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SThis presentation will explore the changing environment for refining investments and product trade – which in one sense is simply an option for investment.
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SThe slides will be focusing on the Atlantic Basin market.  While we frequently only show data for and talk about the U.S., the market of relevance really is the Atlantic Basin – in particular Europe and the U.S., which function together as will be discussed.
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SIn particular, the presentation will explore the major drivers of investments and trade, such as
Demand growth – which drives the need for distillation capacity expansion
Changing mix in products, especially increasing distillate fuel and decreasing gasoline – which encourages changes in investment in refining units downstream of the distillation unit
Crude oil price and the light-heavy crude oil price difference – which impact feedstock changes
Margins or profitability – Ultimately, the bottom line determines if cash and adequate returns warrant investment – or on the other extreme – closures.
SI’ve chosen to discuss these topics from a time-line perspective, beginning with the longer term trends and outlooks seen in early 2007, then reviewing what the recent recession has done, and finally attempting to sort out what trends remain and what trends have shifted or seem to have experienced a kink sending it in a new direction.
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S This first section will focus on a number of important long-term trends as seen in 2007.  These trends involved demand, feedstocks for refiners, and refinery profitability – the major drivers for refinery investments.
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SIn particular, we had entered an era of rising crude prices and increases in the difference in prices between light and heavy crude oil feedstocks.
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SDemand growth and product mix were changing.
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SRefining margins had picked up.
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SAnd some significant policy changes were happening to shift towards more biofuels and increased energy efficiencies. 
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SCrude oil prices had been relatively flat – hovering just under $20 per barrel (nominal)  for many years from the mid 1980’s to 1997.  In 1997-98, they dropped with the Asian financial collapse and lack of OPEC cohesion, but OPEC rallied, pulled back production and prices climbed in 1999.
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SIn nominal terms, prices seemed to resettle in the $30-$35 range.  But in 2004, a large increase in demand driven mainly by growth in China started an increase in crude prices that no one had anticipated. 
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SDemand was outpacing supply, and excess crude oil production capacity dwindled.  EIA’s outlook early in 2007 showed price projections through 2008 around $65 per barrel, but with slow growth in crude oil supply expected, and seemingly unstoppable demand growth, there was much uncertainty.
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SIncreasing prices began to impact feedstock economics for refiners.  For example, Canadian oil sands looked more economic, and biofuels such as ethanol became more attractive.
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SWe now know what happened to prices in 2008, but that will be discussed more later.  As of 2007, price pressure was up.
SThe scatter plot illustrates the relatively strong relationship between crude oil prices and light-heavy crude oil price differences.  As the price of crude oil was rising, the prices of lower quality crude oils were increasing more slowly than the prices of higher quality light crude oils.  That is, the difference between light and heavy crude oil prices was expanding.  We expect the light-heavy crude oil price difference to expand when prices increase because of the way product prices change when crude price increases. 
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SA primary driver of crude price differentials is the product market. Refiners evaluate crude oils by what they can earn from the products the different crude oils produce.
Heavy crude oils contain more heavy bottoms material like residual fuel oil, which sells below the price of crude oil.  When crude prices rise, residual fuel oil price does not rise as much, since it competes with other fuels such as coal and natural gas. 
However, gasoline and distillate prices rise as much as or more than crude oil prices, depending on the tightness of the market.
Refineries that set the price of heavy crude oil produce a larger share of residual fuel from heavier crude oils than other refineries.  As a result, the price of heavy crude oils that contain proportionally more of this residual fuel. tend to rise more slowly than the light crude oils.  Thus residual fuel oil price acts like an anchor, slowing down the increase of the lower quality crude oil prices, and hence, the difference in price between the light crude oils and heavy expands.   
S As crude oil prices fell back to the $40 range, the light-heavy crude price differential fell back.  But in this plot, the scatter around the line indicates that the dynamics behind this relationship may keep the movements from being a simple relationship – even though we show a fitted line for discussion purposes.  Other factors also affect the light heavy differential, such as availability of bottoms upgrading capacity and the market availability of heavy crude oils relative to lighter crude oils.
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SOver the long term, petroleum demand has been growing, albeit differently in different regions of the world.   The developed nations are growing more slowly than other areas of the world, and that is true of the major Atlantic Basin consumers of the U.S. and Europe.
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SThe right-hand chart shows that some of the highest growth is in the rest of the world, with the large Asian economies of China and India now dominating much of that increase.   Being driven by economic development, Asian demand grows as it simply adds cars and trucks, even if those vehicles are the most efficient available.
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SIn 2007, petroleum growth had been robust, and high oil prices did not seem to be stopping demand growth. 
And it is worth mentioning that even after the effects of the recession took hold in 2008, the developing world is showing less impact on their growth than in the developed world. 
One of the unique features of this recession is that it may be the consumers in places like China that pull the world from this economic slowdown rather than consumers of the developed nations. 
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SIn addition to overall petroleum growth, product mix was also shifting, as will be covered in more detail shortly.  Generally distillate fuels, which include diesel, heating oil and jet fuel, have been growing at a higher rate than gasoline for some time – even in the United States. 
SFocusing on the Europe and the U.S., refining capacity was at very low utilization in 1985.  Utilization increased from the mid 1980’s to peak in 1997 as a result of refined product demand growth, refinery closures, and even some refinery capacity reductions.  However, refinery investments were still occurring to meet changing product specifications (e.g., low sulfur diesel, oxygenated gasoline, reformulated gasoline) and some changes in mix from gasoline to more diesel.
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SFor the decade from 1997 to 2007, capacity utilization in the U.S. and Europe ran at fairly high levels.  Although demand continued to increase, so did refining capacity, keeping utilizations at about the same level.  During that time, product price spikes occurred from time to time when low inventory levels met unexpected demand increases.  These price surges raised concerns that refinery capacity might be  inadequate to meet demand. 
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SDuring the 2005-2007 time period, refiners worldwide planned many expansions to meet the seemingly relentless demand increases.
SThe earlier consumption chart combined the U.S. and Europe, while this chart separates them to illustrate some important differences in fuel use that explain how supply has evolved in the Atlantic Basin.
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SThis picture shows the different mix of petroleum products for Europe and the United States and their changes during the twenty years 1987-2007.  The U.S. uses more gasoline than distillate fuels, while Europe is the reverse – using more distillates than gasoline. 
Europe’s concerns over greenhouse gas emissions have resulted in policies to reduce energy consumption by shifting from less efficient gasoline-fueled vehicles to more efficient diesel-fueled vehicles.  This has resulted in diesel demand increasing and gasoline demand falling. 
Although European penetration of new light-duty diesel vehicles may be leveling off, the fleet share of diesel vehicles is still well behind the new sales penetration rate, which implies the trends in demand will continue. 
The diesel and gasoline demand trends have resulted in Europe needing increasing distillate imports and generating increasing volumes of gasoline for export.
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STotal gasoline plus distillate fuel use has grown in Europe and the U.S., but has grown more in the U.S., which increased 31 percent over the twenty-year period shown, while Europe increased about 20 percent. 
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SMuch of Europe’s reduction in petroleum demand growth came from reduced use of residual fuel oil, which is a boiler fuel. 
SEurope, which represents more than a quarter of the world’s middle distillate demand, is a major factor behind the world’s shift from gasoline to distillate over the past decade.
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SSome of the Asian decline seen in this chart may be more an increase in naphtha demand for petrochemical use than of gasoline growth relative to diesel.  But the shift towards more distillate from gasoline is still not the dramatic shift seen in Europe
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S The U.S. also has distillate growing more rapidly than gasoline, but the degree of change is much smaller than that seen in Europe.  However, future shifts in U.S. petroleum product mix are expected to be larger than seen historically, as will be discussed later.
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SPrices have been reflecting product demand shifts.  This chart shows monthly spot price differences between heating oil and gasoline.  Diesel and heating oil prices move together, so the trends here reflect relative diesel price behavior as well.  
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SHistorically, heating oil and diesel prices remained below gasoline except during some of the cold winter months.  But in 2005, for the first time diesel prices stayed above gasoline during the summer months, and only reversed when Hurricanes Katrina and Rita interrupted supplies.   This was a harbinger of tightening distillate markets.   In 2006 and 2007 gasoline returned to typical pattern of rising above diesel prices during spring and summer months.  But during fall and winter, we also were seeing stronger-than-usual surges in diesel prices above gasoline.
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SIt appeared that world growth in distillate demand might finally be manifesting itself in price strength relative to gasoline.  While distillate prices stayed below gasoline, there was no incentive to invest in capacity like hydrocracking to produce more distillate rather than gasoline.  But this price shift in distillate was a signal that such investments might now look more attractive. 
SThe investment environment for refiners in general had picked up.  For much of the past twenty years, the refining industry has experienced low margins and returns. 
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SWhile companies were able to reduce their operating costs, competition and overall market conditions brought prices down with operating costs, keeping the net margins low.
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SRefining profits looked to be trending up since 1995, with a few exceptions.  Growing demand and shrinking surplus refining capacity during the 2003-2007 time period drove definite improvements.  Utilization was high, and even though refined product growth rates were modest, many felt more refining capacity was needed. 
While not shown in this chart, high margins for a given year frequently came as the result of an event like the hurricanes in 2005. 
Profitability for the year was the effect of a limited number of high profit months rather than a smooth general increase, which increases the uncertainty in predicting profitability.
SLight-heavy crude price differences were also expanding at this time, which contributed significantly to profit growth for refiners with the ability to upgrade the heavy crude bottoms. (The growing light-heavy crude price difference is sometimes referred to as the heavy, sour crude oil discount.)
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SOptimism about the future profitability of refining was increasing, and with the cash flow from increasing profits, many refinery expansion and upgrading projects were being planned.
SChanging trade flows are an option to investment.  The U.S. has seen that in our relationship with Europe.
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SHistorically, it has been more economic for Europe to export gasoline to the United States than to invest in shifting yields from gasoline to distillates.  The U.S. was a ready, relatively close market that paid enough for the gasoline to pursue this route.
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SAs Europe’s demand for gasoline declined, it needs to export more and more product.  Much of Europe’s increased export volumes in recent years have found markets other than in the U.S.
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SStill, large investment projects are planned in Europe and the U.S., which will be described later.
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SAs mentioned earlier, European gasoline demand has been declining, while distillate demand has been increasing as light-duty diesel-fueled vehicles continue to penetrate this market.  In 1995, the consumption ratio for middle distillates to gasoline and naphtha was 1.4.  By 2007 it had risen to 2.2,  and it is expected to increase further in the next 5-10 years. 
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SAs the table at the left shows, European refiners have increased distillate yield and decreased gasoline yield modestly over 10 years.  With European refiners having made the operational changes to maximize distillate production, further increases in distillate depend on new hydrocracker and bottoms conversion investments.
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SPast yield changes have fallen short of meeting the changing demand mix.  The result has been a growing increase in distillate imports and gasoline exports.  Distillate imports fell back in 2007, mainly as a result of a reduction in heating oil demand from milder weather, drawing down inventories, and less consumption for power generation.  Diesel demand continued to rise in 2007, and total distillate demand has again risen in 2008, causing imports to renew their upward climb.
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SGasoline exports from Europe increased almost 750 thousand barrels per day from 1998 through 2008.  The U.S. has been a good market for Europe’s excess gasoline, accounting for about 42% of the increase.
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SAfrica accounted for the next highest increase in volumes, covering 23% of the increase, with Mexico next at 16%. 
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SWhile we already provided some glimpses beyond what we were seeing in 2007, this slide steps back to focus on the refinery outlook concerns at that time.
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SAn issue being raised frequently was – will refinery capacity keep up with demand?  Can we build it fast enough.
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SU.S. refiners’ optimism was also still strong, and investment plans added up to about 1 million barrels per day of new capacity over a 5 year period, including some increase due to capacity creep (small increases in capacity that are made in conjunction with other projects).   But some issues were starting to develop.  Costs for construction were high, and biofuels use was increasing, causing some companies to pull back from projects.
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SEuropean refiners focused on investments to deal with their growing need for distillate fuels.  Many projects did not need crude distillation capacity expansion, although some did include increased distillation capacity – particularly in Southern Europe.  The projects being planned were generally upgrading projects that would reduce residual fuel production and increase distillation production, leaving gasoline production relatively unchanged. 
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SMost of the world’s capacity expansion plans were in the Middle East and Asia, where expansions were targeting the high demand growth of those areas primarily.  Upgrading projects were also being planned to make more use of heavy crude oils.
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SSo stepping back, in 2007 we were seeing a future with:
High crude oil prices, which in turn supported development of oil sands and more use of biofuels.
Policy changes worldwide that were supporting more biofuel use.
Petroleum demand still growing strongly.
Distillate markets expected to stay particularly tight.
Good refining margins for several years – and hopes for a “Golden Age” for this industry emerging
Refining capacity remaining tight in general, and a large number of expansion and upgrading plans emerging.
SYet some concerns were being voiced.  Were the expansion plans going to result in an over-supply of capacity?  The chart shows that at that time, the main capacity additions in the Middle East and Asia might exceed demand increases in those regions, but demand seemed healthy.
S2008 was unusual in a number of ways.  The first was an unusually tight distillate market.  It provided insights into the kinds of price behavior we could see from time to time in the future, and it showed us what U.S. refiners could do to meet increasing distillate needs without further investments.
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S2008 also came with the recession, which resulted in many market factors reversing. 
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SThe issue is attempting to determine what will rebound, and what has shifted permanently.
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SPrior to 2008, we saw that distillate prices had begun to show strength relative to gasoline.  But 2008 saw distillate rise to new highs relative to gasoline.   U.S. refiners had never seen such strong incentives to product more distillate and less gasoline.
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SIn 2008, strong international demand for diesel brought about by economic growth in emerging countries, along with some unusual circumstances created a very tight market. 
A number of regions were experiencing high diesel demand for electricity generation, such as in Latin America, where droughts diminished hydropower, and natural gas supply  fell . 
China  also  imported extra diesel, in part to provide adequate supplies for the Olympics and substitute power after the large earthquake. 
And Europe needed extra ULSD in 2008 as well.   
SIn 2009, the strong market for diesel relative to gasoline disappeared.  Both are now weak.  Gasoline demand has been affected less by the recession, and its price now exceeds diesel price in the United States and at times in Europe. 
SOne of the most interesting outcomes of the strong distillate market in 2008 is what it told us about U.S. refiners, and what they might be able to do in the future.
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SU.S. refineries have in the past been run to produce gasoline, based on the large U.S. demand for gasoline compared to distillates.  With the strong distillate incentives in 2008, we began to see how much more distillate U.S. refiners could make basically through operating changes. 
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SDistillate yields started out 2008 at typical levels, but during summer 2008, gasoline margins were sometimes negative, and distillate margins were very high.  Once refiners became convinced that this high-margin distillate picture was going to last some time, refiners began focusing on shifting to higher distillate yields at the expense of gasoline, which had surplus supply (as evidenced by some very high gasoline inventories).
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SIn the summer months of 2008, the average distillate yield increase compared to 2007 was about 3 percentage points, and even from October through December, when distillate yield would be at its normal seasonal maximum, the increase was still over 2 percentage points higher than the prior year.
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SAs 2009 began, distillate yield remained high, but distillate demand was plummeting, and the export market was also loosing its luster.  It took until June for refiners to reverse this shift to higher distillate yields, and the higher U.S. distillate production has contributed to the high distillate inventories in this country as well as in Europe.
SThe prior industry slide masks some extraordinary refinery operations. Individual refiners accomplished some very large yield shifts away from gasoline and into distillate simply through operating changes.  This chart shows the average yield shift for individual refineries in PADDs 1, 2, 3 and 5 for May to August in 2008, compared to the same months in 2007.  The table only shows refineries that did not have any major unit outages during those months in both years, although in a few cases, the change is based on only 3 months.
SThe most important observation was that yield shifts were across a wide range of refineries.  We explored various refining dimensions to see if certain refinery variables favored yield shifts more than others.  Differences were modest.  The shifts occurred:  
In refineries operated by all companies,
In all regions of the country
The largest shift was in PADD 3 which showed distillate yield up +5.0 percentage points , and gasoline down -3.5.
In refineries of all complexity
The yield shift for less complex refineries (FCC only) averaged +3.1 percentage points of distillate and –2.0 of gasoline, compared to +5.3 percentage points of distillate and –4.6% of gasoline for FCC plus coking refineries, and +4.7distillate, -3.2% gasoline for refineries with FCC, coking, and hydrocracking.
In refineries running from light to heavy crude oil,
The greatest shift occurred for refineries running intermediate gravity crude oil (32-35°API)
In refineries with different starting gasoline-to-distillate ratios
The distillate yield increase was slightly greater for refiners with higher initial gasoline/distillate production ratios.
SWhile the distillate market was going through the unsually tight situation in 2008 just described, the recession was underway.  The recession officially began in December of 2007, but petroleum demand in the U.S. and Europe did not plummet until the second half of 2008.  Across the year, U.S. gasoline demand dropped 3.2% annually in 2008 from 2007, and distillate demand fell 5.7%.
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SThis chart compares 2008 and 2009 for the U.S. and Europe.  While both regions show declines, there are some distinct differences.  In the U.S., the gasoline decline seems to have slowed, and for the year, we expect demand to grow slightly in 2009 over 2008.  Distillate demand, on the other hand is still expected to drop significantly by 8.4%.  Distillate demand in the U.S. is used mainly in the heavy-duty trucking sector, which is hit hard with a slow economy since there are fewer goods to be moved.
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SEurope, on the other hand, is seeing a larger decline in gasoline and less in distillate.  This is the result of the continued move to use more distillate in the light-duty fleet.  That is, Europe’s distillate market contains light-duty vehicle use, which is less subject to economic declines than the commercial heavy-duty use.  This is cushioning the distillate decline compared to distillate use in the U.S.
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SThere still is much uncertainty as to when and how much of a rebound we will see in product demand.  But we may see European distillate growth return to positive numbers sooner than in the U.S. as a result of its light-duty vehicle use.  But the rebound may be slow in coming.  While EIA is forecasting improvement in the U.S. economic situation in 2010, with U.S. total petroleum demand increasing over 2009, total demand at 19.09 million barrels per day is smaller than demand in 2008. 
SRefinery inputs and utilization fell substantially with demand in the second half of 2008.
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SIn the first half of 2009, European refinery inputs were down over 900 thousand barrels per day (7 percent) from first half 2008, and U.S. inputs were down 550 thousand barrels per day (4 percent).
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SIn spite of the drops in crude inputs, Europe and the U.S. saw more supply than demand, especially in distillates, where inventories built substantially.
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SLooking more closely at U.S. supply of gasoline, not only did production fall with demand, so did imports.  Gasoline imports declined both in 2008 and again in 2009.  The declines have been divided relatively proportionally among the major import sources (Virgin Islands, Canada, and Western Europe). 
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SWhile the location of Canada and the Virgin Islands might appear to provide a competitive advantage for these areas over Europe, it is not clear that will be the case in the future.  Europe has gasoline to place that is essentially a by-product, and that gasoline will be priced to compete.
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SGasoline imports should continue to be competitive with U.S. produced gasoline in the future.  In Europe’s situation, the volumes that compete in the U.S. will depend on Europe’s ability to dispose of its excess gasoline in other areas of the world.
SWe have seen distillate inventories build substantially during 2008 and 2009 to extraordinary levels, despite reductions in refined product supply.
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SIn Europe, distillate production fell more than demand declined, but imports were strong.  Distillate is the largest volume product from European refineries.  In 2009, while distillate production dropped with inputs, imports were so strong that inventories rose substantially.   
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SU.S. refiners are more focused on gasoline, which is their largest volume product produced.  While U.S. refiners avoided large builds in gasoline stocks, they saw distillate stocks build because
Distillate demand fell much more sharply than gasoline demand,
It took some time to shift from the high distillate yields of 2008 to more traditional distillate yields in 2009,
Refiners had more difficulty finding export opportunities as attractive as in 2008
Contango in the futures market (future month prices higher than nearby prices) encouraged stock building as suppliers were able to lock in profits.
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SThis overhang in inventories will ultimately need to be drawn down, and serves as a reminder that while distillate markets may tighten in the long term, downward price pressure relative to crude oil could be with us for a while in the short term.  
SGasoline markets have not seen the build in inventories that distillate fuel experienced. 
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SIn Europe, inventories were below the typical range for the second half of 2008 and into 2009.  But with declining demand for this product, such low inventories are not the concern that they might be in the United States.
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SU.S. inventories built at the end of 2008 and have been on the high side of the normal range for most of 2009.  Recalling that demand for gasoline was not hit as hard as demand for distillate, refiners kept up with gasoline demand without oversupplying this market significantly. 
SEven with the recession underway in early 2008, world demand seemed slow to respond, and oil prices rose to peak in July 2008 before tumbling. 
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SCrude oil prices fell back to around $40 per barrel, but OPEC cuts and continued demand strength in developing countries caused prices to spring back up somewhat.
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SFor 2010, EIA is projecting prices around $70 per barrel.  With demand down, OPEC surplus capacity has grown and is projected to remain at more “comfortable” (i.e., larger) levels than seen before the recession.  But there is much uncertainty in the markets. 
On the one hand, demand could spring back faster than anticipated, tightening markets more.
On the other hand, new supply sources in the face of a slow demand comeback could diminish OPEC’s ability to hold back production, causing prices to soften.
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SStill, the current EIA outlook is for prices not to drop back to $40, but to stay higher.
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SRecall that the light-heavy price difference is what affects return on bottoms upgrading investments.
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SThe light-heavy crude oil price difference is shown on this graph along with the light-heavy product price difference.  Since the relative value of crude oil depends on the value of the barrel of products that are refined from the crude, it follows that the light-heavy crude oil price differential is related to the relative value of the product barrel that is made from the heavy crude versus the light crude barrel.  With the crude oil price declined in 2008, residual fuel became more competitive and the light-heavy product price difference fell.  But this was not the only factor working to collapse the price difference.
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SAvailable conversion capacity relative to demand has also narrowed light-heavy price differences.  The fall in demand and the associated reduction in refinery inputs (7 percent in Europe and 4 percent in the U.S.) reduced the pressure on downstream conversion units. This means that the heavy crude oil marginal barrel may have shifted to refineries that can get more value from heavy oils.
Typically we see the marginal barrel of heavy crude oil being run in a non-coking cracking refinery.  These refineries cannot upgrade the residual fuel oil, so the product value they can achieve from the heavy crude oil less than what a coking refinery can achieve. 
Thus, when non-coking refineries are the marginal price setters, they would set the heavy crude value less than would a coking refinery.
More complex coking refineries may now be running the marginal heavy crude barrels. Their ability to get more value from the heavy crude oil tends to increase the heavy crude oil value relative to lighter crude oils. 
SReduced supply of heavy crude is also likely narrowing the price spread.  Heavy crude oil production was down in Mexico, Venezuela, and the Middle East, which made discretionary production cuts as prices fell.  When Western Hemisphere crudes had to go in search of markets beyond the U.S., their relative prices were lower.  In the current market, U.S. refiners don’t have enough Western Hemisphere heavy crude oils, and the refiners are going in search of heavy feedstocks elsewhere – a situation that increases the attractiveness of heavy crudes relative to higher quality crude oils, decreasing the light-heavy price difference.
SThis plot shows U.S. Gulf Coast margins for Light Louisiana Sweet (LLS) crude oil in a cracking refinery and the margin for heavy Mexican Maya crude oil (22 API) in a complex cracking and coking refinery.  Before the recession, Maya coking margins grew more than LLS cracking margins because of the increasing light-heavy crude and product price differentials shown on the previous slide.
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SMargins have collapsed for both in 2009, with weak product demand, falling utilizations, and rising inventories.  Now, the Maya coking margin is not any higher than the LLS cracking margin, as Maya-LLS price differences have contracted sharply.  There is even some discretionary reduction in coking inputs.  In the past, the coker was viewed as a high-margin unit by refiners to be run flat out.
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SWill the relative margins for coking refineries improve?  Much of the crude oil now off the market is heavy, and when it returns, heavy crude will be less attractive.  But with heavy production in decline in the Western Hemisphere and growth in conversion capacity, a return to the heady days of 2005-07 is unlikely unless world demand for residual fuel oil runs into difficulty because of quality issues such as reduced sulfur in bunker fuels.
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SThe investment incentive for new coking units is not there currently.
SWith the decline in refining margins and light-heavy price differentials, the enthusiasm for refinery projects has diminished.  That does not mean planned projects will be cancelled.  The decision to cancel/delay may depend on whether the project belongs to an independent refinery or an integrated company.  It may also depend on the type of project and its stage of development, or on refinery location and crude oil sources. SAn independent refiner, such as Valero, sees more impact on cash flow intended for capital expenditures.  Valero has indefinitely suspended their Port Arthur expansion and delayed the other major project at their St. Charles, Louisiana facility. SCanadian oil sands production delays have been occurring, and production forecasts show less increase in volume over the next five years or so than had been forecast in the past.  The latest Canadian Association of Petroleum Producers projection is for oil sands production to rise from the 2008 level of 1.2 million barrels per day to 2 or 2.2 million barrels per day in 2015.  There are a number of pipeline proposals to move the oil sands crude to the Gulf Coast, but it might be 2015 before large volumes could move to that U.S. refining area. SMarathon’s Garyville refinery 180-thousand-barrel-per-day expansion is nearing completion, and Motiva is continuing its 325 thousand-barrel-per-day Port Arthur refinery expansion.  Both include heavy oil upgrading SMost Midwest refinery projects are tied to using increasing volume of Canadian oil sands crude oil.  ConocoPhillips joint venture with Encana is moving ahead with the expansion and bottoms upgrading for heavy oil sands crude, as is BP, which is converting its Whiting refinery for this feedstock.  SMarathon’s Detroit refinery, Husky’s Lima facility, and Husky/BP’s Toledo refinery projects have announced delays that may be associated with upstream production delays.
SDemand growth issues:
Recession (and missing rebound on distillates)
Potential energy policy impacts
Gasoline will be in surplus no matter what
Distillate export opportunities
SCrude supply issues
Declining heavy sour (Mexican and Venezuelan)
PADD III now needs Canadian dilbit – Dilbit had been looking for a market, and now the market needs it.  But Canadian production estimates have been pulled back significantly
SRefining capacity
Will be in excess in Atlantic Basin in midterm
Closures are occurring
SMargins – Not likely to return to high levels in mid term.
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SThe outlook for petroleum demand has changed dramatically in the past few years.  At the beginning of 2007, the EIA outlook showed strong demand growth and the need for new refining capacity.  Prices were lower in this forecast.
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SThe current forecast has higher prices and higher efficiencies affecting demand.  It also has the recession, which has a slowing effect on demand for some time.
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SEven if there is more rebound after the recession than currently forecast, it is not likely we will see the kind of growth forecast in early 2007.
SInterest in biofuels is not new, as they provide a means for helping to deal with national security and greenhouse gas control.  And higher prices seen before the recession were making ethanol and other biofuels in the United States and elsewhere look more attractive. 
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SPolicy changes are affecting current and future biofuel use even more than prices.  The Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007 include a growing renewable fuel standard for transportation fuels as well as increasing efficiency requirements for cars and light-duty trucks.
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SThe increases in efficiency and ethanol use have significant implications for the refining industry as shown on the next slide. 
SIn the next 15 years, we see a significant shift in demand for petroleum-based gasoline versus distillate that is the result of recent U.S. legislation:
The Energy Policy Act of 2005 included a mandated use of renewable fuels, and ethanol was the only fuel that could practically meet the mandate.  The increased use of ethanol requires less petroleum-based gasoline to meet  demand.
The Energy Independence and Security Act of 2007 increased the renewable fuel mandate, requiring even more ethanol blending.  In addition, the legislation increased light-duty vehicle efficiency standards, which reduces the future need for gasoline demand.
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SWhile still not the shift that Europe has seen, U.S. refiners will be facing a significant change in product mix that will impact investments. 
Overall liquid fuel demand is not expected to grow much over the next 30 years – perhaps about 0.2% per year (annual average) as shown in EIA’s 2009 outlook.
But distillate demand may still grow fairly strongly, while gasoline demand declines; however distillate growth needs to recover from the recession’s impact before that occurs.
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SThe increased use of biofuels and increased light-duty vehicle efficiency standards result in a decline in petroleum-based gasoline of about 580 thousand barrels per day (7%) from 2008 to 2023.
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SPetroleum-based distillate, on the other hand, continues to grow (590 thousand barrels per day or 11%).  Increased use of biodiesel, distillate from coal-to-liquids (CTL) and from biofuels-to-liquids (BTL) processing is decreasing the petroleum distillate need by 360 thousand barrels per day.  If that non-petroleum-based distillate does not materialize, petroleum-based distillate requirements might increase substantially more than what is shown in the table. 
S2008 provided us with some insights on how U.S. refiners might respond to the longer term need for more distillate and less gasoline.  Recall that, although U.S. gasoline and distillate demand were declining, the increase in world demand for distillate and the associated increase in distillate margins, resulted in short-term opportunities for U.S. refiners to export distillate fuel. 
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SThe U.S. is usually a net importer of distillate.  For example, in 2006, distillate net imports were 150 KB/D (thousand barrels per day).  But in 2008, we became a net exporter.  Net export volumes were 315 KB/D – a change of 465 KB/D in just two years (with most of that change coming between 2007 and 2008), and the highest distillate net exports ever.
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SThe chart on the right shows the U.S. export volumes by destination. About 70% of distillate exports come from Gulf Coast refineries (PADD 3). 
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S In the past, the main destination for Gulf Coast exports was Latin America. In 2008, both Latin America and Europe grew substantially as U.S. distillate export destinations.
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SLooking more closely at 2008 and then 2009, we see that exports began to grow from Latin American needs during the first half of the year, but spiked in June, July and August as a result of both Latin American needs and demand from Europe.
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S With the hurricanes in September 2008, exports fell back, but resumed again when refiners recovered.  By November and December, exports were back up, with about 60% moving to Europe.
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SIn 2009, exports have remained relatively strong, even though high margin opportunities are diminished.  Latin American growth as well as high exports to Europe have continued.
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SHow are U.S. refiners doing this?  With operational yield shifts, as described earlier.  And keep in mind that the 2008 yield shift was not all that U.S. refiners can do.  Not all  individual refiners shifted as far as them might be able to do if the incentives are there.  If we don’t have an unusually strong demand rebound following the recession, U.S. refiners should be able to continue to meet shifting U.S. demand and take advantage of international opportunities with distillate exports.
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SDistillate may well provide more profit opportunities for some time in the Atlantic Basin than gasoline due to declining demand for crude based gasoline and increased supply availability as that demand declines – which brings us to Europe and its growing supply of gasoline for export.
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SAs European gasoline exports have continued to grow, they have found some other markets beyond the U.S., which remains the primary destination.  But will these other locations continue to absorb more or even the same volumes?  Will European refiners find other locations?
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SWe judge some of the locations to be subject to increased competition.  With U.S. capacity in surplus, U.S. refiners on the Gulf Coast may take the Mexican market.  The U.S. has historically exported some gasoline to Mexico from the Gulf Coast region.
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SEuropean gasoline exports to the Middle East market could face increased competition from new capacity in India and also from the expansions planned in the Middle East itself.
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SAfrica seems to be the market where refining is perhaps in least jeopardy from outside competition, but Middle East expansions could also compete there.
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SEuropean refiners will continue to need to export gasoline as they run their facilities for their own regional distillate demand.  They will continue to be a very competitive supplier for the U.S. East Coast, and we do not see these European import volumes to the U.S. being displaced by U.S. Gulf Coast refiners.
SEven with flat to slightly declining European transportation product demand, the demand for diesel is projected to increase, while gasoline demand declines.  Additional refinery upgrades to produce more distillate are not expected to keep up with demand growth.  As a result, more imports will be needed, albeit at a lower rate of increase than in the past decade.
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SThe recession’s impact on transportation fuels was less in Europe than in the U.S.  As the economy recovers, diesel demand will grow again.
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SU.S. refiners have demonstrated they can increase distillate production, and can be an important source of European imports.  India and the Middle East, both with expanding capacity, are also targeting Europe.  All of this may make it less likely Europe will see the supply situation as tight as it was in 2008.
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SThe second bullet summarizes the point made in the last slide.
SDemand forecasts for Europe and the United States have been revised downward with little or no growth for refined products.  That means planned refinery expansions will only create excess capacity. 
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SWith low utilization and potential for more capacity from planned projects, closures may occur to try to restore profitability, as evidenced by the recent indefinite idling of Sunoco’s Eagle Point refinery in New Jersey.
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SClosures are also more likely since the resale market that existed earlier will now attract few if any buyers.  There could be exceptions, particularly in areas where less competition exists due to limited demand.
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SMany U.S. projects include bottoms upgrading (added coking capacity).  The prospects for these projects has dimmed with lower light-heavy price differentials, and a changed picture for heavy crude oil availability – especially in the Western Hemisphere.
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SPADD 2 projects that are tied to Canadian oil sands production look more attractive than PADD 3 bottoms upgrading projects.
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SMany European projects include added hydrocracking capacity to make more distillate, but in some cases, they also include crude distillation capacity expansion – which is not needed now.
SFrom 1990 to 2006, heavy sour crude imports from Latin America (primarily Mexico and Venezuela) increased from less than 1 million barrels per day to over 2.5 million barrels per day.  U.S. Gulf Coast refineries became the primary recipients of those import volumes.
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SMany bottoms conversion capacity projects were build in PADD 3 refineries with coking capacity more than doubling from 565 thousand barrels per calendar day (KB/CD) in 1990 to 1,255 KB/CD in 2006.  Coking was 7.9 percent of distillation capacity in 1990, and 15.2 percent in 2006.
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SCoking had come to be viewed as a high return capital project in the Gulf Coast region with rising heavy crude supplyh and increasing ligh-heavy crude prices differences.  Before the recession, PADD 3 showed an additional 272 KB/CD of planned coking capacity additions.
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SGulf Coast refiners had expected heavy crude from Canada (dilbit) to exceed what could be refined in PADD 2 refiners, and to find a home in PADD 3, replacing the declining Latin American heavy crude oils.
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SBut with falling demand, falling crude oil prices, and carbon emission concerns, forecasts of future Canadian oil sands production have declined, as have expectations of likely volumes to reach the Gulf Coast any time soon. 
SWith refinery profits down dramatically in 2009, both independent and integrated refiners are decreasing refining capital expenditures to avoid financing projects with debt.
SThe status of at least half of the planned and approved projects are described with words such as:
Delayed 1 to 2 years…
Project suspended indefinitely…
Will re-evaluate before a final investment decision…
Project awaiting improved market conditions
SOf over 800 thousand barrels per day of expansion planned for the next 4 years, over half are being delayed, suspended, and are in jeopardy of ever being completed.
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SPADD 2 projects that are tied to Canadian oil sands supply by some form of supply agreement or partnership are more secure, but there are also delays in these projects.
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SWill margins and light-heavy price differences rebound?  Yes, to some extent, but probably not quickly.  The heavy crude supply picture in the last slide does not argue for a quick rebound in light-heavy differentials.  To increase those differentials, we need to see high crude prices, more oil sand production, and a poor market for residual fuel. 
SThere are similarities between the U.S. and European refinery investment situations. Reduced profits are impacting capital for investment expenses, but we have seen less press about European project delays than U.S. delays.
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SThe major focus of European refinery projects is increased hydrocracker capacity. However, projects also include over 300 thousand barrels per day of distillation capacity expansions and 150 thousand barrels per day of additional coking capacity.
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SRefinery projects are concentrated in southern Europe (Spain, Portugal, Italy and Greece).  At about 2/3 of projects are in that region, with the other third in Eastern Europe.
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SIn 2009, talk of refinery closures has increased in Europe. The recently started-up  Reliance export refinery in India and potential new capacity in the Middle East are adding to concerns already triggered by lower utilizations.  Not only does new capacity increase surplus supply, it is generally quite efficient and thus very cost competitive, adding much pressure to less efficient facilities.
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