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SThis past year has been unusual for petroleum markets, and it raises the question as to whether 2004 might be an indicator of what lies ahead.
SThis talk will explore what happened in 2004 to try to answer the question posed in the title; however, as these quotes illustrate, history can provide clues, but not necessarily a clear vision. 
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SThe historical clues that we are seeking are the main drivers at work behind the price dynamics in 2004.  All too frequently, we have a laundry list of possible factors affecting the market without a good understanding of what were the most important market drivers.
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SOnce we have the most important price drivers, we can begin to determine the potential for future change in prices, differentials and margins. 
SThe three variables shown on this slide affect refiners’ financial performance, and thus affect investment plans.  While high crude oil prices affect feedstock costs, the high margins and light-heavy price differentials are primary incentives for adding refinery capacity. 
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SThe balloon helps to remind us that, while such prices and margins are currently up, the path will eventually return to earth.  But will it be after a trip round the world or simply after a two hour tour?
SIn 2004, crude oil prices almost doubled from 2003, rising from about $30 per barrel at the end of 2003 to peak at $56.37 on October 26. 
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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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SPrices 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 to that low price 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 as demand grew in the face of OPEC production discipline. 
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SIs the 2004 run-up a harbinger of a new, even higher level, and what is behind this latest increase in price?
SThe year 2004 brought not only high crude prices, but also high light-heavy crude price differentials.
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SThe wider the difference in quality, the wider the price spread.  Thus, WTI-Maya has the widest price spread and West Texas Sour has the smallest spread. 
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SNote that, like crude oil prices, the light-heavy price differentials showed different behavior after 2000 than during the 1990’s, which is not a coincidence, as will be discussed later.
SLast, margins also increased in 2004.  This graph shows a surrogate for refiners gross margin.  It simply measures what price refiners received for gasoline and distillate fuels compared to the price they paid for crude oil. 
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SDuring the 1990’s refining was not a particularly good business in which to invest.  Actual financial margins and returns were low. 
Many large integrated companies reduced their refining assets, choosing to be net purchasers of product and putting their investment dollars in places where they could earn a higher return.
Some independent  refiners (those without upstream assets), however, chose to grow, both by purchasing assets from integrated companies and expanding capacity in their existing facilities. 
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SSince 2000, the petroleum market has tightened, and with the exception of 2002, returns were better than in the 1990’s.  This is leading some refiners to see a better financial future than previously.
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SHowever, there is much uncertainty about the future.  As this graph illustrates, the increase in spreads came as a result of price volatility rather than smoothly. 
SThe remainder of this presentation will explain the increases in prices, margins and differentials by addressing four questions, beginning with what was behind the crude price increase this past year.
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SThat will be followed by a discussion on the major drivers behind light-heavy crude oil price spreads in 2004.
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SAs the third bullet indicates, the next section will explore the role that refinery capacity and the extra volumes of heavy crude oil may have played.   In 2004, concerns were raised that a “mismatch” between the type of crude oil available and refinery capacity to use that crude oil was having significant price implications.
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SAnd finally, the presentation will explore refinery margins and what all of these findings imply for the future.
SCrude oil prices in 2004 rose dramatically due to tightening in the fundamental balance between supply and demand.
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SHowever, some different fundamentals were at work in 2004 that we don’t usually see.
SThe first major factor tightening 2004 world supply/demand balances was demand growth, which grew much more than anticipated by most analysts.  China was probably the biggest surprise, as it grew by 1 million barrels per day from 2003, compared to 0.4 million barrels per day between 2002 and 2003.  China and the US combined, account for almost 60% of the increase in demand in 2004.
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SOn the supply side, growth in non-OPEC supply fell well short of meeting world needs in 2004, and is expected to continue to fall short for the next several years.
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 (0.5 million bbl/d of the 0.9 million bbl/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, 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 million bbl/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 increase significantly, and as I will soon show, the surplus capacity ready to meet this demand shrank considerably in 2004, and for the next 2 years, EIA sees the world balance remaining relatively tight.  
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SAs 2004 unfolded, analysts were watching inventories, which measure the balance between supply and demand, for signs of changing market tightness and thus price movements.
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SInventories were low for the first half of 2004, indicating a tight market, but they were not lower than seen in 2000 or 2003.  Furthermore, 2004 inventories recovered towards year end before falling sharply again.  Yet, 2004 prices rose higher than in either of those prior years.   
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SWhat was different?
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SOne difference is the shift in China’s demand.  China’s statistics lie outside of OECD.  It  is possible that some of that market pressure was not reflected adequately in OECD inventories. 
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SThe second difference occurred on the supply side, which is shown on the next slide.
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SPerhaps the most interesting supply-side change in 2004 from recent years was the change in 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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SThe graph 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 about 1.6-2.0 million barrels per day of extra production capacity – a level seen during the first Gulf War and briefly after the Venezuelan strike and the Iraq war in 2003, and a level considerably less than the 3 million barrels per day or more that has existed for most years since the first Gulf War.
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SThis lack of capacity surplus is a fundamental tightness.  Note that the surplus started to settle at about 2 million barrels per day in 2003 before demand required OPEC to increase production, which dropped surplus capacity to below 1 million barrels per day for much of 2004 before rising again as OPEC was able to pull back on production.
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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 about  $10/barrel as surplus capacity drops from about 2 million barrels per day to where we were during much of the second half of 2004 at about 0.5 million barrels per day.
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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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SWhen surplus crude oil production capacity is taken into account along with inventories, the model explains most of the variation in crude oil prices (to within $3-$5).
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SThus, very little is left to be explained by other factors.  It is interesting to note that statistical shifts can be detected at two points, April 1999 and December 2003, which correspond to the general time periods when we visually see crude price levels shifting first from $20 to $30, and perhaps now to the next level.  OPEC’s change in behavior following the very low crude prices in 1998 can explain the first shift, but it is too early to tell how stable the second shift may be.
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SAs we look ahead, EIA’s forecast has the general supply/demand balance remaining tight and crude oil prices staying above $40 per barrel for the next 2 years.
SAnother important price change in 2004 was the increase in light-heavy crude price differences that occurred. 
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SAs the data came in for 2004, the main driver behind this rapid increase was not what many analysts were postulating.
SFactors affecting light-heavy crude price differences stem from three areas: crude market, refining, and the product market, each of which can vary in its influence. any one factor does not change alone.  The issue is to sort out the major versus minor influences in 2004.  EIA previously examined how these factors affected crude price differentials in different time periods.  (See URL below)
Shttp://www.eia.gov/pub/oil_gas/petroleum/presentations/1998/california_crude_oil_prices/index.html
SRegarding the crude market, one would expect the differential to increase if heavy crude oil supply is increasing relative to light crude oil supply.  Also, absolute crude price changes affect the light-heavy crude price differential through crude price’s influence on the product market, which will soon be described.  In fact, we will show that crude price increase is the largest factor influencing the differential market in 2004.
SGenerally refiners with the ability to upgrade the heavy ends of the barrel run their downstream upgrading units at or near capacity.  If additional heavy crude oil comes on the market, some refiners that buy the crude oil cannot run more heavy ends through their upgrading equipment, so they produce more residual fuel, thereby getting less product value from that crude oil.  This, in turn, means they will want to pay less for the heavier crude oil.
If crude oil price levels stay elevated for a sustained period, the depressed price of the heavier crude oils provides an incentive for more upgrading equipment in order to make better use of the “cheaper heavy crude oil” and decrease residual fuel production. 
But note the irony.  If enough refiners add upgrading, the demand for heavier crude oil increases and the “cheap” crude will no longer be so cheap.
SProduct markets reflect the value a refiner can achieve from their crude oils.  Product markets react both to the crude market and refiners’ actions, which will be described on the next slide. 
SThe remainder of this section of the presentation will demonstrate how the crude oil price increase was the primary driving force behind the rapidly increasing differentials in 2004.  But before we inspect the data, this chart was drawn to illustrate the mechanism of how crude price affects product values, which in turn affect light-heavy crude price differentials.
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SAs crude oil markets tighten, price increases and the prices for light products increase as much if not more. 
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SResidual fuel prices, however, do not increase as much as crude oil prices, since this fuel competes with other boiler fuels. If the prices of these substitute fuels are not rising as fast as crude oil prices, then residual fuel prices will not increase as much as crude oil prices.
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SAs light products rise relative to crude oil and residual fuel declines relative to crude oil, the value of crude oils that yield higher fractions of light products will increase relative to heavier crude oils that yield more residual fuel and less light product volumes.  Thus, light crude oil prices increase more than heavy crude oil prices and the light-heavy crude price difference grows.
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SThis graph shows the relationship between crude oil price and prices of light and heavy products as represented by No.2 fuel oil and residual fuel oil prices.
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SIn 2004, residual fuel price increased only a small fraction of the amount that crude oil and light product prices increased.
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SThe high valued products like distillate rose as fast or faster than, crude oil price.  As a result the difference in price between distillate and residual fuel increased.
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SBut this graph still does not easily show the relative movement between that light-heavy product price difference and crude oil.
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SThis chart depicts the light-heavy product price spread explicitly, highlighting the correlation with crude oil prices.  This view shows that light-heavy product price movements in 2004 were consistent with historical movements of crude oil.
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SThe slide also shows both U.S. light-heavy product spreads and Northwest European product spreads to illustrate that this product behavior behavior is not just a U.S. issue.
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SThe light-heavy crude oil price differential also has some relationship to crude oil price.
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SWhile the crude oil price differential in this slide uses Maya crude oil, which is a less attractive crude oil than WTI due to its low gravity and high bottoms content, the general relationship holds for other light-heavy crude oil spreads as well.
SNow we put the light-heavy product price differential on the same graph as the light-heavy crude price differential.
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SNote that even though these differentials generally move together, since 2000, the product differential frequently moves ahead of the crude price differential, which illustrates the important feedback of product values to crude price differentials. 
SWhile the preceding slides focused on what seems to explain the light-heavy crude oil price differential, we have not specifically addressed the role that the refinery capacity element might have played, which is the third question on the list. 
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SThis is the question that asks, was there a mismatch between refiners’ ability to process the available supply of heavy crude oil in the market?
SIn this section, we will explore a different view of what has been behind the rapid increase in light-heavy crude oil differentials in 2004.  This view attributes capacity constraints – both distillation and conversion capacity -- as the main drivers behind the high light-heavy price differences.
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SThis issue is being addressed for two reasons.
 The first is that from a refiner’s perspective, understanding the drivers behind the 2004 light-heavy crude price difference will affect projections of the future behavior of that price difference – e.g., when will it fall and how much it might fall. 
The second reason is that consumers and policymakers are concerned over price effects of strained supply, and these theories may have placed too much emphasis on the relationship between refinery constraints and prices in 2004. 
SThe first theory to be addressed assumed that
Light product demand is still growing strongly, but
World refining capacity is being fully utilized,
In this case, the only way for refiners to meet increasing  light product demand would be for them to substitute light crude oil for heavy crude oil in order to improve the yield of light products. 
But additional light crude oil  is unavailable.  Only additional heavy crude  oil  is available.
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SThe consequences of this set of assumptions is that
As light product demand increases, since refiners cannot run more crude oil, inventories are drawn down sharply and light product prices rise. 
As light product prices rise, they pull the light crude oil prices up more than heavy crude oil, thereby increasing the light-heavy crude  oil  differential. 
Furthermore, additional heavy crude oil placed on the market cannot be used, since refiners are running at full capacity.
SHow can we test the world refining capacity limit theory?  There are several ways. 
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SDid we see dramatic imbalances and price surges? 
In the past decade, refinery utilization in the U.S. and Europe has been high.  Occasionally, surges in demand have exceeded supply for short periods (1-2 months).  During these times, inventories dropped much more rapidly than normal.  During such times, product prices spiked relative to crude oil prices.  That did not occur in 2004.
Light product inventories (gasoline and distillate) in the U.S., Europe, and OECD Asia started 2004 at the lower end of their typical ranges, but no significant draw down occurred relative to normal seasonal changes.  That is, production of light products from refineries kept up with rising demand.
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SWere there any signs that incremental heavy crude oil production was not used?
As OPEC increased production of heavy sour crude oil, there  was no indication that this incremental production was not sold or that refiners were unable to process it.  Refinery input rose, and product demand was met.
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SFinally, was world refining capacity running at maximum utilization:  The next several slides will look at refinery capacity utilization in 2004 to explore any indications that world utilization was at its maximum levels.
SWhy did some analysts assert that we are out of refining capacity? In some cases, market observers made an inappropriate comparison of world petroleum demand and world refinery capacity. Petroleum demand is met by natural gas liquids, other hydrocarbons and oxygenates that do not depend on refineries.
Everyone has been noting the increase in demand world wide, and in particular the unexpected jump in demand 2004.  Along with this increase, we naturally see increases in refinery utilization, which causes people to check how much refining capacity remains.
A balance of 83 million barrels per day of refinery capacity against 82 million barrels per day of oil product demand seems to imply a very tight situation.  But that demand includes products being supplied from outside the refinery system.  For example, the U.S. has over 20 million barrels per day of demand and only 16.0 million barrels per day of refinery inputs plus 1.4 million barrels per day 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.
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SHowever, while our view is more restrained than some other analysts that believe world refining capacity utilization is at its maximum, we agree 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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OECD countries, which have low demand growth; Japan has declining demand and refinery closures; Korea has low demand growth.
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High growth countries such as China and India, which have historically developed domestic refining to serve their needs and raised protective tariffs.
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Rest of Asia/Pacific with modest demand growth.
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The major export refinery center of Singapore, which we turn to next.
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SAs a product export center, Singapore 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 in the past 2 years, 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.
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SIn general, regional utilizations in 2003 and 2004 were not at all-time highs.  Refining capacity utilization in most regional markets reached a high point in 1998, and 2004 is showing lower utilizations.
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SAs just described, while Asian demand and utilizations have rebounded, the  utilizations in 2004 are below the 1998 peak levels.
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SOther regions listed on this slide show signs of increases in utilization in 2004 from 2003, but they also are not at maximum levels.
In the Atlantic Basin, utilization was up modestly in both the U.S. and Europe.  Data is not yet available for Latin America, but based on 2003 utilizations, 2004 utilizations will not be at maximum levels.
The Asian demand growth has likely increased utilization in the Middle East, but like the other regions, Asia was not at maximum utilization.
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SIn summary, we are not out of distillate capacity, but what about conversion capacity? 
SIf the assumptions on this slide are correct, then what would result?
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SIf refinery conversion capacity were in fact running at maximum utilization,  then the only way to increase light product production would be to increase refinery crude oil input. 
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SIf the conversion capacity had also been at maximum throughput, then residual fuel oil yield would rise as refinery throughput increased.  If  the added input were light crude oil, then the residual fuel yield increase would be small, but if the feed increase were mostly heavy high-bottoms-content crude oils,  then the residual fuel yield increase would be much larger.
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SThese assumptions might mean that some refiners would prefer more light crude oil because they could produce more light products per barrel of input and avoid large increases in residual fuel oil production. But how can we tell if refiners “only want more light barrels” or even mostly want light crude oil?  A higher price for light sweet crude oil relative to heavy sour crude oil does not mean that demand for light crude oil has increased or that refiners only want light sweet crude oil.  It does mean that the relative value of the heavy crude oil has diminished because of its higher yields of lower-valued products.
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S Keep in mind that, under these assumptions, refiners with or without bottoms conversion capacity are in the same situation.  They can increase light products production by  running more barrels of input, but neither can avoid additional residual fuel oil production.
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S To analyze the validity of the assumptions we need to look at refinery input and outputs in 2004, and particularly focus on residual fuel oil yields and production levels.
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SSome detailed data are available for U.S. refineries that helps provide insights into the affects of conversion capacity, and some helpful world data is also available.
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SFor the U.S., we can explore conversion capacity use, and what various U.S. refiners did, both in terms of crude oil mix and impact on residual fuel yields.  The theory would imply that such refiners would want to lighten their crude mix, and if they moved to a heavier crude oil mix, they would have suffered an increase in residual fuel yields as well as a potential decline in light product yields.
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SBut U.S. refiners may not represent the world situation, since U.S. refineries are the most complex in the world.  Worldwide, if an increase in heavy crude oil supply had a major impact on crude oil price differences due to refinery conversion capacity constraints, we would expect to see increasing residual fuel yields and perhaps additional evidence of an oversupply in residual fuel oil through stock increases.
SBefore looking at what U.S. refiners did in 2004, we need to illustrate a point that is misunderstood by many outside of the refining industry.  The conversion capacity constraint argument implies a world where refining capacity is divided into two types, heavy sour crude oil processors and light sweet crude oil processors. 
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SRefiners are not as constrained as to what type of crude oil they can run as this over-simplification implies.  It is generally true that more light sweet crude oils such as Brent, WTI and Louisiana Light Sweet are run in less complex refineries, and most of the heavier sour crude oils such as Mars, Saudi Heavy and Maya are run in more complex refineries. 
Note that the U.S. “less complex refineries” running light sweet crude oils are considered “complex” by world standards. 
These U.S. refineries virtually all have FCC units and some even have coking units, albeit small units relative to distillation when compared to refiners using heavy sour crude oils.
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SBut, as illustrated in this slide, many refiners in the U.S. run a wide range of crude oils from light sweet to heavy sour in their refineries.  These refiners will shift the crude oil feed mix as crude oil and product prices change. 
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SAlso note that much of the sweet crude oil is run in refineries that also process heavy and medium sour crude oils. 
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SThese exact mixes will change somewhat as economics change, which is illustrated on the next slides with some specific examples.  We will see that refiners were interested in more than just light sweet crude oils.
SWhat can we learn from U.S. complex refiners?  Did they try to increase light crude oils to maximize light product production?  Did they seem constrained in their heavy-sour crude use? 
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SThis chart explores one company’s crude oil shifts in 2004.  It illustrates the dynamics through 2004, showing how the system shifted to using heavier feedstocks as the incentive improved (i.e., the light-heavy price differential increased).  The data here are import volumes for one company that uses over 600 thousand barrels per day of crude oil in its refineries, each of which uses a wide range of crude oils. 
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SAs crude prices increased, and as the prices for light sweet crude oil increased faster than heavier crude oils, this company shifted to running more of the heavier crude oils. 
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SIn this case, the heavy sour crude oil refineries increased their use of heavy sour as well as medium sour, while backing down on medium and heavy sweet crude oils.  While this company’s refineries may have produced more residual fuel oil as a result, that loss in product value was apparently less than the savings on crude oil feedstock costs. 
SIn summary, this chart illustrates that:
The decision to use heavy sour crude oil is complex, with many crude-mix options  available for optimization. 
This company was able to use more heavy sour crude oil, implying the conversion capacity “constraint” was not necessarily getting in the way.
The increases in heavy sour crude oil use followed increases in economic incentives to use more as the light-heavy price differential grew in the latter part of 2004.
SThe next few slides will explore U.S. refinery behavior further in order to see if any effects of conversion capacity limitations can be detected.
SThis slide and the next  were designed to illustrate the versatility of refineries typically running both sweet and sour crude oil from light to heavy, and to illustrate the shift that occurred from  2003 to 2004. 
This information is a compilation of 9 refineries on the Gulf Coast that process heavy sour crude oils and represent about 1.8 million barrels per day of capacity. 
Now we are comparing imported crude oils for 2003 to 10 months in 2004, but these refineries were selected because nearly all of the crude oil inputs were from imports. 
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SOverall, these refineries moved to a somewhat heavier slate in 2004 than 2003, with average API declining slightly.
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SIf there were significant conversion capacity constraints, one would expect to see increased residual fuel yields and less light product yields for these refineries.  The next slide will show the actual yield patterns. 
SWith all the shifts that occurred, light product yields rose very slightly, and residual fuel yields only increased 0.5 percent. 
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SPart of  this was due to the ability of these refiners to increase their use of conversion capacity slightly during the shoulder months.  In addition, as just described, refiners’ use of crude oils is not simple, and complex refiners, such as those we have in the U.S., do have a fair degree of flexibility that they exercise by being able to use a wide range of crude oil feeds.
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SWe also looked at 8 sweet crude oil refineries (on both the Gulf Coast, Midwest, and East Coast), representing almost 2 million barrels per day of refinery inputs.  In this case, we saw some increase in the use of heavy and intermediate sweet crude oils in place of the light sweet crude oils.  But again, we saw only a slight decline in gasoline yield, which may have been due to increased MTBE bans this year as well as the crude oil quality shift.  Residual yield stayed at about the same level.
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SThe U.S. examples tell us that a) complex refineries have more flexibility to use heavy sour crude oils than the simple conversion capacity limitation theory would imply and b) U.S. complex refineries had enough flexibility to both use more heavy sour as the economics improved, but also to do so without much residual yield penalty.
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SThese examples have been for the U.S., where we have detailed data.  But the U.S. has the most complex refinery system in the world.  What about the rest of the world?
SThe detailed crude oil refinery input data that is available for U.S. refineries is not available for the rest of the world, but OECD data is available for refinery output of residual fuel oil and crude runs, which will help to explore if refinery capacity constraints had a major impact.
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SOutside the U.S., there is still a considerable volume of bottoms material in refineries that is not being converted to lighter product.  As a result, if the world crude oil slate had seen a significant decline in gravity in 2004, one would have expected residual fuel oil yields to increase.
The U.S. leads the world in residual fuel destruction.  Residual fuel production is only about 5%of total product production, but we still have some refiners without bottoms processing running some fraction of heavier crude oils and producing residual fuel. 
In Europe and in Asia there are many refineries with no bottoms processing and a number of countries that produce 20 – 30% of their product as residual fuel oil. 
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SThis graph shows that residual fuel oil yield did not increase, implying that the amount of heavy crude oil being added to meet growing demand was not enough to noticeably affect refinery yields, and therefore was probably not a major factor in determining light-heavy crude oil price differences. 
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SResidual fuel oil inventories climbed during the winter of 2003-2004 in both Europe and North America, while remaining flat in OECD Asia.
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SIn 2004, European residual fuel inventories built over the summer, but were drawn down by the end of December.
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SU.S. residual fuel inventories began 2004 at levels higher than in 2003, but declined through much of the year until fall, when a single-month increase in November brought them back up, before they continued to decline again. 
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SA large contributor to that U.S. stock build in November was a falloff in residual fuel exports, which points to other factors that were affecting Atlantic Basin residual fuel oil balances during the fall months.  For example, tanker rates were very high in the fall, which would have reduced  the incentive to move product outside the region to areas such as Asia. 
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SIn summary, even with increased production of residual fuel oil due to increased throughputs  of crude oil, residual fuel oil stocks do not show the kind of build that would indicate a flood of residual fuel oil into the market. 
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SStill, one could argue that perhaps this aggregate data is not sensitive enough to pick up the marginal impacts of the shift in heavy crude oils into the market.  But price, which is set by marginal players, should give us more insight.
SIf conversion capacity were the limiting factor in the market, refineries with and without such capacity would be running extra barrels of crude oil without benefit of conversion, thereby causing the marginal price of heavy crude oil to be set on the basis of a topping/reforming refinery, rather than a more complex refinery.  That did not seem to be the case in 2004. 
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SThe red line compares the product values derived from refineries cracking a light crude oil (Louisiana Light Sweet or LLS) to product values cracked from a heavy crude oil (Mars).  The difference in these product values is then compared to the actual price difference of the two crude oils.  The similarity implies that conversion units were not a major constraint.
While Mars crude (25% bottoms and 2% sulfur compared to LLS at 10% bottoms and 0.5% sulfur) is run mainly in U.S. refineries with coking capability, its price is being set on the world market by refineries that don’t have coking capability, since it competes worldwide with comparable crude oils that are being processed in cracking refineries.
The net result is that refiners having bottoms upgrading capability in this market will make better margins than those without, and as more refiners add coking worldwide, the narrower the differential will grow.
SConsider the case If world refiners had 1 million barrels per day more coking capacity (a 25% increase) at the beginning of 2004 than actually existed. 
About 10% less residual fuel oil would have been produced in the world market, but many refiners still would be producing 20-30% residual fuel.  Lower volumes of residual fuel  would likely improve price, but residual fuel oil prices would still remain well below crude oil prices as this fuel competes with other boiler fuels.  And heavy crude oils would still sell at a large discount to light crude oils.
As crude oil prices increased, that residual fuel oil would still have been an anchor in the short run.  Light product prices would have increased the same or even more than the $20-$25 per barrel, while residual prices would only have increased slightly.  The light-heavy crude oil price differential would have increased proportionally.
SAlthough conversion capacity limits did not seem to be a major factor in the 2004 runup, there is no doubt that many refiners wished they had more bottoms conversion capacity to reduce residual fuel yield in their facilities. 
STo summarize the last series  of slides, we illustrated how the 2004 light-heavy crude oil price difference increased mainly as a result of increasing crude oil prices. 
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SRefining capacity did not seem to be a constraining factor affecting the differentials in any significant way.  The U.S. complex refineries not only had a little more conversion capacity room, they were also able to increase their use of heavy crude oils while suffering little increase in residual fuel oil yield.  
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SThe theory that that lack of upgrading capacity in the face of increasing heavy crude oil  production is what drove the crude oil price differences up in 2004 is not supported by the data. The heavy crude oils were sold and processed; the residual yields and residual inventories did not reflect any large changes; and cracking refineries seemed to continue to set the price difference between light and heavy crude oils as they have been doing for several years -- all of which imply no significant conversion capacity constraints.  
SThe final section of the presentation will focus briefly on margins and what all of these findings mean for the future.
SMargins were high in 2004, probably getting a boost from crude oil prices as will be shown.
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SAfter that short discussion, the presentation will lay out what these observations may mean for the future. 
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SWe have seen margins increase in past years as a result of product market issues, such as a change to a new product specification.  But margins in 2004 likely received a boost from crude oil prices as well.   
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SAs crude oil market fundamentals tighten, product markets also tighten, which results in higher spreads.  The movements on this diagram show that, while spreads and crude oil prices frequently move together, the movements do not always coincide and vary in proportion, which indicates factors other than crude oil also affect product markets.
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SThis chart shows a simple 3-2-1 spread using a light crude oil.  But the increase in light-heavy differentials, which also stems from the increase in crude oil prices, gave an added margin boost to refiners with upgrading equipment using heavy sour crude oils.  For example, Thomas O’Malley stated that Premcor achieved an average $11.10 per barrel gross margin in heavy sour crude oils they processed compared to a $6.30 per barrel gross margin in light sweet crude oils. (Octane Week Feb. 21, 2005)
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SWill the long-term path settle at these higher levels?  As this graph shows, if the crude market balance softens in the longer term, both prices and margins could decline. 
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SGiven the close relationship in 2004 between margins, price differentials and crude oil price, the outlook for crude oil markets is key to determining where margins and differentials may go from here. 
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SIn the short run, higher crude oil prices may last for at least two years, based on EIA’s outlook for the crude oil market.
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SAlso note that differentials are not separable from margins.  Part of the improvement in U.S. margins stemmed from  many U.S. refiners’ ability to process heavy sour crude oil into light products. 
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SBut the longer term picture is not as clear.  Are the low margins of the 1990’s a thing of the past?  The longer term will be affected by industry’s reaction to 2004 and by how different world regions will evolve. 
While strong demand growth may continue in China, India and other developing areas, Europe and the U.S. may evolve differently.  Both price and policy can affect these growth patterns.
While fuel specification changes played less of a role in this year’s prices than in previous years, the future still holds more changes, such as sulfur content in products like residual fuel, which will affect investment decisions.
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SIn general, refiners will be facing decisions on not only increased throughputs, but also on gasoline vs. diesel product balance, changes in bottom-of-the-barrel processing, and continued product quality changes across the full product array.
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SAs we look ahead, 2004 may have encouraged more refiners to consider adding capacity.  It certainly should not have discouraged capacity investments. 
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SU.S. capacity has been expanding for the past decade, and is likely to continue to expand for 2 reasons.  First, improving margins in recent years have provided both capital and incentive for expansion; and second, the recent diversion of capital into the low sulfur fuels programs should be winding down, allowing companies to shift to expansion opportunities.
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SThis is not to say expansion will keep up with demand growth.  Gasoline imports grew historically because they provided a more economic alternative than domestic supply.  The European gasoline surplus is expected to grow.  However, changing U.S. production specifications tend both to diminish the available volume of product imports and to increase the price required to attract the required quality of product.
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SThus, incentives to expand capacity in the U.S. could increase as a result of an increasing price needed to attract imports.  In other words, U.S. capacity expansion decisions are influenced by world markets and associated world capacity changes.
SWorld capacity decisions will also likely be influenced by what occurred in 2004.  While world refining capacity in 2004 was not run at its total limit, utilizations have increased because demand has been rising faster than capacity.  The Asian capacity surplus has largely disappeared, with a few exceptions such as Japan.  China and India are straining to build capacity to keep up with demand growth.
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SThere is much activity emerging to increase capacity in Asia as well as in the Middle East.  The players include national oil companies, integrated majors,  and producing countries in the Middle East.  The producing countries are discussing adding refining capacity both in their own regions as well as in Asian countries. 
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SThe concern remains if the expansion projects will reach completion in time to avoid an exceedingly tight balance, with large price increases ultimately having to balance the market.
SAt $40-$50 per barrel, refiners with bottoms upgrading capacity are experiencing a more attractive profit margin than those without.  This will cause other refiners to consider adding such capability. 
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SThe United States has the least opportunities left for adding upgrading capacity without also expanding distillation, but there still are some opportunities.  Generally past expansions were done in conjunction with heavy crude oil producers. This same approach – teaming with heavy crude oil producers – may prove to be the favored strategy abroad. 
The high light-heavy crude oil price difference affects the heavy crude oil producers as well as refiners. 
In the past, many producing countries have participated with refiners in adding bottoms upgrading projects as a means of assuring that they have an outlet for their lower quality crude oils.  Thus, if their heavy crude oil is steeply discounted in the market, they may benefit from higher refining margins.  
SAsia may be the next major area for expansion in conversion capacity.  Demand is growing, particularly for the light products, and upgrading can help to meet that growth without adding distillation capacity.  Will more partnerships with Middle Eastern heavy crude oil producers accompany such changes?  Very possibly.
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SEurope may also see some changes, but demand is not growing much there.  In this case, refinery investments to better match demand might be the driver, with the need to destroy high sulfur residual fuel oil production as an important driver.  High sulfur residual fuel oil is becoming more and more difficult to market, and future limits on sulfur content of bunker fuels will only increase the difficulty.
SIn 2004, the tightening crude oil market and increasing price  -- not conversion capacity or distillation capacity – was the main driver behind high prices, high differentials, and high margins. 
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SIn the short-run, forecasts and risk analyses looking at differentials and margins should focus on what will happen to crude oil markets more than what will happen to refinery capacity.
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SThis is not to say we can forget about refining capacity needs.
SThe role of refinery capacity in explaining price behavior in 2004 may have been overstated by some analysts in 2004.   The world still has some extra capacity.
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SWhile the refining situation in 2004 was not dire, refinery capacity is an issue for the future since demand is outpacing refining expansion. 
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SHowever, market analysts should beware of over-simplifications that indicate additional barrels of heavy crude oil cannot be used or won't help the market due to some mismatch with refining.  The presentation tried to illustrate that the role of conversion capacity versus distillation capacity in meeting demand is complex when feedstocks are also taken into account.
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SIt is clear that new capacity worldwide will be needed, and "what" capacity (i.e., conversion, distillation, etc.) will be worked out by the industry.
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SIt is also clear that the focus should be on more refining capacity worldwide sooner rather than later.  That is, timing is a concern as demand continues to grow. 
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SWithin the United States, the petroleum product supply dialogue must deal with the rising importance of supply among the competing concerns of: security (capacity here versus abroad), environment (NIMBY, fuel specification timing), and supply availability. 
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SExplanatory Notes:
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SSlides 31-34
SThese slides were prepared by sorting the crude oil import data (Form EIA-814) for individual refineries into the following categories:
SLt Sweet Med+Hvy Swt   Lt Sour Med Sour Hvy Sour
SAPI=,>35   API<35   API>32 API 28-32 API<28
SThe data were aggregated with other refineries having some attributes in common. Slide 31 is based on all U.S. refineries reporting crude oil imports.  For slides 33 and 34, the import data were brought together with refinery input and product output data (as reported in form EIA-810) and with data on unit inputs for distillation, FCC, hydrocracking and coking (also EIA-810 data).
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SSlide 38
SOne line on Figure 38 shows the difference in the calculated total product value when LLS (Light Louisiana Sweet) is run in a cracking refinery on the U.S Gulf Coast minus the total product value when running a heavier Mars crude oil through the same refinery type. The lower value for Mars comes from the higher yield of residual fuel oil and lower gasoline and distillate yields as shown in the table below:
SRegion       Refinery Type Crude Oil              Refinery Product Yield (Vol %)
S          Petroleum Gasoline/           Gases        Naphtha         Distillates      Fuel Oil
SUSGC Cracking      LLS          -2.7              49.1                40.9                10.8
SUSGC Cracking      Mars         -0.4             43.4                 22.5               32.8
SNW Europe Cracking      Brent         4.7              42.6                 41.3               10.5
SNW Europe Cracking      Urals         3.9              37.3                 41.9               17.1
SSource: Purvin & Gertz foe IEA as reported in IEA Users Guide (2004 Edition)- 11 Aug 2004 pg 66
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SThe other line shows the difference in the spot market prices for the two crude oils. 
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