# Memorandum

DATE: TO: 

### FROM: SUBJECT: February 25, 2013 EPA DocketNo. EPA-HQ-OAR-2011-0135 Peter Keller,

# E~**~r-~ ce**  ofAir Quality Planning and Standards, Air Quality Policy**Division/ ~**  

### New ource Review Permitting Impact Analysis for Proposed Tier 3 Gasoline Program 

### Introduction and Summary The EPA Office ofTransportation and Air Quality (OTAQ) is developing proposed Tier 3 fuel standards that will require lower sulfur concentrations for gasoline sold in the U.S. To meet the proposed Tier 3 standards, it will be necessary for some U.S. refineries to install new equipment and/or modify existing equipment and processes resulting in increased emissions ofsome regulated airpollutants. Refinery projects designed to meet the new fuel standards could trigger preconstruction air permitting requirements under the Clean Air Act and the EPA'sNew Source Review (NSR) regulations. The EPA Office ofAir Quality Planning and Standards (OAQPS) performed an analysis of potential NSRpermitting implications associated with the proposed Tier 3 fuel standards. Refinery-specific emissions increases were calculated based on process activity dataprovided by OTAQ 1 

### and representative industry emission factors. Resulting emissions increases were then compared to pollutant-specific "majormodification" permitting thresholds under the NSR regulations, including Prevention ofSignificant Deterioration (PSD) and Nonattainment New Source Review (NNSR), as applicable. Refineries projected to trigger PSD and/orNNSR for specific regulated NSR pollutants were identified. This memorandum documents the NSRpermitting analysis performed by OAQPS in support of the Tier 3 fuel standard proposal and presents findings and conclusions. In summary, the analysis supports the conclusion that NSRpermitting impacts associated with the proposed Tier 3 fuel standards are limited, with only 13 refineries projected to trigger PSD and/or NNSR for criteria pollutants and an additional 6 refineries projected to only trigger PSD for GHGs under the worst case impact scenario. 

### Calculation Approach A "majormodification" is aphysical change or change inthe method ofoperation thatresults in a significant emissions increase and a significantnet emissions increase.2 

### In accordance withthe major NSR applicability procedures contained in the federal regulations, the calculation

1 See Section 5.4 ofthe draft RIA. 2 This analysis is focused only on the project emissions increase (step 1) and does not address the net emissions increase calculation (step 2). Even ifa project results in a significant emissions increase, the source may be able to demonstrate that the net emissions increase is insignificant and thus the project does not constitute a major modification.approach for determining whether a significant emissions increase will occur depends uponthe type ofemissions units involved in the project. Three different tests canpotentially apply: (1) the actual-to-projected-actual test for projects that involve only existing emissions units, (2) the actual-to-potential test for projects that only involve construction ofnewemissions unit(s) and (3) the hybrid test for projects that involve multiple types ofemissions units. Under the hybrid test, the appropriate calculation is performedby emissions unit depending onnewvs. existing unit status. The terms "existing emissions unit" and "new emissions unit" are defined in the regulations. "Replacementunits" meeting specified criteria are treated as existing emissions units for the purpose ofcalculating emissions increases. 3
The actual-to-projected-actual test involves calculating baseline actual emissions andprojected actual emissions for each emissions unit affected by a project and calculating the project emissions increase as the sum ofthe differences between projected actual emissions and baseline actual emissions for each unit. The definition ofprojected actual emissions provides that the owner or operator shall exclude, in calculating the increase from a particular emissions unit, that portion ofthe unit's emissions following the project that the unit could have accommodated in the selected baseline actual emissions period and that are also umelatedto the project, including any increased utilization due to demand growth. The actual-to-potential test compares the potential to emit ofa unit with the baseline actual emissions and does notprovide for the exclusion ofany emissions in calculating the increase. For newemissions units other than those qualifying as replacement units, baseline actual emissions are zero. Because individual refinery project details were not available for this**analy~is,** OAQPS used a simplified approach to approximate the results from the application ofthe actual-to-projectedactual and/or or actual-to-potential tests for affected units at each source. The approach relied upon OTAQ estimates ofincremental energy, hydrogen and sulfur recovery demands associated with meeting the proposed Tier 3 fuel standards and the application ofscaling factors to adjust from base year to projected maximum annual rates and design rates for existing and newunits, respectively. Representative industry emission factors were identified for each affected emissions unit category (i.e., process heaters/boilers, hydrogenplants and sulfur recovery units) and emissions increases were calculated as the product ofthe production or activity data (e.g., MMBtu energy demand)**an~** corresponding emission factors (e.g., lb/MMBtu). The activity data and emission factors used in the analysis are discussed in further detail below. 

### ActivityData OT AQ performed a refinery-by-refinery analysis ofprocess and equipment changes likely to be implemented to meet the proposed Tier 3 fuel standards and from this analysis generated refinery-specific estimates ofenergy demand, hydrogen demand and increased sulfur recovery

3 The actual-to-projected actual test was adopted in the federal regulations as part ofthe 2002 NSR Reform rulemaking (Reform Rule). At this time, the Reform Rule provisions are available to sources in a large majority of state/localjurisdictions either by delegation or adoption into state/local rules (most ofwhich are SIP approved). There may be isolated cases where; at the time that Tier 3 projects are being evaluated for NSR applicability, Reform Rule applicability procedures are not available. For the purpose ofthis analysis, it was assumed that the federal NSR applicability procedures were available for all affected sources because: I) this is the case for most refmeries presently, and 2) the analysis is sufficiently conservative such that applying alternative applicability calculations is not expected to significantly affect the overall conclusions. 2unit (SRU) loading for 111 U.S. refineries. 4 Energy demand includes fuel needed to generate process heat, steam and electricity. Hydrogen demand is associated with increased hydrotreating ofpost-fluid catalytic cracking (FCC) naphtha and light straight run (LSR) streams, which may involve new or revamped hydrotreater units. Increased SRU loading results from the increased fuel desulfurization and associated H2S generation. Two Tier 3 fuel standard implementation scenarios were evaluated for NSRpermitting impacts: 1. No Averaging, Banking & Trading (ABT) Scenario: Each refinery makes the required changes to produce 1 0-ppm sulfur gasoline; assumes no trading ofsulfur credits between any refineries, either owned by a common company or on the open market. 2. Primary ABT Scenario: Refineries are allowed to produce gasoline that exceeds the 10 ppm sulfur standard (i.e., 5 ppm) and generate credits for use at another refinery which does not comply with the 1 0 ppm sulfur standard. In this case, sulfur credits are assumed to be traded only betweenrefineries owned by the same parent company. This is the primary scenario for the Tier 3 fuel standard proposal. For each scenario, to estimate the Tier 3 emissions impacts, it was first necessary to establish the production volumes ofthe units that would be affected by the standards. A "normal operating" case reflecting calendar year volumes was developed using refinery-specific actual base-year (year 2009) production data and production-normalized impact data (e.g., MMBtuper 1000 bbl gasoline production and MMscfhydrogenper 1000 bbl gasoline production). Normal operating production rates were then scaled up to reflect maximum annual capacity utilization rates and further adjusted using "overdesign" factors in certain cases as summarized below. This scaling was done under the assumption that, for the purpose ofdetermining NSR applicability, each refinery would project emissions based on the maximum achievable productionrate for existing units and would use design capacity to calculate potential·to emit for

.newunits. Itwas not tied to any particular assumption about overall gasoline demand. • Forrefineries projected to meet Tier 3 sulfur specifications by revamping existing hydrotreater units, demands were scaled up to 92 percent ofthe refinery's maximum design production. Ifa particularrefinery ran its FCC at a utilization level above 92 percent in the base year, it was assumed thatthat refinery was already operating at its annual capacity and no adjustment was made. • Forrefineries projected to meet Tier 3 standards by installing newFCC posttreatment units (post-treaters), the same scale-up approach documented above for revamps was applied, and an additional overdesign factor of 15 percent was applied to represent a maximum stream day capacity. • For refineries projected to install newLSR treating units, the same approach was applied as documented above for newFCCpost-treaters. • For SRUs, the additional sulfur loading was calculatedbased onthe incremental sulfur reduction required to meet the proposed standards and the scaled-up production estimates documented above for FCC revamps. From the scaled utility demand data, low and high impact cases were designed for estimating emissions increases under each scenario as follows:

4 See Section 5.4 ofthe draft RIA. 

### 3

### • Low case: Each refiner buys its additional hydrogen, high octane blendstocks and electricity externally. • High case: Each refiner generates the required additional hydrogen, high octane blendstocks and electricity internally. The low case represents external sourcing ofsome ofthe energy and chemical demand associated with meeting the proposed standards, meaning that emissions associated with these activities do not occur from the refinery itselfand are not accounted for in determining NSR applicability. The high case represents internal production ofall required energy and chemical demand, meaning that these impacts do occur at the refinery itselfand are accounted for in determining NSR applicability. 

### Emission Factors The emission factors used to estimate Tier 3project emissions increases are documented in the table below. 

### Emission Factors

Unit Pollutant 

### EF Units Reference Heaters & NO, 0.040 lb/MMBtu Assumed average for new/modified units equipped Boilers with ultra-low NO, burners; consistent with NSPS subpart Ja for natural draft heaters (40 CFR 60.102a). Calculated based on 8 ppmv annual average S02limit sol 0

.012 lb/MMBtu in NSPS subpart Ja (40 CFR 60

. 1 02a). co 0

.040 lb/MMBtu Recent BACT determinations -burner design and good combustion practices

. voc 0.0055 lb/MMBtu AP-42 Chapter 1.4. PM 10 0.0075 lb/MMBtu AP-42 Chapter 1.4. PMz .s 0

.0075 lb/MMBtu AP-42 Chapter 1.4. H2S04 0.0004 lb/MMBtu Assumes 2% oxidation ofS02to S03 (non-SCR). 40 CFR 98 Tables C-1, C-2 (C02EF for fuel gas; C02e 130.6 lb/MMBtu CH4 & N2 0 EFs for_l)_etroleurn). H2Plant C02 25.0 tons/MMscfH2 Bonaquist, Dante. Analysis ofC02 Emissions, Reductions, and Capture for Large-Scale Hydrogen Production Plants, White Paper. Praxair, Oct. 2010. (Available in docket). SRU NO, 0.271 lb/ton S Calculated industry average EF based on 2005 NEI. so2 3

.792 lb/ton S Calculated industry average EF based on 2005 NEI. co 0

.882 lb/ton S Calculated industry average EF based on 2005 NEI. voc 0.039 lb/ton S Calculated industry average EF based on 2005 NEI. PMIO 0.020 lb/ton S Calculated industl}'_average EF based on 2005 NEI. PM2.s 0

.017 lb/ton S Calculated industl}'_average EF based on 2005 NEI. H2 S04 0

.290 lb/ton S Calculated as 5% ofS02EF corrected for mol. wt
. COz 806.9 lb/ton S Technical Support Document for the Petroleum Refining Sector: Proposed Rule for Mandatory Reporting ofGreenhouse Gases. EPA OAR, Sept. 8, 2008, p. 11

. (Available in docket). 

### 4

### Pollutants Evaluated: 

### The regulated NSRpollutants identified in the table above were determined to have some probability oftriggering majorNSR as a result ofprojects designed to

- meet the proposed Tier 3 fuel standards. Certain other regulatedNSRpollutants, including total

reduced sulfur (TRS), H2 S and reduced sulfur compounds (RSC) may be emitted at very low rates from potentially affected refinery units, but were determined to have little or no probability ofexceeding significant emission rate thresholds. Therefore, these pollutants were not included in the quantitative analysis. Heaters andBoilers: 

### The emission factors selected for refinery process heaters and boilers represent combustion emissions from refinery fuel gas (RFG) and/or natural gas. The worst case (higher emitting fuel) was assumed where fuel-specific factors were available. ForNOx, an emission factor of0.040 lb/MMBtu was selected to represent average emissions from new and modified refinery process heaters and boilers. In most cases, emissions at this level are achievable using ultra-lowNOx burners and without the addition ofadd-on controls such as selective catalytic reduction (SCR). Withthe use ofSCR, emissions substantially belowthis level, on the order ofO.Ollb/MMBtu or less are achievable. An 

### S02emission factor of0.012 lb/MMBtu was calculated based onthe NSPS subpart Ja annual average S02limit of8ppmv for fuel gas combustionunits. A CO emission factor of0.040 lb/MMBtu was selected based on recent BACTdeterminations that represent burner design and good combustion practices.5 

### VOC and PM emission factors are based onEPA AP-42 Chapter 1.4: Natural Gas Combustion and are consistentwithpermitprecedent for refinery heaters. 6 

### For sulfuric acid mist, it was conservatively assumed that 2 percent ofso2 emissions oxidize to so3 and then condense to form H2S04. A GHG emission factor of 130.6lb/MMBtu C02equivalent (C02e) was calculated as the sum ofC02, CH4 

### and N2

### 0 emission factors reported in 40 CFR98 (EPA GHG Reporting Rule, Subpart C) for fuel gas multiplied by their respective global warming potentials

.

. Hydrogen Plants: 

### In addition to emissions associated with process heat, hydrogen production by steam methane reforming (SMR) generates C02 

### emissions as a byproduct. The selected C02 

### emission factor of25 lb/MMscfH2 

### is based on data from Praxair, a major hydrogen plant engineering and design firm and hydrogen supplier to the refining industry inthe U.S. Sulfur Recovery Units: 

### Emissions from SRUs can vary significantly depending on design and upstream variables, making published emission factors inappropriate in general. To account for this variability, OAQPS derived industry average emission factors for mostpollutants based on total refinery SRU emissions reported in the 2005 National Emissions Inventory (NEI) database combined with sulfurplantproduction data from the U.S. Energy Information Administration (EIA). For sulfuric acid mist, it was conservatively assumed that 5 percent ofS02 emissions oxidize to S03 and then condense to form H2

### S04
.For GHGs, a C02 

### emission factor from the EPA Technical Support Document for the proposed GHG Reporting Rule for the petroleum refining sector was used.

5 Based on a review ofrecent BACT determinations documented in the EPA RACT/ BACT/LAER Clearinghouse available at:http://cfpub

.epa.gov/RBLC/index.cfin?action=Home.Home 6 Available at: http://www.epa.gov/ttn/chief/ap42/ch0 !/final/cO ls04.pdf 

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### AttainmentStatus The attainment status ofeachrefinery location for ozone and PM (PM2.s and PMw) was determined using nonattainment area designation information from the EPA Green Book website as ofDecember 14, 2012. 7 

### Based on the attainment status and classification (for ozone nonattainment areas), NNSR and PSD triggers were resolved for each**r~finery.** 

### For serious and severe ozone nonattainment areas, or areas required to maintainNSRprogramrequirements consistent with those designations under the prior 1-hour ozone standard as a result ofthe "antibacksliding"policy, major modification thresholds of25 tons per year were assumed for the precursors NOx and VOC, versus 40 tons per year in attainment areas and areas classified as marginal or moderate nonattainment.8 

### NSR Applicability Results The results ofthe Tier 3 projectNSR applicability analysis are summarized below for the lowest and highestNSR impact scenario/case combinations. In total, 111 refineries determined to be potentially affected bythe proposed standards were included in the analysis. No ABT Scenario; Low Case • 14 refineries trigger PSD and/or NNSR

. • 11 ofthe 14 refineries trigger PSD and/or NNSR for criteriapollutant(s) • 3 ofthe 14 refineries only trigger PSD for GHGs Primary ABT Scenario; High Case • 19 refineries trigger PSD and/or NNSR • 13 ofthe 19 refineries trigger PSD and/or NNSR for criteriapollutant(s) • 6 ofthe 19 refineries only trigger PSD for GHGs The pollutants driving majorNSR applicability, in descending order offrequency, are GHGs, NOx, PM2
.5 

### and PM10. 

### None ofthe otherpollutants evaluated, including S02, CO, VOC and H2 S04 

### exceeded major modification thresholds at any refinery. It 

### should also be noted that in several cases, emissions increases shown to trigger NSRwere very close to the respective thresholds, indicating that there would likely be opportunities to design these projects in such a way to avoid NSR applicability, at least for some pollutants. 

### Example Calculations The following example calculations illustrate the approach used to determine NSR applicability on a refinery-by-refinery basis. The calculations are based on hypothetical Tier 3 project impacts.

7 Available at: http://www.epa.gov/oaqpsOOl/greenbk/ 8 The significant emission rate (SER) threshold in severe ozone nonattainment areas is 25 tpy ofNOx and VOC. While the SER in serious nonattainment areas is 40 tpy ofNOx and VOC, increases in both serious and severe nonattainment areas are also affected by CAA §182(c)(6), which limits aggregated NOx and VOC emissions over a five-year period to less than 25 tpy to avoid major NSR. For the purpose ofthis analysis, a SER of25 tpy for NOx and VOC was conservatively assumed for both serious and severe ozone nonattainment areas. 6

### Assumptions • Refinery located in an area designated as attainment/unclassifiable for all criteria pollutants (PSD area) • Incremental demand estimates reflect "high case" assumptions, i.e., hydrogen and electrical power demand generated internally Tier 3 Incremental Refinery Demand Estimates: Total energy demand: 1,500,000 MMBtu/yr Hydrogen demand: 400 MMscf/yr SRUproduction: 150 tons S/yr Emissions Increase- NOx.;_ [(1,500,000 MMBtu/yr) x 

### (0.040 lb/MMBtu) 

### + (150 tons S/yr) x 

### (0.271lb/ton)] x 

### (1 ton/2,000 lb) 

### = 30.0 tons

### NOxlyr The applicable significant emission rate threshold for 

### NOx is 

### 40 tpy,· therefore, theprojectdoes not trigger PSD for

### NOx. Emissions Increase

- PM2.s: [(1,500,000 MMBtu/yr) x 

### (0.0075lb/MMBtu) 

### + (150 tons S/yr) x 

### (0.017lb/ton)] x (1 

### ton/2,000 lb) = 

### 5.63 tons PM2 .s/yr The applicable significant emission rate threshold for directPM2

.5is 10 tpy,· therefore, the projectdoes nottrigger PSD for PM2.5. 

### Emissions Increase- GHGs (C02u [(1,500,000 MMBtu/yr) x 

### (130.6 lb/MMBtu) 

### + (150 tons S/yr) x 

### (806.9lb/ton)] x 

### (1 ton/2,000 lb) 

### + (400 MMscfH2 /yr) x 

### (25 tons/MMscf) = 

### 108,011 tons C02e/yr The applicable "subject to regulation" thresholdfor GHGs is 

### 75,000 tpy C02e andthe applicable significant emission rate threshold is any increase on a mass basis; therefore, the project triggers PSD for GHGs.



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