### From: Brenda Shine [mailto:Shine.Brenda@epamail.epa.gov] Sent: Friday, April 27, 2012 3:16 PM To: Higgins, Cortney Cc: Robin Langdon; Penny Lassiter; Alex Macpherson; William Nickerson; Susan Stahle Subject: Interagency Comments on the Petroleum Refinery NSPS Ja Preamble and RIA

Hi Cortney, Attached are redline and clean versions of the preamble and rule package, and the RIA addressing your comments. Also, regarding the question below, both scenarios contain the same monitoring costs. This is because installation of recovery systems could allow for less stringent monitoring and would presumably reduce the frequency of RCA events to address, but it is difficult to estimate to what extent this would happen (it would be a guess, since the rule allows for less burdensome monitoring if the system captures enough gas to limit flow through the water seal to 4 or less events per year-- it does not automatically provide for less burdensome monitoring if facilities install recovery systems) and ultimately this value, as y our reviewer indicates, is not significant when compared to the difference in costs associated with the installation of the recovery systems. Thanks and please call me with questions or comments.

<< EO12866_PetRefineriesSubpart_J_2060-AN72FnlRule_04-27- 12_InteragencycommentsunderEO13563 REDLINE.docx >> << EO12866_PetRefineriesSubpart_J_2060-AN72FnlRule_04-27- 12_InteragencycommentsunderEO13563 CLEAN.docx >> << NSPS Ja Reconsideration RIA_InteragencycommentsunderEO13563 04_27_2012.docx >>***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

**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 Deleted: **20120405*****E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 3 of 293 (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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 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 Code 1 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 6 of 293 307(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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 7 of 293 **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 Comment [ A 1]: For all equipment affected by this rule, is it possible to include a table of what the previous and new standards are as a way to simplify this text? I’m thinking about a table you would generate for a fact sheet or “what emissions standards apply” type FAQ e.g. Affected unit Old Standard New Standard Natural draft Process heaters ### 30 ppmv NOX Forced draft process heaters ### 40 ppmv NOX***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 8 of 293 Forced

Draft

Process

Heaters NOx Emission

Limits 40 ppmv 60 ppmv or 0.06 lb/MM

BTU

Forced

Draft

Process

Heaterswith Cofired (oil and gas)

Burners NOx Emission

Limits 40 ppmv 150 ppmv or Weighted average based on oil

a t 0.40 lb/MM BTU and gas at 0.11 lb/MM BTU

Natural

Draft

Process

Heaterswith 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 9 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 10 of 293 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

i ntermittent/emergency

o nly 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-***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 11 of 293 based NO X emissions limits and alternative heating value-based

NO X emissions limits, both determined daily on a 30-day rolling average basis. These final amendments establish limits of 40 ppmv NO x (or 0.04 lb/mmBTU) and 60 ppmv NO x (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

NO x 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 NO X 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 NO x 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 SO 2 (expressed as a 162 ppmv short-term H 2 S 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 H 2 S fuel gas concentration limit. As explained in section IV***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 12 of 293 of this preamble, we determined that requiring refineries to ensure the fuel gas they send to their flares meets a long-term

H 2 S 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 SO 2 in a 24-hour period; and (3) optimize management of the fuel gas by limiting the short-term

concentration of H 2 S 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 13 of 293 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 SO 2 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 14 of 293 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 Deleted: 1 Comment [ A 2]: Please move this footnote into the text.

Deleted: for

Deleted: , based on the updated number of flares.

Deleted:***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 15 of 293 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. 2 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

2 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 16 of 293 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. We estimate that the final requirements for flares will

reduce emissions of SO 2 by 3,200 tons per year (tons/yr), NO X 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 CO 2 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 17 of 293 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 r eductions (tons SO 2 /yr) Annual emission r eductions (tons NO X /yr) Annual emission r eductions (tons VOC/yr) Costeffectiveness ($/ton em i ssions 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

SO 2 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)

Subtotal 1 72,000 16,000 (6,700) 9,000 2 ,600 5 0 6 60 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

SO 2 RCA/CA 0 220 0 220 290 0 0 760

Flowrate RCA/CA 0 100 (740) (640) 0.4 6 43 (13,000) Subtotal 1 390,000 81,000 (170,000) (88,000) 660 1,100 2,800 (20,000)

Total 1 460,000 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. 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. Comment [A3]: This table is confusing, and the text is more clear. In order to clarify what this rule does, can this table be reorganized to track with the actions described in A.1. Category 1: Final Amendments to requirements for flares and process heaters Category 2: Provisions from the 2008 rule for which the stay is being lifted And then drop a footnote with the original estimates (for only 40 flares) from the 2008 rule? Comment [ A 4]: Discussed that don’t need to revised Table 1. Deleted: ¶

Comment [ A 5]: Can you provide the table number in the RIA?***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 18 of 293

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 SO 2 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, such as the long-term H 2 S limit for flares, these are impacts did

not result in emission reductions and were not monetized

. **B. Background of the Refinery NSPS** Comment [ A 6]: Based on the revisions to the table, this paragraph may need to be rewritten.

Deleted: non-monetized benefits of the rule***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 19 of 293 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. 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 20 of 293 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, 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 21 of 293 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; 3 (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 (NO X ) 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 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

3 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.”***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 22 of 293 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. 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 23 of 293 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 NO x 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 NO x at proposal to 60 ppmv NO x . 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 NO x concentration limit (i.e., 0.04 lb/mmBTU for natural draft and 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 24 of 293 also finalizing an alternative case-specific compliance option that allows owners and operators to obtain EPA approval for a site-specific NO X 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 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*****E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 25 of 293 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 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 26 of 293 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 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)?***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 27 of 293 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-firedprocess heaters, we divided natural draft and forced draft cofired process heaters into separate subcategories with different

emissions limits. For each of the first two subcategories, the final

amendments include a concentration-based NO X emissions limit and a heating value-based NO X emissions limit, both determined daily***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 28 of 293 on a 30-day rolling average basis. For the natural draft process heater subcategory, the concentration-based NO X 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 NO X 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 NO X emissions limit differs from the proposed limit in that it is a more direct numerical conversion from 40 ppmv NO X . 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 NO X emissions 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 NO x burners meet the emission limits described above if compliance is determined on a 30-day rolling average***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 29 of 293 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 NO X 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 NO X 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 NO X emissions limit is a more direct numerical conversion from 60 ppmv NO X . 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 NO X emissions limit or the***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 30 of 293 heating value-based NO X 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 NO X emissions limit. If the refinery owner or operator does not choose to monitor fuel composition, then they must comply with the concentration-based

NO X 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 NO x Emission Limits 40 ppmv or 0.035 lb/MM BTU 40 ppmv or 0.04 lb/MM BTU

Forced Draft NO x 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

Co-fired Burner (oil and gas) NO x 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 31 of 293

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 NO X emission rate is calculated using the oxygen (O 2 )-based F factor, dry basis according to EPA Method 19 of 40 CFR part 60, appendix A-7. Ongoing compliance with this NO X emissions limit is determined using a NO X 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 section IV.A of this preamble, co-fired process heaters do notinclude 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 32 of 293 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 NO X limit for certain process heaters. This 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 33 of 293 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 NO X burners or otherwise meet the applicable limit and some co-fired units may not be able to

achieve the NO X limitations even with ultra-low NO X burner control technology. In addition, commenters noted that downwardly fired process heaters with induced draft fans have

similar NO X 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 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 NO X burner control technologies. The***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 34 of 293 ultra-low NO X 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 NO X concentrations at low firing rates. Therefore, all types of process heaters with ultra-low NO X 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 NO X burner technology is not feasible or that the technology cannot meet

the NO X 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 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-NO X burners or ultra-low NO X***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 35 of 293 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 O 2 operating limit, including provisions on how to develop an O 2 operating curve to ensure compliance with the NO X 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 O 2 concentration operating limit or operating curve that can be met at all times, even during turndown, and comply with the O 2 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 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 36 of 293 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”). 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 37 of 293 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 (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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 38 of 293 limit the long-term concentration of hydrogen sulfide (H 2 S) to 60 ppmv (determined daily on a 365 successive calendar day rolling average basis) (hereafter referred to as the long-term 60 ppmv

H 2 S 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 H 2 S 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 H 2 S 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 (SO 2 ) 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 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 39 of 293 cause analyses and take corrective action when the emissions

from the flare exceed 500 lb of SO 2 in a 24-hour period (instead

of 500 lb SO 2 above the emissions limit); and (4) optimize management of the fuel gas by limiting the short-term

concentration of H 2 S 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 SO 2 (expressed as a 162 ppmv short-term H 2 S 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 SO 2 are created in the flame that burns outside the flare tip. Therefore, we have determined that this suite of work practice standards, which includes optimization of fuel gas management (based on limiting

concentration of H 2 S to 160 ppmv) is more appropriate for flares, as opposed to the H 2 S 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 40 of 293 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, 4 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 SO 2 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 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 SO 2 or flow rate root

4 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 ).***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 41 of 293 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 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 42 of 293 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 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 43 of 293 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 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 44 of 293 requirements for these monitors and are allowing the use of cylinder gas audits for relative accuracy assessments. We are finalizing the H 2 S 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 SO 2 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

SO 2 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 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 45 of 293 triggered by an exceedance of the flow rate threshold long before they exceed the 500 lb SO 2 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 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 46 of 293 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 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 47 of 293 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 SO 2 emissions. In addition, if flow 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 48 of 293 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” that will achieve a reduction in emissions at least equivalent to the reduction in emissions achieved under any of the final***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 49 of 293 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 SO 2 above the emission limit, but the proposed amendments directed the owner or operator to compare the SO 2 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 SO 2 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 finalizing an amendment that states that the threshold for a root cause analysis and corrective action analysis for both***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 50 of 293 sulfur recovery plants and fuel gas combustion devices is 500 lb above the emission limit during one or more consecutive periods

of excess emissions 5 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 corrective action analysis requirements already described. We are also finalizing 40 CFR 60.108a(c), as proposed, to add

5 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.”***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 51 of 293 recordkeeping requirements for the proposed monitoring option that is based on periodic manual sampling and analysis to

determine the total sulfur-to-H 2 S 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 equipment are integral to the operation of a delayed coking unit. Therefore, we are revising the definition of “delayed***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 52 of 293 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

a revision to the definition of “flare” to refer to the “flare gas header system” rather than repeat the components of the***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 53 of 293 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 shale or tar sands-derived crude oil for further processing using only solvent extraction and/or distillation to recover***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 54 of 293 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 petroleum refinery are producing refinery fuel gases. We also proposed to amend the definition to state that gas generated by***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 55 of 293 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 “H 2 S.” 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 loading facilities downstream of the sulfur pits are not part of***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 56 of 293 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 (HS 2 ), each calculated as ppm SO 2 by volume (dry basis) at zero percent excess air” with “300 ppmv of reduced sulfur compounds and 10 ppmv of H 2 S, each calculated as ppmv SO 2 ( 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 57 of 293 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 “Opacity st ” 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 58 of 293 60.107a(a)(2)(i) Replace “320 ppmv H 2 S” with “300 ppmv H 2 S” to make the span value for a H 2 S 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 “t h e 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 59 of 293 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 NO X , 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 NO X ). 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) NO X 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 60 of 293 air preheat. Actual NO X 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 NO X 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 NO X 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 NO X . Consequently, we are raising the NO X emissions limit (while concurrently reducing the averaging time) for all new forced draft process heaters to be equivalent to the emissions limit***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 61 of 293 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 NO X 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 NO X 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 62 of 293 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 NO X 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,***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 63 of 293 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 NO X limit. The heating value-based NO X emission rate is calculated using the oxygen (O 2 )-based F factor, which is the ratio of combustion gas volume to heat input. Ongoing compliance with

this NO X emissions limit is determined using a NO X 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 NO X concentration (ppmv, dry basis, corrected to 0-percent excess air) and a 30-day rolling average NO X 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 NO X concentration above the 60 ppmv limit, but below the 0.060***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 64 of 293 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 NO X concentrations will likely be above the emissions limits, but the mass of NO X emissions is no greater***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 65 of 293 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 O 2 levels during turndown and requested that the proposed

maximum O 2 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 longeraveraging 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 66 of 293 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

NO X 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 NO X 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 NO X concentrations of process heaters using ultra-low NO X 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 O 2 concentrations at normal conditions (i.e. , at exhaust O 2 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 O 2 concentrations for these units during normal (i.e. , nonturndown) firing rates. That is, these process heaters were not being operated optimally for reducing NO X emissions. Furthermore,***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 67 of 293 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 O 2 concentrations for reducing NO X 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 NO X burners that operated at excess O 2 concentrations less than 6 percent (i.e. , operated in a manner consistent with proper low NO X burner operation), all such process heaters could comply with the final NO X 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 68 of 293 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 O 2 concentrations increase at lower firing rates; and (2)

exhaust NO X concentrations (corrected to 0-percent excess O 2 ) increase with increasing O 2 concentration (regardless of firing rates). These data, along with the need to operate the process heater at higher O 2 concentrations during low firing rates to maintain flame stability, suggest that an alternative NO X 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 NO X emissions limit that would be equivalent to the mass of NO X 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 theprocess heaters were able to meet the applicable concentrationbased emissions limit (40/60 ppmv) or the heating value-based***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 69 of 293 (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 O 2 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 O 2 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 O 2 concentration at which flame stability is achieved while minimizing NO X formation. That is, even when a process heater is operating at less than 50 percent design capacity, excess O 2 concentrations should still be controlled to

minimize NO X 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 O 2 concentrations cannot meet the emissions***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 70 of 293 limits. However, we acknowledge that the correlations with firing rates and O 2 and/or NO X concentrations and the need for higher O 2 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 O 2 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 foran 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 NO X CEMS, turndown is also expected to be***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 71 of 293 an issue with respect to achieving the O 2 operating limit. As described above, higher O 2 concentrations are generally needed to maintain flame stability at low firing rates. To address potential turndown compliance issues with the O 2 operating limit, we have provided an allowance for process heater owners or operators to develop an O 2 operating curve to provide different

O 2 operating limits based on the firing rate of the process heater. If a single O 2 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 O 2 to maintain flame stability, a separate O 2 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 O 2 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 72 of 293 emission rate should be extended to 365 days. One commenter

noted that the notation “E NOx,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 NO X 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 73 of 293 burner emissions test data provided by another commenter 6 (conducted under well-controlled conditions using best available

ultra-low NO X 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 NO X emissions limits for co-fired process heaters to those described above. We

note that we have revised the concentration-based NO X 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

6 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 74 of 293 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 O 2 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-NO X burner technologies exist, are demonstrated and are cost effective forco-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,***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 75 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 76 of 293 from a process unit to the flare. Other commenters suggested that the flare modification provision should be focused on volatile organic compounds (VOC) and SO 2 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 77 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 78 of 293 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 SO 2 . Flares are known to emit VOC, SO 2 , carbon monoxide (CO), PM and NO X , 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, SO 2 , CO, PM and NO X . 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 79 of 293 control VOC emissions at other refinery process units will increase CO, PM and NO X 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 SO 2 , VOC, CO, NO X 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 SO 2 , VOC, CO, PM,

NO X 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;***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 80 of 293 (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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 81 of 293 (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 SO 2 . 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 82 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 83 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 84 of 293 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 85 of 293 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 NO X ) 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, SO 2 , CO, PM and NO X . 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 86 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 87 of 293 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 H 2 S. We reiterate that SO 2 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 SO 2 root cause analysis threshold. We carefully considered temporary connections for purging existing equipment (Item 13 above), but we failed to see how***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 88 of 293 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 89 of 293 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 90 of 293 (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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 91 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 92 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 93 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 94 of 293 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 areeffectively 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 NO X 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 95 of 293 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 flares 7 from

the H 2 S 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.

7 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 H 2 S concentration limits in 40 CFR 60.102a(g)(1).***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 96 of 293 The commenter asserted that the CAA also requires that a section 111-compliant standard that reflects BSER 8 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

8 The commenter asserted, without providing support, that it is not BSER to exempt flares from the H 2 S concentration limits during startup and shutdown events. The commenter also stated that the EPA, at a minimum, must demonstrate how the exemption from the H 2 S concentration limits during SSM events does, in fact, represent BSER, but the commenter stated that the EPA has failed to make this demonstration.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 97 of 293 performance for flares, 9 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 H 2 S 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 H 2 S 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 H 2 S 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

9 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.”***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 98 of 293 “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 H 2 S concentration limits during SSM events.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 99 of 293 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 H 2 S 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 100 of 293 their variability.” Therefore, for all of the above reasons, the commenter asserted that exempting a flare from the H 2 S 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 H 2 S 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 SO 2 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

SO 2 emissions exceed 500 lb in a 24-hour period; and (4) optimize management of the fuel gas by limiting the short-term

concentration of H 2 S 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 101 of 293 111-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 SO 2 , are not created until combustion occurs, which happens in the flame that burns outside of the flare tip. In other words, the SO 2 , NO X , 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 102 of 293 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 SO 2 (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 SO 2 emissions for fuel gas combustion devices which also applied to flares. 39 FR 9308, 9315 (March 8, 1974). The standard is expressed as an H 2 S concentration limit because it was developed as an alternative to measuring the SO 2 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 H 2 S in the fuel gas combusted in those devices is directly indicative of the SO 2 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 SO 2 emissions, expressed as an H 2 S concentration limit or a total sulfur limit at the inlet to the flare. However, as explained***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 103 of 293 above, flares are substantially different from other fuel gas combustion devices so that this approach is not workable for flares. For example, SO 2 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, 10 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 SO 2 . Since so many factors affect the potential formation of SO 2 emissions outside the flare tip, we realized that we could not properly

derive an H 2 S concentration limit or a total sulfur limit at the flare inlet that would directly correlate with those SO 2 emissions. Thus, we determined that we cannot set a standard of performance for SO 2 emissions at the flare. However, we still recognize that reducing the amount of

sulfur that is sent to a flare will reduce the SO 2 emissions at the flare. Even with the uncertainty described above, we

10 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 104 of 293 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 SO 2 emissions. Rather than

eliminate the H 2 S concentration limit altogether, we are instead requiring under CAA section 111(h) that refineries limit the

short-term concentration of H 2 S 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 H 2 S 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 H 2 S concentration limit during periods when high fuel gas flows would likely overwhelm these flare gas recovery systems would***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 105 of 293 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 H 2 S 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 SO 2 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 SO 2 emission limits for flares

have been established under state law and in FederalImplementation 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 SO 2 FIP for the Billings/Laurel Montana area includes a SO 2 emission limit of***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 106 of 293 150 lb of SO 2 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 SO 2 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 SO 2 /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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 107 of 293 flare is converted to SO 2 , 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 SO 2 at the flare tip and how these factors affect how much of the sulfur in the gases sent into the flare actually converts to SO 2 . Therefore, although setting such source-specific limits was appropriate to satisfy what the modeling showed was necessary to meet the SO 2 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 H 2 S 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 H 2 S as a baseline because many refinery streams currently sent to the***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 108 of 293 flare contain H 2 S concentrations below 162 ppmv, so 162 ppmv H 2 S 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 SO 2 emissions estimates. One commenter stated that the long-term 60 ppmv H 2 S 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 H 2 S 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 H 2 S 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 109 of 293 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 H 2 S 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 H 2 S 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

H 2 S concentration to 60 ppmv in addition to the short-term H 2 S concentration of 162 ppmv during normal operating conditions. We determined that, for refineries to demonstrate that their fuel gas complies with a long-term H 2 S 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 110 of 293 the long-term concentration of H 2 S 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 H 2 S 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 H 2 S concentration to a combined short-term 162 ppmv H 2 S concentration and long-term 60 ppmv H 2 S concentration. While we are aware that some consent decrees require refineries to limit the

concentration of H 2 S in the fuel gas to levels lower than the short-term 162 ppmv H 2 S 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 H 2 S concentration limit in 40 CFR part 60, subpart J).***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 111 of 293 Table 2. National Fifth Year Impacts of Meeting a Long-Term 60 ppmv H 2 S Concentration for Flares Subject to 40 CFR Part 60, Subpart Ja

Capital cost ($1,000) Total annual cost ($1,000/yr)a Emission reduction (tons SO 2 /yr) b Emission reduction (tons NO X /yr) b Emission reduction (tons VOC/yr) b Costeffectiveness ($/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 H 2 S 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 H 2 S concentration in the fuel gas to 162 ppmv to the originally proposed combined short-term 162 ppmv H 2 S concentration and long-term 60 ppmv H 2 S 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.”***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 112 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 113 of 293 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,***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 114 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 115 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 116 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 117 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 118 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 119 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 120 of 293 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 rootcause 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 121 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 122 of 293 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 scfd 11 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

11 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 123 of 293 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

SO 2 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 124 of 293 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),***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 125 of 293 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 SO 2 in***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 126 of 293 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 SO 2 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 127 of 293 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,***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 128 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 129 of 293 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 H 2 S concentration requirements and flares with properly designed flare gas recovery systems, commenters stated that engineering

calculations are sufficient to determine if the SO 2 root cause analysis threshold of 500 lb in any 24-hour period is exceeded. One commenter requested that the EPA allow owners or operators***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 130 of 293 to submit and use an alternative monitoring plan to demonstrate that the flare gas recovery system is operating within its capacity and to calculate SO 2 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-H 2 S 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 H 2 S 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 131 of 293 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 H 2 S monitoring due to low sulfur content are alsoexempt 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 SO 2 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

H 2 S 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 H 2 S monitoring at a central location is allowed for flares as well). Thus, we agree that if***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 132 of 293 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 H 2 S 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 SO 2 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-H 2 S 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 133 of 293 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 134 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 135 of 293 flares are for total reduced sulfur or total sulfur. The commenter noted that measuring total sulfur is the simplest and

most inclusive measurement of SO 2 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-H 2 S (or total reduced

sulfur-to-H 2 S) 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 H 2 S concentration in fuel gas sent to a flare to 162 ppmv without the need for a duplicative continuous H 2 S 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 SO 2 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 136 of 293 to be in the form of total reduced sulfur compounds, which include carbon disulfide, carbonyl sulfide and H 2 S. 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 SO 2 emissions at the flare. These include optimizing management of the fuel gas by limiting the short-term concentration of H 2 S to 162 ppmv during normal operating conditions. We expected most refineries would already have the H 2 S monitor and did not consider the useof a total sulfur monitor for use in complying with the shortterm 162 ppmv H 2 S concentration in the fuel gas. As the H 2 S concentration will always be less than the total reduced sulfur concentration, it is acceptable to use the total reduced sulfurmonitor to verify that the fuel gas does not exceed the shortterm H 2 S 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 H 2 S. The owner or operator using this method must essentially be able to demonstrate they can achieve a 162 ppmv total reduced sulfur***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 137 of 293 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 H 2 S monitor was already in-place, as well as the expected accuracy needed for the system to assess the SO 2 root cause analysis threshold. As few cases would exist where the flaring event would be right at the SO 2 root cause analysis threshold of 500 lb in any 24-hour period, inaccuracies associated with the average total sulfur-to-H 2 S ratio were not expected to be significant. On the other hand, the short-term 162 ppmv H 2 S concentration in the fuel gas must be continuously maintained, and the total

sulfur-to-H 2 S 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 H 2 S, the non-H 2 S reduced sulfur concentration is expected to be fairly constant, with most of the fluctuations in total sulfur content being attributable to

fluctuations in H 2 S 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 H 2 S. Therefore, owners or operators of affected flares may use the***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 138 of 293 direct output of a total reduced sulfur monitor to assess compliance with the short-term 162 ppmv H 2 S concentration in the fuel gas, or they must install a continuous H 2 S monitor.

Comment : One commenter supported the proposed amendment revising the span value for fuel gas H 2 S 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 H 2 S 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 H 2 S concentration limits and that engineering calculations can be used to assess

exceedances of the SO 2 root cause analysis threshold of 500 lb in any 24-hour period. Response : The H 2 S span value is at 300 ppmv to verify compliance with the H 2 S 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 H 2 S analyzers both to assess compliance with the short-term 162 ppmv H 2 S concentration requirement for the fuel gas and to

assess exceedances of the SO 2 root cause analysis threshold of***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 139 of 293 500 lb in any 24-hour period, a dual range monitor will be necessary. For the purposes of the SO 2 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 H 2 S concentration requirement for the fuel gas and the SO 2 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 H 2 S monitoring alternative, and the same span considerations apply for these monitors.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 140 of 293 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 H 2 S concentration to 162 ppmv, long-term 60 ppmv H 2 S 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

H 2 S 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 141 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 142 of 293 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 H 2 S fuel gas concentration limit to flares, the comments related to the amount of time needed to comply with a long-term 60 ppmv H 2 S 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 H 2 S 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 H 2 S 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 143 of 293 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 H 2 S 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 144 of 293 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 H 2 S 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 145 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 146 of 293 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. 12 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

12 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).***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 147 of 293 this paragraph. The final rule requires all new, modified and reconstructed flares to meet the short-term 162 ppmv H 2 S 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 148 of 293

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 unitdoes not limit process operations to distillation, redistillation, cracking or reforming, and it is not limited to***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 149 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 150 of 293 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 H 2 S 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 H 2 S 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.”***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 151 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 152 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 153 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 154 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 155 of 293 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 156 of 293

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 O 2 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

H 2 S concentration limits (or alternative SO 2 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 157 of 293 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 H 2 S 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 SO 2 emissions limits or the H 2 S 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 158 of 293 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 SO 2 emissions limits or the H 2 S 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 159 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 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 Deleted: impacts are expressed as incremental***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 161 of 293 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 H 2 S concentration of 162 ppmv in the fuel gas are included in the baseline rather than the incremental impacts because this limit Deleted: the impacts of petroleum refinery process units complying with Formatted: No underline

Deleted: (i.e., baseline)

.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 162 of 293 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 SO 2 by 3,200 tons per year (tons/yr), NO X 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 163 of 293 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 SO 2 by 3,200 tons per year (tons/yr), NO X 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. Deleted: incremental***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 164 of 293 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 r eductions (tons S O 2 / yr) Annual emission r eductions (tons N O X / yr) Annual emission r eductions (tons V OC/yr) Costeffectiveness ($/ton emissions r educed ) 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 CO 2 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 NO X burners). We did Deleted: I ncremental

Comment [ A 7]: Please clarify what is the baseline used in this table for these amendments. Is it the 2008 final rule (as would seem to be appropriate according to Circular A-4), or the state of the world without the final rule? If the latter, please explain why this baseline is appropriate. Comment [ A 8]: 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 165 of 293 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 NO X 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 NO X***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 166 of 293 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 NO X 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 NO X 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 167 of 293 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 H 2 S 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 168 of 293 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 SO 2 , NOx and

VOC as well as CO 2 . SO 2 , NOx and VOC are precursors to PM 2.5 (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

PM 2.5 from emission reductions of SO 2 and NOx and the climate

benefits associated with CO 2 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) Deleted:

Deleted: Either with the annualized compliance costs estimated to be negative or if no

Deleted: and total annualized compliance costs are estimated to be $10.7 million Comment [ A 9]: This clause is awkward, does the substitution “Regardless of whether any refineries install flare gas recovery systems,” preserve the intended meaning?***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 169 of 293 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 PM 2.5 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. 13 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 SO 2 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.

13 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 170 of 293

Table 4. Summary of the Monetized PM 2.5 and CO 2 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 PM 2.5 Benefits b SO 2 3,200 $210 to $510 $190 to $460 NO X 1,100 $7.1 to $18 $6.4 to $16 PM Total: $220 to $530 $ 190 to $480 CO 2 Benefits c 1,900,000 d $46 $46 Total Monetized Benefits: $260 to $580 $240 to $520 Without Flare Gas Recovery PM 2.5 Benefits b SO 2 2,900 $190 to $450 $170 to $410 NO X 56 $0.36 to $0.87 $0.32 to $0.78 PM Total: $190 to $460 $170 to $410 CO 2 Benefits c 110,000 d $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 PM 2.5 through reductions of PM 2.5 precursors, such as NO X and SO 2 as well as CO2 . It is important to note that the monetized benefits do not include reduced health effects from direct exposure to SO 2 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 CO 2 emission reductions (shown in metric tonnes) have been reduced to reflect the anticipated emission increases associated Comment [ A 10]: Suggest breaking down benefits to show required and optional (ie with gas recovery) to maintain comparability with cost estimates. Deleted: ¶***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 171 of 293 with the energy disbenefits. CO 2 -related benefits were calculated using the social cost of carbon (SCC), which is discussed further in the RIA. The net present value of reduced CO 2 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 CO 2 benefits using discount rates of 5 percent (average), 2.5 percent (average), and 3 percent (95 th percentile). d Metric tonnes These benefits estimates represent the total monetized human health benefits for populations exposed to less PM 2.5 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 PM 2.5 -related health impacts and monetized benefits based on changes in SO 2 and NOx emissions. These benefit-per-ton factors were derived using the general approach and methodology laid out in Fann, Fulcher, and Hubbell (2009). 14 This approach

uses a model to convert emissions of PM 2.5 precursors into changes in ambient PM 2.5 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

14 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 172 of 293 use air quality modeling data specific to the petroleum

refineries sector. 15 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, theair 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

15 U.S. Environmental Protection Agency. 2011. Technical support document: Estimating the benefit per ton of reducing PM 2.5 precursors from the petroleum refineries sector

. EPA, Research Triangle Park, NC.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 173 of 293 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 SO 2 and NOx and multiply them by the corresponding emission reductions. The sector-specific modeling does not provide estimates of the PM 2.5 - related benefits associated with reducing VOC emissions, but these unquantified benefits are generally small compared to

other PM 2.5 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 PM 2.5 precursors affected by this rule

are SO 2 and NO X . 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 PM 2.5 levels, which drive population exposure. For example, SO 2 has a lower benefit-per-ton estimate than direct

PM 2.5 because it does not form as much PM 2.5 , thus, the exposure***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 174 of 293 would be lower, and the monetized health benefits would be

lower. It is important to note that the magnitude of the PM 2.5 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 PM 2.5 concentrations and premature mortality. We cite two key empirical studies, one based on the American Cancer Society cohort study 16 and the extended Six Cities cohort study. 17 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

16 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. 17 Laden, et al. , 2006. Reduction in Fine Particulate Air Pollution and Mortality . American Journal of Respiratory and Critical Care Medicine 173: 667-672.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 175 of 293 model for assessing the mortality benefits associated with reducing PM 2.5 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 PM 2.5 . 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

PM 2.5 level. As a surrogate measure of mortality impacts, we provide the percentage of the population exposed at each PM 2.5 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 PM 2.5 levels at or above the LML of 7.5 micrograms per cubic meter (μg/m 3 ). Using the Laden, et al. (2006) study, 25 percent of the population is exposed above the LML of 10 μg/m 3

.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 176 of 293 It is important to emphasize that we have high confidence in

PM 2.5 -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 PM 2.5 , 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 PM 2.5 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 PM 2.5 NAAQS benefits analysis 18 provides an indication of the sensitivity of

18 U.S. Environmental Protection Agency, 2006. Final Regulatory Impact Analysis: PM 2.5 NAAQS . Prepared by Office of Air and***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 177 of 293 our results to various assumptions. This rule is expected to reduce CO 2 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 CO 2 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 178 of 293 Technical Support Document (SCC TSD) provides a complete discussion of the methods used to develop these SCC estimates. 19 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 CO 2 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 95 th 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

19 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 179 of 293 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 95 th 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 SO 2 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,***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 180 of 293 such as the long-term H 2 S 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 181 of 293 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 Benefits b $270 to $580 $240 to $530 Total Compliance Costs c -$79 -$79 Net Benefits $340 to $660 $320 to $610 Non-Monetized Benefits Health effects from direct exposure to SO 2 and NO 2 Health effects from PM 2 .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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 182 of 293 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 estimated affected flares 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 analyses, Comment [ A 11]: Please remind reader how many flares for this rule.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 183 of 293 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,***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 184 of 293 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 approvedannual 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 185 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 186 of 293 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 187 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 188 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 189 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 190 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 191 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 192 of 293 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 H 2 S: 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 193 of 293 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).***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 194 of 293 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).***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 195 of 293 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 196 of 293 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]** 

.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 198 of 293 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 Sources 1 * * * * * 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.

* * * * ****E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 199 of 293 **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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 200 of 293 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).***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 201 of 293 (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),***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 202 of 293 (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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 203 of 293 (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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 204 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 205 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 206 of 293 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.

* * * * ****E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 207 of 293 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 (E s ) of PM shall be computed for each run using the following equation:

E s = F + A (H/R c )

Where:

E s = 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). R c = 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:***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 208 of 293 **§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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 209 of 293 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 210 of 293 (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 “Airpreheat,” “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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 211 of 293 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 loadingoperations, 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 212 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 213 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 214 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 215 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 216 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 217 of 293 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 H 2 S and/or SO 2 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 218 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 219 of 293 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 H 2 S, each calculated as ppmv SO 2 (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 SO 2 in excess of 20 ppmv (dry basis, corrected to 0-percent excess air)***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 220 of 293 determined hourly on a 3-hour rolling average basis and SO 2 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 H 2 S in excess of 162 ppmv determined hourly on a 3-hour rolling average basis and H 2 S 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

NO X 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 221 of 293 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:***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 222 of 293 (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:

ER NOx = Daily allowable average emission rate of NO X , lb/MMBtu (higher heating value basis); Q gas = Daily average volumetric flow rate of fuel gas, standard cubic feet per day (scf/day); Q oil = Daily average volumetric flow rate of fuel oil, scf/day; HHV gas = Daily average higher heating value of gas fired to the process heater, MMBtu/scf; and HHV oil = 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: oil oil gas gas oil oil gas gas NOx 

## HHV Q HHV Q HHV Q HHV Q ER  

 35

. 0 06

. 0

oil oil gas gas oil oil gas gas NOx 

## HHV Q HHV Q HHV Q HHV Q ER  

 35

. 0 06

. 0 Deleted: gas gas NOx 

## H Q H Q ER  06

. 0

g

gas g gas NOx 

## HHV Q HHV Q ER  06

. 0

Formatted: Lowered by 16 pt***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 223 of 293

(Eq. 4)

Where:

ER NOx = Daily allowable average emission rate of NO X , lb/MMBtu (higher heating value basis); Q gas = Daily average volumetric flow rate of fuel gas, scf/day; Q oil = Daily average volumetric flow rate of fuel oil, scf/day; HHV gas = Daily average higher heating value of gas fired to the process heater, MMBtu/scf; and HHV oil = 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 NO X 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 NO X emissions limit: (i) A modified or reconstructed process heater that lacks sufficient space to accommodate installation and proper oil oil gas gas oil oil gas gas NOx 

## HHV Q HHV Q HHV Q HHV Q ER  

 40

. 0 11

. 0

oil oil gas gas oil oil gas gas NOx 

## HHV Q HHV Q HHV Q HHV Q ER  

 40

. 0 11

. 0 Deleted: gas gas NOx 

## H Q Q ER  11

. 0

gas gas NOx 

## HHV Q HHV Q ER  11

. 0

Formatted: Lowered by 16 pt***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 224 of 293 operation of combustion modification-based technology (e.g. , ultra-low NO X 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 NO X 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 NO X 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 225 of 293 (ii) An explanation of how the data in paragraph (i)(2)(i)

demonstrate that ultra-low NO X 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 NO X 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 NO X 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 226 of 293 (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 NO X emissions limit is described in paragraphs (i)(4)(i) through (iii) of this section. (i) Approval by the Administrator of a facility-specific NO X 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-NO X burner designs and other combustion modifications considered for reducing NO X emissions; (C) The combustion modification option selected; and (D) The operating conditions (firing rate, heater box temperature and excess oxygen concentration) at which the NO X emission level was established.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 227 of 293 (ii) If the request is approved by the Administrator, a facility-specific NO X emissions limit will be established at the

NO X 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 228 of 293 (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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 229 of 293 (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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 230 of 293 (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, H 2 S 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, H 2 S, 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,***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 231 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 232 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 233 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 234 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 235 of 293 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 SO 2 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 (m 3 ) (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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 236 of 293 (2) For a fuel gas combustion device, each exceedance of an applicable short-term emissions limit in §60.102a(g)(1) if the

SO 2 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 SO 2 emissions are more than 227 kg (500 lb) greater than the amount that would

have been emitted if the SO 2 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 237 of 293 (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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 238 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 239 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 240 of 293 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 H 2 S 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 241 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 242 of 293 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**

.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 243 of 293 (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.*****E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 244 of 293 (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 (E PM ) 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; c s = Concentration of total PM, grams per dry standard cubic meter (g/dscm) (gr/dscf); Q sd = Volumetric flow rate of effluent gas, dry standard cubic meters per hour (dry standard cubic feet per hour); R c = Coke burn-off rate, kilograms per hour (kg/hr) [lb per hour (lb/hr)] coke; and c sd s 

## R K Q c E 

c sd s 

## R K Q c E  Deleted: c sd s 

## R K Q c E 

c sd s 

## R K Q c E 

Formatted: Lowered by 15 pt***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 245 of 293 K = Conversion factor, 1.0 grams per gram (7,000 grains per lb).

(iii) The coke burn-off rate (R c ) is computed for each run using Equation 6 of this section:

(Eq. 6)

Where:

R c = Coke burn-off rate, kg/hr (lb/hr); Q r = 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)]; Q a = 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); Q oxy = Volumetric flow rate of O 2 enriched air to FCCU regenerator or fluid coking unit, as determined from the unit’s control room instrumentation, dscm/min (dscf/min); %CO 2 = Carbon dioxide (CO 2 ) 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); %O 2 = O 2 concentration in FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis); %O oxy = O 2 concentration in O 2 enriched air stream inlet to the FCCU regenerator or fluid coking burner, percent by volume (dry basis); K 1 = Material balance and conversion factor, 0.2982 (kgmin)/(hr-dscm-%) [0.0186 (lb-min)/(hr-dscf-%)]; K 2 = Material balance and conversion factor, 2.088 (kgmin)/(hr-dscm) [0.1303 (lb-min)/(hr-dscf)]; and K 3 = Material balance and conversion factor, 0.0994 (kgmin)/(hr-dscm-%) [0.00624 (lb-min)/(hr-dscf-%)].



#   

#     oxy oxy r a r c 

## O Q K O CO CO Q K Q K CO CO Q K R % % % 2 % % % 3 2 2 3 2 2 1 

##   

    

#   

#     oxy oxy r a r c 

## O Q K O CO CO Q K Q K CO CO Q K R % % % 2 % % % 3 2 2 3 2 2 1 

##   

    Deleted: 

# 

r c 

## C O CO Q K R % % 2 1 

##   

#  

r c 

## K CO CO Q K R % % 2 2 1 

##   ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 246 of 293 * * * * * (v) For subsequent calculations of coke burn-off rates or exhaust gas flow rates, the volumetric flow rate of Q r 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: Q r = 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); Q a = 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); Q oxy = Volumetric flow rate of O 2 enriched air to FCCU regenerator or fluid coking unit, as determined from the unit’s control room instrumentation, dscm/min (dscf/min); %CO 2 = 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; %O 2 = O 2 concentration in FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis); and %O oxy = O 2 concentration in O 2 enriched air stream inlet to the FCCU regenerator or fluid coking burner, percent by volume (dry basis).

* * * * * 

##  

2 2 

### % % % 100 % 100 79 O CO CO Q Oxy Q Q oxy a r



###    

  

 

##  

2 2 

### % % % 100 % 100 79 O CO CO Q Oxy Q Q oxy a r



###    

  

 Deleted: 

## 

2 

### % % 100 % 100 79 C O CO Ox Q Q a

r



###     

 

##  

2 

### % % % 100 % 100 79 O CO CO Q Oxy Q Q o a r



###    

  



Formatted: Lowered by 15 pt***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 247 of 293 (8) The owner or operator shall adjust PM, NO X , SO 2 and CO pollutant concentrations to 0-percent excess air or 0-percent O 2 using Equation 8 of this section:

(Eq. 8)

Where:

C adj = pollutant concentration adjusted to 0-percent excess air or O 2 , parts per million (ppm) or g/dscm; C meas = pollutant concentration measured on a dry basis, ppm or g/dscm; 20.9 c = 20.9 percent O 2 − 0.0 percent O 2 (defined O 2 correction basis), percent; 20.9 = O 2 concentration in air, percent; and %O 2 = O 2 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; Opacity st = Hourly average opacity measured during the source test, percent; and PMEmR st = PM emission rate measured during the source test, lb/1,000 lb coke burn.

* * * * * 

##        

  2 % 9

. 20 9

. 20 O C C c meas adj 

##        

  2 % 9

. 20 9

. 20 O C C c meas adj

       

 st st PMEmR

x Opacity Limit Opacity burn coke lb 000 , 1 / lb 1

       

 st st PMEmR

x Opacity Limit Opacity burn coke lb 000 , 1 / lb 1 Deleted: 

##    

  % 9

. 20 9

. 20 C C c meas adj 

##        

  2 % 9

. 20 9

. 20 O C C c meas adj

Formatted: Lowered by 13 pt

Deleted:  st x Opacity Limit Opacity    

 st x

Opacity Limit Opacity 1 / lb 1

Formatted: Lowered by 16 pt***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 248 of 293 (h) * * * (5) * * * (iv) The owner or operator shall use Equation 8 of this section to adjust pollutant concentrations to 0-percent O 2 or 0- percent excess air. (i) The owner or operator shall determine compliance with

the SO 2 and NO X 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 O 2 operating limit or O 2 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 O 2 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 249 of 293 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 NO X concentration for the performance test as the average of

the NO X concentrations from each of the three test runs. If the

NO X concentration for the performance test is less than or equal to the numerical value of the applicable NO X emissions limit (regardless of averaging time), then the test is considered to

be a valid test. (C) Determine the average O 2 concentration for each test run

of a valid test. (D) Calculate the O 2 operating limit as the average O 2 concentration of the three test runs from a valid test. (ii) If an O 2 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 O 2 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 250 of 293 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 NO X concentration for the performance test as the average of

the NO X concentrations from each of the three test runs. If the

NO X concentration for the performance test is less than or equal to the numerical value of the applicable NO X 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 O 2 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 O 2 concentration for each test run

of a valid test.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 251 of 293 (E) Calculate the O 2 operating limit for each operating range as the average O 2 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 O 2 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 O 2 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 NO X 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 252 of 293 between 40 and 100 MMBtu/hr that elects to demonstrate continuous compliance with a maximum excess O 2 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 O 2 or 0- percent excess air. (j) The owner or operator shall determine compliance with the applicable H 2 S 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 H 2 S concentration for affected facilities using an H 2 S 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 253 of 293 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 254 of 293 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 CO 2 , O 2 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) * * ****E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 255 of 293 (5) All rolling 7-day periods during which the average

concentration of SO 2 as measured by the SO 2 CEMS under §60.105a(g) exceeds 50 ppmv, and all rolling 365-day periods during which the average concentration of SO 2 as measured by the

SO 2 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);***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 256 of 293 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 SO 2 or H 2 S limit and flares subject to H 2 S 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 SO 2 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 H 2 S concentration limits in §60.102a(g)(1)(ii) or a flare that is subject to the H 2 S 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 SO 2 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 SO 2 emissions into the atmosphere. The monitor must include an O 2 monitor for correcting the data for excess air.

* * * * ****E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 257 of 293 (2) The owner or operator of a fuel gas combustion device that elects to comply with the H 2 S concentration limits in §60.102a(g)(1)(ii) or a flare that is subject to the H 2 S 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 H 2 S 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 H 2 S monitor according to Performance Specification 7 of Appendix B to part 60. The span value for this instrument is 300 ppmv H 2 S.

* * * * * (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 H 2 S 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 H 2 S 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 258 of 293 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 H 2 S 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 H 2 S 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

H 2 S 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 259 of 293 (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 H 2 S 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 H 2 S 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 260 of 293 submit new information to support an exemption, the owner or operator must begin H 2 S 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 H 2 S 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 H 2 S 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 NO X concentrationbased limit . The owner or operator of a process heater subject

to the NO X 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 NO X 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 O 2 monitor for correcting the data for excess air.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 261 of 293 (1) Except as provided in paragraph (c)(6) of this section, the owner or operator shall install, operate and maintain each

NO X monitor according to Performance Specification 2 of Appendix B to part 60. The span value of this NO X 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 NO X emissions (i.e. , low-NO X burners, ultra-low-NO X 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 O 2 operating limit or operating curve according to the requirements in §60.104a(i)(6) and comply with

the O 2 monitoring requirements in paragraphs (c)(3) through (5) of this section to demonstrate compliance. If an O 2 operating curve is used (i.e. , if different O 2 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.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 262 of 293 (d) Process heaters complying with the NO X heating valuebased or mass-based limit . The owner or operator of a process heater subject to the NO X 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 NO X 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 NO X 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 NO X 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 263 of 293 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

NO X monitor according to the requirements in paragraphs (c)(1) through (5) of this section. The monitor must include an O 2 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 264 of 293 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:

F d = F factor on dry basis at 0-percent excess air, dscf/MMBtu. X i = mole or volume fraction of each component in the fuel gas. MEV i = molar exhaust volume, dry standard cubic feet per mole (dscf/mol). MHC i = 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); 

#     

#  

  

 i i i i d 

## MHC X MEV X F 000 , 000 , 1 

#     

#  

  

 i i i i d 

## MHC X MEV X F 000 , 000 , 1

Deleted: 

#   

#  

 

 i d 

## MH X X F 000 , 000 , 1 

#    

#  

  

 i i i d 

## MHC X M X F 000 , 000 , 1

Formatted: Lowered by 16 pt***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 265 of 293 (iii) ASTM D1946–90 (Reapproved 2006), Standard Method for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference-see §60.17); (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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 266 of 293 flow monitor according to the requirements in §60.13 and Performance Specification 6 of Appendix B to part 60. Any of the 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 PipesUsing 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 UsingSmall Bore Precision Orifice Meters (incorporated by referencesee §60.17);***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 267 of 293 (viii) ASME MFC-18M-2001, Measurement of Fluid Flow Using Variable Area Meters (incorporated by reference-see §60.17); (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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 268 of 293 according to the requirements in §60.13 and Performance Specification 6 of Appendix B to part 60. Any of the following 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)***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 269 of 293 through (ix) of this section. If a common fuel supply system provides fuel gas or fuel oil to several process heaters, the 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).***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 270 of 293 (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). (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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 271 of 293 (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 NO X emissions (i.e. , low-NO X burners or ultra-low NO X burners) may 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 O 2 operating limit or operating curve according to the requirements in §60.104a(i)(6) and comply with

the O 2 monitoring requirements in paragraphs (c)(3) through (5) of this section to demonstrate compliance. If an O 2 operating curve is used (i.e. , if different O 2 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 272 of 293 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 (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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 273 of 293 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 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 274 of 293 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. (2) H 2 S monitoring requirements . The owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration of H 2 S 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 H 2 S 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 H 2 S 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 275 of 293 (ii) The owner or operator shall conduct performance

evaluations of each H 2 S 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 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 H 2 S 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,***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 276 of 293 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. (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-H 2 S ratio and 95-percent confidence interval as

follows: (A) Calculate the ratio of the total sulfur concentration

to the H 2 S concentration for each day during which samples are

collected. (B) Determine the 10-day average total sulfur-to-H 2 S ratio as the arithmetic average of the daily ratios calculated in paragraph (e)(2)(vi)(A) of this section.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 277 of 293 (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. (Eq. 11)

Where: AR = Acceptable range of subsequent ratio determinations, unitless. Ratio Avg = 10-day average total sulfur-to-H 2 S 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-H 2 S concentration ratios used to develop the 10-day average total sulfur-to-H 2 S 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-H 2 S ratio by the daily average H 2 S concentrations obtained using the monitor as required by paragraph (e)(2)(i) through (iii) of this section to estimate total sulfur

concentrations. 

### SDev Ratio AR Avg 

###    262

. 2 

### SDev Ratio AR Avg 

###    262

. 2 Deleted: 

### Ratio AR Avg 

###    262

. 2 

### SDev Ratio AR Avg 

###    262

. 2

Formatted: Lowered by 7 pt***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 278 of 293 (ix) If the total sulfur-to-H 2 S 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 data for the outlying weekly sample plus data collected over the following 9 operating days. (3) SO 2 monitoring requirements . The owner or operator shall install, operate, calibrate and maintain an instrument for continuously monitoring and recording the concentration of SO 2 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 SO 2 ) in the fuel gas using Equation 12 of this

section. (Eq. 12)

Where:

TS FG = Total sulfur concentration, as SO 2 , in the fuel gas, ppmv. C SO2 = Concentration of SO 2 in the exhaust gas, ppmv (dry basis at 0-percent excess air). FG d SO FG 

### HHV F C TS    2 FG d SO FG 

### HHV F C TS    2 Deleted: F d SO FG 

### HH V F C TS    2 FG d SO FG 

### HHV F C TS    2 Formatted: Lowered by 7 pt***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 279 of 293

F d = F factor gas on dry basis at 0-percent excess air, dscf/MMBtu. HHV FG = 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 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 SO 2 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 H 2 S 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 280 of 293 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 primary flare should be used to calculate SO 2 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 281 of 293 (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. (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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 282 of 293 (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 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 283 of 293 (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. (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,***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 284 of 293 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 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) SO 2 or H 2 S limits for fuel gas combustion devices

. (i) If the owner or operator of a fuel gas combustion device elects to comply with the SO 2 emission limits in §60.102a(g)(1)(i), each rolling 3-hour period during which the average concentration of SO 2 as measured by the SO 2 continuous***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 285 of 293 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 SO 2 as measured by the SO 2 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 H 2 S concentration limits in §60.102a(g)(1)(ii), each rolling 3-hour period during which the average concentration of H 2 S as measured by the H 2 S 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 H 2 S 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 H 2 S exceeds 162 ppmv and each rolling 365-day period during which the average

concentration of H 2 S exceeds 60 ppmv. (2) H 2 S concentration limits for flares . (i) Each rolling 3- hour period during which the average concentration of H 2 S as measured by the H 2 S continuous monitoring system required under paragraph (a)(2) of this section exceeds 162 ppmv.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 286 of 293 (ii) If the owner or operator of a flare 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 H 2 S exceeds 162 ppmv. (3) Rolling 30-day average NO X limits for fuel gas

combustion devices . Each rolling 30-day period during which the average concentration of NO X as measured by the NO X 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 NO X 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 NO X limits for fuel gas combustion devices . Each day during which the concentration of NO X as measured by the NO X 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).***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 287 of 293 (5) Daily O 2 limits for fuel gas combustion devices . Each day during which the concentration of O 2 as measured by the O 2 continuous monitoring system required under paragraph (c)(6) of

this section exceeds the O 2 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 288 of 293 Notifications required by this paragraph shall be submitted with the notification of initial startup required by §60.7(a)(3). (c) * * * (1) A copy of the flare management plan.

* * * * * (6) Records of discharges greater than 500 lb SO 2 in any 24- hour period from any affected flare, discharges greater than 500

lb SO 2 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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 289 of 293 each 24-hour period. For a flare, record the measured or calculated cumulative quantity of gas discharged to the flare 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 SO 2 in any 24- hour period from a flare, the measured total sulfur

concentration or both the measured H 2 S 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 SO 2 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 H 2 S in the fuel gas or the measured concentration of SO 2 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 SO 2 in excess of the allowable limits from a sulfur recovery plant, either the***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 290 of 293 measured concentration of reduced sulfur or SO 2 discharged to the atmosphere. (vii) For each discharge greater than 500 lb SO 2 in any 24- hour period from any affected flare or discharge greater than

500 lb SO 2 in excess of the allowable limits from a fuel gas combustion device or sulfur recovery plant, the cumulative quantity of H 2 S and SO 2 released into the atmosphere. For releases controlled by flares, assume 99-percent conversion of

reduced sulfur or total sulfur to SO 2 . For fuel gas combustion devices, assume 99-percent conversion of H 2 S to SO 2 . (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***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 291 of 293 completed, a schedule for implementation, including proposed commencement and completion dates. (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 H 2 S and total sulfur analyses of each grab or integrated sample, the calculated daily

total sulfur-to-H 2 S ratios, the calculated 10-day average total

sulfur-to-H 2 S ratios and the 95-percent confidence intervals for each 10-day average total sulfur-to-H 2 S 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 292 of 293 * * * * * 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 MEV a dscf/mol MHC b Btu/mol Methane (CH 4 ) 7.29 842 Ethane (C 2 H 6 ) 12.96 1,475 Hydrogen (H 2 ) 1.61 269 Ethene (C 2 H 4 ) 11.34 1,335 Propane (C 3 H 8 ) 18.62 2,100 Propene (C 3 H 6 ) 17.02 1,947 Butane (C 4 H 10 ) 24.30 2,717 Butene (C 4 H 8 ) 22.69 2,558 Inerts 0.85 0***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** Page 293 of 293

a MEV = molar exhaust volume, dry standard cubic feet per grammole (dscf/g-mol) at standard conditions of 68° Farhenheit and 1 atmosphere

b MHC = molar heat content (higher heating value basis), Btu per gram-mole (Btu/g-mol)

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***



## 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 3 of 293 (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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## 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 Code 1 

## 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 6 of 293 307(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.

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 7 of 293 **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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## Page 8 of 293 Forced

Draft

Process

Heaters NOx Emission

Limits 40 ppmv 60 ppmv or 0.06 lb/MM

BTU

Forced

Draft

Process

Heaterswith Cofired (oil and gas)

Burners NOx Emission

Limits 40 ppmv 150 ppmv or Weighted average based on oil

a t 0.40 lb/MM BTU and gas at 0.11 lb/MM BTU

Natural

Draft

Process

Heaterswith 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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## Page 9 of 293 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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## Page 10 of 293 within 1 yearsFlares 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

o r 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

i ntermittent/emergency only f lares 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-

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 11 of 293 based NO X 

## emissions limits and alternative heating value-based

NO X 

## emissions limits, both determined daily on a 30-day rolling average basis. These final amendments establish limits of 40 ppmv NO x 

## (or 0.04 lb/mmBTU) and 60 ppmv NO x 

## (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

NO x 

## 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 NO X 

## 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 NO x 

## 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 SO 2 

## (expressed as a 162 ppmv short-term H 2 

## S 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 H 2 

## S fuel gas concentration limit. As explained in section IV

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## Page 12 of 293 of this preamble, we determined that requiring refineries to ensure the fuel gas they send to their flares meets a long-term

H 2 

## S 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 SO 2 

## in a 24-hour period; and (3) optimize management of the fuel gas by limiting the short-term

concentration of H 2 

## S 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 13 of 293 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 SO 2 

## 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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## Page 14 of 293 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 15 of 293 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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## Page 16 of 293 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. We estimate that the final requirements for flares will

reduce emissions of SO 2 

## by 3,200 tons per year (tons/yr), NO X 

## 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 CO 2 

## 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

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## Page 17 of 293 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 ($1,000/ yr) Annual emission r eductions (tons SO 2 /yr) Annual emission r eductions (tons NO X /yr) Annual emission reductions (tons VOC/yr) Costeffectiveness ($/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

SO 2 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)

Subtotal 1 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

SO 2 RCA/CA 0 220 0 220 290 0 0 760

Flowrate

RCA/CA 0 100 (740) (640) 0.4 6 43 (13,000)

Subtotal 1 390,000 81,000 (170,000) (88,000) 660 1,100 2,800 (20,000)

Total 1 460,000 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. 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.

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## Page 18 of 293

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 SO 2 

## 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, such as the long-term H 2 

## S limit for flares, these are impacts did

not result in emission reductions and were not monetized. **B. Background of the Refinery NSPS**

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 19 of 293 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. 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

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## Page 20 of 293 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, 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 21 of 293 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 (NO X 

## ) 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 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

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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## Page 22 of 293 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. 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

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## Page 23 of 293 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 NO x 

## 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 NO x 

## at proposal to 60 ppmv NO x 

## . 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 NO x 

## concentration limit (i.e., 0.04 lb/mmBTU for natural draft and 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

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## Page 24 of 293 also finalizing an alternative case-specific compliance option that allows owners and operators to obtain EPA approval for a site-specific NO X 

## 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 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**

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## Page 25 of 293 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 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

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## Page 26 of 293 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 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)?

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 27 of 293 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-firedprocess heaters, we divided natural draft and forced draft cofired process heaters into separate subcategories with different

emissions limits. For each of the first two subcategories, the final

amendments include a concentration-based NO X 

## emissions limit and a heating value-based NO X 

## emissions limit, both determined daily

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## Page 28 of 293 on a 30-day rolling average basis. For the natural draft process heater subcategory, the concentration-based NO X 

## 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 NO X 

## 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 NO X 

## emissions limit differs from the proposed limit in that it is a more direct numerical conversion from 40 ppmv NO X 

## . 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 NO X 

## emissions 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 NO x 

## burners meet the emission limits described above if compliance is determined on a 30-day rolling average

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## Page 29 of 293 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 NO X 

## 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 NO X 

## 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 NO X 

## emissions limit is a more direct numerical conversion from 60 ppmv NO X 

## . 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 NO X 

## emissions limit or the

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## Page 30 of 293 heating value-based NO X 

## 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 NO X 

## emissions limit. If the refinery owner or operator does not choose to monitor fuel composition, then they must comply with the concentration-based

NO X 

## 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 NO x 

## Emission Limits 40 ppmv or 0.035 lb/MM BTU 40 ppmv or 0.04 lb/MM BTU

Forced Draft NO x 

## 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

Co-fired Burner (oil and gas) NO x 

## 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

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## Page 31 of 293

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 NO X 

## emission rate is calculated using the oxygen (O 2 

## )-based F factor, dry basis according to EPA Method 19 of 40 CFR part 60, appendix A-7. Ongoing compliance with this NO X 

## emissions limit is determined using a NO X 

## 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 section IV.A of this preamble, co-fired process heaters do notinclude 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

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## Page 32 of 293 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 NO X 

## limit for certain process heaters. This 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

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## Page 33 of 293 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 NO X 

## burners or otherwise meet the applicable limit and some co-fired units may not be able to

achieve the NO X 

## limitations even with ultra-low NO X 

## burner control technology. In addition, commenters noted that downwardly fired process heaters with induced draft fans have

similar NO X 

## 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 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 NO X 

## burner control technologies. The

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## Page 34 of 293 ultra-low NO X 

## 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 NO X 

## concentrations at low firing rates. Therefore, all types of process heaters with ultra-low NO X 

## 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 NO X 

## burner technology is not feasible or that the technology cannot meet

the NO X 

## 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 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-NO X 

## burners or ultra-low NO X

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 35 of 293 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 O 2 

## operating limit, including provisions on how to develop an O 2 

## operating curve to ensure compliance with the NO X 

## 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 O 2 

## concentration operating limit or operating curve that can be met at all times, even during turndown, and comply with the O 2 

## 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 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

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## Page 36 of 293 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”). 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

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## Page 37 of 293 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 (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

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## Page 38 of 293 limit the long-term concentration of hydrogen sulfide (H 2 

## S) to 60 ppmv (determined daily on a 365 successive calendar day rolling average basis) (hereafter referred to as the long-term 60 ppmv

H 2 

## S 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 H 2 

## S 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 H 2 

## S 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 (SO 2 

## ) 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 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

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## Page 39 of 293 cause analyses and take corrective action when the emissions

from the flare exceed 500 lb of SO 2 

## in a 24-hour period (instead

of 500 lb SO 2 

## above the emissions limit); and (4) optimize management of the fuel gas by limiting the short-term

concentration of H 2 

## S 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 SO 2 

## (expressed as a 162 ppmv short-term H 2 

## S 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 SO 2 

## are created in the flame that burns outside the flare tip. Therefore, we have determined that this suite of work practice standards, which includes optimization of fuel gas management (based on limiting

concentration of H 2 

## S to 160 ppmv) is more appropriate for flares, as opposed to the H 2 

## S 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.

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## Page 40 of 293 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 SO 2 

## 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 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 SO 2 

## or flow rate root

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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## Page 41 of 293 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 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.

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## Page 42 of 293 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 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

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## Page 43 of 293 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 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

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## Page 44 of 293 requirements for these monitors and are allowing the use of cylinder gas audits for relative accuracy assessments. We are finalizing the H 2 

## S 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 SO 2 

## 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

SO 2 

## 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 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

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## Page 45 of 293 triggered by an exceedance of the flow rate threshold long before they exceed the 500 lb SO 2 

## 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 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.

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## Page 46 of 293 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 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

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## Page 47 of 293 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 SO 2 

## emissions. In addition, if flow 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

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## Page 48 of 293 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” that will achieve a reduction in emissions at least equivalent to the reduction in emissions achieved under any of the final

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## Page 49 of 293 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 SO 2 

## above the emission limit, but the proposed amendments directed the owner or operator to compare the SO 2 

## 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 SO 2 

## 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 finalizing an amendment that states that the threshold for a root cause analysis and corrective action analysis for both

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## Page 50 of 293 sulfur recovery plants and fuel gas combustion devices is 500 lb above the emission limit during one or more consecutive periods

of excess emissions 4 

## 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 corrective action analysis requirements already described. We are also finalizing 40 CFR 60.108a(c), as proposed, to add

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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## Page 51 of 293 recordkeeping requirements for the proposed monitoring option that is based on periodic manual sampling and analysis to

determine the total sulfur-to-H 2 

## S 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 equipment are integral to the operation of a delayed coking unit. Therefore, we are revising the definition of “delayed

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## Page 52 of 293 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

a revision to the definition of “flare” to refer to the “flare gas header system” rather than repeat the components of the

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## Page 53 of 293 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 shale or tar sands-derived crude oil for further processing using only solvent extraction and/or distillation to recover

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## Page 54 of 293 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 petroleum refinery are producing refinery fuel gases. We also proposed to amend the definition to state that gas generated by

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## Page 55 of 293 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 “H 2 

## S.” 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 loading facilities downstream of the sulfur pits are not part of

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## Page 56 of 293 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 (HS 2 

## ), each calculated as ppm SO 2 

## by volume (dry basis) at zero percent excess air” with “300 ppmv of reduced sulfur compounds and 10 ppmv of H 2 

## S, each calculated as ppmv SO 2 

## (dry basis) at 0- p ercent 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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## Page 57 of 293 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 f o r 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 “Opacity st 

## ” 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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## Page 58 of 293 60.107a(a)(2)(i) Replace “320 ppmv H 2 

## S” with “300 ppmv H 2 

## S” to make the span value for a H 2 

## S 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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## Page 59 of 293 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 NO X 

## , 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 NO X 

## ). 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) NO X 

## 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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## Page 60 of 293 air preheat. Actual NO X 

## 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 NO X 

## 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 NO X 

## 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 NO X 

## . Consequently, we are raising the NO X 

## 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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## Page 61 of 293 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 NO X 

## 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 NO X 

## 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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## Page 62 of 293 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 NO X 

## 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,

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 63 of 293 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 NO X 

## limit. The heating value-based NO X 

## emission rate is calculated using the oxygen (O 2 

## )-based F factor, which is the ratio of combustion gas volume to heat input. Ongoing compliance with

this NO X 

## emissions limit is determined using a NO X 

## 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 NO X 

## concentration (ppmv, dry basis, corrected to 0-percent excess air) and a 30-day rolling average NO X 

## 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 NO X 

## concentration above the 60 ppmv limit, but below the 0.060

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 64 of 293 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 NO X 

## concentrations will likely be above the emissions limits, but the mass of NO X 

## emissions is no greater

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## Page 65 of 293 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 O 2 

## levels during turndown and requested that the proposed

maximum O 2 

## 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 longeraveraging 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 66 of 293 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

NO X 

## 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 NO X 

## 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 NO X 

## concentrations of process heaters using ultra-low NO X 

## 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 O 2 

## concentrations at normal conditions (i.e. , at exhaust O 2 

## 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 O 2 

## concentrations for these units during normal (i.e. , nonturndown) firing rates. That is, these process heaters were not being operated optimally for reducing NO X 

## emissions. Furthermore,

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 67 of 293 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 O 2 

## concentrations for reducing NO X 

## 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 NO X 

## burners that operated at excess O 2 

## concentrations less than 6 percent (i.e. , operated in a manner consistent with proper low NO X 

## burner operation), all such process heaters could comply with the final NO X 

## 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.

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 68 of 293 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 O 2 

## concentrations increase at lower firing rates; and (2)

exhaust NO X 

## concentrations (corrected to 0-percent excess O 2 

## ) increase with increasing O 2 

## concentration (regardless of firing rates). These data, along with the need to operate the process heater at higher O 2 

## concentrations during low firing rates to maintain flame stability, suggest that an alternative NO X 

## 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 NO X 

## emissions limit that would be equivalent to the mass of NO X 

## 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 theprocess heaters were able to meet the applicable concentrationbased emissions limit (40/60 ppmv) or the heating value-based

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## Page 69 of 293 (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 O 2 

## 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 O 2 

## 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 O 2 

## concentration at which flame stability is achieved while minimizing NO X 

## formation. That is, even when a process heater is operating at less than 50 percent design capacity, excess O 2 

## concentrations should still be controlled to

minimize NO X 

## 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 O 2 

## concentrations cannot meet the emissions

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## Page 70 of 293 limits. However, we acknowledge that the correlations with firing rates and O 2 

## and/or NO X 

## concentrations and the need for higher O 2 

## 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 O 2 

## 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 foran 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 NO X 

## CEMS, turndown is also expected to be

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## Page 71 of 293 an issue with respect to achieving the O 2 

## operating limit. As described above, higher O 2 

## concentrations are generally needed to maintain flame stability at low firing rates. To address potential turndown compliance issues with the O 2 

## operating limit, we have provided an allowance for process heater owners or operators to develop an O 2 

## operating curve to provide different

O 2 

## operating limits based on the firing rate of the process heater. If a single O 2 

## 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 O 2 

## to maintain flame stability, a separate O 2 

## 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 O 2 

## 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 72 of 293 emission rate should be extended to 365 days. One commenter

noted that the notation “E NOx,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 NO X 

## 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 73 of 293 burner emissions test data provided by another commenter 5 

## (conducted under well-controlled conditions using best available

ultra-low NO X 

## 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 NO X 

## emissions limits for co-fired process heaters to those described above. We

note that we have revised the concentration-based NO X 

## 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.

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 74 of 293 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 O 2 

## 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-NO X 

## burner technologies exist, are demonstrated and are cost effective forco-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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## Page 75 of 293 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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## Page 76 of 293 from a process unit to the flare. Other commenters suggested that the flare modification provision should be focused on volatile organic compounds (VOC) and SO 2 

## 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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## Page 77 of 293 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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## Page 78 of 293 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 SO 2 

## . Flares are known to emit VOC, SO 2 

## , carbon monoxide (CO), PM and NO X 

## , 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, SO 2 

## , CO, PM and NO X 

## . 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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## Page 79 of 293 control VOC emissions at other refinery process units will increase CO, PM and NO X 

## 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 SO 2 

## , VOC, CO, NO X 

## 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 SO 2 

## , VOC, CO, PM,

NO X 

## 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;

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 80 of 293 (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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 81 of 293 (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 SO 2 

## . 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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## Page 82 of 293 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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## Page 83 of 293 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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## Page 84 of 293 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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## Page 85 of 293 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 NO X 

## ) 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, SO 2 

## , CO, PM and NO X 

## . 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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## Page 86 of 293 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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## Page 87 of 293 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 H 2 

## S. We reiterate that SO 2 

## 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 SO 2 

## 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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## Page 88 of 293 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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## Page 89 of 293 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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## Page 90 of 293 (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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## Page 91 of 293 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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## Page 92 of 293 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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## Page 93 of 293 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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## Page 94 of 293 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 areeffectively 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 NO X 

## 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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## Page 95 of 293 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 flares 6 

## from

the H 2 

## S 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 H 2 

## S concentration limits in 40 CFR 60.102a(g)(1).

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## Page 96 of 293 The commenter asserted that the CAA also requires that a section 111-compliant standard that reflects BSER 7 

## 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 H 2 

## S concentration limits during startup and shutdown events. The commenter also stated that the EPA, at a minimum, must demonstrate how the exemption from the H 2 

## S 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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## Page 97 of 293 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 H 2 

## S 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 H 2 

## S 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 H 2 

## S 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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## Page 98 of 293 “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 H 2 

## S concentration limits during SSM events.

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## Page 99 of 293 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 H 2 

## S 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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## Page 100 of 293 their variability.” Therefore, for all of the above reasons, the commenter asserted that exempting a flare from the H 2 

## S 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 H 2 

## S 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 SO 2 

## 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

SO 2 

## emissions exceed 500 lb in a 24-hour period; and (4) optimize management of the fuel gas by limiting the short-term

concentration of H 2 

## S 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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## Page 101 of 293 111-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 SO 2 

## , are not created until combustion occurs, which happens in the flame that burns outside of the flare tip. In other words, the SO 2 

## , NO X 

## , 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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## Page 102 of 293 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 SO 2 

## (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 SO 2 

## emissions for fuel gas combustion devices which also applied to flares. 39 FR 9308, 9315 (March 8, 1974). The standard is expressed as an H 2 

## S concentration limit because it was developed as an alternative to measuring the SO 2 

## 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 H 2 

## S in the fuel gas combusted in those devices is directly indicative of the SO 2 

## 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 SO 2 

## emissions, expressed as an H 2 

## S concentration limit or a total sulfur limit at the inlet to the flare. However, as explained

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## Page 103 of 293 above, flares are substantially different from other fuel gas combustion devices so that this approach is not workable for flares. For example, SO 2 

## 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 SO 2 

## . Since so many factors affect the potential formation of SO 2 

## emissions outside the flare tip, we realized that we could not properly derive an

H 2 

## S concentration limit or a total sulfur limit at the flare inlet that would directly correlate with those SO 2 

## emissions. Thus, we determined that we cannot set a standard of performance

for SO 2 

## emissions at the flare. However, we still recognize that reducing the amount of

sulfur that is sent to a flare will reduce the SO 2 

## 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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## Page 104 of 293 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 SO 2 

## emissions. Rather than

eliminate the H 2 

## S concentration limit altogether, we are instead requiring under CAA section 111(h) that refineries limit the

short-term concentration of H 2 

## S 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 H 2 

## S 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 H 2 

## S concentration limit during periods when high fuel gas flows would likely overwhelm these flare gas recovery systems would

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## Page 105 of 293 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 H 2 

## S 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 SO 2 

## 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 SO 2 

## emission limits for flares

have been established under state law and in FederalImplementation 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 SO 2 

## FIP for the Billings/Laurel Montana area includes a SO 2 

## emission limit of

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## Page 106 of 293 150 lb of SO 2 

## 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 SO 2 

## 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 SO 2 

## /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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## Page 107 of 293 flare is converted to SO 2 

## , 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 SO 2 

## at the flare tip and how these factors affect how much of the sulfur in the gases sent into the flare actually converts to SO 2 

## . Therefore, although setting such source-specific limits was appropriate to satisfy what the modeling showed was necessary to meet the SO 2 

## 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 H 2 

## S 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 H 2 

## S as a baseline because many refinery streams currently sent to the

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## Page 108 of 293 flare contain H 2 

## S concentrations below 162 ppmv, so 162 ppmv H 2 

## S 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 SO 2 

## emissions estimates. One commenter stated that the long-term 60 ppmv H 2 

## S 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 H 2 

## S 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 H 2 

## S 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 109 of 293 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 H 2 

## S 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 H 2 

## S 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

H 2 

## S concentration to 60 ppmv in addition to the short-term H 2 

## S concentration of 162 ppmv during normal operating conditions. We determined that, for refineries to demonstrate that their fuel gas complies with a long-term H 2 

## S 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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## Page 110 of 293 the long-term concentration of H 2 

## S 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 H 2 

## S 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 H 2 

## S concentration to a combined short-term 162 ppmv H 2 

## S concentration and long-term 60 ppmv H 2 

## S concentration. While we are aware that some consent decrees require refineries to limit the

concentration of H 2 

## S in the fuel gas to levels lower than the short-term 162 ppmv H 2 

## S 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 H 2 

## S concentration limit in 40 CFR part 60, subpart J).

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## Page 111 of 293 Table 2. National Fifth Year Impacts of Meeting a Long-Term 60 ppmv H 2 

## S Concentration for Flares Subject to 40 CFR Part 60, Subpart Ja

Capital cost ($1,000) Total annual cost ($1,000/yr)a Emission reduction (tons SO 2 /yr) b Emission reduction (tons NO X /yr) b Emission reduction (tons VOC/yr) b Costeffectiveness ($/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 H 2 S 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 H 2 S concentration in the fuel gas to 162 ppmv to the originally proposed combined short-term 162 ppmv H 2 S concentration and long-term 60 ppmv H 2 S 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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## Page 112 of 293 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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## Page 113 of 293 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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## Page 114 of 293 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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## Page 115 of 293 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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## Page 116 of 293 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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## Page 117 of 293 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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## Page 118 of 293 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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## Page 119 of 293 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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## Page 120 of 293 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 rootcause 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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## Page 121 of 293 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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## Page 122 of 293 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 scfd 10 

## 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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## Page 123 of 293 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

SO 2 

## 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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## Page 124 of 293 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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## Page 125 of 293 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 SO 2 

## in

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## Page 126 of 293 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 SO 2 

## 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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## Page 127 of 293 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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## Page 128 of 293 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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## Page 129 of 293 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 H 2 

## S concentration requirements and flares with properly designed flare gas recovery systems, commenters stated that engineering

calculations are sufficient to determine if the SO 2 

## 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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## Page 130 of 293 to submit and use an alternative monitoring plan to demonstrate that the flare gas recovery system is operating within its capacity and to calculate SO 2 

## 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-H 2 

## S 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 H 2 

## S 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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## Page 131 of 293 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 H 2 

## S monitoring due to low sulfur content are alsoexempt 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 SO 2 

## 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

H 2 

## S 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 H 2 

## S monitoring at a central location is allowed for flares as well). Thus, we agree that if

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## Page 132 of 293 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 H 2 

## S 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 SO 2 

## 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-H 2 

## S 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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## Page 133 of 293 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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## Page 134 of 293 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 135 of 293 flares are for total reduced sulfur or total sulfur. The commenter noted that measuring total sulfur is the simplest and

most inclusive measurement of SO 2 

## 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-H 2 

## S (or total reduced

sulfur-to-H 2 

## S) 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 H 2 

## S concentration in fuel gas sent to a flare to 162 ppmv without the need for a duplicative continuous H 2 

## S 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 SO 2 

## 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 136 of 293 to be in the form of total reduced sulfur compounds, which include carbon disulfide, carbonyl sulfide and H 2 

## S. 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 SO 2 

## emissions at the flare. These include optimizing management of the fuel gas by limiting the short-term concentration of H 2 

## S to 162 ppmv during normal operating conditions. We expected most refineries would already have the H 2 

## S monitor and did not consider the useof a total sulfur monitor for use in complying with the shortterm 162 ppmv H 2 

## S concentration in the fuel gas. As the H 2 

## S concentration will always be less than the total reduced sulfur concentration, it is acceptable to use the total reduced sulfurmonitor to verify that the fuel gas does not exceed the shortterm H 2 

## S 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 H 2 

## S. The owner or operator using this method must essentially be able to demonstrate they can achieve a 162 ppmv total reduced sulfur

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 137 of 293 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 H 2 

## S monitor was already in-place, as well as the expected accuracy needed for the system to assess the SO 2 

## root cause analysis threshold. As few cases would exist where the flaring event would be right at the SO 2 

## root cause analysis threshold of 500 lb in any 24-hour period, inaccuracies associated with the average total sulfur-to-H 2 

## S ratio were not expected to be significant. On the other hand, the short-term 162 ppmv H 2 

## S concentration in the fuel gas must be continuously maintained, and the total

sulfur-to-H 2 

## S 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 H 2 

## S, the non-H 2 

## S reduced sulfur concentration is expected to be fairly constant, with most of the fluctuations in total sulfur content being attributable to

fluctuations in H 2 

## S 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 H 2 

## S. Therefore, owners or operators of affected flares may use the

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## Page 138 of 293 direct output of a total reduced sulfur monitor to assess compliance with the short-term 162 ppmv H 2 

## S concentration in the fuel gas, or they must install a continuous H 2 

## S monitor.

Comment : One commenter supported the proposed amendment revising the span value for fuel gas H 2 

## S 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 H 2 

## S 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 H 2 

## S concentration limits and that engineering calculations can be used to assess

exceedances of the SO 2 

## root cause analysis threshold of 500 lb in any 24-hour period. Response : The H 2 

## S span value is at 300 ppmv to verify compliance with the H 2 

## S 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 H 2 

## S analyzers both to assess compliance with the short-term 162 ppmv H 2 

## S concentration requirement for the fuel gas and to

assess exceedances of the SO 2 

## root cause analysis threshold of

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 139 of 293 500 lb in any 24-hour period, a dual range monitor will be necessary. For the purposes of the SO 2 

## 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 H 2 

## S concentration requirement for the fuel gas and the SO 2 

## 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 H 2 

## S monitoring alternative, and the same span considerations apply for these monitors.

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 140 of 293 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 H 2 

## S concentration to 162 ppmv, long-term 60 ppmv H 2 

## S 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

H 2 

## S 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 141 of 293 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 142 of 293 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 H 2 

## S fuel gas concentration limit to flares, the comments related to the amount of time needed to comply with a long-term 60 ppmv H 2 

## S 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 H 2 

## S 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 H 2 

## S 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 143 of 293 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 H 2 

## S 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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## Page 144 of 293 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 H 2 

## S 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 145 of 293 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 146 of 293 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).

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 147 of 293 this paragraph. The final rule requires all new, modified and reconstructed flares to meet the short-term 162 ppmv H 2 

## S 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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## Page 148 of 293

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 unitdoes not limit process operations to distillation, redistillation, cracking or reforming, and it is not limited to

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 149 of 293 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 150 of 293 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 H 2 

## S 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 H 2 

## S 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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## Page 151 of 293 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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## Page 152 of 293 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 153 of 293 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 154 of 293 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 155 of 293 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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## Page 156 of 293

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 O 2 

## 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

H 2 

## S concentration limits (or alternative SO 2 

## 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 157 of 293 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 H 2 

## S 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 SO 2 

## emissions limits or the H 2 

## S 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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## Page 158 of 293 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 SO 2 

## emissions limits or the H 2 

## S 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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## Page 159 of 293 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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## Page 161 of 293 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 H 2 

## S 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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## Page 162 of 293 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 SO 2 

## by 3,200 tons per year (tons/yr), NO X 

## 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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## Page 163 of 293 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 SO 2 

## by 3,200 tons per year (tons/yr), NO X 

## 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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## Page 164 of 293 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 ($1,000/ yr) Annual emission r eductions (tons SO 2 /yr) Annual emission r eductions (tons NO X /yr) Annual emission reductions (tons VOC/yr) Costeffectiveness ($/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 CO 2 

## 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 NO X 

## burners). We did

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## Page 165 of 293 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 NO X 

## 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 NO X

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## Page 166 of 293 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 NO X 

## 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 NO X 

## 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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## Page 167 of 293 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 H 2 

## S 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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## Page 168 of 293 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 SO 2 

## , NOx and

VOC as well as CO 2 

## . SO 2 

## , NOx and VOC are precursors to PM 2.5 

## (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

PM 2.5 

## from emission reductions of SO 2 

## and NOx and the climate

benefits associated with CO 2 

## 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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## Page 169 of 293 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 PM 2.5 

## 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 SO 2 

## 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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## Page 170 of 293

Table 4. Summary of the Monetized PM 2.5 

## and CO 2 

## 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 PM 2.5 

## Benefits b 

## SO 2 

## 3,200 $210 to $510 $190 to $460 NO X 

## 1,100 $7.1 to $18 $6.4 to $16 PM Total: $220 to $530 $190 to $480 CO 2 

## Benefits c 

## 1,900,000 d 

## $46 $46 Total Monetized Benefits: $260 to $580 $240 to $520 Without Flare Gas Recovery PM 2.5 

## Benefits b 

## SO 2 

## 2,900 $190 to $450 $170 to $410 NO X 

## 56 $0.36 to $0.87 $0.32 to $0.78 PM Total: $190 to $460 $170 to $410 CO 2 

## Benefits c 

## 110,000 d 

## $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 PM 2.5 

## through reductions of PM 2.5 

## precursors, such as NO X 

## and SO 2 as well as CO2 

## . It is important to note that the monetized benefits do not include reduced health effects from direct exposure to SO 2 

## 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 CO 2 

## emission reductions (shown in metric tonnes) have been reduced to reflect the anticipated emission increases associated

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## Page 171 of 293 with the energy disbenefits. CO 2 

## -related benefits were calculated using the social cost of carbon (SCC), which is discussed further in the RIA. The net present value of reduced CO 2 

## 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 CO 2 

## benefits using discount rates of 5 percent (average), 2.5 percent (average), and 3 percent (95 th 

## percentile). d 

## Metric tonnes These benefits estimates represent the total monetized human health benefits for populations exposed to less PM 2.5 

## 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 PM 2.5 

## -related health impacts and monetized benefits based on changes in SO 2 

## 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 PM 2.5 

## precursors into changes in ambient PM 2.5 

## 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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## Page 172 of 293 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, theair 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 PM 2.5 

## precursors from the petroleum refineries sector

. EPA, Research Triangle Park, NC.

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## Page 173 of 293 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 SO 2 

## and NOx and multiply them by the corresponding emission reductions. The sector-specific modeling does not provide estimates of the PM 2.5 

## - related benefits associated with reducing VOC emissions, but these unquantified benefits are generally small compared to

other PM 2.5 

## 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 PM 2.5 

## precursors affected by this rule

are SO 2 

## and NO X 

## . 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 PM 2.5 

## levels, which drive population exposure. For example, SO 2 

## has a lower benefit-per-ton estimate than direct

PM 2.5 

## because it does not form as much PM 2.5 

## , thus, the exposure

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 174 of 293 would be lower, and the monetized health benefits would be

lower. It is important to note that the magnitude of the PM 2.5 

## 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 PM 2.5 

## concentrations and premature mortality. We cite two key empirical studies, one based on the American Cancer Society cohort study 15 

## 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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## Page 175 of 293 model for assessing the mortality benefits associated with reducing PM 2.5 

## 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 PM 2.5 

## . 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

PM 2.5 

## level. As a surrogate measure of mortality impacts, we provide the percentage of the population exposed at each PM 2.5 

## 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 PM 2.5 

## levels at or above the LML of 7.5 micrograms per cubic meter (μg/m 3 

## ). Using the Laden, et al. (2006) study, 25 percent of the population is exposed above the LML of 10 μg/m 3



## .

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## Page 176 of 293 It is important to emphasize that we have high confidence in

PM 2.5 

## -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 PM 2.5 

## , 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 PM 2.5 

## 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 PM 2.5 

## NAAQS benefits analysis 17 

## provides an indication of the sensitivity of

17 

## U.S. Environmental Protection Agency, 2006. Final Regulatory Impact Analysis: PM 2.5 

## NAAQS . Prepared by Office of Air and

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## Page 177 of 293 our results to various assumptions. This rule is expected to reduce CO 2 

## 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 CO 2 

## 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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## Page 178 of 293 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 CO 2 

## 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 95 th 

## 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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## Page 179 of 293 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 95 th 

## 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 SO 2 

## 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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## Page 180 of 293 such as the long-term H 2 

## S 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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## Page 181 of 293 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 Benefits b 

## $270 to $580 $240 to $530 Total Compliance Costs c 

## -$79 -$79 Net Benefits $340 to $660 $320 to $610 Non-Monetized Benefits Health effects from direct exposure to SO 2 

## and NO 2 

## Health effects from PM 2 .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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## Page 182 of 293 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 estimated affected flares 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 analyses,

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## Page 183 of 293 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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## Page 184 of 293 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 approvedannual 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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## Page 185 of 293 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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## Page 186 of 293 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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## Page 187 of 293 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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## Page 188 of 293 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 189 of 293 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 190 of 293 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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## Page 191 of 293 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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## Page 192 of 293 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 H 2 

## S: 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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## Page 193 of 293 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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## Page 194 of 293 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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## Page 195 of 293 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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## Page 196 of 293 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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## Page 198 of 293 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 Sources 1 

## * * * * * 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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## Page 199 of 293 **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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## Page 200 of 293 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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## Page 201 of 293 (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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## Page 202 of 293 (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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## Page 203 of 293 (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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## Page 204 of 293 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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## Page 205 of 293 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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## Page 206 of 293 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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## Page 207 of 293 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 (E s 

## ) of PM shall be computed for each run using the following equation:

E s 

## = F + A (H/R c 

## )

Where:

E s 

## = 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). R c 

## = 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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## Page 208 of 293 **§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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## Page 209 of 293 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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## Page 210 of 293 (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 “Airpreheat,” “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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## Page 211 of 293 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 loadingoperations, 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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## Page 212 of 293 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 213 of 293 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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## Page 214 of 293 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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## Page 215 of 293 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 216 of 293 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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## Page 217 of 293 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 H 2 

## S and/or SO 2 

## 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 218 of 293 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 219 of 293 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 H 2 

## S, each calculated as ppmv SO 2 

## (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 SO 2 

## in excess of 20 ppmv (dry basis, corrected to 0-percent excess air)

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## Page 220 of 293 determined hourly on a 3-hour rolling average basis and SO 2 

## 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 H 2 

## S in excess of 162 ppmv determined hourly on a 3-hour rolling average basis and H 2 

## S 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

NO X 

## 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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## Page 221 of 293 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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## Page 222 of 293 (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:

ER NOx 

## = Daily allowable average emission rate of NO X 

## , lb/MMBtu (higher heating value basis); Q gas 

## = Daily average volumetric flow rate of fuel gas, standard cubic feet per day (scf/day); Q oil 

## = Daily average volumetric flow rate of fuel oil, scf/day; HHV gas 

## = Daily average higher heating value of gas fired to the process heater, MMBtu/scf; and HHV oil 

## = 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: oil oil gas gas oil oil gas gas NOx 

# HHV Q HHV Q HHV Q HHV Q ER  

 35

. 0 06

. 0

oil oil gas gas oil oil gas gas NOx 

# HHV Q HHV Q HHV Q HHV Q ER  

 35

. 0 06

. 0

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 223 of 293

(Eq. 4)

Where:

ER NOx 

## = Daily allowable average emission rate of NO X 

## , lb/MMBtu (higher heating value basis); Q gas 

## = Daily average volumetric flow rate of fuel gas, scf/day; Q oil 

## = Daily average volumetric flow rate of fuel oil, scf/day; HHV gas 

## = Daily average higher heating value of gas fired to the process heater, MMBtu/scf; and HHV oil 

## = 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 NO X 

## 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 NO X 

## emissions limit: (i) A modified or reconstructed process heater that lacks sufficient space to accommodate installation and proper oil oil gas gas oil oil gas gas NOx 

# HHV Q HHV Q HHV Q HHV Q ER  

 40

. 0 11

. 0

oil oil gas gas oil oil gas gas NOx 

# HHV Q HHV Q HHV Q HHV Q ER  

 40

. 0 11

. 0

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## Page 224 of 293 operation of combustion modification-based technology (e.g. , ultra-low NO X 

## 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 NO X 

## 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 NO X 

## 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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## Page 225 of 293 (ii) An explanation of how the data in paragraph (i)(2)(i)

demonstrate that ultra-low NO X 

## 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 NO X 

## 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 NO X 

## 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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## Page 226 of 293 (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 NO X 

## emissions limit is described in paragraphs (i)(4)(i) through (iii) of this section. (i) Approval by the Administrator of a facility-specific NO X 

## 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-NO X 

## burner designs and other combustion modifications considered for reducing NO X 

## emissions; (C) The combustion modification option selected; and (D) The operating conditions (firing rate, heater box temperature and excess oxygen concentration) at which the NO X 

## emission level was established.

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## Page 227 of 293 (ii) If the request is approved by the Administrator, a facility-specific NO X 

## emissions limit will be established at the

NO X 

## 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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## Page 228 of 293 (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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## Page 229 of 293 (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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## Page 230 of 293 (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, H 2 

## S 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, H 2 

## S, 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,

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 231 of 293 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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## Page 232 of 293 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 233 of 293 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 234 of 293 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 235 of 293 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 SO 2 

## 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 (m 3 

## ) (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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## Page 236 of 293 (2) For a fuel gas combustion device, each exceedance of an applicable short-term emissions limit in §60.102a(g)(1) if the

SO 2 

## 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 SO 2 

## emissions are more than 227 kg (500 lb) greater than the amount that would

have been emitted if the SO 2 

## 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.

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 237 of 293 (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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## Page 238 of 293 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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## Page 239 of 293 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 240 of 293 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 H 2 

## S 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 241 of 293 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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## Page 242 of 293 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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## Page 243 of 293 (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.**

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 244 of 293 (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 (E PM 

## ) 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; c s 

## = Concentration of total PM, grams per dry standard cubic meter (g/dscm) (gr/dscf); Q sd 

## = Volumetric flow rate of effluent gas, dry standard cubic meters per hour (dry standard cubic feet per hour); R c 

## = Coke burn-off rate, kilograms per hour (kg/hr) [lb per hour (lb/hr)] coke; and c sd s 

# R K Q c E 

c sd s 

# R K Q c E 

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 245 of 293 K = Conversion factor, 1.0 grams per gram (7,000 grains per lb).

(iii) The coke burn-off rate (R c 

## ) is computed for each run using Equation 6 of this section:

(Eq. 6)

Where:

R c 

## = Coke burn-off rate, kg/hr (lb/hr); Q r 

## = 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)]; Q a 

## = 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); Q oxy 

## = Volumetric flow rate of O 2 

## enriched air to FCCU regenerator or fluid coking unit, as determined from the unit’s control room instrumentation, dscm/min (dscf/min); %CO 2 

## = Carbon dioxide (CO 2 

## ) 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); %O 2 

## = O 2 

## concentration in FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis); %O oxy 

## = O 2 

## concentration in O 2 

## enriched air stream inlet to the FCCU regenerator or fluid coking burner, percent by volume (dry basis); K 1 

## = Material balance and conversion factor, 0.2982 (kgmin)/(hr-dscm-%) [0.0186 (lb-min)/(hr-dscf-%)]; K 2 

## = Material balance and conversion factor, 2.088 (kgmin)/(hr-dscm) [0.1303 (lb-min)/(hr-dscf)]; and K 3 

## = Material balance and conversion factor, 0.0994 (kgmin)/(hr-dscm-%) [0.00624 (lb-min)/(hr-dscf-%)]. 

#   

#     oxy oxy r a r c 

# O Q K O CO CO Q K Q K CO CO Q K R % % % 2 % % % 3 2 2 3 2 2 1 

#   

    

#   

#     oxy oxy r a r c 

# O Q K O CO CO Q K Q K CO CO Q K R % % % 2 % % % 3 2 2 3 2 2 1 

#   

   

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 246 of 293 * * * * * (v) For subsequent calculations of coke burn-off rates or exhaust gas flow rates, the volumetric flow rate of Q r 

## 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: Q r 

## = 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); Q a 

## = 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); Q oxy 

## = Volumetric flow rate of O 2 

## enriched air to FCCU regenerator or fluid coking unit, as determined from the unit’s control room instrumentation, dscm/min (dscf/min); %CO 2 

## = 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; %O 2 

## = O 2 

## concentration in FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis); and %O oxy 

## = O 2 

## concentration in O 2 

## enriched air stream inlet to the FCCU regenerator or fluid coking burner, percent by volume (dry basis).

* * * * * 

#  

2 2 

## % % % 100 % 100 79 O CO CO Q Oxy Q Q oxy a r



##    

  

 

#  

2 2 

## % % % 100 % 100 79 O CO CO Q Oxy Q Q oxy a r



##    

  



### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 247 of 293 (8) The owner or operator shall adjust PM, NO X 

## , SO 2 

## and CO pollutant concentrations to 0-percent excess air or 0-percent O 2 

## using Equation 8 of this section:

(Eq. 8)

Where:

C adj 

## = pollutant concentration adjusted to 0-percent excess air or O 2 

## , parts per million (ppm) or g/dscm; C meas 

## = pollutant concentration measured on a dry basis, ppm or g/dscm; 20.9 c 

## = 20.9 percent O 2 

## − 0.0 percent O 2 

## (defined O 2 

## correction basis), percent; 20.9 = O 2 

## concentration in air, percent; and %O 2 

## = O 2 

## 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; Opacity st 

## = Hourly average opacity measured during the source test, percent; and PMEmR st 

## = PM emission rate measured during the source test, lb/1,000 lb coke burn.

* * * * * (h) * * * 

#        

  2 

## % 9

. 20 9

. 20 O C C c meas adj 

#        

  2 

### % 9

. 20 9

. 20 O C C c meas adj



##        

 st st 

## PMEmR

x Opacity Limit Opacity burn coke lb 000 , 1 / lb 1

       

 st st 

## PMEmR

x Opacity Limit Opacity burn coke lb 000 , 1 / lb 1

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 248 of 293 (5) * * * (iv) The owner or operator shall use Equation 8 of this section to adjust pollutant concentrations to 0-percent O 2 

## or 0- percent excess air. (i) The owner or operator shall determine compliance with

the SO 2 

## and NO X 

## 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 O 2 

## operating limit or O 2 

## 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 O 2 

## 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 249 of 293 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 NO X 

## concentration for the performance test as the average of

the NO X 

## concentrations from each of the three test runs. If the

NO X 

## concentration for the performance test is less than or equal to the numerical value of the applicable NO X 

## emissions limit (regardless of averaging time), then the test is considered to

be a valid test. (C) Determine the average O 2 

## concentration for each test run

of a valid test. (D) Calculate the O 2 

## operating limit as the average O 2 

## concentration of the three test runs from a valid test. (ii) If an O 2 

## 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 O 2 

## 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 250 of 293 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 NO X 

## concentration for the performance test as the average of

the NO X 

## concentrations from each of the three test runs. If the

NO X 

## concentration for the performance test is less than or equal to the numerical value of the applicable NO X 

## 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 O 2 

## 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 O 2 

## concentration for each test run

of a valid test.

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 251 of 293 (E) Calculate the O 2 

## operating limit for each operating range as the average O 2 

## 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 O 2 

## 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 O 2 

## 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 NO X 

## 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 252 of 293 between 40 and 100 MMBtu/hr that elects to demonstrate continuous compliance with a maximum excess O 2 

## 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 O 2 

## or 0- percent excess air. (j) The owner or operator shall determine compliance with the applicable H 2 

## S 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 H 2 

## S concentration for affected facilities using an H 2 

## S 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 253 of 293 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 254 of 293 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 CO 2 

## , O 2 

## 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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## Page 255 of 293 (5) All rolling 7-day periods during which the average

concentration of SO 2 

## as measured by the SO 2 

## CEMS under §60.105a(g) exceeds 50 ppmv, and all rolling 365-day periods during which the average concentration of SO 2 

## as measured by the

SO 2 

## 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);

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 256 of 293 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 SO 2 

## or H 2 

## S limit and flares subject to H 2 

## S 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 SO 2 

## 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 H 2 

## S concentration limits in §60.102a(g)(1)(ii) or a flare that is subject to the H 2 

## S 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 SO 2 

## 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 SO 2 

## emissions into the atmosphere. The monitor must include an O 2 

## monitor for correcting the data for excess air.

* * * * *

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## Page 257 of 293 (2) The owner or operator of a fuel gas combustion device that elects to comply with the H 2 

## S concentration limits in §60.102a(g)(1)(ii) or a flare that is subject to the H 2 

## S 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 H 2 

## S 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 H 2 

## S monitor according to Performance Specification 7 of Appendix B to part 60. The span value for this instrument is 300 ppmv H 2 

## S.

* * * * * (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 H 2 

## S 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 H 2 

## S 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 258 of 293 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 H 2 

## S 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 H 2 

## S 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

H 2 

## S 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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## Page 259 of 293 (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 H 2 

## S 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 H 2 

## S 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 260 of 293 submit new information to support an exemption, the owner or operator must begin H 2 

## S 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 H 2 

## S 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 H 2 

## S 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 NO X 

## concentrationbased limit . The owner or operator of a process heater subject

to the NO X 

## 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 NO X 

## 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 O 2 

## monitor for correcting the data for excess air.

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 261 of 293 (1) Except as provided in paragraph (c)(6) of this section, the owner or operator shall install, operate and maintain each

NO X 

## monitor according to Performance Specification 2 of Appendix B to part 60. The span value of this NO X 

## 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 NO X 

## emissions (i.e. , low-NO X 

## burners, ultra-low-NO X 

## 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 O 2 

## operating limit or operating curve according to the requirements in §60.104a(i)(6) and comply with

the O 2 

## monitoring requirements in paragraphs (c)(3) through (5) of this section to demonstrate compliance. If an O 2 

## operating curve is used (i.e. , if different O 2 

## 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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## Page 262 of 293 (d) Process heaters complying with the NO X 

## heating valuebased or mass-based limit . The owner or operator of a process heater subject to the NO X 

## 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 NO X 

## 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 NO X 

## 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 NO X 

## 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 263 of 293 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

NO X 

## monitor according to the requirements in paragraphs (c)(1) through (5) of this section. The monitor must include an O 2 

## 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 264 of 293 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:

F d 

## = F factor on dry basis at 0-percent excess air, dscf/MMBtu. X i 

## = mole or volume fraction of each component in the fuel gas. MEV i 

## = molar exhaust volume, dry standard cubic feet per mole (dscf/mol). MHC i 

## = 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 

# MHC X MEV X F 000 , 000 , 1 

#     

#  

  

 i i i i d 

# MHC X MEV X F 000 , 000 , 1

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 265 of 293 (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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 266 of 293 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 PipesUsing 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 UsingSmall 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);

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 267 of 293 (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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 268 of 293 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 269 of 293 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).

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 270 of 293 (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 NO X 

## emissions (i.e. , low-NO X 

## burners or ultra-low NO X 

## burners) may

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 271 of 293 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 O 2 

## operating limit or operating curve according to the requirements in §60.104a(i)(6) and comply with

the O 2 

## monitoring requirements in paragraphs (c)(3) through (5) of this section to demonstrate compliance. If an O 2 

## operating curve is used (i.e. , if different O 2 

## 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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 272 of 293 (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

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 273 of 293 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.

### ***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

## Page 274 of 293 (2) H 2 

## S monitoring requirements . The owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration of H 2 

## S 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 H 2 

## S 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 H 2 

## S 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 H 2 

## S 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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## Page 275 of 293 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 H 2 

## S 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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## Page 276 of 293 (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-H 2 

## S ratio and 95-percent confidence interval as

follows: (A) Calculate the ratio of the total sulfur concentration

to the H 2 

## S concentration for each day during which samples are

collected. (B) Determine the 10-day average total sulfur-to-H 2 

## S 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. (Eq. 11) 

## SDev Ratio AR Avg 

##    262

. 2 

## SDev Ratio AR Avg 

##    262

. 2

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## Page 277 of 293 Where: AR = Acceptable range of subsequent ratio determinations, unitless. Ratio Avg 

## = 10-day average total sulfur-to-H 2 

## S 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-H 2 

## S concentration ratios used to develop the 10-day average total sulfur-to-H 2 

## S 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-H 2 

## S ratio by the daily average H 2 

## S 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-H 2 

## S 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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## Page 278 of 293 data for the outlying weekly sample plus data collected over the following 9 operating days. (3) SO 2 

## monitoring requirements . The owner or operator shall install, operate, calibrate and maintain an instrument for continuously monitoring and recording the concentration of SO 2 

## 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 SO 2 

## ) in the fuel gas using Equation 12 of this

section. (Eq. 12)

Where:

TS FG 

## = Total sulfur concentration, as SO 2 

## , in the fuel gas, ppmv. C SO2 

## = Concentration of SO 2 

## in the exhaust gas, ppmv (dry basis at 0-percent excess air). F d 

## = F factor gas on dry basis at 0-percent excess air, dscf/MMBtu. HHV FG 

## = 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 FG d SO FG 

## HHV F C TS    2 FG d SO FG 

## HHV F C TS    2

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## Page 279 of 293 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 SO 2 

## 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 H 2 

## S 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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## Page 280 of 293 primary flare should be used to calculate SO 2 

## 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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## Page 281 of 293 (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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## Page 282 of 293 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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## Page 283 of 293 (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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## Page 284 of 293 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) SO 2 

## or H 2 

## S limits for fuel gas combustion devices

. (i) If the owner or operator of a fuel gas combustion device elects to comply with the SO 2 

## emission limits in §60.102a(g)(1)(i), each rolling 3-hour period during which the average concentration of SO 2 

## as measured by the SO 2 

## 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 SO 2 

## as measured by the SO 2

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## Page 285 of 293 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 H 2 

## S concentration limits in §60.102a(g)(1)(ii), each rolling 3-hour period during which the average concentration of H 2 

## S as measured by the H 2 

## S 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 H 2 

## S 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 H 2 

## S exceeds 162 ppmv and each rolling 365-day period during which the average

concentration of H 2 

## S exceeds 60 ppmv. (2) H 2 

## S concentration limits for flares . (i) Each rolling 3- hour period during which the average concentration of H 2 

## S as measured by the H 2 

## S 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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## Page 286 of 293 (b)(3)(iii) of this section, each day during which the daily

concentration of H 2 

## S exceeds 162 ppmv. (3) Rolling 30-day average NO X 

## limits for fuel gas

combustion devices . Each rolling 30-day period during which the average concentration of NO X 

## as measured by the NO X 

## 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 NO X 

## 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 NO X 

## limits for fuel gas combustion devices . Each day during which the concentration of NO X 

## as measured by the NO X 

## 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 O 2 

## limits for fuel gas combustion devices . Each day during which the concentration of O 2 

## as measured by the O 2

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## Page 287 of 293 continuous monitoring system required under paragraph (c)(6) of

this section exceeds the O 2 

## 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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## Page 288 of 293 (c) * * * (1) A copy of the flare management plan.

* * * * * (6) Records of discharges greater than 500 lb SO 2 

## in any 24- hour period from any affected flare, discharges greater than 500

lb SO 2 

## 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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## Page 289 of 293 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 SO 2 

## in any 24- hour period from a flare, the measured total sulfur

concentration or both the measured H 2 

## S 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 SO 2 

## 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 H 2 

## S in the fuel gas or the measured concentration of SO 2 

## 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 SO 2 

## in excess of the allowable limits from a sulfur recovery plant, either the

measured concentration of reduced sulfur or SO 2 

## discharged to the atmosphere.

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## Page 290 of 293 (vii) For each discharge greater than 500 lb SO 2 

## in any 24- hour period from any affected flare or discharge greater than

500 lb SO 2 

## in excess of the allowable limits from a fuel gas combustion device or sulfur recovery plant, the cumulative quantity of H 2 

## S and SO 2 

## released into the atmosphere. For releases controlled by flares, assume 99-percent conversion of

reduced sulfur or total sulfur to SO 2 

## . For fuel gas combustion devices, assume 99-percent conversion of H 2 

## S to SO 2 

## . (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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## Page 291 of 293 (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 H 2 

## S and total sulfur analyses of each grab or integrated sample, the calculated daily

total sulfur-to-H 2 

## S ratios, the calculated 10-day average total

sulfur-to-H 2 

## S ratios and the 95-percent confidence intervals for each 10-day average total sulfur-to-H 2 

## S 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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## Page 292 of 293 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 MEV a 

## dscf/mol MHC b 

## Btu/mol Methane (CH 4 

## ) 7.29 842 Ethane (C 2 

## H 6 

## ) 12.96 1,475 Hydrogen (H 2 

## ) 1.61 269 Ethene (C 2 

## H 4 

## ) 11.34 1,335 Propane (C 3 

## H 8 

## ) 18.62 2,100 Propene (C 3 

## H 6 

## ) 17.02 1,947 Butane (C 4 

## H 10 

## ) 24.30 2,717 Butene (C 4 

## H 8 

## ) 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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## Page 293 of 293

b 

## MHC = molar heat content (higher heating value basis), Btu per gram-mole (Btu/g-mol)

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# 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 Deleted: March

### *** Draft – Do Not Cite, Quote, or Release During Review ***

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 Stan dards, 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.

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iii TABLE OF CONTENTS

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

1.1 I NTRODUCTION

.............................................................................................................................. .................. 1-1

1. 2 R ESULTS

.............................................................................................................................. ............................ 1-2 1. 3 R EFERENCES

.............................................................................................................................. ...................... 1- 7 2 I NDUSTRY P ROFILE ............................................................................................................. 2-1

2.1 I NTRODUCTION

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

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

2.2.1 Production Process, Inputs, and Outputs ....................................................................................... ....... 2-1 2.2.2 Emissions and Controls in Petroleum Refining .................................................................................. . 2-9 2.2.3 Costs of Production ........................................................................................................... .................. 2-10 2.3 T HE D EMAND S IDE

.............................................................................................................................. .......... 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 I NDUSTRY O RGANIZATION ............................................................................................................................ 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 M ARKETS

.............................................................................................................................. ........................ 2-30

2.5.1 U.S. Petroleum Consumption .................................................................................................... ......... 2-30 2.5.2 U.S. Petroleum Production ..................................................................................................... ............ 2-36 2.5.3 International Trade ........................................................................................................... ................... 2-37 2.5.4 Market Prices ................................................................................................................. ..................... 2-39 2.5.5 Profitability of Petroleum Refineries ......................................................................................... ........ 2-41 2.5.6 Industry Trends ............................................................................................................... .................... 2-43 2.6 R EFERENCES

.............................................................................................................................. .................... 2-45 3 NSPS R EGULATORY O PTIONS , C OSTS AND E MISSION R EDUCTIONS FROM C OMPLYING WITH THE NSPS .......................................................................................................................... 3-1 4 E CONOMIC I MPACT A NALYSIS : M ETHODS AND R ESULTS ................................................. 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 4.4 REFERENCES........................................................................................................4- 8 5 E XECUTIVE O RDERS ........................................................................................................... 5-1

5.1 UNFUNDED MANDATES ............................................................................................................. .............. 5-1 5.2 ENVIRONMENTAL JUSTICE ..................................................................................................................... 5 -1 5.3 SIGNIFICANT ENERGY ACTIONS .................................................................................................... ....... 5-1 6 H UMAN H EALTH B ENEFITS OF E MISSIONS R EDUCTIONS .................................................. 6-1 Deleted: 1.2 R EASON FOR T ODAY ’ S A CTION : M ARKET F AILURE OR O THER S OCIAL P URPOSE 1-22 Deleted: 3 Deleted: 4

Deleted: 3 Deleted: 4 Deleted: 7

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iv 6.1 C ALCULATION OF PM 2.5 -R ELATED H UMAN H EALTH B ENEFITS ..................................................................... 6-1 6.2 S OCIAL C OST OF C ARBON AND G REENHOUSE G AS B ENEFITS ..................................................................... 6- 14 6.3 E NERGY D ISBENEFITS

.............................................................................................................................. ..... 6- 17 6.4 T OTAL M ONETIZED B ENEFITS ...................................................................................................................... 6- 18 6.5 U NQUANTIFIED B ENEFITS

............................................................................................................................. 6- 19 6.5.1 Additional SO 2 and NO 2 Benefits ...................................................................................................... 6- 19 6.5.2 Ozone Benefits ................................................................................................................ .................... 6- 22 6.5.3 Visibility Impairment.......................................................................................................... ................ 6- 22 6.6 C HARACTERIZATION OF U NCERTAINTY IN THE M ONETIZED B ENEFITS ....................................................... 6- 23 6.7 R EFERENCES

.............................................................................................................................. .................... 6- 28 7 C OMPARISON OF B ENEFITS AND C OSTS ............................................................................. 7-1 A PPENDIX A P ARENT C OMPANY I NFORMATION FOR P ETROLEUM R EFINERIES ..................... A-1 Deleted: 19

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v LIST OF TABLES Table 1-1 National Incremental Cost Impacts , Emission Reductions, and Cost Effectiveness for Petroleum Refinery Flares Subject to Amended Standards Unde r 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- 5 Table 2-1. Types and Characteristics of Raw Materials used in Petroleum Refineries ........................................ 2- 7 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 .......................................... 2-31 Table 2-10. Total Petroleum Products Supplied (millions of barrels per year) ..................................................... 2-36 Table 2-11. U.S. Refinery and Blender Net Production (millions of barrels per year) ......................................... 2-36 Table 2-12. Value of Product Shipments of the Petroleum Refining Industry ...................................................... 2-38 Table 2-13. Imports of Major Petroleum Products (millions of barrels per year) ................................................. 2-38 Table 2-14. Exports of Major Petroleum Products (millions of barrels per year) ................................................. 2-39 Table 2-15. Average Price of Major Petroleum Products Sold to End Users (cents per gallon) .......................... 2-40 Table 2-16. Producer Price Index Industry Data: 1995 to 2010 ............................................................................ 2 -41 Table 2-17. Mean Ratios of Profit before Taxes as a Percenta ge of Net Sales for Petroleum Refiners, Sorted by Value of Assets ............................................................................................................... ..................... 2-42 Table 2-18. Net Profit Margins for Publicly Owned, Small Petroleum Refiners: 2010 ....................................... 2-43 Table 2-19. Forecasted Average Price of Major Petroleum Produc ts Sold to End Users in 2009 Currency (cents per gallon) ................................................................................................................... ......................... 2-44 Table 2-20. Total Petroleum Products Supplied (millions of barrels per year) ..................................................... 2-44 Table 2-21. Full Production Capacity Utilization Rates for Petroleum Refineries ............................................... 2-45 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 Co st-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 Inves t ment for Refineries................................................................4-2 Table 4-2. Impact Levels of Prop osed NSPS Amendments on Small Firms..........................................4- 6 Table 4-3. Summary of Sales Ratios for Fi rms Affected by Proposed NSPS Amendments........................4- 7 Table 6-1. Human Health Effects of PM 2.5 ............................................................................................................. 6-3 Table 6-2. General Summary of Monetized PM-Related Health Benefits Estimates for Petroleum Refineries NSPS Reconsideration (millions of 2006$) * ...................................................................................... 6-11 Table 6-3. Summary of Reductions in Health Incidences from PM 2.5 Benefits for Petroleum Refineries NSPS Reconsideration* .............................................................................................................. ................... 6-12 Table 6-4. All PM 2.5 Benefits Estimates for the Final Petroleum Refineries NSPS Reconsideration at discount rates of 3% and 7% in 2017 (in millions of 2006$)* ......................................................................... 6- 13 Table 6-5. Social Cost of Carbon (SCC) Estimates (per tonne of CO 2 ) for 2017 a .............................................. 6- 16 Table 6-6. Monetized SCC-Derived Benefits of CO 2 Emission Reductions in 2017 a,b ..................................... 6- 17 Table 7-1. National Incremental Cost Impacts, Emission Redu ctions, and Cost Effectiveness for Petroleum Refinery Flares Subject to Amended Standards Unde r 40 CFR part 60, subpart Ja (Fifth Year After Effective Date of Final Rule Amendments) ......................................................................................... 7- 2 Table 7-2. Summary of the Monetized Benefits, Social Cost s, and Net Benefits for the Final Petroleum Refineries NSPS in 2017.......................................................................................7-3 Table A-1. Parent Company Information for Petroleum Refineries .......................................................................A-2 Deleted: Applicability Deleted: Table 1-2 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 Applicability ¶ Date)..........................................

................................................... ...................1-3¶ Deleted: 3 Deleted: 4 Deleted: 8

Deleted: Applicability Deleted: Applicability

Deleted: 5 Deleted: 6 Deleted: (millions of 2006$) Deleted: Summary of the Monetized Benefits, Social Costs, and Net Benefits for the Final Petroleum Refineries NSPS in 2017 (millions of 2006$) 1 Deleted: 111 Formatted: Normal, Indent: Before: 0", First line: 0", Tab stops: Not at 0.83" + 6.49" Deleted: 2 Formatted: Font: (Default) Times New Roman, 10 pt, Complex Script Font: Times New Roman, 10 pt, Check spelling and grammar

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vi LIST OF FIGURES Figure 2-1. Outline of the Refining Process ............................................................................................... ............. 2-3 Figure 2-2. Desalting Process ............................................................................................................. ..................... 2-3 Figure 2-3. Atmospheric Distillation Process .............................................................................................. ........... 2-4 Figure 2-4. Vacuum Distillation Process ................................................................................................... ............. 2-5 Figure 2-5. Petroleum Refinery Expenditures ............................................................................................... ....... 2-11 Figure 2-6. Employment Distribution of Companies Owning Petroleum Refineries (N=61) ............................. 2-25 Figure 2-7. Average Revenue of Companies Owning Petroleum Refineries by Employment (N=61) .............. 2-26 Figure 2-8. Revenue Distribution of Large Companies Owning Petroleum Refineries (N=25) ......................... 2-27 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) .................................................... 2-35 Figure 6-1: Breakdown of Monetized PM 2.5 Health Benefits using Mortality F unction from Pope et al. (2002)6-10 Figure 6-2: Monetized PM 2.5 Benefits of Final Petroleum Refineries Reconsideration in 2017 ......................... 6- 14 Figure 6-3: Breakdown of Monetized Benefits for Final Petroleu m Refineries NSPS Reconsideration by Pollutant ...6- 18 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 PM 2.5 Exposure in the Baseline .......................... 6- 25 Figure 6- 6

. Cumulative Distribution of Adult Population by Annual Mean PM 2.5 Exposure in the Baseline .... 6- 26 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 Deleted: Total

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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 pe rformance 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/reconstructe d sources, and these limits are set for sulfur dioxide (SO 2 ), nitrogen oxides (NO x ), 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, solven ts, and a variety of other products. Petroleum refining falls under the North American Indust rial Classification Syst em (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 fac ilities 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 Bu siness 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 sa vings, 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). Formatted: Numbered + Level: 1 + Numbering Style: 1, 2, 3, ... + Start at: 1 + Alignment: Left + Aligned at: 0" + Indent at: 0.25" Deleted: Reason for Today’s Action: Market Failure or Other Social Purpose¶ <#>¶ <#>The petroleum refinery NSPS is of sufficient impact to be considered as falling under the requirements for Executive Order 12866 (OMB, 2003). This final regulation is being issued in response to a decision between U.S. EPA and various parties requiring review of the existing NSPS. Among the reasons a regulation such as this one may also be issued is to address market failure. The major types of market failure include: externality, market power, and inadequate or asymmetric information. Correcting market failures is a reason for regulation, but it is not the only reason. Other possible justifications include improving the functioning of government, removing distributional unfairness, or promoting privacy and personal freedom.¶ 1.3 Comment [ A 1]: This is a general market failure discussion, but not particularly relevant on for this rule.

Deleted: s Deleted: and 1-2 Deleted: Table 1-1. National Incremental Cost Impacts for Petroleum Refinery Flares Subject to Amended Standards Under 40 CFR part 60, subpart Ja (Fifth Year After Applicability Date)*** Draft – Do Not Cite, Quote, or Release During Review ***1-0Table 1-1. National Incremental Cost Impacts, Emission Reductions, and Cost Effectiveness for Petroleum Refinery Flares SubjecttoAmended Standards Under 40 CFR part 60, subpart Ja (Fifth Year After Effective Date of Final Rule Amendments)1Subpart JaRequirementsTotalcapitalcost(millions)Totalannual costwithoutcredit(millions/yr)Naturalgasoffset/productrecoverycredit(millions)Totalannual cost(millions/yr)Annualemissionreductions(tonsSO2/yr)Annualemissionreductions(tonsNOX/yr)Annualemissionreductions(tonsVOC/yr)Costeffectiveness($/tonemissionsreduced)Annualemissionreductions(metrictonsCO2/yr)2MonetizedBenefits(millions, 3%discount rate forhealth andclimate benefits)MonetizedBenefits(millions, 3%discount rate forhealth and 7%for climatebenefits)

Small FlaresFlareMonitoring$72$12$0$120000$0to$0$0to$0Flare gasrecovery$0$0$0$00000$0to$0$0to$0FlareManagement$0$0.79$0$0.7900270$2,9000$0to$0$0to$0SO2 RCA/CA$0$1.9$0$1.92,60000$7600$170to$410$150to$370FlowrateRCA/CA$0$0.90-$6.7-$5.83.450390-$13,00098,000$2.9to$3.7$2.9to$3.6Total$72$16-$6.7$9.02,60050660$2,70098,000$170to$410$150to$370

Large FlaresFlareMonitoring$12$2.0$0$2.00000$0to$0$0to$0Flare gasrecovery$380$78-$170-$903801,1002,700-$22,0001,800,000$74to$120$71to$110FlareManagement$0$0.088$0$0.0880030$2,9000$0to$0$0to$0SO2 RCA/CA$0$0.22$0$0.2229000$7600$18to$45$17to$41FlowrateRCA/CA$0$0.10-$0.74-$0.640643-$13,00011,000$0to$0$0to$0Total$390$81-$170-$886601,1002,800-$20,0001,800,000$93to$160$88to$150

All FlaresFlareMonitoring$84$14$0$140000$0to$0$0to$0Flare gasrecovery$380$78-$170-$903801,1002,700-$22,0001,800,000$74to$120$71to$110FlareManagement$0$0.88$0$0.8800300$2,9000$0to$0$0to$0SO2 RCA/CA$0$2.2$0$2.22,90000$7600$180to$450$170to$410FlowrateRCA/CA$0$1.00-$7.4-$6.43.456430-$13,000110,000$3.2to$4.0$3.1to$3.9Total$460$96-$180-$793,2001,1003,400-$10,0001,900,000$260to$580$240to$5201All estimates are for the implementation year (2017), and are rounded to two significant figures.2The emission reductions of CO2reflect the anticipated emission increases associated with the energy disbenefits from additional electricity consumption.Formatted:Indent: Before: 0"

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1-0 EPA estimates that the total monetized bene fits 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 PM 2.5 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 SO 2 and NOx benefits, ozone benefits, ecosy stem benefits, and visibility benefits have not been monetized in this analysis. EPA estimates the net benefits of the fina l 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. Deleted: ¶ Table 1-2. National IncrementalEmission Reductions and CostEffectiveness for Petroleum Refinery Flares Subject to Amended Standards Under 40 CFR part 60, subpart Ja (Fifth Year After Applicability Date)¶ Sub p art Ja Re q uirements ... [1] Deleted: In the year of full implementation (2017) Deleted: 3

Deleted: In the year of full implementation (2017), Deleted: 3

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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 Benefits 2 $260 to $580 $240 to $520 Total Compliance Costs 3 -$79 -$79 Net Benefits $340 to $660 $320 to $600

Non-monetized Benefits Health effects from SO 2, NO 2 , 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 heal th benefits associated with reducing exposure to PM 2.5 through

reductions of PM 2.5 precursors such as NOx and SO 2 as well as CO 2 benefits. It is important to note that the monetized benefits do not include the reduced health effects from direct exposure to SO 2 and NOx, ozone exposure, ecosystem effects, or visibility impairment. Huma n 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 mort ality because the scientific evidence is not yet sufficient to allow differentiation of effects estimates by particle type. The net present value of reduced CO 2 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. Deleted: 3

Comment [ A 2]: Did EPA update the cost estimates to reflect a 3% discount rate? Response - No

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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) a nd $88 million to $150 million (7% discount rate for health benefits and 3-percent discount rate fo r climate benefits). All estimates are in 2006 dollars for the year 2017. Deleted: in the year of full implementation (2017)

Deleted: of the final NSPS are

Deleted: (Table 1-4)

Deleted: ¶

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1-3 1. 3 References Laden, F., J. Schwartz, F.E. Speizer, and D.W. Dockery. 2006. Reduction in Fine Particulate Air Pollution and Mortality. American Journal of Respirat ory 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. Deleted: 4

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2-1 2. PROFILE OF THE PETROLEUM REFININGINDUSTRY 2.1 Introduction This industry profile of the petroleum refini ng 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 categ orized 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 product s 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 pr ices 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 co sts 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 processe d over several stages. This section describes the typical stages involved in this proce ss 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 coul d 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 set tler tank. Gradually, the salts present in the oil will be dissolved into the process water (EPA, 1995). After this takes place, the process water is separated from the oil by adding demulsifier 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 Sa fety 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_i v/otm_iv_2.html>. As obtained on October 23, 2006.

Figure 2-2 Desalting Process Source: U.S. Department of Labor, Occupational Sa fety 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_i v/otm_iv_2.html>. As obtained on October 23, 2006.

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2-4 Atmospheric Distillation. The desalted crude oil is then heated in a furnace to 750°F and fed into a vertical distillation column at atmospheric pressure. After entering the tower, the lighter fractions flash into vapor and travel up the tower. This leaves only the heaviest fractions (which have a much higher boiling point) at the bottom of the tower. These fractions include heavy fuel oil and asphalt residue (EPA, 1995). As the hot vapor rises, its temperature is gradually reduced. Lighter fractions condense onto trays located at successively higher portions of the tower. For example, motor gasoline will condense at higher portion of the tower than kerosene because it condenses at lower temperatures. This process is illustrated in Figure 2-3. As thes e 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 Sa fety 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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2-5 Figure 2-4 Vacuum Distillation Process Source: U.S. Department of Labor, Occupational Sa fety 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 afte r 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, isomer ization, polymerization, catalytic reforming, solvent extraction, merox, dewaxing, propane deasphalting and other op erations (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 refini ng operations or discharged. Petroleum refineries typically utilize two stages of wastewater treatment. In primary wa stewater 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 tr eatment 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 SO x 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 dioxid e. 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 characteristi cs. 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 Deleted: The most common ether additives being used today are methyl tertiary butyl ether (MTBE), and tertiary amyl methyl ether (TAME). Larger refineries tend to manufacture these additives themselves by reacting isobutylene (a by-product of several refinery processes) with methanol (OSHA, 2003 Deleted: ). Comment [ A 3]: Suggest delete?

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2-7 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 in tentional 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. Th ese 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 ra nges 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 us ed 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 character istics, and their applications. Table 2-1 Types and Characteristics of Raw Materials used in Petroleum Refineries

1 Crude oil processing requires large volumes of water, a la rge portion of which is continually recycled. The amount of water used by a refinery can vary significantly, de pending 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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2-8 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 us ed in some treatment processes. Source: U.S. Department of Labor, Occupational Sa fety 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_i v/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. Deleted: methyl tertiary butyl ether (MTBE Comment [ A 4]: Suggest delete?

Deleted: ),

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2-9 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, lubri cants (such as motor oil and industrial greases), and solvents (such as benzene, toluene, and xylene). Feedstock

Sulfur Many products derived from crude oil re fining, such as ethylene, propylene, butylene, and isobutylene, are primarily intended for use as petrochemical feedstock in the production of plastics, synt hetic 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 Sa fety 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_i v/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 HA Ps include metals and toxic organic compounds; the CAPs include carbon monoxide (CO), sulfur oxides (SO x ), nitrogen oxides (NO x ), particulates, and volatile organic compounds (VOC s); and the other pollutants include spent acids, gaseous pollutants, ammonia (NH 3 ), and hydrogen sulfide (H 2 S). 2.2.2.1 Gaseous and VOC Emissions As previously mentioned, CO, SO x , NO x , NH 3 , and H 2 S emissions are produced along with petroleum products. Sources of these emissi ons from refineries include fugitive emissions of the volatile constituents in cr ude 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 SO x , NO x , CO, and hydrocarbons emissions. Emissions are low when process heaters are operating properly and using clean fuels such as refinery fuel gas, fuel oil, or natural gas. However, if combustion is not complete, or the heaters are fueled using fuel pitch or residuals, emissions can be significant (EPA, 1995).

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2-10 The majority of gas streams exiting each refinery process contain varying amounts of refinery fuel gas, H 2 S, and NH 3 . These streams are directed to the gas treatment and sulfur recovery units described in the 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 H 2 S, SO x , and NO x gases (EPA, 1995). For additional de tails 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. Howeve r, 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 variet y of wastewaters including process water (water used in process operations like desalting), cooling water (wat er 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, NH 3 , sulfides, and other compounds) and is treated in on-site facilities before being recycled back into the production process or discharged. Other wastes include forms of sludges, spent process catalysts, filter clay, and incinerator ash. These wastes are controlled through a variet y 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 tota l 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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2-11 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 Manufacture s. 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 Manufacture s. 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 Manufacture s. M99(AS)-1 (RV). Washington, DC: Government Printing Office. Available at <http://www.census.gov/prod/2001pubs/ U.S. Department of Commerce, Bureau of the Census. 1998. 1996 Annual Survey of Manufacture s. M96(AS)-1 (RV). Washington, DC: Government Printing Office. Available at <http://www.census.gov/prod/3/98pubs/ U.S. Department of Commerce, Bureau of the Census. 1997. 1995 Annual Survey of Manufacture s. M95(AS)-1. Washington, DC: Government Printing Office. Available at <http://www.census.gov/prod/2/manmin/ U.S. Census Bureau, American FactFinder; “S ector 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; “S ector 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 Expendi tures for Petroleum Refineries (NAICS 324110) Payroll ($millions) Materials ($mi llions) 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 Manufacture s. M05(AS)-1. Washington, DC: Government Printing Office. Ava ilable at <http://www.census.gov/prod/2006pubs/ am0531gs1.pdf>. As obtained on October 23, 2007. U.S. Department of Commerce, Bureau of the Census. 2003a. 2001 Annual Survey of Manufacture s. M01(AS)-1. Washington, DC: Government Printing Office. Ava ilable at <http://www.cens us.gov/prod/2003pubs/ m01as-1.pdf>. As obtained on October 23, 2006. U.S. Department of Commerce, Bureau of the Census. 2001. 1999 Annual Survey of Manufacture s. M99(AS)-1 (RV). Washington, DC: Government Printing Office. Available at <http://www. census.gov/pr od/2001pubs/ m99-as1.pdf>. As obtained on October 23, 2006. U.S. Department of Commerce, Bureau of the Census. 1998. 1996 Annual Survey of Manufacture s. M96(AS)-1 (RV). Washington, DC: Government Printing Office. Available at <http://www.census.gov/prod/3/98pubs/ m96-as1.pdf>. As obtained on October 23, 2006. U.S. Department of Commerce, Bureau of the Census. 1997. 1995 Annual Survey of Manufacture s. M95(AS)-1. Washington, DC: Government Printing Office. Ava ilable 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.cen sus.gov/servlet/IBQTable?_bm=y&- NAICSASM=324110&-ds_name=AM0931GS101&-ib_t ype=NAICSASM&-_industry=324110&-_lang=en

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2-13 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/se rvlet/IBQTable?_bm=y&-geo_id= 01000US&-ds_name=EC0731I1&- NAICS2007=324110&-_lang=en

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2-14 Table 2-4 Costs of Materials Used in Petroleum Refining Industry 2007 2002

Material Delivered Cost ($10 3 ) Percentage of Material Costs Delivered Cost ($10 3 ) Percentage of Material Costs Petroleum Refineries NAICS 324110 Total materials 440,165,193 100.00% 157,415,200 100.00% Domestic crude petroleum, including lease

condensate 133,567,383 30.3% 63,157,497 40.1% Foreign crude petroleum, including lease

condensate 219,780,279 49.9% 69,102,574 43.9% Foreign unfinished oils (received from

foreign countries for further processing) D 2,297,967 1.5% Ethane (C2) (80% purity or more) — D Propane (C3) (80% purity or more) — 118,257 0.1% Butane (C4) (80% purity or more) 7,253,910 1.7% 1,925,738 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%

H 2 SO 4 ) 67,458 0.0% 189,912 0.1% Metal containers D 9,450 0.0% Plastics containers D D Paper and paperboard containers 1,819 0.0% D Cost of materials received from petroleum

refineries and lube manufacturers 20,951,741 4.8% 8,980,758 5.7% All other materials and components, parts,

containers, and supplies 24,839,320 5.6% 5,722,580 3.6% Materials, ingredients, containers, and

supplies 4,745,614 1.1% 576,175 0.4% Sources: U.S. Department of Commerce, Bureau of the Census. 2004. 2002 Economic Census, Industry Series— Shipbuilding and Repair . Washington, DC: Government Printing Office. 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.censu s.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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2-15 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). Sim ilarly, fuels made from petroleum are used to run vehicles and industrial machinery and genera te 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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2-16  Commercial sector—nonmanufacturing or nont ransportation 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 (C 3 H 8 ) and butane (C 4 H 10 ). It is primarily used as a fuel in domestic heating, cooking, and farming operations. Distillate fuel oil Distillate fuel oil includes diesel oil, heating oils, and industrial oils. It is used to power diesel engines in buses, trucks, trains, automobiles, as well as other machinery. Residual fuels Residual fuels are the fuels disti lled from the heavier oils that remain after atmospheric distillation; they find their primary use generating electricity in electric utilities. However, residual fuels can also be used as fuel for ships, industrial boiler fuel, and commercial heating fuel. Petroleum coke Coke is a high carbon residue that is the final product of thermal decomposition in the condensation process in cracking. Coke can be used as a low-ash solid fuel for power plants. Finished Nonfuel Products Coke In addition to use as a fuel, petroleum coke can be used a raw material for many carbon and graphite products such as furnace electrodes and liners. Asphalt Asphalt, used for roads and roofing mate rials, must be inert to most chemicals and weather conditions. Lubricants Lubricants are the result of a special refining process that produce lubricating oil base stocks, which are mixed with various a dditives. 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 C 2 H 4 . It is the most produced organic compound in the world and it is used in the production of many products. For example, one of ethylene’s derivatives is ethylene oxide, which is a primary raw material in the production of detergents. Propylene Propylene is an organic compound with the chemical formula C 3 H 6 . It is primarily used the production of polypropylene, which is used in the production of food packaging, ropes, and textiles. Sources: U.S. Department of Labor, Occupational Sa fety 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_i v/otm_iv_2.html>. As obtained on October 23, 2006. U.S. Department of Energy, Energy Information Administration (EIA). 1999.

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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 transportati on sector, it is currently difficult to switch quickly from one fuel to another without costly and irreversible equipment changes, but other sectors can switch relatively quickly and easily (EIA, 1999a). For example, equipment at large manufacturing plants often can use either residual fuel oil or natural gas. Often coal an d 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. Technolog ical 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 th e U.S. petroleum refining industry, including market structure, firm characteristics, plant lo cation, 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 compet itive, then individual producers cannot raise their

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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 micro economic 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 refine ry 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 av erage costs than firms that are established and produce at higher levels, which will make it mo re 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 diff icult 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 existi ng 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 potentia lly raise their prices above competitive levels with less worry about new firms entering the market to compete away their customers with lower

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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 indust ry, 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-fir m concentration ratios (CR4), eight-firm concentration ratios (CR8), and Herfindahl-Hirschmann indexes (HHI). The CR4s and CR8s measure the percentage of sales accounted for by the top four and eight firms in the industry. The HHIs are the sums of the squared market shares of firms in the industry. These measures of industry concentrated are 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 par tially 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 criteri on for determining market structure based on the values of these concentration ratios. Howe ver, accepted criteria have been established for determining market structure based on the HHIs for use in horizontal merger analyses (U.S. Department of Justice and the Federal Trade Commission, 1992). According to these criteria, industries with HHIs below 1,000 are consid ered 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 hi gher 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 initia lly created during World Wa r II to help manage

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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 Pe troleum 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 geographi c markets were not highly concentrated. PADDs I, II, and III (East Coast, Midwest, and Gulf Coast) were sufficiently connected that they exerted a competitive influence on each other. The HHI for these combined regions was 789 in 2003, indicating a low concentration level. 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 a nd using marketing to establish brand loyalty, manufacturers can raise their prices above marginal cost without losing market share to their competitors. While we saw in Section 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

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2-21 refining businesses producing specialty products fo r small niche markets. As a result, there may be some instances where product differentiatio n 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. Alth ough 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 Re fineries 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) in to finished petroleum pr oducts. 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 wher e 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 info rmation on refineries, su ch 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 signifi cant portion of petroleum refineries are located along the Gulf of Mexico region. The leading petr oleum 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 percen t. 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-

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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 petrol eum 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 crud e oil) by the industry’s operational capacity.

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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 Ut ilization 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/dna v/pet/ pet_pnp_unc_dcu_nus_m.htm>. As obtained on January, 2007. U.S. Energy Information Administration (EIA), “R efinery 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 barrel s 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 Busine sses 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 cumulativ e capacity of processing over 17 million barrels of crude per calendar day (EIA, 2011a). We identified 64 parent companies owning refineries in the United States and were able to collect employment and sales data for 61 (95%) of them. We

3 See Table in 13 CFR 121.201, NAICS code 324110.

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2-25 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 companie s 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.

Figure 2-6 Employment Distribution of Companies Owning Petroleum Refineries (N=61) Sources: Employment Data from Petroleum Refinery Em issions Information Collection, where available, Component 1, OMB Control No. 2060-0657. Hoovers 2011 Online Data, accessed through 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 throug h 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. 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 >1,500Shareoffirms(%)

Number of Employees

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2-26 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 Le xisNexis at University of Virginia’s Alderman Library.

Figure 2-7 Average Revenue of Companies Owning Petroleum Refineries by Employment (N=61) Sources: Employment Data from Petroleum Refinery Em issions 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 throug h 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 webs ites, 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 Le xisNexis at University of Virginia’s Alderman Library. 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

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2-27 Figure 2-8 Revenue Distribution of Large Co mpanies Owning Petroleum Refineries (N=25) Sources: Employment Data from Petroleum Refinery Em issions Information Collection, where available, Component 1, OMB Control No. 2060-0657. Hoovers 2011 Online Data, accessed through Universi ty 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 Privat e 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 Inform ation 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 Le xisNexis at University of Virginia’s Alderman Library. 1 firm 1 firm 23 firms

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

<5 5

‐ 10 10

‐ 50 50

‐ 100 100

‐ 500 500

‐ 1,000 >1,000 Revenue ($milllions)

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2-28 Figure 2-9 Revenue Distribution of Small Compan ies Owning Petroleum Refineries (N=36) Sources: Employment Data from Petroleum Refinery Em issions Information Collection, where available, Component 1, OMB Control No. 2060-0657. Hoovers 2011 Online Data, accessed through 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 Privat e 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 Inform ation 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 Le xisNexis at University of Virginia’s Alderman Library.

Employment, crude capacity, and location inform ation 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)

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2-29 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 competitiv e 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, lubr icants, and other products. A good example of a firm producing niche products is Calumet Special ty 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. Ho wever, the firm’s specialty products unit is its largest unit (Hoovers, 2011 online). Also Ar abian American Development Company’s South Hampton Resources facility specializes in produci ng 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.

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2-30 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). Th ese 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 ***



### 2-31Table 2-9 Characteristics of Small Businesses in the Petroleum Refining IndustryParent CompanyParentCompanyTypeCumulativeCrudeCapacity(bbl/cd)ParentCompanyEmployment(#)Facility NameFacilityCityFacility StateFacility CountyFacilityCountyPopulationDensity (2000)FacilityCountyPopulationDensity (2010)AGE Refining, Inc. Private 14,021 124 AGE Refining Inc San Antonio TX Bexar County 1,117 1,383American Refining Group,Inc.Private 10,000 323AmericanRefining GroupIncBradford PA McKean County 47 44Arabian AmericanDevelopment CoPublic 0 145South HamptonResources Inc.Silsbee TX Hardin County 54 61BTB Refining Private 0 37 Trigeant Ltd.CorpusChristiTX Nueces County 375 406Calcasieu Refining Company Private 78,000 92CalcasieuRefining Co.LakeCharlesLA Calcasieu Parish 171 181Calumet Specialty ProductsPartners, L.P.Public 57,000 654CalumetShreveport LLCShreveport LA Caddo Parish 286 290Calumet Specialty ProductsPartners, L.P.Public 13,020 654CalumetLubricants Co LPCottonValleyLA Caddo Parish 286 290Calumet Specialty ProductsPartners, L.P.Public 8,300 654CalumetLubricants Co LPPrinceton LA Caddo Parish 286 290CHS, Inc. Public 59,600 287Cenex HarvestStatesLaurel MTYellowstoneCounty49 56Connacher Oil and Gas,LimitedPublic 10,000 170Montana RefiningCo.Great Falls MT Cascade County 30 30CVR Energy, Inc. Public 115,700 371CoffeyvilleResourcesRfg&Mktg LLCCoffeyville KSMontgomeryCounty56 55Countrymark Cooperative Private 26,500 425CountrymarkCooperative, Inc.Mt. Vernon IN Posey County 66 63Cross Oil Refining &Marketing, Inc.Private 7,500 110Martin MidstreamPartners LPSmackover AR Union County 44 40Foreland Refining Corp. Private 2,000 27Foreland RefiningCo.Ely NVWhite PineCounty1 1Frontier Oil Corp. Private 47,000 723Frontier RefiningIncCheyenne WY Laramie County 30 34(continued)*** Draft – Do Not Cite, Quote,or Release During Review ***



### 2-32Table 2-9. Characteristics of Small Businessesin the Petroleum Refining Industry (continued)Parent CompanyParentCompanyTypeCumulativeCrudeCapacity(bbl/cd)ParentCompanyEmployment(#)Facility NameFacilityCityFacility StateFacility CountyFacilityCountyPopulationDensity (2000)FacilityCountyPopulationDensity (2010)Frontier Oil Corp. Private 138,000 723 Frontier ElDorado RefiningCoEl Dorado KS Butler County 42 46Garco Energy Private 3,600 16Garco EnergyLLCDouglas WYConverseCounty3 3Gary-Williams EnergyCorporationPrivate 70,000 260WynnewoodRefining Co.Wynnewood OK Garvin County 34 34Goodway Refining, LLC Private 4,100 17GoodwayRefining LLCAtmore ALEscambiaCounty41 41Gulf Atlantic OperationsLLCPrivate 32Gulf AtlanticOperations LLCMobile Bay AL Mobile County 324 336Holly Corporation Public 25,050 1,321Holly Refining &Marketing CoWoodsCrossUT Davis County 785 1,026Holly Corporation Public 105,000 1,321Navajo RefiningCo.Artesia NM Eddy County 12 13Holly Corporation Public 70,300 1,321Holly Refining &Marketing CoTulsa East OK Tulsa County 988 1,058Holly Corporation Public 85,000 1,321Holly Refining &Marketing CoTulsa West OK Tulsa County 988 1,058Hunt Refining Co. Private 36,000 1,100 Hunt Refining Co. Tuscaloosa AL TuscaloosaCounty125 147Hunt Refining Co. Private 11,000 1,100 Hunt SouthlandRefining CoSandersville MS Lamar County 79 112Kern Oil & Refining Co. Private 26,000 346Kern Oil &Refining Co.Bakersfield CA Kern County 81 103Lion Oil Co. Private 75,000 350 Lion Oil Co. El Dorado AR Union County 44 40National CooperativeRefinery AssociationPublic 85,500 612NationalCooperativeRefineryAssociationMcPherson KSMcPhersonCounty33 33NuStar Energy LP Public 70,000 1,492Nustar AsphaltRefining LLCPaulsboro NJ Gloucester 784 895NuStar Energy LP Public 28,000 1,492 Nustar AsphaltRefining LLCSavannah GA Chatham 530 622(continued)*** Draft – Do Not Cite, Quote,or Release During Review ***



### 2-33Table 2-9. Characteristics of Small Businessesin the Petroleum Refining Industry (continued)Parent CompanyParentCompanyTypeCumulativeCrudeCapacity(bbl/cd)ParentCompanyEmployment(#)Facility NameFacilityCityFacility StateFacility CountyFacilityCountyPopulationDensity (2000)FacilityCountyPopulationDensity (2010)Pasadena Refining SystemsInc.Private120,000348Pasadena RefiningSystems Inc.PasadenaTX Harris County 1967 2,402Pelican Refining Co LLC Private033Pelican RefiningCo. LLCLakeCharlesLA Calcasieu Parish 171 181Petro Star Inc. Private 19,700 400 Petro Star Inc. North Pole AKFairbanks NorthStar11 13Petro Star Inc. Private 55,000 400 Petro Star Inc. Valdez AK Valdez Cordova 0.3 0Placid Refining Private 57,000 207Placid RefiningInc.Port Allen LAWest BatonRouge Parish113 124San Joaquin Refining Co. Private 15,000 108San JoaquinRefining Co., Inc.Bakersfield CA Kern County 81 103Santa Maria RefiningCompanyPrivate 9,500 47 Greka Energy Santa Maria CASanta BarbaraCounty146 155Silver Eagle Refining Inc. Private 3,000 60Silver EagleRefiningEvanston WY Uinta County 10 10Silver Eagle Refining Inc. Private 10,250 60Silver EagleRefiningWoodsCrossUT Davis County 785 1,026Somerset Oil Inc. Private 5,500 11Somerset EnergyRefinery LLCSomerset KY Pulaski County 85 96US Oil & Refining Co. Private 38,800 182US Oil & RefiningCo.Tacoma WA Pierce County 417 476Ventura Refining &Transmission, LLCPrivate 12,000 37 Ventura Refining& TransmissionLLCThomas OK Custer County 27 28Western Refining, Inc. Public 122,000 636Western RefiningCompany LPEl Paso TX El Paso County 671 791Western Refining, Inc. Public 66,300 636Western RefiningYorktown IncYorktown VA York County 533 625Western Refining, Inc. Public 16,800 636Western RefiningSouthwest IncBloomfield NM San Juan County 21 24Western Refining, Inc. Public 21,100 636Western RefiningSouthwest IncGallup NMMcKinleyCounty14 13(continued)*** Draft – Do Not Cite, Quote,or Release During Review ***



### 2-34Table 2-9. Characteristics of Small Businessesin the Petroleum Refining Industry (continued)Parent CompanyParentCompanyTypeCumulativeCrudeCapacity(bbl/cd)ParentCompanyEmployment(#)Facility NameFacilityCityFacilityStateFacility CountyFacilityCountyPopulationDensity (2000)FacilityCountyPopulationDensity (2010)World Oil Marketing Co. Private 8,500 65 Lunday-ThagardCo.South Gate CA Los AngelesCounty2,344 2,420Wyoming Refining Co. Private 14,000 96 WyomingRefining CoNew Castle WY Weston County 3 3Total1,875,641 11,264103Sources: U.S. Census Bureau, American Fact Finder, “2010 Census Summary File 1 Population, Housing Units, Area & Density: 2010-County – Census Tract100% Data 2010 Census” (Data accessed on 10/21/2011); http://factfinder2.census.gov/faces/tableservices/jsf/pages/productview.xhtml?ftp=tableHoovers 2011 Online Data, accessed through University of South Carolina’s Moore School of Business Library. Hoovers 2011 Online Data reflectseither actual data for 2010/2011 reported by companies, estimated data for 2011, or occasionally 2009 values.Million Dollar Database online, 2011, accessed through University of South Carolina’s Moore School of Business Library. Million Dollar Online Datareflects either actual data for 2011 reported by companies or estimated data for 2011.Ward’s Business Directory of Public and Private Companies, 2011, accessed at James Branch Cabell Library (Virginia Commonwealth University).Ward’s Business Directory compiles financial data from several sources such as annual reports, company websites, and phone interviews. If financialdata 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 be2010 or 2011.Global Duns Market Identifiers, accessed through LexisNexis at University of Virginia’s Alderman Library.Employment Data from Petroleum Refinery Emissions InformationCollection, 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 andIndividual Refinery as of January 1, 2011 <http://www.eia.gov/petroleum/refinerycapacity/>

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2-

35 Between 2000 and 2004, U.S. consumption of petroleum products increased by 5%. Consumption leveled off by 2007 and dropped by 9% between 2007 and 2009 (Figure 2-10). This reduced growth was primarily the result of less jet fuel, residual fuel, distillate fuel, and other products being consumed in recent years. Consumption of all petroleum products, except for motor gasoline, increased between 2009 and 2010, but the total consumption of petroleum products did not reach 2000-2004 levels. The cumulative decrease in consumption over the 11 year period is 3% (Table 2-10).

Figure 2-10 Total Petroleum Products Supplied (millions of barrels per year) Sources: U.S. Department of Energy . 2011 Energy Information Administ ration (EIA). 1996–2011. “Petroleum Supply Annuals, Volume 1.” (Data accessed on Februa ry 23, 2012) [Source for 2000–2010 numbers.] < http://www.eia.gov/dnav/pet/pet_cons_psup_dc_nus_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

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2-

36 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/pet roleum/data_publications/ petroleum_supply_annual/psa_volume1/psa_volum e1.html>. As obtained on October 31, 2007. U.S. Department of Energy. 201 1 Energy Information Administra tion (EIA). 1996–2011. “Petroleum Supply Annuals, Volume 1.” (Data accessed on Oc tober 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. produc tion 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.e ia.doe.gov/oil_gas/petro leum/data_publications/ petroleum_supply_annual/psa_volume1/psa_volum e1.html>. As obtained on October 31, 2007.

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37 U.S. Department of Energy. 201 1 Energy Information Administra tion (EIA). 1996–2011. “Petroleum Supply Annuals, Volume 1.” (Data accessed on Oct ober 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.

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38 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. 1996–2 011. 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=3366514 23017&_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 Informat ion Administration (EIA).1996–2007. “Petroleum Supply Annuals, Volume 1.” Available at <http://www.e ia.doe.gov/oil_gas/petro leum/data_publications/ petroleum_supply_annual/psa_volume1/psa_volum e1.html>. As obtained on October 31, 2007.

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39 U.S. Department of Energy. 201 1 Energy Information Administratio n (EIA). 1996–2011. “Petroleum Supply Annuals, Volume 1.” (Data accessed on Oct ober 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 Petroleu m 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.e ia.doe.gov/oil_gas/petro leum/data_publications/ petroleum_supply_annual/psa_volume1/psa_volum e1.html>. As obtained on October 31, 2007. U.S. Department of Energy. 201 1 Energy Information Administration (EIA). 1996–2011. “Petroleum Supply Annuals, Volume 1.” (Data accessed on Oc tober 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 consum er of the product. This includes bulk consumers, such as agriculture, industry, and utilities, as well as residential and commercial consumers.

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40 Table 2-15 Average Price of Major Petroleum Pr oducts 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.ei a.doe.gov/dnav/pet/pet_pri_refoth_dcu_nus_m.htm>. As obtained on January 11, 2008. U.S. Department of Energy. 201 1 Energy Information Administra tion (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 receive d 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.

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41 Table 2-16 Producer Price Index Industry Data: 1995 to 2010 Petroleum Refining (NAICS 3241 1) 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.

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42 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 report ed 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 thei r publicly available 2010 income statements. These ratios are presented in Table 2-18.

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43 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 Cor poration 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 Refini ng, 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 Res ources, 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. (D ata 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, 20 11. 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 (E IA’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 assump tions 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 rema in 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 demand ed 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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44 Higher prices and tighter fuel efficiency stan dards (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 Petr oleum 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, Ener gy Information Administration (EIA). 2011. “Annual En ergy 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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45 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, Ener gy Information Administration (EIA). 2011. ”Annual En ergy 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 American Petroleum Institute (API). 2006. “FYI on Refineries: Operating at Record Levels.” Available at <http://new.api.org/abo utoilgas/sectors/refining/upload/ FYI_Refineries.pdf>. As obtained on October 31, 2006. Arizona Clean Fuels. 2007. Company Home Page. Available at <http://www.arizonacleanfuels.com/>. As obtained on February 5, 2007. Arabian American Develop Co., South Hamp ton Resources, Inc. Arabian American Development Co. Q4 & FY2010 Financial Results. (Data accessed on 10/21/11) [Source for 2010 numbers.] <http://www.arabianam ericandev.com/images/uploads/investor/ 2010eoyearningspresentation.pdf> Arabian American Development Co. April 6, 2007. 10K for year ended December 31, 2006. EDGAR Database. Available at <http: //www.sec.gov/Archives/edgar/data/ 7039/000095013407007709/0000950134-07-007709-index.htm>. Calumet Specialty Products Partners, Morningsta r for Calumet Specialty Products Partners 10K. February 22, 2011. 10K for year ended December 31, 2010. (Data accessed on 10/21/11)[Source for 2010 numbers.] <http://quote.morningstar.com/stock-filing/AnnualReport/2010/12/31/t.aspx?t=XNAS:CLMT&ft=10- K&d=c7dd2813722445ded56c7e3aefebf2ca>

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.

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46 Calumet Specialty Products Partners. February 23, 2007. 10K for year ended December 31, 2006. EDGAR Database. Available at <h ttp://www.sec.gov/Archives/edgar/data/ 1340122/000095013407003992/h43776e10vk.htm>. Copyright 2011 Experian Information Solutions, Inc., Experian Business Reports accessed through LexisNexis at James Branch Cabell Library (Virginia Commonwealth University). Copyright 2011 Harte-Hanks Market Intelligence, Inc., All Rights Reserved. CI Technology Database, September 2011. CVR Energy Inc. 2006. Google Finance. Available at <http://finance.google.com/finance?q=NYSE:CVI>. As obtained on February 28, 2008. 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> Dun & Bradstreet Small Business Solutions. Small Business Database. Available at <http://smallbusiness.dnb.com/default.asp?bhcd2=1107465546>. Dun & Bradstreet. 2007. 2007 D&B Million Dollar Directory . Pennsylvania: Dun & Bradstreet Inc. 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/> Federal Trade Commission (FTC). 2004. “The Pe troleum Industry: Mergers, Structural Change, and Antitrust Enforcement.” Availabl e at <http://www.ftc.gov/opa/2004/08/ oilmergersrpt.shtm>. As obtained on February 6, 2007. Gale Research Inc. 2007. Ward’s Business Directory of U.S. Private and Public Companies. Detroit: Gale Research. General Accounting Office (FTC). 2007. “Energ y Markets: Factors That Influence Gasoline Prices.” Available at <http://www.gao.gov/new.items/d07902t.pdf>. As obtained on February 6, 2007. Global Duns Market Identifiers, accessed through LexisNexis at University of Virginia’s Alderman Library. Holly Corporation. March 1, 2007. 10K for year ended December 31, 2006. EDGAR Database. Available at <http://www.sec.gov/Archives/edgar/data/48039/000095013407004555/ d44106e10vk.htm>.

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47 Holly Corporation, EDGAR database for 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> 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 or estimated data for 2011. Hoovers. 2007. Free Content, Company Information. Available at <http://www.hoovers.com/free/>. As obtained on April 11, 2007. Langinier, Corrine. 2004. “Are Patents Strategic Barriers to Entry?” Journal of Economics and Business 56:349-361. MathTech, Inc. 1997. “Industry Profile for the Petroleum Refinery NESHAP.” Available at <http://www.epa.gov/ttnecas1/regdata /IPs/Petroleum%20Refinery%20 (Sulfur%20Recovery%20Units,%20Catalytic%20Crackin.pdf>. As obtained on October 31, 2006. Million Dollar Database online, 2011, accessed through University of South Carolina’s Moore School of Business Li brary. Million Dollar Online Data reflects either actual data for 2011 reported by companies or estimated data for 2011. Nicholson, Walter. 2005. Microeconomic Theory: Basic Principles and Extensions . Mason, OH: South-Western Publishing. Oil & Gas Journal, September 21, 1992. K.S. Eble and J. Feathers, “Process Water Reuse, Part I.” OGJ 1992a

Oil and Gas Journal, December 6, 2010 Petroleum Refinery Emissions Information Coll ection Request, Component 1, OMB Control No. 2060-0657 Reference USA, accessed thru Jefferson Madison Regional Library, Charlottesville, Virginia. Oil and Gas Journal. April 7, 2008.Worldwide Construction Update. Risk Management Association (RMA). 2008. Annual Statement Studies 2007-2008. Pennsylvania: RMA, Inc. Risk Management Association (RMA). 2011. Annual Statement Studies 2010–2011. Pennsylvania: RMA, Inc.

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48 Reuters. July 19, 2007. “U.S. Refinery Expansion Plans.” Available at <http://uk.reuters.com/article/oilRp t/idUKN199746120070719>. As obtained on February 5, 2007. Small Business Administration. 2011. Table of Sm all Business Size Standards. Available at < http://www.sba.gov/sites/default/files/Size_ Standards_Table.pdf>. As obtained October 2011. Speight, James G. 2006. “The Chemistry and Technology of Petroleum.” 4 th Edition, page 178. U.S. Bureau of Labor Statistics (BLS), 2011. “P roducer 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>. U.S. Bureau of Labor Statistics (BLS). 2007. “P roducer Price Index Industry Data: Customizable Industry Data Tables.” Available at <http:/ /www.bls.gov/ppi/>. As obtained on October 11, 2007. U.S. Census Bureau, using American FactFinder; “Sector 31: Annual Survey of Manufacturers: 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, using 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> U.S. Census Bureau, using 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> U.S. Census Bureau, using 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>

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49 U.S. Department of Commerce, Bureau of the Census, FactFinder. 2011. 2009 Annual Survey of Manufactures. 1996–2011. Obtained through American FactFinder Database. (Data accessed on October 14, 2011.) [Source for 2007–2009 numbers] <http://factfinder.census.gov/servlet/DatasetMainPageServlet?_lang=en&_ts=336651423 017&_ds_name=AM0931GS101&_program=EAS>. U.S. Department of Commerce, Bureau of the Census. 1997. 1995 Annual Survey of Manufacturer s. M95(AS)-1. Washington, DC: Government Printing Office. Available at <http://www.census.gov/prod/2/manmin/asm/m95as1.pdf>. As obtained on October 23, 2006. U.S. Department of Commerce, Bureau of the Census. 1998. 1996 Annual Survey of Manufacturer s. M96(AS)-1 (RV). Washington, DC: Government Printing Office. Available at <http://www.censu s.gov/prod/3/98pubs/m96-as1.pdf>. As obtained on October 23, 2006. U.S. Department of Commerce, Bureau of the Census. 2000. “Population Density by County: Census 2000 Summary File 1 (SF 1) 100-Percent Data”. Available through American FactFinder <http://factfinder.census.gov/hom e/saff/main.html?_lang=en>. As obtained on February 21, 2008. U.S. Department of Commerce, Bureau of the Census. 2001. 1999 Annual Survey of Manufacturer s. M99(AS)-1 (RV). Washington, DC: Government Printing Office. Available at <http://www.census.gov/prod/2001pubs/m99-as1.pdf>. As obtained on October 23, 2006. U.S. Department of Commerce, Bureau of the Census. 2003a. 2001 Annual Survey of Manufacturer s. M01(AS)-1. Washington, DC: Government Printing Office. Available at <http://www.census.gov/prod/2003pubs/m01as-1.pdf>. As obtained on October 23, 2006. U.S. Department of Commerce, Bureau of the Census. 2003b. 2001 Annual Survey of Manufacturers . 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. 2004. 2002 Economic Census, Industry Series—Petroleum Refineries . Washington, DC: Government Printing Office. Available at <http://www.census.gov/prod/ec02/ec0231i324110.pdf>. As obtained on October 23, 2006. U.S. Department of Commerce, Bureau of the Census. 2006. 2005 Annual Survey of Manufacturer s. M05(AS)-1. Washington, DC: Government Printing Office. Available at <http://www.census.gov/prod/2005pubs/am0431gs1.pdf>. As obtained on October 23, 2006. U.S. Department of Commerce, Bureau of the Census. 2007. 2006 Annual Survey of Manufacturers. Obtained through American Fact Finder Database <http://factfinder.census.gov/home/saff/main.html?_lang=en>.

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50 U.S. Department of Energy, Energy Information Administration (EIA). 2012. “Petroleum & Other Liquids, Weekly Imports & Exports.” < http://www.eia.gov/dnav/pet/pet_move_wkly_dc_NUS-Z00_mbblpd_4.htm >. U.S. Department of Energy, 2011 Energy Information Administration (EIA). 1996–2011. “Petroleum Supply Annuals, Volume 1.” (Data accessed on October 7, 2011) [Source for 2007–2010 numbers.] <http://www.eia.gov/dnav/pet/pet_sum_snd_d_nus_ mbbl_a_cur.htm>. U.S. Department of Energy, 2011 Energy Information Administration (EIA). 1996–2011. “Petroleum Supply Annuals, Volume 1.” (Data accessed on October 7, 2011) [Source for 2007–2010 numbers.] <http://www.eia.gov/dnav/pet/pet_pnp_refp_dc_nus_ mbbl_a.htm>. U.S. Department of Energy, 2011 Energy Information Administration (EIA). 1996–2011. “Petroleum Supply Annuals, Volume 1.” (Data accessed on October 7, 2011.) [Source for2007–2010 numbers.] <http://www.eia.gov/dnav/pet/pet_move_imp_dc_NUSZ00_mbbl_a.htm> U.S. Department of Energy, 2011 Energy Information Administration (EIA). 1996–2011. “Petroleum Supply Annuals, Volume 1.” (Data accessed on October 7, 2011.) [Source for2007–2010 numbers] <http://www.eia.gov/dnav/pet/pet_move_exp_dc_NUSZ00_mbbl_a.htm>. U.S. Department of Energy, 2011 Energy Information Administration (EIA). 1996–2011. “Petroleum Supply Annuals, Volume 1.” (Data accessed on October 7, 2011.) [Source for 2007–2010 numbers.]<http://www.eia.gov/dnav/pet/pet_pri_refoth_dcu_nus_a.htm>. U.S. Department of Energy, Energy Information Administration (EIA). 1996–2007. “Petroleum Supply Annuals, Volume 1.” Availabl e at <http://www.eia.doe.gov/oil_gas/ petroleum/data_publications/petroleum_supply_annual/psa_volume1/psa_ volume1.html>. As obtained on October 31, 2007. U.S. Department of Energy, Energy Information Administration (EIA). 2006a. “A Primer on Gasoline Prices.” Available at <http ://www.eia.doe.gov/bookshelf/brochures/ gasolinepricesprimer/printerversion.pdf>. As obtained on October 31, 2007. U.S. Department of Energy, Energy Informatio n Administration (EIA). 1999a. “Petroleum: An Energy Profile 1999.” DOE/EIA-0545(99). Available at <http://tonto.eia.doe.gov/ FTPROOT/petroleum/054599.pdf>. As obtained on October 23, 2006. U.S. Department of Energy, Energy Inform ation Administration (EIA). 2006b. “Refinery Capacity Report 2006.” Available at <h ttp://www.eia.doe.gov/oil_gas/petroleum/ data_publications/refinery_capacity_data/ref capacity.html/>. As obta ined on October 23, 2006.

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51 U.S. Department of Energy, Energy Information Administration (EIA). 2006c. “Petroleum Supply Annual 2005, Volume 1.” Available at <http://www.eia.doe.gov/pub/oil_gas/ petroleum/data_publications/petroleum_supp ly_annual/psa_volume1/historical/2005/psa _volume1_2005.html>. As obtained on October 31, 2007. U.S. Department of Energy, Energy Information Administration (EIA). 2007a. “Refinery Utilization and Capacity.” Available at <http://tonto.eia.doe.gov/dnav/pet/ pet_pnp_unc_dcu_nus_m.htm>. As obtained on January 7, 2008. U.S. Department of Energy, Energy Inform ation Administration (EIA). 2007b. “Refiner Petroleum Product Prices by Sales Type.” Available at <http://tonto.eia.doe.gov/ dnav/pet/pet_pri_refoth_dcu_nus_m.htm>. As obtained on January 11, 2008. U.S. Department of Energy, Energy Information Administration (EIA). 2007c. “Annual Energy Outlook.” Available at <http://www.eia.doe. gov/oiaf/archive/aeo07/ pdf/0383(2007).pdf>. As obtained on January 21, 2007. U.S. Department of Energy, Energy Information Administration (EIA). 2010. “Petroleum Supply Annual 2010, Volume 1.” Available at http://www.eia.gov/petroleum/supply/annual/volume1/archive/2010/pdf/table15.pdf

. U.S. Department of Energy, Energy Informa tion Administration (EIA). 2011, “Annual Energy Outlook.” (Data accessed on October 11, 2011) [Source for 2011–2019 numbers.]<http://www.eia.gov/for ecasts/aeo/pdf/0383(2011).pdf>. U.S. Department of Justice and the Federal Trade Commission. 1992. Horizontal Merger Guidelines. Available at <http://www.ftc.gov/ bc/docs/horizmer.htm>. As obtained on October 28, 2006. U.S. Department of Labor, Occupational Safety and Health Administration (OSHA). 2003. OSHA Technical Manual, Section IV: Chapter 2, Petroleum Refining Processes. TED 01- 00-015. Washington, DC: U.S. DOL. Avai lable at <http://www.osha.gov/dts/osta/ otm/otm_iv/otm_iv_2.html>. As obtained on October 23, 2006. U.S. Energy Information Administration (EIA), 2011a. “Refinery Utilization and Capacity.” Available at http://www.eia.gov/dnav/pet/p et_pnp_unc_dcu_nus_a.htm; Release date: 7/28/11; (Data accessed on 10/11/11). [Source for 2007–2010 numbers] U.S. Energy Information Administration (EIA), Form EIA-820, “Annual Refinery Report. Table 1. Number and Capacity of Operable Petroleu m Refineries by PAD District and State as of January 1, 2011” Release Date: June 24, 2011; (Data accessed on 10/12/11). [Source for 2011 numbers.] <http://www.eia.gov/petroleum/refinerycapacity/> U.S. Environmental Protection Agency. 1995. “EPA Office of Compliance Sector Notebook Project: Profile of the Petroleum Refining Industry.” EPA/310-R-95-013. Washington, DC: U.S. EPA. Available at <http://www.epa.gov/compliance/resources/ publications/assistance/sectors/notebooks/petrefsn.pdf>. As obtained on October 23, 2006.

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52 U.S. Environmental Protection Agency. 2006. “Proposed MHA Nation Clean Fuels Refinery.” Available at <http://www.epa.gov/Region8/co mpliance/nepa/refinerydeis.html>. As obtained on February 6, 2007. Ward’s Business Directory of Public and Private Companies, 2011, accessed at James Branch Cabell Library (Virginia Co mmonwealth University). Western Refining, Inc. March 8, 2007. 10K for year ended December 31, 2006. EDGAR Database. Available at <http://www.sec.gov/Archives/edgar/data/1339048/000095 013407005096/h44360e10vk.htm>. Western Refining, Thomson Reuters Western Refining, Inc. 10K. March 8, 2011. 10K for year ended December 31, 2010. (Data accessed on 10/23/11) [Source for 2010 numbers.] <http://phx.corporate-ir.net/phoenix.zhtml?c=194293&p=irol-sec>

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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 requirement s 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 the se final amendments to subpart Ja and the final June 2008 NSPS requirements of 40 CFR part 60, subpart J a (i.e., baseline). The impacts are presented for petroleum refinery fl ares that commence construction, reconstruction or modification over the next 5 years. We anticipat e that there will be 400 a ffected flares over the next 5 years and most of the flares would become affect ed 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 aff ected flares, or 120 flares, either would meet the definition of “emergency flare” in 40 CF R 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 unch anged 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 SO 2 by 3,200 tons per year (tons/yr), NO x by 1,100 tons/yr , VOC by 3,400 tons/yr , and CO 2 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 Deleted: current

Deleted: are assumed to Deleted: are assumed to be Deleted: (approximately 80% of the current population of refinery flares will become affected due to the modification provisions for flares in subpart Ja), or about three flares per refinery, and

Deleted: and Deleted: 2,006,108

Deleted: a cost savings of about $79 million (2006 dollars) due to the

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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 estimate d 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 Recovery 7 380,000 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 [ A 5]: Separate out cost and cost savings

Deleted: Applicability Date

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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 SO 2 /yr) Annual emission reductions (tons NO x /yr) Annual emission reductions

(tons VOC/yr) Cost effectiveness ($/ton emissions reduced) Annual emission reductions (metric tons

CO 2 /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 Anal y sis/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 SO 2 by 2,820 tons/yr, NO x by 56 tons/yr, VOC by 730 tons/yr, and CO 2 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 ga s 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 flar es, 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 estim ated 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 combusti on 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 indi cated, for this analysis we anticipate that there will be 400 affected flares that will be subject to this final rule. Deleted: Applicability Date

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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 NO x 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 se parate 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 NO x 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 wasbased on the performance of advanced combustion monitoring controls in conjunction with ultralow NO x 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 th e emission reductions estimated for the two different types of process heaters as a means to bound the range of anticipated NO x emission reductions to be from 7,100 to 8,600 tons/yr in the fifth year after promulgation (see Revised NO x 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 Formatted: Font: Times New Roman

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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 sh ould 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 antic ipate 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 es timated 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 discussi on 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 recovery systems at 10 percent of the 400 flares, or at approximately 40 flares. We assume that a

9 These guidelines are currently under review by the Agency. Deleted: approximately Deleted: average Deleted: would be minor Deleted: because of the estimated cost savings

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4-2 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

T he 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 purchas es is $168 million. Using these figures, we estimate the implied rate of return for actions no t required by the rule to be 90 percent and the overall rate of return to be 80 percent. T he 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 government intervention. The cost analysis of this RIA nevertheless is based on the observation that process actions (i.e., installation of a flare ga s recovery system) that appear to be profitable

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.” Deleted: While t Deleted: by refineries that install flare gas recovery systems

Deleted: of the entire rule Deleted: 80

Deleted: Meanwhile, t

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4-3 in our analysis have not been widely adopted. One explanation for why there appears to be negative cost control technologies that are not ge nerally 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 thes e process improvements is not reflected in the engineering cost estimates. Because of the high vo latility 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 woul d 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 re quires refiners to conduct a thorough review of the flare system so that flare gas recovery syst ems 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 The Regulatory Flexibility Act (RFA) as am ended by the Small Business Regulatory Enforcement Fairness Act (SBREFA) generally requires an agency to prepare a regulatory

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4-4 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 substa ntial number of small entities. Small entities include small businesses, small gov ernmental jurisdictions, and smal l 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 appli cation of the definitio n 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-sale s ratio, or the “sales test.” The “sales test” is the impact methodology EPA employs in analyzing small entity impacts as opposed to a “profits test,” in which annualized compliance costs are calculated as a share of profits. The sales test is frequently used because revenues or sales data are commonly available for entities impacted by EPA regulations, and profits data normally made available are often not the true profit earned by

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 firms because of accounting and tax considerations . The use of a “sales test” for estimating small business impacts for a rulemaking is co nsistent with guidance offered by EPA on compliance with the RFA 12 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 contin ental 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 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.

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> 13 U.S. SBA, Office of Advocacy. A Guide for Governme nt Agencies, How to Comply with the Regulatory Flexibility Act, Implementing the President’s Small Bu siness Agenda and Executive Order 13272, June 2010. 14 The U.S. Census Bureau’s Statistics of U.S. Busi nesses 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 ow nership or control. The firm and the establishment are the same for single-establishment firms. For each multi-es tablishment 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 spec ified 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 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 im pacts on small refiners. At present to better identify disproportionate imp acts, 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 an d 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 im pacts 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 th e 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 co st-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 fi rms 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).

Table 4-3 Summary of Sales Test Ratios for Firms Affected by Proposed NSPS Amendments Deleted: Table 4- Deleted: Table 4-

Deleted: Table 4- Deleted: Table 4-

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4-7 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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4-7 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/f rstables.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. Formatted: Font: Not Bold

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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 re quirements 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 provi sion 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 orenvironmental 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 Re gulations 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 supp ly, 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 t oday’s action is not a “significant energy action” as defined in Executive Order 13211. Deleted: Because Deleted: is Deleted: 80 percent of the estimated annual cost of the proposed amendments is associated with voluntarily installing flare gas recovery systems and because the remaining costs are not significant,

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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 PM 2.5 precursors including SO 2 , NOx, and VOCs, as well as climate benefits associated with reducing emissions of CO 2 . SO 2 , NOx, and VOCs are precursors to PM 2.5 , 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 PM 2.5 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 possibl e 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 NO 2 and SO 2 , ozone exposure, ecosystem effects, and visibility impairment. 6.1 Calculation of PM 2.5 -Related Human Health Benefits

This final NSPS Reconsideration would reduce emissions of SO 2 , NO X , and VOCs. Because these emissions are precursors to PM 2.5, reducing these emissions would also reduce PM 2.5 formation, human exposure and the incidence of PM 2.5 -related health effects. Due to analytical limitations, it was not possible to provide a comprehensive estimate of PM 2.5 -related benefits or provide estimates of the health be nefits associated with direct exposure to SO 2 and NOx or exposure to ozone. Instead, we used the “benefit-per-ton” approach to estimate these benefits. The methodology employed in this analys is 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 PM 2.5 -related health benefits for emissions reductions in specific sectors. The key assumptions are described in detail below. These PM 2.5 benefit-per-ton estimates provide the total monetized human health benefits (the sum of premature mortality and premature morbidity) of reducing one ton of PM 2.5 from a specified source. EPA has used the Deleted: in the fifth year (2017)

Deleted: would

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6-2 benefit per-ton technique in several previous RIAs, including the recent SO 2 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 PM 2.5, which include premature morality and a variety of morbidity effects asso ciated 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 unquan tified health effects associated with exposure to ozone, SO 2 , and NOx nor welfare effects such as eco system 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 PM 2.5

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 PM 2.5 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 PM 2.5 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 cerebrovasc ular disease (age 50-79) -- -- Section 5.4 Other cardiovascular effects (e.g., other ages) -- -- PM ISA 2 Other respiratory effects (e.g., pulmonaryfunction, non-asthma ER visits, nonbronchitis chronic diseases, other ages and populations) -- -- PM ISA 2 Reproductive and developmental effects (e.g., low birth weight, pre-term births, etc) -- -- PM ISA 2,3 Cancer, mutagenicity, and genotoxicity effects -- -- PM ISA 2,3

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 ev idence 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 repor ted 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 concentratio n-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/m 3 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 PM 2.5 NAAQS, has been used as an alternative estimate in the PM 2.5 NAAQS RIA and PM 2.5 benefits estimates in RIAs completed since the PM 2.5 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/m 3 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 PM 2.5 -mortality relationship and interpreted for benefits analysis in EPA’s final RIA for the PM 2.5 NAAQS. For that study, twelve experts (labeled A through L) provided independent estimates of the PM 2.5 -mortality concentration-response function. EPA practice has been to develop independent estimates of PM 2.5 -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 calcu lated 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 rela tionship between exposure to PM 2.5 and premature mortality (Roman et al., 2008). 16 Within this assessment, we include the benefits estimates derived from the

15 These two studies specify multi-pollutant models that control for SO 2 , among other co-pollutants. 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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6-5 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 PM 2.5 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 PM 2.5 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 combinatio ns, 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 es timates 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 popu lation 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 calcu lated for this sector separately for SO 2 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 becau se the scientific evidence is not yet sufficient to allow differentiation of effects estimates by particle type. SO 2 and NOx are the primary PM 2.5 precursors affected by this rule. 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 PM 2.5 levels, which drive population exposure. The sectorspecific modeling does not provide estimates of the PM 2.5 -related benefits associated with Deleted: While the air quality data used in Fann, Fulcher, and Hubbell (2009) reflects broad pollutant/source category combinations, the source apportionment modeling data used in this analysis issector-specific. As a result, the benefitper-ton estimates presented herein better reflect the geographic areas and population likely to be affected by the proposed rule.

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6-6 reducing VOC emissions, but these unquantified be nefits are generally small compared to other PM 2.5 precursors (U.S. EPA, 2012). The benefit-per-ton coefficients in this analys is 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 with out 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 PM 2.5 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 consis tently 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 PM 2.5 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 coho rt studies that estimate PM-related mortality. While an LML assessment provides some insight in to the level of uncerta inty in the estimatedPM 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 PM 2.5 -related effects down to the lowest LML of the major cohort studies, which is 5.8 μg/m 3 . Just because we have greater confidence in the

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 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 PM 2.5 -mortality relationship, see the Technical Support Document (TSD) entitled Summary of Expert Opinions on the Existence of a Threshold in the ConcentrationResponse Function for PM 2.5 -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 PM 2.5 level. However, we believe that it is still important to ch aracterize the distributi on of exposure to baseline air quality levels. As a surrogate measure of mortality impacts, we provide the percentage of the population exposed at each PM 2.5 level using the source apportionment modeling used to calculate the benefit-per-ton estimates for this sector. It is im portant 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 (2 004-2008), 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 studi es. OAR arrived at a VSL using a range of $1 million to $10 million (2000$) consistent with tw o 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 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

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.

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6-8 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 re port 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 thos e 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 cont rols may lead to reductions in ambient PM 2.5 below the National Ambient Air Quality Standards (NAAQS) for PM in some areas and assist other areas with attaining the PM NAAQS. Be cause the PM NAAQS RIAs also calculate PM benefits, there are important differences worth noti ng in the design and analytical objectives of each RIA. The NAAQS RIAs illustrate the potentia l 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 pr edict, the control strategies that States may

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 va luation guidance would be forthcoming in the near future. Therefore, this report does not re present final agency policy. 20 In this analysis, we adjust the VSL to account for a different currency y ear ($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 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 regula tions 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 PM 2.5 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 rule s 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 forwar d 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 SO 2 NAAQS RIA (U.S. EPA, 2010a).

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6-10 Figure 6.1 illustrates the relative breakdown of the monetized PM 2.5 health benefits.

Figure 6-1: Breakdown of Monetized PM 2.5 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 us ing 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 be nefits 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 infa rctions (AMIs) and premature mortality. For AMIs, we assume 5 years of follow-up medical costs and lost wage s. For premature mortality, we assume that there is a “cessation” lag between PM exposures and the total rea lization of changes in health effects. Although the structure of the lag is uncertain, EPA follows the advi ce 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 PM 2.5 (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 va luation of premature mortalities that o ccur after the analys is year. As such, the monetized benefits using a 7% discount rate are onl y 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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6-11 6-2 provides a visual representation of the range of PM 2.5 -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 PM 2.5 Precursors SO 2 2,600 $65,000 $160,000 $58,000 $140,000 $170 to $410 $150 to $370 NO X 50 $6,400 $16,000 $5,700 $14,000 $.32 to $.79 $.29 to $.71 Total $170 to $410 $150 to $370

Large Flares PM 2.5 Precursors SO 2 660 $65,000 $160,000 $58,000 $140,000 $43 to $100 $38 to $94 NO X 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 PM 2.5 Precursors SO 2 3,200 $65,000 $160,000 $58,000 $140,000 $210 to $510 $190 to $460 NO X 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 SO 2 and NOx, ozone exposure, ecosystem effects, or visibility impairment. These estimates do not include CO 2 benefits estimated at $4 6 million (3% discount rate). All fine pa rticles are assumed to have equivalent health effects, but the benefit per ton estimates vary becau se each ton of precursor redu ced has a different propensity to form PM 2.5 . 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. Deleted: 9

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6-12 Table 6- 3 : Summary of Reductions in Health Incidences from PM 2.5 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 effect s 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. Deleted: 34

Deleted: ¶

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6-13 Table 6- 4 : All PM 2.5 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 CO 2 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 estimate s associated with the concentration-response function. Confidence intervals are unavailable for this analysis because of the benefit-per-ton methodology Deleted: 54

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6-14 Figure 6-2: Monetized PM 2.5 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 fro m the studies or expert elicitation; rather, the estimates are based in part on the concentration-response function pr ovided in those studies. These estimates do not include CO 2 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 (CO 2 ) 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$)

PM 2.5 mortality benefits estimates derived from 2 epidemiology functions and 12 expert functions 3% DR 7% DR

Deleted: Total

Deleted: 49

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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 CO 2 emissions 23 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 S CC 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.

22 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 En vironmental 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 23 The interagency group decided that these estimates apply only to CO 2 emissions. Given that warming profiles and impacts other than temperature cha nge (e.g., ocean acidification) vary across GHGs, the group concluded “transforming gases into CO 2 -equivalents using GWP, and then multiplying the carbon-equivalents by the SCC, would not result in accurate estimates of the social costs of non-CO 2 gases” (SCC TSD, pg 13).

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6-16 Table 6-5. Social Cost of Carbon (SCC) Estimates (per tonne of CO 2 ) for 2017 a Discount Rate and Statistic SCC estimate (2006$) 5% (Average) $5.9 3% (Average) $24.1 2.5% (Average) $38.6 3% (95 th 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 Scien ce (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 climat e system, (3) the impact of changes in climate on the physical and biological environment, a nd (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, eco nomics, and ethics and should be viewed as provisional. The interagency group noted a number of limitations to the SCC analysis, including theincomplete way in which the integrated assessment models capture catastrophic and noncatastrophic impacts, their incomplete treatme nt 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 Fede ral 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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6-17 Applying the global SCC estimates to the estimated reductions in CO 2 emissions for the range of policy scenarios, we estimate the dollar va lue of the climate-relate d 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 CO 2 Emission Reductions in 2017 a,b

Discount Rate and Statistic Monetized Climate Benefits w ith flare gas recovery (millions of 2006$) Monetized Climate Benefits without flare gas recovery (millions of 2006$)

Tonnes of CO 2 1,900,000 110,000 5% (Average) $11 $0.6 3% (Average) $46 $2.6 2.5% (Average) $73 $4.2 3% (95 th 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 CO 2 emission reductions in this table reflect the an ticipated 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 emissi ons of pollutants from electric utility boilers (EGU boilers) that supply electricity to th e non-EGU boiler facilities by 104,381 tonnes CO 2 . In the calculation of CO 2 benefits, we have already subtracted these CO 2 emission increases associated with increased electricity usage from the CO 2 emission reductions associated with the regulatory requirements in the benefits shown in Table 6-6.

24 It is possible that other benefits or cost s of proposed regulations unrelated to CO 2 emissions will be discounted at rates that differ from those used to develop the SCC estimates. 25 As 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 es timates. 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. Deleted: (millions of 2006$) Moved down [1]: With flare gas recovery¶ Moved (insertion) [1] Deleted: W Deleted: 1,901,727

Deleted: $141

Deleted: have been reduced from 2,006,108 tonnes to

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6-18 6.4 Total Monetized Benefits The total monetized benefits of this rulema king include both the PM-related health benefits as well as the CO 2 -related climate benefits. We estim ate 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 di scount rate for climate benefits). All estimates are in 2006 dollars for the year 2017.

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% Deleted: in the fifth year (2017)

Deleted: a

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6-19 Figure 6-4: Breakdown of Monetized Benefi ts for Final Petroleum Refineries NSPS Reconsideration by Requirement and Flare Size 6.5 Unquantified Benefits 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 SO 2 and NOx, ozone exposure, ecosystem effects, and visibility impairment. NO x and SO 2 emissions also contribute to adverse welfare effects, in cluding acidic deposition in aquatic and terrestrial ecosystems and visibility impairment. 6.5.1 Additional SO 2 and NO 2 Benefits In addition to being a precursor to PM 2.5 , SO 2 and NO x emissions are also associated with a variety of respiratory health effects. Unfortunately, we were unable to estimate the health benefits associated with reduced SO 2 and NO 2 exposure in this analysis because we do not have air quality modeling data available. Therefore, this analysis only quantifies and monetizes the PM 2.5 benefits associated with the reductions in SO 2 and NO 2 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 Flare Gas Recovery

28% SO 2 RCA/CA

71% Flow Rate RCA/CA

1.2%

Flare Monitoring 0% Flare Management Plans 0% Small flares 65% Large flares 35% Deleted: ¶

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6-20 effects and short-term exposure to SO 2 (U.S. EPA, 2008b). According to summary of the ISA in EPA’s risk and exposure assessment (REA) for the SO 2 NAAQS, “the immediate effect of SO 2 on the respiratory system in humans is bronchoconstriction” (U.S. EPA, 2009b). Asthmatics are more sensitive to the effects of SO 2 likely resulting from preexisting inflammation associated with this disease. A clear concentration-re sponse relationship has been demonstrated in laboratory studies following exposures to SO 2 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 SO 2 ISA identified as a “causal relationship”: asthma exacerbation, respiratory-related emergency department visits, and respiratory-related hospita lizations. The differing evidence and associated strength of the evidence for these differen t effects is described in detail in the SO 2 ISA. The SO 2 ISA also concluded that the relationship between short-term SO 2 exposure and premature mortality was “suggestive of a causal relationship” because it is difficult to attribute the mortality risk effects to SO 2 alone. Although the SO 2 ISA stated that studies are generally consistent in reporting a relationship between SO 2 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 likely causal relationship between respiratory health effects and short-term exposure to NO 2 (U.S. EPA, 2008c). Persons with preexisting respiratory disease, children, and older adults may be more susceptible to the effects of NO 2 exposure. Based on our review of this information, we identified four short-term morbidity endpoints that the NO 2 ISA identified as a “likely causal relationship”: asthma exacerbation, respiratory-related emergency department visits, and respiratory-related hospitalizations. The diffe ring evidence and associated strength of the evidence for these different effects is described in detail in the NO 2 ISA. The NO 2 ISA also concluded that the relationship between short-term NO 2 exposure and premature mortality was “suggestive but not sufficient to infer a causal rela tionship” because it is difficult to attribute the mortality risk effects to NO 2 alone. Although the NO 2 ISA stated that studies consistently reported a relationship between NO 2 exposure and mortality, the effect was generally smaller than that for other pollutants such as PM.

SO 2 and NOx emissions also contribute to a va riety of adverse welfare effects, including acidic deposition, visibility impairment, nutrient enrichment (NOx only) and enhanced mercury methylation (SO 2 only). Deposition of sulfur and nitrog en causes acidification, which can cause a loss of biodiversity of fishes, zooplankton, and macro invertebrates in aquatic ecosystems, as

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6-21 well as a decline in sensitive tree species, such as red spruce ( Picea rubens ) and sugar maple ( Acer saccharum ) in terrestrial ecosystems. In the nort heastern 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. Bi ological 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, incl uding declines in hab itat 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, particular ly fish and shellfish production, and a variety of cultural ecosystem services, including water-based recreational and aesthetic services. Terrestrial nutrient enrichme nt is associated with changes in the types and number of species and biodiversity in terrestria l 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 re sults in methylmercury accumula tion in fish (Drevnick et al., 2007; Munthe et al, 2007). The NOx/SO x 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 SO 2 and NO x emissions and the secondary formation of PM 2.5 would improve the level of visibility throughout the United Stat es. Fine particles with significant light-

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6-22 extinction efficiencies include sulfates, nitrates, organic carbon, elemental carbon, and soil (Sisler, 1996). These suspended particles a nd gases degrade visibility by scattering and absorbing light. Higher visibility impairment le vels 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 contribu tor 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 epidemiol ogical studies (U.S. EPA, 2006c). These health effects include respiratory morbidity such as fewe r asthma attacks, hospital and ER visits, school loss days, as well as premature mortality. 6.5.3 Visibility Impairment Reducing secondary formation of PM 2.5 would improve visibility throughout the U.S. Fine particles with significant light-extinction efficiencies include sulf ates, nitrates, organic carbon, elemental carbon, and soil (Sisler, 1996). Suspended particles and gases degrade visibility by scattering and abso rbing 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 dire ct 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 ar e 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.

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6-23 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 paramete rs 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 PM 2.5 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 reduc tions and specific air quality and benefits modeling assumptions. For example, these estimate s do not reflect local variability in population density, meteorology, exposure, baseline health in cidence rates, or other local factors. Use of these $/ton values to estimate benefits associat ed with different emission control programs (e.g., for reducing emissions from large stationary sour ces 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 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.

PM 2.5 mortality benefits are the largest benef it category that we monetized in this analysis. To better characterize the uncertainty associated with mortality impacts that are estimated to occur in areas wi th low baseline levels of PM 2.5 , 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 pe rcentage of premature mortality associated with this specific rule’s emission reductions at each PM 2.5 level. As a surrogate measure of mortality impacts, we provide the percentage of the population exposed at each PM 2.5 level using the source apportionment modeling used to calculate th e 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

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6-24 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 PM 2.5 levels at or above the LML. Using the Pope et al. (2002) study, the 77% of the population is exposed to annual mean PM 2.5 levels at or above the LML of 7.5 μg/m 3 . Using the Laden et al. (2006) study, 25% of the population is exposed above the LML of 10 μg/m 3

. As we model avoided premature deaths among populations exposed to levels of PM 2.5 , we have lower confidence in levels below the LML for each study. It is important to emphasize that we have high confidence in PM 2.5 -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 o ccurs below the level of the National Ambient Air Quality Standard (NAAQS) for annual PM 2.5 at 15 μg/m 3 , which was set 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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6-25 Figure 6-5. Percentage of Adult Population by Annual Mean PM 2.5 Exposure in the Baseline

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6-26 Figure 6-6. Cumulative Distribution of Adult Population by Annual Mean PM 2.5 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. PM 2.5 benefits were derived through benefit per-ton estimates, which do not reflect local variability in population density, meteorology, exposure, baseline healthincidence rates, or other local factors that might lead to an over-estimate or underestimate of the actual be nefits 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 es timate the proportion of benefits occurring in different locations, such as designated nonattainment areas. In addition, the benefit-per-ton estimates are based on emissi ons from existing sources. To the extent

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6-27 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, rega rdless of their chemical composition, are equally potent in causing premature mortality. This is an important assumption, because PM 2.5 produced via transported precursors emitted from EGUs may differ significantly from direct PM 2.5 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 functio n for fine particles is linear down to the lowest air quality levels modeled in this an alysis. Thus, the estimates include health benefits from reducing fine particles in areas with varied concentrations of PM 2.5, 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 PM 2.5 and premature mortality (which typically accounts for 85% to 95% of total monetized benefits), we include a set of twelve estimates based on re sults of the expert elicitation study in addition to our core estimates. Even th ese 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 PM 2.5 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 PM 2.5 benefits, please consult the PM 2.5 NAAQS RIA (Table 5.5).

This RIA does not include the type of deta iled 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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6-28 6.7 References Fann, N., C.M. Fulcher, B.J. Hubbell. 2009. “The influence of location, source, and emission type in estimates of the human health bene fits of reducing a ton of air pollution.” Air Qual Atmos Health 2:169–176. Kochi, I., B. Hubbell, and R. Kramer. 2006. “An Empirical Bayes Approach to Combining Estimates of the Value of Statistical Life for Environmental Policy Analysis .” Environmental and Resource Economics. 34: 385-406. Krewski D, Jerrett M, Burnett RT, Ma R, Hughes E, Shi, Y, et al. 2009. Extended follow-up and spatial analysis of the American Cancer Soci ety study linking particulate air pollution and mortality. HEI Research Report, 140, Health Effects Institute, Boston, MA. Laden, F., J. Schwartz, F.E. Speizer, and D.W. Dockery. 2006. Reduction in Fine Particulate Air Pollution and Mortality. American Journal of Respirat ory and Critical Care Medicine. 173: 667-672. Mrozek, J.R., and L.O. Taylor. 2002. “What Determines the Value of Life? A Meta-Analysis.” Journal of Policy Analysis and Management 21(2):253-270. National Research Council (NRC). 2002. Estimating the Public Health Benefits of Proposed Air Pollution Regulations . Washington, DC: The National Academies Press. National Research Council (NRC). 2009. Hidden Costs of Energy: Unpriced Consequences of Energy Production and Use. National Academies Press. Washington, DC. Office of Management and Budget (OMB). 2003. Circular A-4: Regulatory Analysis. Washington, DC. Available on the Internet at http://www.whitehouse.gov/omb/circulars/a004/a-4.html

. 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. Roman, Henry A., Katherine D. Walker, Tyra L. Walsh, Lisa Conner, Harvey M. Richmond, Bryan J. Hubbell, and Patrick L. Kinney. 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. Sisler, J.F. 1996. Spatial and seasonal patterns and long-term variability of the composition of the haze in the United States: an analysis of data from the IMPROVE network . CIRA Report, ISSN 0737-5352-32, Colorado State University.

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6-29 U.S. Environmental Protection Agency (U.S. EPA). 2000. Guidelines for Preparing Economic Analyses. EPA 240-R-00-003. National Center for Environmental Economics, Office of Policy Economics and Innovation. Washington, DC. September. Available on the Internet at < http://yosemite.epa.gov/ee/epa/eed.nsf/web pages/Guidelines.html/$file/cover.pdf >. U.S. Environmental Protection Agency. 2006. Regulatory Impact Analysis, 2006 National Ambient Air Quality Standards for Particulate Matter , Chapter 5. Available at < http://www.epa.gov/ttn/ecas/regdata /RIAs/Chapter%205--Benefits.pdf >. U.S. Environmental Protection Agency. 2008a. Regulatory Impact Analysis, 2008 National Ambient Air Quality Standa rds for Ground-level Ozone , Chapter 6. Available at < http://www.epa.gov/ttn/ecas/regda ta/RIAs/6-ozoneriachapter6.pdf >. U.S. Environmental Protection Agency (U.S. EPA). 2008b. Integrated Science Assessment for Sulfur Oxides—Health Criteria (Final Report). National Center for Environmental Assessment, Research Triangle Park, NC. Available at <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=198843>. U.S. Environmental Protection Agency (U.S. EPA). 2008c. Integrated Science Assessment for Oxides of Nitrogen - Health Criteria (Final Report). National Center for Environmental Assessment, Research Triangle Park, NC. July. Available at at <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=194645>. U.S. Environmental Protection Agency (U.S. EPA). 2008d. Integrated Science Assessment for Oxides of Nitrogen and Sulfur–Ecological Criteria National (Final Report). National Center for Environmental Assessment, Research Tria ngle Park, NC. EPA/600/R-08/139. December. Available at <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=201485>. U.S. Environmental Protection Agency (U.S. EPA). 2009a . Regulatory Impact Analysis: National Emission Standards for Hazardous Air Pollutants from the Portland Cement Manufacturing Industry . Office of Air Quality Planning and Standards, Research Triangle Park, NC. April. Available on the Internet at < http://www.epa.gov/ttn/ecas/regdata /RIAs/portlandcementria_4-20-09.pdf >. U.S. Environmental Protection Agency (U.S. EPA). 2009b. Integrated Science Assessment for Particulate Matter (Final Report) . EPA-600-R-08-139F. National Center for Environmental Assessment – RTP Division. December. Available on the Internet at < http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546 >. U.S. Environmental Protection Agency (U.S. EPA). 2010a. Final Regulatory Impact Analysis (RIA) for the SO 2 National Ambient Air Quality Standards (NAAQS). Office of Air Quality Planning and Standards, Research Triangle Park, NC. June. Available at <http://www.epa.gov/ttn/ecas/ria.html>. U.S. Environmental Protection Agency (U.S. EPA). 2010b. Technical Support Document: Summary of Expert Opinions on the Existence of a Threshold in the Concentration-Response

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6-30 Function for PM 2.5 -related Mortality . Research Triangle Park, NC. June. Available on the Internet at <www.epa.gov/ttn/ecas/regdata/Benefits/threshold s tsd.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 Policy Economics and Innovation. Washington, DC. December. Available on the Internet at < http://yosemite.epa.gov/ee/epa/eerm.nsf/ vwAN/EE-0568-50.pdf/$file/EE-0568-50.pdf >. U.S. Environmental Protection Agency (U.S. EPA). 2011a. The Benefits and Costs of the Clean Air Act from 1990 to 2020 . Office of Air and Radiation, Washington, DC. March. <http://www.epa.gov/air/sect812/feb11/fullreport.pdf>. Accessed March 30, 2011. U.S. Environmental Protection Agency (U.S. EPA). 2011b. Regulatory Impact Analysis for the Final Transport Rule . Office of Air Quality Planning and Standards, Research Triangle Park, NC. June. Available at <http://www .epa.gov/airtransport/pdfs/FinalRIA.pdf>. U.S. Environmental Protection Agency (U.S. EPA). 2012. Technical Support Document: Estimating the Benefit per ton of Reducing PM 2.5 Precursors from the Petroleum Refineries Sector . Office of Air Quality Planning and Standards, Research Triangle Park, NC. January. U.S. Environmental Protection Agency - Science Advisory Board (U.S. EPA-SAB). 2007. SAB Advisory on EPA’s Issues in Va luing Mortality Risk Reduction. EPA-SAB-08-001. October. Available on the Internet at < http://yosemite.epa.gov/sab/sabproduct.nsf/4128007E7876B8F0852573760058A978/$File/ sab-08-001.pdf >. U.S. Environmental Protection Agency - Science Advisory Board (U.S. EPA-SAB). 2009a. Review of EPA’s Integrated Science Assessm ent 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/$File/EPA-CASAC-09-008-unsigned.pdf >. U.S. Environmental Protection Agency - Science Advisory Board (U.S. EPA-SAB). 2009b. Consultation on EPA’s Particulate Matter Na tional Ambient Air Quality Standards: Scope and Methods Plan for Health Risk and Exposure Assessment. EPA-COUNCIL-09-009. May. Available on the Internet at < http://yosemite.epa.gov/sab/SABPRODUCT.NSF/81e39f4c09954fcb85256ead006be86e/72 3FE644C5D758DF852575BD00763A32/$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.

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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 a nd $240 million to $520 million at a 7% discount rate in 2017. The annualized costs are a cost savings of $79 mi llion 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 PM 2.5 mortality functions at the 3% discount rate, a nd 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 taki ng 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) a nd $88 million to $150 million (7% discount rate for health benefits and 3-percent discount rate for climate benefits). All estimates are in 2006 dollars for the year 2017.*** Draft – Do Not Cite, Quote, or Release During Review ***7-2Table7-1. National Incremental Cost Impacts, Emission Reductions, and Cost Effectiveness for Petroleum Refinery Flares Subject toAmended Standards Under 40 CFR part 60, subpart Ja (Fifth Year After Effective Date of Final Rule Amendments)1Subpart JaRequirementsTotalcapitalcost(millions)Totalannual costwithoutcredit(millions/yr)Naturalgasoffset/productrecoverycredit(millions)Totalannual cost(millions/yr)Annualemissionreductions(tonsSO2/yr)Annualemissionreductions(tonsNOX/yr)Annualemissionreductions(tonsVOC/yr)Costeffectiveness($/tonemissionsreduced)Annualemissionreductions(metrictonsCO2/yr)2MonetizedBenefits(millions, 3%discount rate forhealth andclimate benefits)MonetizedBenefits(millions, 3%discount rate forhealth and 7%for climatebenefits)

Small FlaresFlareMonitoring$72$12$0$120000$0to$0$0to$0Flare gasrecovery$0$0$0$00000$0to$0$0to$0FlareManagement$0$0.79$0$0.7900270$2,9000$0to$0$0to$0SO2 RCA/CA$0$1.9$0$1.92,60000$7600$170to$410$150to$370FlowrateRCA/CA$0$0.90-$6.7-$5.83.450390-$13,00098,000$2.9to$3.7$2.9to$3.6Total$72$16-$6.7$9.02,60050660$2,70098,000$170to$410$150to$370

Large FlaresFlareMonitoring$12$2.0$0$2.00000$0to$0$0to$0Flare gasrecovery$380$78-$170-$903801,1002,700-$22,0001,800,000$74to$120$71to$110FlareManagement$0$0.088$0$0.0880030$2,9000$0to$0$0to$0SO2 RCA/CA$0$0.22$0$0.2229000$7600$18to$45$17to$41FlowrateRCA/CA$0$0.10-$0.74-$0.640643-$13,00011,000$0to$0$0to$0Total$390$81-$170-$886601,1002,800-$20,0001,800,000$93to$160$88to$150

All FlaresFlareMonitoring$84$14$0$140000$0to$0$0to$0Flare gasrecovery$380$78-$170-$903801,1002,700-$22,0001,800,000$74to$120$71to$110FlareManagement$0$0.88$0$0.8800300$2,9000$0to$0$0to$0SO2 RCA/CA$0$2.2$0$2.22,90000$7600$180to$450$170to$410FlowrateRCA/CA$0$1.00-$7.4-$6.43.456430-$13,000110,000$3.2to$4.0$3.1to$3.9Total$460$96-$180-$793,2001,1003,400-$10,0001,900,000$260to$580$240to$5201All estimates are for the implementation year (2017), and are rounded to two significant figures.2The emission reductions of CO2reflect the anticipated emission increases associated with the energy disbenefits from additional electricity consumption.Formatted:Indent: Before: 0"

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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 Benefits 2 $260 to $580 $240 to $520 Total Compliance Costs 3 -$79 -$79 Net Benefits $340 to $660 $320 to $600

Non-monetized Benefits Health effects from ozone, SO 2 , NO 2 exposure Health effects from PM 2.5 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 heal th benefits associated with reducing exposure to PM 2.5 through

reductions of PM 2.5 precursors such as NOx and SO 2 as well as CO 2 benefits. It is important to note that the monetized benefits do not include the reduced health effects from direct exposure to SO 2 and NOx, ozone exposure, ecosystem effects, or visibility impairment. Huma n 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 mort ality because the scientific evidence is not yet sufficient to allow differentiation of effects estimates by particle type. The net present value of reduced CO 2 emissions is calculated differently th an 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. Deleted: 1

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7-4 Figure 7-1. Net Benefits for Final Petroleu m Refineries NSPS Reconsideration at 3% discount rate* *Net Benefits are quantified in terms of PM 2.5 and CO 2 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

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7-5 Figure 7-2. Net Benefits for Final Petroleu m Refineries NSPS Reconsideration at 7% discount rate* *Net Benefits are quantified in terms of PM 2.5 benefits at a 7% discount rate and CO 2 benefits at a 3% discount rate for 2017. This graph shows 14 benefits estimates combined w ith 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

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A-1 APPENDIX A PARENT COMPANY INFORMATION FOR PETROLEUM REFINERIES

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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)

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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)

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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 12 5,000 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)

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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 10,25 0 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 Sources: 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 throug h 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 webs ites, 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 Le xisNexis at University of Virginia’s Alderman Library. 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 Individua l 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 Deleted: March

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## Table 1-2. National Incremental Emission Reductions and Cost-Effectiveness for Petroleum Refinery Flares Sub ject to Amended Standards Un der 40 CFR part 60, subpart Ja (Fifth Year After Applicability Date)

Subpart Ja Requirements Annual emission reductions (tons SO 2 

### /yr) Annual emission reductions (tons NO x 

### /yr) Annual emission reductions (tons VOC/yr) Annual emission reductions (metric tons CO 2 

### /yr) Cost effectiveness ($/ton emissions reduced) Estimates from June 2008 Final Rule 80 6 200 -- (23,000) Total for Revised Estimates for Amendments 3,200 1,100 3,400 1,897,759 (10,000) Flare Monitoring 0 0 0 -- -- Flare Gas Recovery 375 1,059 2,696 1,799,479 (18,000) Flare Management Plans 0 0 300 -- 2,900 SO2 Root Cause Anal y sis/Corrective Action 2,900 0 0 -- 760 Flow Rate Root Cause Analysis/ Corrective Action 4 56 430 98,280 (13,000)