# Presentation: 662261

## Effects of Feed Quality and Product Specification Changes on Refined Product Supply

**Joanne Shore**
**John Hackworth**
**Energy Information Administration**
**NPRA Annual Meeting**
**San Antonio, Texas**
**March 2003**

**www.eia.doe.gov**

**Notes:**
As we look ahead for the next 5 to 10 years, many changes will affect the refining industry in the United States and its ability to produce petroleum products and supply market demand.

This presentation explores two such changes – feedstock quality and product specifications to produce cleaner fuels.

## Petroleum Product Supply Affected By Numerous Factors

**Changing Product Specifications**

**Changing Feed Quality**

**Capacity Changes**

**Petroleum Refined Product Supply**

**Technology**

**Imports**

**Notes:**
This presentation focuses on how changes in quality of refining inputs and changes in product specifications will likely affect refining supply.    

As background to the feedstock and regulatory impacts, the presentation begins with a brief review of two other factors affecting supply:    
The capacity of U.S. refineries – expansions compared to shutdowns, and
Import availability.

Technology changes will only be mentioned briefly during the presentation, leaving the rest of the meeting’s papers to fill out that factor’s impact on refinery production.

## U.S. Refining Capacity: Where We Are Today

**Source: EIA**

**Notes:**
The reason that various factors affecting refining supply are of interest is that today U.S. capacity is fully utilized.  But this situation is relatively new.  The industry experienced almost 20 years of surplus capacity up until the mid 1990’s.  This surplus capacity diminished between 1980 to 1995.  But since 1995, demand and capacity have grown by about the same volumes, with a small amount of spare capacity remaining.

In 1997 and 1998, refiners were running near maximum capability.   Since then, both capacity increases and strong imports eased the situation.  The system has been working with about 600 thousand barrels per day (MB/D) of spare capacity, which can quickly disappear.  

As we look ahead, we are entering uncharted territory.  With little excess capacity and with product specification changes that will affect refinery yields and also import availability, where will new supply come from?  Will we see some tight capacity situations while the market sorts this out?  

History may help us to see into the future. 

## Domestic Capacity Is Expected To Grow

**Source: EIA**

| Time Period | Annual Average Shutdown Capacity
(MB/CD) | Average Annual Growth of Continuously Operating Capacity
(MB/CD) |
| --- | --- | --- |
| 1990-1995 | 139 | 76 |
| 1995-2000 | 96 | 324 |
| 2000-2007 | 60 | 346 |

**Historical shutdowns are for years 1990-1994, 1995-1999.**

**Notes:**
Gasoline and diesel demand are forecast to continue to increase, and some of that demand growth will likely be met by domestic capacity expansion.   

Historically, shutdowns of small, less efficient refineries have been occurring in every year, but the rate of shutdowns has been slowing.  More important, those refineries staying in operation have been expanding – even during the recession years in the early 1990’s.  Since 1995, some refiners have expanded because they 1) saw demand growth opportunities, 2) had adequate financial ability to invest, and 3) could put together expansion projects that with existing and anticipated margins offered adequate returns.

If recent historical patterns of refinery shutdowns and expansion continue, the United States could see a net increase in capacity of about 1.7% per year.  However, refinery expansion since 2000 has fallen short of this trend.

A number of factors may continue to hold growth down in the short term.  For example, the large low-sulfur fuel program expenditures this industry is facing could accelerate the shutdowns of marginal refiners for several years.  Another uncertainty is refinery margins.  If refinery margins are poor, companies will limit asset expansion.

## Gasoline Imports Are Important Source of Supply for East Coast

**Source: EIA**** **

**Notes:**
In addition to domestic refining, gasoline imports are an important source of gasoline supply – particularly for the East Coast, where they served 22% of demand in 2001 (including blending components).   The East Coast received 89% of U.S. gasoline imports.  Not surprisingly, with the East Coast being the main region using these imports, the Atlantic Basin countries provide most of this supply.  

Canada, the Virgin Islands, and Venezuela direct sizeable export volumes to the United States on a regular basis.  Western Europe, on the other hand, is a swing supplier, in that volumes come to the United States if the economic opportunity window opens.  Average import shares into PADDs 1 through 3 from 1996 through 2001 are:
Canada		15%
Venezuela		17%
Western Europe		28%
Virgin Islands		21%
Other South American Countries	  8%
Eastern Europe		  4%
Middle East		  4%

But what about the future?  Western Europe, one of our primary supply sources for RFG and RFG blending components, may have less of these high quality volumes available economically in the future.  European countries are establishing tax incentives to supply low sulfur gasoline, which likely will diminish RFG volumes flowing to the United States.

Furthermore, if the East Coast moves to needing low RVP RBOB for ethanol blending, European refineries may come up short of supplies initially, since some investment is required.  Gulf Coast refineries may become a larger supplier of RFG quality streams to the East Coast than in the past.

## Changing Feedstocks: Any Signs of Supply Impacts?

**Growing use of heavier crude oils impact on light product yields**
**Historical changes in the use of C4’s, C5’s and oxygenates in gasoline**

**Notes:**
Keeping in mind the background covered in the prior slides, this section focuses on refinery feedstock changes and what, if any, changes can be observed historically in gasoline and distillate yields as a result of those changes.

Changes in both crude oil quality and use of butanes, pentanes and other light hydrocarbons as well as oxygenates will be explored. 

## Heavier Crude Oils Accounted for Import Growth

**Source: EIA**

**Notes:**
Imported crude oil represented over 60% of U.S. crude oil supply in 2002, so imported crude quality data provide an indication of change in quality of crude oil input to U.S. refineries.  This graph is a rough approximation of import quality, based on country import data, and estimates of a country’s quality breakdown, based on samples from the import cargo data.

The graph shows that the growth in imports has been greatest in the medium to heavy oils category.  The increased use of medium to heavy, sour crude oil has been prompted by:
Refiners’ concerns that the availability of light, sweet crude oil in the Atlantic Basin will diminish at some point, even though, for the past decade, this prospect has been pushed further into the future;
Increased participation in U.S. refining by Western Hemisphere heavy crude oil producers to assure markets for their oil.    

Future sweet crude oil availability in the Atlantic Basin over the next 5-10 years looks favorable.  

## U.S. Refinery Input Quality

**Source: EIA**

**Notes:**
Given the changes in quality of imported crude oil, it is not surprising that total refinery feedstocks have been moving to higher sulfur and lower gravity crude oils in general.

## Rapid Growth in Bottoms Processing for Heavy Sour Crude Oils

**Source: EIA – Capacity as of January Each Year**

**Notes:**
The changes in refinery feedstocks toward poorer quality crude oils are reflected in in capacity changes.  Coking capacity, the main choice for bottoms processing, has grown the most on a percentage basis.  It has increased 56% since 1987, followed by hydrocracking capacity at 37%, and fluid catalytic cracking (FCC) capacity, which increased by 14%.

Looking to the future, will refiners facing large investment requirements to produce low-sulfur gasoline and ULSD have the interest and resources to engage in heavy crude projects?  The answer is probably yes, but the rate of growth of coker capacity will probably slow.

There are three factors that could cause future coker capacity growth in the near term to moderate:
There are fewer and fewer U.S. refineries with residual fuel production that can be eliminated with a coker project.  
There will continue to be light, sweet crude oil available in the Atlantic Basin. 
Heavy crude oil processing projects yield more cracked stock with more aromatics and sulfur -- not an attractive feedstock in the ULSD future, and they also yield more high-sulfur coke that may be more difficult to market in the future.

## Changes in Light-Product Yields at Refineries with Coker and Heavy Crude Oils Projects

**Explored changes in refineries adding cokers between 1998 and 2001**
**Looked at two groups with different product yield impacts:**
**Group A : Little change in crude gravity, reduction in residual fuel oil yield**
**Group B - Large drop in crude gravity, little residual fuel oil  to reduce**

**Notes:**
From 1991 to 2001, refinery crude input rose 14%, from 13,300 MB/D to 15,127 MB/D. At the same time, refiners used more heavy crude oil.  As refiners shifted to heavier crude oil slates, inputs to cokers rose by 38%, from 1,423 MB/D to 1,963 MB/D. 

The increase in coking allowed us to explore whether the shift to heavier feeds had resulted in any light-product yield impact.  We analyzed 8 projects that were finished during 1998-2001, in which 270 MB/D of coker capacity was added. 

The projects fell into two categories: In the first group of four refiners, prior to the coking projects, some of the crude oil bottoms had been going to residual fuel oil.  The addition of the cokers allowed these refiners to convert the bottoms and reduce residual fuel oil production.  These refiners were already using medium to heavy crude oils, and their average crude quality changed little after the addition of the cokers.  

In the second group of  projects, refiners chose to add coking capacity and run much heavier crude oils with more bottoms. 

## Before & After Coker Additions

|  | Group A |  | Group B |  | Total |  |
| --- | --- | --- | --- | --- | --- | --- |
|  | Before | After | Before | After | Before | After |
| Crude API Gravity | 28.0 | 26.2 | 33.1 | 25.7 | 29.7 | 26.0 |
| As Percent Crude & Unfinished |  |  |  |  |  |  |
| FCC Input | 35.0 | 35.9 | 36.9 | 35.4 | 35.7 | 35.7 |
| Hydrocracker Input | 5.6 | 5.0 | 8.1 | 13.5 | 6.5 | 8.2 |
| Coker Input | 11.0 | 21.0 | 7.5 | 23.1 | 9.8 | 21.8 |
| Pentanes Plus Input | 0.3 | 2.3 | 2.0 | 3.9 | 0.9 | 2.9 |
| C4+MTBE Input | 4.8 | 3.4 | 5.2 | 4.6 | 5.0 | 3.9 |
| Yield Adj Mogas: % C+U | 45.9 | 43.8 | 48.9 | 46.2 | 46.9 | 44.7 |
| Yield Distillate: % C+U | 31.2 | 35.8 | 36.0 | 35.4 | 32.9 | 35.6 |
| Yield Light Prod: % C+U | 78.8 | 81.2 | 88.5 | 84.1 | 82.3 | 82.2 |
| Yield Residual: % C+U | 8.1 | 3.1 | 1.7 | 1.2 | 5.8 | 2.4 |

- NOTE: Group A: 4 refineries, 140 MB/D coking capacity added; Group B: 4 refineries, 130 MB/D coking added.  Gasoline yield is adjusted by removing contributions from C4, C5 and oxygenate blend components so that yields reflect only gasoline product derived from crude oil and unfinished feedstocks (C+U).

**Notes:**
This table summarizes the results of the coker analysis.  Group A saw only a small drop in crude oil gravity of 1.8 API after installing the cokers.  That is, the purpose of the added coker capacity was mainly to reduce residual fuel oil production, which fell from 8.1 to 3.1%, without much shift in crude oil gravity.  Light product yield for these projects increased by 2.5%, rising from 78.8 to 81.2% yield.

Group B refiners reduced feedstock gravity from 33.1 to 25.7% ( 7.4 degrees API) after installing the cokers.  These refiners saw a large increase in coker input from 7.5 to 23.1% of crude and unfinished oils, and a significant increase in hydrocracker inputs as well (8.1 to 13.5%).  Their average light-product yield dropped about 4% from 88.5 to 84.1%.    

For the eight refiners combined, the impacts on light product yield in this period was small.  Many of the refiners in both groups worked to counter light-product yield loss by including in their projects other process improvements and by making greater use of supplemental light feedstocks.

This analysis highlights that the main reason aggregate light-product yield has not changed much for refiners adding coking capacity was due to the number of refineries that simply upgraded to lighter products (Group A).  In the future, there will be fewer refineries in the Group A category, historically producing residual fuel to upgrade.  To the extent that heavy crude projects continue -- and they probably will, albeit at a slower rate, they will be more like the Group B refinery projects, and there will be a negative impact on light-product production capability. `

## Oxygenates, C4’s and C5’s Contribute Significant Volumes to Gasoline Production 

**Source: EIA**

**Notes:**
In addition to changes in crude oil quality, refiners have made changes in the use of gasoline feedstocks that contribute to gasoline production.  This chart shows the normal butanes (C4’s) and pentanes plus that U.S. refineries have been using.  Most of these materials go into gasoline – either directly or through other processing.  For example, pentanes plus are sometimes sent to isomerization units or reformers.

Because of reduction in RVP specifications, use of normal butane in gasoline has declined, but it still provides a significant volume.

The use of pentanes plus volume from gas processing has also declined, but volumes popped back up in 2001 and 2002.  Some of the use of pentanes plus has been by refiners with heavy crude projects to maintain gasoline volumes.  

Oxygenates, however, more than compensated for the loss of the butanes and pentanes plus.  The oxygenate increase is primarily from the increase in use of MTBE in gasoline for RFG production.

## Flat Crude-Based Gasoline Yield

**Source: EIA**

**Notes:**
The changes in feedstocks shown in the prior slide affected gasoline yield.  Gasoline yield in total increased during the 1990’s, driven by the addition of oxygenates.  That portion of the gasoline produced from crude oil and unfinished feedstocks (e.g., FCC feedstocks) was relatively flat.  Thus, the increase in total gasoline volumes produced stemmed from increases in throughput and from the addition of oxygenates.

Yields of diesel and jet increased to meet the strong demand growth for these products.

Overall, light-product yield from crude and unfinished oils grew.  This has occurred from the addition of oxygenates, from process additions and improvements, and from reduction in bottom products.

But the future is shaping up to change this picture.  Technology advances will continue to help improve yields in some areas, but a number of regulatory changes will act to counter these gains and possibly even reverse some of the historical yield gains.

## New Regulatory Supply Impacts

**MTBE/Ether Bans**
**MSAT with MTBE Bans**
**ULSD**

**Notes:**
Now we turn to the impacts product-specification regulations may have on supply and begin by exploring three recent regulations.  

## Losing MTBE – Not Just MTBE Volume Loss 

**MTBE represents over 10% RFG, 3% total gasoline supply.**
**But physical & chemical properties are critical factors.  **
**No other hydrocarbon or alcohol can equal the emission and engine performance characteristics of MTBE and other ethers.**

**Notes:**
A number of States have banned MTBE, the primary oxygenate used in RFG, due to concerns over water contamination. 

The MTBE volumes used in U.S. gasoline are substantial  – adding over 10% to RFG supply and 3% to the total gasoline pool.  

What is not fully appreciated by many people outside of the petroleum business, is that losing MTBE is more than just losing the volumes of this blending component.

As the slide says, no other hydrocarbon or alcohol equals the emission and engine performance characteristics of ethers such as MTBE.  Hence, losing a barrel of MTBE results in losing more than a barrel of gasoline production.

When you remove a clean, high performance gasoline stream from the gasoline pool, it is difficult to find material to replace its volume and quality contributions.  Ethanol will be one of the preferred materials used to help replace MTBE.

## MTBE and Ethanol Property Comparison

**Both good octane and clean relative to other gasoline components**
**Issue is Ethanol relative to MTBE:**
**Higher oxygen content, so less volume needed for RFG oxygen requirement (5.8% v. 11.2% for MTBE)**
**Higher blending RVP than MTBE (VOCs problem)**
**Higher toxics than MTBE (MSAT issue)**
**Higher NOx in California model, not Federal model**

**Notes:**
How does ethanol compare when it is used in place of MTBE?

Both ethanol and MTBE improve octane and have clean air-emission characteristics relative to other gasoline components.  These favorable characteristics of ethanol are why we expect to see ethanol being used in many areas where MTBE is banned, regardless of the requirement to use oxygen in the gasoline.

However, ethanol has far fewer air emission benefits than does MTBE, which means further changes must be made to the gasoline.  In particular other components must be removed to compensate for ethanol’s characteristics.  For example, ethanol’s high blending RVP requires refiners to remove other gasoline components with high RVP’s, such as butane or pentane, to counter ethanol’s RVP impact.

## 2007 Loss of Volumes When Moving from MTBE to Ethanol – Add Backs (Constant Inputs, MB/D)

|  | PADD 1(1) | PADD
 2 | PADD
 3 | PADD
 5 | Total U.S. |
| --- | --- | --- | --- | --- | --- |
| Loss of MTBE Volumes | -100 | 0 | -93 | -113 | -306 |
| Addition of Ethanol to RFG | 75 | 0 | 18 | 58 | 151 |
| Refinery Increased Alkylate Production | 9 | 10 | 71 | 17 | 107 |
| Commercial Alkylate or Iso-Octane Production | 0 | 0 | 25 | 10 | 35 |
| Net Before Other Losses | -16 | 10 | 21 | -28 | -13 |

- Assumes MSAT volume issues are resolved and rule does not  hinder RFG production.

**Source: EIA**

**Notes:**
Last year, a Federal MTBE ban was being proposed that would begin in 2007.  This and the next slide illustrate how much gasoline production volume may be lost by 2007, if we assume MTBE continues to be used (both at State and Federal levels) versus a total ban.  This analysis explores the “easiest” volumes that refiners might use to replace MTBE.

If MTBE were continuing to be used in 2007, it would be adding about 300 MB/D to the gasoline pool.  The first row shows this volume as the loss that must be made up.

The second row assumes that ethanol is used to replace MTBE, maintaining the same oxygen content that MTBE provided.  Since ethanol has about twice the oxygen content as MTBE, only half as much volume is used.  

Refiners that are currently producing MTBE will be able to use the MTBE feedstocks to produce more alkylate.  If all of the refinery MTBE facilities currently in operation produced alkylate in 2007, we might see an additional 107 thousand barrels of product.

We also know of several merchant facilities that will likely be producing some alkylate or iso-octane, adding another 35 MB/D.  It is unclear whether other merchant or “on purpose” MTBE plants will convert, since economics today do not support these changes.

At this point, the balance is only 13 MB/D short.  But corrections have not yet been made for the RVP and distillation profile changes that occur when ethanol is added in place of MTBE.

## 2007 Loss of Volumes When Moving from MTBE to Ethanol – Further Losses (Constant Inputs, MB/D)

|  | PADD 1(1) | PADD
 2 | PADD
 3 | PADD
 5 | Total U.S. |
| --- | --- | --- | --- | --- | --- |
| Net Before Other Losses | -16 | 10 | 21 | -28 | -13 |
| Reduction in Light Ends for RVP | -25 | 0 | -38 | -50 | -113 |
| Reduce Heavy Ends for Distillation Points | -14 | 0 | -9 | -17 | -40 |
| Added Ethanol in Conventional | 0 | -20 | 0 | 0 | -20 |
| Total | -55 | -10 | -26 | -95 | -186 |

- (1) Assume MSAT volume issues are resolved and rule does not  hinder RFG production

**Source: EIA**

**Notes:**
Starting where we left off at 13 MB/D short, refiners now have to remove some light, high-RVP gasoline components (e.g., pentanes and butanes) to counter the RVP boost from ethanol.  That results in a loss of over 100 MB/D of product.

In order to counter shifts in the distillation profile that affect emissions, some heavy-end material must also be removed.  Also in this scenario, some of the ethanol that had been used in conventional gasoline when MTBE was used, had to be shifted to RFG.  This results in a small loss of volume from the conventional gasoline pool.

The net result is a loss of almost 170 MB/D of RFG production capability and another 20 from conventional gasoline.

These results do not take into consideration losses that might occur as a result of the Mobile Source Air Toxics rule (MSAT), which is illustrate don the next slide.

## The MSAT Issue Concerning Ethanol (Complex Model)

| Blend | Component Share
(Percent) |  |  | Emission Reduction from Industry Baseline
(Percent Reduction) |  |  | Volume Percent |
| --- | --- | --- | --- | --- | --- | --- | --- |
| Oxygen-
ate | Hydro-carbons | MTBE | Ethanol | VOC | Toxics | NOx | Benzene  |
| MTBE | 88.8 | 11.2 | 0 | 25.9 | 33.4 | 8.1 | 0.3 |
| Ethanol 1 | 94.2 | 0 | 5.8 | 15.5 | 28.3 | 7.2 | 0.4 |
| Ethanol 2 | 90.0 | 0 | 10.0 | 18.6 | 28.8 | 7.9 | 0.3 |

- Note: Fractions of specific components in the hydrocarbon blend are the same in all cases.  Emissions reductions are based on comparisons to 1990 industry average baseline fuel composition.

**Source: EIA**

**Notes:**
MTBE is a very clean component from an air emission standpoint.  It contains oxygen and has no sulfur, no aromatics, no olefins, and an RVP that is very close to the RVP of the remaining gasoline components.  In addition it has high octane.  Ethanol is an attractive substitute for MTBE.  It has good octane and , as mentioned previously, has about twice the oxygen content as MTBE.  As a result, only about half as much ethanol is needed compared to MTBE to meet the current oxygen requirement in RFG.  

However, ethanol gasoline blends have worse air emission qualities than blends made with MTBE.  The second row shows the emission effects of replacing all of the MTBE in Federal RFG with half the quantity of ethanol.  Ethanol increases gasoline’s tendency to evaporate, thereby raising the VOCs emissions, as mentioned previously.  

In addition, ethanol increases toxic emissions over MTBE.  While in this example, the level is within the Federal RFG requirements (20% reduction), it violates the Mobile Source Air Toxics rule (MSAT), which does not allow refineries to produce more toxics than they did during 1998-2000.  Adding 10% ethanol instead of the 5.8% does not change the result much.  

Some refiners have been producing very clean RFG using MTBE.  Generally, a refiner would reduce sulfur and aromatics to reduce toxics, but when a refiner is already producing gasoline low in sulfur and aromatics, there is little they can do to reduce toxics when they switch to ethanol.  This could result in some current suppliers of RFG reducing volumes.

## ULSD - The Lower the Sulfur and the Higher the Volume the Greater the Cost

**Source: EIA**

**Notes:**
The other recent regulation that is likely to have supply impacts is the move to ultra-low sulfur diesel (ULSD) in the United States.  In 2001, EIA analyzed the cost for individual refineries to produce ULSD for the highway diesel market, and found that the cost to comply would vary widely, as shown by the cost curve in this slide.  

The principal factors that determined the added cost for refiners to produce ULSD were:
 The volume of highway diesel (hence, scale of unit), 
 Whether the refiner had an existing unit that could be revamped or had to add a new unit, 
 The feed sulfur content, and 
 The percent of cracked stock in the feed to the desulfurization unit.

 The key question at the time of the previous study was what would be the decision of refiners in the upper portion of the cost curve?  Would they wait to invest in ULSD production, thereby leaving supply short of EPA’s 80-percent target at the beginning of the ULSD program? 

This question still remains and will likely be revisited as the requirements for off-road diesel are established, which brings our discussion to potential future regulations.

## Potential Regulatory Changes

**More ULSD (off-road)**
**More diesel light duty vehicles (diesel quality and volume issues)**
**Increased ethanol use (mandated or otherwise)**
**Other product clean up (sulfur reduction jet fuel, home heating oil)**

**Notes:**
In addition to existing regulations, a number of potential new laws and regulations will also impact supply.  

We soon will see the specifications for off-road diesel.  If refiners have to produce more ULSD to meet off road requirements, their challenge to meet supply targets increases.  Producing more ULSD raises the cost curve seen in the prior slide and makes it steeper, as refiners have to process greater fractions of the more difficult cracked stocks to produce the added volumes. 

 Also, if growth of light-duty diesel-fueled vehicles increases, ULSD volume requirements increase further, and there likely would be a push for higher cetane and lower aromatics content.

If a renewable fuel standard (RFS) becomes law, it will increase ethanol use.  An RFS may be the only future legal or regulatory product change that is designed to increase supply, but even it may add little to volume as emissions and supply tradeoffs are made.

Last, we can expect tighter specification changes in other products such as home heating oil and jet, either at the State or Federal level.  As these specification changes occur, refiners have less flexibility in their operations, which affects supply.  

The next set of slides highlight issues in more detail associated with several of these potential changes.

## Increased U.S. Light Duty Diesel Fuel Use?

***2001 New Retail Sales Light Duty Vehicles***

**Sources: US Chart --  ORNL *****Investigation of Class 2bTrucks*****, March 2002 & EIA Estimates; Europe Chart -- ACEA**

**Notes:**
First, consider a potential move to increase light-duty diesel-fueled vehicles in the U.S. Due to the greater efficiency diesel-fueled vehicles offer, the issue has been raised about encouraging more light duty diesel use in the United States.  In 2001, light-duty diesel-fueled vehicle share of new sales in the U.S. was around 2%.  

In contrast to the U.S., Europe has made a concerted effort through tax incentives to move away from gasoline to diesel fuel.  Well over 1/3 of its light-duty vehicle sales are now diesel fueled.  Its current light-duty fleet may already be about 25% diesel fueled.

Should the U.S. move to using more light-duty diesel-fueled vehicles, further quality improvements to diesel fuel likely would be called for – including increased cetane and decreased aromatics.  Such changes would require more investment by many refiners, and, in some cases, would suggest a different investment path to ULSD than would be the case under the current ULSD regulation alone.

The longer term impact is that such a change requires more highway diesel volume and less gasoline.  While conversion of the vehicle fleet from gasoline to diesel would not happen quickly, it nevertheless would have implications for the U.S. refining system that is configured to produce gasoline rather than highway diesel fuel.

## Proposed Renewable Fuel Standard

**Source: EIA, Monthly Oxygenate Survey and H.R. 4**

**Notes:**
Last year, several bills contained a renewable fuel standard that required an increasing volume of renewable fuel be used, and similar proposals are expected to appear in this year’s energy bills.

The renewable fuel requirement translates to an increasing use of ethanol in the near term, as other renewable fuels are not economic.  

Without ether bans, one might expect ethanol use to grow in conventional gasoline, where it is more easily accommodated from an emission and performance standpoint.  Credit trading would theoretically allow areas that can most economically use the ethanol to saturate first, selling credits to those suppliers that would find it less economic.

The 2012 target of  5 billion gallons of ethanol represents about 3% of the gasoline pool (versus about 1.5% in 2002).  

But the ability of this ethanol to “substitute” for petroleum, will be function of ether bans and States’ abilities to override the 1-pound RVP waiver when using ethanol in conventional gasoline.  
Earlier slides summarized the net volume loss when losing MTBE and substituting ethanol in RFG.  
However ethanol can add to supply when used in conventional gasoline.  The size of the contribution will depend on whether or not the current 1-pound RVP waiver is used, as illustrated in the next slide.

## Elimination of RVP Waiver Diminishes Ethanol Supply Contribution

| Volume and Energy Effects to Adjust for RVP When Adding Ethanol to Make 10% Blend |  |  |  |  |
| --- | --- | --- | --- | --- |
| RVP (psi) | Volume Increase (Decrease) By Adding Ethanol |  | Energy Increase (Decrease) By Adding Ethanol |  |
|  | With RVP Waiver | Without RVP Waiver | With RVP Waiver | Without RVP Waiver |
| 9.0 | 11.1% | 7.5% | 7.5% | 4.5% |
| 7.8 | 10.3% | 2.2% | 6.8% | -0.2% |
| 7.0 | 8.3% | -0.9% | 5.1% | -2.8% |

**Source: EIA**

**Notes:**
An RFS would mean that, at some point, areas not now using ethanol-blended conventional gasoline would be doing so in the future.  Currently, conventional gasoline containing 10% ethanol is allowed to exceed the Federal Clear Air Act Amendment RVP requirements by 1 pound. Thus areas that began using ethanol blended conventional gasoline would see higher RVP volumes, and, in turn, higher VOCs emissions from this gasoline.  As a result, some provision for allowing States to override the use of the 1-pound waiver has been considered.

While denying the waiver will prevent VOC emissions from increasing, it reduces the supply contributions that ethanol would make.  This slide shows the volume and energy effects of adding ethanol to conventional gasoline – both with and without the current 1-pound RVP waiver.  

Consider the effect on supply of 9.0 RVP conventional gasoline, which represents about 75% of conventional gasoline use in the United States. The waiver allows suppliers of 9.0 RVP gasoline to extend the gasoline volumes produced at the refinery by more than 11%.  However, if the waiver is removed, some other high-RVP gasoline compounds must be removed, and the effect is to reduce the added contribution of ethanol to 7.5% from 11.1% with the waiver.  

Similarly, the energy contribution is reduced from a 7.5% addition to a 4.5% addition – a 40% reduction in supply contribution.   

Areas which are restricted to lower RVP gasoline would find that removal of the waiver actually reduces supply of gasoline from an energy perspective.  

## Results of Tighter Product Specs and Greater Refinery Complexity

**Increased likelihood of outages**
**Single unit outage has greater impact on product production**
**Decrease in maximum achievable utilization**
**Diminished yields of prime fuels per barrel of crude oil**
**Greater “stay-in-business” investment hurdle for smaller refiners**

**Notes:**
As we look ahead at the direction of product specification regulations, we can expect a continuing move to lower sulfur and generally tighter specifications in all petroleum products. Regardless of the crude feedstock availability, refiners will have to make significant changes to deal with these changes. In general, refiners are facing  more deep desulfurization and/or some increased hydrocracking, more alkylation, and little latitude to change the component fractions in product blends.

The market implications of these refinery changes are first, we likely will see an increase in outages with the increased complexity and decreased blending flexibility.
Losing one process unit will likely have a greater impact on production than historically.
More units, higher severity operations, more complexity means more things that can go wrong and hence more outages.
That means that we will see some decline in maximum achievable utilization.

Second, the increasing restrictions on product specifications result in “more processing” (more units to lose yield), and running at higher severity, which reduces yield.  

And third, the investments needed to simply stay in business are large, and in the short term, we could see an acceleration of shutdowns.  

## Summary: Impacts of Feedstock Changes

**Fewer heavy crude projects, but will result in some light-product yield loss**
**Reduced ability to use light components (C4’s & C5’s) and MTBE will reduce gasoline yield per barrel of crude input**

**Notes:**
More heavy crude oils will be a drag on light product yields. 

MTBE bans will reduce the C4’s, C5’s and the oxygenate contribution to gasoline production from historical levels.   This indicates a potential reduction in gasoline yields in the future.

## Summary: Potential Regulatory Impacts on Gasoline

**Ether Bans ******** Largest supply challenge with significant RFG production loss, exacerbated by MSAT (Loss of MTBE, C4’s C5’s exceeds ethanol additions)**
**RFS ******** Adds some volume, but loss of 1-lb RVP waiver reverses some of that gain**
**Import streams meeting RFG specifications likely to become harder to find and more expensive**
**More distinct gasoline types adding to distribution system stress**

**Notes:**
Gasoline supply will be challenged by a number of regulations in the future.

Ether bans will strain both domestic RFG production and potentially limit import sources, since not all foreign-source refineries may wish to invest in RBOB production capability.

The one potential regulation that has some prospect of increasing supply is the renewable fuel standard.  But even this regulation will provide limited supply increases due to concerns over increases in VOCs emissions.  

While not discussed in the prior slides, the current and potential regulations being considered all trend towards more distinct gasoline types, which adds strain to the distribution system.  

## Summary: Potential Regulatory Impacts on Diesel

**ULSD ******** High and widely varying costs of production and new technology may cause some refiners to delay implementation & create shortages initially**
**Possible increase in light duty diesel vehicles ******** More ULSD volume and near-term quality improvements that increase refining challenges**
**Distribution losses with ultra-clean products is a challenging unknown**

**Notes:**
Diesel production capability may also be strained in the future as product specifications change.  

The current ULSD rule leaves concern that the transition may come up short of EPA target volumes.  Many refiners can delay production of diesel, and with ULSD production cost disparity among refiners being high, there is economic incentive for some to delay.

Looking down the road, should the United States decide to encourage light-duty diesel-fueled vehicle production and should such vehicles gain consumer acceptance, then refiners can expect a call for more quality changes in diesel fuel, such as higher cetane levels and lower aromatics.  Such changes would further increase refinery production challenges.

The distribution issues with ULSD are not just adding another distinct fuel to the distribution system.  They are creating a whole new level of segregation and contamination concerns that are yet to be resolved.

## Conclusion: Challenging Environment Implies Tight Market Years Ahead

_**Light Product Yield**_
**Feedstock changes – Loss of light product yield**
**Product spec changes – Net loss of light product yield**

_**Capacity**_
**Need more capacity to meet demand, yield loss, potential lower utilizations**
**Pressures to increase:**
**Demand growth**
**Higher import prices**
**Pressures hindering expansion**
**Resources limited to spec changes**
**Margins**
**Shutdowns**

**Notes:**
Both refinery light-product yield and capacity are being affected by feedstock and product specification changes.

Light product yield in the future can be expected to be adversely affected by both feedstock changes and regulatory changes.  The only proposed regulation leading to more supply is the renewable fuel standard, and even that will likely be somewhat limited in its supply contribution due to emission concerns.

Capacity expansion is expected to occur, but not without avoiding tight markets.  At best, refinery capacity may expand at the 1.7% per year rate seen from 1995-2001. However, the high investment requirements for desulfurization capability to produce ultra clean gasoline and diesel may diminish the resources available for refinery throughput expansion, particularly if margins are slow to improve.  High investment requirements to meet more stringent product specifications also may increase clsure rates.

Refiners face a challenging supply environment.  Collectively, based on the factors discussed, the refined product supply/demand situation in the U.S. will likely be tight as we progress through this decade.  If capacity is slow to respond to demand increases, the tighter market will give rise to higher prices, which in turn will attract higher-priced imports.  However, U.S. product specifications will likely limit product import supply more than in the past, giving rise to better margins for domestic expansion.

Supply will always meet demand, with price as the equalizing factor.  Exactly how supply will evolve under these circumstances remains to be seen.