From: "Higgins, Cortney" <Cortney_Higgins@omb.eop.gov>

Sent: 04/30/2012 11:54 AM

To: Brenda Shine/RTP/USEPA/US@EPA

Cc: Robin Langdon/RTP/USEPA/US@EPA, Penny Lassiter/RTP/USEPA/US@EPA, Alex 

Macpherson/RTP/USEPA/US@EPA, William Nickerson/DC/USEPA/US@EPA, 

Susan Stahle/DC/USEPA/US@EPA

Subject: RE: Interagency Comments on the Petroleum Refinery NSPS Ja Preamble and RIA

Hi Brenda,

We had a handful of comments on these latest drafts. Please give me a call if you have any 

questions.

Regards,

Cortney

<< NSPS Ja Reconsideration RIA_InteragencycommentsunderEO13563 04_30_2012.docx>>

<< EO12866_PetRefineriesSubpart_J_2060-AN72FnlRule_04-30-

12_InteragencycommentsunderEO13563.docx>>
*** Draft – Do Not Cite, Quote, or Release During Review ***

Regulatory Impact Analysis

Petroleum Refineries

New Source Performance Standards Ja

April 2012

U.S. Environmental Protection Agency

Office of Air and Radiation

Office of Air Quality Planning and Standards

Research Triangle Park, NC 27711
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ii

CONTACT INFORMATION

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

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

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

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

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

ACKNOWLEDGEMENTS

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

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

under contract number EP-D-06-003. 
*** Draft – Do Not Cite, Quote, or Release During Review ***

iii

TABLE OF CONTENTS

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

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

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

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

1.1 INTRODUCTION ............................................................................................................................................ 1-1

1.2 RESULTS ...................................................................................................................................................... 1-2

1.3 REFERENCES ................................................................................................................................................ 1-6

1.2 RESULTS ...................................................................................................................................................... 1-2

1.3 REFERENCES ................................................................................................................................................ 1-7

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

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

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

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

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

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

2.3 THE DEMAND SIDE .................................................................................................................................... 2-15

2.3.1 Product Characteristics.................................................................................................................... 2-15

2.3.2 Uses and Consumers........................................................................................................................ 2-15

2.3.3 Substitution Possibilities in Consumption ....................................................................................... 2-17

2.4 INDUSTRY ORGANIZATION......................................................................................................................... 2-17

2.4.1 Market Structure .............................................................................................................................. 2-17

2.4.2 Characteristics of U.S. Petroleum Refineries and Petroleum Refining Companies......................... 2-21

2.5 MARKETS................................................................................................................................................... 2-30

2.5.1 U.S. Petroleum Consumption .......................................................................................................... 2-30

2.5.2 U.S. Petroleum Production .............................................................................................................. 2-41

2.5.3 International Trade........................................................................................................................... 2-42

2.5.4 Market Prices................................................................................................................................... 2-44

2.5.5 Profitability of Petroleum Refineries............................................................................................... 2-46

2.5.6 Industry Trends................................................................................................................................ 2-48

2.6 REFERENCES .............................................................................................................................................. 2-50

3 NSPS REGULATORY OPTIONS, COSTS AND EMISSION REDUCTIONS FROM COMPLYING 

WITH THE NSPS .......................................................................................................................... 3-1

4 ECONOMIC IMPACT ANALYSIS: METHODS AND RESULTS................................................. 4-1

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

4.2 FLARE GAS RECOVERY SYSTEMS..............................................................................4-1

4.3 SMALL BUSINESS IMPACT ANALYSIS.........................................................................4-3

 4.3.1 Small Entity Economic Impact 

Measures.................................................................................................................................

.......4-4

 4.3.2 Small Entity Economic Impact 

Analysis..................................................................................................................................

.......4-5
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4.4

REFERENCES..............................................................................................................

.....................................................................................................4-8

5 EXECUTIVE ORDERS............................................................................................................ 5-1

5.1 UNFUNDED MANDATES........................................................................................................................ 5-1

5.2 ENVIRONMENTAL JUSTICE.................................................................................................................. 5-1

5.3 SIGNIFICANT ENERGY ACTIONS ........................................................................................................ 5-1

6 HUMAN HEALTH BENEFITS OF EMISSIONS REDUCTIONS.................................................. 6-1

6.1 CALCULATION OF PM2.5-RELATED HUMAN HEALTH BENEFITS ................................................................... 6-1

6.2 SOCIAL COST OF CARBON AND GREENHOUSE GAS BENEFITS.................................................................... 6-14

6.3 ENERGY DISBENEFITS ................................................................................................................................ 6-17

6.4 TOTAL MONETIZED BENEFITS.................................................................................................................... 6-18

6.5 UNQUANTIFIED BENEFITS .......................................................................................................................... 6-20

6.5.1 Additional SO2 and NO2 Benefits........................................................................................................ 6-

6.5.2 Ozone Benefits................................................................................................................................. 6-23

6.5.3 Visibility Impairment....................................................................................................................... 6-24

6.6 CHARACTERIZATION OF UNCERTAINTY IN THE MONETIZED BENEFITS ...................................................... 6-24

6.7 REFERENCES ......................................................................................................................................... 6-296.2

SOCIAL COST OF CARBON AND GREENHOUSE GAS BENEFITS.................................................................... 6-14

6.3 ENERGY DISBENEFITS ................................................................................................................................ 6-17

6.4 TOTAL MONETIZED BENEFITS.................................................................................................................... 6-18

6.5 UNQUANTIFIED BENEFITS .......................................................................................................................... 6-20

6.5.1 Additional SO2 and NO2 Benefits.................................................................................................... 6-19

6.5.2 Ozone Benefits................................................................................................................................. 6-23

6.5.3 Visibility Impairment....................................................................................................................... 6-24

6.6 CHARACTERIZATION OF UNCERTAINTY IN THE MONETIZED BENEFITS ...................................................... 6-24

6.7 REFERENCES .............................................................................................................................................. 6-29

7 COMPARISON OF BENEFITS AND COSTS ............................................................................. 7-1

APPENDIX A PARENT COMPANY INFORMATION FOR PETROLEUM REFINERIES ..................... A-1
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LIST OF TABLES

Table 1-1 National Incremental Cost Impacts, Emission Reductions, and Cost Effectiveness for Petroleum 

Refinery Flares Subject to Amended Standards Under 40 CFR part 60, subpart Ja (Fifth Year After 

Effective Date of Final Rule Amendments) ....................................................................................... 1-3

Table 1-2 Summary of the Monetized Benefits, Social Costs, and Net Benefits for the Final Petroleum 

 Refineries NSPS in 2017.........................................................................................1-

45

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

Table 2-2. Major Refinery Product Categories.................................................................................................... 2-9

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

Table 2-4. Costs of Materials Used in Petroleum Refining Industry................................................................. 2-14

Table 2-5. Major Refinery Products.................................................................................................................. 2-16

Table 2-6. Market Concentration Measures of the Petroleum Refining Industry: 1985 to 2007....................... 2-20

Table 2-7. Number of Petroleum Refineries, by State....................................................................................... 2-23

Table 2-8. Full Production Capacity Utilization Rates for Petroleum Refineries.............................................. 2-24

Table 2-9. Characteristics of Small Businesses in the Petroleum Refining Industry......................................... 2-34

Table 2-10. Total Petroleum Products Supplied (millions of barrels per year) ................................................... 2-41

Table 2-11. U.S. Refinery and Blender Net Production (millions of barrels per year)........................................ 2-41

Table 2-12. Value of Product Shipments of the Petroleum Refining Industry .................................................... 2-43

Table 2-13. Imports of Major Petroleum Products (millions of barrels per year)................................................ 2-43

Table 2-14. Exports of Major Petroleum Products (millions of barrels per year)................................................ 2-44

Table 2-15. Average Price of Major Petroleum Products Sold to End Users (cents per gallon) ......................... 2-45

Table 2-16. Producer Price Index Industry Data: 1995 to 2010 .......................................................................... 2-46

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

Value of Assets................................................................................................................................. 2-47

Table 2-18. Net Profit Margins for Publicly Owned, Small Petroleum Refiners: 2010 ...................................... 2-48

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

per gallon) ........................................................................................................................................ 2-49

Table 2-20. Total Petroleum Products Supplied (millions of barrels per year) ................................................... 2-49

Table 2-21. Full Production Capacity Utilization Rates for Petroleum Refineries.............................................. 2-50

Table 3-1. National Incremental Cost Impacts for Petroleum Refinery Flares Subject to Amended Standards 

Under 40 CFR part 60, subpart Ja (Fifth Year After Effective Date of Final Rule Amendments)..... 3-2

Table 3-2. National Incremental Emissions Reductions and Cost-Effectiveness for Petroleum Refinery Flares 

Subject to Amended Standards Under 40 CFR part 60, subpart Ja (Fifth Year After Effective Date of 

Final Rule Amendments).................................................................................................................... 3-3

Table 4-1. Rates of Return on Investment for 

Refineries................................................................................................................................

.4-2

Table 4-2. Impact Levels of Proposed NSPS Amendments on Small 

Firms......................................................................................4-6

Table 4-3. Summary of Sales Ratios for Firms Affected by Proposed NSPS 

Amendments.................................................4-7

Table 6-1. Human Health Effects of PM2.5 .......................................................................................................... 6-3

Table 6-2. General Summary of Monetized PM-Related Health Benefits Estimates for Petroleum Refineries 

NSPS Reconsideration (millions of 2006$)* .................................................................................... 6-11

Table 6-3. Summary of Reductions in Health Incidences from PM2.5 Benefits for Petroleum Refineries NSPS 

Reconsideration*.............................................................................................................................. 6-12

Table 6-4. All PM2.5 Benefits Estimates for the Final Petroleum Refineries NSPS Reconsideration at discount 

rates of 3% and 7% in 2017 (in millions of 2006$)*........................................................................ 6-13

Table 6-5. Social Cost of Carbon (SCC) Estimates (per tonne of CO2) for 2017a............................................. 6-16

Table 6-6. Monetized SCC-Derived Benefits of CO2 Emission Reductions in 2017b2017 a,b ........................... 6-17

Table 7-1. National Incremental Cost Impacts, Emission Reductions, and Cost Effectiveness for Petroleum 

Refinery Flares Subject to Amended Standards Under 40 CFR part 60, subpart Ja (Fifth Year After 

Effective Date of Final Rule Amendments) ....................................................................................... 7-2
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vi

Table 7-2. Summary of the Monetized Benefits, Social Costs, and Net Benefits for the Final Petroleum 

 Refineries NSPS in 

2017......................................................................................................................................

..........................................7-3

Table A-1. Parent Company Information for Petroleum Refineries.................................................................... A-2

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.................................................................................................... 2-11

Figure 2-6. Employment Distribution of Companies Owning Petroleum Refineries (N=61) ............................ 2-26

Figure 2-7. Average Revenue of Companies Owning Petroleum Refineries by Employment (N=61).............. 2-28

Figure 2-8. Revenue Distribution of Large Companies Owning Petroleum Refineries (N=25)......................... 2-29

Figure 2-9. Revenue Distribution of Small Companies Owning Petroleum Refineries (N=36)..................2-28

Figure 2-10. Total Petroleum Products Supplied (millions of barrels per year)................................................... 2-39

Figure 6-1: Breakdown of Monetized PM2.5 Health Benefits using Mortality Function from Pope et al. (2002)6-10

Figure 6-2: Monetized PM2.5 Benefits of Final Petroleum Refineries Reconsideration in 2017......................... 6-14

Figure 6-3: Breakdown of Monetized Benefits for Final Petroleum Refineries NSPS Reconsideration by Pollutant

...6-19

Figure 6-4. Breakdown of Monetized Benefits for Final Petroleum Refineries NSPS Reconsideration by 

 Requirement and Flare Size...................................................................................6-19

Figure 6-5. Percentage of Adult Population by Annual Mean PM2.5 Exposure in the Baseline ......................... 6-26

Figure 6-6. Cumulative Distribution of Adult Population by Annual Mean PM2.5 Exposure in the Baseline .... 6-27

Figure 7-1. Net Benefits for Final Petroleum Refineries NSPS Reconsideration at 3% discount rate*............... 7-4

Figure 7-2. Net Benefits for Final Petroleum Refineries NSPS Reconsideration at 7% discount rate*............... 7-5
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1-1

1. EXECUTIVE SUMMARY

1.1 Introduction

On June 24, 2008, EPA promulgated amendments to the Standards of Performance for 

Petroleum Refineries and new standards of performance for petroleum refinery process units 

constructed, reconstructed, or modified after May 14, 2007. EPA subsequently received three

petitions for reconsideration of these final rules. On September 26, 2008, EPA granted 

reconsideration and issued a stay for the issues raised in the petitions regarding process heaters 

and flares. On December 22, 2008, EPA addressed those specific issues by proposing

amendments to certain provisions for process heaters and flares. This final regulation includes

emissions limits for new and modified/reconstructed sources, and these limits are set for sulfur 

dioxide (SO2), nitrogen oxides (NOx), volatile organic compounds (VOC), and other pollutants.

The petroleum refining industry comprises establishments primarily engaged in refining 

crude petroleum into refined petroleum. Examples of refined petroleum products include 

gasoline, kerosene, asphalt, lubricants, solvents, and a variety of other products. Petroleum 

refining falls under the North American Industrial Classification System (NAICS) 324110. 

This regulatory impact analysis (RIA) was prepared in response to requirements under 

Executive Order 12866. The RIA presents the results of analyses undertaken in support of this 

final rule including compliance costs, benefits, economic impacts, and impacts to small 

businesses. This RIA is organized as follows:

 Section 1: Executive Summary,

 Section 2 and an Appendix A: Profile of the Petroleum Refining Industry,

 Section 3: NSPS Regulatory Alternatives, and Costs and Emission Reductions From 

Complying with the NSPS,

 Section 4: Economic Impact Analysis: Methods and Results,

 Section 5: Executive Orders, 

 Section 6: Benefits of the NSPS, and

 Section 7: Comparison of Benefits and Costs.
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1-2

1.2 Results

EPA has characterized the facilities and companies potentially affected by the NSPS by 

examining existing refineries and the companies that own them. EPA projects that new refineries 

and processes will be similar to existing ones, and that the companies owning new sources will 

also be similar to the companies owning existing refineries. EPA has collected data on 148

existing refineries, owned by 64 companies. Of the affected parent companies, thirty-six are 

identified as small entities based on the Small Business Administration size standard criteria for 

NAICS 324110, for they employ 1,500 or fewer employees.

EPA estimates that complying with the final NSPS will have an annualized cost savings 

of approximately $79 million per year (2006 dollars) in 2017. The estimated nationwide 5-year 

incremental emissions reductions and cost impacts for the final standards are summarized in 

Table 1-1 below. Given that there are cost savings, EPA anticipates that the NSPS will have no 

negative impacts on the market for petroleum products. Based on sales data obtained for the 

affected small entities, as well as expected annualized cost savings, EPA estimates that the NSPS 

will not result in a SISNOSE (significant economic impact on a substantial number of small 

entities).

Comment [A1]: Please review the RIA 

and the preamble to make sure that the 

cost, energy savings and net cost estimates 

are presented consistently? 

p. 1-2: cost savings=79 mil;

p. 3-2: annualized cost=96 mil, cost

savings=79 mil;

p. 4-2: compliance cost=78 mil, energy 

savings=168 mil, net compliance cost=90.
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1-0

Table 1-1. National Incremental Cost Impacts, Emission Reductions, and Cost Effectiveness for Petroleum Refinery Flares Subject to 

Amended Standards Under 40 CFR part 60, subpart Ja (Fifth Year After Effective Date of Final Rule Amendments)

1

Subpart Ja 

Requirements

Total 

capital 

cost 

(millions)

Total 

annual cost 

without 

credit 

(millions/yr)

Natural 

gas 

offset/ 

product 

recovery 

credit 

(millions)

Total 

annual cost 

(millions/yr)

Annual 

emission 

reductions 

(tons 

SO2/yr)

Annual 

emission 

reductions 

(tons 

NOX/yr)

Annual 

emission 

reductions 

(tons 

VOC/yr)

Cost 

effectiveness 

($/ton 

emissions 

reduced)

Annual 

emission 

reductions 

(metric 

tons 

CO2/yr)2

Monetized 

Benefits 

(millions, 3%

discount rate for 

health and 

climate benefits)

Monetized 

Benefits 

(millions, 3%

discount rate for 

health and 7% 

for climate 

benefits)

Small Flares

Flare 

Monitoring $72 $12 $0 $12 0 0 0 0 $0 to $0 $0 to $0

Flare gas 

recovery

$0 $0 $0 $0 0 0 0 0 $0 to $0 $0 to $0

Flare 

Management $0 $0.79 $0 $0.79 0 0 270 $2,900 0 $0 to $0 $0 to $0

SO2 RCA/CA $0 $1.9 $0 $1.9 2,600 0 0 $760 0 $170 to $410 $150 to $370

Flowrate 

RCA/CA $0 $0.90 -$6.7 -$5.8 3.4 50 390 -$13,000 98,000 $2.9 to $3.7 $2.9 to $3.6

Total $72 $16 -$6.7 $9.0 2,600 50 660 $2,700 98,000 $170 to $410 $150 to $370

Large Flares

Flare 

Monitoring $12 $2.0 $0 $2.0 0 0 0 0 $0 to $0 $0 to $0

Flare gas 

recovery

$380 $78 -$170 -$90 380 1,100 2,700 -$22,000 1,800,000 $74 to $120 $71 to $110

Flare 

Management $0 $0.088 $0 $0.088 0 0 30 $2,900 0 $0 to $0 $0 to $0

SO2 RCA/CA $0 $0.22 $0 $0.22 290 0 0 $760 0 $18 to $45 $17 to $41

Flowrate 

RCA/CA $0 $0.10 -$0.74 -$0.64 0 6 43 -$13,000 11,000 $0 to $0 $0 to $0

Total $390 $81 -$170 -$88 660 1,100 2,800 -$20,000 1,800,000 $93 to $160 $88 to $150

All Flares

Flare 

Monitoring $84 $14 $0 $14 0 0 0 0 $0 to $0 $0 to $0

Flare gas 

recovery

$380 $78 -$170 -$90 380 1,100 2,700 -$22,000 1,800,000 $74 to $120 $71 to $110

Flare 

Management $0 $0.88 $0 $0.88 0 0 300 $2,900 0 $0 to $0 $0 to $0

SO2 RCA/CA $0 $2.2 $0 $2.2 2,900 0 0 $760 0 $180 to $450 $170 to $410

Flowrate 

RCA/CA $0 $1.00 -$7.4 -$6.4 3.4 56 430 -$13,000 110,000 $3.2 to $4.0 $3.1 to $3.9

Total $460 $96 -$180 -$79 3,200 1,100 3,400 -$10,000 1,900,000 $260 to $580 $240 to $520

1

All estimates are for the implementation year (2017), and are rounded to two significant figures. 2 The emission reductions of CO2 reflect the anticipated emission increases associated with the energy disbenefits from additional electricity consumption.

Formatted: Font: Arial
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1-0

EPA estimates that the total monetized benefits of the final NSPS are $260 million to 

$580 million and $240 million to $520 million, at 3% and 7% discount rates, respectively (Table 

1-2). All estimates are in 2006 dollars for the year 2017. Using alternate relationships between 

PM2.5 and premature mortality supplied by experts, higher and lower benefits estimates are 

plausible, but most of the expert-based estimates fall between these estimates. In addition, direct 

exposure to SO2 and NOx benefits, ozone benefits, ecosystem benefits, and visibility benefits 

have not been monetized in this analysis. 

EPA estimates the net benefits of the final NSPS are $340 million to $660 million and 

$320 million to $600 million, at 3% and 7% discount rates, respectively (Table 1-2). All 

estimates are in 2006 dollars for the year 2017.
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1-1

Table 1-2. Summary of the Monetized Benefits, Social Costs, and Net Benefits for the 

Final Petroleum Refineries NSPS in 2017 (millions of 2006$)1

3% Discount Rate 7% Discount Rate

Final Major Source NSPS

Total Monetized Benefits2 $260 to $580 $240 to $520

Total Compliance Costs3 -$79 -$79

Net Benefits $340 to $660 $320 to $600

Non-monetized Benefits

Health effects from SO2, NO2, and ozone exposure

Health effects from PM exposure from VOCs

Ecosystem effects 

Visibility impairment 

1

All estimates are for the implementation year (2017), and are rounded to two significant figures. 2 The total monetized benefits reflect the human health benefits associated with reducing exposure to PM2.5 through 

reductions of PM2.5 precursors such as NOx and SO2 as well as CO2 benefits. It is important to note that the 

monetized benefits do not include the reduced health effects from direct exposure to SO2 and NOx, ozone 

exposure, ecosystem effects, or visibility impairment. Human health benefits are shown as a range from Pope et 

al. (2002) to Laden et al. (2006). These models assume that all fine particles, regardless of their chemical 

composition, are equally potent in causing premature mortality because the scientific evidence is not yet 

sufficient to allow differentiation of effects estimates by particle type. The net present value of reduced CO2

emissions is calculated differently than other benefits. This table includes monetized climate benefits using the 

global average social cost of carbon (SCC) estimated at a 3 percent discount rate because the interagency 

workgroup deemed the SCC estimate at a 3 percent discount rate to be the central value. 3 The engineering compliance costs are annualized using a 7 percent discount rate. 
*** Draft – Do Not Cite, Quote, or Release During Review ***

1-2

Alternatively, if no refineries install flare gas recovery systems, EPA estimates the costs 

would be $10.7 million with monetized benefits of $190 to $460 million and $170 to $410 

million at a discount rates of 3% and 7% respectively. Thus, net benefits without flare gas 

recovery systems would be $180 million to $450 million and $160 million to $400 million, at 3% 

and 7% discount rates, respectively. All estimates are in 2006 dollars for the year 2017.

For small flares, we estimate the monetized benefits are $170 million to $410 million (3-

percent discount rate) and $150 million to $370 million (7% discount rate for health benefits and 

3% discount rate for climate benefits). For large flares, we estimate the monetized benefits are

$93 million to $160 million (3% discount rate) and $88 million to $150 million (7% discount rate 

for health benefits and 3-percent discount rate for climate benefits). All estimates are in 2006

dollars for the year 2017.
*** Draft – Do Not Cite, Quote, or Release During Review ***

1-3

1.43 References

Laden, F., J. Schwartz, F.E. Speizer, and D.W. Dockery. 2006. Reduction in Fine Particulate Air

Pollution and Mortality. American Journal of Respiratory and Critical Care Medicine. 173: 

667-672.

Office of Management and Budget. Circular A-4, September 17, 2003. Available on the 

Internet at http://www.whitehouse.gov/omb/circulars_a004_a-4. 

Pope, C.A., III, R.T. Burnett, M.J. Thun, E.E. Calle, D. Krewski, K. Ito, and G.D. Thurston.

2002. “Lung Cancer, Cardiopulmonary Mortality, and Long-term Exposure to Fine

Particulate Air Pollution.” Journal of the American Medical Association 287:1132-1141.
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2-1

2. PROFILE OF THE PETROLEUM REFININGINDUSTRY

2.1 Introduction

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

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

(EIAs) that will assess the impacts of these standards. 

At its core, the petroleum refining industry comprises establishments primarily engaged 

in refining crude petroleum into finished petroleum products. Examples of these petroleum 

products include gasoline, kerosene, asphalt, lubricants, and solvents, among others. 

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

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

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

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

2009 and 2008). 

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

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

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

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

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

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

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

projections for the industry. 

2.2 The Supply Side

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

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

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

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

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

2.2.1 Production Process, Inputs, and Outputs

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

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

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

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

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

2.2.1.1 The Production Process

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

phases and a number of supporting operations. These phases are described in detail in the 

following section. In the first phase, crude oil is desalted and then separated into its various 

hydrocarbon components (known as “fractions”). These fractions include gasoline, kerosene, 

naphtha, and other products (EPA, 1995). 

In the second phase, the distilled fractions are converted into petroleum products (such as 

gasoline and kerosene) using three different types of downstream processes: combining, 

breaking, and reshaping (EPA, 1995). An outline of the refining process is presented in Figure 2-

1.

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

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

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

process water, and depositing it into a gravity settler tank. Gradually, the salts present in the oil 

will be dissolved into the process water (EPA, 1995). After this takes place, the process water is 

separated from the oil by adding demulsifier chemicals (a process known as chemical separation) 

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

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

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

is illustrated in Figure 2-2. 
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2-3

Figure 2-1 Outline of the Refining Process

Source: U.S. Department of Labor, Occupational Safety and Health Administration (OSHA). 2003. OSHA 

Technical Manual, Section IV: Chapter 2, Petroleum Refining Processes. TED 01-00-015. Washington, DC: U.S. 

DOL. Available at <http://www.osha.gov/dts/osta/otm/otm_iv/otm_iv_2.html>. As obtained on October 23, 2006. 

Figure 2-2 Desalting Process

Source: U.S. Department of Labor, Occupational Safety and Health Administration (OSHA). 2003. OSHA 

Technical Manual, Section IV: Chapter 2, Petroleum Refining Processes. TED 01-00-015. Washington, DC: U.S. 

DOL. Available at <http://www.osha.gov/dts/osta/otm/otm_iv/otm_iv_2.html>. As obtained on October 23, 2006. 
*** Draft – Do Not Cite, Quote, or Release During Review ***

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

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

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

(which have a much higher boiling point) at the bottom of the tower. These fractions include 

heavy fuel oil and asphalt residue (EPA, 1995).

As the hot vapor rises, its temperature is gradually reduced. Lighter fractions condense onto 

trays located at successively higher portions of the tower. For example, motor gasoline will 

condense at higher portion of the tower than kerosene because it condenses at lower temperatures. 

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

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

Figure 2-3 Atmospheric Distillation Process

Source: U.S. Department of Labor, Occupational Safety and Health Administration (OSHA). 2003. OSHA 

Technical Manual, Section IV: Chapter 2, Petroleum Refining Processes. TED 01-00-015. Washington, DC: U.S. 

DOL. Available at <http://www.osha.gov/dts/osta/otm/otm_iv/otm_iv_2.html>. As obtained on October 23, 2006.

Vacuum Distillation. The atmospheric distillation tower cannot distill the heaviest 

fractions (those at the bottom of the tower) without cracking under requisite heat and pressure. 

So these fractions are separated using a process called vacuum distillation. This process takes 

place in one or more vacuum distillation towers and is similar to the atmospheric distillation 

process, except very low pressures are used to increase volatilization and separation. A typical 

first-phase vacuum tower may produce gas oils or lubricating-oil base stocks (EPA, 1995). This 

process is illustrated in Figure 2-4.
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Figure 2-4 Vacuum Distillation Process

Source: U.S. Department of Labor, Occupational Safety and Health Administration (OSHA). 2003. OSHA 

Technical Manual, Section IV: Chapter 2, Petroleum Refining Processes. TED 01-00-015. Washington, DC: U.S. 

DOL. Available at <http://www.osha.gov/dts/osta/otm/otm_iv/otm_iv_2.html>. As obtained on October 23, 2006.

Downstream Processing. To produce the petroleum products desired by the market 

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

downstream processes change the molecular structure of the hydrocarbon molecules by breaking 

them into smaller molecules, joining them to form larger molecules, or shaping them into higher 

quality molecules (EPA, 1995).

Downstream processes include thermal cracking, coking, catalytic cracking, catalytic 

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

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

2.2.1.2 Supporting Operations

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

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

the major supporting operations are described in this section.

Wastewater Treatment. Petroleum refining operations produce a variety of wastewaters 

including process water (water used in process operations like desalting), cooling water (water 

used for cooling that does not come into direct contact with the oil), and surface water runoff 

(resulting from spills to the surface or leaks in the equipment that have collected in drains). 
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2-6

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

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

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

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

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

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

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

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

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

catalytic cracking emit gases with a high concentration of hydrogen sulfide mixed with light 

refinery fuel gases (such as methane and ethane). Sulfur must be removed from these gases in 

order to comply with the Clean Air Act’s SOx emission limits and to recover saleable elemental 

sulfur. 

Sulfur is recovered by first separating the fuel gases from the hydrogen sulfide gas. Once 

this is done, elemental sulfur is removed from the hydrogen sulfide gas using a recovery system 

known as the Claus Process. In this process, hydrogen sulfide is burned under controlled 

conditions producing sulfur dioxide. A bauxite catalyst is then used to react with the sulfur 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Comment [A2]: Suggest delete?
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systems enable the safe handling of liquids and gases that are released by pressure-relieving 

devices and blow-downs. According to the OSHA Technical Manual, “pressure relief is an 

automatic, planned release when operating pressure reaches a predetermined level. A blow-down 

normally refers to the intentional release of material, such as blow-downs from process unit 

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

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

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

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

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

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

2.2.1.3 Inputs

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

labor, capital, and water.1 The inputs specific to this industry are crude oil and the variety of 

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

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

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

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

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

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

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

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

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

production of finished petroleum products (EIA 2010).2

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

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

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

petroleum refineries, their characteristics, and their applications. 

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

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

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

refineries was estimated between 65 and 90 gallons per barrel of crude oil processed (OGJ 1992a). 2 A barrel is a unit of volume that is equal to 42 U.S. gallons.
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Table 2-1 Types and Characteristics of Raw Materials used in Petroleum Refineries

Type Description

Crude Oil Heterogeneous mixture of different hydrocarbon compounds. 

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

gasoline blend. Ethanol, ethyl tertiary butyl ether (ETBE), and methanol are 

common oxygenates.

Caustics Caustics are added to desalting water to neutralize acids and reduce corrosion. 

They are also added to desalted crude in order to reduce the amount of corrosive 

chlorides in the tower overheads. They are used in some refinery treating processes 

to remove contaminants from hydrocarbon streams.

Leaded Gasoline Additives Tetraethyl lead (TEL) and tetramethyl lead (TML) are additives formerly used to 

improve gasoline octane ratings but are no longer in common use except in 

aviation gasoline.

Sulfuric Acid and 

Hydrofluoric Acid

Sulfuric acid and hydrofluoric acid are used primarily as catalysts in alkylation 

processes. Sulfuric acid is also used in some treatment processes.

Source: U.S. Department of Labor, Occupational Safety and Health Administration (OSHA). 2003. OSHA 

Technical Manual, Section IV: Chapter 2, Petroleum Refining Processes. TED 01-00-015. Washington, DC: U.S. 

DOL. Available at <http://www.osha.gov/dts/osta/otm/otm_iv/otm_iv_2.html>. As obtained on October 23, 2006. 

In 2010, the petroleum refining industry used 971 million barrels of natural gas liquids 

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

2.2.1.4 Types of Product Outputs

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

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

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

products can be found in Section 2.3. 
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Table 2-2 Refinery Product Categories

Product Category Description

Fuels Finished Petroleum products that are capable of releasing energy. These products 

power equipment such as automobiles, jets, and ships. Typical petroleum fuel 

products include gasoline, jet fuel, and residual fuel oil.

Finished nonfuel products Petroleum products that are not used for powering machines or equipment. These 

products typically include asphalt, lubricants (such as motor oil and industrial 

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

Feedstock

Sulfur

Many products derived from crude oil refining, such as ethylene, propylene, 

butylene, and isobutylene, are primarily intended for use as petrochemical 

feedstock in the production of plastics, synthetic fibers, synthetic rubbers, and other 

products.

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

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

industrial chemical.

Source: U.S. Department of Labor, Occupational Safety and Health Administration (OSHA). 2003. OSHA 

Technical Manual, Section IV: Chapter 2, Petroleum Refining Processes. TED 01-00-015. Washington, DC: U.S. 

DOL. Available at <http://www.osha.gov/dts/osta/otm/otm_iv/otm_iv_2.html>. As obtained on October 23, 2006. 

2.2.2 Emissions and Controls in Petroleum Refining

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

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

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

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

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

2.2.2.1 Gaseous and VOC Emissions

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

with petroleum products. Sources of these emissions from refineries include fugitive emissions 

of the volatile constituents in crude oil and its fractions, emissions from the burning of fuels in 

process heaters, and emissions from the various refinery processes themselves. Fugitive 

emissions occur as a result of leaks throughout the refinery and can be reduced by purchasing 

leak-resistant equipment and maintaining an ongoing leak detection and repair program (EPA, 

1995).

The numerous process heaters used in refineries to heat process streams or to generate 

steam (boilers) for heating or other uses can be potential sources of SOx, NOx, CO, and 

hydrocarbons emissions. Emissions are low when process heaters are operating properly and 

using clean fuels such as refinery fuel gas, fuel oil, or natural gas. However, if combustion is not 

complete, or the heaters are fueled using fuel pitch or residuals, emissions can be significant 

(EPA, 1995). 
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The majority of gas streams exiting each refinery process contain varying amounts of 

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

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

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

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

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

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

NSPS available in the docket.

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

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

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

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

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

particulates (EPA, 1995).

2.2.2.2 Wastewater and Other Wastes

Petroleum refining operations produce a variety of wastewaters including process water 

(water used in process operations like desalting), cooling water (water used for cooling that does 

not come into direct contact with the oil), and surface water runoff (resulting from spills to the 

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

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

sulfides, and other compounds) and is treated in on-site facilities before being recycled back into 

the production process or discharged.

Other wastes include forms of sludges, spent process catalysts, filter clay, and incinerator 

ash. These wastes are controlled through a variety of methods including incineration, land filling, 

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

2.2.3 Costs of Production

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

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

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

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

(1995–2009)

Figure 2-5 Petroleum Refinery Expenditures

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

Obtained through American Fact Finder Database 

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

U.S. Department of Commerce, Bureau of the Census. 2006. 2005 Annual Survey of Manufactures. 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

geo_id=01000US&-ds_name=EC0731I1&-NAICS2007=324110&-_lang=en
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2-12

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

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

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

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

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

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

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

Payroll ($millions) Materials ($millions) Total Capital ($millions)

Year Reported 2005 Reported 2005 Reported 2005

1995 3,791 4,603 112,532 136,633 5,937 7,209

1996 3,738 4,435 132,880 157,658 5,265 6,247

1997 3,885 4,595 127,555 150,865 4,244 5,020

1998 3,695 4,415 92,212 110,187 4,169 4,982

1999 3,983 4,682 114,131 134,146 3,943 4,635

2000 3,992 4,509 180,568 203,967 4,685 5,292

2001 4,233 4,743 158,733 177,838 6,817 7,638

2002 4,386 4,947 166,368 187,646 5,152 5,811

2003 4,752 5,227 185,369 203,893 6,828 7,510

2004 5,340 5,635 251,467 265,369 6,601 6,966

2005 5,796 5,796 345,207 345,207 10,525 10,525

2006 5,984 5,751 396,980 381,546 11,175 10,741

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

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

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

Note: Adjusted for inflation using the producer price index industry for total manufacturing industries (Table 5-6).

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

Obtained through American Fact Finder Database <http://factfinder.census.gov/home/saff/main.html?_lang=en>.

U.S. Department of Commerce, Bureau of the Census. 2006. 2005 Annual Survey of Manufactures. M05(AS)-1. 

Washington, DC: Government Printing Office. Available at <http://www.census.gov/prod/2006pubs/

am0531gs1.pdf>. As obtained on October 23, 2007.

U.S. Department of Commerce, Bureau of the Census. 2003a. 2001 Annual Survey of Manufactures. M01(AS)-1. 

Washington, DC: Government Printing Office. Available at <http://www.census.gov/prod/2003pubs/

m01as-1.pdf>. As obtained on October 23, 2006.

U.S. Department of Commerce, Bureau of the Census. 2001. 1999 Annual Survey of Manufactures. M99(AS)-1 

(RV). Washington, DC: Government Printing Office. Available at <http://www.census.gov/prod/2001pubs/

m99-as1.pdf>. As obtained on October 23, 2006.

U.S. Department of Commerce, Bureau of the Census. 1998. 1996 Annual Survey of Manufactures. M96(AS)-1 

(RV). Washington, DC: Government Printing Office. Available at <http://www.census.gov/prod/3/98pubs/

m96-as1.pdf>. As obtained on October 23, 2006.

U.S. Department of Commerce, Bureau of the Census. 1997. 1995 Annual Survey of Manufactures. M95(AS)-1. 

Washington, DC: Government Printing Office. Available at <http://www.census.gov/prod/2/manmin/

asm/m95as1.pdf>. As obtained on October 23, 2006.

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

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

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

NAICSASM=324110&-ds_name=AM0931GS101&-ib_type=NAICSASM&-_industry=324110&-_lang=en
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U.S. Census Bureau, American FactFinder; “Sector 31: Manufacturing: Industry Series: Detailed Statistics by 

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

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

NAICS2007=324110&-_lang=en
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Table 2-4 Costs of Materials Used in Petroleum Refining Industry

2007 2002

Material

Delivered 

Cost ($103)

Percentage 

of Material 

Costs

Delivered 

Cost ($103)

Percentage 

of Material 

Costs

Petroleum Refineries NAICS 324110

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

Domestic crude petroleum, including lease 

condensate

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

Foreign crude petroleum, including lease 

condensate

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

Foreign unfinished oils (received from 

foreign countries for further processing)

D 2,297,967 1.5%

Ethane (C2) (80% purity or more) — D

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

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

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

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

Other natural gas liquids, including plant 

condensate

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

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

Additives (including antioxidants, 

antiknock compounds, and inhibitors)

D 40,842 0.0%

Other additives (including soaps and 

detergents)

— 709 0.0%

Animal and vegetable oils — D

Chemical catalytic preparations D D

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

Sodium hydroxide (caustic soda) (100% 

NaOH)

209,918 0.1% 129,324 0.1%

Sulfuric acid, excluding spent (100% 

H2SO4)

67,458 0.0% 189,912 0.1%

Metal containers D 9,450 0.0%

Plastics containers D D

Paper and paperboard containers 1,819 0.0% D

Cost of materials received from petroleum 

refineries and lube manufacturers

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

All other materials and components, parts, 

containers, and supplies

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

Materials, ingredients, containers, and 

supplies

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

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

Shipbuilding and Repair. Washington, DC: Government Printing Office. Available at 

<http://www.census.gov/prod/ec02/ec0231i324110.pdf>. As obtained on October 23, 2006.

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

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

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

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

fds_name=EC0700A1>
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2.3 The Demand Side

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

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

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

consumers, and possible substitutes. 

2.3.1 Product Characteristics

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

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

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

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

groups based on their intended uses (EIA, 1999a):

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

gasoline

 nonfuel products—petroleum products that are not used for powering machines or 

equipment such as solvents and lubricating oils

 petrochemical feedstocks—petroleum products that are used as a raw material in the 

production of plastics, synthetic rubber, and other goods

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

description of each product’s characteristics and primary uses. 

2.3.2 Uses and Consumers

Finished petroleum products are rarely consumed as final goods. Instead, they are used as 

primary inputs in the creation of a vast number of other goods and services. For example, goods 

created from petroleum products include fertilizers, pesticides, paints, thinners, cleaning fluids, 

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

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

demand for many finished petroleum products is derived from the demand for the goods and 

services they are used to create. 

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

 Residential sector—private homes and residences

 Industrial sector—manufacturing, construction, mining, agricultural, and forestry 

establishments

 Transportation sector—private and public vehicles that move people and 

commodities such as automobiles, ships, and aircraft
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 Commercial sector—nonmanufacturing or nontransportation business establishments 

such as hotels, restaurants, retail stores, religious and nonprofit organizations, as well 

federal, state, and local government institutions

 Electric utility sector—privately and publicly owned establishments that generate, 

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

producers are not included in this sector 

Table 2-5 Major Refinery Products

Product Description

Fuels

Gasoline A blend of refined hydrocarbons, motor gasoline ranks first in usage among petroleum 

products. It is primarily used to fuel automobiles and lightweight trucks as well as 

boats, recreational vehicles, lawn mowers, and other equipment. Other forms of 

gasoline include Aviation gasoline, which is used to power small planes. 

Kerosene Kerosene is a refined middle-distillate petroleum product that finds considerable use 

as a jet fuel. Kerosene is also used in water heaters, as a cooking fuel, and in lamps. 

Liquefied petroleum gas 

(LPG)

LPG consists principally of propane (C3H8) and butane (C4H10). It is primarily used 

as a fuel in domestic heating, cooking, and farming operations.

Distillate fuel oil Distillate fuel oil includes diesel oil, heating oils, and industrial oils. It is used to 

power diesel engines in buses, trucks, trains, automobiles, as well as other machinery. 

Residual fuels Residual fuels are the fuels distilled from the heavier oils that remain after 

atmospheric distillation; they find their primary use generating electricity in electric 

utilities. However, residual fuels can also be used as fuel for ships, industrial boiler

fuel, and commercial heating fuel. 

Petroleum coke Coke is a high carbon residue that is the final product of thermal decomposition in the 

condensation process in cracking. Coke can be used as a low-ash solid fuel for power 

plants.

Finished Nonfuel Products

Coke In addition to use as a fuel, petroleum coke can be used a raw material for many 

carbon and graphite products such as furnace electrodes and liners. 

Asphalt Asphalt, used for roads and roofing materials, must be inert to most chemicals and 

weather conditions.

Lubricants Lubricants are the result of a special refining process that produce lubricating oil base 

stocks, which are mixed with various additives. Petroleum lubricating products 

include spindle oil, cylinder oil, motor oil, and industrial greases.

Solvents A solvent is a fluid that dissolves a solid, liquid, or gas into a solution. Petroleum 

based solvents, such as Benzyme, are used to manufacture detergent and synthetic 

fibers. Other solvents include toluene and xylene.

Feedstock

Ethylene Ethylene is the simplest alkene and has the chemical formula C2H4. It is the most 

produced organic compound in the world and it is used in the production of many 

products. For example, one of ethylene’s derivatives is ethylene oxide, which is a 

primary raw material in the production of detergents. 

Propylene Propylene is an organic compound with the chemical formula C3H6. It is primarily 

used the production of polypropylene, which is used in the production of food 

packaging, ropes, and textiles. 

Sources: U.S. Department of Labor, Occupational Safety and Health Administration (OSHA). 2003. OSHA 

Technical Manual, Section IV: Chapter 2, Petroleum Refining Processes. TED 01-00-015. Washington, DC: U.S. 

DOL. Available at <http://www.osha.gov/dts/osta/otm/otm_iv/otm_iv_2.html>. As obtained on October 23, 2006. 

U.S. Department of Energy, Energy Information Administration (EIA). 1999.
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-17

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

products, accounting for 67% of total consumption in 2005 (EIA, 2006a). In fact, petroleum 

products like motor gasoline, distillate fuel, and jet fuel provide virtually all of the energy 

consumed in the transportation sector (EIA, 1999a). 

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

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

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

2006a). 

2.3.3 Substitution Possibilities in Consumption

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

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

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

sectors can switch relatively quickly and easily (EIA, 1999a). 

For example, equipment at large manufacturing plants often can use either residual fuel 

oil or natural gas. Often coal and natural gas can be easily substituted for residual fuel oil at 

electricity utilities. As a result, we would expect demand in these industries to be more sensitive 

to price (in the short run) than in others (EIA, 1999a). 

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

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

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

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

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

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

2.4 Industry Organization

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

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

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

2.4.1 Market Structure

Market structure characterizes the level and type of competition among petroleum 

refining companies and determines their power to influence market prices for their products. For 

example, if an industry is perfectly competitive, then individual producers cannot raise their 
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-18

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

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

subsequent EIAs.

According to basic microeconomic theory, perfectly competitive industries are 

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

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

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

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

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

on these three factors.

2.4.1.1 Barriers to Entry

Firms wanting to enter the petroleum refining industry may face at least two major 

barriers to entry. First, according to a 2004 Federal Trade Commission staff study, there are 

significant economies of scale in petroleum refinery operations. This means that costs per unit 

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

produce at relatively low levels will face higher average costs than firms that are established and 

produce at higher levels, which will make it more difficult for these new firms to compete 

(Nicholson, 2005). This is known as a technical barrier to entry. 

Second, legal barriers could also make it difficult for new firms to enter the petroleum 

refining industry. The most common example of a legal barrier to entry is patents—intellectual 

property rights, granted by the government, that give exclusive monopoly to an inventor over his 

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

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

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

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

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

entrants or new pollution sources. Such regulations would raise the operating costs of new firms 

without affecting the operating costs of existing ones. As a result, new firms may be less 

competitive. 

Although neither of these barriers is impossible for new entrants to overcome, they can 

make it more difficult for new firms to enter the market for manufactured petroleum products. As 

a result, existing petroleum refiners could potentially raise their prices above competitive levels 

with less worry about new firms entering the market to compete away their customers with lower 
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-19

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

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

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

existing firms would work to keep prices at competitive levels. 

2.4.1.2 Measures of Industry Concentration

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

industry. Common measures include four-firm concentration ratios (CR4), eight-firm 

concentration ratios (CR8), and Herfindahl-Hirschmann indexes (HHI). The CR4s and CR8s 

measure the percentage of sales accounted for by the top four and eight firms in the industry. The 

HHIs are the sums of the squared market shares of firms in the industry. These measures of 

industry concentrated are reported for the petroleum refining industry (NAICS 324110) in Table 

2-6 for selected years between 1985 and 2007.

Between 1990 and 2000, the HHI rose from 437 to 611, which indicates an increase in 

market concentration over time. This increase is partially due to merger activity during this time 

period. Between 1990 and 2000, over 2,600 mergers occurred across the petroleum industry; 

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

From 2000 to 2007 the HHI rose again.

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

the values of these concentration ratios. However, accepted criteria have been established for 

determining market structure based on the HHIs for use in horizontal merger analyses (U.S. 

Department of Justice and the Federal Trade Commission, 1992). According to these criteria, 

industries with HHIs below 1,000 are considered unconcentrated (i.e., more competitive); 

industries with HHIs between 1,000 and 1,800 are considered moderately concentrated (i.e., 

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

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

recent years.

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

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

in one geographic region may not exert competitive pressure on a refinery in another region if 

transportation costs are high. This was done by comparing HHIs across Petroleum 

Administration for Defense Districts (PADDs). PADDs separate the United States into five 

geographic regions or districts. They were initially created during World War II to help manage 
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-20

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

of organizing petroleum market information (FTC, 2004).

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

Measure 1985 1990 1996 2000 2001 2002 2003 2007

Herfindahl-Hirschmann Index 

(HHI)

493 437 412 611 686 743 728 807

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

Eight-firm concentration ratio 

(CR8)

54.6 52.2 48.4 61.6 67.2 70.0 69.4 73.1

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

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

February 6, 2007. 

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

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

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

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

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

_industry=324110&-_lang=en>

This study concluded that these geographic markets were not highly concentrated. 

PADDs I, II, and III (East Coast, Midwest, and Gulf Coast) were sufficiently connected that they 

exerted a competitive influence on each other. The HHI for these combined regions was 789 in 

2003, indicating a low concentration level. Concentration in PADD IV (Rocky Mountains) was 

also low in 2003, with an HHI of 944. PADD V gradually grew more concentrated in the 1990s 

after a series of significant refinery mergers. By 2003, the region’s HHI was 1,246, indicating a 

growth to a moderate level of concentration (FTC, 2004). 

2.4.1.3 Product Differentiation

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

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

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

competitors. 

While we saw in Section 3.3 that there are a wide variety of petroleum products with 

many different uses, individual petroleum products are by nature quite homogenous. For 

example, there is little difference between premium motor gasoline produced at different 

refineries (Mathtech, 1997). As a result, the role of product differentiation is probably quite 

small for many finished petroleum products. However, there are examples of relatively small 
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-21

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

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

2.4.1.4 Competition among Firms in the Petroleum Refining Industry

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

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

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

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

current structure of the market. 

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

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

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

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

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

report and refer to the physical location where products are manufactured. Likewise, the terms 

“company” and “firm” are used interchangeably to refer to the legal business entity that owns 

one or more facilities. This section presents information on refineries, such as their location and 

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

2.4.2.1 Geographic Distribution of U.S. Petroleum Refineries

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

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

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

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

California.

2.4.2.2 Capacity Utilization

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

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

production volumes to full-capacity production volumes. For example, if an industry is 

producing as much output as possible without adding new floor space for equipment, the 

capacity utilization rate would be 100 percent. On the other hand, if under the same constraints 

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

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

from year to year depending on economic conditions. It is also variable on a company-by-
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-22

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

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

floor space, others need additional space or capacity.

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

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

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

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

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

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

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

atmospheric crude oil distillation, such as crude oil) by the industry’s operational capacity.
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-23

Table 2-7 Number of Petroleum Refineries, by State

State Number of Petroleum Refineries

Alabama 3

Alaska 6

Arkansas 2

California 20

Colorado 2

Delaware 1

Georgia 1

Hawaii 2

Illinois 4

Indiana 2

Kansas 3

Kentucky 2

Louisiana 19

Michigan 1

Minnesota 2

Mississippi 3

Montana 4

Nevada 1

New Jersey 5

New Mexico 3

North Dakota 1

Ohio 4

Oklahoma 6

Pennsylvania 5

Tennessee 1

Texas 26

Utah 5

Virginia 1

Washington 5

West Virginia 1

Wisconsin 1

Wyoming 6

Total 148

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

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

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

http://www.eia.gov/petroleum/refinerycapacity/
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2-24

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

Year

Petroleum Refineries

Capacity Utilization Rates 

(NAICS 324110)

Gross Input to Atmospheric 

Crude Oil Distillation Units 

(1,000s of barrels per day)

Operational Capacity 

(1,000s of barrels per day)

2000 92.6 15,299 16,525

2001 92.6 15,352 16,582

2002 90.7 15,180 16,744

2003 92.6 15,508 16,748

2004 93.0 15,783 16,974

2005 90.6 15,578 17,196

2006 89.7 15,602 17,385

2007 88.5 15,450 17,450

2008 85.3 15,027 17,607

2009 82.9 14,659 17,678

2010 86.4 15,177 17,575

Sources: U.S. Department of Energy, Energy Information Administration (EIA). 2007a. “Refinery Utilization and 

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

January, 2007.

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

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

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

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

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

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

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

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

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

resulting in a 2.8 percent decrease in utilization.

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

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

refinery with no more than 1,500 employees.3

 For this analysis we applied the small refiner 

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

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

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

Number 122, page 35858). 

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

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

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

 3 See Table in 13 CFR 121.201, NAICS code 324110.
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-25

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

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

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

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

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

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

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

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

different levels of revenue are presented in Figures 2-8 and 2-9. 
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-26

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

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

Component 1, OMB Control No. 2060-0657.

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

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

estimated data for 2011, or occasionally 2009 values.

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

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

estimated data for 2011.

14 firms

6 firms

9 firms

4 firms 3 firms

25 firms

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

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

Share of firms (%)

Number of Employees

14 firms

6 firms

9 firms

4 firms 3 firms

25 firms

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

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

Share of firms (%)

Number of Employees
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-27

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

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

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

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

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

September 2011.

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

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

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

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

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

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

2-28

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

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

Component 1, OMB Control No. 2060-0657.

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

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

estimated data for 2011, or occasionally 2009 values.

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

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

estimated data for 2011.

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

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

2-29

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

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

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

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

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

September 2011.

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

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

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

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

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

Library.

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

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)

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

2-30

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

Component 1, OMB Control No. 2060-0657.

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

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

estimated data for 2011, or occasionally 2009 values.

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

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

estimated data for 2011.

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

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

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

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

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

September 2011.

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

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

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

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

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

Library.

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

2-31

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

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

Component 1, OMB Control No. 2060-0657.

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

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

estimated data for 2011, or occasionally 2009 values.

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

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

estimated data for 2011.

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

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

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

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

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

September 2011.

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

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

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

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

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

Library.

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

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

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

5 firms

1 firm

8 firms

2 firms

7 firms

4 firms

9 firms

0%

5%

10%

15%

20%

25%

30%

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

Revenue ($millions)
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-32

In Section 3.4.2.1, we discussed how petroleum refining operations are characterized by 

economies of scale—that the cost per unit falls as a refinery produces more finished petroleum 

products. This means that smaller petroleum refiners face higher per unit costs than larger 

refining operations because they produce fewer petroleum products. As a result, some smaller 

firms have sought to overcome their competitive disadvantage by locating close to productconsuming areas to lower transportation costs and serving niche product markets (FTC, 2004).

A good example of a firm locating close to prospective customers is Countrymark 

Cooperative, Inc., which was started in the 1930s for the express purpose of providing farmers in 

Indiana with a consistent supply of fuels, lubricants, and other products. A good example of a 

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

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

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

largest unit (Hoovers, 2011 online). Also Arabian American Development Company’s South 

Hampton Resources facility specializes in producing high purity solvents for the plastics and 

foam industries. 

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

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

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

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

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

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

their refining operations. 

Capacity information for the refineries owned by small businesses also suggests that 

fewer small businesses are focusing on developing specialty products or serving local customers 

as major parts of their business plan. For example, in 2006 29 small refineries had a collective 

crude refining capacity of 778,920 barrels per calendar day or 857,155 barrels per stream day 

(EIA, 2006c). Approximately 21% of this total capacity was devoted to producing specialty 

products or more locally focused products such as aromatics, asphalt, lubricants, and petroleum 

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

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

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

As discussed in Section 3.4.1.3, fuel products tend to be quite homogenous (gasoline from one 

refinery is not very different from gasoline from another refinery), and they are also normally 

transported by pipeline.
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-33

2.5 Markets

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

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

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

petroleum refining industry. 

2.5.1 U.S. Petroleum Consumption

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

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

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

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

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

2-34

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

Parent Company

Parent 

Company 

Type

Cumulative 

Crude 

Capacity 

(bbl/cd)

Parent 

Company 

Employment

(#) Facility Name

Facility 

City

Facilit

y State Facility County

Facility 

County 

Population 

Density (2000)

Facility 

County 

Population 

Density (2010)

AGE Refining, Inc. Private 14,021 124 AGE Refining Inc San Antonio TX Bexar County 1,117 1,383

American Refining Group, 

Inc.

Private 10,000 323 American 

Refining Group 

Inc

Bradford PA McKean County 47 44

Arabian American 

Development Co

Public 0 145 South Hampton 

Resources Inc.

Silsbee TX Hardin County 54 61

BTB Refining Private 0 37 Trigeant Ltd. Corpus 

Christi

TX Nueces County 375 406

Calcasieu Refining Company Private 78,000 92 Calcasieu 

Refining Co.

Lake 

Charles

LA Calcasieu Parish 171 181

Calumet Specialty Products 

Partners, L.P.

Public 57,000 654 Calumet 

Shreveport LLC

Shreveport LA Caddo Parish 286 290

Calumet Specialty Products 

Partners, L.P.

Public 13,020 654 Calumet 

Lubricants Co LP

Cotton 

Valley

LA Caddo Parish 286 290

Calumet Specialty Products 

Partners, L.P.

Public 8,300 654 Calumet 

Lubricants Co LP

Princeton LA Caddo Parish 286 290

CHS, Inc. Public 59,600 287 Cenex Harvest 

States

Laurel MT Yellowstone 

County

49 56

Connacher Oil and Gas, 

Limited

Public 10,000 170 Montana Refining 

Co.

Great Falls MT Cascade County 30 30

CVR Energy, Inc. Public 115,700 371 Coffeyville 

Resources 

Rfg&Mktg LLC

Coffeyville KS Montgomery 

County

56 55

Countrymark Cooperative Private 26,500 425 Countrymark 

Cooperative, Inc.

Mt. Vernon IN Posey County 66 63

Cross Oil Refining & 

Marketing, Inc.

Private 7,500 110 Martin Midstream 

Partners LP

Smackover AR Union County 44 40

Foreland Refining Corp. Private 2,000 27 Foreland Refining 

Co.

Ely NV White Pine 

County

1 1

Frontier Oil Corp. Private 47,000 723 Frontier Refining 

Inc

Cheyenne WY Laramie County 30 34

(continued)
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-35

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

Parent Company

Parent 

Company 

Type

Cumulative 

Crude 

Capacity 

(bbl/cd)

Parent 

Company 

Employment 

(#) Facility Name

Facility 

City

Facilit

y State Facility County

Facility 

County 

Population 

Density (2000)

Facility 

County 

Population 

Density (2010)

Frontier Oil Corp. Private 138,000 723 Frontier El 

Dorado Refining 

Co

El Dorado KS Butler County 42 46

Garco Energy Private 3,600 16 Garco Energy 

LLC

Douglas WY Converse 

County

3 3

Gary-Williams Energy 

Corporation

Private 70,000 260 Wynnewood 

Refining Co.

Wynnewood OK Garvin County 34 34

Goodway Refining, LLC Private 4,100 17 Goodway 

Refining LLC

Atmore AL Escambia 

County

41 41

Gulf Atlantic Operations 

LLC

Private 32 Gulf Atlantic 

Operations LLC

Mobile Bay AL Mobile County 324 336

Holly Corporation Public 25,050 1,321 Holly Refining & 

Marketing Co

Woods 

Cross

UT Davis County 785 1,026

Holly Corporation Public 105,000 1,321 Navajo Refining 

Co.

Artesia NM Eddy County 12 13

Holly Corporation Public 70,300 1,321 Holly Refining & 

Marketing Co

Tulsa East OK Tulsa County 988 1,058

Holly Corporation Public 85,000 1,321 Holly Refining & 

Marketing Co

Tulsa West OK Tulsa County 988 1,058

Hunt Refining Co. Private 36,000 1,100 Hunt Refining Co. Tuscaloosa AL Tuscaloosa 

County

125 147

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

Refining Co

Sandersville MS Lamar County 79 112

Kern Oil & Refining Co. Private 26,000 346 Kern Oil & 

Refining Co.

Bakersfield CA Kern County 81 103

Lion Oil Co. Private 75,000 350 Lion Oil Co. El Dorado AR Union County 44 40

National Cooperative 

Refinery Association

Public 85,500 612 National 

Cooperative 

Refinery 

Association

McPherson KS McPherson 

County

33 33

NuStar Energy LP Public 70,000 1,492 Nustar Asphalt 

Refining LLC

Paulsboro NJ Gloucester 784 895

NuStar Energy LP Public 28,000 1,492 Nustar Asphalt 

Refining LLC

Savannah GA Chatham 530 622

(continued)
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-36

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

Parent Company

Parent 

Company 

Type

Cumulative 

Crude 

Capacity 

(bbl/cd)

Parent 

Company 

Employment 

(#) Facility Name

Facility 

City

Facilit

y State Facility County

Facility 

County 

Population 

Density (2000)

Facility 

County 

Population 

Density (2010)

Pasadena Refining Systems 

Inc.

Private 120,000 348 Pasadena Refining 

Systems Inc.

Pasadena TX Harris County 1967 2,402

Pelican Refining Co LLC Private 0 33 Pelican Refining 

Co. LLC

Lake 

Charles

LA Calcasieu Parish 171 181

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

Star

11 13

Petro Star Inc. Private 55,000 400 Petro Star Inc. Valdez AK Valdez Cordova 0.3 0

Placid Refining Private 57,000 207 Placid Refining 

Inc.

Port Allen LA West Baton 

Rouge Parish

113 124

San Joaquin Refining Co. Private 15,000 108 San Joaquin 

Refining Co., Inc.

Bakersfield CA Kern County 81 103

Santa Maria Refining 

Company

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

County

146 155

Silver Eagle Refining Inc. Private 3,000 60 Silver Eagle 

Refining

Evanston WY Uinta County 10 10

Silver Eagle Refining Inc. Private 10,250 60 Silver Eagle 

Refining

Woods 

Cross

UT Davis County 785 1,026

Somerset Oil Inc. Private 5,500 11 Somerset Energy 

Refinery LLC

Somerset KY Pulaski County 85 96

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

Co.

Tacoma WA Pierce County 417 476

Ventura Refining & 

Transmission, LLC

Private 12,000 37 Ventura Refining 

& Transmission 

LLC

Thomas OK Custer County 27 28

Western Refining, Inc. Public 122,000 636 Western Refining 

Company LP

El Paso TX El Paso County 671 791

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

Yorktown Inc

Yorktown VA York County 533 625

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

Southwest Inc

Bloomfield NM San Juan County 21 24

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

Southwest Inc

Gallup NM McKinley 

County

14 13

(continued)
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-37

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

Parent Company

Parent 

Company 

Type

Cumulative 

Crude 

Capacity 

(bbl/cd)

Parent 

Company 

Employment 

(#) Facility Name

Facility 

City

Facility 

State Facility County

Facility 

County 

Population 

Density (2000)

Facility 

County 

Population 

Density (2010)

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

Co.

South Gate CA Los Angeles 

County

2,344 2,420

Wyoming Refining Co. Private 14,000 96 Wyoming 

Refining Co

New Castle WY Weston County 3 3

Total 1,875,641 11,264 103

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

100% Data 2010 Census” (Data accessed on 10/21/2011); http://factfinder2.census.gov/faces/tableservices/jsf/pages/productview.xhtml?ftp=table

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

either actual data for 2010/2011 reported by companies, estimated data for 2011, or occasionally 2009 values.

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

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

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

Ward’s Business Directory compiles financial data from several sources such as annual reports, company websites, and phone interviews. If financial 

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

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

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

Copyright 2011 Experian Information Solutions, Inc., Experian Business Reports accessed through LexisNexis at James Branch Cabell Library 

(Virginia Commonwealth University). Experian Business Reports reflects the most recent data reported by a company, which may be 2010 or 2011.

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

Employment Data from Petroleum Refinery Emissions Information Collection, where available, Component 1, OMB Control No. 2060-0657.

Energy Information Administration (EIA), Form EIA 820, “Annual Refinery Report,” Table 3. Capacity of Operable Petroleum Refineries by State and 

Individual Refinery as of January 1, 2011 <http://www.eia.gov/petroleum/refinerycapacity/>
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-38

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

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

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

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

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

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

year period is 3% (Table 2-10). 
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-39

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

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

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

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

6,400

6,600

6,800

7,000

7,200

7,400

7,600

7,800

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Millions of barrels 

per year

Year

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

2-40
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-41

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

Year

Motor 

Gasoline Jet Fuel

Distillate 

Fuel Oil

Residual 

Fuel Oil

Liquefied 

Petroleum Gases

Other 

Products Total

2000 3,101 631 1,362 333 816 967 7,211

2001 3,143 604 1,404 296 746 978 7,172

2002 3,229 591 1,378 255 789 969 7,213

2003 3,261 576 1,433 282 757 1,003 7,312

2004 3,333 597 1,485 316 780 1,076 7,588

2005 3,343 613 1,503 336 741 1,057 7,593

2006 3,377 596 1,522 251 749 1,055 7,551

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

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

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

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

Sources: Annuals, Volume 1.” Available at <http://www.eia.doe.gov/oil_gas/petroleum/data_publications/

petroleum_supply_annual/psa_volume1/psa_volume1.html>. As obtained on October 31, 2007.

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

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

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

2.5.2 U.S. Petroleum Production

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

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

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

and 2009 production declined by slightly. 

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

Year

Motor 

Gasoline Jet Fuel

Distillate 

Fuel Oil

Residual 

Fuel Oil

Liquefied 

Petroleum Gases

Other 

Products Total

2000 2,910 588 1,310 255 258 990 6,311

2001 2,928 558 1,349 263 243 968 6,309

2002 2,987 553 1,311 219 245 990 6,305

2003 2,991 543 1,353 241 240 1,014 6,383

2004 3,025 566 1,396 240 236 1,057 6,520

2005 3,036 564 1,443 229 209 1,015 6,497

2006 3,053 541 1,475 232 229 1,032 6,561

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

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

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

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

Sources: U.S. Department of Energy, Energy Information Administration (EIA). 1996–2007. “Petroleum Supply 

Annuals, Volume 1.” Available at <http://www.eia.doe.gov/oil_gas/petroleum/data_publications/

petroleum_supply_annual/psa_volume1/psa_volume1.html>. As obtained on October 31, 2007.
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-42

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

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

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

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

two hurricanes (Hurricane Katrina and Hurricane Rita) on the U.S. Gulf Coast—the location of 

many U.S. petroleum refineries (Section 3.4.2). According to the American Petroleum Institute, 

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

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

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

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

2.5.3 International Trade

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

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

1995 and 2006, while imports of most major petroleum products grew at approximately the same 

rate, the growth of petroleum product exports was driven largely by residual fuel oil and other 

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

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

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

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

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

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

2010 were 2.4 times the level of exports in 2001. 

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

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

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

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

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

of total petroleum products (EIA 2012).4

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

http://www.eia.gov/dnav/pet/pet_move_wkly_dc_NUS-Z00_mbblpd_4.htm.
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-43

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

Year Millions of $Reported Millions of $2005

1997 152,756 180,671

1998 114,439 136,746

1999 140,084 164,651

2000 210,187 237,425

2001 195,898 219,476

2002 186,761 210,647

2003 216,764 238,425

2004 290,280 306,328

2005 419,063 419,063

2006 489,051 470,037

2007 551,997 510,996

2008 682,756 585,664

2009 436,974 394,348

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

Industries (Table 2-16).

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

Obtained through American Fact Finder Database 

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

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

M01(AS)-2. Washington, DC: Government Printing Office. Available at 

<http://www.census.gov/prod/2003pubs/m01as-2.pdf>. As obtained on March 4, 2008.

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

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

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

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

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

Year

Motor 

Gasoline Jet Fuel

Distillate 

Fuel Oil

Residual 

Fuel Oil

Liquefied 

Petroleum Gases

Other 

Products Total

1995 97 35 71 68 53 262 586

1996 123 40 84 91 61 322 721

1997 113 33 83 71 62 345 707

1998 114 45 77 101 71 324 731

1999 139 47 91 86 66 344 774

2000 156 59 108 129 79 343 874

2001 166 54 126 108 75 400 928

2002 182 39 98 91 67 396 872

2003 189 40 122 119 82 397 949

2004 182 47 119 156 96 520 1,119

2005 220 69 120 193 120 587 1,310

2006 173 68 133 128 121 687 1,310

2007 151 79 111 136 90 688 1,255

2008 110 38 78 128 93 700 1,146

2009 82 29 82 121 66 597 977

2010 49 36 83 134 56 584 942

Sources: U.S. Department of Energy, Energy Information Administration (EIA).1996–2007. “Petroleum Supply 

Annuals, Volume 1.” Available at <http://www.eia.doe.gov/oil_gas/petroleum/data_publications/

petroleum_supply_annual/psa_volume1/psa_volume1.html>. As obtained on October 31, 2007.
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-44

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

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

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

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

Year

Motor 

Gasoline Jet Fuel

Distillate 

Fuel Oil

Residual 

Fuel Oil

Liquefied 

Petroleum Gases

Other 

Products Total

1995 38 8 67 49 21 128 312

1996 38 17 70 37 19 138 319

1997 50 13 56 44 18 147 327

1998 46 9 45 50 15 139 305

1999 40 11 59 47 18 124 300

2000 53 12 63 51 27 157 362

2001 48 10 44 70 16 159 347

2002 45 3 41 65 24 177 356

2003 46 7 39 72 20 186 370

2004 45 15 40 75 16 183 374

2005 49 19 51 92 19 183 414

2006 52 15 79 103 21 203 472

2007 46 15 98 120 21 213 513

2008 63 22 193 130 25 216 649

2009 71 25 214 152 36 224 723

2010 108 31 239 148 48 270 843

Sources: U.S. Department of Energy, Energy Information Administration (EIA). 1996–2007. “Petroleum Supply 

Annuals, Volume 1.” Available at <http://www.eia.doe.gov/oil_gas/petroleum/data_publications/

petroleum_supply_annual/psa_volume1/psa_volume1.html>. As obtained on October 31, 2007.

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

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

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

2.5.4 Market Prices

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

for selected years in Table 2-15.5 As these data illustrate, nominal prices rose substantially 

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

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

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

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

agriculture, industry, and utilities, as well as residential and commercial consumers.
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-45

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

Product 1995 2000 2005 2008 2009 2010

Motor gasoline 76.5 110.6 183 278 189 230

No. 1 distillate fuel 62.0 98.8 183 298 214 271

No. 2 distillate fuel 56.0 93.4 178 314 184 232

Jet fuel 54.0 89.9 174 305 170 220

Residual fuel oil 39.2 60.2 105 196 134 171

Note: Prices do not include taxes.

Sources: U.S. Department of Energy, Energy Information Administration (EIA). 2007b. “Refiner Petroleum Product 

Prices by Sales Type.” Available at <http://tonto.eia.doe.gov/dnav/pet/pet_pri_refoth_dcu_nus_m.htm>. As 

obtained on January 11, 2008.

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

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

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

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

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

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

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

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

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

levels, however the decrease was 36% for petroleum refineries and 5% for all manufacturing firms.
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-46

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

Petroleum Refining (NAICS 32411) Total Manufacturing Industries

Year PPI

Annual Percentage 

Change in PPI PPI

Annual Percentage 

Change in PPI

1995 74.5 3% 124.2 3%

1996 85.3 14% 127.1 2%

1997 83.1 −3% 127.5 0%

1998 62.3 −25% 126.2 −1%

1999 73.6 18% 128.3 2%

2000 111.6 52% 133.5 4%

2001 103.1 −8% 134.6 1%

2002 96.3 −7% 133.7 −1%

2003 121.2 26% 137.1 3%

2004 151.5 25% 142.9 4%

2005 205.3 36% 150.8 6%

2006 241.0 17% 156.9 4%

2007 266.9 11% 162.9 4%

2008 338.3 27% 175.8 8%

2009 217.0 −36% 167.1 −5%

2010 289.4 33% 175.4 5%

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

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

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

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

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

2.5.5 Profitability of Petroleum Refineries

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

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

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

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

based on the value of assets owned by the reporting firms.
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-47

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

Sorted by Value of Assets 

Fiscal Year

Total 

Number of 

Statements

0 to 

500,000

500,000 to 

2 Million

2 Million 

to 10 

Million

10 Million 

to 50 

Million

50 Million 

to 100 

Million

100 Million 

to 250 

Million

All 

Firms

4/1/2006–

3/31/2007

44 — — 4.6 6.5 — — 6.7

4/1/2009–

3/31/2010

43 — — 5.5 — — — 4.1

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

Pennsylvania: RMA, Inc.

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

Pennsylvania: RMA, Inc.

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

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

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

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

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

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

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

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

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

Obtaining profitability information specifically for small petroleum refining companies 

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

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

the Arabian American Development Co., CVR Energy Inc., Calumet Specialty Products 

Partners, L.P., Holly Corporation, and Western Refining, Inc. Profit ratios were calculated for 

these companies using data obtained from their publicly available 2010 income statements. 

These ratios are presented in Table 2-18.
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Table 2-18 Net Profit Margins for Publicly Owned, Small Petroleum Refiners: 2010 

Company

Net Income 

($millions)

Total Revenue 

($millions)

Net Profit Margin 

(%)

Arabian American Development Co. 2.69 139.11 1.93%

Calumet Specialty Products Partners 16.70 2,190.80 0.76%

CVR Energy Inc. 14.30 4,079.80 0.35%

Holly Corporation 133.10 8,323.00 1.60%

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

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

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

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

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

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

Arabian American Develop Co., South Hampton Resources, Inc. Arabian American Development Co. Q4 

& FY2010 Financial Results. (Data accessed on 10/21/11) [Source for 2010 numbers.] 

http://www.arabianamericandev.com/images/uploads/investor/2010eoyearningspresentation.pdf> 

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

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

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

K&d=c7dd2813722445ded56c7e3aefebf2ca>

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

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

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

2.5.6 Industry Trends

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

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

capacity utilization to the year 2035. Trends in these variables are affected by many factors that 

are difficult to predict, such as energy prices, U.S. economic growth, advances in technologies, 

changes in weather patterns, and future public policy decisions. As a result, the EIA evaluated a 

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

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

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

(EIA, Form EIA-820). 

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

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

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

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

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

petroleum products sold to end users are expected to rise over the same period (Table 2-19). 
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Higher prices and tighter fuel efficiency standards (enlarged production of non-oil fuels) will 

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

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

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

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

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

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

(cents per gallon)

Product 2011 2012 2013 2014 2015 2016 2017 2018 2019

Motor gasoline 286.1 291.3 312.3 326.9 342.1 353.6 369.5 382.9 395.5

Jet fuel 233.0 252.2 261.8 270.4 280.3 297.9 314.5 330.8 346.1

Distillate fuel 302.6 289.8 301.9 313.9 326.9 345.8 364.1 382.3 400.4

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

LPGs 178.9 180.5 186.7 193.6 200.4 208 217 226.2 235.4

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

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

2007.

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

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

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

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

Year

Motor 

Gasoline Jet Fuel

Distillate 

Fuel Oil

Residual 

Fuel Oil

Liquefied 

Petroleum Gases

Other 

Products Total

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

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

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

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

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

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

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

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

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

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

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

2007.

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

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

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

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

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

during this period. 
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Table 2-21 Full Production Capacity Utilization Rates for Petroleum Refineries

Year

Petroleum Refineries

Capacity Utilization Rates 

(NAICS 324110)

Gross Input to Atmospheric 

Crude Oil Distillation Units 

(1,000s of barrels per day)6

Operational Capacity 

(1,000s of barrels per day)

2011 85.0% 14,946 17,583

2012 83.2% 14,672 17,635

2013 84.2% 14,836 17,626

2014 84.7% 14,851 17,524

2015 84.9% 14,847 17,497

2016 85.6% 14,853 17,342

2017 86.5% 14,827 17,142

2018 87.5% 14,778 16,887

2019 88.2% 14,743 16,706

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

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

2007.

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

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

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

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

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

2.6 References

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

utilization rate by the operational capacity.
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-51

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

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d44106e10vk.htm>.
*** Draft – Do Not Cite, Quote, or Release During Review ***

2-52

Holly Corporation, EDGAR database for Holly Corporation 10K. February 25, 2011. 10K for 

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

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2011 reported by companies or estimated data for 2011.

Nicholson, Walter. 2005. Microeconomic Theory: Basic Principles and Extensions. Mason, OH: 

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Oil & Gas Journal, September 21, 1992. K.S. Eble and J. Feathers, “Process Water Reuse, Part 

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2-53

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ds_name=EC0731I1&-NAICS2007=324110&-_lang=en>

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

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2-54

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

2-55

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

2-56

U.S. Department of Energy, Energy Information Administration (EIA). 2006c. “Petroleum 

Supply Annual 2005, Volume 1.” Available at <http://www.eia.doe.gov/pub/oil_gas/

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1. Number and Capacity of Operable Petroleum Refineries by PAD District and State as 

of January 1, 2011” Release Date: June 24, 2011; (Data accessed on 10/12/11). [Source 

for 2011 numbers.] <http://www.eia.gov/petroleum/refinerycapacity/>

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publications/assistance/sectors/notebooks/petrefsn.pdf>. As obtained on October 23, 

2006. 
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2-57

U.S. Environmental Protection Agency. 2006. “Proposed MHA Nation Clean Fuels Refinery.” 

Available at <http://www.epa.gov/Region8/compliance/nepa/refinerydeis.html>. As 

obtained on February 6, 2007.

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Database. Available at <http://www.sec.gov/Archives/edgar/data/1339048/000095

013407005096/h44360e10vk.htm>. 

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

<http://phx.corporate-ir.net/phoenix.zhtml?c=194293&p=irol-sec>
*** Draft – Do Not Cite, Quote, or Release During Review ***

3-1

3 NSPS REGULATORY OPTIONS, COSTS AND EMISSION REDUCTIONS 

FROM COMPLYING WITH THE NSPS

The emissions reduction and cost impacts presented in this section for flares are revised 

estimates for the impacts of the final requirements of 40 CFR part 60, subpart Ja for flares, as 

amended by this action. The impacts are expressed as incremental differences between the 

impacts of petroleum refinery process units complying with these final amendments to subpart Ja 

and the final June 2008 NSPS requirements of 40 CFR part 60, subpart Ja (i.e., baseline). The 

impacts are presented for petroleum refinery flares that commence construction, reconstruction 

or modification over the next 5 years. We anticipate that there will be 400 affected flares over the 

next 5 years and most of the flares would become affected due to the modification provisions for 

flares in subpart Ja. For this analysis we assumed 90 percent of the flares would be modified or 

reconstructed and 10 percent of the flares would be newly constructed.

Further, we estimate that 30 percent of the 400 affected flares, or 120 flares, either would 

meet the definition of “emergency flare” in 40 CFR part 60, subpart Ja or would be equipped 

with a flare gas recovery system such that robust sulfur and flow monitoring would not be 

required. Therefore, the values presented in this section include the costs and emissions 

reductions for 400 flares to comply with the flare management plan and root cause and corrective 

action analyses requirements and for 280 flares to comply with the sulfur and flow monitoring 

requirements. The cost and emissions reductions for the affected flares to comply with the shortterm H2S concentration of 162 ppmv in the fuel gas are included in the baseline rather than the 

incremental impacts because this limit is unchanged from the requirements in subpart J. For 

further detail on the methodology of these calculations, see the January 25, 2012 memorandum 

entitled “Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for 

Amendments to the Petroleum Refinery NSPS”, in Docket ID No. EPA-HQ-OAR-2007-0011.

We estimate that the final requirements for flares will reduce emissions of SO2 by 3,200

tons per year (tons/yr), NOx by 1,100 tons/yr, VOC by 3,400 tons/yr, and CO2 by 1,900,000

metric tons/yr from the baseline. The estimated annual cost, including annualized capital costs

for flare gas recovery systems, is $96 million (2006 dollars). The estimated annual cost, 

including replacement of some natural gas purchases with recovered flare gas and the retention 
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3-2

of intermediate and product streams due to a reduction in the number of malfunctions associated 

with refinery process units and ancillary equipment connected to the flare, is a cost savings of 

$79 million (2006 dollars). Note that not all refiners will realize a cost savings as only flare 

systems with high waste gas flows (about 10% of all flares) are expected to install vapor 

recovery systems. The overall cost effectiveness is a cost savings of about $10,000 per ton of 

combined pollutants removed. The estimated nationwide 5-year incremental emissions 

reductions and cost impacts for the final standards are summarized in Tables 3-1 and 3-2 below.

Table 3-1. National Incremental Cost Impacts for Petroleum Refinery Flares Subject to 

Amended Standards Under 40 CFR part 60, subpart Ja (Fifth Year After the Effective 

Date of the Final Rule Amendments)

Subpart Ja Requirements

Total capital 

cost ($1,000)

Total annual 

cost without 

credit 

($1,000/yr)

Natural gas 

offset/ product 

recovery credit 

($1,000)

Total Annual 

Cost ($1,000/ 

yr)

Estimates from June 2008 Final 

Rule 40,000 (7,000)

Total for Revised Estimates for 

Amendments 460,000 96,000 (180,000) (79,000)

Flare Monitoring 84,000 14,000 0 14,000

Flare Gas Recovery7 380,000 78,000 (170,000) (90,000)

Flare Management Plans -- 880 -- 880

SO2 Root Cause 

Analysis/Corrective Action -- 2,200 -- 2,200

Flow Rate Root Cause Analysis/

Corrective Action -- 1,000 (7,400) (6,400)

 7 Forty flare systems are estimated to have sufficient waste gas to install recovery systems.

Comment [A3]: Suggested change to 

maintain consistency with preamble. Also, 

please include a note stating that all costs 

here are relative to the baseline for the 

2008 rule.
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3-3

Table 3-2. National Incremental Emission Reductions and Cost-Effectiveness for 

Petroleum Refinery Flares Subject to Amended Standards Under 40 CFR part 60, subpart 

Ja (Fifth Year After the Effective Date of the Final Rule Amendments)

Subpart Ja Requirements

Annual 

emission 

reductions 

(tons SO2/yr)

Annual 

emission 

reductions 

(tons NOx/yr)

Annual 

emission 

reductions

(tons 

VOC/yr)

Cost 

effectiveness 

($/ton 

emissions 

reduced)

Annual 

emission 

reductions

(metric tons 

CO2/yr)

Estimates from June 2008 

Final Rule 80 6 200 (23,000) --

Total for Revised Estimates 

for Amendments 3,200 1,100 3,400 (10,000) 1,900,000

Flare Monitoring 0 0 0 -- --

Flare Gas Recovery 380 1,100 2,700 (22,000) 1,800,000

Flare Management Plans 0 0 300 2,900 --

SO2 Root Cause 

Analysis/Corrective Action 2,900 0 0 760 --

Flow Rate Root Cause 

Analysis/

Corrective Action

3.4 56 430 (13,000) 98,000

Alternatively, if no refineries install flare gas recovery systems, the final requirements for 

flares would reduce emissions of SO2 by 2,820 tons/yr, NOx by 56 tons/yr, VOC by 730 tons/yr, 

and CO2 by 98,000 metric tons/yr from the baseline. The estimated annual cost would be about 

$10.7 million (2006 dollars).

The provisions for flares and other fuel gas combustion devices (i.e., process heaters and 

boilers) from the final June 2008 standards were stayed. The analysis for this final rule includes 

the same unit costs for the flare provisions as the final June 2008 rule but reflects recalculated 

total costs using data collected in the March 2011 ICR to update the number of flares.8 Table 3-1 

includes the recalculated cost estimates for flares, broken out by specific flare requirements, 

based on the updated number of flares. For the other fuel gas combustion devices, the total 

annualized costs for those provisions were estimated at $24 million (2006 dollars) in the June 

2008 rule and remain the same. As discussed below, because there are no additional incremental 

costs associated with the other fuel gas combustion device provisions, we consider those annual 

costs accounted for in the final June 2008 standards. We are presenting them here again, even 

 8 For the June 2008 standards we estimated 40 flares. As indicated, for this analysis we anticipate that there will be 

400 affected flares that will be subject to this final rule. Formatted: Underline
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3-4

though we estimate no changes to these costs, since these provisions will become effective upon 

this final action to lift the stay on certain provisions in the June 2008 rule.

The cost, environmental and economic impacts for the final amendments to 40 CFR part 

60, subpart Ja for process heaters are not expected to be different than those reported for the final 

June 2008 standards. We expect owners and operators to install the same technology to meet 

these final amendments that we anticipated they would install to meet the June 2008 final subpart 

Ja requirements (i.e., ultra-low NOx burners). We did revise our emissions estimates based on the 

type of process heater, creating separate impacts for forced draft process heaters and natural draft 

process heaters. Dividing process heaters into separate subcategories, based on the draft type, 

required us to develop new distributions of baseline emissions for each type of process heater. 

The baseline emissions estimates for natural draft process heaters are slightly lower than those 

developed for the existing subpart Ja requirements (per affected process heater), but the average 

emission reduction achieved by ultra-low NOx burners was adjusted to 80 percent (rather than 75 

percent used for generic process heaters). For forced draft process heaters, the baseline (i.e., 

uncontrolled) emissions rate for forced draft process heaters was revised slightly upward, based 

on the available emissions data. Because of these differences, the mix of controls needed to meet 

a 40 ppmv emissions limit was no longer cost effective for forced draft process heaters, but the 

emission reductions associated with process heaters complying with the 60 ppmv standard were 

higher than those previously estimated for generic process heaters. Thus, the creation of new 

subcategories of process heaters with different emissions limits for each subcategory did not 

impact the control or compliance methods used by the facilities (i.e., BSER in all cases was 

based on the performance of advanced combustion monitoring controls in conjunction with ultralow NOx burners) and did not change the estimated compliance costs. As we do not have 

adequate data regarding the prevalence of natural draft process heaters versus forced draft 

process heaters that will become subject to the rule, we used the emission reductions estimated 

for the two different types of process heaters as a means to bound the range of anticipated NOx

emission reductions to be from 7,100 to 8,600 tons/yr in the fifth year after promulgation (see 

Revised NOx Impact Estimates for Process Heaters, in Docket ID No. EPA-HQ-OAR-2007-

0011). We estimated the emission reductions to be 7,500 tons/yr for the June 2008 final 

standards, which falls well within the anticipated range of emissions reductions for the standards 
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3-5

we are finalizing here. Given the uncertainty in the emissions estimates, as well as the 

uncertainty in the relative number of natural draft process heaters versus forced draft process 

heaters, we concluded that the impacts previously developed for subpart Ja accurately represent 

the impacts for process heaters in these final amendments. 

We note that, in the preamble to the June 2008 final standards, we estimated costs and 

emissions reductions for 30 fuel gas combustion devices, but we subsequently determined that 

those estimates did not fully account for the number of affected flares (which, at the time, were 

considered a subset of fuel gas combustion devices). Therefore, in the preamble to the December 

2008 proposed amendments, we presented revised emission reduction and cost estimates for 

affected fuel gas combustion devices. Because these final amendments consider flares to be a 

separate affected source, the emission reductions and costs for fuel gas combustion devices are 

not affected by these final amendments and are not included in this action. Rather, the final 

emission reduction and cost estimates for fuel gas combustion devices are very close to the 

impacts presented in the June 2008 final rule; the details of the analysis and the final impacts are 

presented in the January 25, 2012 memorandum entitled “Impact Estimates for Fuel Gas 

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

NSPS”, in Docket ID No. EPA-HQ-OAR-2007-0011. 

The final amendments to 40 CFR part 60, subpart J are technical corrections or 

clarifications to the existing rule and should have no negative emissions impacts.
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4-1

4 ECONOMIC IMPACT ANALYSIS: METHODS AND RESULTS

4.1 Introduction

The economic impact analysis (EIA) is designed to inform decision makers about the 

potential economic consequences of a regulatory action. An economic welfare analysis 

estimates the social costs and consumer and producer surplus changes associated with a

regulatory program. The welfare analysis identifies how the regulatory costs are distributed 

across the two broad classes of stakeholders -- consumers and producers. As defined in EPA’s 

(2010) Guidelines for Preparing Economic Analyses,

9 social costs are the value of the goods and 

services lost by society resulting from using resources to comply with and implement a 

regulation. In addition, national engineering compliance cost estimates can be used to 

approximate the welfare impacts of a regulatory program.

Because the proposed amendments apply to new or modifying sources, we are not able to 

predict which specific sources will trigger applicability. Also, assuming no refineries install fuel 

gas recovery systems, the estimated, incremental annual costs would be about $10.7 million 

(2006 dollars), which represents substantially less than 0.001% of total refinery industry 

revenues in 2010. If we assume a full cost pass through, we do not anticipate any resulting price 

increases. As such, we did not employ a detailed economic model to estimate the social costs of 

the proposed amendments, nor to estimate the social cost distribution across stakeholders. For 

this rule, based on our analysis and an estimated annual cost savings of $79 million (2006

dollars) expected in the fifth year, no national-level negative economic impacts are expected. 

The remainder of this section includes a discussion of why firms may consider installing flare 

gas recovery systems, as well as the small business impact analysis.

4.2 Flare Gas Recovery Systems

As indicated in Section 3, we estimate there are approximately 500 flares industry-wide, 

and about 80 percent, or 400 flares, would be subject to the proposed amendments over the next 

five years. We further estimate that it would be cost-effective to install compressors and 

 9 These guidelines are currently under review by the Agency.

Comment [A4]: This justification seems 

inadequate. Given that the negative costs 

are ancillary to the rule (not required by 

the rule itself), and that they accrue to 

only 10 percent of affected firms, it would 

seem appropriate to estimate their 

incidence.
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4-2

recovery systems at 10 percent of the 400 flares, or at approximately 40 flares. We assume that a 

flare gas recovery system would be considered for flares with average releases greater than 

500,000 scf per 24-hour period. And while we do not have current data on where all of the 

potential 40 flares are located, data from the 2002 National Emissions Inventory indicate the 

flares are likely located at large refineries.

10 

The total annualized engineering compliance costs are estimated at $96 million, and the 

estimated annual savings from offset natural gas purchases and product recovery credits is 

estimated at $180 million, giving rise to the net savings discussed in Section 3. The annualized 

compliance costs for actions required by the rule are estimated at $18 million, and the estimated 

savings from product recovery credits is $7.4 million. Using these figures, we estimate the 

implied rate of return for actions required by the rule to be (10) percent. The annualized 

compliance costs for actions not required by the rule are estimated at $78 million, and the 

estimated savings from offset natural gas purchases is $168 million. Using these figures, we 

estimate the implied rate of return for actions not required by the rule to be 90 percent and the 

overall rate of return to be 80 percent. The actual rate of return varies greatly over time because 

of industry and economic factors. See Table 4-1 for refinery rates of return on investment from 

2000 through 2009. It is readily observed that the rate of return related to the pollution control 

equipment and activities by this rule exceeds that of the rate of return associated with 

investments in the refining sector.

Table 4-1 Rates of Return on Investment for Refineries

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

Rate of Return on 

Investment 9.6 14.5 (1.7) 9.3 18.4 23.2 25.3 21.2 2.4 (6.6)

(EIA 2009)

Assuming financially rational producers, standard economic theory suggests that 

refineries would incorporate all cost-effective improvements, which they are aware of, without 

 10 For details on where flares of this size were located as of the 2002 National Emissions Inventory, see Appendix A 

of the January 25, 2012 memorandum entitled “Impact Estimates for Fuel Gas Combustion Device and Flare 

Regulatory Options for Amendments to the Petroleum Refinery NSPS.”

Comment [A5]: Please break down this 

discussion into costs *required* by the 

rule and the costs that EPA expects firms 

to undertake voluntarily in response to the 

rule.
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4-3

government intervention. The cost analysis of this RIA nevertheless is based on the observation 

that process actions (i.e., installation of a flare gas recovery system) that appear to be profitable 

in our analysis have not been widely adopted. One explanation for why there appears to be 

negative cost control technologies that are not generally adopted is imperfect information. If 

process improvements in the refining sector are not well understood, firms may underestimate 

the potential financial returns to those improvements. Another explanation is the cost associated 

with the irreversibility of implementing these process improvements is not reflected in the 

engineering cost estimates. Because of the high volatility of natural gas prices, it is important to 

recognize the value of flexibility taken away from firms when requiring them to install and use a 

particular process technology. 

If a firm has not adopted the technology on its own, then a regulation encouraging its use 

means the firm may require reprioritizing other non-environmental investments. Although the 

rule does not specifically require installation of flare gas recovery systems, we anticipate that 

owners and operators of flares receiving high waste gas flows will conclude, upon installation of 

monitors, implementation of their flare management plans, and implementation of root causes 

analyses, that installing flare gas recovery would result in fuel savings by using the recovered 

flare gas where purchased natural gas is now being used to fire equipment such as boilers and 

process heaters. The flare management plan requires refiners to conduct a thorough review of 

the flare system so that flare gas recovery systems are installed and used where these systems are 

warranted. As part of the development of the flare management plan, refinery owners and 

operators must provide rationale and supporting evidence regarding the flare waste gas reduction 

options considered, the quantity of flare gas that would be recovered or prevented by the option, 

the BTU content of the flare gas and the ability or inability of the reduction option to offset 

natural gas purchases. In addition, regulatory requirements imply firms are unable to suspend 

use of the technology if it becomes unprofitable in the future. Therefore, the true cost of the 

regulation should include the lost option value, as well as the engineering costs. In the absence 

of quantitative estimates of this option value, the costs presented in this RIA may underestimate 

the full costs faced by the affected firms. 

4.3 Small Business Impact Analysis

Comment [A6]: This rule does not 

require the equipment. Please be specific 

about how this rule will ‘encourage’ the 

use of equipment that EPA believes is 

profitable even without the rule. 
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4-4

The Regulatory Flexibility Act (RFA) as amended by the Small Business Regulatory 

Enforcement Fairness Act (SBREFA) generally requires an agency to prepare a regulatory 

flexibility analysis of any rule subject to notice and comment rulemaking requirements under the 

Administrative Procedure Act or any other statute, unless the agency certifies that the rule will 

not have a significant economic impact on a substantial number of small entities. Small entities 

include small businesses, small governmental jurisdictions, and small not-for-profit enterprises. 

The petroleum refining industry (NAICS code 324110) does not include small governmental 

jurisdictions or small not-for-profit enterprises. For this analysis we applied the Small Business 

Administration’s small refiner definition of a refinery with no more than 1,500 employees (SBA, 

2011). For additional discussion of the Agency’s application of the definition for small refiner, 

see the June 24, 2008 Federal Register Notice for 40 CFR Part 60, Standards of Performance for 

Petroleum Refineries (Volume 73, Number 122, page 35858).11 

4.3.1 Small Entity Economic Impact Measures

The analysis provides EPA with an estimate of the magnitude of impacts that the 

provisions of the proposed standards may have on the ultimate domestic parent companies that 

own the small refineries. This section references the data sources used in the screening analysis 

and presents the methodology we applied to develop estimates of impacts, the results of the 

analysis, and conclusions drawn from the results. 

The small business impacts analysis for Subpart Ja New Source Performance Standards 

amendments relies upon data collected through the March 2011 Information Collection Request 

(ICR -- OMB Control No. 2060-0657). Information collected through component 1 of the ICR 

includes facility location, products produced, capacity, throughput, process and emissions, and 

employment and sales receipt data. EPA performed a screening analysis for impacts on all 

affected small refineries by comparing compliance costs to revenues at the parent company level. 

This is known as the cost-to-revenue or cost-to-sales ratio, or the “sales test.” The “sales test” is 

the impact methodology EPA employs in analyzing small entity impacts as opposed to a “profits 

test,” in which annualized compliance costs are calculated as a share of profits. The sales test is 

 11 Refer to http://www.sba.gov/sites/default/files/Size_Standards_Table.pdf for more information on SBA small 

business size standards. 
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4-5

frequently used because revenues or sales data are commonly available for entities impacted by 

EPA regulations, and profits data normally made available are often not the true profit earned by 

firms because of accounting and tax considerations. The use of a “sales test” for estimating 

small business impacts for a rulemaking is consistent with guidance offered by EPA on 

compliance with the RFA12 and is consistent with guidance published by the U.S. SBA’s Office 

of Advocacy that suggests that cost as a percentage of total revenues is a metric for evaluating 

cost increases on small entities in relation to increases on large entities (U.S. SBA, 2010).13

4.3.2 Small Entity Economic Impact Analysis

As discussed in Section 2 of this RIA, as of January 2011 there were 148 petroleum 

refineries operating in the continental United States and US territories with a cumulative capacity 

of processing over 17 million barrels of crude per calendar day (EIA, 2011b). Sixty-four (64) 

parent companies own these refineries, and EPA has employment and sales data for 61 (95%) of 

the parent companies. Thirty-six (36) companies (59% of the 61 total) employ fewer than 1,500 

workers and are considered small businesses. These firms earned an average of $1.36 billion of 

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

billion of revenue per year.14

Based on data collected through the March 2011 ICR, EPA performed the sales test 

analysis for impacts on affected small refineries. Four of the 36 small refiners were removed 

from the analysis because we determined they were not major sources and would not be subject 

 12 The RFA compliance guidance to EPA rule writers regarding the types of small business analysis that should be 

considered can be found at <http://www.epa.gov/sbrefa/documents/rfaguidance11-00-06.pdf> 13U.S. SBA, Office of Advocacy. A Guide for Government Agencies, How to Comply with the Regulatory 

Flexibility Act, Implementing the President’s Small Business Agenda and Executive Order 13272, June 2010. 14 The U.S. Census Bureau’s Statistics of U.S. Businesses include the following relevant definitions: (i) 

establishment – a single physical location where business is conducted or where services or industrial operations 

are performed; (ii) firm – a firm is a business organization consisting of one or more domestic establishments in the 

same state and industry that were specified under common ownership or control. The firm and the establishment are 

the same for single-establishment firms. For each multi-establishment firm, establishments in the same industry 

within a state will be counted as one firm; and (iii) enterprise -- an enterprise is a business organization consisting 

of one or more domestic establishments that were specified under common ownership or control. The enterprise and 

the establishment are the same for single-establishment firms. Each multi-establishment company forms one 

enterprise.
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4-6

to the rules, and one of the 36 small refiners (Gulf Atlantic Operations) was not analyzed 

because we had no ICR and/or other publically available employment and sales data. 

While we estimated the natural gas recovery offsets or credit at a national level and 

believe that larger firms are more likely to offset natural gas purchases, the revenues from natural

gas recovery offsets might mask disproportionate impacts on small refiners. At present to better 

identify disproportionate impacts, we examined the potential impacts on refiners based on a

scenario where no firms adopt flare gas recovery systems and comply with the NSPS through 

flare monitoring and flare management and root cause analysis actions. Refer to Tables 3-1 and 

3-2 in the prior Section for details on the costs and emissions reductions associated with each of 

the potential compliance actions. Table 4-2 presents the distribution of estimated cost-to-sales 

ratios for the small firms in our analysis. The incremental compliance costs imposed on small 

refineries are not estimated to create significant impacts on a cost-to-sales ratio basis at the firm 

level.

Table 4-2 Impact Levels of Proposed NSPS Amendments on Small Firms 

Impact Level

Number of Small Firms in 

Sample Estimated to be 

Affected

% of Small Firms in 

Sample Estimated to be 

Affected

Cost-to-Sales Ratio less than 1% 31 100%

Cost-to-Sales Ratio 1-3% 0 --

Cost-to-Sales Ratio greater than 3% 0 --

For comparison, we calculated the cost-to-sales ratios for all of the affected refineries to 

determine whether potential costs would have a more significant impact on small refineries. As 

presented in Table 4-3, for all large firms, the average cost-to-sales ratio is less than 0.01 

percent; the median cost-to-sales ratio is less than 0.01 percent; and the maximum cost-to-sales 

ratio is 0.02 percent. For small firms, the average cost-to-sales ratio is about 0.06 percent, the 

median cost-to-sales ratio is 0.02 percent, and the maximum cost-to-sales ratio is 0.63 percent. 

While the potential costs show a somewhat larger impact on small refiners, the impacts on small 

refiners are not significant. Because no small firms are expected to have cost-to-sales ratios 

greater than one percent, we determined that the cost impacts for Subpart Ja New Source 

Performance Standards amendments will not have a significant economic impact on a substantial 

number of small entities (SISNOSE).
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Table 4-3 Summary of Sales Test Ratios for Firms Affected by Proposed NSPS Amendments

Firm Size

No. of Known 

Affected Firms

% of Total Known 

Affected Firms

Mean Cost-to-Sales 

Ratio

Median Cost-toSales Ratio

Min. 

Cost-toSales 

Ratio

Max. Costto-Sales 

Ratio

Small 31 55% 0.06% 0.02% <0.01% 0.63%

Large 25 45% <0.01% <0.01% <0.01% 0.02%

All 56 100% 0.02% <0.01% <0.01% 0.63%
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4.4 References

U.S. Department of Energy, 2009 Energy Information Administration (EIA). “Performance 

Profiles of Major Energy Producers 2009.” (Data accessed on March 5, 2012.) 

<http://www.eia.gov/cfapps/frs/frstables.cfm?tableNumber=9>

U.S. Environmental Protection Agency, 2010. Guidelines for Preparing Economic Analyses, 

EPA 240-R-10-001. <http://yosemite.epa.gov/ee/epa/eed.nsf/pages/Guidelines.html> 

Accessed on: 11/14/11.
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5-1

5 EXECUTIVE ORDERS

5.1 Unfunded Mandates

This rule does not contain a Federal mandate that may result in expenditures of $100 

million or more for State, local, and tribal governments, in the aggregate, or the private sector in 

any one year. The costs of the final amendments would not increase costs associated with the 

final rule. Thus, this rule is not subject to the requirements of sections 202 or 205 of the 

Unfunded Mandates Reform Act of 1995 (UMRA).

This rule is also not subject to the requirements of section 203 of UMRA because it 

contains no regulatory requirements that might significantly or uniquely affect small 

governments. The proposed amendments contain no requirements that apply to such 

governments, and impose no obligations upon them. 

5.2 Environmental Justice

Executive Order 12898 (59 FR 7629, February 16, 1994) establishes Federal executive 

policy on environmental justice. Its main provision directs Federal agencies, to the greatest 

extent practicable and permitted by law, to make environmental justice part of their mission by 

identifying and addressing, as appropriate, disproportionately high and adverse human health or 

environmental effects of their programs, policies, and activities on minority populations and lowincome populations in the United States.

EPA has determined that this final rule will not have disproportionately high and adverse 

human health or environmental effects on minority or low-income populations because it 

increases the level of environmental protection for all affected populations without having any 

disproportionately high and adverse human health or environmental effects on any population, 

including any minority or low-income population. This rule is a nationwide standard that will 

yield reductions in various criteria pollutant emissions from new, modified, and reconstructed 

process heaters and flares at petroleum refineries, thus decreasing the amount of such emissions 

to which all affected populations are exposed. 

5.3 Significant Energy Actions

These proposed amendments do not represent a “significant energy action” as defined in 

Executive Order 13211, “Actions Concerning Regulations That Significantly Affect Energy 

Supply, Distribution, or Use” (66 FR 28355 [May 22, 2001]) because they are not likely to have 
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5-2

a significant adverse effect on the supply, distribution, or use of energy. Assuming no refineries 

install a flare gas recovery system, the estimated annualized compliance costs for the proposed 

requirements are substantially less than 0.001% of total refinery industry revenues in 2010. 

Assuming a full cost pass through, we do not anticipate any resulting price increases, and we 

estimate there will be no significant increase in our dependence on foreign energy supplies. 

Finally, today’s action will have no adverse effect on crude oil supply, coal production, 

electricity production, and energy distribution. Based on the findings from the analysis of 

impacts on energy markets, we conclude that today’s action is not a “significant energy action”

as defined in Executive Order 13211.

Comment [A7]: Please be more specific 

regarding the reasoning behind EPA’s 

assertion that these costs are not 

significant. What is the significance 

threshold?
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6-1

6 HUMAN HEALTH BENEFITS OF EMISSIONS REDUCTIONS

Synopsis

In this section, we provide an estimate of the monetized benefits for the final Petroleum 

Refineries NSPS Reconsideration associated with reducing exposure to ambient particulate 

matter (PM) by reducing emissions of PM2.5 precursors including SO2, NOx, and VOCs, as well 

as climate benefits associated with reducing emissions of CO2. SO2, NOx, and VOCs are 

precursors to PM2.5, and NOx and VOCs are precursors to ozone. These estimates reflect the 

monetized human health benefits of reducing cases of morbidity and premature mortality among 

populations exposed to PM2.5 reduced by this reconsideration. We estimate the total monetized 

benefits to be $260 million to $580 million at a 3% discount rate and $240 million to $520

million at a 7% discount rate. All estimates are in 2006$ in the year 2017.

These estimates reflect EPA’s most current interpretation of the scientific literature. 

Higher or lower estimates of benefits are possible using other assumptions; examples of this are 

provided in Figure 6-2 on page 6-14). Data, resource, and methodological limitations prevented 

EPA from monetizing the benefits from several important benefit categories, including benefits 

from reducing direct exposure to NO2 and SO2, ozone exposure, ecosystem effects, and visibility 

impairment.

6.1 Calculation of PM2.5-Related Human Health Benefits

This final NSPS Reconsideration would reduce emissions of SO2, NOX, and VOCs. 

Because these emissions are precursors to PM2.5, reducing these emissions would also reduce 

PM2.5 formation, human exposure and the incidence of PM2.5-related health effects. Due to 

analytical limitations, it was not possible to provide a comprehensive estimate of PM2.5-related 

benefits or provide estimates of the health benefits associated with direct exposure to SO2 and 

NOx or exposure to ozone. Instead, we used the “benefit-per-ton” approach to estimate these 

benefits. The methodology employed in this analysis is similar to the work described in Fann, 

Fulcher, and Hubbell (2009), but represents an improvement that EPA believes will provide 

more reliable estimates of PM2.5-related health benefits for emissions reductions in specific 

sectors. The key assumptions are described in detail below. These PM2.5 benefit-per-ton 

estimates provide the total monetized human health benefits (the sum of premature mortality and 

premature morbidity) of reducing one ton of PM2.5 from a specified source. EPA has used the 
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6-2

benefit per-ton technique in several previous RIAs, including the recent SO2 NAAQS RIA (U.S. 

EPA, 2010). 

The Integrated Science Assessment (ISA) for Particulate Matter (U.S. EPA, 2009b) 

identified the human health effects associated with ambient PM2.5, which include premature 

morality and a variety of morbidity effects associated with acute and chronic exposures. Table 6-

1 shows the quantified and unquantified benefits captured in those benefit-per-ton estimates, but 

this table does not include entries for the unquantified health effects associated with exposure to 

ozone, SO2, and NOx nor welfare effects such as ecosystem effects and visibility that are 

described in section 6.2. It is important to emphasize that the list of unquantified benefit 

categories is not exhaustive, nor is quantification of each effect complete.
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6-3

Table 6-1: Human Health Effects of PM2.5 

Category Specific Effect

Effect Has 

Been 

Quantified

Effect Has 

Been 

Monetized

More 

Information 

(refers to 

CSAPR RIA)

Improved Human Health

Reduced incidence of 

premature mortality 

from exposure to PM2.5

Adult premature mortality based on cohort 

study estimates and expert elicitation 

estimates (age >25 or age >30)

  Section 5.4

Infant mortality (age <1)   Section 5.4

Reduced incidence of 

morbidity from 

exposure to PM2.5

Non-fatal heart attacks (age > 18)   Section 5.4

Hospital admissions—respiratory (all 

ages)   Section 5.4

Hospital admissions—cardiovascular (age 

>20)   Section 5.4

Emergency room visits for asthma (all 

ages)   Section 5.4

Acute bronchitis (age 8-12)   Section 5.4

Lower respiratory symptoms (age 7-14)   Section 5.4

Upper respiratory symptoms (asthmatics 

age 9-11)   Section 5.4

Asthma exacerbation (asthmatics age 6-

18)   Section 5.4

Lost work days (age 18-65)   Section 5.4

Minor restricted-activity days (age 18-65)   Section 5.4

Chronic Bronchitis (age >26)   Section 5.4

Emergency room visits for cardiovascular 

effects (all ages) -- -- Section 5.4

Strokes and cerebrovascular disease (age 

50-79) -- -- Section 5.4

Other cardiovascular effects (e.g., other 

ages) -- -- PM ISA2

Other respiratory effects (e.g., pulmonary 

function, non-asthma ER visits, nonbronchitis chronic diseases, other ages and 

populations)

-- -- PM ISA2

Reproductive and developmental effects 

(e.g., low birth weight, pre-term births, 

etc)

-- -- PM ISA2,3

Cancer, mutagenicity, and genotoxicity 

effects -- -- PM ISA2,3

1 We assess these benefits qualitatively due to time and resource limitations for this analysis. 2 We assess these benefits qualitatively because we do not have sufficient confidence in available data or methods.

3 We assess these benefits qualitatively because current evidence is only suggestive of causality or there are other 

significant concerns over the strength of the association.

Consistent with the Portland Cement NESHAP (U.S. EPA, 2009a), the benefits estimates 

utilize the concentration-response functions as reported in the epidemiology literature, as well as 

the 12 functions obtained in EPA’s expert elicitation study as a sensitivity analysis. 
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6-4

 One estimate is based on the concentration-response (C-R) function developed from 

the extended analysis of American Cancer Society (ACS) cohort, as reported in Pope 

et al. (2002), a study that EPA has previously used to generate its primary benefits 

estimate. When calculating the estimate, EPA applied the effect coefficient as 

reported in the study without an adjustment for assumed concentration threshold of 10 

μg/m3 as was done in recent (2006-2009) Office of Air and Radiation RIAs.

 One estimate is based on the C-R function developed from the extended analysis of 

the Harvard Six Cities cohort, as reported by Laden et al (2006). This study, 

published after the completion of the Staff Paper for the 2006 PM2.5 NAAQS, has 

been used as an alternative estimate in the PM2.5 NAAQS RIA and PM2.5 benefits 

estimates in RIAs completed since the PM2.5 NAAQS. When calculating the 

estimate, EPA applied the effect coefficient as reported in the study without an 

adjustment for assumed concentration threshold of 10 μg/m3 as was done in recent 

(2006-2009) RIAs.

 Twelve estimates are based on the C-R functions from EPA’s expert elicitation study 

(Roman et al., 2008) on the PM2.5 -mortality relationship and interpreted for benefits 

analysis in EPA’s final RIA for the PM2.5 NAAQS. For that study, twelve experts 

(labeled A through L) provided independent estimates of the PM2.5 -mortality 

concentration-response function. EPA practice has been to develop independent 

estimates of PM2.5 -mortality estimates corresponding to the concentration-response 

function provided by each of the twelve experts, to better characterize the degree of 

variability in the expert responses.

The effect coefficients are drawn from epidemiology studies examining two large 

population cohorts: the American Cancer Society cohort (Pope et al., 2002) and the Harvard Six 

Cities cohort (Laden et al., 2006).15 These are logical choices for anchor points in our 

presentation because, while both studies are well designed and peer reviewed, there are strengths 

and weaknesses inherent in each, which we believe argues for using both studies to generate 

benefits estimates. Previously, EPA had calculated benefits based on these two empirical 

studies, but derived the range of benefits, including the minimum and maximum results, from an 

expert elicitation of the relationship between exposure to PM2.5 and premature mortality (Roman 

 15 These two studies specify multi-pollutant models that control for SO2, among other co-pollutants.
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6-5

et al., 2008).16 Within this assessment, we include the benefits estimates derived from the 

concentration-response function provided by each of the twelve experts to better characterize the 

uncertainty in the concentration-response function for mortality and the degree of variability in 

the expert responses. Because the experts used these cohort studies to inform their 

concentration-response functions, benefits estimates using these functions generally fall between 

results using these epidemiology studies (see Figure 6-2). In general, the expert elicitation 

results support the conclusion that the benefits of PM2.5 control are very likely to be substantial.

Readers interested in reviewing the general methodology for creating the benefit-per-ton 

estimates used in this analysis should consult the draft Technical Support Document (TSD) on

estimating the benefits per ton of reducing PM2.5 and its precursors from the petroleum refineries 

sector specifically (U.S. EPA, 2012). The primary difference between the estimates used in this 

analysis and the estimates reported in Fann, Fulcher, and Hubbell (2009) is the air quality 

modeling data utilized. While the air quality data used in Fann, Fulcher, and Hubbell (2009) 

reflects broad pollutant/source category combinations, such as all non-EGU stationary point 

sources, the air quality modeling data used in this analysis is sector-specific. In addition, the 

updated air quality modeling data reflects more recent emissions data (2005 rather than 2001) 

and has a higher spatial resolution (12km rather than 36 km grid cells). As a result, the benefitper-ton estimates presented herein better reflect the geographic areas and populations likely to be 

affected by this sector. The benefits methodology, such as health endpoints assessed, risk 

estimates applied, and valuation techniques, applied did not change. As noted below in the 

characterization of uncertainty, these updated estimates still have similar limitations as all 

national-average benefit-per-ton estimates in that they reflect the geographic distribution of the 

modeled emissions, which may not exactly match the emission reductions in this rulemaking, 

and they may not reflect local variability in population density, meteorology, exposure, baseline 

health incidence rates, or other local factors for any specific location. In this analysis, we apply 

these national benefit-per-ton estimates calculated for this sector separately for SO2 and NOx and 

multiply them by the corresponding emission reductions.

These models assume that all fine particles, regardless of their chemical composition, are 

equally potent in causing premature mortality because the scientific evidence is not yet sufficient 

to allow differentiation of effects estimates by particle type. SO2 and NOx are the primary PM2.5

precursors affected by this rule. Even though we assume that all fine particles have equivalent 

 16 Please see the Section 5.2 of the Portland Cement RIA in Appendix 5A for more information regarding the change 

in the presentation of benefits estimates. 
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health effects, the benefit-per-ton estimates vary between precursors depending on the location 

and magnitude of their impact on PM2.5 levels, which drive population exposure. The sectorspecific modeling does not provide estimates of the PM2.5-related benefits associated with 

reducing VOC emissions, but these unquantified benefits are generally small compared to other 

PM2.5 precursors (U.S. EPA, 2012).

The benefit-per-ton coefficients in this analysis were derived using modified versions of 

the health impact functions used in the PM NAAQS Regulatory Impact Analysis (U.S. EPA, 

2006). Specifically, this analysis uses the benefit-per-ton method first applied in the Portland 

Cement NESHAP RIA (U.S. EPA, 2009a), which incorporated three updates: a new population 

dataset, an expanded geographic scope of the benefit-per-ton calculation, and the functions 

directly from the epidemiology studies without an adjustment for an assumed threshold.17 

Removing the threshold assumption is a key difference between the method used in this analysis 

of PM benefits and the methods used in RIAs prior to Portland Cement proposal, and we now 

calculate incremental benefits down to the lowest modeled PM2.5 air quality levels. 

Based on our review of the current body of scientific literature, EPA now estimates PMrelated mortality without applying an assumed concentration threshold. EPA’s Integrated 

Science Assessment for Particulate Matter (U.S. EPA, 2009b), which was reviewed by EPA’s 

Clean Air Scientific Advisory Committee (U.S. EPA-SAB, 2009a; U.S. EPA-SAB, 2009b), 

concluded that the scientific literature consistently finds that a no-threshold log-linear model 

most adequately portrays the PM-mortality concentration-response relationship while 

recognizing potential uncertainty about the exact shape of the concentration-response function. 

Consistent with this finding, we have conformed the previous threshold sensitivity 

analysis to the current state of the PM science by incorporating a “Lowest Measured Level” 

(LML) assessment, which is a method EPA has employed in several recent RIAs including the 

Cross-State Air Pollution Rule (U.S. EPA, 2011b). This information allows readers to determine 

the portion of population exposed to annual mean PM2.5 levels at or above the LML of each 

study; in general, our confidence in the estimated PM mortality decreases as we consider air 

quality levels further below the LML in major cohort studies that estimate PM-related mortality. 

While an LML assessment provides some insight into the level of uncertainty in the estimated 

 17 The benefit-per-ton estimates have also been updated since the Portland Cement RIA to incorporate a revised 

VSL, as discussed below. 
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6-7

PM mortality benefits, EPA does not view the LML as a threshold and continues to quantify PMrelated mortality impacts using a full range of modeled air quality concentrations. It is important 

to emphasize that we have high confidence in PM2.5-related effects down to the lowest LML of 

the major cohort studies, which is 5.8 μg/m3

. Just because we have greater confidence in the 

benefits above the LML, this does not mean that we have no confidence that benefits occur 

below the LML. For a summary of the scientific review statements regarding the lack of a 

threshold in the PM2.5-mortality relationship, see the Technical Support Document (TSD) 

entitled Summary of Expert Opinions on the Existence of a Threshold in the ConcentrationResponse Function for PM2.5-related Mortality (U.S. EPA, 2010b).

For this analysis, policy-specific air quality data is not available due to time or resource 

limitations. For these rules, we are unable to estimate the percentage of premature mortality 

associated with this specific rule’s emission reductions at each PM2.5 level. However, we believe 

that it is still important to characterize the distribution of exposure to baseline air quality levels. 

As a surrogate measure of mortality impacts, we provide the percentage of the population 

exposed at each PM2.5 level using the source apportionment modeling used to calculate the 

benefit-per-ton estimates for this sector. It is important to note that baseline exposure is only one 

parameter in the health impact function, along with baseline incidence rates population, and 

change in air quality. In other words, the percentage of the population exposed to air pollution 

below the LML is not the same as the percentage of the population experiencing health impacts 

as a result of a specific emission reduction policy. The most important aspect, which we are 

unable to quantify for rules without rule-specific air quality modeling, is the shift in exposure 

associated with this specific rule. Therefore, caution is warranted when interpreting the LML 

assessment for this rule. The results of this analysis are provided in Section 6.3.

As is the nature of RIAs, the assumptions and methods used to estimate air quality 

benefits evolve over time to reflect the Agency’s most current interpretation of the scientific and 

economic literature. For a period of time (2004-2008), the Office of Air and Radiation (OAR) 

valued mortality risk reductions using a value of statistical life (VSL) estimate derived from a 

limited analysis of some of the available studies. OAR arrived at a VSL using a range of $1 

million to $10 million (2000$) consistent with two meta-analyses of the wage-risk literature. 

The $1 million value represented the lower end of the interquartile range from the Mrozek and 

Taylor (2002) meta-analysis of 33 studies. The $10 million value represented the upper end of 
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6-8

the interquartile range from the Viscusi and Aldy (2003) meta-analysis of 43 studies. The mean 

estimate of $5.5 million (2000$)18 was also consistent with the mean VSL of $5.4 million 

estimated in the Kochi et al. (2006) meta-analysis. However, the Agency neither changed its 

official guidance on the use of VSL in rulemakings nor subjected the interim estimate to a 

scientific peer-review process through the Science Advisory Board (SAB) or other peer-review 

group. 

During this time, the Agency continued work to update its guidance on valuing mortality 

risk reductions, including commissioning a report from meta-analytic experts to evaluate 

methodological questions raised by EPA and the SAB on combining estimates from the various 

data sources. In addition, the Agency consulted several times with the Science Advisory Board 

Environmental Economics Advisory Committee (SAB-EEAC) on the issue. With input from the 

meta-analytic experts, the SAB-EEAC advised the Agency to update its guidance using specific, 

appropriate meta-analytic techniques to combine estimates from unique data sources and 

different studies, including those using different methodologies (i.e., wage-risk and stated 

preference) (U.S. EPA-SAB, 2007). 

Until updated guidance is available, the Agency determined that a single, peer-reviewed 

estimate applied consistently best reflects the SAB-EEAC advice it has received. Therefore, the 

Agency has decided to apply the VSL that was vetted and endorsed by the SAB in the Guidelines 

for Preparing Economic Analyses (U.S. EPA, 2000)19 while the Agency continues its efforts to 

update its guidance on this issue. This approach calculates a mean value across VSL estimates 

derived from 26 labor market and contingent valuation studies published between 1974 and 

1991. The mean VSL across these studies is $6.3 million (2000$).20 The Agency is committed 

to using scientifically sound, appropriately reviewed evidence in valuing mortality risk 

reductions and has made significant progress in responding to the SAB-EEAC’s specific 

recommendations. 

In implementing these rules, emission controls may lead to reductions in ambient PM2.5 

below the National Ambient Air Quality Standards (NAAQS) for PM in some areas and assist 

 18 After adjusting the VSL for a different currency year (2006$) and to account for income growth to 2015 of the 

$5.5 million value, the VSL is $7.4 million. 19 In revised Economic Guidelines (U.S. EPA, 2010c), EPA retained the VSL endorsed by the SAB with the 

understanding that further updates to the mortality risk valuation guidance would be forthcoming in the near future. 

Therefore, this report does not represent final agency policy. 

20 In this analysis, we adjust the VSL to account for a different currency year ($2006) and to account for income 

growth to 2015. After applying these adjustments to the $6.3 million value, the VSL is $8.5 million. 
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6-9

other areas with attaining the PM NAAQS. Because the PM NAAQS RIAs also calculate PM 

benefits, there are important differences worth noting in the design and analytical objectives of 

each RIA. The NAAQS RIAs illustrate the potential costs and benefits of attaining a new air 

quality standard nationwide based on an array of emission control strategies for different sources. 

In short, NAAQS RIAs hypothesize, but do not predict, the control strategies that States may 

choose to enact when implementing a NAAQS. The setting of a NAAQS does not directly result 

in costs or benefits, and as such, the NAAQS RIAs are merely illustrative and are not intended to 

be added to the costs and benefits of other regulations that result in specific costs of control and 

emission reductions. However, some costs and benefits estimated in this RIA account for the 

same air quality improvements as estimated in the illustrative PM2.5 NAAQS RIA. 

By contrast, the emission reductions for implementation rules are from a specific class of 

well-characterized sources. In general, EPA is more confident in the magnitude and location of 

the emission reductions for implementation rules rather than illustrative NAAQS analyses. 

Emission reductions achieved under these and other promulgated rules will ultimately be 

reflected in the baseline of future NAAQS analyses, which would reduce the incremental costs 

and benefits associated with attaining the NAAQS. EPA remains forward looking towards the 

next iteration of the 5-year review cycle for the NAAQS, and as a result does not issue updated 

RIAs for existing NAAQS that retroactively update the baseline for NAAQS implementation. 

For more information on the relationship between the NAAQS and rules such as analyzed here, 

please see Section 1.2.4 of the SO2 NAAQS RIA (U.S. EPA, 2010a).
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Figure 6.1 illustrates the relative breakdown of the monetized PM2.5 health benefits. 

Figure 6-1: Breakdown of Monetized PM2.5 Health Benefits using Mortality Function 

from Pope et al. (2002)* *This pie chart breakdown is illustrative, using the results based on Pope et al. (2002) as an example. Using the 

Laden et al. (2006) function for premature mortality, the percentage of total monetized benefits due to adult 

mortality would be 97%. This chart shows the breakdown using a 3% discount rate, and the results would be similar 

if a 7% discount rate was used. 

Table 6-2 provides a general summary of the monetized PM-related health benefits by 

precursor, including the emission reductions and benefit-per-ton estimates at discount rates of 

3% and 7%.21 Table 6-3 provides a summary of the reductions in health incidences as a result of 

the pollution reductions. In Table 6-4, we provide the benefits using our anchor points of Pope 

et al. and Laden et al. as well as the results from the expert elicitation on PM mortality. Figure 

 21 To comply with Circular A-4, EPA provides monetized benefits using discount rates of 3% and 7% (OMB, 2003). 

These benefits are estimated for a specific analysis year (i.e., 2017), and most of the PM benefits occur within 

that year with two exceptions: acute myocardial infarctions (AMIs) and premature mortality. For AMIs, we 

assume 5 years of follow-up medical costs and lost wages. For premature mortality, we assume that there is a 

“cessation” lag between PM exposures and the total realization of changes in health effects. Although the 

structure of the lag is uncertain, EPA follows the advice of the SAB-HES to assume a segmented lag structure 

characterized by 30% of mortality reductions in the first year, 50% over years 2 to 5, and 20% over the years 6 to 

20 after the reduction in PM2.5 (U.S. EPA-SAB, 2004). Changes in the lag assumptions do not change the total 

number of estimated deaths but rather the timing of those deaths. Therefore, discounting only affects the AMI 

costs after the analysis year and the valuation of premature mortalities that occur after the analysis year. As such, 

the monetized benefits using a 7% discount rate are only approximately 10% less than the monetized benefits

using a 3% discount rate. 

Adult Mortality - Pope et 

al. 93%

Chronic Bronchitis 4%

AMI 2%

Acute Respiratory Symptoms 

0.5%

Infant Mortality 0.4%

Work Loss Days 0.2%

Hospital Admissions, Cardio 

0.2% Hospital Admissions, Resp 

0.04%

Asthma Exacerbation 0.01%

Acute Bronchitis 0.01%

Upper Resp Symp 0.00%

Lower Resp Symp 0.00%

ER Visits, Resp 0.00%

Other 1%

 
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6-2 provides a visual representation of the range of PM2.5-related benefits estimates using 

concentration-response functions supplied by experts. 

Table 6-2: General Summary of Monetized PM-Related Health Benefits Estimates for 

Petroleum Refineries NSPS Reconsideration (millions of 2006$)*

Pollutant

Emissions 

Reductions 

(tons)

Benefit 

per ton 

(Pope, 

3%)

Benefit 

per ton 

(Laden, 

3%)

Benefit 

per ton 

(Pope, 

7%)

Benefit 

per ton 

(Laden, 

7%)

Total Monetized 

Benefits (millions 

of 2006$ at 3%)

Total Monetized 

Benefits (millions 

of 2006$ at 7%)

Small 

Flares

PM2.5 Precursors

 SO2 2,600 $65,000 $160,000 $58,000 $140,000 $170 to $410 $150 to $370

 NOX 50 $6,400 $16,000 $5,700 $14,000 $.32 to $.79 $.29 to $.71

Total $170 to $410 $150 to $370

Large 

Flares

PM2.5 Precursors

 SO2 660 $65,000 $160,000 $58,000 $140,000 $43 to $100 $38 to $94

 NOX 1,100 $6,400 $16,000 $5,700 $14,000 $6.80 to $17.00 $6.10 to $15.00

Total $49 to $120 $44 to $110

All 

Flares

PM2.5 Precursors

 SO2 3,200 $65,000 $160,000 $58,000 $140,000 $210 to $510 $190 to $460

 NOX 1,100 $6,400 $16,000 $5,700 $14,000 $7.1 to $18.0 $6.4 to $16

Total $220 to $530 $190 to $480

* All estimates are for the analysis year (2017), and are rounded to two significant figures so numbers may not sum 

across columns. It is important to note that the monetized benefits do not include reduced health effects from direct 

exposure to SO2 and NOx, ozone exposure, ecosystem effects, or visibility impairment. These estimates do not 

include CO2 benefits estimated at $46 million (3% discount rate). All fine particles are assumed to have equivalent 

health effects, but the benefit per ton estimates vary because each ton of precursor reduced has a different propensity 

to form PM2.5. The monetized benefits incorporate the conversion from precursor emissions to ambient fine 

particles. Confidence intervals are unavailable for this analysis because of the benefit-per-ton methodology.
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Table 6-3: Summary of Reductions in Health Incidences from PM2.5 Benefits for the Final 

Petroleum Refineries NSPS Reconsideration*

Avoided Premature Mortality

Pope et al. 26

Laden et al. 66

Avoided Morbidity

Chronic Bronchitis 19

Emergency Department Visits, Respiratory 19

Hospital Admissions, Respiratory 5

Hospital Admissions, Cardiovascular 10

Acute Bronchitis 43

Lower Respiratory 550

Upper Respiratory 420

Minor Restricted Activity Days 23,000

Work Loss Days 3,800

Asthma Exacerbation 920

Acute Myocardial Infarction 27

* All estimates are for the analysis year (2017) and are rounded to whole numbers with two significant figures. All 

fine particles are assumed to have equivalent health effects because the scientific evidence is not yet sufficient to 

allow differentiation of effects estimates by particle type. Confidence intervals are unavailable for this analysis 

because of the benefit-per-ton methodology.
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Table 6-4: All PM2.5 Benefits Estimates for the Final Petroleum Refineries NSPS 

Reconsideration at discount rates of 3% and 7% in 2017 (in millions of 

2006$)*

3% 7%

Benefit-per-ton Coefficients Derived from Epidemiology Literature

Pope et al. $220 $190

Laden et al. $530 $480

Benefit-per-ton Coefficients Derived from Expert Elicitation

Expert A $560 $510

Expert B $430 $380

Expert C $430 $380

Expert D $300 $270

Expert E $700 $630

Expert F $390 $350

Expert G $260 $230

Expert H $320 $290

Expert I $420 $380

Expert J $350 $310

Expert K $83 $74

Expert L $290 $260

*

All estimates are rounded to two significant figures. These estimates do not include CO2 benefits estimated at $49

million (3% discount rate). The benefits estimates from the Expert Elicitation are provided as a reasonable 

characterization of the uncertainty in the mortality estimates associated with the concentration-response function. 

Confidence intervals are unavailable for this analysis because of the benefit-per-ton methodology
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Figure 6-2: Monetized PM2.5 Benefits of Final Petroleum Refineries Reconsideration in 

2017

*This graph shows the estimated benefits at discount rates of 3% and 7% using effect coefficients derived from the 

Pope et al. study and the Laden et al study, as well as 12 effect coefficients derived from EPA’s expert elicitation on 

PM mortality. The results shown are not the direct results from the studies or expert elicitation; rather, the estimates 

are based in part on the concentration-response function provided in those studies. These estimates do not include 

CO2 benefits estimated at $46 million (3% discount rate).

6.2 Social Cost of Carbon and Greenhouse Gas Benefits

EPA has assigned a dollar value to reductions in carbon dioxide (CO2) emissions using 

recent estimates of the “social cost of carbon” (SCC). The SCC is an estimate of the monetized 

damages associated with an incremental increase in carbon emissions in a given year. It is 

intended to include (but is not limited to) changes in net agricultural productivity, human health, 

property damages from increased flood risk, and the value of ecosystem services due to climate 

change. The SCC estimates used in this analysis were developed through an interagency process 

that included EPA and other executive branch entities, and concluded in February, 2010. EPA 

first used these SCC estimates in the benefits analysis for the final joint EPA/DOT Rulemaking 

to establish Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average 

Fuel Economy Standards; see the rule’s preamble for discussion about application of SCC (75 

$0

$100

$200

$300

$400

$500

$600

$700

Pope et al.

Laden et al.

Millions (2006$)

PM2.5 mortality benefits estimates derived from 2 epidemiology functions and 12 expert functions

 

 

3% DR

7% DR
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6-15

FR 25324; 5/7/10). The SCC Technical Support Document (SCC TSD) provides a complete 

discussion of the methods used to develop these SCC estimates.

22

The interagency group selected four SCC values for use in regulatory analyses, which we 

have applied in this analysis: $5, $21, $35, and $65 per metric ton of CO2 emissions23 in 2010, in 

2007 dollars. The first three values are based on the average SCC from three integrated 

assessment models, at discount rates of 2.5, 3, and 5 percent, respectively. SCCs at several 

discount rates are included because the literature shows that the SCC is quite sensitive to 

assumptions about the discount rate, and because no consensus exists on the appropriate rate to 

use in an intergenerational context. The fourth value is the 95th percentile of the SCC from all 

three models at a 3 percent discount rate. It is included to represent higher-than-expected impacts 

from temperature change further out in the tails of the SCC distribution. Low probability, high 

impact events are incorporated into all of the SCC values through explicit consideration of their 

effects in two of the three models as well as the use of a probability density function for 

equilibrium climate sensitivity. Treating climate sensitivity probabilistically results in more high 

temperature outcomes, which in turn lead to higher projections of damages.

The SCC increases over time because future emissions are expected to produce larger 

incremental damages as physical and economic systems become more stressed in response to 

greater climatic change. Note that the interagency group estimated the growth rate of the SCC 

directly using the three integrated assessment models rather than assuming a constant annual 

growth rate. This helps to ensure that the estimates are internally consistent with other modeling 

assumptions. The SCC estimates for the analysis years of 2014, in 2005 dollars are provided in 

Table 6-5.

 22Docket ID EPA-HQ-OAR-2009-0472-114577, Technical Support Document: Social Cost of Carbon for 

Regulatory Impact Analysis Under Executive Order 12866, Interagency Working Group on Social Cost of 

Carbon, with participation by Council of Economic Advisers, Council on Environmental Quality, Department of 

Agriculture, Department of Commerce, Department of Energy, Department of Transportation, Environmental 

Protection Agency, National Economic Council, Office of Energy and Climate Change, Office of Management 

and Budget, Office of Science and Technology Policy, and Department of Treasury (February 2010). Also 

available at http://www.epa.gov/otaq/climate/regulations.htm 23The interagency group decided that these estimates apply only to CO2 emissions. Given that warming profiles and 

impacts other than temperature change (e.g., ocean acidification) vary across GHGs, the group concluded 

“transforming gases into CO2-equivalents using GWP, and then multiplying the carbon-equivalents by the SCC, 

would not result in accurate estimates of the social costs of non-CO2 gases” (SCC TSD, pg 13).
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Table 6-5. Social Cost of Carbon (SCC) Estimates (per tonne of CO2) for 2017a

Discount Rate and Statistic SCC estimate (2006$)

5% (Average) $5.9 

3% (Average) $24.1 

2.5% (Average) $38.6 

3% (95th percentile) $73.9 

a The SCC values are dollar-year and emissions-year specific. SCC values represent only a partial accounting of 

climate impacts.

When attempting to assess the incremental economic impacts of carbon dioxide 

emissions, the analyst faces a number of serious challenges. A recent report from the National 

Academies of Science (NRC, 2009) points out that any assessment will suffer from uncertainty, 

speculation, and lack of information about (1) future emissions of greenhouse gases, (2) the 

effects of past and future emissions on the climate system, (3) the impact of changes in climate 

on the physical and biological environment, and (4) the translation of these environmental 

impacts into economic damages. As a result, any effort to quantify and monetize the harms 

associated with climate change will raise serious questions of science, economics, and ethics and 

should be viewed as provisional. 

The interagency group noted a number of limitations to the SCC analysis, including the 

incomplete way in which the integrated assessment models capture catastrophic and noncatastrophic impacts, their incomplete treatment of adaptation and technological change, 

uncertainty in the extrapolation of damages to high temperatures, and assumptions regarding risk 

aversion. The limited amount of research linking climate impacts to economic damages makes 

the interagency modeling exercise even more difficult. The interagency group hopes that over 

time researchers and modelers will work to fill these gaps and that the SCC estimates used for 

regulatory analysis by the Federal government will continue to evolve with improvements in 

modeling. Additional details on these limitations are discussed in the SCC TSD.

In light of these limitations, the interagency group has committed to updating the current 

estimates as the science and economic understanding of climate change and its impacts on 

society improves over time. Specifically, the interagency group has set a preliminary goal of 

revisiting the SCC values within two years or at such time as substantially updated models 

become available, and to continue to support research in this area. 
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Applying the global SCC estimates to the estimated reductions in CO2 emissions for the 

range of policy scenarios, we estimate the dollar value of the climate-related benefits captured by 

the models for each analysis year. For internal consistency, the annual benefits are discounted 

back to net present value (NPV) terms using the same discount rate as each SCC estimate (i.e., 

5%, 3%, and 2.5%) rather than 3% and 7%.24 These estimates are provided in Table 6-6.

Table 6-6. Monetized SCC-Derived Benefits of CO2 Emission Reductions in 2017 a,b

Discount Rate and Statistic

Monetized Climate Benefits with 

flare gas recovery

(millions of 2006$)

Monetized Climate Benefits 

without flare gas recovery

(millions of 2006$)

Tonnes of CO2 1,900,000 110,000

5% (Average) $11 $0.6 

3% (Average) $46 $2.6 

2.5% (Average) $73 $4.2 

3% (95th percentile) $140 $8.1 

a All estimates have been rounded to two significant digits. The SCC values are dollar-year and emissions-year 

specific. SCC values represent only a partial accounting of climate impacts.

b The tonnes of CO2 emission reductions in this table reflect the anticipated emission increases associated with the 

energy disbenefits described in section 6.3.

6.3 Energy Disbenefits

In this section, we provide an estimate of the energy disbenefits associated with the 

increased emissions from additional energy usage.25 We estimate that electricity usage associated 

with operation of the control devices would increase by 123 GWh/yr nationwide.26 This 

electricity usage is anticipated to increase emissions of pollutants from electric utility boilers 

(EGU boilers) that supply electricity to the non-EGU boiler facilities by 104,381 tonnes CO2. In 

the calculation of CO2 benefits, we have already subtracted these CO2 emission increases 

associated with increased electricity usage from the CO2 emission reductions associated with the 

regulatory requirements in the benefits shown in Table 6-6.

 24It is possible that other benefits or costs of proposed regulations unrelated to CO2 emissions will be discounted at 

rates that differ from those used to develop the SCC estimates. 25As we use the term “energy disbenefits” in this analysis, we are not referring to the cost of purchasing additional 

electricity or fuel, which are captured within the cost estimates. We use the term to refer to the increase in 

emissions associated with additional energy use. 26 See Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to the 

Petroleum Refinery NSPS, in Docket ID No. EPA-HQ-OAR-2007-0011.
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6.4 Total Monetized Benefits

The total monetized benefits of this rulemaking include both the PM-related health 

benefits as well as the CO2-related climate benefits. We estimate the total monetized benefits to 

be $260 million to $580 million at a 3% discount rate and $240 million to $520 million at a 7% 

discount rate. All estimates are in 2006$ for the year 2017. Figures 6-3 and 6-4 provide a visual 

representation of the breakdown of total monetized benefits by pollutant and requirement, 

respectively. 

Alternatively, if no refineries install flare gas recovery systems, EPA estimates the 

monetized benefits of $190 to $460 million and $170 to $410 million at discount rates of 3% and 

7% respectively. For small flares only, we estimate the monetized benefits are $170 million to 

$410 million (3% discount rate) and $150 million to $370 million (7% discount rate for health 

benefits and 3% discount rate for climate benefits). For large flares, we estimate the monetized 

benefits are $93 million to $160 million (3% discount rate) and $88 million to $150 million (7%

discount rate for health benefits and 3-percent discount rate for climate benefits). All estimates 

are in 2006 dollars for the year 2017.
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Figure 6-3: Breakdown of Monetized Benefits for Final Petroleum Refineries NSPS 

Reconsideration by Pollutant

* This chart uses the results based on Pope et al. (2002) and a 3% discount rate as an example.

SO2

80%

NOX

3%

CO2

17%

SO2

80%

NOX

3%

CO2

17%
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Figure 6-4: Breakdown of Monetized Benefits for Final Petroleum Refineries NSPS 

Reconsideration by Requirement and Flare Size

6.5 Unquantified Benefits

Flare 

Gas 

Recovery

28%

SO2

RCA/CA

71%

Flow 

Rate 

RCA/CA

1.2%

Flare Monitoring 0%

Flare Management Plans 0%

Small 

flares

65%

Large 

flares

35%

Flare 

Gas 

Recovery

28%

SO2

RCA/CA

71%

Flow 

Rate 

RCA/CA

1.2%

Flare Monitoring 0%

Flare Management Plans 0%

Small 

flares

65%

Large 

flares

35%

Formatted: Font: Not Bold
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The monetized benefits estimated in this RIA only reflect a subset of benefits attributable 

to the health effect reductions associated with ambient fine particles. Data, time, and resource

limitations prevented EPA from quantifying the impacts to, or monetizing the benefits from 

several important benefit categories, including benefits from reducing direct exposure to SO2 and 

NOx, ozone exposure, ecosystem effects, and visibility impairment. NOx and SO2 emissions 

also contribute to adverse welfare effects, including acidic deposition in aquatic and terrestrial 

ecosystems and visibility impairment. 

6.5.1 Additional SO2 and NO2 Benefits

In addition to being a precursor to PM2.5, SO2 and NOx emissions are also associated with 

a variety of respiratory health effects. Unfortunately, we were unable to estimate the health 

benefits associated with reduced SO2 and NO2 exposure in this analysis because we do not have 

air quality modeling data available. Therefore, this analysis only quantifies and monetizes the 

PM2.5 benefits associated with the reductions in SO2 and NO2 emissions. 

Following an extensive evaluation of health evidence from epidemiologic and laboratory 

studies, the U.S. EPA has concluded that there is a causal relationship between respiratory health 

effects and short-term exposure to SO2 (U.S. EPA, 2008b). According to summary of the ISA in 

EPA’s risk and exposure assessment (REA) for the SO2 NAAQS, “the immediate effect of SO2 

on the respiratory system in humans is bronchoconstriction” (U.S. EPA, 2009b). Asthmatics are 

more sensitive to the effects of SO2 likely resulting from preexisting inflammation associated 

with this disease. A clear concentration-response relationship has been demonstrated in 

laboratory studies following exposures to SO2 at concentrations between 20 and 100 ppb, both in 

terms of increasing severity of effect and percentage of asthmatics adversely affected. Based on 

our review of this information, we identified four short-term morbidity endpoints that the SO2

ISA identified as a “causal relationship”: asthma exacerbation, respiratory-related emergency 

department visits, and respiratory-related hospitalizations. The differing evidence and associated 

strength of the evidence for these different effects is described in detail in the SO2 ISA. The SO2 

ISA also concluded that the relationship between short-term SO2 exposure and premature 

mortality was “suggestive of a causal relationship” because it is difficult to attribute the mortality 

risk effects to SO2 alone. Although the SO2 ISA stated that studies are generally consistent in 

reporting a relationship between SO2 exposure and mortality, there was a lack of robustness of 

the observed associations to adjustment for pollutants. 

Following an extensive evaluation of health evidence from epidemiologic and laboratory 

studies, the Integrated Science Assessment (ISA) for Nitrogen Dioxide concluded that there is a 
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likely causal relationship between respiratory health effects and short-term exposure to NO2 

(U.S. EPA, 2008c). Persons with preexisting respiratory disease, children, and older adults may 

be more susceptible to the effects of NO2 exposure. Based on our review of this information, we 

identified four short-term morbidity endpoints that the NO2 ISA identified as a “likely causal 

relationship”: asthma exacerbation, respiratory-related emergency department visits, and 

respiratory-related hospitalizations. The differing evidence and associated strength of the 

evidence for these different effects is described in detail in the NO2 ISA. The NO2 ISA also 

concluded that the relationship between short-term NO2 exposure and premature mortality was 

“suggestive but not sufficient to infer a causal relationship” because it is difficult to attribute the 

mortality risk effects to NO2 alone. Although the NO2 ISA stated that studies consistently 

reported a relationship between NO2 exposure and mortality, the effect was generally smaller 

than that for other pollutants such as PM. 

SO2 and NOx emissions also contribute to a variety of adverse welfare effects, including 

acidic deposition, visibility impairment, nutrient enrichment (NOx only) and enhanced mercury 

methylation (SO2 only). Deposition of sulfur and nitrogen causes acidification, which can cause 

a loss of biodiversity of fishes, zooplankton, and macro invertebrates in aquatic ecosystems, as 

well as a decline in sensitive tree species, such as red spruce (Picea rubens) and sugar maple 

(Acer saccharum) in terrestrial ecosystems. In the northeastern United States, the surface waters 

affected by acidification are a source of food for some recreational and subsistence fishermen 

and for other consumers and support several cultural services, including aesthetic and 

educational services and recreational fishing. Biological effects of acidification in terrestrial 

ecosystems are generally linked to aluminum toxicity, which can cause reduced root growth, 

which restricts the ability of the plant to take up water and nutrients. These direct effects can, in 

turn, increase the sensitivity of these plants to stresses, such as droughts, cold temperatures, 

insect pests, and disease leading to increased mortality of canopy trees. Terrestrial acidification 

affects several important ecological services, including declines in habitat for threatened and 

endangered species (cultural), declines in forest aesthetics (cultural), declines in forest 

productivity (provisioning), and increases in forest soil erosion and reductions in water retention 

(cultural and regulating). (U.S. EPA, 2008d)

Deposition of nitrogen is also associated with aquatic and terrestrial nutrient enrichment. 

In estuarine waters, excess nutrient enrichment can lead to eutrophication. Eutrophication of 

estuaries can disrupt an important source of food production, particularly fish and shellfish 

production, and a variety of cultural ecosystem services, including water-based recreational and 

aesthetic services. Terrestrial nutrient enrichment is associated with changes in the types and 
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number of species and biodiversity in terrestrial systems. Excessive nitrogen deposition upsets 

the balance between native and nonnative plants, changing the ability of an area to support 

biodiversity. When the composition of species changes, then fire frequency and intensity can 

also change, as nonnative grasses fuel more frequent and more intense wildfires. (U.S. EPA, 

2008d)

Mercury is a highly neurotoxic contaminant that enters the food web as a methylated 

compound, methylmercury (U.S. EPA, 2008d). The contaminant is concentrated in higher 

trophic levels, including fish eaten by humans. Experimental evidence has established that only 

inconsequential amounts of methylmercury can be produced in the absence of sulfate (U.S. EPA, 

2008d). Current evidence indicates that in watersheds where mercury is present, increased 

sulfate deposition very likely results in methylmercury accumulation in fish (Drevnick et al., 

2007; Munthe et al, 2007). The NOx/SOx Ecological ISA concluded that evidence is sufficient 

to infer a casual relationship between sulfur deposition and increased mercury methylation in 

wetlands and aquatic environments (U.S. EPA, 2008d). 

Reducing SO2 and NOx emissions and the secondary formation of PM2.5 would improve 

the level of visibility throughout the United States. Fine particles with significant lightextinction efficiencies include sulfates, nitrates, organic carbon, elemental carbon, and soil 

(Sisler, 1996). These suspended particles and gases degrade visibility by scattering and 

absorbing light. Higher visibility impairment levels in the East are due to generally higher 

concentrations of fine particles, particularly sulfates, and higher average relative humidity levels. 

In fact, particulate sulfate is the largest contributor to regional haze in the eastern U.S. (i.e., 40% 

or more annually and 75% during summer). In the western U.S., particulate sulfate contributes 

to 20-50% of regional haze (U.S. EPA, 2009c). Visibility has direct significance to people’s 

enjoyment of daily activities and their overall sense of wellbeing. Good visibility increases the 

quality of life where individuals live and work, and where they engage in recreational activities. 

6.5.2 Ozone Benefits

In the presence of sunlight, NOx and VOCs can undergo a chemical reaction in the 

atmosphere to form ozone. Reducing ambient ozone concentrations is associated with 

significant human health benefits, including mortality and respiratory morbidity (U.S. EPA, 

2008a). Epidemiological researchers have associated ozone exposure with adverse health effects 

in numerous toxicological, clinical and epidemiological studies (U.S. EPA, 2006c). These health 

effects include respiratory morbidity such as fewer asthma attacks, hospital and ER visits, school 

loss days, as well as premature mortality.
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6.5.3 Visibility Impairment

Reducing secondary formation of PM2.5 would improve visibility throughout the U.S.

Fine particles with significant light-extinction efficiencies include sulfates, nitrates, organic

carbon, elemental carbon, and soil (Sisler, 1996). Suspended particles and gases degrade

visibility by scattering and absorbing light. Higher visibility impairment levels in the East are

due to generally higher concentrations of fine particles, particularly sulfates, and higher average

relative humidity levels. Visibility has direct significance to people’s enjoyment of daily

activities and their overall sense of wellbeing. Good visibility increases the quality of life where

individuals live and work, and where they engage in recreational activities. Previous analyses

(U.S. EPA, 2006; U.S. EPA, 2011a; U.S. EPA, 2011b) show that visibility benefits are a

significant welfare benefit category. Without air quality modeling, we are unable to estimate

visibility related benefits, nor are we able to determine whether VOC emission reductions would 

be likely to have a significant impact on visibility in urban areas or Class I areas.

6.6 Characterization of Uncertainty in the Monetized Benefits

In any complex analysis, there are likely to be many sources of uncertainty. Many inputs 

are used to derive the final estimate of economic benefits, including emission inventories, air 

quality models (with their associated parameters and inputs), epidemiological estimates of 

concentration-response (C-R) functions, estimates of values, population estimates, income 

estimates, and estimates of the future state of the world (i.e., regulations, technology, and human 

behavior). For some parameters or inputs it may be possible to provide a statistical 

representation of the underlying uncertainty distribution. For other parameters or inputs, the 

necessary information is not available. As discussed in the PM2.5 NAAQS RIA (Table 5.5) (U.S. 

EPA, 2006), there are a variety of uncertainties associated with these PM benefits. Therefore, 

the estimates of annual benefits should be viewed as representative of the magnitude of benefits 

expected, rather than the actual benefits that would occur every year. 

It is important to note that the monetized benefit-per-ton estimates used here reflect 

specific geographic patterns of emissions reductions and specific air quality and benefits 

modeling assumptions. For example, these estimates do not reflect local variability in population 

density, meteorology, exposure, baseline health incidence rates, or other local factors. Use of 

these $/ton values to estimate benefits associated with different emission control programs (e.g., 

for reducing emissions from large stationary sources like EGUs) may lead to higher or lower 

benefit estimates than if benefits were calculated based on direct air quality modeling. Great care 

should be taken in applying these estimates to emission reductions occurring in any specific 
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6-25

location, as these are all based on national or broad regional emission reduction programs and 

therefore represent average benefits-per-ton over the entire United States. The benefits-per-ton 

for emission reductions in specific locations may be very different than the estimates presented 

here. 

PM2.5 mortality benefits are the largest benefit category that we monetized in this 

analysis. To better characterize the uncertainty associated with mortality impacts that are 

estimated to occur in areas with low baseline levels of PM2.5, we included the LML assessment. 

For this analysis, policy-specific air quality data is not available due to time or resource 

limitations, thus we are unable to estimate the percentage of premature mortality associated with 

this specific rule’s emission reductions at each PM2.5 level. As a surrogate measure of mortality 

impacts, we provide the percentage of the population exposed at each PM2.5 level using the 

source apportionment modeling used to calculate the benefit-per-ton estimates for this sector. A 

very large proportion of the population is exposed at or above the lowest LML of the cohort 

studies (Figures 6-5 and 6-6), increasing our confidence in the PM mortality analysis. Figure 6-5

shows a bar chart of the percentage of the population exposed to various air quality levels in the 

pre- and post-policy policy. Figure 6-6 shows a cumulative distribution function of the same 

data. Both figures identify the LML for each of the major cohort studies. As the policy shifts 

the distribution of air quality levels, fewer people are exposed to PM2.5 levels at or above the 

LML. Using the Pope et al. (2002) study, the 77% of the population is exposed to annual mean 

PM2.5 levels at or above the LML of 7.5 μg/m3. Using the Laden et al. (2006) study, 25% of the 

population is exposed above the LML of 10 μg/m3.

 As we model avoided premature deaths 

among populations exposed to levels of PM2.5, we have lower confidence in levels below the 

LML for each study. It is important to emphasize that we have high confidence in PM2.5-related 

effects down to the lowest LML of the major cohort studies. Just because we have greater 

confidence in the benefits above the LML, this does not mean that we have no confidence that 

benefits occur below the LML. 

A large fraction of the baseline exposure occurs below the level of the National Ambient 

Air Quality Standard (NAAQS) for annual PM2.5 at 15 μg/m3, which wasset in 2006. It is 

important to emphasize that NAAQS are not set at a level of zero risk. Instead, the NAAQS 

reflect the level determined by the Administrator to be protective of public health within an 

adequate margin of safety, taking into consideration effects on susceptible populations. While 

benefits occurring below the standard may be less certain than those occurring above the 

standard, EPA considers them to be legitimate components of the total benefits estimate.
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6-26

Figure 6-5. Percentage of Adult Population by Annual Mean PM2.5 Exposure in the 

Baseline
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Figure 6-6. Cumulative Distribution of Adult Population by Annual Mean PM2.5 

Exposure in the Baseline

Above we present the estimates of the total benefits, based on our interpretation of the 

best available scientific literature and methods and supported by the SAB-HES and the NAS 

(NRC, 2002). The benefits estimates are subject to a number of assumptions and uncertainties. 

For example, for key assumptions underlying the estimates for premature mortality, which 

typically account for at least 90% of the total benefits, we were able to quantify include the 

following: 

1. PM2.5 benefits were derived through benefit per-ton estimates, which do not reflect 

local variability in population density, meteorology, exposure, baseline health 

incidence rates, or other local factors that might lead to an over-estimate or underestimate of the actual benefits of controlling directly emitted fine particulates. We do 

not have data on the specific location of the air quality changes associated with this 

rulemaking; as such, it is not feasible to estimate the proportion of benefits occurring 

in different locations, such as designated nonattainment areas. In addition, the 

benefit-per-ton estimates are based on emissions from existing sources. To the extent 
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6-28

that the geographic distribution of the emissions reductions for this rule are different 

than the modeled emissions, the benefits may be underestimated or overestimated. In 

general, there is inherently more uncertainty for new sources, which may not be 

included in the emissions inventory, than existing sources.

2. We assume that all fine particles, regardless of their chemical composition, are 

equally potent in causing premature mortality. This is an important assumption, 

because PM2.5 produced via transported precursors emitted from EGUs may differ 

significantly from direct PM2.5 released from diesel engines and other industrial 

sources, but no clear scientific grounds exist for supporting differential effects 

estimates by particle type. 

3. We assume that the health impact function for fine particles is linear down to the 

lowest air quality levels modeled in this analysis. Thus, the estimates include health 

benefits from reducing fine particles in areas with varied concentrations of PM2.5,

including both regions that are in attainment with fine particle standard and those that 

do not meet the standard down to the lowest modeled concentrations. 

4. To characterize the uncertainty in the relationship between PM2.5 and premature 

mortality (which typically accounts for 85% to 95% of total monetized benefits), we 

include a set of twelve estimates based on results of the expert elicitation study in 

addition to our core estimates. Even these multiple characterizations omit the 

uncertainty in air quality estimates, baseline incidence rates, populations exposed and 

transferability of the effect estimate to diverse locations. As a result, the reported 

confidence intervals and range of estimates give an incomplete picture about the 

overall uncertainty in the PM2.5 estimates. This information should be interpreted 

within the context of the larger uncertainty surrounding the entire analysis. For more 

information on the uncertainties associated with PM2.5 benefits, please consult the 

PM2.5 NAAQS RIA (Table 5.5).

This RIA does not include the type of detailed uncertainty assessment found in the PM 

NAAQS RIA because we lack the necessary air quality input and monitoring data to run the 

benefits model. In addition, we have not conducted any air quality modeling for this rule. 

Moreover, it was not possible to develop benefit-per-ton metrics and associated estimates of 

uncertainty using the benefits estimates from the PM RIA because of the significant differences 

between the sources affected in that rule and those regulated here. However, the results of the 

Monte Carlo analyses of the health and welfare benefits presented in Chapter 5 of the PM RIA 

can provide some evidence of the uncertainty surrounding the benefits results presented in this 

analysis. 
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6.7 References

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U.S. Environmental Protection Agency (U.S. EPA). 2000. Guidelines for Preparing Economic 

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(RIA) for the SO2 National Ambient Air Quality Standards (NAAQS). Office of Air Quality 

Planning and Standards, Research Triangle Park, NC. June. Available at 

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Summary of Expert Opinions on the Existence of a Threshold in the Concentration-Response 
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Function for PM2.5-related Mortality. Research Triangle Park, NC. June. Available on the 

Internet at <www.epa.gov/ttn/ecas/regdata/Benefits/thresholdstsd.pdf>.

U.S. Environmental Protection Agency (U.S. EPA). 2010c. Guidelines for Preparing Economic 

Analyses. EPA 240-R-10-001. National Center for Environmental Economics, Office of 

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U.S. Environmental Protection Agency (U.S. EPA). 2011a. The Benefits and Costs of the Clean 

Air Act from 1990 to 2020. Office of Air and Radiation, Washington, DC. March. 

<http://www.epa.gov/air/sect812/feb11/fullreport.pdf>. Accessed March 30, 2011.

U.S. Environmental Protection Agency (U.S. EPA). 2011b. Regulatory Impact Analysis for the 

Final Transport Rule. Office of Air Quality Planning and Standards, Research Triangle 

Park, NC. June. Available at <http://www.epa.gov/airtransport/pdfs/FinalRIA.pdf>. 

U.S. Environmental Protection Agency (U.S. EPA). 2012. Technical Support Document: 

Estimating the Benefit per ton of Reducing PM2.5 Precursors from the Petroleum Refineries 

Sector. Office of Air Quality Planning and Standards, Research Triangle Park, NC. January. 

U.S. Environmental Protection Agency - Science Advisory Board (U.S. EPA-SAB). 2007. SAB 

Advisory on EPA’s Issues in Valuing Mortality Risk Reduction. EPA-SAB-08-001. October. 

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<http://yosemite.epa.gov/sab/sabproduct.nsf/4128007E7876B8F0852573760058A978/$File/

sab-08-001.pdf >.

U.S. Environmental Protection Agency - Science Advisory Board (U.S. EPA-SAB). 2009a. 

Review of EPA’s Integrated Science Assessment for Particulate Matter (First External 

Review Draft, December 2008). EPA-COUNCIL-09-008. May. Available on the Internet at 

<http://yosemite.epa.gov/sab/SABPRODUCT.NSF/81e39f4c09954fcb85256ead006be86e/73

ACCA834AB44A10852575BD0064346B/$File/EPA-CASAC-09-008-unsigned.pdf>.

U.S. Environmental Protection Agency - Science Advisory Board (U.S. EPA-SAB). 2009b. 

Consultation on EPA’s Particulate Matter National Ambient Air Quality Standards: Scope 

and Methods Plan for Health Risk and Exposure Assessment. EPA-COUNCIL-09-009. 

May. Available on the Internet at 

<http://yosemite.epa.gov/sab/SABPRODUCT.NSF/81e39f4c09954fcb85256ead006be86e/72

3FE644C5D758DF852575BD00763A32/$File/EPA-CASAC-09-009-unsigned.pdf>.

U.S. Environmental Protection Agency - Science Advisory Board (U.S. EPA-SAB). 2010. 

Review of EPA’s DRAFT Health Benefits of the Second Section 812 Prospective Study of the 

Clean Air Act. EPA-COUNCIL-10-001. June. Available on the Internet at 

<http://yosemite.epa.gov/sab/sabproduct.nsf/0/72D4EFA39E48CDB28525774500738776/$F

ile/EPA-COUNCIL-10-001-unsigned.pdf>.

Viscusi, V.K., and J.E. Aldy. 2003. “The Value of a Statistical Life: A Critical Review of 

Market Estimates throughout the World.” Journal of Risk and Uncertainty 27(1):5-76.
*** Draft – Do Not Cite, Quote, or Release During Review ***

7-1

7 COMPARISON OF BENEFITS AND COSTS

EPA estimates the range of benefits of this reconsideration to be $260 million to $580

million at a 3% discount rate and $240 million to $520 million at a 7% discount rate in 2017. 

The annualized costs are a cost savings of $79 million at a 7% interest rate. Thus, net benefits 

are $340 million to $660 million at a 3% discount rate for the benefits and $320 million to $600

million at a 7% discount rate. All estimates are in 2006$.

Table 7-1 provides details, by flare size, of the monetized benefits and Table 7-2 shows a 

summary of the monetized benefits, social costs, and net benefits. Figure 7-1 shows the full 

range of net benefits estimates (i.e., benefits minus annualized costs) utilizing the 14 different 

PM2.5 mortality functions at the 3% discount rate, and Figure 7-2 shows this information at a 7% 

discount rate. EPA believes that the benefits of this rule are likely to exceed the costs by a 

substantial margin even when taking into account uncertainties in the cost and benefit estimates. 

Alternatively, if no refineries install flare gas recovery systems, EPA estimates the costs 

would be $10.7 million with monetized benefits of $190 to $460 million and $170 to $410 

million at a discount rates of 3% and 7% respectively. Thus, net benefits without flare gas 

recovery systems would be $180 million to $450 million and $160 million to $400 million, at 3% 

and 7% discount rates, respectively. All estimates are in 2006 dollars for the year 2017.

For small flares, we estimate the monetized benefits are $170 million to $410 million (3-

percent discount rate) and $150 million to $370 million (7% discount rate for health benefits and 

3% discount rate for climate benefits). For large flares, we estimate the monetized benefits are

$93 million to $160 million (3% discount rate) and $88 million to $150 million (7% discount rate 

for health benefits and 3-percent discount rate for climate benefits). All estimates are in 2006

dollars for the year 2017.
*** Draft – Do Not Cite, Quote, or Release During Review ***

7-2

Table 7-1. National Incremental Cost Impacts, Emission Reductions, and Cost Effectiveness for Petroleum Refinery Flares Subject to 

Amended Standards Under 40 CFR part 60, subpart Ja (Fifth Year After Effective Date of Final Rule Amendments)

1

Subpart Ja 

Requirements

Total 

capital 

cost 

(millions)

Total 

annual cost 

without 

credit 

(millions/yr)

Natural 

gas 

offset/ 

product 

recovery 

credit 

(millions)

Total 

annual cost 

(millions/yr)

Annual 

emission 

reductions 

(tons 

SO2/yr)

Annual 

emission 

reductions 

(tons 

NOX/yr)

Annual 

emission 

reductions 

(tons 

VOC/yr)

Cost 

effectiveness 

($/ton 

emissions 

reduced)

Annual 

emission 

reductions 

(metric 

tons 

CO2/yr)2

Monetized 

Benefits 

(millions, 3%

discount rate for 

health and 

climate benefits)

Monetized 

Benefits 

(millions, 3%

discount rate for 

health and 7% 

for climate 

benefits)

Small Flares

Flare 

Monitoring $72 $12 $0 $12 0 0 0 0 $0 to $0 $0 to $0

Flare gas 

recovery

$0 $0 $0 $0 0 0 0 0 $0 to $0 $0 to $0

Flare 

Management $0 $0.79 $0 $0.79 0 0 270 $2,900 0 $0 to $0 $0 to $0

SO2 RCA/CA $0 $1.9 $0 $1.9 2,600 0 0 $760 0 $170 to $410 $150 to $370

Flowrate 

RCA/CA $0 $0.90 -$6.7 -$5.8 3.4 50 390 -$13,000 98,000 $2.9 to $3.7 $2.9 to $3.6

Total $72 $16 -$6.7 $9.0 2,600 50 660 $2,700 98,000 $170 to $410 $150 to $370

Large Flares

Flare 

Monitoring $12 $2.0 $0 $2.0 0 0 0 0 $0 to $0 $0 to $0

Flare gas 

recovery

$380 $78 -$170 -$90 380 1,100 2,700 -$22,000 1,800,000 $74 to $120 $71 to $110

Flare 

Management $0 $0.088 $0 $0.088 0 0 30 $2,900 0 $0 to $0 $0 to $0

SO2 RCA/CA $0 $0.22 $0 $0.22 290 0 0 $760 0 $18 to $45 $17 to $41

Flowrate 

RCA/CA $0 $0.10 -$0.74 -$0.64 0 6 43 -$13,000 11,000 $0 to $0 $0 to $0

Total $390 $81 -$170 -$88 660 1,100 2,800 -$20,000 1,800,000 $93 to $160 $88 to $150

All Flares

Flare 

Monitoring $84 $14 $0 $14 0 0 0 0 $0 to $0 $0 to $0

Flare gas 

recovery

$380 $78 -$170 -$90 380 1,100 2,700 -$22,000 1,800,000 $74 to $120 $71 to $110

Flare 

Management $0 $0.88 $0 $0.88 0 0 300 $2,900 0 $0 to $0 $0 to $0

SO2 RCA/CA $0 $2.2 $0 $2.2 2,900 0 0 $760 0 $180 to $450 $170 to $410

Flowrate 

RCA/CA $0 $1.00 -$7.4 -$6.4 3.4 56 430 -$13,000 110,000 $3.2 to $4.0 $3.1 to $3.9

Total $460 $96 -$180 -$79 3,200 1,100 3,400 -$10,000 1,900,000 $260 to $580 $240 to $520

1

All estimates are for the implementation year (2017), and are rounded to two significant figures. 2 The emission reductions of CO2 reflect the anticipated emission increases associated with the energy disbenefits from additional electricity consumption.

Formatted: Font: Arial
*** Draft – Do Not Cite, Quote, or Release During Review ***

7-3

Table 7-2. Summary of the Monetized Benefits, Social Costs, and Net Benefits for the 

Final Petroleum Refineries NSPS in 2017 (millions of 2006$)1

3% Discount Rate 7% Discount Rate

Total Monetized Benefits2 $260 to $580 $240 to $520

Total Compliance Costs3 -$79 -$79

Net Benefits $340 to $660 $320 to $600

Non-monetized Benefits

Health effects from ozone, SO2, NO2 exposure

Health effects from PM2.5 exposure from VOCs

Ecosystem effects 

Visibility impairment 

1

All estimates are for the implementation year (2017), and are rounded to two significant figures. 2 The total monetized benefits reflect the human health benefits associated with reducing exposure to PM2.5 through 

reductions of PM2.5 precursors such as NOx and SO2 as well as CO2 benefits. It is important to note that the 

monetized benefits do not include the reduced health effects from direct exposure to SO2 and NOx, ozone 

exposure, ecosystem effects, or visibility impairment. Human health benefits are shown as a range from Pope et 

al. (2002) to Laden et al. (2006). These models assume that all fine particles, regardless of their chemical 

composition, are equally potent in causing premature mortality because the scientific evidence is not yet 

sufficient to allow differentiation of effects estimates by particle type. The net present value of reduced CO2

emissions is calculated differently than other benefits. This table includes monetized climate benefits using the 

global average social cost of carbon (SCC) estimated at a 3 percent discount rate because the interagency 

workgroup deemed the SCC estimate at a 3 percent discount rate to be the central value. 3 The engineering compliance costs are annualized using a 7 percent discount rate. 
*** Draft – Do Not Cite, Quote, or Release During Review ***

7-4

Figure 7-1. Net Benefits for Final Petroleum Refineries NSPS Reconsideration at 3% 

discount rate* *Net Benefits are quantified in terms of PM2.5 and CO2 benefits at a 3% discount rate for 2017. This graph shows 14 

benefits estimates combined with the cost estimate. All fine particles are assumed to have equivalent health effects. 

The monetized benefits incorporate the conversion from precursor emissions to ambient fine particles. 

$0

$100

$200

$300

$400

$500

$600

$700

$800

$900

Pope et al.

Laden et al.

Millions (2006$)

Cost estimate combined with total monetized benefits estimates derived from 2 epidemiology functions and 12 expert 

functions
*** Draft – Do Not Cite, Quote, or Release During Review ***

7-5

Figure 7-2. Net Benefits for Final Petroleum Refineries NSPS Reconsideration at 7% 

discount rate* *Net Benefits are quantified in terms of PM2.5 benefits at a 7% discount rate and CO2 benefits at a 3% discount rate 

for 2017. This graph shows 14 benefits estimates combined with the cost estimate. All fine particles are assumed to 

have equivalent health effects. The monetized benefits incorporate the conversion from precursor emissions to 

ambient fine particles. 

$0

$100

$200

$300

$400

$500

$600

$700

$800

Pope et al.

Laden et al.

Millions (2006$)

Cost estimate combined with total monetized benefits estimates derived from 2 epidemiology functions and 12 expert 

functions
*** Draft – Do Not Cite, Quote, or Release During Review ***

A-1

APPENDIX A

PARENT COMPANY INFORMATION FOR PETROLEUM REFINERIES
*** Draft – Do Not Cite, Quote, or Release During Review ***

A-2

Table A-1. Parent Company Information for Petroleum Refineries

Facility Name City State

Capacity 

(bbl/cd) Parent Company Name

Parent Company 

Sales

Parent Company 

Employment

AGE Refining Inc San Antonio TX 14,021 AGE Refining, Inc. 65.00 124

Alon Bakersfield 

Operating Inc

Bakersfield CA Alon Israel Oil Company 

LTD

7,283.06 12,000

Alon Refining Krotz 

Springs Inc

Krotz Springs LA 80,000 Alon Israel Oil Company 

LTD

7,283.06 12,000

Alon USA Energy Inc. Big Spring TX 67,000 Alon Israel Oil Company 

LTD

7,283.06 12,000

American Refining Group 

Inc

Bradford PA 10,000 American Refining 

Group, Inc.

737.19 323

Big West Oil Co. North Salt Lake UT 29,400 Flying J Oil & Gas Inc. 1,719.00 15,000

BP Exploration Alaska Inc Prudhoe Bay AK 12,780 BP PLC 297,107.00 12,633

BP Products North 

America Inc

Whiting IN 405,000 BP PLC 297,107.00 12,633

BP Products North 

America Inc

Texas City TX 406,570 BP PLC 297,107.00 12,633

BP West Coast Products 

LLC

Los Angeles CA 253,000 BP PLC 297,107.00 12,633

BP West Coast Products 

LLC

Ferndale WA 225,000 BP PLC 297,107.00 12,633

BP-Husky Refining LLC Toledo OH 131,400 BP PLC 297,107.00 12,633

Calcasieu Refining Co. Lake Charles LA 78,000 Calcasieu Refining 

Company

291.74 92

Calumet Lubricants Co LP Cotton Valley LA 13,020 Calumet Specialty 

Products Partners, L.P.

2,190.75 654

Calumet Lubricants Co LP Princeton LA 8,300 Calumet Specialty 

Products Partners, L.P.

2,190.75 654

Calumet Shreveport LLC Shreveport LA 57,000 Calumet Specialty 

Products Partners, L.P.

2,190.75 654

Cenex Harvest States Laurel MT 59,600 CHS, Inc. 23.30 287

Chalmette Refining LLC Chalmette LA 192,500 ExxonMobil Corp. 383,221.00 83,600

Chevron USA Inc. Perth Amboy NJ 80,000 Chevron Corporation 204,928.00 58,267

Chevron USA Inc. Salt Lake City UT 45,000 Chevron Corporation 204,928.00 58,267

Chevron USA Inc. Pascagoula MS 330,000 Chevron Corporation 204,928.00 58,267

Chevron USA Inc. El Segundo CA 273,000 Chevron Corporation 204,928.00 58,267

Chevron USA Inc. Richmond CA 245,271 Chevron Corporation 204,928.00 58,267

Chevron USA Inc. Honolulu HI 54,000 Chevron Corporation 204,928.00 58,267

Citgo Corpus Christi TX 163,000 CITGO Petroleum 

Corporation

475.80 3,506

Citgo Petroleum Corp. Lake Charles LA 427,800 CITGO Petroleum 

Corporation

475.80 3,506

Coffeyville Resources Rfg 

& Mktg LLC

Coffeyville KS 115,700 CVR Energy, Inc. 4,079.77 371

ConocoPhillips Sweeny TX 247,000 ConocoPhillips 198,655.00 29,700

ConocoPhillips Linden NJ 238,000 ConocoPhillips 198,655.00 29,700

ConocoPhillips Wilmington CA 139,000 ConocoPhillips 198,655.00 29,700

ConocoPhillips SF—Rodeo CA 120,200 ConocoPhillips 198,655.00 29,700

ConocoPhillips Belle Chasse LA 247,000 ConocoPhillips 198,655.00 29,700

ConocoPhillips Alaska Inc Prudhoe Bay AK 15,000 ConocoPhillips 198,655.00 29,700

ConocoPhillips Co Trainer PA 185,000 ConocoPhillips 198,655.00 29,700

(continued)
*** Draft – Do Not Cite, Quote, or Release During Review ***

A-3

Table A-1. Parent Company Information for Petroleum Refineries (continued)

Facility Name City State

Capacity 

(bbl/cd) Parent Company Name

Parent Company 

Sales

Parent Company 

Employment

ConocoPhillips Company Westlake LA 239,400 ConocoPhillips 198,655.00 29,700

ConocoPhillips Company Ponca City OK 198,400 ConocoPhillips 198,655.00 29,700

ConocoPhillips Company Billings MT 58,000 ConocoPhillips 198,655.00 29,700

ConocoPhillips Company Ferndale WA 100,000 ConocoPhillips 198,655.00 29,700

Countrymark Cooperative, 

Inc.

Mt. Vernon IN 26,500 Countrymark 

Cooperative

862.97 425

Deer Park Refining LTD 

Partnership

Deer Park TX 327,000 Royal Dutch Shell, PLC 378,152.00 93,000

Delaware City Refining Co 

LLC

Delaware City DE 182,200 PBF Holdings LLC Not Listed Not Listed

Delek Refining Ltd Tyler TX 60,000 Delek US Holdings, Inc. 3,755.60 3,296

Equistar Chemicals LP Channelview TX Lyondell Basell

Industries N.V.

27,684.00 14,000

Ergon Refining Inc. Vicksburg MS 23,000 Ergon, Inc. 3,830.00 1,625

Ergon West Virginia Inc. Newell WV 20,000 Ergon, Inc. 3,830.00 1,625

Excel Paralubes Westlake LA Koch Industries Inc 9,182.50 62,544

ExxonMobil Corp. Beaumont TX 344,500 ExxonMobil Corp. 383,221.00 83,600

ExxonMobil Corp. Torrance CA 149,500 ExxonMobil Corp. 383,221.00 83,600

ExxonMobil Oil Corp Baytown TX 560,640 ExxonMobil Corp. 383,221.00 83,600

ExxonMobil Refining & 

Supply Co

Baton Rouge LA 502,000 ExxonMobil Corp. 383,221.00 83,600

ExxonMobil Refining & 

Supply Co

Billings MT 60,000 ExxonMobil Corp. 383,221.00 83,600

ExxonMobil Refining & 

Supply Co

Joliet IL 238,600 ExxonMobil Corp. 383,221.00 83,600

Flint Hills Resources Corpus Christi TX 290,078 Koch Industries Inc 9,182.50 62,544

Flint Hills Resources North Pole AK 219,500 Koch Industries Inc 9,182.50 62,544

Flint Hills Resources Saint Paul MN 262,000 Koch Industries Inc 9,182.50 62,544

Foreland Refining Co. Ely NV 2,000 Foreland Refining Corp. 12.55 27

Frontier El Dorado 

Refining Co

El Dorado KS 138,000 Frontier Oil Corp. 5,884.91 723

Frontier Refining Inc Cheyenne WY 47,000 Frontier Oil Corp. 5,884.91 723

Garco Energy LLC Douglas WY 3,600 Garco Energy 11.44 16

Goodway Refining LLC Atmore AL 4,100 Goodway Refining, LLC 2.00 17

Greka Energy Santa Maria CA 9,500 Santa Maria Refining 

Company

2.80 47

Gulf Atlantic Operations Mobile Bay AL 20,000 Gulf Atlantic Operations 

LLC

76.99 32

Hess Corporation Port Reading NJ Hess Corporation 34,613.00 13,800

Holly Refining & 

Marketing Co

Woods Cross UT 25,050 Holly Corporation 8,323.00 1,321

Holly Refining & 

Marketing Co

Tulsa East OK 70,300 Holly Corporation 8,323.00 1,321

Holly Refining & 

Marketing Co

Tulsa West OK 85,000 Holly Corporation 8,323.00 1,321

Houston Refining LP Houston TX 280,390 Lyondell Basell 

Industries N.V.

27,684.00 14,000

Hunt Refining Co. Tuscaloosa AL 36,000 Hunt Refining Co. 4,871.00 346

Hunt Southland Refining 

Co

Sandersville MS 11,000 Hunt Refining Co. 4,871.00 1,100

(continued)
*** Draft – Do Not Cite, Quote, or Release During Review ***

A-4

Table A-1. Parent Company Information for Petroleum Refineries (continued)

Facility Name City State

Capacity 

(bbl/cd) Parent Company Name

Parent Company 

Sales

Parent Company 

Employment

Kern Oil & Refining Co. Bakersfield CA 26,000 Kern Oil & Refining Co. 282.00 105

Lima Refining Company Lima OH 155,000 Husky Energy, Inc. 18,174.36 4,491

Lion Oil Co. El Dorado AR 75,000 Lion Oil Co. 169.60 350

Little America Refining 

Co.

Evansville WY 24,500 Sinclair Co.’s 7,753.46 7,000

Lunday-Thagard Co. South Gate CA 8,500 World Oil Marketing Co. 35.40 65

Marathon Petroleum Co. 

LLC

Robinson IL 206,000 Marathon Oil Corp 73,621.00 29,677

Marathon Petroleum Co. 

LLC

Catlettsburg KY 212,000 Marathon Oil Corp 73,621.00 29,677

Marathon Petroleum Co. 

LLC

Detroit MI 106,000 Marathon Oil Corp 73,621.00 29,677

Marathon Petroleum Co. 

LLC

Canton OH 78,000 Marathon Oil Corp 73,621.00 29,677

Marathon Petroleum Co. 

LLC

Texas City TX 76,000 Marathon Oil Corp 73,621.00 29,677

Marathon Petroleum Co. 

LLC

Garyville LA 464,000 Marathon Oil Corp 73,621.00 29,677

Martin Midstream Partners 

LP

Smackover AR 7,500 Cross Oil Refining & 

Marketing, Inc.

265.00 110

Montana Refining Co. Great Falls MT 10,000 Connacher Oil and Gas, 

Limited

574.19 265

Motiva Enterprises Port Arthur TX 285,000 Motiva Enterprises LLC 26,400.00 2,900

Motiva Enterprises LLC Norco LA 233,500 Motiva Enterprises LLC 26,400.00 2,900

Motiva Enterprises LLC Convent LA 235,000 Motiva Enterprises LLC 26,400.00 2,900

Murphy Oil USA Inc. Superior WI 34,300 Murphy Oil Corp 23,345.07 8,994

Murphy Oil USA Inc. Meraux LA 125,000 Murphy Oil Corp 23,345.07 8,994

National Cooperative 

Refinery Association

McPherson KS 85,500 National Cooperative 

Refinery Association

2,810.30 612

Navajo Refining Co. Artesia NM 105,000 Holly Corporation 8,323.00 1,321

Nustar Asphalt Refining 

LLC

Paulsboro NJ 70,000 NuStar Energy LP 4,403.06 1,492

Nustar Asphalt Refining 

LLC

Savannah GA 28,000 NuStar Energy LP 4,403.06 1,492

Paramount Petroleum Co Long Beach CA 31,500 Alon Israel Oil Company 

LTD

7,283.06 12,000

Paramount Petroleum 

Corp.

Paramount CA 53,000 Alon Israel Oil Company 

LTD

7,283.06 12,000

Pasadena Refining Systems 

Inc.

Pasadena TX 100,000 Pasadena Refining 31.00 348

Paulsboro Refining Co 

LLC

Paulsboro NJ 160,000 PBF Holding Company 

LLC 

Not Listed Not Listed

PDV Midwest Refining Lemont IL 167,000 Petróleos de Venezuela 

S.A. (PDVSA)

75.00 102,750

Pelican Refining Co. LLC Lake Charles LA Pelican Refining Co LLC 4.00 33

Petro Star Inc. North Pole AK 19,700 Petro Star Inc. 887.00 400

Petro Star Inc. Valdez AK 55,000 Petro Star Inc. 887.00 400

Placid Refining Inc. Port Allen LA 57,000 Placid Refining 3,351.84 207

Premcor Refining Group 

Inc

Memphis TN 180,000 Valero Energy 82,233.00 20,313

(continued)
*** Draft – Do Not Cite, Quote, or Release During Review ***

A-5

Table A-1. Parent Company Information for Petroleum Refineries (continued)

Facility Name City State

Capacity 

(bbl/cd) Parent Company Name

Parent Company 

Sales

Parent Company 

Employment

Premcor Refining Group 

Inc

Port Arthur TX 292,000 Valero Energy 82,233.00 20,313

San Joaquin Refining Co., 

Inc.

Bakersfield CA 15,000 San Joaquin Refining Co. 3.50 108

Shell Chemical LP St. Rose LA 55,000 Royal Dutch Shell, PLC 378,152.00 93,000

Shell Chemical LP Saraland AL 80,000 Royal Dutch Shell, PLC 378,152.00 93,000

Shell Oil Products US Anacortes WA 145,000 Royal Dutch Shell, PLC 378,152.00 93,000

Shell Oil Products US Martinez CA 156,400 Royal Dutch Shell, PLC 378,152.00 93,000

Silver Eagle Refining Evanston WY 3,000 Silver Eagle Refining Inc. 225.87 60

Silver Eagle Refining Woods Cross UT 10,250 Silver Eagle Refining Inc. 225.87 60

Sinclair Wyoming 

Refining Co

Sinclair WY 74,000 Sinclair Co.’s 7,753.46 7,000

Somerset Energy Refinery 

LLC

Somerset KY 5,500 Somerset Oil Inc. 16.90 11

South Hampton Resources 

Inc.

Silsbee TX Arabian American 

Development Co

139.11 145

St Paul Park Refining Co. 

LLC

Saint Paul MN 74,000 Northern Tier Energy 

LLC

Not listed Not Listed

Suncor Energy Inc. Commerce City 

West

CO 67,000 Suncor Energy Inc. 34,398.09 12,978

Suncor Energy Inc. Commerce City 

East

CO 36,000 Suncor Energy Inc. 34,398.09 12,978

Sunoco, Inc. Marcus Hook PA 178,000 Sunoco, Inc. 37,489.00 4,544

Sunoco, Inc. Toledo OH 160,000 Sunoco, Inc. 37,489.00 4,544

Sunoco, Inc. (R&M) Philadelphia PA 335,000 Sunoco, Inc. 37,489.00 4,544

Tenby Inc. Oxnard CA 2,800 Ten By Inc. NotListed NotListed

Tesoro Alaska Petroleum 

Co

Kenai AK 68,000 Tesoro Corp 20,583.00 5,261

Tesoro Hawaii Corp Ewa Beach HI 93,500 Tesoro Corp 20,583.00 5,261

Tesoro Refining & 

Marketing Corporation

Martinez CA 166,000 Tesoro Corp 20,583.00 5,261

Tesoro Refining & 

Marketing Corporation

Wilmington CA 94,300 Tesoro Corp 20,583.00 5,261

Tesoro West Coast Mandan ND 58,000 Tesoro Corp 20,583.00 5,261

Tesoro West Coast Salt Lake City UT 57,500 Tesoro Corp 20,583.00 5,261

Tesoro West Coast Anacortes WA 120,000 Tesoro Corp 20,583.00 5,261

Total Petrochemicals Inc Port Arthur TX 232,000 Total SA 186,158.80 92,855

Trigeant Ltd. Corpus Christi TX BTB Refining 5.00 37

United Refining Co. Warren PA 65,000 United Refining 

Company

2,654.40 4,434

US Oil & Refining Co. Tacoma WA 38,800 US Oil & Refining Co. 26.90 182

Valero Energy Corporation Three Rivers TX 93,000 Valero Energy 82,233.00 20,313

Valero Energy Corporation Sunray TX 156,000 Valero Energy 82,233.00 20,313

Valero Refining Co 

California

Benicia CA 132,000 Valero Energy 82,233.00 20,313

Valero Refining Co 

California

Wilmington 

Asphalt Plant

CA 6,300 Valero Energy 82,233.00 20,313

Valero Refining Co 

California

Wilmington 

Refinery

CA 78,000 Valero Energy 82,233.00 20,313

Valero Refining Co 

Oklahoma

Ardmore OK 85,000 Valero Energy 82,233.00 20,313

(continued)
*** Draft – Do Not Cite, Quote, or Release During Review ***

A-6

Table A-1. Parent Company Information for Petroleum Refineries (continued)

Facility Name City State

Capacity 

(bbl/cd) Parent Company Name

Parent Company 

Sales

Parent Company 

Employment

Valero Refining Co Texas 

LP

Corpus Christi TX 142,000 Valero Energy 82,233.00 20,313

Valero Refining Co Texas 

LP

Houston TX 88,000 Valero Energy 82,233.00 20,313

Valero Refining Co Texas 

LP

Texas City TX 225,000 Valero Energy 82,233.00 20,313

Valero Refining New 

Orleans LLC

Norco LA 205,000 Valero Energy 82,233.00 20,313

Ventura Refining & 

Transmission LLC

Thomas OK 12,000 Ventura Refining & 

Transmission, LLC

3.10 37

Western Refining 

Company LP

El Paso TX 122,000 Western Refining, Inc. 7,965.05 636

Western Refining 

Southwest Inc

Bloomfield NM 16,800 Western Refining, Inc. 7,965.05 636

Western Refining 

Southwest Inc

Gallup NM 21,100 Western Refining, Inc. 7,965.05 636

Western Refining 

Yorktown Inc

Yorktown VA 66,300 Western Refining, Inc. 7,965.05 636

WRB Refining LLC Borger TX 146,000 ConocoPhillips 198,655.00 29,700

WRB Refining LLC Wood River IL 362,000 ConocoPhillips 198,655.00 29,700

Wynnewood Refining Co. Wynnewood OK 70,000 Gary-Williams Energy 

Corporation

49.90 260

Wyoming Refining Co New Castle WY 14,000 Wyoming Refining Co. 125.00 96

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Oil & Gas Journal, December 6, 2010

Energy Information Administration (EIA), Form EIA-820, “Annual Refinery Report.” Table 3. Capacity of 

Operable Petroleum Refineries by State and Individual Refinery as of January 1, 2011. (Data accessed on 

October 31, 2011.) [Source for 2009–2011 numbers.] <http://www.eia.gov/petroleum/refinerycapacity/
United States

Environmental Protection

Agency

Office of Air and Radiation

Office of Air Quality Planning and Standards

Research Triangle Park, NC

April 2012
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EO12866_PetRefineriesSubpart J 2060-AN72FnlRule_20120427

6560-50-P

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 9 and 60

[EPA-HQ-OAR-2007-0011; FL- ]

RIN 2060-AN72

Standards of Performance for Petroleum Refineries; Standards of 

Performance for Petroleum Refineries for Which Construction, 

Reconstruction, or Modification Commenced After May 14, 2007

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule; lift stay of effective date.

SUMMARY: On June 24, 2008, the EPA promulgated amendments to the 

Standards of Performance for Petroleum Refineries and new 

standards of performance for petroleum refinery process units 

constructed, reconstructed or modified after May 14, 2007. The 

EPA subsequently received three petitions for reconsideration of 

these final rules. On September 26, 2008, the EPA granted 

reconsideration and issued a stay for the issues raised in the 

petitions regarding process heaters and flares. On December 22, 

2008, the EPA addressed those specific issues by proposing 

amendments to certain provisions for process heaters and flares. 

The EPA also proposed technical corrections to the rules for 

issues that were raised in the petitions for reconsideration. In 

this action, the EPA is finalizing those amendments and 
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Page 2 of 293

technical corrections and is lifting the stay of all the 

provisions granted on September 26, 2008.

DATES: The stay of all the provisions is lifted and the final 

rule is effective on [INSERT DATE 60 DAYS FROM DATE OF 

PUBLICATION IN THE FEDERAL REGISTER]. The incorporation by

reference of certain publications listed in the final rule is 

approved by the Director of the Federal Register as of [INSERT 

DATE 60 DAYS FROM DATE OF PUBLICATION IN THE FEDERAL REGISTER].

ADDRESSES: The EPA has established a docket for this action 

under Docket ID No. EPA-HQ-OAR-2007-0011. All documents in the 

docket are listed in the www.regulations.gov index. Although

listed in the index, some information is not publicly available, 

e.g., confidential business information (CBI) or other 

information whose disclosure is restricted by statute. Certain 

other material, such as copyrighted material, is not placed on 

the Internet and will be publicly available only in hard copy 

form. Publicly available docket materials are available either 

electronically in www.regulations.gov or in hard copy at the EPA 

Docket Center, Standards of Performance for Petroleum Refineries 

Docket, EPA West Building, Room 3334, 1301 Constitution Ave., 

NW, Washington, DC. The Public Reading Room is open from 8:30 

a.m. to 4:30 p.m., Monday through Friday, excluding legal 

holidays. The telephone number for the Public Reading Room is 
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(202) 566-1744, and the telephone number for the Air Docket is 

(202) 566-1742.

FOR FURTHER INFORMATION CONTACT: Ms. Brenda Shine, Office of Air 

Quality Planning and Standards, Sector Policies and Programs 

Division, Refining and Chemicals Group (E143-01), Environmental 

Protection Agency, Research Triangle Park, NC 27711, telephone 

number: (919) 541-3608; fax number: (919) 541-0246; email 

address: shine.brenda@epa.gov.

SUPPLEMENTARY INFORMATION:

The information in this preamble is organized as follows:

I. General Information

A. Does this action apply to me?

B. Where can I get a copy of this document?

C. Judicial Review

II. Background Information

III. Summary of the Final Rules and Changes Since Proposal

A. What are the final amendments to the standards of performance

for petroleum refineries (40 CFR part 60, subpart J)?

B. What are the final amendments to the standards of performance

for process heaters (40 CFR part 60, subpart Ja)?

C. What are the final amendments to the standards of performance

for flares (40 CFR part 60, subpart Ja)?

D. What are the final amendments to the definitions in 40 CFR

part 60, subpart Ja?

E. What are the final technical corrections to 40 CFR part 60,

subpart Ja?

IV. Summary of Significant Comments and Responses

A. Process Heaters

B. Flares

C. Other Comments

V. Summary of Cost, Environmental, Energy and Economic Impacts

A. What are the emission reduction and cost impacts for the

final amendments?

B. What are the economic impacts?

C. What are the benefits?

VI. Statutory and Executive Order Reviews
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Page 4 of 293

A. Executive Order 12866: Regulatory Planning and Review and

Executive Order 13563: Improving Regulation and Regulatory

Review

B. Paperwork Reduction Act

C. Regulatory Flexibility Act

D. Unfunded Mandates Reform Act

E. Executive Order 13132: Federalism

F. Executive Order 13175: Consultation and Coordination with

Indian Tribal Governments

G. Executive Order 13045: Protection of Children from

Environmental Health Risks and Safety Risks

H. Executive Order 13211: Actions Concerning Regulations That

Significantly Affect Energy Supply, Distribution, or Use

I. National Technology Transfer and Advancement Act

J. Executive Order 12898: Federal Actions to Address

Environmental Justice in Minority Populations and Low-Income 

Populations

K. Congressional Review Act

I. General Information

A. Does this action apply to me?

Categories and entities potentially regulated by these 

final rules include:

Category NAICS 

Code1

Examples of Regulated Entities

Industry............. 32411 Petroleum refiners.

Federal government... Not affected.

State/local/tribal 

government...........

Not affected.

1 North American Industry Classification System

This table is not intended to be exhaustive, but rather 

provides a guide for readers regarding entities likely to be 

regulated by this action. To determine whether your facility 

would be regulated by this action, you should examine the 

applicability criteria in 40 CFR 60.100 and 40 CFR 60.100a. If 
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Page 5 of 293

you have any questions regarding the applicability of this 

proposed action to a particular entity, contact the person 

listed in the preceding FOR FURTHER INFORMATION CONTACT section.

B. Where can I get a copy of this document?

In addition to being available in the docket, an electronic 

copy of this final action is available on the World Wide Web 

(WWW) through the Technology Transfer Network (TTN). Following 

signature, a copy of this final action will be posted on the 

TTN’s policy and guidance page for newly proposed or promulgated 

rules at http://www.epa.gov/ttn/oarpg. The TTN provides

information and technology exchange in various areas of air 

pollution control.

The EPA has created a redline document comparing the 

existing regulatory text of 40 CFR part 60, subpart Ja and the 

final amendments to aid the public’s ability to understand the 

changes to the regulatory text. This document has been placed in 

the docket for this rulemaking (Docket ID No. EPA-HQ-OAR-2007-

0011).

C. Judicial Review

Under section 307(b)(1) of the Clean Air Act (CAA), 

judicial review of these final rules is available only by filing 

a petition for review in the United States Court of Appeals for 

the District of Columbia Circuit by [INSERT DATE 60 DAYS FROM 

DATE OF PUBLICATION IN THE FEDERAL REGISTER]. Under section 
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307(b)(2) of the CAA, the requirements established by these 

final rules may not be challenged separately in any civil or 

criminal proceedings brought by the EPA to enforce these 

requirements.

Section 307(d)(7)(B) of the CAA further provides that 

“[o]nly an objection to a rule or procedure which was raised 

with reasonable specificity during the period for public comment 

(including any public hearing) may be raised during judicial 

review.” This section also provides a mechanism for us to 

convene a proceeding for reconsideration, “[i]f the person 

raising an objection can demonstrate to the EPA that it was 

impracticable to raise such objection within [the period for 

public comment] or if the grounds for such objection arose after 

the period for public comment (but within the time specified for 

judicial review) and if such objection is of central relevance 

to the outcome of the rule.” Any person seeking to make such a 

demonstration to us should submit a Petition for Reconsideration 

to the Office of the Administrator, U.S. EPA, Room 3000, Ariel 

Rios Building, 1200 Pennsylvania Ave., NW, Washington, DC 20460, 

with a copy to both the person(s) listed in the preceding FOR 

FURTHER INFORMATION CONTACT section, and the Associate General 

Counsel for the Air and Radiation Law Office, Office of General 

Counsel (Mail Code 2344A), U.S. EPA, 1200 Pennsylvania Ave., NW, 

Washington, DC 20460.
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II. Background Information

A. Executive Summary

1. Purpose of the Regulatory Action

This action finalizes amendments that were proposed on 

December 22, 2008 to address reconsideration issues related to 

the promulgation of NSPS for flares and process heaters on June 

24, 2008. This action also lifts the stay that was granted in 

September 2008 on the provisions at issue.

2. Summary of Major Provisions

Table 1 presents a summary of major changes to the rule 

since it was first promulgated on June 24, 2008. The following 

discussion is a summary of major provisions of this rule.

Affected 

Source

Aspect NSPS Ja 

(June 24, 

2008)

NSPS Ja Final

All 

Process 

Heater NOx 

limits

Averaging 

time

24-hour 

rolling 

average

30-day rolling average

Natural 

Draft 

Process 

Heaters 

NOx Emission 

Limits

40 ppmv 40 ppmv or 0.04 lb/MM 

BTU
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Forced 

Draft 

Process 

Heaters

NOx Emission 

Limits

40 ppmv 60 ppmv or 0.06 lb/MM 

BTU

Forced 

Draft 

Process 

Heaters 

with Cofired (oil 

and gas) 

Burners

NOx Emission 

Limits

40 ppmv 150 ppmv or Weighted 

average based on oil 

at 0.40 lb/MM BTU and 

gas at 0.11 lb/MM BTU 

Natural 

Draft 

Process 

Heaters 

with Cofired (oil 

and gas) 

Burners

NOx Emission 

Limits

40 ppmv 150 ppmv or weighted 

average based on oil 

at 0.35 lb/MM BTU and 

gas at 0.06 lb/MM BTU 

Process 

Heaters 

Alternate 

Emission 

Standards

None Case by case approval

for some circumstances
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Flares Applicability New or 

reconstructed 

flare systems 

or existing 

flare systems 

that are 

physically 

altered to 

increase flow 

or to add new 

connections. 

Similar, except 

specific list of 

connections that do 

not trigger 

applicability.

Fuel gas 

combustion 

devices

H2S 

concentration 

limit

162 ppmv H2S 

(3-hour 

average);

60 ppmv H2S 

(annual 

rolling 

average)

162 ppmv H2S (3-hour 

average);

No 60 ppmv H2S long 

term concentration 

limit for flares

Flares Compliance 

date for 

modified 

flares

Comply with 

H2S limit at 

start-up, and 

all other 

requirements 

Comply with H2S limit 

at start-up, and all 

other requirements 

within 3 years
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within 1 years

Flares Flow limits Flare systemwide flow 

limit of 

250,000 scfd

No limits

Flares Root Cause 

Analysis and 

Corrective 

Action 

(RCA/CA)

RCA/CA 

required on 

upsets or 

malfunctions 

in excess of 

500,000 scfd 

or 500 lbs/day 

SO2 from SSM

RCA/CA required for 

500,000 scfd above 

base load and 500 lbs 

SO2 in any 24-hour 

period

Flares Flow 

monitoring

Continuous Continuous except for 

intermittent/emergency 

only flares with water 

seal monitoring and 

limited releases; 

Flares Sulfur 

Monitoring

Continuous 

Total Reduced 

Sulfur (TRS)

Continuous TRS, using 

reference method 15A 

(Total Sulfur)

Affected process heaters are those that were modified, 

reconstructed or constructed after May 14, 2007. For these 

affected sources, these final amendments include concentration-
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based NOX emissions limits and alternative heating value-based 

NOX emissions limits, both determined daily on a 30-day rolling 

average basis. These final amendments establish limits of 40 

ppmv NOx (or 0.04 lb/mmBTU) and 60 ppmv NOx (or 0.06 lb/mmBTU)

for natural draft and forced draft process heaters, 

respectively. Co-fired process heaters, designed to operate on 

gaseous and liquid fuel (e.g., oil), must meet either 150 ppmv 

NOx or alternative heating value-based limits, weighted based on 

oil and gas use. The NSPS also contains an alternative 

compliance option that allows owners and operators to obtain EPA 

approval for a site-specific NOX limit for process heaters that 

may have difficulty meeting the standards under certain 

situations. These final amendments also include monitoring, 

recordkeeping and reporting requirements necessary to 

demonstrate compliance with the NOx emission standards. 

For flares, these final amendments define a flare as a 

separate affected facility rather than a type of fuel gas 

combustion device. As such, these final amendments remove 

requirements for flares to comply with the performance standards 

for SO2 (expressed as a 162 ppmv short-term H2S concentration 

limit) and instead, establish a separate suite of standards for 

flares. We are not finalizing the requirement in the December 

22, 2008 proposed amendments for flares to meet the long-term 60 

ppmv H2S fuel gas concentration limit. As explained in section IV 
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of this preamble, we determined that requiring refineries to 

ensure the fuel gas they send to their flares meets a long-term 

H2S concentration of 60 ppmv is not appropriate for flares.

Affected flares are those that were modified, reconstructed 

or constructed after June 24, 2008. In general, a flare is 

modified if a connection is made into the flare header that can 

increase emissions from the flare. The NSPS specifically 

identifies certain connections to a flare that do not constitute 

a modification of the flare because they do not result in 

emissions increases. 

The final amendments for flares include a suite of 

standards that apply at all times. This suite of standards 

requires refineries to: (1) develop and implement a flare 

management plan; (2) conduct root cause analyses and take 

corrective action when waste gas sent to the flare exceeds a 

flow rate of 500,000 standard cubic feet per day (scfd) above 

the baseline flow or contains sulfur that, upon combustion, will 

emit more than 500 lb of SO2 in a 24-hour period; and (3) 

optimize management of the fuel gas by limiting the short-term 

concentration of H2S to 162 ppmv during normal operating 

conditions. 

The final amendments require that flares be equipped with 

flow and sulfur monitors except in cases where flares are used 

infrequently or are configured such that they cannot receive 
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high sulfur gas. For flares that are configured such that they 

only receive inherently low sulfur gas streams, continuous 

sulfur monitors are not necessary because a root cause analysis 

will be triggered by an exceedance of the flow rate threshold 

long before they exceed the 500 lb SO2 trigger in a 24-hour 

period. 

For infrequently used flares, the NSPS allows for less 

burdensome monitoring, consisting of monitoring the differential 

pressure between the flare header and the flare water seal to 

determine if a gas release to the flare has occurred. Any 

instance where the pressure upstream of the water seal 

(expressed in inches of water) exceeds the water seal height 

triggers a requirement to perform a root cause analysis and 

corrective action analysis, unless the discharge is related to 

flare gas recovery system compressor cycling or a planned 

startup or shutdown (of a refinery process unit or ancillary 

equipment connected to the flare) following the procedures in 

the flare management plan. The NSPS also contains an alternative 

compliance option for refinery flares located in the South Coast 

Air Quality Management District (SCAQMD) or the Bay Area Air 

Quality Management District (BAAQMD). An affected flare subject 

to subpart Ja may elect to comply with SCAQMD Rule 1118 or both 

BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12, Rule 12 

as an alternative to complying with the requirements of Ja.
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3. Costs and Benefits

The provisions for flares and other fuel gas combustion 

devices (i.e., process heaters and boilers) from the final June 

2008 standards were stayed. The analysis for this final rule 

includes the same unit costs for the flare provisions as the 

final June 2008 rule but reflects recalculated total costs using 

data collected in the March 2011 ICR to update the number of 

flares. For the June 2008 standards we estimated that 40 flares

would be affected. We now anticipate that there will be 400 

affected flares that will be subject to this final rule. Table 1 

includes the recalculated cost estimates based on the updated 

number of flares since 2008, broken out by specific flare 

requirements. For the other fuel gas combustion devices, the 

total annualized costs for those provisions were estimated at 

$24 million (2006 dollars) in the June 2008 rule and remain the 

same. As discussed below, because there are no additional 

incremental costs associated with the other fuel gas combustion 

device provisions, we consider those annual costs accounted for 

in the final June 2008 standards. We are presenting these costs 

and benefits here again, even though we estimate no changes to 

them, since these provisions will become effective upon this 

final action to lift the stay on certain provisions in the June 

2008 rule. For the June 2008 rule, we estimated the benefits to 
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be $220 million to $1.9 billion and $200 to $1.7 billion at a 3 

percent discount rate and 7 percent discount rate, respectively.1

Cost impacts for flares are presented in Table 1. The 

estimated total capital cost of complying with the final 

amendments to NSPS subpart Ja for flares is $460 million dollars

(2006 dollars). The estimated annual cost, including annualized 

capital costs, is a cost savings of about $79 million (2006 

dollars) due to the replacement of some natural gas purchases 

with recovered flare gas and the retention of intermediate and 

product streams due to a reduction in the number of malfunctions 

associated with refinery process units and ancillary equipment

connected to the flare. Note that not all refiners will realize 

a cost savings since we only estimate that refineries with high 

flare flows will install vapor recovery systems. Although the 

rule does not specifically require installation of flare gas 

recovery systems, we project that owners and operators of flares 

receiving high waste gas flows will conclude, upon installation 

of monitors, implementation of their flare management plans, and 

implementation of root causes analyses, that installing flare 

 1 It is important to note that EPA has implemented several substantial changes 

to the benefits methodology since 2008, which makes it challenging to compare 

the benefits of the June 2008 rule to the benefits of the current rulemaking. 

The changes with the largest impact on the range of monetized benefits are 

the removal of the assumption of a threshold in the concentration-response 

function, the revision of the value-of-a-statistical-life, and the range of 

risk estimates from epidemiology studies rather than the range of risk 

estimates supplied by experts. See the regulatory impact analysis for the 

current rulemaking for more information regarding these changes, which is 

available in the docket.
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gas recovery would result in fuel savings by using the recovered 

flare gas where purchased natural gas is now being used to fire 

equipment such as boilers and process heaters. The flare 

management plan requires refiners to conduct a thorough review 

of the flare system so that flare gas recovery systems are 

installed and used where these systems are warranted. As part of 

the development of the flare management plan, refinery owners 

and operators must provide rationale and supporting evidence 

regarding the flare waste gas reduction options considered. In 

addition, consistent with E.O. 13563 (Improving Regulation and 

Regulatory Review, issued on January 18, 2011), for facilities 

implementing flare gas recovery, we are finalizing provisions 

that would allow the owner or operator to reduce monitoring 

costs and the number of root cause analyses, corrective actions, 

and corresponding recordkeeping and reporting they would need to 

perform. The costs calculated for this rule, however, do not 

account for potential savings due to this reduced monitoring, 

root cause analysis, etc. We estimate that the final 

requirements for flares will reduce emissions of SO2 by 3,200

tons per year (tons/yr), NOX by 1,100 tons/yr, and VOC by 3,400

tons/yr from the baseline. The overall cost effectiveness is a 

cost savings of about $10,000 per ton of combined pollutants 

removed. We also estimate that the final requirements for flares 

will result in emissions reduction co-benefits of CO2 equivalents 

Comment [A1]: Clarification.
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by 1,900,000 metric tonnes per year, predominantly as a result 

of our estimate of the largest flares employing flare gas 

recovery and to a lesser extent, as a result of the flow rate 

root cause analyses and corrective actions applicable to all 

flares.

Table 1. Cost Impacts for Petroleum Refinery Flares Subject to 

Amended Standards under 40 CFR part 60, subpart Ja (Fifth Year 

After the Effective Date of these Final Rule Amendments).

Subpart Ja 

Requirements

Total 

capital 

cost 

($1,000)

Total 

annual

cost 

without 

credit

($1,000/ 

yr)

Natural 

gas 

offset/ 

product 

recovery 

credit 

($1,000)

Total 

annual

cost

($1,000/ 

yr)

Annual 

emission 

reductions 

(tons 

SO2/yr)

Annual 

emission 

reductions 

(tons 

NOX/yr)

Annual 

emission 

reductions 

(tons 

VOC/yr)

Cost 

effectiveness 

($/ton 

emissions 

reduced)

Majority of flares (approximately 360 flares)

Flare 

Monitoring 72,000 12,000 0 12,000 0 0 0 --

Flare gas 

recovery 0 0 0 0 0 0 0 --

Flare 

Management 0 790 0 790 0 0 270 2,900

SO2

RCA/CA 0 1,900 0 1,900 2,600 0 0 760

Flowrate 

RCA/CA 900 (6,700) (5,800) 3.4 50 390 (13,000)

Subtotal1 72,000 16,000 (6,700) 9,000 2,600 50 660 2,700

Largest flares (approximately 40 flares)2

Flare 

Monitoring 12,000 2,000 0 2,000 0 0 0 --

Flare gas 

recovery 380,000 78,000 (170,000) (90,000) 380 1,100 2,700 (22,000)

Flare 

Management 0 88 0 88 0 0 30 2,900

SO2

RCA/CA 0 220 0 220 290 0 0 760

Flowrate 

RCA/CA 0 100 (740) (640) 0.4 6 43 (13,000)

Subtotal1 390,000 81,000 (170,000) (88,000) 660 1,100 2,800 (20,000)

Total1 460,000 96,000 (180,000) (79,000) 3,200 1,100 3,400 (10,000)

1 All estimates are rounded to two significant figures so numbers 

may not sum down columns.
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2

EPA has conducted an alternative analysis that presents the 

costs and benefits of the rule assuming that no refiners will 

opt to install flare gas recovery systems as part of their flare 

management strategy. This analysis is presented in the 

Regulatory Impact Analysis in the discussion provided in the 

executive summary and in Section 4.1, available in the docket 

for this rulemaking.

We estimate the monetized benefits of this final regulatory 

action for all flares to be $260 million to $580 million (3-

percent discount rate) and $240 million to $520 million (7-

percent discount rate for health benefits and 3-percent discount 

rate for climate benefits). For small flares only, we estimate 

the monetized benefits are $170 million to $410 million (3-

percent discount rate) and $150 million to $370 million (7-

percent discount rate for health benefits and 3-percent discount 

rate for climate benefits). For large flares only, we estimate 

the monetized benefits are $93 million to $160 million (3-

percent discount rate) and $88 million to $150 million (7-

percent discount rate for health benefits and 3-percent discount 

rate for climate benefits). Several benefits categories, 

including direct exposure to SO2 and NOx benefits, ozone 

benefits, ecosystem benefits, and visibility benefits are not 

included in these monetized benefits. All estimates are in 2006 

dollars for the year 2017.

Although this final rule provides refiners with some 

additional compliance options and removes some requirements, 
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Page 19 of 293

such as the long-term H2S limit for flares, these are impacts did 

not result in emission reductions and were not monetized.the

cost savings due this increased flexibility have not been 

calculated for inclusion in the benefit-cost analysis. .

B. Background of the Refinery NSPS

Section 111(b)(1)(A) of the Clean Air Act (CAA) requires 

the EPA to establish federal standards of performance for new, 

modified and reconstructed sources for source categories which 

cause or contribute significantly to air pollution which may 

reasonably be anticipated to endanger public health or welfare.

The standard of performance must reflect the application of the

best system of emission reductions that (taking into 

consideration the cost of achieving such emission reductions,

any non-air quality health and environmental impact and energy 

requirements) the Administrator determines has been adequately 

demonstrated (CAA section 111(a)(1)). If it is not feasible to 

prescribe or enforce a standard of performance, the 

Administrator may instead promulgate a design, equipment, work 

practice or operational standard, or a combination of these 

types of standards (CAA section 111(h)(1)). Since 1970, the new 

source performance standards (NSPS) have been successful in 

achieving long-term emissions reductions in numerous industries 

by assuring cost effective controls are installed on newly 

constructed, reconstructed or modified sources.

Comment [A2]: It seems that these edits are 

getting away from the original point here, namely, 

that increased flexibility should in principle lead to 

cost reductions, but that these cost reductions 

weren’t calculated and thus do not appear in the 

monetized costs and benefits.
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The level of control prescribed by CAA section 111 

historically has been referred to as “Best Demonstrated 

Technology” or BDT. In order to better reflect that CAA section 

111 was amended in 1990 to clarify that “best systems” may or 

may not be “technology,” the EPA is now using the term “best 

system of emission reduction” or BSER in its rulemaking 

packages. See e.g. 76 FR 52738, 52740 (8/23/11); 76 FR 63878, 

63879 (10/14/11). As was done previously in analyzing BDT, the 

EPA uses available information and considers the emissions 

reductions achieved by the different systems available and the 

costs of achieving those reductions. The EPA also considers the 

“other factors” prescribed by the statute in its BSER analysis.

After considering all of this information, the EPA then 

establishes the appropriate standard representative of BSER. 

Sources may use whatever system meets the standard.

Section 111(b)(1)(B) of the CAA requires the EPA to 

periodically review and, as appropriate, revise the standards of 

performance to reflect improvements in methods for reducing 

emissions. As a result of our periodic review of the NSPS for 

petroleum refineries (40 CFR part 60, subpart J), we proposed 

amendments to the current standards of performance and separate 

standards of performance for new process units (40 CFR part 60, 

subpart Ja) (72 FR 27278, May 14, 2007) and we subsequently 

promulgated those amendments and new standards (73 FR 35838, 
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June 24, 2008). Following promulgation, we received three 

separate petitions for reconsideration from: (1) the American 

Petroleum Institute (API), the National Petrochemical and 

Refiners Association (NPRA) and the Western States Petroleum 

Association (WSPA) (collectively referred to as “Industry 

Petitioners”); (2) HOVENSA, LLC (“HOVENSA”); and (3) the 

Environmental Integrity Project, Sierra Club and Natural 

Resources Defense Council (collectively referred to as 

“Environmental Petitioners”). On September 26, 2008, the EPA 

issued a Federal Register notice (73 FR 55751) granting 

reconsideration of the following issues: (1) the newly 

promulgated flare modification provision;2 (2) the “flare” 

definition; (3) the fuel gas combustion device sulfur limits as 

they apply to flares; (4) the flow limit for flares; (5) the 

total reduced sulfur and flow monitoring requirements for 

flares; and (6) the nitrogen oxide (NOX) limit for process

heaters. The EPA also granted Industry Petitioners’ and 

HOVENSA’s request for a 90-day stay for those same provisions 

under reconsideration. On December 22, 2008, three Federal 

 2 The September 26, 2008, Federal Register notice (73 FR 55751)

described the first issue for which EPA granted reconsideration 

as “the definition of ‘modification.’” However, because what we 

are actually reconsidering is the specific flare modification 

provision that applies to flares at petroleum refineries rather 

than the more generally applicable definition of “modification,” 

we have revised the description of this issue as “the newly 

promulgated flare modification provision.”
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Register notices (73 FR 78260, 73 FR 78546 and 73 FR 78549) were 

published to extend this stay until a final decision is reached 

on those issues.

In the September 26, 2008, Federal Register notice (73 FR 

55751), we also identified other issues for which Petitioners 

requested reconsideration. We stated that, at that time, we were 

“taking no action on all of the other issues raised in the

petitions but will consider all of the outstanding issues in a 

future notice.” On December 29, 2009, we sent a letter to the 

Petitioners, through their counsel, stating that “[t]he 

Administrator has decided to grant reconsideration of all the 

remaining issues” and that “EPA will address the substantive 

aspects of the issues under reconsideration through notice and 

comment actions published in the Federal Register.” A copy of 

the letter to the Petitioners can be found in the docket for 

this rulemaking (Docket Item No. EPA-HQ-OAR-2007-0011-0318).

In this action, we are finalizing the amendments for which 

we granted reconsideration and a stay as outlined in the 

September 26, 2008, notice and for which we proposed amendments 

on December 22, 2008. We are also addressing certain other minor 

issues raised by Industry Petitioners in this action, as 

discussed later in this preamble. We will take action on all of 

the remaining issues raised by Petitioners for reconsideration 

in future notices. 
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We received a total of 22 comments from the following 

groups on the proposed amendments during the public comment 

period: (1) refineries, industry trade associations and 

consultants; (2) state and local environmental and public health 

agencies; (3) environmental groups; and (4) other members of the 

public. These final amendments reflect our full consideration of 

all of the comments we received. Detailed responses to the 

comments not included in this preamble, as well as more detailed 

summaries of the comments addressed in this preamble, are 

contained in Standards of Performance for Petroleum Refineries: 

Background Information for Final Amendments - Summary of Public 

Comments and Responses, dated December 2011, which is included 

in Docket ID No. EPA-HQ-OAR-2007-0011. 

In summary, major comments on the proposed process heater 

requirements were related to the proposed NOx concentration 

limits, the alternative heating value limits, consideration of 

turndown (i.e., when a process heater is operated at less than 

50 percent design capacity) and other factors that influence the 

achievable emissions limits. In response, we are raising the 

limit for new forced draft process heaters from 40 ppmv NOx at 

proposal to 60 ppmv NOx. For both natural draft and forced draft 

process heaters, we are finalizing alternative heating value 

limits derived from a more direct numerical conversion of the NOx

concentration limit (i.e., 0.04 lb/mmBTU for natural draft and 
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0.06 lb/mmBTU for forced draft). For newly constructed, 

modified and reconstructed natural draft and forced draft 

process heaters we are reducing the averaging time for 

compliance from a 365-day rolling average to a 30-day rolling 

average applicable during periods of normal operation. We are 

also finalizing an alternative case-specific compliance option 

that allows owners and operators to obtain EPA approval for a 

site-specific NOX limit in certain conditions such as turndown.

Major comments on the proposed requirements for flares were 

related to the definition of flare modification for purposes of 

triggering applicability to this rule, the proposed removal of 

the flare flow limit, clarification of flare monitoring 

requirements, and clarification of the differences between the 

requirement for flares and the requirements for other fuel gas 

combustion devices. We address these comments by clarifying the 

definition of flare modification and by expanding the list 

included in the December 22, 2008 proposal, which specifies 

certain connections that do not constitute a modification of the 

flare because they do not result in emissions increases. We are 

finalizing the proposed removal of the flare flow limit and 

instead, we are promulgating a suite of work practice standards 

that apply to affected flares. Based on comments received on the 

December 22, 2008 proposal, we are finalizing definitions of 

“fuel gas combustion device” and “flare” to specify that a flare 
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is a separate affected facility rather than a type of fuel gas 

combustion device. We are also finalizing amendments to clarify 

certain monitoring requirements and to provide additional 

monitoring alternatives under certain circumstances.

III. Summary of the Final Rules and Changes Since Proposal 

NSPS for petroleum refineries (40 CFR part 60, subpart J) 

apply to the affected facilities at the refinery, such as fuel 

gas combustion devices (which include process heaters, boilers

and flares), that commence construction, reconstruction or 

modification after June 11, 1973, but on or before May 14, 2007 

(on or before June 24, 2008 for flares). The NSPS were 

originally promulgated on March 8, 1974, and have been amended 

several times. In this action, we are promulgating technical 

clarifications and corrections to subpart J.

New standards of performance for petroleum refineries (40 

CFR part 60, subpart Ja) apply to flares that commence 

construction, reconstruction or modification after June 24, 

2008, and other affected facilities at petroleum refineries, 

including process heaters and other fuel gas combustion devices 

that commence construction, reconstruction or modification after 

May 14, 2007. In this action, we are finalizing amendments to 

subpart Ja to address the issues raised by Petitioners regarding 

flares and process heaters. We are also finalizing technical 

corrections to subpart Ja for certain issues that were 
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identified by Industry Petitioners in their August 21, 2008, 

supplement to their original administrative reconsideration 

request (Docket Item No. EPA-HQ-OAR-2007-0011-0246).

The following sections summarize the amendments in both 40 

CFR part 60, subpart J and 40 CFR part 60, subpart Ja. Section 

IV contains the rationale for these amendments, while the 

amendments themselves follow the preamble.

A. What are the final amendments to the standards of performance 

for petroleum refineries (40 CFR part 60, subpart J)?

The final amendments add a new paragraph to 40 CFR 60.100 

to allow 40 CFR part 60, subpart J affected sources the option 

of complying with subpart J by following the requirements in 40 

CFR part 60, subpart Ja. The subpart Ja requirements are at 

least as stringent as those in subpart J, so providing this 

option will allow all process units in a refinery to follow the 

same requirements and simplify compliance. We are also 

finalizing a correction to the value and units (in the metric 

system) for the allowable incremental rate of particulate matter 

(PM) emissions in 40 CFR 60.106(c)(1). We amended the units for 

this constant in 40 CFR 60.102(b) on June 24, 2008, and we are 

now correcting 40 CFR 60.106(c)(1) accordingly. Finally, we are 

finalizing a definition of “fuel gas” that incorporates the same 

clarifications regarding vapors from wastewater treatment units 

and marine tank vessel loading operations identified in the 
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subpart Ja definition of “fuel gas” (described later in this 

preamble).

B. What are the final amendments to the standards of performance 

for process heaters (40 CFR part 60, subpart Ja)?

We proposed several amendments to the standards of 

performance for process heaters, including adding emission 

limits in units of pounds per million British thermal units 

(lb/MMBtu), extending the emission limit averaging time from 24 

hours to 365 days, raising the emission limit for modified and 

reconstructed forced draft process heaters and raising the 

emission limit for co-fired process heaters. After consideration 

of all of the public comments and our own additional analyses, 

we are finalizing the process heater requirements, as described 

in this section.

Table 2 presents a comparison of the proposed and final Ja 

amendments for process heaters. The final amendments include 

four subcategories of process heaters: (1) natural draft process 

heaters; (2) forced draft process heaters; (3) co-fired natural 

draft process heaters; and (4) co-fired forced draft process 

heaters. At proposal, all co-fired process heaters were included 

in one subcategory, for a total of three process heater 

subcategories, but, based on emissions data from co-fired 

process heaters, we divided natural draft and forced draft co-
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fired process heaters into separate subcategories with different 

emissions limits.

For each of the first two subcategories, the final 

amendments include a concentration-based NOX emissions limit and 

a heating value-based NOX emissions limit, both determined daily 

on a 30-day rolling average basis. For the natural draft process 

heater subcategory, the concentration-based NOX emissions limit 

for newly constructed, modified and reconstructed natural draft 

process heaters is 40 parts per million by volume (ppmv) (dry 

basis, corrected to 0-percent excess air) determined daily on a 

30-day rolling average basis. The heating value-based NOX

emissions limit for newly constructed, modified and 

reconstructed natural draft process heaters is 0.040 lb/MMBtu 

higher heating value basis determined daily on a 30-day rolling 

average basis. The averaging time for both of these limits is 

shorter than the 365-day averaging time that was proposed, and 

the heating value-based NOX emissions limit differs from the 

proposed limit in that it is a more direct numerical conversion 

from 40 ppmv NOX. At proposal, we provided a longer averaging 

time so that short periods of turndown (i.e., when a process 

heater is operating at less than 50 percent design capacity) 

would not significantly affect the overall performance of the 

unit. Our analysis of the additional data that we obtained 

following the proposal supported revising all NOX emissions 
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limits to be on a 30-day rolling average basis, which is 

achievable for process heaters during periods of normal 

operation. These data indicate that process heaters equipped 

with ultra low NOx burners meet the emission limits described 

above if compliance is determined on a 30-day rolling average 

basis. We are finalizing alternative compliance options that 

allow the owners and operator to establish site-specific limits 

applicable during certain conditions such as turndown. Section 

IV.A of this preamble provides additional information regarding 

the rationale and analyses leading to these final amendments.

For the second subcategory, forced draft process heaters, 

the concentration-based NOX emissions limit for newly 

constructed, modified and reconstructed forced draft process 

heaters is 60 ppmv (dry basis, corrected to 0-percent excess 

air) determined daily on a 30-day rolling average basis. The 

heating value-based NOX emissions limit for newly constructed, 

modified and reconstructed forced draft process heaters is 0.060 

lb/MMBtu higher heating value basis determined daily on a 30-day 

rolling average basis. The higher limit for new forced draft 

process heaters (at proposal, the limit was 40 ppmv) is based on 

additional data and a re-evaluation of BSER, as described later 

in this preamble. As with natural draft process heaters, the 

averaging time for both of these limits is shorter than 

proposed, and the final heating value-based NOX emissions limit 
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is a more direct numerical conversion from 60 ppmv NOX. Section 

IV.A of this preamble provides additional information regarding 

the rationale and analyses leading to these final amendments.

For each of these subcategories, a process heater need only 

meet either the concentration-based NOX emissions limit or the 

heating value-based NOX emissions limit. The refinery owner or 

operator may choose to comply with either limit at any time, 

provided that they are monitoring the appropriate variables to 

assess the heating value-based NOX emissions limit. If the 

refinery owner or operator does not choose to monitor fuel 

composition, then they must comply with the concentration-based 

NOX emissions limit. 

Table 2. Proposed and Final Amendments for Process Heaters

Proposal

(December 22, 2008)

Final

Averaging 

time 

365-day rolling average 30-day rolling average 

Natural Draft 

NOx

Emission 

Limits

40 ppmv or 0.035 lb/MM 

BTU 

40 ppmv or 0.04 lb/MM BTU 

Forced Draft 

NOx 

Emission

Limits

New: 40 ppmv or 0.035 

lb/MM BTU 

M/R: 60 ppmv or 0.055 

lb/MM BTU 

60 ppmv or 0.06 lb/MM BTU 
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Co-fired 

Burner (oil 

and gas) NOx 

Emission 

Limits

150 ppmv or Weighted 

average based on oil at 

0.27 lb/MM BTU and gas 

at 0.08 lb/MM BTU 

150 ppmv or Weighted average based on oil at 

0.40 lb/MM BTU and gas at 0.11 lb/MM BTU 

forced draft and weighted average based on oil at 

0.35 lb/MM BTU and gas at 0.06 lb/MM BTU for 

natural draft 

As proposed, initial compliance with the heating valuebased emissions limits will be demonstrated by conducting a 

performance evaluation of the continuous emission monitoring 

system (CEMS) in accordance with Performance Specification 2 in 

appendix B to 40 CFR part 60, with EPA Method 7 of 40 CFR part 

60, appendix A-4 as the Reference Method, along with fuel flow 

measurements and fuel gas compositional analysis. The NOX

emission rate is calculated using the oxygen (O2)-based F factor, 

dry basis according to EPA Method 19 of 40 CFR part 60, appendix 

A-7. Ongoing compliance with this NOX emissions limit is 

determined using a NOX CEMS and at least daily sampling of fuel 

gas heat content or composition to calculate a daily average 

heating value-based emissions rate, which is subsequently used 

to determine the 30-day average.

The third and fourth subcategories of process heaters are 

co-fired process heaters. A co-fired process heater is a process 

heater that employs burners that are designed to be supplied by 

both gaseous and liquid fuels. As described in more detail in 
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section IV.A of this preamble, co-fired process heaters do not 

include gas-fired process heaters that have emergency oil backup burners. There are two compliance options for each 

subcategory of co-fired process heaters: (1) 150 ppmv (dry 

basis, corrected to 0-percent excess air) determined daily on a 

30 successive operating day rolling average basis; and (2) a 

source-specific daily average emissions limit. Unlike gas-fired 

process heaters, the owner or operator of a co-fired process 

heater must choose one emissions limit and show compliance with 

that limit. For co-fired natural draft process heaters, the 

daily average emissions limit is based on a limit of 0.06 

lb/MMBtu for the gas portion of the firing and 0.35 lb/MMBtu for 

the oil portion of the firing. For co-fired forced draft process 

heaters, the daily average emissions limit is based on a limit 

of 0.11 lb/MMBtu for the gas portion of the firing and 0.40 

lb/MMBtu for the oil portion of the firing. These limits are 

different than proposed, based on a re-evaluation of BSER with 

new data received during the public comment period. All of the 

requirements for emissions monitoring, recordkeeping and 

reporting for co-fired process heaters are the same as for the 

other process heater subcategories.

We are also finalizing an alternative compliance option 

that allows owners and operators to obtain EPA approval for a 

site-specific NOX limit for certain process heaters. This 
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compliance option was provided in the proposed amendments, but 

it was limited to (1) natural draft and forced draft modified or 

reconstructed process heaters that lack sufficient space to 

accommodate combustion modification-based technology and (2) 

natural draft and forced draft co-fired process heaters. In the 

final amendments, we are finalizing this compliance option for 

those process heaters mentioned above while also providing this 

compliance option for the following additional types of process 

heaters: (3) modified or reconstructed induced draft process 

heaters that have downwardly firing burners and (4) forced draft 

and natural draft process heaters that operate at low firing 

rates, or turndown, for an extended period of time. As we noted 

in the preamble to the proposed amendments, in limited cases, 

existing natural draft or forced draft process heaters have 

limited firebox size or other constraints such that they cannot 

apply the BSER of ultra-low NOX burners or otherwise meet the 

applicable limit and some co-fired units may not be able to 

achieve the NOX limitations even with ultra-low NOX burner 

control technology. In addition, commenters noted that 

downwardly fired process heaters with induced draft fans have 

similar NOX control issues as forced draft heaters, but the 

definition of forced draft heater does not include these induced 

draft heaters (these are defined as natural draft process 

heaters). Therefore, we added a provision to allow induced draft 
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process heaters with downwardly-firing burners to use the

alternative compliance option.

Finally, we note that the emissions limits for forced draft 

and natural draft gas-fired process heaters are based on the 

performance of ultra-low NOX burner control technologies. The 

ultra-low NOX burner technology suppliers recommend operating 

with higher excess air rates at low firing rates (at or below 

approximately one-half of the maximum firing capacity), which 

causes higher NOX concentrations at low firing rates. Therefore, 

all types of process heaters with ultra-low NOX burner control 

technologies may be unable to meet the emissions limits if they 

are operated at low firing rates for an extended period of time. 

Requesting a site-specific emissions limit requires a detailed 

demonstration that the application of the ultra-low NOX burner 

technology is not feasible or that the technology cannot meet 

the NOX emissions limits given the conditions of the process 

heater (downward fired induced draft, co-fired or prolonged 

turndown); the refinery must also conduct source tests in 

developing a site-specific emissions limit for its process 

heater. This analysis must be submitted to and approved by the 

Administrator.

We are finalizing the proposed clarification that owners 

and operators of process heaters in any subcategory with a rated 

heating capacity of less than 100 million British thermal units 
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per hour (MMBtu/hr) have the option of using CEMS. The final

rule states that owners and operators of process heaters subject 

to 40 CFR part 60, subpart Ja should use CEMS to demonstrate 

compliance unless the heater is equipped with combustion 

modification-based technology (low-NOX burners or ultra-low NOX

burners) with a rated heating capacity of less than 100 

MMBtu/hr; owners and operators of those specific process heaters 

have the alternative option of biennial source testing to 

determine compliance. As requested by commenters, we have 

provided additional detail in the final rule regarding how to 

develop the O2 operating limit, including provisions on how to 

develop an O2 operating curve to ensure compliance with the NOX

emission limit at different process heater firing rates. We are 

requiring that owners and operators with process heaters in any 

subcategory that are complying using biennial source testing 

establish a maximum excess O2 concentration operating limit or 

operating curve that can be met at all times, even during 

turndown, and comply with the O2 monitoring requirements for 

ongoing compliance demonstration.

C. What are the final amendments to the standards of performance 

for flares (40 CFR part 60, subpart Ja)?

We proposed several amendments to the standards of 

performance for flares, including, but not limited to, amending 

the flare modification provision, removing the numerical limit 
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on the flow rate to the flare, revising the flare management 

plan requirements to include a list of connections to the flare 

and an identification of baseline conditions, clarifying when a 

root cause analysis is required, revising the sulfur and flow 

monitoring requirements and providing additional time for 

compliance. After consideration of all of the public comments, 

and our own additional analyses, we are finalizing the flare 

requirements, as described in this section.

We did not propose to revise the definitions of “fuel gas 

combustion device” and “flare” on December 22, 2008. However, 

based on public comment and changes to the flare requirements,

as described later in this section, we have decided to finalize 

revisions to these definitions to specify that, for purposes of 

40 CFR part 60, subpart Ja, a flare is a separate affected 

facility rather than a type of fuel gas combustion device. This 

change makes clearer the differences between the requirements 

for flares and the requirements for fuel gas combustion devices, 

particularly in terms of sulfur and flow rate monitoring 

requirements and thresholds for root cause analyses and 

corrective action analyses. We are also making corrections, as 

needed, in numerous paragraphs throughout subpart Ja for 

consistency with the amended definitions (e.g., adding “and 

flares,” where applicable, to paragraphs with requirements for 

“fuel gas combustion devices”).
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We are finalizing the flare modification provision in 40 

CFR 60.100a(c), as described below, to specify certain 

connections to a flare that do not constitute a modification of 

the flare because they do not result in emissions increases. On 

December 22, 2008, we proposed that the following types of 

connections to a flare would not be considered a modification of 

the flare: (1) connections made to install monitoring systems to 

the flares; (2) connections made to install a flare gas recovery 

system; (3) connections made to replace or upgrade existing 

pressure relief or safety valves, provided the new pressure 

relief or safety valve has a set point opening pressure no lower 

and an internal diameter no greater than the existing equipment 

being replaced or upgraded; and (4) replacing piping or moving 

an existing connection from a refinery process unit to a new 

location in the same flare, provided the new pipe diameter is 

less than or equal to the diameter of the pipe/connection being 

replaced/moved. We are finalizing those proposed amendments and 

also adding the following types of connections to the list of 

connections to flares that are not modifications of flares: (1) 

connections between flares; (2) connections for flare gas sulfur 

removal; and (3) connections made to install redundant flare 

equipment (such as a back-up compressor). We are also clarifying 

one of the proposed exemptions to indicate that connections made 

to upgrade or enhance components of flare gas recovery systems 
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(e.g., additional compressors or recycle lines) are not 

modifications.

We are not finalizing the proposed amendment to provide 

additional time for flares that need to install additional amine 

scrubbing and amine stripping columns to meet the requirement to 

limit the long-term concentration of hydrogen sulfide (H2S) to 60 

ppmv (determined daily on a 365 successive calendar day rolling 

average basis) (hereafter referred to as the long-term 60 ppmv 

H2S fuel gas concentration limit). Instead, based on comments 

received during the public comment period for the proposed 

amendments and our own additional analyses, we are removing the 

requirement for flares to meet the long-term 60 ppmv H2S fuel gas 

concentration limit. As explained in section IV, we determined 

that requiring refineries to ensure the fuel gas they send to 

their flares meets a long-term H2S concentration of 60 ppmv is 

not appropriate for flares.

We are promulgating final amendments for flares that 

include a suite of standards that apply at all times that are 

aimed at reducing sulfur dioxide (SO2) emissions from flares.

These amendments include several provisions that were proposed 

on December 22, 2008, as well as others that differ from those 

proposed, but are a logical outgrowth of the proposed 

amendments. This suite of standards requires refineries to: (1)

develop and implement a flare management plan; (2) conduct root 
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cause analyses and take corrective action when waste gas sent to 

the flare exceeds a flow rate of 500,000 standard cubic feet

(scf) above the baseline flow to a flare in any 24-hour period 

(rather than the proposed threshold of 500,000 scf in any 24-

hour period without considering the baseline); (3) conduct root 

cause analyses and take corrective action when the emissions 

from the flare exceed 500 lb of SO2 in a 24-hour period (instead 

of 500 lb SO2 above the emissions limit); and (4) optimize

management of the fuel gas by limiting the short-term 

concentration of H2S to 162 ppmv during normal operating 

conditions (determined hourly on a 3-hour rolling average 

basis). As explained further in preamble section IV.B, NSPS 

subpart J sets a performance standard for SO2 (expressed as a 162 

ppmv short-term H2S concentration limit) in fuel gas entering 

fuel gas combustion devices. However, for this final rule, we 

have determined that flares should be treated separately from 

other fuel gas combustion devices because they meet the criteria 

set forth in CAA section 111(h)(2)(A) since emissions from a 

flare do not occur “through a conveyance designed and 

constructed to emit or capture such pollutant.” The flare 

itself is not a “conveyance” that is ”emitting” or “capturing” 

these pollutants. Instead, pollutants such as SO2 are created in 

the flame that burns outside the flare tip. Therefore, we have 

determined that this suite of work practice standards, which 
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includes optimization of fuel gas management (based on limiting 

concentration of H2S to 160 ppmv) is more appropriate for flares, 

as opposed to the H2S performance standard in subpart J, 

applicable to fuel gas systems. See section IV.B of this 

preamble for a more detailed explanation of these requirements.

In this rule, we are using the term “normal operating 

conditions” to describe situations where the process is 

operating in a routine, predictable manner, such that the gases 

from the process are predictable, as opposed to less-predictable 

swings related to emergency situations during which the flare 

begins to operate as a safety device. All of these requirements 

will apply during the vast majority of the time. Under a very 

narrow and limited set of circumstances, such as when a flare is 

used as a safety device under emergency conditions,3 the flare 

will be subject to all of these requirements except for the 

requirement to optimize management of the fuel gas.

In addition, we are specifying that, if a discharge 

exceeding either or both of the SO2 or flow thresholds described 

above is the result of a planned startup or shutdown of a 

refinery process unit or ancillary equipment connected to the 

flare, and the flare management plan procedures for minimizing 

 3 Background Information for New Source Performance Standards,

Vol. 3, Promulgated Standards (APTD-1352c; Publication No. EPA 

450/2-74-003), pg 127 (February 1974) (NSPS BID Vol. 3). 
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flow (which minimizes emissions) during that type of event are

followed, a root cause analysis and corrective action analysis 

are not required. Finally, we are finalizing the proposed added 

provisions to ensure that owners and operators implement 

corrective actions on the findings of the SO2 or flow rate root 

cause analyses and to specify a deadline for performing the 

corrective actions. 

We are finalizing the proposed amendment to remove the 

250,000 standard cubic feet per day (scfd) 30-day average flow 

rate limit. Our rationale for this decision is explained in the 

preamble to the proposed amendments (73 FR 78530) and also in 

section IV of this preamble.

We are finalizing one proposed amendment to the flare 

management plan and adding several new requirements as a logical 

outgrowth of the proposed amendments, considering the public 

comments we received, to ensure compliance with the flare 

standards. First, as proposed, we are requiring a list of 

refinery process units and fuel gas systems connected to each 

affected flare. However, we are also adding a requirement for a 

simple process flow diagram showing the design of the flare, 

connections to the flare header and subheader system(s), and all 

gas lines associated with the flare. With these two 

requirements, we are clarifying that the flare management plan 

must include a diagram of the flare and connections, but the 
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diagram need not be a detailed piping and instrumentation 

diagram that shows all process units and ancillary equipment

connected to the flare. We are also requiring the owner and 

operator of an affected flare to assess and minimize flow to 

affected flares from these process units and fuel gas systems.

Second, we are adding new requirements that the flare management 

plan include design and operation details about the affected 

flare, including tip diameter, type of flare, monitoring methods

and a description of the flare gas recovery system, if present.

The inclusion of these details will ensure that the rest of the 

flare management plan is reasonable and appropriate for that 

affected flare. 

Third, as a logical outgrowth of the proposed amendments,

considering the public comments we received, we are adding a new 

requirement for owners and operators to determine the baseline 

flow to each flare, including purge and sweep gas, and include 

this baseline flow in the flare management plan. As described 

later in this preamble, developing the baseline is important 

because the final threshold for the flare flow root cause 

analysis takes this baseline flow into consideration. Finally, 

we are adding a new requirement to minimize the volume of gas 

flared during maintenance of a flare gas recovery system.

We have decided to remove the requirement for the owner or 

operator to explain in the flare management plan how a root 
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cause analysis and corrective action analysis will be conducted 

if the flow to the flare exceeds the specified threshold. 

Instead, all the requirements for determining when and how to 

conduct a root cause analysis and corrective action analysis,

and the requirements for when and how to implement a corrective 

action, have been expanded, as described later in this section,

and moved to 40 CFR 60.103a(c) through (e).

We are specifying that, for modified flares, the flare 

management plan must be developed and implemented by no later 

than [INSERT DATE 3 YEARS FROM DATE OF PUBLICATION IN THE 

FEDERAL REGISTER] or upon startup of the modified flare, 

whichever is later (the proposed amendments provided 18 months 

with an additional 6 months if the owner or operator committed 

to installing a flare gas recovery system). In addition, because 

of the lack of a direct flow limit and the addition of the 

baseline flow value, we are adding a requirement that the flare 

management plan must be submitted to the Administrator.

As with the flare management plan, the owner or operator of 

an affected flare must comply with the root cause analysis and 

corrective action analysis requirements within 3 years from the 

effective date of this final rule or upon startup of the 

modified flare, whichever is later.

We are finalizing several proposed amendments to the sulfur 

monitoring requirements and revising other requirements as a 
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logical outgrowth of the proposed amendments, considering the 

public comments we received. We consolidated the proposed 

alternatives to monitor reduced sulfur compounds and total 

sulfur compounds into a provision that allows the use of total

reduced sulfur monitoring. We also clarified the span 

requirements for these monitors and are allowing the use of 

cylinder gas audits for relative accuracy assessments. We are 

finalizing the H2S monitoring alternative method for determining 

total sulfur content in the flare gas, as proposed, but we have 

clarified the span requirements for this monitor and are 

allowing the use of cylinder gas audits for relative accuracy 

assessments, similar to the total reduced sulfur monitor 

requirements. For refineries that measure SO2 concentrations in 

the exhaust from a fuel gas combustion device that combusts gas 

representative of the gas discharged to the flare, we added an 

alternative to allow the owner or operator to use the existing 

SO2 CEMS data to calculate the total sulfur content in the flare 

gas.

We received public comments stating that the flow and 

sulfur monitoring requirements for flares were too burdensome 

for flares that are used infrequently or that are configured

such that they cannot receive high sulfur flare gas. Based on 

our evaluation of these comments, we are providing new 

alternatives to continuous flow and sulfur monitoring for 
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certain flares. First, for flares that are configured such that 

they only receive inherently low sulfur gas streams described in 

40 CFR 60.107a(a)(3)(i) through (iv) or (b), continuous sulfur 

monitors are not necessary because a root cause analysis will be 

triggered by an exceedance of the flow rate threshold long 

before they exceed the 500 lb SO2 trigger in a 24-hour period. 

Second, we are providing an alternative monitoring option 

for emergency flares, secondary flares and flares equipped with 

a flare gas recovery system designed, sized and operated to 

capture all flows (except flows resulting from planned startup

and shutdown that are addressed in the flare management plan). 

If this option is applicable, the owner or operator may elect to 

continuously monitor the water seal height and the pressure in 

the flare header just upstream of the water seal rather than 

install total sulfur and flow monitoring systems. If this 

monitoring option is selected, any instance where the pressure 

upstream of the water seal (expressed in inches of water) 

exceeds the water seal height triggers a requirement to perform 

a root cause analysis and corrective action analysis, unless the 

discharge is related to flare gas recovery system compressor 

cycling or a planned startup or shutdown (of a refinery process 

unit or ancillary equipment connected to the flare) following 

the procedures in the flare management plan. An “emergency 

flare” is a flare that combusts gas exclusively released as a 
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result of malfunctions (and not startup, shutdown, routine 

operations or any other cause) and is characterized as having 

four or fewer discharge events in any 365 consecutive calendar 

days.

Owners or operators of affected flares that have flare gas 

recovery systems with staged compressors that elect to use this 

monitoring option must identify these flares in their flare 

management plan, identify the time period required for the 

staged compressors to actively start to recover gas and identify 

the operating parameters monitored and procedures employed to 

minimize the duration of flaring during compressor staging. If a

pressure exceedance is caused during compressor staging and the 

duration of the pressure exceedance is less than the time 

specified in the flare management plan, then a root cause 

analysis is not required and the pressure exceedance is not 

required to be reported. If a pressure exceedance is not 

attributable to compressor staging (i.e., all staged compressors 

are active), if a pressure exceedance is the result of a planned 

startup and shutdown event during which the flare management 

plan is not followed or if the duration of a pressure exceedance 

attributable to compressor staging is greater than the time 

specified in the flare management plan, then a root cause 

analysis and corrective action analysis are required and the 

pressure exceedance must be reported. More than four pressure 
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exceedances required to be reported, as described above and 

under 40 CFR 60.108a(d)(5) (hereafter referred to as “reportable 

pressure exceedances”) in any 365 consecutive calendar days is 

an indication that the flare gas recovery system is not 

adequately sized, and the sulfur and flow monitors, as required 

in 40 CFR 60.107a(e) and (f), must be installed if that occurs. 

Third, we are clarifying that monitors for flow and sulfur 

on the second flare in a staged flare configuration are not 

required where the water seal monitoring requirements adequately 

and appropriately address this scenario. Under most 

circumstances, the root cause analysis is expected to be 

triggered, based on the flow to or emissions from the primary 

flare. However, in cases where the capacity of the primary flare 

is small (less than 500,000 scfd), this may not always be the 

case. Additionally, we consider the water seal monitoring on the 

secondary flare to be appropriate to ensure that gases are not 

released to the secondary flare inadvertently. We clarify in 

this final rule that if a root cause analysis is triggered for 

the primary flare, releases to the secondary flare do not 

trigger an additional root cause analysis (i.e., the releases 

may be treated as one event). However, if flow is diverted to 

the secondary flare, then a root cause analysis is required,

even if a root cause analysis was not triggered for the primary 

flare, based on flow rate or SO2 emissions. In addition, if flow 
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is diverted to the secondary flare five or more times in a 365-

day period, flow monitoring of the secondary flare is required. 

We anticipate that the upstream sulfur monitor on the primary 

flare can be used to determine the sulfur content of the gas 

diverted to the secondary flare.

In response to comments, we are also finalizing a new 

amendment providing an alternative compliance option in 40 CFR 

60.103a(g) and 40 CFR 60.107a(h) for certain flares. 

Specifically, for refineries located in the South Coast Air 

Quality Management District (SCAQMD), an affected flare subject 

to 40 CFR part 60, subpart Ja may elect to comply with SCAQMD 

Rule 1118 as an alternative to complying with the requirements

for flares in 40 CFR 60.103a(a) through (e) and the associated 

monitoring provisions in 40 CFR 60.107a(e) and (f). Similarly, 

for refineries located in the Bay Area Air Quality Management 

District (BAAQMD), an affected flare subject to subpart Ja may 

elect to comply with both BAAQMD Regulation 12, Rule 11 and 

BAAQMD Regulation 12, Rule 12 as an alternative to complying

with the requirements for flares in 40 CFR 60.103a(a) through 

(e) and the associated monitoring provisions in 40 CFR 

60.107a(e) and (f). We are also finalizing specific provisions 

within the standards for owners or operators (and manufacturers 

of equipment) to submit a request for a determination of 

equivalence for “an alternative means of emission limitation” 
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that will achieve a reduction in emissions at least equivalent 

to the reduction in emissions achieved under any of the final 

subpart Ja design, equipment, work practice or operational 

requirements in accordance with CAA section 111(h). 

For fuel gas combustion devices and sulfur recovery plants, 

we are correcting and clarifying the threshold for a root cause 

analysis and corrective action analysis. The proposed root cause 

analysis threshold for both types of process units was 500 lb SO2

above the emission limit, but the proposed amendments directed 

the owner or operator to compare the SO2 emissions to “the period 

of the exceedance” for fuel gas combustion devices and “the 

entire 24-hour period” for sulfur recovery plants. That language 

meant that if one 12-hour average for a sulfur recovery plant 

was above the emission limit, the owner or operator would have 

compared those emissions to the emissions allowed over an entire 

24 hours to determine if root cause analysis was required. 

However, although a 12-hour average above the emission limit 

clearly means that more SO2 was emitted than allowed by that

emissions limit, it is possible that, since the time periods 

being compared were not analogous, the “allowed emissions” over 

24 hours could be more than the actual emissions that made up 

the one 12-hour average. Upon further consideration, we see no 

reason for the requirements to be different for fuel gas 

combustion devices and sulfur recovery plants. Therefore, we are 
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finalizing an amendment that states that the threshold for a 

root cause analysis and corrective action analysis for both 

sulfur recovery plants and fuel gas combustion devices is 500 lb 

above the emission limit during one or more consecutive periods

of excess emissions4 or any 24-hour period, whichever is shorter. 

This clarifying amendment is needed to ensure that the magnitude 

of the emissions limit exceedance is properly compared to what 

would have been emitted if the emissions were equivalent to the 

emissions limit based on the averaging time allowed for that 

emissions limit.

Finally, we are finalizing the amendments at 40 CFR 

60.108a(c) and (d) mostly as proposed to clarify recordkeeping 

and reporting when a root cause analysis and corrective action 

analysis are required. These clarifications were needed to more 

clearly delineate the differences in the recordkeeping and 

reporting requirements for flares, fuel gas combustion devices

and sulfur recovery plants. The differences between the proposed 

amendments and the final amendments are corrections to be 

consistent with changes to the root cause analysis and 

 4 As noted above, the proposed amendments used the term “period 

of the exceedance” for fuel gas combustion devices. That term 

was intended to have the same meaning as a period of excess 

emissions (or multiple consecutive periods of excess emissions), 

as defined in 40 CFR 60.106a(b) or 40 CFR 60.107a(i)). 

Therefore, the final amendments refer to “one or more 

consecutive periods of excess emissions” rather than “period of 

the exceedance.”
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corrective action analysis requirements already described. We 

are also finalizing 40 CFR 60.108a(c), as proposed, to add 

recordkeeping requirements for the proposed monitoring option 

that is based on periodic manual sampling and analysis to 

determine the total sulfur-to-H2S ratio.

D. What are the final amendments to the definitions in 40 CFR 

part 60, subpart Ja?

We proposed amendments to a number of definitions in 40 CFR 

60.101a. This section describes whether we are finalizing the 

amendments as proposed, finalizing an amendment different than

(but as a logical outgrowth of) what was proposed or not 

finalizing the proposed amendment.

We are finalizing amendments to the definitions of

“flexicoking unit” and “fluid coking unit,” as proposed. 

We are finalizing a definition of “delayed coking unit” 

that is different than the proposed amendments to clarify what 

pieces are included in a delayed coking unit. The final June 

2008 rule did not explicitly describe the pieces of a delayed 

coking unit. We proposed to amend the definition in December 

2008 to specify that a delayed coking unit “consists of the coke 

drums and associated fractionator.” In the course of evaluating 

public comments on the proposed definition, we looked more 

closely at the operation of delayed coking units and determined 

that the fractionators, quench water system and coke cutting 
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equipment are integral to the operation of a delayed coking 

unit. Therefore, we are revising the definition of “delayed 

coking unit” in these final amendments to include “the coke 

drums associated with a single fractionator and the associated 

fractionator; the coke drum cutting water and quench system,

including the jet pump and coker quench water tank; process 

piping and associated equipment such as pumps, valves and 

connectors; and the coke drum blowdown recovery compressor 

system.”

We are finalizing definitions of “forced draft process 

heater,” “natural draft process heater” and “co-fired process 

heater,” which will enable owners and operators to determine the 

appropriate subcategory for each of their process heaters. Based 

on public comments, the final amendments have been revised 

slightly from the proposed definitions to clarify that induced 

draft systems are defined as natural draft process heaters and 

balanced draft systems are defined as forced draft process 

heaters. We are also revising the definition of “co-fired 

process heater” to clarify that this type of process heater does 

not include gas burners that have emergency oil back-up burners.

We are finalizing the definition of “air preheat,” as proposed.

We are finalizing the definitions of “flare gas recovery 

system” and “process upset gas,” as proposed, and we are adding 

a new definition of “flare gas header system.” We are finalizing 
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a revision to the definition of “flare” to refer to the “flare 

gas header system” rather than repeat the components of the 

flare gas header system within the definition of flare. In 

addition, we are clarifying in the definition of “flare” that,

in the case of an interconnected flare gas header system (i.e., 

two or more flare tips share the same flare gas header system or 

are otherwise connected such that they receive flare gas from 

the same source), the “flare” includes each combustion device 

serviced by the interconnected flare gas header system and the 

interconnected flare gas header system.

We are finalizing definitions of “corrective action,” 

“corrective action analysis” and “root cause analysis” with 

minor changes from proposal to update section references and to 

expand upon the types of factors that should be taken into 

consideration for root cause and corrective action analyses. We 

are adding definitions of “purge gas” and “sweep gas” to clarify 

the requirements of the flare minimization plan. We are also 

adding new definitions of “emergency flare,” “cascaded flare 

system,” “non-emergency flare,” “primary flare” and “secondary 

flare” to clarify the types of flares that are and are not 

allowed to use the water seal monitoring alternative for flares. 

We are finalizing the amendments to the definition of 

“petroleum refinery,” as proposed. As we noted in the preamble 

to the proposed amendments, facilities that only produce oil 
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shale or tar sands-derived crude oil for further processing 

using only solvent extraction and/or distillation to recover 

diluent that is then sent to a petroleum refinery are not 

themselves petroleum refineries. Facilities that produce oil 

shale or tar sands-derived crude oil and then upgrade these 

materials and produce refined products would be petroleum 

refineries. Additionally, facilities that produce oil shale or 

tar sands-derived crude oil using any cracking process would be 

considered petroleum refineries. 

We are not finalizing the proposed amendments to “refinery 

process unit” to avoid possible conflicts and confusion caused 

by having different definitions for “refinery process unit” in 

40 CFR part 60, subparts J and Ja, but we are adding a new 

definition of “ancillary equipment” and using this term to 

clarify that the flare modification provisions and standards 

apply to the types of units listed in the proposed definition of 

“refinery process unit.” Specifically, we are adding the 

following definition to subpart Ja:

Ancillary equipment means equipment used in conjunction 

with or that serve a refinery process unit. Ancillary 

equipment includes, but is not limited to, storage tanks, 

product loading operations, wastewater treatment systems, 

steam- or electricity-producing units (including coke 

gasification units), pressure relief valves, pumps, 

sampling vents and continuous analyzer vents.

We are amending the definition of “fuel gas,” as proposed,

to clarify that process units that gasify petroleum coke at a 
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petroleum refinery are producing refinery fuel gases. We also 

proposed to amend the definition to state that gas generated by

process units that calcine petroleum coke into anode grade coke 

is not fuel gas. Based on public comment, we are amending the 

definition to state that gas generated by coke calciners 

producing all premium grade coke (rather than just anode grade 

coke, as proposed) is not fuel gas. Also upon consideration of 

public comments, we are amending the definition of “fuel gas” to 

clarify which vapor streams we intended to exclude. The proposed 

definition indicated that vapors collected and combusted to 

comply with specific standards were not considered fuel gas. The 

final amended definition clarifies that vapors that are 

collected and combusted in a thermal oxidizer or flare installed 

to control emissions from wastewater treatment units other than 

those processing sour water, marine tank vessel loading 

operations and asphalt processing units are not considered fuel 

gas, regardless of whether the action is required by another 

standard.

Finally, we are finalizing several proposed amendments to 

the definition of “sulfur recovery plant” to clarify the intent 

of the definition. We are correcting the spelling of “H2S.” We 

are also clarifying that multiple units recovering sulfur from a 

common source of sour gas produced at a refinery are considered 

one sulfur recovery plant. In addition, we are clarifying that 
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loading facilities downstream of the sulfur pits are not part of 

the sulfur recovery plant (the proposed definition only 

specified secondary sulfur storage vessels).

E. What are the final technical corrections to 40 CFR part 60, 

subpart Ja?

See Table 3 of this preamble for miscellaneous technical 

corrections that we are finalizing throughout 40 CFR part 60, 

subpart Ja. As mentioned previously, some of these technical 

corrections are in response to straightforward issues raised by 

Industry Petitioners in their August 21, 2008, supplement to 

their original petition for reconsideration (Docket Item No. 

EPA-HQ-OAR-2007-0011-0246). Other technical corrections are 

needed to correct typographical errors and to correct equation 

and paragraph designations.

Table 3. Technical Corrections to 40 CFR part 60, Subpart Ja

Section Technical correction and reason

60.102a(f)(1)(ii) Replace “300 ppm by volume of reduced 

sulfur compounds and 10 ppm by volume of 

hydrogen sulfide (HS2), each calculated as 

ppm SO2 by volume (dry basis) at zero 

percent excess air” with “300 ppmv of 

reduced sulfur compounds and 10 ppmv of 

H2S, each calculated as ppmv SO2 (dry basis) 

at 0-percent excess air” for consistency of 

units and to correct a typographical error.

60.104a(d)(4)(ii) Redesignate Equation 3 as Equation 5 to 

provide for the addition of new Equations 3 

and 4.

60.104a(d)(4)(iii) Redesignate Equation 4 as Equation 6 to 

provide for the addition of new Equations 3 

and 4.
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60.104a(d)(4)(v) Redesignate Equation 5 as Equation 7 to 

provide for the addition of new Equations 3 

and 4.

60.104a(d)(8) Redesignate Equation 6 as Equation 8 to 

provide for the addition of new Equations 3 

and 4.

60.104a(f)(3) Redesignate Equation 7 as Equation 9 to 

provide for the addition of new Equations 3 

and 4.

Replace “hourly” with “3-hour” in the 

definition of the new Equation 9 variable 

“Opacity limit” and replace “source test 

runs” with “source test” in the definition 

of the new Equation 9 variable “Opacityst” 

to clarify the information required for new 

Equation 9.

60.104a(h)(5)(iv) Redesignate the reference to Equation 6 as 

a reference to Equation 8 to provide for 

the addition of new Equations 3 and 4.

60.105a(b) Replace “in §60.102a(b)(1) shall comply 

with the requirements in paragraphs (b)(1) 

through (3) of this section” with “in 

§60.102a(b)(1) that uses a control device 

other than fabric filter or cyclone shall 

comply with the requirements in paragraphs 

(b)(1) and (2) of this section” to clarify 

applicability of the requirements and 

remove the reference to a nonexistent 

paragraph.

60.105a(b)(1) Replace “according to the requirements in 

paragraph (b)(1)(i) through (iii) of this 

section” with “according to the applicable 

requirements in paragraphs (b)(1)(i) 

through (v) of this section” to clarify and 

correct paragraph reference.

60.105a(b)(1)(ii)(A) Replace “alterative” with “alternative” to 

correct the use of an incorrect word.

60.105a(i)(5) Replace “Except as provided in paragraph 

(i)(7) of this section, all rolling 7-day 

periods” with “All rolling 7-day periods” 

to remove the reference to a nonexistent 

paragraph.
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60.107a(a)(2)(i) Replace “320 ppmv H2S” with “300 ppmv H2S” 

to make the span value for a H2S monitor 

consistent with the span value in 40 CFR 

part 60, subpart J.

60.108a(d)(5) Replace “the information described in 

paragraph (e)(6) of this section” with “the 

information described in paragraph (c)(6) 

of this section” to correct the reference 

to a nonexistent paragraph.

IV. Summary of Significant Comments and Responses

As previously noted, we received a total of 22 comments 

addressing the proposed amendments. These comments were received 

from refineries, industry trade associations, consultants, state 

and local environmental and public health agencies, 

environmental groups and members of the public. Brief summaries 

of the major comments and our complete responses to those 

comments are included in the following sections. A summary of 

the remainder of the comments received during the comment period

and responses thereto, as well as more detailed summaries of the 

comments addressed in this preamble, can be found in Standards 

of Performance for Petroleum Refineries: Background Information 

for Final Amendments - Summary of Public Comments and Responses,

which is included in the docket for the final amendments (Docket 

ID No. EPA–OAR–HQ–2007–0011). The docket also contains further 

details on all the analyses summarized in the responses below.

In responding to the public comments, we re-evaluated the 

cost and emission reduction impact estimates of some of the 
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control options and re-evaluated the related BSER

determinations. In our BSER determinations, we took all relevant 

factors into account consistent with other agency decisions.

A. Process Heaters

Comment: Commenters stated that new forced draft process 

heaters cannot meet the proposed emissions limit of 40 ppmv NOX, 

so the EPA should revise the emissions limits for new forced 

draft process heaters to be the same as the limit for modified 

and reconstructed forced draft process heaters (60 ppmv NOX). One 

commenter referenced a general technical document written by a 

process heater burner manufacturer regarding a new forced draft 

process heater at their refinery to support the assertion that 

new process heaters cannot meet the proposed limit without 

selective catalytic reduction or other add-on controls. Another 

commenter also requested higher emissions limits for new forced 

draft process heaters with air preheat.

Response: The commenters provided only limited and 

theoretical data to support their argument that new forced draft 

process heaters cannot meet the 40 ppmv (or 0.040 lb/MMBtu) NOX

emissions limit. Specifically, the John Zink white paper cited 

by the commenter (submitted as an attachment to Docket Item No. 

EPA-HQ-OAR-2007-0011-0296) stated only that the 40 ppmv 

emissions limit could not be “guaranteed” for a new forced draft 

process heater, based on the design conditions, which included 
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air preheat. Actual NOX performance data for that commenter’s new 

forced draft process heaters are not available, as those 

particular process heaters are not yet operational. As such, the 

actual performance of these forced draft process heaters is 

still in question. However, we acknowledge that we only have 

data for one new forced draft process heater without air preheat 

that is currently operating that could meet a 40 ppmv NOX

emissions limit on a 365-day average. We conducted additional 

data evaluations to determine appropriate limits and averaging 

times for all process heaters at normal operating conditions 

while considering this and other public comments we received. As 

part of the data analysis effort, we obtained a year’s worth of 

hourly CEMS data for the new forced draft process heater without 

air preheat capable of meeting 40 ppmv on a 365-day average. As 

discussed later in this section, our analysis of the additional 

data that we obtained following the proposal supported revising 

all NOX emissions limits to be on a 30-day average basis. The 

data indicate that the 30-day averages for the new forced draft 

process heater without air preheat capable of meeting 40 ppmv on 

a 365-day average exceeded 40 ppmv 15 percent of the time, but 

none of the 30-day averages exceeded 60 ppmv NOX.

Consequently, we are raising the NOX emissions limit (while 

concurrently reducing the averaging time) for all new forced 

draft process heaters to be equivalent to the emissions limit 
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for modified and reconstructed forced draft process heaters 

(i.e., 60 ppmv or 0.060 lb/MMBtu with a 30-day averaging 

period). Furthermore, based on the information provided by the 

commenters, as well as the available performance data for 

existing forced draft process heaters with air preheat that have 

been retrofitted with ultra-low NOX burners, we also conclude 

that the 60 ppmv (or 0.060 lb/MMBtu) on a 30-day rolling average 

basis adequately accommodates forced draft process heaters that 

use air preheat. Based on our review of CEMS data for new and 

retrofitted forced draft process heaters, we conclude that 60 

ppmv (or 0.060 lb/MMBtu) on a 30-day rolling average basis is 

BSER for new, reconstructed or modified forced draft process 

heaters. (For additional details, see Revised NOX Impact 

Estimates for Process Heaters, in Docket ID No. EPA-HQ-OAR-2007-

0011.)

Comment: Commenters asserted that the heating value-based 

emissions limits (i.e., the limits in units of lb/MMBtu) should 

be numerically equivalent to the concentration-based emissions 

limits (e.g., 40 ppmv should be equivalent to 0.040 lb/MMBtu 

rather than 0.035 lb/MMBtu).

Response: In August 2008, Industry Petitioners provided 

the EPA with suggestions for revising the process heater 

standards (Docket Item No. EPA-HQ-OAR-2007-0011-0257). One of 

their recommendations was to include emissions limits based on 
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heating value (lb/MMBtu) to account for hydrogen content 

variations in the fuel gas. They suggested that, on an annual 

basis, most natural draft process heaters could meet 0.035 

lb/MMBtu and all other process heaters could meet 0.055 

lb/MMBtu. We evaluated these suggested emissions limits and 

determined that they were reasonably equivalent to the 

concentration-based limits we were proposing. We also requested 

comment on their use and their equivalency, as described in the 

preamble to the proposed amendments (see 73 FR 78527). Industry 

commenters now assert that the emissions limit numerically 

equivalent to the 40 ppmv concentration limit is 0.040 lb/MMBtu 

and the emissions limit numerically equivalent to the 60 ppmv 

concentration limit is 0.060 lb/MMBtu. 

We note that, as discussed in the preamble to the proposed 

amendments, the exact conversion from ppmv to lb/MMBtu depends 

on the hydrogen content of the fuel gas. However, our 

calculations generally support the more direct numerical 

conversion suggested by commenters over the typical range of 

hydrogen concentrations expected in the fuel gas (see Revised NOX

Impact Estimates for Process Heaters, in Docket ID No. EPA-HQOAR-2007-0011). Therefore, we are finalizing heating value-based 

emissions limits of 0.040 lb/MMBtu and 0.060 lb/MMBtu for 

natural draft process heaters and forced draft process heaters, 
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respectively, based on direct numerical conversions from the 

concentration-based emissions limits.

We are also clarifying that the owner or operator must 

demonstrate that the process heater is in compliance with either 

the applicable concentration-based or heating value-based NOX

limit. The heating value-based NOX emission rate is calculated 

using the oxygen (O2)-based F factor, which is the ratio of 

combustion gas volume to heat input. Ongoing compliance with 

this NOX emissions limit is determined using a NOX CEMS and at 

least daily sampling of fuel gas heat content or composition to 

calculate a daily average heating value-based emissions rate, 

which is subsequently used to determine the 30-day average.

Specifically, if the F factor is determined at least daily, 

the owner or operator may elect to calculate both a 30-day 

rolling average NOX concentration (ppmv, dry basis, corrected to 

0-percent excess air) and a 30-day rolling average NOX emission 

factor (in lb/MMBtu) and demonstrate that the process heater is 

in compliance with either one of these limits. For most fuel gas 

systems, the alternative emissions limits are expected to be 

identical; however, there may be instances where a process 

heater may be complying with one of the emissions limits and not 

the other. For example, a process heater combusting fuel gas 

with very high hydrogen content may have an average NOX

concentration above the 60 ppmv limit, but below the 0.060 
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lb/MMBtu limit, largely due to the concentration limit being 

determined on a dry basis (and understanding that the combustion 

of hydrogen produces only water and not carbon dioxide). 

Provided that the appropriate monitoring is conducted, an 

affected source would only be out of compliance if it exceeds 

both the concentration-based limit and the heating value-based 

limit at the same time. However, to have the option to determine 

compliance with the alternative heating value-based emissions 

limit, the refinery owner or operator must, at least daily, 

determine the F factor (dry basis) for the fuel gas according to 

the monitoring provisions in 40 CFR 60.107a(d). If the F factor 

is not determined at least daily, the heating value-based 

alternative cannot be used. Generally fuel gas heating value is 

important to the overall operation of refinery boilers and 

process heaters; as such, refiners maintain their fuel gas 

within an operating range that they need to fire these sources, 

often by mixing with natural gas, etc., so we anticipate that 

most, if not all, refiners will already have this information 

available on a daily basis.

Comment: Several commenters addressed the need for the rule 

to address turndown, which is a period of time when process 

heaters are firing below capacity. Commenters stated that during 

these periods, the NOX concentrations will likely be above the 

emissions limits, but the mass of NOX emissions is no greater 
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than when the heater is operating at full capacity because the 

lower firing rate results in a lower exhaust flow rate. 

Commenters noted that turndown conditions could exist for 

extended periods, so special provisions are needed for these 

conditions. Commenters requested a mass-based emission rate 

(lb/MMBtu limit multiplied by the heater’s rated capacity) that 

would apply when the process heater is firing at less than full 

capacity (some commenters suggested 50 percent of capacity; one 

commenter suggested 70-percent capacity as a cutoff). One 

commenter also noted that process heaters must often operate at 

higher O2 levels during turndown and requested that the proposed 

maximum O2 operating limit not apply when small furnaces that are 

not required to install CEMS are firing at less than full 

capacity.

Response: In our proposed amendments, we provided a longer 

averaging time (365-day average) so that short periods of turndown would not significantly affect the overall performance of 

the unit. However, according to the commenters, the longer 

averaging time does not adequately address turndown conditions. 

Therefore, we re-evaluated the available data, including our 

existing data and additional data provided by the industry, to 

determine the appropriate emissions limits during different 

types of operation, including turndown. The additional data 

provided by Industry and our evaluation of those data are 
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included in the docket for the final amendments (Docket ID No. 

EPA–OAR–HQ–2007–0011). Based on our analysis of the data 

(described in greater detail in the next paragraph), we 

concluded that a 30-day averaging period is appropriate for the 

NOX emission limits under most operating scenarios.

Upon examination of all available CEMS data, we determined 

that, for periods of normal operation (i.e., firing at 50 

percent or more of design capacity), the proposed NOX emissions 

limits of 40 and 60 ppmv were not achievable for all process 

heaters using a 24-hour averaging period (the averaging period 

included in the final June 2008 rule). From the available data, 

short-term fluctuations in the NOX concentrations of process 

heaters using ultra-low NOX burners caused them to exceed a 24-

hour average limit somewhat frequently, but a 30-day average 

provided adequate time to average out the short-term 

fluctuations. We note that a few of the process heaters operated 

at relatively high excess O2 concentrations at normal conditions

(i.e., at exhaust O2 concentrations of 6 percent or more). These 

units had periods of excess emissions above the 30-day average 

emission limits, but we rejected the performance of these 

process heaters as BSER because of the high exhaust O2

concentrations for these units during normal (i.e., nonturndown) firing rates. That is, these process heaters were not 

being operated optimally for reducing NOX emissions. Furthermore, 
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when these process heaters were operated at the lower range of 

exhaust concentrations for the unit (although generally higher 

than what would be considered optimal excess O2 concentrations 

for reducing NOX emissions), the process heater could meet the

applicable 40 or 60 ppmv emissions limit on a 30-day averaging 

period. Based on our review of CEMS data for process heaters 

with ultra-low NOX burners that operated at excess O2

concentrations less than 6 percent (i.e., operated in a manner 

consistent with proper low NOX burner operation), all such 

process heaters could comply with the final NOX emissions limits 

on a 30-day average basis. Consequently, we revised the basic 

emissions limits to be on a 30-day average.

As described previously in this section, we conclude that 

the applicable 40 or 60 ppmv emissions limit on a 30-day 

averaging period is achievable for process heaters during 

periods of normal operation. Our next step was to evaluate the 

achievability of the emissions limits during turndown conditions 

and alternative approaches for establishing emissions 

limitations where necessary. The following paragraphs describe 

our analysis of the data, including our evaluation of 

alternative methods for accommodating turndown conditions and 

our rationale for providing the site-specific alternative for 

extended turndown conditions.
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There were very limited CEMS data available for process 

heaters operating under turndown conditions (i.e., firing below 

50 percent of design capacity). However, two general trends were 

observed in the CEMS data that were available: (1) typical 

exhaust O2 concentrations increase at lower firing rates; and (2)

exhaust NOX concentrations (corrected to 0-percent excess O2) 

increase with increasing O2 concentration (regardless of firing

rates). These data, along with the need to operate the process 

heater at higher O2 concentrations during low firing rates to 

maintain flame stability, suggest that an alternative NOX

emissions limit could, in some instances, be needed to address 

extended turndown conditions (turndown events lasting a majority 

of the 30-day averaging time). As such, we considered 

alternative compliance options to address turndown conditions.

One alternative compliance option considered to address 

turndown was a mass-based NOX emissions limit that would be 

equivalent to the mass of NOX emitted from a unit meeting the 

0.040 (or 0.060) lb/MMBtu limit while firing at 50 percent of 

capacity, as suggested by commenters. However, for most units 

for which CEMS data are available, the alternative mass-based 

emissions limit did not improve the ability of the process 

heater to meet the emissions limit. We note that most of the 

process heaters were able to meet the applicable concentrationbased emissions limit (40/60 ppmv) or the heating value-based 
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(0.040/0.060 lb/MMBtu) emissions limit during turndown. 

Therefore, the issue appears to be limited to a few of the 

process heaters that must operate at relatively high excess O2

concentrations during turndown conditions. For these units, the 

alternative mass-based emissions limit that we were considering 

rarely, if ever, provided a means for these units to comply with 

the performance standard. 

We understand that technology providers recommend operating 

process heaters that are turned down at higher excess O2

concentrations to improve flame stability and ensure safe 

operation of the process heater; however, based on the 

information provided by the technology providers, there is still 

an optimal excess O2 concentration at which flame stability is 

achieved while minimizing NOX formation. That is, even when a 

process heater is operating at less than 50 percent design 

capacity, excess O2 concentrations should still be controlled to 

minimize NOX formation within the safe operating constraints to 

maintain flame stability. We do not have specific data on 

process heaters that are near, but below, the concentration 

emissions limits when firing above 50-percent capacity, but 

cannot meet the concentration limit when firing below 50-percent 

capacity, so we have no data that show that process heaters 

operating at less than 50-percent design capacity and 

controlling excess O2 concentrations cannot meet the emissions 
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limits. However, we acknowledge that the correlations with 

firing rates and O2 and/or NOX concentrations and the need for 

higher O2 concentrations to maintain flame stability generally 

support the commenter’s argument that a few marginally compliant 

process heaters will have difficulty meeting the basic emissions 

limit when the unit is turned down. As such, we acknowledge that 

there may be periods of turndown in which a process heater is 

operating as recommended, but may be unable to meet the 

concentration or heating value-based emissions limits in the 

final rule, especially when the unit is operated at turndown for 

extended periods (e.g., for 20 days or more compared to the 30-

day averaging time). As the need for an alternative limit 

appears to be limited to a few process heaters and the optimal O2

concentration is expected to vary, based on fuel gas 

composition, we determined that a site-specific emissions limit 

was the best approach to account for these extended turndown 

conditions. As such, the final rule provides owners and 

operators that have a process heater operating in turndown for 

an extended period of time the option of developing a sitespecific emissions limit that would apply to those operating 

conditions and requesting approval from the Administrator to use 

that limit.

For process heaters between 40 and 100 MMBtu/hr capacity 

that do not install a NOX CEMS, turndown is also expected to be 
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an issue with respect to achieving the O2 operating limit. As 

described above, higher O2 concentrations are generally needed to 

maintain flame stability at low firing rates. To address 

potential turndown compliance issues with the O2 operating limit, 

we have provided an allowance for process heater owners or 

operators to develop an O2 operating curve to provide different 

O2 operating limits based on the firing rate of the process 

heater. If a single O2 operating limit is established, it must be 

determined when the process heater is being fired at 70 percent 

or more of capacity (i.e., far from turndown conditions). For 

process heaters that routinely operate at less than 50 percent 

of design capacity and require additional O2 to maintain flame 

stability, a separate O2 operating limit should be established 

for turndown by conducting a second performance test while the 

unit is operating at less than 50 percent of capacity. 

Additional performance tests can be conducted to develop O2

operating limits for additional operating ranges.

Comment: Several commenters requested that the EPA revise 

the emissions limits for co-fired process heaters or remove the 

limits for co-fired process heaters from this rulemaking and 

address them at a later date due to lack of sufficient data to 

set an achievable emissions limit. One commenter provided a 

white paper to support higher emissions limits. Commenters also 

asserted that the averaging time for the weighted average 
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emission rate should be extended to 365 days. One commenter 

noted that the notation “ENOx,hour” in Equation 3 was confusing 

since the purpose of the equation was to determine the daily 

emission rate. 

Response: The final June 2008 rule included only one 

emissions limit for all co-fired process heaters, and Industry 

Petitioners asserted that differences in the configuration and 

operation of different types of process heaters warranted 

different emissions limits. The proposed amendments introduced 

two specific emissions limits for co-fired process heaters, one 

based on vendor guarantees for the burners and one based on an 

average NOX concentration for a combination of fuel gas and fuel 

oil. We note that, for purposes of this rule, a co-fired process 

heater is defined as a process heater that employs burners that 

are designed to be supplied by both gaseous and liquid fuels. In 

other words, co-fired process heaters are designed to routinely 

fire both oil and gas in the same burner. These do not include 

burners that are designed to burn gas, but have supplemental oil 

firing capability that is not routinely used (i.e., emergency 

oil back-up).

To respond to the comments requesting higher emissions 

limits for co-fired process heaters, we reviewed the white paper 

provided by one commenter (submitted as an attachment to Docket 

Item No. EPA-HQ-OAR-2007-0011-0308), as well as additional 
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burner emissions test data provided by another commenter5

(conducted under well-controlled conditions using best available 

ultra-low NOX burner technologies at the manufacturer’s testing 

facility). This information indicates that, for co-fired natural 

draft process heaters, a daily average emissions limit 

calculated based on a limit of 0.06 lb/MMBtu for the gas portion 

of the firing and 0.35 lb/MMBtu for the oil portion of the 

firing is achievable. Similarly, the information indicates that,

for co-fired forced draft process heaters, a daily average 

emissions limit calculated based on a limit of 0.11 lb/MMBtu for 

the gas portion of the firing and 0.40 lb/MMBtu for the oil 

portion of the firing is achievable. As noted above, these 

values are based on burner performance tests, which are

considered a better source of information than the vendor 

guarantees that were relied upon to develop the proposed 

emissions limit. Therefore, we are revising the NOX emissions 

limits for co-fired process heaters to those described above. We 

note that we have revised the concentration-based NOX emissions 

limits to be on a 30-day average basis (same as the limits for 

gas-fired process heaters). We have also revised the 

nomenclature of the daily average emissions limit in Equations 3 

 5 The commenter providing this data asserted that it is CBI. We 

will follow our CBI regulations in 40 CFR part 2 in handling 

this data. The data has been placed in the docket, but is not 

publicly available. 
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and 4 (proposed Equation 3) to be clear that we intend the limit 

to be determined on a daily basis rather than on an hourly 

basis.

We also note that the burner performance tests were 

conducted in a controlled environment at the burner 

manufacturer’s full-scale facilities. While it is incumbent on 

the owner or operator of an affected process heater to control 

certain operating parameters, such as excess O2 concentrations, 

to the extent possible, we recognize that the performance limits 

in the final amendments are based on limited data, none of which 

are direct test data for a co-fired process heater operated at a 

petroleum refinery. We conclude that the low-NOX burner 

technologies exist, are demonstrated and are cost effective for 

co-fired process heaters and they are, therefore, BSER for cofired process heaters. However, as the performance limits are 

based on limited operational data, we also conclude that it is 

reasonable to provide an alternative, site-specific limit in the 

event that factors outside the influence of the burner design 

and operation (such as nitrogen content in the fuel oil) 

suggests the emission limits in the final rule are inappropriate 

for a specific application. Consequently, co-fired process 

heaters that cannot meet the limits specified above, can request 

approval for a site-specific emissions limit, as allowed above,
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for process heaters that operate for extended periods under 

turndown. 

B. Flares

Comment: Several commenters asserted that routine 

connections to a flare should not be considered modifications of 

the flare because they do not change the maximum physical 

capacity of the flare and do not generally increase emissions. 

One commenter asserted that the Part 60 Subpart A General 

Provisions in 40 CFR 60.14 can and should apply to flares, so a 

special modification provision for flares in 40 CFR part 60, 

subpart Ja is unnecessary. Commenters noted that some 

connections to the flare have the primary purpose of reducing 

emissions, which has been excluded under 40 CFR 60.14(e)(5), a 

paragraph that is not limited to pollutants “to which the 

standard is applicable.” One commenter noted that a single 

project may remove some connections and add others such that the 

net emissions could actually be reduced. Another commenter 

asserted that an increase in flow should not be considered a 

modification because flow is not a regulated pollutant.

Instead, commenters asserted that the modification 

provision for a flare should focus on physical and operational 

changes that increase emissions from the flare. One commenter 

suggested that the EPA should focus the flare modification 

provision on connections that provide a primary/routine flow 
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from a process unit to the flare. Other commenters suggested 

that the flare modification provision should be focused on 

volatile organic compounds (VOC) and SO2 emissions and should 

only include connections that result in a net increase of those 

pollutants emitted “during normal operations” and connections 

that cause an increase in the total volume of gas containing VOC 

or sulfur compounds under standard conditions that could reach 

the flare.

Response: The agency made a conscious decision to 

promulgate a separate provision for a flare modification in 40 

CFR part 60, subpart Ja (see 40 CFR 60.14(f)) because flares are 

operated differently from other refinery process units, making 

it difficult to apply the modification provision in the General 

Provisions (40 CFR 60.14) to them. The physical capacity of a 

flare is based on the amount of gas potentially discharged to a 

flare as a result of emergency relief. Refiners frequently make 

connections to existing flares that result in emissions 

increases at the flares, but may never approach the physical 

capacity of the flare system. Contrary to commenters’ 

assertions, the flare modification provision in 40 CFR 

60.100a(c) does meet the statutory definition of “modification” 

in CAA section 111(a)(4), which is “any physical change in, or 

change in the method of operation of, a stationary source which 

increases the amount of any air pollutant emitted by such source 
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or which results in the emission of any air pollutant not 

previously emitted.” It is axiomatic that the connections to the 

flare described in 40 CFR 60.100a(c) qualify as physical or 

operational changes to the flare. Additionally, we explained in 

the proposed rule how these connections also resulted in 

emissions increases from the flare (see 73 FR 78529). Thus, 

these types of new connections of refinery process units

(including ancillary equipment) and fuel gas systems to the 

flare qualify as a “modification” of the flare and trigger 

subpart Ja applicability for the flare.

Those connections we identified that do not increase 

emissions from the flare were specifically excluded from 

triggering 40 CFR part 60, subpart Ja applicability under this 

same provision (see 40 CFR 60.100a(c)(1)). Specifically, we 

proposed on December 22, 2008, that the following types of 

connections to a flare would not be considered a modification of 

the flare: (1) connections made to install monitoring systems to 

the flares; (2) connections made to install a flare gas recovery 

system; (3) connections made to replace or upgrade existing 

pressure relief or safety valves, provided the new pressure 

relief or safety valve has a set point opening pressure no lower 

and an internal diameter no greater than the existing equipment 

being replaced or upgraded; and (4) replacing piping or moving 

an existing connection from a refinery process unit to a new 
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location in the same flare, provided the new pipe diameter is 

less than or equal to the diameter of the pipe/connection being

replaced/moved. While we agree that there may be other 

connections to a flare that would not result in an emissions 

increase from the flare (see response to the next comment for 

specific details), we disagree with the commenters that the 

flare modification provision should be further limited beyond 

what is already provided in the provision.

We disagree with commenters that we must consider the “net” 

emissions from the process unit and the flare when determining 

whether a flare is modified. The affected facility is the flare 

and does not include the process units that are tied into the 

flare header system. See Asarco v. EPA, 578 F.2d 319, 325(D.C. 

Cir. 1978) (holding that emission increases had to be determined 

based on emissions from the affected facility). We also disagree 

that a modification determination should be limited to emissions 

increases of VOC or SO2. Flares are known to emit VOC, SO2, 

carbon monoxide (CO), PM and NOX, as well as other air 

pollutants, all of which are relevant when determining whether a 

flare has been modified. See CAA section 111(a)(4). That is, we 

consider the standards for flares to be emission standards for 

VOC, SO2, CO, PM and NOX. See, generally, 73 FR 35838, 35842, 

35854-35856 (June 24, 2008); 73 FR 78522, 78533 (December 22, 

2008), as well as Table 3 of this preamble. Using the flare to 
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control VOC emissions at other refinery process units will 

increase CO, PM and NOX emissions from the flare and are,

therefore, considered modifications of the flare, even if there 

is a net reduction in VOC emissions at the refinery.

In evaluating whether a flare has been modified, we

consider increases in flow to the flare to be directly 

indicative of increased emissions from the flare. While we agree 

that “flow” is not a pollutant, we evaluated flow limits as a 

means to reduce SO2, VOC, CO, NOX and other emissions from the 

flare. The emissions from the flare are very difficult, if not 

impossible, to measure accurately, but flow to the flare can be 

measured, and the flow to the flare generates SO2, VOC, CO, PM, 

NOX and other emissions. Therefore, a physical or operational 

change to a flare that causes an increase of flow to the flare 

will increase emissions of at least one of these pollutants and 

is considered a modification of the flare.

Comment: Many commenters responded to the EPA’s request for 

comment on types of connections that do not result in an 

increase in emissions from a flare. The commenters suggested 

numerous specific connections that should not be considered 

modifications, including: 

(1) Connections made to upgrade or enhance (not just to 

install) a flare gas recovery system;

(2) connections made for flare gas sulfur removal; 
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(3) connections made to install back-up equipment;

(4) flare interconnects;

(5) all emergency pressure relief valve connections from 

existing equipment;

(6) connections of monitoring system purge gases and 

analyzer exhausts or closed vent sampling systems; 

(7) purge and clearing vapors, block and bleeder vents and 

other uncombusted vapors where the flare is the control device; 

(8) connections made to comply with other federal, state or 

local rules where the flare is the control device; 

(9) connections of “unregulated gases” such as hydrogen, 

nitrogen, ammonia, other non-hydrocarbon gases or natural gas or 

any connection that is not fuel gas; 

(10) new connections upstream of an existing flare gas 

recovery system, provided the new connections do not compromise 

or exceed the flare gas recovery system’s capacity; 

(11) any new, moved or replaced piping or pressure relief 

valve connections that do not result in a net increase in 

emissions from the flare, regardless of piping or pressure 

relief valve size; 

(12) vapors from tanks used to store sweet or treated 

products; 

(13) temporary connections for purging existing equipment,

as these are essentially “existing” connections; and 
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(14) connections of safety instrumentation systems (SIS) 

described under Occupational Safety and Health Administration 

(OSHA) process safety standards at 29 CFR 1910.119, the EPA’s 

risk management program at 49 CFR 68 and/or American National 

Standards Institute (ANSI)/International Society of Automation 

(ISA)-84.00.01-2004. 

Response: We carefully reviewed the commenters’ suggested 

changes to the flare modification provision to determine whether 

there are additional connections that should not be considered 

modifications to the flare. We agree that the first four

connections in the commenters’ list should not be considered 

modifications of a flare. Projects to upgrade or enhance 

components of a flare gas recovery system (e.g., addition of 

compressors or recycle lines) will improve the operation of the 

flare gas recovery system, and connections to these additional 

components will not result in increased emissions. Connections 

made for removal of sulfur from flare gas (Item 2 above) will

generally result in a slight decrease in volumetric flow and a 

large decrease in emissions of SO2. Connections made to install 

back-up or redundant equipment (Item 3 above), such as a back-up 

compressor, will result in fewer released emissions if there is 

a malfunction in the main equipment.

The request to exclude flare interconnections (Item 4 

above) is a complicated issue because interconnecting two 
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separate flares alters what we consider to be the affected 

facility. The definition of “flare” specifically includes the 

flare gas header system as part of the flare. Prior to 

interconnecting the flares, presumably each flare header system 

is independent, and there would be two separate “flares,” each 

of which could potentially be an affected facility subject to 40 

CFR part 60, subpart Ja. However, because the flare includes the 

flare header system, we consider that an interconnected flare 

system is a single affected facility, and we have amended the 

definition of “flare” for clarity. We agree that 

interconnections between flares will not alter the cumulative 

amount of gas being flared (i.e., interconnecting two flares 

does not result in an emissions increase relative to the two 

single flares prior to interconnection). We also see cases where

the emissions from a single flare tip will likely be reduced due 

to the flare interconnect. For example, when a large release 

event occurs, this gas will now flow to both of the 

interconnected flares rather than a single flare. The maximum 

emission rate for the original single flare actually decreases, 

while the combined emissions from both flares is the same

quantity as prior to the interconnection. Considering this, we 

agree that the interconnection of two flares does not 

necessarily result in a modification of the flare and we have 
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specifically excluded flare interconnections from the 

modification provisions. 

However, we also clarify in this response that when a flare 

that is subject to 40 CFR part 60, subpart Ja is interconnected 

with a flare that is not subject to subpart Ja, then the 

resulting interconnected flare is subject to subpart Ja. That 

is, the only case in which an interconnection between two (or 

more) flares results in a combined, interconnected flare that is 

not subject to subpart Ja is when none of the original 

individual flares were subject to subpart Ja. Additionally, we 

note that if a new connection is made to the interconnected 

flare, then the flare (including each individual flare tip 

within the interconnected flare header system) is modified and

becomes an affected facility subject to subpart Ja. 

While we agree that connections that do not increase the 

emissions from the flare should not trigger a modification, we 

disagree with the commenter that their other suggested 

connections do not increase the flare’s emissions at the time 

gases are discharged via the new connection. Each of the 

commenters’ suggestions is discussed in the following 

paragraphs.

We previously proposed an exemption for emergency pressure 

relief valve connections from existing equipment (Item 5 above) 

if they replace or upgrade existing equipment and do not 
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increase the instantaneous release rate to the flare (i.e., the 

new pressure relief valve has a pressure set point and diameter 

no greater than the equipment being replaced). As stated 

previously in this preamble, we are finalizing that amendment,

as proposed. However, new connections, even if they are made to 

“existing equipment,” will result in an increase in flow to the 

flare during periods of process upset that cause the pressure 

relief valve to open.

Connections of monitoring system purge gases and analyzer 

exhausts or closed vent sampling systems (Item 6 above) will 

increase the emissions from the flare. Similarly, connections of 

purge and clearing vapors and block and bleeder vents (Item 7 

above), also trigger a modification of the flare because the 

increase of gas flow to the flare will increase the emissions 

from the flare. 

We recognize that connections to a flare may be made to 

comply with other federal, state or local rules where the flare 

is an emissions control device (Item 8 above). In fact, nearly 

all flares could be considered “control devices.” We agree that 

using a flare as an emissions control device is preferable to 

venting the process unit to the atmosphere. However, while using 

the flare as an emissions control device does decrease emissions 

from the process unit being controlled, the increase of gas flow 

to the flare will increase the emissions from the flare. 
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Therefore, a connection from a process unit to a flare for use 

as an emissions control device results in a modification of that 

flare.

Comments suggesting that connections of “unregulated gases” 

such as hydrogen, nitrogen, ammonia, other non-hydrocarbon gases 

or natural gas or connections that are not “fuel gas,” should 

not be considered a modification of the flare (Item 9 above) are 

in conflict with the statutory definition of “modification.” 

Each of the streams mentioned by the commenter, when directed to 

a flare, will increase emissions of at least one pollutant

(either PM, CO or NOX) from the flare (all of which the standard 

is intended to reduce). That is, we reiterate that we consider 

the standards for flares to be emission standards for VOC, SO2, 

CO, PM and NOX. As such, we do not agree that the types of gas 

streams suggested by the commenters should be exempt from the 

modification determination.

New connections upstream of an existing flare gas recovery 

system (Item 10 above) will increase the likelihood of an event 

that would cause an exceedance of the flare gas recovery 

system’s capacity (even if the new connections “do not exceed 

the flare gas recovery system’s capacity” under normal 

conditions), and the amount of gases sent to the flare would 

increase as a result of such an event, thereby increasing the 

emissions from the flare. 
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We reiterate that we proposed an exemption for any moved or 

replaced piping or pressure relief valve connections of the same 

size. However, we disagree with the commenter’s suggestion that

any “new, moved, or replaced piping or pressure relief valve 

connections that do not result in a net increase in emissions 

from the flare regardless of piping or pressure relief valve 

size” should be exempted (Item 11 above). The premise of the 

suggested amendment is that new or larger connections somehow 

will not increase emissions from the flare. We have discussed 

new connections previously, so we will concentrate on the 

“regardless of piping or pressure relief valve size” comment in 

this paragraph. First, the size of the pressure relief valve or

piping does correlate to the discharge rate to the flare, with 

larger pressure relief valves or larger diameter piping allowing 

higher discharge rates to the flare at a given pressure. In 

fact, larger pressure relief valves and larger diameter pipes

are specifically designed to allow higher flow rates to the 

flare. Second, higher flow rates will lead to higher emission 

rates. For a pressure relief event that occurs for several 

hours, the flow rate to the flare during the first hour of 

relief using the larger pressure relief valve or larger diameter 

piping will be larger than the flow rate experienced using the 

smaller pressure relief valve or smaller diameter piping and 

will result in higher emissions from the flare. Therefore, we 
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reject the notion that larger diameter pipes and larger pressure 

relief valves do not increase the emissions rate from the flare 

during a release event. We are finalizing the proposed 

exemptions for moved or replaced piping or pressure relief 

valves with the size and design restrictions for the new piping 

or pressure relief valves as proposed on December 22, 2008.

Commenters suggested that connections of vapors from tanks 

used to store sweet or treated products (Item 12 above) should 

not be modifications because those gas streams have less than 

162 ppmv H2S. We reiterate that SO2 is not the only pollutant 

emitted from flares and that the additional flow of sweet gases 

will increase the emissions of at least one pollutant from the 

flare, so we are not exempting these types of connections to the 

flare from the 40 CFR part 60, subpart Ja flare modification

provision. However, we have amended the sulfur monitoring 

requirements for flares to exempt vapors from tanks used to 

store sweet or treated products from the flare sulfur monitoring 

requirements. This monitoring exemption is justified because it 

is not needed for the purposes of a root cause analysis or other 

compliance purpose. For these sweet vapors, the flow rate root 

cause analysis threshold will be exceeded well before the SO2

root cause analysis threshold.

We carefully considered temporary connections for purging 

existing equipment (Item 13 above), but we failed to see how 
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these temporary connections are essentially “existing 

connections.” According to the commenters, “maintenance gases 

have been routed in some form or other to the flare for years, 

and the temporary tie-in to accomplish that is not a change and 

is not an increase in emissions when viewed from a before and 

after perspective.” If the connections already exist, then 

opening an existing valve to allow for this type of purging 

would not trigger a flare modification. If the connection is 

being relocated and the piping used is the same diameter as the 

pre-existing connection, then this scenario is adequately 

covered by the proposed exclusion for relocated connections. 

However, if a new connection is made specifically to purge an 

existing piece of equipment, this purge gas unequivocally 

represents additional gas flow sent to the flare that did not 

exist and could not exist prior to the connection being made. 

Again, we consider that the increase in gas flow to the flare 

will result in an increase in emissions of at least one 

pollutant from the flare. As such, no exemption is provided for 

new connections to existing equipment, regardless if these 

connections are temporary or permanent. We also find that these 

types of flows should be expressly considered in the flare 

management plan and that flaring from these “temporary” 

connections should be minimized to the extent practicable. 
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The impact of connections of SIS described under OSHA 

process safety standards at 29 CFR 1910.119, the EPA’s risk 

management program at 49 CFR 68 and ANSI/ISA-84.00.01-2004 (Item 

14 above) should be evaluated on a case-by-case basis to 

determine whether these connections result in a flare 

modification. We expect that, if these connections are made for 

flare monitoring purposes, these connections are already 

excluded in the exemption for flare monitoring systems. If the 

“SIS” are process unit analyzers and the new connections are 

being made to connect the analyzer exhaust to the flare, these 

connections would be considered a modification, as previously 

discussed. The commenter may also be referring to new 

connections for additional pressure relief valves identified in 

the safety reviews required by the cited rules, which we would 

consider to be a modification of the flare. 

Following all of the above review and analysis, we are 

finalizing three of the connections, as proposed, adding three

of the connections requested by commenters and revising one of 

the proposed connections as requested by commenters in 40 CFR 

60.100a(c)(1). Thus, the following seven types of connections 

are not considered a modification of the flare:

(1) Connections made to install monitoring systems to the 

flare.
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(2) Connections made to install a flare gas recovery system 

or connections made to upgrade or enhance components of a flare 

gas recovery system (e.g., addition of compressors or recycle 

lines).

(3) Connections made to replace or upgrade existing 

pressure relief or safety valves, provided the new pressure 

relief or safety valve has a set point opening pressure no lower 

and an internal diameter no greater than the existing equipment

being replaced or upgraded.

(4) Connections that interconnect two or more flares. 

(5) Connections made for flare gas sulfur removal. 

(6) Connections made to install back-up (redundant) 

equipment associated with the flare (such as a back-up 

compressor) that does not increase the capacity of the flare.

(7) Replacing piping or moving an existing connection from 

a refinery process unit to a new location in the same flare, 

provided the new pipe diameter is less than or equal to the 

diameter of the pipe/connection being replaced/moved.

Comment: Several commenters suggested that de minimis

emission increases and net emission decreases resulting from new 

connections to a flare made to control and combust fugitive 

emissions such as leaks from compressor seals, valves or pumps, 

should not be considered modifications of a flare. One commenter 

suggested allowing site-specific exemptions for connections that 
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do not increase emissions or that result in a de minimis

emissions increase. However, another commenter objected to 

setting a de minimis emissions increase to determine whether a 

change to a flare is a modification and stated that allowing a 

de minimis approach would cause confusion over the applicability 

of 40 CFR part 60, subpart Ja because flare emissions are 

difficult to estimate. 

Response: In the preamble to our proposed amendments, the 

EPA specifically requested comment on using the de minimis

exception in the flare modification provision. 73 FR 78522, 

78529. Industry Petitioners had suggested some type of de

minimis emissions increase should be allowed without triggering 

40 CFR part 60, subpart Ja applicability. Id. The EPA 

acknowledged that these exceptions are “permissible but not 

required” under the modification provision in the CAA. Id. The 

EPA also stated: “We request comments on a de minimis approach 

and on specific changes that may occur to flares that will 

result in de minimis increases in emissions. We also request 

comments on the type, number, and amount of emissions that would 

be considered de minimis.” Id.

Industry Petitioners continue to recommend that any 

emissions increases resulting from “routine connections” to the 

flare system “will be de minimis” and should not trigger 40 CFR 

part 60, subpart Ja applicability at the flare, but they have 
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not provided the comments or data requested in the proposal 

preamble that the EPA could consider to evaluate the impacts of 

such an approach. Docket Item No. EPA-HQ-OAR-2007-0011-0311

(second attachment), pg 20. Industry Petitioners again suggest 

that the EPA exercise its authority and “authorize exceptions 

from otherwise clear statutory mandates” by promulgating de

minimis exemptions for the flare modification provision. Id.; 

Alabama Power Co. v. Costle, 636 F.2d 323, 360 (D.C. Cir. 1979).

As explained in Alabama Power, the de minimis exception allows 

agency flexibility in interpreting a statute to prevent 

“pointless expenditures of effort.” Id. However, as Industry 

Petitioners recognize, nothing mandates that the EPA use its de

minimis authority in any given instance, and courts especially 

recognize the significant deference due an agency’s use of a de

minimis exception. Id. at 400; Shays v. Federal Election Com’n, 

414 F.3d 76, 113 (D.C. Cir. 2005); Environmental Defense Fund, 

Inc. v. EPA, 82 F.3d 451, 466 (D.C. Cir. 1996); Ass’n of Admin. 

Law Judges v. Fed. Labor Relations Auth., 397 F.3d 957, 961 

(D.C. Cir. 2005).

In exercising that discretion, the EPA must consider the 

cautionary advice it received from the Alabama Court regarding 

its use of the de minimis exception: “EPA must take into account 

in any action. . .that this exemption authority is narrow in 

reach and tightly bounded by the need to show that the situation 
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is genuinely de minimis.” Id. at 361. The Court also noted that 

exemptions from “the clear commands of a regulatory statute, 

though sometimes permitted, are not favored.” Id. at 358. The

EPA must exercise this authority cautiously, and only in those 

circumstances that truly warrant its application.

The EPA has found no basis for promulgating a de minimis

exception to the flare modification provision. Despite its 

assertions, Industry Petitioners have still provided no data to 

support a finding that the emissions increases resulting from 

the alleged “routine connections” to a flare system are truly 

“trivial or [of] no value.” Docket Item No. EPA-HQ-OAR-2007-

0011-0311 (second attachment), pg 20. Without the requested 

information showing that “the situation is genuinely de

minimis,” Alabama Power, 636 F.2d at 361 and, therefore,

warrants this kind of exception, we believe such an exemption 

would be inappropriate.

Additionally, Industry Petitioners’ example that “venting a 

new small storage tank to a flare system. . .easily would cost a 

typical refinery tens of millions of dollars” since “the entire

flare system” (emphasis in original) would be subject to subpart 

Ja is unavailing for its argument that the EPA should promulgate 

a de minimis exception for the flare modification provision.

Docket Item No. EPA-HQ-OAR-2007-0011-0311 (second attachment), 

pg 21. As the District of Columbia Circuit specifically states 
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in Shays, authority for promulgating a de minimis exception 

“does not extend to a situation where the regulatory function 

does provide benefits, in the sense of furthering regulatory 

objectives, but the agency concludes the acknowledged benefits 

are exceeded by the costs.” Shays, 414 F.3d 76, 114 (emphasis 

added). By focusing solely on cost, Industry Petitioners are

effectively asking the agency to engage in the type of costbenefit analysis prohibited by the Shays Court. Such cost 

analyses are improper in these types of decisions. Industry 

Petitioners generally focus their discussion on VOC emissions 

and effectively admit that connecting the small storage tank to 

the flare system increases emissions from the flare (e.g., 

“uncontrolled tank emissions would be essentially eliminated by 

combustion in a flare” (Docket Item No. EPA-HQ-OAR-2007-0011-

0311 (second attachment), pg 21, emphasis added)). Furthermore, 

they disregard additional emissions of NOX and CO resulting from 

the combustion of these gases at the flare. Industry Petitioners 

also provide no data quantifying these emissions increases and,

therefore, cannot demonstrate that they are “trivial or [of] no 

value” or, in other words, that the emissions increases are, in 

fact, de minimis. As releases to the flare are often event 

driven, one can envision situations where the release from even 

a small storage tank could be significant. On the other hand, 

the EPA sees a substantial environmental benefit in requiring 
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controls that will reduce the cumulative emissions from a flare 

that becomes subject to 40 CFR part 60, subpart Ja because of 

any of these alleged “routine connections.” Thus, given the 

nature of releases to the flare, we determined that a de minimis

exemption from the modification provisions for flares is 

unworkable and unwarranted.

Comment: One commenter stated that exempting flares6 from 

the H2S concentration limits during startup, shutdown and 

malfunction (SSM) events is illegal because the CAA requires 

continuous compliance with standards of performance promulgated 

under CAA section 111. See CAA sections 111(a)(1), 302(k). For 

support, the commenter cited Sierra Club v. EPA, 551 F.3d 1019 

(D.C. Cir. 2008), in which the Court stated: “When sections 112 

and 302(k) are read together, then, Congress has required that 

there must be continuous section 112-compliant standards.” The 

commenter noted that the Court found that the exemption from 

compliance with CAA section 112 standards during SSM events 

violates the CAA because the general duty to minimize emissions 

during SSM events is not a CAA section 112-compliant standard.

 6 The comments submitted referenced “fuel gas combustion devices” 

as the affected source when describing the exemption during SSM 

events. However, the exemption only applies to flares. See 40 

CFR 60.103a(h). The discussion in this preamble is, therefore, 

focused on flares as distinguished from other types of fuel gas 

combustion devices that are required to comply at all times with 

the H2S concentration limits in 40 CFR 60.102a(g)(1).
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The commenter asserted that the CAA also requires that a section 

111-compliant standard that reflects BSER7 be in effect at all 

times for flares.

The commenter further asserted that work practice standards 

for flares are not CAA section 111-compliant standards because 

this is not one of those “limited instances” in which CAA 

section 111(h) authorizes such standards. The commenter stated 

that the EPA must show that a standard of performance for flares 

is “not feasible to prescribe or enforce” because “(A) a 

pollutant. . .cannot be emitted through a conveyance designed 

and constructed to emit or capture such pollutant, or that any 

requirement for, or use of, such a conveyance would be 

inconsistent with any federal, state or local law or (B) the 

application of measurement methodology to a particular class of 

sources is not practicable due to technological or economic 

limitations.” See CAA section 111(h)(2). The commenter stated 

that neither of these exemptions appear to apply and the EPA 

cannot claim that it is infeasible to promulgate a standard of

 7 The commenter asserted, without providing support, that it is 

not BSER to exempt flares from the H2S concentration limits 

during startup and shutdown events. The commenter also stated 

that the EPA, at a minimum, must demonstrate how the exemption 

from the H2S concentration limits during SSM events does, in 

fact, represent BSER, but the commenter stated that the EPA has 

failed to make this demonstration.
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performance for flares,8 so the EPA cannot set a work practice 

standard for flares. Thus, the commenter asserted that a CAA 

section 111-compliant standard does not continuously apply to 

flares since both the exemption from the H2S concentration limits 

during SSM events and the flare work practice standards are not 

lawful under the CAA.

Another commenter disagreed and provided several reasons 

why they believe the EPA may lawfully exempt flares from the H2S 

concentration limits during SSM events. First, the commenter 

noted that 40 CFR part 60, subpart Ja was promulgated as part of 

the mandatory periodic review of 40 CFR part 60, subpart J 

required by CAA section 111(b)(1)(B). The commenter noted that 

subpart J exempts a flare from the H2S concentration limits when 

combusting certain gases generated during SSM events (see 40 CFR 

60.104(a)(1), 60.101(e)) and stated that the record contains 

 8 The commenter cited the EPA’s rationale for proposing work 

practice standards for flaring in which we state: "It is not 

feasible to prescribe or enforce a standard of performance for 

these sources because either the pollution prevention measures 

eliminate the emission source, so that there are no emissions to 

capture and convey, or the emissions are so transient, and in 

some cases, occur so randomly, that the application of a 

measurement methodology to these sources is not technically and 

economically practical." 72 FR 27178, 27194-27195 (May 14, 

2007). In response, the commenter stated: “[T]he plain language 

of the Act recognizes that standards of performance leading to 

the ‘capture’ of emissions are not infeasible [citation 

omitted], and EPA has proposed to apply measurement 

methodologies to flares in spite of the transience of their 

emissions.”
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“ample evidence” to support maintaining that provision in 

subpart Ja. The commenter asserted that including these same 

provisions in subpart Ja is “an appropriate exercise of EPA’s 

authority to ‘not review’ this aspect of the existing standard 

in light of the efficacy of the existing standard.” See CAA 

section 111(b)(1)(B).

Second, the commenter noted that the Sierra Club decision 

was largely grounded in the Court’s determination that Congress 

amended CAA section 112 out of concern “about the slow pace of 

EPA’s regulation of HAPs,” eliminating much of the EPA’s 

discretion and requiring sources to “meet the strictest 

standards” without variance “based on different time periods.” 

The commenter further explained that the Court pointed to CAA 

section 112(d)(1) regarding the EPA’s authority to “distinguish 

among classes, types, and sizes of sources” when promulgating 

CAA section 112 standards as further evidence for constraining

the EPA’s ability to adopt different standards applicable during 

SSM events. In contrast, the commenter asserted that “Congress 

has expressed no such concern about EPA’s efforts to implement 

section 111” despite revisions to CAA section 111 in 1977 and 

1990. Therefore, the commenter asserted, Congress has 

“effectively ratified EPA’s longstanding approach to SSM under 

the NSPS program,” which includes the exemption for flares from 

the H2S concentration limits during SSM events. 
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The commenter also asserted that, regardless of the above

and despite the similar nature of the provisions in CAA sections 

111 and 112, the EPA has the discretion to implement them 

differently “under the markedly differently context of the NSPS 

program v. the MACT program.” See Environmental Defense v. Duke 

Energy Corp., 549 U.S. 561, 575-576 (2007). For example, the 

commenter asserted that the word “continuous” as used in the 

NSPS program could be interpreted and applied differently, as 

acknowledged by the Court in National Lime Ass’n v. EPA, 627 

F.2d 416, 434 (D.C. Cir. 1980) (deferring to agency regarding 

the effect of “the perplexing implications of Congress’ new 

requirement of systems of continuous emission reduction” on the 

agency’s longstanding “regulations permitting flexibility to 

account for startups, shutdowns, and malfunctions”). The 

commenter urged the EPA to exercise this discretion and 

“reassert the many practical, technical and economic factors” 

that justify promulgating separate standards for SSM events in 

the NSPS program.

Third, the commenter asserted that requiring flares to meet 

the H2S concentration limits during SSM events does not represent 

BSER for this time period. According to the commenter, “startup 

and shutdown gases are intermittent streams that cannot be cost

effectively treated for sulfur removal because of their 

infrequent occurrence, their scattered points of generation and 
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their variability.” Therefore, for all of the above reasons, the 

commenter asserted that exempting a flare from the H2S 

concentration limits when combusting certain gases generated 

during SSM events is lawful under CAA section 111. 

Alternatively, the commenter stated that if a standard must 

apply during SSM events, the flare work practice standards are 

appropriate in lieu of the H2S concentration limit.

Response: Regardless of whether or how the Sierra Club

decision under CAA section 112 applies to NSPS promulgated under 

CAA section 111, we are promulgating final amendments for flares

that include a suite of standards that apply at all times and 

are aimed at reducing SO2 emissions from flares. As described 

previously, this suite of standards requires refineries to: (1)

develop and implement a flare management plan; (2) conduct root 

cause analysis and take corrective action when waste gas sent to 

the flare exceeds a flow rate of 500,000 scf above the baseline; 

(3) conduct root cause analysis and take corrective action when 

SO2 emissions exceed 500 lb in a 24-hour period; and (4) optimize

management of the fuel gas by limiting the short-term 

concentration of H2S to 162 ppmv during normal operating 

conditions. Additionally, refineries must install and operate 

monitors for measuring sulfur and flow at the inlet of all of 

their flares. Together, these requirements provide CAA section 
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111-compliant standards that collectively cover all operating 

conditions of the flare. 

As the commenter notes, CAA section 111(h)(1) allows the

EPA to promulgate a design, equipment, work practice or 

operational standard or “combination thereof,” when “it is not 

feasible to prescribe or enforce a standard of performance” 

which reflects BSER for the particular affected source. CAA 

section 111(h)(2) defines the phrase “not feasible to prescribe 

or enforce a standard of performance” as follows:

[A]ny situation in which the Administrator determines that 

(A) a pollutant or pollutants cannot be emitted through a 

conveyance designed and constructed to emit or capture such 

pollutant, or that any requirement for, or use of, such a 

conveyance would be inconsistent with any Federal, State,

or local law, or (B) the application of measurement 

methodology to a particular class of sources is not 

practicable due to technological or economic limitations.

We have determined that flares meet the criteria set forth 

in CAA section 111(h)(2)(A) because emissions from a flare do 

not occur “through a conveyance designed and constructed to emit 

or capture such pollutant.” Gases are conveyed to the flare for 

destruction, and combustion products such as SO2, are not created 

until combustion occurs, which happens in the flame that burns 

outside of the flare tip. In other words, the SO2, NOX, PM, CO, 

VOC and other pollutants generated from burning the gases are

only created once the gases pass through the flare and come into 

contact with the flame burning on the outside of the flare. The 
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flare itself is not a “conveyance” that is “emitting” or 

“capturing” these pollutants; instead, it is a structure 

designed to combust the gases in the open air. Thus, setting a 

standard of performance for SO2 (and other pollutants) is not 

“feasible,” allowing the EPA to instead promulgate standards 

under CAA section 111(h), which will collectively limit 

emissions from the flare.

The EPA previously promulgated a standard of performance 

for SO2 emissions for fuel gas combustion devices which also 

applied to flares. 39 FR 9308, 9315 (March 8, 1974). The 

standard is expressed as an H2S concentration limit because it 

was developed as an alternative to measuring the SO2

concentration in the stack gases exiting fuel gas combustion 

devices other than flares (i.e., boilers and process heaters). 

That approach is appropriate for fuel gas combustion devices 

other than flares because measuring the H2S in the fuel gas 

combusted in those devices is directly indicative of the SO2

emitted from the exhaust stacks of those other devices. As 

explained in section III of this preamble, we are, for the first 

time, designating flares as their own affected facility. As 

such, in finalizing these amendments for flares, we considered 

whether we could also apply a standard of performance for SO2

emissions, expressed as an H2S concentration limit or a total 

sulfur limit at the inlet to the flare. However, as explained 
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above, flares are substantially different from other fuel gas 

combustion devices so that this approach is not workable for 

flares. For example, SO2 emissions from a flare are dependent on 

many factors, including the flow rates of all gases sent to the 

flare, the total sulfur content of all gases sent to the flare

and the combustion efficiency at the flare. Each of these 

factors is also dependent on many variables. For example, 

combustion efficiency at the flare is dependent upon the 

flammability of the gases entering the flare, the turbulence at 

the flare,9 the wind speed and wind direction and the presence of 

other pollutants in the gases that can react with the sulfur to 

form sulfur-containing pollutants other than SO2. Since so many 

factors affect the potential formation of SO2 emissions outside

the flare tip, we realized that we could not properly derive an 

H2S concentration limit or a total sulfur limit at the flare 

inlet that would directly correlate with those SO2 emissions. 

Thus, we determined that we cannot set a standard of performance 

for SO2 emissions at the flare.

However, we still recognize that reducing the amount of 

sulfur that is sent to a flare will reduce the SO2 emissions at 

the flare. Even with the uncertainty described above, we 

 9 Turbulence is needed to insure good mixing at the flare, but is 

affected by whether the flare is assisted with air or steam or 

non-assisted.
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understand the importance of refineries managing the fuel gas 

sent to their flares in a way that minimizes the sulfur content 

so as to ultimately minimize the SO2 emissions. Rather than 

eliminate the H2S concentration limit altogether, we are instead 

requiring under CAA section 111(h) that refineries limit the 

short-term concentration of H2S to 162 ppmv in the fuel gas sent 

to flares during normal operating conditions. Refineries rely on 

various methods for optimizing the management of fuel gas, 

including the use of amine treatment and flare gas recovery 

systems. Amine treatment removes the H2S from the flare gas that 

generates the pollutants before the gas is sent to the flare. 

Flare gas recovery systems remove the flare gas altogether and 

instead treat this gas in a fuel gas treatment system to be used

elsewhere as fuel gas in the refinery. Requiring refineries to 

meet this concentration limit at the flare ensures that the fuel 

gas has been adequately treated and managed such that it can be 

used as fuel gas in the fuel gas system elsewhere in the 

refinery. We are not requiring refineries to meet this limit 

during other periods of operation because flare gas recovery 

systems that capture gases prior to amine treatment can be 

quickly overwhelmed and fail to properly function during high 

fuel gas flows. Thus, requiring that flares meet this H2S 

concentration limit during periods when high fuel gas flows 

would likely overwhelm these flare gas recovery systems would 
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not fully address the circumstances refineries face in managing 

these high flow periods. Designing flare gas recovery systems to 

capture the full range of gas flows to the flare would not only 

require the ability to predict the full range of gas flows in 

the flare headers, but also would require refiners to install 

recovery compressors in a staged fashion such that all events 

causing high gas flows could be captured and managed, neither of 

which are practical. Therefore, promulgating flare requirements

that include the H2S fuel gas concentration limit during normal 

operating conditions, coupled with requirements for refineries 

to develop and implement a flare management plan and conduct 

root cause analyses and take corrective action when waste gas 

sent to the flare exceeds a flow rate of 500,000 scf above the 

baseline or 500 lb of SO2 in a 24-hour period, recognizes these 

unique circumstances while still requiring the refinery to take 

all reasonable measures for reducing or eliminating the flow and 

sulfur content of gases being sent to the flares.

We are aware that numeric SO2 emission limits for flares

have been established under state law and in Federal 

Implementation Plan (FIP) regulatory requirements. Those sourcespecific circumstances differ markedly from this nationally 

applicable rulemaking, necessitating different decisions in two 

very different circumstances. For example, the EPA's SO2 FIP for 

the Billings/Laurel Montana area includes a SO2 emission limit of 
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150 lb of SO2 per 3 hours for four sources that apply to the 

flares at all times. See 40 CFR 52.1392(d)(2)(i), (e)(2)(i), 

(f)(2)(i) and (g)(2)(i). These source-specific limits were 

appropriately based on dispersion modeling in the 

Billings/Laurel area to determine what was needed to meet 

national ambient air quality standards (NAAQS) for SO2 in the 

Billings/Laurel area. In contrast, the nationally applicable 

standards and requirements we are promulgating in this rule must 

represent the best system of emission reduction achievable for 

an entire industry sector scattered across the entire country. 

This requires that we consider costs and other non-air quality 

factors that affect all petroleum refineries nationwide in 

making that decision and not just as applied to a particular 

group of sources in a particular location. 

Additionally, those four sources subject to the 

Billings/Laurel FIP demonstrate compliance with the 150 lb SO2/3-

hour emission limit by measuring the total sulfur concentration 

and volumetric flow rate of the gas stream at the inlet to the 

flare. See 40 CFR 52.1392(d)(2)(ii), (e)(2)(ii), (f)(2)(ii), 

(g)(2)(ii) and (h). Since the FIP must include emissions limits 

that insure attainment and maintenance of the NAAQS in the 

Billings/Laurel area, it was appropriate, in setting the 

standards for the Billings/Laurel FIP, to conservatively assume 

that 100 percent of the sulfur in the gases discharged to the 
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flare is converted to SO2, and based on this conversion, set the 

numeric limit as a value that is not to be exceeded. However,

that same assumption is not appropriate when setting national 

standards for flares. Instead, we must consider the many factors 

affecting the formation of SO2 at the flare tip and how these 

factors affect how much of the sulfur in the gases sent into the 

flare actually converts to SO2. Therefore, although setting such 

source-specific limits was appropriate to satisfy what the 

modeling showed was necessary to meet the SO2 NAAQS in the 

Billings/Laurel area, a different analysis and standard is 

appropriate for a national rulemaking.

Therefore, for the reasons discussed above, the EPA is 

finalizing this collective set of CAA section 111(h)-compliant 

standards for flares, based on our interpretation of CAA section 

111(h) as it applies to flares.

Comment: Numerous commenters asserted that the long-term 60 

ppmv H2S fuel gas concentration limit is not cost effective for 

flares and, therefore, not BSER for flares. The commenters noted 

that the EPA did not include costs for compressors, additional 

amine units and sulfur recovery units, and one commenter stated 

that the EPA did not consider the range of costs that are 

incurred by individual refineries. Commenters also asserted that

the EPA overstated emission reductions by using 162 ppmv H2S as a 

baseline because many refinery streams currently sent to the 
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flare contain H2S concentrations below 162 ppmv, so 162 ppmv H2S 

does not reflect long-term performance. Commenters noted that 

the Btu content of flare gas is highly variable and generally 

lower than that used by the EPA, so the EPA’s analysis 

overestimated the value of the recovered flare gas. One 

commenter noted that the EPA should have considered consent 

decree requirements in the baseline SO2 emissions estimates.

One commenter stated that the long-term 60 ppmv H2S fuel gas 

concentration limit could preclude some refineries from 

processing high-sulfur crude oils, thereby limiting refining 

production capacity. Another commenter noted that many flares 

will receive both fuel gas and process upset gas, so it would be

impossible to determine if an exceedance is caused by the 

regulated fuel gas or by the exempt gas. The commenter 

recommended that the EPA apply the long-term 60 ppmv H2S fuel gas 

concentration limit only to fuel gas combusted in process 

heaters, boilers and similar fuel gas combustion devices, and 

not to flares, or that the EPA allow Alternative Monitoring 

Plans to demonstrate compliance with the emissions limits for 

non-exempt gas streams upstream of the flare header.

Response: We acknowledge that, at proposal, we determined 

that a long-term 60 ppmv H2S fuel gas concentration limit was 

cost effective primarily for process heaters, boilers and other 

fuel gas combustion devices that are fed by the refinery’s fuel 
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gas system. Based on the typical configuration at a refinery, 

adding one new fuel gas combustion device to the fuel gas system 

would essentially require the owner or operator to limit the 

long-term concentration of H2S in the entire fuel gas system to 

60 ppmv, so emission reductions would result from all fuel gas 

combustion devices tied to that fuel gas system. Upon review of 

the BSER analysis conducted at proposal for fuel gas combustion 

devices, we now realize that the analysis is not applicable to 

flares (See Docket Item No. EPA-HQ-OAR-2007-0011-0289). 

Moreover, since we are regulating flares separately from 

other fuel gas combustion devices in this final rule, we should

separately consider whether a long-term H2S concentration limit 

is appropriate for fuel gas sent to flares.

In developing the suite of CAA section 111(h) standards for 

flares, we considered whether refineries should be required to 

optimize management of their fuel gas by limiting the long-term 

H2S concentration to 60 ppmv in addition to the short-term H2S 

concentration of 162 ppmv during normal operating conditions. We 

determined that, for refineries to demonstrate that their fuel 

gas complies with a long-term H2S concentration of 60 ppmv, 

refineries would have to install a flare gas recovery system 

(which was not needed for other fuel gas combustion devices) and 

then upgrade the fuel gas desulfurization system. Alternatively, 

refineries would have to treat the recovered fuel gas to limit 
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the long-term concentration of H2S to 60 ppmv with new amine 

treatment units on each flare.

While some of the costs provided by the commenters did not 

include the value of the recovered gas and appeared, at times, 

to include equipment not necessarily required by the regulation, 

we generally agree with the commenters, based on our own cost 

estimates, that optimizing management of the fuel gas system to 

limit the long-term concentration of H2S to 60 ppmv is not cost

effective for flares (see Table 2 below). We note that the costs 

provided by the commenters and the costs and emissions 

reductions in our analysis are the incremental costs and 

emissions reductions of going from the short-term 162 ppmv H2S 

concentration to a combined short-term 162 ppmv H2S concentration 

and long-term 60 ppmv H2S concentration. While we are aware that 

some consent decrees require refineries to limit the 

concentration of H2S in the fuel gas to levels lower than the 

short-term 162 ppmv H2S concentration, our baseline when 

evaluating the impacts of a national standard (in this case, 40 

CFR part 60, subpart Ja) is the national set of requirements to 

which an affected flare would be subject in the absence of 

subpart Ja (i.e., the short-term 162 ppmv H2S concentration limit 

in 40 CFR part 60, subpart J).
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Table 2. National Fifth Year Impacts of Meeting a Long-Term 60 

ppmv H2S Concentration for Flares Subject to 40 CFR Part 60, 

Subpart Ja

Capital 

cost

($1,000)

Total annual 

cost 

($1,000/yr)a

Emission 

reduction 

(tons 

SO2/yr)b

Emission 

reduction

(tons 

NOX/yr)b

Emission 

reduction

(tons

VOC/yr)b

Cost 

effectiveness 

($/ton)

New 80,000 15,000 6 34 130 84,000

Modified/ 

Reconstructed 860,000 160,000 53 310 1,200 100,000

a Because of the heat content of recovered gas, each scf of recovered gas is assumed 

to offset one scf of natural gas; a value of $5/10000 scf of natural gas was used to 

estimate recovery credit.

b These emission reductions are based on flares already meeting the short-term 162 

ppmv H2S fuel gas concentration limit in 40 CFR part 60, subpart J (i.e., these are

the incremental emission reductions achieved from a baseline of optimizing management 

of the fuel gas system to limit the short-term H2S concentration in the fuel gas to 

162 ppmv to the originally proposed combined short-term 162 ppmv H2S concentration and 

long-term 60 ppmv H2S concentration in the fuel gas).

Comment: Several commenters addressed the EPA’s request for 

comment on “the equivalency of the subpart Ja requirements as 

proposed to be amended today and the SCAQMD Rule 1118” and 

“whether EPA could deem a facility in compliance with subpart Ja 

as proposed to be amended today if that facility was found to be 

in compliance with SCAQMD Rule 1118, or other equivalent State 

or local rules” (73 FR 78532, December 22, 2008). One commenter 

disagreed with the EPA’s position, alleging that “EPA’s 

suggestion that it can waive compliance with the NSPS in this 

manner is contrary to the Clean Air Act.” The commenter stated

that the EPA’s suggestion “that existing state and local 

requirements render the federal requirements irrelevant only 

confirms that EPA’s proposed flaring requirements do not reflect 

the best technological system of continuous emission reduction.” 
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42 U.S.C. §7411(h)(1) (emphasis added). The commenter also 

stated that the CAA already provides a mechanism for 

implementation of alternative work practice standards in 

narrowly defined circumstances (42 U.S.C. §7411(h)(3)); an owner 

or operator may demonstrate to the Administrator that an 

alternative means of emissions limitation is equivalent to the 

federal standard on a case-by-case basis. Therefore, the 

commenter asserted, the CAA clearly states that “EPA’s authority 

to waive federal work practice standards is case specific.”

Finally, the commenter stated that the EPA did not explain how 

emissions reductions achieved through compliance with SCAQMD 

Rule 1118 are equivalent to 40 CFR part 60, subpart Ja. Further, 

the commenter asserted that the EPA neither identified other 

state or local rules that could be considered equivalent to 

subpart Ja, nor explained how the EPA would determine that a 

specific state or local rule is equivalent to subpart Ja.

Therefore, the commenter asserted, it is impossible to fully 

assess the merit of the EPA’s idea and provide meaningful 

comments.

Another commenter stated that “most stringent” is not one 

of the criteria that must be applied under the law to determine 

BSER. Therefore, the commenter asserted, it is not appropriate 

to argue that the EPA did not properly determine BSER simply 

because there exist state or local rules that are more stringent 
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than federal requirements. The commenter also asserted that the

EPA has full authority to establish alternative regulatory 

standards that are determined to be as stringent as or more 

stringent than BSER, and CAA section 111(h)(3) generally applies 

after the EPA has completed a national rulemaking and an owner 

or operator requests approval for a site-specific alternative at 

a later date. The commenter asserted that it is logical that, if 

an alternative method is identified during the rulemaking 

process, “the law would allow EPA to establish a site-specific 

alternative [in the rule itself] (especially, as under [CAA

section 111], where the alternative would have to be determined 

through notice and comment rulemaking).”

Other commenters recommended that refineries complying with 

SCAQMD Rule 1118 be deemed in compliance with 40 CFR part 60, 

subparts J and Ja. According to one commenter, SCAQMD Rule 1118 

is “in all respects equivalent to or more stringent than the 

corresponding requirements” of subparts J and Ja. Commenters 

also recommended that refineries should be able to consider 

compliance with BAAQMD Regulation 12, Rule 11 and Regulation 12, 

Rule 12 as compliance with the appropriate provisions of subpart

Ja. One commenter provided a table comparing each of the six 

proposed flare management plan requirements in 40 CFR 60.103a(a) 

to the SCAQMD and BAAQMD regulations. The table identified 

sections of BAAQMD Regulation 12, Rule 11 and Regulation 12, 
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Rule 12 that are equivalent to the six subpart Ja flare 

management plan requirements. The commenter also noted that 

SCAQMD Rule 1118 is only equivalent to five of the proposed 

requirements; it does not require an owner or operator to 

identify procedures to reduce flaring in cases of fuel gas 

imbalance (although another commenter noted that SCAQMD Rule 

1118 requires minimization of all flaring, including fuel gas 

imbalance). While most commenters focused on the equivalence of 

the flare management plan requirements of the SCAQMD and BAAQMD 

rules and the flare management plan requirements of subpart Ja, 

one commenter requested that the periodic sampling of BAAQMD 

Regulation 12, Rule 11 be considered equivalent to the 

continuous sulfur monitoring requirements of subpart Ja for 

emergency flares.

Response: First, we note that there seems to be some 

misunderstanding regarding how a determination that SCAQMD Rule 

1118 or BAAQMD Regulation 12, Rule 11 and Regulation 12, Rule 12

are equivalent to 40 CFR part 60, subpart Ja would actually be 

implemented in subpart Ja. The EPA will not “waive” the 

obligation to comply with subpart Ja if the source is complying 

with SCAQMD Rule 1118 or BAAQMD Regulation 12, Rule 11 and 

Regulation 12, Rule 12. In other words, the EPA will not allow 

the owner or operator to “choose” to comply with SCAQMD Rule 

1118 or BAAQMD Regulation 12, Rule 11 and Regulation 12, Rule 12 
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instead of subpart Ja. Rather, the source must always 

demonstrate compliance with subpart Ja. If SCAQMD Rule 1118 or 

BAAQMD Regulation 12, Rule 11 and Regulation 12, Rule 12 are 

determined to be equivalent to subpart Ja, then these 

requirements would be provided as an alternative within subpart 

Ja for the source to demonstrate that it is meeting the 

requirements of subpart Ja. 

To assess the comments, we reviewed SCAQMD Rule 1118, 

BAAQMD Regulation 12, Rule 11, and BAAQMD Regulation 12, Rule 12 

and compared these rules to the 40 CFR part 60, subpart Ja 

requirements we are finalizing here. We have included 

documentation of this review in Docket ID No. EPA-HQ-OAR-2007-

0011 that shows the sections of each of those rules that we 

consider are equivalent to the subpart Ja requirements. We 

determined that SCAQMD Rule 1118 and BAAQMD Regulation 12, Rule 

11 and Regulation 12, Rule 12 will result in equivalent to or 

greater than the emissions reductions resulting from the subpart 

Ja flare management plan requirements. As a result of our 

analysis, we have amended subpart Ja, as described in the 

following paragraphs.

We determined that SCAQMD Rule 1118 is equivalent to the 

flare requirements and monitoring, recordkeeping and reporting 

provisions for determining compliance with the flare 

requirements in 40 CFR part 60, subpart Ja. We also determined 
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that the combined provisions of BAAQMD Regulation 12, Rule 11 

and BAAQMD Regulation 12, Rule 12 are equivalent to the flare 

requirements and monitoring, recordkeeping and reporting 

provisions for determining compliance with the flare 

requirements in subpart Ja. Therefore, we have added specific 

compliance options for flares that are located in the SCAQMD and 

are in compliance with SCAQMD Rule 1118, as well as for flares 

that are located in the BAAQMD and are in compliance with both 

BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12, Rule 12.

Flares that are in compliance with these alternative compliance 

options are in compliance with the flare standards in subpart 

Ja. Specifically, 40 CFR 60.103a(g) specifies that flares that 

are located in the SCAQMD may elect to comply with SCAQMD Rule 

1118 and flares that are located in the BAAQMD may elect to 

comply with both BAAQMD Regulation 12, Rule 11 and BAAQMD 

Regulation 12, Rule 12 to comply with the flare management plan 

requirements of 40 CFR 60.103a(a) and (b) and the root cause 

analysis and corrective action analysis requirements of 40 CFR 

60.103a(c) though (e). In addition, 40 CFR 60.107a(h) indicates

that flares that are located in the SCAQMD may elect to comply

with the monitoring requirements of SCAQMD Rule 1118 and flares 

that are located in the BAAQMD may elect to comply with the 

combined monitoring requirements of both BAAQMD Regulation 12, 

Rule 11 and BAAQMD Regulation 12, Rule 12 to comply with the 
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monitoring requirements of 40 CFR 60.107a(e) and (f). The owner 

or operator must notify the Administrator, as specified in 40 

CFR 60.103a(g), that the flare is in compliance with SCAQMD Rule 

1118 or both BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 

12, Rule 12. The owner or operator must also submit a copy of 

the existing flare management plan (if applicable), as specified 

in 40 CFR 60.103a(g). 

We note that, as pointed out by commenters, an owner or 

operator maintains the ability under CAA section 111(h)(3) to 

submit a request to establish, on a case-by-case basis, that “an 

alternative means of emission limitation will achieve a 

reduction in emissions. . .at least equivalent to the reduction 

in emissions” achieved under the flare standards of 40 CFR part 

60, subpart Ja. Pursuant to CAA section 111(h)(3), we also 

included specific provisions within 40 CFR 60.103a for owners or 

operators to submit a request for “an alternative means of 

emission limitation” that will achieve a reduction in emissions

at least equivalent to the reduction in emissions achieved under 

the final standards in subpart Ja.

Comment: Commenters suggested that the requirement to 

minimize discharges to the flare in 40 CFR 60.103a(a)(1) should 

specifically address routine discharges, and the EPA should

limit the minimization requirements to actions that: (1) are 

“consistent with good engineering practices” and (2) consider 
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costs and other health and environmental impacts, as required by 

section 111 of the CAA.

Response: We agree that the language in proposed 40 CFR 

60.103a(a)(1) appears to require an assessment of flare 

minimization irrespective of cost or other relevant 

considerations, as contained in CAA section 111, which was not 

our intent. We are clarifying, through this response, that cost, 

safety and emissions reductions may be considered when 

evaluating what actions should be taken to minimize discharges 

to a flare, but we disagree that the flare minimization 

assessment should be limited to “routine discharges.” We have 

revised the flare management plan requirements in 40 CFR 

60.103a(a) to more fully describe the types of information that 

must be evaluated and included in the plan. 

As noted in the summary of this rule (section III.C of this 

preamble), we are finalizing our proposed withdrawal of the 

250,000 scfd 30-day rolling average flow limit for flares. This 

limitation does not adequately account for site-specific factors 

regarding flare gas Btu content, ability to offset natural gas 

purchase and other considerations. We find that these factors 

need to be addressed in a site-specific basis and are more 

appropriately addressed through the flare management plan. In 

the absence of the specific flow limitation, we have included 

additional requirements in the flare management plan to prompt a 
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thorough review of the flare system so that, as an example, 

flare gas recovery systems are installed and used where these 

systems are warranted. We have also revised the flare 

minimization requirements to require the flare management plans

to be submitted to the Administrator (40 CFR 60.103a(b)). 

As part of the development of the flare management plan, 

refinery owners and operators can provide rationale and 

supporting evidence regarding the flare reduction options 

considered, the costs of each option, the quantity of flare gas 

that would be recovered or prevented by the option, the Btu 

content of the flare gas and the ability or inability of the 

reduction option to offset natural gas purchases. The plan will

also include the rationale for the selected reduction option,

including consideration of safety concerns. The owner or 

operator must comply with the plan, as submitted to the 

Administrator. Major revisions to the plan, such as the addition 

of an alternative baseline (see next comment for further detail 

on baselines), must also be submitted to the Administrator.

In summary, although we did not incorporate the commenter’s 

suggested language for limiting the scope of the minimization 

requirements to actions that are “consistent with good 

engineering practices” and that “consider costs and other health 

and environmental impacts,” we acknowledge that these are valid 

considerations in the selection of the minimization alternatives 
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available for a given affected flare. We find that the process 

of developing and submitting the flare management plan will 

ensure that these factors are considered consistent with CAA 

section 111 and that the requirement to minimize discharges to 

the flare is implemented consistently across all affected 

sources. 

Comment: Commenters asserted that the flare flow root cause 

analysis threshold of 500,000 scf in any 24-hour period is 

arbitrary and cannot be fairly applied to all flares at all 

refineries. One commenter cited an ultracracker flare that 

routinely cycles from 5 million to 25 million scfd as an example

of a flare for which the threshold of 500,000 scf in any 24-hour 

period would result in constant and meaningless root cause 

analyses. The commenters suggested removing the numerical 

threshold and limiting root cause analysis to upsets and 

malfunctions as initially promulgated in June 2008 (because root 

cause analysis is generally only effective for reducing nonroutine flows) or using a site- or flare-specific threshold 

instead. Even if the numerical threshold is revised, the 

commenters suggested that a number of streams be excluded from 

the calculation of flow, such as hydrogen and nitrogen, purge 

and sweep gas, natural gas added to increase the Btu content of 

the flare gas and gases regulated by other rules to avoid 

performing multiple root cause analyses for routine events. One 
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commenter suggested that owners or operators should be able to 

use one root cause analysis report for an event that occurs 

routinely (as allowed in the consent decrees).

Response: We proposed the flare flow root cause analysis 

threshold of 500,000 scf in any 24-hour period because we 

projected that flare gas recovery would be a cost effective 

emission reduction technique for flares with fuel gas flows that 

routinely exceed 500,000 scfd, although we acknowledge that the 

threshold at which flare gas recovery becomes cost effective is 

strongly (inversely) correlated to the average Btu content of 

the flare gas (i.e., a relatively small reduction in the Btu 

content of the gas makes the recovery system significantly less 

cost effective). Although we did not specifically exclude sweep 

or purge gas from the flow, we expected that the flow rates of 

sweep or purge gas (i.e., gases needed to ensure the readiness 

of the flare and the safety of the flare gas system) would be 

negligible when compared to the root cause analysis threshold of 

500,000 scf in any 24-hour period. In fact, in our original 

analysis of the appropriate flow rate root cause analysis

threshold (Docket Item No. EPA-HQ-OAR-2007-0011-0246), we 

essentially assumed that the sweep and purge gas flow rates were 

zero, and we estimated costs and emissions reductions of the 

500,000 scf in any 24-hour period threshold, based on recovering 
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that amount of gas or eliminating recurring events of that size 

(rather than 500,000 scf minus the sweep or purge gas flow).

However, while we do not believe that 5 million scfd10 is a 

reasonable base flow for a flare, we do acknowledge that the 

size of the flare, as well as the flare header system, will 

greatly impact the required flow needed to maintain the 

readiness of the flare. Although we can derive suitable flare 

flow thresholds for average conditions, these thresholds are not 

necessarily reasonable when applied to all flows, and we did not 

intend for on-going root cause analyses to be conducted on 

account of sweep or purge gas. 

Therefore, rather than specifying a one-size-fits-all 

threshold, the final rule requires facilities to develop their 

own base flare flow rates as part of their flare management

plan. A flow-based root cause analysis is triggered if flows 

measured by the flow monitor exceed 500,000 scf greater than the 

 10 Regarding commenter’s cited ultracracker flare example, it is 

difficult to believe that sweep gas alone accounts for 5 million 

scfd of flare gas flow. Additionally, a compositional analysis 

of the base flare gas from the normal flow, based on data 

provided from a DIAL study of this refinery, suggests that the 

base flare gas is of sufficient quality to recover. It also 

appears, based on the data provided by the commenter, that the 

hydrogen stream recycle compressor was off-line approximately 

half the year. For such huge gas flows, considering the cost of 

purchasing or producing additional hydrogen and the emissions 

associated with that process, it is reasonable to expect that 

the facility would have a back-up compressor if the primary 

compressor is unreliable.
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base flare flow rate in any 24-hour period. Evaluating the flow 

rate threshold above a baseline better reflects our original 

analysis of the impacts of flow-based root cause analyses when 

the sweep or purge gas flow rates are not negligible. We also 

note that 40 CFR 60.103a(d) allows a single root cause analysis 

to be conducted for any single continuous discharge that causes 

the flare to exceed either the root cause analysis threshold for 

SO2 or flow for two or more consecutive 24-hour periods.

The final rule does not limit root cause analyses to upsets 

and malfunctions of refinery process units and ancillary 

equipment connected to the flare, nor does it explicitly allow 

owners or operators to use one root cause analysis report for an 

event that occurs routinely. When we decided to eliminate the 

numerical limit on flare flow rate, we specifically increased 

the scope of the flare flow root cause analysis to cover more 

than just upsets and malfunctions. We also decided not to 

explicitly allow owners or operators to use one root cause 

analysis report for an event that occurs routinely as a means to 

discourage routine flaring of recoverable gas. However, we 

recognize that there may be recurring discharges to the flare 

that are not recoverable for various reasons. Therefore, the 

final rule does allow for several base cases, which could 

include recurring maintenance; this provision will avoid

multiple root cause analyses for a recurring event. As described 
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above, the flare management plan (as well as significant 

revisions to the plan to include alternative baselines) must be 

submitted to the Administrator. The Administrator or delegated 

authority (e.g., the state) may review the plan, although formal 

approval of the plan is not required. Not specifying a formal 

approval process is intended to minimize the burden associated 

with reviewing flare management plans. Rather, the rule 

specifies elements of the plan that need to be addressed in 

order for the plan to be considered adequate and provides an 

opportunity for a delegated authority to find the plan not 

adequate if they choose to do so. 

We expect that a final flare management plan in compliance 

with 40 CFR part 60, subpart Ja will possess the following 

characteristics: (1) completeness (all gas streams are 

considered, all required elements are included and all 

appropriate flare reduction measures are evaluated); (2) 

accuracy (the emission reductions and cost estimates for the 

different options are accurate); and (3) reasonableness (the 

selection of reduction options is correct and the baseline flow 

value is reasonable). If the Administrator identifies 

deficiencies in the plan (e.g., the plan does not contain all 

the required elements, alternative flare reduction options were 

not evaluated or selected when reasonable, the baseline or 

alternative baseline flow rates are considered unreasonable), 
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the Administrator will notify the owner or operator of the 

apparent deficiencies. The owner or operator must either revise 

the plan to address the deficiencies or provide additional 

information to document the reasonableness of the plan.

Comment: Commenters requested alternative monitoring 

options or an exemption from continuous flow monitoring for: (1) 

flares designed to handle less than 500,000 scfd of gas; (2) 

pilot gas; (3) flares with flare gas recovery systems; (4) 

emergency flares; and (5) secondary flares. The commenters 

asserted that flow meters are costly and engineering 

calculations, which are currently used, are sufficient to 

evaluate when the flow to a flare exceeds 500,000 scf in any 24-

hour period. One commenter stated that, for flares with flare 

gas recovery systems, the pressure drop across the flare seal 

drum can be used to calculate flow rate.

Response: In the final rule, flow monitoring is used to 

determine whether a root cause analysis is required rather than 

to ensure compliance with a specific flow limit. We have 

reviewed the commenters’ suggestions and agree that, in certain 

specific cases, monitoring is not necessary and should not be 

required. However, as a general rule, we believe flow monitors 

are needed, not only to provide a verifiable measure of 

exceedances of the flow root cause analysis threshold, but also 

exceedances of the root cause analysis threshold of 500 lb SO2 in 
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any 24-hour period. In addition, when we evaluated local rules,

such as the initial BAAQMD rule for flare monitoring, we saw 

that the measured flare flow rates were several times greater 

than previously projected by the facilities. 

Consequently, we find great value in the flow monitoring 

requirements for flares. These monitoring requirements will 

greatly improve the accuracy of emissions estimates from these 

flares. The resulting improved accuracy of flare emissions 

estimates will also lead to better decision-making as we conduct 

future reviews of rules applicable to petroleum refineries. We 

did consider each of the commenters’ suggested exemptions in 

light of this fact; our specific considerations follow. 

We did not specifically consider that some flares would not 

be capable of exceeding the flow root cause analysis threshold 

(i.e., designed to handle less than 500,000 scfd of gas). 

However, these small flares could still exceed the root cause 

analysis threshold of 500 lb SO2 in any 24-hour period. As such, 

we did not provide an exemption from the monitoring requirements 

for these small flares.

We agree that the monitoring of pilot gas flow is not 

needed. In the final rule, a root cause analysis is required if 

the gas flow to the flare exceeds 500,000 scf above the baseline

in any 24-hour period. The flow of pilot gas is considered to be 

part of the baseline flow and is assumed to be constant. As 
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such, monitoring of pilot gas would not be necessary to

determine whether a flare has exceeded 500,000 scf above the 

baseline in any 24-hour period. In practice, the actual baseline 

flow set for the flare may or may not expressly include the 

pilot gas flow rate. Generally, the configuration of the flare 

header is such that the flare flow monitor would not measure 

pilot gas flow. In this case, the baseline flow determined for 

the flare would not expressly include the pilot gas flow rate.

If the flare flow monitor is configured in such a way that it 

does measure pilot gas, then pilot gas would be considered part 

of the baseline conditions for that flare.

We agree with commenters that flares with flare gas 

recovery systems do have unique conditions and these warrant 

alternative monitoring options. Additionally, we recognize that 

the monitoring requirements may be burdensome for flares that 

are truly “emergency only” (i.e., flares that flare gas rarely, 

if at all, during a typical year) or for secondary flares in a 

cascaded flare system. These flares are expected to have a water 

seal that prevents flare use during normal operations and 

ensures that the pressure upstream of the water seal (expressed 

in inches of water) does not exceed the water seal height during 

normal operations (hereafter referred to as “properly maintain a 

water seal”). We find that, for these select types of flares, 
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water seal monitoring as an alternative to the flow (and sulfur) 

monitoring provisions is appropriate. 

For flares with a flare gas recovery system and other 

emergency or secondary flares that properly maintain a water 

seal, the final rule states that an owner or operator may elect 

to monitor the pressure in the gas header just before the water 

seal and monitor the water seal liquid height to verify that the 

flare header pressure is less than the water seal, which is an 

indication that no flow of gas occurs. If the flare header 

pressure exceeds the water seal liquid level, a root cause 

analysis is triggered unless the pressure exceedance is 

attributable to staging of compressors. This alternative reduces 

the costs associated with installing sulfur and flow monitoring 

systems for flares that rarely receive fuel gas. Engineering 

calculations can be used to estimate the emissions during the 

event, but not for determining whether or not a root cause 

analysis is required.

To ensure that this option is only used for flares that are 

truly emergency flares and not for flares that are used for 

routine discharges, the final rule contains a limit on the 

number of pressure exceedances requiring root cause analyses 

that can occur in one year. Following the fifth reportable 

pressure exceedance in any consecutive 365 days, the owner or 

operator must comply with the sulfur and flow monitoring 
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requirements of 40 CFR 60.107a(e) and (f). Based on a review of 

available flaring data, we expect that gas may be sent to an 

emergency flare three to four times per year, on average. 

Consistent with this information, we are providing in these 

final amendments that an “emergency flare” may receive up to 

four releases to the flare in any consecutive 365-day period to 

account for year-to-year variability. However, a flare receiving 

more than four discharges in a consecutive 365-day period can no 

longer be considered an “emergency flare” and must install the 

required sulfur and flow monitors.

Comment: Commenters requested an exemption from continuous 

sulfur monitoring or alternative monitoring options for flares 

handling only gases inherently low in sulfur content, emergency 

flares, flares with properly designed flare gas recovery systems

and secondary flares. For flares handling gases low in sulfur, 

the commenters noted that continuous monitoring is unnecessary 

and certain fuel gas streams are already exempted from 

monitoring if they are combusted in a fuel gas combustion 

device. For flares that handle only gases exempt from the H2S

concentration requirements and flares with properly designed 

flare gas recovery systems, commenters stated that engineering 

calculations are sufficient to determine if the SO2 root cause 

analysis threshold of 500 lb in any 24-hour period is exceeded. 

One commenter requested that the EPA allow owners or operators 
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to submit and use an alternative monitoring plan to demonstrate 

that the flare gas recovery system is operating within its 

capacity and to calculate SO2 emissions from engineering 

calculations and flare gas sampling. For secondary flares, one 

commenter noted that the continuous sulfur monitor on the 

primary flare could be used to determine the sulfur content of 

the gas being flared from the secondary flare.

One commenter requested that the EPA allow the use of 

engineering calculations to determine the sulfur-to-H2S ratio 

because sampling can be difficult for emergency flares. One 

commenter noted that the EPA should allow the use of an existing 

continuous monitoring system if the gas sent to the flare is 

already monitored elsewhere. As examples, the commenter cited 

fuel gas and pilot gas already monitored within the fuel gas 

system.

For flares that rarely see flow, commenters particularly 

cited difficulties with performance tests. Commenters noted 

that, to meet the sulfur monitor performance test requirements, 

an owner or operator may have to intentionally flare gas that 

may not meet the H2S concentration limits. One commenter also 

stated that performing the required relative accuracy test audit 

(RATA) could cause the flare to exceed the root cause analysis 

threshold. The commenter recommended revising the performance 
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test requirements for flares with flare gas recovery to require 

only a cylinder gas audit.

Response: We have amended the final rule so that gases that 

are exempt from H2S monitoring due to low sulfur content are also 

exempt from sulfur monitoring requirements for flares. For lowsulfur gases, the flare root cause analysis will always be 

triggered by an exceedance of the flow rate threshold well 

before the SO2 threshold is exceeded, so no sulfur monitoring is 

required. However, this exemption can only be used for flares 

that are configured to receive only fuel gas streams that are 

inherently low in sulfur content, as described in 40 CFR 

60.107a(a)(3), such as flares used for pressure relief of 

propane or butane product spheres (fuel gas streams meeting 

commercial grade product specifications for sulfur content of 30 

ppmv or less) or flares used to combust fuel gas streams 

produced in process units that are intolerant to sulfur 

contamination (e.g., hydrogen plant, catalytic reforming unit,

isomerization unit or hydrogen fluoride alkylation unit). We 

already clarified that flare pilot gas is not required to be 

monitored. Also, 40 CFR part 60, subpart Ja already allows for 

H2S monitoring at a central location, such as the fuel mix drum, 

for all fuel gas combustion devices (and we are finalizing 

amendments to ensure it is clear that H2S monitoring at a central 

location is allowed for flares as well). Thus, we agree that if 
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a flare only burns natural gas, fuel gas monitored elsewhere or 

fuel gas streams that are inherently low in sulfur content (as 

defined in 40 CFR 60.107a(a)(3)), then no H2S monitor is needed.

The remaining issue is whether or not sulfur monitoring is 

necessary for “emergency only” flares. (An emergency flare is 

defined as a flare that combusts gas exclusively released as a 

result of malfunctions (and not startup, shutdown, routine 

operations or any other cause) on four or fewer occasions in a 

rolling 365-day period. For purposes of the rule, a flare cannot 

be categorized as an emergency flare unless it maintains a water 

seal.) We acknowledge that there are difficulties and costs with 

installing monitors on flares that rarely operate. However, we 

are concerned about how the owner or operator will detect 

emissions above 500 lb SO2 in any 24-hour period during an upset 

or malfunction of a refinery process unit or ancillary equipment

connected to the flare. Commenters appear to have conflicting 

opinions regarding the ability to sample the flare gas to 

determine the sulfur content (or total sulfur-to-H2S ratio) 

during a flaring event. If samples could be taken during the 

flaring events, then that would be a potential option. However, 

during a process upset or malfunction, focus should be on 

alleviating the problem rather than taking a special sample. 

Also, given the duration of some of these events, it appears 

unlikely that representative samples can be manually collected. 
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Taking the difficulties discussed above into account, we 

have developed an alternative monitoring option for emergency 

flares. As noted in the previous response, emergency flares are 

expected to properly maintain a water seal. We provide pressure 

and water seal liquid level monitoring, as previously described 

as an alternative to the sulfur and flow monitors. As described 

in more detail above, any fuel gas pressure exceeding the water 

seal liquid level triggers a root cause analysis and there is a 

limit to the number of exceedances in one year. Under this 

option, a root cause analysis is triggered, based on the 

monitored pressure and water seal height, so accurate 

measurements of flow rate and sulfur concentrations are less 

critical than for flares that must evaluate these parameters to 

determine if a root cause analysis is needed. Consequently, for 

these flares, engineering calculations can be used to estimate 

the reported emissions during the flaring event, but the root 

cause analysis must be performed regardless of the magnitude of 

these engineering estimates. Using this alternative monitoring 

option, emergency flares are not required to install continuous 

sulfur monitoring systems. Flares that do not meet the 

conditions of an emergency flare are required to install 

continuous sulfur monitoring systems and cannot elect this 

alternative monitoring option.
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We also agree that flaring solely for the purpose of a RATA 

or other performance test is not desirable. The “cylinder gas 

audit” procedures requested by the commenter are described as 

alternative relative accuracy procedures in section 16.0 of 

Performance Specification 2 (referenced from Performance 

Specification 5). We reviewed the alternative relative accuracy 

procedures and considered how they may apply to flares, and we 

have determined that the alternative relative accuracy 

procedures are appropriate for flares. We expect that, for most 

affected flares, the variability in flow (including no flow 

conditions) and sulfur content of the gases discharged to the 

flare create significant barriers to the normally required 

relative accuracy assessments, particularly if those assessments 

need to be made over a range of sulfur concentrations 

potentially seen by the monitor. Therefore, we are amending 40 

CFR 60.107a(e)(1)(ii) and 40 CFR 60.107a(e)(2)(ii) to specify 

that the owner or operator of a flare may elect to use the 

alternative relative accuracy procedures in section 16.0 of 

Performance Specification 2 of Appendix B to part 60. As 

required by 40 CFR 60.108a(b), the owner or operator shall 

notify the Administrator of their intent to use the alternative 

relative accuracy procedures.

Comment: One commenter requested that the EPA clarify 

whether the additionally proposed sulfur monitoring options for 
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flares are for total reduced sulfur or total sulfur. The 

commenter noted that measuring total sulfur is the simplest and 

most inclusive measurement of SO2 emissions and it is the method 

included in SCAQMD Rule 1118. The commenter also requested that 

methods for measuring total sulfur in gaseous fuels be included 

as acceptable options to perform the relative accuracy 

evaluations of the CEMS.

One commenter requested that provisions be made in 40 CFR 

60.107a(e)(2) to develop a total sulfur-to-H2S (or total reduced 

sulfur-to-H2S) ratio so that the total sulfur monitor can be used 

for both the root cause analysis requirements and for compliance 

with the requirement to limit short-term H2S concentration in 

fuel gas sent to a flare to 162 ppmv without the need for a 

duplicative continuous H2S monitor. Another commenter supported 

the addition of alternative monitoring methods for the sulfur 

content of flare gas, but noted that since the composition of 

flare gas is highly variable, the alternative methods must meet 

continuous monitoring requirements.

Response: We have clarified and consolidated the monitoring 

requirements to allow total reduced sulfur monitoring for 

flares. For the purposes of evaluating the SO2 root cause 

analysis threshold, total sulfur monitoring provides the most 

accurate assessment. However, in most cases, the vast majority 

of sulfur contained in gases discharged to the flare is expected 
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to be in the form of total reduced sulfur compounds, which 

include carbon disulfide, carbonyl sulfide and H2S. Our test 

method for measuring total reduced sulfur includes the use of 

EPA Method 15A as a reference method, and because EPA Method 15A 

measures total sulfur, the total reduced sulfur monitoring 

requirement is equivalent to a total sulfur monitoring method.

As discussed previously, we are relying on the suite of 

flare requirements we are promulgating to limit SO2 emissions at 

the flare. These include optimizing management of the fuel gas

by limiting the short-term concentration of H2S to 162 ppmv 

during normal operating conditions. We expected most refineries 

would already have the H2S monitor and did not consider the use 

of a total sulfur monitor for use in complying with the shortterm 162 ppmv H2S concentration in the fuel gas. As the H2S 

concentration will always be less than the total reduced sulfur 

concentration, it is acceptable to use the total reduced sulfur 

monitor to verify that the fuel gas does not exceed the shortterm H2S concentration of 162 ppmv. Therefore, we have provided

for the use of total reduced sulfur monitors, provided the 

monitor can also meet the 300 ppmv span requirement.

However, we have not provided a correction factor to scale 

down the total reduced sulfur concentration to H2S. The owner or 

operator using this method must essentially be able to 

demonstrate they can achieve a 162 ppmv total reduced sulfur 
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concentration in the fuel gas. The concentration ratio was 

provided for the purposes of the root cause analysis because of 

the costs of adding a total sulfur monitoring system when a dual 

range H2S monitor was already in-place, as well as the expected 

accuracy needed for the system to assess the SO2 root cause 

analysis threshold. As few cases would exist where the flaring 

event would be right at the SO2 root cause analysis threshold of 

500 lb in any 24-hour period, inaccuracies associated with the 

average total sulfur-to-H2S ratio were not expected to be 

significant. 

On the other hand, the short-term 162 ppmv H2S concentration 

in the fuel gas must be continuously maintained, and the total 

sulfur-to-H2S ratio at these low concentrations is expected to be 

highly variable, depending on the efficiency of the amine 

scrubber systems. As the amine scrubber systems, according to 

previous industry comments, are not effective for reduced sulfur 

compounds other than H2S, the non-H2S reduced sulfur

concentration is expected to be fairly constant, with most of 

the fluctuations in total sulfur content being attributable to 

fluctuations in H2S concentrations. Consequently, we have 

determined that the inaccuracies of the ratio approach are not 

acceptable for continuously demonstrating that the short-term 

concentration in the fuel gas does not exceed 162 ppmv H2S. 

Therefore, owners or operators of affected flares may use the 
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direct output of a total reduced sulfur monitor to assess 

compliance with the short-term 162 ppmv H2S concentration in the 

fuel gas, or they must install a continuous H2S monitor.

Comment: One commenter supported the proposed amendment 

revising the span value for fuel gas H2S analyzers to match the 

span requirements in 40 CFR part 60, subpart J, stating this 

will save time and money. However, the commenter stated that the 

span value for the flare H2S monitoring option is too restrictive 

and suggested that requirements in Appendix F to part 60 provide 

sufficient quality assurance/quality control (QA/QC) without the 

need for the rule to specify the span range. The commenter also 

requested clarification of the sulfur monitor span for flares, 

suggesting that it should be based on the H2S concentration 

limits and that engineering calculations can be used to assess 

exceedances of the SO2 root cause analysis threshold of 500 lb in 

any 24-hour period.

Response: The H2S span value is at 300 ppmv to verify 

compliance with the H2S concentration requirement for the fuel 

gas; the span of the total sulfur monitor needs to be much 

greater than that to be able to quantify the sulfur content in 

streams containing several percent sulfur. For units that use 

the H2S analyzers both to assess compliance with the short-term 

162 ppmv H2S concentration requirement for the fuel gas and to 

assess exceedances of the SO2 root cause analysis threshold of 
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500 lb in any 24-hour period, a dual range monitor will be 

necessary. For the purposes of the SO2 root cause analysis

threshold of 500 lb in any 24-hour period, we intended that the 

monitor be capable of accurately determining the sulfur 

concentration for the range of concentrations expected to be 

seen at the flare. We are particularly interested in quantifying 

the concentrations of high sulfur-containing streams as these 

would be the streams most likely to trigger a root-cause 

analysis at low flows. We proposed that the span for the flare 

sulfur monitor be selected from a range of 1 to 5 percent. We 

agree with the commenter that this may be too restrictive, and

we have revised the span requirements to be determined, based on 

the maximum sulfur content of gas that can be discharged to the 

flare (e.g., roughly 1.1 to 1.3 times the maximum anticipated 

sulfur concentration), but no less than 5,000 ppmv. A single 

dual range monitor may be used to comply with the short-term 162 

ppmv H2S concentration requirement for the fuel gas and the SO2

root cause analysis threshold monitoring requirement provided 

the applicable span specifications are met. In reviewing the 

span specifications, we noted that span requirements were 

inadvertently omitted from the total reduced sulfur compound 

monitoring alternative. The purpose of these monitors is 

identical to the H2S monitoring alternative, and the same span 

considerations apply for these monitors.
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We disagree that the QA/QC procedures in Appendix F to part 

60 are sufficient without specifying the span values. Procedure 

1 of Appendix F to part 60 defines “span value” as: “The upper 

limit of a gas concentration measurement range that is specified 

for affected source categories in the applicable subpart of the 

regulation.” The concentrations used for calibration are based 

on the span value. Several of the QA/QC procedures in Appendix F 

are undefined if the span value is not defined in the rule.

Comment: Commenters stated that time is needed to install 

continuous monitors and to make other necessary changes (such as 

installing a flare gas recovery system or additional amine 

treatment) to comply with all the flare requirements (e.g., 

limiting short-term H2S concentration to 162 ppmv, long-term 60 

ppmv H2S fuel gas concentration limit, flare management plan, 

root cause analysis and continuous monitoring), especially 

considering how quickly a flare may become a modified affected 

source. While most commenters focused on the amount of time 

needed to install equipment to comply with the long-term 60 ppmv 

H2S fuel gas concentration limit, other commenters asserted that 

additional time for activities, such as planning and re-piping,

would be needed to meet the standards. Commenters requested 

differing amounts of additional time generally ranging from 3 to 

5 years. Commenters noted that the additional time would allow 

owners and operators to schedule any process unit shutdowns 
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needed to install new equipment or monitors during a turnaround. 

One commenter recommended that the extra time to begin root 

cause analyses provided to refiners committing to install flare 

gas recovery systems should also be provided to refiners 

committing to expand an existing flare gas recovery system. 

Commenters also noted that experience implementing SCAQMD Rule 

1118 suggests that there will be difficulty obtaining and 

installing continuous monitors in less than 3 years due to the 

availability of monitor manufacturers and the need to stage the 

installation of monitors at refineries with multiple affected 

flares. One commenter requested that the EPA consider a 

compliance schedule in 40 CFR part 60, subpart Ja that is 

consistent with compliance schedules in consent decrees. 

Commenters objected to phasing out the additional time after the 

rule has been in place for 5 years.

One commenter requested clarification regarding the trigger 

date from which the additional time to comply with the flare 

provisions (e.g., 2 years when installing a flare gas recovery 

system) begins. The commenter questioned whether the trigger 

date is when construction starts, at startup or when the stay is 

removed (or whichever is later). Another commenter agreed that 

the EPA should set the compliance time based on the initial 

startup of the modification. The commenter noted that the EPA 

should follow the 40 CFR part 60 General Provisions for 
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performance test timing and the 40 CFR part 63 General 

Provisions for compliance timing.

Response: As we are no longer applying the long-term 

60 ppmv H2S fuel gas concentration limit to flares, the comments 

related to the amount of time needed to comply with a long-term 

60 ppmv H2S fuel gas concentration limit are moot. We do, 

however, recognize that a flare modification can occur much more 

quickly than modifications of traditional process-related 

emission sources. Therefore, we evaluated the comments regarding 

the amount of time needed to meet the various requirements for 

flares while keeping the 40 CFR part 60, subpart Ja flare 

modification provision in mind. We discuss each requirement and 

the time for demonstrating compliance with that requirement in 

the following paragraphs.

We find it appropriate to require flares to meet the H2S 

concentration upon startup of the affected flare because, as 

indicated by earlier comments, it is likely that most refiners 

are already operating their fuel gas collection and treatment 

systems to achieve a short term H2S concentration of 162 ppmv. 

Thus, fuel gas discharged to the flare during normal operations 

will have already been treated to meet this limit in the 

existing refinery fuel gas collection and treatment system. We 

also note that consent decrees typically require immediate 

compliance with this requirement. Therefore, the final rule 
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requires all refineries with new, modified and reconstructed

flares to manage the fuel gas sent to these flares such that 

they meet the short-term H2S concentration of 162 ppmv upon 

startup of the affected flare.

As we noted in the preamble to the proposed amendments, 

many of the connections that would trigger applicability to 40 

CFR part 60, subpart Ja are critical to the safe and efficient 

operation of the refinery. These connections can, and often 

must, be installed quickly. At the same time, nearly all 

refineries will need time for planning, designing, purchasing

and installing (including any necessary re-piping) sulfur and 

flow monitors that are newly required by subpart Ja. Some 

refineries will elect to add flare gas recovery and/or sulfur 

treatment equipment to minimize their emissions as part of the 

evaluations conducted, as required by the new flare management 

plan requirements, and time will be needed for planning, 

designing, purchasing and installing these components as well.

Given that many flares will become modified affected sources 

relatively quickly, owners and operators will be competing with 

one another for the services and products of a finite number of 

vendors who provide the necessary monitors and other equipment.

Several commenters specifically noted availability of monitors 

as an issue when complying with SCAQMD Rule 1118. As such, we 

find that immediate compliance with some of the requirements for 
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flares, such as the planning, designing, purchasing and 

installation of (including any necessary re-piping) sulfur and 

flow monitors, may be difficult for operators to meet,

especially in situations where quick connections to the flare 

are made. A phased compliance schedule allows for the operators 

to comply with some requirements associated with flares, such as 

optimizing their fuel gas system to achieve a short-term H2S 

concentration of 162 ppmv immediately, while allowing time to 

install monitoring equipment to comply with the other elements 

of the standards. 

A phased compliance schedule will also allow owners and 

operators to minimize process interruption by coordinating the 

installation of monitoring equipment with process shutdowns or 

turnarounds. In addition to providing operating flexibility to 

the refinery, we are taking into consideration the fact that a 

process shutdown and subsequent startup can generate significant 

emissions, even if the refinery is taking care to minimize those 

emissions. We consider a phased compliance schedule that allows 

owners and operators to avoid startups and shutdowns that are 

not necessary to maintain the equipment and process to be 

environmentally beneficial overall and the best system of 

emissions reduction for a quickly modified flare. Considering 

the time needed to complete engineering specifications, order 

and install the required monitoring equipment, and considering 
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the need to coordinate this installation with process unit 

shutdown or turnarounds, we determined that completion of these 

activities within 3 years is consistent with the best system of 

emissions reductions for quickly modified flares.

We note, however, that this phased compliance schedule for

the flare requirements in 40 CFR part 60, subpart Ja is intended 

for those situations when a flare modification occurs quickly 

and the owner or operator does not have significant planning 

opportunities to install the required monitors or implement the 

selected flare minimization options without significant process 

interruptions. For a future large project on a schedule that 

includes time for planning, designing, purchasing and installing 

equipment and monitors, we expect that the owner and operator 

will have time to assess whether or not the refinery flares will 

become affected sources through modification. If a project will 

result in the modification of a flare, we expect that the owner 

or operator will then plan how to meet the standards in subpart 

Ja as part of the project itself, including the installation of 

the monitoring systems and the development of a flare management 

plan. Because of the ability to plan ahead, flares that are 

modified as part of a large project will not have all of the 

difficulties meeting the subpart Ja flare requirements upon 

completion of the modification as those flares that are modified 

quickly. Therefore, we find that compliance with the flare
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requirements upon startup of the modified flare is appropriate

and consistent with the best system of emissions reduction for 

large projects resulting in a modification of a flare. Thus, we 

determined that the appropriate time period for compliance with 

the flare standards is either: (1) 3 years from the effective

date of these amendments or (2) upon startup of the modified 

flare, whichever is later.11 In this manner, flares that become 

subject to subpart Ja quickly, based on a small safety-related 

connection (or have already become subject to subpart Ja based 

on a modification prior to the effective date of these 

amendments), will have up to 3 years from the effective date of 

these amendments to comply fully with the flare standards, but 

flares that are modified as the result of a significant project, 

such as the installation of a new process unit that will be tied 

into an existing flare, will effectively be required to comply 

with the flare standards at the startup of the new process unit. 

Therefore, for the reasons described above, we are 

providing flares that become affected facilities subject to 40 

CFR part 60, subpart Ja through modification with a phased 

compliance schedule for the flare standards, as described in 

 11 For the purposes of this subpart, startup of the modified 

flare occurs when any of the activities in 40 CFR 60.100a(c)(1) 

or (2) is completed (e.g., when a new connection is made to a 

flare such that flow from a refinery process unit or ancillary 

equipment can flow to the flare via that new connection).
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this paragraph. The final rule requires all new, modified and 

reconstructed flares to meet the short-term 162 ppmv H2S 

concentration requirement upon startup of the affected flare. 

Additionally, we are requiring owners and operators of modified 

flares to complete and implement the flare management plan under 

40 CFR 60.103a(a) by 3 years from the effective date of these 

amendments or upon startup of the modified flare, whichever is 

later. We are requiring owners and operators of modified flares 

to begin conducting root cause and corrective action analyses 

under 40 CFR 60.103a(c) and (d) no later than 3 years from the 

effective date of these amendments or the date of the startup of 

the modified flare, whichever is later, so that the facility can 

complete the flare management plan and establish baseline flow 

rates prior to performing the root cause and corrective action 

analyses. We are also requiring owners and operators of modified 

flares to install and begin operating the monitors necessary to 

demonstrate compliance with these provisions, as required under 

40 CFR 60.107a(e) through (g) within 3 years from the effective 

date of these amendments or by the startup date of the modified 

flare, whichever is later, when the monitors are not already in 

place. Compliance with the phased compliance schedule 

constitutes compliance with the flare standards as of the 

effective date.

C. Other Comments
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Comment: Several commenters objected to the change to the 

definition of “refinery process unit.” The commenters objected 

to the proposed amendments to include coke gasification, loading 

and wastewater treatment, stating the change makes the term more 

expansive. The commenters stated that the EPA did not evaluate 

the impacts or explain the consequences of the revised 

definition. One commenter stated that product loading is 

generally considered part of the refinery process unit to which 

it is associated and that wastewater treatment is a utility. 

Another commenter suggested that the definition specify SIC 2911 

(as in Refinery MACT 1).

Response: The original definition of “refinery process 

unit” in 40 CFR part 60, subpart J and the definition of

“refinery process unit” promulgated in 40 CFR part 60, subpart 

Ja in June 2008 read as follows: “Refinery process unit means 

any segment of the petroleum refinery in which a specific 

processing operation is conducted.” Thus, to be considered a 

refinery process unit, only two criteria are needed: (1) the 

unit must be located at a petroleum refinery; and (2) the unit 

must be used to conduct “a specific processing operation.” The 

definition does not directly limit the scope of “processing 

operations.” That is, the definition of refinery process unit 

does not limit process operations to distillation, redistillation, cracking or reforming, and it is not limited to 
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only those processes used to produce gasoline, kerosene, fuel 

oils, etc. In the proposed amendment to this definition, we 

listed “operations” that we construed as conducting a “specific 

processing operation” when these operations are located at a 

petroleum refinery. Consequently, we considered the proposed 

inclusion of examples of refinery process units to be a 

clarification of the existing definition rather than an 

expansion of the original definition.

We reviewed the impact of the proposed revision of this 

definition on 40 CFR part 60, subpart Ja, as well as its 

historic use in 40 CFR part 60, subpart J. The term “refinery 

process unit” is used primarily in the definitions of certain 

affected facilities, “process gas” and “process upset gas” in 

subparts J and Ja. The term is also used in the flare provisions 

in subpart Ja. With respect to the definitional terms, there can 

be no issue with including the designation of “refinery process 

unit” within the definitions for specific process units. 

“Process gas” is not used at all in either rule, although it was 

revised between proposal and promulgation of subpart J. In 

response to a comment that the definition of “process gas” 

“should have included the non-hydrocarbon gases produced by 

various process units in a refinery,” the EPA responded: “The 

definition has been revised to include all gases produced by 

process units in a refinery except fuel gas and process upset 
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gas.” (See page 127 of Background Information For New Source

Performance Standards, Volume 3, Promulgated Standards (BID Vol. 

3), EPA 450/2-74-003 (Feb. 1974), Docket Item No. EPA-HQ-OAR2007-0011-0082). The definition had actually been revised to 

include “any gas generated by a petroleum refinery process 

unit.” The response in BID Vol. 3 suggests that the EPA 

considered “refinery process units” and “process units in a 

refinery” to have the same meaning, and there is no mention of 

limiting what is considered to be a “refinery process unit” or a 

“process units in a refinery.” 

“Process upset gas” is used only to provide an exemption to 

the H2S concentration limit for process upset gas sent to a 

flare. See 40 CFR 60.104(a)(1), 60.103a(h). Therefore, a narrow

definition of “refinery process unit” would only limit those 

gases sent to a flare that would qualify as “process upset gas.” 

For example, if a coke gasifier is not a refinery process unit, 

then gases generated during the startup, shutdown or malfunction 

of a coke gasifier located at the refinery would not be “process 

upset gas” and would be required to comply with the requirement 

to limit short-term H2S concentration in fuel gas to 162 ppmv if 

sent to a flare. We find that the historical application of the 

“process upset gas” exclusion has considered a broad definition 

of what constitutes a “refinery process unit.” 
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For 40 CFR part 60, subpart Ja, the definition of “refinery 

process unit” also impacts the flare provisions. Based on the 

proposed revisions of “refinery process unit,” it was clearly 

our intent that a broad definition of “refinery process unit” 

should apply to the flare requirements. Specifically, we

intended that a flare modification occurs when a wide range of 

equipment at the petroleum refinery is newly connected to the 

flare. It was also our intent that the flare management plan

consider flare minimization methods for this broadly defined 

range of equipment referred to collectively as “refinery process 

units.”

Based on our review of the impacts of changes to the

definition of “refinery process unit,” and considering all of 

the comments received, we maintain that the existing definition 

of “refinery process unit” is broad and should be broadly 

interpreted. For consistency between 40 CFR part 60, subparts J 

and Ja, we have elected to maintain the existing definition and 

not include an example list of refinery process units within the 

definition. However, to clarify that a modification to a flare 

occurs when these types of equipment are connected to the flare, 

we revised the language in the flaring provisions to refer to 

“refinery process units, including ancillary equipment.” This 

revision is made to clarify our original intent that coke 

gasification units, storage tanks, product loading operations
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and wastewater treatment systems, as well as pressure relief 

valves, pumps, sampling vents, continuous analyzer vents and 

other similar equipment are units from which a connection to a 

flare would trigger a flare modification and generate gas 

streams that should be considered in the flare management plan.

We have included in the final amendments a definition of 

“ancillary equipment.” Specifically:

Ancillary equipment means equipment used in conjunction 

with or that serve a refinery process unit. Ancillary 

equipment includes, but is not limited to, storage tanks, 

product loading operations, wastewater treatment systems, 

steam- or electricity-producing units (including coke 

gasification units), pressure relief valves, pumps, 

sampling vents, and continuous analyzer vents.

Sulfur recovery plants are also units from which a 

connection to a flare would trigger a flare modification and 

generate gas streams that should be considered in the flare 

management plan. We recognize that on-site sulfur recovery 

plants are considered refinery process units, and we proposed 

amendments to the definitions of “refinery process unit” and 

“sulfur recovery plant” to clarify that we consider a sulfur 

recovery plant to be “a segment of the petroleum refinery in 

which a specific processing operation is conducted.” However, 

the strict definition of “refinery process unit” would only 

apply to sulfur recovery plants physically located at the 

refinery. As 40 CFR part 60, subpart Ja also applies to off-site 

sulfur recovery plants (see 40 CFR 60.100(a) and 40 CFR 
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60.100a(a)), we found it potentially contradictory to define a 

sulfur recovery plant located outside the refinery as a 

“refinery process unit,” so we are also not finalizing the 

proposed amendment to include the term “all refinery process 

units” in the definition of “sulfur recovery plant.” However, 

while connections to a refinery flare from an off-site sulfur 

recovery plant are not expected to be common, off-site sulfur 

recovery plants are subject to subpart Ja. We clarify in this 

response that we would consider such a connection to a flare to 

be from a “refinery process unit, including ancillary 

equipment,” such that connecting an off-site sulfur recovery 

plant that is subject to subpart Ja to a flare at a refinery

would cause that flare to be a modified flare subject to subpart 

Ja.

Further, in reviewing the definition of “sulfur recovery 

plant,” we noticed an inadvertent error that also suggests that 

the sulfur recovery plant must be located at a petroleum 

refinery, which is not consistent with the applicability 

provisions in 40 CFR 60.100(a) and 40 CFR 60.100a(a). 

Specifically, we inadvertently omitted the word “produced” in 

this first sentence, so we are amending the definition of 

“sulfur recovery plant” to clarify that a sulfur recovery plant 

recovers sulfur from sour gases “produced at the petroleum 

refinery.” Thus, we are amending the definition of “sulfur 
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recovery plant” to correct inadvertent errors and to clarify 

that off-site sulfur recovery plants are included in the 

definition of “sulfur recovery plant,” as these plants are 

expressly considered to be affected facilities in 40 CFR part 

60, subpart Ja.

Comment: Commenters supported the revised definition of 

“delayed coking unit,” but stated that, since 40 CFR part 60,

subpart Ja only sets standards for the coke drums, the 

definition should just include the coke drums associated with a 

single fractionator. The commenters stated that the definition 

should not include the fractionator itself because VOC emissions 

from the fractionator are covered by NSPS for equipment leaks.

Response: The proposed amendments to the definition of 

“delayed coking unit” specifically listed the primary components 

of the delayed coking unit. In particular, based on the 

operation of the delayed coking unit, we find that the 

fractionator is an integral part of the delayed coking unit. The 

fresh feed to the delayed coking unit is generally introduced in 

the fractionator tower bottoms receiver. This integral use of 

the fractionator is different than the use of fractionators used 

for other units defined in 40 CFR part 60, subpart Ja, such as 

the fluid catalytic cracking unit (FCCU). For the FCCU, fresh 

feed is introduced in the riser, which is part of the affected 

facility in subpart Ja. As the feed to the delayed coking unit
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is to the fractionator, we find that the fractionator is an 

integral part of the delayed coking unit, so we specifically 

include it as part of the affected facility. While our proposed 

amendments covered only the major components of the delayed 

coking unit, upon our review of the definition based on the 

comments received, we note that there are several other 

components of the delayed coking unit that are integral to the 

operation of the delayed coking unit. Additionally, even though 

the standards are specific to the coke drum, many of these 

integral components are interconnected and necessary for the 

delayed coking unit to meet the applicable standards. Based on 

our review of the operation of a delayed coking unit, we also 

include coke cutting and blowdown recovery equipment in the 

final definition because this equipment is also integral to the 

overall cyclical operation of the process unit. The definition 

of “delayed coking unit” has been amended in the final rule to 

read as follows:

Delayed coking unit means a refinery process unit in which 

high molecular weight petroleum derivatives are thermally 

cracked and petroleum coke is produced in a series of 

closed, batch system reactors. A delayed coking unit

includes but is not limited to all of the coke drums 

associated with a single fractionator; the fractionator, 

including bottoms receiver and overhead condenser; the coke 

drum cutting water and quench system, including the jet 

pump and coker quench water tank; process piping and 

associated equipment such as pumps, valves and connectors; 

and the coke drum blowdown recovery compressor system.
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Comment: One commenter stated that 40 CFR part 63, subpart 

LLLLL indicates at 40 CFR 63.8681(e) that 40 CFR part 60, 

subpart J does not apply for asphalt blowing stills subject to 

subpart LLLLL, and the commenter requested similar clarification 

for 40 CFR part 60, subpart Ja by exempting this process in 40 

CFR 60.100a.

Response: We reviewed the requirement in 40 CFR part 63, 

subpart LLLLL. Due to the O2 content of this process gas, we 

agree that it is not suitable for recovery as fuel gas and 

subsequent amine treatment; therefore, it is not BSER for 

combustion controls used on asphalt blowing stills to meet the 

H2S concentration limits (or alternative SO2 emissions limits). 

We reviewed 40 CFR 60.100a, but we feel a blanket exemption from 

40 CFR part 60, subpart Ja is not necessary. Instead, we have 

included an exemption within the definition of fuel gas similar 

to the exemptions included for combustion controls on vapors 

collected and combusted from wastewater treatment and marine 

vessel loading operations. Specifically, we amended the 

definition of fuel gas in 40 CFR 60.101a to clarify that fuel 

gas does not include vapors that are collected and combusted to 

control emissions from asphalt processing units (i.e., asphalt 

blowing stills).

Comment: One commenter recommended that the exclusion from 

the definition of “fuel gas” be extended to vapors “from marine 
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vessel loading operations or waste management units that are 

collected and combusted” without any reference to a federal 

requirement. At a minimum, the commenter stated that marine 

benzene loading under 40 CFR part 61, subpart BB; the wastewater 

provisions of 40 CFR part 63, subpart G; remediation efforts 

regulated under Resource Conservation and Recovery Act (RCRA) 

corrective action; and RCRA 7003 orders should be added to the 

exclusion. 

Response: We were originally concerned that removing the 

reference to a federal standard may inadvertently exempt the use 

of these vapors when used in process heaters or boilers. We 

determined that it was not BSER to require thermal oxidizers 

used to comply with the cited federal standards to comply with 

the H2S concentration limits due to the typically remote location 

of the combustion sources (control devices) relative to refinery 

process units (see technical memorandum entitled Fuel Gas 

Treatment of Marine Vessel Loading and Wastewater Treatment Unit 

Off-gas, in Docket ID No. EPA-HQ-OAR-2007-0011). However, if 

these gases are currently routed to a fuel gas system or 

directly to a process heater or boiler, treatment of the fuel 

gas to meet the SO2 emissions limits or the H2S concentration

limits is expected to be economically viable. Additionally, 

these gases are expected to be only a small portion of the fuel 

gas combusted in these units, and the refinery has an option to 
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over-treat the primary fuel gas so that gases from the 

wastewater treatment system or marine vessel loading operation 

can remain untreated while the fuel gas combustion device itself 

can comply with the SO2 emissions limits or the H2S concentration 

limits, based on the mixture of fuels used in the device. 

In reviewing the rules suggested by the commenter, as well 

as those we originally listed, we noted that acceptable “control 

devices” or “combustion units” in these rules include process 

heaters and boilers. We did not intend to exclude vapors that 

are collected and routed to a process heater or boiler to be 

exempt from the definition of fuel gas. In other words, when 

developing this exclusion, we specifically considered the 

combustion of these gases via a thermal oxidizer or flare 

currently located at the marine vessel loading or wastewater 

treatment location. These remote combustion devices were really 

the subject of the analysis, but we did not want to exclude 

these combustion units themselves because other fuel gas is 

often fed to these units to ensure adequate combustion of the 

vapors being controlled. It is clear from our rationale and the 

description of the exemption included in the preamble of the 

proposed rule that the exemption was intended “to exempt vapors 

that are collected and combusted in an air pollution control 

device installed to comply with” specific wastewater or marine 

vessel loading emissions standards. (72 FR 27180 and also at 
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27183; emphasis added.) Process heaters or boilers would not be 

“installed” to comply with these provisions, and it was not our 

intent to exclude vapors sent to these types of combustion 

units. However, the regulatory text is more ambiguous and 

appears to exclude any vapors collected and combusted, 

regardless of where they are combusted. As such, we are amending 

this exclusion to better represent our original intent. 

Additionally, with the added clarity in the regulatory 

text, it seems appropriate to extend this exclusion to control 

devices used at these locations regardless of why the emission 

controls were installed. That is, while we originally considered 

air pollution control devices that were mandated by the EPA, we 

see no reason to discriminate against air pollution control 

devices that were installed voluntarily to reduce the emissions 

from these sources. Further, we intend to clarify that gases off 

the sour water system, including the sour water stripper, would 

likely contain higher amounts of reduced sulfur and would be 

economically viable to treat. Therefore, we are also clarifying 

that the exemption does not extend to the sour water system. 

Therefore, the amended definition of “fuel gas” in both 40 CFR 

part 60, subparts J and Ja states that fuel gas “does not 

include vapors that are collected and combusted in a thermal 

oxidizer or flare installed to control emissions from wastewater 

treatment units other than those processing sour water, marine 
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Page 160 of 293

tank vessel loading operations, or asphalt processing units 

(i.e., asphalt blowing stills).” 

With respect to remediation efforts conducted under RCRA 

corrective actions, we are unwilling to grant such an exclusion 

from the definition of “fuel gas” in 40 CFR part 60, subpart Ja. 

First, we anticipate that most vapors from remediation efforts 

would be low in sulfur and, if so, the owner or operator could

apply for the alternative monitoring methods provided in the 

rule. Also, although some remediation efforts may occur in 

remote locations, many of the remediation efforts are conducted 

in reasonable proximity to existing process units. Finally, the 

range of activities included in RCRA remediation efforts is 

broad, and we have little information regarding the number and 

types of RCRA remediation activities that are being conducted.

The commenter provided no description of such activities, nor 

did they provide a reasonable rationale as to why the vapors 

from these activities should be exempted.

V. Summary of Cost, Environmental, Energy and Economic Impacts

A. What are the emission reduction and cost impacts for the 

final amendments?

The emission reduction and cost impacts presented in this 

section for flares are revised estimates for the impacts of the 

final requirements of 40 CFR part 60, subpart Ja for flares, as 

amended by this action. The table shows the differences in 
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anticipated impacts between these final amendments to subpart Ja 

and the final June 2008 NSPS requirements of 40 CFR part 60, 

subpart Ja, which were estimated assuming only 40 flares would 

trigger applicability to the rule. The impacts are presented for 

400 affected flares that commence construction, reconstruction 

or modification that will be required to comply with this final 

rule. We anticipate that most of the flares would become 

affected due to the modification provisions for flares set forth 

in the final June 2008 subpart Ja rule. For this analysis, we 

assumed that 90 percent of the flares will be modified or 

reconstructed and 10 percent of the flares will be newly 

constructed. Further, we estimate that 30 percent of the 400 

affected flares, or 120 flares, either would meet the definition 

of “emergency flare” in 40 CFR part 60, subpart Ja or would be 

equipped with a flare gas recovery system such that robust 

sulfur and flow monitoring would not be required. Therefore, the 

values in Table 3 of this preamble include the costs and 

emissions reductions for 400 flares to comply with the flare 

management plan and root cause and corrective action analyses

requirements and for 280 flares to comply with the sulfur and 

flow monitoring requirements. The cost and emissions reductions 

for the affected flares to comply with the short-term H2S 

concentration of 162 ppmv in the fuel gas are included in the 

baseline rather than the incremental impacts because this limit 
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is unchanged from the requirements in subpart J. For further 

detail on the methodology of these calculations, see 

Documentation of Impact Estimates for Fuel Gas Combustion Device 

and Flare Regulatory Options for Amendments to the Petroleum 

Refinery NSPS, in Docket ID No. EPA-HQ-OAR-2007-0011.

We estimate that the final requirements for flares will 

reduce emissions of SO2 by 3,200 tons per year (tons/yr), NOX by

1,100 tons/yr and VOC by 3,400 tons/yr from the baseline. The 

estimated annual cost, including annualized capital costs, is a 

cost savings of about $79 million (2006 dollars) due to the 

replacement of some natural gas purchases with recovered flare 

gas and the retention of intermediate and product streams due to 

a reduction in the number of malfunctions associated with

refinery process units and ancillary equipment connected to the 

flare. Note that not all refiners will realize a cost savings 

since we only estimate that refineries with high flare flows 

will install vapor recovery systems. Although the rule does not 

specifically require installation of flare gas recovery systems, 

we project that owners and operators of flares receiving high 

waste gas flows will conclude, upon installation of monitors, 

implementation of their flare management plans, and 

implementation of root causes analyses, that installing flare 

gas recovery would result in fuel savings by using the recovered 

flare gas where purchased natural gas is now being used to fire 
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equipment such as boilers and process heaters. The flare 

management plan requires refiners to conduct a thorough review 

of the flare system so that flare gas recovery systems are 

installed and used where these systems are warranted. As part of 

the development of the flare management plan, refinery owners 

and operators must provide rationale and supporting evidence 

regarding the flare waste gas reduction options considered, the 

quantity of flare gas that would be recovered or prevented by 

the option, the BTU content of the flare gas and the ability or 

inability of the reduction option to offset natural gas 

purchases. In addition, consistent with E.O. 13563 (Improving 

Regulation and Regulatory Review, issued on January 18, 2011), 

for facilities implementing flare gas recovery, we are 

finalizing provisions that would allow the owner or operator to 

reduce monitoring costs and the number of root cause analyses, 

corrective actions, and corresponding recordkeeping and 

reporting they would need to perform. We estimate that the 

final requirements for flares will reduce emissions of SO2 by 

3,200 tons per year (tons/yr), NOX by 1,100 tons/yr, and VOC by 

3,400 tons/yr from the baseline. The overall cost effectiveness 

is a cost savings of about $10,000 per ton of combined 

pollutants removed. The estimated nationwide 5-year emissions 

reductions and cost impacts for the final standards are 

summarized in Table 3 of this preamble.
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Table 3. National Emission Reductions and Cost Impacts for 

Petroleum Refinery Flares Subject to Amended Standards Under 40 

CFR part 60, subpart Ja (Fifth Year After the Effective Date of 

these Final Rule Amendments)

Subpart Ja 

Requirements

Total 

capital 

cost 

($1,000)

Total 

annual

cost 

without 

credit

($1,000/ 

yr)

Natural 

gas 

offset/ 

product 

recovery 

credit 

($1,000)

Total 

annual

cost

($1,000/ 

yr)

Annual 

emission 

reductions 

(tons 

SO2/yr)

Annual 

emission 

reductions 

(tons 

NOX/yr)

Annual 

emission 

reductions 

(tons 

VOC/yr)

Cost 

effectiveness 

($/ton 

emissions

reduced)

Estimates 

from June 

2008 Final 

Rule

40,000 (7,000) 80 6 200 (23,000)

Revised 

Estimates 

for 

Amendments 

460,000 100,000 (180,000) (79,000) 3,200 1,100 3,400 (10,000)

We also estimate that the final requirements for flares will 

result in emissions reduction co-benefits of CO2 equivalents by 

1,900,000 metric tonnes per year, predominantly as a result of 

our estimate of the largest flares employing flare gas recovery 

and to a lesser extent, as a result of the root cause analyses 

applicable to all flares.

The cost, environmental and economic impacts for the final 

amendments to 40 CFR part 60, subpart Ja for process heaters are 

not expected to be different than those reported for the final 

June 2008 standards. We expect owners and operators to install 

the same technology to meet these final amendments that we 

anticipated they would install to meet the June 2008 final 

subpart Ja requirements (i.e., ultra-low NOX burners). We did 

Comment [A3]: EPA Response: The impacts are 

not “incremental” to the 2008 rule ,which was 

stayed; in other words, the 2008 rule did not 

actually require any flare controls so there was no 

cost; we are now reassessing the impacts of the rule 

based on a new flare count; the 460 million we show 

for impacts of this rule is not in addition to the 40 

million estimated in 2008; it is instead of, hence this 

is not an incremental difference. Revised the 

language to remove references to 

“incremental”analysis.

Comment [A4]: Interagency Comment: OK, but 

please include a note so that the reader understands 

what is going on. Perhaps something like, “All costs 

in this table are relative to the baseline used for the 

2008 final rule.” Otherwise it may be confusing.
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revise our emission estimates based on the type of process 

heater, creating separate impacts for forced draft process 

heaters and natural draft process heaters. Dividing process 

heaters into separate subcategories, based on the draft type,

required us to develop new distributions of baseline emissions 

for each type of process heater. The baseline emission estimates 

for natural draft process heaters are slightly lower than those 

developed for the existing subpart Ja requirements (per affected 

process heater), but the average emission reduction achieved by 

ultra-low NOX burners was adjusted to 80 percent (rather than 75 

percent used for generic process heaters). For forced draft 

process heaters, the baseline (i.e., uncontrolled) emissions 

rate for forced draft process heaters was revised slightly 

upward, based on the available emissions data. Due to these 

differences, the mix of controls needed to meet a 40 ppmv 

emissions limit was no longer cost effective for forced draft 

process heaters, but the emission reductions associated with 

process heaters complying with the 60 ppmv standard were higher 

than those previously estimated for generic process heaters.

Thus, the creation of new subcategories of process heaters with 

different emissions limits for each subcategory did not impact 

the control or compliance methods used by the facilities (i.e., 

BSER in all cases was based on the performance of advanced 

combustion monitoring controls in conjunction with ultra-low NOX
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burners) and did not change the estimated compliance costs. As 

we do not have adequate data regarding the prevalence of natural 

draft process heaters versus forced draft process heaters that 

will become subject to the rule, we used the emission reductions 

estimated for the two different types of process heaters as a 

means to bound the range of anticipated NOX emission reductions 

to be from 7,100 to 8,600 tons/yr in the fifth year after the 

effective date of this final rule (see Revised NOX Impact 

Estimates for Process Heaters, in Docket ID No. EPA-HQ-OAR-2007-

0011). We estimated the emission reductions to be 7,500 tons/yr

for the June 2008 final standards, which falls well within the 

anticipated range of emissions reductions for the standards we 

are finalizing here. Given the uncertainty in the emissions 

estimates, as well as the uncertainty in the relative number of 

natural draft process heaters versus forced draft process 

heaters, we concluded that the impacts previously developed for 

subpart Ja accurately represent the impacts for process heaters 

in these final amendments.

We note that, in the preamble to the June 2008 final 

standards, we estimated costs and emissions reductions for 30 

fuel gas combustion devices, but we subsequently determined that 

those estimates did not fully account for the number of affected 

flares (which, at the time, were considered a subset of fuel gas 

combustion devices). Therefore, in the preamble to the December 
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2008 proposed amendments, we presented revised emission 

reduction and cost estimates for affected fuel gas combustion 

devices. As previously explained, we are not finalizing the 

long-term 60 ppmv H2S fuel gas concentration limit for flares, as 

proposed, and we revised our cost estimates accordingly. Because 

these final amendments consider flares to be a separate affected 

source, the emission reductions and costs for fuel gas 

combustion devices are not affected by these final amendments 

and are not included in this preamble. Rather, the final 

emission reduction and cost estimates for fuel gas combustion 

devices are very close to the impacts presented in the June 2008 

final rule; the details of the analysis and the final impacts 

are presented in Documentation of Impact Estimates for Fuel Gas 

Combustion Device and Flare Regulatory Options for Amendments to 

the Petroleum Refinery NSPS, in Docket ID No. EPA-HQ-OAR-2007-

0011. 

The final amendments to 40 CFR part 60, subpart J are 

technical corrections or clarifications to the existing rule and 

should have no negative emissions impacts.

B. What are the economic impacts?

The total annualized compliance costs are estimated to save

about $79 million (2006 dollars) in the fifth year after the 

effective date of these final amendments. Note that not all 

refiners will realize a cost savings as only flare systems with 
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high waste gas flows (about 10 percent of all flares) are 

expected to install vapor recovery systems. Alternatively, if no 

refineries install flare gas recovery systems, total annualized 

compliance costs are estimated to be $10.7 million (2006 

dollars) in the fifth year after proposal. Regardless of whether 

any refineries install flare gas recovery systems, we do not 

anticipate any adverse economic impacts associated with this 

regulatory action, as no increase in refined petroleum product 

prices or decrease in refined petroleum product output is

expected.

For more information, please refer to the Regulatory Impact 

Analysis (RIA) that is in the docket for this final rule.

C. What are the benefits?

Emission controls installed to meet the requirements of 

this rule will generate benefits by reducing emissions of 

criteria pollutants and their precursors, including SO2, NOx and 

VOC as well as CO2. SO2, NOx and VOC are precursors to PM2.5

(particles smaller than 2.5 microns), and NOx and VOC are 

precursors to ozone. For this rule, we were only able to 

quantify the health benefits associated with reduced exposure to 

PM2.5 from emission reductions of SO2 and NOx and the climate 

benefits associated with CO2 emission reductions. We estimate the 

monetized benefits of this final regulatory action to be $270 

million to $580 million (2006 dollars, 3-percent discount rate) 
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in the fifth year (2017). The benefits at a 7-percent discount 

rate for health benefits and 3-percent discount rate for climate 

benefits, are $240 million to $530 million (2006 dollars). For 

small flares only, we estimate the monetized benefits are $170 

million to $410 million (3-percent discount rate) and $150 

million to $370 million(7-percent discount rate for health 

benefits and 3-percent discount rate for climate benefits). For 

large flares only, we estimate the monetized benefits are $93 

million to $160 million (3-percent discount rate) and $88 

million to $150 million (7-percent discount rate for health 

benefits and 3-percent discount rate for climate benefits).

Using alternate relationships between PM2.5 and premature 

mortality supplied by experts, higher and lower benefits 

estimates are plausible, but most of the expert-based estimates 

fall between these two estimates.12 A summary of the monetized 

benefits estimates by pollutant for all flares at discount rates 

of 3 percent and 7 percent is in Table 4 of this preamble. 

Several benefits categories, including direct exposure to SO2 and 

NOx benefits, ozone benefits, ecosystem benefits, and visibility 

benefits are not included in these monetized benefits. All 

estimates are in 2006 dollars for the year 2017.

 12 Roman, et al., 2008. Expert Judgment Assessment of the 

Mortality Impact of Changes in Ambient Fine Particulate Matter 

in the U.S., Environ. Sci. Technol., 42, 7, 2268 – 2274.
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Table 4. Summary of the Monetized PM2.5 and CO2 Benefits for 

Amended Petroleum Refineries Standards (millions of 2006 

dollars)a 

Pollutant

Emission 

reductions 

(tons per 

year)

Total monetized 

benefits

(3 percent 

Discount)

Total monetized 

benefits

(7 percent 

Discount)

With Flare Gas Recovery

PM2.5 Benefitsb

SO2 3,200 $210 to $510 $190 to $460

NOX 1,100 $7.1 to $18 $6.4 to $16

PM Total: $220 to $530 $190 to $480

CO2 Benefitsc 1,900,000d $46 $46

Total 

Monetized 

Benefits:

$260 to $580 $240 to $520

Without Flare Gas Recovery

PM2.5 Benefitsb

SO2 2,900 $190 to $450 $170 to $410

NOX 56 $0.36 to $0.87 $0.32 to $0.78

PM Total: $190 to $460 $170 to $410

CO2 Benefitsc 110,000d $2.6 $2.6

Total 

Monetized 

Benefits:

$190 to $460 $170 to $410

a All estimates are for the analysis year (2017) and are rounded 

to two significant figures so numbers may not sum across rows. 

The total monetized benefits reflect the human health benefits 

associated with reducing exposure to PM2.5 through reductions of 

PM2.5 precursors, such as NOX and SO2 as well as CO2. It is important 

to note that the monetized benefits do not include reduced 

health effects from direct exposure to SO2 and NOx, ozone

exposure, ecosystem effects or visibility impairment. b PM benefits are shown as a range from Pope, et al. (2002) to 

Laden, et al. (2006). These models assume that all fine 

particles, regardless of their chemical composition, are equally 

potent in causing premature mortality because the scientific 

evidence is not yet sufficient to allow differentiation of 

effects estimates by particle type. c The CO2 emission reductions (shown in metric tonnes) have been 

reduced to reflect the anticipated emission increases associated 

Comment [A5]: Suggest breaking down benefits 

to show required and optional (ie with gas recovery) 

to maintain comparability with cost estimates.
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with the energy disbenefits. CO2-related benefits were calculated 

using the social cost of carbon (SCC), which is discussed 

further in the RIA. The net present value of reduced CO2

emissions is calculated differently than other benefits. This 

table shows monetized climate benefits using the global average 

SCC estimate at a 3 percent discount rate because the 

interagency workgroup deemed the SCC at a 3 percent discount 

rate to be the central value. In the RIA, we also provide the 

monetized CO2 benefits using discount rates of 5 percent 

(average), 2.5 percent (average), and 3 percent (95th

percentile).

d

Metric tonnes

These benefits estimates represent the total monetized 

human health benefits for populations exposed to less PM2.5 in 

2017 from controls installed to reduce air pollutants in order 

to meet this rule. To estimate human health benefits of this 

rule, the EPA used benefit-per-ton factors to quantify the 

changes in PM2.5-related health impacts and monetized benefits 

based on changes in SO2 and NOx emissions. These benefit-per-ton 

factors were derived using the general approach and methodology 

laid out in Fann, Fulcher, and Hubbell (2009).13 This approach 

uses a model to convert emissions of PM2.5 precursors into 

changes in ambient PM2.5 levels and another model to estimate the 

changes in human health associated with that change in air 

quality, which are then divided by the emission reductions to 

create the benefit-per-ton estimates. However, for this rule, we 

 13 Fann, N., C.M. Fulcher, B.J. Hubbell. 2009. The influence of 

location, source, and emission type in estimates of the human 

health benefits of reducing a ton of air pollution. Air Qual 

Atmos Health (2009) 2:169–176.
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use air quality modeling data specific to the petroleum 

refineries sector.14 The primary difference between the estimates 

used in this analysis and the estimates reported in Fann, 

Fulcher, and Hubbell (2009) is the air quality modeling data 

utilized. While the air quality data used in Fann, Fulcher, and 

Hubbell (2009) reflects broad pollutant/source category 

combinations, such as all non-EGU stationary point sources, the 

air quality modeling data used in this analysis is sectorspecific. In addition, the updated air quality modeling data 

reflects more recent emissions data (2005 rather than 2001) and 

has a higher spatial resolution (12km rather than 36 km grid 

cells). As a result, the benefit-per-ton estimates presented 

herein better reflect the geographic areas and populations

likely to be affected by this sector. The benefits methodology, 

such as health endpoints assessed, risk estimates applied, and 

valuation techniques applied did not change. However, these 

updated estimates still have similar limitations as all 

national-average benefit-per-ton estimates in that they reflect 

the geographic distribution of the modeled emissions, which may 

not exactly match the emission reductions in this rulemaking, 

and they may not reflect local variability in population 

 14 U.S. Environmental Protection Agency. 2011. Technical support 

document: Estimating the benefit per ton of reducing PM2.5

precursors from the petroleum refineries sector. EPA, Research 

Triangle Park, NC.
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density, meteorology, exposure, baseline health incidence rates, 

or other local factors for any specific location.

We apply these national benefit-per-ton estimates

calculated for this sector separately for SO2 and NOx and 

multiply them by the corresponding emission reductions. The 

sector-specific modeling does not provide estimates of the PM2.5-

related benefits associated with reducing VOC emissions, but 

these unquantified benefits are generally small compared to 

other PM2.5 precursors. More information regarding the derivation 

of the benefit-per-ton estimates for the petroleum refining 

sector is available in the technical support document, which is 

available in the docket.

These models assume that all fine particles, regardless of 

their chemical composition, are equally potent in causing 

premature mortality because the scientific evidence is not yet 

sufficient to allow differentiation of effects estimates by 

particle type. The main PM2.5 precursors affected by this rule 

are SO2 and NOX. Even though we assume that all fine particles 

have equivalent health effects, the benefit-per-ton estimates 

vary between precursors depending on the location and magnitude 

of their impact on PM2.5 levels, which drive population exposure. 

For example, SO2 has a lower benefit-per-ton estimate than direct 

PM2.5 because it does not form as much PM2.5, thus, the exposure 
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would be lower, and the monetized health benefits would be 

lower.

It is important to note that the magnitude of the PM2.5 

benefits is largely driven by the concentration response 

function for premature mortality. Experts have advised the EPA 

to consider a variety of assumptions, including estimates based 

both on empirical (epidemiological) studies and judgments 

elicited from scientific experts, to characterize the 

uncertainty in the relationship between PM2.5 concentrations and 

premature mortality. We cite two key empirical studies, one 

based on the American Cancer Society cohort study15 and the 

extended Six Cities cohort study.16 In the RIA for this final

rule, which is available in the docket, we also include benefits 

estimates derived from the expert judgments and other 

assumptions.

The EPA strives to use the best available science to 

support our benefits analyses. We recognize that interpretation 

of the science regarding air pollution and health is dynamic and 

evolving. After reviewing the scientific literature, we have 

determined that the no-threshold model is the most appropriate 

 15 Pope, et al., 2002. Lung Cancer, Cardiopulmonary Mortality, 

and Long-term Exposure to Fine Particulate Air Pollution. 

Journal of the American Medical Association 287:1132-1141. 16 Laden, et al., 2006. Reduction in Fine Particulate Air 

Pollution and Mortality. American Journal of Respiratory and 

Critical Care Medicine 173: 667-672.
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model for assessing the mortality benefits associated with 

reducing PM2.5 exposure. Consistent with this finding, we have 

conformed the previous threshold sensitivity analysis to the 

current state of the PM science by incorporating a new “Lowest 

Measured Level” (LML) assessment in the RIA accompanying this 

rule. While an LML assessment provides some insight into the 

level of uncertainty in the estimated PM mortality benefits, the 

EPA does not view the LML as a threshold and continues to 

quantify PM-related mortality impacts using a full range of 

modeled air quality concentrations.

Most of the estimated PM-related benefits in this rule 

would accrue to populations exposed to higher levels of PM2.5. 

For this analysis, policy-specific air quality data is not 

available due to time or resource limitations, thus, we are 

unable to estimate the percentage of premature mortality 

associated with this specific rule’s emission reductions at each 

PM2.5 level. As a surrogate measure of mortality impacts, we 

provide the percentage of the population exposed at each PM2.5 

level using the source apportionment modeling used to calculate 

the benefit-per-ton estimates for this sector. Using the Pope,

et al. (2002) study, 77 percent of the population is exposed to 

annual mean PM2.5 levels at or above the LML of 7.5 micrograms 

per cubic meter (μg/m3). Using the Laden, et al. (2006) study, 25 

percent of the population is exposed above the LML of 10 μg/m3

.
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It is important to emphasize that we have high confidence in 

PM2.5-related effects down to the lowest LML of the major cohort 

studies. This fact is important, because, as we model avoided 

premature deaths among populations exposed to levels of PM2.5, we 

have lower confidence in levels below the LML for each study. 

Every benefit analysis examining the potential effects of a 

change in environmental protection requirements is limited, to 

some extent, by data gaps, model capabilities (such as 

geographic coverage) and uncertainties in the underlying 

scientific and economic studies used to configure the benefit 

and cost models. Despite these uncertainties, we believe the 

benefit analysis for this rule provides a reasonable indication 

of the expected health benefits of the rulemaking under a set of 

reasonable assumptions. This analysis does not include the type 

of detailed uncertainty assessment found in the 2006 PM2.5 NAAQS 

RIA because we lack the necessary air quality input and 

monitoring data to run the benefits model. In addition, we have 

not conducted air quality modeling for this rule, and using a 

benefit-per-ton approach adds another important source of 

uncertainty to the benefits estimates. The 2006 PM2.5 NAAQS 

benefits analysis17 provides an indication of the sensitivity of 

 17 U.S. Environmental Protection Agency, 2006. Final Regulatory 

Impact Analysis: PM2.5 NAAQS. Prepared by Office of Air and 
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our results to various assumptions. 

This rule is expected to reduce CO2 emissions from the 

electricity sector. The EPA has assigned a dollar value to 

reductions in CO2 emissions using recent estimates of the 

“social cost of carbon” (SCC). The SCC is an estimate of the 

monetized damages associated with an incremental increase in 

carbon emissions in a given year or the per metric ton benefit 

estimate relating to decreases in CO2 emissions. It is intended 

to include (but is not limited to) changes in net agricultural 

productivity, human health, property damage from increased flood 

risk, and the value of ecosystem services due to climate change.

The SCC estimates used in this analysis were developed through 

an interagency process that included the EPA and other executive 

branch entities, and that concluded in February 2010. We first 

used these SCC estimates in the benefits analysis for the final 

joint EPA/DOT Rulemaking to establish Light-Duty Vehicle 

Greenhouse Gas Emission Standards and Corporate Average

Fuel Economy Standards; see the rule’s preamble for discussion 

about application of the SCC (75 FR 25324; May 7, 2010). The SCC 

 

Radiation. October. Available on the Internet at 

http://www.epa.gov/ttn/ecas/ria.html.
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Technical Support Document (SCC TSD) provides a complete

discussion of the methods used to develop these SCC estimates.18

The interagency group selected four SCC values for use in

regulatory analyses, which we have applied in this analysis:

$5.9, $24.3, $39, and $74.4 per metric ton of CO2 emissions in

2016, in 2007 dollars. The first three values are based on the

average SCC from three integrated assessment models, at discount

rates of 5, 3, and 2.5 percent, respectively. Social cost of

carbon values at several discount rates are included because the

literature shows that the SCC is quite sensitive to assumptions

about the discount rate, and because no consensus exists on the

appropriate rate to use in an intergenerational context. The

fourth value is the 95th percentile of the SCC from all three

values at a 3 percent discount rate. It is included to represent

higher-than-expected impacts from temperature change further out

in the extremes of the SCC distribution. Low probability, high

impact events are incorporated into all of the SCC values

 18 Docket ID EPA-HQ-OAR-2009-0472-114577, Technical Support 

Document: Social Cost of Carbon for Regulatory Impact Analysis 

Under Executive Order 12866, Interagency Working Group on Social

Cost of Carbon, with participation by Council of Economic 

Advisers, Council on Environmental Quality, Department of 

Agriculture, Department of Commerce, Department of Energy, 

Department of Transportation, Environmental Protection Agency, 

National Economic Council, Office of Energy and Climate Change, 

Office of Management and Budget, Office of Science and 

Technology Policy, and Department of Treasury (February 2010). 

Also available at http://epa.gov/otaq/climate/regulations.htm
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through explicit consideration of their effects in two of the

three values as well as the use of a probability density

function for equilibrium climate sensitivity. Treating climate

sensitivity probabilistically results in more high temperature

outcomes, which in turn leads to higher projections of damages.

Applying the global SCC estimates using a 3 percent

discount rate, we estimate the value of the climate related

benefits of this rule in 2017 is $49 million (2006$), as shown

in Table 4. See the RIA for more detail on the methodology used

to calculate these benefits and additional estimates of climate

benefits using different discount rates and the 95th percentile

of the 3 percent discount rate SCC. Important limitations and

uncertainties of the SCC approach are also described in the RIA.

It should be noted that the monetized benefits estimates 

provided above do not include benefits from several important 

benefit categories, including direct exposure to SO2 and NOx, 

ozone exposure, ecosystem effects and visibility impairment.

Although we do not have sufficient information or modeling 

available to provide monetized estimates for this rulemaking, we 

include a qualitative assessment of these unquantified benefits

in the RIA for this final rule.

Although this final rule provides refiners with some 

additional compliance options and removes some requirements, 
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such as the long-term H2S limit for flares, these are nonmonetized benefits of the rule.

For more information on the benefits analysis, please refer 

to the RIA for this rulemaking, which is available in the 

docket.

VI. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and 

Executive Order 13563: Improving Regulation and Regulatory 

Review

Under section 3(f)(1) of Executive Order 12866 (58 FR 

51735, October 4, 1993), this action is an “economically 

significant regulatory action” because it is likely to have an 

annual effect on the economy of $100 million or more. 

Accordingly, the EPA submitted this action to the Office of 

Management and Budget (OMB) for review under Executive Order 

12866 and Executive Order 13563 (76 FR 3821, January 21, 2011), 

and any changes made in response to OMB recommendations have 

been documented in the docket for this action. In addition, the 

EPA prepared a RIA of the potential costs and benefits 

associated with this action.

A summary of the monetized benefits, compliance costs and 

net benefits for the final rule at discount rates of 3 percent 

and 7 percent is in Table 5 of this preamble. 
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Table 5. Summary of the Monetized Benefits, Compliance Costs and 

Net benefits for the Final Petroleum Refineries NSPS in 2017 

(millions of 2006 dollars)a

3-Percent Discount 

Rate

7-Percent Discount 

Rate

Total Monetized 

Benefitsb $270 to $580 $240 to $530

Total Compliance 

Costsc -$79 -$79

Net Benefits $340 to $660 $320 to $610

Non-Monetized 

Benefits

Health effects from direct exposure to SO2

and NO2

Health effects from PM2.5 exposure from VOC

Ecosystem effects 

Visibility impairment a All estimates are for the implementation year (2017) and are 

rounded to two significant figures. b The total monetized benefits reflect the human health benefits 

associated with reducing exposure to PM2.5 through reductions of 

PM2.5 precursors such as NOx and SO2 as well as CO2 benefits. It 

is important to note that the monetized benefits do not include 

the reduced health effects from direct exposure to SO2 and NOx, 

ozone exposure, ecosystem effects, or visibility impairment. 

Human health benefits are shown as a range from Pope et al.

(2002) to Laden et al. (2006). These models assume that all fine 

particles, regardless of their chemical composition, are equally 

potent in causing premature mortality because the scientific 

evidence is not yet sufficient to allow differentiation of 

effects estimates by particle type. The net present value of 

reduced CO2 emissions is calculated differently than other 

benefits. This table includes monetized climate benefits using 

the global average social cost of carbon (SCC) estimated at a 3 

percent discount rate because the interagency workgroup deemed 

the SCC estimate at a 3 percent discount rate to be the central 

value.

c The engineering compliance costs are annualized using a 7-

percent discount rate.

To support the determination of BSER for the June 24, 2008 

final rule, we considered a number of regulatory options and 

their costs and benefits. Those results are presented in the 

RIA for the June 24, 2008 final rulemaking, which is available 
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in the docket. These final rule amendments are in response to 

comments received on the December 22, 2008 proposed rule

amendments. Costs and benefits associated with the amendments 

in this final rule differ from the June 24, 2008 final rule and 

the December 22, 2008 proposed rule amendments primarily as a 

result of correcting the number of flares projected to have to 

comply with this rule (i.e., 40 estimated400 affected flares in 

this rule compared to 40 estimated in the June 24, 2008 final 

rule and 150 estimated affected flares in the December 22, 2008

proposed amendments). In addition, the amendments in this final 

rule to address comments received for the other fuel gas 

combustion devices do not affect the projected costs and 

benefits from the December 22, 2008 proposal, which also did not 

change from the June 24, 2008 final rule. Therefore, for 

purposes of developing these final rule amendments, we did not 

re-evaluate the suite of regulatory options for flares and other 

fuel gas combustion devices considered to support the June 24, 

2008 final rule. However, even with the flare count adjustment, 

this final rule is consistent with E.O. 13563 (Improving 

Regulation and Regulatory Review) because the monetized benefits 

of this final rule exceed the costs. In addition, for facilities 

implementing flare gas recovery, we are reducing regulatory 

burden by finalizing provisions that would allow the owner or 

operator to reduce monitoring costs and the number of root cause 

Comment [A6]: Please remind reader how many 

flares for this rule.
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analyses, corrective actions, and corresponding recordkeeping 

and reporting they would need to perform. 

For more information on the cost-benefits analysis, please 

refer to the RIA for this rulemaking, which is available in the 

docket.

B. Paperwork Reduction Act

The final amendments to the Standards of Performance for 

Petroleum Refineries (40 CFR part 60, subpart J) do not impose 

any new information collection burden. The final amendments are 

clarifications and technical corrections that do not affect the 

estimated burden of the existing rule. Therefore, we have not 

revised the information collection request (ICR) for the 

existing rule. However, OMB has previously approved the 

information collection requirements contained in the existing 

rule (40 CFR part 60, subpart J) under the provisions of the

Paperwork Reduction Act, 44 U.S.C. 3501, et seq., and has 

assigned OMB control number 2060–0022. The OMB control numbers 

for the EPA’s regulations are listed in 40 CFR part 9.

The OMB has approved the information collection 

requirements in the amendments to the Standards of Performance 

for Petroleum Refineries for Which Construction, Reconstruction, 

or Modification Commenced After May 14, 2007 (40 CFR part 60, 

subpart Ja) under the provisions of the Paperwork Reduction Act, 
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44 U.S.C. 3501, et seq., and has assigned OMB control number 

2060–0602.

The information requirements in these final amendments add 

new compliance options, provide more time to comply with the 

requirements for flares, clarify the flare management plan 

requirements and clarify the flare modification provision. 

Overall, these changes are expected to reduce the costs 

associated with testing, monitoring, recording and reporting, so 

they will not result in any increase in burden for the affected 

facilities for which the EPA previously estimated the burden. 

However, the EPA has revised the number of flares expected to 

become subject to the rule over the first 3 years of the ICR. 

Therefore, the annual burden was estimated for the additional 

affected facilities. The total burden for 40 CFR part 60, 

subpart Ja can be estimated by summing the previously approved 

annual burden for OMB control number 2060–0602 (5,340 laborhours per year at a cost of $481,249 per year, annualized 

capital costs of $2,052,000 per year, and operation and 

maintenance costs of $1,117,440 per year) and the annual burden 

for this ICR, as described below.

The annual burden for this information collection averaged 

over the first 3 years of this ICR is estimated to total 54,572

labor-hours per year at a cost of $4,918,110 per year. The 

annualized capital costs are estimated at $11,266,000 per year 
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and operation and maintenance costs are estimated at $8,750,000 

per year. We note that the capital costs, as well as the 

operation and maintenance costs, are for the continuous 

monitors; these costs are also included in the cost impacts 

presented in section V.A of this preamble. Therefore, the burden 

costs associated with the continuous monitors presented in the 

ICR are not additional costs incurred by affected sources 

subject to final 40 CFR part 60, subpart Ja. Burden is defined 

at 5 CFR 1320.3(b).

An agency may not conduct or sponsor, and a person is not 

required to respond to, a collection of information unless it 

displays a currently valid OMB control number. The OMB control 

numbers for the EPA's regulations are listed in 40 CFR part 9. 

The EPA is amending the table in 40 CFR part 9 of currently 

approved ICR control numbers for various regulations to list 

regulatory citations for the information requirements contained 

in this final rule. This amendment updates the table to list the 

information collection requirements being promulgated here as 

amendments to the NSPS for petroleum refineries.

The EPA will continue to present OMB control numbers in a 

consolidated table format to be codified in 40 CFR part 9 of the 

agency’s regulations and in each CFR volume containing the EPA 

regulations. The table lists the section numbers with reporting 

and recordkeeping requirements and the current OMB control 
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numbers. This listing of the OMB control numbers and their 

subsequent codification in the CFR satisfy the requirements of 

the Paperwork Reduction Act (44 U.S.C. 3501, et seq.) and OMB’s 

implementing regulations at 5 CFR part 1320.

C. Regulatory Flexibility Act

The Regulatory Flexibility Act generally requires an agency 

to prepare a regulatory flexibility analysis of any rule subject 

to notice and comment rulemaking requirements under the 

Administrative Procedure Act or any other statute unless the 

agency certifies that the rule would not have a significant 

economic impact on a substantial number of small entities. Small 

entities include small businesses, small organizations and small 

governmental jurisdictions.

For purposes of assessing the impact of this final action 

on small entities, small entity is defined as: (1) a small 

business whose parent company has no more than 1,500 employees, 

that is primarily engaged in refining crude petroleum into 

refined petroleum as defined by NAICS code 32411 (as defined by 

Small Business Administration size standards); (2) a small 

governmental jurisdiction that is a government of a city, 

county, town, school district or special district with a 

population of less than 50,000; and (3) a small organization 

that is any not-for-profit enterprise which is independently 

owned and operated and is not dominant in its field.
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While we estimated the natural gas recovery offsets or 

credit at a national level and believe that larger firms are 

more likely to offset natural gas purchases, the revenues from 

natural gas recovery offsets might mask disproportionate impacts 

on small refiners. To better identify disproportionate impacts, 

we examined the potential impacts on refiners based on a 

scenario where no firms adopt flare gas recovery systems and 

comply with the NSPS through flare monitoring and flare 

management and root cause analysis actions. The incremental 

compliance costs imposed on small refineries are not estimated 

to create significant impacts on a cost-to-sales ratio basis at 

the firm level. Therefore, no adverse economic impacts are 

expected for any small or large entity.

After considering the economic impacts of these final 

amendments on small entities, I certify that this action will 

not have a significant economic impact on a substantial number 

of small entities. In determining whether a rule has a 

significant economic impact on a substantial number of small 

entities, the impact of concern is any significant adverse

economic impact on small entities, since the primary purpose of 

the regulatory flexibility analyses is to identify and address 

regulatory alternatives “which minimize any significant economic 

impact of the rule on small entities.” 5 U.S.C. 603 and 604. 

Thus, an agency may certify that a rule will not have a 
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significant economic impact on a substantial number of small 

entities if the rule relieves regulatory burden or otherwise has 

a positive economic effect on all of the small entities subject 

to the rule.

D. Unfunded Mandates Reform Act

This rule contains no federal mandates under the provisions 

of Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 

2 U.S.C. 1531-1538, that may result in expenditures of $100 

million or more for state, local and tribal governments, in the 

aggregate, or the private sector in any one year. The costs of 

the final amendments would not increase costs associated with 

the final rule. Thus, this rule is not subject to the 

requirements of sections 202 or 205 of the UMRA.

This rule is also not subject to the requirements of 

section 203 of UMRA because it contains no regulatory 

requirements that might significantly or uniquely affect small 

governments. The final amendments contain no requirements that 

apply to such governments and impose no obligations upon them.

E. Executive Order 13132: Federalism

This action does not have federalism implications. It will 

not have substantial direct effects on the states, on the 

relationship between the national government and the states or 

on the distribution of power and responsibilities among the 

various levels of government, as specified in Executive Order 
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13132. This action does not modify existing responsibilities or 

create new responsibilities among EPA Regional offices, states 

or local enforcement agencies. Thus, Executive Order 13132 does 

not apply to this action.

F. Executive Order 13175: Consultation and Coordination with 

Indian Tribal Governments

This action does not have tribal implications, as specified 

in Executive Order 13175 (65 FR 67249, November 9, 2000). The 

final amendments impose no requirements on tribal governments. 

Thus, Executive Order 13175 does not apply to this action.

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks

The EPA interprets Executive Order 13045 (62 FR 19885,

April 23, 1997) as applying to those regulatory actions that 

concern health or safety risks, such that the analysis required 

under section 5-501 of the Executive Order has the potential to 

influence the regulation. This action is not subject to 

Executive Order 13045 because it is based solely on technology 

performance. 

H. Executive Order 13211: Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use

This action is not a “significant energy action” as defined 

in Executive Order 13211 (66 FR 28355, May 22, 2001), because it 

is not likely to have a significant adverse effect on the 
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supply, distribution or use of energy. The final amendments 

would not increase the level of energy consumption required for 

the final rule and may decrease energy requirements.

I. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and 

Advancement Act of 1995 (NTTAA), Public Law No. 104-113, 12(d) 

(15 U.S.C. 272 note) directs the EPA to use voluntary consensus 

standards (VCS) in its regulatory activities, unless to do so 

would be inconsistent with applicable law or otherwise 

impractical. VCS are technical standards (e.g., materials 

specifications, test methods, sampling procedures and business 

practices) that are developed or adopted by VCS bodies. NTTAA 

directs the EPA to provide Congress, through OMB, explanations 

when the agency decides not to use available and applicable VCS.

This rulemaking involves technical standards. The EPA has 

decided to use the following VCS for determining the higher 

heating value of fuel fed to process heaters: ASTM D240-02 

(Reapproved 2007), Standard Test Method for Heat of Combustion 

of Liquid Hydrocarbon Fuels by Bomb Calorimeter; ASTM D1826-94 

(Reapproved 2003), Standard Test Method for Calorific (Heating) 

Value of Gases in Natural Gas Range by Continuous Recording 

Calorimeter; ASTM D3588-98 (Reapproved 2003), Standard Practice 

for Calculating Heat Value, Compressibility Factor, and Relative 

Density of Gaseous Fuels; ASTM D4809-06, Standard Test Method 
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for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb 

Calorimeter (Precision Method); ASTM D4891-89 (Reapproved 2006), 

Standard Test Method for Heating Value of Gases in Natural Gas 

Range by Stoichiometric Combustion; ASTM D1945-03, Standard 

Method for Analysis of Natural Gas by Gas Chromatography; and 

ASTM D1946-90 (Reapproved 2006), Standard Method for Analysis of 

Reformed Gas by Gas Chromatography.

The EPA has decided to use the following VCS as acceptable 

alternatives to EPA Methods 2, 2A, 2B, 2C or 2D for conducting 

relative accuracy evaluations of fuel gas flow monitors: 

American Society of Mechanical Engineers (ASME) MFC-3M-2004, 

Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and 

Venturi; ANSI/ASME MFC-4M-1986 (Reaffirmed 2008), Measurement of 

Gas Flow by Turbine Meters; ASME MFC-6M-1998 (Reaffirmed 2005), 

Measurement of Fluid Flow in Pipes Using Vortex Flowmeters; 

ASME/ANSI MFC-7M-1987 (Reaffirmed 2006), Measurement of Gas Flow 

by Means of Critical Flow Venturi Nozzles; ASME MFC-11M-2006, 

Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters; 

ASME MFC-14M-2003, Measurement of Fluid Flow Using Small Bore 

Precision Orifice Meters; and ASME MFC-18M-2001, Measurement of 

Fluid Flow Using Variable Area Meters.

The EPA has also decided to use the following VCS as 

acceptable alternatives to EPA Methods 2, 2A, 2B, 2C or 2D for 

conducting relative accuracy evaluations of fuel oil flow 
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monitors: ANSI/ASME MFC-5M-1985 (Reaffirmed 2006), Measurement 

of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic 

Flowmeters; ASME/ANSI MFC-9M-1988 (Reaffirmed 2006), Measurement 

of Liquid Flow in Closed Conduits by Weighing Method; ASME MFC16-2007, Measurement of Liquid Flow in Closed Conduits with 

Electromagnetic Flowmeters; ASME MFC-22-2007, Measurement of 

Liquid by Turbine Flowmeters; and ISO 8316: Measurement of 

Liquid Flow in Closed Conduits — Method by Collection of the 

Liquid in a Volumetric Tank (1987–10–01) — First Edition.

The EPA has decided to use the following VCS as acceptable 

alternatives to EPA Method 15A and 16A for conducting relative 

accuracy evaluations of monitors for reduced sulfur compounds, 

total sulfur compounds, and H2S: ANSI/ASME PTC 19.10-1981, Flue 

and Exhaust Gas Analyses. The EPA has decided to use the 

following VCS as acceptable alternatives to EPA Method 16A for 

analysis of total sulfur samples: ASTM D4468-85 (Reapproved 

2006), Standard Test Method for Total Sulfur in Gaseous Fuels by 

Hydrogenolysis and Rateometric Colorimetry; and ASTM D5504-08, 

Standard Test Method for Determination of Sulfur Compounds in 

Natural Gas and Gaseous Fuels by Gas Chromatography and 

Chemiluminescence.

The EPA has decided to use the following VCS as acceptable 

alternatives to EPA Method 18 for relative accuracy evaluations 

of gas composition analyzers for gas-fired process heaters: ASTM 
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D1945-03, Standard Method for Analysis of Natural Gas by Gas 

Chromatography; ASTM D1946-90 (Reapproved 2006), Standard Method 

for Analysis of Reformed Gas by Gas Chromatography; ASTM UOP539-

97, Refinery Gas Analysis by Gas Chromatography; and ASTM D6420-

99 (Reapproved 2004), Standard Test Method for Determination of 

Gaseous Organic Compounds by Direct Interface Gas 

Chromatography-Mass Spectrometry. However, ASTM D6420-99 is a 

suitable alternative to EPA Method 18 only where:

(1) The target compound(s) are those listed in Section 1.1 

of ASTM D6420-99, and 

(2) the target concentration is between 150 parts per 

billion by volume and 100 ppmv. 

For target compound(s) not listed in Section 1.1 of ASTM 

D6420-99, but potentially detected by mass spectrometry, the 

regulation specifies that the additional system continuing 

calibration check after each run, as detailed in Section 10.5.3 

of the ASTM method, must be followed, met, documented and 

submitted with the data report even if there is no moisture 

condenser used or the compound is not considered water soluble. 

For target compound(s) not listed in Section 1.1 of ASTM D6420-

99 and not amenable to detection by mass spectrometry, ASTM 

D6420-99 does not apply.

These above-listed VCS are incorporated by reference (see 

§60.17).
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The EPA has also decided to use American Gas Association 

Report No. 3: Orifice Metering for Natural Gas and Other Related 

Hydrocarbon Fluids, Part 1: General Equations and Uncertainty 

Guidelines (1990), American Gas Association Report No. 3:

Orifice Metering for Natural Gas and Other Related Hydrocarbon 

Fluids, Part 2: Specification and Installation Requirements

(2000), American Gas Association Report No. 11: Measurement of 

Natural Gas by Coriolis Meter (2003), American Gas Association 

Transmission Measurement Committee Report No. 7, Measurement of 

Natural Gas by Turbine Meters (Revised February 2006) and API’s 

Manual of Petroleum Measurement Standards, Chapter 22-Testing 

Protocol, Section 2-Differential Pressure Flow Measurement 

Devices, First Edition, August 2005, for conducting relative 

accuracy evaluations of fuel gas flow monitors; Gas Processors

Association (GPA) Standard 2261-00, Analysis for Natural Gas and 

Similar Gaseous Mixtures by Gas Chromatography (2000), for 

relative accuracy evaluations of gas composition analyzers for 

gas-fired process heaters; and GPA 2172-09, Calculation of Gross 

Heating Value, Relative Density, Compressibility and Theoretical 

Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody 

Transfer, for determining the higher heating value of fuel fed 

to process heaters. These methods are also incorporated by 

reference (see §60.17).
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While the agency has identified five VCS as being 

potentially applicable to this rule, we have decided not to use 

these VCS in this rulemaking. The use of these VCS would be 

impractical because they do not meet the objectives of the 

standards cited in this rule. See the docket for this rule for 

the reasons for these determinations. 

Under 40 CFR 60.13(i) of the NSPS General Provisions, a 

source may apply to the EPA for permission to use alternative 

test methods or alternative monitoring requirements in place of 

any required testing methods, performance specifications or 

procedures in the final rule and amendments.

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations

Executive Order 12898 (59 FR 7629, February 16, 1994) 

establishes federal executive policy on environmental justice. 

Its main provision directs federal agencies, to the greatest 

extent practicable and permitted by law, to make environmental 

justice part of their mission by identifying and addressing, as 

appropriate, disproportionately high and adverse human health or 

environmental effects of their programs, policies and activities 

on minority populations and low-income populations in the United 

States.
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The EPA has determined that this final rule will not have 

disproportionately high and adverse human health or 

environmental effects on minority or low-income populations 

because it does not affect the level of protection provided to 

human health or the environment. The final amendments are either 

clarifications or compliance alternatives which will neither 

increase or decrease environmental protection.

K. Congressional Review Act

The Congressional Review Act, 5 U.S.C. 801, et seq., as 

added by the Small Business Regulatory Enforcement Fairness Act 

of 1996, generally provides that before a rule may take effect 

the agency promulgating the rule must submit a rule report, 

which includes a copy of the rule, to each House of Congress and 

to the Comptroller General of the United States. The EPA will 

submit a report containing these final rules and other required 

information to the United States Senate, the United States House 

of Representatives and the Comptroller General of the United 

States prior to publication of the final rules in the Federal 

Register. A major rule cannot take effect until 60 days after it 

is published in the Federal Register. This action is a “major 

rule” as defined by 5 U.S.C. 804(2). This final rule will be 

effective on [INSERT DATE 60 DAYS FROM DATE OF PUBLICATION IN 

THE FEDERAL REGISTER].
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Standards of Performance for Petroleum Refineries; Standards of 

Performance for Petroleum Refineries for Which Construction, 

Reconstruction, or Modification Commenced After May 14, 2007

Page 197 of 293

List of Subjects in 40 CFR Part 9 

Environmental protection, Reporting and recordkeeping 

requirements.

List of Subjects in 40 CFR Part 60

Environmental protection, Administrative practice and 

procedure, Air pollution control, Incorporations by reference, 

Intergovernmental relations, Reporting and recordkeeping 

requirements.

 

Dated:

Lisa P. Jackson,

Administrator.
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For the reasons stated in the preamble, title 40, chapter 

I, of the Code of Federal Regulations is amended as follows:

PART 9--[AMENDED]

1. The authority citation for part 9 continues to read as 

follows:

Authority: 7 U.S.C. 135, et seq., 136–136y; 15 U.S.C. 2001, 

2003, 2005, 2006, 2601–2671; 21 U.S.C. 331j, 346a, 348; 31 

U.S.C. 9701; 33 U.S.C. 1251, et seq., 1311, 1313d, 1314, 1318, 

1321, 1326, 1330, 1342, 1344, 1345(d) and (e), 1361; E.O. 11735, 

38 FR 21243, 3 CFR, 1971–1975 Comp. p. 973; 42 U.S.C. 241, 242b, 

243, 246, 300f, 300g, 300g–1, 300g–2, 300g–3, 300g–4, 300g–5, 

300g–6, 300j–1, 300j–2, 300j–3, 300j–4, 300j–9, 1857, et seq., 

6901–6992k, 7401–7671q, 7542, 9601–9657, 11023, 11048.

2. The table in Section 9.1 is amended by adding an entry 

in numerical order for 60.103a–60.108a under the heading 

“Standards of Performance for New Stationary Sources” to read as 

follows:

§9.1 OMB Approvals under the Paperwork Reduction Act.

* * * * *

40 CFR citation OMB control No.

* * * * *

Standards of Performance for New Stationary Sources1

* * * * *

60.103a–60.108a 2060–0602

* * * * *

1 The ICR referenced in this section of the table encompass the 

applicable general provisions contained in 40 CFR part 60, 

subpart A, which are not independent information collection 

requirements.

* * * * *
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PART 60--[AMENDED]

3. The authority citation for part 60 continues to read as 

follows:

Authority: 42 U.S.C. 7401, et seq.

Subpart A--[AMENDED]

4. Section 60.17 is amended by:

a. Revising paragraphs (a)(68) and (a)(84);

b. Adding paragraphs (a)(93) through (a)(101);

c. Adding paragraph (c)(2);

d. Revising paragraph (h)(4) and adding paragraphs (h)(5) 

through (h)(15);

e. Revising paragraph (m)(2) and adding paragraph (m)(3); 

and

f. Adding paragraphs (o) and (p) to read as follows:

§60.17 Incorporations by reference.

* * * * *

(a) * * *

(68) ASTM D4468-85 (Reapproved 2006), Standard Test Method 

for Total Sulfur in Gaseous Fuels by Hydrogenolysis and 

Rateometric Colorimetry, IBR approved for §§60.107a(e)(2)(v), 

60.335(b)(10)(ii), and 60.4415(a)(1)(ii).

* * * * *

(84) ASTM D6420–99 (Reapproved 2004), Standard Test Method 

for Determination of Gaseous Organic Compounds by Direct 
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Interface Gas Chromatography-Mass Spectrometry, IBR approved for 

§60.107a(d)(4)(iv) of subpart Ja and table 2 of subpart JJJJ of 

this part.

* * * * *

(93) ASTM D240-02 (Reapproved 2007), Standard Test Method 

for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb 

Calorimeter, IBR approved for §60.107a(d)(7)(i).

(94) ASTM D1826-94 (Reapproved 2003), Standard Test Method 

for Calorific (Heating) Value of Gases in Natural Gas Range by 

Continuous Recording Calorimeter, IBR approved for 

§60.107a(d)(7)(ii).

(95) ASTM D1945–03, Standard Method for Analysis of Natural 

Gas by Gas Chromatography, IBR approved for §§60.107a(d)(4)(ii) 

and 60.107a(d)(7)(iii).

(96) ASTM D1946–90 (Reapproved 2006), Standard Method for 

Analysis of Reformed Gas by Gas Chromatography, IBR approved for 

§§60.107a(d)(4)(iii) and 60.107a(d)(7)(iv).

(97) ASTM D3588-98 (Reapproved 2003), Standard Practice for 

Calculating Heat Value, Compressibility Factor, and Relative 

Density of Gaseous Fuels, IBR approved for §60.107a(d)(7)(v).

(98) ASTM D4809-06, Standard Test Method for Heat of 

Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter 

(Precision Method), IBR approved for §60.107a(d)(7)(vi).
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(99) ASTM D4891-89 (Reapproved 2006), Standard Test Method 

for Heating Value of Gases in Natural Gas Range by 

Stoichiometric Combustion, IBR approved for §60.107a(d)(7)(vii).

(100) ASTM D5504-08, Standard Test Method for Determination 

of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas 

Chromatography and Chemiluminescence, IBR approved for 

§60.107a(e)(2)(v). 

(101) ASTM UOP539-97, Refinery Gas Analysis by Gas 

Chromatography, IBR approved for §60.107a(d)(4)(vi).

* * * * *

(c) * * *

(2) Manual of Petroleum Measurement Standards, Chapter 22-

Testing Protocol, Section 2-Differential Pressure Flow 

Measurement Devices, First Edition, August 2005, IBR approved 

for §60.107a(d)(5)(xiii) of subpart Ja of this part.

* * * * *

(h) * * *

(4) ANSI/ASME PTC 19.10–1981, Flue and Exhaust Gas Analyses 

[part 10, Instruments and Apparatus], IBR approved for 

§60.106(e)(2) of subpart J, §§60.104a(d)(3), (d)(5), (d)(6), 

(h)(3), (h)(4), (h)(5), (i)(3), (i)(4), (i)(5), (j)(3), and 

(j)(4), 60.105a(d)(4), (f)(2), (f)(4), (g)(2), and (g)(4), 

60.106a(a)(1)(iii), (a)(2)(iii), (a)(2)(v), (a)(2)(viii), 

(a)(3)(ii), and (a)(3)(v), and 60.107a(a)(1)(ii), (a)(1)(iv), 
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(a)(2)(ii), (c)(2), (c)(4), (e)(1)(iii), and (e)(2)(ii) of 

subpart Ja, tables 1 and 3 of subpart EEEE, tables 2 and 4 of 

subpart FFFF, table 2 of subpart JJJJ, and §§60.4415(a)(2) and 

60.4415(a)(3) of subpart KKKK of this part.

(5) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes 

Using Orifice, Nozzle, and Venturi, IBR approved for 

§60.107a(d)(5)(ii) of subpart Ja of this part.

(6) ANSI/ASME MFC-4M-1986 (Reaffirmed 2008), Measurement of 

Gas Flow by Turbine Meters, IBR approved for §60.107a(d)(5)(iii) 

of subpart Ja of this part. 

(7) ANSI/ASME-MFC-5M-1985 (Reaffirmed 2006), Measurement of 

Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic 

Flowmeters, IBR approved for §60.107a(d)(6)(ii) of subpart Ja of 

this part. 

(8) ASME MFC-6M-1998 (Reaffirmed 2005), Measurement of 

Fluid Flow in Pipes Using Vortex Flowmeters, IBR approved for 

§60.107a(d)(5)(iv) of subpart Ja of this part. 

(9) ASME/ANSI MFC-7M-1987 (Reaffirmed 2006), Measurement of 

Gas Flow by Means of Critical Flow Venturi Nozzles, IBR approved 

for §60.107a(d)(5)(v) of subpart Ja of this part.

(10) ASME/ANSI MFC-9M-1988 (Reaffirmed 2006), Measurement 

of Liquid Flow in Closed Conduits by Weighing Method, IBR 

approved for §60.107a(d)(6)(iii) of subpart Ja of this part.
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(11) ASME MFC-11M-2006, Measurement of Fluid Flow by Means 

of Coriolis Mass Flowmeters, IBR approved for §60.107a(d)(5)(vi) 

of subpart Ja of this part.

(12) ASME MFC-14M-2003, Measurement of Fluid Flow Using 

Small Bore Precision Orifice Meters, IBR approved for 

§60.107a(d)(5)(vii) of subpart Ja of this part.

(13) ASME MFC-16-2007, Measurement of Liquid Flow in Closed 

Conduits with Electromagnetic Flowmeters, IBR approved for 

§60.107a(d)(6)(iv) of subpart Ja of this part.

(14) ASME MFC-18M-2001, Measurement of Fluid Flow Using 

Variable Area Meters, IBR approved for §60.107a(d)(5)(viii) of 

subpart Ja of this part.

(15) ASME MFC-22-2007, Measurement of Liquid by Turbine 

Flowmeters, IBR approved for §60.107a(d)(6)(v) of subpart Ja of 

this part.

* * * * *

(m) * * *

(2) Gas Processors Association Standard 2172-09, 

Calculation of Gross Heating Value, Relative Density, 

Compressibility and Theoretical Hydrocarbon Liquid Content for 

Natural Gas Mixtures for Custody Transfer (2009), IBR approved 

for §60.107a(d)(7)(viii) of subpart Ja of this part.

(3) Gas Processors Association Standard 2261-00, Analysis 

for Natural Gas and Similar Gaseous Mixtures by Gas 
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Chromatography (2000), IBR approved for §60.107a(d)(4)(v) of 

subpart Ja of this part.

* * * * *

(o) The following American Gas Association material is 

available for purchase from the following address: ILI Infodisk, 

610 Winters Avenue, Paramus, New Jersey 07652:

(1) American Gas Association Report No. 3: Orifice Metering 

for Natural Gas and Other Related Hydrocarbon Fluids, Part 1: 

General Equations and Uncertainty Guidelines (1990), IBR 

approved for §60.107a(d)(5)(ix) of subpart Ja of this part.

(2) American Gas Association Report No. 3: Orifice Metering 

for Natural Gas and Other Related Hydrocarbon Fluids, Part 2: 

Specification and Installation Requirements (2000), IBR approved 

for §60.107a(d)(5)(x) of subpart Ja of this part.

(3) American Gas Association Report No. 11: Measurement of 

Natural Gas by Coriolis Meter (2003), IBR approved for 

§60.107a(d)(5)(xi) of subpart Ja of this part.

(4) American Gas Association Transmission Measurement 

Committee Report No. 7: Measurement of Gas by Turbine Meters 

(Revised February 2006), IBR approved for §60.107a(d)(5)(xii) of 

subpart Ja of this part.

(p) The following material is available for purchase from 

the International Standards Organization (ISO), 1, ch. de la 
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Voie-Creuse, Case postale 56, CH–1211 Geneva 20, Switzerland, 

+41 22 749 01 11, http://www.iso.org/iso/home.htm.

(1) ISO 8316: Measurement of Liquid Flow in Closed Conduits

— Method by Collection of the Liquid in a Volumetric Tank (1987–

10–01) — First Edition, IBR approved for §60.107a(d)(6)(vi) of 

subpart Ja of this part.

(2) [Reserved]

Subpart J--[AMENDED]

5. Section 60.100 is amended by:

a. Revising paragraph (b);

b. Redesignating paragraph (e) as (f); and

c. Adding a new paragraph (e) to read as follows:

§60.100 Applicability, designation of affected facility, and 

reconstruction.

* * * * *

(b) Any fluid catalytic cracking unit catalyst regenerator 

or fuel gas combustion device under paragraph (a) of this 

section other than a flare as defined in §60.101a which 

commences construction, reconstruction or modification after 

June 11, 1973, and on or before May 14, 2007, or any fuel gas 

combustion device under paragraph (a) of this section that meets 

the definition of a flare as defined in §60.101a which commences 

construction, reconstruction or modification after June 11, 

1973, and on or before June 24, 2008, or any Claus sulfur 
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recovery plant under paragraph (a) of this section which 

commences construction, reconstruction or modification after 

October 4, 1976, and on or before May 14, 2007, is subject to 

the requirements of this subpart except as provided under 

paragraphs (c) through (e) of this section.

* * * * *

(e) Owners or operators may choose to comply with the 

applicable provisions of subpart Ja of this part to satisfy the 

requirements of this subpart for an affected facility.

* * * * *

6. Section 60.101 is amended by revising paragraph (d) to 

read as follows:

§60.101 Definitions.

* * * * *

(d) Fuel gas means any gas which is generated at a 

petroleum refinery and which is combusted. Fuel gas includes 

natural gas when the natural gas is combined and combusted in 

any proportion with a gas generated at a refinery. Fuel gas does 

not include gases generated by catalytic cracking unit catalyst 

regenerators and fluid coking burners. Fuel gas does not include 

vapors that are collected and combusted in a thermal oxidizer or 

flare installed to control emissions from wastewater treatment 

units or marine tank vessel loading operations.

* * * * *
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7. Section 60.106 is amended by revising paragraph (c)(1) 

to read as follows:

§60.106 Test methods and procedures.

* * * * *

(c) * * *

(1) The allowable emission rate (Es) of PM shall be computed 

for each run using the following equation:

Es = F + A (H/Rc)

Where:

Es = Emission rate of PM allowed, kg/Mg (lb/ton) of coke burnoff in catalyst regenerator.

F = Emission standard, 1.0 kg/Mg (2.0 lb/ton) of coke burn-off 

in catalyst regenerator.

A = Allowable incremental rate of PM emissions, 43 g/GJ (0.10 

lb/million Btu).

H = Heat input rate from solid or liquid fossil fuel, GJ/hr 

(million Btu/hr).

Rc = Coke burn-off rate, Mg coke/hr (ton coke/hr).

* * * * *

Subpart Ja--[AMENDED]

7. In §60.100a, lift the stay on paragraph (c) published 

December 22, 2008 (73 FR 78552).

8. Section 60.100a is amended by:

a. Revising paragraph (a);

b. Revising paragraph (b); and

c. Revising paragraph (c) introductory text and paragraph 

(c)(1) to read as follows:
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§60.100a Applicability, designation of affected facility, and 

reconstruction.

(a) The provisions of this subpart apply to the following 

affected facilities in petroleum refineries: fluid catalytic 

cracking units (FCCU), fluid coking units (FCU), delayed coking 

units, fuel gas combustion devices (including process heaters), 

flares and sulfur recovery plants. The sulfur recovery plant 

need not be physically located within the boundaries of a 

petroleum refinery to be an affected facility, provided it 

processes gases produced within a petroleum refinery.

(b) Except for flares, the provisions of this subpart apply 

only to affected facilities under paragraph (a) of this section 

which commence construction, modification or reconstruction 

after May 14, 2007. For flares, the provisions of this subpart 

apply only to flares which commence construction, modification

or reconstruction after June 24, 2008. For the purposes of this 

subpart, a modification to a flare commences when a project that 

includes any of the activities in paragraphs (c)(1) or (2) of 

this section is commenced.

(c) For all affected facilities other than flares, the 

provisions in §60.14 regarding modification apply. As provided 

in §60.14(f), the special provisions set forth under this 

subpart shall supersede the provisions in §60.14 with respect to 

flares. For the purposes of this subpart, a modification to a 
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flare occurs as provided in paragraphs (c)(1) or (2) of this 

section. 

(1) Any new piping from a refinery process unit, including 

ancillary equipment, or a fuel gas system is physically 

connected to the flare (e.g., for direct emergency relief or 

some form of continuous or intermittent venting). However, the 

connections described in paragraphs (c)(1)(i) through (vi) of 

this section are not considered modifications of a flare.

(i) Connections made to install monitoring systems to the 

flare.

(ii) Connections made to install a flare gas recovery 

system or connections made to upgrade or enhance components of a 

flare gas recovery system (e.g., addition of compressors or 

recycle lines).

(iii) Connections made to replace or upgrade existing 

pressure relief or safety valves, provided the new pressure 

relief or safety valve has a set point opening pressure no lower 

and an internal diameter no greater than the existing equipment 

being replaced or upgraded.

(iv) Connections made for flare gas sulfur removal. 

(v) Connections made to install back-up (redundant) 

equipment associated with the flare (such as a back-up 

compressor) that does not increase the capacity of the flare.
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(vi) Replacing piping or moving an existing connection from 

a refinery process unit to a new location in the same flare, 

provided the new pipe diameter is less than or equal to the 

diameter of the pipe/connection being replaced/moved.

(vii) Connections that interconnect two or more flares.

* * * * *

9. In §60.101a, lift the stay on the definition of “flare”

published December 22, 2008 (73 FR 78552).

10. Section 60.101a is amended by:

a. Adding, in alphabetical order, definitions of “Air 

preheat,” “Ancillary equipment,” “Cascaded flare system,” “Cofired process heater,” “Corrective action,” “Corrective action 

analysis,” “Emergency flare,” “Flare gas header system,” “Flare 

gas recovery system,” “Forced draft process heater,” “Natural 

draft process heater,” “Non-emergency flare,” “Primary flare,” 

“Purge gas,” “Root cause analysis,” and “Secondary flare,” and 

“Sweep gas”; and

b. Revising the definitions of “Delayed coking unit,” 

“Flare,” “Flexicoking unit,” “Fluid coking unit,” “Fuel gas,” 

“Fuel gas combustion device,” “Petroleum refinery,” “Process 

upset gas” and “Sulfur recovery plant” to read as follows: 

§60.101a Definitions.

Terms used in this subpart are defined in the Clean Air Act 

(CAA), in §60.2 and in this section.
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Air preheat means a device used to heat the air supplied to 

a process heater generally by use of a heat exchanger to recover 

the latent heat of exhaust gas from the process heater. 

Ancillary equipment means equipment used in conjunction 

with or that serve a refinery process unit. Ancillary equipment

includes, but is not limited to, storage tanks, product loading 

operations, wastewater treatment systems, steam- or electricityproducing units (including coke gasification units), pressure 

relief valves, pumps, sampling vents and continuous analyzer 

vents.

Cascaded flare system means a series of flares connected to 

one flare gas header system arranged with increasing pressure 

set points so that discharges will be initially directed to the 

first flare in the series (i.e., the primary flare). If the 

discharge pressure exceeds a set point at which the flow to the 

primary flare would exceed the primary flare’s capacity, flow 

will be diverted to the second flare in the series. Similarly, 

flow would be diverted to a third (or fourth) flare if the 

pressure in the flare gas header system exceeds a threshold 

where the flow to the first two (or three) flares would exceed 

their capacities.

Co-fired process heater means a process heater that employs 

burners that are designed to be supplied by both gaseous and 

liquid fuels on a routine basis. Process heaters that have gas 
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burners with emergency oil back-up burners are not considered 

co-fired process heaters.

* * * * *

Corrective action means the design, operation and 

maintenance changes that one takes consistent with good 

engineering practice to reduce or eliminate the likelihood of

the recurrence of the primary cause and any other contributing 

cause(s) of an event identified by a root cause analysis as 

having resulted in a discharge of gases to an affected flare in 

excess of specified thresholds. 

Corrective action analysis means a description of all 

reasonable interim and long-term measures, if any, that are 

available, and an explanation of why the selected corrective 

action(s) is/are the best alternative(s), including, but not 

limited to, considerations of cost effectiveness, technical 

feasibility, safety and secondary impacts.

Delayed coking unit means a refinery process unit in which 

high molecular weight petroleum derivatives are thermally 

cracked and petroleum coke is produced in a series of closed, 

batch system reactors. A delayed coking unit includes, but is 

not limited to, all of the coke drums associated with a single 

fractionator; the fractionator, including the bottoms receiver 

and the overhead condenser; the coke drum cutting water and 

quench system, including the jet pump and coker quench water 
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tank; process piping and associated equipment such as pumps, 

valves and connectors; and the coke drum blowdown recovery 

compressor system.

Emergency flare means a flare that combusts gas exclusively 

released as a result of malfunctions (and not startup, shutdown, 

routine operations or any other cause) on four or fewer 

occasions in a rolling 365-day period. For purposes of this 

rule, a flare cannot be categorized as an emergency flare unless 

it maintains a water seal.

Flare means a combustion device that uses an uncontrolled 

volume of air to burn gases. The flare includes the foundation, 

flare tip, structural support, burner, igniter, flare controls,

including air injection or steam injection systems, flame 

arrestors and the flare gas header system. In the case of an 

interconnected flare gas header system, the flare includes each 

individual flare serviced by the interconnected flare gas header 

system and the interconnected flare gas header system.

Flare gas header system means all piping and knockout pots, 

including those in a subheader system, used to collect and

transport gas to a flare either from a process unit or a 

pressure relief valve from the fuel gas system, regardless of 

whether or not a flare gas recovery system draws gas from the 

flare gas header system. The flare gas header system includes 

piping inside the battery limit of a process unit if the purpose 
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of the piping is to transport gas to a flare or knockout pot 

that is part of the flare. 

Flare gas recovery system means a system of one or more 

compressors, piping and the associated water seal, rupture disk 

or similar device used to divert gas from the flare and direct 

the gas to the fuel gas system or to a fuel gas combustion 

device. 

Flexicoking unit means a refinery process unit in which 

high molecular weight petroleum derivatives are thermally 

cracked and petroleum coke is continuously produced and then 

gasified to produce a synthetic fuel gas.

* * * * *

Fluid coking unit means a refinery process unit in which 

high molecular weight petroleum derivatives are thermally 

cracked and petroleum coke is continuously produced in a 

fluidized bed system. The fluid coking unit includes the coking 

reactor, the coking burner, and equipment for controlling air 

pollutant emissions and for heat recovery on the fluid coking 

burner exhaust vent.

Forced draft process heater means a process heater in which 

the combustion air is supplied under positive pressure produced 

by a fan at any location in the inlet air line prior to the 

point where the combustion air enters the process heater or air 

preheat. For the purposes of this subpart, a process heater that 
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uses fans at both the inlet air side and the exhaust air side 

(i.e., balanced draft system) is considered to be a forced draft 

process heater.

Fuel gas means any gas which is generated at a petroleum 

refinery and which is combusted. Fuel gas includes natural gas 

when the natural gas is combined and combusted in any proportion 

with a gas generated at a refinery. Fuel gas does not include 

gases generated by catalytic cracking unit catalyst 

regenerators, coke calciners (used to make premium grade coke) 

and fluid coking burners, but does include gases from 

flexicoking unit gasifiers and other gasifiers. Fuel gas does 

not include vapors that are collected and combusted in a thermal 

oxidizer or flare installed to control emissions from wastewater 

treatment units other than those processing sour water, marine 

tank vessel loading operations or asphalt processing units 

(i.e., asphalt blowing stills). 

Fuel gas combustion device means any equipment, such as 

process heaters and boilers, used to combust fuel gas. For the 

purposes of this subpart, fuel gas combustion device does not 

include flares or facilities in which gases are combusted to 

produce sulfur or sulfuric acid.

* * * * *

Natural draft process heater means any process heater in 

which the combustion air is supplied under ambient or negative 
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pressure without the use of an inlet air (forced draft) fan. For 

the purposes of this subpart, a natural draft process heater is 

any process heater that is not a forced draft process heater, 

including induced draft systems.

Non-emergency flare means any flare that is not an 

emergency flare as defined in this subpart.

* * * * *

Petroleum refinery means any facility engaged in producing 

gasoline, kerosene, distillate fuel oils, residual fuel oils, 

lubricants, asphalt (bitumen) or other products through 

distillation of petroleum or through redistillation, cracking or 

reforming of unfinished petroleum derivatives. A facility that

produces only oil shale or tar sands-derived crude oil for 

further processing at a petroleum refinery using only solvent 

extraction and/or distillation to recover diluent is not a 

petroleum refinery.

Primary flare means the first flare in a cascaded flare

system.

* * * * *

Process upset gas means any gas generated by a petroleum 

refinery process unit or by ancillary equipment as a result of 

startup, shutdown, upset or malfunction.

Purge gas means gas introduced between a flare’s water seal 

and a flare’s tip to prevent oxygen infiltration (backflow) into 
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the flare tip. For flares with no water seals, the function of 

purge gas is performed by sweep gas (i.e., flares without water 

seals do not use purge gas).

* * * * *

Root cause analysis means an assessment conducted through a 

process of investigation to determine the primary cause, and any 

other contributing cause(s), of a discharge of gases in excess 

of specified thresholds.

Secondary flare means a flare in a cascaded flare system 

that provides additional flare capacity and pressure relief to a 

flare gas system when the flare gas flow exceeds the capacity of 

the primary flare. For purposes of this subpart, a secondary 

flare is characterized by infrequent use and must maintain a 

water seal.

* * * * *

Sulfur recovery plant means all process units which recover 

sulfur from H2S and/or SO2 from a common source of sour gas 

produced at a petroleum refinery. The sulfur recovery plant also 

includes sulfur pits used to store the recovered sulfur product, 

but it does not include secondary sulfur storage vessels or 

loading facilities downstream of the sulfur pits. For example, a 

Claus sulfur recovery plant includes: Reactor furnace and waste 

heat boiler, catalytic reactors, sulfur pits and, if present, 

oxidation or reduction control systems or incinerator, thermal 
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oxidizer or similar combustion device. Multiple sulfur recovery 

units are a single affected facility only when the units share 

the same source of sour gas. Sulfur recovery plants that receive 

source gas from completely segregated sour gas treatment systems 

are separate affected facilities.

Sweep gas means the gas introduced in a flare gas header 

system to maintain a constant flow of gas to prevent oxygen 

buildup in the flare header. For flares with no water seals, 

sweep gas also performs the function of preventing oxygen 

infiltration (backflow) into the flare tip.

11. In §60.102a, lift the stay on paragraph (g) published 

December 22, 2008 (73 FR 78552).

12. Section 60.102a is amended by:

a. Revising paragraph (a);

b. Revising paragraph (f)(1)(ii);

c. Revising paragraph (g); 

d. Revising paragraph (h); and

e. Revising paragraph (i) to read as follows:

§60.102a Emissions limitations.

(a) Each owner or operator that is subject to the 

requirements of this subpart shall comply with the emissions 

limitations in paragraphs (b) through (i) of this section on and 

after the date on which the initial performance test, required 

by §60.8, is completed, but not later than 60 days after 
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achieving the maximum production rate at which the affected 

facility will be operated or 180 days after initial startup, 

whichever comes first. 

* * * * *

(f) * * *

(1) * * *

(ii) For a sulfur recovery plant with a reduction control 

system not followed by incineration, the owner or operator shall 

not discharge or cause the discharge of any gases into the 

atmosphere in excess of 300 ppmv of reduced sulfur compounds and 

10 ppmv of H2S, each calculated as ppmv SO2 (dry basis) at 0-

percent excess air; or

* * * * *

(g) Each owner or operator of an affected fuel gas 

combustion device shall comply with the emissions limits in 

paragraphs (g)(1) and (2) of this section.

(1) Except as provided in (g)(1)(iii) of this section, for 

each fuel gas combustion device, the owner or operator shall 

comply with either the emission limit in paragraph (g)(1)(i) of 

this section or the fuel gas concentration limit in paragraph 

(g)(1)(ii) of this section.

(i) The owner or operator shall not discharge or cause the 

discharge of any gases into the atmosphere that contain SO2 in 

excess of 20 ppmv (dry basis, corrected to 0-percent excess air) 
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determined hourly on a 3-hour rolling average basis and SO2 in 

excess of 8 ppmv (dry basis, corrected to 0-percent excess air), 

determined daily on a 365 successive calendar day rolling 

average basis; or

(ii) The owner or operator shall not burn in any fuel gas 

combustion device any fuel gas that contains H2S in excess of 162 

ppmv determined hourly on a 3-hour rolling average basis and H2S

in excess of 60 ppmv determined daily on a 365 successive 

calendar day rolling average basis.

(iii) The combustion in a portable generator of fuel gas 

released as a result of tank degassing and/or cleaning is exempt 

from the emissions limits in paragraphs (g)(1)(i) and (ii).

(2) For each process heater with a rated capacity of 

greater than 40 million British thermal units per hour 

(MMBtu/hr) on a higher heating value basis, the owner or 

operator shall not discharge to the atmosphere any emissions of 

NOX in excess of the applicable limits in paragraphs (g)(2)(i) 

through (iv) of this section.

(i) For each natural draft process heater, comply with the 

limit in either paragraph (g)(2)(i)(A) or (B) of this section. 

The owner or operator may comply with either limit at any time, 

provided that the appropriate parameters for each alternative 

are monitored as specified in §60.107a; if fuel gas composition 

is not monitored as specified in §60.107a(d), the owner or 
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operator must comply with the concentration limits in paragraph 

(g)(2)(i)(A) of this section. 

(A) 40 ppmv (dry basis, corrected to 0-percent excess air) 

determined daily on a 30-day rolling average basis; or

(B) 0.040 pounds per million British thermal units 

(lb/MMBtu) higher heating value basis determined daily on a 30-

day rolling average basis.

(ii) For each forced draft process heater, comply with the 

limit in either paragraph (g)(2)(ii)(A) or (B) of this section. 

The owner or operator may comply with either limit at any time, 

provided that the appropriate parameters for each alternative 

are monitored as specified in §60.107a; if fuel gas composition 

is not monitored as specified in §60.107a(d), the owner or 

operator must comply with the concentration limits in paragraph 

(g)(2)(ii)(A) of this section.

(A) 60 ppmv (dry basis, corrected to 0-percent excess air) 

determined daily on a 30-day rolling average basis; or

(B) 0.060 lb/MMBtu higher heating value basis determined 

daily on a 30-day rolling average basis.

(iii) For each co-fired natural draft process heater, 

comply with the limit in either paragraph (g)(2)(iii)(A) or (B) 

of this section. The owner or operator must choose one of the 

emissions limits with which to comply at all times:
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(A) 150 ppmv (dry basis, corrected to 0-percent excess air) 

determined daily on a 30 successive operating day rolling 

average basis; or

(B) The daily average emissions limit calculated using 

Equation 3 of this section:

(Eq. 3)

Where:

ERNOx = Daily allowable average emission rate of NOX, lb/MMBtu 

(higher heating value basis);

Qgas = Daily average volumetric flow rate of fuel gas, standard 

cubic feet per day (scf/day);

Qoil = Daily average volumetric flow rate of fuel oil, scf/day;

HHVgas = Daily average higher heating value of gas fired to the 

process heater, MMBtu/scf; and

HHVoil = Daily average higher heating value of fuel oil fired to 

the process heater, MMBtu/scf.

(iv) For each co-fired forced draft process heater, comply 

with the limit in either paragraph (g)(2)(iv)(A) or (B) of this 

section. The owner or operator must choose one of the emissions 

limits with which to comply at all times:

(A) 150 ppmv (dry basis, corrected to 0-percent excess air) 

determined daily on a 30 successive operating day rolling 

average basis; or

(B) The daily average emissions limit calculated using 

Equation 4 of this section:

gas gas oil oil

gas gas oil oil

NOx Q HHV Q HHV

Q HHV Q HHV

ER

+

+ = 0.06 0.35

gas gas oil oil

gas gas oil oil

NOx Q HHV Q HHV

Q HHV Q HHV

ER

+

+ = 0.06 0.35
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(Eq. 4)

Where:

ERNOx = Daily allowable average emission rate of NOX, lb/MMBtu 

(higher heating value basis);

Qgas = Daily average volumetric flow rate of fuel gas, scf/day;

Qoil = Daily average volumetric flow rate of fuel oil, scf/day;

HHVgas = Daily average higher heating value of gas fired to the 

process heater, MMBtu/scf; and

HHVoil = Daily average higher heating value of fuel oil fired to 

the process heater, MMBtu/scf.

(h) [Reserved]

(i) For a process heater that meets any of the criteria of 

paragraphs (i)(1)(i) through (iv) of this section, an owner or 

operator may request approval from the Administrator for a NOX

emissions limit which shall apply specifically to that affected 

facility. The request shall include information as described in 

paragraph (i)(2) of this section. The request shall be submitted 

and followed as described in paragraph (i)(3) of this section.

(1) A process heater that meets one of the criteria in 

paragraphs (i)(1)(i) through (iv) of this section may apply for 

a site-specific NOX emissions limit:

(i) A modified or reconstructed process heater that lacks 

sufficient space to accommodate installation and proper 

gas gas oil oil

gas gas oil oil

NOx Q HHV Q HHV

Q HHV Q HHV

ER

+

+ = 0.11 0.40

gas gas oil oil

gas gas oil oil

NOx Q HHV Q HHV

Q HHV Q HHV

ER

+

+ = 0.11 0.40
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operation of combustion modification-based technology (e.g., 

ultra-low NOX burners); or

(ii) A modified or reconstructed process heater that has 

downwardly firing induced draft burners; or

(iii) A co-fired process heater; or

(iv) A process heater operating at reduced firing 

conditions for an extended period of time (i.e., operating in 

turndown mode). The site-specific NOX emissions limit will only 

apply for those operating conditions.

(2) The request shall include sufficient and appropriate 

data, as determined by the Administrator, to allow the 

Administrator to confirm that the process heater is unable to 

comply with the applicable NOX emissions limit in paragraph 

(g)(2) of this section. At a minimum, the request shall contain 

the information described in paragraphs (i)(2)(i) through (iv) 

of this section.

(i) The design and dimensions of the process heater, 

evaluation of available combustion modification-based 

technology, description of fuel gas and, if applicable, fuel oil 

characteristics, information regarding the combustion conditions

(temperature, oxygen content, firing rates) and other 

information needed to demonstrate that the process heater meets 

one of the four classes of process heaters listed in paragraph 

(i)(1) of this section.
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(ii) An explanation of how the data in paragraph (i)(2)(i) 

demonstrate that ultra-low NOX burners, flue gas recirculation, 

control of excess air or other combustion modification-based 

technology (including combinations of these combustion 

modification-based technologies) cannot be used to meet the 

applicable emissions limit in paragraph (g)(2) of this section.

(iii) Results of a performance test conducted under 

representative conditions using the applicable methods specified 

in §60.104a(i) to demonstrate the performance of the technology 

the owner or operator will use to minimize NOX emissions.

(iv) The means by which the owner or operator will document 

continuous compliance with the site-specific emissions limit.

(3) The request shall be submitted and followed as 

described in paragraphs (i)(3)(i) through (iii) of this section.

(i) The owner or operator of a process heater that meets 

one of the criteria in paragraphs (i)(1)(i) through (iv) of this 

section may request approval from the Administrator within 180 

days after initial startup of the process heater for a NOX

emissions limit which shall apply specifically to that affected 

facility.

(ii) The request must be submitted to the Administrator for 

approval. The owner or operator must comply with the request as 

submitted until it is approved.
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(iii) The request shall also be submitted to the following 

address: U.S. Environmental Protection Agency, Office of Air 

Quality Planning and Standards, Sector Policies and Programs 

Division, U.S. EPA Mailroom (E143-01), Attention: Refinery 

Sector Lead, 109 T.W. Alexander Drive, Research Triangle Park, 

NC 27711. Electronic copies in lieu of hard copies may also be 

submitted to refinerynsps@epa.gov.

(4) The approval process for a request for a facilityspecific NOX emissions limit is described in paragraphs (i)(4)(i) 

through (iii) of this section.

(i) Approval by the Administrator of a facility-specific NOX

emissions limit request will be based on the completeness, 

accuracy and reasonableness of the request. Factors that the EPA 

will consider in reviewing the request for approval include, but 

are not limited to, the following:

(A) A demonstration that the process heater meets one of 

the four classes of process heaters outlined in paragraphs 

(i)(1) of this section;

(B) A description of the low-NOX burner designs and other 

combustion modifications considered for reducing NOX emissions;

(C) The combustion modification option selected; and 

(D) The operating conditions (firing rate, heater box 

temperature and excess oxygen concentration) at which the NOX

emission level was established. 
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(ii) If the request is approved by the Administrator, a 

facility-specific NOX emissions limit will be established at the 

NOX emission level demonstrated in the approved request.

(iii) If the Administrator finds any deficiencies in the 

request, the request must be revised to address the deficiencies 

and be re-submitted for approval.

13. Section 60.103a is amended by:

a. Revising the section heading;

b. Revising paragraph (a);

c. Revising paragraph (b);

d. Revising paragraph (c); and

e. Adding new paragraphs (d) through (j) to read as 

follows:

§60.103a Design, equipment, work practice or operational 

standards.

(a) Except as provided in paragraph (g) of this section, 

each owner or operator that operates a flare that is subject to 

this subpart shall develop and implement a written flare 

management plan no later than the date specified in paragraph 

(b) of this section. The flare management plan must include the 

information described in paragraphs (a)(1) through (7) of this 

section. 
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(1) A listing of all refinery process units, ancillary 

equipment, and fuel gas systems connected to the flare for each 

affected flare. 

(2) An assessment of whether discharges to affected flares 

from these process units, ancillary equipment and fuel gas 

systems can be minimized. The flare minimization assessment must 

(at a minimum) consider the items in paragraphs (a)(2)(i) 

through (iv) of this section. The assessment must provide clear 

rationale in terms of costs (capital and annual operating), 

natural gas offset credits (if applicable), technical 

feasibility, secondary environmental impacts and safety 

considerations for the selected minimization alternative(s) or a 

statement, with justifications, that flow reduction could not be 

achieved. Based upon the assessment, each owner or operator of 

an affected flare shall identify the minimization alternatives 

that it has implemented by the due date of the flare management 

plan and shall include a schedule for the prompt implementation 

of any selected measures that cannot reasonably be completed as 

of that date.

(i) Elimination of process gas discharge to the flare 

through process operating changes or gas recovery at the source.

(ii) Reduction of the volume of process gas to the flare 

through process operating changes.
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(iii) Installation of a flare gas recovery system or, for 

facilities that are fuel gas rich, a flare gas recovery system 

and a co-generation unit or combined heat and power unit.

(iv) Minimization of sweep gas flow rates and, for flares 

with water seals, purge gas flow rates.

(3) A description of each affected flare containing the 

information in paragraphs (a)(3)(i) through (vii) of this

section.

(i) A general description of the flare, including the 

information in paragraphs (a)(3)(i)(A) through (G) of this 

section. 

(A) Whether it is a ground flare or elevated (including 

height).

(B) The type of assist system (e.g., air, steam, pressure, 

non-assisted).

(C) Whether it is simple or complex flare tip (e.g., 

staged, sequential).

(D) Whether the flare is part of a cascaded flare system 

(and if so, whether the flare is primary or secondary).

(E) Whether the flare serves as a backup to another flare.

(F) Whether the flare is an emergency flare or a nonemergency flare.

(G) Whether the flare is equipped with a flare gas recovery 

system.
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(ii) Description and simple process flow diagram showing 

the interconnection of the following components of the flare: 

flare tip (date installed, manufacturer, nominal and effective 

tip diameter, tip drawing); knockout or surge drum(s) or pot(s) 

(including dimensions and design capacities); flare header(s) 

and subheader(s); assist system; and ignition system.

(iii) Flare design parameters, including the maximum vent 

gas flow rate; minimum sweep gas flow rate; minimum purge gas 

flow rate (if any); maximum supplemental gas flow rate; maximum 

pilot gas flow rate; and, if the flare is steam-assisted, 

minimum total steam rate.

(iv) Description and simple process flow diagram showing 

all gas lines (including flare, purge (if applicable), sweep, 

supplemental and pilot gas) that are associated with the flare. 

For purge, sweep, supplemental and pilot gas, identify the type 

of gas used. Designate which lines are exempt from sulfur, H2S or 

flow monitoring and why (e.g., natural gas, inherently low 

sulfur, pilot gas). Designate which lines are monitored and 

identify on the process flow diagram the location and type of 

each monitor. 

(v) For each flow rate, H2S, sulfur content, pressure or 

water seal monitor identified in paragraph (a)(3)(iv) of this 

section, provide a detailed description of the manufacturer's 

specifications, including, but not limited to, make, model, 
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type, range, precision, accuracy, calibration, maintenance and 

quality assurance procedures.

(vi) For emergency flares, secondary flares and flares 

equipped with a flare gas recovery system designed, sized and 

operated to capture all flows except those resulting from 

startup, shutdown or malfunction:

(A) Description of the water seal, including the operating 

range for the liquid level.

(B) Designation of the monitoring option elected (flow and 

sulfur monitoring or pressure and water seal liquid level 

monitoring). 

(vii) For flares equipped with a flare gas recovery system:

(A) A description of the flare gas recovery system, 

including number of compressors and capacity of each compressor.

(B) A description of the monitoring parameters used to 

quantify the amount of flare gas recovered.

(C) For systems with staged compressors, the maximum time 

period required to begin gas recovery with the secondary 

compressor(s), the monitoring parameters and procedures used to 

minimize the duration of releases during compressor staging and 

a justification for why the maximum time period cannot be 

further reduced.

(4) An evaluation of the baseline flow to the flare. The 

baseline flow to the flare must be determined after implementing 
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the minimization assessment in paragraph (a)(2) of this section. 

Baseline flows do not include pilot gas flow or purge gas flow 

(i.e., gas introduced after the flare’s water seal) provided 

these gas flows remain reasonably constant (i.e., separate flow 

monitors for these streams are not required). Separate baseline 

flow rates may be established for different operating conditions 

provided that the management plan includes:

(i) A primary baseline flow rate that will be used as the 

default baseline for all conditions except those specifically 

delineated in the plan;

(ii) A description of each special condition for which an 

alternate baseline is established, including the rationale for 

each alternate baseline, the daily flow for each alternate 

baseline and the expected duration of the special conditions for 

each alternate baseline; and

(iii) Procedures to minimize discharges to the affected 

flare during each special condition described in paragraph 

(a)(4)(ii) of this section, unless procedures are already 

developed for these cases under paragraph (a)(5) through (7) of 

this section, as applicable. 

(5) Procedures to minimize or eliminate discharges to the 

flare during the planned startup and shutdown of the refinery 

process units and ancillary equipment that are connected to the 

affected flare, together with a schedule for the prompt 
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implementation of any procedures that cannot reasonably be 

implemented as of the date of the submission of the flare 

management plan.

(6) Procedures to reduce flaring in cases of fuel gas 

imbalance (i.e., excess fuel gas for the refinery's energy 

needs), together with a schedule for the prompt implementation 

of any procedures that cannot reasonably be implemented as of 

the date of the submission of the flare management plan.

(7) For flares equipped with flare gas recovery systems, 

procedures to minimize the frequency and duration of outages of 

the flare gas recovery system and procedures to minimize the 

volume of gas flared during such outages, together with a 

schedule for the prompt implementation of any procedures that 

cannot reasonably be implemented as of the date of the 

submission of the flare management plan.

(b) Except as provided in paragraph (g) of this section, 

each owner or operator required to develop and implement a 

written flare management plan as described in paragraph (a) of 

this section must submit the plan to the Administrator as 

described in paragraphs (b)(1) through (4) of this section. 

(1) The owner or operator of a newly constructed or 

reconstructed flare must develop and implement the flare 

management plan by no later than the date that the flare becomes 

an affected facility subject to this subpart, except for the 
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selected minimization alternatives in paragraph (a)(2) and/or 

the procedures in paragraphs (a)(5) though (a)(7) of this 

section that cannot reasonably be implemented by that date, 

which the owner or operator must implement in accordance with 

the schedule in the flare management plan. The owner or operator 

of a modified flare must develop and implement the flare 

management plan by no later than [INSERT DATE 3 YEARS FROM DATE 

OF PUBLICATION IN THE FEDERAL REGISTER] or upon startup of the 

modified flare, whichever is later.

(2) The owner or operator must comply with the plan as 

submitted by the date specified in paragraph (b)(1). The plan 

should be updated periodically to account for changes in the 

operation of the flare, such as new connections to the flare or 

the installation of a flare gas recovery system, but the plan 

need be re-submitted to the Administrator only if the owner or 

operator adds an alternative baseline flow rate, revises an 

existing baseline as described in paragraph (a)(4) of this 

section, installs a flare gas recovery system or is required to 

change flare designations and monitoring methods as described in 

§60.107a(g). The owner or operator must comply with the updated 

plan as submitted.

(3) All versions of the plan submitted to the Administrator 

shall also be submitted to the following address: U.S. 

Environmental Protection Agency, Office of Air Quality Planning 
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and Standards, Sector Policies and Programs Division, U.S. EPA 

Mailroom (E143-01), Attention: Refinery Sector Lead, 109 T.W. 

Alexander Drive, Research Triangle Park, NC 27711. Electronic 

copies in lieu of hard copies may also be submitted to 

refinerynsps@epa.gov.

(c) Except as provided in paragraphs (f) and (g) of this 

section, each owner or operator that operates a fuel gas 

combustion device, flare or sulfur recovery plant subject to 

this subpart shall conduct a root cause analysis and a 

corrective action analysis for each of the conditions specified 

in paragraphs (c)(1) through (3) of this section.

(1) For a flare:

(i) Any time the SO2 emissions exceed 227 kilograms (kg) 

(500 lb) in any 24-hour period; or

(ii) Any discharge to the flare in excess of 14,160 

standard cubic meters (m3) (500,000 standard cubic feet (scf)) 

above the baseline, determined in paragraph (a)(4) of this 

section, in any 24-hour period; or

(iii) If the monitoring alternative in §60.107a(g) is 

elected, any period when the flare gas line pressure exceeds the 

water seal liquid depth, except for periods attributable to 

compressor staging that do not exceed the staging time specified 

in paragraph (a)(3)(vii)(C) of this section.
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(2) For a fuel gas combustion device, each exceedance of an 

applicable short-term emissions limit in §60.102a(g)(1) if the 

SO2 discharge to the atmosphere is 227 kg (500 lb) greater than 

the amount that would have been emitted if the emissions limits 

had been met during one or more consecutive periods of excess 

emissions or any 24-hour period, whichever is shorter.

(3) For a sulfur recovery plant, each time the SO2 emissions 

are more than 227 kg (500 lb) greater than the amount that would 

have been emitted if the SO2 or reduced sulfur concentration was 

equal to the applicable emissions limit in §60.102a(f)(1) or (2) 

during one or more consecutive periods of excess emissions or 

any 24-hour period, whichever is shorter.

(d) Except as provided in paragraphs (f) and (g) of this 

section, a root cause analysis and corrective action analysis 

must be completed as soon as possible, but no later than 45 days 

after a discharge meeting one of the conditions specified in 

paragraphs (c)(1) through (3) of this section. Special 

circumstances affecting the number of root cause analyses and/or 

corrective action analyses are provided in paragraphs (d)(1) 

through (5) of this section.

(1) If a single continuous discharge meets any of the 

conditions specified in paragraphs (c)(1) through (3) of this 

section for 2 or more consecutive 24-hour periods, a single root 

cause analysis and corrective action analysis may be conducted.
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(2) If a single discharge from a flare triggers a root 

cause analysis based on more than one of the conditions 

specified in paragraphs (c)(1)(i) through (iii) of this section, 

a single root cause analysis and corrective action analysis may 

be conducted.

(3) If the discharge from a flare is the result of a 

planned startup or shutdown of a refinery process unit or 

ancillary equipment connected to the affected flare and the 

procedures in paragraph (a)(5) of this section were followed, a 

root cause analysis and corrective action analysis is not 

required; however, the discharge must be recorded as described 

in §60.108a(c)(6) and reported as described in §60.108a(d)(5).

(4) If both the primary and secondary flare in a cascaded 

flare system meet any of the conditions specified in paragraphs 

(c)(1)(i) through (iii) of this section in the same 24-hour 

period, a single root cause analysis and corrective action 

analysis may be conducted.

(5) Except as provided in paragraph (d)(4) of this section, 

if discharges occur that meet any of the conditions specified in 

paragraphs (c)(1) through (3) of this section for more than one 

affected facility in the same 24-hour period, initial root cause 

analyses shall be conducted for each affected facility. If the 

initial root cause analyses indicate that the discharges have 

the same root cause(s), the initial root cause analyses can be 
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recorded as a single root cause analysis and a single corrective 

action analysis may be conducted.

(e) Except as provided in paragraphs (f) and (g) of this 

section, each owner or operator of a fuel gas combustion device, 

flare or sulfur recovery plant subject to this subpart shall 

implement the corrective action(s) identified in the corrective 

action analysis conducted pursuant to paragraph (d) of this 

section in accordance with the applicable requirements in 

paragraphs (e)(1) through (3) of this section.

(1) All corrective action(s) must be implemented within 45 

days of the discharge for which the root cause and corrective 

action analyses were required or as soon thereafter as 

practicable. If an owner or operator concludes that corrective 

action should not be conducted, the owner or operator shall 

record and explain the basis for that conclusion no later than 

45 days following the discharge as specified in 

§60.108a(c)(6)(ix).

(2) For corrective actions that cannot be fully implemented 

within 45 days following the discharge for which the root cause 

and corrective action analyses were required, the owner or 

operator shall develop an implementation schedule to complete 

the corrective action(s) as soon as practicable. 

(3) No later than 45 days following the discharge for which 

a root cause and corrective action analyses were required, the 
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owner or operator shall record the corrective action(s) 

completed to date, and, for action(s) not already completed, a 

schedule for implementation, including proposed commencement and 

completion dates as specified in §60.108a(c)(6)(x). 

(f) Modified flares shall comply with the requirements of 

paragraphs (c) through (e) of this section by [INSERT DATE 3 

YEARS FROM DATE OF PUBLICATION IN THE FEDERAL REGISTER] or at 

startup of the modified flare, whichever is later.

(g) An affected flare subject to this subpart located in 

the Bay Area Air Quality Management District (BAAQMD) may elect 

to comply with both BAAQMD Regulation 12, Rule 11 and BAAQMD 

Regulation 12, Rule 12 as an alternative to complying with the 

requirements of paragraphs (a) through (e) of this section. An 

affected flare subject to this subpart located in the South 

Coast Air Quality Management District (SCAQMD) may elect to 

comply with SCAQMD Rule 1118 as an alternative to complying with 

the requirements of paragraphs (a) through (e) of this section.

The owner or operator of an affected flare must notify the 

Administrator that the flare is in compliance with BAAQMD 

Regulation 12, Rule 11 and BAAQMD Regulation 12, Rule 12 or 

SCAQMD Rule 1118. The owner or operator of an affected flare 

shall also submit the existing flare management plan to the 

following address: U.S. Environmental Protection Agency, Office 

of Air Quality Planning and Standards, Sector Policies and 
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Programs Division, U.S. EPA Mailroom (E143-01), Attention: 

Refinery Sector Lead, 109 T.W. Alexander Drive, Research 

Triangle Park, NC 27711. Electronic copies in lieu of hard 

copies may also be submitted to refinerynsps@epa.gov.

(h) Each owner or operator shall not burn in any affected 

flare any fuel gas that contains H2S in excess of 162 ppmv 

determined hourly on a 3-hour rolling average basis. The 

combustion in a flare of process upset gases or fuel gas that is 

released to the flare as a result of relief valve leakage or 

other emergency malfunctions is exempt from this limit.

(i) Each owner or operator of a delayed coking unit shall 

depressure each coke drum to 5 lb per square inch gauge (psig)

or less prior to discharging the coke drum steam exhaust to the 

atmosphere. Until the coke drum pressure reaches 5 psig, the 

coke drum steam exhaust must be managed in an enclosed blowdown 

system and the uncondensed vapor must either be recovered (e.g., 

sent to the delayed coking unit fractionators) or vented to the 

fuel gas system, a fuel gas combustion device or a flare.

(j) Alternative means of emission limitation. (1) Each 

owner or operator subject to the provisions of this section may 

apply to the Administrator for a determination of equivalence 

for any means of emission limitation that achieves a reduction 

in emissions of a specified pollutant at least equivalent to the 
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reduction in emissions of that pollutant achieved by the 

controls required in this section.

(2) Determination of equivalence to the design, equipment, 

work practice or operational requirements of this section will 

be evaluated by the following guidelines:

(i) Each owner or operator applying for a determination of 

equivalence shall be responsible for collecting and verifying 

test data to demonstrate the equivalence of the alternative

means of emission limitation.

(ii) For each affected facility for which a determination 

of equivalence is requested, the emission reduction achieved by 

the design, equipment, work practice or operational requirements 

shall be demonstrated.

(iii) For each affected facility for which a determination 

of equivalence is requested, the emission reduction achieved by 

the alternative means of emission limitation shall be 

demonstrated.

(iv) Each owner or operator applying for a determination of 

equivalence to a work practice standard shall commit in writing 

to work practice(s) that provide for emission reductions equal 

to or greater than the emission reductions achieved by the 

required work practice.

(v) The Administrator will compare the demonstrated 

emission reduction for the alternative means of emission 
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limitation to the demonstrated emission reduction for the 

design, equipment, work practice or operational requirements 

and, if applicable, will consider the commitment in paragraph 

(j)(2)(iv) of this section.

(vi) The Administrator may condition the approval of the 

alternative means of emission limitation on requirements that 

may be necessary to ensure operation and maintenance to achieve 

the same emissions reduction as the design, equipment, work 

practice or operational requirements.

(3) An owner or operator may offer a unique approach to 

demonstrate the equivalence of any equivalent means of emission 

limitation.

(4) Approval of the application for equivalence to the 

design, equipment, work practice or operational requirements of 

this section will be evaluated by the following guidelines:

(i) After a request for determination of equivalence is 

received, the Administrator will publish a notice in the Federal 

Register and provide the opportunity for public hearing if the 

Administrator judges that the request may be approved.

(ii) After notice and opportunity for public hearing, the 

Administrator will determine the equivalence of a means of 

emission limitation and will publish the determination in the

Federal Register.
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(iii) Any equivalent means of emission limitations approved 

under this section shall constitute a required work practice, 

equipment, design or operational standard within the meaning of 

section 111(h)(1) of the CAA.

(5) Manufacturers of equipment used to control emissions

may apply to the Administrator for determination of equivalence 

for any alternative means of emission limitation that achieves a 

reduction in emissions achieved by the equipment, design and 

operational requirements of this section. The Administrator will 

make an equivalence determination according to the provisions of 

paragraphs (j)(2) through (4) of this section.

14. Section 60.104a is amended by:

a. Revising paragraph (a);

b. Revising paragraphs (d)(4)(ii), (d)(4)(iii), (d)(4)(v) 

and (d)(8);

c. Revising paragraph (f)(3); 

d. Revising paragraph (h)(5)(iv); 

e. Revising paragraph (i) introductory text;

f. Adding paragraphs (i)(6) through (i)(8);

g. Revising paragraph (j) introductory text and paragraph 

(j)(4) introductory text; and

h. Revising paragraph (j)(4)(iv) to read as follows:

§60.104a Performance tests.
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(a) The owner or operator shall conduct a performance test 

for each FCCU, FCU, sulfur recovery plant, flare and fuel gas 

combustion device to demonstrate initial compliance with each 

applicable emissions limit in §60.102a according to the 

requirements of §60.8. The notification requirements of §60.8(d) 

apply to the initial performance test and to subsequent 

performance tests required by paragraph (b) of this section (or 

as required by the Administrator), but does not apply to 

performance tests conducted for the purpose of obtaining 

supplemental data because of continuous monitoring system 

breakdowns, repairs, calibration checks and zero and span 

adjustments.

* * * * *

(d) * * *

(4) * * *

(ii) The emissions rate of PM (EPM) is computed for each run 

using Equation 5 of this section:

(Eq. 5)

Where:

E = Emission rate of PM, g/kg (lb/1,000 lb) of coke burn-off;

cs = Concentration of total PM, grams per dry standard cubic 

meter (g/dscm) (gr/dscf);

Qsd = Volumetric flow rate of effluent gas, dry standard cubic 

meters per hour (dry standard cubic feet per hour);

Rc = Coke burn-off rate, kilograms per hour (kg/hr) [lb per 

hour (lb/hr)] coke; and

c

s sd

K R

c Q E =

c

s sd

K R

c Q E =
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K = Conversion factor, 1.0 grams per gram (7,000 grains per 

lb).

(iii) The coke burn-off rate (Rc) is computed for each run 

using Equation 6 of this section:

(Eq. 6)

Where:

Rc = Coke burn-off rate, kg/hr (lb/hr);

Qr = Volumetric flow rate of exhaust gas from FCCU regenerator 

or fluid coking burner before any emissions control or 

energy recovery system that burns auxiliary fuel, dry 

standard cubic meters per minute (dscm/min) [dry standard 

cubic feet per minute (dscf/min)];

Qa = Volumetric flow rate of air to FCCU regenerator or fluid 

coking burner, as determined from the unit’s control room 

instrumentation, dscm/min (dscf/min);

Qoxy = Volumetric flow rate of O2 enriched air to FCCU 

regenerator or fluid coking unit, as determined from the 

unit’s control room instrumentation, dscm/min (dscf/min);

%CO2 = Carbon dioxide (CO2) concentration in FCCU regenerator or 

fluid coking burner exhaust, percent by volume (dry 

basis);

%CO = CO concentration in FCCU regenerator or fluid coking 

burner exhaust, percent by volume (dry basis);

%O2 = O2 concentration in FCCU regenerator or fluid coking 

burner exhaust, percent by volume (dry basis);

%Ooxy = O2 concentration in O2 enriched air stream inlet to the 

FCCU regenerator or fluid coking burner, percent by 

volume (dry basis);

K1 = Material balance and conversion factor, 0.2982 (kgmin)/(hr-dscm-%) [0.0186 (lb-min)/(hr-dscf-%)];

K2 = Material balance and conversion factor, 2.088 (kgmin)/(hr-dscm) [0.1303 (lb-min)/(hr-dscf)]; and

K3 = Material balance and conversion factor, 0.0994 (kgmin)/(hr-dscm-%) [0.00624 (lb-min)/(hr-dscf-%)].

( ) ( ) ( ) c r a r CO O K Qoxy Ooxy R K Q CO CO K Q K Q CO % % % 2 % % % = 1 2 + + 2 − 3 + 2 + 2 + 3

( ) ( ) ( ) c r a r CO O K Qoxy Ooxy R K Q CO CO K Q K Q CO % % % 2 % % % = 1 2 + + 2 − 3 + 2 + 2 + 3
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* * * * *

(v) For subsequent calculations of coke burn-off rates or 

exhaust gas flow rates, the volumetric flow rate of Qr is 

calculated using average exhaust gas concentrations as measured 

by the monitors required in §60.105a(b)(2), if applicable, using 

Equation 7 of this section:

(Eq. 

7)

Where:

Qr = Volumetric flow rate of exhaust gas from FCCU regenerator 

or fluid coking burner before any emission control or 

energy recovery system that burns auxiliary fuel, 

dscm/min (dscf/min);

Qa = Volumetric flow rate of air to FCCU regenerator or fluid 

coking burner, as determined from the unit’s control room 

instrumentation, dscm/min (dscf/min);

Qoxy = Volumetric flow rate of O2 enriched air to FCCU 

regenerator or fluid coking unit, as determined from the 

unit’s control room instrumentation, dscm/min (dscf/min);

%CO2 = Carbon dioxide concentration in FCCU regenerator or fluid 

coking burner exhaust, percent by volume (dry basis);

%CO = CO concentration FCCU regenerator or fluid coking burner 

exhaust, percent by volume (dry basis). When no auxiliary 

fuel is burned and a continuous CO monitor is not 

required in accordance with §60.105a(h)(3), assume %CO to 

be zero;

%O2 = O2 concentration in FCCU regenerator or fluid coking 

burner exhaust, percent by volume (dry basis); and

%Ooxy = O2 concentration in O2 enriched air stream inlet to the 

FCCU regenerator or fluid coking burner, percent by 

volume (dry basis).

* * * * *

( )

% 2 % % 2 100

79 100 %

CO CO O

Q Oxy Q Q a oxy

r − − −

× + − × = ( )

% 2 % % 2 100

79 100 %

CO CO O

Q Oxy Q Q a oxy

r − − −

× + − × =
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(8) The owner or operator shall adjust PM, NOX, SO2 and CO 

pollutant concentrations to 0-percent excess air or 0-percent O2

using Equation 8 of this section:

(Eq. 8)

Where:

Cadj = pollutant concentration adjusted to 0-percent excess air 

or O2, parts per million (ppm) or g/dscm;

Cmeas = pollutant concentration measured on a dry basis, ppm or 

g/dscm;

20.9c = 20.9 percent O2−0.0 percent O2 (defined O2 correction 

basis), percent;

20.9 = O2 concentration in air, percent; and

%O2 = O2 concentration measured on a dry basis, percent.

* * * * *

(f) * * *

(3) Compute the site-specific limit using Equation 9 of 

this section:

(Eq. 9)

Where:

Opacity limit = Maximum permissible 3-hour average opacity, 

percent, or 10 percent, whichever is greater;

Opacityst = Hourly average opacity measured during the 

source test, percent; and

PMEmRst = PM emission rate measured during the source 

test, lb/1,000 lb coke burn.

* * * * *

(h) * * *

( )

 

 − = 9 % 2 20.

20.9

O C C c adj meas ( )

 

 − = 9 % 2 20.

20.9

O C C c adj meas















 =

st

st PMEmR Opacity Limit Opacity x 1lb /1,000lbcoke burn















 =

st

st PMEmR Opacity Limit Opacity x 1lb /1,000lbcoke burn
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(5) * * *

(iv) The owner or operator shall use Equation 8 of this 

section to adjust pollutant concentrations to 0-percent O2 or 0-

percent excess air.

(i) The owner or operator shall determine compliance with 

the SO2 and NOX emissions limits in §60.102a(g) for a fuel gas 

combustion device according to the following test methods and 

procedures:

* * * * *

(6) For process heaters with a rated heat capacity between 

40 and 100 MMBtu/hr that elect to demonstrate continuous 

compliance with a maximum excess oxygen limit as provided in 

§60.107a(c)(6) or (d)(8), the owner or operator shall establish 

the O2 operating limit or O2 operating curve based on the 

performance test results according to the requirements in 

paragraph (i)(6)(i) or (ii) of this section, respectively.

(i) If a single O2 operating limit will be used:

(A) Conduct the performance test following the methods 

provided in paragraphs (i)(1), (2), (3) and (5) of this section 

when the process heater is firing at no less than 70 percent of 

the rated heat capacity. For co-fired process heaters, conduct 

at least one of the test runs while the process heater is being 

supplied by both fuel gas and fuel oil and conduct at least one 
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of the test runs while the process heater is being supplied 

solely by fuel gas.

(B) Each test will consist of three test runs. Calculate 

the NOX concentration for the performance test as the average of 

the NOX concentrations from each of the three test runs. If the 

NOX concentration for the performance test is less than or equal 

to the numerical value of the applicable NOX emissions limit 

(regardless of averaging time), then the test is considered to 

be a valid test.

(C) Determine the average O2 concentration for each test run 

of a valid test.

(D) Calculate the O2 operating limit as the average O2

concentration of the three test runs from a valid test. 

(ii) If an O2 operating curve will be used:

(A) Conduct a performance test following the methods 

provided in paragraphs (i)(1), (2), (3) and (5) of this section 

at a representative condition for each operating range for which 

different O2 operating limits will be established. Different 

operating conditions may be defined as different firing rates 

(e.g., above 50 percent of rated heat capacity and at or below 

50 percent of rated heat capacity) and/or, for co-fired process 

heaters, different fuel mixtures (e.g., primarily gas fired, 

primarily oil fired, and equally co-fired, i.e., approximately 

50 percent of the input heating value is from fuel gas and 
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approximately 50 percent of the input heating value is from fuel 

oil). Performance tests for different operating ranges may be 

conducted at different times.

(B) Each test will consist of three test runs. Calculate 

the NOX concentration for the performance test as the average of 

the NOX concentrations from each of the three test runs. If the 

NOX concentration for the performance test is less than or equal 

to the numerical value of the applicable NOX emissions limit 

(regardless of averaging time), then the test is considered to 

be a valid test. 

(C) If an operating curve is developed for different firing 

rates, conduct at least one test when the process heater is 

firing at no less than 70 percent of the rated heat capacity and 

at least one test under turndown conditions (i.e., when the 

process heater is firing at 50 percent or less of the rated heat 

capacity). If O2 operating limits are developed for co-fired 

process heaters based only on overall firing rates (and not by 

fuel mixtures), conduct at least one of the test runs for each 

test while the process heater is being supplied by both fuel gas 

and fuel oil and conduct at least one of the test runs while the 

process heater is being supplied solely by fuel gas.

(D) Determine the average O2 concentration for each test run

of a valid test.
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(E) Calculate the O2 operating limit for each operating 

range as the average O2 concentration of the three test runs from 

a valid test conducted at the representative conditions for that 

given operating range.

(F) Identify the firing rates for which the different 

operating limits apply. If only two operating limits are 

established based on firing rates, the O2 operating limits 

established when the process heater is firing at no less than 70 

percent of the rated heat capacity must apply when the process 

heater is firing above 50 percent of the rated heat capacity and 

the O2 operating limits established for turndown conditions must 

apply when the process heater is firing at 50 percent or less of 

the rated heat capacity.

(G) Operating limits associated with each interval will be 

valid for 2 years or until another operating limit is 

established for that interval based on a more recent performance 

test specific for that interval, whichever occurs first. Owners 

and operators must use the operating limits determined for a 

given interval based on the most recent performance test 

conducted for that interval.

(7) The owner or operator of a process heater complying 

with a NOX limit in terms of lb/MMBtu as provided in 

§60.102a(g)(2)(i)(B), (g)(2)(ii)(B), (g)(2)(iii)(B) or 

(g)(2)(iv)(B) or a process heater with a rated heat capacity 
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between 40 and 100 MMBtu/hr that elects to demonstrate 

continuous compliance with a maximum excess O2 limit, as provided 

in §60.107a(c)(6) or (d)(8), shall determine heat input to the 

process heater in MMBtu/hr during each performance test run by 

measuring fuel gas flow rate, fuel oil flow rate (as applicable)

and heating value content according to the methods provided in 

§60.107a(d)(5), (d)(6), and (d)(4) or (d)(7), respectively. 

(8) The owner or operator shall use Equation 8 of this 

section to adjust pollutant concentrations to 0-percent O2 or 0-

percent excess air.

(j) The owner or operator shall determine compliance with 

the applicable H2S emissions limit in §60.102a(g)(1) for a fuel 

gas combustion device or the concentration requirement in 

§60.103a(h) for a flare according to the following test methods 

and procedures:

* * * * *

(4) EPA Method 11, 15 or 15A of Appendix A–5 to part 60 or 

EPA Method 16 of Appendix A–6 to part 60 for determining the H2S 

concentration for affected facilities using an H2S monitor as 

specified in §60.107a(a)(2). The method ANSI/ASME PTC 19.10–

1981, “Flue and Exhaust Gas Analyses,” (incorporated by 

reference—see §60.17) is an acceptable alternative to EPA Method 

15A of Appendix A–5 to part 60. The owner or operator may 

demonstrate compliance based on the mixture used in the fuel gas 
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combustion device or flare or for each individual fuel gas 

stream used in the fuel gas combustion device or flare.

* * * * *

(iv) If monitoring is conducted at a single point in a 

common source of fuel gas as allowed under §60.107a(a)(2)(iv), 

only one performance test is required. That is, performance 

tests are not required when a new affected fuel gas combustion 

device or flare is added to a common source of fuel gas that 

previously demonstrated compliance.

15. Section 60.105a is amended by:

a. Revising paragraph (b) introductory text, and paragraph 

(b)(1) introductory text, and paragraphs (b)(1)(ii)(A), 

(b)(2)(i) and (b)(2)(ii); and

b. Revising paragraph (i)(5) to read as follows:

§60.105a Monitoring of emissions and operations for fluid 

catalytic cracking units (FCCU) and fluid coking units (FCU).

* * * * *

(b) Control device operating parameters. Each owner or 

operator of a FCCU or FCU subject to the PM per coke burn-off 

emissions limit in §60.102a(b)(1) that uses a control device 

other than fabric filter or cyclone shall comply with the 

requirements in paragraphs (b)(1) and (2) of this section.

(1) The owner or operator shall install, operate and 

maintain continuous parameter monitor systems (CPMS) to measure 
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and record operating parameters for each control device 

according to the applicable requirements in paragraphs (b)(1)(i) 

through (v) of this section.

* * * * *

(ii) * * *

(A) As an alternative to pressure drop, the owner or 

operator of a jet ejector type wet scrubber or other type of wet 

scrubber equipped with atomizing spray nozzles must conduct a 

daily check of the air or water pressure to the spray nozzles 

and record the results of each check.

* * * * *

(2) * * *

(i) The owner or operator shall install, operate and 

maintain each monitor according to Performance Specifications 3 

and 4 of Appendix B to part 60.

(ii) The owner or operator shall conduct performance 

evaluations of each CO2, O2 and CO monitor according to the 

requirements in §60.13(c) and Performance Specifications 3 and 4 

of Appendix B to part 60. The owner or operator shall use EPA 

Method 3 of Appendix A–3 to part 60 and EPA Method 10, 10A or 

10B of Appendix A–4 to part 60 for conducting the relative 

accuracy evaluations.

* * * * *

(i) * * *
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(5) All rolling 7-day periods during which the average 

concentration of SO2 as measured by the SO2 CEMS under 

§60.105a(g) exceeds 50 ppmv, and all rolling 365-day periods 

during which the average concentration of SO2 as measured by the 

SO2 CEMS exceeds 25 ppmv.

* * * * *

16. In §60.107a, lift the stay on paragraphs (d) and (e)

published December 22, 2008 (73 FR 78552).

17. Section 60.107a is amended by:

a. Revising the section heading;

b. Revising paragraph (a) introductory text, paragraph 

(a)(1) introductory text, paragraph (a)(2) introductory text, 

(a)(2)(i), (a)(2)(iv) and paragraph (a)(3) introductory text;

c. Adding paragraph (a)(2)(v);

d. Revising paragraph (b) introductory text and paragraphs 

(b)(1)(i), (b)(1)(v) and (b)(3)(iii);

e. Revising paragraph (c) introductory text and paragraphs 

(c)(1) and (c)(6);

f. Redesignating paragraphs (d), (e), and (f) as paragraphs 

(e), (f) and (i), respectively;

g. Adding a new paragraph (d);

h. Revising newly redesignated paragraph (e);

i. Revising newly redesignated paragraph (f);

j. Adding a new paragraph (g);
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k. Adding a new paragraph (h); and

l. Revising newly redesignated paragraph (i) to read as 

follows:

§60.107a Monitoring of emissions and operations for fuel gas 

combustion devices and flares.

(a) Fuel gas combustion devices subject to SO2 or H2S limit

and flares subject to H2S concentration requirements. The owner 

or operator of a fuel gas combustion device that is subject to 

§60.102a(g)(1) and elects to comply with the SO2 emission limits 

in §60.102a(g)(1)(i) shall comply with the requirements in 

paragraph (a)(1) of this section. The owner or operator of a 

fuel gas combustion device that is subject to §60.102a(g)(1) and 

elects to comply with the H2S concentration limits in 

§60.102a(g)(1)(ii) or a flare that is subject to the H2S 

concentration requirement in §60.103a(h) shall comply with 

paragraph (a)(2) of this section.

(1) The owner or operator of a fuel gas combustion device 

that elects to comply with the SO2 emissions limits in 

§60.102a(g)(1)(i) shall install, operate, calibrate and maintain 

an instrument for continuously monitoring and recording the 

concentration (dry basis, 0-percent excess air) of SO2 emissions

into the atmosphere. The monitor must include an O2 monitor for 

correcting the data for excess air.

* * * * *
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(2) The owner or operator of a fuel gas combustion device 

that elects to comply with the H2S concentration limits in 

§60.102a(g)(1)(ii) or a flare that is subject to the H2S 

concentration requirement in §60.103a(h) shall install, operate, 

calibrate and maintain an instrument for continuously monitoring 

and recording the concentration by volume (dry basis) of H2S in 

the fuel gases before being burned in any fuel gas combustion 

device or flare.

(i) The owner or operator shall install, operate and 

maintain each H2S monitor according to Performance Specification 

7 of Appendix B to part 60. The span value for this instrument 

is 300 ppmv H2S.

* * * * *

(iv) Fuel gas combustion devices or flares having a common 

source of fuel gas may be monitored at only one location, if 

monitoring at this location accurately represents the 

concentration of H2S in the fuel gas being burned in the 

respective fuel gas combustion devices or flares.

(v) The owner or operator of a flare subject to §60.103a(c) 

through (e) may use the instrument required in paragraph (e)(1) 

of this section to demonstrate compliance with the H2S 

concentration requirement in §60.103a(h) if the owner or 

operator complies with the requirements of paragraph (e)(1)(i) 

through (iv) and if the instrument has a span (or dual span, if 
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necessary) capable of accurately measuring concentrations 

between 20 and 300 ppmv. If the instrument required in paragraph 

(e)(1) is used to demonstrate compliance with the H2S 

concentration requirement, the concentration directly measured 

by the instrument must meet the numeric concentration in

§60.103a(h).

(3) The owner or operator of a fuel gas combustion device 

or flare is not required to comply with paragraph (a)(1) or (2) 

of this section for fuel gas streams that are exempt under 

§§60.102a(g)(1)(iii) or 60.103a(h) or, for fuel gas streams 

combusted in a process heater, other fuel gas combustion device 

or flare that are inherently low in sulfur content. Fuel gas 

streams meeting one of the requirements in paragraphs (a)(3)(i) 

through (iv) of this section will be considered inherently low 

in sulfur content.

* * * * *

(b) Exemption from H2S monitoring requirements for lowsulfur fuel gas streams. The owner or operator of a fuel gas 

combustion device or flare may apply for an exemption from the 

H2S monitoring requirements in paragraph (a)(2) of this section 

for a fuel gas stream that is inherently low in sulfur content. 

A fuel gas stream that is demonstrated to be low-sulfur is 

exempt from the monitoring requirements of paragraphs (a)(1) and 
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(2) of this section until there are changes in operating 

conditions or stream composition.

(1) * * *

(i) A description of the fuel gas stream/system to be 

considered, including submission of a portion of the appropriate 

piping diagrams indicating the boundaries of the fuel gas 

stream/system and the affected fuel gas combustion device(s) or 

flare(s) to be considered;

* * * * *

(v) A description of how the 2 weeks (or seven samples for 

infrequently operated fuel gas streams/systems) of monitoring 

results compares to the typical range of H2S concentration (fuel 

quality) expected for the fuel gas stream/system going to the 

affected fuel gas combustion device or flare (e.g., the 2 weeks 

of daily detector tube results for a frequently operated loading 

rack included the entire range of products loaded out and, 

therefore, should be representative of typical operating 

conditions affecting H2S content in the fuel gas stream going to 

the loading rack flare).

* * * * *

(3) * * *

(iii) If the operation change results in a sulfur content 

that is outside the range of concentrations included in the 

original application and the owner or operator chooses not to 
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submit new information to support an exemption, the owner or 

operator must begin H2S monitoring using daily stain sampling to 

demonstrate compliance. The owner or operator must begin 

monitoring according to the requirements in paragraphs (a)(1) or 

(a)(2) of this section as soon as practicable, but in no case 

later than 180 days after the operation change. During daily 

stain tube sampling, a daily sample exceeding 162 ppmv is an 

exceedance of the 3-hour H2S concentration limit. The owner or 

operator of a fuel gas combustion device must also determine a 

rolling 365-day average using the stain sampling results; an 

average H2S concentration of 5 ppmv must be used for days within 

the rolling 365-day period prior to the operation change.

(c) Process heaters complying with the NOX concentrationbased limit. The owner or operator of a process heater subject 

to the NOX emissions limit in §60.102a(g)(2) and electing to 

comply with the applicable emissions limit in 

§60.102a(g)(2)(i)(A), (g)(2)(ii)(A), (g)(2)(iii)(A) or 

(g)(2)(iv)(A) shall install, operate, calibrate and maintain an 

instrument for continuously monitoring and recording the 

concentration (dry basis, 0-percent excess air) of NOX emissions 

into the atmosphere according to the requirements in paragraphs 

(c)(1) through (5) of this section, except as provided in 

paragraph (c)(6) of this section. The monitor must include an O2

monitor for correcting the data for excess air. 
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(1) Except as provided in paragraph (c)(6) of this section, 

the owner or operator shall install, operate and maintain each 

NOX monitor according to Performance Specification 2 of Appendix 

B to part 60. The span value of this NOX monitor must be between 

2 and 3 times the applicable emissions limit, inclusive.

* * * * *

(6) The owner or operator of a process heater that has a 

rated heating capacity of less than 100 MMBtu and is equipped 

with combustion modification-based technology to reduce NOX

emissions (i.e., low-NOX burners, ultra-low-NOX burners) may 

elect to comply with the monitoring requirements in paragraphs 

(c)(1) through (5) of this section or, alternatively, the owner 

or operator of such a process heater shall conduct biennial 

performance tests according to the requirements in §60.104a(i), 

establish a maximum excess O2 operating limit or operating curve 

according to the requirements in §60.104a(i)(6) and comply with 

the O2 monitoring requirements in paragraphs (c)(3) through (5) 

of this section to demonstrate compliance. If an O2 operating 

curve is used (i.e., if different O2 operating limits are 

established for different operating ranges), the owner or 

operator of the process heater must also monitor fuel gas flow 

rate, fuel oil flow rate (as applicable) and heating value 

content according to the methods provided in paragraphs (d)(5), 

(d)(6), and (d)(4) or (d)(7) of this section, respectively.
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(d) Process heaters complying with the NOX heating valuebased or mass-based limit. The owner or operator of a process 

heater subject to the NOX emissions limit in §60.102a(g)(2) and 

electing to comply with the applicable emissions limit in 

§60.102a(g)(2)(i)(B) or (g)(2)(ii)(B) shall install, operate, 

calibrate and maintain an instrument for continuously monitoring 

and recording the concentration (dry basis, 0-percent excess 

air) of NOX emissions into the atmosphere and shall determine the 

F factor of the fuel gas stream no less frequently than once per 

day according to the monitoring requirements in paragraphs 

(d)(1) through (4) of this section. The owner or operator of a 

co-fired process heater subject to the NOX emissions limit in 

§60.102a(g)(2) and electing to comply with the heating valuebased limit in §60.102a(g)(2)(iii)(B) or (g)(2)(iv)(B) shall 

install, operate, calibrate and maintain an instrument for 

continuously monitoring and recording the concentration (dry 

basis, 0-percent excess air) of NOX emissions into the atmosphere 

according to the monitoring requirements in paragraph (d)(1) of 

this section; install, operate, calibrate and maintain an 

instrument for continuously monitoring and recording the flow 

rate of the fuel gas and fuel oil fed to the process heater 

according to the monitoring requirements in paragraph (d)(5) and 

(6) of this section; for fuel gas streams, determine gas 

composition according to the requirements in paragraph (d)(4) of 
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this section or the higher heating value according to the 

requirements in paragraph (d)(7) of this section; and for fuel 

oil streams, determine the heating value according to the 

monitoring requirements in paragraph (d)(7) of this section.

(1) Except as provided in paragraph (d)(8) of this section, 

the owner or operator shall install, operate and maintain each 

NOX monitor according to the requirements in paragraphs (c)(1) 

through (5) of this section. The monitor must include an O2

monitor for correcting the data for excess air. 

(2) Except as provided in paragraph (d)(3) of this section, 

the owner or operator shall sample and analyze each fuel stream 

fed to the process heater using the methods and equations in 

section 12.3.2 of EPA Method 19 of Appendix A-7 to part 60 to 

determine the F factor on a dry basis. If a single fuel gas 

system provides fuel gas to several process heaters, the F 

factor may be determined at a single location in the fuel gas 

system provided it is representative of the fuel gas fed to the 

affected process heater(s). 

(3) As an alternative to the requirements in paragraph 

(d)(2) of this section, the owner or operator of a gas-fired 

process heater shall install, operate and maintain a gas 

composition analyzer and determine the average F factor of the 

fuel gas using the factors in Table 1 of this subpart and 

Equation 10 of this section. If a single fuel gas system 
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provides fuel gas to several process heaters, the F factor may 

be determined at a single location in the fuel gas system 

provided it is representative of the fuel gas fed to the 

affected process heater(s).

(Eq. 10)

Where:

Fd = F factor on dry basis at 0-percent excess air,

dscf/MMBtu.

Xi = mole or volume fraction of each component in the 

fuel gas.

MEVi = molar exhaust volume, dry standard cubic feet per 

mole (dscf/mol).

MHCi = molar heat content, Btu per mole (Btu/mol).

1,000,000 = unit conversion, Btu per MMBtu.

(4) The owner or operator shall conduct performance 

evaluations of each compositional monitor according to the 

requirements in Performance Specification 9 of Appendix B to 

part 60. Any of the following methods shall be used for 

conducting the relative accuracy evaluations:

(i) EPA Method 18 of Appendix A–6 to part 60;

(ii) ASTM D1945–03, Standard Method for Analysis of Natural 

Gas by Gas Chromatography (incorporated by reference-see 

§60.17); 

(iii) ASTM D1946–90 (Reapproved 2006), Standard Method for 

Analysis of Reformed Gas by Gas Chromatography (incorporated by 

reference-see §60.17); 

( )

∑( )

∑

×

× × =

i i

i i

d X MHC

X MEV

F

1,000,000 ( )

∑( )

∑

×

× × =

i i

i i

d X MHC

X MEV

F

1,000,000
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(iv) ASTM D6420–99 (Reapproved 2004), Standard Test Method 

for Determination of Gaseous Organic Compounds by Direct 

Interface Gas Chromatography-Mass Spectrometry (incorporated by 

reference-see §60.17);

(v) Gas Processors Association Standard 2261-00, Analysis 

for Natural Gas and Similar Gaseous Mixtures by Gas 

Chromatography (2000) (incorporated by reference-see §60.17); or

(vi) ASTM UOP539-97, Refinery Gas Analysis by Gas 

Chromatography (incorporated by reference-see §60.17). 

(5) The owner or operator shall install, operate and 

maintain fuel gas flow monitors according to the manufacturer’s 

recommendations. For volumetric flow meters, temperature and 

pressure monitors must be installed in conjunction with the flow 

meter or in a representative location to correct the measured 

flow to standard conditions (i.e., 68° Fahrenheit and 1 

atmosphere). For mass flow meters, use gas compositions 

determined according to paragraph (d)(4) of this section to 

determine the average molecular weight of the fuel gas and 

convert the mass flow to a volumetric flow at standard 

conditions (i.e., 68° Fahrenheit and 1 atmosphere). The owner or 

operator shall conduct performance evaluations of each fuel gas 

flow monitor according to the requirements in §60.13 and 

Performance Specification 6 of Appendix B to part 60. Any of the 
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following methods shall be used for conducting the relative 

accuracy evaluations:

(i) EPA Method 2, 2A, 2B, 2C or 2D of Appendix A–2 to part 

60;

(ii) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes 

Using Orifice, Nozzle, and Venturi (incorporated by referencesee §60.17);

(iii) ANSI/ASME MFC-4M-1986 (Reaffirmed 2008), Measurement 

of Gas Flow by Turbine Meters (incorporated by reference-see 

§60.17); 

(iv) ASME MFC-6M-1998 (Reaffirmed 2005), Measurement of 

Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by 

reference-see §60.17); 

(v) ASME/ANSI MFC-7M-1987 (Reaffirmed 2006), Measurement of 

Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated 

by reference-see §60.17);

(vi) ASME MFC-11M-2006, Measurement of Fluid Flow by Means 

of Coriolis Mass Flowmeters (incorporated by reference-see 

§60.17);

(vii) ASME MFC-14M-2003, Measurement of Fluid Flow Using 

Small Bore Precision Orifice Meters (incorporated by referencesee §60.17);

(viii) ASME MFC-18M-2001, Measurement of Fluid Flow Using 

Variable Area Meters (incorporated by reference-see §60.17);
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(ix) American Gas Association (AGA) Report No. 3: Orifice 

Metering for Natural Gas and Other Related Hydrocarbon Fluids, 

Part 1: General Equations and Uncertainty Guidelines (1990)

(incorporated by reference-see §60.17);

(x) AGA Report No. 3: Orifice Metering for Natural Gas and 

Other Related Hydrocarbon Fluids, Part 2: Specification and 

Installation Requirements (2000) (incorporated by reference-see 

§60.17);

(xi) AGA Report No. 11: Measurement of Natural Gas by 

Coriolis Meter (2003) (incorporated by reference-see §60.17);

(xii) American Gas Association Transmission Measurement 

Committee Report No. 7: Measurement of Gas by Turbine Meters 

(Revised February 2006) (incorporated by reference-see §60.17); 

and

(xiii) American Petroleum Institute (API) Manual of 

Petroleum Measurement Standards, Chapter 22-Testing Protocol, 

Section 2-Differential Pressure Flow Measurement Devices, First

Edition, August 2005 (incorporated by reference-see §60.17).

(6) The owner or operator shall install, operate and 

maintain each fuel oil flow monitor according to the 

manufacturer’s recommendations. The owner or operator shall 

conduct performance evaluations of each fuel oil flow monitor 

according to the requirements in §60.13 and Performance 

Specification 6 of Appendix B to part 60. Any of the following 
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methods shall be used for conducting the relative accuracy 

evaluations:

(i) Any one of the methods listed in paragraph (d)(5) of 

this section that are applicable to fuel oil (i.e., “fluids”);

(ii) ANSI/ASME-MFC-5M-1985 (Reaffirmed 2006), Measurement 

of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic 

Flowmeters (incorporated by reference-see §60.17);

(iii) ASME/ANSI MFC-9M-1988 (Reaffirmed 2006), Measurement 

of Liquid Flow in Closed Conduits by Weighing Method 

(incorporated by reference-see §60.17);

(iv) ASME MFC-16-2007, Measurement of Liquid Flow in Closed 

Conduits with Electromagnetic Flowmeters (incorporated by

reference-see §60.17);

(v) ASME MFC-22-2007, Measurement of Liquid by Turbine 

Flowmeters (incorporated by reference-see §60.17); or

(vi) ISO 8316: Measurement of Liquid Flow in Closed 

Conduits—Method by Collection of the Liquid in a Volumetric Tank 

(1987–10-01)—First Edition (incorporated by reference-see 

§60.17).

(7) The owner or operator shall determine the higher 

heating value of each fuel fed to the process heater using any 

of the applicable methods included in paragraphs (d)(7)(i) 

through (ix) of this section. If a common fuel supply system 

provides fuel gas or fuel oil to several process heaters, the 
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higher heating value of the fuel in each fuel supply system may 

be determined at a single location in the fuel supply system 

provided it is representative of the fuel fed to the affected 

process heater(s). The higher heating value of each fuel fed to 

the process heater must be determined no less frequently than 

once per day except as provided in paragraph (d)(7)(x) of this 

section.

(i) ASTM D240-02 (Reapproved 2007), Standard Test Method 

for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb 

Calorimeter (incorporated by reference-see §60.17).

(ii) ASTM D1826-94 (Reapproved 2003), Standard Test Method 

for Calorific (Heating) Value of Gases in Natural Gas Range by 

Continuous Recording Calorimeter (incorporated by reference-see 

§60.17).

(iii) ASTM D1945-03, Standard Method for Analysis of 

Natural Gas by Gas Chromatography (incorporated by reference-see 

§60.17).

(iv) ASTM D1946-90 (Reapproved 2006), Standard Method for 

Analysis of Reformed Gas by Gas Chromatography (incorporated by 

reference-see §60.17).

(v) ASTM D3588-98 (Reapproved 2003), Standard Practice for 

Calculating Heat Value, Compressibility Factor, and Relative 

Density of Gaseous Fuels (incorporated by reference-see §60.17).
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(vi) ASTM D4809-06, Standard Test Method for Heat of 

Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter 

(Precision Method) (incorporated by reference-see §60.17). 

(vii) ASTM D4891-89 (Reapproved 2006), Standard Test Method 

for Heating Value of Gases in Natural Gas Range by 

Stoichiometric Combustion (incorporated by reference-see 

§60.17).

(viii) Gas Processors Association Standard 2172-09, 

Calculation of Gross Heating Value, Relative Density, 

Compressibility and Theoretical Hydrocarbon Liquid Content for 

Natural Gas Mixtures for Custody Transfer (2009) (incorporated 

by reference-see §60.17).

(ix) Any of the methods specified in section 2.2.7 of 

Appendix D to part 75.

(x) If the fuel oil supplied to the affected co-fired 

process heater originates from a single storage tank, the owner 

or operator may elect to use the storage tank sampling method in 

section 2.2.4.2 of Appendix D to part 75 instead of daily 

sampling, except that the most recent value for heating content

must be used. 

(8) The owner or operator of a process heater that has a 

rated heating capacity of less than 100 MMBtu and is equipped 

with combustion modification based technology to reduce NOX

emissions (i.e., low-NOX burners or ultra-low NOX burners) may 
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elect to comply with the monitoring requirements in paragraphs 

(d)(1) through (7) of this section or, alternatively, the owner 

or operator of such a process heater shall conduct biennial 

performance tests according to the requirements in §60.104a(i), 

establish a maximum excess O2 operating limit or operating curve 

according to the requirements in §60.104a(i)(6) and comply with 

the O2 monitoring requirements in paragraphs (c)(3) through (5) 

of this section to demonstrate compliance. If an O2 operating 

curve is used (i.e., if different O2 operating limits are 

established for different operating ranges), the owner or 

operator of the process heater must also monitor fuel gas flow 

rate, fuel oil flow rate (as applicable) and heating value 

content according to the methods provided in paragraphs (d)(5), 

(d)(6), and (d)(4) or (d)(7) of this section, respectively.

(e) Sulfur monitoring for assessing root cause analysis 

threshold for affected flares. Except as described in paragraphs

(e)(4) and (h) of this section, the owner or operator of an 

affected flare subject to §60.103a(c) through (e) shall 

determine the total reduced sulfur concentration for each gas 

line directed to the affected flare in accordance with either 

paragraph (e)(1), (e)(2) or (e)(3) of this section. Different 

options may be elected for different gas lines. If a monitoring 

system is in place that is capable of complying with the 

requirements related to either paragraph (e)(1), (e)(2) or 
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(e)(3) of this section, the owner or operator of a modified 

flare must comply with the requirements related to either 

paragraph (e)(1), (e)(2) or (e)(3) of this section upon startup 

of the modified flare. If a monitoring system is not in place 

that is capable of complying with the requirements related to 

either paragraph (e)(1), (e)(2) or (e)(3) of this section, the

owner or operator of a modified flare must comply with the 

requirements related to either paragraph (e)(1), (e)(2) or 

(e)(3) of this section no later than [INSERT DATE 3 YEARS FROM 

DATE OF PUBLICATION IN THE FEDERAL REGISTER] or upon startup of

the modified flare, whichever is later.

(1) Total reduced sulfur monitoring requirements. The owner 

or operator shall install, operate, calibrate and maintain an 

instrument for continuously monitoring and recording the 

concentration of total reduced sulfur in gas discharged to the 

flare. 

(i) The owner or operator shall install, operate and 

maintain each total reduced sulfur monitor according to 

Performance Specification 5 of Appendix B to part 60. The span 

value should be determined based on the maximum sulfur content 

of gas that can be discharged to the flare (e.g., roughly 1.1 to 

1.3 times the maximum anticipated sulfur concentration), but may 

be no less than 5,000 ppmv. A single dual range monitor may be 

used to comply with the requirements of this paragraph and 
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paragraph (a)(2) of this section provided the applicable span 

specifications are met.

(ii) The owner or operator shall conduct performance 

evaluations of each total reduced sulfur monitor according to 

the requirements in §60.13(c) and Performance Specification 5 of 

Appendix B to part 60. For flares that routinely have flow, the 

owner or operator of each total reduced sulfur monitor shall use 

EPA Method 15A of Appendix A-5 to part 60 for conducting the 

relative accuracy evaluations. The method ANSI/ASME PTC 19.10-

1981, “Flue and Exhaust Gas Analyses,” (incorporated by 

reference-see §60.17) is an acceptable alternative to EPA Method 

15A of Appendix A-5 to part 60. The alternative relative 

accuracy procedures described in section 16.0 of Performance 

Specification 2 of Appendix B to part 60 (cylinder gas audits) 

may be used for conducting the relative accuracy evaluations. 

For flares that do not receive routine flow, the alternative 

relative accuracy procedures described in section 16.0 of 

Performance Specification 2 of Appendix B to part 60 (cylinder 

gas audits) may be used for conducting the relative accuracy 

evaluations, except that it is not necessary to include as much 

of the sampling probe or sampling line as practical.

(iii) The owner or operator shall comply with the 

applicable quality assurance procedures in Appendix F to part 60 

for each total reduced sulfur monitor.
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(2) H2S monitoring requirements. The owner or operator shall 

install, operate, calibrate, and maintain an instrument for 

continuously monitoring and recording the concentration of H2S in 

gas discharged to the flare according to the requirements in 

paragraphs (e)(2)(i) through (iii) of this section and shall 

collect and analyze samples of the gas and calculate total 

sulfur concentrations as specified in paragraphs (e)(2)(iv) 

through (ix) of this section.

(i) The owner or operator shall install, operate and 

maintain each H2S monitor according to Performance Specification 

7 of Appendix B to part 60. The span value should be determined 

based on the maximum sulfur content of gas that can be 

discharged to the flare (e.g., roughly 1.1 to 1.3 times the 

maximum anticipated sulfur concentration), but may be no less 

than 5,000 ppmv. A single dual range H2S monitor may be used to 

comply with the requirements of this paragraph and paragraph 

(a)(2) of this section provided the applicable span 

specifications are met.

(ii) The owner or operator shall conduct performance 

evaluations of each H2S monitor according to the requirements in 

§60.13(c) and Performance Specification 7 of Appendix B to part 

60. For flares that routinely have flow, the owner or operator 

shall use EPA Method 11, 15 or 15A of Appendix A–5 to part 60 

for conducting the relative accuracy evaluations. The method 
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ANSI/ASME PTC 19.10–1981, “Flue and Exhaust Gas Analyses,” 

(incorporated by reference—see §60.17) is an acceptable 

alternative to EPA Method 15A of Appendix A–5 to part 60. The 

alternative relative accuracy procedures described in section 

16.0 of Performance Specification 2 of Appendix B to part 60 

(cylinder gas audits) may be used for conducting the relative 

accuracy evaluations. For flares that do not receive routine 

flow, the alternative relative accuracy procedures described in 

section 16.0 of Performance Specification 2 of Appendix B to 

part 60 (cylinder gas audits) may be used for conducting the 

relative accuracy evaluations, except that it is not necessary 

to include as much of the sampling probe or sampling line as

practical.

(iii) The owner or operator shall comply with the 

applicable quality assurance procedures in Appendix F to part 60 

for each H2S monitor.

(iv) In the first 10 operating days after the date the 

flare must begin to comply with §60.103a(c)(1) of this subpart, 

the owner or operator shall collect representative daily samples 

of the gas discharged to the flare. The samples may be grab 

samples or integrated samples. The owner or operator shall take 

subsequent representative daily samples at least once per week 

or as required in paragraph (e)(2)(ix) of this section.
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(v) The owner or operator shall analyze each daily sample 

for total sulfur using either EPA Method 15A of Appendix A-5 to 

part 60, EPA Method 16A of Appendix A-6 to part 60, ASTM Method 

D4468-85 (Reapproved 2006) “Standard Test Method for Total 

Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric 

Colorimetry” (incorporated by reference—see §60.17) or ASTM 

Method D5504-08 “Standard Test Method for Determination of 

Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas 

Chromatography and Chemiluminescence” (incorporated by 

reference—see §60.17).

(vi) The owner or operator shall develop a 10-day average 

total sulfur-to-H2S ratio and 95-percent confidence interval as 

follows:

(A) Calculate the ratio of the total sulfur concentration 

to the H2S concentration for each day during which samples are 

collected.

(B) Determine the 10-day average total sulfur-to-H2S ratio 

as the arithmetic average of the daily ratios calculated in 

paragraph (e)(2)(vi)(A) of this section.

(C) Determine the acceptable range for subsequent weekly 

samples based on the 95-percent confidence interval for the 

distribution of daily ratios based on the 10 individual daily 

ratios using Equation 11 of this section.

AR = RatioAvg ± 2.262× SDev AR = RatioAvg ± 2.262× SDev (Eq. 11)
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Where:

AR = Acceptable range of subsequent ratio determinations, 

unitless.

RatioAvg = 10-day average total sulfur-to-H2S concentration

ratio, unitless.

2.262 = t-distribution statistic for 95-percent 2-sided 

confidence interval for 10 samples (9 degrees of 

freedom).

SDev = Standard deviation of the 10 daily average total 

sulfur-to-H2S concentration ratios used to develop 

the 10-day average total sulfur-to-H2S concentration 

ratio, unitless.

(vii) For each day during the period when data are being 

collected to develop a 10-day average, the owner or operator 

shall estimate the total sulfur concentration using the measured 

total sulfur concentration measured for that day.

(viii) For all days other than those during which data are 

being collected to develop a 10-day average, the owner or 

operator shall multiply the most recent 10-day average total 

sulfur-to-H2S ratio by the daily average H2S concentrations 

obtained using the monitor as required by paragraph (e)(2)(i) 

through (iii) of this section to estimate total sulfur 

concentrations.

(ix) If the total sulfur-to-H2S ratio for a subsequent 

weekly sample is outside the acceptable range for the most 

recent distribution of daily ratios, the owner or operator shall 

develop a new 10-day average ratio and acceptable range based on 
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data for the outlying weekly sample plus data collected over the 

following 9 operating days.

(3) SO2 monitoring requirements. The owner or operator shall 

install, operate, calibrate and maintain an instrument for 

continuously monitoring and recording the concentration of SO2

from a process heater or other fuel gas combustion device that 

is combusting gas representative of the fuel gas in the flare 

gas line according to the requirements in paragraph (a)(1) of 

this section, determine the F factor of the fuel gas at least 

daily according to the requirements in paragraphs (d)(2) through 

(4) of this section, determine the higher heating value of the 

fuel gas at least daily according to the requirements in 

paragraph (d)(7) of this section and calculate the total sulfur 

content (as SO2) in the fuel gas using Equation 12 of this 

section. 

(Eq. 12)

Where:

TSFG = Total sulfur concentration, as SO2, in the fuel gas, 

ppmv.

CSO2 = Concentration of SO2 in the exhaust gas, ppmv (dry basis 

at 0-percent excess air).

Fd = F factor gas on dry basis at 0-percent excess air, 

dscf/MMBtu.

HHVFG = Higher heating value of the fuel gas, MMBtu/scf.

(4) Exemptions from sulfur monitoring requirements. Flares 

identified in paragraphs (e)(4)(i) through (iv) of this section 

TS FG = CSO2 × Fd × HHVFG TS FG = CSO2 × Fd × HHVFG
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are exempt from the requirements in paragraphs (e)(1) through 

(3) of this section. For each such flare, except as provided in 

paragraph (e)(4)(iv), engineering calculations shall be used to 

calculate the SO2 emissions in the event of a discharge that may 

trigger a root cause analysis under §60.103a(c)(1).

(i) Flares that can only receive:

(A) Fuel gas streams that are inherently low in sulfur 

content as described in paragraph (a)(3)(i) through (iv) of this 

section; and/or 

(B) Fuel gas streams that are inherently low in sulfur 

content for which the owner or operator has applied for an 

exemption from the H2S monitoring requirements as described in 

paragraph (b) of this section.

(ii) Emergency flares, provided that for each such flare, 

the owner or operator complies with the monitoring alternative 

in paragraph (g) of this section.

(iii) Flares equipped with flare gas recovery systems 

designed, sized and operated to capture all flows except those 

resulting from startup, shutdown or malfunction, provided that 

for each such flare, the owner or operator complies with the 

monitoring alternative in paragraph (g) of this section.

(iv) Secondary flares that receive gas diverted from the 

primary flare. In the event of a discharge from the secondary 

flare, the sulfur content measured by the sulfur monitor on the 
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primary flare should be used to calculate SO2 emissions, 

regardless of whether or not the monitoring alternative in 

paragraph (g) of this section is selected for the secondary 

flare.

(f) Flow monitoring for flares. Except as provided in 

paragraphs (f)(2) and (h) of this section, the owner or operator 

of an affected flare subject to §60.103a(c) through (e) shall 

install, operate, calibrate and maintain, in accordance with the 

specifications in paragraph (f)(1) of this section, a CPMS to 

measure and record the flow rate of gas discharged to the flare.

If a flow monitor is not already in place, the owner or operator 

of a modified flare shall comply with the requirements of this 

paragraph by no later than [INSERT DATE 3 YEARS FROM DATE OF 

PUBLICATION IN THE FEDERAL REGISTER] or upon startup of the 

modified flare, whichever is later.

(1) The owner or operator shall install, calibrate, operate 

and maintain each flow monitor according to the manufacturer’s 

procedures and specifications and the following requirements.

(i) Locate the monitor in a position that provides a 

representative measurement of the total gas flow rate.

(ii) Use a flow sensor with a measurement sensitivity of no 

more than 5 percent of the flow rate or 10 cubic feet per 

minute, whichever is greater.
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(iii) Use a flow monitor that is maintainable online, is 

able to continuously correct for temperature and pressure and is 

able to record flow in standard conditions (as defined in §60.2) 

over one-minute averages.

(iv) At least quarterly, perform a visual inspection of all 

components of the monitor for physical and operational integrity 

and all electrical connections for oxidation and galvanic 

corrosion if the flow monitor is not equipped with a redundant 

flow sensor.

(v) Recalibrate the flow monitor in accordance with the 

manufacturer's procedures and specifications biennially (every 

two years) or at the frequency specified by the manufacturer.

(2) Emergency flares, secondary flares and flares equipped 

with flare gas recovery systems designed, sized and operated to 

capture all flows except those resulting from startup, shutdown

or malfunction are not required to install continuous flow 

monitors; provided, however, that for any such flare, the owner 

or operator shall comply with the monitoring alternative in 

paragraph (g) of this section.

(g) Alternative monitoring for certain flares equipped with 

water seals. The owner or operator of an affected flare subject 

to §60.103a(c) through (e) that can be classified as either an 

emergency flare, a secondary flare or a flare equipped with a 

flare gas recovery system designed, sized and operated to 
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capture all flows except those resulting from startup, shutdown

or malfunction may, as an alternative to the sulfur and flow 

monitoring requirements of paragraphs (e) and (f) of this 

section, install, operate, calibrate and maintain, in accordance 

with the requirements in paragraphs (g)(1) through (7) of this 

section, a CPMS to measure and record the pressure in the flare 

gas header between the knock-out pot and water seal and to 

measure and record the water seal liquid level. If the required 

monitoring systems are not already in place, the owner or 

operator of a modified flare shall comply with the requirements 

of this paragraph by no later than [INSERT DATE 3 YEARS FROM 

DATE OF PUBLICATION IN THE FEDERAL REGISTER] or upon startup of

the modified flare, whichever is later.

(1) Locate the pressure sensor(s) in a position that 

provides a representative measurement of the pressure and locate 

the liquid seal level monitor in a position that provides a 

representative measurement of the water column height.

(2) Minimize or eliminate pulsating pressure, vibration and 

internal and external corrosion.

(3) Use a pressure sensor and level monitor with a minimum 

tolerance of 1.27 centimeters of water.

(4) Using a manometer, check pressure sensor calibration 

quarterly.
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(5) Conduct calibration checks any time the pressure sensor 

exceeds the manufacturer's specified maximum operating pressure 

range or install a new pressure sensor.

(6) In a cascaded flare system that employs multiple 

secondary flares, pressure and liquid level monitoring is 

required only on the first secondary flare in the system (i.e., 

the secondary flare with the lowest pressure release set point).

(7) This alternative monitoring option may be elected only 

for flares with four or fewer pressure exceedances required to 

be reported under §60.108a(d)(5) (“reportable pressure 

exceedances”) in any 365 consecutive calendar days. Following 

the fifth reportable pressure exceedance in a 365-day period, 

the owner or operator must comply with the sulfur and flow 

monitoring requirements of paragraphs (e) and (f) of this 

section as soon as practical, but no later than 180 days after 

the fifth reportable pressure exceedance in a 365-day period.

(h) Alternative monitoring for flares located in the BAAQMD 

or SCAQMD. An affected flare subject to this subpart located in 

the BAAQMD may elect to comply with the monitoring requirements 

in both BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12, 

Rule 12 as an alternative to complying with the requirements of 

paragraphs (e) and (f) of this section. An affected flare 

subject to this subpart located in the SCAQMD may elect to 

comply with the monitoring requirements in SCAQMD Rule 1118 as 
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an alternative to complying with the requirements of paragraphs

(e) and (f) of this section.

(i) Excess emissions. For the purpose of reports required 

by §60.7(c), periods of excess emissions for fuel gas combustion 

devices subject to the emissions limitations in §60.102a(g) and 

flares subject to the concentration requirement in §60.103a(h)

are defined as specified in paragraphs (i)(1) through (5) of 

this section. Determine a rolling 3-hour or a rolling daily 

average as the arithmetic average of the applicable 1-hour 

averages (e.g., a rolling 3-hour average is the arithmetic 

average of three contiguous 1-hour averages). Determine a 

rolling 30-day or a rolling 365-day average as the arithmetic 

average of the applicable daily averages (e.g., a rolling 30-day 

average is the arithmetic average of 30 contiguous daily 

averages).

(1) SO2 or H2S limits for fuel gas combustion devices.

(i) If the owner or operator of a fuel gas combustion device 

elects to comply with the SO2 emission limits in 

§60.102a(g)(1)(i), each rolling 3-hour period during which the 

average concentration of SO2 as measured by the SO2 continuous 

monitoring system required under paragraph (a)(1) of this 

section exceeds 20 ppmv, and each rolling 365-day period during 

which the average concentration of SO2 as measured by the SO2
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continuous monitoring system required under paragraph (a)(1) of 

this section exceeds 8 ppmv.

(ii) If the owner or operator of a fuel gas combustion 

device elects to comply with the H2S concentration limits in 

§60.102a(g)(1)(ii), each rolling 3-hour period during which the 

average concentration of H2S as measured by the H2S continuous 

monitoring system required under paragraph (a)(2) of this 

section exceeds 162 ppmv and each rolling 365-day period during 

which the average concentration as measured by the H2S continuous 

monitoring system under paragraph (a)(2) of this section exceeds 

60 ppmv.

(iii) If the owner or operator of a fuel gas combustion 

device becomes subject to the requirements of daily stain tube 

sampling in paragraph (b)(3)(iii) of this section, each day 

during which the daily concentration of H2S exceeds 162 ppmv and 

each rolling 365-day period during which the average 

concentration of H2S exceeds 60 ppmv.

(2) H2S concentration limits for flares. (i) Each rolling 3-

hour period during which the average concentration of H2S as 

measured by the H2S continuous monitoring system required under 

paragraph (a)(2) of this section exceeds 162 ppmv.

(ii) If the owner or operator of a flare becomes subject to 

the requirements of daily stain tube sampling in paragraph 
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(b)(3)(iii) of this section, each day during which the daily 

concentration of H2S exceeds 162 ppmv.

(3) Rolling 30-day average NOX limits for fuel gas 

combustion devices. Each rolling 30-day period during which the 

average concentration of NOX as measured by the NOX continuous 

monitoring system required under paragraph (c) or (d) of this 

section exceeds:

(i) For a natural draft process heater, 40 ppmv and, if 

monitored according to §60.107a(d), 0.040 lb/MMBtu;

(ii) For a forced draft process heater, 60 ppmv and, if 

monitored according to §60.107a(d), 0.060 lb/MMBtu; and

(iii) For a co-fired process heater electing to comply with 

the NOX limit in §60.102a(g)(2)(iii)(A) or (g)(2)(iv)(A), 150 

ppmv.

(iv) The site-specific limit determined by the 

Administrator under §60.102a(i).

(4) Daily NOX limits for fuel gas combustion devices. Each 

day during which the concentration of NOX as measured by the NOX

continuous monitoring system required under paragraph (d) of 

this section exceeds the daily average emissions limit 

calculated using Equation 3 in §60.102a(g)(2)(iii)(B) or 

Equation 4 in §60.102a(g)(2)(iv)(B).

(5) Daily O2 limits for fuel gas combustion devices. Each

day during which the concentration of O2 as measured by the O2
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continuous monitoring system required under paragraph (c)(6) of 

this section exceeds the O2 operating limit or operating curve 

determined during the most recent biennial performance test.

18. Section 60.108a is amended by:

a. Revising paragraph (b);

b. Revising paragraph (c)(1);

c. Revising paragraph (c)(6) introductory text and 

paragraphs (c)(6)(ii) through (vi);

d. Adding paragraphs (c)(6)(vii), (viii), (ix), (x) and 

(xi);

e. Adding paragraph (c)(7); and

f. Revising paragraph (d)(5) to read as follows:

§60.108a Recordkeeping and reporting requirements.

* * * * *

(b) Each owner or operator subject to an emissions 

limitation in §60.102a shall notify the Administrator of the 

specific monitoring provisions of §§60.105a, 60.106a and 60.107a 

with which the owner or operator intends to comply. Each owner

or operator of a co-fired process heater subject to an emissions 

limitation in §60.102a(g)(2)(iii) or (iv) shall submit to the 

Administrator documentation showing that the process heater 

meets the definition of a co-fired process heater in §60.101a. 

Notifications required by this paragraph shall be submitted with 

the notification of initial startup required by §60.7(a)(3).
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(c) * * *

(1) A copy of the flare management plan.

* * * * *

(6) Records of discharges greater than 500 lb SO2 in any 24-

hour period from any affected flare, discharges greater than 500 

lb SO2 in excess of the allowable limits from a fuel gas 

combustion device or sulfur recovery plant and discharges to an 

affected flare in excess of 500,000 scf above baseline in any 

24-hour period as required by §60.103a(c). If the monitoring 

alternative provided in §60.107a(g) is selected, the owner or 

operator shall record any instance when the flare gas line 

pressure exceeds the water seal liquid depth, except for periods 

attributable to compressor staging that do not exceed the 

staging time specified in §60.103a(a)(3)(vii)(C). The following 

information shall be recorded no later than 45 days following 

the end of a discharge exceeding the thresholds:

* * * * *

(ii) The date and time the discharge was first identified 

and the duration of the discharge.

(iii) The measured or calculated cumulative quantity of gas 

discharged over the discharge duration. If the discharge 

duration exceeds 24 hours, record the discharge quantity for 

each 24-hour period. For a flare, record the measured or 

calculated cumulative quantity of gas discharged to the flare 
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over the discharge duration. If the discharge duration exceeds 

24 hours, record the quantity of gas discharged to the flare for 

each 24-hour period. Engineering calculations are allowed for 

fuel gas combustion devices, but are not allowed for flares,

except for those complying with the alternative monitoring 

requirements in §60.107a(g).

(iv) For each discharge greater than 500 lb SO2 in any 24-

hour period from a flare, the measured total sulfur 

concentration or both the measured H2S concentration and the 

estimated total sulfur concentration in the fuel gas at a 

representative location in the flare inlet.

(v) For each discharge greater than 500 lb SO2 in excess of 

the applicable short-term emissions limit in §60.102a(g)(1) from 

a fuel gas combustion device, either the measured concentration 

of H2S in the fuel gas or the measured concentration of SO2 in 

the stream discharged to the atmosphere. Process knowledge can 

be used to make these estimates for fuel gas combustion devices,

but cannot be used to make these estimates for flares, except as 

provided in §60.107a(e)(4).

(vi) For each discharge greater than 500 lb SO2 in excess of 

the allowable limits from a sulfur recovery plant, either the 

measured concentration of reduced sulfur or SO2 discharged to the 

atmosphere.
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(vii) For each discharge greater than 500 lb SO2 in any 24-

hour period from any affected flare or discharge greater than 

500 lb SO2 in excess of the allowable limits from a fuel gas 

combustion device or sulfur recovery plant, the cumulative 

quantity of H2S and SO2 released into the atmosphere. For 

releases controlled by flares, assume 99-percent conversion of 

reduced sulfur or total sulfur to SO2. For fuel gas combustion 

devices, assume 99-percent conversion of H2S to SO2.

(viii) The steps that the owner or operator took to limit 

the emissions during the discharge.

(ix) The root cause analysis and corrective action analysis 

conducted as required in §60.103a(d), including an 

identification of the affected facility, the date and duration 

of the discharge, a statement noting whether the discharge 

resulted from the same root cause(s) identified in a previous 

analysis and either a description of the recommended corrective 

action(s) or an explanation of why corrective action is not 

necessary under §60.103a(e).

(x) For any corrective action analysis for which corrective 

actions are required in §60.103a(e), a description of the 

corrective action(s) completed within the first 45 days 

following the discharge and, for action(s) not already 

completed, a schedule for implementation, including proposed 

commencement and completion dates.
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(xi) For each discharge from any affected flare that is the 

result of a planned startup or shutdown of a refinery process 

unit or ancillary equipment connected to the affected flare, a 

statement that a root cause analysis and corrective action 

analysis are not necessary because the owner or operator 

followed the flare management plan.

(7) If the owner or operator elects to comply with 

§60.107a(e)(2) for a flare, records of the H2S and total sulfur 

analyses of each grab or integrated sample, the calculated daily 

total sulfur-to-H2S ratios, the calculated 10-day average total 

sulfur-to-H2S ratios and the 95-percent confidence intervals for 

each 10-day average total sulfur-to-H2S ratio.

(d) * * *

(5) The information described in paragraph (c)(6) of this 

section for all discharges listed in paragraph (c)(6) of this 

section. For a flare complying with the monitoring alternative 

under §60.107a(g), following the fifth discharge required to be 

recorded under paragraph (c)(6) of this section and reported 

under this paragraph, the owner or operator shall include 

notification that monitoring systems will be installed according 

to §60.107a(e) and (f) within 180 days following the fifth

discharge.

* * * * *
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19. Section 60.109a is amended by revising paragraph (b) 

introductory text and adding paragraph (b)(4) to read as 

follows:

§60.109a Delegation of authority.

* * * * *

(b) In delegating implementation and enforcement authority 

of this subpart to a state, local or tribal agency, the approval 

authorities contained in paragraphs (b)(1) through (4) of this 

section are retained by the Administrator of the U.S. EPA and 

are not transferred to the state, local or tribal agency.

* * * * *

(4) Approval of an application for an alternative means of 

emission limitation under §60.103a(j) of this subpart.

20. Table 1 to subpart Ja is added to read as follows:

Tables to Subpart Ja of Part 60

Table 1 to Subpart Ja of Part 60--Molar Exhaust Volumes and 

Molar Heat Content of Fuel Gas Constituents

Constituent

MEVa

dscf/mol

MHCb

Btu/mol

Methane (CH4) 7.29 842

Ethane (C2H6) 12.96 1,475

Hydrogen (H2) 1.61 269

Ethene (C2H4) 11.34 1,335

Propane (C3H8) 18.62 2,100

Propene (C3H6) 17.02 1,947

Butane (C4H10) 24.30 2,717

Butene (C4H8) 22.69 2,558

Inerts 0.85 0 a MEV = molar exhaust volume, dry standard cubic feet per grammole (dscf/g-mol) at standard conditions of 68° Farhenheit and 1 

atmosphere
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b MHC = molar heat content (higher heating value basis), Btu per 

gram-mole (Btu/g-mol)