## From: "Higgins, Cortney" < Cortney_Higgins@omb.eop.gov > Sent: 02/29/2012 01:32 PM
To: Brenda Shine/RTP/USEPA/US@EPA Cc: Penny Lassiter/RTP/USEPA/US@EPA, Al ex Macpherson/RTP/USEPA/US@EPA, William Nickerson/DC/USEPA/US@EPA Subject: Interagency Comments under EO 13563 on Petroleum Ja draft final rule

Hi Brenda, Attached are comments on the Flares memo.

Regards, Cortney

<< Impacts_FlareGasRecovery_FGCD-01-25-12_InteragencyCommentsunderEO13563.doc >>

### FROM: Kristin Sroka and Jeff Coburn, RTI International

TO: Brenda Shine, EPA/OAQPS/SPPD

FOR: Petroleum Refinery NSPS Docket No. EPA-HQ-OAR-2007-0011

DATE: January 25, 2012

SUBJECT: Impact Estimates for Fuel Gas Combus tion Device and Flare Regulatory Options for Amendments to the Petroleum Refinery NSPS

1. Introduction

The U.S. Environmental Protection Agency (EPA) issued new source performance standards (NSPS) for petroleum refineries beginning constr uction, reconstruction, or modification after May 14, 2007 (40 CFR part 60, subpart Ja) on June 24, 2008. Following promulgation, EPA received petitions for reconsideration from: 1) the American Petroleum Institute (API), the National Petrochemical and Refiners Associati on (NPRA), and the Western States Petroleum Association (WSPA) (collectively referred to as “Industry Petitioners”); 2) HOVENSA, LLC; and 3) the Environmental Integrity Project, Sierra Club, and Natural Resources Defense Council (collectively referred to as “Environmental Petiti oners”). Based on information provided by the petitioners, EPA proposed amendments to subpart Ja regarding the requirements for flares and process heaters on December 22, 2008.

The petitioners and commenters on the proposed amendments to the subpart Ja requirements provided information to improve the cost and emissi on reduction estimates that were presented at the time of promulgation of the final standards and the proposed amendments to the standards. Industry Petitioners noted that the provisions desc ribing what actions cause a flare to become a modified source would cause many more than 30 flares to become subject to subpart Ja over the next 5 years. Environmental Petitioners noted that the sulfur dioxide (SO 2 

### ) emissions per flaring event and emissions reductions per root cause an alysis (RCA) were significantly underestimated, and they provided data on SO 2 

### emissions from flares from three refineries in Texas (Schaeffer, 2008). Public commenters stated that EPA should consider the impacts of the long-term hydrogen sulfide (H 2 

### S) concentration requirements for fuel gas sent to flares separately from the impacts of the other flare requirements.

The costs and emission reduction impacts of seve ral regulatory options were evaluated based on this additional information. Note that for purp oses of the regulatory alternatives considered in this memorandum, flares are not considered fuel gas combustion devices (FGCD); rather, they are considered as separate affected sour ces. The regulatory options are as follows:

 A limit of 60 parts per million by volume (ppmv) H 2 

### S or 8 ppmv SO 2 

### over a 365-day rolling average for FGCD (as noted above, this does not include flares);

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to th e Petroleum Refinery NSPS January 25, 2012

2  Requiring owners and operators to limit the concentration of H 2 

### S in the fuel gas sent to flares to 60 ppmv on a 365-day rolling average; and

 Requirements for flaring events, including a flare management plan, RCA for a discharge that causes 500 pounds (lb) SO 2 

### emissions in a 24-hour period; and RCA for a discharge that causes flow rate to a flare in excess of 500,000 standard cubic feet (scf) above a baseline flow rate defined in the flare management plan within a 24-hour period.

The purpose of this memorandum is to document the procedures and methodologies used to estimate the costs (in 2006 dollars) and emission reduction impacts for new, reconstructed, and modified flares and FGCD over the first 5 years for selected regulatory options. All impacts are expressed as the costs and emission reductions achieved beyond implementing the current requirements of subpart J.

The nationwide impacts for the first regulatory option, the long-term fuel gas sulfur limit for FGCD, are shown in Table 1. Table 2 presents the nationwide impacts for the second regulatory option, the long-term sulfur concentration requirem ent for fuel gas sent to flares. The nationwide impacts for the third regulatory option, the standa rds for flaring events, are shown in Table 3.

Table 1. Projected National Fi fth Year Impacts of the Long-Te rm Fuel Gas Sulfur Limit for Potentially Affected Fuel Gas Combustion Devices

Process Unit Capital cost ($1,000) Total annual cost ($1,000/ yr) Emission reduction (ton SO 2 /yr) Cost effectiveness ($/ton) New Fuel Gas Systems 1,200 560 520 1,100
Modified and Reconstructed Fuel Gas Systems 33,000 11,000 4,800 2,300

Total 34,000 12,000 5,300 2,200 Comment [ A 1]: Why 2006 dollars?Technical Memorandum – Impact Estimatesfor Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to thePetroleum Refinery NSPSJanuary 25, 20123Table 2. Projected National Fifth Year Impacts of Long-Term Sulfur Concentration Requirement for Fuel Gas Sent toPotentially Affected FlaresProcess UnitCapitalcost($1,000)Annualoperating costwithoutnatural gasoffset ($1,000)Naturalgasoffset($1,000)Netannualoperatingcost($1,000)Totalannualcost($1,000/yr)SO2Emissionreduction(tonSO2/yr)NOXEmissionreduction(tonNOX/yr)VOCEmissionreduction(tonVOC/yr)Costeffectiveness($/ton)New Flares 80,000 8,000 (4,000) 3,200 15,000 6 34 130 84,000Modified andReconstructed Flares860,000 74,000 (39,000) 35,000 160,000 53 310 1,200 100,000Total900,000 80,000 (44,000) 38,000 170,000 59 340 1,300 99,000Table 3. Projected National Fifth Year Impacts ofOther Standards for Potentially Affected FlaresStandardCapitalcost($1,000)Total annualcost withoutoffset orcredit ($1,000)Annualoffset orcredit($1,000)Totalannual cost($1,000/yr)Emissionreduction(tonSO2/yr)Emissionreduction(tonNOX/yr)Emissionreduction(tonVOC/yr)Overall costeffectiveness ($/ton)Sulfur and Flow RateMonitoring + Recovery forLargest Flares460,000 92,000 (170,000) (76,000) 370 1,100 2,700 (18,000)Flare Management Plan -- 880 -- 880 -- -- 300 2,900SO2RCA/ Corrective ActionAnalysis-- 2,200 -- 2,200 2,900 -- -- 760Flow Rate RCA/ CorrectiveAction Analysis-- 1,000 (7,400) (6,400) 3.8 56 430 (13,000)Grand Total460,000 96,000 (180,000) (79,000) 3,200 1,100 3,400 (10,000)Comment [A2]:Why don’t these add up? Seemsmore than rounding error.Comment [A3]:Why doesn’t add up?

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to th e Petroleum Refinery NSPS January 25, 2012

4 2. Number of Impacted Process Units

It was assumed at proposal that 30 refineries will construct, reconstruct, or modify one or more FGCD over the next 5 years. Industry representa tives have indicated that most fuel gas systems are centralized. Therefore, the entire system that includes the new, reconstructed, or modified FGCD will essentially have to meet the sulfur sta ndards in order for the affected FGCD to be in compliance. For that reason, it is more accurate to consider whether the fuel gas system is existing or will be constructed than whether the FG CD is new, reconstructed, or modified. In other words, if a new FGCD is added to an existi ng fuel gas system, the refinery will need to retrofit that existing system, so it is more accurate to consider that situation as a reconstructed or modified fuel gas system. For this analysis, it was assumed that 90 percent of the fuel gas systems with affected FGCD w ill be reconstructed or modified and 10 percent will be new.

It was also assumed that 150 refineries will constr uct, reconstruct, or modi fy one or more flares over the next 5 years, based in part on the Industry Petitioners’ information. An estimate of the total number of flares in the petroleum refining industry was developed based on data collected from the 2002 National Emissions Inventory (NEI) for carbon monoxide (CO) emissions from sources with the source characterization code (SCC) for flares. Emissions were reported specifically for 252 flares at 77 refineries, s uggesting that there approximately 3.3 flares per refinery. Applying that ratio to the 150 petroleum refineries, there are approximately 500 flares in the industry. It is assumed that 80 percent of these flares, or 400 flares, would become subject to subpart Ja over the next 5 years; the remaining flares are assumed to be dedicated flares that would not be modified quickly ( e.g. , flares dedicated to butane spheres). It was also assumed that 30 percent of the 400 affected flares, or 120 flares, either would meet the definition of “emergency flare” in subpart Ja or would be equipped with a flare gas recovery system.

The number of coking units at the affected f acilities was estimated based on information from Refinery Capacity 2006 (EIA, 2006) and the “2005 Worldwide Refining Survey” (Stell, 2005); the compiled list includes 150 operating refineries . There are 53 refineries with delayed coking units, four refineries with fluid or flexi-coking units, and two refineries with both delayed and fluid/flexi-coking units, for a total of 59 refineri es that have at least one coking unit, which is 39 percent of all refineries. For the FGCD analysis, therefore, 39 percent of the 30 affected facilities, or 12 refineries, have a fuel gas syst em that includes fuel gas generated by a coking unit.

3. Long-term Sulfur Limit for Fuel Gas Combustion Devices

A. Emissions Estimates

Baseline SO 2 

### emissions from FGCD are dependent on the amount of fuel gas produced and the amount of sulfur in the fuel gas combusted. The primary sources of fuel gas are expected to be the crude distillation unit, the fluid catalytic cracking unit, and the coking unit, with each providing approximately equal amounts of fuel ga s to a fuel gas system. The primary sulfur Comment [ A 4]: What percent?

Comment [ A 5]: Confusing, suggest rephrasing.

Comment [ A 6]: Than what?

Comment [ A 7]: Percent?

Comment [ A 8]: What are the implications of this assumption?
Comment [ A 9]: Can you discuss additional information you received from the ICR or from the GHG reporting?
Comment [ A 10]: Has there been any update to this number based on the ICR or other data?

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to th e Petroleum Refinery NSPS January 25, 2012

5 compound in fuel gas is typically H 2 

### S, which is readily removed by amine treatment. However, information received by EPA from Flint Hills Resources suggests that there are other reduced sulfur compounds in fuel gas generated by coking units, mostly mercaptans, that contribute to SO 2 

### emissions (Wilkes, 2005). These other sulfur compounds are not removed well by conventional amine treatment. As such, the SO 2 

### emissions from FGCD at facilities that have coking units are expected to be significantly diffe rent than those at facilities that do not have coking units. Consequently, two model fuel gas systems were used to evaluate the baseline SO 2 

### emissions and subsequent emission reductions achieved by a long-term sulfur limit.

For this analysis, it is assumed that there is on e affected centralized fuel gas system at the refinery providing fuel gas to one or more affected FGCD. The capacity of the centralized fuel gas system is dependent, among other things, on the types of units present at the facility. A fuel gas system that includes fuel gas generated by a coking unit was estimated to have an average gas flow rate of 50,000 standard cubic feet pe r minute (scfm). A fuel gas system without a coking unit would have an average gas flow rate of about one-third less, or 33,300 scfm ( i.e. , the fuel gas is generated by just the crude distil lation unit and the fluid catalytic cracking unit). These two model systems were developed based on information from various sources (Fedich et al., 2004; Polasek et al., 1982; Voltz et al., 2004); further details about the models are included in Section 3.B of this memorandum.

In the absence of subpart Ja requirements for new, modified, or reconstructed FGCD, the affected FGCD would meet the current requiremen ts of subpart J. Nearly all FGCD currently meeting those standards comply with the H 2 

### S concentration limit of 0.1 grains per dry standard cubic feet (gr/dscf) in the fuel gas (equivalent to 162 ppmv H 2 

### S in the fuel gas) on a 3-hour average. For the model fuel gas system without a coking unit, a fuel flow rate of 33,300 scfm and a concentration of 162 ppmv H 2 

### S would emit approximately 0.90 pounds of SO 2 

### per minute (lb SO 2 

### /min), or 240 tons of SO 2 

### per year (ton SO 2 

### /yr) at baseline (note that 64 lb of SO 2 

### is released during the combustion of 34 lb of H 2 

### S in the fuel gas).

As discussed previously, there is strong evidence that coking units generate other reduced sulfur compounds, mostly mercaptans, that contribute to SO 2 

### emissions from the FGCD (Wilkes, 2005). In their public comments on the original proposed rule (72 FR 27178, May 14, 2007), ExxonMobil provided an estimated range of 200 to 300 ppmv mercaptans in fuel gas generated by a coking unit and they used a value of 300 ppmv when describing a specific treatment system (Feerick, 2007). The mercaptan concentration estimate provided by Flint Hills was higher than 300 ppmv (although the exact value cannot be provided here due to confidentiality concerns), so a value of 300 ppmv mercaptans was selected as the midpoint of the range to calculate baseline SO 2 

### emissions. This additional sulfur content on ly applies to the fuel gas generated by the coking unit, which is assumed to be 16,700 scfm in the model plant ( i.e. , 50,000 – 33,300). The weighted average sulfur content in the model fuel gas system with a coking unit was subsequently calculated to be 262 ppmv ([(300 ppmv mercaptans + 162 ppmv H 2 

### S) × 16,700 scfm + 162 ppmv H 2 

### S × 33,300 scfm] / 50,000 scfm). Assuming an ideal gas at standard temperature and pressure (specifically, 20 °C and 1 atmosphere), 262 ppmv reduced sulfur is

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to th e Petroleum Refinery NSPS January 25, 2012

6 about 2.2 lb SO 2 

### /min, so the baseline for one model fuel gas system with a coking unit is 570 ton SO 2 

### /yr at baseline.

Based on the facility analysis presented in Section 2, it is estimated that 12 of the fuel gas systems with affected FGCD will be represented by th e model fuel gas system that contains a coking unit and 18 of the affected fuel gas systems ( i.e. , 30 – 12) would not have a coking unit. Therefore, the total nationwide baseline SO 2 

### emissions are estimated to be approximately 11,000 tons per year (ton/yr) (240 ton/yr × 18 fuel gas systems + 570 ton/yr × 12 fuel gas systems) from FGCD.

The SO 2 

### emissions attributed to this re gulatory option for FGCD are the SO 2 

### emissions released when the FGCD meets the long-term sulfur limit. It was assumed that refiners would comply with the long-term H 2 

### S concentration limit rath er than the direct SO 2 

### limit. While the H 2 

### S and SO 2 

### limits are roughly equivalent when H 2 

### S is the primary sulfur compound in the fuel gas, it is much easier for fuel gas systems with coking units to meet the 60 ppmv H 2 

### S concentration limit in the fuel gas than the 8 ppmv SO 2 

### emission limit in the FGCD exhaust. For fuel gas systems without a coking unit, the SO 2 

### emissions when meeting the long-term H 2 

### S concentration limit were estimated to be 0.33 lb SO 2 

### /min, or 87 ton SO 2 

### /yr (assuming an ideal gas at 20 °C and 1 atmosphere, 60 ppmv H 2 

### S for a 33,300 scfm system is equivalent to 0.18 pounds of H 2 

### S per minute (lb H 2 

### S/min), or 0.33 lb SO 2 

### /min). Because the amine treatment system is not expected to reduce mercaptans for fuel gas systems with a coking unit, SO 2 

### emissions reductions are based on a reduction of 102 ppmv H 2 

### S. Therefore, for fuel gas systems with a coking unit, the SO 2 

### emissions when meeting the long-term H 2 

### S concentration limit were estimated to be 1.33 lb SO 2 

### /min, or 350 ton SO 2 

### /yr (assuming an ideal gas at 20 °C and 1 atmosphere, a reduction of 102 ppmv H 2 

### S for a 50,000 scfm system is equivale nt to a reduction in reduced sulfur compounds of 0.45 pounds per minute (lb/min), or a reduction of 0.85 lb SO 2 

### /min). The weighted average reduced sulfur content would be 160 ppmv when meeting the regulatory option ([(300 ppmv mercaptans + 60 ppmv H 2 

### S) × 16,700 scfm + 60 ppmv H 2 

### S × 33,300 scfm] / 50,000 scfm).

The baseline SO 2 

### emissions and the SO 2 

### emissions for the two model fuel gas systems (one with a coking unit and one without) meeting the long-term fuel gas sulfur limit regulatory option are shown in Table 4. Table 4 also provides the nationwide emissions at baseline and at the 60 ppmv H 2 

### S long-term concentration limit and the SO 2 

### emission reduction from the baseline.

Table 4. Emissions for Model Plants Meet ing Long-Term Sulfur Limit for Fuel Gas Combustion Devices

Conditions Emissions from Model Fuel Gas System Nationwide Emissions (ton SO 2 /yr) Reduction from baseline (ton SO 2 /yr) Without a coking unit (ton SO 2 /yr) With a coking unit (ton SO 2 /yr)
Baseline 240 570 11,000 --- 60 ppmv H 2 S 87 350 5,800 5,300

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to th e Petroleum Refinery NSPS January 25, 2012

7 B. Cost Analysis

It was estimated that roughly 85 percent of the existing fuel ga s systems with affected FGCD would achieve the long-term sulfur limit by incr easing the amine circulation rate of an amine treatment system designed to meet the current requirements of subpart J and 15 percent would add amine capacity. The model amine treatment system has a steam ratio of 0.9 pounds of steam per gallon (lb/gal) of amine; this value is the median of the steam ratios for the systems described in various sources (Fedich et al., 2004; Polasek et al., 1982; Voltz et al., 2004). For fuel gas systems without a coking unit, the amine circulation rate is 1,333 gallons per minute (gpm); for fuel gas systems that include fuel gas generated by a coking unit, the amine circulation rate is 2,000 gpm. It is estimated that the owner or operator would need to increase the amine circulation rate by 3.5 percent to meet this regulatory option; the new amine circulation rate would be 1,380 gpm for fuel gas systems without a coking unit and 2,070 gpm for fuel gas systems that include fuel gas generated by a coking unit. The incremental cost between subpart J and this regulatory option is the additional cost of the steam required to regenerate the rich amine solution at the increased amine circulation rate. The cost of steam was estimated to be $7.25 per 1000 pounds (Voltz et al., 2004).

Estimated costs for fuel gas systems that would add amine treatment capacity were based on costs provided by public commenters. The commenters provided capital costs, annual operating costs, and total annual costs for eight relevant projects; further details on these projects are considered confidential business informati on (Chittim, 2007; Garg, 2007). Based on the averages for these eight projects, the estimated capital and total annual costs of increasing amine capacity for an existing fuel gas system were $11 million and $1.5 million, respectively. For a new fuel gas system that includes fuel gas from a coking unit, the estimated incremental capital cost between a fuel gas system designed to meet subpart J and a fuel gas system designed to meet the regulatory option was 11 percent of the cost of adding amine capacity to an existing system, or $1.2 million.

Table 5 presents the estimate of the numbers of fu el gas systems with affected FGCD expected to use the various technologies described above to co mply with the long-term sulfur limit. Table 6 is a summary of the emission reductions and costs for each of the models for fuel gas systems. Given the number of each model fuel gas system as presented in Table 5 and the costs and emission reductions per model fuel gas system, the nationwide impacts of the long-term sulfur limits can be calculated; these results are presented in Table 7 (which is identical to Table 1).

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to th e Petroleum Refinery NSPS January 25, 2012

8 Table 5. Number of Model Fuel Gas Systems Selecting Each Compliance Method to Meet a Long-Term Sulfur Limit for Fuel Gas Combustion Devices

Type of Fuel Gas System Number of Fuel Gas Systems
Increase in Amine Recirculation Rate Additional Amine Capacity New, without a coking unit 2 0 New, with a coking unit 1 0 Modified/Reconstructed, without a coking unit 14 2 Modified/Reconstructed, with a coking unit 10 1



### Table 6. Summary of Costs and SO 2 

### Emission Reductions for Each Model System for

Two Compliance Methods Employed to Meet a Long-Term Sulfur Limit for Fuel Gas Combustion Devices

Type of Fuel Gas System SO 2 Emission Reduction

(ton/yr) Increase in Amine Recirculation Rate Additional Amine Capacity Capital

Cost ($1,000) Total Annual Cost

($1000/yr) Capital Cost ($1,000) Total Annual Cost ($1000/yr) New, without a coking unit 150 0 160 --- --- New, with a coking unit 220 1,200 240 --- --- Modified/ Reconstructed, without a coking unit 150 0 240 11,000 1,500

Modified/ Reconstructed, with a coking unit 220 0 360 11,000 1,500



### Table 7. Projected National Fifth Year Impacts of the Long-Term Sulfur Limit for Potentially Affected Fuel Gas Combustion Devices

Process Unit Capital cost ($1,000) Total annual cost ($1,000/ yr) Emission reduction (ton SO 2 /yr) Cost effectiveness ($/ton) New Fuel Gas Systems 1,200 560 520 1,100
Modified and Reconstructed Fuel Gas Systems 33,000 11,000 4,800 2,300

Total 34,000 12,000 5,300 2,200

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to th e Petroleum Refinery NSPS January 25, 2012

9 4. Long-term Sulfur Concentration Requirement for Fuel Gas Sent to Flares

A. Emissions Estimates

In their comments on the proposed amendments to address the flare requirements, industry representatives stated that it is not cost effective to manage the fuel gas sent to flares by limiting the long-term concentration of H 2 

### S to 60 ppmv. They noted that almost all refineries with affected flares would need to add amine capacity rather than increasing the circulation of the amine (Cade, 2009; Chittim, 2009; Feerick, 2009; Saffell, 2009). Therefore, as previously noted, this analysis evaluates the cost and emission reductions from flares separately from FGCD. For this analysis, it is assumed that there are an average of 1.9 impacted flares per refinery (280 impacted flares at 150 refineries).

Baseline SO 2 

### emissions from flares, like FGCD, are the result of H 2 

### S and other reduced sulfur compounds in the fuel gas. Therefore, two flare scenarios were used to evaluate the baseline SO 2 

### emissions and subsequent emission reductions achieved by the limiting the long-term concentration of sulfur in fuel gas sent to flares. In the first scenario, the gas being flared does not contain fuel gas from a coking unit, and in the second scenario, the gas being flared is from a coking unit. In the absence of subpart Ja requirements for new, modified, or reconstructed flares, the affected flare would meet the current requirements of subpart J as an FGCD. As noted previously, nearly all FGCD currently meeting those standards comply with the H 2 

### S concentration limit of 0.1 gr/dscf in the fuel gas (equivalent to 162 ppmv H 2 

### S in the fuel gas) on a 3-hour average.

The first step in this piece of the analysis was determining the amount of flare gas recovered and treated to meet the long-term sulfur concentration requirement. The flare flow rate selected for this analysis was 25,000,000 standard cubic feet per year (scf/yr); this is about the 50 th 

### percentile of the flow rates examined for the overall flare impacts analysis (See Section 5.A and Table 13 for more information on the analysis of gas flow rates to flares). The flare flow was then converted to 48 scfm per flare (25,000,000 scf/yr ÷ 365 days per year ÷ 24 hours per day ÷ 60 minutes per hour). Using a calculation simila r to that for FGCD (Section 3.A), baseline SO 2 

### emissions for this additional 48 scfm are 0.0013 lb/min, or 0.34 ton/yr, assuming none of the flare gas is from a coking unit. If the 48 scfm are from a coking unit, then the total baseline SO 2 

### emissions are 0.0037 lb/min, or 0.96 ton/yr.

Based on the facility analysis presented in Section 2, it is estimated that 59 of the affected flares will receive gas from a coking unit and 221 of the affected flares ( i.e. , 280 – 59) will not receive gas from a coking unit. Therefore, the total nationwide baseline SO 2 

### emissions from affected flares are estimated to be approximately 131 ton/yr (0.34 ton/yr × 221 flares + 0.96 ton/yr × 59 flares).

The SO 2 

### emissions attributed to this re gulatory option for flares are the SO 2 

### emissions released when the gas being flared meets the long-term sulfur concentration requirement. Similar to the calculations for FGCD, SO 2 

### emissions for flares without coking unit gas meeting the long-term

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to th e Petroleum Refinery NSPS January 25, 2012

10 sulfur concentration requirement are based on a reduction of 102 ppmv H 2 

### S (162 – 60 ppmv H 2 

### S), and the SO 2 

### emissions were estimated to be 0.00047 lb SO 2 

### /min, or 0.12 ton SO 2 

### /yr (assuming an ideal gas at 20 °C and 1 atmosphere, 60 ppmv H 2 

### S for 48 scfm is equivalent to 0.00025 lb H 2 

### S/min, or 0.00047 lb SO 2 

### /min).

As with FGCD, the amine treatment system is not expected to reduce mercaptans for flare gas from a coking unit, so SO 2 

### emissions reductions for flare gas from a coking unit are also based on a reduction of 102 ppmv H 2 

### S [(300 ppmv mercaptans + 162 ppmv H 2 

### S) – (300 ppmv mercaptans + 60 ppmv H 2 

### S)]. Therefore, for fuel gas systems with a coking unit, the SO 2 

### emissions when meeting the long-term H 2 

### S concentration requirement for fuel gas were estimated to be 0.0028 lb SO 2 

### /min, or 0.75 ton SO 2 

### /yr (assuming an ideal gas at 20 °C and 1 atmosphere, a reduction of 102 ppmv H 2 

### S for 48 scfm is equivalent to a reduction in reduced sulfur compounds of 0.00043 lb/min, or a reduction of 0.00081 lb SO 2 

### /min).

The baseline SO 2 

### emissions and the SO 2 

### emissions for the two model flares (one with a coking unit and one without) meeting the long-term fuel gas sulfur concentration requirement for fuel gas are shown in Table 8. Table 8 also provides the nationwide emissions at baseline, the nationwide emissions for model flares meeting the 60 ppmv H 2 

### S long-term concentration requirement, and the SO 2 

### emission reduction from the baseline for flares.

Table 8. Emissions for Model Flares Meeting Long-Term Sulfur Concentration Requirement for Fuel Gas Sent to Flares

Conditions Emissions from Model Flare Nationwide Emissions (ton SO 2 /yr) Reduction from baseline (ton SO 2 /yr) Without a coking unit (ton SO 2 /yr) With a coking unit (ton SO 2 /yr)

Baseline 0.34 0.96 131 --- 60 ppmv H 2 S 0.12 0.75 72 59



### While SO 2 

### reductions are the primary focus of the long-term H 2 

### S concentration requirement for fuel gas, when these reductions are accomplished via flare gas recovery, there are also reductions in other pollutants, such and nitrogen oxides (NO X 

### ) and volatile organic compounds (VOC). As described in Section 5.A of this memorandum, th e lower heating value for flare gas is estimated to be 1,440 Btu/scf (lower heating value basis). Using the emission factors for NO X 

### , in EPA’s Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area Sources (AP-42) (U.S. EPA, 1995), recovery of 48 scfm of gas from being discharged to the flare would reduce NO X 

### emissions by 1.2 tons/yr per flare. Only a small fraction of the VOC in the flare gas will be emitted, as the flare is expected to achieve 98 percent destruction efficiency. If that gas is recovered, it will likely be burn ed in an alternate co mbustion source such as a process heater or boiler. Assuming the alternate combustion source achieves 99 percent destruction efficiency, a net 1 percent reduction in VOC emissions is expected to be achieved due to flare gas recovery. If 25 percent of the flare gas is VOC with an average molecular weight of 58 g/mol, recovering 48 scfm of flare gas is expected to yield VOC emission reductions of 4.8 tons/yr per flare.

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to th e Petroleum Refinery NSPS January 25, 2012

11 B. Cost Analysis

Based on industry information described previously, it was estimated that to meet the long-term sulfur concentration requirement, existing and new affected flares would need to add a flare gas recovery system to recover flare gas not meeting the sulfur concentration requirement. It is possible that some flares may need additional amine capacity to treat the recovered gas, but based on the small amount of gas recovered by the model flare (48 scfm), it is assumed for purposes of this analysis that once the gas is recovered, existing amine treatment systems at the refinery could handle the additional gas. Cost es timates were derived based on a series of flare gas recovery projects reported in the literature (John Zink Co, 2006; Envirocomb Limited, 2006; U.S. DOE, 2005). From these case studies, the following cost equations were developed:

Total Capital Investment (TCI) Costs
TCI ($) = 1,000,000 + 10,000,000 (FlowRate/876,000) 0.65 

### (Eqn. 1)

Annual Operating Costs (AOC)
AOC ($/yr) = 100,000 + 100,000 (FlowRate/876,000) (Eqn. 2)

where:

FlowRate = flare gas recovery system design flow rate, 1,000 scf/yr.

The capital cost estimates include system design, costs of retrofitting the water seal and other ancillary equipment, and installation. The equati ons calculate the cost of installing a recovery system when constructing a new flare; to calcul ate the cost of retrofitting a reconstructed or modified flare with a recovery system, the capital cost was multiplied by a factor of 1.2. Capital costs were annualized using a 10-year equipment life and a 7 percent annual interest rate. In addition, the annualized costs include taxes and insurance equal to 4 percent of the capital cost. All costs are in 2006 U.S. dollars.

Control costs were estimated using a system desi gn flow rate of 50,000,000 scf/yr, or twice the average flow rate of the flare, so that the recovery system would be capable of handling variations in flow to the flare ( i.e. , capable of recovering short-term flaring events above the average annual flow rate to the flare). For each system, 80 percent of the flare gas is expected to be recovered, and all of the recovered flare gas can be used to reduce the refinery’s natural gas purchases. The other 20 percent would be unable to offset natural gas purchases due to undesirable characteristics ( e.g. , a heating value too low for combustion). The heat content of the recovered gas was calculated based on the estimated average heating value of the flare gas ( i.e. , 1,600 British thermal units per standard cubi c foot [Btu/scf]). Natural gas has a heat content of approximately 1,028 Btu/scf (DOE, 2007, Table B2); therefore, each scf of flare gas recovered off-sets the purchase of 1.55 scf of natural gas. The average industrial cost of natural Comment [ A 11]: Although taxes should be reported as a cost to refiners, they are not a social
cost.

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to th e Petroleum Refinery NSPS January 25, 2012

12 gas was $7.86/1,000 scf (DOE, 2007, Table 23) in 2006 and was $5.33/1,000 scf (DOE, 2010, Table 23) in 2009; therefore, a value of $5.00 per 1,000 scf was used in the analysis to account for times when the recovered gas cannot offset natural gas purchases (assumed to be roughly 10 percent of the time).

Monitoring costs were also estimated for measuring the flow rate and sulfur content of gas to the flare. The capital costs of these monitors were estimated as $300,000 and the annual operating costs were estimated as $50,000. These costs are approximately 1.5 times the costs for these monitors as estimated by the CEMS Cost Model (U.S. EPA, 2007) to account for additional costs associated with monitoring highly flammable gase s. The capital costs of the monitoring system were annualized using a 10-year equipment life and a 7 percent annual interest rate.

Table 9 presents the estimate of the numbers of affected flares; the derivation of these estimates was described in Sections 2 and 3. Table 10 is a summary of the emission reductions and costs for each of the models for flares. Given the number of each model flare as presented in Table 9 and the costs and emission reductions per model flare, the nationwide impacts of the long-term sulfur concentration requirement for fuel gas sent to flares can be calculated; these results are presented in Table 11 (which is identical to Table 2).

Table 9. Number of Affected Flares for Each Model and Scenario

Flare Model and Scenario Number of Flares New, without a coking unit 22 New, with a coking unit 6 Modified/Reconstructed, without a coking unit 199 Modified/Reconstructed, with a coking unit 53 Comment [ A 12]: Please explain why you do not use EIA projections of gas prices over next 5 years.

Comment [ A 13]: Should probably also do 3% as per OMB guidance.

Comment [ A 14]: Was the estimate of the new units estimates described n these sections?Technical Memorandum – Impact Estimatesfor Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to thePetroleum Refinery NSPSJanuary 25, 201213Table 10. Summary of Costs for a Single Flare to Meetthe Long-Term Sulfur Concentration Requirement for Fuel GasAffected FlareSO2EmissionReduction(ton/yr)Recovery System CostsCapital Cost($1,000)AnnualOperating Cost($1000/yr)Natural GasOffsets($1000/yr)Net AnnualOperating Cost($1000/yr)Total AnnualCost($1000/yr)New, without a coking unit0.212,900270160110520New, with a coking unit0.212,900270160110520Modified/ Reconstructed,without a coking unit0.21 3,400 290 160 140 620Modified/ Reconstructed, with acoking unit0.21 3,400 290 160 140 620Table 11. Projected National Fifth Year Impacts of Long-Term Sulfur Concentration Requirement for Fuel Gas Sent toPotentially Affected FlaresProcess UnitCapitalcost($1,000)Annualoperating costwithoutnatural gasoffset ($1,000)Naturalgasoffset($1,000)Netannualoperatingcost($1,000)Totalannualcost($1,000/yr)SO2Emissionreduction(tonSO2/yr)NOXEmissionreduction(tonNOX/yr)VOCEmissionreduction(tonVOC/yr)Costeffectiveness($/ton)New Flares80,000 8,000 (4,000) 3,200 15,000 634 130 84,000Modified andReconstructed Flares860,000 74,000 (39,000) 35,000 160,000 53 310 1,200 100,000Total 900,00080,000(44,000)38,000170,000593401,30099,000

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to th e Petroleum Refinery NSPS January 25, 2012

14 5. Other Standards for Flares

This section describes the development of costs and emissions estimates for the requirements for flaring events, including a flare management pl an, RCA for a discharge that causes 500 lb SO 2 

### emissions in a 24-hour period; and RCA for a discharge that causes flow rate to a flare in excess of 500,000 scf above a baseline flow rate defined in the flare management plan within a 24-hour period.

A. Flow Estimates

Carbon monoxide (CO) emissions from flares that were reported in the 2002 NEI were used to estimate the amount of fuel gas discharged to flar es. CO emissions were reported specifically for the flare SCC for 252 flares at 77 refineries; these data are summarized in Attachment A. It is anticipated that some facilities/ states did not estimate CO emissions from flares or the emissions were reported using a more generic SCC code. As such, the fact that approximately 50 percent of the refineries reported CO emissions for flares is not surprising. The CO emissions reported in the NEI were assumed to be representativ e of the refinery flare usage nationwide.

The CO emission factor for flares in EPA’s Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area Sources (AP-42) is 0.37 pounds per million British thermal units (lb/MMBtu) (U.S. EPA, 1995). If 1 ton/yr of CO emissions were reported, then that facility is expected to have flared 5,405 mill ion British thermal units per year (MMBtu/yr) of gas (1 ton/yr × 2000 lb/ton / 0.37 lb/MMBtu).

The composition of refinery flare gas is highly variable. Table 12 presents ranges of flare gas composition reported in the literature (Peterson et al., 2007). The aver age composition of flare gas as reported in Table 12 was used to estimate a typical heat content of flare gas. The lower heating value (LHV) was calculated to be 1,540 Btu/scf and the higher heating value (HHV) was calculated to be 1,680 Btu/scf. The LHV is usually used for flares when calculating emissions, but if the fuel is recovered and used in process heaters, the HHV is typically monitored. For the purposes of this assessment, the fuel gas was assumed to have a HHV of 1,600 Btu/scf and a LHV of 1,440 Btu/scf. The LHV was used to estim ate the flare flow rate from the CO emissions data and the HHV was used to estimate the amount of natural gas purchases that could be offset if the flare gas is recovered. Continuing the example of 1 ton/yr of CO, the 5,405 MMBtu/yr would equate to a flare gas flow rate of 3.75 million standard cubic feet per year (MMscf/yr).

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to th e Petroleum Refinery NSPS January 25, 2012

15 Table 12. Typical Waste Gas Composition and Range

Flare gas component Gas Composition Range Minimum, % Maximum,% Average,%
Methane CH 4 7.17 82 43.6
Ethane C 2 H 6 0.55 13.1 3.66 Propane C 3 H 8 2.04 64.2 20.3
n-Butane C 4 H 10 0.199 28.3 2.78
Isobutane C 4 H 10 1.33 57.6 14.3
n-Pentane C 5 H 12 0.008 3.39 0.266 Isopentane C 5 H 12 0.096 4.71 0.53
neo-Pentane C 5 H 12 0 0.342 0.017

n-Hexane C 6 H 14 0.026 3.53 0.635 Ethylene C 2 H 4 0.081 3.2 1.05 Propylene C 3 H 6 0 42.5 2.73
1-Butene C 4 H 8 0 14.7 0.696
Carbon monoxide CO 0 0.932 0.186

Carbon dioxide CO 2 0.023 2.85 0.713 Hydrogen sulfide H 2 S 0 3.8 0.256 Hydrogen H 2 0 37.6 5.54 Oxygen O 2 0.019 5.43 0.357 Nitrogen N 2 0.073 32.2 1.3
Water H 2 O 0 14.7 1.14
Source: Peterson et al., 2007



### Reported CO emissions were converted to flare gas flow rates using the AP-42 emission factor and average flare gas heating value as described above. Ten model flares were developed from these data. The 5 th 

### percentile flare flow rate from the data set was used to represent the smallest 10 percent of flares. The 15 th 

### percentile flare flow rate from the data set was used to represent the next smallest 10 percent of flares, and so on so that the 95 th 

### percentile flare flow rate was used to represent the largest 10 percent of flares. Table 13 summarizes the model flares resulting from this analysis.

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to th e Petroleum Refinery NSPS January 25, 2012

16 Table 13. Model Flare Flow Rates

Plant Model Flow to flare (1000 scf/yr) Model Flare 1 (5th percentile, 0 to 10%) - Model Flare 2 (15th percentile, 10 to 20%) 969 Model Flare 3 (25th percentile, 20 to 30%) 3,754 Model Flare 4 (35th percentile, 30 to 40%) 11,070 Model Flare 5 (45th percentile, 40 to 50%) 21,006 Model Flare 6 (55th percentile, 50 to 60%) 40,648 Model Flare 7 (65th percentile, 60 to 70%) 49,926 Model Flare 8 (75th percentile, 70 to 80%) 101,351 Model Flare 9 (85th percentile, 80 to 90%) 167,505 Model Flare 10 (95th percentile, 90 to 100%) 675,931



### Note that for this analysis, each model flare represents 10 percent of the 400 total affected flares in the industry, or 40 flares. Model Flares 1, 2, and 3 represent a total of 120 flares that handle only startup, shutdown, and upset gases, which is consistent with the flare counts presented in Section 2 of this memorandum, and Model Flares 4 through 10 represent the remaining 280 impacted flares.

B. Cost Analysis for Flare Recovery and Monitoring System

To determine the cost impacts of the requirements for flaring events, or “other standards,” it was assumed that a flare gas recovery system would be considered for flares with average releases greater than the RCA and corrective action analysis threshold of 500,000 scf per 24 hours (183 MMscf/yr) above baseline. At this action level, only the flares represented by Model Plant 10 in Table 13 would consider installing a flare gas recovery system. Owners or operators of flares receiving routine flows that can offset natural gas purchases by recovering flare gas are likely to conclude that installing a flare gas reco very system would be a cost effective alternative to the flaring event requirements. For this asse ssment, it was assumed that all of the flares represented by Model Plant 10 would install a flare gas recovery system as a result of their flare management plan analyses. Cost estimates were derived as described in Section 4.B. Control costs were estimated using the model plant flow rates as the system design flow rate. Each model system was estimated to recover 80 percent of the flare gas design flow rate. As discussed in Section 4.B, the recovered flare gas is expected to reduce the refinery’s natural gas purchases; each scf of flare gas recovered off-sets the purchas e of 1.55 scf of natural gas, and a value of $5.00 per 1,000 scf of natural gas was used for this analysis (see Section 4.B of this memorandum).

Monitoring costs were also estimated for measuring the flow rate and sulfur content of gas to the flare to comply with these standards. The capital costs of these monitors were estimated as Comment [ A 15]: How was this level chosen? Why only at that action level would facilities consider installing a flare gas system?

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to th e Petroleum Refinery NSPS January 25, 2012

17 $300,000 and the annual operating costs were estimated as $50,000. These costs are approximately 1.5 times the costs for these monitors as estimated by the CEMS Cost Model (U.S. EPA, 2007) to account for additional costs associated with monitoring highly flammable gases. The capital costs of the monitoring system were annualized using a 10-year equipment life and a 7 percent annual interest rate.

The total capital cost of a flare gas recovery syst em for certain flares and monitors for 280 flares is $460 million, and the total annual cost saving s is $76 million (including an annual cost of $92 million and a natural gas offset of $170 million).

C. Costs for Root Cause Analysis and Flare Management Plan

Three different standards were included in this step of the analysis: RCA and corrective action analysis based on SO 2 

### emissions; a flow rate RCA and corrective action analysis for reducing volatile organic compound (VOC) emissions; and a flare management plan for, among other things, minimizing flow and emissions from refinery process units connected to an affected flare. These standards primarily require additional labor hours to perform the RCA, determine the proper corrective action, or to evaluate the start-up and shutdown procedures to identify ways to reduce flaring. The following labor rates were used in the analysis:

Labor Category Hourly Wage Environmental engineering labor cost, $/ hr (BLS May 2006, SOC 17-2081) $38.29 General and operations managers labor cost, $/hr (BLS May 2006, SOC 11-1021) $57.58 General office and admin support labor cost , $/hr (BLS May 2006, SOC 43-0000) $17.46

Labor requirements were made based on direct technical hours ( i.e. , hour of environmental engineering). For each technical hour, 0.05 hours of management time and 0.1 hours of administrative support time were projected to be required. In addition, benefits and other overhead costs were estimated to be 60% of the direct labor costs. As such, each technical hour was estimated to cost $68.66 [($38.29 + 0.05 × $57.58 + 0.1 × $17.46) × 1.6].

An estimated 45 labor hours would be required to perform each RCA and associated corrective action analysis (whether triggered by SO 2 

### or flow). The flare management plan was estimated to require 160 technical labor hours to develop. Unlike the direct control systems, these standards are expected to initiate routine operational or ma intenance practices that will typically avoid a periodic emission event that may not occur again for one or two years.

One of the primary considerations for the impacts of the RCA and corrective action analysis is the threshold at which the analyses are triggered. For the SO 2 

### RCA and corrective action analysis, the refinery consent decrees have established a trigger of 500 lb in any 24-hour period. Using this as the threshold for the SO 2 

### analyses, the cost effectiveness is estimated to be Comment [ A 16]: Please explain - this is the first mention of this.

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to th e Petroleum Refinery NSPS January 25, 2012

18 approximately $490/ton of SO 2 

### emissions avoided in the fifth y ear and an average of $760/ton of SO 2 

### emissions avoided per year over the first 5 years.

For the VOC/flow rate-based RCA and corrective ac tion analysis trigger, it is assumed that the standards would reduce malfunctions and upsets th at release VOC that would otherwise become product. Therefore, the cost savings is based on the value of the product rather than a reduction in natural gas purchases. The value of the product is assumed to be $560/ton of VOC, which is an approximate conversion from an estimate of $1 .75 per gallon. That estimate assumes that the value of recovered VOC is consistent with the average of the price of brent crude (crack spread spot price of $74.96 per barrel ($1.78 per gallon) on September 7, 2007) and the product value (crack spread spot price of $87.04 per barrel ($2.08 per gallon) on September 7, 2007) (Stell, 2007). The value of the product also assumes that the average petroleum refinery process stream has a specific gravity of 0.75. It is also assumed that the flares are operating properly and achieve a VOC destruction efficiency of 98 percent. In other words, 100 lb of VOC sent to the flare results in 2 lb of VOC emissions from the flare (the other 98 lb are converted to combustion products carbon dioxide and water). Therefore, the product credit of $560/ton of VOC sent to the flare is equivalent to $28,000 per ton of VOC emissions avoided. When the costs of conducting the analyses at flow events exceeding 500,000 scf in any 24-hour period are combined with the VOC credits, the resulting cost ef fectiveness is estimated to be a cost savings of $26,000/ton of VOC emissions avoided in the fifth year and an average cost savings of $15,000/ton of VOC emissions avoided per year over the first 5 years.

Tables 14 and 15 summarize some of the key inputs for the cost and emission reduction calculations as well as the overall costs and emissi ons reductions for this regulatory option. Consistent with other impacts, over 5 years, a total of 150 different refineries were projected to become subject to the root cause analysis requirements (50 refineries in each of the first 3 years). In addition, owners and operators would be requir ed to develop a flare management plan for all 400 affected flares. Average annual nationwide costs in the fifth year were estimated as the average costs across the 5-year period (as the annual costs were generally higher in Year 3 than in Year 5). The annual emission reductions achieved in Year 5 were used directly. Comment [ A 17]: Did EPA run this analysis with a range of values, rather than a point estimate?

Comment [ A 18]: Why is year 3 higher than year 5?
Comment [ A 19]: Why was Year 5 chosen?

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to th e Petroleum Refinery NSPS January 25, 2012

19 Table 14. Key Inputs and Outputs for SO 2 

### RCA and Corrective Action Analysis

Item Description Refineries Affected SO 2 Discharge Size Large Medium Small Labor required to perform each RCA and corrective action analysis 45 hours 45 hours 45 hours

Emissions over 24 hours 6.25 tons 2.5 tons 0.5 tons
Success rate of RCA/corrective action 35% 35% 35% Reduction efficiency for successfully avoided event 100% of SO 2 100% of SO 2 100% of SO 2 Average mass emissions per avoided event 2.19 tons 0.88 tons 0.18 tons Events per refinery (avg.), Year 1 50 5 3 2 Events per refinery, Year 2 100 4 3 2 Events per refinery, Year 3 150 3 2 1 Events per refinery, Year 4 150 2 2 1 Events per refinery, Year 5 150 1 1.2 0.5 Cost per analysis ($) 3,090 Nationwide average annual cost over 5 years ($1000/yr) 2,160 Nationwide annual emission reductions (ton SO 2 /yr) 2,900

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to th e Petroleum Refinery NSPS January 25, 2012

20 Table 15. Key Inputs and Outputs for Flow RCA and Flare Management Impacts
Item Description VOC/Flow RCA Flare Management

Size of average event 2,000,000 scf/ 24 hours 1 1,000,000 scf/ event 2

Labor required to comply with requirements 45 hours 160 hours
Success rate of RCA/corrective action 35% N/A

Reduction efficiency for successfully avoided event 2% for VOC 3
100% of SO 2 2% for VOC 3

Average mass emissions per avoided event 0.75 tons 4 VOC 0.38 tons 4 VOC Product recovery credit ($/day) 21,085

Number of new refineries per year 50 each in Years 1-3 --

Number of new flares per year -- 140 in Year 1; 130 each in Years 2 and 3 Events per year (avg.), Year 1 5 per refinery 2 per flare Events per year, Year 2 4 per refinery 2 per flare Events per year, Year 3 3 per refinery 2 per flare Events per year, Year 4 2 per refinery 2 per flare Events per year, Year 5 1.5 per refinery 2 per flare Cost per analysis or plan ($) 3,090 11,000 Nationwide average annual cost over 5 years ($1000/yr) 1,000 880 Nationwide average annual credit over 5 years ($1000/yr) (7,400) -- Overall nationwide average annual cost over 5 years ($1000/yr) (6,400) 880
Nationwide annual VOC emission reductions (ton VOC/yr) 430 300
Nationwide annual SO 2 emission reductions (ton SO 2 /yr) 3.8 --
Nationwide annual NO X emission reductions (ton NO X /yr) 56 --

1 Average size of event that exceeds 500,000 scf.

2 Estimated size of a planned startup or shutdown.

3 Based on a flare destruction efficiency of 98 percent.

4 VOC content of the flared gases was estimated to be 25 percent of the volumetric flow with an average molecular

weight of for VOC of 58 g/mol (based on butane).



### For the two standards for which credits are estima ted (natural gas offset credit for flare gas recovery on larger flares and product recovery credit for flow rate RCA), the magnitude of the credit is dependent on either the cost of natural gas or the value of the recovered product. To evaluate the sensitivity of the analysis to these va lues, the analysis was repeated with the cost at the low end of the potential range s for natural gas price and product credit. If the natural gas price is reduced to $3.50/scf, then the total annual natural gas offset for flare gas recovery for larger flares is reduced from $170 million to $120 million, and the total annual cost savings is reduced from $76 million to $26 million. If VOC is reduced to $400/ton (an approximate

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to th e Petroleum Refinery NSPS January 25, 2012

21 conversion from an estimate of $1.00 per gallon based on the average of the price of crude ($31.84 per barrel on December 26, 2008) and the price of gasoline ($1.255 per gallon without taxes in December 2008) (Stell, 2009)), then the total annual product recovery credit for flow rate RCA is reduced from $7.4 million to $5.3 million, and the total annual cost savings is reduced from $6.4 million to $4.3 million. Co nsidering these minimal credits and offsets together, then the overall total annual cost of all four flaring event standards would be reduced from a savings of $79 million to a savings of $27 million. Therefore, although the analysis depends on the magnitude of the credits and offsets, consideration of minimal values for these credits and offsets still results in an annual cost savings. (In fact, based on this analysis, natural gas cost could dip to as low as $3.00/scf and VOC could be as low as $50/ton and these standards would continue to result in an annual cost savings.)

The cost and emission reduction impacts of the final standards presented in Table 16 (identical to Table 3) were calculated as the sum of the impacts for flare gas recovery systems (expected to be needed for approximately 10 percent of the affected flares to limit the number of events above 500,000 scf/24 hrs above baseline), the impacts for SO 2 

### and flow root cause analyses, the impacts of flare management plans, and the impact s of flow and sulfur monitors associated with the flaring event requirements.Technical Memorandum – Impact Estimatesfor Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to thePetroleum Refinery NSPSJanuary 25, 201222Table 16. Projected National Fifth Year Impacts of Other Standards for Potentially Affected FlaresStandardCapitalcost($1,000)Total annualcost withoutoffset orcredit ($1,000)Annualoffset orcredit($1,000)Totalannual cost($1,000/ yr)Emissionreduction(tonSO2/yr)Emissionreduction(tonNOX/yr)Emissionreduction(tonVOC/yr)Overall costeffectiveness ($/ton)Sulfur and Flow RateMonitoring + Recovery forLargest Flares460,000 92,000 (170,000) (76,000) 370 1.100 2,700 (18,000)Flare Management Plan -- 880 -- 880 -- -- 300 2,900SO2RCA/ Corrective ActionAnalysis-- 2,200 -- 2,200 2,900 -- -- 760Flow Rate RCA/ CorrectiveAction Analysis-- 1,000 (7,400) (6,400) 3.8 56 430 (13,100)Grand Total460,000 96,000 (180,000) (79,000) 3,200 1,100 3,400 (10,000)Comment [A20]:Doesn’t seem to add up.

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to th e Petroleum Refinery NSPS January 25, 2012

23 The final parameter evaluated was the reduction in CO 2 

### emissions due to flow rate RCA and flare gas recovery. An emissions factor of 211,641.6 lb/MMscf was used, converted from the emissions factor of 60 kg/MMBtu from the Mandatory Greenhouse Gas Reporting Rule based on the heat content of fuel gas given in Section 4. B of this memorandum. For the flow rate RCA, the CO 2 

### emissions factor was applied to the flow rate of releases prevented in the fifth year, 1,138 MMscf/yr, for an emissions reduction of 120,000 ton/yr, or 110,000 metric tonnes per year (tonne/yr). For flare gas recovery, the CO 2 

### emissions prevented per large flare were estimated by applying an 80 percent recovery factor (see Section 4.B of this memorandum) to the CO 2 

### emissions for Model Flare 10 without a flare gas recovery system (65,000 ton/yr; see Section 4.A and Attachment A of this memorandum), resulting in an emissions reduction of 52,000 ton/yr per flare for flares that install flare ga s recovery. For 40 large flares, the CO 2 

### emissions reductions would be 2.1 million ton/yr, or 1.9 million tonne/yr.

In addition to the primary emissions reduction impacts, the secondary CO 2 

### emissions generated as the result of the electricity needed to operate the compressors for flare gas recovery systems were evaluated. Based on information provided by Envirocomb Limited (2006), 1,927 megawatt hours per year (MWh/yr) would be needed to operate a system designed to handle a flare flow of 1,000 to 1,600 cubic meters per hour (m 3 

### /hr); the midpoint of that range, 1,300 m 3 

### /hr, is equal to a flow rate of 424 million scf/yr. Based on these values, a flare gas recovery system would need 4.5 MWh of electricity for every 1 million scf of design capacity. Given that Model Flare 10 is 676 million scf/yr, the additional electrical consumption for Model Flare 10 would be 3,100 MWh/yr, or 120,000 MWh/yr for 40 flares. If the additional electricity is purchased from a power plant, the standards will increase secondary CO 2 

### emissions by 110,000 ton/yr, or 100,000 tonne/yr.

The final estimate of CO 2 

### emissions reductions, considering the reductions from both flare requirements as well as the secondary impacts described above, would be 2.1 million ton/yr, or 1.9 million tonne/yr. See Table 17 for a summary of the CO 2 

### emissions reduction impacts.

Table 17. Nationwide Estimate of CO 2 

### Emissions Reductions for Flare Standards 1

Standard CO 2 emissions reductions (ton/yr) CO 2 emissions reductions (tonne/yr) Electricity Generation for Flare Gas Recovery (120,000 MWh/yr Nationwide) (110,000) (100,000)

Flare Gas Recovery for Largest Flares 2,100,000 1,900,000 Flow Rate RCA/ Corrective Action Analysis 120,000 110,000 Total 2,100,000 1,900,000

1 Emissions reductions are shown as positive values; emissions increases are shown as negative values

( i.e. , negative reductions).

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to th e Petroleum Refinery NSPS January 25, 2012

24 6. References

Cade, R. 2009. Marathon Petroleum Company LLC Comments on EPA Proposed Amendments to Proposed Standards of Pe rformance for Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After May 14, 2007 (Proposed 40 CFR 60Subpart Ja). Letter to EPA Docket Center. February 3. Docket Item No. EPA-HQ-OAR2007-0011-0296.

Chittim, R. 2007. Comments of American Petroleum Institute (API), the National Petrochemical and Refiners Association (NPRA), and the Western States Petroleum Association (WSPA) on the proposed Standards of Performance for Petroleum Refineries:Proposed Rule. Letter to EPA Docket Center. August 27. Docket Item No. EPA-HQ-OAR2007-0011-0154.

Chittim, R. 2009. Comments of American Petroleum Institute (API), the National Petrochemical and Refiners Association (NPRA), and the Western States Petroleum Association (WSPA) on the Standards of Performance for Petroleum Refineries: ProposedAmendments. Letter to EPA Docket Center. February 5. Docket Item No. EPA-HQ-OAR2007-0011-0311.

Energy Information Administration (EIA), U.S. Department of Energy. 2006. Refinery Capacity Report 2006 . June 15. Docket Item No. EPA-HQ-OAR-2007-0011-0048.

Envirocomb Limited. 2006. Zero flaring by flare gas recovery . Presented at the Gas Processors Association 1 st 

### Specialized Technical Session: Zero Flaring Seminar. Al-Khobar, Saudi Arabia, November 29. Available at: http://www.gpa-gccchapter.org/PDF/Zero%20Flaring%20By%20Flare%20Gas%20Recovery.pdf

Fedich, R.B., A.C. Woerner, and G.K. Chitnis. 2004. “Selective H 2 

### S Removal.” Hydrocarbon Engineering , Vol. 9, No. 5, pp. 89-92. May. Docket Item No. EPA-HQ-OAR-2007-0011- 0032.

Feerick, C. 2007. ExxonMobil Comments on NSPS Ja Proposed Rule. Letter to EPA Docket Center. August 24. Docket Item No. EPA-HQ-OAR-2007-0011-0148.

Feerick, C. 2009. ExxonMobil Comments on Proposed Revisions to NSPS Ja. Letter to EPA Docket Center. February 5. Docket Item No. EPA-HQ-OAR-2007-0011-0301.

Garg, D. 2007. Valero Energy Corporation Comments on the Proposed Revisions to New Source Performance Standards Subpart J and the Proposed Promulgation of Subpart Ja. Letter to EPA Docket Center. August 27. Docket Item No. EPA-HQ-OAR-2007-0011- 0138.

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to th e Petroleum Refinery NSPS January 25, 2012

25 John Zink Company. 2006. Flare gas recovery (FGR) to reduce plant flaring. Presented at the Gas Processors Association 1 st 

### Specialized Technical Session: Zero Flaring Seminar. AlKhobar, Saudi Arabia, November 29. Available at: http://www.gpa-gccchapter.org/PDF/Flare%20Gas%20Recovery%20White%20Paper.pdf

Peterson, J., N. Tuttle, H. Cooper, and C. Bauka l. 2007. Minimize facility flaring. Hydrocarbon Processing . June. Pp. 111-115. Available at: http://www.johnzink.com/products/flares /pdfs/flare_hydro_proc_june_2007.pdf

. Polasek, J.C., J.A. Bullin, and S.T. Donnelly. 1982. “Alternative Flow Schemes to Reduce Capital and Operating Costs of Amine Sweetening Units.” Proceedings of the 1982 AIChE Spring National Meeting , New York, NY: American Institute of Chemical Engineers. Docket Item No. EPA-HQ-OAR-2007-0011-0020. http://www.bre.com/portals/0/technicalarti cles/Alternative%20Flow%20Schemes%20to%20 Reduce%20Capital%20and%20Operating%20Costs%20of%20Amine%20Sweetening%20U nits.pdf

. Saffell, K. 2009. Valero Energy Corporation Comments on the Proposed Amendments to New Source Performance Standards (“NSPS”), Subpart J and Subpart Ja. Letter to EPA Docket Center. February 5. Docket Item No. EPA-HQ-OAR-2007-0011-0310.

Schaeffer, E. 2008. TCEQ Refinery Emission Data. Email to K. Hustvedt, USEPA, from E. Schaeffer, Environmental Integrity Project. September 25.

Stell, J., ed. 2005. “2005 Worldwide Refining Survey.” Oil & Gas Journal , Vol. 103, No. 47. (Available online only: http://www.ogj.com/resourcecenter/survey.cfm#worldref .)

Stell, J., ed. 2007. “Statistics,” Oil & Gas Journal , Vol. 105, Issue 35. “OGJ Crack Spread,” p. 90. September 17.

Stell, J., ed. 2009. “Statistics,” Oil & Gas Journal , Vol. 107, Issue 2. “OGJ Gasoline Prices” and “World Crude Prices,” p. 57. January 12.

U.S. Department of Energy. 2005. Petroleu m Best Practices Plant-wide Assessment Case Study. Valero: Houston refinery uses plant-wide assessment to develop an energy optimization and management system. DOE/GO-102005-2121. Available at: http://www1.eere.energy.gov/industry/bestpractices/pdfs/valero.pdf

. U.S. Department of Energy, Energy Information Administration (EIA). 2007. Natural Gas Annual 2006 . DOE/EIA-0131(06). October. Available at: http://www.eia.gov/pub/oil_gas/natural_gas/data _publications/natural_g as_annual/historical/ 2006/nga_2006.html

.

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to th e Petroleum Refinery NSPS January 25, 2012

26 U.S. Department of Energy, Energy Information Administration (EIA). 2010. Natural Gas Annual 2009 . DOE/EIA-0131(09). December. Available at: http://www.eia.gov/pub/oil_gas/natural_gas/data _publications/natural_g as_annual/historical/ 2009/nga_2009.html

. U.S. EPA (Environmental Protection Agency). 1995. Compilation of Air Pollutant Emission Factors. Volume 1: Stationary Point and Area Sources . AP-42, Fifth Edition. Office of Air Quality Planning and Standards, Research Triangle Park, NC.

U.S. EPA (Environmental Protection Agency), Emissions Measurement Center. 2007. CEMS Cost Model

. http://www.epa.gov/ttn/emc/cem.html . March 7.

Voltz, B.L., J.D. Corley, and R.B. Fedich. 2004. “Benefits of a TGCU Amine Solvent Changeover.” Sour Oil & Gas Advanced Technology 2004 International Conference

. November. Docket Item No. EPA-HQ-OAR-2007-0011-0033.

Wilkes, J. 2005. Letter to U.S. Department of Justice and U.S. Environmental Protection Agency containing Flint Hills Resources, L.P ., Pine Bend, Minnesota Refinery Combined Technology Test Report (18-month report). September 26.

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to the Petr oleum Refinery NSPS – Attachment A January 25, 2012

A-1 Attachment A. Flare Data from 20 02 National Emissions Inventory

Facility Number Facility Name Emission Unit Description Annual CO Emissions

per flare

(tpy) Projected Flow Rate

(1000 scf/yr) 2 Hunt Refining Company 0.73 2,740 2 Hunt Refining Company 0.73 2,740 2 Hunt Refining Company 0.73 2,740 8 Tesoro Alaska Company - Kenai Refinery Refinery Flare, J-801, Unit 0042 0.03 113

8 Tesoro Alaska Company - Kenai Refinery Sru Flare, Unit 0043 0.03 113

8 Tesoro Alaska Company - Kenai Refinery Refinery Flare, J-801, Unit 0042 5.43 20,383

12 Lion Oil Company Sn822--823 High/Low Flare 13.80 51,802 16 Chevron Usa Inc. - Richmond V-282 South Isom 3.65 13,701 16 Chevron Usa Inc. - Richmond North Isomax Fla 3.65 13,701 16 Chevron Usa Inc. - Richmond Fcc Flare V-731 3.65 13,701
16 Chevron Usa Inc. - Richmond Alkane Flare 0.24 893 16 Chevron Usa Inc. - Richmond "V-732, Alky-Poly" 0.08 282 16 Chevron Usa Inc. - Richmond Refinery Waste G 3.65 13,701 16 Chevron Usa Inc. - Richmond High Level Flare 3.65 13,701 18 Shell Oil Products Us - Martinez Refinery Waste Gas F 11.60 43,532 18 Shell Oil Products Us - Martinez Opc1_Fxg Flare 73.80 277,023 18 Shell Oil Products Us - Martinez Logi2-Lpg Loadin 2.53 9,508 18 Shell Oil Products Us - Martinez Lrgo Flare 0.30 1,115 18 Shell Oil Products Us - Martinez Opc7_Hc Flare 24.66 92,583 21 Tricor Refining (Prev. Golden Bear Oil Specialties) Lube Oil Finishing 0.00 -

30.1 Conocophillips Co. - Rodeo (Prev. Phillips 66 Co.) Refinery Waste Gas F 5.48 20,552

30.1 Conocophillips Co. - Rodeo (Prev. Phillips 66 Co.) C-1 Flare 15.51 58,228

30.2 Conocophillips Co. - Santa Maria (Prev. Phillips 66 Co.) Incinerators 0.67 2,504

31 Tesoro (Prev. Ultramar Inc.) 39.24 147,286 31 Tesoro (Prev. Ultramar Inc.) 8.21 30,826 31 Tesoro (Prev. Ultramar Inc.) 39.24 147,286 31 Tesoro (Prev. Ultramar Inc.) 39.24 147,286 31 Tesoro (Prev. Ultramar Inc.) 39.24 147,286 33 Valero Refining Co. - Benicia Refinery Waste Gas F 15.51 58,228

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to the Petr oleum Refinery NSPS – Attachment A January 25, 2012

A-2 Attachment A. Flare Data from 20 02 National Emissions Inventory

Facility Number Facility Name Emission Unit Description Annual CO Emissions

per flare

(tpy) Projected Flow Rate

(1000 scf/yr) 33 Valero Refining Co. - Benicia Refinery Waste Gas F 5.48 20,552 37 Valero Refining Co. (Prev. Motiva Enterprises LLC) Propane Pit Flare 1.60 6,006

37 Valero Refining Co. (Prev. Motiva Enterprises LLC) Repower - Clean Gas Flare 798.30 2,996,622

37 Valero Refining Co. (Prev. Motiva Enterprises LLC) Repower - Raw Gas Flare 112.40 421,922

37 Valero Refining Co. (Prev. Motiva Enterprises LLC) Flare System 18.90 70,946

37 Valero Refining Co. (Prev. Motiva Enterprises LLC) Accidental Releases 0.00 -

39 Chevron Hawaii Refinery Fcc Flare, Vocs 19.51 73,236 39 Chevron Hawaii Refinery Crude Flare, Vocs 19.51 73,236 40 Tesoro Hawaii Corp. Refinery Flare 0.11 424 40 Tesoro Hawaii Corp. Refinery Flare 49.56 186,051 41 Pdv Midwest Refining Llc (Citgo Petroleum) South Refinery Flare Gas Recovery System 844c-3 2.66 9,985

46 Conocophillips Co. (Prev. Phillips 66 Co.) Process Unit Vents To Flares 100.94 378,904

46 Conocophillips Co. (Prev. Phillips 66 Co.) N Prop Ground Flare(Hydrocarbon Recovery) 13.27 49,812

46 Conocophillips Co. (Prev. Phillips 66 Co.) Aromatic High Pressure Flare (Hydrocarbon Recovery Flare) 5.60 21,021

46 Conocophillips Co. (Prev. Phillips 66 Co.) Aromatic Low Pressure Flare (Hydrocarbon Recovery Flare) 11.87 44,557

46 Conocophillips Co. (Prev. Phillips 66 Co.) Wrr-16 Alkylation Unit 60.53 227,215

46 Conocophillips Co. (Prev. Phillips 66 Co.) Distill Flare (Hydrocarbon Recovery) 4.20 15,766

48 Countrymark Cooperative Inc. Flare 3.21 12,064 53 Marathon Petroleum Company Llc Point 0qu 0.00 - 54 Somerset Refinery Inc Point 004 0.49 1,833 56 Calcasieu Refining Co 0.00 - 56 Calcasieu Refining Co 0.00 -
57 Calumet Lubricants Co. - Cotton Valley 0.00 -

61 Citgo Petroleum Corp. - Lake Charles 16.00 60,060

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to the Petr oleum Refinery NSPS – Attachment A January 25, 2012

A-3 Attachment A. Flare Data from 20 02 National Emissions Inventory

Facility Number Facility Name Emission Unit Description Annual CO Emissions

per flare

(tpy) Projected Flow Rate

(1000 scf/yr) 61 Citgo Petroleum Corp. - Lake Charles 27.00 101,351

61 Citgo Petroleum Corp. - Lake Charles 27.00 101,351

61 Citgo Petroleum Corp. - Lake Charles 31.00 116,366

61 Citgo Petroleum Corp. - Lake Charles 27.00 101,351

61 Citgo Petroleum Corp. - Lake Charles 27.00 101,351

61 Citgo Petroleum Corp. - Lake Charles 27.00 101,351

61 Citgo Petroleum Corp. - Lake Charles 27.00 101,351

61 Citgo Petroleum Corp. - Lake Charles 27.00 101,351

61 Citgo Petroleum Corp. - Lake Charles 27.00 101,351

61 Citgo Petroleum Corp. - Lake Charles 1.00 3,754

61 Citgo Petroleum Corp. - Lake Charles 11.00 41,291

61 Citgo Petroleum Corp. - Lake Charles 27.00 101,351

61 Citgo Petroleum Corp. - Lake Charles 53.00 198,949

61 Citgo Petroleum Corp. - Lake Charles 2.00 7,508

61 Citgo Petroleum Corp. - Lake Charles 0.00 -

62 Conocophillips Co. - Westlake (Prev. Conoco Inc.) 18.00 67,568

66 Motiva Enterprises,Llc/Convent 0.00 - 66 Motiva Enterprises,Llc/Convent 0.00 - 66 Motiva Enterprises,Llc/Convent 35.00 131,381 66 Motiva Enterprises,Llc/Convent 55.00 206,456 66 Motiva Enterprises,Llc/Convent 108.00 405,405 74 Valero Refining Co. - Krotz Springs 16.00 60,060

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to the Petr oleum Refinery NSPS – Attachment A January 25, 2012

A-4 Attachment A. Flare Data from 20 02 National Emissions Inventory

Facility Number Facility Name Emission Unit Description Annual CO Emissions

per flare

(tpy) Projected Flow Rate

(1000 scf/yr) 74 Valero Refining Co. - Krotz Springs 5.00 18,769

78 Chevron Products Company, Pascagoula Ref Aa-384 159.00 596,847

78 Chevron Products Company, Pascagoula Ref Aa-591 320.00 1,201,201

78 Chevron Products Company, Pascagoula Ref Aa-381 134.00 503,003

78 Chevron Products Company, Pascagoula Ref Aa-382 256.00 960,961

78 Chevron Products Company, Pascagoula Ref Aa-383 263.00 987,237

78 Chevron Products Company, Pascagoula Ref Aa-592 205.00 769,520

78 Chevron Products Company, Pascagoula Ref Aa-757 102.00 382,883

82 Cenex Harvest States 1.00 3,754 83 Conocophillips Co. (Prev. Conoco Inc.) 3.00 11,261

84 Exxonmobil Billings Refinery 8.00 30,030 84 Exxonmobil Billings Refinery 0.00 - 85 Montana Refining 0.00 - 87 Hess Corporation (Prev. Amerada-Hess Corp.) RF; The Refinery Flare Is A Safety Device For Combusting Emergency Releases From 11.14 41,817

88 Sunoco, Inc. (Prev. Coastal Eagle Point Oil Co.) Refinery Fla; Refinery Plant Flare System To Control Relief Gas Releases Through 5.78 21,697

90 Valero Refining Co.- N.J. Sru Therm.Ox; Sru Thermal Oxidizer 0.27 1,014

91 Giant Industries Inc. - Bloomfield F-1 Flare Zink 1.22 4,580 95 Bp Products North America Inc East Flare 276.66 1,038,514 95 Bp Products North America Inc Sru #1 Flare 11.47 43,056 95 Bp Products North America Inc West Flare 83.16 312,162 95 Bp Products North America Inc East Acid Gas Flare 11.47 43,056 96 Marathon Petroleum Company Llc North Area Flare 0.22 826 96 Marathon Petroleum Company Llc South Area Flare 0.14 526 99 Conocophillips Co. (Prev. Conoco Inc.) South Plant Flare 3.20 12,027

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to the Petr oleum Refinery NSPS – Attachment A January 25, 2012

A-5 Attachment A. Flare Data from 20 02 National Emissions Inventory

Facility Number Facility Name Emission Unit Description Annual CO Emissions

per flare

(tpy) Projected Flow Rate

(1000 scf/yr) 99 Conocophillips Co. (Prev. Conoco Inc.) Div. C Flare For Alky, Cat Poly Coker, #2 Reformer 140.22 526,340

99 Conocophillips Co. (Prev. Conoco Inc.) West Flare For Lube Plant, No. 1 CTU, No. 4 CTU, SGP 11.71 43,971

99 Conocophillips Co. (Prev. Conoco Inc.) East Plant Flare - South For No. 3 Reformer 6.94 26,059

100 Wynnewood Refining Co. (Prev. Gary-Williams Energy Corp.) North Vapor Recovery Backup Flare 0.04 150

100 Wynnewood Refining Co. (Prev. Gary-Williams Energy Corp.) South Vapor Recovery Flare 4.28 16,066

100 Wynnewood Refining Co. (Prev. Gary-Williams Energy Corp.) Peabody Flare 0.01 38

101 Sinclair Oil Corp Flares No 1 & No 2 (Point 5) 53.81 201,989 102 Sunoco Inc Wpu Flare Id 266 0.64 2,402 102 Sunoco Inc #2 Alkyllation Flare Id 267 16.35 61,374 102 Sunoco Inc Coker Flare Id 268 1.29 4,854 102 Sunoco Inc Lube Flare Id 269 0.51 1,907 104 American Refining Group Inc. Refinery Gas Flare 3.33 12,500 105 Sunoco Inc (R&M)/Marcus Hook Refinery 12 Plant Flare 2.15 8,071

105 Sunoco Inc (R&M)/Marcus Hook Refinery 10 Plant Flare 1.50 5,631

106 Sunoco Inc. - Philadelphia Gp Flare 433 6.00 22,523 106 Sunoco Inc. - Philadelphia Gp Flare 1231 40.60 152,402 106 Sunoco Inc. - Philadelphia Gp Flare 1232 0.00 - 106 Sunoco Inc. - Philadelphia Flare At Srtf 8.60 32,282 107 Conocophillips Co. (Prev. Phillips 66 Co.) Main Flare 237.10 890,015

109 Valero Refining Co. (Prev. Premcor Refining, Prev. Williams Refining LLC) 93.90 352,477

111 Alon USA Energy Inc. (Prev. Alon USA LP) Southside Flare 0.56 2,120

111 Alon USA Energy Inc. (Prev. Alon USA LP) Tank From Flare 0.26 986

111 Alon USA Energy Inc. (Prev. Alon USA LP) Crude Unit Flare 1.06 3,988

111 Alon USA Energy Inc. (Prev. Alon USA LP) North Side Flare (East) 1.06 3,988

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to the Petr oleum Refinery NSPS – Attachment A January 25, 2012

A-6 Attachment A. Flare Data from 20 02 National Emissions Inventory

Facility Number Facility Name Emission Unit Description Annual CO Emissions

per flare

(tpy) Projected Flow Rate

(1000 scf/yr) 111 Alon USA Energy Inc. (Prev. Alon USA LP) Reformer Flare 0.38 1,424

111 Alon USA Energy Inc. (Prev. Alon USA LP) Gtr Asphalt Vcu 0.05 193

112 Total Petrochemicals Inc. (Prev. Atofina Petrochemicals, Inc.) Marine Dock Flare 1 7.96 29,880

112 Total Petrochemicals Inc. (Prev. Atofina Petrochemicals, Inc.) Benzene Vapor Combustor 1.28 4,805

112 Total Petrochemicals Inc. (Prev. Atofina Petrochemicals, Inc.) East End Tanks Flare 7.32 27,477

113 Bp - Texas City Flare #3 10.82 40,614 113 Bp - Texas City Flare #4 0.88 3,304 113 Bp - Texas City Ultracracker Flare 1.97 7,394 113 Bp - Texas City Flare No. 1 1.09 4,103 113 Bp - Texas City Flare #2 4.81 18,054 113 Bp - Texas City Hydrogen Plant Flare 0.69 2,596 113 Bp - Texas City Resid/Cat Feed Flare 1.37 5,155 113 Bp - Texas City Sulfur Recovery Unit 0.74 2,770 113 Bp - Texas City Flare 11.76 44,141 113 Bp - Texas City Aru Benzene Flare 0.45 1,705 113 Bp - Texas City Acid Plant 0.00 - 113 Bp - Texas City Aromatics Unit #2 5.39 20,233 113 Bp - Texas City Wastewater Treatment Plant Flare 47.99 180,143

114 Western Refining Co. LP - North (Prev. Chevron USA Inc.) Rheniformer Flare 0.25 938

114 Western Refining Co. LP - North (Prev. Chevron USA Inc.) Relief Gas Flare 3.00 11,261

114 Western Refining Co. LP - South (Prev. Chevron USA Inc.) Process Flare 3.08 11,562

114 Western Refining Co. LP - South (Prev. Chevron USA Inc.) S.W.S. Emergency Flare 0.49 1,839

117 Pasadena Refining Systems Inc. (Prev. Crown Central Petroleum Corp.) Emergency Flare - East 1.37 5,154

117 Pasadena Refining Systems Inc. (Prev. Crown Central Petroleum Corp.) Emergency Flare - West 3.64 13,661

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to the Petr oleum Refinery NSPS – Attachment A January 25, 2012

A-7 Attachment A. Flare Data from 20 02 National Emissions Inventory

Facility Number Facility Name Emission Unit Description Annual CO Emissions

per flare

(tpy) Projected Flow Rate

(1000 scf/yr) 118 Exxonmobil Corp. - Baytown Flare Stack 04 (Wlfs) 47.79 179,390 118 Exxonmobil Corp. - Baytown Flare Stack 05 (Wlfs) 3.69 13,846 118 Exxonmobil Corp. - Baytown Flare Stack 06 (Wlfs) 7.22 27,089 118 Exxonmobil Corp. - Baytown Flare Stack 11 (Fecc) 0.16 602 118 Exxonmobil Corp. - Baytown Flare Stack 14 (Fecc) 26.62 99,928 118 Exxonmobil Corp. - Baytown Flare Stack 03 (Wlfs) 3.21 12,039 118 Exxonmobil Corp. - Baytown Flare Stack 15 (Lcc) 6.09 22,875 118 Exxonmobil Corp. - Baytown Flare Stack 16 (Lcc) 43.62 163,738 118 Exxonmobil Corp. - Baytown Flare Stack 17 (Fncc) 6.86 25,735 118 Exxonmobil Corp. - Baytown Flare Stack 20 6.86 25,735 118 Exxonmobil Corp. - Baytown Flare Stack 21 (Fncc) 6.86 25,735 118 Exxonmobil Corp. - Baytown Flare Stack 18 (Fncc) 6.86 25,735 118 Exxonmobil Corp. - Baytown Flare Stack 22 (Fncc) 0.00 - 118 Exxonmobil Corp. - Baytown Flare Stack 25 (Fxk) 0.00 - 118 Exxonmobil Corp. - Baytown Flare Stack 26 (Fxk) 444.82 1,669,729 118 Exxonmobil Corp. - Baytown Flare Stack 27 (Ps7) 1.28 4,816 119 Exxonmobil Corp. - Beaumont Flare System Chd-1 Flare 13.03 48,914 119 Exxonmobil Corp. - Beaumont Flare System Chd-2 Flare 2.00 7,505 119 Exxonmobil Corp. - Beaumont Flare System High Pressure Flare 13.03 48,914

119 Exxonmobil Corp. - Beaumont Flare System Coker Flare 13.03 48,914 119 Exxonmobil Corp. - Beaumont Flare System Low Pressure Flare 13.03 48,914

119 Exxonmobil Corp. - Beaumont Flare System No.6 Flare 13.03 48,914 119 Exxonmobil Corp. - Beaumont Flare System No. 7 Flare 13.03 48,914 119 Exxonmobil Corp. - Beaumont Flare System Fcc Flare 13.03 48,914 119 Exxonmobil Corp. - Beaumont Flare System Isom Flare 13.03 48,914 120 Flint Hills Resources Lp - Corpus Christi East West Flare 4.04 15,180

120 Flint Hills Resources Lp - Corpus Christi East Emergency Flare 22.20 83,328

120 Flint Hills Resources Lp - Corpus Christi West 2nd Stage (Main,Ag,Uf)Flare 37.84 142,030

120 Flint Hills Resources Lp - Corpus Christi West 1st Stage Flare 14.92 55,991

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to the Petr oleum Refinery NSPS – Attachment A January 25, 2012

A-8 Attachment A. Flare Data from 20 02 National Emissions Inventory

Facility Number Facility Name Emission Unit Description Annual CO Emissions

per flare

(tpy) Projected Flow Rate

(1000 scf/yr) 120 Flint Hills Resources Lp - Corpus Christi West 3rd Stage Flare 12.39 46,509

121 Delek Refining Ltd (Prev. Lagloria Oil & Gas Co.) Flare No. 3 24.82 93,168

121 Delek Refining Ltd (Prev. Lagloria Oil & Gas Co.) Flare No. 1 6.55 24,587

121 Delek Refining Ltd (Prev. Lagloria Oil & Gas Co.) Flare No. 5 1.23 4,598

121 Delek Refining Ltd (Prev. Lagloria Oil & Gas Co.) Flare No. 2 7.26 27,260

121 Delek Refining Ltd (Prev. Lagloria Oil & Gas Co.) Flare No. 4 7.91 29,684

121 Delek Refining Ltd (Prev. Lagloria Oil & Gas Co.) Wastewater Flare 1.12 4,204

122 Houston Refining Lp Flare 338k0007 88.09 330,681 122 Houston Refining Lp Flare 338k0008 216.80 813,812 122 Houston Refining Lp Flare 338k0001 7.92 29,719 122 Houston Refining Lp North Plant Flare ("Merox Flare") 11.70 43,918

122 Houston Refining Lp Flare 338k0005 0.58 2,160 123 Marathon Petroleum Company Llc V.D.U. Flare 0.13 469 125 Conocophillips Co. - Borger (Prev. Phillips 66 Co.) East Refinery Flare 62.59 234,964

125 Conocophillips Co. - Borger (Prev. Phillips 66 Co.) West Refinery Flare 14.80 55,567

125 Conocophillips Co. - Borger (Prev. Phillips 66 Co.) Cat Flare 39.24 147,301

125 Conocophillips Co. - Borger (Prev. Phillips 66 Co.) Ngl Non-Corrosive Flare 131.52 493,699

125 Conocophillips Co. - Borger (Prev. Phillips 66 Co.) Ngl Corrosive Flare 19.40 72,817

125 Conocophillips Co. - Borger (Prev. Phillips 66 Co.) Ngl Acid Gas Flare 21.85 82,026

125 Conocophillips Co. - Borger (Prev. Phillips 66 Co.) 100m Swt Brine Flare Pit @ Jtf 0.09 340

125 Conocophillips Co. - Borger (Prev. Phillips 66 Co.) 100m Sour Brine Flare Pit @ Jtf 0.09 340

125 Conocophillips Co. - Borger (Prev. Phillips 66 Co.) 55m Sour Brine Flare Pit @ Jtf 0.09 340

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to the Petr oleum Refinery NSPS – Attachment A January 25, 2012

A-9 Attachment A. Flare Data from 20 02 National Emissions Inventory

Facility Number Facility Name Emission Unit Description Annual CO Emissions

per flare

(tpy) Projected Flow Rate

(1000 scf/yr) 125 Conocophillips Co. - Borger (Prev. Phillips 66 Co.) 100m Swt Brine Flare Pit @ Jtf 0.09 340

125 Conocophillips Co. - Borger (Prev. Phillips 66 Co.) 30m Swt Brine Flare Pit @ Jtf 0.09 340

125 Conocophillips Co. - Borger (Prev. Phillips 66 Co.) Ards Derrick Flare 51.07 191,704

125 Conocophillips Co. - Borger (Prev. Phillips 66 Co.) Ards Hydrocarbon Flare 38.28 143,676

126 Conocophillips Co. - Sweeny (Prev. Phillips 66 Co.) Sour Water Stripper Flare 0.72 2,691

126 Conocophillips Co. - Sweeny (Prev. Phillips 66 Co.) Dea Stripper Flare 1.20 4,498

127 Valero Refining Co. - Port Arthur (Prev. Premcor Refining Group Inc.) Emergency Flare No.19 0.00 -

128 Deer Park Refining Limited Partnership (Shell Oil Products Us) Ep Flare:East Prop Flare Stack 293.43 1,101,467

128 Deer Park Refining Limited Partnership (Shell Oil Products Us) Flarelub:Lube Flare 5.52 20,716

128 Deer Park Refining Limited Partnership (Shell Oil Products Us) Wp Flare:West Prop Flare Stack 41.10 154,272

128 Deer Park Refining Limited Partnership (Shell Oil Products Us) Flarelht:Lht Flare 6.57 24,662

128 Deer Park Refining Limited Partnership (Shell Oil Products Us) Flnflare:North Property Flare 111.32 417,858

128 Deer Park Refining Limited Partnership (Shell Oil Products Us) Ckgflare:Coker/Goht Flare 242.46 910,148

129 Trigeant LTD Flare Pilot 1.01 3,791 129 Trigeant LTD Flare Streams 67.96 255,105 129.5 South Hampton Resources Inc. (Prev. South Hampton Refining Co.) Plant Flare 1.48 5,556

130 Valero Energy Corp. - Three Rivers (Prev. Diamond Shamrock Refining) West Plant Flare 9.74 36,572

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to the Petr oleum Refinery NSPS – Attachment A January 25, 2012

A-10 Attachment A. Flare Data from 20 02 National Emissions Inventory

Facility Number Facility Name Emission Unit Description Annual CO Emissions

per flare

(tpy) Projected Flow Rate

(1000 scf/yr) 130 Valero Energy Corp. - Three Rivers (Prev. Diamond Shamrock Refining) Hcu Flare 12.46 46,767

130 Valero Energy Corp. - Three Rivers (Prev. Diamond Shamrock Refining) East Plant Flare 25.36 95,203

130 Valero Energy Corp. - Three Rivers (Prev. Diamond Shamrock Refining) Dot/Btx Flare 13.47 50,568

131 Valero Energy Corp. - Mckee (Prev. Diamond Shamrock Refining) Refinery & Gasoline Plant Units To Flare 22.58 84,764

131 Valero Energy Corp. - Mckee (Prev. Diamond Shamrock Refining) F.C.C. Units To Flare 24.28 91,124

131 Valero Energy Corp. - Mckee (Prev. Diamond Shamrock Refining) H.C.U. Unit To Flare 11.87 44,556

131 Valero Energy Corp. - Mckee (Prev. Diamond Shamrock Refining) Flare "Fl-4" Pilot 0.41 1,551

132 Valero Refining Co. - Corpus Christi East Sour Water Stripper Emergency Flare 1.25 4,681

132 Valero Refining Co. - Corpus Christi West Main Flare 8.54 32,057

132 Valero Refining Co. - Corpus Christi West M.T.B.E. Flare 0.00 -

132 Valero Refining Co. - Corpus Christi West Main Flare & Acid Gas 0.00 -

132 Valero Refining Co. - Corpus Christi West Ground Flare 31.13 116,854

134 Valero Refining Co. - Texas City Safety Flare No. 2 19.40 72,813 134 Valero Refining Co. - Texas City Flare No.4 11.51 43,197 134 Valero Refining Co. - Texas City No. 1 Flare 1.23 4,619 134 Valero Refining Co. - Texas City Safety Flare No. 3 44.43 166,780 134 Valero Refining Co. - Texas City Sws Emergency Flare 0.00 - 135 Tesoro - Salt Lake City 27.19 102,072 135 Tesoro - Salt Lake City 44.98 168,853 135 Tesoro - Salt Lake City 4.35 16,343 136 Chevron - Salt Lake City 11.23 42,161

### Technical Memorandum – Impact Estimates for Fuel Gas Combustion Device and Flare Regulatory Options for Amendments to the Petr oleum Refinery NSPS – Attachment A January 25, 2012

A-11 Attachment A. Flare Data from 20 02 National Emissions Inventory

Facility Number Facility Name Emission Unit Description Annual CO Emissions

per flare

(tpy) Projected Flow Rate

(1000 scf/yr) 136 Chevron - Salt Lake City 11.23 42,161 136 Chevron - Salt Lake City 11.23 42,161 137 Silver Eagle Refining 0.50 1,877 138 Big West Oil Co. (Flying J) 7.69 28,866 138 Big West Oil Co. (Flying J) 7.69 28,866 139 Holly Corp. (Prev. Phillips 66 Co.) 0.70 2,628 139 Holly Corp. (Prev. Phillips 66 Co.) 6.49 24,362 141 Bp West Coast Products - Cherry Point Low Pressure Flare 37.00 138,889

141 Bp West Coast Products - Cherry Point High Pressure Flare 95.00 356,607

142 Shell - Anacortes Flares (For Emergencies Only) 131.00 491,742 144 Tesoro Northwest Company Flares 44.00 165,165 147 Ergon - West Virginia, Inc. Plant Flares 13.52 50,751 147 Ergon - West Virginia, Inc. Plant Flares 0.84 3,153 150 Little America Refining Co. (Sinclair) Emergency Flare 0.90 3,378

151 Sinclair Oil Corp-Sinclair Refinery Refinery Flare 50.26 188,664 152 Wyoming Refining Co_Newcastle Refinery Flare Pilots (H_10) 0.10 375