# Presentation: 138316

## Ethanol, Gasoline, and ULSD Supply Issues in 2006

**State Heating Oil and Propane Conference**
**August 2006**
**John Hackworth**
**Joanne Shore**
**Energy Information Administration**

## Overview

**MTBE to Ethanol Shift**
**Challenges**
**Progress to date**
**Gasoline Supply Issues**
**Refinery limitations**
**MTBE to ethanol issues**
**Import changes**
**ULSD Supply**
**Implementation so far**
**Areas to watch**

**Notes:**
This discussion will focus in on the supply issues in three areas:
The shift from MTBE blended RFG to ethanol blended RFG;
Gasoline supply looking at refinery limitations, MTBE to ethanol, and the important role of imports; and 
Progress in the move to ULSD.

## MTBE Elimination: Northeast & Texas

**Region served mainly by pipeline**

**Notes:**
MTBE was mostly used in reformulated gasoline (RFG) for emission and driving performance.   Initially, all RFG except that used in Chicago Milwaukee, used MTBE.  Chicago Milwaukee RFG was blended with ethanol.

Beginning in 2003, State MTBE bans in California, New York and Connecticut resulted in reformulated gasoline (RFG) suppliers in those areas shifting from MTBE to ethanol. That left the remainder of the East Coast reformulated gasoline regions (shown in the chart) and the reformulated gasoline area around Dallas/Fort Worth Texas using MTBE.  

In spring 2006, MTBE was eliminated from RFG and replaced with ethanol on the U.S. East Coast and in Texas.

There were three distinct areas from the standpoint of gasoline and ethanol delivery systems.

In the area north of the Mason-Dixon line, New York and Connecticut had already converted to ethanol use in RFG, so the industry had some experience getting ethanol to this region and blending it into gasoline.  But New York and Connecticut represent less than 40% of the RFG demand for the area north of the Mason Dixon line.  Hence, a significant transition had to occur.  Moreover, gasoline and gasoline blending component imports represent a significant part of supply for the region.   

For Maryland, Delaware, D.C., and Virginia, most RFG is supplied by refineries on the Gulf Coast.  No ethanol supply or blending infrastructure existed prior to this spring.

In the Houston and Dallas/Ft Worth areas of Texas using RFG, there was no concern over RBOB availability, but ethanol delivery capability was an issue.

## Eliminating MTBE and Replacing with Ethanol

**MTBE mainly used in RFG (11.4% volume per gallon)**
**Both MTBE and ethanol have good octane and are clean**
**Issue is ethanol relative to MTBE.  Ethanol has:**
**Higher blending RVP (VOCs problem)**
**Higher toxics (MSAT issue)**
**Higher affinity for water, which means shipping separately from petroleum and blending at terminals**

**Notes:**
While both MTBE and ethanol have high octane and are relatively clean-burning, there are some important differences.

The operational challenge is perhaps the most prominent issue.  Because of ethanol’s affinity for water, it cannot be blended with other petroleum components at the refinery, but must be shipped separately to final blending terminal locations for addition to the petroleum RBOB coming from refineries or import sources.

Ethanol also differs from MTBE in terms of physical and chemical properties.  Ethanol has a higher blending vapor pressure, i.e., it evaporates more readily, and when burned, produces more toxic emissions than MTBE.

## VOCs: Summer Gasoline Capability Loss When Switching  from MTBE to Ethanol

**RFG Outside of CA – net 5-6% loss**
**Lose 11% MTBE**
**Gain 10% ethanol**
**Lose 5% light ends to compensate for ethanol’s increased RVP**
**CARB RFG – net 10% loss**
**Lose 11% MTBE**
**Gain 6% ethanol**
**Lose 5% light ends to compensate for ethanol’s increase RVP**
**May also need small additional volume to compensate for lower energy of ethanol vs. MTBE**
**Longer term, refiners will make changes to compensate**

**Notes:**
The physical and chemical properties of ethanol impact refiners’ gasoline production capability.

Ethanol increases the rate of evaporation of gasoline, which, during the summer months, must be controlled.  In order to counter this characteristic, refiners must remove petroleum components that tend to evaporate.  Outside of California, refiners would experience a net RFG production loss of about 5-6% during the summer.

A subset of refiners are also affected by the Mobile Source Air Toxics Rule (MSAT), which limits the toxic emissions of gasoline to what a refinery was producing in a base year.  Some refineries producing a large percentage of RFG and using MTBE had very clean baselines.  Ethanol increases gasoline toxic emissions over MTBE, and the very clean refineries were unable to produce as much RFG using ethanol in order to keep their emissions under their base year.

The energy content of MTBE is only 81% of gasoline, and ethanol is even less at 66%.  As a result, replacing MTBE with ethanol also has a small impact on vehicle miles per gallon.  

## MTBE Bans Increased Ethanol Use

**CA, NY/CT**

**Notes:**
Since 2003, the use of ethanol in gasoline has risen steadily, while MTBE’s use has declined.  The current production is being exported or put into gasoline for export.  

As indicated earlier, the rapid increase in ethanol use beginning in 2003 was due to California, New York and Connecticut banning MTBE.  California’s official ban was delayed until 2004, but about half of the industry began in 2003, when the ban was originally scheduled to begin.  New York’s and Connecticut’s MTBE bans began in 2004.

Now in 2006, suppliers moved to eliminate using the remaining MTBE due to concerns over the perceived potential for increased liability exposure when the oxygen requirement was removed as a part of EPAct 2005.  

Based on weekly production of ether blended RFG production, use of MTBE in May averaged less than 6 thousand barrels per day, while ethanol was about 370 thousand barrels per day.

## Use of Ethanol-Blended Gasoline Increased in May as Industry Eliminated MTBE

**Notes:**
This slide shows the shift to ethanol-blended RFG in 2006. 

The transition took place during the winter-to-summer gasoline transition, when tanks have to be turned anyway.

## RFG Gasoline in 2006

**MTBE being eliminated and replaced with ethanol**
**About 130 KB/D of additional ethanol needed to replace MTBE**
**Added ethanol not all available from domestic production**
**Move ethanol from E10 sold in conventional gasoline markets and use in RFG**
**More ethanol imports?**
**May reduce RFG ethanol blend from 10% to 5.7% for a time**
**Ethanol distribution & terminal preparation challenges**
**Shift in RBOB supply to East Coast (Less East Coast production, more from Gulf Coast and imports)**
**RFG v. conventional gasoline differentials could be high – possible price surges**

**Notes:**
Summarizing the shift, we estimated that an additional 130 KB/D of ethanol would be needed to replace the MTBE being used in RFG.

Domestic production of ethanol was inadequate to meet this additional volume, so several supply responses have occurred:
Discretionary blending of ethanol in conventional gasoline was reduced; allowing that ethanol to move to the RFG areas now needing the ethanol
Ethanol imports increased;
While RFG could be blended with less than 10% ethanol, that did not seem to be needed.  That shift requires a separate RBOB from the 10% RBOB and, as a result, is not always an option for individual suppliers due to limitations in the distribution system.

Delivery and storage had to be set up for ethanol.  Blending facilities had to be added at terminals, and retail outlets had to be prepared.  Many retail dealers require equipment changes as well as tank cleaning/turnover activities to prepare for using ethanol blends.

We also expected more RBOB to move from the Gulf Coast to the Northeast to make up for potential losses of East Coast production and imports.  However, as we will show in a minute, imports have remained strong.

Finally, because RBOB supplies were expected to tighten, RBOB prices versus conventional gasoline were expected to increase, which they have done.  

## “Room” for 400 KB/D of Ethanol

| BALANCE | KB/D |
| --- | --- |
| 2005 Ethanol Use | 263 |
| Extra Demand in 2006 (East Coast, Texas) | 130 |
| Potential Ethanol Demand | ~400 |
| Ethanol Production & Imports March 2006 | 332 |
| Balance? “Discretionary Shift”, production, or imports | ~60 |

**Notes:**
This table summarizes the ethanol balance.

EIA estimated that, once the switch was made from MTBE to ethanol in May 2006, the extra ethanol demand could be 130 KB/D for RFG production to supply the East Coast and Texas.

The U.S. averaged 263 KB/D of ethanol use in 2005, and if that 130 KB/D was all incremental demand, we would expect ethanol demand to push towards 400 KB/D.  On the other hand, we could also see some shift away from the volumes used to make conventional ethanol-blended gasoline in 2005.

In March, production and imports were about 332 KB/D, and in April and May they were a little less (319 and 315 KB/D respectively).  As we move through the remainder of the summer, the balance will be made from increasing ethanol production, increasing imports, and/or shifts from discretionary conventional gasoline blending.    

## Ethanol Production Increasing

**Notes:**
So how is production coming along?

Ethanol has been increasing rapidly in the last year.  During May and June, 5 new ethanol plants came on line, adding nearly 20 thousand barrels per day of additional capacity.

Based on plant construction plans, the U.S. could reach over 360 thousand barrels per day of ethanol production by the end of 2006.  

## Historical Ethanol Imports

**Notes:**
As expected, ethanol imports have also been strong this year.  It is still difficult to gauge what imports levels may be as gasoline demand is peaking.

Brazil is the primary source of imports.  We are receiving volumes directly from Brazil, which are subject to the full import tariff, and we are receiving volumes indirectly through the Caribbean Basin Initiative countries – Costa Rica, El Salvador, Jamaica. Trinidad/Tobago.  These countries are not subject to the ethanol import tariff.  Most of the ethanol they send to the United States was produced elsewhere.  These countries then remove water and/or denature the material to prepare it for fuel use in the U.S.  Brazil is a major source of their ethanol supply.

Unlike U.S. corn-based ethanol that is produced year round from corn that is harvested or stored, Brazil’s production uses sugar cane as the feedstock.  This product is not stored, and as result, Brazil’s ethanol production is highly seasonal.  The lowest production is in January through April, and production peaks in the August through October period.  Brazil\’s peak ethanol production can be six times what it was in the January through April period.

Data is not yet available on monthly import volumes for the summer months.  Anecdotal information speaks of numerous cargo liftings, and price incentives would point to strong imports as well.

## Ethanol Generally Follows Gasoline

**Source: Bloomberg**

**Notes:**
Since 2000, rack prices of ethanol in the Midwest have generally tracked gasoline prices.  This is what one would expect when ethanol supply and demand are in relative balance, since the price would be set based on the value of ethanol as a gasoline component.
Note that the price shown in this graph is the price after subtracting the tax credit, which is currently 51cents per gallon.  
The full price is received by the ethanol producer.
The ethanol blender pays the full price, and then takes the 51cent credit.

But in the last year and a half, ethanol supply relative to demand has resulted in some major departures from that pattern.

In the first half of 2005, ethanol production increased rapidly, partially in anticipation of Atlanta and New Orleans potentially increasing their use of ethanol.  This demand did not materialize, and the over-supply situation pushed ethanol prices down well below that of gasoline.  The variable cost of producing ethanol is the floor that ethanol prices would approach in over-supply conditions.

The beginning of 2006 has seen the opposite situation.  In early July, the average Midwest ethanol price (after the tax credit) was running about $1 per gallon over the price of gasoline in the Northeast.  Recently prices have relaxed with speculation that increased imports have relieved the price pressure somewhat.

## Gasoline Supply Issues

**Lower utilization and higher imports**
**Focus on East Coast markets**
**Transition to ethanol**
**Imports (sources and volumes to meet demand)**
**Regional prices and implications**

**Notes:**
Refinery utilization has been unusually low for every month of 2006 compared to typical historical patterns.  As a result, higher imports were needed to meet growing demand.

We also had a significant transition to ethanol in  2006, which resulted in changes in supply patterns. 

Large transitions in fuel specifications often result in shifts in import supply sources, as well as changes in relative  prices of product – both by product type and by region.  

## Utilization Patterns Reflect Maintenance & Hurricanes

**Typical Range is 10-year average 1995-2004 +/- 2 standard deviations**

**Notes:**
The U.S. began 2006 with some refineries totally out of service because of damage from hurricanes Katrina and Rita.  Other Gulf Coast refineries still had some lingering hurricane-related problems that affected production, while still others needed to perform more maintenance than usual, due both to postponement of maintenance in the fall following the hurricanes, and to prepare for the ultra-low sulfur diesel program.

Of special note is the outage at the large 437 thousand barrel per day BP refinery at Texas City, which suffered a deadly explosion before the hurricanes and was completely shut down until recently.  It is returning to service slowly, addressing safety concerns as well as the additional problems brought on by the hurricanes.

As the graph shows, summer utilization rates of 95 percent and higher are common.  In June, the utilization rate was estimated to be 93.9%.  During July, a number of unplanned outages occurred, and utilization is estimated at about 93%.  For the remainder  of the summer, utilization may remain  about 1-2% below typical levels due to known refinery issues, which translates to about 150 thousand barrels per day of lost gasoline production.  

## Total Gasoline Imports Year-to-Date Jan-May

**Note: Total gasoline is finished product plus blending components.**
**Source: EIA, Form EIA-814**

**Notes:**
Gasoline is the main product import the U.S. depends on.  Much of the growth in gasoline imports to the U.S. during the past few years has come from European sources.

As I will show shortly, Europe has an excess of gasoline, which we are able to take advantage of.  

In addition, fuel quality has also been a factor influencing growth in volumes from Europe.  Europe’s low-sulfur gasoline program is similar to the U.S. program.  This chart illustrates that for January through May, since 2003, before the U.S. Tier 2 low-sulfur gasoline program began, we have increased gasoline imports from Western Europe by over 300 KB/D, which is more than double the volume imported in 2003.  

At the same time, we saw a drop in volumes of 49 thousand barrels per day from Brazil and Other Latin America.  

## Europe’s Diesel Use Exceeds Gasoline, & Gasoline Demand is Falling

**Notes:**
The “dieselization” of Europe  is a phrase relating to changes in Europe’s transportation sector.  Europe has large incentives to purchase diesel-fueled light-duty vehicles and use diesel fuel rather than gasoline.  

The resulting shift in new light duty vehicle sales has increased demand for diesel fuel in Europe, and decreased demand for gasoline as the share of gasoline versus diesel-fueled light duty vehicles shifts.

Moreover, the  rate of  decline in gasoline demand has been increasing since 2000. 

## Europe’s Excess Gasoline Supply Is Growing

**Notes:**
European refiners have been unable to reduce gasoline production and increase distillate production to accommodate  the demand shift from gasoline to diesel.  

Gasoline yield from European refineries has only been reduced by about 1.5% over ten years, but crude oil input to refineries has increased slightly, countering the yield reduction.  

The balance between refinery production and consumer demand is achieved with distillate imports and gasoline exports.

As the graph shows, the  growing gap between gasoline demand and gasoline production means that European gasoline export volumes have been growing each year.

## Europe’s Domestic Light Product Supply Imbalance Grown Strongly since 1998

**Notes:**
This graph shows the growth in distillate imports and the exports of gasoline that have enabled  Europe to deal with the imbalance between refinery production and consumer demand.

When I discussed the shift  to diesel vehicles, I noted the increase in the rate of gasoline demand decline after 2000.  As shown above, during the four years from 2001 through 2005, gasoline  exports more  than  doubled from just under 400 thousand barrels per day to over 800 thousand barrels per day.

European refiners have had to find a market for their gasoline  exports, and that market has been the U.S.

## U.S. Imports Growing and Blending Component Share Increasing

**Notes:**
This slide shows the increase in U.S. gasoline imports in 2006.  January through May, total  gasoline imports are up 150 KB/D over  the same period in 2005.

There also has been a shift to more blending  components in 2006.  This is in part because finished RFG has been replaced with RBOB and blending components for producing RBOB for ethanol blending.  RBOB is treated as a blending component.

EIA has expressed concerns over import availability of the low RVP RBOB and other  blending components needed when using ethanol.  These materials are more difficult to produce than RFG blended with MTBE.   However, early indications are that importers have adjusted quickly and increased total imported materials from which RFG can be made.  

## Largest Gasoline Suppliers to U.S. (Thousand Barrels Per Day)

|  | 2004
Jan-May | 2005
Jan-May | 2006
Jan-May |
| --- | --- | --- | --- |
| Canada | 170 | 180 | 160 |
| Netherlands | 72 | 93 | 146 |
| U.K. | 107 | 98 | 116 |
| Virgin Islands | 116 | 101 | 95 |
| Venezuela | 44 | 76 | 77 |

**Notes:**
We have historically thought of Atlantic Canada, the Virgin Islands, and Venezuela as source locations that considered the U.S. East Coast as a primary market for their gasoline production.

Now European countries seem to be evolving to where the U.S. East Coast is an essential part of their gasoline market.  For January through May 2006, Netherlands and the UK rank second and third in terms of countries sending the largest volumes of gasoline to the United States.

These large-volume countries are also important sources of high quality gasoline.  In May 2006, all the RBOB imports for blending with ethanol to make RFG came from  the 5 countries on this slide.

We have become accustomed to market analysts commenting on whether the “arbitrage window” or the “trans-Atlantic differential” is sufficient to draw imports.  For many European countries, the U.S. East Coast is an important and steady part of their market, and volumes will flow each and every month from these countries just as they do from Canada and the Virgin Islands.

## U.S. Is Becoming More Important Destination for UK and Netherlands

| UK and Netherlands Gasoline Production & Exports 
(Thousand Barrels Per Day) |  |  |  |
| --- | --- | --- | --- |
|  | Gasoline Production | Net Exports to OECD Europe | Net Exports to U.S. |
| Netherlands |  |  |  |
| 1995 | 344 | 119 | 20 |
| 2005 | 330 | 22 | 87 |
| UK |  |  |  |
| 1995 | 631 | 81 | 44 |
| 2005 | 524 | 4 | 107 |

**Notes:**
The Netherlands and the UK have been net exporters of gasoline for a long time.  But with the decline in European gasoline demand, there has been a shift in the main market for their exports.

In 1995, both countries exported some of their gasoline production to other countries Their main export destination was other European countries, with a smaller amount to the U.S.

By 2005, the pattern had reversed, with the U.S. now being the main export destination.  Moreover, both of these countries have the capability of meeting RFG standards with at least a portion of their exports.

## New York’s Recent Prolonged Discount to Gulf Coast Prices

**Notes:**
Most U.S. gasoline imports flow into the Northeast markets.  Thus, prices in that region may at times rise to attract additional imports and at other times may be depressed by high levels of imports.  The Northeast is also a region where RFG represents a large share of gasoline consumption.  With the transition from MTBE to ethanol, which mainly affected  RFG, there was concern than East Coast prices could by pushed up.

Gasoline import volumes are generally higher in the first half of the year, and it is not unusual to see New York Harbor gasoline prices below Gulf Coast prices during that time.  The transition to ethanol could have changed that situation, but as shown in the previous slide, that did not occur.  Imports have been high this year, and New York Harbor prices were less than Gulf Coast prices even more than usual during the first two quarters of the year.  

## RBOB Showing Extra Strength in 2006

**Notes:**
However, the transition to ethanol did seem to put some added pressure on RBOB relative to conventional gasoline prices in the Northeast.

## Ultra-Low Sulfur Diesel (ULSD)

**Few basics**
**Production so far**
**Things to watch**
*Info website:*
*www.clean-diesel.org*

**Notes:**
This next section will touch on the beginning of the ultra-low sulfur diesel program.  

## Clean Fuel Quality Requirements & Supply

**Gasoline**
**Low sulfur requirements **
**MTBE elimination**
**Import impacts**
**Ultra-Low Sulfur Diesel (ULSD)**
**ULSD requirements (trending to all USLD)**
**ULSD implementation**
**Implications for other distillate fuels**

**Notes:**
Gasoline sulfur content has been phasing down for several years.  Diesel had a sulfur reduction required back in 1993 (550 ppm), and this year, highway diesel will see a tremendous drop to 15 ppm.    

For the next several slides I will focus on the move to ultra-low-sulfur diesel for highway vehicles, which began this past June.  While this new fuel will help to improve air quality, it will increase diesel costs.

## ULSD Phase In Summary

| Fuel | 2006 | 2007 | 2008 | 2009 | 2010 | 2011 | 2012 | 2013 | 2014 |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Highway | 80% 15 ppm & 
20% 500 ppm |  |  |  | 15 ppm | 15 ppm | 15 ppm | 15 ppm | 15 ppm |
| Non-Road |  | 500 ppm | 500 ppm | 500 ppm | 15 ppm | 15 ppm | 15 ppm | 15 ppm | 15 ppm |
| LM |  | 500 ppm | 500 ppm | 500 ppm | 500 ppm | 500 ppm | 15 ppm | 15 ppm | 15 ppm |
| NRLM w/ Credits |  | HS | HS | HS | 500 ppm | 500 ppm | 500 ppm | 500 ppm | 15 ppm |

**Notes: LM – Locomotive and Marine; ppm – parts per million**
**Source: EPA Presentation ULSD Workshop Nov 2004**

**Notes:**
This summer is only the beginning of the ULSD change.

The regulatory changes to remove sulfur from various distillate fuels will occur over the next 7 years.  The program began with on-highway diesel this past June, when suppliers (refineries, importers and blenders) began producing ULSD in earnest.

The next phase will be the non-road market (tractors, construction equipment, etc.) excluding locomotives and marine.  It must drop to 500 ppm by June 2007, and to 15 ppm by June 2010. 

Locomotive and marine fuels also drop to 500 ppm in June 2007, and they remain at that level until June 2012, when they drop to 15 ppm.

There are more divisions, like small refiner schedules and the ability to use high sulfur fuel in the NRLM market with credits.  

## As ULSD Requirements Grow, Non-ULSD Pool Shrinks & Production Issues Grow

**Source: EIA estimates derived from EPA planned capacity survey, EPA Regulatory Impact Analysis, EIA Sector Demand, EIA AEO 2006 distillate projections.**

**Notes:**
In 2006, distribution of ULSD may be the largest problem in starting the program.  In fact, EPA is projecting over-compliance of ULSD production.  With about 2500 KB/D of production expected from June through December 2006, that still leaves 820 KB/D of remaining highway, non-road and locomotive/marine demand that will be using higher sulfur distillate.  

As we progress, more of the distillate pool will be ULSD.  In 2010, the only segment left out of the 15 ppm ULSD pool is the locomotive and marine segment, and by 2012, virtually all of the segments required to use ULSD will be doing so.  There still is some ability to use credits and some small-refinery waivers that may be used until 2014. The heating oil distillate demand will remain, which represents almost 20% of total distillate, but this volume is mostly used in the Northeast.

Refiners will find completing the ULSD program after 2006 more challenging.  
First, the remaining material in the distillate feedstock pool is likely to contain larger volumes of cracked stock components than the distillate material desulfurized for 2006.  This cracked stock contains sulfur that is more difficult to remove than in other distillate components.  Thus, it will be more expensive to convert the remaining barrels to ULSD.  
Second, refiners are expected to be running more poor quality heavy crude oils containing more of the difficult-to-desulfurize cracked stocks and more feedstocks derived from tar sands, which are high in aromatics.   

As more and more of the distillate pool moves to ULSD, the price premium will likely increase  as well.
The implications that the move to ULSD may have on the quantity and supply of heating oil and kerosene bears watching and further analysis.

## ULSD Production Is Progressing Rapidly

**Notes:**
Prior to June 2006, we saw very little production of ULSD, although some was being produced for special markets.

By the last week in June, ULSD refinery production was over 2.1 million barrels per day and growing.

While the hurricane damage to refineries and heavy maintenance schedules may have caused some delays in ULSD unit startups, we appear to be likely to reach the 80% level rapidly, and may exceed that to meet EPA’s higher precompliance estimate.

## Diesel Production June 2005 vs Last Week June 2006

**Notes:**
The movement to ULSD  production has varied by PADD.  PADD’s 4 and 5 moved quickly to ULSD production in June.

PADD’s 1 and 3 are the areas moving most slowly.  Keep in mind, though that PADD historical diesel production may not have all been going to the highway market.  

## Number of Refineries Producing Diesel By Sulfur Level

|  | EPA Precompliance Report (2005) | 6/30/2006 Reported | Comments |
| --- | --- | --- | --- |
| PADD 3 |  |  |  |
| 100% 15 ppm | 29 | 9 |  |
| Mix 15 & 500 | 3 | 12 | 7 are Hi ULSD |
| 100% 500 ppm | 8 | 13 |  |
| PADD 2 |  |  |  |
| 100% 15 ppm | 17 | 7 |  |
| Mix 15 & 500 | 3 | 10 | 4 are Hi ULSD |
| 100% 500 ppm | 4 | 6 |  |

- Note: EPA data include all refineries.  The EIA 6/30 reported data are from the weekly sample, which does not cover all refineries.

**Notes:**
By the end of June, ULSD production volumes in PADD 2 were nearly 90% of EPA’s 2005 precompliance estimate.  EIA collects weekly data on 23 refineries and EPA’s report accounts for 24 refineries.

PADD 3 volumes were only 69% of EPA’s estimate for the year.  Here weekly data only report on 34 refineries compared to EPA’s count of 42.  But 8 refineries not reporting on the weekly survey are small.  Our assessment is that the implementation is moving more slowly in PADD 3, which is also supported by refiners’ public comments on delays they have been experiencing.

## ULSD Summary

**Refinery production began in June.  Refiners should average 80% for June through December.**
**Issues to watch**
**Distribution and contamination – next presentation**
**Kerosene/jet and winter diesel blending**
**Import availability**
**State interest in limiting heating oil sulfur content**

**Notes:**
In summary, while ULSD production is well underway, the next hurdle we are all watching is distribution.

We also don’t know how the availability of ULSD kerosene/jet may impact blending for winter diesel.  It is too early to see anything from a data perspective, and because the transition is underway, it may even be too early for those who plan on producing winter blending material to commit to contracts. 

Import availability for ULSD will be limited.  Those refineries in Canada and the Virgin Islands that are dedicated to the U.S. market are likely sources of imports.  While Europe also has a very low sulfur standard, it is short on diesel.  

Looking ahead even further, States are showing an interest in reducing the sulfur content of heating oil to that of diesel fuel, which could create some significant supply challenges during winter cold spells, when high imports are a large source of supply response to temporary high demand.

## Wrap Up: Year of Record Fuel Prices

**Record crude oil prices**
**High refinery limitations – hurricane and maintenance**
**Two difficult fuel specification changes – MTBE to ethanol and ULSD**

**Notes:**
I have covered a number of complex topics.

The main theme that we all are aware of is this year of record fuel prices.

While crude prices have been a major factor,  the U.S. has dealt with refinery production limitations from the hurricanes and maintenance.

And the industry has and is going through two difficult fuel specification changes, which also adds to market pressures, as discussed in the earlier slides.

With the ULSD change still in progress, we could still see issues emerge.  Significant problems can spill over into the heating oil market, but with the Northeast able to take advantage of heating oil imports, spillover effects may be limited.