Economic Impact Analysis 

Petroleum Refineries 

Proposed Amendments to the National Emissions 

Standards for Hazardous Air Pollutants and New 

Source Performance Standards 

U.S. Environmental Protection Agency 

Office of Air and Radiation 

Office of Air Quality Planning and Standards 

Research Triangle Park, NC 27711 

February 2014 
ii 

CONTACT INFORMATION 

This document has been prepared by staff from the Office of Air Quality Planning and 

Standards, U.S. Environmental Protection Agency and RTI International. Questions related to 

this document should be addressed to Alexander Macpherson, U.S. Environmental Protection 

Agency, Office of Air Quality Planning and Standards, C445-B, Research Triangle Park, North 

Carolina 27711 (email: macpherson.alex@epa.gov). 

ACKNOWLEDGEMENTS

In addition to EPA staff from the Office of Air Quality Planning and Standards, 

personnel from RTI International contributed significant data and analysis to this document 

under contract number EP-D-06-003. 

 
iii 

TABLE OF CONTENTS 

TABLE OF CONTENTS .................................................................................................................... III

LIST OF TABLES .............................................................................................................................. V

LIST OF FIGURES ........................................................................................................................... VI

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

1.1 BACKGROUND .............................................................................................................................................. 1-1

1.2 RESULTS ...................................................................................................................................................... 1-1

1.3 ORGANIZATION OF THIS REPORT .................................................................................................................. 1-2

2 INDUSTRY PROFILE ............................................................................................................. 2-1

2.1 INTRODUCTION ............................................................................................................................................ 2-1

2.2 THE SUPPLY SIDE ......................................................................................................................................... 2-1

2.2.1 Production Process, Inputs, and Outputs ........................................................................................... 2-1

2.2.1.1 The Production Process ............................................................................................................ 2-2

2.2.1.2 Supporting Operations .............................................................................................................. 2-5

2.2.1.3 Inputs ........................................................................................................................................ 2-7

2.2.1.4 Types of Product Outputs ......................................................................................................... 2-8

2.2.2 Emissions and Controls in Petroleum Refining ................................................................................. 2-9

2.2.2.1 Gaseous and VOC Emissions ................................................................................................... 2-9

2.2.2.2 Wastewater and Other Wastes ................................................................................................ 2-10

2.2.3 Costs of Production .......................................................................................................................... 2-10

2.3 THE DEMAND SIDE .................................................................................................................................... 2-14

2.3.1 Product Characteristics .................................................................................................................... 2-14

2.3.2 Uses and Consumers ........................................................................................................................ 2-14

2.3.3 Substitution Possibilities in Consumption ....................................................................................... 2-16

2.4 INDUSTRY ORGANIZATION ......................................................................................................................... 2-16

2.4.1 Market Structure .............................................................................................................................. 2-16

2.4.1.1 Barriers to Entry ..................................................................................................................... 2-17

2.4.1.2 Measures of Industry Concentration ...................................................................................... 2-18

2.4.1.3 Product Differentiation ........................................................................................................... 2-19

2.4.1.4 Competition among Firms in the Petroleum Refining Industry ............................................. 2-20

2.4.2 Characteristics of U.S. Petroleum Refineries and Petroleum Refining Companies ......................... 2-20

2.4.2.1 Geographic Distribution of U.S. Petroleum Refineries .......................................................... 2-20

2.4.2.2 Capacity Utilization ................................................................................................................ 2-20

2.4.2.3 Characteristics of Small Businesses Owning U.S. Petroleum Refineries ............................... 2-23

2.5 MARKETS ................................................................................................................................................... 2-29

2.5.1 U.S. Petroleum Consumption .......................................................................................................... 2-29

2.5.2 U.S. Petroleum Production .............................................................................................................. 2-35

2.5.3 International Trade ........................................................................................................................... 2-36

2.5.4 Market Prices ................................................................................................................................... 2-38

2.5.5 Profitability of Petroleum Refineries ............................................................................................... 2-40

2.5.6 Industry Trends ................................................................................................................................ 2-42

2.6 REFERENCES .............................................................................................................................................. 2-44

3 EMISSIONS AND ENGINEERING COSTS ................................................................................ 3-1

3.1 INTRODUCTION ............................................................................................................................................ 3-1

3.2 SUMMARY OF PROPOSED RULE AMENDMENTS ............................................................................................ 3-2

3.2.1 Storage Vessels .................................................................................................................................. 3-2

3.2.2 Delayed Coking Units ........................................................................................................................ 3-5

3.2.3 Fenceline Monitoring ......................................................................................................................... 3-8

3.2.4 Relief Valve Monitoring .................................................................................................................. 3-10
iv 

3.2.5 Flare Monitoring .............................................................................................................................. 3-12

3.2.6 FCCU Testing .................................................................................................................................. 3-17

3.3 SUMMARY OF COSTS OF PROPOSED RULE AMENDMENTS .......................................................................... 3-17

4 ECONOMIC IMPACT ANALYSIS AND DISTRIBUTIONAL ASSESSMENTS............................... 4-1

4.1 INTRODUCTION ............................................................................................................................................ 4-1

4.2 MARKET ANALYSIS ..................................................................................................................................... 4-1

4.2.1 Market Analysis Methods .................................................................................................................. 4-1

4.2.2 Model Baseline .................................................................................................................................. 4-4

4.2.3 Model Parameters .............................................................................................................................. 4-5

4.2.4 Entering Estimated Annualized Engineering Compliance Costs into Economic Model ................... 4-6

4.2.5 Model Results .................................................................................................................................... 4-7

4.2.6 Limitations ......................................................................................................................................... 4-9

4.3 DISCUSSION OF EMPLOYMENT IMPACTS ...................................................................................................... 4-9

4.3.1 Theory .............................................................................................................................................. 4-10

4.3.2 Current State of Knowledge Based on the Peer-Reviewed Literature ............................................. 4-15

4.3.2.1 Regulated Sector ................................................................................................................... 4-16

4.3.2.2 Environmental Protection Sector ........................................................................................ 4-17

4.3.2.3 Labor Supply Impacts ......................................................................................................... 4-17

4.3.3 Macroeconomic Net Employment Effects ....................................................................................... 4-18

4.3.4 Conclusions...................................................................................................................................... 4-19

4.4 SMALL BUSINESS IMPACTS ANALYSIS ....................................................................................................... 4-19

4.4.1 Small Entity Economic Impact Measures ........................................................................................ 4-20

4.4.2 Small Entity Economic Impact Analysis ......................................................................................... 4-21

4.5 REFERENCES .............................................................................................................................................. 4-24

 
v 

LIST OF TABLES 

Table 2-1 Types and Characteristics of Raw Materials used in Petroleum Refineries ....................................... 2-8

Table 2-2 Refinery Product Categories .............................................................................................................. 2-8

Table 2-3 Labor, Material, and Capital Expenditures for Petroleum Refineries (NAICS 324110).................. 2-12

Table 2-4 Costs of Materials Used in Petroleum Refining Industry ................................................................ 2-13

Table 2-5 Major Refinery Products .................................................................................................................. 2-15

Table 2-6 Market Concentration Measures of the Petroleum Refining Industry: 1985 to 2007 ...................... 2-19

Table 2-7 Number of Petroleum Refineries, by State ...................................................................................... 2-22

Table 2-8 Full Production Capacity Utilization Rates for Petroleum Refineries ............................................. 2-23

Table 2-9 Characteristics of Small Businesses in the Petroleum Refining Industry ........................................ 2-30

Table 2-10 Total Petroleum Products Supplied (millions of barrels per year) ................................................... 2-35

Table 2-11 U.S. Refinery and Blender Net Production (millions of barrels per year) ....................................... 2-35

Table 2-12 Value of Product Shipments of the Petroleum Refining Industry .................................................... 2-37

Table 2-13 Imports of Major Petroleum Products (millions of barrels per year) ............................................... 2-37

Table 2-14 Exports of Major Petroleum Products (millions of barrels per year) ............................................... 2-38

Table 2-15 Average Price of Major Petroleum Products Sold to End Users (cents per gallon) ......................... 2-39

Table 2-16 Producer Price Index Industry Data: 1995 to 2010 .......................................................................... 2-40

Table 2-17 Mean Ratios of Profit before Taxes as a Percentage of Net Sales for Petroleum Refiners, Sorted by 

Value of Assets ........................................................................................................................................................ 2-41

Table 2-18 Net Profit Margins for Publicly Owned, Small Petroleum Refiners: 2010 ...................................... 2-42

Table 2-19 Forecasted Average Price of Major Petroleum Products Sold to End Users in 2009 Currency (cents 

per gallon) 2-43

Table 2-20 Total Petroleum Products Supplied (millions of barrels per year) ................................................... 2-43

Table 2-21 Full Production Capacity Utilization Rates for Petroleum Refineries ............................................. 2-44

Table 3-1 Nationwide Emissions Reduction and Cost Impacts of Control Options for Storage Vessels at 

Petroleum Refineries ................................................................................................................................................. 3-5

Table 3-2 Nationwide VOC Impacts for Delayed Coking Unit Control Options . ............................................. 3-6

Table 3-3 Nationwide HAP Impacts for Delayed Coking Unit Control Options ............................................... 3-8

Table 3-4 Nationwide Costs (in 2009$) for Fenceline Monitoring at Petroleum Refineries ............................ 3-10

Table 3-5 Nationwide Costs for Equipment Leaks (2009$) ............................................................................. 3-12

Table 3-6 Summary of Capital and Annualized Costs for Flare Control Alternatives (2010$) ........................ 3-15

Table 3-7 Detailed Costs of Flare Monitoring Requirements (2010$) ............................................................. 3-15

Table 3-8 Emissions Sources, Points, and Controls Included in Regulatory Options ...................................... 3-19

Table 4-1 Baseline Petroleum Product Market Data, 2016 ................................................................................ 4-5

Table 4-2 Estimates of Price Elasticity of Demand and Supply ......................................................................... 4-5

Table 4-3 Estimated Annualized Engineering Compliance Costs by Petroleum Product Modeled ................... 4-7

Table 4-4 Summary of Petroleum Product Market Impacts ............................................................................... 4-8

Table 4-5 Impact Levels of Proposed NESHAP Amendments on Small Firms .............................................. 4-22

Table 4-6 Summary of Sales Test Ratios for Firms Affected by Proposed NESHAP Amendments ............... 4-23

 

 
vi 

LIST OF FIGURES 

Figure 2-1 Outline of the Refining Process ......................................................................................................... 2-3

Figure 2-2 Desalting Process ............................................................................................................................... 2-3

Figure 2-3 Atmospheric Distillation Process ....................................................................................................... 2-4

Figure 2-4 Vacuum Distillation Process .............................................................................................................. 2-5

Figure 2-5 Petroleum Refinery Expenditures .................................................................................................... 2-10

Figure 2-6 Employment Distribution of Companies Owning Petroleum Refineries (N=61) ............................ 2-24

Figure 2-7 Average Revenue of Companies Owning Petroleum Refineries by Employment (N=61) .............. 2-25

Figure 2-8 Revenue Distribution of Large Companies Owning Petroleum Refineries (N=25) ......................... 2-26

Figure 2-9 Revenue Distribution of Small Companies Owning Petroleum Refineries (N=36) ......................... 2-27

Figure 2-10 Total Petroleum Products Supplied (millions of barrels per year) ................................................... 2-34
1-1 

1 EXECUTIVE SUMMARY 

1.1 Background 

As part of the regulatory process, EPA is required to perform economic analysis. EPA 

estimates the proposed NESHAP and NSPS amendments will have annualized cost of impacts of 

less than $100 million, so the Agency has prepared an Economic Impact Analysis (EIA). This 

EIA includes an analysis of economic impact analysis anticipated from the proposed NESHAP 

and NSPS amendments. We also provide a small business impacts analysis within this EIA. We 

assume an analysis year of 2016. 

1.2 Results 

For the proposed rule, the key results of the EIA follow: 

 Engineering Cost Analysis: Total annualized engineering costs measure the costs incurred 

by affected industries annually. The annualized engineering costs for the proposed regulatory 

alternative are estimated to be $42.4 million.1 As discussed in Section 3, the annualized 

engineering costs include $4.5 million associated with proposed requirements for storage 

vessels, delayed coking units, and fugitive emissions monitoring. The proposed requirements 

would also result in $36.3 million in annual costs for flare monitoring, $1.4 million in annual 

costs to monitor relief device releases, and $213,000 in annual costs to conduct performance 

tests for the FCCU at existing sources. 

• Market Analysis: The proposed option is predicted to induce minimal change in the average 

national price of refined petroleum product. Product prices are predicted to increase less than 

0.0001% on average, while production levels decrease less than 0.0001% on average, as a 

result of the proposed option. 

 Small Entity Analyses: Based on data collected through the April 2011 ICR, EPA 

performed a cost-to-sales screening analysis for impacts for 28 affected small refineries. The 

cost-to-sales ratio was below 1 percent for all affected small firms. As such, we determined 

that proposed options will not have a significant economic impact on a substantial number of 

small entities (SISNOSE). 

 Employment Impacts Analysis: We provide a qualitative framework for considering the 

potential influence of environmental regulation on employment in the U.S. economy, and we 

discuss the limited empirical literature available. The discussion focuses on both short- and 

long-term employment impacts on regulated industries. 

 

1

 Note that this estimate does not reflect any corrective action taken in response to the fenceline monitoring program. 

Any corrective actions associated with fenceline monitoring will result in additional emissions reductions and 

additional costs. 
1-2 

1.3 Organization of this Report 

The remainder of this report details the methodology and the results of the EIA. Section 

2 presents the industry profile of petroleum refining industry. Section 3 describes the emissions 

and engineering cost analysis. Section 4 presents market, employment impact, and small 

business impact analyses.
2-1 

2 INDUSTRY PROFILE 

2.1 Introduction 

This industry profile of the petroleum refining industry provides information that will 

support this and subsequent regulatory impact analyses (RIAs) and economic impact analyses 

(EIAs) that will assess 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, kerosene, asphalt, lubricants, and solvents, among others. 

Firms engaged in petroleum refining are categorized under the North American Industry 

Classification System (NAICS) code 324110. In 2010, 148 establishments owned by 64 parent 

companies were refining petroleum in the continental United States. In 2009, the petroleum 

refining industry shipped products valued at over $436 billion (U.S. Census Bureau, Sector 31: 

2009 and 2008). 

This industry profile report is organized as follows. Section 2.2 provides a detailed 

description of the inputs, outputs, and processes involved in petroleum refining. Section 2.3 

describes the applications and users of finished petroleum products. Section 2.4 discusses the 

organization of the industry and provides facility- and company-level data. In addition, small 

businesses are reported separately for use in evaluating the impact on small business to meet the 

requirements of the Small Business Regulatory Enforcement and Fairness Act (SBREFA). 

Section 2.5 contains market-level data on prices and quantities and discusses trends and 

projections for the industry. 

2.2 The Supply Side 

Estimating the economic impacts of any regulation on the petroleum refining industry 

requires a good understanding of how finished petroleum products are produced (the “supply 

side” of finished petroleum product markets). This section describes the production process used 

to manufacture these products as well as the inputs, outputs, and by-products involved. The 

section concludes with a description of costs involved with the production process. 

2.2.1 Production Process, Inputs, and Outputs 

Petroleum pumped directly out of the ground, known as crude oil, is a complex mixture 

of hydrocarbons (chemical compounds that consist solely of hydrogen and carbon) and various 

impurities such as salt. To manufacture the variety of petroleum products recognized in everyday 
2-2 

life, this mixture must be refined and processed over several stages. This section describes the 

typical stages involved in this process as well as the inputs and outputs. 

2.2.1.1 The Production Process 

The process of refining crude oil into useful petroleum products can be separated into two 

phases and a number of supporting operations. These phases are described 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 are 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 2-

1. 

Desalting. Before separation into fractions, crude oil is treated to remove salts, 

suspended solids, and other impurities that could clog or corrode the downstream equipment. 

This process, known as “desalting,” is typically done by first heating the crude oil, mixing it with 

process water, and depositing it into a gravity settler tank. Gradually, the salts 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 chemicals (a process known as chemical separation) 

and/or by applying an electric field to concentrate the suspended water globules at the bottom of 

the settler tank (a process known as electrostatic separation). The effluent water is then removed 

from the tank and sent to the refinery wastewater treatment facilities (EPA, 1995). This process 

is illustrated in Figure 2-2. 
2-3 

Figure 2-1 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 2-2 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. 
2-4 

Atmospheric Distillation. The desalted crude oil is then heated in a furnace to 750°F and 

fed into a vertical distillation column at atmospheric pressure. After entering the tower, the 

lighter fractions flash into vapor and travel up the tower. This leaves only the heaviest fractions 

(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 gradually 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 kerosene because it condenses at lower temperatures. 

This process is illustrated in Figure 2-3. As these fractions condense, they will be drawn off their 

respective trays and potentially sent downstream for further processing (OSHA, 2003; EPA, 1995). 

Figure 2-3 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 tower cannot distill the heaviest 

fractions (those at the bottom of the tower) without cracking under requisite 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 volatilization 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 2-4. 
2-5 

Figure 2-4 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 Processing. To produce the petroleum products desired by the market 

place, most fractions must be further refined after distillation or “downstream” processes. These 

downstream processes change the molecular structure 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, catalytic cracking, catalytic 

hydrocracking, hydrotreating, alkylation, isomerization, polymerization, catalytic reforming, 

solvent extraction, merox, dewaxing, propane deasphalting and other operations (EPA, 1995). 

2.2.1.2 Supporting Operations 

In addition to the processes described above, there are other refinery operations that do 

not directly involve the production of hydrocarbon fuels, but serve in a supporting role. Some of 

the major supporting operations are described in this section. 

Wastewater Treatment. Petroleum refining operations produce a variety of wastewaters 

including process water (water used in process operations like 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 surface or leaks in the equipment that have collected in drains). 
2-6 

Wastewater typically contains a variety of contaminants (such as hydrocarbons, 

suspended solids, phenols, ammonia, sulfides, and other compounds) and must be treated before 

it is recycled back into refining operations or discharged. Petroleum refineries typically utilize 

two stages of wastewater treatment. In primary wastewater treatments, oil and solids present in 

the wastewater are removed. After this is completed, wastewater can be discharged to a publicly 

owned treatment facility or undergo secondary treatment before being discharged directly to 

surface water. In secondary treatment, microorganisms are used to dissolve oil and other organic 

pollutants that are present in the wastewater (EPA, 1995; OSHA, 2003). 

Gas Treatment and Sulfur Recovery. Petroleum refinery operations such as coking and 

catalytic cracking emit gases with a high concentration 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 the Clean Air Act’s SOx emission limits and to recover saleable elemental 

sulfur. 

Sulfur is recovered by first separating the fuel 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 used to react with the sulfur 

dioxide and the unburned hydrogen sulfide to produce elemental sulfur. However, the Claus 

process only removes 90% of the hydrogen sulfide present in the gas stream, so other processes 

must be used to recover the remaining sulfur (EPA, 1995). 

Additive Production. A variety of chemicals are added to petroleum products to 

improve their quality or add special characteristics. For example, ethers have been added to 

gasoline to increase octane levels and reduce CO emissions since the 1970s. 

Heat Exchangers, Coolers, and Process Heaters. Petroleum refineries require very 

high temperatures to perform many of their refining processes. To achieve these temperatures, 

refineries use fired heaters fueled by refinery or natural gas, distillate, and residual oils. This heat 

is managed through heat exchangers, which are composed of bundles of pipes, tubes, plate coils, 

and other equipment that surround heating or cooling water, steam, or oil. Heat exchangers 

facilitate the indirect transfer of heat as needed (OSHA, 2003). 

Pressure Release and Flare Systems. As liquids and gases expand and contract through 

the refining process, pressure must be actively managed to avoid accident. Pressure-relief 

systems enable the safe handling of liquids and gases that are released by pressure-relieving 
2-7 

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 material, such as blow-downs from process unit 

startups, furnace blow-downs, shutdowns, and emergencies” (OSHA, 2003). 

Blending. Blending is the final operation in petroleum refining. It is the physical mixture 

of a number of different liquid hydrocarbons to produce final petroleum products that have 

desired characteristics. For example, additives such as ethers can be blended with motor gasoline 

to boost performance and reduce emissions. Products can be blended in-line through a manifold 

system, or batch blended in tanks and vessels (OSHA, 2003). 

2.2.1.3 Inputs 

The inputs in the production process of petroleum products include general inputs such as 

labor, capital, and water.2

 The inputs specific to this industry are crude oil and the variety of 

chemicals used in producing petroleum products. These two specific inputs are discussed below. 

Crude Oil. Crude oils are complex, heterogeneous mixtures and contain many different 

hydrocarbon compounds that vary in appearance and composition from one oil field to another. 

An “average” crude oil contains about 84% carbon; 14% hydrogen; and less than 2% sulfur, 

nitrogen, oxygen, metals, and salts (OSHA, 2003). The proportions of crude oil elements vary 

over a narrow limit: the proportion of carbon ranges from 83 to 87 percent; hydrogen ranges 

from 10 to 14 percent; nitrogen ranges from 0.1 to 2 percent; oxygen ranges from 0.5 to 1.5 

percent; and sulfur ranges from 0.5 to 6 percent (Speight 2006). 

In 2010, the petroleum refining industry used 5.4 billion barrels of crude oil in the 

production of finished petroleum products (EIA 2010).3

Common Refinery Chemicals. In addition to crude oil, a variety of chemicals are used 

in the production of petroleum products. The specific chemicals used will depend on specific 

characteristics of the product in question. Table 2-1 lists the most common chemicals used by 

petroleum refineries, their characteristics, and their applications. 

 

2

 Crude oil processing requires large volumes of water, a large portion of which is continually recycled. The amount 

of water used by a refinery can vary significantly, depending on process configuration, refinery complexity, 

capability for recycle, degree of sewer segregation, and local rainfall. In 1992, the average amount of water used in 

refineries was estimated between 65 and 90 gallons per barrel of crude oil processed (OGJ 1992a). 

3

 A barrel is a unit of volume that is equal to 42 U.S. gallons. 
2-8 

Table 2-1 Types and Characteristics of Raw Materials used in Petroleum Refineries 

Type Description 

Crude Oil Heterogeneous mixture of different hydrocarbon compounds. 

Oxygenates Substances which, when added to gasoline, increase the amount of oxygen in that 

gasoline blend. Ethanol, 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 tetramethyl 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 used 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 2010, the petroleum refining industry used 971 million barrels of natural gas liquids 

and other liquids in the production of finished petroleum products (EIA 2010). 

2.2.1.4 Types of Product Outputs 

The petroleum refining industry produces a number of products that fall into one of three 

categories: fuels, finished nonfuel products, and feedstock for the petrochemical industry. Table 

2-2 briefly describes these product categories. A more detailed discussion of petroleum fuel 

products can be found in Section 2.3. 

Table 2-2 Refinery Product Categories 

Product Category Description 

Fuels Finished Petroleum products that are capable of releasing 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, lubricants (such as motor oil and industrial 

greases), and solvents (such as benzene, toluene, and xylene). 

Feedstock 

Sulfur 

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. 

Commercial uses are primarily in fertilizers, because of the relatively high 

requirement of plants for it, and in the manufacture of sulfuric acid, a primary 

industrial chemical. 

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. 
2-9 

2.2.2 Emissions and Controls in Petroleum Refining 

Petroleum refining results in emissions of hazardous air pollutants (HAPs), criteria air 

pollutants (CAPs), and other pollutants. The HAPs include metals and toxic organic compounds; 

the CAPs include carbon monoxide (CO), sulfur oxides (SOx), nitrogen oxides (NOx), 

particulates, and volatile organic compounds (VOCs); and the other pollutants include spent 

acids, gaseous pollutants, ammonia (NH3), and hydrogen sulfide (H2S). 

2.2.2.1 Gaseous and VOC Emissions 

As previously mentioned, CO, SOx, NOx, NH3, and H2S emissions are produced along 

with petroleum products. Sources of these emissions 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 and can be reduced by purchasing 

leak-resistant equipment and maintaining an ongoing leak detection and repair 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 SOx, NOx, 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 refinery process contain varying amounts of 

refinery fuel gas, H2S, and NH3. These streams are directed to the gas treatment and sulfur 

recovery units described in the previous section. Here, refinery fuel gas and sulfur are recovered 

using a variety of processes. These processes create emissions of their own, which normally 

contain H2S, SOx, and NOx gases (EPA, 1995). For additional details on refinery fuel, or waste, 

gas composition, see Table 12 of the January 25, 2012 Impact Estimates for Fuel Gas 

Combustion Device and Flare Regulatory Options for Amendments to the Petroleum Refinery 

NSPS available in the docket. 

Emissions can also be created by the periodic regeneration of catalysts that are used in 

downstream processes. These processes generate streams that may contain relatively high levels 

of CO, particulate, and VOC emissions. However, these emissions are treated before being 

discharged to the atmosphere. First, the emissions are processed through a CO boiler to burn CO 
2-10 

and any VOC, and then through an electrostatic precipitator or cyclone separator to remove 

particulates (EPA, 1995). 

2.2.2.2 Wastewater and Other Wastes 

Petroleum refining operations produce a variety of wastewaters including process water 

(water used in process operations like 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 

surface or leaks in the equipment that have collected in drains). This wastewater typically 

contains a variety of contaminants (such as hydrocarbons, suspended solids, phenols, NH3, 

sulfides, and other compounds) and is treated in on-site 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 including incineration, land filling, 

and neutralization, among other treatment methods (EPA, 1995). 

2.2.3 Costs of Production 

Between 1995 and 2009, expenditures on input materials accounted for the largest cost to 

petroleum refineries—amounting to 95% of total expenses (Figure 2-5). These material costs 

included the cost of all raw materials, containers, scrap, and supplies used in production or repair 

during the year, as well as the cost of all electricity and fuel consumed. 

Average Percentage 

(1995–2009) 

Figure 2-5 Petroleum Refinery Expenditures 
2-11 

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 Manufactures. 

M05(AS)-1. Washington, DC: Government Printing Office. Available at 

<http://www.census.gov/prod/2006pubs/ 

 U.S. Department of Commerce, Bureau of the Census. 2003a. 2001 Annual Survey of Manufactures. 

M01(AS)-1. Washington, DC: Government Printing Office. Available at 

<http://www.census.gov/prod/2003pubs/ 

 U.S. Department of Commerce, Bureau of the Census. 2001. 1999 Annual Survey of Manufactures. 

M99(AS)-1 (RV). Washington, DC: Government Printing Office. Available at 

<http://www.census.gov/prod/2001pubs/ 

 U.S. Department of Commerce, Bureau of the Census. 1998. 1996 Annual Survey of Manufactures. 

M96(AS)-1 (RV). Washington, DC: Government Printing Office. Available at 

<http://www.census.gov/prod/3/98pubs/ 

 U.S. Department of Commerce, Bureau of the Census. 1997. 1995 Annual Survey of Manufactures. 

M95(AS)-1. Washington, DC: Government Printing Office. Available at 

<http://www.census.gov/prod/2/manmin/ 

U.S. Census Bureau, American FactFinder; “Sector 31: Annual Survey of Manufactures: 

General Statistics: Statistics for Industry Groups and Industries: 2009 and 2008 “ Release Date: 

12/3/10; (Data accessed on 10/10/11). [Source for 2008 and 2009 numbers] 

http://factfinder.census.gov/servlet/IBQTable?_bm=y&-NAICSASM=324110&-ds_name= 

AM0931GS101&-ib_type=NAICSASM&-_industry=324110&-_lang=en

U.S. Census Bureau, American FactFinder; “Sector 31: Manufacturing: Industry Series: 

Detailed Statistics by Industry for the United States: 2007” Release Date 10/30/09; (Data accessed 

on 10/11/11). [Source for 2007 numbers] http://factfinder.census.gov/servlet/IBQTable?_bm=y&-

geo_id=01000US&-ds_name=EC0731I1&-NAICS2007=324110&-_lang=en

Labor and capital accounted for the remaining expenses faced by petroleum refiners. 

Capital expenditures include permanent additions and alterations to facilities and machinery and 

equipment used for expanding plant capacity or replacing existing machinery. A detailed 

breakdown of how much petroleum refiners spent on each of these factors of production over 

this 15-year period is provided in Table 2-3. A more exhaustive assessment of the costs of 

materials used in petroleum refining is provided in Table 2-4. 
2-12 

Table 2-3 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 

2007 6,357 5,885 470,946 435,965 17,105 15,834 

2008 6,313 5,415 649,784 557,380 17,660 15,148 

2009 6,400 5,776 398,679 359,790 16,824 15,183 

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 Manufactures. 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 Manufactures. 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 Manufactures. 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 Manufactures. 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 Manufactures. 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. 

 U.S. Census Bureau, American FactFinder; “Sector 31: Annual Survey of Manufactures: General Statistics: 

Statistics for Industry Groups and Industries: 2009 and 2008 “ Release Date: 12/3/10; (Data accessed on 

10/10/11). [Source for 2008 and 2009 numbers] http://factfinder.census.gov/servlet/IBQTable?_bm=y&-

NAICSASM=324110&-ds_name=AM0931GS101&-ib_type=NAICSASM&-_industry=324110&-_lang=en

 U.S. Census Bureau, American FactFinder; “Sector 31: Manufacturing: Industry Series: Detailed Statistics by 

Industry for the United States: 2007” Release Date 10/30/09; (Data accessed on 10/11/11). [Source for 2007 

numbers] http://factfinder.census.gov/servlet/IBQTable?_bm=y&-geo_id=01000US&-ds_name=EC0731I1&-

NAICS2007=324110&-_lang=en
2-13 

Table 2-4 Costs of Materials Used in Petroleum Refining Industry 

 2007 2002 

Material 

Delivered 

Cost ($103) 

Percentage 

of Material 

Costs 

Delivered 

Cost ($103) 

Percentage 

of Material 

Costs 

Petroleum Refineries NAICS 324110 

Total materials 440,165,193 100.00% 157,415,200 100.00% 

Domestic crude petroleum, including lease 

condensate 

133,567,383 30.3% 63,157,497 40.1% 

Foreign crude petroleum, including lease 

condensate 

219,780,279 49.9% 69,102,574 43.9% 

Foreign unfinished oils (received from 

foreign countries for further processing) 

D 2,297,967 1.5% 

Ethane (C2) (80% purity or more) — D 

Propane (C3) (80% purity or more) — 118,257 0.1% 

Butane (C4) (80% purity or more) 7,253,910 1.7% 1,925,738 1.2% 

Gas mixtures (C2, C3, C4) — 1,843,708 1.2% 

Isopentane and natural gasoline 5,117,182 1.2% 810,530 0.5% 

Other natural gas liquids, including plant 

condensate 

3,356,718 0.8% 455,442 0.3% 

Toluene and xylene (100% basis) 1,801,972 0.4% 159,563 0.1% 

Additives (including antioxidants, 

antiknock compounds, and inhibitors) 

D 40,842 0.0% 

Other additives (including soaps and 

detergents) 

— 709 0.0% 

Animal and vegetable oils — D 

Chemical catalytic preparations D D 

Fats and oils, all types, purchased 87,038 0.0% — — 

Sodium hydroxide (caustic soda) (100% 

NaOH) 

209,918 0.1% 129,324 0.1% 

Sulfuric acid, excluding spent (100% 

H2SO4) 

67,458 0.0% 189,912 0.1% 

Metal containers D 9,450 0.0% 

Plastics containers D D 

Paper and paperboard containers 1,819 0.0% D 

Cost of materials received from petroleum 

refineries and lube manufacturers 

20,951,741 4.8% 8,980,758 5.7% 

All other materials and components, parts, 

containers, and supplies 

24,839,320 5.6% 5,722,580 3.6% 

Materials, ingredients, containers, and 

supplies 

4,745,614 1.1% 576,175 0.4% 

Sources: 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. 

 U.S. Census Bureau, American FactFinder; “Sector 31: Manufacturing: Industry Series: Materials 

 Consumed by Kind for the United States: 2007” Release Date 10/30/09; (Data accessed on 10/11/11). [

 Source for 2007 numbers] <http://factfinder.census.gov/servlet/IBQTable?_bm=y&-ds_name=EC0731I3&-

 NAICS2007=324110&-ib_type=NAICS2007&-geo_id=&-_industry=324110&-_lang=en&-

 fds_name=EC0700A1> 
2-14 

2.3 The Demand Side 

Estimating the economic impact the regulation will have on the petroleum refining 

industry also requires characterizing various aspects of the demand for finished petroleum 

products. This section describes the characteristics of finished petroleum products, their uses and 

consumers, and possible substitutes. 

2.3.1 Product Characteristics 

Petroleum refining firms produce a variety of different products. The characteristics these 

products possess largely depend on their intended use. For example, the gasoline fueling our 

automobiles has different characteristics than the oil lubricating the car’s engine. However, as 

discussed in Section 2.1.4, finished petroleum products can be categorized into three broad 

groups based on their intended 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, synthetic rubber, and other goods 

A list of selected products from each of these groups is presented in Table 2-5 along with a 

description of each product’s characteristics and primary uses. 

2.3.2 Uses and Consumers 

Finished petroleum products are rarely consumed as final goods. 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 include fertilizers, pesticides, paints, thinners, cleaning fluids, 

refrigerants, and synthetic fibers (EPA, 1995). Similarly, fuels made from petroleum are used to 

run vehicles and industrial machinery and generate heat and electrical power. As a result, the 

demand for many finished 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—manufacturing, construction, mining, agricultural, and forestry 

establishments 

 Transportation sector—private and public vehicles that move people and 

commodities such as automobiles, ships, and aircraft 
2-15 

 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—privately and publicly owned establishments that generate, 

transmit, distribute, or sell electricity (primarily) to the public; nonutility power 

producers are not included in this sector 

Table 2-5 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 water heaters, as a cooking fuel, and in lamps. 

Liquefied petroleum gas 

(LPG) 

LPG consists principally of propane (C3H8) and butane (C4H10). 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 materials, must be inert to most chemicals and 

weather conditions. 

Lubricants Lubricants are the result of a special refining 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 to manufacture detergent and synthetic 

fibers. Other solvents include toluene and xylene. 

Feedstock 

Ethylene Ethylene is the simplest alkene and has the chemical formula C2H4. 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 compound with the chemical formula C3H6. 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. 
2-16 

Of these end users, the transportation sector consumes the largest share of petroleum 

products, accounting for 67% of total consumption 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). 

Of the three petroleum product categories, end-users primarily consume fuel. Fuel 

products account for 9 out of 10 barrels of petroleum used in the United States (EIA, 1999a). In 

2005, motor gasoline alone accounted for 49% of demand for finished petroleum products (EIA, 

2006a). 

2.3.3 Substitution Possibilities in Consumption 

A major influence on the demand for finished petroleum products is the availability of 

substitutes. In some sectors, like the transportation sector, it is currently difficult to switch 

quickly from one fuel to another without costly and irreversible equipment changes, but other 

sectors can switch relatively quickly 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) than in others (EIA, 1999a). 

However, over time, demand for petroleum products could become more elastic. For 

example, automobile users could purchase more fuel-efficient vehicles or relocate to areas that 

would allow them to make fewer trips. Technological advances could also create new products 

that compete with petroleum products that currently have no substitutes. An example of such a 

technological advance would be the invention of ethanol (an alcohol produced from biomass), 

which can substitute for gasoline in spark-ignition motor vehicles (EIA, 1999a). 

2.4 Industry Organization 

This section examines the organization of the U.S. petroleum refining industry, including 

market structure, firm characteristics, plant location, and capacity utilization. Understanding the 

industry’s organization helps determine how it will be affected by new emissions standards. 

2.4.1 Market Structure 

Market structure characterizes the level 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 competitive, then individual producers cannot raise their 
2-17 

prices above the marginal cost of production without losing market share to their competitors. 

Understanding pricing behavior in the petroleum refining industry is crucial for performing 

subsequent EIAs. 

According to basic microeconomic theory, perfectly competitive industries are 

characterized by unrestricted entry and exit of firms, large numbers of firms, and undifferentiated 

(homogenous) products being sold. Conversely, imperfectly competitive industries or markets 

are characterized by barriers to entry and exit, a smaller number of firms, and differentiated 

products (resulting from either differences in product attributes or brand name recognition of 

products). This section considers whether the petroleum refining industry is competitive, based 

on these three factors. 

2.4.1.1 Barriers to Entry 

Firms wanting to enter the petroleum refining 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 refinery operations. This means that costs per unit 

fall as a refinery produces more finished petroleum products. As a result, new firms that must 

produce at relatively low levels will face higher average 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 difficult 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 government, that give exclusive monopoly to an inventor over his 

invention for a limited time period. In the petroleum refining industry, firms rely heavily on 

process patents to appropriate returns from their innovations. As a result, firms seeking to enter 

the petroleum refining industry must develop processes that respect the novelty requirements of 

these patents, which could potentially make entry more difficult for new firms (Langinier, 2004). 

A second example of a legal barrier would be environmental regulations that apply only to new 

entrants or new pollution sources. Such regulations 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 barriers is 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 potentially raise their prices above competitive levels 

with less worry about new firms entering the market to compete away their customers with lower 
2-18 

prices. It was not possible during this analysis to quantify how significant these barriers would be 

for new entrants or what effect they would have on market prices. However, existing firms 

would still face competition from each other. In an unconcentrated industry, competition among 

existing firms would work to keep prices at competitive levels. 

2.4.1.2 Measures of Industry Concentration 

Economists often use a variety of measures to assess the concentration of a given 

industry. Common measures include four-firm 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 reported for the petroleum refining industry (NAICS 324110) in Table 

2-6 for selected years between 1985 and 2007. 

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 occurred across the petroleum industry; 

13% of these mergers occurred in the industry’s refining and marketing segments (GAO, 2007). 

From 2000 to 2007 the HHI rose again. 

Unfortunately, there is no objective criterion for determining market structure based on 

the values of these concentration ratios. However, 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). According 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 considered moderately concentrated (i.e., 

moderately competitive); and industries with higher HHIs are considered heavily concentrated. 

Based on this criterion, the petroleum refining industry continues to be unconcentrated even in 

recent years. 

A more rigorous examination of market concentration was conducted in a 2004 Federal 

Trade Commission (FTC) staff study. This study explicitly accounted for the fact that a refinery 

in one geographic region may not exert competitive 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 during World War II to help manage 
2-19 

the allocation of fuels during wartime. However, they have remained in use as a convenient way 

of organizing petroleum market information (FTC, 2004). 

Table 2-6 Market Concentration Measures of the Petroleum Refining Industry: 1985 to 

2007 

Measure 1985 1990 1996 2000 2001 2002 2003 2007 

Herfindahl-Hirschmann Index 

(HHI) 

493 437 412 611 686 743 728 807 

Four-firm concentration ratio (CR4) 34.4 31.4 27.3 40.2 42.5 45.4 44.4 47.5 

Eight-firm concentration ratio 

(CR8) 

54.6 52.2 48.4 61.6 67.2 70.0 69.4 73.1 

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

Antitrust Enforcement.” Available at <http://www.ftc.gov/opa/2004/08/oilmergersrpt.shtm>. As obtained on 

February 6, 2007. 

 U.S. Census Bureau, American FactFinder; “Sector 31: Manufacturing: Subject Series: Concentration Ratios: 

Share of Value of Shipments Accounted for by the 4, 8, 20, and 50 Largest Companies for Industries: 2007 “ 

Release Date 1/7/2011; (Data accessed on 10/12/11) [Source for 2007 

numbers]<http://factfinder.census.gov/servlet/IBQTable?_bm=y&-ds_name=EC0731SR12&-

NAICS2007=324110&-ib_type=NAICS2007&-NAICS2007sector=*6&-industrySel=324110&-geo_id=&-

_industry=324110&-_lang=en> 

This study concluded that these geographic 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. Concentration in PADD IV (Rocky Mountains) was 

also low in 2003, with an HHI of 944. PADD V gradually 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). 

2.4.1.3 Product Differentiation 

Another way firms can influence market prices for their product is through product 

differentiation. By differentiating one’s product and using marketing to establish brand loyalty, 

manufacturers can raise their prices above marginal cost without losing market share to their 

competitors. 

While we saw in Section 2.3 that there are a wide variety of petroleum products with 

many different uses, individual petroleum products 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 role of product differentiation is probably quite 

small for many finished petroleum products. However, there are examples of relatively small 
2-20 

refining businesses producing specialty products for small niche markets. As a result, there may 

be some instances where product differentiation is important for price determination. 

2.4.1.4 Competition among Firms in the Petroleum Refining Industry 

Overall, the petroleum industry is characterized as producing largely generic products for 

sale in relatively unconcentrated markets. Although it is not possible to quantify how much 

barriers to entry and other factors will affect competition among firms, it seems unlikely that 

individual petroleum refiners would be able to significantly influence market prices given the 

current structure of the market. 

2.4.2 Characteristics of U.S. Petroleum Refineries and Petroleum Refining Companies 

A petroleum refinery is a facility where labor and capital are used to convert material 

inputs (such as crude oil and other materials) into finished petroleum products. Companies that 

own these facilities are legal business entities that conduct transactions and make decisions that 

affect the facility. The terms “facility,” “establishment,” and “refinery” are synonymous in this 

report 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 information on refineries, such as their location and 

capacity utilization, as well as financial data for the companies that own these refineries. 

2.4.2.1 Geographic Distribution of U.S. Petroleum Refineries 

There are approximately 148 petroleum refineries operating in the United States, spread 

across 32 states. The number of petroleum refineries located in each of these states is listed in 

Table 2-7. This table illustrates that a significant portion of petroleum refineries are located 

along the Gulf of Mexico region. The leading petroleum refining states are Texas, Louisiana, and 

California. 

2.4.2.2 Capacity Utilization 

Capacity utilization indicates how well current refineries meet demand. One measure of 

capacity utilization is capacity utilization rates. A capacity utilization rate is the ratio of actual

production volumes to full-capacity production volumes. 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 other hand, if under the same constraints 

the industry were only producing 75 percent of its maximum possible output, the capacity 

utilization rate would be 75 percent. On an industry-basis, capacity utilization is highly variable 

from year to year depending on economic conditions. It is also variable on a company-by-
2-21 

company basis depending not only on economic conditions, but also on a company’s strategic 

position in its particular industry. While some plants may have idle production lines or empty 

floor space, others need additional space or capacity. 

Table 2-8 lists the capacity utilization rates for petroleum refineries from 2000 to 2010. It 

is interesting to note the declines in capacity utilization from 2007 to 2008 and again from 2008 

to 2009. These declines seem counter intuitive because there does not appear to be evidence that 

demand for petroleum products is dropping. To understand this better, it is important to realize 

that the capacity utilization ratio in the petroleum industry represents the utilization of the 

atmospheric crude oil distillation units. This ratio is calculated for the petroleum industry by 

dividing the gross input to atmospheric crude oil distillation units (all inputs involved in 

atmospheric crude oil distillation, such as crude oil) by the industry’s operational capacity. 

 
2-22 

Table 2-7 Number of Petroleum Refineries, by State 

State Number of Petroleum Refineries 

Alabama 3 

Alaska 6 

Arkansas 2 

California 20 

Colorado 2 

Delaware 1 

Georgia 1 

Hawaii 2 

Illinois 4 

Indiana 2 

Kansas 3 

Kentucky 2 

Louisiana 19 

Michigan 1 

Minnesota 2 

Mississippi 3 

Montana 4 

Nevada 1 

New Jersey 5 

New Mexico 3 

North Dakota 1 

Ohio 4 

Oklahoma 6 

Pennsylvania 5 

Tennessee 1 

Texas 26 

Utah 5 

Virginia 1 

Washington 5 

West Virginia 1 

Wisconsin 1 

Wyoming 6 

Total 148 

Source: U.S. Energy Information Administration (EIA), Form EIA-820, “Annual Refinery Report. Table 1. Number 

and Capacity of Operable Petroleum Refineries by PAD District and State as of January 1, 2011” Release

Date: June 24, 2011; (Data accessed on 10/12/11). [Source for 2011 numbers.] 

http://www.eia.gov/petroleum/refinerycapacity/
2-23 

Table 2-8 Full Production Capacity Utilization 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 

2007 88.5 15,450 17,450 

2008 85.3 15,027 17,607 

2009 82.9 14,659 17,678 

2010 86.4 15,177 17,575 

Sources: U.S. Department of Energy, Energy Information 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. 

 U.S. Energy Information Administration (EIA), “Refinery Utilization and Capacity.” Available at 

http://www.eia.gov/dnav/pet/pet_pnp_unc_dcu_nus_a.htm; Release date: 7/28/11; (Data accessed on 

10/11/11). [Source for 2007-2010 numbers] 

From 2007 to 2008 operational capacity increased from 17,450,000 barrels per calendar 

day to 17,607,000 barrels per calendar day at the same time gross inputs fell from 15,450,000 

barrels per calendar day to 15,027,000 barrels per calendar day resulting in a 3.6 percent 

decrease in utilization. Similarly, from 2008 to 2009 operational capacity increased from 

17,607,000 barrels per calendar day to 17,678,000 barrels per calendar day at the same time 

gross inputs fell from 15,027,000 barrels per calendar day to 14,659,000 barrels per calendar day 

resulting in a 2.8 percent decrease in utilization.

2.4.2.3 Characteristics of Small Businesses Owning U.S. Petroleum Refineries 

Under Small Business Administration (SBA) regulations, a small refiner is defined as a 

refinery with no more than 1,500 employees.4

 For this analysis we applied the small refiner 

definition of a refinery with no more than 1,500 employees. For additional information on the 

Agency’s application of the definition for small refiner, see the June 24, 2008 Federal Register 

Notice for 40 CFR Part 60, Standards of Performance for Petroleum Refineries (Volume 73, 

Number 122, page 35858). 

As of January 2011, there were 148 petroleum refineries operating in the continental 

United States and US territories with a cumulative capacity of processing over 17 million barrels 

of crude per calendar day (EIA, 2011a). We identified 64 parent companies owning refineries in 

 

4

 See Table in 13 CFR 121.201, NAICS code 324110. 
2-24 

the United States and were able to collect employment and sales data for 61 (95%) of them. We 

were not able to collect employment and sales data for Ten By Inc., PBF Holdings LLC, and 

Northern Tier Energy LLC, representing 2.36% of refining capacity. 

The distribution of employment across companies is illustrated in Figure 2-6. As this 

figure shows, 36 companies (59% of the 61 total) employ fewer than 1,500 workers and would 

be considered small businesses. These firms earned an average of $1.36 billion of revenue per 

year, while firms employing more than 1,500 employees earned an average of $82.5 billion of 

revenue per year (Figure 2-7). Distributions of the number of large and small firms earning 

different levels of revenue are presented in Figures 2-8 and 2-9. 

Figure 2-6 Employment Distribution of Companies Owning Petroleum Refineries 

(N=61) 

Sources: Employment Data from Petroleum Refinery Emissions Information Collection, where available, 

Component 1, OMB Control No. 2060-0657. 

 Hoovers 2011 Online Data, accessed through University of South Carolina’s Moore School of Business 

Library. Hoovers 2011 Online Data reflects either actual data for 2010/2011 reported by companies, 

estimated data for 2011, or occasionally 2009 values. 

 Million Dollar Database online, 2011, accessed through University of South Carolina’s Moore School of

Business Library. Million Dollar Online Data reflects either actual data for 2011 reported by companies or 

estimated data for 2011. 

 Ward’s Business Directory of Public and Private Companies, 2011, accessed at James Branch Cabell 

Library (Virginia Commonwealth University). Ward’s Business Directory compiles financial data from 

several sources such as annual reports, company websites, and phone interviews. If financial data from

private companies is unavailable, Ward’s staff estimates the information. 

 Copyright 2011 Harte-Hanks Market Intelligence, Inc., All Rights Reserved. CI Technology Database, 

September 2011. 

14 firms

6 firms

9 firms

4 firms 3 firms

25 firms

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

<100 100-250 250-500 500-1,000 1,000-1,500 >1,500

Share of firms (%)

Number of Employees
2-25 

 Reference USA, accessed thru Jefferson Madison Regional Library, Charlottesville, Virginia. 

 Copyright 2011 Experian Information Solutions, Inc., Experian Business Reports accessed through 

LexisNexis at James Branch Cabell Library (Virginia Commonwealth University). Experian Business 

Reports reflects the most recent data reported by a company, which may be 2010 or 2011. 

 Global Duns Market Identifiers, accessed through LexisNexis at University of Virginia’s Alderman 

Library. 

Figure 2-7 Average Revenue of Companies Owning Petroleum Refineries by 

Employment (N=61) 

Sources: Employment Data from Petroleum Refinery Emissions Information Collection, where available, 

Component 1, OMB Control No. 2060-0657. 

 Hoovers 2011 Online Data, accessed through University of South Carolina’s Moore School of Business 

Library. Hoovers 2011 Online Data reflects either actual data for 2010/2011 reported by companies, 

estimated data for 2011, or occasionally 2009 values. 

 Million Dollar Database online, 2011, accessed through University of South Carolina’s Moore School of

Business Library. Million Dollar Online Data reflects either actual data for 2011 reported by companies or 

estimated data for 2011. 

 Ward’s Business Directory of Public and Private Companies, 2011, accessed at James Branch Cabell 

Library (Virginia Commonwealth University). Ward’s Business Directory compiles financial data from 

several sources such as annual reports, company websites, and phone interviews. If financial data from

private companies is unavailable, Ward’s staff estimates the information. 

 Copyright 2011 Harte-Hanks Market Intelligence, Inc., All Rights Reserved. CI Technology Database, 

September 2011. 

 Reference USA, accessed thru Jefferson Madison Regional Library, Charlottesville, Virginia. 

 Copyright 2011 Experian Information Solutions, Inc., Experian Business Reports accessed through 

LexisNexis at James Branch Cabell Library (Virginia Commonwealth University). Experian Business 

Reports reflects the most recent data reported by a company, which may be 2010 or 2011. 

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

<100 100-250 250-500 500-1,000 1,000-1,500 >1,500

Average revenue

($ millions)

Number of Employees
2-26 

 Global Duns Market Identifiers, accessed through LexisNexis at University of Virginia’s Alderman 

Library. 

Figure 2-8 Revenue Distribution of Large Companies Owning Petroleum Refineries 

(N=25) 

Sources: Employment Data from Petroleum Refinery Emissions Information Collection, where available, 

Component 1, OMB Control No. 2060-0657. 

 Hoovers 2011 Online Data, accessed through University of South Carolina’s Moore School of Business 

Library. Hoovers 2011 Online Data reflects either actual data for 2010/2011 reported by companies, 

estimated data for 2011, or occasionally 2009 values. 

 Million Dollar Database online, 2011, accessed through University of South Carolina’s Moore School of

Business Library. Million Dollar Online Data reflects either actual data for 2011 reported by companies or 

estimated data for 2011. 

 Ward’s Business Directory of Public and Private Companies, 2011, accessed at James Branch Cabell 

Library (Virginia Commonwealth University). Ward’s Business Directory compiles financial data from 

several sources such as annual reports, company websites, and phone interviews. If financial data from

private companies is unavailable, Ward’s staff estimates the information. 

 Copyright 2011 Harte-Hanks Market Intelligence, Inc., All Rights Reserved. CI Technology Database, 

September 2011. 

 Reference USA, accessed thru Jefferson Madison Regional Library, Charlottesville, Virginia. 

 Copyright 2011 Experian Information Solutions, Inc., Experian Business Reports accessed through 

LexisNexis at James Branch Cabell Library (Virginia Commonwealth University). Experian Business 

Reports reflects the most recent data reported by a company, which may be 2010 or 2011. 

 Global Duns Market Identifiers, accessed through LexisNexis at University of Virginia’s Alderman 

Library. 

1 firm 1 firm

23 firms

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

<5 5-10 10-50 50-100 100-500 500-1,000 >1,000

Revenue ($milllions)
2-27 

Figure 2-9 Revenue Distribution of Small Companies Owning Petroleum Refineries 

(N=36) 

Sources: Employment Data from Petroleum Refinery Emissions Information Collection, where available, 

Component 1, OMB Control No. 2060-0657. 

 Hoovers 2011 Online Data, accessed through University of South Carolina’s Moore School of Business 

Library. Hoovers 2011 Online Data reflects either actual data for 2010/2011 reported by companies, 

estimated data for 2011, or occasionally 2009 values. 

 Million Dollar Database online, 2011, accessed through University of South Carolina’s Moore School of

Business Library. Million Dollar Online Data reflects either actual data for 2011 reported by companies or 

estimated data for 2011. 

 Ward’s Business Directory of Public and Private Companies, 2011, accessed at James Branch Cabell 

Library (Virginia Commonwealth University). Ward’s Business Directory compiles financial data from 

several sources such as annual reports, company websites, and phone interviews. If financial data from

private companies is unavailable, Ward’s staff estimates the information. 

 Copyright 2011 Harte-Hanks Market Intelligence, Inc., All Rights Reserved. CI Technology Database, 

September 2011. 

 Reference USA, accessed thru Jefferson Madison Regional Library, Charlottesville, Virginia. 

 Copyright 2011 Experian Information Solutions, Inc., Experian Business Reports accessed through 

LexisNexis at James Branch Cabell Library (Virginia Commonwealth University). Experian Business 

Reports reflects the most recent data reported by a company, which may be 2010 or 2011. 

 Global Duns Market Identifiers, accessed through LexisNexis at University of Virginia’s Alderman 

Library. 

Employment, crude capacity, and location information are provided in Table 2-9 for each 

refinery owned by a parent company employing 1,500 employees or less. Similar information 

can be found for all 64 companies owning petroleum refineries in Appendix A. 

5 firms

1 firm

8 firms

2 firms

7 firms

4 firms

9 firms

0%

5%

10%

15%

20%

25%

30%

<5 5-10 10-50 50-100 100-500 500-1,000 >1,000

Revenue ($millions)
2-28 

In Section 2.4.2.1, we discussed how petroleum 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 refiners 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 competitive disadvantage by locating close to productconsuming areas to lower transportation costs and serving niche product 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, lubricants, and other products. A good example of a 

firm producing niche products is Calumet Specialty Product Partners. The firm produces both 

basic fuels like gasoline, diesel fuel and jet fuel and specialty products like lubricating oils, 

solvents, waxes, and other petroleum products. However, the firm’s specialty products unit is its 

largest unit (Hoovers, 2011 online). 

However, recent developments are making these factors less important for success in the 

industry. For example, the entry of new product pipelines is eroding the locational advantage of 

smaller refineries (FTC, 2004). This trend can possibly be illustrated by the fact that most 

refineries owned by small businesses tend to be located in relatively rural areas (see Table 2-9). 

The median population density of counties occupied by small refineries is 103 people per square 

mile. This could suggest that refineries do not rely on the population surrounding them to support 

their refining operations. 

 Capacity information for the 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 example, in 2006 29 small 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, lubricants, and petroleum 

coke. The remaining 79% was used to produce gasoline, kerosene, diesel fuel, and liquefied 

petroleum gases. Similarly, in 2011, approximately 20% of small businesses’ total capacity was 

dedicated to producing specialty products and 80% was dedicated to producing fuel products. 

As discussed in Section 2.4.1.3, 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. 
2-29 

2.5 Markets 

This section provides data on the volume of petroleum products produced and consumed 

in the United States, the quantity of products imported and exported, and the average prices of 

major petroleum products. The section concludes with a discussion of future trends for the 

petroleum refining industry. 

2.5.1 U.S. Petroleum Consumption 

Figure 2-10 illustrates the amount of petroleum products supplied between 2000 and 

2010 (measured in millions of barrels of oil). These data represent the approximate consumption 

of petroleum products because it measures the disappearance of these products from primary 

sources (i.e., refineries, natural gas processing plants, blending plants, pipelines, and bulk 

terminals). 
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-30 

Table 2-9 Characteristics of Small Businesses in the Petroleum Refining Industry 

Parent Company 

Parent 

Company 

Type 

Cumulative 

Crude 

Capacity 

(bbl/cd) 

Parent 

Company 

Employment 

(#) Facility Name 

Facility 

City 

Facilit

y State Facility County

Facility 

County 

Populatio

Density (20

AGE Refining, Inc. Private 14,021 124 AGE Refining Inc San Antonio TX Bexar County 1,117 American Refining Group, Inc. 

Private 10,000 323 American 

Refining Group Inc 

Bradford PA McKean County 47 

Calcasieu Refining Company Private 78,000 92 Calcasieu 

Refining Co. 

Lake Charles 

LA Calcasieu Parish 171 

Calumet Shreveport Lubricants and Waxes, LLC 

Public 57,000 654 Calumet 

Shreveport LLC 

Shreveport LA Caddo Parish 286 

Calumet Lubricants Company, L.P. 

Public 13,020 654 Calumet 

Lubricants Co LP 

Cotton Valley 

LA Caddo Parish 286 

Calumet Lubricants Company, L.P. 

Public 8,300 654 Calumet 

Lubricants Co LP 

Princeton LA Caddo Parish 286 

CHS, Inc. Public 59,600 287 Cenex Harvest 

States 

Laurel MT Yellowstone 

County 

49 

Calumet (Montana Refining Company) 

Public 10,000 170 Montana Refining 

Co. 

Great Falls MT Cascade County 30 

CVR Energy, Inc. Public 115,700 371 Coffeyville 

Resources LLC 

Coffeyville KS Montgomery 

County 

56 

Countrymark Cooperative Private 26,500 425 Countrymark 

Cooperative, Inc. 

Mt. Vernon IN Posey County 66 

Cross Oil Refining & Marketing, Inc. 

Private 7,500 110 Martin Midstream 

Partners LP 

Smackover AR Union County 44 

Deerfield Refining and Production Corp. 

Private 2,000 27 Foreland Refining 

Co. 

Ely NV White Pine 

County 

1 

Frontier Refining and Marketing 

Private 47,000 723 Frontier Refining 

Inc 

Cheyenne WY Laramie County 30 

Frontier Oil Corp. Private 138,000 723 Frontier El 

Dorado Refining Co 

El Dorado KS Butler County 42 
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-31 

Table 2-9. Characteristics of Small Businesses in the Petroleum Refining Industry (continued) 

Parent Company 

Parent 

Company 

Type 

Cumulative 

Crude 

Capacity 

(bbl/cd) 

Parent 

Company 

Employment 

(#) Facility Name 

Facility 

City 

Facilit

y State Facility County

Facility 

County 

Populatio

Density (20

CVR Refining (Wynnewood Refining Co.) 

Private 70,000 260 Wynnewood 

Refining Co. 

Wynnewood OK Garvin County 34 

Goodway Refining, LLC Private 4,100 17 Goodway 

Refining LLC 

Atmore AL Escambia 

County 

41 

Wood Cross Refining Company, LLC 

Public 25,050 1,321 Holly Refining & 

Marketing Co 

Woods Cross 

UT Davis County 785 

Holly Frontier Refinery Public 105,000 1,321 Navajo Refining 

Co. 

Artesia NM Eddy County 12 

Holly Refining & Marketing – Tulsa, LLC - East Plant 

Public 70,300 1,321 Holly Refining & 

Marketing Co 

Tulsa East OK Tulsa County 988 

Holly Refining & Marketing – Tulsa, LLC - West Plant 

Public 85,000 1,321 Holly Refining & 

Marketing Co 

Tulsa West OK Tulsa County 988 

Hunt Refining Co. Private 36,000 346 Hunt Refining Co. Tuscaloosa AL Tuscaloosa 

County 

125 

Hunt Southland Refining Co. Private 11,000 1,100 Hunt Southland 

Refining Co 

Sandersville MS Lamar County 79 

Kern Oil & Refining Co. Private 26,000 105 Kern Oil & 

Refining Co. 

Bakersfield CA Kern County 81 

Lion Oil Co. Private 75,000 350 Lion Oil Co. El Dorado AR Union County 44 National Cooperative Refinery Association 

Public 85,500 612 National 

Cooperative Refinery Association 

McPherson KS McPherson 

County 

33 

Pasadena Refining Systems Inc. 

Private 100,000 348 Pasadena Refining 

Systems Inc. 

Pasadena TX Harris County 1967 

Petro Star Inc. Private 19,700 400 Petro Star Inc. North Pole AK Fairbanks North 

Star 

11 

Petro Star Inc. Private 55,000 400 Petro Star Inc. Valdez AK Valdez Cordova 0.
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-32 

Table 2-9. Characteristics of Small Businesses in the Petroleum Refining Industry (continued) 

Parent Company 

Parent 

Company 

Type 

Cumulative 

Crude 

Capacity 

(bbl/cd) 

Parent 

Company 

Employment 

(#) Facility Name 

Facility 

City 

Facility 

State 

Facility 

County 

Facility 

County 

Populatio

Density (20

Placid Refining Private 57,000 207 Placid Refining 

Inc. 

Port Allen LA West Baton 

Rouge Parish 

113 

Kenneth Faite (San Joaquin) Private 15,000 108 San Joaquin 

Refining Co., Inc. 

Bakersfield CA Kern County 81 

Santa Maria Refining Company 

Private 9,500 47 Greka Energy Santa Maria CA Santa Barbara 

County 

146 

Somerset Oil Inc. Private 5,500 11 Somerset Energy

Refinery LLC 

Somerset KY Pulaski County 85 

US Oil & Refining Co. Private 38,800 182 US Oil & Refining 

Co. 

Tacoma WA Pierce County 417 

Ventura Refining & Transmission, LLC 

Private 12,000 37 Ventura Refining 

& Transmission LLC 

Thomas OK Custer County 27 

Western Refining Company, LP 

Public 122,000 636 Western Refining 

Company LP 

El Paso TX El Paso County 671 

Western Refining, Inc. Public 66,300 636 Western Refining 

Yorktown Inc 

Yorktown VA York County 533 

Western Refining, Inc. Public 16,800 636 Western Refining 

Southwest Inc 

Bloomfield NM San Juan 

County 

21 

Western Refining, Inc. Public 21,100 636 Western Refining 

Southwest Inc 

Gallup NM McKinley 

County 

14 

World Oil Marketing Co. Private 8,500 65 Lunday-Thagard 

Co. 

South Gate CA Los Angeles 

County 

2,344 

Wyoming Refining Co. Private 14,000 96 Wyoming 

Refining Co 

New Castle WY Weston County 3 

Total 1,614,091 8,454 

Sources: U.S. Census Bureau, American Fact Finder, “2010 Census Summary File 1 Population, Housing Units, Area & Density: 2010

100% Data 2010 Census” (Data accessed on 10/21/2011); http://factfinder2.census.gov/faces/tableservices/jsf/pages/productvi

 Hoovers 2011 Online Data, accessed through University of South Carolina’s Moore School of Business Library. Hoovers 201

either actual data for 2010/2011 reported by companies, estimated data for 2011, or occasionally 2009 values. 
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-33 

 Million Dollar Database online, 2011, accessed through University of South Carolina’s Moore School of Business Library. Mi

reflects either actual data for 2011 reported by companies or estimated data for 2011. 

 Ward’s Business Directory of Public and Private Companies, 2011, accessed at James Branch Cabell Library (Virginia Comm

Ward’s Business Directory compiles financial data from several sources such as annual reports, company websites, and phone data from private companies is unavailable, Ward’s staff estimates the information. 

 Copyright 2011 Harte-Hanks Market Intelligence, Inc., All Rights Reserved. CI Technology Database, September 2011.  Reference USA, accessed thru Jefferson Madison Regional Library, Charlottesville, Virginia.  Copyright 2011 Experian Information Solutions, Inc., Experian Business Reports accessed through LexisNexis at James Branc

(Virginia Commonwealth University). Experian Business Reports reflects the most recent data reported by a company, which 

 Global Duns Market Identifiers, accessed through LexisNexis at University of Virginia’s Alderman Library. 

 Employment Data from Petroleum Refinery Emissions Information Collection, where available, Component 1, OMB Control  Energy Information Administration (EIA), Form EIA 820, “Annual Refinery Report,” Table 3. Capacity of Operable Petroleum 

Individual Refinery as of January 1, 2011 <http://www.eia.gov/petroleum/refinerycapacity/> 
2-34 

Between 2000 and 2004, U.S. consumption of petroleum products increased by 5%. 

Consumption leveled off by 2007 and dropped by 9% between 2007 and 2009 (Figure 2-10). 

This reduced growth was primarily the result of less jet fuel, residual fuel, distillate fuel, and 

other products being consumed in recent years. Consumption of all petroleum products, except 

for motor gasoline, increased between 2009 and 2010, but the total consumption of petroleum 

products did not reach 2000-2004 levels. The cumulative decrease in consumption over the 11 

year period is 3% (Table 2-10). 

Figure 2-10 Total Petroleum Products Supplied (millions of barrels per year) 

Sources: U.S. Department of Energy. 2011 Energy Information Administration (EIA). 1996–2011. “Petroleum 

Supply Annuals, Volume 1.” (Data accessed on February 23, 2012) [Source for 2000–2010 numbers.] < 

http://www.eia.gov/dnav/pet/pet_cons_psup_dc_nus_mbbl_a.htm >. 

6,400

6,600

6,800

7,000

7,200

7,400

7,600

7,800

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Millions of barrels 

per year

Year
2-35 

Table 2-10 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 

2007 3,389 592 1,532 264 761 1,011 7,548 

2008 3,290 563 1,444 228 715 896 7,136 

2009 3,284 509 1,325 187 749 799 6,852 

2010 3,282 523 1,387 195 793 820 7,001 

Sources: 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. 

 U.S. Department of Energy. 2011 Energy Information Administration (EIA). 1996–2011. “Petroleum 

Supply Annuals, Volume 1.” (Data accessed on October 11, 2011) [Source for 2007–2010 numbers.] 

<http://www.eia.gov/dnav/pet/pet_sum_snd_d_nus_mbbl_a_cur.htm>. 

2.5.2 U.S. Petroleum Production 

Table 2-11 reports the number of barrels of major petroleum products produced in the 

United States between 2000 and 2010. U.S. production of petroleum products at refineries and 

blenders grew steadily, resulting in a 7% cumulative increase for the period. However, in 2005 

and 2009 production declined by slightly. 

Table 2-11 U.S. Refinery and Blender Net Production (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 

2007 3,051 528 1,509 246 239 464 6,568 

2008 3,129 546 1,572 227 230 950 6,641 

2009 3,207 510 1,478 218 227 1,418 6,527 

2010 3,306 517 1,542 213 240 1,747 6,735 

Sources: 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. 

 U.S. Department of Energy. 2011 Energy Information Administration (EIA). 1996–2011. “Petroleum 

Supply Annuals, Volume 1.” (Data accessed on October 7, 2011) [Source for 2007–2010 numbers.] 

<http://www.eia.gov/dnav/pet/pet_pnp_refp_dc_nus_mbbl_a.htm>. 
2-36 

 The 2005 decline in production (0.35%) was possibly the result of damage inflicted 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 Petroleum Institute, 

approximately 30% of the U.S. refining industry was shut down as a result of the damage (API, 

2006). The 2009 decline in production (1.72%) was probably the result of the global economic 

crisis. Additional production data are presented in Table 2-12, which reports the value of 

shipments of products produced by the petroleum refining industry between 1997 and 2009. 

2.5.3 International Trade 

International trade trends are shown in Tables 2-13 and 2-14. Between 1995 and 2006, 

imports and exports of petroleum products increased by 123% and 51% respectively. Between 

1995 and 2006, 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. More recently, between 2008 and 2010 exports of petroleum products such 

as motor gasoline, jet fuel, distillate fuel oil and liquefied petroleum gases have also increased. 

Since 2006, industry import and export trends have diverged significantly. Between 2006 

and 2010 imports declined by 28%, returning close to 2001 levels. In 2010, U.S. net imports 

were 98 million barrels, accounting for 10% of the country’s imports and around 1% of total 

petroleum products consumed in that year. Exports grew at an average annual rate of 12% and in 

2010 were 2.4 times the level of exports in 2001. 

In 2011, U.S. net imports of crude oil, based on a four-week average, ranged from 8,138 

to 9,474 thousand barrels per day. And while 2011 started out with the U.S. as a net importer of 

total petroleum products, from July 2011 through December 2011 the U.S. became a net exporter 

of total petroleum products. From July to December 2011, based on a four-week average, the 

U.S. exported an average of 405,000 barrels per day with a maximum of 809,000 barrels per day 

of total petroleum products (EIA 2012).5

 

5

 Data for 2011 located on the Energy Information Administration’s website at 

http://www.eia.gov/dnav/pet/pet_move_wkly_dc_NUS-Z00_mbblpd_4.htm. 
2-37 

Table 2-12 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 

2007 551,997 510,996 

2008 682,756 585,664 

2009 436,974 394,348 

Note: Numbers were adjusted for inflation using producer price index industry data for Total Manufacturing 

Industries (Table 2-16). 

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. 

 U.S. Department of Commerce, Bureau of the Census, FactFinder. 2011. 2009 Annual Survey of 

Manufactures. 1996–2011. Obtained through American Fact Finder Database. (Data accessed on October 

14, 2011.) [Source for 2007–2009 numbers] <http://factfinder.census.gov/servlet/ 

DatasetMainPageServlet?_lang=en&_ts=336651423017&_ds_name=AM0931GS101&_program=EAS>. 

Table 2-13 Imports of Major Petroleum Products (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 

2007 151 79 111 136 90 688 1,255 

2008 110 38 78 128 93 700 1,146 

2009 82 29 82 121 66 597 977 

2010 49 36 83 134 56 584 942 

Sources: 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. 
2-38 

 U.S. Department of Energy. 2011 Energy Information Administration (EIA). 1996–2011. “Petroleum 

Supply Annuals, Volume 1.” (Data accessed on October 7, 2011.) [Source for 2007–2010 numbers.] 

http://www.eia.gov/dnav/pet/pet_move_imp_dc_NUS-Z00_mbbl_a.htm

Table 2-14 Exports of Major Petroleum Products (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 

2007 46 15 98 120 21 213 513 

2008 63 22 193 130 25 216 649 

2009 71 25 214 152 36 224 723 

2010 108 31 239 148 48 270 843 

Sources: 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. 

 U.S. Department of Energy. 2011 Energy Information Administration (EIA). 1996–2011. “Petroleum 

Supply Annuals, Volume 1.” (Data accessed on October 7, 2011.) [Source for 2007–2010 numbers] 

<http://www.eia.gov/dnav/pet/pet_move_exp_dc_NUS-Z00_mbbl_a.htm>. 

2.5.4 Market Prices 

The average nominal prices of major petroleum products sold to end users are provided 

for selected years in Table 2-15.6

 As these data illustrate, nominal prices rose substantially 

between 2005 and 2008. In 2009 there was a drop in prices, resulting in a return to 2005 price 

levels for most products. In 2010 nominal prices increased. During the 2008–2010 period, the 

most volatile price was jet fuel price: it declined by 44% in 2009 and increased by 29% in 2010. 

 

 

6

 Sales to end users are those made directly to the consumer of the product. This includes bulk consumers, such as 

agriculture, industry, and utilities, as well as residential and commercial consumers. 
2-39 

Table 2-15 Average Price of Major Petroleum Products Sold to End Users (cents per 

gallon) 

Product 1995 2000 2005 2008 2009 2010 

Motor gasoline 76.5 110.6 183 278 189 230 

No. 1 distillate fuel 62.0 98.8 183 298 214 271 

No. 2 distillate fuel 56.0 93.4 178 314 184 232 

Jet fuel 54.0 89.9 174 305 170 220 

Residual fuel oil 39.2 60.2 105 196 134 171 

Note: Prices do not include taxes. 

Sources: 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. 

 U.S. Department of Energy. 2011 Energy Information Administration (EIA). 1996–2011. “Petroleum 

Supply Annuals, Volume 1.” (Data accessed on October 7, 2011.) [Source for 2007–2010 

numbers.]<http://www.eia.gov/dnav/pet/pet_pri_refoth_dcu_nus_a.htm>. 

The nominal prices domestic petroleum refiners receive for their products have been 

volatile, especially compared to prices received by other U.S. manufacturers. This trend is 

demonstrated in Table 2-16 by comparing the producer price index (PPI) for the petroleum 

refining industry against the index for all manufacturing industries. Between 1995 and 2010, prices 

received by petroleum refineries for their products rose by 288%, while prices received by all 

manufacturing firms rose by 41%. In 2009, both price indexes experienced a decline from 2008 

levels, however the decrease was 36% for petroleum refineries and 5% for all manufacturing firms. 

 
2-40 

Table 2-16 Producer Price Index Industry Data: 1995 to 2010 

 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% 

2007 266.9 11% 162.9 4% 

2008 338.3 27% 175.8 8% 

2009 217.0 −36% 167.1 −5% 

2010 289.4 33% 175.4 5% 

Sources: U.S. Bureau of Labor Statistics (BLS). 2007. “Producer Price Index Industry Data: Customizable Industry 

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

 U.S. Bureau of Labor Statistics (BLS). 2011. “Producer Price Index Industry Data: Customizable Industry 

Data Tables.” (Data accessed on October 11, 2011.) [Source for 2007–2010 

numbers]<http://data.bls.gov/cgi-bin/dsrv?pc>. 

2.5.5 Profitability of Petroleum Refineries 

Estimates of the mean profit (before taxes) to net sales ratios for petroleum refiners are 

reported in Table 2-17 for the 2006–2007 and 2009-2010 fiscal years. These ratios were 

calculated by Risk Management Associates by dividing net income into revenues for 44 firms for 

the 2006-2007 fiscal year and 43 firms for the 2009-2010 fiscal year. They are broken down 

based on the value of assets owned by the reporting firms. 

 
2-41 

Table 2-17 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 

4/1/2009–

3/31/2010 

43 — — 5.5 — — — 4.1 

Sources: Old Source: Risk Management Association (RMA). 2008. Annual Statement Studies 2007–2008. 

Pennsylvania: RMA, Inc. 

 New Source: Risk Management Association (RMA). 2011. Annual Statement Studies 2010–2011. 

Pennsylvania: RMA, Inc. 

As these ratios demonstrate, firms that reported a greater value of assets also received a 

greater return on sales. For example, for the 2006–2007 fiscal year, firms with assets valued 

between $10 and $50 million received a 6.5% average return on net sales, while firms with assets 

valued between $2 and $10 million only received a 4.6% average return. Firms with assets 

valued between $2 and 10 million received 5.5% average return between 2009 and 2010. The 

data for other asset size categories is not shown for the fiscal year 2009–2010 because RMA 

received fewer than 10 financial statements in those categories and RMA does not consider those 

samples to be representative. The average return on sales for the entire industry was 6.7% during 

the 2006–2007 fiscal year and declined to 4.1% during the 2009–2010 fiscal year. 

Obtaining profitability information specifically for small petroleum refining companies 

can be difficult as most of these firms are privately owned. However, some of the small, 

domestic petroleum refining firms identified in Section 3.4.2.3 are publicly owned companies— 

CVR Energy Inc., Calumet Specialty Products Partners, L.P., Holly Corporation, and Western 

Refining, Inc. Profit ratios were calculated for these companies using data obtained from their 

publicly available 2010 income statements. These ratios are presented in Table 2-18. 

 
2-42 

Table 2-18 Net Profit Margins for Publicly Owned, Small Petroleum Refiners: 2010 

Company 

Net Income 

($millions) 

Total Revenue 

($millions) 

Net Profit Margin 

(%) 

Calumet Specialty Products Partners 16.70 2,190.80 0.76% 

CVR Energy Inc. 14.30 4,079.80 0.35% 

Holly Corporation 133.10 8,323.00 1.60% 

Western Refining, Inc. −17.05 7,965.10 −0.21% 

Sources: Holly Corporation, EDGAR database Holly Corporation 10K. February 25, 2011. 10K for year ended 

December 31, 2010. (Data accessed on 10/23/11) [Source for 2010 numbers.] 

http://files.shareholder.com/downloads/FTO/1428853845x0xS950123-11-18524/48039/filing.pdf> 

 Western Refining, Thomson Reuters Western Refining, Inc. 10K. March 8, 2011. 10K for year ended 

December 31, 2010. (Data accessed on 10/23/11) [Source for 2010 numbers.] http://phx.corporateir.net/phoenix.zhtml?c=194293&p=irol-sec> 

 Calumet Specialty Products Partners, Morningstar for Calumet Specialty Products Partners 10K. February 

22, 2011. 10K for year ended December 31, 2010. (Data accessed on 10/21/11) [Source for 2010 numbers.]

http://quote.morningstar.com/stock-filing/Annual-Report/2010/12/31/t.aspx?t=XNAS:CLMT&ft=10-

K&d=c7dd2813722445ded56c7e3aefebf2ca> 

 CVR Energy Inc., EDGAR database for CVR Energy Inc. 10K. March 7, 2011. 10K for year ended 

December 31, 2010. (Data accessed on 10/23/11) [Source for 2010 numbers.] 

<http://www.sec.gov/Archives/edgar/data/1376139/000095012311022741/y90110e10vk.htm> 

2.5.6 Industry Trends 

The Energy Information Administration’s (EIA’s) 2011 Annual Energy Outlook provides 

forecasts of average petroleum prices, petroleum product consumption, and petroleum refining 

capacity utilization to the year 2035. Trends in these variables 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 policy decisions. As a result, the EIA evaluated a 

wide variety of cases based on different assumptions of how these factors will behave in the 

future. This section focuses on the EIA’s “reference case” forecasts, which assume that current 

policies affecting the energy sector will remain unchanged throughout the projection period 

(EIA, Form EIA-820). 

According to the 2011 Annual Energy Outlook’s reference forecast, world oil prices 

(defined as the average price of low-sulfur, light crude oil) are expected to steadily increase over 

the next 10 years as the amount of oil demanded by non-OECD and OECD countries increases. 

Since crude oil is the primary input in petroleum refining, an increase in its price would likewise 

represent an increase in production costs of petroleum refiners. As a result, the prices of 

petroleum products sold to end users are expected to rise over the same period (Table 2-19). 

Higher prices and tighter fuel efficiency standards (enlarged production of non-oil fuels) will 

moderate the growth in petroleum products consumed by the recovering US economy (Table 2-

20). Between 2011 and 2019, the prices of major petroleum products are expected to rise 
2-43 

approximately from 32% to 49%, while consumption of all of those products is expected to rise 

by 7%. In particular the price of the most supplied product, motor gasoline, is projected to rise 

by 38% and its consumption is projected to slightly increase by 2%. 

Table 2-19 Forecasted Average Price of Major Petroleum Products Sold to End Users in 

2009 Currency (cents per gallon) 

Product 2011 2012 2013 2014 2015 2016 2017 2018 2019 

Motor gasoline 286.1 291.3 312.3 326.9 342.1 353.6 369.5 382.9 395.5 

Jet fuel 233.0 252.2 261.8 270.4 280.3 297.9 314.5 330.8 346.1 

Distillate fuel 302.6 289.8 301.9 313.9 326.9 345.8 364.1 382.3 400.4 

Residual fuel oil 186.2 183.1 191.3 202.9 213.6 225.9 236.8 249.1 259.9 

LPGs 178.9 180.5 186.7 193.6 200.4 208 217 226.2 235.4 

Sources: U.S. Department of Energy, Energy Information Administration (EIA). 2007c. “Annual Energy Outlook.” 

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

2007. 

 U.S. Department of Energy, Energy Information Administration (EIA). 2011. “Annual Energy Outlook.”; 

(Data accessed on October 11, 2011) [Source for 2011–2019 numbers.] 

<http://www.eia.gov/forecasts/aeo/pdf/0383(2011).pdf>. 

Table 2-20 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 

2011 3,317 515 1,367 199 768 806 6,972 

2012 3,407 554 1,451 219 823 838 7,291 

2013 3,424 555 1,501 218 835 866 7,400 

2014 3,429 560 1,501 216 843 876 7,425 

2015 3,432 564 1,509 217 848 888 7,459 

2016 3,438 569 1,524 217 850 891 7,490 

2017 3,416 575 1,538 218 850 891 7,487 

2018 3,392 580 1,550 218 850 881 7,472 

2019 3,371 585 1,563 218 850 876 7,463 

Sources: U.S. Department of Energy, Energy Information Administration (EIA). 2007c. “Annual Energy Outlook.” 

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

2007. 

 U.S. Department of Energy, Energy Information Administration (EIA). 2011. “Annual Energy Outlook.”; 

(Data accessed on October 11, 2011) [Source for 2016–2019 numbers.] 

<http://www.eia.gov/forecasts/aeo/pdf/0383(2011).pdf>. 

Overall, the EIA forecasts that U.S. operational capacity will decrease by a total of 5% 

between 2011 and 2019 (Table 2-21). The rate of capacity utilization is projected to average 86% 

during this period. 
2-44 

Table 2-21 Full Production Capacity Utilization 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)7

Operational Capacity 

(1,000s of barrels per day) 

2011 85.0% 14,946 17,583 

2012 83.2% 14,672 17,635 

2013 84.2% 14,836 17,626 

2014 84.7% 14,851 17,524 

2015 84.9% 14,847 17,497 

2016 85.6% 14,853 17,342 

2017 86.5% 14,827 17,142 

2018 87.5% 14,778 16,887 

2019 88.2% 14,743 16,706 

Sources: U.S. Department of Energy, Energy Information Administration (EIA). 2007c. “Annual Energy Outlook.” 

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

2007. 

 U.S. Department of Energy, Energy Information Administration (EIA). 2011. ”Annual Energy Outlook.”; 

(Data accessed on February 23, 2012) [Source for 2011–2019 numbers.] < Capacity utilization -- 

http://www.eia.gov/oiaf/aeo/tablebrowser/#release=AEO2011&subject=0-AEO2011&table=11-

AEO2011®ion=0-0&cases=ref2011-d020911a and Domestic Refinery Distillation Capacity -- 

http://www.eia.gov/forecasts/aeo/excel/aeotab_11.xls>. 

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Arizona Clean Fuels. 2007. Company Home Page. Available at 

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Calumet Specialty Products Partners, Morningstar for Calumet Specialty Products Partners 10K. 

February 22, 2011. 10K for year ended December 31, 2010. (Data accessed on 10/21/11) 

[Source for 2010 numbers.] <http://quote.morningstar.com/stock-filing/AnnualReport/2010/12/31/t.aspx?t=XNAS:CLMT&ft=10-

K&d=c7dd2813722445ded56c7e3aefebf2ca> 

Calumet Specialty Products Partners. February 23, 2007. 10K for year ended December 31, 

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1340122/000095013407003992/h43776e10vk.htm>. 

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through LexisNexis at James Branch Cabell Library (Virginia Commonwealth 

University). 

 

7

 For each year, the gross input to atmospheric crude oil distillation units is calculated by multiplying the capacity 

utilization rate by the operational capacity. 
2-45 

Copyright 2011 Harte-Hanks Market Intelligence, Inc., All Rights Reserved. CI Technology 

Database, September 2011. 

CVR Energy Inc. 2006. Google Finance. Available at 

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reported by companies or estimated data for 2011. 
2-46 

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U.S. Bureau of Labor Statistics (BLS). 2007. “Producer Price Index Industry Data: Customizable 

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2-48 

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Manufacturers. M05(AS)-1. Washington, DC: Government Printing Office. Available at 

<http://www.census.gov/prod/2005pubs/am0431gs1.pdf>. As obtained on October 23, 

2006. 

U.S. Department of Commerce, Bureau of the Census. 2007. 2006 Annual Survey of 

Manufacturers. Obtained through American Fact Finder Database 

<http://factfinder.census.gov/home/saff/main.html?_lang=en>. 

U.S. Department of Energy, Energy Information Administration (EIA). 2012. “Petroleum & 

Other Liquids, Weekly Imports & Exports.” 

<http://www.eia.gov/dnav/pet/pet_move_wkly_dc_NUS-Z00_mbblpd_4.htm>. 

U.S. Department of Energy, 2011 Energy Information Administration (EIA). 1996–2011. 

“Petroleum Supply Annuals, Volume 1.” (Data accessed on October 7, 2011) [Source for 

2007–2010 numbers.] <http://www.eia.gov/dnav/pet/pet_sum_snd_d_nus_ 

mbbl_a_cur.htm>. 

U.S. Department of Energy, 2011 Energy Information Administration (EIA). 1996–2011. 

“Petroleum Supply Annuals, Volume 1.” (Data accessed on October 7, 2011) [Source for 

2007–2010 numbers.] <http://www.eia.gov/dnav/pet/pet_pnp_refp_dc_nus_ 

mbbl_a.htm>. 
2-49 

U.S. Department of Energy, 2011 Energy Information Administration (EIA). 1996–2011. 

“Petroleum Supply Annuals, Volume 1.” (Data accessed on October 7, 2011.) [Source for 

2007–2010 numbers.] <http://www.eia.gov/dnav/pet/pet_move_imp_dc_NUSZ00_mbbl_a.htm> 

U.S. Department of Energy, 2011 Energy Information Administration (EIA). 1996–2011. 

“Petroleum Supply Annuals, Volume 1.” (Data accessed on October 7, 2011.) [Source for 

2007–2010 numbers] <http://www.eia.gov/dnav/pet/pet_move_exp_dc_NUSZ00_mbbl_a.htm>. 

U.S. Department of Energy, 2011 Energy Information Administration (EIA). 1996–2011. 

“Petroleum Supply Annuals, Volume 1.” (Data accessed on October 7, 2011.) [Source for 

2007–2010 numbers.]<http://www.eia.gov/dnav/pet/pet_pri_refoth_dcu_nus_a.htm>. 

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. 

U.S. Department of Energy, Energy Information 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). Available at <http://tonto.eia.doe.gov/ 

FTPROOT/petroleum/054599.pdf>. As obtained on October 23, 2006. 

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. 

U.S. Department of Energy, Energy Information Administration (EIA). 2006c. “Petroleum 

Supply Annual 2005, Volume 1.” Available at <http://www.eia.doe.gov/pub/oil_gas/ 

petroleum/data_publications/petroleum_supply_annual/psa_volume1/historical/2005/psa

_volume1_2005.html>. As obtained on October 31, 2007. 

U.S. Department of Energy, Energy Information 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 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. 

U.S. Department of Energy, Energy Information Administration (EIA). 2007c. “Annual Energy 

Outlook.” Available at <http://www.eia.doe.gov/oiaf/archive/aeo07/pdf/0383(2007).pdf>. 

As obtained on January 21, 2007. 
2-50 

U.S. Department of Energy, Energy Information Administration (EIA). 2010. “Petroleum Supply 

Annual 2010, Volume 1.” Available at 

http://www.eia.gov/petroleum/supply/annual/volume1/archive/2010/pdf/table15.pdf. 

U.S. Department of Energy, Energy Information Administration (EIA). 2011, “Annual Energy 

Outlook.” (Data accessed on October 11, 2011) [Source for 2011–2019 

numbers.]<http://www.eia.gov/forecasts/aeo/pdf/0383(2011).pdf>. 

U.S. Department of Justice and the Federal 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 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. Energy Information Administration (EIA), 2011a. “Refinery Utilization and Capacity.” 

Available at http://www.eia.gov/dnav/pet/pet_pnp_unc_dcu_nus_a.htm; Release date: 

7/28/11; (Data accessed on 10/11/11). [Source for 2007–2010 numbers] 

U.S. Energy Information Administration (EIA), Form EIA-820, “Annual Refinery Report. Table 

1. Number and Capacity of Operable Petroleum Refineries by PAD District and State as 

of January 1, 2011” Release Date: June 24, 2011; (Data accessed on 10/12/11). [Source 

for 2011 numbers.] <http://www.eia.gov/petroleum/refinerycapacity/> 

U.S. Environmental Protection Agency. 1995. “EPA Office of Compliance Sector Notebook 

Project: Profile of the Petroleum Refining 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. “Proposed MHA Nation Clean Fuels Refinery.” 

Available at <http://www.epa.gov/Region8/compliance/nepa/refinerydeis.html>. As 

obtained on February 6, 2007. 

Ward’s Business Directory of Public and Private Companies, 2011, accessed at James Branch 

Cabell Library (Virginia Commonwealth University). 

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>. 

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ended December 31, 2010. (Data accessed on 10/23/11) [Source for 2010 numbers.] 

<http://phx.corporate-ir.net/phoenix.zhtml?c=194293&p=irol-sec> 
3-1 

3 EMISSIONS AND ENGINEERING COSTS 

3.1 Introduction 

The emissions standards that are the subject of the proposed rulemaking include: (1) 

National Emission Standards for Hazardous Air Pollutants from Petroleum Refineries (40 CFR 

part 63, subpart CC) (Refinery MACT 1); (2) National Emission Standards for Hazardous Air 

Pollutants for Petroleum Refineries: Catalytic Cracking Units, Catalytic Reforming Units, and 

Sulfur Recovery Units (40 CFR part 63, subpart UUU) (Refinery MACT 2); (3) Standards of 

Performance for Petroleum Refineries (40 CFR part 60, subpart J) (Refinery NSPS J); and (4) 

Standards of Performance for Petroleum Refineries for which Construction, Reconstruction, or 

Modification Commenced After May 14, 2007 (40 CFR part 60, subpart Ja) (Refinery NSPS Ja). 

The sources or processes affected by amendments to these standards include storage vessels, 

delayed coking units, and fugitive emissions subject to Refinery MACT 1. The proposed 

amendments also reflect requirements to ensure compliance, including flare monitoring and 

operational requirements, requirements for relief valve monitoring, and PM emissions source 

performance tests for the fluid catalytic cracking units (FCCUs) at existing sources (Refinery 

MACT 2). In addition, these proposed amendments address technical corrections and 

clarifications raised in a 2008 industry petition for reconsideration applicable to Refinery NSPS 

Ja.8

 These technical corrections and clarifications are addressed in this proposal because they 

also affect sources subject to the proposed amendments to Refinery MACT 1 and 2. 

In this section, we provide an overview of the engineering cost analysis used to estimate 

the additional private expenditures industry may make in order to comply with the following 

portions of the proposed rule amendments: 

• For storage vessels, require fitting controls on slotted guidepoles and un-slotted guidepoles, 

as well as fittings for other openings on affected floating roof storage vessels. 

• Work practice standards for the delayed coking units (DCU). 

• New work practice requirements for fugitive emissions sources, which include establishing a 

fenceline concentration, conducting fenceline monitoring, and requiring corrective actions if 

 

8

 The Refinery NSPS J was amended in 2008, following a review of the NSPS. As part of the review, EPA 

developed separate standards of performance for new process units (NSPS Ja). 
3-2 

the fenceline monitoring results indicate that benzene concentrations exceed a specific 

concentration action level. 

• Relief valve monitoring using a system that is capable of identifying and recording the time 

and duration of each pressure release and of notifying operators that a pressure release has 

occurred. 

• Operating and monitoring requirements for refinery flares used as control devices in refinery 

MACT 1 and 2 to ensure flares are meeting the emissions limits required by the refinery 

MACT standards. Owners or operators of flares used as a control device are required to 

monitor at least one of the following parameters in the flare vent gas: (1) net heating value; 

(2) lower flammability limit; and/or (3) total volumetric fraction of combustible components 

present. For flares using steam- or air-assist, monitoring of steam- and/or air-assist rates is 

also required to determine compliance with the operating limits. 

• PM emissions testing requirements for FCCUs consistent with Refinery NSPS Ja. 

For additional discussion of the proposed amendments, see Section IV.A. What actions are we 

taking pursuant to CAA sections 112(d)(2) and 112(d)(3)?of the proposed rule preamble. 

3.2 Summary of Proposed Rule Amendments 

3.2.1 Storage Vessels 

Storage vessels, also referred to as storage tanks, are used to store liquid and gaseous 

feedstocks for use in a process, as well as liquid and gaseous products coming from a process. 

Most storage vessels are designed for operation at atmospheric or near atmospheric pressures. 

High-pressure vessels are used to store compressed gases and liquefied gases. In the engineering 

cost analysis, fitting controls and monitoring options were identified as developments in 

practices, processes and control technologies for storage vessels. Emission reduction options 

identified include: (1) Option 1 -- requiring guidepole controls and other fitting controls for 

existing external or internal floating roof tanks as required in the Generic MACT for storage 

vessels (40 CFR part 63, subpart WW) in 40 CFR 63.1063; (2) Option 2 -- Option 1 plus 

revising the definition of Group 1 storage vessel to include smaller capacity storage vessels 

and/or storage vessels containing materials with lower vapor pressures; and (3) Option 3 -- 

Option 2 plus requiring additional monitoring to prevent roof landings, liquid level overfills and 
3-3 

to identify leaking vents and fittings from tanks. Options 1 and 2 were identified as 

developments in practices, processes and control technologies because these options are required 

for similar tanks in some chemical manufacturing MACT standards and are considered 

technologically feasible for storage vessels at refineries. Option 3 is also an improvement in 

practices because these monitoring methods have been required for refineries by other regulatory 

agencies. 

 Based on the engineering cost analysis, Option 2 was considered to be cost effective and 

is included in the proposal to revise Refinery MACT 1; the proposal will cross-reference the 

corresponding storage vessels requirements in the Generic MACT and revise the definition of 

Group 1 storage vessels.9

 Table 3-1 includes a summary of option costs. The annualized cost of 

capital estimates were determined based on a 7 percent interest rate. The storage vessel-related 

capital costs were annualized over 15 years. As the storage vessel controls do not require 

significant on-going operating and maintenance costs, the annualized costs of capital is the 

primary cost for the storage vessel controls. For further details on the assumptions and 

methodologies used in this analysis, see the technical memorandum titled Impacts for Control 

Options for Storage Vessels at Petroleum Refineries, Revised November 14, 2012, in Docket ID 

Number EPA-HQ-OAR-2010-0682. 

In addition, negative annualized costs, or recovery credits, were estimated as part of the 

storage vessel control option. For storage vessels, if a product storage tank has fewer VOC 

emissions, then there will be more product remaining in the tank that can be sold. The product 

recovery credit is based on the VOC emissions reductions projected to be achieved at each 

specific refinery. For storage vessels, these emissions reductions are based on the types and 

number of tanks present at each refinery, the types of controls currently used for each tank, and 

the average vapor pressure of the liquid stored. Negative annualized costs introduce the question 

of why, if these emissions can be reduced profitably using environmental controls, are more 

producers not adopting the controls in their own economic self-interest. Assuming financially 

rational producers, standard economic theory suggests that all refineries would incorporate all 

cost-effective improvements, of which they are aware, without government intervention. This 

 

9

 The proposed revised definition will include (1) storage vessels with capacities greater than or equal to 20,000 

gallons, but less than 40,000 gallons if the maximum true vapor pressure is 1.9 psia or greater and (2) storage 

tanks greater than 40,000 gallons if the maximum true vapor pressure is 0.75 psia or greater. 
3-4 

cost analysis is based on the observation that emissions reductions that appear to be profitable, 

on average, in the analysis have not been adopted by a significant segment of the industry. This 

observation, often termed the “energy paradox”, has been noted to occur in other contexts where 

consumers and firms appear to undervalue a wide range of investments in energy conservation, 

even when they pay off over relatively short time periods. We discuss some possible 

explanations for the apparent paradox in the context of the storage vessel requirements in this 

proposal. 

First, there may be an opportunity cost associated with the installation of environmental 

controls (for purposes of mitigating the emissions of pollutants) that is not reflected in the 

control costs. In the event that the environmental investment displaces other investment in 

productive capital, the difference between the rate of return on the marginal investment displaced 

by the mandatory environmental investment is a measure of the opportunity cost of the 

environmental requirement to the regulated entity. However, if firms are not capital constrained, 

there may not be any displacement of investment, and the rate of return on other investments in 

the industry would not be relevant as a measure of opportunity cost. If firms should face higher 

borrowing costs as they take on more debt, there may be an additional opportunity cost to the 

firm. To the extent that any opportunity costs are not added to the control costs, the compliance 

costs presented above may be underestimated. 

A second explanation could be that the average impacts identified in this analysis are not 

reflective of the true costs compelled by the regulation relative to the controls installed 

voluntarily. A third explanation for why there appear to be negative cost control technologies 

that are not generally adopted is imperfect information. If emissions from the refining sector are 

not well understood, firms may underestimate the potential financial returns to capturing 

emissions. Finally, the cost from the irreversibility associated with implementing these 

environmental controls is not reflected in the engineering cost estimates above. It is important to 

recognize the value of flexibility taken away from firms when requiring them to install and use a 

particular emissions capture technology. If a firm has not adopted the technology on its own, 

then a regulation mandating its use means the firm loses the option to postpone investment in the 

technology in order to pursue alternative investments today, and the option to suspend use of the 

technology if it becomes unprofitable in the future. Therefore, the full cost of the regulation to 

the firm is the engineering cost and the lost option value minus the revenues from the sale of the 
3-5 

additional recovered product. In the absence of quantitative estimates of this option, the cost 

estimates for the storage vessel controls may underestimate the full costs faced by the affected 

firms. 

Table 3-1 Nationwide Emissions Reduction and Cost Impacts of Control Options for 

Storage Vessels at Petroleum Refineries 

Control Option

Total 

Capital 

Investment 

(million 

2009$) 

Total 

Annualized 

Costs w/o 

Recovery 

Credits 

(million 

$/yr) 

Recovery 

Credits 

(million 

$/yr) 

Total Annualized Costs w/ 

VOC Recovery 

Credits 

(million $/yr) 

Emissions 

Reductions, 

VOC (tpy) 

Emissions 

Reductions, 

HAP (tpy) 

Overall Cost 

Effectiveness 

with VOC 

Recovery Credit 

($/ton HAP) 

1 11.9 1.8 (6.6) (4.8) 11,800 720 (6,690) 

2 -- Proposed 

Option 18.5 3.1 (8.2) (5.1) 14,600 910 (5,530) 

3 36.4 9.6 (9.1) 0.56 16,000 1,000 560 

3.2.2 Delayed Coking Units 

 DCUs use thermal cracking to upgrade heavy feedstocks and to produce petroleum coke. 

Unlike most other refinery operations, which are continuous, DCUs are operated in a semi-batch 

system. Most DCUs consist of a large process heater, two or more coking drums, and a single 

product distillation column. Bottoms from the distillation column are heated to near cracking 

temperatures and the heavy oil is fed to one of the coking drums. As the cracking reactions 

occur, coke is produced in the drum and begins to fill the drum with sponge-like solid coke 

material. When one coking drum is filled, the feed is diverted to the second coke drum. The full 

coke drum is purged and cooled by adding steam and water to the vessel. The initial water added 

to the vessel quickly turns to steam, and the steam helps to cool and purge organics in the coke 

matrix. After the coke drum is sufficiently cooled and filled with water in sufficient volumes to 

cover the coke, the drum is opened, the water drained, and the coke is removed from the vessel 

using high pressure water. Once the coke is cut out of the drum, the drum is closed, and 

prepared to go back on-line. A typical coke drum cycle is typically 28 to 36 hours from start of 

feed to start of feed. 

 During the reaction process, the DCU is a closed system. When the coke drum is taken 

off line, the initial steaming process gas is also recovered through the unit’s product distillation 

column. As the cooling cycle continues, the produced steam is sent to a blowdown system to 
3-6 

recover the liquids. Refinery MACT 1 standards (40 CFR part 63, subpart CC) define the 

releases to the blowdown system as the delayed coker vent and these emissions must be 

controlled following the requirements for miscellaneous process vents. Near the end of the 

cooling process, a vent is opened on the drum to allow the remaining steam and vapors to be 

released directly to the atmosphere prior to draining, deheading, and decoking (coke cutting) the 

coke from the drum. Emissions from DCU occur during this depressuring (commonly referred 

to as the steam vent) and subsequent decoking steps. 

Establishing a lower pressure set point at which a DCU owner or operator can switch 

from venting to an enclosed blowdown system to venting to the atmosphere is the primary 

control technique identified for reducing emissions from delayed coking operations. Essentially, 

there is a fixed quantity of steam that will be generated as the coke drum and its contents cool. 

The lower pressure set point will require the DCU to vent to the closed blowdown system longer, 

where emissions can be recovered or controlled. This will result in fewer emissions released 

during the venting, draining and deheading process.

Refinery NSPS Ja establishes a pressure limit of 5 psig prior to allowing the coke drum to 

be vented to the atmosphere. Based on a review of permit limits and consent decrees, EPA 

found that coke drum vessel pressure limits have been established and achieved as low as 2 psig. 

Based on the 2011 ICR responses, there are 75 operating DCU, indicating that the sixth 

percentile is represented by the fifth-best performing DCU. EPA researched permits, consent 

decrees, refinery ICR responses, and other rules addressing DCU depressurizing limits. Out of 

the 75 DCU, EPA identified at least 27 DCU that either currently operate or are required to 

operate by venting to the atmosphere only after the coke drum vessel pressure has reached 2 psig 

or less. See Table 2 of the September 12, 2013 Impact Estimates for Delayed Coking Units 

memorandum for more details on these DCU. To be in compliance with their permit limits, the 

best-performing sources must be able to depressurize at 2 psig or less at all times. Therefore, the 

MACT floor for DCU decoking operations is to depressure at 2 psig or less prior to venting to 

the atmosphere for both new and existing sources. 

 EPA also considered control options beyond the floor level of 2 psig to determine if 

additional emissions reductions could be cost effectively achieved. EPA considered a control 

option that allowed atmospheric venting only after the DCU vessel pressure reached 1 psig or 
3-7 

less, since some facilities reported in the 2011 ICR depressurizing to that level prior to venting. 

EPA determined that there are several technical difficulties associated with establishing a 

pressure limit at this lower level. EPA also considered whether there were means to connect the 

bottom of the coke drum to a large diameter “hose” so that the drained water and/or the coke 

cutting slurry could be discharged from the DCU and enter the coke pit in a submerged fill 

manner. However, EPA could identify no commercially available equipment to connect the coke 

drum to the coke pit. Because these options were either not technically feasible or equipment 

was not commercially available, EPA did not estimate costs. 

 For existing sources, EPA assumed all DCU that reported a “typical drum pressure prior 

to venting” of more than 2 psig would install and operate a steam ejector system to reduce the 

coke drum pressure to 2 psig prior to venting to atmosphere or draining. The operating costs of 

the steam ejector system are offset, to some extent, by the additional recovered vapors. Vapors 

from the additional gases routed to the blowdown system contain high levels of methane 

(approximately 70 percent by volume on a dry basis) based on DCU steam vent test data. If these 

vapors are directed to the closed blowdown system rather than to the atmosphere, the dry gas can 

generally be recovered in the refinery fuel gas system or light-ends gas plant. This recovered 

methane is expected to offset natural gas purchases for the fuel gas system. Also, EPA 

anticipates that new DCU sources can be built with a closed blowdown system designed to 

achieve a 2 psig vessel pressure with no significant increase in capital or operating costs of the 

new DCU. There may be a slight increase in capital costs for the low pressure valve design or for 

larger diameter piping; however, these design improvements generally lower the operating costs 

of the DCU. 

 The proposal includes appropriate work practice standards in place of emission limits for 

the DCU – the work practice standards include a lower pressure set point for venting. Costs and 

emissions reductions were evaluated on a DCU-specific basis using the data reported by 

petroleum refineries in the detailed 2011 ICR responses, along with vendor quotes obtained in 

2011. The cumulative nationwide costs calculated for the petroleum refining industry for this 

option are summarized in Table 3-2 and Table 3-3. Annualized cost of capital estimates were 

determined based on a 7 percent interest rate. The DCU capital costs were annualized over 15 

years. For additional discussion, see the technical memorandum titled Impact Estimates for 

Delayed Coking Units, September 12, 2013, in Docket ID Number EPA-HQ-OAR-2010-0682. 
3-8 

Table 3-2 Nationwide VOC Impacts for Delayed Coking Unit Control Options 

Control 

Option 

Total Capital 

Investment 

(million 2009$)

10

Total 

Annualized 

Costs w/o 

Recovery 

(million $/yr) 

Recovery 

Credits 

(million 

$/yr) 

Total 

Annualized 

Costs w/ 

Recovery 

(million $/ yr)

Emissions 

Reduction, 

VOC (tpy) 

Cost 

Effectiveness 

($/ton VOC 

reduced) 

Venting at 

2 psig $52.0 $10.2 ($6.20) $3.98 4,250 $940 

Table 3-3 Nationwide HAP Impacts for Delayed Coking Unit Control Options 

Control 

Option 

Total Capital 

Investment 

(million 2009$)

Total 

Annualized 

Costs w/o 

Recovery 

(million $/yr) 

Recovery 

Credits 

(million 

$/yr) 

Total 

Annualized 

Costs w/ 

Recovery 

(million $/ yr)

Emissions 

Reduction, 

HAP (tpy) 

Cost 

Effectiveness 

($/ton HAP 

reduced) 

Venting at 

2 psig $52.0 $10.2 ($6.20) $3.98 850 $4,700 

3.2.3 Fenceline Monitoring 

Certain emissions sources, such as fugitive leaks from equipment and wastewater 

collection and treatment systems, are inherently difficult to quantify with methods currently 

available. In general, uncertainties in emissions estimates result from: 

o Exclusion of nonroutine emissions; 

o Omission of sources that are unexpected, not measured, or not considered part of the 

affected source, such as emissions from process sewers, wastewater systems, or other 

fugitive emissions; 

o Improper characterization of sources for emissions models and emissions factors; and 

o Inherent uncertainty in emissions estimation methodologies. 

In 2009, the EPA conducted a year-long diffusive tube monitoring pilot project at the 

fenceline of Flint Hills West Refinery in Corpus Christi, Texas. The study concluded that the 

modeled-derived concentrations are significantly lower than the actual measured values at 

 

10 The technical memo entitled Impact Estimates for Delayed Coking Units includes the following note of clarification: 

“Although the control cost estimates for delayed coking units were developed from 2011 vendor quotes, the impacts for other 

petroleum refinery sources are reported in 2009 dollars to be consistent with other cost estimates developed for other Refinery 

MACT 1 emission sources. Given the low inflation across this time period, it was assumed that the delayed coking unit costs 

developed from the 2011 vendor quote could be used without correction to estimate the delayed coking units control costs in 

2009 dollars.” 
3-9 

virtually every point along the fenceline. On average, the measured values were a factor of 10 

times higher than the modeled values. Although EPA would not expect the values to be 

identical, such a significant difference is an indicator that emissions may, in fact, be far more 

significant than accepted methodologies and procedures can predict. 

Measurement of the concentration of expected pollutants at the fenceline provides an 

indication of the uncertainty associated with emissions estimates for all near ground-level 

sources, including fugitives. EPA reviewed the available literature and identified several 

different methods for measuring fugitive emissions around the fenceline of a petroleum refinery. 

These methods include: (1) passive diffusive tube monitoring networks; (2) active monitoring 

station networks; and (3) open path monitoring systems. As a result of the year-long fenceline 

monitoring pilot project at Flint Hills West Refinery in Corpus Christi, EPA found the passive 

diffusive tube monitoring technology to be capable of providing cost-effective, relatively robust 

monitoring data. 

Average annual costs were estimated for a ten-year period (the useful life of the 

analytical equipment is expected to be ten years, according to the analytical equipment 

manufacturer representatives) and assumed an annualized cost of capital based on a 7 percent 

interest rate. The initial costs include the cost of purchasing and installing the monitoring 

stations, collecting the samples, and performing the analyses for the first year. Initial costs also 

include the cost of purchasing a gas chromatograph, a thermal desorption unit with an 

autosampler, and the diffusive tubes and caps. Analytical equipment cost estimates were 

developed from vendor quotes, which included both the cost of the analytical equipment and 

materials, as well as man-hour estimates for performing the analyses. Recurring costs include 

the cost (man-hours) for collecting the samples and the cost of analyzing the samples (and any 

materials consumed). 

Table 3-4 presents nationwide cost estimates of applying the different monitoring options 

to all refineries. To generate the estimates, it was assumed that refineries with crude refining 

capacity of less than 125,000 barrels per day would fall into the small size (less than 750 acres); 

refineries with crude refining capacity greater than or equal to 125,000 barrels per day and less 

than 225,000 barrels per day would fall into the medium size facility range (greater than or equal 

to 750 and less than 1,500 acres); and refineries with crude throughput of greater than or equal to 

225,000 barrels per day would fall into the large facility size (greater than or equal to 1,500 
3-10 

acres). The nationwide costs included for the proposed amendments assume that all facilities 

would use passive diffuse tube monitoring stations and elect to purchase the equipment 

necessary to perform the analysis in-house. For additional discussion, see the technical 

memorandum titled Fenceline Monitoring Technical Support Document, January 17, 2014, in 

Docket ID Number EPA-HQ-OAR-2010-0682. 

Table 3-4 Nationwide Costs (in 2009$) for Fenceline Monitoring at Petroleum Refineries 

Refinery Area Size 

Number 

of 

Refineries

Number of 

Monitoring 

Sites per 

Refinery 

Capital Costs 

for All 

Refineries 

($) 

Annualized 

Cost ($/yr) 

Option 1 (Proposed Option) - Passive Diffusive Tube Monitoring Station Network 

Small 

(< 750 acres) 84 12 7,177,000 3,049,000 

Medium (≥ 750 and < 

1,500 acres) 27 18 2,340,000 1,107,000 

Large 

(≥1,500 acres) 31 24 2,736,000 1,423,000 

Total 142 2,238 12,250,000 5,580,000

Option 2 - Active Monitoring Station Network 

Small 

(< 750 acres) 84 12 11,090,000 16,300,000 

Medium (≥ 750 and < 

1,500 acres) 27 18 4,130,000 6,930,000 

Large 

(≥1,500 acres) 31 24 5,390,000 9,900,000 

Total 142 2,238 20,600,000 33,100,000

Option 3 - Open Path Monitoring Network

Total 142 56811 71,000,000 45,600,000 

3.2.4 Relief Valve Monitoring 

Relief valve releases vented directly to the atmosphere are caused by malfunctions, and 

emissions vented to the atmosphere by relief valves can contain emissions that are regulated 

 

11 For the monitoring approach, EPA assumed 4 monitoring stations per refinery – 142 refineries * 4 monitoring 

stations = 568 total monitoring sites. 
3-11 

under Refinery MACT 1. Using CAA Section 112(d)(2) and (3), the proposal specifies that 

relief valves in organic HAP service may not discharge to the atmosphere. The proposed rule 

provides that a relief valve release, unless ducted to an air pollution control device meeting the 

process vent limits, is a violation of the emissions standard. 

 EPA analyzed several options for improvements to the existing leak detection and repair 

(LDAR) program in Refinery MACT 1, including LDAR using EPA Method 21 (in 40 CFR part 

60, Appendix A-7), LDAR using optical gas imaging, and requiring monitoring of pressure 

release devices (PRD) for compliance assurance. We assessed several monitoring options, 

including: 

• Option 1 -- leak threshold that required repair defined as 500 ppm for valves in G and 

LL service and 2,000 ppm for pumps in LL service. 

• Option 2 -- leak thresholds the same as Option 1 but a majority of refineries were 

assumed to conduct monitoring with an optical gas imaging device. 

• Option 3 -- monitoring and repair for connectors in G and LL service, where the leak 

threshold that required repair was defined as 500 ppm. 

EPA also assessed continuous monitoring requirements for PRD that would record the time and 

duration of a release as well as alert operators when there is a release. Table 3-5 presents 

nationwide cost estimates of applying the different monitoring options to all refineries. 

To ensure compliance with this amendment, the proposal requires that sources monitor 

relief valves using a system that is capable of identifying and recording the time and duration of 

each pressure release and of notifying operators that a pressure release has occurred. Where a 

pressure release occurs, it is important to identify and mitigate it as quickly as possible. For 

purposes of estimating the costs of this requirement, it was assumed that operators would install 

electronic monitors on each relief valve that vents to the atmosphere to identify and record the 

time and duration of each pressure release. However, the proposal allows owners and operators 

to use a range of methods to satisfy these requirements, including the use of a parameter 

monitoring system on the process operating pressure that is sufficient to indicate that a pressure 

release has occurred, as well as record the time and duration of that pressure release. Annualized 

cost of capital estimates were determined based on a 7 percent interest rate and a 10-year 
3-12 

equipment life. Based on cost assumptions, the nationwide capital cost of installing these 

electronic monitors is $9.54 million and the annualized capital cost is $1.36 million per year 

(2009$). For additional discussion of the proposed relief valve monitoring amendments, see the 

technical memorandum titled Impacts for Equipment Leaks at Petroleum Refineries, December 

19, 2013, in Docket ID Number EPA-HQ-OAR-2010-0682 and Section IV.A.4.a. Vent Control 

Bypasses, Relief Valve Discharges of the proposed rule preamble. 

Table 3-5 Nationwide Costs for Equipment Leaks (2009$) 

Option 

Incremental 

Capital 

Cost 

(million $) 

Incremental 

Annualized 

Capital Cost 

(million $/yr) 

Incremental 

Annual 

Expenses 

(million $/yr) 

Total 

Annualized 

Cost 

(million $/yr) 

Option 1 -- Valves G and 

LL, Pumps LL 1.23 0.176 0.355 0.531 

Option 2 – Option 1 

w/Optical Gas Imaging 

Instrument b

5.76 0.821 (4.33)a (3.51)a

Option 3 -- Connectors 52.1 7.40 6.52 13.9 

Proposed Option – PRD – G 

and Liquid 9.54 1.36 NA 1.36 

a

 Parentheses indicate estimated cost savings. 

b

 Costs for Option 2 are estimates of the potential costs of monitoring with an optical gas imaging instrument using 

an EPA protocol still in development. 

3.2.5 Flare Monitoring 

All of the requirements for flares operating at petroleum refineries are intended to ensure 

compliance with the Refinery MACT 1 and 2 standards when using a flare as an air pollution 

control device. Refinery MACT 1 and 2 reference the flare requirements in the General 

Provisions12, which require a flare used as an air pollution control device operate with a pilot 

flame present at all times.13 The proposal removes the cross-reference to the General Provisions 

and includes the requirement that flares operate with a pilot flame at all times and be 

 

12 General Provisions are the general provisions under 40 CFR Part 63 for National Emissions Standards for 

Hazardous Pollutants for Source Categories located at: http://www.ecfr.gov/cgi-bin/textidx?SID=4cd63c1d1e17697310ac3328e81aa5d3&tpl=/ecfrbrowse/Title40/40cfr63_main_02.tpl. 

13 Pilot flames are proven to improve flare flame stability; even short durations of an extinguished pilot could cause 

a significant reduction in flare destruction efficiency. 
3-13 

continuously monitored for using a thermocouple or any other equivalent device in Refinery 

MACT 1 and 2. The proposal also amends Refinery MACT 1 and 2 to add a new operational 

requirement to use automatic relight systems for all flare pilot flames.14 Because of safety issues 

with manual relighting, EPA believes that nearly all refinery flares are currently equipped with 

an automated device to relight the pilot flame. The proposal also amends Refinery MACT 1 and 

2 to add a requirement that a visible emissions test be conducted each day and whenever visible 

emissions are observed from the flare using an observation period of 5 minutes and EPA Method 

22 of 40 CFR part 60, Appendix A-7. 

The General Provisions at 40 CFR 63.11(b) specify maximum flare tip velocities based 

on flare type (non-assisted, steam-assisted, or air-assisted) and the net heating value of the flare 

vent gas. These maximum flare tip velocities are required to ensure that the flame does not “lift 

off” the flare, which could cause flame instability and/or potentially result in a portion of the 

flare gas being released without proper combustion. In addition to proposing to remove the 

cross-reference to the General Provisions, the proposal consolidates the requirements for 

maximum flare tip velocity into Refinery MACT 1 and 2 as a single equation, irrespective of 

flare type. Based on an analysis of the various studies for air-assisted flares, EPA is proposing 

that air-assisted flares at refineries use the same equation that non-assisted and steam-assisted 

flares currently use to establish the flare tip velocity operating limit. 

The current requirements for flares in the General Provisions specify that the flare vent 

gas must meet a minimum net heating value of 200 British thermal units per standard cubic foot 

(Btu/scf) for non-assisted flares and 300 Btu/scf for air- and steam-assisted flares. Refinery 

MACT 1 and 2 reference these requirements, but neither the General Provisions nor Refinery 

MACT 1 and 2 include specific monitoring requirements to monitor the net heating value of the 

vent gas. In addition, recent flare testing results indicate that this parameter alone does not 

adequately address instances when the flare may be over-assisted. Because approximately 90 

percent of all flares at refineries are either steam- or air-assisted, it is critical to ensure the assist 

media be accounted for. Recent flare test data have shown that the best way to account for 

situations of over-assisting is to consider the properties of the mixture of all gases at the flare tip 

 

14 An automatic relight system provides a quicker response time to relighting a snuffed out flare than manual 

methods and results in improved flare flame stability. 
3-14 

in the combustion zone when evaluating the ability to combust efficiently. The proposal adds 

definitions of two key terms relevant to refinery flare performance. First, the proposal defines 

“flare vent gas” to include all waste gas, sweep gas, purge gas and supplemental gas, but not 

include pilot gas or assist media. The proposal also defines the “combustion zone gas” as flare 

vent gas plus the total steam-assist media and premix assist air that is supplied to the flare. 

 EPA expects that the newly proposed requirements for refinery flares will affect all flares 

at petroleum refineries. Based on data received as a result of the 2011 ICR, EPA estimates that 

there are 510 flares operating at petroleum refineries and that 285 of these receive flare vent gas 

flow on a regular basis. EPA expects that refineries will need a flare gas flow monitor and either 

a gas chromatograph, total hydrocarbon analyzer, or calorimeter (Btu monitor). EPA believes 

that most flares have already installed a flare gas flow monitor in order to comply with the 

requirements of Subpart Ja. The engineering cost analysis reflects potential supplemental natural 

gas use and steam savings projections estimated based on the refinery flare dataset. Steam 

reduction credits and supplemental natural gas costs were only assigned to flares electing 

continuous monitoring; flares using the engineering calculation were assumed to maintain their 

current steam and natural gas use rates.15

 

 EPA does not know the specific timing of how regulated firms will expend resources on 

new environmental compliance activities. Because the compliance timeline for implementation 

of these proposed flare monitoring requirements is three years from promulgation, EPA 

anticipates that capital expenditures will occur over that three year period and not result in 

expenditures of greater than $100 million in any single year. Industry costs submitted to EPA 

through consent decrees were used as the primary source of cost estimation. These costs 

included all installation and ancillary costs associated with the installation of the monitors (i.e., 

analyzer shelters and electrical connections). Costs were estimated for each flare for a given 

refinery, considering operational type and current monitoring systems already installed on each 

individual flare. Costs for any additional monitoring systems needed were estimated based on 

installed costs received from petroleum refineries and, if installed costs were unavailable, costs 

were estimated based on vendor-purchased equipment. The baseline emissions estimate and 

 

15 As an alternative to continuous monitoring systems, process knowledge, engineering calculations and/or grab 

samples can be used to determine the composition (or heat content) of the flare gas. 
3-15 

emissions reductions achieved by the proposed rule were estimated based on current vent gas and 

steam flow data submitted by industry representatives. Table 3-6 provides a summary of total 

capital and annualized cost for flare control alternatives. Table 3-7 provides detailed cost 

information for the flare monitoring requirements. For additional discussion, see the technical 

memorandum titled Petroleum Refinery Sector Rule: Flare Impact Estimates, January 16, 2014, 

in Docket ID Number EPA-HQ-OAR-2010-0682. The specific cost data collected for the flare 

costs estimates are provided in Attachment 3 to this technical memorandum. See Attachment 3 

for details on the assumptions made for equipment life and interest rate. 

Table 3-6 Summary of Capital and Annualized Costs for Flare Control Alternatives 

(2010$) 

Control Alternative Description 

Flares Currently Subject to 

40 CFR 63.11 

All Flares at Major Source 

Refineries 

Total Capital 

Investment 

(million $) 

Total 

Annualized 

Cost 

(million $/yr) 

Total Capital 

Investment 

(million$) 

Total 

Annualized 

Cost 

(million $/yr) 

Option 1 (Proposed Option) – 

270 Btu/scf; Engineering Calculations 

98 23.4 147 36.3 

Option 2 – 

270 Btu/scf; Monitors Only 

219 66.1 439 92.5 

Table 3-7 Detailed Costs of Flare Monitoring Requirements (2010$)

Monitoring 

Equipment 

Total 

Capital 

Investment 

($/flare)* 

Total 

Annualized 

Cost 

($/year/flare)*

# of 

Flares 

Total TCI 

($) 

Total TAC 

($/year) Notes16

Calorimeter $105,000 $30,000 85 $8,925,000 $2,550,000 

85 flares (Table 9) 

Column labeled -- 

Number of flares 

needing to install a 

new heat content 

monitor, All. 

Row labeled -- 

Total no. of flares. 

Steam 

Flow/Controls $684,000 $124,300 190 $129,960,000 $23,617,000 

190 flares (Table 

3) 

Column labeled -- 

Number of 

 

16 The tables referenced are located in the technical memo entitled “Petroleum Refinery Sector Rule: Flare Impact 

Estimates”, January 16, 2014. 
3-16 

Routine Flow 

Flares, All; 

Rows -- SteamAssisted (228) – 

Air-Assisted (38) 

= 190 

Air 

Flow/Controls $164,000 $52,000 38 $6,232,000 $1,976,000 

38 flares (Table 3) 

Column labeled -- 

Number of 

Routine Flow 

Flares, All; 

Row labeled -- 

Air-Assisted (38) 

Supplemental 

Natural Gas $0 $98,660 190 $0 $18,745,400 

190 flares (Table 

3) 

Column labeled -- 

Number of 

Routine Flow 

Flares, All; 

Rows -- SteamAssisted (228) – 

Air-Assisted (38) 

= 190 

Steam Savings $0 -$73,770 190 $0 -$14,016,300 

190 flares (Table 

3) 

Column labeled -- 

Number of 

Routine Flow 

Flares, All; 

Rows -- SteamAssisted (228) – 

Air-Assisted (38) 

= 190 

Engineering 

Cost 

Calculations 

$7,000 $13,160 267 $1,869,000 $3,513,720 

267 flares (510 

flares – 243 

flares)

Table 3: Column 

labeled – Total 

Number of Flares, 

All; 

Row labeled – 

Total No. of Flares 

(510) 

Table 9: Column 

labeled – Number 

of Routine flares 

that do not have 

full FGRS, All 
3-17 

Row labeled – 

Total No. of Flares 

(243) 

Total N/A N/A N/A $146,986,000 $36,385,900 N/A 

* Costs are located in Table 7. Summary of Flare Monitoring Equipment and Material Costs (2010$) in the technical 

memo entitled “Petroleum Refinery Sector Rule: Flare Impact Estimates”, January 16, 2014. 

N/A = Not applicable 

3.2.6 FCCU Testing 

Under Refinery MACT 2, an initial emissions source performance demonstration is 

required to show that the FCCU is compliant with the emissions limits selected by the refinery 

owner or operator. The performance test is a one-time requirement; additional performance tests 

are only required if the owner or operator elects to establish new operating limits, or to modify 

the FCCU or control system in such a manner that could affect the control system’s performance. 

Currently, the Refinery MACT 2 does not include periodic performance tests for any 

FCCU. The lack of any ongoing performance test requirements is inconsistent with 

developments in practices for ensuring ongoing compliance with emission limits. For the 

proposed amendments, we considered adding an annual testing requirement for FCCU subject to 

Refinery MACT 2. The annual nationwide cost burden would exceed $1 million per year, and 

only modest improvements in control performance resulting from the performance 

demonstrations were projected. We then considered requiring FCCU emissions source 

performance tests once every 5 years (i.e., once per title V permit period). The nationwide annual 

cost of this additional testing requirement for the FCCU is projected to be, on average, $213,000 

per year. Therefore, the proposal includes a requirement for an emissions source performance 

test once every 5 years for all FCCU subject to Refinery MACT 2. 

3.3 Summary of Costs of Proposed Rule Amendments 

 The total capital investment cost of the proposed amendments and enhanced monitoring 

provisions is estimated at $239 million -- $82.8 million from proposed amendments and $156.6 

million from standards to ensure compliance. The annualized costs are estimated to be 

approximately $42.4 million, which includes an estimated $14.4 million credit for recovery of 

lost product, some operation and maintenance costs, and the annualized cost of capital. EPA 

does not know the specific timing of how regulated firms will expend resources on new 
3-18 

environmental compliance activities. Because the compliance timeline for implementation of 

these proposed standard revisions is three years from promulgation, EPA anticipates that capital 

expenditures will occur over that three year period and not result in expenditures of greater than 

$100 million in any single year. 

 The total capital investment cost of the proposed amendments associated with proposed 

requirements for storage vessels, delayed coking units, and fugitive emissions monitoring is 

estimated at $82.8 million. We estimate annualized costs associated with those proposed 

requirements to be approximately $4.5 million, which includes the estimated $14.4 million credit 

for recovery of lost product and the annualized cost of capital. The proposed requirements for 

storage vessels would result in additional capital costs of $18.5 million and a negative annualized 

cost of $5.1 million per year. The proposed requirements for DCUs would result in additional 

capital costs of $52 million and an annualized cost of $4 million per year, and the proposed 

requirements associated with fenceline monitoring would result in additional capital costs of 

$12.3 million and an annualized cost of $5.6 million per year. The proposed amendments will 

achieve a nationwide HAP emission reduction of about 1,760 tons/year with a concurrent 

reduction in VOC emissions of about 18,850 tons/year. The top section of Table 3-8 below 

summarizes the cost and emissions reduction impacts of these proposed standards and 

amendments. 

 In addition, the proposed amendments to include flare monitoring and operational 

requirements to ensure compliance would result in an additional total nationwide capital cost of 

$156.6 million and an annualized cost of $37.9 million. The proposed requirements for relief 

valve monitoring would result in additional capital costs of $9.6 million and an annualized cost 

of $1.36 million per year. The proposed requirements for flare monitoring would result in 

additional capital costs of $147 million and an annualized cost of $36.3 million per year. The 

proposed requirements also include requirements for PM emissions source performance tests at 

least once every five years (once per title V permit period) for the FCCUs at existing sources. 

The nationwide annual cost of this additional requirement for all FCCUs is projected to be, on 

average, $213,000 per year. We were not able to estimate (i) product recovery credits associated 

with the proposed amendments for relief valve monitoring, flare monitoring and source 

performance testing at the FCCUs, or (ii) emissions reductions associated with the proposed 

amendments for relief valve monitoring and source performance testing. As such, these 
3-19 

estimates are not included in Table 3-8. The proposed operational and monitoring amendments 

for flares have the potential to reduce excess emissions from flares by approximately 3,800 tons 

per year of HAP and 33,000 tons per year of VOC. The bottom section of Table 3-8 below 

summarizes the cost impacts of these proposed standards and amendments. 

Table 3-8 Emissions Sources, Points, and Controls Included in Regulatory Options 

Affected source 

Total 

capital 

investment 

($ million)

Total 

annualized 

cost 

without 

credit 

($ million/ 

year) 

Product 

recovery 

credit 

($ million/ 

year) 

Total 

annualized 

costs 

($ million/ 

year) 

VOC 

emission 

reductions 

(tpy) 

Cost 

effectiveness ($/ton 

VOC) 

HAP 

emission 

reductions 

(tpy) 

Cost 

effectiveness ($/ton 

HAP) 

Storage vessels 18.5 3.1 (8.2) (5.1) 14,600 (345) 910 (5,530) 

Delayed coking 

units 52.0 10.2 (6.2) 4.0 4,250 937 850 4,680 

Fugitive Emissions 

(Fenceline 

Monitoring) 

12.3 5.6 --- a 5.6 --- --- --- --- 

Subtotal 82.8 18.9 (14.4) 4.5 18,850 241 1,760 2,570 

Relief Valve 

Monitoring 9.6 1.4 --- b

 --- --- --- --- --- 

Flare Monitoring 147.0 36.3 --- c

 --- --- --- --- --- 

FCCU Testing --- 0.21 --- d

 --- --- --- --- --- 

Subtotal 156.6 37.9 --- 37.9 --- --- --- --- 

Total 239.4 56.8 (14.4) 42.4 18,850 --- 1,760 --- 

a

 Any corrective actions taken in response to the fugitive emissions fenceline monitoring program will result in 

additional emissions reductions and additional costs and these are not included in the results. 

b

 Any corrective actions taken in response to relief valve monitoring may result in additional emissions reductions 

and additional costs and these are not included in the results. 

c

 Any corrective actions taken in response to flare monitoring may result in additional emissions reductions and 

additional costs and these costs are not included in the results. 

d

 Any corrective actions taken in response to PM emissions source performance tests for the fluid catalytic cracking 

units may result in additional emissions reductions and additional costs and these are not included in the results. 
4-1 

4 ECONOMIC IMPACT ANALYSIS AND DISTRIBUTIONAL ASSESSMENTS 

4.1 Introduction 

This section includes three sets of analyses: 

• Market Analysis 

• Employment Impacts 

• Small Business Impacts Analysis 

4.2 Market Analysis 

 EPA performed a series of single-market partial equilibrium analyses of national markets 

for five major petroleum products to provide a partial measure of the economic consequences of 

the regulatory options. With the basic conceptual model described below, we estimated how the 

regulatory program affects prices and quantities for motor gasoline, jet fuel, distillate fuel oil, 

residual fuel oil, and liquefied petroleum gases which, when aggregated, constitute a large 

proportion of refinery production in the United States. We also conducted an economic welfare 

analysis that estimates the consumer and producer surplus changes associated with the regulatory 

program. The welfare analysis identifies how the regulatory costs are distributed across two 

broad classes of stakeholders, consumers and producers, for the five products under evaluation. 

Because we do not have data on changes in refinery utilization rates, the market analysis does 

not address costs associated with loss in producer surplus due to potentially lower utilization 

rates that may result from the proposed standards. 

4.2.1 Market Analysis Methods 

The national compliance cost estimates are often used to approximate the welfare impacts 

of the rule. However, in cases where the engineering costs of compliance are used to estimate 

welfare impacts, the burden of the regulation is typically measured as falling solely on the 

affected producers, who experience a profit loss exactly equal to these cost estimates. Thus, the 

entire loss is a change in producer surplus with no change (by assumption) in consumer surplus, 

because no changes in price and consumption are estimated. This is typically referred to as a 

“full-cost absorption” scenario in which all factors of production are assumed to be fixed and 

firms are unable to adjust their output levels when faced with additional costs. In contrast, 
4-2 

EPA’s economic analysis builds on the engineering cost analysis and incorporates economic 

theory related to producer and consumer behavior to estimate changes in market conditions. 

The partial equilibrium models use a common analytic expression to analyze supply and 

demand in a single market (Berck and Hoffmann 2002; Fullerton and Metcalf 2002) and follows 

EPA guidelines for conducting an EIA (U.S. Environmental Protection Agency 2010). We 

illustrate our approach for estimating market-level impacts using a simple, single partial 

equilibrium model. The method involves specifying a set of nonlinear supply and demand 

relationships for the affected market, 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). 

First, we consider the formal definition of the elasticity of supply, qs, with respect to 

changes in own price, p, where s

ε represents the market elasticity of supply: 

/

/

s s

s

dq q

dp p

ε = (4.1) 

Next, we can use “hat” notation to transform Eq. 1 to proportional changes and rearrange terms: 

ˆ ˆ

s s

q p = ε (4.1a) 

where ˆ

s

q equals the percentage change in the quantity of market supply, and ˆp equals the 

percentage change in market price. As Fullerton and Metcalfe (2002) note, we have taken the 

elasticity definition and turned it into a linear behavioral equation for the market we are 

analyzing. 

To introduce the direct impact of the regulatory program, we assume the per-unit cost 

associated with the regulatory program, c, leads to a proportional shift in the marginal cost of 

production (mc). The per-unit costs are estimated by dividing the total estimated annualized 

engineering costs accruing to producers within a given product market by the baseline national 

production in that market. Under the assumption of perfect competition (e.g., price equaling 

marginal cost), we can approximate this shift at the initial equilibrium point as follows: 
4-3 



0 0

c c

mc

mc p

= = . (4.1b) 

The with-regulation supply equation can now be written as 

 ˆ ˆ ( )

s s

q p mc = − ε . (4.1c) 

Next, we can specify a demand equation as follows: 

ˆ ˆ d d q p = η (4.2) 

where 

ˆ

d

q = percentage change in the quantity of market demand, 

ηd

 = market elasticity of demand, and 

ˆp = percentage change in market price. 

Finally, we specify the market equilibrium conditions in the affected market. In response 

to the exogenous increase in production costs, producer and consumer behaviors are represented 

in Eq. 4-1a and Eq. 4-2, and the new equilibrium satisfies the condition that the change in supply 

equals the change in demand: 

ˆ ˆ s d q q = . (4.3) 

We now have three linear equations and three unknowns ( ˆp , ˆ

d

q , and ˆ

s

q ), and we can 

solve for the proportional price change in terms of the elasticity parameters ( s

ε and ηd

) and the 

proportional change in marginal cost: 

(

 )





( ) 



ˆ ˆ

ˆ ˆ

ˆ ˆ

ˆ

ˆ

s d

s s d

s d s

s d s

s

s d

p mc p

p mc p

p p mc

p mc

p mc

ε η

ε ε η

ε η ε

ε η ε

ε

ε η

− =

− =

− =

− =

=

−

 

 (4.4)

 
4-4 

Given this solution, we can solve for the proportional change in market quantity using Eq. 4-2. 

The change in consumer surplus in the affected market can be estimated using the 

following linear approximation method: 

∆ = − × + × ∆ × ∆ cs q p q p ( 1 ) (0.5 ) (4.5) 

where 1

q equals with-regulation quantities produced. As shown, higher market prices and 

reduced consumption lead to welfare losses for consumers. 

For affected supply, the change in producer surplus can be estimated with the following 

equation: 

∆ = × ∆ − × − × ∆ × ∆ − ps q p q c q p c ( 1 1 ) ( ) (0.5 ( )). (4.6) 

Increased regulatory costs and output declines have a negative effect on producer surplus, 

because the net price change (∆ − p c) is negative. However, these losses are mitigated, to some 

degree, as a result of higher market prices. 

4.2.2 Model Baseline 

Standard EIA practice compares and contrasts the state of a market with and without the 

regulatory policy. EPA selected 2016 as the baseline year for the analysis and collected 

petroleum product price and quantity forecast information from the Energy Information 

Administration’s 2012 Reference Case Annual Energy Outlook (U.S. EIA 2011a). Baseline data 

are reported in Table 4-1. Annual Energy Outlook (AEO) reports the quantity of petroleum 

products produced 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. 

 
4-5 

Table 4-1 Baseline Petroleum Product Market Data, 2016 

 

Motor 

Gasoline Jet Fuel 

Distillate 

Fuel Oil 

Residual 

Fuel Oil 

Liquified 

Petroleum 

Gases 

Price ($2010/per gallon)1 3.17 2.73 3.42 2.25 0.96 

Quantity (billion gallons/per year)2130.61 22.69 66.69 7.82 40.93 

1Source: AEO2012 Reference Case, Petroleum Product Prices (Table 12) 

2Source: AEO2012 Reference Case, Liquid Fuels Supply and Disposition (Table 11) 

4.2.3 Model Parameters 

Demand elasticity is calculated as the percentage change in the quantity of a product 

demanded divided by the percentage change in price. An increase in price causes a decrease in 

the quantity demanded, hence the negative values seen in Table 4-2, which presents the demand 

elasticities used in this analysis. Demand is considered elastic if demand elasticity exceeds 1.0 

in absolute value (i.e., the percentage change in quantity exceeds the percentage change in price). 

The quantity demanded, then, is very sensitive to price increases. Demand is considered 

inelastic if demand elasticity is less than 1.0 in absolute value (i.e., the percentage change in 

quantity is less than the percentage change in price). Inelastic demand implies that the quantity 

demanded changes very little in response to price changes. As shown in Table 4-2, we draw 

demand elasticities from U.S. EPA (1995). 

Table 4-2 Estimates of Price Elasticity of Demand and Supply1

Motor 

Gasoline Jet Fuel

Distillate Fuel 

Oil

Residual Fuel 

Oil

Liquified 

Petroleum 

Gases

Demand elasticity -0.69 -0.15 -0.75 -0.68 -0.80

Supply elasticity 1.24 1.24 1.24 1.24 1.24

1 The source for these elasticities is U.S. EPA (1995). The literature review performed for this EIA indentified more 

recent estimates of long-term demand elasticities for motor gasoline, which are lower than the elasticity used in this 

analysis, but we were unable to identify more recent estimates of the other elasticities. 

Supply elasticity is calculated as the percentage change in quantity supplied divided by 

the percentage change in price. An upward sloping supply curve has a positive elasticity since 

price and quantity move in the same direction. If the supply curve has elasticity greater than one, 

then supply is considered elastic, which means a small price increase will lead to a relatively 

large increase in quantity supplied. A supply curve with elasticity less than one is considered 

inelastic, which means an increase in price will cause little change in quantity supplied. In the 
4-6 

long-run, when producers have sufficient time to completely adjust their production to a change 

in price, the price elasticity of supply is usually greater than one. As shown in Table 4-2, we 

draw supply elasticities from U.S. EPA (1995). 

4.2.4 Entering Estimated Annualized Engineering Compliance Costs into Economic Model 

To collect comprehensive, updated information for the proposed rulemaking, EPA 

conducted a one-time information collection request (ICR) through a survey, under the authority 

of CAA section 114, of all potentially affected petroleum refineries. The ICR was comprised of 

four components, and the information collected through component 1 of the ICR included 

facility location, products produced, capacity, throughput, process and emissions, and 

employment and sales receipt data for 2010.17 The throughput quantities provided were the same 

as those reported to the U.S. EIA on form EIA-810. The ICR information was used to analyze 

and calculate compliance costs by refinery for the proposed rulemaking. These annualized 

engineering compliance costs provided the basis for the environmental cost inputs for the series 

of partial equilibrium economic models. 

 

 The annualized engineering compliance cost inputs are incorporated into the partial 

equilibrium models on a per barrel refining capacity basis. Several steps were required to 

convert the annualized engineering compliance cost data, by refinery, into the data format 

required for the economic analysis. First, for each refinery we allocated the compliance costs 

across total barrels of refinery production. Because EPA collected production information for 

thirty-nine (39) different refinery products and the economic models allow for production input 

data for five product types, we then mapped the ICR product types to the shorter list of products 

used in the economic model. We assumed a uniform refinery utilization rate of 86.4%, which is 

the operable utilization rate for U.S. refineries for 2010.18 

 

 

17 Detailed information on the ICR can be located at https://refineryicr.rti.org/. OMB approved the ICR on March 

28, 2011. The OMB Control Number is 2060-0657, and approval expires March 31, 2014. 

18 Recent and historical refinery utilization rate information can be located at U.S. EIA’s website: 

http://www.eia.gov/dnav/pet/pet_pnp_unc_dcu_nus_a.htm. 
4-7 

Table 4-3 Estimated Annualized Engineering Compliance Costs by Petroleum Product 

Modeled (2010 dollars) 

 

Motor 

Gasoline Jet Fuel

Distillate 

Fuel Oil

Residual 

Fuel Oil

Liquified 

Petroleum 

Gases Other 

All 

Products

Total Annualized 

Engineering 

Compliance Costs 

$20,136,107 $4,130,446 $12,872,696 $1,893,999 $1,514,516 $15,762,038 $56,309,802

Capacity (millions 

bbls/year) 

2,782.51 611.74 1,536.15 227.53 191.97 2,121.04 7,470.94 

Capacity (millions 

gallons/year) 

116,865.42 25,693.01 64,518.41 9,556.20 8,062.72 89,083.84 313,779.60

Compliance Costs Per 

Gallon Capacity 

($2010) 

$0.00017 $0.00016 $0.00020 $0.00020 $0.00019 $0.00018 $0.00018 

 Using this engineering cost information and total national production of petroleum 

products, we estimated the annualized compliance cost per gallon of product produced. These 

annualized per gallon engineering compliance costs are presented in Table 4-3. For this analysis, 

we included engineering compliance costs that do not reflect the product recovery credits. At the 

national level, the total annualized engineering compliance costs are estimated at less than 

$0.00018 per gallon, or less than two one-hundredths of a cent per gallon. These per-gallon 

annualized engineering costs estimates were then entered into the series of partial equilibrium 

market models to estimate impacts on the respective petroleum product markets. 

4.2.5 Model Results 

Based on EPA’s partial equilibrium analysis, the costs induced by this regulatory 

program do not have a significant impact on market-level prices or quantities. The results of this 

analysis are summarized in Table 4-4. As this table shows, prices for each of the five products 

rise by less than two one-hundredths of a penny per gallon, and the quantity of each petroleum 

product produced declines slightly. Motor gasoline and liquified petroleum gases face the largest 

absolute quantity reductions (3.14 million and 3.91 million gallons, respectively, or less than 

0.0001 percent in both cases). 

 
4-8 

Table 4-4 Summary of Petroleum Product Market Impacts 

 

Motor 

Gasoline Jet Fuel 

Distillate 

Fuel Oil 

Residual 

Fuel Oil 

Liquified 

Petroleum 

Gases 

Change in Price (%) < 0.0001 < 0.0001 < 0.0001 < 0.0001 < 0.0001

Change in Price (2010$) 0.0001 0.0001 0.0001 0.0001 0.0001

Change In Quantity (%) < 0.0001 < 0.0001 < 0.0001 < 0.0001 < 0.0001

Change In Quantity (million gallons per year) -3.14 -0.18 -1.82 -0.30 -3.91

 Welfare Impacts 

Change in consumer surplus ($ millions) -14.46 -3.25 -8.29 -1.00 -4.67

Change in producer surplus ($ millions) -7.87 -0.23 -4.81 -0.35 -2.83

Change in total surplus ($ millions) -22.33 -3.48 -13.10 -1.35 -7.50

As a result of higher prices, consumers of petroleum products see a decline in surplus, as 

shown in Table 4-4. For example, consumers of motor gasoline are estimated to lose $14.46 

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 $7.87 million. Total surplus losses 

for consumers and producers of motor gasoline are estimated to be $22.33 million. The total 

annualized loss in surplus for the five markets analyzed is $47.77 million. In addition to the loss 

in surplus for consumers and producers of these five major petroleum products, an additional 

$15.7 million in costs will affect markets for petroleum products that were not explicitly 

modeled in this analysis. These include markets for asphalt, lubricants, road oil, petroleum coke 

and others. 

As a sensitivity analysis, we used a more recently estimated, long-run elasticity of 

demand for motor gasoline from Small and Van Dender (2007), which is based on crosssectional, time-series data from the U.S. for the period of 1966-2001. If we use this elasticity 

(-0.38), consumers of motor gasoline could lose $17.23 million of surplus, or an additional $2.77 

million loss in surplus compared to the estimate above (Small and Van Dender 2007). In 

addition, producers of motor gasoline could lose $5.1 million of surplus, or reduce their surplus 

loss by $2.77 million. 
4-9 

4.2.6 Limitations 

Ultimately, the regulatory program may cause negligible increases in the costs of 

supplying petroleum products to consumers. The partial equilibrium model used in this EIA is 

designed to evaluate behavioral responses to this change in costs within an equilibrium setting 

within nationally competitive markets. The national competitive market assumption is clearly 

strong because the markets in petroleum products may be regional for some products, as well as 

some product markets within the refining industry may be interdependent. Regional price and 

quantity impacts could be different from the average impacts reported if local market structures, 

production costs, or demand conditions are substantially different from those used in this 

analysis. 

4.3 Discussion of Employment Impacts 

 Executive Order 13563 directs federal agencies to consider the effect of regulations on 

job creation and employment. According to the Executive Order, “our regulatory system must 

protect public health, welfare, safety, and our environment while promoting economic growth, 

innovation, competitiveness, and job creation. It must be based on the best available science” 

(Executive Order 13563, 2011). Although standard benefit-cost analyses have not typically 

included a separate analysis of regulation-induced employment impacts,19 during periods of 

sustained high unemployment, employment impacts are of particular concern and questions may 

arise about their existence and magnitude. This section provides a conceptual framework for 

considering the potential influence of environmental regulation on employment in the U.S. 

economy and discusses the limited empirical literature that is available. The section then 

discusses the potential employment impacts in the environmental protection sector, e.g. for 

construction, manufacture, installation, and operation of needed pollution control equipment. 

Section 4.3.1 describes the economic theory used for analyzing regulation-induced employment 

impacts, discussing how standard neoclassical theory alone does not point to a definitive net 

effect of regulation on labor demand for regulated firms. Section 4.3.2 presents an overview of 

the peer-reviewed literature relevant to evaluating the effect of environmental regulation on 

employment. Section 4.3.3 discusses macroeconomic net employment effects. The EPA is 

 

19 Labor expenses do, however, contribute toward total costs in the EPA’s standard benefit-cost analyses. 
4-10 

currently in the process of seeking input from an independent expert panel on economy-wide 

impacts, including employment effects. Finally, Section 4.3.4 offers several conclusions. 

4.3.1 Theory 

 The effects of environmental regulation on employment are difficult to disentangle from 

other economic changes and business decisions that affect employment, over time and across 

regions and industries. Labor markets respond to regulation in complex ways. That response 

depends on the elasticities of demand and supply for labor and the degree of labor market 

imperfections (e.g., wage stickiness, long-term unemployment, etc). The unit of measurement 

(e.g., number of jobs, types of jobs hours worked, or earnings) may affect observability of that 

response. Net employment impacts are composed of a mix of potential declines and gains in 

different areas of the economy (i.e., the directly regulated sector, upstream and downstream 

sectors, and the pollution abatement sector) and over time. In light of these difficulties, economic 

theory provides a constructive framework for approaching these assessments and for better 

understanding the inherent complexities in such assessments. In this section, we briefly describe 

theory relevant to the impact of regulation on labor demand at the regulated firm, in the regulated 

industry, and in the environmental protection sector; and highlight the importance of considering 

potential effects of regulation on labor supply, a topic addressed further in a subsequent section. 

 Neoclassical microeconomic theory describes how profit-maximizing firms adjust their 

use of productive inputs in response to changes in their economic conditions.20 In this 

framework, labor is one of many inputs to production, along with capital, energy, and materials. 

In competitive output markets, profit maximizing firms take prices as given, and choose 

quantities of inputs and outputs to maximize profit. Factor demand at the firm, then, is 

determined by input and output prices.21,22

 

 Berman and Bui (2001) and Morgenstern, Pizer, and Shih (2002) have specifically 

tailored one version of the standard neoclassical model to analyze how environmental regulations 

affect labor demand decisions.23 Environmental regulation is modeled as effectively requiring 

 

20 See Layard and Walters (1978), a standard microeconomic theory textbook, for a discussion.

21 See Hamermesh (1993), Chapter 2, for a derivation of the firm’s labor demand function from cost-minimization. 

22 In this framework, labor demand is a function of quantity of output and prices (of both outputs and inputs). 

23 Berman and Bui (2001) and Morgenstern, Pizer, and Shih (2002) use a cost-minimization framework, which is a 

special case of profit-maximization with fixed output quantities. 
4-11 

certain factors of production, such as pollution abatement capital investment, that would not be 

freely chosen by profit maximizing/cost-minimizing firms. 

 In Berman and Bui’s (2001, p. 274-75) theoretical model, the change in a firm’s labor 

demand arising from a change in regulation is decomposed into two main components: output 

and substitution effects.24 For the output effect, by affecting the marginal cost of production, 

regulation affects the profit-maximizing quantity of output. The output effect describes how, if 

labor-intensity of production is held constant, a decrease in output generally leads to a decrease 

in labor demand. However, as noted by Berman and Bui, although it is often assumed that 

regulation increases marginal cost, and thereby reduces output, it need not be the case. A 

regulation could induce a firm to upgrade to less polluting, and more efficient equipment that 

lowers marginal production costs, for example. In such a case, output could theoretically 

increase. For example, in the proposed refinery amendments, the fitting controls and monitoring 

equipment for storage vessels were identified as developments in practices, processes and control 

technologies for storage vessels. The proposed requirement could result in fewer VOC 

emissions and more product remaining in the storage vessel, potentially increasing output. 

 The substitution effect describes how, holding output constant, regulation affects the 

labor-intensity of production. Although increased environmental regulation generally results in 

higher utilization of production factors such as pollution control equipment and energy to operate 

that equipment, the resulting impact on labor demand is ambiguous. For example, equipment 

inspection requirements, specialized waste handling, or pollution technologies that alter the 

production process may affect the number of workers necessary to produce a unit of output. 

Berman and Bui (2001) model the substitution effect as the effect of regulation on “quasi-fixed’’ 

pollution control equipment and expenditures that are required by the regulation and the 

corresponding change in labor-intensity of production. Within the production theory framework, 

when levels of a given set of inputs are fixed by external constraints such as regulatory 

requirements, rather than allowing the firm to freely choose all inputs under cost-minimization 

alone, these inputs are described as “quasi-fixed”. For example, materials would be a “quasi-

 

24 The authors also discuss a third component, the impact of regulation on factor prices, but conclude that this effect 

is unlikely to be important for large competitive factor markets, such as labor and capital. Morgenstern, Pizer and 

Shih (2002) use a very similar model, but they break the employment effect into three parts: 1) the demand 

effect; 2) the cost effect; and 3) the factor-shift effect. 
4-12 

fixed” factor if there were specific requirements for landfill liner construction, but the footprint 

of the landfill was flexible. Brown and Christensen (1981) develop a partial static equilibrium 

model of production with quasi-fixed factors, which Berman and Bui (2001) extend to analyze 

environmental regulations with technology-based standards. 

 In summary, as the output and substitution effects may be both positive, both negative or 

some combination, standard neoclassical theory alone does not point to a definitive net effect of 

regulation on labor demand at regulated firms. Operating within the bounds of standard 

neoclassical theory, however, rough estimation of net employment effects is possible with 

empirical study, specific to the regulated firms, when data and methods of sufficient detail and 

quality are available. The available literature illustrates some of the difficulties for empirical 

estimation: studies sometimes rely on confidential plant-level employment data from the U.S. 

Census Bureau, possibly combined with pollution abatement expenditure data that are too dated 

to be reliably informative. In addition, the most commonly used empirical methods in the 

literature do not permit the estimation of net effects. These studies will be discussed at greater 

length later in this chapter. 

 The above describes a conceptual framework for analyzing potential employment effects 

at a particular firm, within a regulated industry. It is important to emphasize that employment 

impacts at a particular firm will not necessarily represent impacts for the overall industry, 

therefore the theoretic approach requires some adjustment when applied at the industry level. 

 As stated, the responsiveness of industry labor demand depends on how the output and 

substitution effects interact. 25 At the industry-level, labor demand will be more responsive when: 

(1) the price elasticity of demand for the product is high, (2) other factors of production can be 

easily substituted for labor, (3) the supply of other factors is highly elastic, or (4) labor costs are 

a large share of the total costs of production.26 So, for example, if all firms in the industry are 

faced with the same compliance costs of regulation and product demand is inelastic, then 

industry output may not change much at all, and output of individual firms may only be slightly 

changed.27 In this case the output effect may be small, while the substitution effect will still 

depend on the degree of substitutability or complementarity between factors of production. 

 

25 Marshall’s laws of derived demand – see Ehrenberg & Smith, Chapter 4. 

26 See Ehrenberg & Smith, p. 108. 

27 This discussion draws from Berman and Bui (2001), p. 293. 
4-13 

Continuing the example, if new pollution control equipment requires labor to install and operate, 

labor is more of a complement than a substitute. In this case the substitution effect may be 

positive, and if the output effect is small or zero, the total effect may then be positive. As with 

the potential effects for an individual firm, theory alone is unable to determine the sign or 

magnitude of industry-level regulatory effects on labor. Determining these signs and magnitudes 

requires additional sector-specific empirical study. To conduct such targeted research would 

require estimates of product demand elasticity; production factor substitutability; supply 

elasticity of production factors; and the share of total costs contributed by wages, by industry, 

and perhaps even by facility. For environmental rules, many of these data items are not publicly 

available, would require significant time and resources in order to access confidential U.S. 

Census data for research, and also would not be necessary for other components of a typical EIA 

or RIA. 

 In addition to changes to labor demand in the regulated industry, net employment impacts 

encompass changes within the environmental protection sector, and, potentially in other related 

sectors, as well. Environmental regulations often create increased demand for pollution control 

equipment and services needed for compliance. This increased demand may increase revenue 

and employment in the environmental protection industry. At the same time, the regulated 

industry is purchasing the equipment and these costs may impact labor demand at regulated 

firms. Therefore, it is important to consider the net effect of compliance actions on employment 

across multiple sectors or industries. 

 If the U.S. economy is at full employment, even a large-scale environmental regulation is 

unlikely to have a noticeable impact on aggregate net employment.28 Instead, labor would 

primarily be reallocated from one productive use to another (e.g., from producing electricity or 

steel to producing pollution abatement equipment). Theory supports the argument that, in the 

case of full employment, the net national employment effects from environmental regulation are 

likely to be small and transitory (e.g., as workers move from one job to another).29 On the other 

hand, if the economy is operating at less than full employment, economic theory does not clearly 

indicate the direction or magnitude of the net impact of environmental regulation on 

 

28 Full employment is a conceptual target for the economy where everyone who wants to work and is available to do 

so at prevailing wages is actively employed. 

29 Arrow et. al. 1996; see discussion on bottom of p. 8. In practice, distributional impacts on individual workers can 

be important, as discussed in later paragraphs of this section. 
4-14 

employment; it could cause either a short-run net increase or short-run net decrease 

(Schmalansee and Stavins, 2011). An important fundamental research question is how to 

accommodate unemployment as a structural feature in economic models. This feature may be 

important in evaluating the impact of large-scale regulation on employment (Smith 2012). 

 Affected sectors may experience transitory effects as workers change jobs. Some workers 

may need to retrain or relocate in anticipation of the new requirements or require time to search 

for new jobs, while shortages in some sectors or regions could bid up wages to attract workers. 

It is important to recognize that these adjustment costs can entail local labor disruptions, and 

although the net change in the national workforce is expected to be small, localized reductions in 

employment can still have negative impacts on individuals and communities just as localized 

increases can have positive impacts. 

 While the current discussion focuses on labor demand effects, environmental regulation 

may also affect labor supply. In particular, pollution and other environmental risks may impact 

labor productivity30 or employees’ ability to work. While there is an accompanying, and parallel, 

theoretical approach to examining impacts on labor supply, similar to labor demand, it is even 

more difficult and complex to study labor supply empirically. There is a small, nascent empirical 

literature using more detailed labor and environmental data, and quasi-experimental techniques 

that is starting to find traction on this question. These will be described in Section 4.3.2.3. 

 To summarize the discussion in this section, economic theory provides a framework for 

analyzing the impacts of environmental regulation on employment. The net employment effect 

incorporates expected employment changes (both positive and negative) in the regulated sector, 

the environmental protection sector, and other relevant sectors. Using economic theory, labor 

demand impacts for regulated firms, and also for the regulated industry, can be decomposed into 

output and substitution effects. With these potentially competing forces, under standard 

neoclassical theory estimation of net employment effects is possible with empirical study 

specific to the regulated firms and firms in the environmental protection sector and other relevant 

sectors when data and methods of sufficient detail and quality are available. Finally, economic 

theory suggests that labor supply effects are also possible. In the next section, we discuss the 

available empirical literature.

 

30 e.g., Graff Zivin and Neidell (2012). 
4-15 

4.3.2 Current State of Knowledge Based on the Peer-Reviewed Literature 

 In the labor economics literature there is an extensive body of peer-reviewed empirical 

work analyzing various aspects of labor demand, relying on the above theoretical framework.31

This work focuses primarily on the effects of employment policies, e.g. labor taxes, minimum 

wage, etc.32 In contrast, the peer-reviewed empirical literature specifically estimating 

employment effects of environmental regulations is very limited. In this section, we present an 

overview of the latter. As discussed in the preceding section on theory, determining the direction 

of employment effects in regulated industries is challenging because of the complexity of the 

output and substitution effects. Complying with a new or more stringent regulation may require 

additional inputs, including labor, and may alter the relative proportions of labor and capital used 

by regulated firms (and firms in other relevant industries) in their production processes. 

 Several empirical studies, including Berman and Bui (2001) and Morgenstern et al 

(2002), suggest that net employment impacts may be zero or slightly positive but small even in 

the regulated sector. Other research suggests that more highly regulated counties may generate 

fewer jobs than less regulated ones (Greenstone 2002, Walker 2011). However since these latter 

studies compare more regulated to less regulated counties they overstate the net national impact 

of regulation to the extent that regulation causes plants to locate in one area of the country rather 

than another. List et al. (2003) find some evidence that this type of geographic relocation may be 

occurring. Overall, the peer-reviewed literature does not contain evidence that environmental 

regulation has a large impact on net employment (either negative or positive) in the long run 

across the whole economy. 

 Environmental regulations seem likely to affect the environmental protection sector 

earlier than the regulated industry. Rules are usually announced well in advance of their effective 

dates and then typically provide a period of time for firms to invest in technologies and process 

changes to meet the new requirements. When a regulation is promulgated, the initial response of 

firms is often to order pollution control equipment and services to enable compliance when the 

regulation becomes effective. This can produce a short-term increase in labor demand for 

 

31 Again, see Hamermesh (1993) for a detailed treatment. 

32 See Ehrenberg & Smith (2000), Chapter 4: “Employment Effects: Empirical Estimates” for a concise overview. 
4-16 

specialized workers within the environmental protection sector, particularly workers involved in 

the design, construction, testing, installation, and operation of the new pollution control 

equipment required by the regulation (see Schmalansee and Stavins, 2011; Bezdek, Wendling, 

and Diperna, 2008). Estimates of short-term increases in demand for specialized labor within the 

environmental protection sector have been prepared for several EPA regulations in the past, 

including the Mercury and Air Toxics Standards (MATS).33

 

4.3.2.1 Regulated Sector 

 Determining the direction of net employment effects of regulation on industry is 

challenging. Two papers that present a formal theoretic model of the underlying profitmaximizing/cost-minimizing problem of the firm are Berman and Bui (2001) and Morgenstern, 

Pizer, and Shih (2002) mentioned above. 

 Berman and Bui (2001) developed an innovative approach to estimate the effect on 

employment of environmental regulations in California. Their model empirically examines how 

an increase in local air quality regulation affects manufacturing employment in the South Coast 

Air Quality Management District (SCAQMD), which incorporates Los Angeles and its suburbs. 

During the time frame of their study, 1979 to 1992, the SCAQMD enacted some of the country’s 

most stringent air quality regulations. Using SCAQMD’s local air quality regulations, Berman 

and Bui identify the effect of environmental regulations on net employment in the regulated 

industries.34 In particular, they compare changes in employment in affected plants to those in 

other plants in the same 4-digit SIC industries but in regions not subject to the local 

regulations.35 The authors find that “while regulations do impose large costs, they have a limited 

effect on employment” (Berman and Bui, 2001, p. 269). Their conclusion is that local air quality 

regulation “probably increased labor demand slightly” but that “the employment effects of both 

compliance and increased stringency are fairly precisely estimated zeros, even when exit and 

dissuaded entry effects are included” (Berman and Bui, 2001, p. 269).36 In their view, the limited 

effects likely arose because 1) the regulations applied disproportionately to capital-intensive 

 

33 U.S. EPA (2011b) 

34 Note, like Morgenstern, Pizer, and Shih (2002), this study does not estimate the number of jobs created in the 

environmental protection sector. 

35 Berman and Bui include over 40 4-digit SIC industries in their sample. 

36 Including the employment effect of exiting plants and plants dissuaded from opening will increase the estimated 

impact of regulation on employment. This employment effect is not included in Morgenstern et. al. (2002) 
4-17 

plants with relatively little employment, 2) the plants sold to local markets where competitors 

were subject to the same regulations (so that sales were relatively unaffected), and 3) abatement 

inputs served as complements to employment. 

 Morgenstern, Pizer, and Shih (2002) developed a similar structural approach to Berman 

and Bui’s, but their empirical application uses pollution abatement expenditures from 1979 to 

1991 at the plant-level, including air, water, and solid waste, to estimate net employment effects 

in four highly regulated sectors (pulp and paper, plastics, steel, and petroleum refining). Thus, in 

contrast to Berman and Bui (2001), this study identifies employment effects by examining 

differences in abatement expenditures rather than geographical differences in stringency. They 

conclude that increased abatement expenditures generally have not caused a significant change in 

net employment in those sectors. 

4.3.2.2 Environmental Protection Sector 

 The long-term effects of a regulation on the environmental protection sector, which 

provides goods and services that help protect the environment to the regulated sector, are 

difficult to assess. Employment in the industry supplying pollution control equipment or services 

is likely to increase with the increased demand from the regulated industry for increased 

pollution control.37

 

 A report by the U.S. International Trade Commission (2013) shows that domestic 

environmental services revenues have grown by 41 percent between 2000 and 2010. According 

to U.S. Department of Commerce (2010) data, by 2008, there were 119,000 environmental 

technology (ET) firms generating approximately $300 billion in revenues domestically, 

producing $43.8 billion in exports, and supporting nearly 1.7 million jobs in the United States. 

Air pollution control accounted for 18% of the domestic ET market and 16% of exports. Small 

and medium-size companies represent 99% of private ET firms, producing 20% of total revenue 

(OEEI, 2010).

4.3.2.3 Labor Supply Impacts 

 As described above, the small empirical literature on employment effects of 

environmental regulations focuses primarily on labor demand impacts. However, there is a 

 

37 See Bezdek, Wendling, and Diperna (2008), for example, and U.S. Department of Commerce (2010). 
4-18 

nascent literature focusing on regulation-induced effects on labor supply, though this literature 

remains very limited due to empirical challenges. This new research uses innovative methods 

and new data, and indicates that there may be observable impacts of environmental regulation on 

labor supply, even at pollution levels below mandated regulatory thresholds. Many researchers 

have found that work loss days and sick days as well as mortality are reduced when air pollution 

is reduced.38 EPA’s study of the benefits and costs of implementing clean air regulations used 

these studies to predict how increased labor availability would increase the labor supply and 

improve productivity and the economy. 39 Another literature estimates how worker productivity 

improves at the work site when pollution is reduced. Graff Zivin and Neidell (2013) review the 

work in this literature, focusing on how health and human capital may be affected by 

environmental quality, particularly air pollution. In previous research, Graff Zivin and Neidell 

(2012) use detailed worker-level productivity data from 2009 and 2010, paired with local ozone 

air quality monitoring data for one large California farm growing multiple crops, with a piecerate payment structure. Their quasi-experimental structure identifies an effect of daily variation 

in monitored ozone levels on productivity. They find “that ozone levels well below federal air 

quality standards have a significant impact on productivity: a 10 parts per billion (ppb) decrease 

in ozone concentrations increases worker productivity by 5.5 percent." (Graff Zivin and Neidell, 

2012, p. 3654). Such studies are a compelling start to exploring this new area of research, 

considering the benefits of improved air quality on productivity, alongside the existing literature 

exploring the labor demand effects of environmental regulations. 

4.3.3 Macroeconomic Net Employment Effects 

The preceding sections have outlined the challenges associated with estimating net 

employment effects within the regulated sector, in the environmental protection sector, and labor 

supply impacts. These challenges make it very difficult to accurately produce net employment 

estimates for the whole economy that would appropriately capture the way in which costs, 

compliance spending, and environmental benefits propagate through the macro-economy. 

 

38 The Benefits and Costs of the Clean Air Act from 1990 to 2020 Final Report – Rev. A , U.S. Environmental 

Protection Agency, Office of Air and Radiation, April 2011a. 

http://www.epa.gov/air/sect812/feb11/fullreport_rev_a.pdf

39 The Benefits and Costs of the Clean Air Act from 1990 to 2020 Final Report – Rev. A , U.S. Environmental 

Protection Agency, Office of Air and Radiation, April 2011a. 

http://www.epa.gov/air/sect812/feb11/fullreport_rev_a.pdf
4-19 

Quantitative estimates are further complicated by the fact that macroeconomic models often have 

very little sectoral detail and usually assume that the economy is at full employment. The EPA is 

currently in the process of seeking input from an independent expert panel on modeling 

economy-wide impacts, including employment effects. 

4.3.4 Conclusions 

 In conclusion, deriving estimates of how environmental regulations will impact net 

employment is a difficult task, requiring consideration of labor demand in both the regulated and 

environmental protection sectors. Economic theory predicts that the total effect of an 

environmental regulation on labor demand in regulated sectors is not necessarily positive or 

negative. Peer-reviewed econometric studies that use a structural approach, applicable to overall 

net effects in the regulated sectors, converge on the finding that such effects, whether positive or 

negative, have been small and have not affected employment in the national economy in a 

significant way. Effects on labor demand in the environmental protection sector seem likely to be 

positive. Finally, new evidence suggests that environmental regulation may improve labor supply 

and productivity. 

4.4 Small Business Impacts Analysis 

 The Regulatory Flexibility Act (RFA) as amended by the Small Business Regulatory 

Enforcement Fairness Act (SBREFA) generally 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 significant economic impact on a substantial number of small entities. Small entities 

include small businesses, small governmental jurisdictions, and small not-for-profit enterprises. 

The petroleum refining industry (NAICS code 324110) does not include small governmental 

jurisdictions or small not-for-profit enterprises. Under Small Business Administration (SBA) 

regulations, a small refiner is defined as a refinery with no more than 1,500 employees.40 For 

this analysis we applied the small refiner definition of a refinery with no more than 1,500 

employees. For additional information on the Agency’s application of the definition for small 

 

40 See Table in 13 CFR 121.201, NAICS code 324110. 
4-20 

refiner, see the June 24, 2008 Federal Register Notice for 40 CFR Part 60, Standards of 

Performance for Petroleum Refineries (Volume 73, Number 122, page 35858).41 

4.4.1 Small Entity Economic Impact Measures 

The analysis provides EPA with an estimate of the magnitude of impacts that the 

proposed standards may have on the ultimate domestic parent companies that own the small 

refineries. This section references the data sources used in the screening analysis and presents 

the methodology we applied to develop estimates of impacts, the results of the analysis, and 

conclusions drawn from the results. 

The small business impacts analysis for the risk and technology reviews for existing 

MACT 1 and MACT 2 standards and for Subpart Ja New Source Performance Standards 

amendments relies upon data collected through the April 2011 Information Collection Request 

(ICR -- OMB Control No. 2060-0657). Information collected through component 1 of the ICR 

includes facility location, products produced, capacity, throughput, process and emissions, and 

employment and sales receipt data. EPA performed a screening analysis for impacts on all 

affected small refineries by comparing compliance costs to revenues at the parent company level. 

This is known as the cost-to-revenue or cost-to-sales ratio, or the “sales test.” The “sales test” is

the impact methodology EPA employs in analyzing small entity impacts as opposed to a “profits 

test,” in which annualized compliance costs are calculated as a share of profits. The sales test is 

frequently used because revenues or sales data are commonly available for entities impacted by 

EPA regulations, and profits data normally made available are often not the true profit earned by 

firms because of accounting and tax considerations. The use of a “sales test” for estimating 

small business impacts for a rulemaking is consistent with guidance offered by EPA on 

compliance with the RFA42 and is consistent with guidance published by the U.S. SBA’s Office 

 

41 Refer to http://www.sba.gov/sites/default/files/Size_Standards_Table.pdf for more information on SBA small 

business size standards. 

42 The RFA compliance guidance to EPA rulewriters regarding the types of small business analysis that should be 

considered can be found at <http://www.epa.gov/sbrefa/documents/rfaguidance11-00-06.pdf> 
4-21 

of Advocacy that suggests that cost as a percentage of total revenues is a metric for evaluating 

cost increases on small entities in relation to increases on large entities (U.S. SBA, 2010).43

4.4.2 Small Entity Economic Impact Analysis 

As discussed in Section 2 of this EIA, as of January 2011 there were 148 petroleum 

refineries operating in the continental United States and US territories with a cumulative capacity 

of processing over 17 million barrels of crude per calendar day (EIA, 2011b). Sixty-four (64) 

parent companies own these refineries, and we have employment and sales data for 62 (96%) of 

them. Thirty-five (35) companies (56% of the 62 firm total) employ fewer than 1,500 workers 

and are considered small businesses. These firms earned an average of $1.36 billion of revenue 

per year, while firms employing more than 1,500 employees earned an average of $82.5 billion 

of revenue per year.44

 Based on data collected through the April 2011 ICR, EPA performed the sales test 

analysis for impacts on affected small refineries. Five (5) of the 35 small refiners were removed 

from the analysis because we determined they were not major sources and would not be subject 

to the rules, and two (2) of the 35 small refiners were not analyzed because we had no ICR 

and/or other publically available employment and sales data. The 5 small refiners removed from 

the analysis had parent company revenues ranging from $5 million to $225 million, with average 

revenues of $64 million. Two of these small refiners had revenues of less than $10 million, and 

another small refiner had revenues just over $10 million. Of the 2 small refiners that were not 

analyzed because of missing data, one (1) small refiner shut down in 2007 and the other provided 

information that they were a specialty chemical company and not a refinery. These seven small 

refiners will not be subject to the rule. 

 

43U.S. SBA, Office of Advocacy. A Guide for Government Agencies, How to Comply with the Regulatory 

Flexibility Act, Implementing the President’s Small Business Agenda and Executive Order 13272, June 2010. 

44 The U.S. Census Bureau’s Statistics of U.S. Businesses include the following relevant definitions: (i)

establishment – a single physical location where business is conducted or where services or industrial operations 

are performed; (ii) firm – a firm is a business organization consisting of one or more domestic establishments in the 

same state and industry that were specified under common ownership or control. The firm and the establishment are 

the same for single-establishment firms. For each multi-establishment firm, establishments in the same industry 

within a state will be counted as one firm; and (iii) enterprise -- an enterprise is a business organization consisting 

of one or more domestic establishments that were specified under common ownership or control. The enterprise and 

the establishment are the same for single-establishment firms. Each multi-establishment company forms one 

enterprise. 
4-22 

Table 4-5 presents the distribution of estimated cost-to-sales ratios for the small firms in 

our analysis. We analyzed the estimated cost-to-sales with and without the recovery credit, and 

in both cases the incremental compliance costs imposed on small refineries are not estimated to 

create significant impacts on a cost-to-sales ratio basis at the firm level. 

Table 4-5 Impact Levels of Proposed NESHAP Amendments on Small Firms 

Impact Level 

Number of Small Firms in 

Sample Estimated to be 

Affected 

% of Small Firms in 

Sample Estimated to be 

Affected 

Cost-to-Sales Ratio less than 1% 28 100% 

Cost-to-Sales Ratio 1-3% 0 -- 

Cost-to-Sales Ratio greater than 3% 0 -- 

 For comparison, we calculated the cost-to-sales ratios for all of the affected refineries to 

determine whether potential costs would have a more significant impact on small refineries. As 

presented in Table 4-6, for large firms, without recovery credits the average cost-to-sales ratio is 

approximately 0.02 percent; the median cost-to-sales ratio is less than 0.01 percent; and the 

maximum cost-to-sales ratio is approximately 0.89 percent; with recovery credits these impacts 

do not substantially change, except the maximum cost-to-sales ratio decreases to approximately 

0.44 percent. For small firms, without recovery credits the average cost-to-sales ratio is about 

0.07 percent, the median cost-to-sales ratio is 0.03 percent, and the maximum cost-to-sales ratio 

is 0.62 percent; with recovery credits these impacts do not substantially change, except the 

maximum cost-to-sales ratio decreases slightly to approximately 0.60 percent. The potential 

costs do not have a more significant impact on small refiners and because no small firms are 

expected to have cost-to-sales ratios greater than one percent, we determined that the cost 

impacts for the risk and technology reviews for existing MACT 1 and MACT 2 standards will 

not have a significant economic impact on a substantial number of small entities (SISNOSE). 
4-23 

Table 4-6 Summary of Sales Test Ratios for Firms Affected by Proposed NESHAP 

Amendments 

Firm Size 

No. of Known 

Affected Firms

% of Total Known 

Affected Firms 

Mean Cost-toSales Ratio Median Cost-toSales Ratio 

Min. 

Cost-toSales 

Ratio 

Max. Costto-Sales 

Ratio 

Small 28 51% 0.07% 0.03% <0.01% 0.62%

Large 27 49% 0.02% <0.01% <0.01% 0.89% 

All 55 100% 0.03% <0.01% <0.01% 0.89% 

 
4-24 

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