# 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 2014ii CONTACT INFORMATION
This document has been prepared by staff from the O ffice of Air Quality Planning and Standards, U.S. Environmental Protection Agency and RTI International. Questions related to this document should be addressed to Alexander Macp herson, U.S. Environmental Protection Agency, Office of Air Quality Planning and Standard s, C445-B, Research Triangle Park, North Carolina 27711 (email: macpherson.alex@epa.gov ).

ACKNOWLEDGEMENTS

In addition to EPA staff from the Office of Air Qua lity Planning and Standards, personnel from RTI International contributed signif icant data and analysis to this document under contract number EP-D-06-003.iii TABLE OF CONTENTS

T ABLE OF C ONTENTS .................................................. ................................................... ............... III L IST OF T ABLES .................................................. ................................................... ......................... V L IST OF F IGURES .................................................. ................................................... ...................... VI 1 E XECUTIVE S UMMARY .................................................. ................................................... ... 1-1
1.1 B ACKGROUND

.................................................. ................................................... ......................................... 1-1 1.2 R ESULTS

.................................................. ................................................... ................................................. 1 -1 1.3 O RGANIZATION OF THIS R EPORT

.................................................. ................................................... ............. 1-2 2 I NDUSTRY P ROFILE .................................................. ................................................... ........ 2-1
2.1 I NTRODUCTION

.................................................. ................................................... ....................................... 2-1 2.2 T HE S UPPLY S IDE

.................................................. ................................................... .................................... 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 T HE D EMAND S IDE

.................................................. ................................................... ............................... 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 I NDUSTRY O RGANIZATION

.................................................. ................................................... .................... 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 I ndustry ........................................... .. 2-20 2.4.2 Characteristics of U.S. Petroleum Refineries and Pe troleum Refining Companies ........................ . 2-20 2.4.2.1 Geographic Distribution of U.S. Petroleum Refinerie s ................................................. ......... 2-20 2.4.2.2 Capacity Utilization ..............................

................................................... ............................... 2-20 2.4.2.3 Characteristics of Small Businesses Owning U.S. Pet roleum Refineries ............................... 2 -23 2.5 M ARKETS

.................................................. ................................................... .............................................. 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 R EFERENCES

.................................................. ................................................... ......................................... 2-44 3 E MISSIONS AND E NGINEERING C OSTS .................................................. .............................. 3-1
3.1 I NTRODUCTION

.................................................. ................................................... ....................................... 3-1 3.2 S UMMARY OF P ROPOSED R ULE A MENDMENTS

.................................................. .......................................... 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 ...........................

................................................... .................................... 3-10iv

3.2.5 Flare Monitoring ..................................

................................................... ......................................... 3-12 3.2.6 FCCU Testing ......................................

................................................... ......................................... 3-17 3.3 S UMMARY OF C OSTS OF P ROPOSED R ULE A MENDMENTS

.................................................. ........................ 3-17 4 E CONOMIC I MPACT A NALYSIS AND D ISTRIBUTIONAL A SSESSMENTS ............................... 4-1
4.1 I NTRODUCTION

.................................................. ................................................... ....................................... 4-1 4.2 M ARKET A NALYSIS

.................................................. ................................................... ................................ 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 Complianc e Costs into Economic Model ................... 4-6 4.2.5 Model Results .....................................

................................................... ............................................ 4-7 4.2.6 Limitations .......................................

................................................... ............................................... 4-9 4.3 D ISCUSSION OF E MPLOYMENT I MPACTS

.................................................. ................................................... . 4-9 4.3.1 Theory ............................................

................................................... ............................................... 4-1 0 4.3.2 Current State of Knowledge Based on the Peer-Review ed 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 S MALL B USINESS I MPACTS A NALYSIS

.................................................. ................................................... .. 4-19 4.4.1 Small Entity Economic Impact Measures .............

................................................... ........................ 4-20 4.4.2 Small Entity Economic Impact Analysis .............

................................................... ......................... 4-21 4.5 R EFERENCES

.................................................. ................................................... ......................................... 4-24v 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 Petro leum Refineries (NAICS 324110).................. 2- 12 Table 2-4 Costs of Materials Used in Petroleum Refining Indus try ............................................... ................. 2-13 Table 2-5 Major Refinery Products ...........................

................................................... .................................... 2-15 Table 2-6 Market Concentration Measures of the Petroleum Refi ning 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 Petr oleum Refineries .................................. ........... 2-23 Table 2-9 Characteristics of Small Businesses in the Petroleu m Refining Industry ............................... ......... 2-30 Table 2-10 Total Petroleum Products Supplied (millions of barr els 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 Refinin g Industry ........................................ ............ 2-37 Table 2-13 Imports of Major Petroleum Products (millions of ba rrels per year) ................................... ............ 2-37 Table 2-14 Exports of Major Petroleum Products (millions of ba rrels per year) ................................... ............ 2-38 Table 2-15 Average Price of Major Petroleum Products Sold to E nd 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 Petrol eum Refiners: 2010 ................................ ...... 2-42 Table 2-19 Forecasted Average Price of Major Petroleum Product s Sold to End Users in 2009 Currency (cents per gallon) 2-43 Table 2-20 Total Petroleum Products Supplied (millions of barr els per year) ..................................... .............. 2-43 Table 2-21 Full Production Capacity Utilization Rates for Petr oleum Refineries .................................. ........... 2-44 Table 3-1 Nationwide Emissions Reduction an d Cost Impacts of Control Options for Storage Vesse ls 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$) for Fe nceline Monitoring at Petroleum Refineries ........ .................... 3-10 Table 3-5 Nationwide Costs for Equipment Lea ks (2009$) ........................................ ..................................... 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 b y 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 Smal l Firms ........................................... ... 4-22 Table 4-6 Summary of Sales Test Ratios for Firms Affected by Proposed NESHAP Amendments ............... 4-23vi 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 Petrole um Refineries (N=61) ............................ 2 -24 Figure 2-7 Average Revenue of Companies Owning Petroleum Refin eries by Employment (N=61) .............. 2-25 Figure 2-8 Revenue Distribution of Large Companies Owning Petr oleum Refineries (N=25) ......................... 2 -26 Figure 2-9 Revenue Distribution of Small Companies Owning Petr oleum Refineries (N=36) ......................... 2 -27 Figure 2-10 Total Petroleum Products Supplied (millions of barr els per year) ..................................... .............. 2-341-1 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 w ill 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 analysi s anticipated from the proposed NESHAP and NSPS amendments. We also provide a small busin ess 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 f ollow:

 Engineering Cost Analysis: Total annualized engineering costs measure the cost s incurred by affected industries annually. The annualized eng ineering 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 w ith proposed requirements for storage vessels, delayed coking units, and fugitive emissio ns 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 $213,0 00 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. Produ ct prices are predicted to increase less than 0.0001% on average, while production levels decreas e 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 im pacts for 28 affected small refineries. The cost-to-sales ratio was below 1 percent for all aff ected small firms. As such, we determined that proposed options will not have a significant e conomic 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 industrie s.

1 Note that this estimate does not reflect any corre ctive action taken in response to the fenceline mon itoring program. Any corrective actions associated with fenceline mo nitoring will result in additional emissions reduct ions and additional costs.1-2

1.3 Organization of this Report
The remainder of this report details the methodolog y and the results of the EIA. Section 2 presents the industry profile of petroleum refini ng 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 ind ustry provides information that will support this and subsequent regulatory impact analy ses (RIAs) and economic impact analyses (EIAs) that will assess the impacts of these standa rds.
At its core, the petroleum refining industry compri ses establishments primarily engaged in refining crude petroleum into finished petroleum products. Examples of these petroleum products include gasoline, kerosene, asphalt, lubri cants, 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 continenta l 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 follow s. Section 2.2 provides a detailed description of the inputs, outputs, and processes i nvolved in petroleum refining. Section 2.3 describes the applications and users of finished pe troleum 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 evalu ating the impact on small business to meet the requirements of the Small Business Regulatory Enfor cement and Fairness Act (SBREFA). Section 2.5 contains market-level data on prices an d quantities and discusses trends and projections for the industry.

2.2 The Supply Side Estimating the economic impacts of any regulation o n the petroleum refining industry requires a good understanding of how finished petro leum 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 invol ved 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 so lely of hydrogen and carbon) and various impurities such as salt. To manufacture the variety of petroleum products recognized in everyday2-2

life, this mixture must be refined and processed ov er 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 petro leum 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”). Thes e fractions include gasoline, kerosene, naphtha, and other products (EPA, 1995).
In the second phase, the distilled fractions are co nverted 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 tre ated to remove salts, suspended solids, and other impurities that could c log or corrode the downstream equipment. This process, known as “desalting,” is typically do ne by first heating the crude oil, mixing it with process water, and depositing it into a gravity set tler 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 chemic als (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 t reatment 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 Safe ty 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 Safe ty 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 atmosphe ric pressure. After entering the tower, the lighter fractions flash into vapor and travel up th e tower. This leaves only the heaviest fractions (which have a much higher boiling point) at the bot tom of the tower. These fractions include heavy fuel oil and asphalt residue (EPA, 1995).
As the hot vapor rises, its temperature is graduall y reduced. Lighter fractions condense onto trays located at successively higher portions of th e tower. For example, motor gasoline will condense at higher portion of the tower than kerose ne because it condenses at lower temperatures. This process is illustrated in Figure 2-3. As these fractions condense, they will be drawn off their respective trays and potentially sent downstream fo r further processing (OSHA, 2003; EPA, 1995).

Figure 2-3 Atmospheric Distillation Process Source: U.S. Department of Labor, Occupational Safe ty 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) withou t cracking under requisite heat and pressure. So these fractions are separated using a process ca lled 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 incr ease volatilization and separation. A typical first-phase vacuum tower may produce gas oils or lu bricating-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 Safe ty 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 m arket 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 l arger molecules, or shaping them into higher quality molecules (EPA, 1995).
Downstream processes include thermal cracking, coki ng, catalytic cracking, catalytic hydrocracking, hydrotreating, alkylation, isomeriza tion, polymerization, catalytic reforming, solvent extraction, merox, dewaxing, propane deasph alting 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 th is section.

Wastewater Treatment. Petroleum refining operations produce a variety of wastewaters including process water (water used in process oper ations like desalting), cooling water (water used for cooling that does not come into direct con tact with the oil), and surface water runoff (resulting from spills to the surface or leaks in t he equipment that have collected in drains).2-6

Wastewater typically contains a variety of contamin ants (such as hydrocarbons, suspended solids, phenols, ammonia, sulfides, and o ther compounds) and must be treated before it is recycled back into refining operations or dis charged. Petroleum refineries typically utilize two stages of wastewater treatment. In primary wast ewater 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 treat ment before being discharged directly to surface water. In secondary treatment, microorganis ms 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 concentra tion of hydrogen sulfide mixed with light refinery fuel gases (such as methane and ethane). S ulfur must be removed from these gases in order to comply with the Clean Air Act’s SO x emission limits and to recover saleable elemental sulfur.
Sulfur is recovered by first separating the fuel ga ses 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, hydrog en sulfide is burned under controlled conditions producing sulfur dioxide. A bauxite cata lyst is then used to react with the sulfur dioxide and the unburned hydrogen sulfide to produc e elemental sulfur. However, the Claus process only removes 90% of the hydrogen sulfide pr esent 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 prod ucts to improve their quality or add special characteristic s. For example, ethers have been added to gasoline to increase octane levels and reduce CO em issions 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 he at is managed through heat exchangers, which are compo sed of bundles of pipes, tubes, plate coils, and other equipment that surround heating or coolin g 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 man aged to avoid accident. Pressure-relief systems enable the safe handling of liquids and gas es that are released by pressure-relieving2-7

devices and blow-downs. According to the OSHA Techn ical 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 mater ial, such as blow-downs from process unit startups, furnace blow-downs, shutdowns, and emerge ncies” (OSHA, 2003).
Blending. Blending is the final operation in petroleum refin ing. It is the physical mixture of a number of different liquid hydrocarbons to pro duce final petroleum products that have desired characteristics. For example, additives suc h 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 p roducts 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. The se 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 c omposition from one oil field to another. An “average” crude oil contains about 84% carbon; 1 4% 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 rang es 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 (S peight 2006).
In 2010, the petroleum refining industry used 5.4 b illion 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 a re used in the production of petroleum products. The specif ic 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 th eir applications.

2 Crude oil processing requires large volumes of wat er, a large portion of which is continually recycle d. The amount of water used by a refinery can vary significantly, depending on process configuration, refinery compl exity, capability for recycle, degree of sewer segregation , and local rainfall. In 1992, the average amount o f 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 Material s used in Petroleum Refineries

Type Description Crude Oil Heterogeneous mixture of different hydroc arbon 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 n eutralize acids and reduce corrosion. They are also added to desalted crude in order to r educe 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 i n common use except in aviation gasoline. Sulfuric Acid and Hydrofluoric Acid Sulfuric acid and hydrofluoric acid are used primar ily as catalysts in alkylation processes. Sulfuric acid is also used in some treat ment processes. Source: U.S. Department of Labor, Occupational Safe ty 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 m illion barrels of natural gas liquids and other liquids in the production of finished pet roleum products (EIA 2010).

2.2.1.4 Types of Product Outputs The petroleum refining industry produces a number o f products that fall into one of three categories: fuels, finished nonfuel products, and f eedstock for the petrochemical industry. Table 2-2 briefly describes these product categories. A m ore 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 ship s. Typical petroleum fuel products include gasoline, jet fuel, and residual f uel oil. Finished nonfuel products Petroleum products that a re not used for powering machines or equipment. The se products typically include asphalt, lubricants (suc h as motor oil and industrial greases), and solvents (such as benzene, toluene, a nd xylene). Feedstock

Sulfur Many products derived from crude oil refining, such as ethylene, propylene, butylene, and isobutylene, are primarily intended f or 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 manufactur e of sulfuric acid , a primary industrial chemical. Source: U.S. Department of Labor, Occupational Safe ty 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 hazardou s 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 oxide s (SO x ), nitrogen oxides (NO x ), particulates, and volatile organic compounds (VOCs) ; and the other pollutants include spent acids, gaseous pollutants, ammonia (NH 3 ), and hydrogen sulfide (H 2 S).

2.2.2.1 Gaseous and VOC Emissions As previously mentioned, CO, SO x , NO x , NH 3 , and H 2 S emissions are produced along with petroleum products. Sources of these emissions from refineries include fugitive emissions of the volatile constituents in crude oil and its f ractions, emissions from the burning of fuels in process heaters, and emissions from the various ref inery 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 po tential sources of SO x , NO x , CO, and hydrocarbons emissions. Emissions are low when proc ess heaters are operating properly and using clean fuels such as refinery fuel gas, fuel o il, or natural gas. However, if combustion is not complete, or the heaters are fueled using fuel pitc h or residuals, emissions can be significant (EPA, 1995).
The majority of gas streams exiting each refinery p rocess contain varying amounts of refinery fuel gas, H 2 S, and NH 3 . These streams are directed to the gas treatment a nd sulfur recovery units described in the previous section. H ere, refinery fuel gas and sulfur are recovered using a variety of processes. These processes creat e emissions of their own, which normally contain H 2 S, SO x , and NO x gases (EPA, 1995). For additional details on refi nery fuel, or waste, gas composition, see Table 12 of the January 25, 20 12 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 regen eration of catalysts that are used in downstream processes. These processes generate stre ams that may contain relatively high levels of CO, particulate, and VOC emissions. However, the se emissions are treated before being discharged to the atmosphere. First, the emissions are processed through a CO boiler to burn CO2-10

and any VOC, and then through an electrostatic prec ipitator 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 sur face water runoff (resulting from spills to the surface or leaks in the equipment that have collect ed in drains). This wastewater typically contains a variety of contaminants (such as hydroca rbons, suspended solids, phenols, NH 3 , 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 proces s 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 materi als accounted for the largest cost to petroleum refineries—amounting to 95% of total expe nses (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 electri city and fuel consumed.
Average Percentage (1995–2009)

Figure 2-5 Petroleum Refinery Expenditures2-11

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 Manufacture s. M05(AS)-1. Washington, DC: Government Printing Offi ce. Available at <http://www.census.gov/prod/2006pubs/ U.S. Department of Commerce, Bureau of the Census. 2003a. 2001 Annual Survey of Manufacture s. M01(AS)-1. Washington, DC: Government Printing Offi ce. Available at <http://www.census.gov/prod/2003pubs/ U.S. Department of Commerce, Bureau of the Census. 2001. 1999 Annual Survey of Manufacture s. M99(AS)-1 (RV). Washington, DC: Government Printing Office. Available at <http://www.census.gov/prod/2001pubs/ U.S. Department of Commerce, Bureau of the Census. 1998. 1996 Annual Survey of Manufacture s. M96(AS)-1 (RV). Washington, DC: Government Printing Office. Available at <http://www.census.gov/prod/3/98pubs/ U.S. Department of Commerce, Bureau of the Census. 1997. 1995 Annual Survey of Manufacture s. M95(AS)-1. Washington, DC: Government Printing Offi ce. 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 2 008 and 2009 numbers] http://factfinder.census.gov/servlet/IBQTable?_bm=y &-NAICSASM=324110&-ds_name= AM0931GS101&-ib_type=NAICSASM&-_industry=324110&-_l ang=en U.S. Census Bureau, American FactFinder; “Sector 31 : Manufacturing: Industry Series: Detailed Statistics by Industry for the United Stat es: 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 expen ses faced by petroleum refiners. Capital expenditures include permanent additions an d alterations to facilities and machinery and equipment used for expanding plant capacity or repl acing existing machinery. A detailed breakdown of how much petroleum refiners spent on e ach of these factors of production over this 15-year period is provided in Table 2-3. A mor e 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 Ca pital ($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 pri ce index industry for total manufacturing industrie s (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 <htt p://factfinder.census.gov/home/saff/main.html?_lang =en>. U.S. Department of Commerce, Bureau of the Census. 2006. 2005 Annual Survey of Manufacture s. M05(AS)-1. Washington, DC: Government Printing Office. Availab le at <http://www.census.gov/prod/2006pubs/ am0531gs1.pdf>. As obtained on October 23, 2007. U.S. Department of Commerce, Bureau of the Census. 2003a. 2001 Annual Survey of Manufacture s. M01(AS)-1. Washington, DC: Government Printing Office. Availab le at <http://www.census.gov/prod/2003pubs/ m01as-1.pdf>. As obtained on October 23, 2006. U.S. Department of Commerce, Bureau of the Census. 2001. 1999 Annual Survey of Manufacture s. M99(AS)-1 (RV). Washington, DC: Government Printing Office. A vailable at <http://www.census.gov/prod/2001pubs/ m99-as1.pdf>. As obtained on October 23, 2006. U.S. Department of Commerce, Bureau of the Census. 1998. 1996 Annual Survey of Manufacture s. M96(AS)-1 (RV). Washington, DC: Government Printing Office. A vailable at <http://www.census.gov/prod/3/98pubs/ m96-as1.pdf>. As obtained on October 23, 2006. U.S. Department of Commerce, Bureau of the Census. 1997. 1995 Annual Survey of Manufacture s. M95(AS)-1. Washington, DC: Government Printing Office. Availab le at <http://www.census.gov/prod/2/manmin/ asm/m95as1.pdf>. As obtained on October 23, 2006. U.S. Census Bureau, American FactFinder; “Sector 3 1: Annual Survey of Manufactures: General Statistic s: Statistics for Industry Groups and Industries: 2009 and 2008 “ Release Date: 12/3/10; (Data accessed o n 10/10/11). [Source for 2008 and 2009 numbers] http://factfinder.census.gov/servlet/IBQTable?_bm=y &- NAICSASM=324110&-ds_name=AM0931GS101&-ib_type=NAICS ASM&-_industry=324110&-_lang=en U.S. Census Bureau, American FactFinder; “Sector 3 1: Manufacturing: Industry Series: Detailed Statist ics 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=en2-13

Table 2-4 Costs of Materials Used in Petroleum Refi ning Industry 2007 2002

Material Delivered Cost ($10 3 ) Percentage

of Material Costs Delivered

Cost ($10 3 ) 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% 1,9 25,738 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% H 2 SO 4 ) 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. Avail able 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” Rele ase 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=&-_ind ustry=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 aspec ts of the demand for finished petroleum products. This section describes the characteristic s of finished petroleum products, their uses and consumers, and possible substitutes.

2.3.1 Product Characteristics Petroleum refining firms produce a variety of diffe rent products. The characteristics these products possess largely depend on their intended u se. 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 prod ucts can be categorized into three broad groups based on their intended uses (EIA, 1999a):

 fuels —petroleum products that are capable of releasing e nergy 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 grou ps is presented in Table 2-5 along with a description of each product’s characteristics and p rimary 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). Sim ilarly, 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 deri ved from the demand for the goods and services they are used to create.
The principal end users of petroleum products can b e separated into five sectors:

 Residential sector—private homes and residences

 Industrial sector—manufacturing, construction, mini ng, agricultural, and forestry establishments

 Transportation sector—private and public vehicles t hat move people and commodities such as automobiles, ships, and aircraf t2-15  Commercial sector—nonmanufacturing or nontransporta tion business establishments such as hotels, restaurants, retail stores, religio us and nonprofit organizations, as well federal, state, and local government institutions

 Electric utility sector—privately and publicly owne d establishments that generate, transmit, distribute, or sell electricity (primaril y) 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 gas oline 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 othe r equipment. Other forms of gasoline include Aviation gasoline, which is used t o power small planes. Kerosene Kerosene is a refined middle-distillate pe troleum product that finds considerable use as a jet fuel. Kerosene is also used in water heate rs, as a cooking fuel, and in lamps. Liquefied petroleum gas (LPG) LPG consists principally of propane (C 3 H 8 ) and butane (C 4 H 10 ). It is primarily used as a fuel in domestic heating, cooking, and farming operations. Distillate fuel oil Distillate fuel oil includes di esel oil, heating oils, and industrial oils. It is used to power diesel engines in buses, trucks, trains, auto mobiles, as well as other machinery. Residual fuels Residual fuels are the fuels distill ed from the heavier oils that remain after atmospheric distillation; they find their primary u se 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 i s 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 c an be used a raw material for many carbon and graphite products such as furnace electr odes and liners. Asphalt Asphalt, used for roads and roofing materia ls, must be inert to most chemicals and weather conditions. Lubricants Lubricants are the result of a special r efining process that produce lubricating oil base stocks, which are mixed with various additives. Pet roleum lubricating products include spindle oil, cylinder oil, motor oil, and i ndustrial greases. Solvents A solvent is a fluid that dissolves a soli d, liquid, or gas into a solution. Petroleum based solvents, such as Benzyme, are used to manufa cture detergent and synthetic fibers. Other solvents include toluene and xylene.

Feedstock Ethylene Ethylene is the simplest alkene and has the chemica l formula C 2 H 4 . It is the most produced organic compound in the world and it is us ed in the production of many products. For example, one of ethylene’s derivative s is ethylene oxide, which is a primary raw material in the production of detergent s. Propylene Propylene is an organic compound with the chemical formula C 3 H 6 . It is primarily used the production of polypropylene, which is used in the production of food packaging, ropes, and textiles. Sources: U.S. Department of Labor, Occupational Saf ety 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 Admi nistration (EIA). 1999.2-16

Of these end users, the transportation sector consu mes the largest share of petroleum products, accounting for 67% of total consumption i n 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-user s primarily consume fuel. Fuel products account for 9 out of 10 barrels of petrole um used in the United States (EIA, 1999a). In 2005, motor gasoline alone accounted for 49% of dem and for finished petroleum products (EIA, 2006a).

2.3.3 Substitution Possibilities in Consumption A major influence on the demand for finished petrol eum products is the availability of substitutes. In some sectors, like the transportati on 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 (E IA, 1999a).
For example, equipment at large manufacturing plant s 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, 19 99a).
However, over time, demand for petroleum products c ould 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 eth anol (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 locat ion, 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 o f competition among petroleum refining companies and determines their power to in fluence market prices for their products. For example, if an industry is perfectly competitive, t hen individual producers cannot raise their2-17

prices above the marginal cost of production withou t losing market share to their competitors. Understanding pricing behavior in the petroleum ref ining industry is crucial for performing subsequent EIAs.
According to basic microeconomic theory, perfectly competitive industries are characterized by unrestricted entry and exit of fir ms, large numbers of firms, and undifferentiated (homogenous) products being sold. Conversely, imper fectly 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 prod uct attributes or brand name recognition of products). This section considers whether the petro leum refining industry is competitive, based on these three factors.

2.4.1.1 Barriers to Entry Firms wanting to enter the petroleum refining indus try may face at least two major barriers to entry. First, according to a 2004 Feder al Trade Commission staff study, there are significant economies of scale in petroleum refiner y 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 a verage costs than firms that are established and produce at higher levels, which will make it more d ifficult for these new firms to compete (Nicholson, 2005). This is known as a technical bar rier 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 leg al barrier to entry is patents—intellectual property rights, granted by the government, that gi ve exclusive monopoly to an inventor over his invention for a limited time period. In the petrole um refining industry, firms rely heavily on process patents to appropriate returns from their i nnovations. As a result, firms seeking to enter the petroleum refining industry must develop proces ses that respect the novelty requirements of these patents, which could potentially make entry m ore difficult for new firms (Langinier, 2004). A second example of a legal barrier would be enviro nmental 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 o nes. As a result, new firms may be less competitive.
Although neither of these barriers is impossible fo r new entrants to overcome, they can make it more difficult for new firms to enter the m arket for manufactured petroleum products. As a result, existing petroleum refiners could potenti ally raise their prices above competitive levels with less worry about new firms entering the market to compete away their customers with lower2-18

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 competi tive levels.

2.4.1.2 Measures of Industry Concentration Economists often use a variety of measures to asses s the concentration of a given industry. Common measures include four-firm concent ration ratios (CR4), eight-firm concentration ratios (CR8), and Herfindahl-Hirschma nn indexes (HHI). The CR4s and CR8s measure the percentage of sales accounted for by th e top four and eight firms in the industry. The HHIs are the sums of the squared market shares of f irms in the industry. These measures of industry concentrated are reported for the petroleu m 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 pa rtially due to merger activity during this time period. Between 1990 and 2000, over 2,600 mergers o ccurred across the petroleum industry; 13% of these mergers occurred in the industry’s ref ining 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 Commiss ion, 1992). According to these criteria, industries with HHIs below 1,000 are considered unc oncentrated (i.e., more competitive); industries with HHIs between 1,000 and 1,800 are co nsidered moderately concentrated (i.e., moderately competitive); and industries with higher HHIs are considered heavily concentrated. Based on this criterion, the petroleum refining ind ustry 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 expl icitly 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 com paring HHIs across Petroleum Administration for Defense Districts (PADDs). PADDs separate the United States into five geographic regions or districts. They were initiall y created during World War II to help manage2-19

the allocation of fuels during wartime. However, th ey have remained in use as a convenient way of organizing petroleum market information (FTC, 20 04).

Table 2-6 Market Concentration Measures of the Petr oleum 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, an d Antitrust Enforcement.” Available at <http://www.ft c.gov/opa/2004/08/oilmergersrpt.shtm>. As obtained on February 6, 2007. U.S. Census Bureau, American FactFinder; “Sector 3 1: Manufacturing: Subject Series: Concentration Rat ios: Share of Value of Shipments Accounted for by the 4, 8, 20, and 50 Largest Companies for Industries: 20 07 “ Release Date 1/7/2011; (Data accessed on 10/12/11) [Source for 2007 numbers]<http://factfinder.census.gov/servlet/IBQTa ble?_bm=y&-ds_name=EC0731SR12&- NAICS2007=324110&-ib_type=NAICS2007&-NAICS2007secto r=*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. Concent ration in PADD IV (Rocky Mountains) was also low in 2003, with an HHI of 944. PADD V gradua lly 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, 2 004).

2.4.1.3 Product Differentiation Another way firms can influence market prices for t heir product is through product differentiation. By differentiating one’s product a nd 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 v ariety 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 small2-20

refining businesses producing specialty products fo r 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 I ndustry 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 com petition among firms, it seems unlikely that individual petroleum refiners would be able to sign ificantly influence market prices given the current structure of the market.

2.4.2 Characteristics of U.S. Petroleum Refineries and Pe troleum 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 th at conduct transactions and make decisions that affect the facility. The terms “facility,” “establi shment,” and “refinery” are synonymous in this report and refer to the physical location where pro ducts are manufactured. Likewise, the terms “company” and “firm” are used interchangeably to re fer to the legal business entity that owns one or more facilities. This section presents infor mation 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 Refinerie s There are approximately 148 petroleum refineries op erating in the United States, spread across 32 states. The number of petroleum refinerie s located in each of these states is listed in Table 2-7. This table illustrates that a significan t portion of petroleum refineries are located along the Gulf of Mexico region. The leading petrol eum refining states are Texas, Louisiana, and California.

2.4.2.2 Capacity Utilization Capacity utilization indicates how well current ref ineries 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 volu mes. 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 industr y-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 condit ions, but also on a company’s strategic position in its particular industry. While some pla nts may have idle production lines or empty floor space, others need additional space or capaci ty.
Table 2-8 lists the capacity utilization rates for petroleum refineries from 2000 to 2010. It is interesting to note the declines in capacity uti lization from 2007 to 2008 and again from 2008 to 2009. These declines seem counter intuitive beca use there does not appear to be evidence that demand for petroleum products is dropping. To under stand this better, it is important to realize that the capacity utilization ratio in the petroleu m industry represents the utilization of the atmospheric crude oil distillation units. This rat io is calculated for the petroleum industry by dividing the gross input to atmospheric crude oil d istillation units (all inputs involved in atmospheric crude oil distillation, such as crude o il) 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 PA D 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 Rate s 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 Informat ion Administration (EIA). 2007a. “Refinery Utilizat ion and Capacity.” Available at <http://tonto.eia.doe.gov/ dnav/pet/ pet_pnp_unc_dcu_nus_m.htm>. As obtained o n January, 2007. U.S. Energy Information Administration (EIA), “Ref inery Utilization and Capacity.” Available at http://www.eia.gov/dnav/pet/pet_pnp_unc_dcu_nus_a.h tm; Release date: 7/28/11; (Data accessed on 10/11/11). [Source for 2007-2010 numbers]
From 2007 to 2008 operational capacity increased fr om 17,450,000 barrels per calendar day to 17,607,000 barrels per calendar day at the s ame 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 2 009 operational capacity increased from 17,607,000 barrels per calendar day to 17,678,000 b arrels per calendar day at the same time gross inputs fell from 15,027,000 barrels per calen dar 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. Pet roleum Refineries Under Small Business Administration (SBA) regulatio ns, 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 em ployees. For additional information on the Agency’s application of the definition for small re finer, 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 refine ries 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 identifi ed 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 employme nt 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 ref ining capacity.
The distribution of employment across companies is illustrated in Figure 2-6. As this figure shows, 36 companies (59% of the 61 total) em ploy 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 employe es earned an average of $82.5 billion of revenue per year (Figure 2-7). Distributions of th e number of large and small firms earning different levels of revenue are presented in Figure s 2-8 and 2-9.

Figure 2-6 Employment Distribution of Companies Own ing Petroleum Refineries (N=61) Sources: Employment Data from Petroleum Refinery Em issions Information Collection, where available, Component 1, OMB Control No. 2060-0657. Hoovers 2011 Online Data, accessed through Univers ity of South Carolina’s Moore School of Business Library. Hoovers 2011 Online Data reflects either a ctual data for 2010/2011 reported by companies, estimated data for 2011, or occasionally 2009 value s. Million Dollar Database online, 2011, accessed thr ough University of South Carolina’s Moore School of Business Library. Million Dollar Online Data reflec ts either actual data for 2011 reported by companie s or estimated data for 2011. Ward’s Business Directory of Public and Private Co mpanies, 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 web sites, and phone interviews. If financial data from private companies is unavailable, Ward’s staff esti mates the information. Copyright 2011 Harte-Hanks Market Intelligence, In c., 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 >1,500Share of firms (%)

**Number of Employees**2-25

Reference USA, accessed thru Jefferson Madison Reg ional 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 L exisNexis at University of Virginia’s Alderman Library.

Figure 2-7 Average Revenue of Companies Owning Petr oleum Refineries by Employment (N=61) Sources: Employment Data from Petroleum Refinery Em issions Information Collection, where available, Component 1, OMB Control No. 2060-0657. Hoovers 2011 Online Data, accessed through Univers ity of South Carolina’s Moore School of Business Library. Hoovers 2011 Online Data reflects either a ctual data for 2010/2011 reported by companies, estimated data for 2011, or occasionally 2009 value s. Million Dollar Database online, 2011, accessed thr ough University of South Carolina’s Moore School of Business Library. Million Dollar Online Data reflec ts either actual data for 2011 reported by companie s or estimated data for 2011. Ward’s Business Directory of Public and Private Co mpanies, 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 web sites, and phone interviews. If financial data from private companies is unavailable, Ward’s staff esti mates the information. Copyright 2011 Harte-Hanks Market Intelligence, In c., All Rights Reserved. CI Technology Database, September 2011. Reference USA, accessed thru Jefferson Madison Reg ional 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 L exisNexis 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 Em issions Information Collection, where available, Component 1, OMB Control No. 2060-0657. Hoovers 2011 Online Data, accessed through Univers ity of South Carolina’s Moore School of Business Library. Hoovers 2011 Online Data reflects either a ctual data for 2010/2011 reported by companies, estimated data for 2011, or occasionally 2009 value s. Million Dollar Database online, 2011, accessed thr ough University of South Carolina’s Moore School of Business Library. Million Dollar Online Data reflec ts either actual data for 2011 reported by companie s or estimated data for 2011. Ward’s Business Directory of Public and Private Co mpanies, 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 web sites, and phone interviews. If financial data from private companies is unavailable, Ward’s staff esti mates the information. Copyright 2011 Harte-Hanks Market Intelligence, In c., All Rights Reserved. CI Technology Database, September 2011. Reference USA, accessed thru Jefferson Madison Reg ional 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 L exisNexis 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 Em issions Information Collection, where available, Component 1, OMB Control No. 2060-0657. Hoovers 2011 Online Data, accessed through Univers ity of South Carolina’s Moore School of Business Library. Hoovers 2011 Online Data reflects either a ctual data for 2010/2011 reported by companies, estimated data for 2011, or occasionally 2009 value s. Million Dollar Database online, 2011, accessed thr ough University of South Carolina’s Moore School of Business Library. Million Dollar Online Data reflec ts either actual data for 2011 reported by companie s or estimated data for 2011. Ward’s Business Directory of Public and Private Co mpanies, 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 web sites, and phone interviews. If financial data from private companies is unavailable, Ward’s staff esti mates the information. Copyright 2011 Harte-Hanks Market Intelligence, In c., All Rights Reserved. CI Technology Database, September 2011. Reference USA, accessed thru Jefferson Madison Reg ional 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 L exisNexis at University of Virginia’s Alderman Library.

Employment, crude capacity, and location informatio n 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 refi ning 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 refiner s face higher per unit costs than larger refining operations because they produce fewer petr oleum products. As a result, some smaller firms have sought to overcome their competitive dis advantage by locating close to productconsuming areas to lower transportation costs and s erving niche product markets (FTC, 2004).
A good example of a firm locating close to prospect ive customers is Countrymark Cooperative, Inc., which was started in the 1930s f or the express purpose of providing farmers in Indiana with a consistent supply of fuels, lubrican ts, 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. How ever, the firm’s specialty products unit is its largest unit (Hoovers, 2011 online).
However, recent developments are making these facto rs less important for success in the industry. For example, the entry of new product pip elines is eroding the locational advantage of smaller refineries (FTC, 2004). This trend can poss ibly be illustrated by the fact that most refineries owned by small businesses tend to be loc ated 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 rel y on the population surrounding them to support their refining operations.
Capacity information for the refineries owned by s mall businesses also suggests that fewer small businesses are focusing on developing s pecialty 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 cale ndar day or 857,155 barrels per stream day (EIA, 2006c). Approximately 21% of this total capac ity was devoted to producing specialty products or more locally focused products such as a romatics, asphalt, lubricants, and petroleum coke. The remaining 79% was used to produce gasolin e, 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% w as 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 a nother refinery), and they are also normally transported by pipeline.2-29

2.5 Markets This section provides data on the volume of petrole um products produced and consumed in the United States, the quantity of products impo rted and exported, and the average prices of major petroleum products. The section concludes wit h 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 pro ducts supplied between 2000 and 2010 (measured in millions of barrels of oil). Thes e data represent the approximate consumption of petroleum products because it measures the disap pearance of these products from primary sources (i.e., refineries, natural gas processing p lants, blending plants, pipelines, and bulk terminals).*** Draft – Do Not Cite, Quote, or Release During Review ***

2-30Table 2-9 Characteristics of Small Businesses in the Petroleum Refining IndustryParent CompanyParentCompanyTypeCumulativeCrudeCapacity(bbl/cd)ParentCompanyEmployment(#)Facility NameFacilityCityFacility StateFacility CountyFacilityCountyPopulationDensity (2000)FacilityCountyPopulationDensity (2010)AGE Refining, Inc. Private 14,021 124 AGE RefiningIncSan AntonioTX Bexar County 1,117 1,383American Refining Group,Inc.Private 10,000 323 AmericanRefining GroupIncBradford PA McKean County47 44Calcasieu Refining Company Private 78,000 92 CalcasieuRefining Co.LakeCharlesLA Calcasieu Parish171 181Calumet ShreveportLubricants and Waxes, LLCPublic 57,000 654 CalumetShreveport LLCShreveport LA Caddo Parish 286 290Calumet Lubricants Company,L.P.Public 13,020 654 CalumetLubricants Co LPCottonValleyLA Caddo Parish 286 290Calumet Lubricants Company,L.P.Public 8,300 654 CalumetLubricants Co LPPrinceton LA Caddo Parish 286 290CHS, Inc. Public 59,600 287 Cenex HarvestStatesLaurel MT YellowstoneCounty49 56Calumet (Montana RefiningCompany)Public 10,000 170 Montana RefiningCo.Great Falls MT Cascade County30 30CVR Energy, Inc. Public 115,700 371 CoffeyvilleResources LLCCoffeyville KS MontgomeryCounty56 55Countrymark Cooperative Private 26,500 425 CountrymarkCooperative, Inc.Mt. Vernon IN Posey County 66 63Cross Oil Refining &Marketing, Inc.Private 7,500 110 Martin MidstreamPartners LPSmackover AR Union County 44 40Deerfield Refining andProduction Corp.Private 2,000 27 Foreland RefiningCo.Ely NV White PineCounty1 1Frontier Refining andMarketingPrivate 47,000 723 Frontier RefiningIncCheyenne WY Laramie County 30 34Frontier Oil Corp. Private 138,000 723 Frontier ElDorado RefiningCoEl Dorado KS Butler County 42 46(continued)*** Draft – Do Not Cite, Quote, or Release During Review ***

2-31Table 2-9. Characteristics of Small Businesses in the Petroleum Refining Industry (continued)Parent CompanyParentCompanyTypeCumulativeCrudeCapacity(bbl/cd)ParentCompanyEmployment(#)Facility NameFacilityCityFacility StateFacility CountyFacilityCountyPopulationDensity (2000)FacilityCountyPopulationDensity (2010)CVR Refining (WynnewoodRefining Co.)Private 70,000 260 WynnewoodRefining Co.WynnewoodOK Garvin County 34 34Goodway Refining, LLC Private 4,100 17 GoodwayRefining LLCAtmore AL EscambiaCounty41 41Wood Cross RefiningCompany, LLCPublic 25,050 1,321 Holly Refining &Marketing CoWoodsCrossUT Davis County 785 1,026Holly Frontier Refinery Public 105,000 1,321 NavajoRefiningCo.Artesia NM Eddy County 12 13Holly Refining & Marketing– Tulsa, LLC - East PlantPublic 70,300 1,321 Holly Refining &Marketing CoTulsa East OK Tulsa County 988 1,058Holly Refining & Marketing– Tulsa, LLC - West PlantPublic 85,000 1,321 Holly Refining &Marketing CoTulsa West OK Tulsa County 988 1,058Hunt Refining Co. Private 36,000 346 Hunt RefiningCo.Tuscaloosa AL TuscaloosaCounty125 147Hunt Southland Refining Co.Private 11,000 1,100 Hunt SouthlandRefining CoSandersvilleMS Lamar County 79 112Kern Oil & Refining Co. Private 26,000 105 Kern Oil&Refining Co.Bakersfield CA Kern County 81 103Lion Oil Co. Private 75,000 350 Lion Oil Co. El Dorado AR Union County 44 40National CooperativeRefinery AssociationPublic 85,500 612 NationalCooperativeRefineryAssociationMcPherson KS McPhersonCounty33 33Pasadena Refining SystemsInc.Private100,000348Pasadena RefiningSystems Inc.PasadenaTX Harris County 1967 2,402Petro Star Inc. Private 19,700 400 Petro Star Inc.North Pole AK Fairbanks NorthStar11 13Petro Star Inc. Private 55,000 400 Petro Star Inc.Valdez AK Valdez Cordova 0.3 0(continued)*** Draft – Do Not Cite, Quote, or Release During Review ***

2-32Table 2-9. Characteristics of Small Businesses in the Petroleum Refining Industry (continued)Parent CompanyParentCompanyTypeCumulativeCrudeCapacity(bbl/cd)ParentCompanyEmployment(#)Facility NameFacilityCityFacilityStateFacilityCountyFacilityCountyPopulationDensity (2000)FacilityCountyPopulationDensity (2010)Placid Refining Private 57,000 207 Placid RefiningInc.Port Allen LA West BatonRouge Parish113 124Kenneth Faite (San Joaquin)Private 15,000 108 San JoaquinRefining Co., Inc.Bakersfield CA Kern County 81 103Santa Maria RefiningCompanyPrivate 9,500 47 Greka Energy Santa MariaCA Santa BarbaraCounty146 155Somerset Oil Inc. Private 5,500 11 Somerset EnergyRefinery LLCSomerset KY Pulaski County85 96US Oil & Refining Co. Private 38,800 182US Oil & RefiningCo.Tacoma WA Pierce County 417 476Ventura Refining &Transmission, LLCPrivate 12,000 37 Ventura Refining& TransmissionLLCThomas OK Custer County 27 28Western Refining Company,LPPublic 122,000 636 Western RefiningCompany LPEl Paso TX El Paso County671 791Western Refining, Inc. Public 66,300 636 Western RefiningYorktown IncYorktown VA York County 533 625Western Refining, Inc. Public 16,800 636 Western RefiningSouthwest IncBloomfield NM San JuanCounty21 24Western Refining, Inc. Public 21,100 636 Western RefiningSouthwest IncGallup NM McKinleyCounty14 13World Oil Marketing Co. Private 8,500 65 Lunday-ThagardCo.South Gate CA Los AngelesCounty2,344 2,420Wyoming Refining Co. Private 14,000 96 WyomingRefining CoNew Castle WY Weston County3 3Total1,614,091 8,454103Sources: U.S. Census Bureau, American Fact Finder,“2010 Census Summary File 1 Population, Housing Units, Area & Density: 2010- County – Census Tract100% Data 2010 Census” (Data accessed on 10/21/2011); http://factfinder2.census.gov/faces/tableservices/jsf/pages/productview.xhtml?ftp=tableHoovers 2011 Online Data, accessed through University of South Carolina’s Moore School of Business Library. Hoovers 2011 Online Data reflectseither actual data for 2010/2011 reported by companies, estimated data for 2011, or occasionally 2009values.*** Draft – Do Not Cite, Quote, or Release During Review ***

2-33Million Dollar Database online, 2011, accessed through University of South Carolina’s Moore School ofBusiness Library. Million Dollar Online Datareflects 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, companywebsites, and phone interviews. If financialdata from private companies is unavailable, Ward’sstaff 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 Data from Petroleum Refinery EmissionsInformation Collection, where available, Component1, OMB Control No. 2060-0657.Energy Information Administration (EIA), Form EIA820, “Annual Refinery Report,” Table 3. Capacity ofOperable Petroleum Refineries by State andIndividual Refinery as of January 1, 2011 <http://www.eia.gov/petroleum/refinerycapacity/>2-34

Between 2000 and 2004, U.S. consumption of petroleu m products increased by 5%. Consumption leveled off by 2007 and dropped by 9% b etween 2007 and 2009 (Figure 2-10). This reduced growth was primarily the result of les s jet fuel, residual fuel, distillate fuel, and other products being consumed in recent years. Con sumption 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 cumul ative decrease in consumption over the 11 year period is 3% (Table 2-10).

Figure 2-10 Total Petroleum Products Supplied (mill ions of barrels per year) Sources: U.S. Department of Energy. 2011 Energy Inf ormation Administration (EIA). 1996–2011. “Petroleu m Supply Annuals, Volume 1.” (Data accessed on Februa ry 23, 2012) [Source for 2000–2010 numbers.] < http://www.eia.gov/dnav/pet/pet_cons_psup_dc_nus_mb bl_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 (milli ons 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://w ww.eia.doe.gov/oil_gas/petroleum/data_publications/ petroleum_supply_annual/psa_volume1/psa_volume1.htm l>. 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 Octobe r 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 p etroleum products produced in the United States between 2000 and 2010. U.S. productio n of petroleum products at refineries and blenders grew steadily, resulting in a 7% cumulativ e 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 Informat ion Administration (EIA). 1996–2007. “Petroleum Sup ply Annuals, Volume 1.” Available at <http://www.eia.do e.gov/oil_gas/petroleum/data_publications/ petroleum_supply_annual/psa_volume1/psa_volume1.htm l>. 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 Octobe r 7, 2011) [Source for 2007–2010 numbers.] <http://www.eia.gov/dnav/pet/pet_pnp_refp_dc_nus_mb bl_a.htm>.2-36

The 2005 decline in production (0.35%) was possib ly the result of damage inflicted by two hurricanes (Hurricane Katrina and Hurricane Rit a) on the U.S. Gulf Coast—the location of many U.S. petroleum refineries (Section 3.4.2). Acc ording 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 p robably 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 ref ining 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 petroleu m products grew at approximately the same rate, the growth of petroleum product exports was d riven 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 an d 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 t o 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 De cember 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 Ad ministration’s website at http://www.eia.gov/dnav/pet/pet_move_wkly_dc_NUS-Z0 0_mbblpd_4.htm.2-37

Table 2-12 Value of Product Shipments of the Petrol eum 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 pro ducer price index industry data for Total Manufactu ring 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 Offi ce. 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://f actfinder.census.gov/servlet/ DatasetMainPageServlet?_lang=en&_ts=336651423017&_d s_name=AM0931GS101&_program=EAS>. Table 2-13 Imports of Major Petroleum Products (mil lions 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 Informat ion Administration (EIA).1996–2007. “Petroleum Supp ly Annuals, Volume 1.” Available at <http://www.eia.do e.gov/oil_gas/petroleum/data_publications/ petroleum_supply_annual/psa_volume1/psa_volume1.htm l>. 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 Octobe r 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 (mil lions 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 Informat ion Administration (EIA). 1996–2007. “Petroleum Sup ply Annuals, Volume 1.” Available at <http://www.eia.do e.gov/oil_gas/petroleum/data_publications/ petroleum_supply_annual/psa_volume1/psa_volume1.htm l>. 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 Octobe r 7, 2011.) [Source for 2007–2010 numbers] <http://www.eia.gov/dnav/pet/pet_move_exp_dc_NUS-Z0 0_mbbl_a.htm>.

2.5.4 Market Prices The average nominal prices of major petroleum produ cts sold to end users are provided for selected years in Table 2-15. 6 As these data illustrate, nominal prices rose subs tantially 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 in creased. 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 consume rs, such as agriculture, industry, and utilities, as well as re sidential and commercial consumers.2-39

Table 2-15 Average Price of Major Petroleum Product s 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 Informat ion Administration (EIA). 2007b. “Refiner Petroleum Product Prices by Sales Type.” Available at <http://tonto.e ia.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 Octobe r 7, 2011.) [Source for 2007–2010 numbers.]<http://www.eia.gov/dnav/pet/pet_pri_refot h_dcu_nus_a.htm>.
The nominal prices domestic petroleum refiners rece ive 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 produce r price index (PPI) for the petroleum refining industry against the index for all manufac turing 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 pric e 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 Manufacturi ng 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). 200 7. “Producer Price Index Industry Data: Customizabl e Industry Data Tables.” Available at <http://www.bls.gov/ppi/ >. As obtained on October 11, 2007. U.S. Bureau of Labor Statistics (BLS). 2011. “Prod ucer Price Index Industry Data: Customizable Indust ry 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 2009-2 010 fiscal years. These ratios were calculated by Risk Management Associates by dividin g 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 (R MA). 2008. Annual Statement Studies 2007–2008

. Pennsylvania: RMA, Inc. New Source: Risk Management Association (RMA). 201 1. 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% aver age return between 2009 and 2010. The data for other asset size categories is not shown f or the fiscal year 2009–2010 because RMA received fewer than 10 financial statements in thos e 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% duri ng the 2009–2010 fiscal year.
Obtaining profitability information specifically fo r small petroleum refining companies can be difficult as most of these firms are private ly owned. However, some of the small, domestic petroleum refining firms identified in Sec tion 3.4.2.3 are publicly owned companies— CVR Energy Inc., Calumet Specialty Products Partner s, L.P., Holly Corporation, and Western Refining, Inc. Profit ratios were calculated for th ese companies using data obtained from their publicly available 2010 income statements. These ra tios are presented in Table 2-18.2-42

Table 2-18 Net Profit Margins for Publicly Owned, S mall 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 Co rporation 10K. February 25, 2011. 10K for year ende d December 31, 2010. (Data accessed on 10/23/11) [Sou rce for 2010 numbers.] http://files.shareholder.com/downloads/FTO/14288538 45x0xS950123-11-18524/48039/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) [Sou rce for 2010 numbers.] http://phx.corporateir.net/phoenix.zhtml?c=194293&p=irol-sec> Calumet Specialty Products Partners, Morningstar f or Calumet Specialty Products Partners 10K. Februar y 22, 2011. 10K for year ended December 31, 2010. (Da ta accessed on 10/21/11) [Source for 2010 numbers.] http://quote.morningstar.com/stock-filing/Annual-Re port/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) [Sou rce for 2010 numbers.] <http://www.sec.gov/Archives/edgar/data/1376139/000 095012311022741/y90110e10vk.htm>

2.5.6 Industry Trends The Energy Information Administration’s (EIA’s) 201 1 Annual Energy Outlook provides forecasts of average petroleum prices, petroleum pr oduct consumption, and petroleum refining capacity utilization to the year 2035. Trends in th ese 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 poli cy decisions. As a result, the EIA evaluated a wide variety of cases based on different assumption s of how these factors will behave in the future. This section focuses on the EIA’s “referenc e case” forecasts, which assume that current policies affecting the energy sector will remain un changed throughout the projection period (EIA, Form EIA-820).
According to the 2011 Annual Energy Outlook’s refer ence 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 r efining, an increase in its price would likewise represent an increase in production costs of petrol eum refiners. As a result, the prices of petroleum products sold to end users are expected t o 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 pet roleum products are expected to rise2-43

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 supplie d 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 Petrol eum Products Sold to End Users in 2009 Currency (cents per gallon) Product 2011 2012 2013 2014 2015 2016 2017 2018 201 9 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 23 5.4 Sources: U.S. Department of Energy, Energy Informat ion Administration (EIA). 2007c. “Annual Energy Out look.” Available at <http://www.eia.doe.gov/oiaf/archive/a eo07/pdf/0383(2007).pdf>. As obtained on January 21
, 2007. U.S. Department of Energy, Energy Information Admi nistration (EIA). 2011. “Annual Energy Outlook.”; (Data accessed on October 11, 2011) [Source for 201 1–2019 numbers.] <http://www.eia.gov/forecasts/aeo/pdf/0383(2011).pd f>. Table 2-20 Total Petroleum Products Supplied (milli ons 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 Informat ion Administration (EIA). 2007c. “Annual Energy Out look.” Available at <http://www.eia.doe.gov/oiaf/archive/a eo07/pdf/0383(2007).pdf>. As obtained on January 21
, 2007. U.S. Department of Energy, Energy Information Admi nistration (EIA). 2011. “Annual Energy Outlook.”; (Data accessed on October 11, 2011) [Source for 201 6–2019 numbers.] <http://www.eia.gov/forecasts/aeo/pdf/0383(2011).pd f>.
Overall, the EIA forecasts that U.S. operational ca pacity will decrease by a total of 5% between 2011 and 2019 (Table 2-21). The rate of cap acity utilization is projected to average 86% during this period.2-44

Table 2-21 Full Production Capacity Utilization Rat es 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 Informat ion Administration (EIA). 2007c. “Annual Energy Out look.” Available at <http://www.eia.doe.gov/oiaf/archive/a eo07/pdf/0383(2007).pdf>. As obtained on January 21
, 2007. U.S. Department of Energy, Energy Information Admi nistration (EIA). 2011. ”Annual Energy Outlook.”; (Data accessed on February 23, 2012) [Source for 20 11–2019 numbers.] < Capacity utilization -- http://www.eia.gov/oiaf/aeo/tablebrowser/#release=A EO2011&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.xl s >.

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7 For each year, the gross input to atmospheric crud e oil distillation units is calculated by multiplyi ng the capacity utilization rate by the operational capacity.2-45

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U.S. Department of Energy, Energy Information Admin istration (EIA). 2006b. “Refinery Capacity Report 2006.” Available at <http://www.eia .doe.gov/oil_gas/petroleum/ data_publications/refinery_capacity_data/refcapacit y.html/>. As obtained on October 23, 2006.
U.S. Department of Energy, Energy Information Admin istration (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, 200 7. U.S. Department of Energy, Energy Information Admin istration (EIA). 2007a. “Refinery Utilization and Capacity.” Available at <http://ton to.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 Admin istration (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 Admin istration (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 Admin istration (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 Admin istration (EIA). 2011, “Annual Energy Outlook.” (Data accessed on October 11, 2011) [Sour ce for 2011–2019 numbers.]<http://www.eia.gov/forecasts/aeo/pdf/0383 (2011).pdf>.
U.S. Department of Justice and the Federal Trade Co mmission. 1992. Horizontal Merger Guidelines. Available at <http://www.ftc.gov/bc/doc s/horizmer.htm>. As obtained on October 28, 2006.
U.S. Department of Labor, Occupational Safety and H ealth Administration (OSHA). 2003. OSHA Technical Manual, Section IV: Chapter 2, Petro leum Refining Processes. TED 01- 00-015. Washington, DC: U.S. DOL. Available at <htt p://www.osha.gov/dts/osta/ otm/otm_iv/otm_iv_2.html>. As obtained on October 2 3, 2006.
U.S. Energy Information Administration (EIA), 2011a . “Refinery Utilization and Capacity.” Available at http://www.eia.gov/dnav/pet/pet_pnp_un c_dcu_nus_a.htm; Release date: 7/28/11; (Data accessed on 10/11/11). [Source for 2 007–2010 numbers]
U.S. Energy Information Administration (EIA), Form EIA-820, “Annual Refinery Report. Table 1. Number and Capacity of Operable Petroleum Refine ries by PAD District and State as of January 1, 2011” Release Date: June 24, 2011; (D ata accessed on 10/12/11). [Source for 2011 numbers.] <http://www.eia.gov/petroleum/re finerycapacity/> U.S. Environmental Protection Agency. 1995. “EPA Of fice 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/comp liance/resources/ publications/assistance/sectors/notebooks/petrefsn. pdf>. As obtained on October 23, 2006.
U.S. Environmental Protection Agency. 2006. “Propos ed 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 Com panies, 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>.
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.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 Pollu tants from Petroleum Refineries (40 CFR part 63, subpart CC) (Refinery MACT 1); (2) Nationa l Emission Standards for Hazardous Air Pollutants for Petroleum Refineries: Catalytic Crac king 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 6 0, subpart J) (Refinery NSPS J); and (4)
Standards of Performance for Petroleum Refineries f or which Construction, Reconstruction, or Modification Commenced After May 14, 2007 (40 CFR p art 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 subjec t to Refinery MACT 1. The proposed amendments also reflect requirements to ensure comp liance, including flare monitoring and operational requirements, requirements for relief v alve 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 ad dress technical corrections and clarifications raised in a 2008 industry petition f or reconsideration applicable to Refinery NSPS
Ja. 8 These technical corrections and clarifications ar e addressed in this proposal because they also affect sources subject to the proposed amendme nts to Refinery MACT 1 and 2.
In this section, we provide an overview of the engi neering cost analysis used to estimate the additional private expenditures industry may ma ke in order to comply with the following portions of the proposed rule amendments:

• For storage vessels, require fitting controls on sl otted 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 unit s (DCU).

• New work practice requirements for fugitive emissio ns sources, which include establishing a fenceline concentration, conducting fenceline monit oring, 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 benz ene concentrations exceed a specific
concentration action level.

• Relief valve monitoring using a system that is capa ble of identifying and recording the time and duration of each pressure release and of notify ing 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 emiss ions 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 volu metric fraction of combustible components present. For flares using steam- or air-assist, mo nitoring of steam- and/or air-assist rates is also required to determine compliance with the oper ating limits.

• PM emissions testing requirements for FCCUs consist ent with Refinery NSPS Ja.
For additional discussion of the proposed amendment s, 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 opti ons were identified as developments in practices, processes and control technologies for s torage vessels. Emission reduction options identified include: (1) Option 1 -- requiring guidepole controls and other fitting controls for existing external or internal floating roof tanks a s required in the Generic MACT for storage vessels (40 CFR part 63, subpart WW) in 40 CFR 63.1 063; (2) Option 2 -- Option 1 plus revising the definition of Group 1 storage vessel t o include smaller capacity storage vessels and/or storage vessels containing materials with lo wer vapor pressures; and (3) Option 3 -- Option 2 plus requiring additional monitoring to pr event roof landings, liquid level overfills and3-3

to identify leaking vents and fittings from tanks. Options 1 and 2 were identified as developments in practices, processes and control te chnologies because these options are required for similar tanks in some chemical manufacturing MA CT standards and are considered technologically feasible for storage vessels at ref ineries. Option 3 is also an improvement in practices because these monitoring methods have bee n required for refineries by other regulatory agencies.
Based on the engineering cost analysis, Option 2 w as 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 G eneric MACT and revise the definition of Group 1 storage vessels. 9 Table 3-1 includes a summary of option costs. Th e annualized cost of capital estimates were determined based on a 7 perc ent interest rate. The storage vessel-related capital costs were annualized over 15 years. As th e storage vessel controls do not require significant on-going operating and maintenance cost s, 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 techni cal 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 remainin g in the tank that can be sold. The product recovery credit is based on the VOC emissions reduc tions projected to be achieved at each specific refinery. For storage vessels, these emis sions 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. N egative annualized costs introduce the question of why, if these emissions can be reduced profitabl y using environmental controls, are more producers not adopting the controls in their own ec onomic self-interest. Assuming financially rational producers, standard economic theory sugges ts that all refineries would incorporate all cost-effective improvements, of which they are awar e, without government intervention. This

9 The proposed revised definition will include (1) s torage vessels with capacities greater than or equa l to 20,000 gallons, but less than 40,000 gallons if the maximu m true vapor pressure is 1.9 psia or greater and (2 ) storage tanks greater than 40,000 gallons if the maximum tr ue vapor pressure is 0.75 psia or greater.3-4

cost analysis is based on the observation that emis sions reductions that appear to be profitable, on average, in the analysis have not been adopted b y 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 ran ge of investments in energy conservation, even when they pay off over relatively short time p eriods. We discuss some possible explanations for the apparent paradox in the contex t 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 meas ure 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, an d 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 ma y 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 impa cts identified in this analysis are not reflective of the true costs compelled by the regul ation relative to the controls installed voluntarily. A third explanation for why there ap pear to be negative cost control technologies that are not generally adopted is imperfect informa tion. If emissions from the refining sector are not well understood, firms may underestimate the po tential financial returns to capturing emissions. Finally, the cost from the irreversibil ity associated with implementing these environmental controls is not reflected in the engi neering 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 investmen ts 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 optio n value minus the revenues from the sale of the3-5

additional recovered product. In the absence of qu antitative estimates of this option, the cost estimates for the storage vessel controls may under estimate the full costs faced by the affected
firms.

Table 3-1 Nationwide Emissions Reduction and Cost I mpacts of Control Options for Storage Vessels at Petroleum Refineries

Control Option Total

Capital Investment (million 2009$) Total

Annual ized 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 feedsto cks and to produce petroleum coke. Unlike most other refinery operations, which are co ntinuous, DCUs are operated in a semi-batch system. Most DCUs consist of a large process heate r, two or more coking drums, and a single product distillation column. Bottoms from the dist illation 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 f ill 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 drain ed, and the coke is removed from the vessel using high pressure water. Once the coke is cut ou t of the drum, the drum is closed, and prepared to go back on-line. A typical coke drum c ycle is typically 28 to 36 hours from start of
feed to start of feed.
During the reaction process, the DCU is a closed s ystem. 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 produc ed steam is sent to a blowdown system to3-6

recover the liquids. Refinery MACT 1 standards (40 CFR part 63, subpart CC) define the releases to the blowdown system as the delayed coke r vent and these emissions must be controlled following the requirements for miscellan eous process vents. Near the end of the cooling process, a vent is opened on the drum to al low the remaining steam and vapors to be released directly to the atmosphere prior to draini ng, deheading, and decoking (coke cutting) the
coke from the drum. Emissions from DCU occur durin g 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 vent ing 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 gen erated as the coke drum and its contents cool. The lower pressure set point will require the DCU t o vent to the closed blowdown system longer,
where emissions can be recovered or controlled. Thi s 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 be en established and achieved as low as 2 psig. Based on the 2011 ICR responses, there are 75 opera ting DCU, indicating that the sixth percentile is represented by the fifth-best perform ing DCU. EPA researched permits, consent decrees, refinery ICR responses, and other rules ad dressing DCU depressurizing limits. Out of the 75 DCU, EPA identified at least 27 DCU that eit her 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 Imp act 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 depressuriz e at 2 psig or less at all times. Therefore, the MACT floor for DCU decoking operations is to depres sure at 2 psig or less prior to venting to the atmosphere for both new and existing sources.
EPA also considered control options beyond the flo or level of 2 psig to determine if
additional emissions reductions could be cost effec tively achieved. EPA considered a control option that allowed atmospheric venting only after the DCU vessel pressure reached 1 psig or3-7

less, since some facilities reported in the 2011 IC R depressurizing to that level prior to venting.
EPA determined that there are several technical dif ficulties associated with establishing a pressure limit at this lower level. EPA also consi dered 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 commerciall y available equipment to connect the coke drum to the coke pit. Because these options were e ither not technically feasible or equipment was not commercially available, EPA did not estimat e costs. For existing sources, EPA assumed all DCU that rep orted a “typical drum pressure prior to venting” of more than 2 psig would install and o perate a steam ejector system to reduce the coke drum pressure to 2 psig prior to venting to at mosphere 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 sy stem 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 r ather than to the atmosphere, the dry gas can generally be recovered in the refinery fuel gas sys tem 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 significan t 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 impro vements generally lower the operating costs
of the DCU.
The proposal includes appropriate work practice st andards in place of emission limits for the DCU – the work practice standards include a low er pressure set point for venting. Costs and emissions reductions were evaluated on a DCU-specif ic basis using the data reported by petroleum refineries in the detailed 2011 ICR respo nses, along with vendor quotes obtained in
2011. The cumulative nationwide costs calculated fo r 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 technica l 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 Cokin g 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 Coki ng 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 f rom equipment and wastewater collection and treatment systems, are inherently di fficult 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 measu red, or not considered part of the affected source, such as emissions from process sew ers, wastewater systems, or other fugitive emissions;

o Improper characterization of sources for emissions models and emissions factors; and

o Inherent uncertainty in emissions estimation method ologies.

In 2009, the EPA conducted a year-long diffusive tu be monitoring pilot project at the fenceline of Flint Hills West Refinery in Corpus Ch risti, Texas. The study concluded that the modeled-derived concentrations are significantly lo wer than the actual measured values at

10 The technical memo entitled Impact Estimates for D elayed Coking Units includes the following note of clarification: “Although the control cost estimates for delayed co king units were developed from 2011 vendor quotes, the impacts for other petroleum refinery sources are reported in 2009 dol lars to be consistent with other cost estimates dev eloped for other Refinery MACT 1 emission sources. Given the low inflation ac ross this time period, it was assumed that the dela yed coking unit costs developed from the 2011 vendor quote could be used without correction to estimate the delayed coking u nits control costs in 2009 dollars.”3-9

virtually every point along the fenceline. On aver age, 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 indi cator that emissions may, in fact, be far more significant than accepted methodologies and procedu res can predict. Measurement of the concentration of expected pollut ants at the fenceline provides an indication of the uncertainty associated with emiss ions estimates for all near ground-level sources, including fugitives. EPA reviewed the ava ilable literature and identified several different methods for measuring fugitive emissions around the fenceline of a petroleum refinery. These methods include: (1) passive diffusive tube m onitoring networks; (2) active monitoring station networks; and (3) open path monitoring syst ems. As a result of the year-long fenceline monitoring pilot project at Flint Hills West Refine ry 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, a ccording to the analytical equipment manufacturer representatives) and assumed an annual ized 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 th e 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. Ana lytical equipment cost estimates were developed from vendor quotes, which included both t he cost of the analytical equipment and materials, as well as man-hour estimates for perfor ming 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 app lying the different monitoring options to all refineries. To generate the estimates, it w as 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 tha n or equal to 125,000 barrels per day and less than 225,000 barrels per day would fall into the me dium size facility range (greater than or equal to 750 and less than 1,500 acres); and refineries w ith crude throughput of greater than or equal to 225,000 barrels per day would fall into the large f acility size (greater than or equal to 1,5003-10

acres). The nationwide costs included for the prop osed 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 ad ditional discussion, see the technical memorandum titled Fenceline Monitoring Technical Su pport Document, January 17, 2014, in Docket ID Number EPA-HQ-OAR-2010-0682.

Table 3-4 Nationwide Costs (in 2009$) for Fenceline Monitor ing 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 142 568 11 71,000,000 45,600,000

3.2.4 Relief Valve Monitoring Relief valve releases vented directly to the atmosp here 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 monitor ing stations per refinery – 142 refineries * 4 moni toring 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 discha rge 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 emission s standard.
EPA analyzed several options for improvements to t he existing leak detection and repair (LDAR) program in Refinery MACT 1, including LDAR u sing 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 def ined 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 bu t a majority of refineries were assumed to conduct monitoring with an optical gas i maging device.

• Option 3 -- monitoring and repair for connectors in G and LL service, where the leak threshold that required repair was defined as 500 p pm. EPA also assessed continuous monitoring requirement s for PRD that would record the time and duration of a release as well as alert operators wh en 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 propo sal requires that sources monitor relief valves using a system that is capable of ide ntifying and recording the time and duration of each pressure release and of notifying operators th at a pressure release has occurred. Where a pressure release occurs, it is important to identif y and mitigate it as quickly as possible. For purposes of estimating the costs of this requiremen t, 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 requirem ents, 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 an d duration of that pressure release. Annualized cost of capital estimates were determined based on a 7 percent interest rate and a 10-year3-12

equipment life. Based on cost assumptions, the nat ionwide capital cost of installing these electronic monitors is $9.54 million and the annual ized 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 L eaks 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 (200 9$)

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 ins trument using an EPA protocol still in development.

3.2.5 Flare Monitoring All of the requirements for flares operating at pet roleum 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
Provisions 12 , which require a flare used as an air pollution co ntrol device operate with a pilot flame present at all times. 13 The proposal removes the cross-reference to the G eneral Provisions and includes the requirement that flares operate wi th a pilot flame at all times and be

12 General Provisions are the general provisions unde r 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=/ecfrb rowse/Title40/40cfr63_main_02.tpl. 13 Pilot flames are proven to improve flare flame sta bility; even short durations of an extinguished pil ot could cause a significant reduction in flare destruction effici ency.3-13

continuously monitored for using a thermocouple or any other equivalent device in Refinery MACT 1 and 2. The proposal also amends Refinery MA CT 1 and 2 to add a new operational requirement to use automatic relight systems for al l flare pilot flames. 14 Because of safety issues with manual relighting, EPA believes that nearly al l refinery flares are currently equipped with an automated device to relight the pilot flame. Th e proposal also amends Refinery MACT 1 and 2 to add a requirement that a visible emissions tes t be conducted each day and whenever visible emissions are observed from the flare using an obse rvation 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 m aximum 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 re quired 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 prop osal 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 stu dies 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 vel ocity 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 Br itish thermal units per standard cubic foot (Btu/scf) for non-assisted flares and 300 Btu/scf f or air- and steam-assisted flares. Refinery MACT 1 and 2 reference these requirements, but neit her the General Provisions nor Refinery MACT 1 and 2 include specific monitoring requiremen ts 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 stea m- or air-assisted, it is critical to ensure the as sist
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 pro perties of the mixture of all gases at the flare ti p

14 An automatic relight system provides a quicker res ponse time to relighting a snuffed out flare than m anual methods and results in improved flare flame stabili ty.3-14

in the combustion zone when evaluating the ability to combust efficiently. The proposal adds definitions of two key terms relevant to refinery f lare performance. First, the proposal defines “flare vent gas” to include all waste gas, sweep ga s, purge gas and supplemental gas, but not include pilot gas or assist media. The proposal als o defines the “combustion zone gas” as flare vent gas plus the total steam-assist media and prem ix assist air that is supplied to the flare.
EPA expects that the newly proposed requirements f or 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 refiner ies and that 285 of these receive flare vent gas flow on a regular basis. EPA expects that refineri es 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 a nalysis reflects potential supplemental natural gas use and steam savings projections estimated bas ed on the refinery flare dataset. Steam reduction credits and supplemental natural gas cost s 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 regul ated firms will expend resources on new environmental compliance activities. Because t he compliance timeline for implementation of these proposed flare monitoring requirements is three years from promulgation, EPA anticipates that capital expenditures will occur ov er that three year period and not result in expenditures of greater than $100 million in any si ngle year. Industry costs submitted to EPA through consent decrees were used as the primary so urce of cost estimation. These costs included all installation and ancillary costs assoc iated with the installation of the monitors (i.e., analyzer shelters and electrical connections). Cos ts 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 monitor ing 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/o r grab samples can be used to determine the composition (o r 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 representativ es. Table 3-6 provides a summary of total capital and annualized cost for flare control alter natives. 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 spec ific cost data collected for the flare costs estimates are provided in Attachment 3 to thi s technical memorandum. See Attachment 3 for details on the assumptions made for equipment l ife 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 Requi rements (2010$)

Monitoring Equipment Total

Capital Investment ($/flare)* Total

Annualized Cost ($/year/flare)* # of

Flares Total TCI

($) Total TAC

($/year) Notes 16

Calorimeter $105,000 $30,000 85 $8,925,000 $2,550,0 00 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: Fl are 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, All3-17 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: Fla re 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 th e emissions limits selected by the refinery owner or operator. The performance test is a one-t ime requirement; additional performance tests are only required if the owner or operator elects t o establish new operating limits, or to modify the FCCU or control system in such a manner that co uld affect the control system’s performance.
Currently, the Refinery MACT 2 does not include per iodic performance tests for any FCCU. The lack of any ongoing performance test requ irements is inconsistent with developments in practices for ensuring ongoing comp liance 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 res ulting from the performance demonstrations were projected. We then considered requiring FCCU emissions source performance tests once every 5 years (i.e., once pe r 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 requir ement for an emissions source performance test once every 5 years for all FCCU subject to Ref inery 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 mi llion from proposed amendments and $156.6 million from standards to ensure compliance. The a nnualized costs are estimated to be approximately $42.4 million, which includes an esti mated $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 new3-18

environmental compliance activities. Because the c ompliance timeline for implementation of these proposed standard revisions is three years fr om 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 un its, 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, whic h includes the estimated $14.4 million credit for recovery of lost product and the annualized cos t 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 requir ements 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 w ould result in additional capital costs of $12.3 million and an annualized cost of $5.6 millio n per year. The proposed amendments will
achieve a nationwide HAP emission reduction of abou t 1,760 tons/year with a concurrent reduction in VOC emissions of about 18,850 tons/yea r. 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 fl are monitoring and operational requirements to ensure compliance would result in a n additional total nationwide capital cost of $156.6 million and an annualized cost of $37.9 mill ion. 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 requiremen ts for flare monitoring would result in additional capital costs of $147 million and an ann ualized 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 permi t period) for the FCCUs at existing sources. The nationwide annual cost of this additional requi rement for all FCCUs is projected to be, on average, $213,000 per year. We were not able to es timate (i) product recovery credits associated with the proposed amendments for relief valve monit oring, flare monitoring and source performance testing at the FCCUs, or (ii) emissions reductions associated with the proposed amendments for relief valve monitoring and source p erformance testing. As such, these3-19

estimates are not included in Table 3-8. The propo sed operational and monitoring amendments for flares have the potential to reduce excess emis sions 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 stand ards and amendments.

Table 3-8 Emissions Sources, Points, and Controls I ncluded 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) Costeffectiveness ($/ton VOC) HAP

emission reductions (tpy) Costeffectiveness ($/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 fu gitive emissions fenceline monitoring program will result in additional emissions reductions and additional cost s and these are not included in the results. b Any corrective actions taken in response to relief valve monitoring may result in additional emission s 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 reduc tions and additional costs and these costs are not included i n the results. d Any corrective actions taken in response to PM emi ssions source performance tests for the fluid catal ytic 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 ASSESSM ENTS

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 eq uilibrium analyses of national markets for five major petroleum products to provide a part ial 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 fo r motor gasoline, jet fuel, distillate fuel oil, residual fuel oil, and liquefied petroleum gases wh ich, when aggregated, constitute a large proportion of refinery production in the United Sta tes. We also conducted an economic welfare analysis that estimates the consumer and producer s urplus changes associated with the regulatory program. The welfare analysis identifies how the r egulatory costs are distributed across two broad classes of stakeholders, consumers and produc ers, 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 us ed to approximate the welfare impacts of the rule. However, in cases where the engineeri ng costs of compliance are used to estimate welfare impacts, the burden of the regulation is ty pically measured as falling solely on the affected producers, who experience a profit loss ex actly 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 est imated. This is typically referred to as a “full-cost absorption” scenario in which all factor s 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 c ost analysis and incorporates economic theory related to producer and consumer behavior to estimate changes in market conditions.

The partial equilibrium models use a common analyti c 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. Environm ental 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 equilibri um system of equations (see Fullerton and Metcalfe (2002) for an example).

First, we consider the formal definition of the ela sticity of supply, q s , 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 mar ket supply, and 

### p ˆ equals the percentage change in market price. As Fullerton an d Metcalfe (2002) note, we have taken the elasticity definition and turned it into a linear b ehavioral equation for the market we are analyzing.

To introduce the direct impact of the regulatory pr ogram, we assume the per-unit cost associated with the regulatory program, c , leads to a proportional shift in the marginal cos t of
production 

###  

# ( ) mc . The per-unit costs are estimated by dividing the total estimated annualized
engineering costs accruing to producers within a gi ven 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 th e initial equilibrium point as follows:4-3 

0 0 c c mc mc p = = . (4.1b)

The with-regulation supply equation can now be writ ten 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 dema nd,

d 

### η = market elasticity of demand, and


### p ˆ = percentage change in market price.
Finally, we specify the market equilibrium conditio ns in the affected market. In response to the exogenous increase in production costs, prod ucer and consumer behaviors are represented in Eq. 4-1a and Eq. 4-2, and the new equilibrium sa tisfies 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 unknow ns ( 

### p ˆ
, 

### 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 d 

### η ) 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 proportio nal change in market quantity using Eq. 4-2.

The change in consumer surplus in the affected mark et can be estimated using the following linear approximation method:


## ( ) ( ) 1 0.5 cs q p q p ∆ = − × + × ∆ × ∆ (4.5)

where 1 

### q equals with-regulation quantities produced. As sh own, higher market prices and reduced consumption lead to welfare losses for cons umers.
For affected supply, the change in producer surplus can be estimated with the following equation:


## ( ) ( ) ( ) 

## ( ) 1 1 0.5 ps q p q c q p c ∆ = × ∆ − × − × ∆ × ∆ − . (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, t o some degree, as a result of higher market prices.

4.2.2 Model Baseline

Standard EIA practice compares and contrasts the st ate of a market with and without the regulatory policy. EPA selected 2016 as the baseli ne year for the analysis and collected petroleum product price and quantity forecast infor mation 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 pr ice of petroleum products is reported in terms of dollars per gallon. Therefore, to ensure that co mmon units were being used, the number of barrels produced each year was divided by 42, the n umber of gallons in a barrel.4-5

Table 4-1 Baseline Petroleum Product Market Data, 2 016

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) 2 130.61 22.69 66.69 7.82 40.93

1 Source: AEO2012 Reference Case, Petroleum Product P rices (Table 12) 2 Source: AEO2012 Reference Case, Liquid Fuels Supply and Disposition (Table 11)

4.2.3 Model Parameters

Demand elasticity is calculated as the percentage c hange 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 se en in Table 4-2, which presents the demand elasticities used in this analysis. Demand is cons idered elastic if demand elasticity exceeds 1.0 in absolute value (i.e., the percentage change in q uantity exceeds the percentage change in price). The quantity demanded, then, is very sensitive to p rice 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 pric e). Inelastic demand implies that the quantity demanded changes very little in response to price c hanges. As shown in Table 4-2, we draw demand elasticities from U.S. EPA (1995).

Table 4-2 Estimates of Price Elasticity of Demand a nd Supply 1

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 in dentified more recent estimates of long-term demand elasticities f or motor gasoline, which are lower than the elastic ity used in this analysis, but we were unable to identify more recen t estimates of the other elasticities. Supply elasticity is calculated as the percentage c hange 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 sm all price increase will lead to a relatively large increase in quantity supplied. A supply curv e with elasticity less than one is considered inelastic, which means an increase in price will ca use little change in quantity supplied. In the4-6

long-run, when producers have sufficient time to co mpletely 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 Complianc e Costs into Economic Model

To collect comprehensive, updated information for t he 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 pet roleum refineries. The ICR was comprised of four components, and the information collected thro ugh component 1 of the ICR included facility location, products produced, capacity, thr oughput, 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 capacit y 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 eac h refinery we allocated the compliance costs across total barrels of refinery production. Becau se EPA collected production information for thirty-nine (39) different refinery products and th e 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 r efinery utilization rate of 86.4%, which is the operable utilization rate for U.S. refineries f or 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 in formation can be located at U.S. EIA’s website: http://www.eia.gov/dnav/pet/pet_pnp_unc_dcu_nus_a.h tm.4-7

Table 4-3 Estimated Annualized Engineering Complian ce 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 7,4 70.94
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 $0.000 18 $0.00018

Using this engineering cost information and total national production of petroleum products, we estimated the annualized compliance co st 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 no t reflect the product recovery credits. At the national level, the total annualized engineering co mpliance costs are estimated at less than $0.00018 per gallon, or less than two one-hundredth s of a cent per gallon. These per-gallon annualized engineering costs estimates were then en tered 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 co sts 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 Impac ts

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 petroleu m products see a decline in surplus, as shown in Table 4-4. For example, consumers of moto r gasoline are estimated to lose $14.46 million of surplus. In addition, producers also rec eive a smaller surplus as a result of higher production costs. In the case of motor gasoline, pr oducers lose $7.87 million. Total surplus losses for consumers and producers of motor gasoline are e stimated to be $22.33 million. The total annualized loss in surplus for the five markets ana lyzed is $47.77 million. In addition to the loss in surplus for consumers and producers of these fiv e major petroleum products, an additional $15.7 million in costs will affect markets for petr oleum 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 p eriod 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 ab ove (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 neglig ible increases in the costs of supplying petroleum products to consumers. The par tial equilibrium model used in this EIA is designed to evaluate behavioral responses to this c hange in costs within an equilibrium setting within nationally competitive markets. The nationa l competitive market assumption is clearly strong because the markets in petroleum products ma y be regional for some products, as well as some product markets within the refining industry m ay be interdependent. Regional price and quantity impacts could be different from the averag e impacts reported if local market structures, production costs, or demand conditions are substant ially 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 Execu tive Order, “our regulatory system must protect public health, welfare, safety, and our env ironment while promoting economic growth, innovation, competitiveness, and job creation. It m ust be based on the best available science” (Executive Order 13563, 2011). Although standard be nefit-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 sec tion provides a conceptual framework for considering the potential influence of environmenta l regulation on employment in the U.S. economy and discusses the limited empirical literat ure that is available. The section then discusses the potential employment impacts in the e nvironmental protection sector, e.g. for construction, manufacture, installation, and operat ion of needed pollution control equipment. Section 4.3.1 describes the economic theory used fo r analyzing regulation-induced employment impacts, discussing how standard neoclassical theor y 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 n et employment effects. The EPA is

19 Labor expenses do, however, contribute toward tota l costs in the EPA’s standard benefit-cost analyses

.4-10

currently in the process of seeking input from an i ndependent expert panel on economy-wide impacts, including employment effects. Finally, Se ction 4.3.4 offers several conclusions.

4.3.1 Theory
The effects of environmental regulation on employm ent 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 re gulation in complex ways. That response depends on the elasticities of demand and supply fo r labor and the degree of labor market imperfections (e.g., wage stickiness, long-term une mployment, 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 ov er time. In light of these difficulties, economic theory provides a constructive framework for approa ching these assessments and for better understanding the inherent complexities in such ass essments. In this section, we briefly describe theory relevant to the impact of regulation on labo r demand at the regulated firm, in the regulated industry, and in the environmental protection secto r; 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 pr ofit-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 productio n, along with capital, energy, and materials. In competitive output markets, profit maximizing fi rms 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 m odel 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 microecon omic theory textbook, for a discussion.
21 See Hamermesh (1993), Chapter 2, for a derivation of the firm’s labor demand function from cost-minim ization.
22 In this framework, labor demand is a function of q uantity of output and prices (of both outputs and i nputs). 23 Berman and Bui (2001) and Morgenstern, Pizer, and Shih (2002) use a cost-minimization framework, whic h is a special case of profit-maximization with fixed outp ut quantities.4-11

certain factors of production, such as pollution ab atement 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 decom posed into two main components: output
and substitution effects. 24 For the output effect, by affecting the marginal c ost of production, regulation affects the profit-maximizing quantity o f output. The output effect describes how, if labor-intensity of production is held constant, a d ecrease in output generally leads to a decrease in labor demand. However, as noted by Berman and Bu i, although it is often assumed that regulation increases marginal cost, and thereby red uces output, it need not be the case. A regulation could induce a firm to upgrade to less p olluting, and more efficient equipment that lowers marginal production costs, for example. In s uch a case, output could theoretically increase. For example, in the proposed refinery am endments, the fitting controls and monitoring equipment for storage vessels were identified as de velopments in practices, processes and control technologies for storage vessels. The proposed req uirement could result in fewer VOC emissions and more product remaining in the storage vessel, potentially increasing output.
The substitution effect describes how, holding out put constant, regulation affects the labor-intensity of production. Although increased e nvironmental regulation generally results in higher utilization of production factors such as po llution control equipment and energy to operate that equipment, the resulting impact on labor deman d 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 a re required by the regulation and the corresponding change in labor-intensity of producti on. Within the production theory framework, when levels of a given set of inputs are fixed by e xternal constraints such as regulatory requirements, rather than allowing the firm to free ly 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 im pact of regulation on factor prices, but conclude t hat this effect is unlikely to be important for large competitive f actor markets, such as labor and capital. Morgenste rn, Pizer and Shih (2002) use a very similar model, but they brea k the employment effect into three parts: 1) the de mand effect; 2) the cost effect; and 3) the factor-shift effect.4-12

fixed” factor if there were specific requirements f or landfill liner construction, but the footprint
of the landfill was flexible. Brown and Christense n (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 sta ndards. In summary, as the output and substitution effects may be both positive, both negative or some combination, standard neoclassical theory alon e does not point to a definitive net effect of regulation on labor demand at regulated firms. Oper ating within the bounds of standard neoclassical theory, however, rough estimation of n et employment effects is possible with empirical study, specific to the regulated firms, w hen data and methods of sufficient detail and quality are available. The available literature ill ustrates 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 aba tement expenditure data that are too dated to be reliably informative. In addition, the most c ommonly used empirical methods in the literature do not permit the estimation of net effe cts. These studies will be discussed at greater length later in this chapter. The above describes a conceptual framework for ana lyzing 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 r epresent impacts for the overall industry, therefore the theoretic approach requires some adju stment when applied at the industry level. As stated, the responsiveness of industry labor de mand depends on how the output and
substitution effects interact. 25 At the industry-level, labor demand will be more r esponsive 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 oth er factors is highly elastic, or (4) labor costs ar e 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 out put 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 complem entarity 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 eq uipment 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, theor y alone is unable to determine the sign or magnitude of industry-level regulatory effects on l abor. Determining these signs and magnitudes requires additional sector-specific empirical study . To conduct such targeted research would require estimates of product demand elasticity; pro duction 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 ru les, many of these data items are not publicly available, would require significant time and resou rces in order to access confidential U.S. Census data for research, and also would not be nec essary for other components of a typical EIA
or RIA. In addition to changes to labor demand in the regu lated industry, net employment impacts encompass changes within the environmental protecti on sector, and, potentially in other related sectors, as well. Environmental regulations often c reate increased demand for pollution control equipment and services needed for compliance. This increased demand may increase revenue and employment in the environmental protection indu stry. At the same time, the regulated industry is purchasing the equipment and these cost s may impact labor demand at regulated firms. Therefore, it is important to consider the n et 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 n et 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 employmen t 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 impa ct of environmental regulation on

28 Full employment is a conceptual target for the eco nomy where everyone who wants to work and is availa ble 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 individu al workers can be important, as discussed in later paragraphs of t his section.4-14

employment; it could cause either a short-run net i ncrease or short-run net decrease (Schmalansee and Stavins, 2011). An important funda mental 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 r egulation 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 re gions 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 i s expected to be small, localized reductions in employment can still have negative impacts on indiv iduals and communities just as localized increases can have positive impacts.
While the current discussion focuses on labor dema nd effects, environmental regulation may also affect labor supply. In particular, pollut ion and other environmental risks may impact labor productivity 30 or employees’ ability to work. While there is an a ccompanying, 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 em pirically. There is a small, nascent empirical literature using more detailed labor and environmen tal 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, econom ic theory provides a framework for analyzing the impacts of environmental regulation o n employment. The net employment effect incorporates expected employment changes (both posi tive and negative) in the regulated sector, the environmental protection sector, and other rele vant sectors. Using economic theory, labor demand impacts for regulated firms, and also for th e regulated industry, can be decomposed into output and substitution effects. With these potenti ally competing forces, under standard neoclassical theory estimation of net employment ef fects is possible with empirical study specific to the regulated firms and firms in the en vironmental 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-Review ed Literature

In the labor economics literature there is an exte nsive body of peer-reviewed empirical work analyzing various aspects of labor demand, rel ying on the above theoretical framework. 31 This work focuses primarily on the effects of emplo yment policies, e.g. labor taxes, minimum wage, etc. 32 In contrast, the peer-reviewed empirical literatur e specifically estimating employment effects of environmental regulations is very limited. In this section, we present an overview of the latter. As discussed in the precedi ng section on theory, determining the direction of employment effects in regulated industries is ch allenging because of the complexity of the output and substitution effects. Complying with a n ew or more stringent regulation may require additional inputs, including labor, and may alter t he relative proportions of labor and capital used by regulated firms (and firms in other relevant ind ustries) in their production processes. Several empirical studies, including Berman and Bu i (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 200 2, Walker 2011). However since these latter studies compare more regulated to less regulated co unties 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 do es not contain evidence that environmental regulation has a large impact on net employment (ei ther negative or positive) in the long run across the whole economy. Environmental regulations seem likely to affect th e environmental protection sector earlier than the regulated industry. Rules are usua lly announced well in advance of their effective dates and then typically provide a period of time f or firms to invest in technologies and process changes to meet the new requirements. When a regula tion 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 s hort-term increase in labor demand for

31 Again, see Hamermesh (1993) for a detailed treatme nt. 32 See Ehrenberg & Smith (2000), Chapter 4: “Employme nt Effects: Empirical Estimates” for a concise over view.4-16

specialized workers within the environmental protec tion sector, particularly workers involved in the design, construction, testing, installation, an d operation of the new pollution control equipment required by the regulation (see Schmalans ee and Stavins, 2011; Bezdek, Wendling, and Diperna, 2008). Estimates of short-term increas es 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 (MAT S). 33

4.3.2.1 Regulated Sector
Determining the direction of net employment effect s of regulation on industry is challenging. Two papers that present a formal theor etic 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 appr oach to estimate the effect on employment of environmental regulations in Californ ia. 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 inc orporates 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 SCAQ MD’s local air quality regulations, Berman and Bui identify the effect of environmental regula tions 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 slightl y” but that “the employment effects of both compliance and increased stringency are fairly prec isely estimated zeros, even when exit and dissuaded entry effects are included” (Berman and B ui, 2001, p. 269). 36 In their view, the limited effects likely arose because 1) the regulations app lied disproportionately to capital-intensive

33 U.S. EPA (2011b) 34 Note, like Morgenstern, Pizer, and Shih (2002), th is study does not estimate the number of jobs creat ed in the environmental protection sector. 35 Berman and Bui include over 40 4-digit SIC industr ies 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. (200 2)4-17

plants with relatively little employment, 2) the pl ants 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 si milar structural approach to Berman and Bui’s, but their empirical application uses pol lution 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, p lastics, steel, and petroleum refining). Thus, in contrast to Berman and Bui (2001), this study ident ifies employment effects by examining differences in abatement expenditures rather than g eographical differences in stringency. They conclude that increased abatement expenditures gene rally 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 envir onmental protection sector, which provides goods and services that help protect the e nvironment to the regulated sector, are difficult to assess. Employment in the industry sup plying pollution control equipment or services is likely to increase with the increased demand fro m the regulated industry for increased pollution control. 37 A report by the U.S. International Trade Commissio n (2013) shows that domestic environmental services revenues have grown by 41 pe rcent 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 dome stic 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 labo r demand impacts. However, there is a

37 See Bezdek, Wendling, and Diperna (2008), for exam ple, and U.S. Department of Commerce (2010).4-18

nascent literature focusing on regulation-induced e ffects on labor supply, though this literature remains very limited due to empirical challenges. T his new research uses innovative methods and new data, and indicates that there may be obser vable impacts of environmental regulation on labor supply, even at pollution levels below mandat ed regulatory thresholds. Many researchers have found that work loss days and sick days as wel l as mortality are reduced when air pollution
is reduced. 38 EPA’s study of the benefits and costs of implemen ting clean air regulations used these studies to predict how increased labor availa bility would increase the labor supply and improve productivity and the economy. 39 Another literature estimates how worker productiv ity 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 Californi a farm growing multiple crops, with a piecerate payment structure. Their quasi-experimental st ructure identifies an effect of daily variation in monitored ozone levels on productivity. They fi nd “that ozone levels well below federal air quality standards have a significant impact on prod uctivity: a 10 parts per billion (ppb) decrease in ozone concentrations increases worker productivi ty 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 diff icult to accurately produce net employment estimates for the whole economy that would appropri ately capture the way in which costs, compliance spending, and environmental benefits pro pagate through the macro-economy.

38 The Benefits and Costs of the Clean Air Act from 1 990 to 2020 Final Report – Rev. A , U.S. Environmen tal Protection Agency, Office of Air and Radiation, Apr il 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. Environme ntal Protection Agency, Office of Air and Radiation, Apr il 2011a. http://www.epa.gov/air/sect812/feb11/fullreport_rev _a.pdf4-19

Quantitative estimates are further complicated by t he 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 i ndependent expert panel on modeling economy-wide impacts, including employment effects.

4.3.4 Conclusions
In conclusion, deriving estimates of how environme ntal regulations will impact net employment is a difficult task, requiring considera tion of labor demand in both the regulated and environmental protection sectors. Economic theory p redicts that the total effect of an environmental regulation on labor demand in regulat ed sectors is not necessarily positive or negative. Peer-reviewed econometric studies that us e a structural approach, applicable to overall net effects in the regulated sectors, converge on t he finding that such effects, whether positive or negative, have been small and have not affected emp loyment in the national economy in a significant way. Effects on labor demand in the env ironmental protection sector seem likely to be positive. Finally, new evidence suggests that envir onmental 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 require s 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 substan tial number of small entities. Small entities include small businesses, small governmental jurisd ictions, 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 refine ry with no more than 1,500 employees. 40 For this analysis we applied the small refiner definiti on 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 Not ice for 40 CFR Part 60, Standards of Performance for Petroleum Refineries (Volume 73, Nu mber 122, page 35858). 41

4.4.1 Small Entity Economic Impact Measures

The analysis provides EPA with an estimate of the m agnitude of impacts that the proposed standards may have on the ultimate domesti c parent companies that own the small
refineries. This section references the data sourc es 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 an d 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 A pril 2011 Information Collection Request (ICR -- OMB Control No. 2060-0657). Information co llected through component 1 of the ICR includes facility location, products produced, capa city, 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 c osts to revenues at the parent company level.
This is known as the cost-to-revenue or cost-to-sal es ratio, or the “sales test.” The “sales test” is the impact methodology EPA employs in analyzing sma ll entity impacts as opposed to a “profits test,” in which annualized compliance costs are cal culated 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 ava ilable 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 consiste nt with guidance offered by EPA on compliance with the RFA 42 and is consistent with guidance published by the U .S. SBA’s Office

41 Refer to http://www.sba.gov/sites/default/files/Size_Standar ds_Table.pdf for more information on SBA small business size standards. 42 The RFA compliance guidance to EPA rulewriters reg arding the types of small business analysis that sh ould be considered can be found at <http://www.epa.gov/sbre fa/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 inc reases 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 Januar y 2011 there were 148 petroleum refineries operating in the continental United Stat es 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 fi rm total) employ fewer than 1,500 workers
and are considered small businesses. These firms e arned an average of $1.36 billion of revenue per year, while firms employing more than 1,500 emp loyees 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 n ot 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 sa les data. The 5 small refiners removed from the analysis had parent company revenues ranging fr om $5 million to $225 million, with average revenues of $64 million. Two of these small refine rs had revenues of less than $10 million, and another small refiner had revenues just over $10 mi llion. Of the 2 small refiners that were not analyzed because of missing data, one (1) small ref iner shut down in 2007 and the other provided information that they were a specialty chemical com pany and not a refinery. These seven small refiners will not be subject to the rule.

43 U.S. SBA, Office of Advocacy. A Guide for Governmen t Agencies, How to Comply with the Regulatory Flexibility Act, Implementing the President’s Small Business Agenda and Executive Order 13272, June 20 10. 44 The U.S. Census Bureau’s Statistics of U.S. Busines ses include the following relevant definitions: (i) establishment – a single physical location where business is con ducted 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 c ommon ownership or control. The firm and the establ ishment are the same for single-establishment firms. For each m ulti-establishment firm, establishments in the same industry within a state will be counted as one firm; and (ii i) enterprise -- an enterprise is a business organization consist ing of one or more domestic establishments that were sp ecified under common ownership or control. The ente rprise and the establishment are the same for single-establish ment firms. Each multi-establishment company forms one enterprise.4-22

Table 4-5 presents the distribution of estimated co st-to-sales ratios for the small firms in our analysis. We analyzed the estimated cost-to-sa les with and without the recovery credit, and in both cases the incremental compliance costs impo sed 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 Amendmen ts 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 ra tios 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 re covery credits the average cost-to-sales ratio is approximately 0.02 percent; the median cost-to-sale s ratio is less than 0.01 percent; and the maximum cost-to-sales ratio is approximately 0.89 p ercent; with recovery credits these impacts do not substantially change, except the maximum cos t-to-sales ratio decreases to approximately 0.44 percent. For small firms, without recovery cr edits the average cost-to-sales ratio is about 0.07 percent, the median cost-to-sales ratio is 0.0 3 percent, and the maximum cost-to-sales ratio is 0.62 percent; with recovery credits these impact s do not substantially change, except the maximum cost-to-sales ratio decreases slightly to a pproximately 0.60 percent. The potential costs do not have a more significant impact on smal l 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 exi sting MACT 1 and MACT 2 standards will not have a significant economic impact on a substan tial number of small entities (SISNOSE).4-23

Table 4-6 Summary of Sales Test Ratios for Firms Af fected 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

4.5 References

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