1 Increasing Distillate Production at U.S. Refineries

– Past Changes and Future Potential

U.S. Energy Information Administration Office of Petroleum, Gas, and Biofuels Analysis

Department of Energy Office of Policy and International Affairs

October 2010

Summary

World consumption growth for middle distillate fuels (diesel fuel, heating oil, kerosene

, and jet fuel) has exceeded th e consumption growth for gasoline for some time, and the United States is no exception. Although the decrease in the ratio of tot al gasoline consumption to consumption for middle distillate fuels has been small in the United States, recent legislation requiring increased use of renewable fuels has resulted in forecasts that project a declin e in consumption for petroleum

- based gasoli ne from refineries, which would accelerate the decline in the gasoline

- to

- middle distillate ratio from what ha s been seen historically. Rising fuel economy standards for light duty vehicles are also expected to exert significant downward pressure on gasoli ne demand relative to diesel demand. In addition, price incentives to produce more middle distillate fuels have changed in recent years, with middle distillate margins exceeding those of gasoline more often than in the past.

These changes necessitate inve sti gating the ability of the U.S. refining system to produce more middle distillate fuels and less gasoline

, before any major investments would need to be incurred. The U.S. Energy Information Administration (EIA) and the U.S. Department of Energy ’s Office of Policy and International Affairs (PI) joined together to analyze this issue

. The results are summarized in this report.

This analysis used three approaches to assess how much U.S. refineries might increase middle distillate production: (1) Conducted discu ssions with industry experts (three refiners

, two catalyst and refinery process companies, and a refinery process consultant) and reviewed recent papers on shifting to higher yields of middle distillate s ; (2) Used a refinery model to explore the theoretical li mits and constraints on the ability of refineries to increas e middle distillate yields without significant capital investment; (3) Analyzed refinery production data, which U.S. refineries report to EIA.

Discussions with industry experts emphasized the overall importance to U.S. refineries of efficient distillation and component separations (in crude distillation and conversion units), optimization around fluid catalytic cracker ( FCC ) fee ds and operations, hydrocrackers in maximum distillate mode (where applica ble)

, and optimum hydrotreater operations and catalysts for maximum middle distillate production. Individual refinery equipment and configurations determine whether any or all of thes e strategies can be implement ed effectively at a particular refinery with its unique mix of available crude inputs and market demands. The refinery modeling approach showed that increases in middle distillate yield s greater than 10 percentage points and similar declines in gasoline yield s are possible for some refinery2 configur ations and crude slates, assuming optimum distillation separation and maximum distillate process operations. The analysis showed that crude slate is more important than refinery configuration. Model r uns were made for typical refineries on the East Coast, on the U.S. Gulf Coast, and in the Midwest, but the differences in results derived primarily from the set of crude oils chosen for the regional refinery configurations rather than from the configurations themselves. The model results represent an upper lim it to potential increases in middle distillate yield s at operating refineries. In practice, however, constraints will prevent all refiners from reaching modeled optimum levels.

EIA data for all U.S. refiners show that middle distillate summer yields incre ased by an average of 3.4 percentage points in summer 2008, when distillate margins were high versus gasoline, compared to summer 2007, when gasoline prices exceeded distillate prices

. Each percentage

- point increase in yield on the approximate 16 million b arrels per day of crude and unfinished oil inputs results in an increase in middle distillate production of 160 thousand barrels per day, representing almost 3 percent of U.S. middle distillate consumption during the summer of 2008.

In order to explore th e EIA data on yield increase in more depth, 49 refineries were identified that appeared to be operating normally in both summers. The individual refineries were analyzed and grouped by configuration type, crude oil type, and area location. Analysis of the actual 2007 and 2008 yields showed that significant increases in middle distillate yield s were fairly easily and quickly achieved without major capital investment. The average increase in

summer middle distillate yield for the 49 refineries was 4.5 percent age points ; however, individual results varied from less than 0 to increases more than 10 percentage points. The high end of the range is consistent with modeled results. Middle distillate

- yield increases are expected to be greater in the summer

, since tha t has historically been the maximum gasoline

season ; so annual averages would be smaller.

The conclusion is that, i n the short run, the refining industry could increase annual middle distillate yields by 3 to 5 percentage points on average over typical hi storical yields of about 35 percent

. Such yield increases could be achieved through operating changes , with little or no capital investment

. With more time and sustained higher diesel margins, refiners would spend capital on improved fractionation, and mor e refiners would move to catalysts favoring middle distillate production

, resulting in further yield increases. With such investments, a longer

- term average annual yield increase might be in the range of 4 to 8 percentage point s

.
The potential increases i n middle distillate yield and associated gasoline yield s would go a long

way in helping U.S. refiners meet projections for U.S. gasoline and middle distillate consumption

. Barring a much larger rebound in U.S. middle distillate consumption than that seen i n EIA’s Annual Energy Outlook 2010 , refiners should be able to adjust to changing distillate and gasoline needs without large investments. However, a need for some additional hydrocracking capacity is expected. For example, the economics may justify hydroc racking for refiners running difficult

- to

- process crude oils

, such as Canadian oil sands bitumen.

Refinery middle distillate

- yield increases may again be an attractive option for refiners as the economies of the United States and Europe improve. While U.S

. distillate margins are not expected to exceed gasoline margins to the degree they did in 2008 on a sustained basis, they may be sufficient to promote a more permanent shift of U.S. refining yield toward middle distillates and away from gasoline after the diesel market recovers from the recession.3 1. Introduction

The growth of w orld consumption o f middle distillate fuels (diesel fuel, heating oil, kerosene

, and jet fuel) has exceeded that for gasoline for some time, and the United States is no exception. Alt hough the decrease in the ratio of total gasoline consumption to middle distillate consumption has been small in the United States, recent legislation requiring increased use of renewable fuels has resulted in forecasts that project a declining need for pe troleum

- based gasoline from refineries , which would accelerate the decline in the gasoline

- to

- middle distillate ratio from historical trends

. Rising fuel economy standards for light duty vehicles are also expected to exert significant downward pressure on gasoline demand relative to diesel demand. In addition

, price incentives to produce more middle distillate fuels have changed in recent years, with middle distillate margins exceeding those of gasoline more often than in the past.

These changes h ave given rise to a need to explore the ability of the U.S. refining system to produc e more middle distillate fuels and less gasoline

, before any major investments would need to be incurred. The U.S. Energy Information Administration (EIA) and the U.S. Department o f Energy ’s Office of Policy and International Affairs (PI) joined together to analyze this issue

. The results are summarized in this report.

The report was written for analysts familiar with refining, but the summary and much of the report are intended to be accessible to those less familiar with the technical side of this industry. Section 2 describes the market conditions that evolved to stimulate in terest in this topic. Section 3 outlines the study approach, highlighting the three areas of analysis: ind ustry discussions and literature review; refinery modeling; and review of EIA data on refi nery operati ons

. Sections 4, 5, and 6 review results from these three areas of a nalysis. Section 7 concludes the report with our estimates of U.S. refiners ’ potential yield shifts to more middle distillate production in the future

.

2. World Distillate Demand Is Driving Refinery Changes

For over 50 years, U.S. refineries have focused on maximizi ng gasoline production to meet U.S. market demand. Maximizing gasoline yields during summer

, when driving demand was highest

, was the normal practice. In winter, especially if an unusual cold spell occurred

, refiners would shift yields to increase distillate (diesel and heating oil) production to meet higher heating oil demand. As s hown in Figure 1 below

, in the period from 1995 through 2004, gasoline prices exceeded heating oil prices most of the year except for short winter period s in

some years , when heating oil demand put extra pressure on distillate price s. (H eating oil prices

a re used in th e figure ; dies e l and heating oil prices generally move together. ) F rom 2005 to 2008, the market changed, with heating oil prices exceeding gasoline prices for a large fraction of each year. As the figure also shows, distillate prices in Europe have been stronger compared to gasoline than in the U nited S tates

. Before the recession in 2008, U.S. distillate consumption growth since 1995 was slightly higher on average than gasoline consumption growth

. However , t he market change reflected in the pri ces of Figure 1 ha s come mainly from growing international demand for middle distillate fuels

.4 Figure 1. Atlantic Basin Price Incentives Shifting Toward Distillate

The primary region driving the rise in world middle distillate demand has been Europe , wh ich represents about a quarter of the world’s middle distillate market

. The change in the relative consumption o f middle distillate versus gasoline has been much larger in Europe than in any other world region

, as shown in Figure 2

. The primary factor behi nd the change in Europe has been the switch by light

- duty vehicle consumers from gasoline

- powered vehicl es to diesel

powered vehicles. The move has been driven by European tax incentives on both vehicles and fuel to encourage the use of more energy

- efficie nt diesel

- fueled vehicles. According to the Association of European Car Manufacturers

, diesel cars had a 13.8

- percent market share in 1990, which grew to 32.1 percent in 2000 and 46 .0 percent in 2009

. Despite making both operational and investments changes to increase middle distillate yields, European refineries have not kept up with the demand shift

, and European middle distillate imports have grown

. At the same time, gasoli ne exports from Europe have also grown as European refiners produce as much middle distillate as possible

, and co

- produc e more gasoline than the region needs

.
The principal export market for excess volume s of European refinery gasoline has been the U.S. E ast Coast. Since 1999

, gasoline imports from Europe have grown from about 175 thousand barrels per day to 631 thousand barrels per day in 2008 ( from 29 percent to 58 percent of total U.S. gasoline imports). The increased gasoline import supply, when combin ed with increased ethanol being blended into gasoline

, has diminished the need for production of gasoline at U.S refineries. -50 -30 -10

10 30 50 70 90Jan-95Jan-96Jan-97Jan-98Jan-99Jan-00Jan-01Jan-02Jan-03Jan-04Jan-05Jan-06Jan-07Jan-08Jan-09Jan-10 NY
Harbor Northwest EuropeCents Per Gallon Spot Heating Oil - Gasoline Price Differences

Source: Reuters monthly av erage spot prices: New York Harbor conventional gasoline, No. 2 heating oil; ARA 50 ppm gasoline through 2006; ARA 10 ppm gasoline 2007 and forward; ARA gasoil.5 Figure 2. Ratio of Middle Distillates to Gasoline and Naphtha Consumption Highest in Europe

The U.S. has emer ged in recent years as a middle distillate supply source for the growing middle distillate market in Europe

. The U.S. had not previously been a middle distillate exporter on a net basis, but in 2008 that changed

. The L atin America markets (esp ecially Chile) used more U.S. di stillate in 2008, when Latin American consumption increased as a result of a loss of hydropower from drought conditions an d a natural gas shortage (Figure 3)

. Exports to Western Europe also increased in 2008, apparently to replace reduced volumes from Russ ia and Eastern Europe. D istillate consumption increased in other parts of the world as well, combining to drive up distillate prices relative to gasoline , reaching new highs in Atlantic Basin markets. 0.0 0.5 1.0 1.5 2.0 2.519891991199319951997199920012003200520072009 Europe

Asia

Rest of World Excluding FSU

United States Middle Distillate/Gasoline & Naphtha Consumption Ratios

Source: BP Statistic al Review of World Energy , June 2010.6 Figure 3. Middle Distillate Exports from the United S tates Increased in 2008

U.S. refiners were responsive to the 2008 Atlantic Basin market demand and profit opportunities

, and they produced significantly higher volumes and yields of middle distillate fuel

. As Figure 4 shows, U.S. refinery middle distillat e yield s bumped up noticeably in 2008. The details of refiners’ changes will be described in sections 4

, 5 , and 6 below.

T he trends of 2005

- 2008 were expected to continue, but the severe economic recession in late 2008 impacted world markets. Recessions h ave greater impacts on distillate fuel consumption than on gasoline consumption

, because distillate is strongly tied to manufacturing, being t he major fuel used to move goods.

The economic declines that occurred in 2008 had profound effects on consumption o f gasoline and middle distillate products in the U nited S tates

. U.S. gasoline and middle distillate consumption declined from 2007 levels in 2008. While U.S. gasoline consumption leveled off in 2009, middle distillate fell further. Middle d istillate cons umption was down almost 14 percent from 2007 to 2009, while gasoline fell about 3 perc ent during the same period. The impact on middle distillate s was greater because consumption of diesel fuel (the largest fraction of middle distillate) derives mainly fro m movement of goods in heavy

- duty vehicles, and production and sales of goods declined in the recession. Although growth has resumed, project ed 2011 volumes are still l ower than 2007 consumption

. 0 100 200 300 400 500 600 700 800 900 1,000

Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Other

Canada

Western Europe

Latin AmericaThousand Barrels Per Day Middle Distillate Exports from the U.S.

Source: Energy Information Administration, Petroleum Supply Monthly7 Figure 4. High Middle Distillate Yields in 2008 Returned t o Typical in 2009

The recession also affected the longer term outlook for U.S. gasoline and middle distillate consumption

, as shown in Figure 5. Before the recession

, the outlook was for greater growth in middle distillate fuel consumption than gasoline c onsumption

. That m ay still occur in the future , but middle distillate consumption must first re cover from the recession

- induced decline.

Much uncertainty surrounds the question of how long it will take for U.S middle distillate consumption to return to 20 07 levels and a long

- term growth path. Forecasts for commercial and industrial activity and the linked middle distillate consumption vary. EIA ’s Annual Energy Outlook 2010 show s a slow recovery for industrial and manufacturing activities, return ing to thei r 2007 level s of shipment value in 2013. 1 Th e slow recovery indicates that refineries might not see the U.S. 2007 middle distillate consumption levels again for several years , although continued growth in other areas of the world could provide export incen tives

.

Even with the economic downturn slowing European middle distillate demand, Europe is expected to continue to add pressure to Atlantic Basin distillate markets, while contributing to potential surplus gasoline supply. With growing demand pressure fr om the middle distillate market, r efineries in the United States and Europe may see incentives to respond to the increased middle distillate demand trend with both short

- term operational flexibility and some long

- term processing additions or modifications.

1 U.S. Energy Information Administration, Annual Energy Outlook 2010 , Table 20, http://www.eia.doe.gov/oiaf/aeo/excel/aeotab_20.xls

. 30% 31% 32% 33% 34% 35% 36% 37% 38% 39% 40%

Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Middle Distillate Yield (Middle Distillate Production/Crude + Unfinished Oil Input)

Note: Middle Distillate is di esel , heating oil, kerosene jet fuel and kerosene. Yield is middle distillate production divided by crude plus unfinished oil inputs to refineries. So urce: E nergy Information Administration, Petroleum Supply Monthly

.8 Figure 5. Outlooks Chang e for Gasoline (Including E85) and Middle Distillate Consumption

The demand for crude

- based refinery gasoline and middle distillates will depend not only on economic growth but also on vehicle fuel efficiencies, biofuel use, a nd the availability of product import s

. As a result of recent U.S. laws and regulations, U.S. gasoline demand will be

met with an increasing volume of biofuels (mainly ethanol) , and increasing light

- duty vehicle efficiencies will dramatically slow the grow th in total gasoline demand from histor ic al levels

. In addition, increasing availability of economic gasoline import supply may reduce the need for product from U.S. refiners. At the same time, the heavy

- duty vehicles that use diesel fuel are not expected to see as much improvement in efficiency. While biodiesel fuels will help meet distillate demand in the United States, they are expected to make a smaller contribution to transportation supply than ethanol. In addition, U.S. refiners should see growing ec o nomic opportunities for diesel exports , adding incentive to produc e more middle distillate fuels and less gasoline

, even with a slower economic outlook than previously expected.

The remainder of this report explore s how U.S. refiners can shift product bar rels to meet changing U.S. demand from refineries and middle distillate export opportunities. The discussion will illustrate how significant shifts can be done with operating changes and little investment. If current forecasts for slower middle distillate consumption growth prove wrong, and middle distillate consumption rebounds more quickly than projected, operating changes

can help to fill the gap for some time, while plans are made for larger capital improvements to deal with higher middle distillate nee ds. Still, the market may have to tighten considerably over 0 2 4 6 8 10 12

2007 2009 2011 2013 2015 2017 2019 2021 2023 2025Million Barrels Per Day AEO 2008 Gasoline

AEO 2010 Gasoline

AEO 2008 Middle Distillates

AEO 2010 Middle Distillates Gasoline and Middle Distillate Consumption Forecasts

Note: Gasoline includes E85. Source: U.S. Energy Informatio n Administration, Annual Energy Outlook 2008 and Annual Energy Outlook 2010 Reference Cases.9 today’s situation to increase financial incentives adequately for larger capital programs to look economic al ly attractive

.

3. Analysis Approach

EIA’s analysis of refiners ’ ability to increase middle distillate yield s used a three

- pronged approach :

**•** The first step was to review literature and conduct discussions with industry experts and selected companies. The literature review included papers presented at the 2009 National Petrochemical and Refining Association Annual Meeting. EIA followed up these reviews with conversations with several of the authors. Industry expert interviews included three U.S. refiners, two catalyst and process firms

, and a n FCC process consultant.

**•** The second pro n g of the analy sis path used a refinery model to explore the limits and constraints on the ability of refineries to increas e middle distillate yields without significant capital investment.

**•** The third path was a review of the EIA refinery data, which every U.S. refinery reports to EIA. Middle distillate and gasoline yields for refineries were analyzed over time, looking at variations by refinery configuration type, crude oil quality

, and region.

The remainder of this report assumes some knowledge of refining. Appendix A provides a brief overview of refining to assist those less familiar with refinery operations.

4. Industry Information: Refineries’ Ability to Increase Distillate Yields

U.S. refiners have worked historically to maximize refinery gasoline yields , because gasol ine has usually been the refined product with the highest value

. But in recent years

, the value of middle distillate products has exceeded the value of gasoline more frequently, and refiners are viewing middle distillate fuels as having better prospects fo r demand growth

. As a result, refiners are find ing ways to shift yield to more middle distillate. There are l imitations on increasing middle distillate yields , which vary by refinery

, depending on crude oil feedstocks and refinery configuratio n

. As a resul t, refiners have chosen a variety of options to provide greater middle distillate yields

. The paths include simple distillation cut

- point changes; better separation efficiency around those cut points; changing conversion process operating variables; using catalysts with better distillate selectivity; and other options involvi ng small capital investments. Also, several recent major U.S. refinery expansions (planned and recently operating) have incorporated hydrocracking units rather than FCC units. In discus sions with industry experts, PI and EIA explored what refiners are doing, the extent of change possible with modest investment, and the constraints on making changes.

4.1 Distillation Unit Changes for Increased Distillate Production

A refinery’s middle d istillate production can be increased by expanding the boiling point range of middle distillate material from primary distillation and from downstream conversion units to capture all the material that will meet middle distillate product specifications. Ref iners looking at this approach are faced with a number of potential constraints. If they produce more vo lume10 of middle distillate material, they must have enough d esulfurization capacity to proc ess the additio nal material

. Increasing the cut

- point ranges a lso changes the qual ity of the middle distillate product s , and depending on feedstocks and units downstream of the distillation tower, a refiner might not be able to produce diesel with correct specifications, such as cold flow properties

.

When distillati on unit cut points are altered to increase middle distillate production, the lower end of the boiling range is expanded by decreasing the naphtha end point so that added volume goes into kerosene, rather than being converted to gasoline in the reformer (Fi gure 6 )

. The upper end of the boiling range is expa nded by increasing the straight

- run distillate end point so that acceptable distillate material goes to distillate product rather than being converted to gasoline in the FCC unit. Similarly

, distillation c ut points for the FCC unit’s product fractionator can be adjusted to reduce the FCC gasoline endpoint and increase production of FCC light cycle oil (LCO)

, which is blended into middle distillate products. T he coker distillate cut

- point range can also be e xpanded.

Most of our discussions with refiners indicated that the distillation unit ’s end point for straight

run naphtha could be reduced from a 400

- 430 °F range to 360

- 370 °F, and the end point for straight

- run distillate could be increased from a range of 630

- 650°F to 680

- 700 °F. The FCC LCO and coker distillate boiling ranges could be adjusted similarly to produce more distillate material.

Figure 6 . Illustrative Product Yield, True Boiling Point (TBP) Distillation Curve



### 0 200 400 600 800 1,000 1,200 1,400 1,600

0 20 40 60 80 100



### Volume Percent TBP ( ° F)

Naphtha Kero-Jet Diesel Distillate Boiling Range Expansions

Vacuum Gas Oil (FCC Feed) Vacuum Tower Bottoms (Coker Feed)

Note: Most U.S. refineries use vacuum gas oil as an input to FCC units. Vacuum tower bottoms are used as input to coking units or to produce asphalt or residual fuel oil.11 Poor (or inefficient) fractiona tion can be an obstacle that limit s a refiner ’ s ab ility to expand the boiling

- rang e cut points as just described. Discussions of b oiling

- range cut point s generally refer to true boiling point (TBP) distillation ranges 2 where separations are precise ; but in practice, the quality of distillation in commercial refinery distillation units is usually sloppy. As an example

, cons ider the separation of straight

- run distillate and vacuum gas oil (VGO) or FCC charge stock. One article 3 stated t hat “many FCC [f eeds ] c ontain 25

- 35 percent or more of diesel boiling range material.” That was also shown in a survey designed to measure distillate material in FCC input

. 4 The poor separation not only leaves middle distillate material in the FCC feed, but also heavy ga s

- oil mo lecules in the straight

- run middle distillate blend stream, which increases the diesel end point, thereby increasing the di fficulty of meeting diesel cold

- flow property requirements.

Outside the United States, favorable taxes for diesel have provided an i ncentive to maximize diesel production

, and refiners have worked to capture all middle distillate boiling range material in middle distillate products by implementing more precise distillation processes. 5 The

non

- U.S. refiners may have 10 to 14 trays betwe en the flash zone and the distillate draw, whereas U.S. refiners may have only 2 to 5 trays. Furthermore, the vacuum distillation units used by non

- U.S. refiners are also designed or revamped to produce diesel from the vacuum column’s top

- side draw, enabli ng added middle distillate recovery from the vacuum unit.

In order for some refiners to improve fractionation efficiency, u nit revamps are needed

. To invest in revamp projects, r efiners must believe that higher middle distillate margins compared to gasoli ne margins will exist in the future. When gasoline margins are higher than or comparable to margins for middle distillate fuels, no incentive exists to improve distillation efficiency. Historically in the United States, a middle distillate molecule fed to an FCC unit and cracked to gasoline was attractive

. Only in recent years has t hat situation chang ed

, with middle distillate margins improving over gasoline margins

. On the other hand, improving dis tillation efficiency is a low

- cost path to producing more m iddle distillate fuel s

.

4.2 FCC Unit Changes for Increased Distillate Production

The first thing that refiners point out when discussing increasing distillate yield on the FCC unit is that the yield of LCO ( the distillate product stream from the FCC unit ) can be increased by reducing FCC reactor temperature, which reduces conversion . However , this is unlikely to be economically attractive. D istillate production increases when FCC conversion drops, but so does production of low

- value slurry oil. The result is exchanging gasoline production for a combination of higher margin distillate and considerably lower margin slurry oil and losing total light product volume (sum of higher valued products).

2 True boiling point distillation curves for crude oil are the boiling

- point pro duct yield curves over the entire distillation range (light naphtha to atmospheric residual fuel) in terms of temperature at atmospheric pressure.

3 Scott W. Golden, “Maximizing Diesel Recovery from Crude” PTQ (Petroleum Technology Quarterly), first quarter 2009, pp. 39

- 45.

4 Joseph McLean, BASF, “The Role of FCC Catalyst Technology in Maximizing Diesel Production

– Two North American Refinery Success Stories,” National Petrochemical and Refining Association 2009 Annual Meeting (San Antonio, TX), March 2009, AM

- 09

- 34.

5 Golden, pp. 39

- 45.12 More recently, h owever, new catalyst formulations with better cracking capabilities for heavy, high

- boiling

- point materials enable refiners to make modest distillate yield increases without increasing slurry oil production. A recent paper 6 on strategies for maximizing FCC LCO describe d a diesel catalyst and the use o f recycling a heavy oil fraction. Recycl e of heavy catalytic cracking gas oil was common practice in FCC operation in the pre

- zeolytic catalyst years of the 1960s, but it has disappeared since then. The paper indicated that, in cases using recycl ing and a diesel catalyst with good bottoms c racking characteristics, slurry

- oil volumes remained constant

, and the LCO

- to

- gasoline yield ratio increased. A quick return to use of FCC

- recycle operati on in commercial facilities is not simple

, however, and it is not l ikely to happen quickly. But persistently higher distillate margins could provide the incentive for this change.

4.3 Hydrocracker Unit Changes for Increased Distillate Production

Based on individual refiner discussions and presentations at the 2009 Natio nal Petrochemical and Refiners Association ( NPRA ) Annual Meeting, hydrocracking units (HCU s ) have been used to increase distillate production in several ways , while focusing on overall refinery balances and economics :

(1) Move the HCU operation from “gasoline mode” to “distillate mode” with reaction and distillation changes, noting that existing U.S. HCUs were generally designed to produce

max imum volume gasoline components

.

(2) Lower HCU conversion to the optimum range to produce m ore distillate or heavier

cuts

.

(3) Modify the vacuum gas

- oil feeds to the HCU to include LCO and coker gas oil s

.

(4) Implement a catalyst change that would maximize distillate rather than gasoline.

A combination of strategies (1) through (3) above would cause several yield changes in the HC U . First, the HCU yield of gasoline and distillate combined would decrease by about 5 percent per barrel, but this decrease would allow for a 15

- percent increase in HCU feed rate. Next, the share of distillate in the gasoline

- distillate mixture would inc rease from 40 percent to 60 percent. Although the per barrel yield of gasoline and distillate combined decreases, the increase in yield from the gasoline

- distillate mixture combined with the increase in overall feed rate gives a net result of 20 percent m ore distillate on a barrel

- per

- day basis.

The United States has 43 refineries with either distillate or gas

- oil hydrocrackers. The HCU capacity in this group averages 17 percent of refinery distillation capacity. Since those 43 refineries represent 49 p ercent of all U.S. capacity, the 20

- percent increase in middle distillate yield from the hydrocracker process units translates to an increase of about 1. 5 percentage point s in middle distillate yield for the U nited S tates on total crude oil inputs to refin eries

. The addition of a catalyst

- change strategy can move the 60

- percent HCU middle distillate yield to about 70 percent, rais ing the net impact from 20 percent to about 25 percent more middle

6 David Hunt, Grace Davidson , “Strategies for Maximizing FCC Light Cycle Oil”, Petrochemical and Refining Association 2009 Annual Meeting (San Antonio, TX), March 2009, AM

- 09

- 71.13 distillate volume per day from the HCU base gasoline mode in o ptimized

, maximum

- distillate HCU operation. This translates to a potential increase in middle distillate yield of about 2 percentage point s for total U.S. crude oil inputs.

HCU and FCC changes would typically be cons i dered together to increase middle dist illate yields. T he HCU produc es both products and an unconverted paraffinic stream that is sent to the FCC unit. The FCC unit produces its products and an unconverted aromatic stream that is sent back to the HCU, giving some symbiosis between the units and their unconverted byproducts

.

4.4 Distillate Hydrotreater Impacts on Increasing Distillate Production

Most material in the middle distillate boiling range must be further processed to remove sulfur before being sold. Thus, the more distillate material t hat is recovered in the refinery, the more volume must be processed to remove sulfur. Most refiners revamped or installed distillat e hydrotreaters to produce ultra

- low

- sulfur diesel ( ULSD )

. Many refiners now produce only ULSD, but it is unclear how many de signed their hydrotreaters with extra capacity to accommodate future volume increases. Extra hydrotreating capacity also requires the associated need for more hydrogen. Refiners that have sources from which to purchase hydrogen may not have a constraint, b ut hydrogen supply can be limiting for refiners who generate all their hydrogen.

More volume can be put through a distillate hydrotreater by changing out the catalyst more frequently. Also, catalysts have been and will continue to be improve d , allowing fo r more unit throughput. The wider cut points used to generate more distillate also pose an added burden on hydrotreaters. Some refiners will need to adjust hydrotreating catalysts to deal with cloud point issues. The key point from our industry discussions is that we can, in the short term, expect considerable variation in the constraints that distillate hydr o treating may impose on increased distillate production.

4.5 Total Potential Distillate Yield Shift Based on Industry Discussio n s

The discussions wit h industry indicated that many refiners are able to increase middle distillate yield in the short term, and expanding cut

- point ranges is the primary path being pursued. However, current limitations may limit the yield increase to about half o f what could be achieved with improved fractionation capability. When distillation unit cut

- point changes were made, FCC inputs were reduced because of the increase in distillate cut point (Figure 6 )

. Some, but not many, refiners made changes to their FCC catalyst s to increase FCC production of LCO. The improved catalyst resulted in about a 2

- percentage

- point increase in LCO production on FCC input. In total

, the industry discussions suggested that , in the short run, many refiners could see an increase in distillate yie ld of 3 to 6 percentage points on refinery crude inputs.

As a specific illustration, Valero provided their view for the potential to shift to more distillate production, which is shown in Figure 7

. Valero indicated that a modern, fairly complex refinery s hould be able to increase the distillate yield (measu red as a percent o f crude input ) by
7 to 1 3 percent. Note that to achieve the largest shift to distillate, Valero includes the addition of a hydrocracker , which is a long

- run solution

.14 Figure 7 . Illustr ative Industry View of Potential Distillate Yield Increases

Source: Valero presentation, http://www.slideshare.net/finance2/valero

- energy

- bas ics

- of

refining

- presentation

- january

- 13

- 2009

.

5. Model Analysis: Exploring Theoretical Distillate Yield Shift s

A generalized refinery modeling system was used to examine the theoretical extent to which middle distillate yields could be increased at U.S. ref ineries. 7 As shown in Table 1

, model runs were made using a range of refinery types representing facilities in four U.S. regions running various crude oils.

Major Conve rsion Units Available Types of Crude Oil Run Locations
U.S. Gulf Coast Midwest East Coast West Coast

FCC Light Sweet X X X FCC, Coker Medium Heavy X X FCC, Large Coker Heavy X X FCC, Large Coker, Hydrocracker Heavy X X
Note: FCC

– Flu id catalytic cracking unit.

The types of refineries and configurations chosen were based on a review of U.S. refinery data reported to EIA. While the base configurations do not represent any specific refineries, they

7 Haverly’s GRMPS modeling system was used, with additional inputs and assistance from Jacobs Consultancy. Table 1. Refinery Modeling Array of Refinery Configurations, Crude Slates and Regions15 fall within the range of facilities w ith similar process unit capacities, types of crude oil charges, and product outputs. The biggest difference between model runs and commercial operations is that the refinery model assumes perfect TBP distillation separation of the fraction s from both prim ary distillation and downstream process unit fra ctionators ( s ee Appendix A). While the model runs give an overly optimistic picture relative to actual commercial operations, they do provided useful insight into the impacts of crude oil input differences, p roduct quality constraints, and process unit limitations on shifting yields from gasoline to distillate.

The shift in gasoline to distillate yield was driven in the model by changing the relative price of gasoline and diesel and was in keeping with price changes that occurred from summer 2007 to summer 2008, when distillate prices rose and stay ed well above gasoline prices. Table 2 shows the price change used to drive the yield shift in the model.

Base Case High Distillate Price Bonny Light Crude Oil ($63/Barrel) 150.1 150.1
Conventional Gasoline (87 octane, E10) 180.4 160.4

Ultra

- Low

- Sulfur Diesel 160.4 180.4
Note : E10 is gasoline containing 10 percent ethanol.

Prices for o ther gasoline grade s and type s (e.g., premium reformulated) and other middle distillate products (e.g., heating oil

, ULSD, jet ) were generated as constant differentials to either the conventional regular gasoline or diesel price in Table 2. Model runs were mad e to examine a wider gasoline

- diesel price differential range than those shown in Table 2

, in order

to assure that the Table 2 range encompassed a meaningful refinery operating range.

The c onv ersion unit capacities for different configurations and crude mixes

, shown in Table 3

, were used as upper

- limit constraints. The other units were allowed to use input as needed (i.e., unconstrained capacity)

. A key unit for this analysis was the ULSD hydro treater. When the shift is made from the higher gasoline price to higher diesel price, the refinery increases diesel production, which increases diesel hydrotreating requirements. Some refineries can handle increased input to their diesel hydrotreaters, bu t for many others, th e capacity of th is unit limits distillate yield increase s.

Major Conversions Units Available Crude Oil Mix Run Gulf Coast Process Unit Capacities (Thousand Barrels Per Day)
ADU FCC Coker Hydrocracker
FCC Light Sweet 100 25 FCC, Coker Medium Heavy 100 38 20 FCC, Large Coker Heavy 100 34 30 FCC, Large Coker, Hydrocracker Heavy 100 26 30 17

Note s : ADU = a tmospheric d is tillation u nit; FCC = f luid catalytic cracking unit. Results for these c ases are provided in Appendix B. Table 2. Refinery Modeling Crude and Product Prices (Cents Per Gallon)

Table 3. R efinery Modeling Details of Refinery Configurations16 Th e content s of the crude oil mixes shown in Table 3 are summarized in Table 4. The major case labels, which incorporate the crude mix, refinery units, and other variants in the case name, are shown in Table 5.

Bonny Ligh t Cabinda Saudi Medium Saudi Heavy Maya WTI

Medium Heavy 20% 40% 40% Heavy 20% 20% 60% Light Sweet 100%
Note: WTI = West Texas Intermediate crude oil

.

Case Crude Oil Mix Refine ry Configuration Med Hvy Crude (FCC+Ckr) (Base Case) Medium Heavy FCC, Coker
Hvy Crude (FCC+ Lg Ckr) Heavy FCC, Large Coker Hvy Crude (FCC+Lg Ckr+HydroCkr) Heavy FCC, Large Coker, Hydrocracker Light Sweet Crude (FCC) Light Sweet FCC

The model runs in clude both a summer and winter simulation with appropriate seasonal product specifications. The yield shifts for the change from high gasoline to high diesel price are shown in Figure 9 below

.
Figure 8 shows that, regardless of crude mix or configuration, almost 10 percent more distillate could be made in summer over the amount in the Base Case, which has high gasoline margins. But that i s not the situation during the w inter. In winter, those same crude mixes can interfere with meetin g winter product speci fications; although in some cases

, the problems can be overcome by the processing capabilities of some units.

The fi rst case to the left in Figure 8 is the U.S. Gulf Coast Med Hvy Crude (FCC+Coker) Case. It shows no diesel yield increase in the winter sea son over the Base Case due to cold flow property and jet fuel production limitations. The diesel cold flow property requirements in the winter preclude sending a heavier straight run cut to distillate blending. For the winter season,

t he heavier cut goes t o the FCC unit, as it did in the high

- gasoline

- price Base Case. Also, a minimum jet fuel production requirement exists, which limits availability of additional lighter

distillate material for blending into diesel. Hence, despite the higher distillate price incentive

, the winter maximum for diesel production is the same as that in the winter high

- gasoline

- price Base Case

.
The next case in Figure 8 , the Hvy Crude (FCC+Lg Coker) Case, is essentiall y the same configuration as in the first case, but it uses a d ifferent mix of crude oil feeds

, and the properties of the composite heavy feed allow for increased diesel winter production when the diesel price is higher. However, diesel cold

- flow properties still pose a challenge, and the Table 4. Content of Crude Oil Mix

Table 5 . Example Case Label s Illustrating Naming Convention17 increase in diesel yield is o nly 5 percent during the winter compared to the 10 percent achieved in summer over the high

- gasoline

- price Base Case.

Figure 8

. U

. S

. Gulf Coast Refineries: Increased Middle Distillate Yield with High Diesel Margin vs. Base Case with High Gasoline Margin

The last two cases have rough ly the same distillate yield improvements in both winter and

summer

. These two cases have different crude mix inputs and different configurations. The Light Sweet Crude ( FCC ) Case show s the importance of type of crude oil in meeting winter diesel specifications. With no additional refinery conversion units to help meet winter specifications, w inter cold flow property constraints were avoided because of the hydrocar bon composition of the straight

- run distillation cuts of the cr ude oil used

. In contrast, the Hvy Crude (FCC + Lg Coker + HydroC kr) Case ran the same heavy crude mix as in the Hvy Crude ( FCC + Lg Coker ) Case, but the hydrocracker unit enabled the refiner to produce nearly as much distillate in winter as in summer. Som e production specification constraints still exist for winter production

, as indicated by more jet fuel being made in the summer period.

Several refinery model runs were made to further explore the factors that influence how far distillate production coul d be increased . Figure 9 shows variations for a basic FCC + C oker refinery configuration. The cases vary the content of the m edium

- heavy crude oil mix and look at the impacts of eliminating the need for jet fuel. 0 2 4 6 8 10 12

Summer Winter Med Hvy Crude (FCC + Coker) Hvy Crude (FCC + Lg Coker) Hvy Crude (FCC + Lg Coker + HydroCkr) Light Sweet Crude (FCC) Middle Distillate Percentage Point Yield Increase

Base Case Med Hvy (FCC + Coker): No ChangeBase Case

Source: Model resul ts from Jacobs Consultancy analysis performed for Department of Energy.18 Figure 9 . FCC + Coker Configuration: Middl e Distillate Yield Impacts of Variations in Medium Heavy Crude Types

The first case in Figure 9 is the U.S. Gulf Coast (USGC) Med Hvy Crude (FCC + Coker) B ase C ase shown in Figure 8

. The next case used this same refinery, but exchange d the b ase medium h eavy crude oil blend with a blend of Mars and WTI crude oils of comparable gravity. With the Mars

- WTI blend, the FCC plus c oker refinery increased distillate yield by 12 percent in both summer and winter seasons when distillate prices were higher , highligh ting again the importance of the characteristics of the crude oil refinery runs.

The third case from the left in Figure 9 shows how p roducing jet fuel adds to the difficult y of increas ing t otal distillate yield with the b ase medium heavy crude oil blend, since the jet boiling range material is not available in winter to improve the diesel cold flow properties (reduce the pour point). In this case, the minimum jet fuel production requirement was eliminated to show the impact of th at constraint. With no jet fuel requirement, the refinery increased total distillate yield in winter by 5 percent. That yield increase was still considerably less than the 11

- percent increase achieved in summer in the same case; but it was substantially greater than th e zero increas e for the winter with a minimum jet fuel production requirement.

The last run in this set was for a Midwest refinery with the FCC + Coker configuration, but in this case the crude oil runs were a combination of Canadian Bow River with WTI and WTS. 0 2 4 6 8 10 12 14

Summer Winter USGC Med Hvy Crude (FCC + Coker) USGC Med Hvy Mars/WTI Mix (FCC + Coker) USGC Med Hvy Crude (FCC + Coker) No Min Jet PADD 2 Med Hvy Can/WTI/WTS Mix (FCC +Coker) Middle Distillate Percentage Point Yield Increase

Base Case Med Hvy (FCC + Coker): No ChangeBase Case

Note: USGC

– U.S. Gulf Coast

. Source: Model results from Jacobs Consultancy analysis performed for the U.S. Department of Energy.19 In thi s example, distillate yields increased by 12 percent age point s in summer and 10 percent age points in the winter season.

Model r uns were made for typical refineries on the Gulf Coast and East Coast and in the Midwest, but the differences in results derive primarily from the set of crude oils chosen for the

runs. In conclusion, the model runs described above indicate that crude type is usually more important than refinery configuration in increasing distillate yields.

In summary, the model runs present an u pper range of what might be achieved by refiners today. In actual practice, relatively few have improved their primary and downstream fractionator capability to achieve the highly effi cient cut separation needed to produce the yield swings seen in the mode l runs. However, if distillate prices were to sustain a premium over gasoline, more refineries w ould make the modest investment to improve fractionation, which

w ould allow them to move to the high distillate yield levels achieved by some refineries already , as discussed in the next s ection.

6. Analysis of Actual Responses of U.S. Refiners to High 2008 Distillate Margins

EIA ’s 2008 monthly data showed that U.S. refiners responded to higher distillate margins with increased production of distillate and reduced gasoline production , where gasoline production includes both finished gasoline and gasoline blending components

. Since EIA has monthly reports of product outputs by individual refinery along with inputs to major units, it is possible to examine how distill ate yield changes varied across the range of refineries

, based on the types and complexit ies of refineries, the crude feed quality, the regional location

, and the historic al gasoline/distillate production ratio.

Individual refinery input and output data f or summer (May

- Aug ust ) 2008 were compared with inputs and outputs for the same months in both 2006 and 2007. If a refinery showed no indication of major unit outages or other major operational changes, it was used to compare distillate yield between 2007 a nd 2008. Input and output data for summer 2006 w ere also examined to identify any unusual problem with the 2007 base year. The result was the selection of 49 refineries in all regions except the Rocky Mountain area for the comparison.

A plot of the smalle st to largest distillate yield change fo r the 49 refineries is shown in Figure 10 , which illustrates the wide distribution of distillate yield increases between summer 2007 and summer 2008

. About 60 percent of the refineries had distillate yield increases of more than 4 percent age points , and yield increases at a bout 33 percent of the refineries were in the range of 4 to 6

- percent age point s

. The wide distribution suggest s that it could be difficult to identify unique factors distinguishing those refiners ma king large yield gains from those with small improvements.

The results of trying to identify factors associated with the yield shifts showed only weak relationships. Individual companies did not show striking ly different patterns. A range of yield shifts occurred for various refineries within each refining company, with no single company showing dramatically better or worse results. Geographic location provided no significant insights. Shifts occurred in all regions of the country, although the largest shi fts were for the subset of refineries on the Gulf Coast, which showed an average increase in distillate yield of 5.0 percentage point s and an average decline in gasoline yield of 3.5 percentage points

.20 Figure 10

. Middle Distillate Yield Changes for 49 U. S. Refiners
, Summer 2008 Over Summer 2007

Table 6 shows yield shift results by refinery complexity, as measured by the presence of a coking or hydrocracking unit. While one might have ex pected the refineries with FCC , coking, and hydrocracking units (last column in Table 6 ) to show the greatest change in yield ( since this set of units represents the most flexible refinery configuration ) , that was not the case. The reason was that diesel exports were providing the greatest incentive to shift yields in 2008, and the Gulf Coast was the region best able to take advantage of the export markets. Refineries on the Gulf Coast do not have the highest complexity (all three conversion units). West Coast refineries have the highest complexity, but they were not in a po sition to take much advantage of the export market opportunities and thus had less incentive to push increases in distillate yield. -4% -2% 0% 2% 4% 6% 8% 10% 12% 14%

0 5 10 15 20 25 30 35 40 45 50

Refinery NumberYield Change (Percentage Points)

~ 60% of represented refineries increased yield more than 4 percentage points

Note: The 49 refineries were chosen because they seemed to operate normally (i.e., no unusual changes in inputs or configuration ) in both 2007 and 2008. Source: EIA 810 “Monthly Refinery Report” survey

.21 I ndividual refiner y yield shifts by type of refinery are shown in Figure 11

. The plot represents changes that these refineries made over one year when distillate prices rose well above gasoline and stayed at those higher levels during the summer months. There is a clear relation ship between the increase in distillate and decline in gasoline production as expected, but no significant difference between refinery types.

During 2007

- 2008, refiners had little time for making even modest capital changes. It i s very likely that if those higher distillate

- to

- gasoline price differentials had persisted longer, a number of refiners showing little yield

- shift in Figure 11 would have done more. But with the 2009 market retrenching to roughly the same margins for gaso line and distillate as seen in 2005

- 2007, further shifts have not taken place. Table 6 . Yield Shifts

, Summer 2007 to Summer 2008 , for PADDs 1, 2, 3, and 5 by Refinery Type Refinery Types

FCC FCC, H ydrocracker FCC, Coker FCC, Coker, Hydrocracker Average of Summer 2007 and 2008 API Crude Gravity 35.5 36.0 27.8 27.9 Crude Input (KB/D) 140.9 139.4 176.7 217.7 Change from Summer 2007 to Summer 2 008 (Percentage
P oints) FCC Inp ut

- 0.9

- 0.2

- 3.3

- 0.3
Gasoline Y ield

- 2.0

- 3.5

- 4.6

- 3.2
Middle D istillate Y ield 3.1 4.6 5.2 4.7
Notes: KB /D = t housand barrels per day ; PADD = Petroleum Administration for Defense District. Sources: EIA 810 “Monthly Refinery Report” survey.22 Figure 11 . Refinery Middle Distillate and Gasoline Yield Shifts
, May

- August 2007 to May

- August 2008

7. Middle Distillate Yield Potential and Future U.S. Demand

In summary, ba sed on the analysis and industry discussions described here , we estimate that, in the short run, the refining industry could increase annual yields by 3 to 5 percentage points on average over typical historical yields of about 35 percent

. Such yield increa ses could be achieved through operating changes and little or no capital investment

. With more time and sustained higher diesel margins, refiners would spend capital on improved fractionation, and more refiners would move to catalysts favoring distillate p roduction

, resulting in further yield increases. With such investments, a longer

- term average annual yield increase might be in the range of 4 to 8 percentage point s

.
These estimates for potential industry yield changes in middle distillate fuel and gasol ine can

now be used to explore how such shifts can help to meet future demand. As discussed in Section 1, changes are occurring that are altering the traditional growth patterns for distillate and gasoline demand

. D iesel margins in 2008 were much higher th an gasoline margins

, and 

### -4 -2

0 2 4 6 8 10 12 14

-14 -12 -10 -8 -6 -4 -2 0 2 4

Gasoline Yield Change (Percentage Points 

### ) FCC Only

FCC + Coker

FCC + Hydrocracker

FCC + Hydrocracker + CokerMiddle Distillate Yield Change(Percentage Points)

Source: EIA 810 “Monthly Refinery Report” survey.23 growth in consumption o f middle distillate from petroleum was forecast to be stronger than consumption o f gasoline. Legislation mandating higher light

- duty vehicle efficiency and increasing use of renewable fuels c ombined with grow ing availability of gasoline imports to diminish the need for growth in gasoline derived from petroleum at U.S. refineries. At the same time, diesel growth was increasing with economic growth

, and an emerging export market for diesel was developing. But fo recast s have changed dramatically in the past two years because of the recession

.

T wo editions of EIA ’s Annual Energy Outlook ( AEO ) provide a means to explore several consumption scenarios. T he gasoline and middle distillate consumption proj ections from t he 2008 and 2010 A EO s reflect a sharpl y changed outlook for these fuels

. In order to estimate potential U.S. refinery needs, gasoline and middle distillate consumption from the 2008 and 2010 AEO Reference Cases w ere reduced by the corresponding AEO project ions for ethanol and other biofuel supplies and by two illustrative projection s for gasoline net import s and middle distillate net exports

, as sho wn in Table 7

.
The High and Low Distillate Consumption Cases in Table 7 have the same imports and exports. Yi eld shifts alone are used to meet the changing middle distillate and gasoline consumption over time in the two cases. To meet consumption in the High Distillate Consumption Case, middle distillate yields have to increase by 7.7 percentage points (from 35.4 percent to 43.1 percent) in 2025 over 2007. 8 From the High Consumption forecast perspective, middle distillate consumption growth was being driven by a stronger economy than in the Low Consumption Case, and financial incentives would be expected to be gre ater to encourage investment in more middle distillate production. Consistent with that view, in 2007, a number of refiners had announced plans for additional hydrocracking capacity. The projected 2025 middle distillate yield of 43 percent would be credibl e in an environment where additional hydrocracking capability was being planned.

The Low Distillate Consumption Case shows middle distillate yields at about 39 percent in 2025, which is well within the range of achievable yield increases resulting from re finery changes not requiring major capital investments.

The High Import/Export Case assumes higher net imports of gasoline and net exports of middle distillate than in the High and Low Consumption Cases. In the High Import/Export Case, the middle distilla te yield in 2025 needs to increase by only about 1 percentage point over the Low Consumption Case, to about 40 percent. While a 40

- percent yield is still achievable without major hydrocracking investments, some additional hydrocracking capacity is expected even with this lower consumption scenario. For example, the economics may justify hydrocracking for refiners running difficult

- to

- process crude oils such as Canadian tar sands bitumen.

8 The historical year for comparison is 2007. The 35

- percent middle distillate yield in 2007 was typical for U.S. refineries before 2008, and the unprecedented yield increase toward 38 percent in 2 008 was not sustained in 2009, when distillate consumption fell as the economic downturn accelerated.24 Actual High Distillate Consumption

Case Using AEO 2008 Low Distillate Consumption Case Using AEO 2010 High Import/Export Case Using AEO 2010

Thousand Barrels Per Day Except As Noted 2007 2010 2025 2010 2025 2010 2025

Gasoline Consumption 9.29 9.59 8.84 9.22 9.32 9.22 9.32
E85 Consumption Ethanol Supply 0.45 0.81 1.59 0.89 1.21 0.89 1.21 Gasoline Net Imports* 1.02 0.77 0.70 0.77 0.70 0.90 1.00
Gasoline from U.S. Refineries 7.84 8.01 7.52 7.44 7.47 7.44 7.47
Gasoline Yield (Percent Crude Oil) 49.3 47.5 42.3 48.86 45.20 48.9 45.2

Middle Distillate Consumption 5.82 6.06 7.35 5.23 6.15 5.23 6.15

Biodiesel Supp l y 0.03 0.04 0.07 0.06 0.11 0.06 0.11
Middle Distillate Net Exports* - 0.21 0.38 0.40 0.38 0.40 0.39 0.60

Middle Distillate from U.S. Refineries 5.58 6.40 7.68 5.56 6.64 5.56 6.64

Middle Distillate Yield (Percent Crude Oil) 35.4 37.9 43.1 36.2 39.4 36.5 40.2

* Gasoline net imports and middle distillate net export projections were not AEO projection s. They were based on recent trends and outlooks for the Atlantic Basin in order to illustrate potential distillate production pressures on U.S. refineries.

Increases in r efinery middle distillate yield s are likely to be an attractive option again for

re finers as the economies of the United States and Europe improve. Although distillate margins are not likely to exceed gasoline margins to the degree they did in 2008 on a sustained basis, they may be sufficient to promote a more permanent U.S. refining yie ld shift toward middle distillates and away from gasoline as the diesel market rebounds from the recession

. Table 7

. Consumption Scenarios Illustrating Different Potential Ref inery Yields for Gasoline and Distillate25 A PPENDIX A: Refining Primer

Refining crude oil into petroleum products begins with crude oil entering a large distillation tower, where it is dis tilled or separated into various boiling

- range streams that then move into various units downstream of the crude oil tower. Figure A1 shows the major boiling range breakouts in the crude distillation column. Inside the column, trays are used along the heig ht to maximize vapor

- liquid contact

, which provides better separation

. The lighter streams eventually go to gasoline, the middle streams go to distillates (with sulfur removal)

, and the heavier, high

- boiling

- point streams go to residual fuel or are sent to other units like the hydrocracker, fluid catalytic cracking unit (FCC)

, or coking unit to be broken down to increase the yield of lighter, high

- valued products.

Figure A1. Typical Crude Distillation Tower Boiling Range Cut Points

The units downstream o f the distillation tower (also called the distillation unit) are where most of the crude oil molecules are transformed (i.e., refined) into higher quality, higher valued transportation fuels (Figure A2)

. For example, the light straight

- run gasoline stream that goes directly into the gasoline pool constitutes only about 5 percent of the total gasoline produced. The remaining gasoline volumes come from the downstream units. The downstream units basically do three things: break apart heavy, low

- valued molecule s into lighter, more valuable materials; rearrange molecules to improve performance or meet emission goals; and remove undesirable materials such as sulfur or toxic compounds. The units that break apart or rearrange molecules are also sometimes referred to as conversion units. Crude Oil Distillation: Start of Refining Process

85

- 200 **°** F

200

- 350 **°** F

350

- 450 **°** F

450

- 650 **°** F

650

- 1050 **°** F

1050+ **°** F <85 **°** F

Light Straight Naphtha Gasoline Blending

Naphtha Crude

Oil

Distillate

Heavy Gas Oil

Residuum Catalytic Reforming

Hydrotreating

Hydrotreating

FCC, Hydrocracking
Coking, Hydrocracking Kerosene/Jet **Boiling Range Product**  **Destination**

Butane &

Lighter Gas ProcessingDistillation Unit Light Ends, Low

Boiling Point

Bottoms,

High Boiling Point26 Figure A2. Major Units Downstream from the Crude Distillation Tower

A hydrocracking unit, or hydrocracker, takes light gas oil , which is heavier and has a higher boiling range than distillate fuel oil, and cracks the heavy molecule s into distillate and some gasoline. Many refiners do not have hydrocrackers. In the Gulf Coast region defined by Petroleum Administration for Defense District (PADD) 3, total hydrocracking inputs represent about 8 percent of total gross inputs to refineri es in the region. However, in refineries that have hydrocrackers, the hydrocracking inputs represent 13 percent of total gross inputs. As the name implies, the hydrocracker is a hydrogen

- adding process to break apart large, heavy, low

- valued molecules into higher

- valued lighter materials. The hydrocracker upgrades leftover, low

quality heavy distillates from the distillation tower, the FCC

, and the coking unit s into high

quality, clean

- burning jet fuel, distillates, and gasoline. In the emerging low

- sulfur world, the hydrocracker often converts high

- sulfur materials, which would end up in marine or boiler fuel, into low

- sulfur fuels for vehicles and airplanes. The hydrocracker streams eventually contribute about 5 percent of the gasoline volume in a refinery

.
The reformer is a major gasoline

- producing unit, providing about one

- third of the gasoline volume a refinery produces. A reformer takes low

- octane gasoline material and “reforms” molecules to produce molecules with more complex structures and higher oct ane than the simpler naphtha feedstocks. The high

- octane reformate that is produced contains aromatics that have some undesirable environmental properties. Thus, while the output of the reformer produces a gasoline stream with desirable driving properties, the stream must be balanced with other cleaner

- burning components to reduce its undesirable environmental aspects.DistillationTower Reformer

Hydrotreating

Fluid Catalytic Cracking Alkylation

Hydro

treating

CokerProduct Blending Diesel/Heating Oil Kerosene Light Straight Run Gasoline

Reformate to Gasoline

Alkylate to Gasoline

FCC Gasoline

Light Cycle Oil to Distillate

Coke Refinery Capacity: Distillation, Conversion & Bottoms Upgrading

Crude

Oil

Bottoms Light EndsVacuum Unit Hydrotreating

Pre

treating

Hydrocracker Hydrocrackate Gasoline Diesel/Heating Oil/Jet27 The FCC is another major gasoline

- producing unit. It takes heavy gas oil and cracks the heavy molecules into smaller molecules that are use d to make additional gasoline and some distillate fuel as well. A continuously operating FCC unit will have a primary reactor, where a hot catalyst reacts with the heavy gas

- oil molecules to break them apart ; a dedicated distillation tower to separate the cracked molecules by boiling range ; and a regenerator to burn off the carbon on the catalyst, allowing it to be reused in the reactor. The FCC is one of the largest downstream units and one of the few units whose size is relatively consistent with the size of the distillation tower across refineries. FCC units tend to be from 35 to 40 percent of the size of the distillation tower. Consistent with that, in PADD 3, feed to FCC units represents almost 40 percent of the gross inputs to crude oil distillation to wers in th e region. The FCC unit is mainly a gasoline

- producing unit

, and it provides more than one

- third of the gasoline volume a refinery produces. However, the FCC unit also provides the inputs (olefins) to the alkylation unit, where the alkylate gasoli ne component is produced. Alkylate has desirable clean

- burning properties as well as good drivability characteristics, making it one of the more valuable gasoline components. The FCC and alkylation units, combined, supply close to one

- half of the gasoline volumes a refinery produces.

The coking unit takes residual fuel oil, sometimes referred to as “bottoms” material, and cracks it into gasoline and distillate fuels, leaving petroleum coke behind. Many refiners do not have coking units. The size of the cok ing unit in a refinery is mainly a function of the volume of heavier crude oils being used. (The heavy crude oils produce larger percentages of heavy, residual fuel oil than light crude oils.) Most refiners on the East Coast tend to use lighter crude oils, and as a result, most refineries in th e region do not have coking units. Many Gulf Coast refineries use heavy crude oils from Mexico, Venezuela, and the Middle East and have coking units installed

. Refineries using the heavier syncrudes from Canada also h ave or are installing coking units, and most PADD 5 refineries have installed coking units for use with heavy California crude and other heavy crude oils. In PADD 3, inputs to coking units in total are about 15 percent of the gross input to distillation to wers ; but unlike the FCC units, the size relative to distillation can vary significantly among refineries. Streams from the coking unit are further processed in the refinery and eventually constitute 5 to 10 percent of the gasoline volume a refinery produc es.28 APPENDIX B. Refinery Run Detail

The follo wing tables provide more detailed output from the refinery model runs used in this study.29 Summer Winter Summer Winter Summer Winter Summer Winter Summer Winter Summer Winter Summer Winter Summer Winter

Crude Input: B/D
WTI 0 0 0 0 0 0 0 0 0 0 0 0 100,000 100,000 100,000 100,000 Bonny Lt 20,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000 0 0 0 0 Cabinda 40,000 40,000 40,000 40,000 0 0 0 0 0 0 0 0 0 0 0 0 Mars 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Maya 0 0 0 0 60,000 60,000 60,000 60,000 60,000 60,000 60,000 60,000 0 0 0 0 Saudi Heavy 0 0 0 0 20,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000 0 0 0 0 Saudi Medium 40,000 40,000 40,000 40,000 0 0 0 0 0 0 0 0 0 0 0 0

Other Feed Inputs: B/D Purch Gas (FOE) 3,292 3,468 3,516 3,468 4,857 5,030 5,453 5,091 7,875 7,372 6,651 7,257 2,656 2,541 2,480 2,591 Normal Butane 0 2,609 0 2,609 0 3,292 0 2,455 0 4,161 0 2,374 0 4,605 0 2,899 Iso Butane 2,082 2,013 1,918 2,013 2,091 1,991 1,626 1,951 4,560 1,357 1,056 1,070 3,064 956 690 775 Ethanol - Blending 3,640 3,473 2,989 3,473 3,410 3,512 2,795 3,254 3,679 3,790 2,679 2,967 4,003 4,123 3,075 3,396

Products: B/D Total LPG 6,536 5,226 6,580 5,226 6,551 5,544 6,745 5,519 3,674 5,170 5,898 4,473 2,546 3,626 4,821 3,141 Total Mogas 57,660 55,005 47,347 55,005 54,008 55,628 44,276 51,549 58,281 60,030 42,436 46,991 63,411 65,313 48,714 53,793 Total Jet 4,180 4,000 4,000 4,000 4,000 4,000 4,571 4,000 6,773 4,000 7,317 4,000 4,000 4,000 7,404 7,151 Total Diesel (ULSD) 31,837 37,484 42,051 37,484 32,114 34,913 41,562 38,383 32,169 34,114 42,008 45,201 22,513 23,358 29,978 30,234 Total RFO, Slurry, Lubes 3,812 5,130 3,602 5,130 3,373 3,558 2,353 3,283 2,067 1,931 1,847 1,847 12,513 12,311 11,870 11,870

Total Distillate (Jet+ULSD) 36,016 41,484 46,051 41,484 36,114 38,913 46,132 42,383 38,942 38,114 49,325 49,201 26,513 27,358 37,382 37,385 Total MJD 93,677 96,489 93,399 96,490 90,122 94,541 90,409 93,933 97,223 98,144 91,762 96,193 89,924 92,672 86,096 91,179 Distillate Yield: % 36.0 41.5 46.1 41.5 36.1 38.9 46.1 42.4 38.9 38.1 49.3 49.2 26.5 27.4 37.4 37.4

Unit Inputs: B/D Crude Tower 100,000 100,000 100,000 100,000 100,000 100,000 100,000 100,000 100,000 100,000 100,000 100,000 100,000 100,000 100,000 100,000 Vacuum Tower 43,344 43,344 43,344 43,344 49,212 49,212 49,212 49,212 49,212 49,212 49,212 49,212 27,130 27,130 27,130 27,130 FCC 37,097 37,097 32,664 37,097 33,793 33,793 27,555 33,225 25,376 24,236 19,976 19,976 23,310 23,310 18,128 18,128 Hydrocracker 0 0 0 0 0 0 0 0 16,797 16,488 11,193 13,629 0 0 0 0 Delayed Coker 19,520 19,520 19,520 19,520 29,260 29,260 29,260 29,260 29,260 29,260 29,260 29,260 0 0 0 0 LP SR Reformer 18,027 14,036 14,478 14,036 18,428 14,227 17,066 14,431 19,625 20,704 16,482 14,387 24,074 23,441 22,101 19,233 HF Alkylate 7,217 6,918 6,570 6,918 7,133 6,899 6,109 6,825 10,237 5,816 4,749 4,749 7,180 4,358 3,604 3,604 ULSD HDT 31,961 37,627 42,209 37,627 32,273 35,072 41,765 38,583 25,311 27,392 33,887 34,623 22,567 23,419 30,052 30,308

Key Product Qualities
Diesel Pour Pt. 8 0 10 0 4 0 10 0 -2 0 8 0 -8 -8 0 0 Diesel Cetane 49 48 50 48 47 46 49 46 53 53 53 52 47 47 49 49 Jet Pour Pt. -55 -55 -55 -55 -65 -55 -70 -70 -68 -64 -73 -72 -66 -68 -88 -88 Jet Flash Pt. 156 148 148 148 148 149 143 143 148 154 123 123 165 162 144 144

Swing Cuts Destinations: B/D Hvy SR Nap to Jet 945 4,397 4,397 4,397 0 0 0 0 0 0 0 0 0 0 0 0 AGO to Diesel 1 1 3,484 1 1 1 4,956 1 1 1 4,956 2,520 1 1 5,183 5,183 Heavy Cat Nap to LCO 1 3,354 2,856 3,354 1 1 2,494 2,882 1 1 1 1 1 1 1,630 1,630

FCC LCO Production: MB/D 7,469 9,497 9,081 9,497 7,068 7,068 7,693 9,786 4,180 3,871 3,531 3,531 4,014 4,623 4,769 4,769 Light Sweet Crude (FCC) P20

Base Case Light Sweet Crude (FCC) M20 Hvy Crude (FCC+LgCoker+ HydroCrkr) P20 Hvy Crude (FCC+LgCoker+ HydroCrkr) M20 Hvy Crude (FCC+LgCoker) M20 Hvy Crude (FCC+LgCoker) P20 Med-Hvy Crude (FCC+Coker) P20 Med-Hvy Crude (FCC+Coker) M20

Note: P20 case represents gas oline 20 cents per gallon higher than distillate. M20 represents distillate 20 cents per gallon higher than gasoline. Model results from Jacobs Consultancy analysis performed for Department of Energy Table B

- 1. Illustrative Model Runs Used For Figur e 830 Summer Winter Summer Winter Summer Winter Summer Winter Summer Winter Summer Winter Summer Winter Summer Winter

Crude Input: B/D
WTI 0 0 0 0 30,000 30,000 30,000 30,000 0 0 0 0 30,000 30,000 30,000 30,000 Bonny Lt 20,000 20,000 20,000 20,000 0 0 0 0 20,000 20,000 20,000 20,000 0 0 0 0 Cabinda 40,000 40,000 40,000 40,000 0 0 0 0 40,000 40,000 40,000 40,000 0 0 0 0 Mars 0 0 0 0 70,000 70,000 70,000 70,000 0 0 0 0 0 0 0 0 WTS 0 0 0 0 0 0 0 0 0 0 0 0 35,000 35,000 35,000 35,000 Bow River 0 0 0 0 0 0 0 0 0 0 0 0 35,000 35,000 35,000 35,000 Saudi Medium 40,000 40,000 40,000 40,000 0 0 0 0 40,000 40,000 40,000 40,000 0 0 0 0

Other Feed Inputs: B/D Purch Gas (FOE) 3,292 3,468 3,516 3,468 3,356 3,187 3,276 3,515 3,292 3,491 3,534 3,629 3,555 3,207 3,221 3,531 Normal Butane 0 2,609 0 2,609 0 4,042 0 2,038 0 3,548 0 2,578 1,401 7,595 109 5,275 Iso Butane 2,082 2,013 1,918 2,013 4,302 1,473 1,208 1,279 2,082 2,030 1,857 2,109 5,222 2,074 1,805 1,990 Ethanol - Blending 3,640 3,473 2,989 3,473 4,116 4,239 3,067 3,379 3,640 3,749 2,923 3,420 5,052 5,418 3,719 4,513

Products: B/D Total LPG 6,536 5,226 6,580 5,226 4,447 5,107 6,879 4,475 6,536 5,198 6,416 5,319 2,389 4,778 4,300 4,490 Total Mogas 57,660 55,005 47,347 55,005 65,190 67,145 48,585 53,520 57,659 59,389 46,293 54,175 68,517 70,572 50,436 58,790 Total Jet 4,180 4,000 4,000 4,000 5,943 5,943 6,087 6,087 4,181 100 100 143 4,000 4,000 5,705 5,813 Total Diesel (ULSD) 31,837 37,484 42,051 37,484 25,285 25,285 37,317 37,317 31,836 38,823 47,124 43,504 27,250 27,635 37,669 35,344 Total RFO, Slurry, Lubes 3,812 5,130 3,602 5,130 4,294 4,294 3,710 3,710 3,812 4,412 3,492 3,782 5,041 4,965 4,515 4,662

Total Distillate (Jet+ULSD) 36,016 41,484 46,051 41,484 31,229 31,229 43,405 43,405 36,018 38,923 47,224 43,647 31,250 31,635 43,374 41,157 Total MJD 93,677 96,489 93,399 96,490 96,418 98,374 91,990 96,926 93,677 98,312 93,518 97,824 99,767 102,208 93,811 99,948 Distillate Yield: % 36.0 41.5 46.1 41.5 31.2 31.2 43.4 43.4 36.0 38.9 47.2 43.6 31.3 31.6 43.4 41.2

Unit Inputs: B/D Crude Tower 100,000 100,000 100,000 100,000 100,000 100,000 100,000 100,000 100,000 100,000 100,000 100,000 100,000 100,000 100,000 100,000 Vacuum Tower 43,344 43,344 43,344 43,344 41,340 41,340 41,340 41,340 43,344 43,344 43,344 43,344 40,738 40,738 40,738 40,738 FCC 37,097 37,097 32,664 37,097 33,844 33,844 27,860 27,860 37,097 37,097 30,954 36,632 33,832 33,832 27,674 31,304 Hydrocracker 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Delayed Coker 19,520 19,520 19,520 19,520 19,670 19,670 19,670 19,670 19,520 19,520 19,520 19,520 18,251 18,251 18,251 18,251 LP SR Reformer 18,027 14,036 14,478 14,036 21,139 21,139 17,978 16,129 18,026 13,841 14,533 14,103 20,981 20,679 15,919 15,881 HF Alkylate 7,217 6,918 6,570 6,918 10,562 6,667 5,789 5,789 7,217 6,918 6,318 7,148 10,739 6,449 5,566 6,093 ULSD HDT 31,961 37,627 42,209 37,627 25,399 25,399 37,477 37,477 31,960 38,926 47,275 43,662 27,355 27,741 37,798 35,483

Key Product Qualities
Diesel Pour Pt. 8 0 10 0 -5 -5 0 0 8 0 10 0 0 0 5 0 Diesel Cetane 49 48 50 48 46 46 48 48 49 48 50 47 45 45 47 46 Jet Pour Pt. -55 -55 -55 -55 -55 -55 -80 -80 -55 -55 -55 -55 -55 -55 -79 -79 Jet Flash Pt. 156 148 148 148 166 166 143 143 156 148 148 148 165 167 143 143

Swing Cuts Destinations: B/D Hvy SR Nap to Jet 945 4,397 4,397 4,397 4,397 884 1,087 4,397 4,757 1,241 1,836 4,922 0 0 0 0 AGO to Diesel 1 1 3,484 1 1 1 5,035 5,035 1 1 5,194 466 1 1 5,364 1,734 Heavy Cat Nap to LCO 1 3,354 2,856 3,354 1 1 2,476 2,476 1 1 2,726 3,153 1 1 2,406 2,682

FCC LCO Production: MB/D 7,469 9,497 9,081 9,497 6,724 6,724 7,526 7,526 7,469 6,309 8,467 10,490 7,132 7,132 7,774 9,088 USGC Med-Hvy Crude

(FCC+Coker) P20

Base Case USGC Med-Hvy Crude

(FCC+Coker) M20 PADD2 Med-Hvy (FCC+Coker) P20 PADD 2 Med-Hvy (FCC+Coker) M20 USGC Med-Hvy MARS/WTI Mix (FCC+Coker) P20 USGC Med-Hvy MARS/WTI Mix (FCC+Coker) M20 USGC Med-Hvy Crude (FC C+Coker) P20 No Jet Min USGC Med-Hvy Crude (FCC+Coker) M20 No Jet Min

Note: P20 case represents gasoline 20 cents per gallon higher than distillate. M20 represents distillate 20 cents per gallon higher than gasoline. Model results from Jacobs Consultancy analysis performed for Department of Energy Table B

- 2. Illustrative Model Runs Used for Figure 9