursor pollutants associated with this final rulemaking.

EPA did not perform an air quality mode ling assessment of the emission reductions resulting from installing controls on these refineri es because of the time and resource constraints and the limited value of such an analysis for th e purposes of developing the regulatory approach for this final rule. This lack of air quality modeling limited EPA’s ability to perform a comprehensive benefits analysis for this final ru lemaking since our benefits model requires either air quality modeling or monitoring data.

To estimate the human health benefits of emissi on reductions from refineries for this analysis in the absence of modeling data, we used the studies from the PM NAAQS Regulatory Impact Analysis (RIA) 3 to generate benefit-per-ton values. These PM 2.5 precursor pollutant benefit perton estimates provide the total monetized human health benefits (the sum of premature mortality and premature morbidity) of reducing one ton of PM 2.5 and PM 2.5 precursor emissions from a specified source. These benefits estimates have been updated in the final NSPS to utilize the mortality valuation estimates obt ained in the expert elicitation study, as mentioned in the proposal. In addition, we also include VOC benefit-per-ton estimates. 4 EPA has used a similar technique in previous RIAs, beginning with the PM NAAQS RIA (U.S. EPA, 2006). EPA has requested the SAB to review the presentation of benefits estimates based on the mortality

1 U.S. EPA, 2008 a. T echnical Support Document: Calculating Benefit Per-Ton estimates, Ozone NAAQS Docket #EPA-HQ-OAR-2007-0225-0284.
2 U.S. EPA, 2008 b.

. Regulatory Impact Analysis, 2008 National Ambient Air Qua lity Standards fo r Ground-level Ozone , Chapter 6. Available on the Internet at http://www.e pa.gov/ttn/ecas/regdata/RIAs/6-ozoneriachapter6.pdf.
3 U.S. EPA, 2006. Regulatory Impact Analysis, 2006 National Am bient Air Quality Standards for Particulate Matter , Chapter 5. Available on the Internet at h ttp://www.epa.gov/ttn/ecas/regdata/RIAs/Chapter%205-- Benefits.pdf.
4 In this analysis, the monetized benefits of reducing VOCs only reflect their effects as a PM 2.5 precursor pollutant. In this analysis, we are not quantifyi ng any ozone-related health benefits.7-2 valuation estimates obtained in the expert elic itation study in the cont ext of an RIA. The 14 estimates presented below derive from the application of three alternative methods:

 One estimate is based on the concentrati on-response (C-R) function developed from the study of the American Cancer Societ y (ACS) cohort reported in Pope et al. (2002), which has previously been reported as the primary estimate in recent RIAs

 One estimate is based on Laden et al.’s (2006) reporting of the extended Six Cities cohort study; this study is a more recent PM epidemiological study that was used as an alternative in the PM NAAQS RIA.

 The other 12 estimates are based on the re sults of EPA’s expe rt elicitation study on the PM-mortality relationship, as first reported by Industrial Economics (2006) and interpreted for benefits analysis in EPA's final RIA for the PM NAAQS, published in September 2006 (EPA, 2006). For that study, 12 experts (label ed A through L) provided independent estimates of the PM-m ortality C-R function. EPA practice has been to develop independent estimates of PM-mortality estimates corresponding to the concentration-response function provided by each of the 12 experts.
EPA believes that these updated estimates will better characteri ze the uncertainty associated with using the benefit- per-ton approach to derive an estimate of total benefits. Readers interested in the complete methodology for creati ng the benefit-per-ton estimates used in this analysis may consult the Technical Support Document accompanying th e final Ozone NAAQS RIA (EPA, 2008).

To develop the estimate of the benefits of reducing emissions from this rulemaking, we
calculated the monetized benef its-per-ton of emissions reduc tion estimates for direct PM 2.5 and
each PM 2.5 precursor pollutant. 5 In the TSD, we describe in de tail how we generated the benefitper-ton estimates. In summary, we used a m odel to convert emissions of direct PM 2.5 and PM 2.5 precursors (i.e., SO 2 , NO x , and VOCs) into changes in PM 2.5 air quality. Next, we used the benefits model to estimate the changes in human health based on the change in PM 2.5 air quality. Finally, the monetized health benefits were divided by the emission re ductions to create the benefit per ton estimates. Even t hough all fine particles are assume d to have equivalent health effects, the benefit-per- ton estimates vary because each ton of precursor reduced has a different propensity to become PM 2.5 . For example, NO x has a lower benefit-per- ton estimate than direct
PM 2.5 because it does not form as much PM 2.5 , thus the exposure would be lower, and the
monetized health benefits would be lower.

5 Emission reductions shown in the tables below are in terms of total PM, but it is estimated that 83.3% of the PM emissions are in the PM 2.5 fraction. For the purposes of this benefits analysis, all of the PM benefits shown in the following tables are the PM 2.5 fraction. Therefore, we do not provide any benefits estimates for the reductions of PM other than PM 2.5 (e.g., PM 10 ) that will take place as a result of this final NSPS.7-3 After generating the benefit-per-ton estimate, we then multiply this estimate by the number of tons of each pollutant reduced to deri ve an overall monetary value of benefits. We show a range of benefits estimat es per pollutant (and option) rath er than a single point estimate in order to reflect the range of estimates obtained in the expert elicitation study. 6 Table 7-1 provides a general summary of the results by pollu tant for the selected options, including the emissions reductions and monetized benefits-p er-ton range. Figure 7-1 provides a visual representation of the full range of benefits estimates by pollutant at a discount rate of 3%. Tables 7-2 and 7-3 summarize the range of benefits of the selected options at discount rates of 3% and 7%, respectively. Tables 7-4 and 7-5 provide the range of benefits for all options discounted at
3% and 7% for new and modified/r econstructed units, respectively. All benefits estimates are for the fifth year after proposal (2012). More details on the options, emissions, and emission reductions can be found in Chapter 4 of this RIA.

Table 7-1. General Summary of Range of Benefi ts Estimates for Selected Options in the Final NSPS a

Pollutant Emissions Reductions (tons) Benefit per Ton

(low, 3%) Benefit per Ton

(high, 3%) Benefit per Ton

(low, 7%) Benefit per Ton

(high, 7%) Total Monetized Benefits (millions

2006$ at 3%) Total Monetized Benefits (millions

2006$ at 7%) Direct PM 2.5 1,054 $68,000 $570,000 $63,000 $520,000 $72 to $600 $66 to $540 PM 2.5 Precursor

SO 2 16,714 $8,000 $68,000 $7,400 $62,000 $130 to $1,100 $120 to $1,000 NO x 10,786 $1,300 $11,000 $1,200 $9,600 $14 to $110 $13 to $100 VOC 230 $210 $1,700 $190 $1,500 $.05 to $.38 $.04 to $.35 Total $220 to $1,900 $200 to $1,700

a All estimates are for the analys is year (fifth year after proposal, 2012), and are rounded to two significant figures so

numbers may not sum across columns. Emission reductions reflect the combination of selected options for both new and reconstructed/modified sources. All benefits estimates are shown at both 3% and 7% discount rate. The PM 2.5 fraction of total PM emissions is estimated at 83.3%, and only the reduction in the PM 2.5 fraction is monetized in this analysis. All fine particles are assumed to have equivalent health effects, but the benefit per ton estimates vary because each ton of precursor re duced has a different propensity to become PM 2.5 . The monetized benefits incorporate the conversion from precursor emissions to ambient fine particles.

6 In the Expert Elicitation, Expert K represented the lowest estimate, and Expert E represented the highest estimate. Therefore, the total range of bene fits is presented as the range from Expert K to Expert E.7-4 Po

p e Laden Exper t A

E xper t B

E x p e rt

C

Expert D

E xper t E Expert F

E x p e rt

G Exp e rt

H Ex p e r t I Ex p e rt

J Expert K

E xpert L $

‐ $200 $400 $600 $800 $1,000 $1,200Millionsof2006$

Epidemiology or Expert Derived PM 2.5 Mortality Function

VOC NOX Direct PM2.5 SO2

Figure 7-1. Monetized Benefits for Selected Options for Final Petroleum Refineries NSPS at 3% Discount Rate by PM 2.5 Precursor Emitted in 2012 a

a This graph shows 14 PM benefits estimates, which are treated as independent and equally probable, for each

precursor pollutant. All fine particles are assumed to have equivalent health effects, but the benefit-per-ton estimates vary because each ton of precursor re duced has a different propensity to become PM 2.5 . The monetized benefits incorporate the conversion from precursor emissions to ambient fine particles.

It is important to note that the monetized benefit-per-ton estimates used here reflect specific geographic patterns of emissions redu ctions and specific air quality and benefits modeling assumptions. Use of these $/ton values to estimate benefits associated with different emission control programs (e.g., for reducing emissi ons from large stationary sources like EGUs) may lead to higher or lower benef it estimates than if benefits were calculated based on direct air quality modeling. Great care should be taken in applying these estimates to emission reductions occurring in any specific location, as these ar e all based on national or broad regional emission reduction programs and therefore represent average benefits-p er-ton over the entire United States. The benefits-per-ton for em ission reductions in specific lo cations may be very different than the national average.7-5 Table 7-2. Summary of Monetized Benefits for Selected Options at 3% Discount Rate in 2012 (millions of 2006$)

Process Unit (new) Selected Option a Pollutant b Emissions Reduction

(tons) Total Benefit (millions) c FCCU 2 PM 235 $13

− $110
2 SO 2 1,993 $16

− $140
2 NO x 859 $1.1

− $9.1
Small SRP 2 SO 2 42 $.34

− $2.9 Fuel gas combustion 2 SO 2 524 $4.2

− $36 Flaring gas minimization 3 SO 2 24 $.20

− $1.7
3 NO x 9 $.01

− $.09 3 VOC 277 $.06

− $.46 Delayed cokers 2 SO 2 174 $1.4

− $12 2 VOC 10 $.00

− $.02
Process heater 2 NO x 5,237 $6.9

− $56 Sulfur pits 2 SO 2 30 $.24

− $2.0
Total $43

− $370
Process Unit (modified/reconstructed) FCCU 1 PM 0 $.00

− $.00
2 SO 2 2,350 $19

− $160
2 NO x 1,784 $2.3

− $19 Fluid coker 2 PM 1,030 $47

− $400
2 SO 2 5,893 $59

− $490
Fluid coker 3 NO x 657 $.86

− $7.0
SRP 2 SO 2 381 $3.1

− $26 Fuel gas combustion 2 SO 2 4,717 $38

− $320
Process heaters 2 NO x 2,244 $3.0

− $24 Flaring gas minimization 3 SO 2 97 $.78

− $6.6
3 NO x 35 $.05

− $.37 3 VOC 1,108 $.23

− $1.8 Delayed cokers 2 SO 2 261 $2.1

− $18 2 VOC 15 $.00

− $.02 Sulfur pits 2 SO 2 269 $2.2

− $18
Total $180

− $1,500

a Refer to Chapter 4 of this RIA for more details on options.

b The PM 2.5 fraction is estimated at 83.3% of the total PM emissions, and only reductions in the PM 2.5 fraction is

monetized in this analysis. All fine particles are assumed to have equivalent health effects, but the benefit-per-ton estimates vary because each ton of precursor re duced has a different propensity to become PM 2.5 . The monetized benefits incorporate the conversion from precursor emissions to ambient fine particles.

c All estimates rounded to two significan t figures and may not sum across columns.7-6 Table 7-3. Summary of Monetized Benefits for Selected Options at 7% Discount Rate in 2012 (millions of 2006$)

Process Unit (new) Selected Option a Pollutant b Emissions Reduction

(tons) Total Benefit (millions) c FCCU 2 PM 235 $12

− $100 2 SO 2 1,993 $15

− $120 2 NO x 859 $1.0

− $8.2 Small SRP 2 SO 2 42 $.31

− $2.6 Fuel gas combustion 2 SO 2 524 $3.9

− $32 Flaring gas minimization 3 SO 2 16 $.12

− $1.0 3 NO x 1 $.00

− $.01 3 VOC 41 $.01

− $.06 Delayed cokers 2 SO 2 174 $1.3

− $11 2 VOC 10 $.00

− $.02 Process heater 2 NO x 5,237 $6.3

− $50 Sulfur pits 2 SO 2 30 $.22

− $1.8 Total $40

− $320 Process Unit (modified/reconstructed) FCCU 1 PM 0 $.00

− $.00 2 SO 2 2,350 $17

− $140 2 NO x 1,784 $2.2

− $17 Fluid coker 2 PM 1,030 $43

− $360 2 SO 2 5,893 $54

− $440 Fluid coker 3 NO x 657 $.79

− $6.3 SRP 2 SO 2 381 $2.8

− $23 Fuel gas combustion 2 SO 2 4,717 $35

− $290 Process heaters 2 NO x 2,244 $2.7

− $21 Flaring gas minimization 3 SO 2 64 $.47

− $3.9 3 NO x 4 $.01

− $.04 3 VOC 165 $.03

− $.3 Delayed cokers 2 SO 2 261 $1.9

− $16 2 VOC 15 $.00

− $.02 Sulfur pits 2 SO 2 269 $2.0

− $17 Total $160

− $1,300

a Refer to Chapter 4 of this RIA for more details on options.

b The PM 2.5 fraction is estimated at 83.3% of the total PM emissions, and only reductions in the PM 2.5 fraction is

monetized in this analysis. All fine particles are assumed to have equivalent health effects, but the benefit-per-ton estimates vary because each ton of precursor re duced has a different propensity to become PM 2.5 . The monetized benefits incorporate the conversion from precursor emissions to ambient fine particles.

c All estimates rounded to two significan t figures and may not sum across columns.7-7Table 7-4. Estimated Range of Monetized Benefits in 2012 for All Options ofNew Process Units (thousands of 2006$)aProcess Unit PollutantBOptionTotal BenefitsLow 3%($1,000/yr)Total BenefitsHigh 3%($1,000/yr)Total BenefitsLow 7%($1,000/yr)Total BenefitsHigh 7%($1,000/yr)FCCU PM 1 Baseline (1.0 lb/klb coke burn (M5B or 5F)) $— $— $— $—2 0.5 lb/klb coke burn (M5B or 5F)C$13,000 $110,000 $12,000 $100,0003 0.5 lb/klb coke burn (M5) $17,000 $140,000 $16,000 $130,000FCCU SO21 Baseline $— $— $— $—2 25 ppmvC$16,000 $140,000 $15,000 $120,000FCCU NOX1 150 ppmv $480 $3,900 $450 $3,5002 80 ppmvC$1,100 $9,100 $1,000 $8,2003 20 ppmv $1,800 $15,000 $1,700 $13,000Small SRP SO21 Baseline $— $— $— $—2 Less than 20 ltpd @ 99%C$340 $2,900 $310 $2,6003 All at 250 ppmv $420 $3,500 $380 $3,200Fuel gascombustionSO21 Baseline $— $— $— $—2 long term limit of 60 ppmv H2SC$4,200 $36,000 $3,900 $32,0003 TRS limits of 160/60 ppm $7,400 $63,000 $6,800 $57,000Process heaters NOX1 80 ppmv >20 MMBtu/hr $6,400 $51,000 $5,900 $46,0002 40 ppmv >40 MMBt/hrC$6,900 $56,000 $6,300 $50,0003 20 ppmv, 40 MMBtu/hr $7,700 $62,000 $7,100 $56,000Flare gasminimizationSO2/VOC 1 Baseline (no standard) $— $— $— $—2 RCA >500 lb/day SO2 $120 $1,000 $110 $9103 Option 2 + Flare minimization planC$140 $1,200 $130 $1,1004 Option 2 + No routine flaring $140 $1,200 $130 $1,100Delayed cokers SO2/VOC 1 Depressure to control to 15 psig $— $— $— $—2 Depressure to control to 5 psigC$1,400 $12,000 $1,300 $11,0003 Depressure to control to 2 psig $1,800 $15,000 $1,700 $14,000(continued)7-8Table 7-4. Estimated Range of Monetized Benefits in 2012 for All Options ofNew Process Units (thousands of 2006$)a(continued)Process Unit PollutantBOptionTotal BenefitsLow 3%($1,000/yr)Total BenefitsHigh 3%($1,000/yr)Total BenefitsLow 7%($1,000/yr)Total BenefitsHigh 7%($1,000/yr)Sulfur pits SO21 Do not include sulfur pits $— $— $— $—2 Include primary sulfur pitsC$240 $2,000 $220 $1,8003 Include primary pits and secondary tanks $250 $2,100 $230 $1,900aAll estimates rounded to two significant figures.bThe PM2.5fraction is estimated at 83.3% of the total PM emissions, and only the reduction in the PM2.5fraction is monetized in this analysis. All fine particlesare assumed to have equivalent health effects, but the benefitper ton estimates vary because each ton of precursor reduced hasa different propensity to becomePM2.5. The monetized benefits incorporate the conversion from precursor emissions to ambient fine particles.cThis is the selected option.7-9Table 7-5. Estimated Range of Monetized Benefits in 2012 for All Options ofModified/Reconstructed Process Units(thousands of 2006$)aProcess UnitPollutantbOptionTotal BenefitsLow 3%($1,000/yr)Total BenefitsHigh 3%($1,000/yr)Total BenefitsLow 7%($1,000/yr)Total BenefitsHigh 7%($1,000/yr)FCCU PM 1 Baseline (1.0 lb/klb coke burn (M5B or 5F))c$— $— $— $—2 0.5 lb/klb coke burn (M5B or 5F) $39,000 $330,000 $36,000 $300,0003 0.5 lb/klb coke burn (M5) $46,000 $380,000 $42,000 $350,000FCCU SO21 Baseline $— $— $— $—2 25 ppmvc$19,000 $160,000 $17,000 $140,000FCCU NOx1 150 ppmv $1,100 $9,100 $1,000 $8,2002 80 ppmvc$2,300 $19,000 $2,200 $17,0003 20 ppmv $4,300 $34,000 $3,900 $31,000Fluid coker PM/SO21 Baseline $— $— $— $—2 1.0 lb/klb coke burn (M5B or 5F)/25 ppmvc$110,000 $890,000 $97,000 $810,000Fluid coker NOx1 Baseline $— $— $— $—2 80 ppmvc$540 $4,300 $500 $3,9003 20 ppmv $980 $7,900 $900 $7,100Small SRP SO21 Baseline $— $— $— $—2 Less than 20 ltpd @ 99%c$3,100 $26,000 $2,800 $23,0003 All at 250 ppmv $3,700 $32,000 $3,400 $29,000Fuel gascombustionSO21 Baseline $— $— $— $—2 long term limit of 60 ppmv H2Sc$38,000 $320,000 $35,000 $290,0003 TRS limits of 160/60 ppm $73,000 $620,000 $67,000 $560,000Process heaters NOx1 80 ppmv >20 MMBtu/hr $2,700 $22,000 $2,500 $20,0002 40 ppmv >40 MMBt/hrc$3,000 $24,000 $2,700 $21,0003 20 ppmv, 40 MMBtu/hr $3,300 $27,000 $3,000 $24,000Flare gasminimizationSO2/VOC 1 Baseline (no standard) $— $— $— $—2 RCA >500 lb/day SO2$470 $4,000 $430 $3,6003 Option 2 + Flare minimizationc$550 $4,700 $510 $4,2004 Option 2 + No routine flaring $580 $4,900 $530 $4,400(continued)7-10Table 7-5. Estimated Range of MonetizedBenefits in 2012 for All Options ofModified/Reconstructed Process Units(thousands of 2006$)a(continued)Process UnitPollutantbOptionTotal BenefitsLow 3%($1,000/yr)Total BenefitsHigh 3%($1,000/yr)Total BenefitsLow 7%($1,000/yr)Total BenefitsHigh 7%($1,000/yr)Delayed cokers SO2/VOC 1 Depressure to control to 15 psig $— $— $— $—2 Depressure to control to 5 psigc$2,100 $18,000 $1,900 $16,0003 Depressure to control to 2 psig $2,700 $23,000 $2,500 $21,000Sulfur pits SO21 Do not include sulfur pits $— $— $— $—2 Include primary sulfur pitsc$2,200 $18,000 $2,000 $17,0003 Include primary pits and secondary tanks $2,200 $19,000 $2,000 $17,000aAll estimates rounded to two significant figures.bThe PM2.5fraction is estimated at 83.3% of the total PM emissions, and only the reduction in the PM2.5fraction is monetized in this analysis. All fine particlesare assumed to have equivalent health effects, but the benefitper ton estimates vary because each ton of precursor reduced hasa different propensity to becomePM2.5. The monetized benefits incorporate the conversion from precursor emissions to ambient fine particles.cThis is the selected option.7-11 7.2 Characterization of Uncertainty in the Benefits Estimates
In any complex analysis, there are likely to be many sources of uncertainty. Many inputs
are used to derive the final estimate of econo mic benefits, including emission inventories, air quality models (with their associated paramete rs and inputs), epidemio logical estimates of concentration-response (C-R) f unctions, estimates of values , population estimates, income estimates, and estimates of the future state of the world (i.e., regulati ons, technology, and human behavior). For some parameters or inputs it may be possible to provide a st atistical representation of the underlying uncertainty distribution. For other parameters or inputs, the necessary
information is not available.

The annual benefit estimates presen ted in this analysis are also inherently variable due to the processes that govern pollutant emissions a nd ambient air quality in a given year. Factors such as hours of equipment use a nd weather are constantly variable , regardless of our ability to measure them accurately. As discussed in the PM 2.5 NAAQS RIA (Table 5.5) , there are a variety
of uncertainties associated with these PM benefits. Therefore, the estimates of annual benefits should be viewed as representative of the magnitude of benefits expected, rather than the actual benefits that would occur every year.

Above we present the estimates of the total benefits, based on our interpretation of the
best available scientific l iterature and methods and suppor ted by the SAB-HES and the NAS (NRC, 2002). The benefits estimates are subject to a number of assumptions and uncertainties. For example, for key assumptions underlying th e estimates for premature mortality, which typically account for at least 90% of the total benefits, we were able to quantify include the following:

1. Inhalation of fine particles is causa lly associated with premature death at concentrations near those experienced by most Americans on a daily basis. Although biological mechanisms for this effect have not been established definitively yet, the weight of the available epid emiological evidence supports an assumption of causality. 2. All fine particles, regardless of their chemical composition, are equally potent in causing premature mortality. This is an important assumption, because PM produced via transported precursors emitted from EG Us may differ significantly from direct PM released from diesel engines and othe r industrial sources, but no clear scientific grounds exist for supporting differential e ffects estimates by particle type. 3. The impact function for fine particles is approximately linear within the range of ambient concentrations under considerati on. Thus, the estimates include health benefits from reducing fine particles in areas with varied concentrations of PM,7-12 including both regions that are in attainment with fine particle st andard and those that do not meet the standard.
4. The forecasts for future emissions and associated air quality modeling are valid. Although recognizing the difficulti es, assumptions, and inhere nt uncertainties in the overall enterprise, these analyses are based on peer-reviewed scientific literature and up-to-date assessment tools, and we believe the results are highly useful in assessing this rule. 5. Benefits estimated here reflect the app lication of a national dollar benefit-per-ton estimate of the benefits of reducing directly emitted fine particulates from point sources. Because they are based on nationa l-level analysis, the benefit-per-ton estimates used here do not reflect local va riability in meteorology, exposure, baseline health incidence rates, or ot her local factors that might lead to an over-estimate or under-estimate of the actual benefits of cont rolling directly emitted fine particulates.
This RIA does not include the type of detailed uncertainty assessment found in the PM NAAQS RIA because we lack the necessary air quality input and monitoring data to run the benefits model. Moreover, it was not possible to develop benefit-per-ton metrics and associated estimates of uncertainty using the benefits estim ates from the PM RIA because of the significant
differences between the sources affected in that rule and those regulated here. However, the results of the Monte Carlo analyses of the health and welfare benefits presented in Chapter 5 of the PM RIA can provide some evidence of th e uncertainty surrounding the benefits results presented in this analysis.

7.3 Updating the Benefits Data Underl ying the Benefit-per-Ton Estimates
As described above, the estimates provided in Tables 7-1 through 7- 5 are derived through a benefits transfer technique that adapts monetized benefits from reductions in PM 2.5 precursor pollutants that were estimated for the Ozone RIA utilizing nationally distributed emissions reductions. EPA is currently in the process of ge nerating localized benefit-per-ton estimates to better account for the spatial heterogeneity of benefits. EPA believes that these localized estimates may better represent the actual benef its than estimates that use national averages.

7.4 Comparison of Benefits and Costs
EPA estimates the range of annualized benefits of this rulemaking to be a combined $220 million to $1.9 billion ($2006) for new and reconstr ucted/modified sources at a 3% discount rate
and annualized costs calculated at a 7% interest rate as mentioned in Chapter 4 of this RIA for these sources to be $31 million ($2006) in the fift h year after proposal (2012). Thus, net benefits are $190 million to $1.8 billion in the fifth year after proposal at a 3% discount rate for the benefits. Figure 7-2 shows the full range of net benefits estimates (i.e., annual benefits in 2012 minus annualized costs) u tilizing the 14 different PM 2.5 mortality functions at the 3% discount7-13 rate. EPA believes that the benefits are likely to exceed the costs by a substantial margin under this rulemaking even when taking into account uncer tainties in the cost and benefit estimates.

‐ $2,000 ‐ $1,500 ‐ $1,000

‐ $500 $0 $500 $1,000 $1,500 $2,000

Various Combinations of Costs and Benefits EstimatesMillions(2006$)

Figure 7-2. Range of Estimated Net Benefits for Selected Options for Final Petroleum Refineries NSPS a

a Net Benefits are quantified in terms of PM 2.5 benefits at a 3% discount rate for the fifth year after proposal. This

graph shows 14 benefits estimates combined with the cost estimate. All combinations are treated as independent and equally probable. All fine particles are assumed to have equivalent health effects, but the benefit-per-ton estimates vary because each ton of precursor re duced has a different propensity to become PM 2.5 . The monetized benefits incorporate the conversion from precursor emissions to ambient fine particles.

7.5 References Ayyb, 2002

Guo et al., 1999

. Ibald-Mulli et al., 2001.

Industrial Economics, Inc., 2006. Expanded Expert Judgment Assessm ent of the ConcentrationResponse Relationship Between PM 2.5 Exposure and Mortality . Prepared for the U.S. EPA, Office of Air Quality Plan ning and Standards, September.

National Research Council (NRC). 2002. Estimating the Public Health Benefits of Proposed Air Pollution Regulations . Washington, DC: The Na tional Academies Press.

Laden, F., J. Schwartz, F.E. Speizer, and D.W. Dockery. 2006. Reduction in Fine Particulate Air Pollution and Mortality. American Journal of Respiratory and Critical Care Medicine. 173: 667-672. Benefits are greater than costs7-14 Pope, C.A., III, R.T. Burnett, M.J. Thun, E.E. Calle, D. Krewski, K. Ito, and G.D. Thurston. 2002. “Lung Cancer, Cardiopulmonary Mortal ity, and Long-term Exposure to Fine Particulate Air Pollution.” Journal of the American Medical Association 287:1132-1141.

U.S. Environmental Protection Agency. 2006. Regulatory Impact Analysis, 2006 National Ambient Air Quality Standards for Particulate Matter , Chapter 5. Available at <http://www.epa.gov/ttn/ecas/regdata/R IAs/Chapter%205--Benefits.pdf>.C-1 APPENDIX C OVERVIEW OF ECONOMIC MODEL EQUATIONS

We illustrate our approach for addressing conc eptual questions of market-level impacts using a numerical simulation model. Our met hod involves specifying a set of nonlinear supply and demand relationships for the affected mark ets, simplifying the equations by transforming them into a set of linear equations, and then solving the equilibrium system of equations (see Fullerton and Metcalfe [2002] for an example).

C.1 Discussion and Specification of Model Equations
First, we consider the formal definition of th e elasticity of supply with respect to changes in own price:

p / dp Q / dQ s s s = ε (C.1)

Next, we can use “hat” notation to transform Eq. (C.1) to proportional changes and rearrange

terms:

p ˆ Q ˆ
s

s ε

= (C.1a)

where

s Q ˆ = percentage change in the quantity of market supply,

γ

s = market elasticity of supply, and

p ˆ = percentage change in market price.

As Fullerton and Metcalfe (2002) note, we have ta ken the elasticity definiti on and turned it into a linear behavioral equation for our market.

To introduce the direct impact of the regul atory program, we assume the per-unit cost associated with the regulatory program (c) 1 leads to a proportional shift in the marginal cost of production. Under the assumption of perfect compet ition (price equals marginal cost), we can approximate this shift at the initial equilibrium point as follows:

1 The per-unit costs (c) are computed by dividing the total annualized costs reported in by the baseline consumption. The annual cost savings are included in the supply shift in the primary analysis.C-2 o o p c MC

c C M ˆ

= = . (C.1b)

The with-regulation supply equa tion can now be written as

) C M ˆ p ˆ ( Q ˆ

s

s − ε = . (C.1c)

Next, we can specify a demand equation as follows:

p Q d

d ˆ ˆ η = (C.2)

where

d Q ˆ = percentage change in the quantity of market demand,

η d = market elasticity of demand, and

p ˆ = percentage change in market price.

Finally, we specify the market equilibrium cond itions in the affected markets. In response to the exogenous increase in production costs, pr oducer and consumer behaviors are represented in Eq. (C.1a) and Eq. (C.2), and the new equilib rium satisfies the condition that the change in supply equals the change in demand:

d s Q ˆ Q ˆ

= . (C.3)

We now have three linear e quations in three unknowns ( p ˆ

, d Q ˆ , and s Q ˆ ), and we can solve for the proportional price change in terms of the elas ticity parameters ( ε s and η d ) and the proportional change in marginal cost:



## ( 

# )

( )

48 47 6 A.1.c s Q ˆ

s C M

ˆ p ˆ

− ε = 

## ( ) ( )

8 7 6 A.2 ˆ

ˆ

d Q

d p η (C.4)

=

p s ˆ ε – C M s ˆ ε = η d ( p ˆ )

p s ˆ ε – η d ( p ˆ ) = C M s ˆ ε

p ˆ ( s ε – η d ) = C M s ˆ ε

p ˆ = ε s ( ε s – η d ) C M

ˆ ×C-3 C M

ˆ p ˆ
d s s × η

− ε ε

= . (C.5)

Given this solution, we can solve for the proporti onal change in market qua ntity using Eq. (C.2).

C.2 Consumer and Producer Welfare Calculations
The change in consumer surplus in the a ffected markets can be estimated using the following linear approximation method:

)

CS = – [ Q 1 × ) p ] + [0.5 × ) Q × ) p ]. (C.6)

As shown, higher market prices and reduced cons umption lead to welfare losses for consumers. A geometric representation of this calc ulation is illustra ted in Figure C-1.

For affected supply, the change in producer surplus can be estimate d with the following equation:

) PS = [ Q 1 × ) p ] – [ Q 1 × c ] – [0.5 × ) Q × ( ) p – c )]. (C.7)

Increased regulatory costs and output declines have a negative effect on producer surplus, because the net price change ( ) p – c) is negative. However, thes e losses are mitigated, to some degree, as a result of higher market prices. A geometric repres entation of this calculation is illustrated in Figure C-1.C-4 Q 1 Q 0 P 1

P 0 h

c

a $

Output e d S 1 : With Regulation

S 0 : Without Regulation Price Increase Unit Cost Increase g

f

b

) consumer surplus = –[fghd + dhc] ) producer surplus = [fghd – aehb] – bdc ) total surplus = –[aehb + dhc + bdc] Figure C-1. Welfare CalculationsUnited States Environmental Protection Agency Office of Air Quality Planning and Standards Health and Environmental Impacts Division Research Triangle Park, NC Publication No. EPA 452/R-08-002 April 2008