# Presentation: 102184

## Refinery Investments and Future Market Incentives

**Refinery Investments and Future Market Incentives**

**Joanne Shore**
**John Hackworth**
**U.S. Energy Information Administration**
**September 29, 2008**
**Platts 2****nd**** Annual European Refining Markets Conference**

**Notes:**
In 1998

## Overview: Factors Affecting Investment Decisions

**Demand: Growth and Mix Shift **
**Feedstocks: Incentives to use lower quality feedstocks (Light-heavy differentials)**
**Margins**

- Demand

- Feedstocks

- Margins

**Notes:**
This presentation is divided into three major sections that represent three important dimensions affecting profitability and thus investment decisions.

The first is demand – what will refiners need to supply?  There is no simple answer to this question.  We are seeing and projecting not only variations in growth, but also some significant changes in product mix requirements. 
How much capacity expansion is needed?
Will product mix shifts leave some refiners with lagging profitability?

The second area of concern for investment and profitability is feedstocks.  The increased light-heavy crude price differential has increased the attractiveness of conversion capacity to take advantage of those lower-priced, low quality crude oils. 
What is driving those light-heavy differentials?
Will they stay elevated?
Will the increases in bottoms conversion capacity undermine the light-heavy differential?

The last section will touch on margins using several margin indicators to show how different regions are affected.  

## Future Demand Growth and Product Mix Shifts

**Growth: Mainly outside the Atlantic Basin**
**Product Mix Shifts & Investment:**
**U.S. – Different future**
**Europe – Continued shift in from gasoline to distillate**
**Asia – Less issue of shift than of growth**

- Demand

**Notes:**
This first section is a quick overview of the world demand situation, followed by a more in-depth look at the Atlantic Basin – the U.S. and Europe in particular.

## World Consumption Growing: Largest Growth Outside U.S. & Europe

***U.S. & Europe ***

***Rest of World Excl FSU***

**Source: BP World Statistical Review of World Energy  June 2008**

**Notes:**
After the 1979-80 crude oil price increase, the world saw a significant demand decline.  But this decline was mainly residual fuel oil demand (fuel oil on the chart) which went from over 14 million barrels per day to 10, which is about where we are today.  Fuel oil’s decline represented 60% of the world’s petroleum decline from 1979 to 1983.  That won’t happen today.  

With the lighter products, U.S. CAFÉ standards were taking effect in 1979-80, which gave rise to substantial efficiency improvements in light-duty vehicles, and was a major factor behind a decline in gasoline demand.  Today, however, the “easy” efficiency improvements seen in the early 1980’s are gone.  Efficiency improvements are still possible, but we are likely to see less impact in the short run than we saw in the early 1980’s.  European demand has been flat for some time, and U.S. demand is now falling.  

But the rest of the world continues to grow.  Today, the large Asian economies of China and India are accounting for much of the growth.  They are being driven by economic development.  Even with more efficient cars and trucks than in the U.S. fleet, Asian demand will grow as it is simply adding cars and trucks.   Barring a recession, that growth may be hard to stem.  

Not only is overall demand growing – mainly outside the OECD areas, but the product mix is also shifting, as displayed in the next slide.

## Europe Major Driver of World Consumption  Mix Shift Towards Distillates

**Source: BP World Statistical Review of World Energy  June 2008**

**Notes:**
Europe’s concerns over greenhouse gas emissions have resulted in policies to reduce energy consumption by shifting from less efficient gasoline-fueled vehicles to more efficient diesel-fueled vehicles.  This has resulted in diesel demand increasing and gasoline demand falling.  

Although European penetration of new light-duty diesel vehicles may be leveling off, the fleet share of diesel vehicles is still well behind the new sales penetration rate, which implies the trends in demand will continue.  The diesel and gasoline demand trends have resulted in Europe needing increasing distillate imports and generating increasing volumes of gasoline for export. 

Some of the Asian decline seen in this chart may be more an increase in naphtha demand for petrochemical use than of gasoline growth relative to diesel.  But the shift towards more distillate from gasoline is still not the dramatic shift seen in Europe

 The U.S. also has distillate growing more rapidly than gasoline, but the degree of change is much smaller than that seen in Europe.  However, future shifts in U.S. petroleum product mix are expected to be more dramatic than seen historically, as will be discussed shortly. 

## Atlantic Basin Price Incentives Shifting Toward Distillates

**Source: Bloomberg New York Harbor Conventional Gasoline, No. 2 Heating Oil; NW Europe 0.2% Heating Oil and Premium Gasoline **

**Notes:**
Prices are reflecting the product shifts.  This chart shows monthly spot price differences between heating oil and gasoline.  Diesel and heating oil prices move together, so the trends here reflect relative diesel price behavior as well.   

Historically, heating oil and diesel prices remained below gasoline except during some of the cold winter months.  But starting in 2005, we began to see a different pattern emerging – both in the U.S. and in other places in the world like Europe.

In 2005 we saw diesel prices stay above gasoline for the first time during the summer months, and only reversed when Hurricanes Katrina and Rita interrupted supplies.   Still, in 2005 and 2006, it is hard to separate how much of that diesel premium was due to the changes to low sulfur and ultra-low sulfur fuels in Europe and the United States versus the increasing distillate demand relative to gasoline.

The story is still unfolding, but this year provides a dramatic chapter.  Strong international demand for diesel brought about by economic growth in emerging countries along with some unusual circumstances has created a very tight market.  A number of regions are experiencing unusual diesel demand for electricity generation, such as  in Latin America (Chile especially), where droughts diminished hydropower, and natural gas supply  fell .  China has also been importing extra diesel, in part to provide adequate supplies for the Olympics.  And Europe has needed extra ULSD imports this year as well.  The U.S. has had record diesel exports, and yet we are not experiencing any local shortages apart from hurricane related issues.   

Demand for distillates will continue to grow and may push diesel prices above gasoline more often in the future than we have seen historically.

## U.S. – Steps to Increased Distillate 

**Operating changes – Beginning to see U.S. system potential to shift from gasoline to distillate**
**Planned hydrocracking investments (Marathon Garyville, Motiva Port Arthur, Valero)**

**Notes:**
Turning to the U.S., we are seeing refining changes that reflect the need for more distillate relative to gasoline in the future.  

With improved distillate margins in the United States relative to gasoline, we are seeing both near term operating changes and longer term planned investments to increase distillate production.  

The very high distillate margins in 2008 resulted in some significant shifts in yield from gasoline to distillate.

Longer term, several refiners are investing in major hydrocracking expansions as the major conversion unit, rather than the traditional FCC unit, with the intent to increase the production of distillate.  

## U.S.: Distillate Focus This Summer Illustrated Operating Yield Shift Potential

**Source: EIA Form 810**

**Notes:**
The United States refineries have in the past been run to produce gasoline, based on the large U.S. demand for gasoline compared to distillates.  Basically, second quarter margins, which reflect gasoline profitability, used to be a pretty good indicator of whether or not a refiner would have a good or bad year financially.    

This summer was a different story.  Gasoline margins were sometimes negative, but distillate margins were very high.  Once it became evident that this high-margin distillate picture was going to last some time, refiners began focusing on shifting to higher distillate yields at the expense of gasoline, which had surplus supply (as evidenced by some very high inventories).

This chart shows the yield shift for individual refineries in PADDs 2 and 3 (Midwest and Gulf Coast) for April and May versus the yields for the same months a year ago.  PADDs 2 and 3 represent 68% of U.S. refining capacity – 84% when the West Coast (PADD 5) is excluded.  The table only shows refineries that did not have any major unit outages during those times.

Note first, that 70% (22 of the 30 data points) of the refineries running normally during these months are in the upper left-hand quadrant.  The average increase in distillate yield for PADD2 and PADD 3 was 2.8%, year over year, but the variation was large.  Each refinery’s situation is different, but this illustrates the additional opportunity for added yield shifts in the U.S. if the margins for distillate remain more attractive than gasoline.  Some of the shifts depend on improvements to distillation tower efficiencies, which can only be made during a major turnaround.  

## U.S. Petroleum-Based* Gasoline and Distillate Fuel Needs Shift

| Million Barrels Per Day | 2007 | 2022 | Growth to 2022 |
| --- | --- | --- | --- |
| Petroleum Gasoline | 8.85 | 8.24 | -0.61 |
| Petroleum Distillate | 4.22 | 4.71   | +0.49 |

*** ****Petroleum-Based excludes ethanol, biodiesel, and distillate from coal-to-liquids and biomass-to-liquids. Source: AEO 2008 Reference Case**

**Notes:**
Looking ahead, the longer-term picture seems to justify refiners taking steps to increase distillate production versus gasoline.  The level of facility investment that will achieve a favorable return is less clear.   

In the next 15 years, we see a significant shift in demand for petroleum-based gasoline versus distillate that is the result of recent U.S. legislation: The Energy Policy Act of 2005, which included a mandated use of renewable fuels – which means ethanol in the U.S., and the Energy Independence and Security Act of 2007, which increased the renewable fuel mandate and increased light duty vehicle efficiency standards

While still not the shift that Europe has seen, U.S. refiners will be facing a significant change in product mix from the refinery that will impact investments.  
Overall petroleum demand is not expected to grow much over the next 30 years – perhaps less than 0.5% per year (annual average).
But distillate demand may still grow fairly strongly, while gasoline demand declines. 

The increased use of biofuels and light-duty vehicle efficiency standards over those in place in 2007 result in a decline in petroleum-based gasoline of about 610 thousand barrels per day (7%).

Petroleum-based distillate, on the other hand, continues to grow (690 thousand barrels per day or 12%).  Increased use of biodiesel is decreasing the need for petroleum-based distillate by about 60 thousand barrels per day.  In addition, distillate from coal-to-liquids (CTL) and biofuels-to-liquids (BTL) processing is decreasing the petroleum distillate need by 210 thousand barrels per day.  If that distillate from CTL and BTL does not materialize, petroleum-based distillate requirements might increase 700 thousand barrels per day versus the 490 thousand barrels per day shown in the table.  

## Future U.S. Investment to Produce More Distillate

**Equipment changes: **
**Cut-point shifts**
**Distillation efficiency **
**Hydrotreating expansion**
**Catalyst changes – FCC catalysts to produce more light cycle oil**
**Planned hydrocracking investments coming on stream**
**May not need more to satisfy U.S. demand shift and increase some exports of distillate**

**Notes:**
As a result of this summer, we are getting a better idea of how refiners may invest in this world of increasing diesel need/profitability and declining gasoline need from crude oil.
High distillate margins in 2008 provided refiners with incentives to increase distillate production by:
Expanding the distillation cut point range to reduce distillate going into FCC feed and reduce distillate going into gasoline
Increasing hydrotreating inputs.  With more distillate material, some refiners ran into hydrotreating bottlenecks.  They can change hydrotreating catalysts more frequently, and some even sent feedstock to other refineries that could handle the sulfur to maximize distillate production. Ultimately some hydrotreating capacity expansions may occur. 
Improving fractionation efficiency to keep distillate molecules out of FCC feeds and heavy gas oil out of the distillate cut.
Changing FCC catalyst formulations to improve distillate production
Increasing hydrocracking capacity in the future. 

Thus, U.S. refiners can increase distillate yield further than we saw this summer, and produce enough distillate to satisfy U.S. demand and increase exports before the planned hydrocracking investments add to distillation production capability.  

With the planned hydrocracking capacity, the U.S. refiners might not need to do much more to satisfy U.S. distillate needs and to increase exports of distillate.  (We are looking at this in more detail.)

## Increasing European Distillate Production

**Refineries are already operating at maximum distillate potential (unlike the U.S.)**
**Historical investments resulted in making more distillate by destroying residual fuel rather than reducing gasoline production.**

**Notes:**
Unlike the U.S., European refiners have already been operating at maximum distillate potential.

Historically, European refinery investments  in hydrocracking and coking have resulted in getting more distillate by investing in processes the destroy residual fuel oil, rather than by reducing gasoline production.

Up until the last few years, the higher price of gasoline relative to diesel encouraged such investment strategies.  

## OECD Europe: Imbalance Between Refining and Demand Met with Imports/Exports

**European Refinery Yields**

**Net Import/Export Balance**

|  | 1997 | 2007 |
| --- | --- | --- |
| Distil-late | 44.8% | 48.0% |
| Gaso-line | 26.6% | 25.7% |

**Source: IEA August 2008 Data Base**

**Notes:**
As mentioned earlier, European gasoline demand has been declining, while distillate demand has been increasing as light-duty diesel-fueled vehicles continue to penetrate this market.  In 1995, the consumption ratio for middle distillates to gasoline and naphtha was 1.4.  By 2007 it had risen to 2.2,  and it is expected to increase further in the next 5-10 years.  

As the table at the left shows, European refiners have increased distillate yield and decreased gasoline yield slightly. But these yield changes have fallen short of what has been needed to meet the changing demand mix.  The result has been a growing increase in distillate imports and gasoline exports.  

Distillate imports fell back in 2007, mainly as a result of a reduction in heating oil demand from milder weather, drawing down inventories, and less consumption for power generation.  Diesel demand continued to rise in 2007, and total demand is expected to rise in 2008, causing imports to renew their upward climb.

The U.S. has been a good market for Europe’s excess gasoline.  In fact those gasoline volumes available from Europe have kept U.S. refiners from having to expand capacity as much as they might otherwise have done.   European gasoline exports have increased by almost 600 thousand barrels per day from 1999 to 2007, and U.S. imports have increased about 570 thousand barrels per day over the same time period.  If the U.S. gasoline market turns less profitable, European refiners will feel the pinch as well as U.S. refiners. 

## Europe: What Next for Product Mix Investment?

**Seeing more distillate production investment in Southern Europe.  Hydrocracking expansions include:**
**Portugal ****	****  50 KB/D**
**Spain ****	****	****180 KB/D**
**Italy****	****	****  70 KB/D**
**Greece****	****	****  30 KB/D**
**Total ****	****	****330 KB/D**
**Biodiesel**

**Notes:**
European refiners seem to have made all of the operational changes they could to produce more distillate and less gasoline.   And as mentioned before, prior investments in hydrocracking and coking to produce less residual fuel oil and gasoline and more distillate,  have not kept up with the demand shift.  

In the near term, the focus of European investment to increase distillate has shifted to Southern Europe. There does not seem to be as much planned investment in Northern Europe, maybe some at the Wilhelmshaven refinery.  

There is also expected to be some contribution from biodiesel production, but that may not be very large in the next 5 years.  IEA is estimating an increase of about 50 KB/D in biodiesel production over this time.  (IEA’s 2008 production is shown as 226 KB/D; 2013 production is projected to be  279 KB/D as of the July forecast.) 

## Feedstocks: Investing to Take Advantage of Widening Light-Heavy Differentials

**Drivers behind the widening price difference**
**Supply of light crude**
**Product market influences on the price differentials**
**Conversion capacity impacts on differentials**

- Feedstocks

**Notes:**
Next we turn to the increasing light-heavy price differences, which is the incentive to invest in bottoms conversion capacity to use lower quality feedstocks.

This section will begin with an overview of the drivers behind the increasing light-heavy price difference, ending with a discussion of the influence conversion capacity expansion plans might have on that differential. 

## Supplies of Light Sweet Crude Increasing in Atlantic Basin

***Atlantic Basin Crude Production Projections***

**Note:  Most growth on this chart is in areas with higher quality crude oils.  Latin America includes Venezuela and Mexico with their heavy crude oils, but these areas  is not projected to grow much**
**Source: EIA International Energy Outlook 2008, Wood Mackenzie Presentation NPRA Annual Conference 2007**

**Notes:**
In the late 1970’s, U.S refiners realized that the US would become more reliant on imported crude oil and that light, low-sulfur crude oil reserves in the world export markets were a much smaller fraction of the total. 

U.S. refiners also recognized that light sweet crude oils were being produced at a much higher decline rate than the heavy, high-sulfur reserves. Many at the time believed that those light sweet crude reserves would not be replaced, and that diminished volumes of light sweet crude would be available on the international crude market 

Still, light sweet crude production has continued, representing about 1/3 of world production since the mid 1980s.  IEA projects minimal change in quality of crude produced through 2012. 

EIA and Wood Mackenzie are also showing more light sweet crude oil coming into the Atlantic Basin, which would result in overall quality improvements for that region.
While North Sea crude supply is declining, other sources of light crude oils are more than offsetting the decline.
Caspian increases are high quality crude oils.  FSU Urals crude are being replaced with lighter Caspian crudes.
We are expecting more West African crudes, which are also high quality.

## Light-Heavy Product Price Difference Increases with Crude Oil Price

**Source: Bloomberg spot prices (LLS – Louisiana Light Sweet; GC – Gulf Coast)**

**Notes:**
A primary driver of crude price differentials is the product market: Refiners evaluate crude oils by what they can earn from the products the different crude oils produce.  

This graph shows the relationship between crude oil price and prices of light and heavy products as represented by No.2 fuel oil and residual fuel oil on the U.S. Gulf Coast.  (While not shown here, the light-heavy product spreads in U.S. and Europe move similarly.) 

As has been the case historically, From early 2004 through 2008, residual fuel price increased less than crude oil.  At the same time, the high-valued products like distillate rose as fast or faster than, crude oil price.  As a result, the difference in price between distillate and residual fuel increased.
Residual fuel oil competes with other fuels such as coal and natural gas.  Thus, residual fuel oil price does not rise as quickly as crude oil price.  
However, gasoline and distillate prices rise as much as or more than crude oil prices, depending on the tightness of the market. 
The result is that the light-heavy product price difference moves with crude oil prices.

## Light-Heavy Product Price Differential & Crude Oil Price Move Together

**Source: Bloomberg spot prices (LLS – Louisiana LIght Sweet; GC – Gulf Coast)**

**Notes:**
This graph simply plots the product price difference explicitly against crude oil price to illustrate the correlation.

For many of the world refineries that produce 20%-30% residual fuel oil, that light-heavy product differential represents the fact that the value of the product barrel produced from a heavier crude oil rises less than the product barrel resulting from a light crude oil as crude price increases.  

Note the recent drop in the light-heavy product price difference.  That is due mainly to recent strength in residual fuel prices in the face of falling crude oil prices.  As crude oil prices were weakening in August, supply of residual fuel oil was being reduced with Iran and Saudi Arabia cutting down on exports in order to build supplies for their own demand just when Asian demand was increasing for electricity generation to meet air conditioning needs during a heat wave. 

## Light-Heavy Price DifferentialsMove Together

**Source: Bloomberg spot prices (LLS – Louisiana Light Sweet; GC – Gulf Coast)**

**Notes:**
The light-heavy crude oil price difference is shown on this graph along with the light-heavy product price difference.  Since the relative value of crude oil depends on the value of the barrel of products that are refined from the crude, it follows that the light-heavy crude oil price differential is related to the relative value of the product barrel that is made from the heavy crude versus the light crude barrel.  As shown on the prior slide, the short-term strength in residual fuel prices relative to falling crude price caused not only the light-heavy product price difference to fall, but also the light-heavy crude price difference.

While the crude oil price differential in this slide uses Maya crude oil, which is a far less attractive crude oil than LLS due to its low gravity and high bottoms content, the general relationship in this and the previous slides holds for other light-heavy crude oil spreads as well. 

The light-heavy crude oil price difference relates closely to the value of the product barrel for a refinery without bottoms conversion processing (e.g., coking) when running a heavy crude oil compared with the same refinery running a light crude oil.  

For the refiners with bottoms upgrading, the margins have become very attractive.  The current light-heavy crude differential provides a very strong incentive for added bottoms processing conversion capacity.  A key question is what might cause a major contraction in the differential?  Too much bottoms capacity investment?  An increase in light crude oil availability? A major decline in crude oil price?  Although more light sweet crudes will be available, particularly in the Atlantic Basin, world crude quality is not expected to shift much.  The impact of bottoms investment will be discussed next.

## Higher Light-Heavy Price Differences Go With Higher Price Levels – But Much “Scatter”

**Source: Bloomberg spot prices**

**Notes:**
Now I will explore future uncertainties around differentials and margins in more detail.  We know what incentives are today, but investments must earn a return for many years in the future.  If petroleum markets loosen, and crude oil prices fall back, what could happen to margins and price differentials?

This scatter plot illustrates the relatively strong relationship between crude oil prices and a light-heavy crude oil price difference.  If crude oil prices fall back to $50 per barrel, the light-heavy crude price differential will fall back.  But the scatter around the line indicates that the dynamics behind this relationship may keep the movements from being a simple relationship – even though we show a fitted line for discussion purposes.  In the short-run the scatter around the line represents various short-term market shifts, such as the latest August point that is below the line on the right side of the chart.

Over the longer term, the differential is affected by residual fuel price.  Both demand and supply of residual fuel oil are changing with changing prices, and demand and supply don’t necessarily move together.  
On the demand side, rising prices make residual fuel oil less attractive than alternatives, and demand for residual fuel falls.  Price for residual fuel then does not rise as much as for light products.  Thus, the value of heavier crude oil drops relative to light crude oils.
The increasing light-heavy crude oil and product price differences increase incentives to add bottoms upgrading capacity, such as coking units, and destroy residual fuel oil supply.  
This balance between heavy product supply and demand will vary, and if crude oil prices return to some lower price such as $50, the light-heavy differentials could be higher or  lower than occurred when prices were rising, depending on the strength of the demand or supply response to the price increase.    

## Refiners Continue to Process Crude without Increasing Fuel Oil Yields

**Source: IEA August 2008 Data Base**

**Notes:**
An indication that refiners are not running into any major constraints in processing available crude oils is that refinery yields are not increasing.

As indicated earlier, a refinery can run more heavy crude oils than its bottoms processing can handle.  It will then produce more residual fuel oil and have higher residual fuel yields.

## Future Coking Increases: Will Expansions Affect Light-Heavy Spread?

|  | 2008 |  |  | 2013 |  |  |
| --- | --- | --- | --- | --- | --- | --- |
|  | Distilla-tion Capacity | Coking Capacity | Coking Percent Distillation | Distilla-tion Capacity | Coking Capacity | Coking Percent Distillation |
| U.S. | 17,813 | 2,545 | 14.3% | 18,863 | 3,135 | 16.6% |
| Europe | 17,213 | 387 | 2.2% | 17,527 | 512 | 2.9% |
| Asia  | 26,512 | 1,259 | 4.7% | 29,704 | 1,781 | 6.0% |
| Rest of World | 29,579 | 1,108 | 3.7% | 31,938 | 1,584 | 5.0% |
| Total | 91,116 | 5,298 | 5.8% | 98,033 | 7,011 | 7.2% |

**Source: Purvin & Gertz, GPMO Service **

**Notes:**
Looking ahead to refiners’ plans to take advantage of the wider light-heavy price differentials, this table shows a projection for the increase in coking capacity from 2008 to 2013.  Coking is the primary choice of refiners for bottoms upgrading of heavy crude oils and for reducing residual fuel production.

The U.S., in 2008, has more than half of the world’s coking capacity, and produces much less residual fuel than other world areas.

From 2008 to 2013, world coking capacity increases by 1.7 million barrels per day and from almost 6% of distillation capacity to 7.2%.  But world residual fuel oil production will fall less than 5% from the current 11 million barrels per day.

Many refiners in the world will still be producing 15-20% residual fuel, and if crude prices remain high, residual fuel will be a significantly negative factor in the value of products from heavy crude oils, thereby continuing to depress heavy crude oil values.

Still, the significant size of the coking capacity additions will increase refiners ability to upgrade more of the world’s heavier crude and reduce pressure on the light sweet crude market.  This will act to diminish the light-heavy discounts somewhat.

Increasing demand in the Middle East and Asia for electricity generation would tend to shrink the light-heavy differences, but at the same time, environmental pressure on high sulfur residual fuel will reduce its attractiveness in the product market.  Not only will it continue to be less attractive to natural gas for power generation, upcoming changes in the bunker fuel market could reduce residual fuel demand substantially.  

## Margins – Short Golden Age

**Margin Indicators**
**U.S. vs Europe**
**Future Implications**

- Margins

**Notes:**
Having reviewed some important demand changes and refinery investment paths that are occurring, we come to the bottom line – perhaps the most important driver of future refinery investments.

In this section, two spreads are going to be explored that attempt to capture the trends and differences between U.S. and European refiners. 

After laying out the factors pushing and pulling on the major cracks spread and differentials affecting profitability, I will discuss where we see the net result heading. 

## Refining Output Variations Impact Profitability 

**Source: Purvin & Gertz, GPMO Service**

**Notes:**
For years, a 3-2-1 crack spread has been used in the U.S. as a simple indicator of refinery profitability.  It approximates a U.S. refinery by assuming 3 barrels of crude oil will produce 2 barrels of gasoline and 1 barrel of distillates (heating oil, diesel, jet).  

The 3-2-1 margin is clearly not a good indicator for either European or Asian refineries, where distillate output is larger than gasoline, and the contribution from residual fuel is too large to be ignored.  A 6-2-3-1 (6 barrels of crude, 2 of gasoline, 3 of distillates, 1 of residual fuel) is one simple way of approximating the European region to compare with the U.S.

The different shares and the relative margins for refining in these world areas could change in the future if gasoline margins shift relative to distillate margins. 

## U.S. Margin Indicator Higher Due to No Residual Fuel and More Gasoline

**Notes:**
This graph plots the 3-2-1 spread using New York spot product prices and WTI to approximate the U.S., and the 6-2-3-1 spread using Northwest Europe product spot prices and Brent crude oil to approximate Europe.

In the past, the strong U.S. gasoline market with its peaks in spring and summer, has been key to the higher margins for U.S. refiners.  That was especially true in the 2005-2007 period.  But this year, even in summer, distillate margins exceeded gasoline margins.  High prices and resulting lower demand combined with added ethanol use and increasing import availability to greatly weaken the gasoline margin picture.  Moreover, those factors could continue into the future.  While weak gasoline margins impact the U.S. total refinery margin, weak gasoline margins also affect European margins, albeit to a lesser degree.

Expansion of refining throughput capability, even that geared to higher distillate production, will also affect gasoline production capability and will negatively impact future refining margin prospects in a low demand growth environment.

With a potentially declining market for residual fuel, European investments to lower residual fuel production may not change the overall margin picture much in the longer term.  In fact those investments may be needed to keep the margins from deteriorating.

## Future Profitability

**Light-heavy price differentials**
**May decline some with growing conversion capacity and slightly lower crude oil prices**
**But likely to remain relatively high**
**Margins**
**U.S. gasoline margins under pressure from growing European exports, ethanol use, and improved vehicle efficiencies, but U.S. refinery margins likely to remain higher than in the 1990’s**
**Atlantic Basin distillate margins likely to be higher than gasoline more often in the future as regional distillate imbalance continues**
**European margins  buoyed by strength in distillate demand, but also depend on U.S. gasoline margins**

**Notes:**
Looking to the future, light-heavy price differentials may decline somewhat as crude prices fall back. Crude prices are still expected to remain relatively high for some time, which would tend to support wider differentials.

On the other hand, additional upgrading capacity would tend to contract light-heavy product differentials.  But even with fairly large expansion of bottoms upgrading, residual fuel production will not be much below current levels.  In the longer term, demand for residual fuel oil is also in question.  While areas like Asia and the Middle East may use more residual fuel oil for electricity generation, environmental legislation is putting stress on high sulfur residual markets.  The net impact will likely continue to support higher differentials for some time. 

Margins are more uncertain.  Margins have come off of the recent “golden years” levels.  In the U.S. we see gasoline margins under pressure, but with growing distillate demand and limited refinery expansion, margins may stay above those seen in the 1990s.

With Atlantic Basin distillate margins likely to remain relatively high, European margins may also see some strength.  However, European margins also depend on U.S. gasoline margins and the residual fuel market, which will tend to keep a damper on the refinery sector returns.  

## Summary

**Investment to produce more distillate**
**Future demand shifts imply attractive choice for some refiners to increase distillate yields**
**Bottoms upgrading investment **
**Light heavy differentials likely to stay elevated as crude price stays high **
**Amount of heavy upgrading may not impact light-heavy price differences greatly as total residual production not expected to change much and as residual fuel market demand is affected by environmental concerns.  **
**Margins – Short golden age, but still better than 1990s**
**Margin levels impact all types of refining investment, but especially  expansion  **
**Little need for expansion in Atlantic Basin – expansion could negatively impact margin**

**Notes:**
Investment incentives should continue to encourage some refiners to increase distillate yields.  The U.S. can still increase distillate yields with operating changes and smaller investments such as those to improve distillation tower efficiencies or expand hydrotreating capacilities.  Europe may be faced with a declining market for its gasoline and thus find further hydrocracking investments worthwhile.

Bottoms upgrading investment to take advantage of cheaper, heavier feedstocks will pay off if that price differential stays wide, and while the differential may very well contract in the next 5-10 years with declining crude oil prices, it will not collapse from expanding conversion capacity or residual fuel demand growth.   

The outlook for margins is not as attractive as refiners have seen over the past several years.  But as long as world demand – and especially demand in the high growth Asian areas – does not suffer a large setback, margins will not likely return to the very low levels seen through much of the 1990s.  In the Atlantic Basin, neither Europe nor the United States seems to need more expansion that that already underway.  Too much expansion would help to weaken margins. 

## Questions?

- _[www.eia.doe.gov](http://www.eia.doe.gov/)_
- _[joanne.shore@eia.doe.gov](mailto:joanne.shore@eia.doe.gov)_