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SCrude oil prices this year surprised most analysts, rising from about $30 to nearly $50 in recent weeks. 
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SI am going to focus on what is driving this latest price surge and offer some views on possible future directions, followed by a discussion on what all of this may mean for the U.S.
SAs of October 1, WTI crude oil prices peaked this year at $49.76 on September 28, after having risen from about $30 in late 2003.
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SThis is a significant change from what we experienced in much of the 1990’s, when prices seemed to average close to $20 per barrel. 
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SAfter prices plunged to almost $10 per barrel in late 1998 as a result of the Asian financial crisis slowing demand growth just when extra supply from Iraq was entering the market for the first time since the Gulf War. 
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SOPEC reacted by pulling back production, and we saw prices not only recover, but increase to what seemed to be a new level of about $30 per barrel.
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SIs the recent run-up a harbinger of a new even higher level, and what is behind this latest increase in price?
SIn the next few slides, I am going to look at world demand and supply to see if they offer any clues to the high prices.
SThis graph shows annual changes in demand.  First, note that year-to-year changes in demand have generally been increasing since 1985.  The volumes have varied from as low as 0.1 million barrels per day (MMB/D) in 1992 and 1993 to as high as 1.9 in 1999, and averaging about 1.5% growth rate. 
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SMore recently, since 2000, growth has been about 1.3%, with volume increases around 1 MMB/D, except for the dip in 2002.   Volume increases were slightly lower than seen in the later part of the 1990’s.
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SAlso note that in recent years, non-OECD countries seem to be driving demand growth.
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SBut in 2004, demand is projected to increase by about 2.5 MMB/D or over 3%.
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SThis was a surprise to almost everyone – suppliers  and consumers. 
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SPart of the reason for the surprise is that a very large part of the growth came from China – an area about which we really know very little.  China’s petroleum demand increased almost 1 MMB/D.  (The U.S. was 0.4 MMB/D.)
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SChina’s growth is expected to slow, but as we look ahead, world growth is expected to remain relatively strong at about 2 MMB/D next year.
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SIn summary, two demand features stand out relative to the crude oil  price  increase this  year: surprise and very strong growth.
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SNow look briefly at crude oil supply.  Non-OPEC producers generally produce at maximum capability, and we see production has been increasing since the early 1990’s. 
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SOPEC, on other hand, adjusts its production in an attempt to maintain prices in the face of varying demand and non-OPEC supply. 
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In the late 1970’s and early 1980’s, the large crude oil price increase was accompanied with large demand declines.  In addition both the North Sea and Alaskan North Slope were showing large increases in production.
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OPEC reduced its production to keep prices from plunging too far in the face of falling  demand and increasing non-OPEC supply. 
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As demand began increasing again, OPEC was able to increase its supply.
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SIn the  most recent years, you can see OPEC decreasing production in 2001 and 2002, maintaining prices around the $30 level.  But last year and this year, production has increased in spite of the temporary loss of Venezuelan crude oil  supplies in early 2003 and the Iraq war. 
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SAs we look at the short term, we see strong demand growth with non-OPEC supply falling well short of meeting world needs.
The largest source of non-OPEC production increase is expected to come from the FSU, which is expected to contribute more than 50% of the non-OPEC increase in supply in 2005 (0.9 MMB/D of the 1.3 MMB/D increase).  This is one of the reasons the market reacted to strongly this past year as Yukos’ financial problems threatened FSU export volumes.
Africa, Canada, Mexico, Brazil and Ecuador are other major non-OPEC areas where  production increases are expected.
However there are no large new areas on the horizon that would  add 1  to 2 MMB/D of supply as the North Sea or the Alaskan North slope did in the 1970’s and 1980’s. 
STo meet demand, OPEC production must also increase significantly, and as I will soon show, there is little surplus capacity ready to meet this demand. 
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SThis picture hints at part of the reason for the large price increase this year, but we need to turn to the balance between supply and demand to see  if that offers any further insights.
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SWith surprising growth in demand, far exceeding non-OPEC supply growth this year, the added demand had to be met by OPEC production increases and volumes from inventories. 
SAnalysts usually watch inventories, which measure the balance between supply and demand, for signs of changing market tightness and thus price movements.
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SInventories have been low this year, indicating a tight market, but they have been no lower than seen in 2000 or last year at this time, and we did not see crude oil prices near $50 per barrel back then.
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SWhat is different now?
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SSeveral theories have been circulating about what may be the cause behind this year’s prices, some of which are shown on this slide.
SThe most interesting change is the world’s ability to surge crude oil production to either fill in for unexpected lost supplies (e.g., Venezuela or Iraq) or simply meet unexpected demand strength.
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SThis chart shows an estimate of surplus production capacity in OPEC.  Since OPEC is effectively the only area that maintains short-term surplus production capacity, it represents world surplus capacity available to meet unexpected changes in supply or demand. 
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SAt this point, we seem to have well under 1 million barrels per day of extra production capacity – something seen during the first Gulf War and briefly after the Venezuelan strike and the Iraq war in 2003.
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SThis lack of capacity surplus is a fundamental tightness.  Note that the surplus started to settle at about 2 MMB/D in 2003 before demand required OPEC to increase production, which dropped surplus capacity to current low levels.
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SThis chart shows the relationship between crude oil prices and surplus production capacity since 1999, or about the time we saw the shift in prices up to around $30 per barrel.
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SNotice that price rises almost $10/barrel as surplus capacity drops from about 2 MMB/D to where we are today at about 0.5 MMB/D.
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SEIA took a more rigorous look at the relationship among inventories, surplus capacity, and crude oil price.
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SFirst, we explored the relationship between world balance represented by inventories and price, and as expected, the model, represented by the blue line, falls short this year.  Many other analysts seeing the same thing began theorizing what might be driving prices up further.
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SWhen we take surplus crude oil production capacity into account along with inventories, we explain most of the difference (to within $3-$5), which is well within the uncertainty of the model.
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SThus, very little is left to be explained by other factors.
SStill I want to address some  of  the issues associated with a few of those other factors.
SOne of the problems seems to come from some market observers making a comparison of world product demand and world refinery capacity.  A balance of  83 MMB/D of capacity against 82 MMB/D of demand seems to imply a very tight situation.  But one needs to look more closely.  Petroleum demand is not just supplied by refineries.  For example, the U.S. has over 20 MMB/D of demand and only 16.0  MMB/D of refinery inputs plus 1.4 MMB/D of product imports.  Gas liquids and other hydrocarbons and oxygenates contribute more than 10 percent of supply volume.
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SIn order to see a reasonable picture of refinery utilization on a global scale and how that utilization might affect U.S. markets, it is necessary to look at regional refinery markets, since the refinery status in different regions can have different implications for U.S. imports.
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SHowever, while our view is  more restrained than some other analysts that state that world refining capacity is “maxing out”, it is correct that product demand is growing faster than refinery capacity in recent years, and the situation could become even tighter if high demand growth continues.
SThe largest changes in refinery utilization regionally seem to be in Asia, but Asia is not one homogeneous market.
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SThe Asian oil product market can be broken into four types of countries:
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S(1) OECD countries; Japan has declining demand and refinery closures; Korea has low demand growth.
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S(2) High growth countries such as China and India, which have historically developed domestic refining to serve their needs and raised protective tariffs.
 China, where growth has been most dramatic in 2004, has reported crude runs of over 6 MMB/D in recent months.
 At the same time, the latest source available to us reported a Chinese refining capacity of only 5.2 to 5.4 MMB/D, which means reported capacity is likely to be lower than actual.
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S(3)  Rest of Asia/Pacific with modest demand growth.
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S(4) The major export refinery center of Singapore. 
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SAsia has also been a net product importer and a major market for the export refineries in the Middle East.
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SSingapore, which is a major export center for refined products, has been somewhat of a bellweather for the Asian refinery market. 
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SThe Asian financial collapse in 1998 resulted in demand and refinery utilization falling in Singapore, but subsequent demand recovery resulted in utilization again growing last year and this year, approaching 1998 and 1999 levels.
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SBecause Asian demand also draws on supply from the Middle East, high utilization in Asia is likely to affect Middle Eastern refineries more than any other region. 
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SThere potentially is some spillover into U.S. markets.  California, which sometimes draws product from Asia, could see some higher prices as a result of the tightening Asian market, but most U.S. product imports come from the Atlantic Basin, which is described in the next slide.
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SThe Atlantic Basin reflects a “business as usual” picture when it comes to utilizations.
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SThe relationship between EU 15 oil product demand and refining capacity has shown little change since 1998, and concerns about global warming have created efforts directed at demand declines in the future.
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SStill, we see that utilization  has been high and continues at high levels in both Europe and the U.S.
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SIn general, increased refinery capacity utilization may be adding some product price pressure over and above crude oil, but it is not the cause of the large increase in crude oil  prices.
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SSome market observers have said that the increase in crude oil price is being driven by the fact that the latest increases in crude oil production have been mostly heavy crude oils, and heavy crude oils are the wrong crude oils to serve demand needs. They contend that what is really needed by refiners is light, low-sulfur crude oil, and that production of the wrong crude oil is driving up prices.
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SMy view is production of heavy crude oil increases the price difference between light and heavy crude oil, and that an increase in this price difference does not translate to a higher overall price.  In fact I argue just the opposite -- that high crude oil prices tend to increase the price difference apart from any increases in heavy crude oil production.  High light-heavy crude price differences do not drive higher prices.  The dynamics of situation are described on this slide.
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SHigher crude oil prices increase the price difference between residual fuel prices and prices for gasoline and distillate.  Residual fuel price is affected by alternative fuel prices and generally does not increase with crude oil prices.  That by itself, tends to keep the prices of heavy crude oils from increasing as fast as light crude oils.
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SIf marginal volumes of crude oil production are heavy, that further depresses heavy crude oil prices.
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SFinally, if refineries are running at high utilizations, one might expect yield of residual fuel to increase as conversion capacity becomes fully utilized, which helps to keep heavy crude oil prices lower than lighter crude oils.
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SBut those heavy crude oils are still used, and having those volumes is better than not having any increased volumes
SOne of the often-voiced theories for why crude oil prices rose so high this year has been the influence of speculators.
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SIn fact some observers have attributed speculative behavior as accounting for as much as half of the current crude oil prices. 
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SIf that were the case, one would have to argue that prices would be about $20 or $30 if speculators were not in the market place. 
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SOur analysis shows that is not the case.  As was already discussed, fundamentals do indeed support current price levels, and while speculators can have some effect on prices, they don’t seem to be the major factor behind this year’s increase.
SThis brings us to the question – how high might prices go and for how long?
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SThe answer may not be satisfying to many.  As is often the case, it begins with “It depends...”.
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SBut we can look at the underlying drivers to get a sense of what to watch for.
SWith continued strong demand growth and little surplus capacity readily available, EIA’s forecast in the short term is for continued price strength.  Some forecasters see prices returning to much lower levels sooner than we do.  Our forecast continues to hover near $40 through 2005 for  crude oil, with product prices keeping pace in their usual manner.  Needless to say, there is much uncertainty.
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SOn the down side:
 Future strong demand growth is expected in non-OECD areas, which are areas in which we have the least knowledge.   Could demand growth slow more than expected?  Certainly, but right now it looks like it will remain relatively strong.
The lack of surplus world production capacity is not something that gets resolved overnight.  The timing of new production capability is uncertain, and it is possible that more capacity could be put in place than we expect. 
SOn the up side:
Although world demand growth is expected to be less in 2005 than this year, it is expected to remain strong.  From what we do know about areas like China, even with higher prices, the need for petroleum will likely remain strong.  In OECD areas, the demand is driven by transportation fuels, which are less sensitive  to crude oil price changes than non-transportation fuel petroleum sectors.
The need for more crude oil production capacity cannot be resolved quickly, and is expected to remain an issue throughout the high winter demand season.  Although we may see some relaxation in the second quarter next year, if OPEC does not keep up production to re-build inventories when demand drops seasonally, the markets could remain particularly tight.   Relentless demand growth is expected to stay neck in neck with capacity growth for some time.
Last, high world refinery utilization slows re-balancing of the markets when extra crude oil production does become available, keeping pressure on product prices beyond when crude markets may begin to rebalance.
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SAs we look ahead, the issue is timing.
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SWe have continued demand growth expected – but how much? 
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SExtra crude oil production capacity will eventually emerge – but how fast will extra  capacity emerge?
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SAnd geopolitical risk remains.  In 2004, I argue that the geopolitical uncertainties affecting supply have been greater than they were in the middle of 2003.  After the strike in Venezuela, many people initially felt the country would return to normal operations faster than occurred.  After the war in Iraq, many felt that the country would return to producing oil on a regular basis faster than has occurred. And last, Russian oil supply security was not an issue. 
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SThe balance can swing to where prices relax back somewhat, but with current world demand growth and production expectations, it  is unlikely we would see prices drop into the $20-$30 range again soon.  Will they stay at $40 or higher? Or will they drop closer to $35?  That is outside of our crystal ball accuracy.
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SHow does all of this translate to the United States?
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SClearly crude oil prices mean higher product prices, but there are some other implications as well.
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SKeep in mind that with our own demand growing, we need new product supply sources.  Will these new supply volumes come from the United States or from imports?
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SI will touch on a number of import issues, and end with a summary of the price implications.
SDemand in the U.S. has been growing, driven by light product demand – in particular transportation demand.  (Residual fuel is about 4% of finished product demand, compared to 8% in 1990.)
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SThe expected light product demand increase this year is close to 400 thousand barrels per day, and is expected to be about 300 thousand barrels per day next year. 
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SLooking ahead, if total petroleum demand increases about 1.5% annually over the next 5 to 10 years, as we have experienced historically, we will need on average about 250 thousand barrels per day of new capacity each year in the U.S. or added volumes from imports to meet that demand growth. 
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SSo where might that supply come from?
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SUntil relatively recently, supply increases could come from the U.S., since we had excess refining capacity.  However demand caught up with U.S. refining capacity about the mid 1990’s.
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SSince that time we have seen increases in capacity.  In the last 10 years, capacity has increased about 1.9 MMB/D, or on average about 190 thousand barrels per day each year, which is equivalent to about one medium sized refinery each year. 
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SBut that expansion has not been even.  During the last few years, capacity expansion slowed, probably due to several factors, such as:
Resource constraints as refiners direct both dollars and resources to the large changes that must be made to accommodate the low sulfur fuel programs; and
Availability of economic product imports.
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SIn addition to distillation capacity expansion, we also have seen expansion in units downstream from the distillation unit, which increases yield of light products.
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SBut has that expansion met U.S. demand growth, and will it meet demand growth in the future? 
SIn order to explore the extent to which domestic refining capacity has met demand, and its potential to do so in the future, I am going to focus on gasoline, because gasoline is probably the most critical product import.
SGasoline imports have become an essential component of US supply.  US refiners alone do not have the capacity to fully meet US gasoline demand during the peak summer months.
SCurrently, our expectations about refining capacity additions indicate that gasoline imports need to increase in the future.
SBut will that import supply be available?  To address this issue I will need to discuss:
The magnitude of gasoline imports;
Why imports have been a competitive supply source;
Future impacts of U.S. specification changes;
International supply/demand impacts.
SHistorically, capacity abroad has been very competitive in the U.S. gasoline market, as demonstrated by gasoline imports being a part of our supply even when refining capacity was in excess, and those volumes have grown, doubling in size since 1990.  
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SThis chart focuses on the increases in gasoline supply from domestic refineries and from imports.  From 1998 to 2003, the increases in domestic production and imports have been similar, with net imports comprising 56% of the supply increase and production supplying 44 percent. 
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SGasoline imports have probably been an economic source of supply as implied by refinery utilization being lower in all years from 1999 through 2003 than in 1998.
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SIn 1998, U.S. refining capacity utilization was at an historic high and very near maximum input levels during the summer gasoline season.  While utilization has been somewhat lower since then, only modest capability to produce more gasoline has existed during the summer period.  Moreover, refining capacity increases from 1995 to 2003 have not been sufficient to produce the increases in volume of gasoline sold in the United States.  As a result, gasoline imports increased. 
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SIn the next few slides, we are going to explore recent historical imports to gain some insights into what the future may bring.
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SNet imports of gasoline and gasoline blending components supplied about 8 percent of U.S. gasoline demand in 2003. 
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SThese imports come mainly to the East Coast, where they met 24% of East Coast (PADD 1) demand in 2003.
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SToday, we depend on gasoline imports.  During the peak summer months, they are about 1 million barrels per day, which is beyond our refinery system’s ability to produce. 
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SBut will these imports continue to be available and grow to help meet increasing U.S. demand?
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SGasoline import sources can be grouped based on several important attributes that help us to understand what may drive future imports.
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SThe US is a major market for the refineries in Atlantic Canada and the Hovensa refinery in the Virgin Islands, and to a lesser extent the Venezuelan export refineries.
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SWestern Europe has become a growing source of US gasoline as the US has been the market to absorb their excess gasoline production resulting from the growth of diesel demand in Europe.
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SThere are small volumes from more remote sources, but the economic relationship weakens as the distance between source and market increases and also where other markets are available to compete for the gasoline exports of the source country.
SAnother factor has entered the market that may affect future imports – changing product  specifications.  How might changing gasoline specifications in the United States affect the availability of imports from other regions?
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SSpecification changes raise the possibility of a shift of import source regions, as some areas are possibly eliminated by their inability to produce our new products.  We could even see a drop in total import levels.
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SFor example, U.S. sulfur constraints from Tier 2 gasoline requirements are expected to reduce the number of suppliers in the near term, because the United States is moving towards low sulfur product before many other regions do so.
S- Europe is relatively close to U.S. standards, and its exports to the United States may not be limited by sulfur.  In fact, with its tax incentive programs, gasoline being sold in some European countries today has lower sulfur content than U.S. requirements.
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S- South America generally is producing gasoline with higher sulfur levels than in the United States, and that is not expected to change soon.
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S- Asia is moving to lower sulfur levels in some countries, but still has higher sulfur specifications in many regions.
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SRegional specification changes, along with knowledge of the origin of our imports can give us a clue as to how the U.S. specifications may be affecting imports this year and in the future. 
SThe major sources of imports come from Canada, Virgin Islands and Western Europe, all of which should be able to meet our sulfur specifications, but some changes in the supply sources are occurring this year.
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SBrazil and Other Latin America volume showed declines this year, as was expected from  the sulfur regulation changes.  Eastern Europe is hard to interpret.  It was down this year, which may reflect lack of low sulfur product, but this region should be getting closer to E.U. specifications over time.
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SAs some regions fell back, Western Europe volumes to the United States increased.
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SEarly in the year, imports were behind last year’s volumes, but strong summer imports made up the gap.  We don’t know if the early weakness was due mainly to specification issues or to the strong world demand increasing competition for available imports and driving prices to less attractive levels. 
SNow we turn to another specification change – MTBE bans.  MTBE is used mainly in reformulated gasoline (RFG) to meet the Federal oxygen requirement, reduce air emissions, and add octane.  However concerns over MTBE’s potential to pollute water resulted in a number of States banning its use.
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SIn addition to sulfur reductions, New York and Connecticut banned MTBE this year, which raised concerns over how their sources of RFG supply might shift.  Historically, over half of the RFG used in New York and Connecticut came from imports.  Reformulated gasoline required in those areas now is produced by providing low-RVP RBOB in the summer months that is blended with ethanol locally before being distributed to retail outlets. 
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SThe New York and Connecticut transitions were highly successful with little transition impact to consumers, in spite of very large supply and distribution system changes.
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SThe pie chart on the left shows domestic and import RFG supply sources for these two States in 2001.  About 44% of the two States’ RFG needs were met by refiners on the East and Gulf Coasts (PADDs 1 and 3).  In fact, most of the domestic product was being met by East Coast refiners.  About 1/3 (34%) of the RFG was coming into New York and Connecticut as blending components, and 22% was arriving as finished RFG
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SWe expected the Finished Imports to be replaced with RBOB, but to our surprise, much less volume has arrived as RBOB.  Some blenders indicated they were blending their own RBOB from components imported separately.  Only 10% of the two States’ RFG needs were being met with finished RBOB.  Imports of blending components and RBOB have now fallen to 47% of the total gasoline needs from 56% in 2001, while domestic volumes increased.  It also seems that more volume is coming from the Gulf Coast  to New York and Connecticut than has been the case for quite some time.
SWhat about future import volumes?  In both the case of sulfur reductions and MTBE bans, Western European volumes have been an important source of products.  Will Europe be able to continue to supply increasing volumes?
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SLooking back, the United States has benefited from Europe’s dieselization program.  As Europe’s dieselization program evolved, demand for diesel fuel grew faster than gasoline, and Europe’s refineries produced more gasoline than the region could use.  This provided an economic source of supply for the United States
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SEuropean diesel demand overtook gasoline demand after 1995, and is expected by many forecasters to continue to outstrip gasoline – even to the extent that gasoline demand might continue to decline for some time.
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SThis forecast shows the ratio of gasoline to diesel halving between 1990 and 2015, which has significant impacts for refiners, and is based on a continuation of the change in vehicles in Europe that has occurred historically.
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SThis implies more import volumes may be available from Europe as our demand increases, but will it be enough to both make up for lost suppliers as well as demand growth?  We really don’t know that answer to that question, but we have some reassurance that we may very well see some level of increasing volume availability..
SLooking at the larger import picture, this chart summarizes the factors that will either work to push gasoline imports up or down.
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SIn the short term, we expect imports to be available, but potentially at a less attractive price due both to loss of suppliers and to our need for cleaner or higher-value products.  World demand growth and competition for those volumes will also add to price pressure.
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SAs always, transitions to new fuel specifications give rise to the potential for short-term supply problems as the market adjusts to the change.  We move to 30 ppm refinery average specifications in 2005.  Will we see some additional market tightening?  We still don’t know.  Credits and allocations allow suppliers to use higher sulfur imports, but the available supply sources may be even less than seen this year.  We will be watching this transition closely as we have the last several transitions. 
SClearly as crude prices rise and remain high, product prices will also rise.
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SBut as we saw this spring, light product prices, such as gasoline and distillates, frequently rise even more than crude oil.
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SThere are the usual seasonal increases, but there also is the tendency of higher valued products to move more than feedstock costs and the inability of the world refining and distribution system to adjust quickly to changing market conditions due to the fact that the system is working at relatively high utilizations. 
SThis slide shows how, as world crude markets tighten, light product prices frequently rise even more.  This is most evident with the gasoline crack slide on the left, which shows that the crack spread has risen as crude oil moved from that $20 level shown at the beginning of this presentation to the $30 level after 1999.  It also shows that higher crack spreads have not come smoothly, but in large part as the result of higher volatility.
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SWhen world crude markets tighten, product markets tighten as inventories for both crude oil and products fall in response to changing price signals.  Lower inventories result in less cushion to respond to unexpected imbalances, and thus increase the probability of price volatility.
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SBut tighter refining capacity in the United States and the growth in number of different fuel types since the mid 1990’s also add to the increased potential for volatility, since supply flexibility is reduced.
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SAs we now move into the winter, high distillate demand season, we see U.S. diesel and heating oil cracks increasing.  Although heating oil imports during normal markets are not as critical as gasoline imports, if the United States experiences an unexpected cold snap, European imports have been an important source of supply and price relief.  But European markets for distillates are also strong this year, indicating that any imports we may want to use will come at a higher price. 
SIn summary, we can expect price pressure not only from crude oil prices, but also from higher cost imports and even increased potential for price volatility.
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SIf there is a silver lining to this picture, it is that increased margins should eventually encourage more U.S. refining capacity expansion in the future.
SThe near term future is highly uncertain.  We are seeing an unusual tight world market where even OPEC does not have control over the situation with little surplus production capacity.
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SGiven the geopolitical unrest that exists, we continue to be subject to unexpected supply disruptions.
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SThe United States is going into the winter season with a supply gap caused by a devastating string of hurricanes. 
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SAnd even when the tight market begins to ease, high demand and high refinery utilization worldwide prevents the market from rebalancing quickly.
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SIn summary, timing to a more balanced market is highly uncertain. 
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