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 the consumption growth for gasoline for some time, and the United States is 

no exception. Although the decrease in the ratio of total 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 decline in consumption

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

gasoline-to-middle distillate ratio from what has been seen historically. 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 necessitate investigating 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 discussions 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 distillates;

(2) Used a refinery model to explore the theoretical limits and constraints on the ability of 

refineries to increase 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) feeds and operations, hydrocrackers in 

maximum distillate mode (where applicable), and optimum hydrotreater operations and 

catalysts for maximum middle distillate production. Individual refinery equipment and 

configurations determine whether any or all of these strategies can be implemented 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 yields greater than 

10 percentage points and similar declines in gasoline yields are possible for some refinery 
2

configurations 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 runs 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 limit to potential increases in 

middle distillate yields 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 increased 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 barrels 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 the 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 yields 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 percentage 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 that has historically been the maximum gasoline 

season; so annual averages would be smaller.

The conclusion is that, in the short run, the refining industry could increase annual middle 

distillate yields by 3 to 5 percentage points on average over typical historical 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 more 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 points.

The potential increases in middle distillate yield and associated gasoline yields 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 in 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 hydrocracking 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 world consumption of 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. Although 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 petroleum-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 have given rise to a need to explore 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.

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 interest in this 

topic. Section 3 outlines the study approach, highlighting the three areas of analysis: industry 

discussions and literature review; refinery modeling; and review of EIA data on refinery 

operations. Sections 4, 5, and 6 review results from these three areas of analysis. 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 maximizing 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 shown 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 periods in 

some years, when heating oil demand put extra pressure on distillate prices. (Heating oil prices 

are used in the figure; diesel and heating oil prices generally move together.) From 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 United States. Before the recession in 2008, U.S. distillate consumption

growth since 1995 was slightly higher on average than gasoline consumption growth. 

However, the market change reflected in the prices of Figure 1 has 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, which 

represents about a quarter of the world’s middle distillate market. The change in the relative 

consumption of middle distillate versus gasoline has been much larger in Europe than in any 

other world region, as shown in Figure 2. The primary factor behind the change in Europe has 

been the switch by light-duty vehicle consumers from gasoline-powered vehicles to dieselpowered vehicles. The move has been driven by European tax incentives on both vehicles and 

fuel to encourage the use of more energy-efficient 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, gasoline exports from Europe have also grown as European refiners produce as 

much middle distillate as possible, and co-produce more gasoline than the region needs.

The principal export market for excess volumes of European refinery gasoline has been the 

U.S. East 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 combined 

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

90

Jan-95Jan-96Jan-97Jan-98Jan-99Jan-00Jan-01Jan-02Jan-03Jan-04Jan-05Jan-06Jan-07Jan-08Jan-09Jan-10

NY 

Harbor

Northwest 

Europe

Cents Per Gallon

Spot Heating Oil - Gasoline Price Differences

Source: Reuters monthly average 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 emerged 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 Latin America markets (especially Chile) 

used more U.S. distillate in 2008, when Latin American consumption increased as a result of a 

loss of hydropower from drought conditions and a natural gas shortage (Figure 3). Exports to 

Western Europe also increased in 2008, apparently to replace reduced volumes from Russia 

and Eastern Europe. Distillate 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

2.5

19891991199319951997199920012003200520072009

Europe

Asia

Rest of World 

Excluding FSU

United States

Middle Distillate/Gasoline & Naphtha Consumption Ratios

Source: BP Statistical Review of World Energy, June 2010.
6

Figure 3. Middle Distillate Exports from the United States 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 distillate yields bumped up noticeably in 2008.

The details of refiners’ changes will be described in sections 4, 5, and 6 below.

The trends of 2005-2008 were expected to continue, but the severe economic recession in late 

2008 impacted world markets. Recessions have greater impacts on distillate fuel consumption

than on gasoline consumption, because distillate is strongly tied to manufacturing, being the 

major fuel used to move goods.

The economic declines that occurred in 2008 had profound effects on consumption of gasoline 

and middle distillate products in the United States. 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 distillate consumption was down almost 14 

percent from 2007 to 2009, while gasoline fell about 3 percent during the same period. The 

impact on middle distillates was greater because consumption of diesel fuel (the largest 

fraction of middle distillate) derives mainly from movement of goods in heavy-duty vehicles, 

and production and sales of goods declined in the recession. Although growth has resumed, 

projected 2011 volumes are still lower 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

America

Thousand Barrels Per Day

Middle Distillate Exports from the U.S.

Source: Energy Information Administration, Petroleum Supply Monthly
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Figure 4. High Middle Distillate Yields in 2008 Returned to 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 consumption. That may still occur in the 

future, but middle distillate consumption must first recover 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 2007 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 shows a slow recovery for industrial and manufacturing activities, returning to 

their 2007 levels of shipment value in 2013.1 The 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 incentives.

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 from the middle distillate

market, refineries 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 diesel, heating oil, kerosene jet fuel and kerosene. Yield is 

middle distillate production divided by crude plus unfinished oil inputs to refineries.

Source: Energy Information Administration, Petroleum Supply Monthly.
8

Figure 5. Outlooks Change 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, and the availability of 

product imports. 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 growth in total gasoline demand from historical 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 economic 

opportunities for diesel exports, adding incentive to produce more middle distillate fuels and 

less gasoline, even with a slower economic outlook than previously expected.

The remainder of this report explores how U.S. refiners can shift product barrels 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 needs. 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 2025

Million 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 Information 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 

economically attractive.

3. Analysis Approach

EIA’s analysis of refiners’ ability to increase middle distillate yields 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 an FCC process consultant.

• The second prong of the analysis path used a refinery model to explore the limits and 

constraints on the ability of refineries to increase 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 gasoline 

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 for demand growth. As a result, 

refiners are finding ways to shift yield to more middle distillate. There are limitations on

increasing middle distillate yields, which vary by refinery, depending on crude oil feedstocks 

and refinery configuration. As a result, 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 involving small capital 

investments. Also, several recent major U.S. refinery expansions (planned and recently 

operating) have incorporated hydrocracking units rather than FCC units. In discussions 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 distillate 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. Refiners looking 

at this approach are faced with a number of potential constraints. If they produce more volume 
10

of middle distillate material, they must have enough desulfurization capacity to process the 

additional material. Increasing the cut-point ranges also changes the quality of the middle 

distillate products, 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 distillation 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 (Figure 6). The 

upper end of the boiling range is expanded 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 cut 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. The coker 

distillate cut-point range can also be expanded.

Most of our discussions with refiners indicated that the distillation unit’s end point for straightrun 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) fractionation can be an obstacle that limits a refiner’s ability to expand the 

boiling-range cut points as just described. Discussions of boiling-range cut points generally 

refer to true boiling point (TBP) distillation ranges2 where separations are precise; but in

practice, the quality of distillation in commercial refinery distillation units is usually sloppy. As 

an example, consider the separation of straight-run distillate and vacuum gas oil (VGO) or 

FCC charge stock. One article3 stated that “many FCC [feeds] contain 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 gas-oil molecules in the straight-run middle distillate blend 

stream, which increases the diesel end point, thereby increasing the difficulty of meeting diesel 

cold-flow property requirements.

Outside the United States, favorable taxes for diesel have provided an incentive 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 between 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, enabling added middle distillate recovery from the vacuum unit.

In order for some refiners to improve fractionation efficiency, unit revamps are needed. To 

invest in revamp projects, refiners must believe that higher middle distillate margins compared 

to gasoline 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 that situation changed, with 

middle distillate margins improving over gasoline margins. On the other hand, improving 

distillation efficiency is a low-cost path to producing more middle distillate fuels.

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. Distillate 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 product 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, however, 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 paper6 on strategies for maximizing FCC LCO 

described a diesel catalyst and the use of recycling a heavy oil fraction. Recycle 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 

recycling and a diesel catalyst with good bottoms cracking characteristics, slurry-oil volumes 

remained constant, and the LCO-to-gasoline yield ratio increased. A quick return to use of 

FCC-recycle operation in commercial facilities is not simple, however, and it is not likely 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 National Petrochemical 

and Refiners Association (NPRA) Annual Meeting, hydrocracking units (HCUs) 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 

maximum volume gasoline components.

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

cuts.

(3) Modify the vacuum gas-oil feeds to the HCU to include LCO and coker gas oils.

(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 

HCU. 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 increase 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 more 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 percent 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 

points in middle distillate yield for the United States on total crude oil inputs to refineries. The 

addition of a catalyst-change strategy can move the 60-percent HCU middle distillate yield to 

about 70 percent, raising 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 optimized, maximum-distillate 

HCU operation. This translates to a potential increase in middle distillate yield of about 2

percentage points for total U.S. crude oil inputs.

HCU and FCC changes would typically be considered together to increase middle distillate 

yields. The HCU produces 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 that is recovered in the refinery, the more 

volume must be processed to remove sulfur. Most refiners revamped or installed distillate 

hydrotreaters to produce ultra-low-sulfur diesel (ULSD). Many refiners now produce only 

ULSD, but it is unclear how many designed 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, but 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 improved, allowing for 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 hydrotreating may impose on increased 

distillate production.

4.5 Total Potential Distillate Yield Shift Based on Industry Discussions

The discussions with 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 of 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 catalysts 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 yield 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 should be able to increase the distillate yield (measured as a percent of crude input) by 

7 to 13 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. Illustrative Industry View of Potential Distillate Yield Increases

Source: Valero presentation, http://www.slideshare.net/finance2/valero-energy-basics-ofrefining-presentation-january-13-2009.

5. Model Analysis: Exploring Theoretical Distillate Yield Shifts

A generalized refinery modeling system was used to examine the theoretical extent to which 

middle distillate yields could be increased at U.S. refineries.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 Conversion 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 – Fluid 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 

Regions
15

fall within the range of facilities with 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 fractions from both 

primary distillation and downstream process unit fractionators (see 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, product 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 stayed 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 other gasoline grades and types (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 made 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 conversion 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 hydrotreater. 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, but for many others, the capacity of this unit limits 

distillate yield increases.

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

Notes: ADU = atmospheric distillation unit; FCC = fluid catalytic cracking unit. Results for 

these cases are provided in Appendix B.

Table 2. Refinery Modeling Crude and Product Prices (Cents Per Gallon)

Table 3. Refinery Modeling Details of Refinery Configurations
16

The contents 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 

Light

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 Refinery 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 include 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 is not the situation during the winter. In winter, those same crude mixes can interfere 

with meeting winter product specifications; although in some cases, the problems can be 

overcome by the processing capabilities of some units.

The first 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 season 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, 

the heavier cut goes to 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 lighterdistillate 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 essentially the same 

configuration as in the first case, but it uses a different 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 Labels Illustrating Naming Convention
17

increase in diesel yield is only 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 roughly 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 shows the importance of type of crude oil in meeting winter 

diesel specifications. With no additional refinery conversion units to help meet winter 

specifications, winter cold flow property constraints were avoided because of the hydrocarbon 

composition of the straight-run distillation cuts of the crude oil used. In contrast, the Hvy 

Crude (FCC + Lg Coker + HydroCkr) 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. Some 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 could be increased. Figure 9 shows variations for a basic FCC + Coker 

refinery configuration. The cases vary the content of the medium-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 Change

Base Case

Source: Model results from Jacobs Consultancy analysis performed for Department of 

Energy.
18

Figure 9. FCC + Coker Configuration: Middle 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) Base 

Case shown in Figure 8. The next case used this same refinery, but exchanged the base 

medium heavy crude oil blend with a blend of Mars and WTI crude oils of comparable gravity.

With the Mars-WTI blend, the FCC plus coker refinery increased distillate yield by 12 percent 

in both summer and winter seasons when distillate prices were higher, highlighting again the 

importance of the characteristics of the crude oil refinery runs.

The third case from the left in Figure 9 shows how producing jet fuel adds to the difficulty of 

increasing total distillate yield with the base 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 that 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 the zero increase 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 Change

Base Case

Note: USGC – U.S. Gulf Coast.

Source: Model results from Jacobs Consultancy analysis performed for the U.S. Department 

of Energy.
19

In this example, distillate yields increased by 12 percentage points in summer and 10 

percentage points in the winter season.

Model runs 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 upper 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 efficient cut separation needed to produce the yield 

swings seen in the model runs. However, if distillate prices were to sustain a premium over

gasoline, more refineries would make the modest investment to improve fractionation, which 

would allow them to move to the high distillate yield levels achieved by some refineries 

already, as discussed in the next section.

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 distillate yield changes varied across the range of refineries, based on the types 

and complexities of refineries, the crude feed quality, the regional location, and the historical

gasoline/distillate production ratio.

Individual refinery input and output data for summer (May-August) 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 and 2008. Input and output data for summer 2006 were 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 smallest to largest distillate yield change for 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 percentage points, and yield increases at about 33 percent of the refineries were in the range 

of 4 to 6-percentage points. The wide distribution suggests that it could be difficult to identify 

unique factors distinguishing those refiners making 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 strikingly 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 shifts were for the 

subset of refineries on the Gulf Coast, which showed an average increase in distillate yield of 

5.0 percentage points 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 expected 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 position 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 Number

Yield 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

Individual refinery 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 

relationship 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 is 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 gasoline 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, 

Hydrocracker 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 2008 (Percentage 

Points)

 FCC Input -0.9 -0.2 -3.3 -0.3

 Gasoline Yield -2.0 -3.5 -4.6 -3.2

 Middle Distillate Yield 3.1 4.6 5.2 4.7

Notes: KB/D = thousand 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, based 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 increases 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 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 points.

These estimates for potential industry yield changes in middle distillate fuel and gasoline 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. Diesel margins in 2008 were much higher than 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 +

Coker

Middle Distillate Yield Change

(Percentage Points)

Source: EIA 810 “Monthly Refinery Report” survey.
23

growth in consumption of middle distillate from petroleum was forecast to be stronger than 

consumption of gasoline. Legislation mandating higher light-duty vehicle efficiency and 

increasing use of renewable fuels combined with growing 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 forecasts have changed dramatically in the past two

years because of the recession.

Two editions of EIA’s Annual Energy Outlook (AEO) provide a means to explore several 

consumption scenarios. The gasoline and middle distillate consumption projections from the 

2008 and 2010 AEOs reflect a sharply 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 were reduced by the corresponding AEO projections for ethanol 

and other biofuel supplies and by two illustrative projections for gasoline net imports and 

middle distillate net exports, as shown in Table 7.

The High and Low Distillate Consumption Cases in Table 7 have the same imports and 

exports. Yield 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 greater 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 credible 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 refinery 

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 distillate 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 2008 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 Supply 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 projections. 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 refinery middle distillate yields are likely to be an attractive option again for 

refiners 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 yield shift toward middle 

distillates and away from gasoline as the diesel market rebounds from the recession.

Table 7. Consumption Scenarios Illustrating Different Potential Refinery Yields 

for Gasoline and Distillate
25

APPENDIX A: Refining Primer

Refining crude oil into petroleum products begins with crude oil entering a large distillation 

tower, where it is distilled 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 height 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 of 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 molecules 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 

Processing

Distillation Unit

Light 

Ends, Low 

Boiling 

Point

Bottoms, 

High 

Boiling 

Point
26

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 molecules 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 refineries 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, lowquality heavy distillates from the distillation tower, the FCC, and the coking units into highquality, 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 octane 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. Distillation Tower

Reformer

Hydrotreating

Fluid

Catalytic

Cracking

Alkylation

Hydrotreating

Coker

Product 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 

Ends Vacuum Unit

Hydrotreating

Pretreating

Hydrocracker Hydrocrackate Gasoline

Diesel/Heating Oil/Jet
27

The FCC is another major gasoline-producing unit. It takes heavy gas oil and cracks the heavy 

molecules into smaller molecules that are used 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 towers in the 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 gasoline 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 coking 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 the 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 have 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 towers; 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 produces.
28

APPENDIX B. Refinery Run Detail

The following 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 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-1. Illustrative Model Runs Used For Figure 8
30

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