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4 - 1 

## Chapter 4 **Fuel Pr ogram** **Feasibility 4.1**  **Overview of**  **Refining Operations** Figure 4 - 1 shows a process flow diagram for a t yp ical complex refinery , capable of making a wide product slate (shown on the right side of the figure) from crude oil (input on the left). Following the figure is a brief description of key units and streams focusing more on the gasoline producing units. 1 It ’s important to note that not all refineries have all of these units, which is a key

factor in both the variation in their baseline sulfur levels as well as their cost of sulfur control.

**Gas ol**  **in e** 

**Ke rosine**  **Low Sul**  **fu r**  **Di es**  **el Jet F**  **uel Of**  **f-ro ad**  **Re sid**  Di stillate H ydrot reat er **Fl ui**  **dized Cat Cr** 

**acker** Vacuum To wer Hy drocracker Ref

orm er Crude To we r Napht

ha Spl itter St rai ght Run S pl itter Gas

Pl ant

Ar omat ics Ext raction Hy drotreater Isom erization H 2

H

2 H 2
H 2 H 2 Hy drogen Pl ant **Fuel G**  **as LPG** 

**Cr ude**  **Oi l**  **Nat ur** **al Ga** **s**

**Ar om**  **atics** Pol ym erization Al kylatio n



### A **B**

**Co ke**  Co ker 

### D **iagram o** **f a T**  **yp ic** **al C** **om pl** **ex Re** **fin ery**  **Fue**

**l O il**  **Di esel** 

**Figure 4**  **- 1**  **Process Flow Diagram for a Typical Complex Refinery** Crude Tower The purpose of the crude tower is to perform a distillation separation of crude oil into different streams for additional processing in the refinery and for the production of specific products. Crude oil is shipped to the refinery via pipeline, ship, barge, rail, or truck, whereupon it is sampled, t ested, and approved for processing. The crude oil is heated to between 650 ° F and 700 ° F and fed to crude distillation tower. Crude components vaporize and flow upward through the tower. Draw tray s are installed at specific locations up the tower from which desired side cuts or fractions are withdrawn. The first side - cut above the flash zone is usually atmospheric gasoil (AGO), then diesel and kerosene/jet fuel are the next side - cuts, in that order . The lightest***** E.O. 12866 Review**
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4 - 2 components, referred to here as straight run naphtha, remain in the vapor phase until they exit the tower overhead, following which they are condensed and cooled and sent to the naphtha splitter. Naphtha Splitter The purpose of the naphtha splitter is to perform a distillation separation of straight run naphtha into light straight run naphtha and heav y straight run naphtha. The feed can be split between the C5’s and C6’s in order to assure the C6’s and heavier are fed to the reformer. Naphtha Hy drotreater The purpose of the naphtha hy drotreat er is to reduce the sulfur of light and heav y straight run streams before those streams are refined further b y the isomerization and reformer units. Isomerization Unit The purpose for the isomerization unit is to convert the light naphtha from straight cha in hydrocarbons to branched chain hy drocarbons, increasing the octane of this stream. The isomerate is sent to gasoline blending. Reformer The purpose of the reformer unit is to convert heavy straight run (C6 to C8 or C9 hydrocarbons) into aromatic and other higher octane compounds (benzene is one of the aromatic compounds produced), typically necessary

to produce gasoline with sufficient octane. To protect the very expensive, precious metal catal ys t used in reformers, h eav y straight run naphtha must be hydrotreated first before it is fed to the reformer. As the reformer converts the feed hydrocarbons to aromatics, hydrogen and light gases are produced as by products. The liquid product, known as reformate, is sent directl y to gasoline blending, or to ar omatics extraction. Aromatics Extraction Unit The purpose of aromatics extraction is to separate the aromatic compounds from the rest of the hy drocarbons in reformate using chemical extraction with a solvent to concentrate the individual aromatic compounds, (mainly xylene and benzene) for sale to the chemicals market. Vacuum Tower The purpose of the vacuum distillation tower unit is to enable a refinery to produce more gasoline and diesel fuel out of a barrel of crude oil. It separates the vacuum gasoi l (VGO), which is fed to the FCC unit, from the vacuum tower bottoms (VTB) which is sent to the coker, or in other refineries is made into asphalt. Because most sulfur contained in crude oil is contained in the heaviest part of crude oil, the VGO and VTB are very high in sulfur. Fluidized Cataly

tic Cracker The purpose of the fluidized catal yt ic cracker is to convert heavy hydrocarbons, which have very low value, to higher value lighter hydrocarbons. AGO and VGO are the usual feeds to***** E.O. 12866 Review**
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4 - 3 a fluid catal yt ic cra cker (FCC). The full boiling range cracked product leaves the reactor and is sent to a fractionator. The overhead includes propane, prop yl ene, butane, butylene, fuel gas and FCC naphtha, which contains a significant amount of sulfur. There are two heav y streams; light cy cle oil (LCO), which can be hydrotreated and blended into diesel fuel or hydrocracked into gasoline; and heav y cy cle oil, sometimes called slurry oil, which can be used for refinery fuel. Very simple refineries do not have FCC units, and therefore, their gasoline is very low in sulfur. FCC Feed Hy drotreater or Mild Hydrocracker “A” FCC feed h ydrotreaters and mild hydrocrackers hydrotreat or mildly hydrocrack the feed to the FCC unit which provides two distinct benefits. First, by increas ing the amount of hydrogen in the feed to the FCC unit, the FCC unit increases the conversion of the feed to high value light products, particularly FCC naphtha which increases the gasoline yield. Second, hydrotreating the feed removes some contaminants i n the feed such as nitrogen and sulfur. Nitrogen in the feed negatively affects the FCC cataly st. Removing the sulfur in the feed helps in two way s. Some of the sulfur in the feed is released by the cracking process and results in high SO X emissions that would otherwise have to be controlled b y scrubbers

– the FCC feed hydrotreaters may

prevent the need to add a scrubber. Also, FCC feed hydrotreaters remove sulfur which can allow a refinery to comply

with gasoline sulfur standards. FCC Postreat Hy dtro treater “B” Postreat hydrotreaters solely hydrotreat the naphtha that is produced by the FCC unit to reduce its sulfur level which enables compliance with gasoline sulfur standards. The FCC naphtha is high in olefins which can be saturated by postreat hydrotreaters resulting in lower octane of the FCC naphtha. Vendor companies have developed postreat hydrotreating technologies which minimize this octane loss. Distillate Hydrotreater The purpose of the distillate h ydrotreater is to reduce the sulfur of d istillate, which is also called diesel fuel. Gas Plant The purpose of the gas plant is to use a series of distillation towers to separate various light hydrocarbons for further processing in the alkylation or pol ym erization units or for sale. Alkylation Unit The purpose of the alkyl ation unit is to chemically react light hydrocarbons together to produce a high quality , heavy gasoline product. Alkylation uses sulfuric or hydrofluoric acid as catal ys ts to react butylene or prop yl ene together with isobutan e. Following the main reaction and product separation, the finished alkyl ate is sent to gasoline blending. Alkylate is low in RVP. Poly

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4 - 4 The purpose of the polymerization unit is to react light hy drocarbons together to form a gasoline bl endstock. A poly merization unit, often referred to as a “cat pol y” is somewhat similar to an alkylation unit, in that both use light olefins to produce gasoline blendstocks. The feed is generall y prop yl ene and/or butylene from the gas plant. The product , called polygas is sent to gasoline blending. Coker Unit The purpose of the coker unit is to process vacuum tower bottoms (VTB) to coke and to crack a portion to various lighter h ydrocarbons. The hydrocarbons produced by the coker include cracked gases, coker naphtha, coker distillate and gas oil. The gas is fed to the gas plant, the naphtha to the naphtha hydrotreater after which the heavy coker naphtha is ty

picall y fed to the reformer , and the distillate either to distillate hydrotreating or to the hy drocracker. Hy drocracker The purpose of the h ydrocracker is to crack and “upgrade” the feedstock into higher value products. The feedstock to the hy drocracker is usually light cy cle oil (L CO) and coker distillate, poor quality

distillate blendstocks, whi ch are upgraded to diesel fuel, or cracked to gasoline. Heavier h ydrocarbons such as AGO and HVGO can be feedstocks as well. A more complete description for naphtha h ydrotreating is contained in Section 4.2 . **4.2 Feasibility of R**  **e mov**  **ing Sulfur from Gasoline** The case can be made in two way s that it is feasible to comply with the proposed 10 - ppm gasoline sulfur standard. First, feasibility can be demonstrated by

understanding the technologies currently

available which can achieve the necessary reductions in sulfur, and that these technologies are currentl y being used to achieve significant reductions in gasoline sulfur. The second way

to make the case that it is feasible to comply with the proposed 10 - ppm gasoline sulfur standard is t o highlight that refiners in certain countries or other regions are currentl y complying with a 10 - ppm gasoline sulfur cap standard. These two cases will be made below, but first we will review the source of sulfur in gasoline to understand how sulfur leve ls can be further reduced. 4.2.1 Source of Gasoline Sulfur Sulfur is in gasoline because it naturally occurs in crude oil. Crude oil contains any where from fractions of a percent of sulfur, such as less than 500 ppm (0.05 weight percent ) to as much as 30,000 p pm (3 percent ) . The average amount of sulfur in crude oil refined in the U.S. is about 14,000 ppm . Most of the sulfur in crude oil is in the heaviest part, or in the heaviest petroleum compounds, of the crude oil (outside of the gasoline boiling r ange). In the process of refining crude oil into finished products, such as gasoline, some of the heav y compounds are broken up, or cracked, into smaller compounds and the embedded sulfur can end up in gasoline. Thus, the refinery units which convert the heav y parts of crude oil into gasoline are the units most responsible for putting sulfur into gasoline.***** E.O. 12866 Review**
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4 - 5 The fluidized catal yt ic cracker (FCC) unit is a refinery processing unit that creates a high sulfur content gasoline blendstock. FCC naphtha contain s from hundreds to several thousand parts per million of sulfur. The FCC unit cracks large carbon molecules into smaller ones and produces an yw here from 2 5 to 50 percent of the gasoline in those refineries with FCC units . Because the FCC unit makes a gas oline blendstock out of the heavier, higher sulfur - containing compounds, more than 9 5 percent of sulfur in gasoline blendstocks comes from streams produced in that unit. When complying with the 30 - ppm Tier 2 gasoline sulfur standard, refiners reduced the sulfur content of the FCC naphtha. The impact of this action is described below in subsection 4.2.2 . Straight run naphtha is a gasoline blendstock which contains a moderate amount of sulfur. Straight run naphtha is the part of crude oil which after distillation in the atmospheric crude oil tower falls in the gasoline boiling range. The heaviest portion of straight run, which would have more sulfur, is normally desulfurized and reformed in the reformer (to improve its octane), s o its contribution to the gasoline pool is virtually nil. A The light straight run which contains the five - carbon hy drocarbons contains on the order of 100 ppm sulfur and if this material is not hydrotreated and processed in an isomerizaition unit, it is b lended directly into gasoline. Another refinery

unit which produces naphtha with a significant amount of sulfur is the coker unit. These units produce coke from the heav iest part of the crude oil. In the process of producing coke, a naphtha is produced that contains more than 3 , 000 ppm sulfur and man y very unstable olefins . Because this stream is highl y olefinic and unstable, refiners tend to h ydrotreat coker naphtha. Coker naphtha is normally split into two different streams. The six - to nine carbon hy drocarbons are hy drotreated along with the rest of the heavy naphtha and fed to the reformer. The five - carbon hy drocarbon part of coker naphtha is called light coker naphtha and usually contains on the order of several hundred parts per million sulfur. Light coker naphtha is usually hy drotreated along with the light straight run , and refined further in an isomerization unit if the refinery

has one . Other gasoline blendstocks contain little or no sulfur. Alkyl ate , which is produced from isobutene and b utylenes that contain a small amount of sulfur, can end up with a small amount of sulfur. Most refineries have less than 15 ppm sulfur in this pool, however, some refineries which feed coker naphtha to the alkylate plant can have much more. On average, a lkylate probabl y has about 10 ppm sulfur. One more gasoline blendstock with either very low or no sulfur is hydrocrackate, which is the naphtha produced b y hydrocrackers. Itis low in sulfur because the hydrocracking process removes the sulfur. Ethanol which is eventually blended into gasoline usually has very little or no sulfur . H owever, the hydrocarbon used as a denaturant and blended with ethanol at 2 percent is usually natural gasoline, a C5 to C7 naphtha from natural gas processing, and it contain s any where from a few parts per million to a couple hundred parts per million sulfur. After the denaturant is blended in, the denatured ethanol contains somewhere

A Sulfur interferes in the function of the precious metal catalyst used in the reforming process. As a result, refiners historically have desu lfurized the heavy straight run naphtha feed to the reformer from several hundred ppm sulfur dow n to less than 1 ppm.***** E.O. 12866 Review**
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4 - 6 between 0 and 10 ppm sulfur. To meet current pipeline and California specifications, denatu red ethanol must be less than 10 ppm sulfur. 4.2.2 Complying with the Current Tier 2 Gasoline Sulfur Standard It is important to understand the steps that refiners took to comply with the 30 - ppm Tier 2 gasoline sulfur standard because those capital investments a nd operational changes will play a major role in determining the steps that refiners take to compl y with a more stringent gasoline sulfur standard. The Tier 2 sulfur standard was promulgated February 10, 2000. 2 The sulfur standard requires that refiners reduce their annual average gasoline sulfur levels down to 30 ppm and each gallon of gasoline cannot exceed a per - gallon standard of 80 ppm. The sulfur standard s were phased in from 2004 to 2006. The only exceptions were western refiners (GPA) and small refiners who were given until 2008. Some small refiners had their gasoline sulfur deadlines extended through 2010 in the highway diesel fuel sulfur rule in exchange for on - time compliance there . As of January

1, 2011, all refineries are complying with the Tier 2 30 - ppm sulfur standard. A refinery ’s previous average gasoline sulfur level is an important factor which determined whether a refiner would need to make a substantial capital investment to meet the Tier 2 gasoline sulfur standard s . We believe that those refiners with low gasoline sulfur levels to begin with (i.e., gasoline sulfur levels lower than, perhaps, 50 ppm) probably did not invest in expensive capital. These refineries have very low sulfur levels due to one or more of a number of poss ible reasons. For example, some of these refiners may not have certain refining units, such as a fluidized catal ytic cracker (FCC) unit, or a coker, which convert heav y boiling stocks to gasoline. As stated above, these units push more sulfur into gasoli ne and their absence means much less sulfur in gasoline. Alternativel y, refiners may use a very

low sulfur (sweet) crude oil which can result in a low sulfur gasoline. Or, these refiners may have already

installed an FCC feed h ydrotreat er to improve the operations of their refinery which uses a heavier, higher sulfur (more sour) crude oil. As described above, this unit removes much of the sulfur from the heaviest portion of the heavy gas oil before it is converted into gasoline. Of the refiners in this first category , the refineries with average sulfur levels below 30 ppm may not have had to do any

thing to meet the Tier 2 standard s . On the other hand, those refineries which had sulfur levels above 30 ppm but below some level, such as 50 ppm, probabl y ar e meeting the 30 - ppm sulfur standard by employing operational changes only and avoid ed making capital investments. Most of the refineries with gasoline sulfur levels below 50 ppm prior to the Tier 2 investments either do not have a FCC unit, or if they do , they probabl y have an FCC feed h ydrotreating unit. The vast majority

of gasoline which was being produced was b y refineries with higher sulfur levels, and these refiners had to either adapt some existing hy drotreating capital or install new capital equ ipment in these refineries to meet the Tier 2 gasoline sulfur standard s . As stated above, the FCC unit is responsible for most of the sulfur in gasoline. Thus, investments for desulfurizing gasoline involved the FCC unit to maximize the sulfur reduction, and to minimize the cost. This desulfurization capital investment can be installed to treat the gas oil feed to the***** E.O. 12866 Review**
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4 - 7 FCC unit, or treat the gasoline blendstock which is produced b y the FCC unit. Each method has advantages and disadvantages.

4.2.2.1 Using FCC Fee d Pretreat Hy drotreating to Comply with Tier 2 Some refiners installed FCC feed hy drotreaters (also known as pretreaters) at their refineries to comply

with the Tier 2 gasoline sulfur standard s . FCC pretreaters treat the vacuum gas oil , heavy

coker gas oi l and, in some cases, atmospheric resid ual feed to the FCC unit using a hydrotreater or a mild hydrocracker. These units are designed to operate at high pressures and temperatures to treat a number of contaminants in the feed . Besides sulfur, FCC pretre aters also reduce nitrogen and certain metals such as vanadium and nickel. These nonsulfur contaminants adversel y affect the FCC catal ys t, so the addition of this unit would improve the functioning of the unit. Also, the hy drotreating which occurs in the FCC pretreater reacts hydrogen in the feedstock which increases the yield of the FCC unit by increasing the highest profit - making products produced b y refineries, such as gasoline and light olefins . 3 While FCC pretreaters provide yield benefits that offs et the capital costs of adding this t ype of desulfurization, the costs are still high enough that many refiners would have a hard time justifying the installation of this sort of unit. For a medium to large refinery (i.e., 150,000 - 200,000 BPCD), the capit al costs may exceed $250 million. Because of the higher temperatures and pressures involved, utility costs are expensive relative to postreat hydrotreating as explained below. Another justification for this approach is that it allows refiners to switch t o a heavier, more sour crude oil. These crude oils are less expensive per - barrel and can offset the increased utility cost of the FCC pretreater , providing that the combination of reduced crude oil costs and higher product revenues justify the switch. An other benefit for using FCC pretreaters is that the portion of the distillate pool which comes from the FCC unit would be partiall y h ydrotreated as well. This distillate blendstock, termed light cy cle oil, comprises a relativel y small portion of the total distillate produced in the refinery (about 20 percent of on - road diesel comes from light cy cle oil), and like FCC naphtha, light cy cle oil contributes a larger portion of the total sulfur which ends up in distillate. Thus, FCC pretreaters would also help a refiner meet the 15 - ppm highway and nonroad diesel fuel standards. In terms of desulfurization capability , FCC preateaters have different abilities to remove sulfur from the gas oil feed depending on the unit pressure. FCC pretreaters can be subdivided into high pressure units (1400 psi and above), medium pressure units (900 to 1400 psi), and low pressure units (under 900 psi). High pressure FCC pretreaters are capable of removing about 90 percent of the sulfur contained in the gas oil feedstock to the FCC unit, while low and medium pressure units are capable of removing 65 to 80 percent of the feed sulfur. 4 Because there is no postreating at man y of the refineries with FCC pretreaters, control of the feed to these units is a critical determining facto r for how well the FCC pretreater will function as desulfurizers. If the feed becomes too heav y, the concentration of contaminants increases and the catal ys t may lose its effectiveness. 5 FCC pretreaters improve desulfurization indirectly by improving the desulfurization performance of the FCC unit itself . When FCC units crack the vacuum gas oil into naphtha, about 90 percent of the sulfur is ty picall y cracked out of the hydrocarbons converted to FCC naphtha (or the FCC naphtha contains only about 10 perc ent of the sulfur present in the feed) and is removed as h ydrogen sulfide . When FCC units are preceded by FCC pretreaters , the amount***** E.O. 12866 Review**
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4 - 8 of sulfur in the feed which ends up in the FCC naphtha is only about 5 percent, which means that about 95 percent of the sulfur in the feed is removed from the FCC feed when it is cracked into FCC naphtha. This effect is caused b y the additional hydrogen which reacts with the feed hydrocarbons. With more hy drogen molecules available in the feedstock after hydrotreatment, the FCC cracking reactions can react more h ydrogen with the sulfur contained in the feed to produce more h ydrogen sulfide. For compl yi ng with Tier 2, refiners which alread y had or which installed high pressure FCC pretreaters were able to comply with the 30 - ppm sulfur standard without the need to install a FCC naphtha h ydrotreater. However, if a refinery had a low pressure, or perhaps even a medium pressure FCC feed hy drotreater, they were generally

less able to comply

with the 30 - ppm gasoline sulfur stan dard with the FCC h ydrotreater b y itself, and these refineries were more likely to also install an FCC postreater. 4.2.2.2 Using FCC Naphtha Postreat Hy drotreating to Comply with Tier 2 A less capital intensive alternative for reducing FCC naphtha sulfur levels to comply with Tier 2 is FCC naphtha h ydrotreating (also known as postreaters) . FCC postreaters onl y treat the gasoline blendstock produced b y the FCC unit. Understandabl y, this unit is much smaller because onl y about 50 to 60 percent of the feed to the FC C unit ends up as FCC naphtha, a gasoline blendstock. The unit is sometimes smaller than that as some refiners which choose to use a fixed bed h ydrotreater may only treat the heavier, higher sulfur portion of that stream with hydrotreating, and then treat the lighter fraction with another lower desulfurization cost technology . FCC postreaters operate at lower temperatures and pressures than FCC pretreaters , which further reduces the capital and operating costs associated with this type of desulfurization equipment. Furthermore, the feed to the FCC unit has corrosive properties which require that FCC pretreaters use more corrosi on - expensive metallurgy , which is not needed for postreaters. 6 For a medium to large - sized refinery , the capital costs are on the order of $70 million for a conventional FCC pretreaters

– less than half that of an FCC pretreater . One drawback of this desulfurization methodology is that the octane value and/or some of the gasoline yi eld may be lost depending on the process used for desulfurization. Octane loss occurs b y the saturation of high octane olefins which are produced b y the FCC unit. Most of the olefins are contained in the lighter fraction of FCC naphtha. 7 Increased olefin saturation usually means higher h ydrogen consumption. There can also be a loss in the gasoline yield caused by mild cracking which breaks some of the gasoline components into smaller fractions which are too light for blending into gasoline. If there is octane loss, two of the way s that the octane los s can be made up is by

blending in more ethanol, or by increasing the feed to or the severit y of the reformer, the aromatics production unit of the refinery . Sometimes vendors of FCC pretreater technologies design octane increasing capability into their d esigns, which is discussed below in the section about the individual postreater technologies. The loss of octane and gasoline yield caused by FCC postreating is lower with technologies which were developed prior to the implementation of the Tier 2 program . 8 These processes are termed selective because they achieve the lower sulfur while preserving much of the octane and gasoline yield ( they were designed specificall y for treating FCC naphtha ) . Octane is preserved because the hydrotreating units and their catal ys ts are specially designed to avoid***** E.O. 12866 Review**
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4 - 9 saturating olefins. These selective processes , or parts of these processes, usually operate at less severe conditions which result in less cracking preserv ing yi eld compared to conventional hydrotreating processes . The less severe conditions also lower the capital and operating costs for this process. The lower operating costs arise out of the reduced utility requirements (e.g., lower pressure). For example, because these processes are less severe, there is less saturation of olefins, which means that there is less h ydrogen used. Less olefin saturation also translates into less octane loss which would otherwise have to be made up b y octane boosting processing units in the refinery . The lower capital and operati ng costs of these newer FCC postreaters are important incentives for refiners to choose this desulfurization methodology over FCC pretreaters . For this reason, refiners chose to use the more recentl y developed FCC postreaters technologies for meeting the 30 - ppm Tier 2 gasoline sulfur standard. Not saturating the olefins to preserve octane and limit hydrogen consumption provides a different challenge. When the hydrogen sulfide is formed and there is a significant concentration of olefins present, the hydrogen sulfide compounds tend to react with the olefinic h ydrocarbon compounds forming mercaptan sulfur compounds. This reaction is called “recombination” because the removed sulfur recombines with the olefinic hy drocarbons contained in the naphtha. 9 This is particularly

a problem if the light cat naphtha is present in the hy drotreater because the highest concentration of olefins is in the light cat naphtha. The recombination reactions occur more readily

if the h ydrotreater is operated more severel y (at a higher temperature) to increase the sulfur removal, and the feed to the h ydrotreater is high in sulfur. However, while operating this ty pe of hy drotreater more severel y can result in the further removal of the original sulfur present in the h ydrocarbons, it also can result in the formation of more recombination mercaptans that results in a “floor” reached for the amount of sulfur that can be removed from the hy drocarbons. This cy cle of increased sulfur removal and simultaneous increase in recombination re sults in the saturation of more olefins and increases the consumption of hydrogen. There are a number of different vendor - specific technologies that each vendor may use to avoid or address recombination reactions as discussed below. It is important to no te that the technologies emplo ye d to reduce recombination may require the addition of some capital costs which offsets some or perhaps all the capital cost savings due to the milder operating conditions of these selective hy drotreater technologies compared to nonselective hy drotreating. One means to achieve high levels of desulfurization while avoiding much of the problem with recombination reactions is by using a two - stage h ydrodesulfurization methodology . A two stage unit has two desulfurization reacto rs, but instead of just adding additional reactor volume, the hy drocarbons exiting the first reactor are stripped of gaseous compounds (most importantly , the hy drogen sulfide is removed), injected with fresh hydrogen, and then h ydrodesulfurized again in th e second stage. Both reactors undergo modest desulfurization and hydrogen sulfide concentrations remain sufficientl y low to avoid recombination reactions. The downside of this approach is that the second stage incurs greater capital costs compared to sin gle - stage configurations. Because Tier 2 was not too constraining, we believe that refiners installed few, if any , two - stage desulfurization units to comply with those gasoline sulfur standards . Whatever strategy

chosen by

the refiner to comply

with T ier 2, a critical criterion is that the postreater be capable of cy cle lengths that match that of the FCC unit, which ty pically is 5 ye ars. If the postreater were to require a catal ys t changeout before the FCC unit requires a shutdown, either the refiner would have to shutdown the FCC unit earl y to mirror that of the***** E.O. 12866 Review**
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4 - 10 postreater, or need to store up the high sulfur FCC naphtha (this stream would be too high in sulfur to blend directl y to gasoline under the Tier 2 80 - ppm cap standard) until the postreater wa s started up again and is able to hydrotreat the stored up high sulfur FCC naphtha. We know of six FCC postreater technologies that refiners used to comply with the Tier 2 gasoline sulfur standard s . These are Axens (was IFP ) Prime G and Prime G+, Exxon Sc anfining, CDTech’s CDHy dro and HDS, Sinopec’s (was Phillips ) S - Zorb and UOP’s ISAL and Selectfining . Of the list of FCC postreaters , Axens Prime G+, Exxon Scanfining and UOP’s I SAL and Selectfining are fixed bed desulfurization technologies. These proce sses are called fixed bed because the cataly st resides in a fixed bed reactor. 10 The high sulfur gasoline blendstock is heated to a high temperature (on the order of 600 degrees Fahrenheit) and pumped to a high pressure to maintain the stream as a liquid . It is then combined with h ydrogen before it enters the reactor. The reactions occur within the bed of the catal ys t. While the petroleum is in contact with the catal ys t in the reaction vessel, the sulfur react s with hydrogen and is converted to hydrogen sulfide. Also, depending on the process, some of the olefin compounds which are present in the cracked stream are saturated which increases the amount of octane lost and hydrogen consumed. After the reactor, the gaseous compounds, which include unreacted hydrogen, hy drogen sulfide, and an y light end petroleum compounds which may have been produced in the reactor by cracking reactions, are separated from the liquid compounds by a gas/liquid separator. The hy drogen sulfide must be stripped out from the oth er compounds and then converted to elemental sulfur in a separate sulfur recovery unit . T he recovered sulfur is then sold. If enough h ydrogen is present, and it is economical to recover, it is separated from the remaining h ydrocarbon stream and recy cled. Otherwise, it is burned with light hy drocarbons as fuel gas. Despite the similarities, each of these desulfurization technologies has its differences. Axens Prime G+ desulfurization process largel y preserves olefins as its strategy for diminishing octane loss. 11 , 12 13 The Axens process emplo ys a selective hydrogenation unit (SHU) as a first step. The role of this unit is to saturate the unstable diolefin hydrocarbons in a hydrogen rich environment , and react the light mercaptan and sulfide hydrocarbons t ogether. The SRU also converts exterior olefins to interior olefins which results in a small increase in octane. The mild operating conditions of the SHU tend to avoid the saturation of monoolefins. After exiting the SRU, the FCC naphtha is sent to a di stillation column which separates the light FCC naphtha ( ty pically comprising about one fourth of the total cat naphtha) from the heavy naphtha. Because the light sulfur compounds were reacted together and those compounds no longer fall within the light c at naphtha boiling range, the light cat naphtha is low in sulfur and can be blended directly into gasoline. The heav y cat naphtha which is naturally high in sulfur and which also contains the self - reacted light mercaptans and sulfides from the SHU, is sent to a fixed bed hy drotreater. The fixed bed hydrotreater contains both cobalt - moly bdenum and nickel - moly bdenum catal ys t. An important way

that Axens avoids recombination reactions is by separating the light sulfur compounds from the light naphtha and ke eping the light naphtha out of the fixed bed hydrotreater. The desulfurized heavy cat naphtha is blended into the gasoline pool. If the feed to the Axens Prime G unit is very low in sulfur, a low capital investment option was available to the refiner b y feeding the entire FCC naphtha stream to the hy drotreating***** E.O. 12866 Review**
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4 - 11 reactor avoiding the SHU and splitter. This option trades lower capital cost with somewhat higher octane loss and h ydrogen consumption. Because of the low severity of the hydrotreating reactor ( low severity

is possible because the lower amount of desulfurization that is occurring), the amount of octane loss and hydrogen consumption is modest. There are more than 180 Prime G+ units operating worldwide. The first step in Exxon’s fixed bed Scanfini ng process is to mildly heat the full FCC naphtha and pass it through a small reaction vessel which reacts the diolefins to monoolefins. 14 15 16 17 18 19 The full FCC naphtha is then heated further, injected with hy drogen gas and sent to the fixed bed hydrotreating reactor which is packed with a catal ys t developed jointly between Exxon and Akzo Nobel (now Albermele). If the degree of desulfurization is relatively modest, the amount of recombination is low and the FCC naphtha is sent to gasoline blending. If, h owever, the degree of desulfurization is higher (due to FCC naphtha with a higher sulfur content), then there likel y would be an excessive number of recombination reactions . In this case, Exxon recommends either one of two different technologies to addres s the recombination reactions. One technology

is Zeromer. Zeromer is a fixed bed reactor vessel installed after the main fixed bed hy drotreater reactor that specifically designed to hy drodesulfurize the mercaptan sulfur from the FCC naphtha without satur ating olefins. 20 Another technology Exxon developed, in conjunction with Merichem, is an extractive mercaptan removal technology named Exomer. The Exomer technology

differs from other sulfur extraction technologies in that it is capable of extracting merc aptans from the entire FCC naphtha pool. 21 Li ke Zeromer, the Exomer technology

would be an add - on technology installed after the Scanfining fixed bed reactor. There are 16 Scanfining units operating in the U.S. UOP has licensed two FCC naphtha hy drotreating technologies. When Tier 2 was being phased - in, UOP was licensing a technology named I SAL developed by I NTEVEP S.A. 22 23 The ISAL process is different than the other FCC naphtha hydrotreaters because instead of avoiding the saturation of olefins as sul fur is being h ydrotreated out of FCC naphtha, the I SAL process completely

saturates the olefins. To avoid a large octane loss, the ISAL process separates the olefin - rich , light cat naphtha from the heavy cat naphtha. The light cat naphtha is treated by an extractive desulfurization technology such as Merox which does not saturate olefins. Onl y the heav y cat naphtha is sent to the I SAL reactor. To offset the octane loss caused by the saturation of the olefins in the heavy cat naphtha as it is being desul furized, the I SALcatal ys t isomerizes and conducts some mild cracking and reforming of the heav y cat naphtha. One downside of the ISAL process is that, due to the complete saturation of olefins, the h ydrogen consumption is higher relative to the selective hydrodesulfurization technologies that avoid saturating olefins. UOP has since developed and licenses its own FCC naphtha desulfurization technology named SelectFining. 24 SelectFining is a selective hydrodesulfurization technology that seeks to minimize o lefin saturation to minimize both octane loss and hydrogen consumption. SelectFining treats the full FCC naphtha. The full range FCC naphtha is first sent to a diolefin saturating reactor before being sent to the SelectFining reactor. SelectFining relie s on its catal ys t design to selectivel y remove sulfur and prevent recombination reactions. UOP recommends a two - stage reactor setup for high levels of desulfurization.***** E.O. 12866 Review**
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4 - 12 The next two FCC naphtha desulfurization technologies, CDTech and S - Zo rb do not use f ixed bed reactors, but very different technologies which are also very different from each other. Each will be discussed separatel y. Although the CDT ech process is significantly different from the fixed bed hydrotreating technologies, it still uses the s ame ty pe of catal ys t. The CDT ech process utilizes cataly tic distillation. 25 , 26 , 27 Cataly

tic distillation is a technology which has been applied for a number of different purposes. CDT ech is currently licensing the technology to produce MTBE and selective h ydrogenation processes, including FCC naphtha desulfurization and benzene saturation. As the name implies, distillation and desulfurization, via catal yst, take place in the same vessel. This design feature saves the need to add a separate distillation co lumn sometimes used with fixed bed hy drotreating. All refineries have a distillation column after the FCC unit (called the main fractionation column) which separates the FCC naphtha from the most volatile components (such as liquid petroleum gases), the d istillate or diesel (light cycle oil), and the heav y ends or residual oil. However, if a refiner only wishes to treat a portion of the FCC naphtha, then a second distillation column would need to be added after the main FCC fractionation column to separat e off the portion of the FCC naphtha which he wishes not to treat. With the CDTech process, the refiner can choose to treat the entire pool or a portion of the pool, but choosing to treat a part of the pool can be an option in how the CDTech hardware is a pplied, thus negating an y need for an additional distillation column. The most important portion of the CDTech desulfurization process is a set of two distillation columns loaded with desulfurization cataly st in a packed structure. The first vessel, calle d CDHy dro, treats the lighter compounds of FCC gasoline and separates the heavier portion of the FCC naphtha for treatment in the second column. The second column, called CDHDS, removes the sulfur from the heavier compounds of FCC naphtha. All of the FCC naphtha is fed to the CDHy dro column. The five - and six - carbon petroleum compounds boil off and head up through the catal ys t mounted in the column, along with hy drogen which is also injected in the bottom of the column. The reactions in this column are unique in that the sulfur in the column is not hydrotreated to h ydrogen sulfide, but they instead are reacted with dienes in the feed to form thioethers. Their higher boiling temperature causes the thioethers to fall to the bottom of the column. They

joi n the heavier petroleum compounds at the bottom of the column and are sent to the CDHDS column. Because the pressure and temperature of the first column is much lower than conventional h ydrotreating, saturation of olefins is reduced to very low levels. T he olefin saturation which does occur is necessary to eliminate diolefins. Thus, little excess hy drogen is consumed. CDTech offers an option to refiners to put in an additional catalyst section in the CDHy dro column to increase octane. This octane enhan cing catal ys t isomerizes some of the olefins , which increases the octane of this stream by about three octane numbers, and few of the olefins are saturated to degrade this octane gain. The seven - carbon and heavier petroleum compounds leave the bottom of th e CDHy dro unit and are fed into the CDHDS column. There, the heavier compounds head down the column and the lighter compounds head up. Both sections of the CDHDS column have catal ys t loaded into them which serve as hy drotreating reaction zones. Similar to how hy drogen is fed to the CDHydro column, hydrogen is fed to the bottom of the CDHDS column. The temperature and pressure of the CDTech process columns are lower than fixed bed hydrotreating processes, particularl y in the upper section of the distillat ion column, which is***** E.O. 12866 Review**
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4 - 13 where most of the olefins end up. These operating conditions minimize yield and octane loss. While the CDTech process is very different from conventional hydrotreating, the catal ys t used for removing the sulfur compounds is the same. One important difference between the CDTech process and conventional hy drotreating is that CDTech mounts its catal ys t in a unique support sy stem, while conventional catal ys t is usually dumped into the fixed bed reactor. CDTech has 13 CDHy dro/CDHDS desul furization units in operation in the U.S. Phillips Petroleum Co. commercialized and licensed an adsorption desulfurization technology

called S - Zorb. 28 29 In2007, Phillips sold the S - Zo rb process to SINOPEC. S - Zorb uses a chemical adsorption process, ins tead of hydrotreating, as the principal methodology for the removal of sulfur from FCC naphtha . Adsorption has the benefit of operating at much lower pressure and temperatures, which lowers operating costs. S - Zorb, uses two separate columns and is constantly

moving an adsorption catal ys t from the reactor vessel to the regeneration column, and back again. 30 The untreated FCC naphtha and hydrogen are fed to the reaction vessel where the catal ys t cataly

tically removes the sulfur from the petroleum compound f acilitated b y the hydrogen present in the reactor. The cataly st , which begins to accumulate the removed sulfur, is transferred over to the regeneration column on a continual basis where the sulfur is removed from the cataly st using hy drogen as the scaveng ing compound. Then the hy drogen disulfude is converted to sulfur dioxide and sent to the sulfur recovery unit. Because the process still relies upon catal yt ic processing in the presence of h ydrogen, there is some saturation of olefins, with a commensurat e reduction in octane. Through a lite rature search, we believe that 7 S - Zorb desulfurization units were originally licensed for Tier 2, but our information sources have communicated that only

4 units are actually

operating today . We conducted a literature search or in some cases asked vendors to name which refineries installed their FCC naphtha desulfurization technology to enable compliance with Tier 2. A summary

of the total number of units by vendor and technology

t ype is summarized in Table 4 - 1 . **Table 4**  **- 1**  **Estimated Number of FCC Desulfurization Technologies Installed to comply**

**with Tier 2 by Vendor Company or Technology** Axens Prime G Exxon

Scanfining CDTech Sinopec S Zorb UOP I SAL

UOP Selec t fining FCC Feed

HT No FCC

Unit 4 0 16 1 5 4 1 1 7 1 4 4.2.3 Meeting a 10 - ppm Gasoline Sulfur Standard To meet a 10 - ppm average gasoline sulfur standard, we believe that the primary strategy that refiners would adopt would be to further reduce the sulfur level of FCC naphtha. There are three primary

reasons why

we settled on this as the primary strategy we chose for analyzing the compliance costs for Tier 3. The first reason is that, even after refiners used hy drotreating to reduce the sulfur in the FCC naphtha to comply with Tier 2, FCC naphtha is by far the largest contributor of sulfur to the gasoline pool, by virtue of both its volume and sulfur content. Table 4 - 2 below summarizes the estimated average volumes and average s ulfur levels for the primary blendstocks ty

pically blended into gasoline for the current Tier 2 situation. By using the refinery - by - refinery model to model today ’s situation for the ty pical refinery , we estimate that***** E.O. 12866 Review**
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4 - 14 the FCC naphtha contains about 7 0 ppm for the typical refinery compl yi ng with the 30 - ppm Tier 2 sulfur standard and that gasoline blendstock ty pically contributes to about 40 percent of a refiner’s gasoline pool . Table 4 - 2 also summarizes the changes in gasoline blen dstock sulfur levels we believe would occur when compl yi ng with the proposed 10 - ppm gasoline sulfur standard. Using the refinery - by - refinery model , we project that a 10 - ppm gasoline sulfur standard can be met b y a typical refinery b y reducing the sulfur l evel of FCC naphtha from about 70 ppm to 2 0 ppm. Infact, for virtuall y all refineries that have an FCC unit , refiners would not be able to compl y with the proposed 10 - ppm gasoline sulfur standard without further desulfurizing the FCC naphtha. The second reason why we believe that refiners would address the sulfur in the FCC naphtha is because both vendors and refiners have told us that this is the gasoline blendstock stream that they intend to address. Both vendors and refiners have explained to us that , for most refineries, FCC naphtha h ydrotreaters will alread y be in place that can be retrofitted with only a modest capital cost to realize the sulfur reduction needed. Third, further reducing the sulfur of the FCC naphtha as the means to comply with Tie r 3 is supported by other cost studies . When these studies assessed the costs for further reducing the sulfur levels of gasoline, they also focused further reducing the sulfur levels of the FCC naphtha. See the subsection at the end of Chapter 5 discussi ng these other cost studies. **Table 4**  **- 2**  **Estimated Typical Gasoline Blendstock Volumes and Sulfur Levels after Tier 2**

**and Complying with a 10 -**  **ppm Sulfur Standard** Gasoline Blendstock 30 - ppm Tier 2 Gasoline Sulf ur Standard 10 - ppm Gasoline Sulfur Standard Volume (Percent) Sulfur (ppm) Volume (Percent) Sulfur (ppm) FCC Naphtha 37 72 36 2 2 Reformate 23 0.5 22 0.5 Alkylate 1 3 5 13 5 Isomerate 3 0.5 3 0.5 Butane 4 10 4 1 0 Li ght Straight Run Naphtha and Natura l Gas Liquids 5 34 5 1 Hy drocrackate 3 8 3 8 Ethanol 10 5 12.5 5 Coker Naphtha 2 1 2 1 Other Gasoline Blendstocks 1 10 1 1 Total/Sulfur Average 100 30 100 10 Reducing FCC naphtha from 70 ppm to 2 0 ppm would likely be accomplished in different way s de pending on the desulfurizing technology and configuration used for Tier 2, and whether the current capital emplo yed for lowering gasoline sulfur is severely taxed or not severel y taxed. For purposes of this discussion, we will discuss the likely steps tak en to comply

with Tier 3 based on whether a refiner solel y used an FCC pretreater or FCC postreater to comply with Tier 2. While we provided an example for a t ypical refinery needing to reduce its FCC naphtha from 70 ppm to***** E.O. 12866 Review**
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4 - 15 2 0 ppm to enable compliance with Tier 2, there are many refineries which are not t ypical and so their starting and ending sulfur levels would be different from this example. Despite these differences, we believe that every refinery could technicall y compl y with a 10 - ppm gasoline sulfur standard. This is because gasoline sulfur is eas y to remove - the challenge is to comply while minimizing the cost of doing so. This challenge is further discussed in Section 4.2.3.5 below which discusses the value of the pr oposed averaging, banking and trading program. The one exception is the case where a refinery does not have an FCC unit. Refineries in this situation would likely already be producing gasoline which is 10 ppm or below. If the refinery ’s gasoline is abov e 10 ppm, then the refiner would need to address one or more of several different gasoline blendstocks, including light straight run, butane and natural gas liquids. This is discussed at the end of this section about other gasoline streams. 4.2.3.1 Meeting 10 p pm if Refiners Used an FCC Feed Pretreater to Comply with Tier 2 If a refiner relied on an FCC pretreater to comply with Tier 2 at a refinery , the refiner would likely onl y be able to achieve 10 - ppm sulfur gasoline if their FCC pretreater is a high press ure unit. 31 32 This is because most refineries which have FCC pretreaters process sour crude oils and if the unit is a mid or low - pressure unit, the unit pressure would likely be too low to sufficiently

desulfurize the FCC feed. This is likely true even if the refiner added reactor volume to its existing low or medium pressure FCC pretreater which does cause additional desulfurization. The problem with the mid and low pressure FCC pretreaters is that they just cannot remove enough of the sulfur in the gas oil feed to the FCC unit to achieve adequatel y low sulfur levels in the FCC naphtha. If a refinery processes moderate to low sulfur crude oil and ha s a low to mid - pressure FCC pretreater , however, it may be able to achieve an adequate degree of desulfuriz ation in the FCC naphtha to enable the refiner to reduce its gasoline sulfur down to 10 ppm. Thus, if a refinery

cannot achieve a sufficient level of desulfurization with its current or revamped FCC pretreater to comply with a 10 - ppm gasoline sulfur stand ard, then the refiner will have to install a grassroots FCC postreater. Alternatively , refiners in this situation would be in the best situation to take advantage of the averaging aspect of the averaging, banking and trading program (ABT). Using the ABT provisions to its advantage, the refiner w ould achieve the most desulfurization that it can with its existing FCC pretreater (perhaps 20 ppm sulfur gasoline) , and then would need to purchase credits to demonstrate the remainder of its compliance with the 1 0 - ppm gasoline sulfur standard . This scenario would avoid the need for a refiner to install an expensive grassroots FCC postreater. While they

are expensive to install, FCC pretreaters provide important operating cost advantages over postreaters. An imp ortant advantage of FCC pretreating is that it occurs upstream of the FCC unit and therefore does not je o p ardize the octane value of the olefins produced in the FCC unit. Another advantage of the FCC pretreater is that it tends to increase the yield of na

phtha from the FCC unit which improves operating margins for the refinery with such a unit. Thus, refiners which are able to use FCC pretreaters to comply with the Tier 3 sulfur standard would likel y yi eld a further return on an y investment made, and offs et some or all of the increased operating costs incurred . Perhaps onl y 5 refineries have high pressure FCC pretreaters in the U.S.***** E.O. 12866 Review**
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4 - 16 4.2.3.2 Meeting 10 ppm if Refiners Used an FCC Postreater to comply with Tier 2 If a refiner installed an FCC postreater to comply with the Tier 2 gasoline sulfur standard, there are several considerations about the current configuration of the postreater which would affect how a refiner would use this unit to comply with a 10 - ppm gasoline sulfur standard. The first issue is what is the degree of desulfurization the postreater is currently facing ? Itmakes sense to work through several examples to understand the ty pes of revamps and associated investments that might occur. For the first example, if the refinery is refining a very

s our (high sulfur) crude oil and the sulfur of the FCC naphtha exiting the FCC unit is 2 , 400 ppm, the postreater is currentl y removing almost 97 percent of the feed sulfur assuming that the sulfur level of the FCC naphtha exiting postreater is 7 0 ppm, which is a very high level of desulfurization. When attempting to achieve further sulfur reduction in the FCC naphtha, the refiner must be concerned about the increased occur

re nce of recombination reactions and the potential for much more octane loss and hydro gen consumption. This refiner would strongly consider adding a second stage, which may actuall y reduce the level of recombination reactions and the octane loss currentl y experienced b y the postreater. Most a ll the vendors offer a second stage option. In the case of CDTech, they call the second reactor, added as part of its second stage, a polishing reactor. We contacted the desulfurization engineer at Sinopec who explained that these units could just be turned up and that no additional capital investments would be needed. A Conoco - Phillips hy drotreating specialist we spoke to confirmed that this would be the strategy for their S - Zorb units. Yet one more option, if the refiner is interested in improving its operating margins such as increased gasoline p roduction, and has ample capital dollars to spend, the refiner could add an FCC feed hydrotreater to increase its yield of FCC naphtha, or a mild hydrocracker to increase its production of low sulfur distillate . In contrast, if a refiner is processing a very sweet (low sulfur) crude oil, the sulfur level exiting the FCC unit may be as low as 300 ppm, and under Tier 2, the level of desulfurization necessary to bring that stream down to 70 ppm is about 81 percent which is a very modest level of desulfurizat ion . Similarly , a refinery processing a moderatel y sour crude oil with a medium pressure FCC feed h ydrotreater could be in a similar situation. The refineries in this situation could have a lot more capacity in their existing postreaters to achieve lower sulfur without additional capital cost investments. However, many refiners in this situation which invested in an FCC postreater for Tier 2 may have minimized their capital investments. For example, a refiner may

have avoided the capital and operating c ost of a splitter with its postreater by hydrotreating the full range FCC naphtha . Therefore, the increased severity of the postreater needed to achieve 2 0 ppm in the FCC naphtha to meet a 10 - ppm gasoline sulfur standard might create a larger octane loss and higher h ydrogen consumption than what the refinery c ould easil y provide without a significant additional capital investment. In this case, the refiner can invest some capital in the postreater to minimize the increase in octane loss and hydrogen consumption. For example a refiner with an Axens unit in this situation could add the SHU and a splitter. A refiner with a Scanfining unit in this situation wishing to minimize the octane loss and hy drogen consumption could add a Zeromer or an Exomer unit. A lternatively , if the refiner is processing a moderatel y sour crude oil and has a moderate pressure FCC feed h ydrotreater, the refinery may choose instead to revamp the FCC feed h ydrotreater for its operational benefits rather than revamp the postreater.***** E.O. 12866 Review**
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4 - 17 T he last example of a postreater deserving some discussion is the case where the sulfur level exiting the FCC unit is 800 ppm. This is probably most ty pical of a refinery

refining a crude oil containing an average amount of sulfur, or, perhaps a refinery r efining a very

sour crude oil but treating the vacuum gas oil with a low pressure FCC feed h ydrotreater. The current FCC naphtha h ydrotreater would be achieving about 90 percent desulfurization when producing FCC naphtha with 80 ppm sulfur. In looking to reduce the FCC naphtha down to 2 0 ppm to comply with a 10 - ppm sulfur standard, a refiner in this position would not likely consider adding a second stage. This is because avoiding the increased octane loss and increased h ydrogen consumption for the addit ional increment of sulfur reduction would probably not justify the capital costs associated with a second stage. Instead of a second stage, a refiner could revamp the existing FCC postreater with additional reactor volume, or add cap ital for addressing re combination reactions, both likely to be a lot less capital intensive than a second stage. A no investment option is possible for refiners in this situation, although the increase in octane loss and hy drogen consumption is likely to be significant. Perh aps the most important part of an FCC hydrotreater is the catal ys t used in the unit. Due to continuing research, catal ys ts are constantly being developed which are more active, thus achieving greater desulfurization at a lower temperature, and minimize oc tane loss and hy drogen consumption due to lower olefin saturation. When the Tier 2 naphtha desulfurizers were being put into service the most recent catal ys ts were likely used in those units. These cataly sts can be changed out when the postreater is bein g taken down for regular maintenance, and new and improved catal ys ts can be used to improv e the desulfurization capacit y of the unit. If refiners indeed need to comply

with a 10 - ppm gasoline sulfur standard, they would be expected to upgrade to the most r ecent catal ys t to minimize their costs. Using the most active cataly st available would reduce the capital cost that would need to be incurred and reduce the h ydrogen consumption and octane loss that would otherwise occur. We are aware of newer lines of c atal ys ts being marketed by the various vendors. We can confirm that Axens and UOP have introduced more active cataly sts since the cataly sts were loaded into the FCC postreaters to comply with Tier 2 , although it is likely that all the vendors now offer improved hy drotreating catal ys ts .

4.2.3.3 Desulfurizing Other Blendstocks A more stringent gasoline sulfur standard could require refiners to have to address other gasoline streams that are high enough in sulfur to be a concern to the refiner s . This is because w ithout addressing these gasoline streams, the refiner would have to reduce their FCC naphtha even lower in sulfur resulting in high per gallon costs at the lower sulfur levels. The gasoline streams that we have identified that could require additional des ulfurization include light straight run naphtha , natural gas liquids and butane. Li ght straight run naphtha (L SR) is naturall y occurring in the crude oil and is desulfurized at man y refineries before it is sent to an isomerization unit. However, a numbe r of refineries don’t have isomerization units and therefore some or perhaps many of these refineries may not be treating this stream today . Natural gas liquids (also termed pentanes plus ) are naphtha streams sourced from natural gas wells which are purch ased by refiners and blended into the gasoline pool . Depending on the source of the specific naphtha stream being purchased, these streams could vary

widely in gasoline sulfur, ranging from a few ppm su lfur up to several***** E.O. 12866 Review**
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4 - 18 hundred ppm sulfur . Butane is natural occurring in crude oil and butane is also produced b y the FCC unit, and to a lesser degree, h ydrocrackers. Refiners separate the butane from these various streams and then blend it back into their gasoline pool depending on the RVP requirements of the gasoline market that the refiner is selling their gasoline into. Refiners have multiple options for addressing the sulfur levels of these various streams. The L SR and natural gas liquids can be hy drotreated in either the FCC postreaters or the naphtha hydrotreater s . Because these naphtha streams do not have any olefins, there is essentially no octane loss and , therefore, hydrogen consumption is lower compared to hydrotreating FCC naphtha. Another way

of treating these streams would be to use caustic extraction to extract the mercaptan sulfur from these streams. Since onl y the mercaptans are removed with the extraction technology , the final sulfur level won’t be as low compared to desulfurization using hydrotreating. Finally , the refiner could choose to simply not purchase the natural gas liquids and sell the L SR on the open market as opposed to treating these streams. If a refiner decides to not treat the L SR or natural gas liquids, other refiner s with excess capacit y in their FCC postreaters or nap htha h ydrotreaters could treat these streams. Butane is normall y treated using mercaptan extraction technologies. We are aware that some refiners have installed at least a few of these units at their refineries to address butane sulfur. Because butane is usually relatively

low in sulfur to begin with, refiners are likel y to onl y pursue desulfurizing this gasoline blendstock if the ir butane is higher than average in sulfur, or if they are considering producing a very low sulfur gasoline, such as 5 ppm. In summary , to comply

with a 10 - ppm gasoline sulfur standard, refiners have a range of options available to them, most of which involve reducing the sulfur in the FCC naphtha. If a refinery has a high pressure FCC pretreater, the refiner may be able to j ust turn up the hydrotreating severity

of that unit. I f a refinery has a low or medium pressure FCC pretreater and no postreater , the refinery would likely

need to install a grassroots FCC postreater to compl y with a 10 - ppm gasoline sulfur standard, or ac hieve the most that it can with its current capital and rel y on the ABT program. Refiners with FCC postreaters have multiple options. I f a refinery is short on octane and hydrogen, the refiner is likely to invest in capital to avoid as much octane loss and hydrogen consumption as possible. However, if the refiner has a lot of excess octane and h ydrogen, the refiner may choose to avoid any

capital cost investments or only make small capital investments and tolerate the higher octane loss and h ydrogen cons umption by simply turning up the severity

of its current FCC postreater . Refineries with postreaters could alway s invest in an FCC pretreater (h ydrotreater or mild hy drocracker) to improve its refinery ’s margins or to produce more low sulfur diesel fuel. Finally , in blending up their gasoline, some refiners may

still be blending in some produced or purchased gasoline blendstocks that continue to have high enough sulfur levels which would be a concern when faced with a more stringent gasoline sulfur standard, and several options exist for addressing the sulfur in these gasoline blendstocks.

4.2.3.4 Demonstrated Compliance with a 10 - ppm Gasoline Sulfur Standard There are multiple cases today where refiners are complying with 10 - ppm or lower gasoline sulfur programs. The State of California required gasoline sold in the State to meet a 15 - ppm gasoline sulfur standard on average and a 2 0 - ppm cap (California gasoline’s per - gallon***** E.O. 12866 Review**
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4 - 19 sulfur cap dropp ed to 20 ppm on January 1, 2012 ) . Furthermore, refiners can produce ga soline which varies in composition, provided that the California Predictive Emissions Model (which, like EPA’s Complex Model, estimates vehicle emissions from fuels of varying composition) confirms that the proposed fuel formulation meets or exceeds the em issions reduction that would occur based on the default fuel requirements. California refineries are using the flexibility provided b y the Predictive Model to surpass the prescriptive standards for gasoline sulfur and are producing gasoline which contains around 10 ppm sulfur on average. They are making this very low sulfur gasoline despite using Californian and Alaskan crude oils which are poorer qualit y than most other crude oils being used in the U.S. today . Thus, the experience in California demonstr ates that commercial technologies already exist to permit refiners to produce very low sulfur gasoline. Japan currentl y has a 10 - ppm gasoline sulfur cap that took effect January 2008. Europe also has a 10 - ppm sulfur cap that has been adopted by the 30 M ember States that comprise the European Union (EU) and the European Free Trade Association (EFTA) as well as Albania and Bosnia - Herzegovina. Under a 10 - ppm cap standard, the gasoline sulfur level likely averages about 5 ppm. Although gasoline in Japan an d Europe is made from different crude oil sources and much of the heavier ends are cut into diesel fuel, these international fuel programs (along with California) provide evidence that advanced gasoline desulfurization technologies have been deploy ed and are readil y available enable compliance with the proposed Tier 3 fuel program.

4.2.3.5 Improved Feasibility with the Proposed ABT Provisions The averaging, banking and trading (ABT) and small refiner and small volume refinery aspects of the proposed Tier 3 gas oline sulfur program would ease the feasibility of compliance with the program. To make the point, it is useful to first understand compliance if the ABT and small refiner and small volume refinery provisions did not exist. Without these provisions, all refineries would have to comply with the 10 - ppm gasoline sulfur standard by January 1, 2017. In the approximate 4 y ears after finalizing this rulemaking, most refiners would have to make capital investments in their refineries to enable compliance with th e 10 - ppm gasoline sulfur standard. These investments include revamped FCC pretreaters and postreaters, and the installation of grassroots FCC postreaters. As described above, reaching 10 ppm sulfur in the gasoline pool is attainable by each refinery . Ho wever, refiners assess the economic feasibility of their refineries differently depending on past and expected future economic performance. They therefore have different tolerances for making capital investments and absorbing increased operating costs. T his is particularl y true during a period of time in which gasoline demand is projected to be flat and renewable fuel blending is expected to increase. Refiners who own small refineries are concerned about the higher per - barrel costs for the capital instal led at those small refineries. The small refiner and small volume refinery provisions will delay

compliance for these entities until January

1, 2020. Small refiners need more time because they have smaller engineering staffs that they can dedicate to ove rsee the necessary refinery changes, thus they

are more likely

to complete the necessary changes to their refineries later than large refiners. Also, the delay allows the small refiners to experience improved margins for a couple of y ears when other large r refineries are complying with the gasoline sulfur standards.***** E.O. 12866 Review**
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4 - 20 The banking provisions of the ABT program effectively phase in the sulfur standard over s ix ye ars starting in 2014 through the end of 2019. The phase - in allows refiners to stagger their inves tments to their economic advantage. Refineries which are expected to incur the lowest costs for achieving lower gasoline sulfur levels can comply earl y and earn sulfur credits. These credits can then be used to demonstrate compliance starting in 2017 b y the refineries which are expected to incur higher costs for reducing their gasoline sulfur levels allowing those refineries to delay investments for lowering their gasoline sulfur. This phasing - in of the gasoline sulfur standard will help spread out the p reliminary design demands on the vendor companies which license the desulfurization technology to refiners, spread out the detailed design demands on the engineering companies which provide that service to refiners, spread out the permitting demands on the states which must provide environmental permits to refiners, and spread out the demands on the fabrication shops which construct the reactors and other major hardware which must be installed at refineries to realize the gasoline sulfur reductions. For mo re on how the proposed ABT provisions are expected to help with lead time, refer to Section 4.3 . Finally , the averaging provisions of the ABT program will provide additional flexibility and help to reduce the costs of the gasoline sulfur program. The averaging provisions will allow refiners to reduce the gasoline sulfur levels to under 10 ppm at their lower cost refineries to show compliance or help to show compliance at higher cost or financiall y challenged refineries.

4.2.3.6 Implicati ons of an Average Gasoline Sulfur Standard Less than 10 ppm While there may

be emissions motivations for further reducing gasoline sulfur levels , there are pract ical reasons for proposing a 10 - ppm annual average sulfur standard instead of a more stringent standard, e.g., 5 ppm. The lower the sulfur standard, the more costl y it is for refiners to achieve the lower sulfur standard . We identified several reasons why the costs increase so much for more deepl y desulfurizing the gasoline pool . A s desulfurizat ion severity increases, the operating and capital costs associated with desulfuriz ing FCC naphtha also increases. FCC naphtha is very rich in high - octane olefins. As the severit y of desulfurization increases, more olefins are saturated , further sacrifici ng the octane value of this stream and further increasing h ydrogen consumption. Also , as desulfurization severit y increases, there is an increase in the amount of the removed sulfur (in the form of hydrogen sulfide) which recombines with the olefins in th e FCC naphtha , thus offsetting the principal des u lfurization reactions. There are means to deal with the recombination reactions ; however, this probably means even greater capital investments . For example, the most expensive capital investment for an FCC postreater is a two stage desulfurization unit. A sulfur standard less than 10 ppm would likely require more refiners to invest in a second stage for their FCC postreater. T here are several other reasons which further increases the desulfurization cost f or a gasoline sulfur standard less than 10 ppm bey ond the higher FCC postreater cost . P er Table 4 - 2 , other refinery

streams contain a very modest amount of sulfur , y et a 5 - ppm sulfur standard would likely require desulfurization of s ome of these streams. For example, we believe that to comply with a 5 - ppm gasoline sulfur standard, most refiners would need to treat the butane blended into the gasoline pool. Because refineries have different sulfur levels in their non - FCC streams base d on their feedstock sulfur levels and their configurations, those with higher sulfur levels in other***** E.O. 12866 Review**
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4 - 21 refinery streams may

have to desulfurize additional streams besides butane. Each additional individual gasoline stream that requires desulfurization is i ncrementally a lot more expensive than addressing the sulfur from the FCC unit because the amount of sulfur reduction is a lot lower , but the capital costs are higher on a per - barrel basis for lower volume gasoline blendstock streams. F urther

more , desulfurizing gasoline down to 5 ppm essentially removes the flexibility offered b y the 10 - ppm gasoline sulfur standard with ABT program. Each U.S. refinery is in a different position today , both technicall y and financially , relative to the other refineries . In general, they

are configured to handle the different crude oils they process and turn their crude oil slate into a widely

varyingproduct slate to match their available markets. Those processing heavier, sour crudes would have a more challenging time red ucing gasoline sulfur under the proposed Tier 3 program. Also, U.S. refineries vary greatl y in size (atmospheric crude capacities range from less than 5,000 to more than 500,000 barrels per day) and thus have different economies of scale for adding capita l to their refineries. As such, it is much easier for some refineries to get their sulfur levels below 10 ppm than for others to reach 10 ppm . This allows the ABT program to be used to reduce the cost of the proposed gasoline sulfur standard. If the gas oline sulfur standard were to be 5 ppm, this would essentially end the ability

of the refiners to average sulfur reductions across their refineries thus significantl y increasing the costs while significantl y reducing the desulfurization flexibility . Goin g lower than 10 ppm would cause control costs to quickly escalate as more challenged refineries would be forced into much larger investments. Our cost estimates for 5 ppm versus 10 ppm with averaging bears this out. We estimate the cost for a 10 - ppm gaso line sulfur standard ( assuming intra - compan y credit trading ) to be 0.89 ¢ /gal compared to 1. 38 ¢ /gal for the 5 - ppm standard. The cost per sulfur reduction for the 10 - ppm average standard is 0.89 ¢ /gal for the 20 ppm sulfur reduction from Tier 2, or 0.045 ¢ /ppm - gal. The cost per sulfur reduction for the 5 - ppm standard is 0. 49 ¢ /gal for the 5 - ppm sulfur difference from the 10 - ppm average standard, or 0. 098 ¢ /ppm - gal, which is over 2 times higher. Therefore, we believe that an annual average standard of 10 ppm at the refinery gate with an ABT program appears to be the point which properl y balances feasibility with costs. In much of Europe and Japan, the gasoline sulfur level is capped at 10 ppm. We, however, are not considering a 10 - ppm cap for the U.S. The U.S. gasoline distribution sy stem poses contamination challenges that make it difficult to set and enforce tight downstream per gallon sulfur standards. The U.S. gasoline distribution sy stem poses contamination challenges that make it difficult to set and enforce tight downstream sulfur standards. In Europe, Japan , and California, finished petroleum products are generally shipped short distances directly from the refinery to the terminal with limited susceptibility to contamination. The U.S. has the longest and most complex gasoline distribution sy stem in the world, making it harder to control sulfur contamination than in other countries. Petroleum products are shipped long distances through multi - product pipelines. Further, g asoline goes through th e same pipelines and terminals back to - back with jet fuel (containing up to 2,000 ppm sulfur). Products are often in the custody of a number of separate companies before reaching the terminal. This sy stem is very effective at delivering petroleum product s to the bulk of the country , but pipeline transport inevitably introduces the potential for sulfur contamination of the gasoline being shipped through pipelines. Gasoline additives, needed to provide critical fuel performance characteristics (e.g., corro sion control, demulsifiers ), also contain varying levels of sulfur which contribute to the overall sulfur content of gasoline. Therefore, we are proposing a 10 - ppm average sulfur standard coupled with***** E.O. 12866 Review**
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4 - 22 higher per gallon caps at both the refinery gate and at all points downstream, as currentl y exists under the Tier 2 program. We believe this is the most prudent approach for lowering in - use sulfur while maintaining flexibility considering cost and other factors. These per - gallon caps are important in the co ntext of an average sulfur standard to provide an upper limit on the sulfur concentration that vehicles must be designed to tolerate. Since there are many opportunities for sulfur to be introduced into gasoline downstream of the refinery , these caps also limit downstream sulfur contamination and enable the enforcement of the gasoline sulfur standard in use. For more on our consideration of downstream caps, refer to Section 4.2.4.2 . 4.2.4 Challenges with L owering Today ’s Sulfur Caps

4.2.4.1 Impacts of Lowering the 80 - ppm Refinery Cap We considered lowering the 80 - ppm cap standard that applie s to refiners under the Tier 2 program. If we were to lower the cap standard, we anal yz ed lowering it to two different possible sulfur levels, either 50 p pm or 20 ppm. If we lowered the refinery cap standard to 20 ppm, then the averaging aspect of the ABT program would essentially not be available to refiner s. That is because, under a 20 - ppm cap standard, we estimate that refiners would average about 10 p pm sulfur. Thus, the compliance scenario if the cap standard were 20 ppm would essentially be the same as the non - ABT case we anal yz ed. In this case, refiners would not have much of the flexibility offered by

the ABT program. If the cap standard were to be lowered to 50 ppm, the final compliance scenario under the Tier 3 fuels program would be somewhere between the ABT scenario that we anal yz ed and the non - ABT scenario that we anal yz ed (probabl y much closer to the ABT case) . According to EPA batch dat a, there were 20 refineries that averaged between 40 and 80 ppm sulfur during 2009 . These refineries are using credits to show compliance with the Tier 2 30 - ppm gasoline sulfur standard . If the 80 - ppm cap were to be reduced to 50 ppm, those refineries th at were averaging over 40 ppm would be forced to reduce their sulfur levels below the cap even if their financial situation is more tenable compared to other refineries. However, even if the cap standard were to remain at 80 ppm, most of the 20 refineries that averaged between 40 and 80 ppm under Tier 2 would have to lower their sulfur an yw ay s because of th e stringency of the proposed 10 - ppm sulfur standard . T here would not be sufficient credits available to allow most of those refineries remain at high g asoline sulfur levels. Our cost analy sis, which assumes intra - company credit trading, projects that only one refinery

would remain just above 40 ppm when the fuels program is fully phased in. For more on our cost anal ys is, refer to Chapter 5 of the draft RIA. Another way

that a more stringent cap would affect refiners would be to restrict the ability of refiners to process high sulfur FCC naphtha when there is a short term shutdown of the FCC postreater . If the FCC postreater goes down, the refinery wo uld likely

continue operating the FCC unit and store up the high sulfur FCC naphtha. Since the FCC naphtha is too high in sulfur to blend directl y with gasoline, the refinery would have to either sell the material to other refiners, or h ydrotreat the stor ed up FCC naphtha along with the ongoing production of high sulfur FCC naphtha once the FCC postreater was back online. If a stringent cap were in place, the refiner would have little room for short term production of higher sulfur gasoline if it was feed ing a larger than normal quantity (stored and new production) of FCC naphtha to the FCC postreater . Without this flexibility , the refiner may have to over size the FCC postreater and FCC***** E.O. 12866 Review**
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4 - 23 naphtha storage to ensure that, regardless of the higher feed volume needed to process the stored material, the FCC naphtha desulfurization unit could continue to desulfurize the FCC naphtha down to the required sulfur level that would result in 10 ppm sulfur in the gasoline pool. I f the cap were to be lowered, a 50 - ppm ca p standard would clearl y continue to provide refiners with some flexibility

while a 20 - ppm cap would not. Even if refiners planned to tolerate some higher sulfur batches when h ydrotreating stored FCC naphtha, it could not tolerate much volume of higher su lfur batched because of the need to average 10 ppm over the calendar y ear. If such outages happen very

infrequently , then a small amount of credits could regularl y be banked over time that would allow for some longer term higher sulfur batches of gasoline as the stored FCC naphtha was being h ydrotreated. Alternativel y, the averaging of sulfur credits would help refiners with FCC naphtha hydrotreater outages. Thus, the flexibility of the ABT program coupled with a higher cap standard would provide refiner s with some flexibility to handle FCC unit outages.

4.2.4.2 D ownstream Sulfur Caps The feasibility

of compl ying with a downstream sulfur cap is dependent on the differential between the refinery /importer gate sulfur cap and the downstream cap. This differentia l must provide sufficient flexibility for worst - case situations when the potential sources of sulfur addition downstream of the refinery /importer compound in a single batch of gasoline that was introduced into the sy stem at the refinery /importer gate sulfur cap. We are proposing two potential options for the per - gallon downstream sulfur cap. Under the first option, we are proposing to maintain the current 95 - ppm downstream sulfur cap. This option is associated with the proposed maintenance of the current 80 - ppm refinery /importer gate sulfur cap and is reflected in the draft regulatory text . Under the second option, we are proposing that the downstream sulfur cap would be reduced to 65 ppm . This option is associated with the proposed reduction in the refi nery /importer gate sulfur cap to 50 ppm. Under both of these options, we would be maintaining the current 15 - ppm differential between the refinery /importer gate sulfur cap and the downstream sulfur cap. We are also requesting comment on the potential impl ementation of a downstream sulfur cap as low as 25 ppm. This scenario is associated with a reduction of the refinery /importer gate sulfur cap to as low as 20 ppm. Under this scenario, the differential between the refinery /importer gate sulfur cap and the downstream sulfur cap might be a little as 5 ppm . Under all of these potential approaches, the downstream sulfur cap would apply at all locations downstream of the refinery or importer gate including the gasoline produced b y transmix processors and afte r the use of additives. The potential sources of sulfur addition downstream of the refinery /importer gate and issues associated with the feasibility of meeting the downstream sulfur caps under consideration are discussed in the following subsections.

4.2.4.2.1 Sul

fur Addition Downstream of the Refinery and Importer Gate The sulfur content of gasoline can increase downstream of the refinery /importer due to contamination during distribution, the use of additives, and the disposition of transmix generated during dis tribution.***** E.O. 12866 Review**
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4 - 24 A small amount of sulfur contamination takes place during distribution as a result of the shipment of gasoline over long distances b y pipeline and other modes due to the sharing of the same distribution assets with other higher - sulfur petroleum products , e.g., jet fuel . Steps can be taken to limit sulfur contamination. However, it is an unavoidable feature of the efficient multi product distribution sy stem in the U.S. We estimate that sulfur contamination of gasoline can be limited to a wors t case maximum of 3 or 4 ppm in the future, even for the most involved and long - distance distribution pathway s. There are currently

no direct regulatory

controls on the sulfur content of gasoline additives. The contribution to the sulfur content of finish ed gasoline from gasoline additives is accommodated in the differential between the refinery gate and downstream sulfur caps. The functional components of some gasoline additives such as silver corrosion inhibitors and demulsifiers are inherently high in sulfur content. However, the contribution to the overall sulfur content of the finished fuel is very limited. For example, silver corrosion inhibitors can contain as much as 30 percent sulfur but because of very low treatment rates can add only 0.17 ppm to the sulfur content of the finished fuel. 33 At seldom used highest treatment rates, the use of gasoline additives upstream of the consumer has the potential to add ~1 ppm to the sulfur content of the finished fuel. Aftermarket additives that are added d irectly into the vehicle fuel tank also have the potential to increase gasoline sulfur content. One particular aftermarket performance and anti - wear additive can contribute ~2 ppm sulfur to the treated fuel. B 34 Transmix is a necessary

by product of the mult i - product refined product pipeline distribution sy stem. Batches of different products are shipped in sequence in pipelines without any phy sical barrier between the batches. Transmix is produced when the mixture at the interface between two adjacent produ cts cannot be cut into either batch. Transmix ty picall y accumulates at the end of pipeline sy stems far from refineries. There are two methods of disposing of transmix. Most transmix is sent to transmix processing facilities for separation into salable d istillate and gasoline products through use of a simple distillation tower. The other means of transmix disposal is for pipeline operators to blend small quantities directly into batches of gasoline during shipping. This ty picall y takes place at remote pipeline locations where small volumes of transmix accumulate that would be difficult to consolidate and ship to transmix processors. Pipeline operators that blend transmix into the gasoline in their sy stems must ensure that the resulting gasoline meets a ll fuel quality specifications and the endpoint of the blended gasoline does not exceed 437 °F. C 35 This practice currently can add as much as 3 to 5 ppm to the sulfur content of gasoline although we believe that the contribution is ty picall y less. Transm ix processing facilities do not handle sufficient volumes to support the installation of currently - available desulfurization units. Therefore, the sulfur content of the products they produce is predominantly governed b y the sulfur content of the transmix they receive. In man y cases, transmix contains jet fuel which can have a sulfur content as high as 3,000 ppm. Due to

B Aftermarket additives are defined as additives sold to vehicle operators for direct addition to vehicle fuel tanks. C 437 F is the max imum endpoint allowed for gasoline in the ASTM International specification for gasoline in ASTM D4814.***** E.O. 12866 Review**
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4 - 25 the overlapping distillation characteristics of jet fuel and gasoline, it is unavoidable that some jet fuel in transmix will be present i n the gasoline produced b y transmix processors. Transmix processors produce ~0.1 percent of all gasoline consumed in the U.S. The small volume of transmix - derived gasoline along with the fact that such gasoline is ty picall y mixed with other gasoline befor e delivery to the end user, substantially limits the potential impact on gasoline sulfur levels. Furthermore, data provided b y the largest operator of transmix processing facilities, shown in Figure 4 - 2 , indicates that relativel y few batches of the gasoline they produce approach 80 ppm sulfur. 36 Most batches are approximately 10 ppm above the current 30 - ppm refinery

sulfur average. We anticipate that this 10 - ppm differential would likel y continue under the proposed 10 - ppm ref inery av erage sulfur standard.

**Figure 4**  **- 2**  **Kinder Morgan Transmix Gasoline Product Sulfur Levels** 4.2.4.2.2 Maintaining the Current 15 - ppm Differential Between the Refinery /Importer Gate and Downstream Sulfur Caps Under both of the co - proposals for a downstream sulfur cap (95 ppm and 65 ppm), we would be maintaining the current 15 - ppm differential between the refinery /importer gate sulfur cap and the downstream sulfur cap.***** E.O. 12866 Review**
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4 - 26 The current 15 - ppm differential was established under the Tier 2 program to accommodate the sulfur contamination during distribution, the sulfur contribution from transmix blending b y pipeline operators, the sulfur contribution from the use of additives, and to enable compliant gasoline to be produced b y tran smix processors. Transmix processors need to produce gasoline sufficientl y below the downstream sulfur cap to accommodate the addition of sulfur from the use of additives and contamination during further distribution. Experience under the Tier 2 program has shown that a 15 - ppm differential is sufficient for downstream parties to ensure compliance with the downstream sulfur cap Our co - proposal to maintain the current 95 - ppm downstream sulfur cap with an 80 - ppm refinery /importer gate sulfur cap represents n o change from current requirements. As a result, there would be no increased difficulty or additional costs associated with satisfying a 95 - ppm downstream sulfur cap bey ond those that were already incurred under the Tier 2 program. Our co - proposal to imp lement a 65 - ppm downstream sulfur cap with a 50 - ppm refinery gate sulfur cap would also maintain the current 15 - ppm differential between these sulfur caps under the Tier 2 program. Since it is this differential that determines the difficulty in compl yi ng with the downstream sulfur cap, we expect that there would be no operational changes and additional costs for downstream parties associated with satisfying a 65 - ppm cap downstream sulfur cap bey ond those that were already incurred under the Tier 2 program to comply with the current 95 - ppm downstream sulfur cap. Under both of the co - proposals, the reduction in the refinery average sulfur standard may make it somewhat easier to comply with the downstream sulfur cap given that most gasoline produced would be at or near 10 ppm sulfur.

4.2.4.2.3 Potential Reduction in the Differential Between the Refinery/Importer Gate and Downstream Sulfur Caps We requested comment on the potential implementation of a refinery gate sulfur cap as low as 20 ppm and a corresponding downstream sulfur cap as low as 25 ppm. This was driven by vehicle manufacturers concerns about the potential impacts on emissions performance if vehicles are exposed to gasoline above the proposed 10 - ppm refinery average standard. 37 As discussed in Section s 1.2 and 5.2 of this draft RIA, the vehicle emissions benefits associated with today ’s proposal are driven by the proposed reduction in the average sulfur content of gasoline from 30 to 10 ppm. We believe that the potential benefits from further reductions in the sulfur caps would be minimal. However, further reductions in the sulfur caps could have negative impacts on refiners and downstream parties. The potential impacts on refiners and additional costs associated with a lower refinery /importer gate sulfur cap discussed in Section 4.2.4.1 . A reduction in the differential between the refinery

gate sulfur standard and the downstream sulfur standard could also result in negative impacts and additional costs to downstream entities. Red ucing the current 15 - ppm differential between the refinery /importer gate and downstream sulfur caps could limit the ability of transmix processors to continue to produce finished gasoline, limit the ability of pipeline operators to continue to blend transm ix in gasoline, and potentially require the direct regulation***** E.O. 12866 Review**
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4 - 27 of gasoline additive sulfur content which might cause certain gasoline additives to be removed from the market. Some gasoline additive manufactures relate that it would not be technically possible to reformulate their additives to meet a lower sulfur cap. Hence, the implementation of a sulfur cap for gasoline additives could result in the withdrawal of some necessary and cost - effective gasoline additives (e.g., corrosion inhibitors, and demulsi fiers) from the market. Other additive manufactures related that there would be significant costs in reformulating their additives to meet a lower sulfur cap. Some additive manufactures related that they could not justify

the cost of reformulation and wo uld need to cease manufacture. Since gasoline additives may add as much as 3 ppm to the sulfur content of the finished fuel, allowing for further sulfur contamination during distribution and for test variability means that transmix processors must produce gasoline about 5 ppm below the downstream sulfur cap. The sulfur levels in the transmix that processors must cope with would be reduced due to the proposed reduction the gasoline sulfur requirements for refiners/importers. However, the continued presence of high - sulfur jet fuel in transmix would continue to significantly influence the sulfur content of the gasoline produced b y transmix processors. Given these considerations, a reduction in the differential between the refinery gate sulfur cap and the downstream sulfur cap might require that the majority of the gasoline produced by transmix processors to be desulfurized, something that is cost - prohibitive to do at transmix processing facilities today . Other options for dealing with transmix, however, are just as impractical, including shipping it back to refineries for reprocessing. Refiners are t ypically averse to accepting transmix into their facilities for reprocessing due to technical, logistical, and economic constraints. In addition, transmix would ty

picall y need to be shipped long distances from the ends of the product distribution by

truck to reach a refinery . If pipeline operators were further limited in their ability to blend small amounts of transmix into gasoline due to a reduction in the diff erential between the refinery /importer gate and downstream sulfur caps, they could be compelled to install additional transmix storage and shipping facilities at numerous remote locations to facilitate the shipment of small volumes of transmix to transmix processors b y truck. One major pipeline operator reported that it has over 100 locations on its sy stem where transmix can be injected into gasoline, some of which do not have tank truck access. Thus, a reduction in the differential between the refinery /i mporter gate and downstream sulfur caps could result in substantial additional costs and potential changes to transmix operating practices for the pipeline operators. **4.3 Lead**  **T ime**  **Assessment** 4.3.1 Engineering and Construction Analy sis Given the complexity

of gasoli ne refining, numerous planning and action steps would be required for refiners to complete the refinery changes needed to comply with the proposed Tier 3 sulfur standards. The steps required to implement these changes include: the completion of scoping s tudies, financing, process design for new or revamped refinery units or subunits, permitting, detailed engineering based upon the process design, field construction of the gasoline***** E.O. 12866 Review**
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4 - 28 sulfur reduction facilities, and start - up and shakedown of the newl y instal led desulfurization equipment. W e conducted a more thorough lead time anal ys is in which w e sequenced the estimated time to complete scoping studies, process design, permitting, detailed engineering, field construction, and start - up and shakedown in advance of production based upon the methodology used in our recent gasoline and diesel rules. For the proposed Tier 3 gasoline sulfur program, we estimated refinery lead times required for two general ty pes of refinery

projects: the construction of new grassroot s FCC postreaters and the revamp of existing pre and postreaters. For each refinery project, we estimated lead times for scoping studies, process design, permitting, detailed engineering, field construction, and start - up and shakedown. Estimated required lead times for scoping studies are six months. Process design ranged from six months for desulfurization equipment revamping to nine months for a grassroots postreater. Based on discussions with refiners, a review of the permitting experience for Tier 2 and our current analy sis, we estimate that permitting for desulfurization equipment revamping and the construction of a grassroots postreater would take 9 months. However, we estimate the overall lead - times for Tier - 3 - related revamps t o be considerabl y short er , as described below. The estimates for permitting time are co nsistent with those of EPA’s Office of Air Quality Planning and Standards ( OAQPS ) and our regional offices, both of which have engaged in extensive dialog with potential ly affected parties . A discussion of the permitting implications o f Tier 3 is contained in Section V.B of the preamble. Detailed engineering efforts were estimated to require six months for desulfurization equipment revamping and nine months for grassroo ts postreater s . Field construction was estimated to require six months for revamped pre - and postreaters and 12 months for grassroots postreaters. Start - up and shakedown processes were estimated to require six months for revamped FCC treaters and 9 months for grassroots postreaters. There is some degree of overlap among each of these steps as shown in Table 4 - 3 . To allow refiners to complete all these different steps and compl y with the 10 ppm average gasoline sulfur standard, assuming the Tier 3 proposal were to be finalized by the end of 2013, we would be providing three years of lead time. In addition to the three ye ars of lead time, the proposed rulemaking also provides additional flexibility provided by

the ABT program, small refinery

delay s, and har dship provisions. To support this timeline, we conducted several anal ys es of the expected refinery lead time requirements associated with the proposed Tier 3 standards and found that refinery operators would have more than adequate time to implement the r equired refinery

charges. A justification for proposed timeline appears below. Complying with Tier 3 is expected to involve some grassroots (new) FCC postreaters, but mostly we believe that refiners will revamp existing FCC postreaters. Revamping of exis ting FCC postreaters can be accomplished in approximately 2 y ears, or less (See Table 4 - 3 ) Grassroots FCC postreaters are expected to require on average about three - ye ars to install and start - up (See Table 4 - 3 ). Incomparision to FCC pretreaters, hydrocr ackers and distillate hydrotreaters, FCC postreaters are much less costly , low pressure units that take less time to scope out, require shorter lead times for ordering the equipment, and less time to install. Furthermore, the grassroots FCC postreaters to be installed for Tier 3 are expected to be in a moderate to light desulfurization service because the refineries they will be installed in will***** E.O. 12866 Review**
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4 - 29 alread y be compl yi ng with Tier 2 using an FCC pretreater. FCC naphtha from a refinery with an FCC pretreater i s expected to only contain about 100 ppm sulfur. To comply with Tier 3, refiners installing these grassroots FCC postreaters would only need to desulfurize the FCC naphtha down to 25 ppm (about a 75% reduction). In comparison, a single - stage FCC postreat er would have to desulfurze FCC naphtha from as high as 2400 ppm sulfur down to 25 ppm, a 99% sulfur reduction. The more moderate desulfurization service of the grassroots FCC postreaters needed to compl y with Tier 3 would be expected to streamline the sc oping and design work . **Table 4**  **- 3**  **Anticipated Compliance Timelines** Months 0 - 3 3 - 6 6 - 9 9 - 12 12 - 15 15 - 18 18 - 21 21 - 24 24 - 27 27 - 30 30 - 33 33 - 36 36 - 39 39 - 42 42 - 4 5RevampPre-&Postreaters Scoping Studies Process Design Permitting Detailed Engineering Field Construction Start - up / ShakedownGrassrootsPostreater Scoping Studies Process Design Permitting Detailed Engineering Field Construction Start - up / Shakedown It is useful to compare the proposed lead time for Tier 3 to what was provided for Tier 2. In the ca se of the Tier 2 standard, we provided a three - ye ar lead time along with an ABT program and other flexibilities to ease compliance. Refiners, though, commented that the three ye ar timeline that we provided was not enough time. For the Tier 2 analysis, we assumed that refiners would solely

install low - pressure FCC postreaters, which we believe could be scoped out, designed, installed and started up within a 3 year time period. However, many refiners complied with Tier 2 b y installing high - pressure FCC pre treaters which require long lead times for the procurement of the required equipment. Furthermore, those refiners that did not install high - pressure FCC pretreaters instead installed grassroots FCC postreaters, many of which were designed for severe desul furization service. An additional difference between Tier 3 and Tier 2 is that for Tier 3 we expect the installation of only 16 grassroots units, along with man y revamps,***** E.O. 12866 Review**
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4 - 30 but for Tier 2 virtuall y al l refiners installed both grassroots FCC pretreaters and postreaters. The demands on the desulfurization vendors for scoping studies, and on the E & C industry for design and construction, and on the refiners to train their operations staff and start up the new units, was a lot greater for Tier 2 than what we w ould expect for Tier 3. The total estimated investment cost for Tier 2 versus Tier 3 also highlights the difference in investment demands The total investment for Tier - 2 desulfurization processing units was estimated to be about $ 6.1 billion , while the t otal investment for Tier - 3 desulfurization processing units is estimated to be about $2.1 billion. This simple comparison indicates that the proposed Tier 3 lead time should be adequate for refineries to obtain necessary permits, secure engineering and co nstruction (E&C) resources, install new desulfurization equipment and make all necessary retrofits to meet the proposed sulfur standards. We assessed the permitting situation in more detail working in conjunction with the Office of Air Quality , Planning and Standards (OAQPS). On a refinery - by - refinery basis, we provided OAQPS estimates of the additional heating demands for the new and revamped units per the desulfurization vendor submissions. OAQPS was able to project which refineries would likely trigg er NOx, particulate matter and greenhouse gas emission permitting limits, which would likely

lengthen the permitting process as refiners would need to offset the projected emission increases. As it turns out, only 7 of the 16 refineries which are projecte d to install grassroots units were projected to exceed particular permitting limits, and these solel y did so based on the most conservative assumption that each would produce all the additional hydrogen on site using h ydrogen plants (as opposed to using ex isting reforming capacity) and produce the electricit y on site, to satisfy the needs of the new desulfurization equipment. When we provided a second heat demand estimate to OAQPS which assumes that refiners purchase their h ydrogen and electricity

from thi rd parties, none of the refineries which we projected would install grassroots units was projected to have emission increases which would require offsets. Thus, many of the grassroots units that we project would be installed may end up with a streamlined permitting processe. The various flexibilities that the proposed Tier 3 rule provides to refiners provide refiners additional time for complying. These flexibilities include the ABT program, the small refiner delay provisions and the hardship provisions. The ABT program allows a refiner, either within its own company

or by purchasing credits on the open market, to delay higher investment cost investments, such as the investments in grassroots FCC postreaters, which would provide additional lead time for i nstalling these units. This would occur if refiners would reduce the sulfur levels of their gasoline through operational changes or revamps of their existing FCC pretreaters and postreaters when the ABT Program begins in 2014. Potentially every refinery with either an FCC pretreater or an FCC postreater may be capable of generating earl y credits. Furthermore, we project that 66 refineries would revamp their existing FCC postreaters to comply with Tier 3. Since revamps can be completed within two y ears o r less, these refiners could potentially

begin generating earl y credits during 2016, or before if refiners begin each of these revamps in earl y 2014. During the period between 2014 and 2017, these refineries which reduce their gasoline sulfur levels below that required b y Tier 2 would generate credits. R efiner ie s with higher cost capital investments, such as the grassroots FCC postreaters, could then delay

making those investments through the purchase of credits. We estimate that sufficient credits could be generated earl y to allow man y refiner ie s to delay compliance until as late as***** E.O. 12866 Review**
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4 - 31 2020. The quantitative early credit anal ys is that we conducted showed that if refiners with an existing pretreater or postreater w ould generate early credits by

lowering th eir gasoline sulfur down to 20 ppm starting in 2014 and if revamps were started up in 2016 , one y ear before the program start date , that almost 6 times more credits would be available to offset the earl y credit demand b y the refiners installing grassroots postreater units , assuming that they start up those units in 2018. Even if all grassroots postreaters were assumed to not start up until 2020, there would be almost 4 times more early credits available to those refiners installing grassroots postreaters a ssuming that the same earl y credit generation scenario would occur Additional flexibility

is also provided by

the small refineries provisions which delay s compliance for the refineries which refine less than a net of 75,000 barrels of crude oil per day unt il 2020. Three of the 16 FCC postreater grassroots units that we project will be installed would be by

small refiner ie s. However, small refiner ie s could also decide to comply earl y and generate credits starting as earl y as 2014. As in previous fuel programs, we are proposing hardship provisions to accommodate a refiner’s inability

to comply

with the proposed standard at the start of the Tier 3 program, and to deal with unforeseen circumstances that may occur at any

point during the program. These provis ions would be available to all refiners, small and non - small, though relief would be granted on a case - by - case basis following a showing of certain requirements; primarily that compliance through the use of credits was not feasible. We are proposing that an y hardship waiver would not be a total waiver of compliance; rather, a hardship waiver would be short - term relief that would allow a refiner facing a hardship situation to, for example, receive additional time to comply . This hardship provision would a llow a refiner to seek a delay in the case that there was insufficient time to comply . Finally , we believe that in reality , less leadtime than shown in Table 4 - 3 would actually be necessary . We held discussions with many refiners during most of 2011, and so they have been well aware of Tier 3 and are familiar with the likely requirements. During our subsequent discussions with technology vendors and engineering firms, they explained to us that many refiners have alread y initiated, and b y now, likel y compl eted their scoping studies. Thus, actual time needed for designing, installing and starting of new desulfurization equipment for Tier 3 times would even be less than what we projected because man y refineries may have alread y completed required scoping stud ies in anticipation of the Tier - 3 standards. Moreover, lead times for those refineries that have yet to start the scoping process can also be expected to decrease, since fewer refineries will be competing for the services of the desulfurization vendors. 4.3.2 P ermitting Anal ys is Our anal ys is found that GHG emission increases were the most common reason that Prevention of Significant Deterioration (PSD) applicability would be triggered, followed by NO X emissions. Specifically , 19 refineries appeared likely to have significant emissions for one or more pollutants and thus would trigger major source New Source Review (NSR). Of these 19 refineries, 13 refineries would need permits for NAAQS - related pollutants.***** E.O. 12866 Review**
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4 - 32 With respect to NAAQS - related pollutants, 6 of these 13 refineries were predicted to require both PSD and Nonattainment NSR permits. Of the remaining 7 refineries, 2 required only a Nonattainment NSR permit while the remaining 5 refineries required a PSD permit. In comparison, for the Tier 2 program, EPA exp ected the need for NAAQS - related NSR permits might be widespread among refineries. For the proposed Tier 3 gasoline sulfur standard, however, onl y about 10 refineries would need air permits that address NAAQS pollutants. This number could be lower if th ose refineries apply emission controls, such as selective catal yt ic reduction (SCR) for NO X , to reduce the emission increases below the significance level. For refineries that do need a major source NSR permit for NAAQS pollutants, the permitting process is expected to take 9 - 12 months. For an in depth assessment of stationary source implications, refer to Section V.B of the preamble . 4.3.3 Employ

ment Constraint Analy sis As in prior rules, we also evaluated the capabilit y of E&C industries to design and bui ld gasoline h ydrotreaters as well as performing routine maintenance. This includes an emplo ym ent anal ys is. Two areas where it is important to consider the impact of the fuel proposed sulfur standards are: 1) refiners’ ability to procure design and constr uction services and 2) refiners’ ability to obtain the capital necessary for the construction of new equipment required to meet the new quality

specification. We evaluated the requirement for engineering design, and construction personnel, in a manner con sistent with the Tier 2 analy sis, particularly for three ty pes of workers: front - end designers, detailed designers and construction workers, needed to implement the refinery

changes. We developed estimates of the maximum number of each of these ty pes of w orkers needed throughout the design and construction process and compared those figures to the number of personnel currentl y employ ed in these areas. The number of person - hours necessary to design and build individual pieces of refinery equipment and the person - hours per piece of equipment were t aken from Moncrief and Ragsdale 38

. Their paper summarizes analy ses performed in support of a National Petroleum Council study

of gasoline desulfurization, as well as other potential fuel quality changes. The design and construction factors for desulfurization equ ip ment are summarized in Table 4 - 4 . **Table 4**  **- 4**  **Design and Construction Factors a**  Gasoline Refiners Number of New Pieces of Equipm ent per Refinery 60 Number of Revamped Pieces of Equipment per Refinery 15 Job Hours Per Piece of New Equipment a Front End Design 300 Detailed Design 1,200 Direct and Indirect Construction 9,150 Note:***** E.O. 12866 Review**
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4 - 33 a Revamped equipment estimated to require half as many hours per piece of equipment Refinery projects will differ in complexity and scope. Even if all refiners desired to complete their project by the same date, their projects would inevitably begin over a range of months. Thus, two projects scheduled to start up at exactly the same time are not likel y to proceed through each step of the design and construction process at the same time. Second, the design and construction industries will likely provide refiners with economic incentives to avoid temporary

peaks in the demand for personnel. Applying the above factors, we projected the maximum number of personnel needed in any given month for each ty

pe of job. T he results are shown in Table 4 - 5 . In addition to total personnel requ ired, the percentage of the U.S. workforce in these areas is also shown, assuming that half of all projects occur in the Gulf Coast in Table 4 - 5 . V ery few refineries are expected to require the full 45 - month period to complete scopin g studies, process design, permitting, detailed engineering, field construction, and start - up/shakedown .

**Table 4**  **- 5**  **Maximum Monthly Demand for Personnel**

Front - End Design Detailed

Engineering Construction Tie r 3 Gasoline Sulfur Program Number of Workers 202 809 6,012 Percentage of Current Workforce a 11% 9% 4% Note: a Based on current employment in the U.S. Gulf Coast assuming half of all projects occur in the Gulf Coast To meet the proposed Tier 3 sulfur st andards, refiners are expected to invest $2.2 billion between 2014 and 2019 and utilize approximately 1,000 front - end design and engineering jobs and 6,000 construction jobs. The number of estimated jobs required is small relative to overall number availa

ble in the U.S. job market. As such, we believe that four y ears is adequate lead time for refineries to obtain necessary permits, secure E&C resources, install new desulfurization equipment and make all necessary retrofits to meet the proposed sulfur stan dards. 4.3.4 ABT Impacts We conducted a refinery - by - refinery analy sis to determine the impacts on refinery E&C demand of implementing the 10 - ppm standard without an ABT program . The anal ys is suggests that a greater number of refineries w ould need to make inve stments in refinery apparatus and upgrades than would have under an ABT program . This w ould result in a greater demand on the E&C industry . Moreover, the anal ys is also indicated that the demand upon the E&C industry w ould be spread over a shorter period than with the ABT case . In particular, our refinery - by refinery anal ys is indicates that without an ABT program, 73 refineries would revamp existi ng pre - and postreaters and 21 would install grassroots postreaters in order to meet the proposed sulfur stand ards. The remaining 17 refineries are either alread y in compliance with the 10 - ppm standard or expected to comply with simple process changes . This is compared to 66 refineries***** E.O. 12866 Review**
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4 - 34 that would revamp existing pre - and postreaters and 16 refineries that would install grassroots postreaters in order to meet the proposed sulfur standards under an ABT program.***** E.O. 12866 Review**
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4 - 35 **References**

1 Mey ers, Robert A., Handbook of Petroleum Refining Processes, McGraw Hill, 1997. 2 40 CFR 80 Subpart H 3 Shorey, Scott W., AM

– 99 - 55, Exploiting the Synergy Between FCC and Feed Pretreating Units to Improve Refinery Margins and Produce L ow - Sulfur Fuels, National Petroleum and Refiners Association’s 1999 Annual Meeting. 4 Conversation with Woody Shiflett, Advanced Refining Technologies, October 2011. 5 Barletta, Tony, Refiners must optimize FCC feed hydrotreating when producing low - sulfur gasoline, Oil and Gas Journal, October 14, 2002. 6 Conversation with Woody Shiflett, Advanced Refining Technologies, October 2011. 7 Shorey, Scott W., AM

– 99 - 55, Exploiting the Synergy Between FCC and Feed Pretreating Units to Improve Refinery Margins and Produce Low - Sulfur Fuels, National Petroleum and Refiners Association’s 1999 Annual Meeting. 8 Brunet, Sylvette, On the hydrodesulfurization of FCC gasoline: a review, Applied Catalysis A: General 278 (2005) 143

– 172. 9 Leonard, Laura E., Recombinatio n: A Complicating Issue in FCC Naphtha Desulfurization, Prepared for the AI ChE 2006 Spring National Meeting, April 26, 2006 10 Petroleum Refinery Process Economics, Maples, Robert E., PennWell Books, Tulsa, Oklahoma, 1993. 11 Nocca, J.L., et al, Cost - Effect ive Attainment of New European Gasoline Sulfur Specifications within Existing Refineries, November 1998. 12 Prime G, A Sweet Little Process for Ultra - Lo w Sulfur FCC Gasoline without Heavy Octane Penalty, IFP Industrial Division . 13 Debuisschert, Quentin, Pri me G+ Update, 12 th European FCC Conference

– Grace Davidson Seminar, Seville Spain, May 2004. 14 Beck, J.S., Advanced Catalyst Technology and Applications for Higher Quality Fuels and Fuels, Prepr. Pap. Am Chem Soc., Div. Fuel Chem, 2004 49(2), 507. 15 McGih on, Ron, Exxon Mobil, FCC Naphtha Desulfurization

– New Developments, Presentation at the 2009 Technology Conference, October 5 &6, Dubai, United Arab Emirates. 16 Ellis, E.S., Meeting the demands of low sulfur gasoline, Petroleum Technology Quarterly Sprin g 2002. 17 Successful Start - Up of Ne w Scanfining Unit at Statoil’s Mongstad Refinery, November 19, 2003.***** E.O. 12866 Review**
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4 - 36 18 Greeley, J.P., Zaczepinski, S., Selective Cat Naphtha Hydrofining with Minimal Octane Loss, NPRA 1999 Annual Meeting (this document available from doc ket A - 97 - 10) . 19 Halbert, Thomas R., Technology Options for Meeting Low Sulfur Mogas Targets AM - 00 - 11, Presented at the 2000 Annual Meeting of the National Petrochemical and Refiners Association, March 2000. 20 McGihon, Ron, Exxon Mobil, FCC Naphtha Desulfur ization

– New Developments, Presentation at the 2009 Technology Conference, October 5 &6, Dubai, United Arab Emirates. 21 Refining Processes 2004, Hydrocarbon Processing. 22 Upson, Lawrence L., Low - sulfur specifications cause refiners to look at hydrotreatin g options, Oil and Gas Journal, December 8, 1997. 23 Krenzke, David L., Hydrotreating Technology Improvements for Low - Emissions Fuels AM - 96 - 67, Presented at the 1996 Annual Meeting of the National Petrochemical and Refiners Association, March 1996. 24 UOP Se lectFining TM Process

– New Technology for FCC Naphtha HDS, 2009 25 CDTECH, FCC Gasoline Sulfur Reduction, CDTECH, Sulfur 2000, Hart’s Fuel and Technology Management, Summer 1998 . 26 Rock , Kerry J., Putman, Hugh, Global Gasoline Reformulation Requires New Te chnologies, Presented at Hart’s World Fuels Conference, San Francisco, March 1998. 27 Rock, Kerry L., et al, Improvements in FCC Gasoline Desulfurization via Catalytic Distillation, Presented at the 1998 NPRA Annual Meeting, March 1998. 28 Greenw ood, Gil J., Next Generation Sulfur Removal Technology AM - 00 - 12, Presented at the 2000 NPRA Annual Meeting, March 2000. 29 Meier, Paul F., S Zorb Gasoline Sulfur Removal Technology

– Optimized Design AM - 04 - 14, Presented at the 2004 NPRA Annual Meeting, March 2004. 30 Pr inted Literature by Phillips Petroleum Shared with EPA September 1999. 31 Patal, Raj, Advanced FCC Feed Pretreatment Technology and Catalysts Improves FCC Profitability AM - 02 - 58, Presented at the 2002 NPRA Annual Meeting, March 2002. 32 Conversation with Woo dy Shiflett of Advanced Refining Technologies October 2011. 33 Letter to Margo Oge, EPA, from Mike Ricca, Baker Hughes, July 25, 2011. 34 Letter to Caryn Muellerleine, EPA, from Richard Kelly, Marvel Oil Company, July 13, 2011. 35 The requirements for transmi x blenders are contained in 40 CFR 80.84(d). 36 Graphs of transmix gasoline product sulfur levels at Kinder Morgan transmix processing facilities e - mail from James Holland, Kinder Morgan, August 24, 2011.***** E.O. 12866 Review**
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4 - 37 37 Letter from the Alliance of Automobile Manufactu rers to Administrator Lisa Jackson, October 6, 2011. 38 Moncrief, Philip and Ralph Ragsdale, “Can the U.S. E&C Industry Meet the EPA’s Low Sulfur Timetable,” NPRA 2000 Annual Meeting, March 26 - 28. 2000, Paper No. AM - 00 - 57.