Memorandum 

DATE: 

TO: 

FROM: 

SUBJECT: 

February 25, 2013 

EPA Docket No. EPA-HQ-OAR-2011-0135 

Peter Keller, E~~r-~ce of Air 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 of Transportation and Air Quality (OT AQ) 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 of some 

regulated air pollutants. Refinery projects designed to meet the new fuel standards could trigger 

preconstruction air permitting requirements under the Clean Air Act and the EPA's New Source 

Review (NSR) regulations. 

The EPA Office of Air Quality Planning and Standards (OAQPS) performed an analysis of 

potential NSR permitting implications associated with the proposed Tier 3 fuel standards. 

Refinery-specific emissions increases were calculated based on process activity data provided by 

OTAQ1 and representative industry emission factors. Resulting emissions increases were then 

compared to pollutant-specific "major modification" permitting thresholds under the NSR 

regulations, including Prevention of Significant Deterioration (PSD) and Nonattainment New 

Source Review (NNSR), as applicable. Refineries projected to trigger PSD and/or NNSR for 

specific regulated NSR pollutants were identified. 

This memorandum documents the NSR permitting 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 NSR permitting 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 "major modification" is a physical change or change in the method of operation that results in 

a significant emissions increase and a significant net emissions increase.2 In accordance with the 

major NSR applicability procedures contained in the federal regulations, the calculation 

1 See Section 5.4 of the 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 if a 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 upon the 

type of emissions units involved in the project. Three different tests can potentially 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 of new emissions unit(s) and 

(3) the hybrid test for projects that involve multiple types of emissions units. Under the hybrid 

test, the appropriate calculation is performed by emissions unit depending on new vs. existing 

unit status. The terms "existing emissions unit" and "new emissions unit" are defined in the 

regulations. "Replacement units" meeting specified criteria are treated as existing emissions units 

for the purpose of calculating emissions increases.3 

The actual-to-projected-actual test involves calculating baseline actual emissions and projected 

actual emissions for each emissions unit affected by a project and calculating the project 

emissions increase as the sum of the differences between projected actual emissions and baseline 

actual emissions for each unit. The definition of projected actual emissions provides that the 

owner or operator shall exclude, in calculating the increase from a particular emissions unit, that 

portion of the unit's emissions following the project that the unit could have accommodated in 

the selected baseline actual emissions period and that are also umelated to the project, including 

any increased utilization due to demand growth. The actual-to-potential test compares the 

potential to emit of a unit with the baseline actual emissions and does not provide for the 

exclusion of any emissions in calculating the increase. For new emissions 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 of the actual-to-projectedactual and/or or actual-to-potential tests for affected units at each source. The approach relied 

upon OTAQ estimates of incremental energy, hydrogen and sulfur recovery demands associated 

with meeting the proposed Tier 3 fuel standards and the application of scaling factors to adjust 

from base year to projected maximum annual rates and design rates for existing and new units, 

respectively. Representative industry emission factors were identified for each affected 

emissions unit category (i.e., process heaters/boilers, hydrogen plants and sulfur recovery units) 

and emissions increases were calculated as the product of the 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. 

Activity Data 

OT AQ performed a refinery-by-refinery analysis of process and equipment changes likely to be 

implemented to meet the proposed Tier 3 fuel standards and from this analysis generated 

refinery-specific estimates of energy demand, hydrogen demand and increased sulfur recovery 

3 The actual-to-projected actual test was adopted in the federal regulations as part of the 2002 NSR Reform 

rulemaking (Reform Rule). At this time, the Reform Rule provisions are available to sources in a large majority of 

state/local jurisdictions either by delegation or adoption into state/local rules (most of which 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 of this 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. 

2 
unit (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 

of post-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 NSR permitting impacts: 

1. No Averaging, Banking & Trading (ABT) Scenario: Each refinery makes the required 

changes to produce 1 0-ppm sulfur gasoline; assumes no trading of sulfur 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 between refineries 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 of the 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., MMBtu per 1000 bbl 

gasoline production and MMscfhydrogen per 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 of determining NSR applicability, each 

refinery would project emissions based on the maximum achievable production rate for existing 

units and would use design capacity to calculate potential· to emit for.new units. It was not tied to 

any particular assumption about overall gasoline demand. 

• For refineries projected to meet Tier 3 sulfur specifications by revamping existing 

hydrotreater units, demands were scaled up to 92 percent of the refinery's maximum 

design production. If a particular refinery ran its FCC at a utilization level above 92 

percent in the base year, it was assumed that that refinery was already operating at its 

annual capacity and no adjustment was made. 

• For refineries projected to meet Tier 3 standards by installing new FCC post treatment 

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 new LSR treating units, the same approach was applied 

as documented above for new FCC post-treaters. 

• For SRUs, the additional sulfur loading was calculated based on the 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 of the 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 of some of the energy and chemical demand 

associated with meeting the proposed standards, meaning that emissions associated with these 

activities do not occur from the refinery itself and are not accounted for in determining NSR 

applicability. The high case represents internal production of all required energy and chemical 

demand, meaning that these impacts do occur at the refinery itself and are accounted for in 

determining NSR applicability. 

Emission Factors 

The emission factors used to estimate Tier 3 project 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 60.1 02a). 

Calculated based on 8 ppmv annual average S02 limit 

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 of S02 to S03 (non-SCR). 

40 CFR 98 Tables C-1, C-2 (C02 EF for fuel gas; 

C02e 130.6 lb/MMBtu CH4 & N20 EFs for _l)_etroleurn). 

H2 Plant C02 25.0 tons/MMscf H2 Bonaquist, Dante. Analysis of C02 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. 

H2S04 0.290 lb/ton S Calculated as 5% of S02 EF corrected for mol. wt. 

COz 806.9 lb/ton S Technical Support Document for the Petroleum 

Refining Sector: Proposed Rule for Mandatory 

Reporting of Greenhouse Gases. EPA OAR, Sept. 8, 

2008, p. 11 . (Available in docket). 

4 
Pollutants Evaluated: The regulated NSR pollutants identified in the table above were 

determined to have some probability of triggering major NSR as a result of projects designed to 

- meet the proposed Tier 3 fuel standards. Certain other regulated NSR pollutants, including total 

reduced sulfur (TRS), H2S 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 

of exceeding significant emission rate thresholds. Therefore, these pollutants were not included 

in the quantitative analysis. 

Heaters and Boilers: 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. For NOx, an 

emission factor of 0.040 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-low NOx burners and without the addition of add-on controls such as 

selective catalytic reduction (SCR). With the use of SCR, emissions substantially below this 

level, on the order ofO.Ollb/MMBtu or less are achievable. An S02 emission factor of0.012 

lb/MMBtu was calculated based on the NSPS subpart Ja annual average S02limit of 8 ppmv for 

fuel gas combustion units. A CO emission factor of 0.040 lb/MMBtu was selected based on 

recent BACT determinations that represent burner design and good combustion practices. 5 VOC 

and PM emission factors are based on EPA AP-42 Chapter 1.4: Natural Gas Combustion and are 

consistent with permit precedent for refinery heaters. 6 For sulfuric acid mist, it was 

conservatively assumed that 2 percent of so2 emissions oxidize to so3 and then condense to 

form H2S04. A GHG emission factor of 130.6lb/MMBtu C02 equivalent (C02e) was calculated 

as the sum of C02, CH4 and N20 emission factors reported in 40 CFR 98 (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 of 25 lb/MMscf H2 is based on data from Praxair, a major hydrogen plant 

engineering and design firm and hydrogen supplier to the refining industry in the 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 most pollutants based on 

total refinery SRU emissions reported in the 2005 National Emissions Inventory (NEI) database 

combined with sulfur plant production data from the U.S. Energy Information Administration 

(EIA). For sulfuric acid mist, it was conservatively assumed that 5 percent of S02 emissions 

oxidize to S03 and then condense to form H2S04. 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 of recent 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 

5 
Attainment Status 

The attainment status of each refinery location for ozone and PM (PM2.s and PMw) was 

determined using nonattainment area designation information from the EPA Green Book website 

as of December 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 maintain NSR program requirements 

consistent with those designations under the prior 1-hour ozone standard as a result of the "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 of the Tier 3 project NSR applicability analysis are summarized below for the lowest 

and highest NSR impact scenario/case combinations. In total, 111 refineries determined to be 

potentially affected by the proposed standards were included in the analysis. 

No ABT Scenario; Low Case 

• 14 refineries trigger PSD and/or NNSR . 

• 11 of the 14 refineries trigger PSD and/or NNSR for criteria pollutant(s) 

• 3 ofthe 14 refineries only trigger PSD for GHGs 

Primary ABT Scenario; High Case 

• 19 refineries trigger PSD and/or NNSR 

• 13 of the 19 refineries trigger PSD and/or NNSR for criteria pollutant(s) 

• 6 of the 19 refineries only trigger PSD for GHGs 

The pollutants driving major NSR applicability, in descending order of frequency, are GHGs, 

NOx, PM2.5 and PM10 . None of the other pollutants evaluated, including S02, CO, VOC and 

H2S04 exceeded major modification thresholds at any refinery. It should also be noted that in 

several cases, emissions increases shown to trigger NSR were 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 of this 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 

SRU production: 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, the project does 

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 direct P M2.5 is 10 tpy,· therefore, the 

project does not trigger 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 and the 

applicable significant emission rate threshold is any increase on a mass basis; therefore, the 

project triggers PSD for GHGs. 

7