# Presentation: 493073

## Petroleum Outlook:Increased Inter-PADD Movements Expected

**Joanne Shore**
**Energy Information Administration**
**API Annual Pipeline Conference**
**Dallas, Texas**
**April 2002**

**www.eia.doe.gov**

**Notes:**
The EIA official outlook is done on a national basis, and most people are interested mainly in prices.

This presentation will cover the national price outlook for this year, but presumably many folks at this conference are interested in regional activities that could impact pipeline flows.  As a result, I will also take a closer look at regional supply/demand balances between now and 2007 to see how volume balances may change and the implications for pipeline companies.  

## Introduction

**Supply-Demand Fundamentals Drive Prices**
**Regional Prices Reflect Regional Supply-Demand Balances & Distribution System Needs**
**Future Regional Supply-Demand Balances**

**Notes:**
The presentation begins with an overview of crude oil and U.S. product markets to illustrate the importance of supply/demand balances to prices.

With the onset of the RFG program, we have seen that regional prices can behave very differently, especially for unique fuels within the regions, as a result of changing regional supply/demand balances.

The last half of the presentation will explore potential changes in the regional supply demand balances for light products (gasoline, distillate and jet) as both demand and capacity change in an environment where product specifications and allowed fuel components are also changing.  

## WTI Crude Oil Price: Uncertain Future, But Drivers Adding Upward Pressure

**WTI Crude Oil Price: Uncertain Future, But Drivers Adding Upward Pressure**

**Sources: History:  EIA;  Projections: Short-Term Energy Outlook, April 2002.**

**Notes:**
To begin the price discussion, I will start with crude oil prices.  Crude oil and petroleum product prices are influenced by international petroleum  markets as well as by more local product markets.  

Crude oil has been the cause of the largest long-term swings in product prices. Most price variation in crude oil can be explained by changes in the balance between supply and demand.  Since 1996, we have seen some very large swings in crude oil prices.  The large dip ending in late 1998 and early 1999 was due to supply growth exceeding demand growth.  Iraq returned to the market at the end of 1996, with no compensating cutbacks from other OPEC members.  Shortly thereafter, the Asian financial crisis hit to lower demand growth.  A large build in oil inventories resulted, and West Texas Intermediate crude oil prices sank to nearly $10 per barrel.  

A series of cutbacks by OPEC and other non-OPEC producers in 1999 and into 2000 along with Asia’s economic recovery reversed the situation.  Demand was greater than supply, excess oil inventories were drawn down, and prices rose to nearly $35 per barrel on a monthly average basis.  

In 2001, production again exceeded demand, and price declined. Recently, OPEC again cut back production, and prices turned up.  With an economic recovery beginning, we expect demand to increase.  OPEC is currently planning to hold production down.  In addition unrest in the Middle East and uncertainties about Iraq continue to add price pressure.  

## OPEC Discipline & Economic Recovery Tighten World Balance in 2002

***Total includes commercial and government stocks.**

**Source: EIA**

**Notes:**
Prices are a function of supply/demand balances, and inventories are the best measure of the balance between supply and demand in the petroleum sector.  If supply exceeds demand, inventories rise and, as they exceed normal levels, prices decline vice versa.  OECD country inventories tend to be a good barometer of world petroleum balance and thus world crude oil prices.  

Historically, the large build in 1998, relative to more typical historical levels, occurred when prices dropped to almost $10 per barrel.  The subsequent precipitous drop in inventories and lackluster build occurred when prices climbed to almost $35.  

OECD data is not particularly current, but it appears that inventories in early 2002 have returned to more normal levels.  U.S. inventories seem more bloated than other OECD regions.  While the U.S. saw stock builds in 2001, by the end of the year, both Europe and Japan were experiencing year-on-year declines.

 In total, by the end of 2001, the market seemed fairly well balanced.  

But EIA sees the supply-demand balance tightening again this year with inventories slipping below normal levels.  There are a number of uncertainties, however: OPEC’s ability to restrain production, Iraq’s behavior, and the timing of the world economic recovery.      

EIA’s forecast of a low stock cushion implies we should see higher crude oil prices before the year is out.  

## U.S. Supply/Demand Balance Follows World

**Sources: History:  EIA;  Projections: Short-Term Energy Outlook, April 2002.**

**Notes:**
U.S. inventories have followed world patterns.   Both crude oil and products have shown similar trends, although sometimes one lags or leads the other slightly.

U.S. crude oil inventories are not low now, but they may drop further than shown in EIA’s most recent Short Term Energy Outlook illustrated in the graph.  Inventories in the rest of the world are much tighter than in the United States.  With demand for gasoline picking up and rising crude oil prices adding disincentives for crude oil buyers in the near term, crude inventories could move from what seems to be ample inventory levels to low inventory levels fairly quickly. 

Right now, gasoline inventories are in the normal range, settling on March 29 at 2.5 percent over their 5-year average level for this time of year. Levels improved significantly last week as the turnovers from winter grade product to summer grade progressed.  However, PADD 2 is still somewhat low, with stock levels about 2.6% below their 5-year average for this time of year.  

While product inventory patterns generally follow crude oil inventory patterns, product inventories do not always move at the same time as crude oil inventories, or in the same way among regions, which has an impact on product prices relative to crude oil and on price variations among regions.  

## Product Supply/Demand Balance Affects Wholesale Price Relative to Crude Oil

**Source: Reuters**

**Apr-Aug  ‘99**
**8 cents**

**Apr-Aug  ‘00**
**15cents**

**Apr-Aug  ‘01**
**16cents**

**Notes:**
The gasoline supply/demand balance reflected in inventories shows up as changes in wholesale gasoline prices relative to crude oil.  This graph illustrates the variation in spot price for gasoline over and above the changes in crude oil prices.  As the balance between gasoline supply and demand tightens (inventories drop to low levels), the spread between spot prices and crude oil (sometimes called gasoline crack) increases, and vice versa.
The gasoline crack in 1999 shows how gasoline prices during the winter of 1998/1999 had dropped to about the same level as crude oil prices as the industry struggled with how to deal with the large overhang of petroleum inventories that had evolved.   
In the summer of 1999, excess gasoline inventories began to decline, and crude oil prices increased, pulling gasoline prices along.  But gasoline inventories remained high in spite of reduced refinery runs.  The gasoline crack only averaged about 8 cents per gallon that summer (April-August), compared to 12 cents during the summer of 1997.
By the end of 1999 and early 2000, world inventories had been drawn down to low levels, and U.S. gasoline inventories were no exception.  With only a small crude oil and gasoline inventory cushion, supply problems caused prices to spike during the spring of 2001.  The petroleum markets remained tight in early 2001, and we revisited price volatility both in the spring and in the fall.

But later in 2001, the cycle reversed again with inventories building and margins falling.  Refinery maintenance, run reductions and growing demand have trimmed gasoline inventories somewhat, and some regions remain fairly low.  Spring spreads are again rising, averaging around 14 cents per gallon in late March.  We expect retail gasoline prices to peak around $1.54 per gallon this summer due to strength in spreads as well as crude oil price increases.  

## Regional Supply/Demand Balances Affect Regional Prices

**Source: EIA**

**Notes:**
Regionally, supply demand balances also influence prices.  California has experienced large price swings for some years.  It is in a geographically isolated region, dependent on its own refineries which run at high capacity utilization.   It also uses a unique fuel that few other refineries can produce.  When refinery outages or other factors create supply-demand imbalances, it takes time for the market to resolve the imbalance, and prices can rise considerably during the interim.

The first summer of Phase II RFG created a similar situation in the Midwest.  The ethanol-blended RFG is difficult to make, and not many refineries outside of those serving the Chicago-Milwaukee RFG market on a regular basis can produce that gasoline.  When refineries came up short following the Phase II transition, there was no place else to turn.  In addition, very low inventories provided no cushion for adjustments.  

Last spring, very low inventories again provided little cushion for supply-demand mismatches.  Refinery outages in both the Midwest and East Coast and the loss of Citgo’s Lemont refinery distillation tower late in the summer brought strong price surges in those areas.

 Crude oil prices increases have been driving prices up this year until last month when spreads began to rise rapidly as well.  

The Midwest price surges, in particular, brought attention to the importance of the distribution system in helping to resolve these price surges.  

## Recent Focus on Distribution System’s Ability to Help Restore Regional Imbalances

**Recent Focus on Distribution System’s Ability to Help Restore Regional Imbalances**

**Imports**

**Notes:**
The size and duration of price surges are determined by the size of the imbalance and the time it takes to resolve the problem.  Recently, the distribution system’s role in resolving such issues has been in the limelight.

The regional price surges have brought new attention to the pipeline industry in particular.  For example, it has been clear that pipelines into and within the Midwest run at nearly full capacity, minimizing their ability to resolve supply/demand imbalances quickly, but still how they are able to eventually get extra volumes of needed product into affected regions.  Also, the Longhorn pipeline’s potential role in easing California’s tight market continues to be a long wait.   

One factor that influences the time to fill a gap between supply and demand is the distance that new supply must travel.  
Both East Coast and the Midwest are dependent on products made on the Gulf Coast, which can take several weeks to travel by pipeline or barge.  
In addition, the East Coast depends on imports, some of which also come from some distance, such as Europe.
A small amount of material even moves from the Gulf Coast to the West Coast through the Panama Canal.  

## Pipeline & Barge Movements of Light Products* Critical to Regional Supply

**Note:  Light products are gasoline, distillate and jet fuel.**
**Source: EIA, Petroleum Supply Monthly, 2001**

**Notes:**
This graph shows the regional dependence on long-distance product flows.  The East Coast (PADD 1) is most dependent on distant production.  Over half of its light product needs comes by pipeline or barge.  But of that product moving from other PADD’s, almost 80% comes by pipeline.  The Midwest is also dependent on distant light product production – mainly from the Gulf Coast.  About 86% of the Midwest light products from other PADD’s comes via pipeline.

The Gulf Coast (PADD 3), which is the source of most of the East Coast’s and Midwest’s domestic net receipts, is not dependent on external supply sources.  

Even PADD 4 and PADD 5 receive some products from other PADD’s, but to a much smaller extent than PADD’s 1 and 2.

The future need for inter-PADD product flows will depend on how demand in each PADD is growing relative to its own refinery capacity.

## Light Product Demand Growth Expectedin All Regions 

**Source: EIA**

**Notes:**
U.S. demand for light products in total could increase at an average annual rate of about 1.8%, which is typical of longer-term demand trends.  

Over the past decade, petroleum demand growth was mainly the result of growth in the transportation sector, and that is expected to continue into the future.  
Growth for gasoline, for example, is influenced by the countering factors of improved fuel efficiency (miles per gallon), number of vehicles and miles traveled by those vehicles.  Due to continuing growth of heavier passenger vehicles, such as SUV’s, fuel efficiency is not expected to improve at the rate seen during the 1980’s, assuming fuel efficiency standards stay at current levels and fuel prices remain relatively low in real terms relative to personal incomes.  Demand for higher powered, less fuel-efficient vehicles has not slowed with recent price volatility, and is not likely to slow in the near future, keeping demand strong.  Even September 11 did not seem to slow gasoline demand.  
Although jet fuel was affected strongly by the events of September 11, that fuel also should see continuing growth as the economy recovers, as will diesel fuel.  

But regionally, growth may vary.  The projections shown are based on historical patterns within the PADD’s.

## Potential Increases in Light Product Demand 2001-2007

**Source: EIA**

**Notes:**
The absolute volumes involved in the growth show the large role played by gasoline and diesel.  

PADD 1, 2, and 5’s growth rates are influenced heavily by gasoline followed by diesel.  PADD 3 has seen strong diesel and jet growth compared to gasoline.  While PADD 4 is showing particularly strong diesel and jet growth.

These are the increases in volumes that refineries, importers and the distribution systems will ultimately balance.

## But How Will Supply Grow Relative to Demand?

**Source: EIA**

**Notes:**
Let us turn first to refinery capacity, and how that supply source may change in the future.  Do we have enough capacity to meet the higher demand comfortably?  The answer is a qualified yes.  But to understand that answer we need to look at capacity historically.

Capacity has been growing since 1996.  But in 1997 and 1998, we experienced unusually high utilizations when demand growth exceeded capacity growth.  

In 1999, large volumes of imports and inventory draw downs helped to keep refinery utilization down, and capacity expansion has brought the system to the point where utilization averaged 95.5 during the summer of 2000 and 94.2 during 2001.  

How might capacity and utilization change in the future as demand grows?

## Domestic Supply Is Expected To Grow in Aggregate

**Source: EIA**

| Time Period | Annual Average Shutdown Capacity(*)
(MB/CD) | Growth of Continuously Operating Capacity |
| --- | --- | --- |
| 1990-1995 | 139 | 0.5% |
| 1995-2000 | 96 | 2.0% |
| 2000-2007 | 60 | 2.0% |
| (*)Historical shutdowns are for years 1990-94, 1995-1999. |  |  |

**Notes:**
Because refineries have been both shutting down and expanding at the same time, to understand future capacity, we need to explore both refinery shutdowns as well as capacity expansion by those refineries that have stayed in operation.

Small refineries have been the main facilities being closed, while larger refineries were expanded.  This chart summarizes the shutdowns and growth of refineries remaining in operation.

The capacity shutdown rate has slowed, although shutdowns will continue into the future as refineries with poor competitive cost structures and disadvantages of economies of scale face new facility investments both to the meet new fuel specifications as well as to comply with refinery emissions requirements.    

Still, we see some clear strategies among some groups of refiners to expand capacity in order to meet continuing growth in demand.  We expect the growth in the refineries remaining in operation to continue at about the same rate that was seen 1995 to 2000.  

The net increase in capacity would then average about 1.7% per year, or about the same growth rate as expected for light product demand.  

## Size of Shutdowns Largest in PADD 2, But More Shutdowns Possible

| PADD | Number | Total Shutdowns | Share of 2000 Capacity | Average Size |
| --- | --- | --- | --- | --- |
|  |  | (MB/CD) | (Percent) | (MB/CD) |
| 1 | 7 | 81 | 4.8 | 12  |
| 2 | 12 | 361 | 10.0 | 30  |
| 3 | 19 | 298 | 4.0 | 16  |
| 4 | 3 | 58 | 10.7 | 19  |
| 5 | 14 | 400 | 12.9 | 29  |

**Refinery Shutdowns 1990-2000**

**Source: EIA**

**Notes:**
Both demand and capacity changes will vary among regions.  PADD 2, for example, provides an illustration of some of the dynamics among supply sources.  

Historically, the Midwest (PADD 2) has seen the largest volume of shutdown capacity except for the West Coast.  The average size of the shutdowns in the Midwest has been the largest.  

With the recent opening of the Centennial Pipeline and the expansion of the Explorer, we are seeing even more shutdowns in the Midwest.  Last year, Premcor closed the 80 thousand barrel per day (MB/D) Blue Island refinery, and recently announced the sale or closure of the 64 MB/D Hartford refinery.  The closure of the Hartford refinery may very well have been influenced by the Centennial’s startup.

The California market has been tight historically, but as they move to ban MTBE, it will likely become even tighter.  The Longhorn pipeline could provide some relief as the supplies it might bring to the Arizona market could free up California capacity for its clean gasoline.  Yet, the difficulties in building and opening a new pipeline have been illustrated by the long process Longhorn has been experiencing in overcoming objections by various groups.

## Potential Light Product Volume Changes 2000 - 2007

**Note: Light products are gasoline, distillate & jet**
**Source: EIA**

**Notes:**
To lay the groundwork for the inter-PADD dynamics, we began by looking ahead at a scenario in which MTBE is still being used.  First, the East Coast growth in light product demand will likely be met by growth from all three supply sources – East Coast refinery production, imports, and shipments from the Gulf Coast.  
In this case, imports of finished products into PADD 1 provide the largest supply increase, growing about 350 MB/D over today’s finished product imports of 420 MB/D.  Significant gasoline and distillate imports are needed.  Since distillate demand growth is mainly on-highway diesel, this becomes a concern as we move to ultra-low sulfur diesel. Will those imports be there at a reasonable price?
But net receipts must also increase by over 200 MB/D.

PADD 2’s demand increases will be satisfied both by growth in its own capacity as well as growth in product flow from the Gulf Coast.  If this scenario is correct, the Centennial and Explorer Pipelines expansions are needed.  Net receipts in this case grow by over 200 MB/D from 2000, which would account for most of this new pipeline capacity.  
PADD 3 is supplying that extra growth in PADD 1 and 2 as shown by large growth in production and the negative net receipt bar (i.e., shipments from PADD 3).  
PADD 5 is able to meet its demand growth to a large extent with growth in its own refineries, although there are a number of refineries in that region that cannot expand much further due to land and environmental constraints at the refinery locations..

This balance leaves the refining system running at about 93% utilization in 2007, similar to what was needed in 2000.

## MTBE Ban Refinery Impacts

_**LOSS OF GASOLINE YIELD**_
**Substitute Ethanol for MTBE**
**But Only Need Half As Much Ethanol for Same Oxygen**
**Remove “Light Ends” to Keep RVP Down**
**Remove “Heavy Ends” to Keep DI Down (CA)**

_**BALANCE BY INCREASING:**_
**Crude Oil Throughput (utilization increase)**
**“****Outside” Clean Streams (Iso-octane, alkylate)**
**Volume of Ethanol Used**
**Product Imports If Available**

**Notes:**
The situation shifts significantly in a future without MTBE.  Refineries using MTBE to produce RFG will not be able to produce as much RFG per barrel of crude oil used.  That is, they will experience a loss of yield.  The yield loss comes about for the reasons shown on this slide.
There is a net loss of oxygenate volume, which comes from “outside” the refinery.  If, for example, the oxygen requirement for RFG is maintained, only half as much ethanol as MTBE is needed to provide the same quantity of oxygen in gasoline.  
But ethanol has a much higher blending RVP than MTBE, so when it is added to gasoline, other high RVP components (i.e., the light-weight molecular components) must be removed to compensate.
In the case of California, some heavier-weight molecular materials must be removed to maintain the distillation requirements.
This results in a net loss of volume of gasoline produced per barrel of crude oil being run.

So how will this be addressed?  By some combination of the following:
Refiners might find it economic to run more crude oil and increase capacity utilization. 
The loss of MTBE also means a loss of octane, and there will be a need for some additional clean, high-octane products like iso-octane and alkylate that will come from feedstocks previously used to create MTBE.  
Refiners may also find it economic in some areas to increase ethanol volumes.
And last, if they are available, increased imports might help to fill the gap, but will those imports be available?

## RFG & Blending Component Imports May Not Increase

**Source: EIA**

**Notes:**
RFG imports may not be readily available in the future.  We are expecting a slow down in the availability of RFG and blending components used to produce RFG over the next several years.  This is mainly due to changes in regulations in Europe, one of our biggest import sources for gasoline on the East Coast.  

Different European countries are putting in place at different times tax incentives to produce low sulfur gasoline and diesel.  This allows refineries to “cherry pick” their clean streams to produce product for those markets with the incentives.  This can be done in many cases without making large investments.  This market for clean fuel streams will make U.S. RFG markets less attractive, without some significant price increases.  This graph assumes those U.S. price increases are not there to attract the RFG.

The implication is more RFG may have to come from the Gulf Coast.  Last year, gasoline imports to the East Coast supplied about 22 percent of East Coast gasoline demand.

The situation worsens should an MTBE ban be put in place.  Foreign refiners have similar production capability losses when producing RBOB for blending with ethanol to produce RFG as U.S. refiners experience.  Some foreign refiners may have no incentives to make the required refinery adjustments to produce RBOB.

## Illustrative MTBE Ban ImpactsLight Product Volume Changes 2000 - 2007

- Production

- Net Imports

**Notes:**
Now I will discuss an MTBE ban scenario.  The scenario has optimistic import assumptions.  In this case, we assume the United States is able to get some increase in RFG imports in the future without an MTBE ban, and then is able to maintain that increase to some extent under an MTBE ban.  The import situation is shown in the graph at the left.

Under an MTBE ban, we expect to lose gasoline production capability, which, in this scenario, results in a net light product production decline in both PADD 1 and PADD 5 where RFG demand is concentrated.  

In the MTBE ban scenario, we had to increase refinery utilization to its maximum.  This shows up as more production in PADD 3 refineries to help supply both the East and West Coast demand.

PADD 2 refineries are already using ethanol and thus don’t suffer the decline in volumes when MTBE is removed.  In fact, the incentive will be there for them to run at higher utilizations to free up PADD 3 volumes for flows to PADDs 1 and 5.  

To meet demand, we have to assume more imports are used than may actually be available at a reasonable price, and we have to run the system are very high utilizations.  

## Illustrative MTBE Ban Impacton Net Receipt Changes 2000 - 2007

**Note: Light products are gasoline, distillate & jet**
**Source: EIA**

**Notes:**
Volume flows between PADD’s will change only slightly due to the fact that refineries are only able to increase utilizations marginally.  

PADD 1 needs more product, while PADD 2 could need less.

PADD 3 would need to ship more product out both to the East Coast as well as to the West Coast, which, in an MTBE ban world, will need more gasoline components.  That leg of the journey may be assisted by the Longhorn pipeline.

## Conclusion

**Demand growth will continue to pressure supply**
**Refinery growth is expected, but tight markets produce varying regional balance dynamics**
- PADD 3 key incremental supply source
- Increasing flows to PADD’s 1 and 2
**MTBE bans could pressure distribution system**
- Loss of gasoline production capability
- Loss of imports
- More distinct products to move
- Increased inter-PADD movements

**Notes:**
In spite of the temporary economic slowdown and the events of September 11, demand growth should remain strong enough between now and 2007 to keep refineries running at high utilizations.  

Refinery capacity is expected to grow, in spite of continued shutdowns.  The growth on the Gulf Coast will help to supply the East Coast and Midwest demand increases.

But several details are worrisome.  Will adequate ultra-low sulfur diesel capacity be available domestically to meet the growing diesel market?  Growing imports of diesel are also needed.  Import of availability of RFG or RFG components may be limited.  

Finally, MTBE bans worsen the situation.  A ban results in a loss of refinery capability to produce gasoline.  The number of factors that must fall into place – apart from the distribution system issues of using ethanol – is complex.  Pipelines may not only have to move more volumes, but carry a greater number of products as well.  In an environment where capacity is already running at high utilizations, there is an increased potential for price volatility

Assuming the pipeline system is able to overcome the ultra-low sulfur diesel transport issues, more product flows are going to be needed between now and 2007.  PADD 2 may have recently resolved some of this need with the opening of the Centennial pipeline and the Explorer expansion, but much will depend on the economics of the marginal refineries remaining in PADD 2 relative to Gulf Coast refineries.