Refiners today face a perplexing future. After many years of low returns during the 1990’s, the industry has recently seen an increase in margins and price differentials. However views vary as to the sustainability of this profitability upswing. This presentation will explore some thoughts on whether or not refining may be moving towards a longer-term Golden Age or simply experiencing a short-term cycle, and in the process, lay the grounds for further debate.
Page As shown in this chart, prices for petroleum products have increased substantially since the 1990’s, but most of that increase has been driven by the price of crude oil. Refinery margins have also increased in recent years, but not smoothly, as can be seen to some extent by the distillate crack spread shown in red on the chart. In addition to margins, light-heavy price differentials have also increased. Generally higher margins and light-heavy price differentials are providing increased incentives to invest. The issue the presentation will explore is how these three variables (prices, margins and light-heavy differentials) might relate to each other, and what seem to be the main factors driving these increases. That information will provide us the basis to address how long these variables may stay elevated, or conversely, what could reverse this situation.
To address the issue, the presentation is divided in to three major sections. The first will discuss high prices, which means discussing crude oil prices and our forecast for the next several years. The presentation will then move to margins and light-heavy price differentials, the two major financial variables influencing future investment decisions. The last section will touch on three areas of particular interest today to explore how they may or may not ultimately affect refinery margins. Policies aimed at reducing greenhouse gas emissions and reducing dependence on petroleum are resulting in further energy efficiency requirements and in increased use of biofuels. Increased energy efficiency and biofuels use affect both the mix and volumes of petroleum products needed from refineries. The industry’s capacity expansion plans raise the question of whether we may be heading for an oversupply situation, which might reduce margins. The groundwork will then be laid to answer the question posed in the title of the presentation: Are we seeing a short-term cycle or the beginning of a golden age for refining?
The major factor behind the product price increases is crude oil price. This section will touch on the major factors behind the recent crude oil price increases. The main factor behind the increase in crude oil prices that has occurred over the past several years is probably demand growth. In particular, a large, unanticipated jump in growth in demand in 2004 helped to tighten crude oil markets significantly. Continued growth, albeit less than the 2004 increase, has kept the balance between supply and demand tight. U.S. growth, on an absolute volume basis, has been a major contributor to the ongoing worldwide demand growth, but in recent years, China and India have added significantly to that growth. When you realize that total Chinese demand is about 1/3 of U.S. demand, and yet the incremental volume growth is generally larger than that in the U.S., you can appreciate the tremendous percentage growth rates some of these Asian countries are experiencing. Worldwide supply growth did not keep up with demand from 2003 through 2005, as the next few slides will illustrate. Why haven’t high prices resulted in slower demand growth and more supply? To address this and to understand the basis of our crude oil price forecast, we will look back in time to contrast our current market with that following the price increase in 1979-80.
The strong growth in demand coupled with slower growth on the supply side has resulted in a large drop in excess crude oil production capacity. In 2002, when world demand growth slowed, non-OPEC production remained relatively strong, and OPEC pulled back on its production, leaving over 5 million barrels per day of surplus capacity. But in 2003, the Venezuelan strike, which began in December of 2002, and the Iraq war removed a significant amount of short-term production capability. The remaining OPEC countries increased their production, and surplus capacity fell significantly. While Venezuelan and Iraqi production capability improved in 2004, the large increase in demand that year required a surge in OPEC production, and surplus capacity fell even further. In 2005, the hurricanes in the U.S., large drops in production in the North Sea and smaller growth in Russian production required even more OPEC production, and surplus capacity fell further. There may be a little easing of that tightness this year and next, partially due to projections for some slowing in economic activity, but that could revert back very quickly to the tight levels seen in 2005. In general, EIA is not projecting much growth in spare production capacity as we look ahead over the next few years.
Prices have responded to this lack of surplus production capacity, as the market has recognized the increased risk of inadequate supply resulting from geopolitical turmoil or other events such as hurricanes. The relationship shown in this chart is similar to what you might expect of any commodity. As surplus capacity diminishes, price begins to rise until reaching a point where the market views the situation as operating with little or no surplus. In addition, with so little spare capacity, OPEC can easily respond with production cuts when prices appear to be weakening. As we have seen, price can be quite volatile in the vertical part of this curve around 1 million barrels per day of spare capacity. With prospects for surplus capacity remaining relatively low in the near term, perhaps around 2 million barrels per day, the market continues to recognize that geopolitical turmoil and hurricanes can have a significant effect. Consider the potential for loss of production in any of these countries: Iraq at 2.0 million barrels per day, Iran at 3.8 million barrels per day, Venezuela at 2.4 million barrels per day, Nigeria at 2.3 million barrels per day. For prices to ease, either demand has to give or supply has to increase, or some of both. The next slides contrast our current situation with 1980.
With high prices today, why haven’t we seen demand come down more as it did following the 1979-80 price increase? After the 1979-80 crude oil price increase, the chart shows a significant demand decline. But this fall off was mainly residual fuel oil demand (fuel oil on the chart) which went from over 14 million barrels per day to 10, which is where we are today. Fuel oil’s decline represented 60% of the world’s petroleum decline from 1979 to 1983. That won’t happen today. With the lighter products, CAFÉ standards were instituted in the U.S. at that time, which gave rise to substantial efficiency improvements in light-duty vehicles, and was the major factor behind a decline in gasoline demand. Today, however, the “easy” efficiency improvements seen in the early 1980’s are gone. Efficiency improvements are still possible, but we are likely to see less impact in the short run than we saw in the early 1980’s. Today, the large Asian economies of China and India are accounting for much of the growth. They are being driven by economic development. Even with more efficient cars and trucks than in the U.S. fleet, Asian demand will grow as it is simply adding cars and trucks. Barring a recession, that growth may be harder to stem. While demand is likely to remain relatively robust, can supply respond to ease the market balance tightness?
In 1979-80, the demand collapse left a large supply overhang. In an attempt to maintain price, OPEC had to pull back on production as a result of the demand declines in the face of non-OPEC production growth. Strong production increases were coming from the Alaskan North Slope and North Sea. Within a few years, OPEC’s inability to support prices resulted in a significant price decline. With demand still increasing today, is there the potential for some surge in supply to move ahead of demand sufficiently to ease the tight market? OPEC is limiting production to maintain prices, consistent with their own interests, but can a surge in supply come from non-OPEC sources in the short term?
Non-OPEC supply does not present any obvious areas for strong increases in production in the short run. In particular, we see: Fewer exploration prospects, with field size of new discoveries declining. Limited access to known reserves by private international oil companies. Almost 2/3 of the world’s known reserves are controlled by national oil companies, with the more efficient, private, international oil companies only having full access to about 19% of the world’s reserves. This lack of access potentially means slower and less effective development. At today’s prices, alternative supplies such as tar sands are attractive, but growth of this supply source is slow and expensive. In total, while supply is expected to continue to grow, it won’t be fast, leading to the conclusion that as long as strong demand growth also continues, supply will likely remain tight for some time – perhaps even 3-5 years.
The underlying fundamentals in the crude oil market continue to point to elevated prices. Perceptions of geopolitical risk and other risk factors affecting price shifted in the short-run. A warm winter slowed crude oil demand growth and eased market pressures briefly, but continued unrest in Nigeria, concerns over Iran, pushed prices up again this spring. But overall petroleum demand is still growing, especially distillate, and surplus crude oil production is not improving much. Later in the presentation, future crude oil prices will be revisited again in the context of what uncertainty in this factor might mean for refining profitability.
The last section attempted to illustrate that in general, both supply and demand factors contributing to today’s higher prices are not likely to shift quickly, leading to the conclusion that the tight market we are seeing may be with us for some time. But what about the key indicators of refinery profitability, margins and light-heavy price differentials? This section will explore margins, noting when and how they have grown, including the surprising increase in distillate’s contribution to the bottom line. We also we explore the drivers behind light-heavy differentials, finally pulling the pieces together to lay the groundwork for what the future may bring.
In the 1990’s, crude oil prices varied around $20 per barrel, and the 3-2-1 spread (which is an indicator of refining margins) rarely rose above $5 per barrel. Since 2000, crude oil prices have risen almost steadily to over $70, before falling back to around $60. Margins have also increased, but not smoothly. As the slide shows, margin volatility has increased as well. In the 1990’s, with crude price around $20 per barrel, analysts watched inventory variations as an indicator of changing supply/demand balances, which affected margin increases and decreases. As we will explore in the next few slides, a number of other factors may be at work, besides the short-term supply/demand balance factors. One of the factors may be crude price itself.
This slide with annual average crack spreads for both gasoline and distillate shows more clearly the strong increases in the past two years. While historically gasoline was the larger driver of overall refining margins, distillate is playing a stronger role now. This graphs shows the annual average gasoline and distillate crack spreads since 1990, and highlights the increases that have occurred since 2000. Historically, the gasoline margin has been higher than the distillate crack, but in 2005, the distillate crack spread exceeded gasoline. Even though the distillate crack averaged slightly less than the gasoline crack in 2006, it was close. We are seeing distillate becoming a much stronger contributor to margins than in the past. The strong growth in distillate demand worldwide – and in particular in Europe – is likely a major driver behind this change. The gasoline crack since 2000 is 2.3 times what is was from 1992-1999, and the distillate margin is 2.7 times over the same time periods. These rises in crack spreads (and thus margins) have coincided with crude oil prices increasing from $20-$25 per barrel to over $70 per barrel. We will explore if the margin increase is mainly or partially attributable to the rising crude oil price or some other factors that have been changing during the same time period.
As we struggle to understand the increases in margins and differentials, we have to keep asking, what has changed? As this graph shows, world refining utilization has gone up 2% from 2003 to average 86.3% worldwide. The Atlantic Basin provides some insights into this utilization question. The Atlantic Basin (North America and Europe) has a large impact on refined product markets. (U.S. and EU-25 represent about 43% of world petroleum demand.) The U.S. hit its maximum utilization in 1997, and Europe in 1998. Utilization in these two key markets has not increased in the past few years, but has remained high with little spare capacity. While high utilizations & outages undoubtedly contributed to higher margins in recent years, there was not an Atlantic Basin stock draw during this period of a size one might expect from the 1990’s relationships to support the much higher level of margins seen in 2005 and 2006. The unusual distillate price pressures may be more closely tied to capacity constraints than gasoline. But dynamics in a rising crude price market may still be the larger factor affecting overall margin increases.
Next, the presentation will explore the light-heavy crude oil and product price differentials, since they are critical for success in bottoms-upgrading investments. Many high conversion refiners in the U.S. are very successful at converting the heavy gas oil and bottoms crude oil streams into higher valued products. But many refineries in Europe and Asia still produce significant fractions of their product barrel as residual fuel oil. It appears to be the cracking refineries without residual upgrading who are setting the light heavy price differential.
Page This 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 on the U.S. Gulf Coast. (While not shown here, the light-heavy product spreads in U.S. and Europe move similarly.) As has been the case historically, during 2004 and 2005, residual fuel price increased less than crude oil and light product prices, while the 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. Residual fuel oil competes with other fuels such as coal and natural gas. Thus, residual fuel oil price does not rise as quickly as crude oil price. However, gasoline and distillate prices rise as much as or more than crude oil prices, depending on the tightness of the market. The result is that the light-heavy product price difference moves with crude oil prices. For many of the world refineries that produce 20%-30% residual fuel oil, that light-heavy product differential represents the fact that the value of the product barrel produced from a heavier crude oil rises less than the product barrel resulting from a light crude oil as crude price increases.
Page Now turn to that light-heavy crude oil 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. While the crude oil price differential in this slide uses Maya crude oil, which is a far 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. The light-heavy crude oil price difference relates closely to the value of the product barrel for a refinery without bottoms conversion processing (e.g., coking) when running a heavy crude oil compared with the same refinery running a light crude oil. For the refiners with bottoms upgrading, the margins have become very attractive. The current light-heavy crude differential provides a very strong incentive for added bottoms processing conversion capacity. A key question is what might cause a major contraction in the differential? Too much bottoms investment? An increase in light crude oil availability? A major decline in crude oil price? Investment in bottoms upgrading that destroys 10% of the worlds residual fuel would likely only have a very modest affect on the differential. If the 10% decline was done only with coking, it would take about 1-million-barrels-per-day more coking capacity – 20% more than currently exists. A significant increase in light crude oil production relative to heavy by itself would also not likely collapse the differential – unless it also brought crude oil prices down. Thus, unless there is a significant crude price drop, the contraction in the light-heavy differential is likely to be modest.
Now I will explore future uncertainties around differentials and margins in more detail. We know what incentives are today, but investments must earn a return for many years in the future. If petroleum markets loosen, and crude oil prices fall back, what could happen to margins and price differentials? This scatter plot illustrates the relatively strong relationship between crude oil prices and a light-heavy crude oil price difference. If crude oil prices fall back to $40 per barrel, the light-heavy crude price differential will fall back. But the scatter around the line indicates that the dynamics behind this relationship may keep the movements from being a simple linear relationship – even though we show a linear fit for discussion purposes. That differential is affected by residual fuel price. Both demand and supply of residual fuel oil are changing with changing prices, but demand and supply don’t necessarily move together. On the demand side, rising prices make residual fuel oil less attractive than alternatives, and demand for residual fuel falls. Price for residual fuel then does not rise as much as for light products. Thus, the value of heavier crude oil drops relative to light crude oils. The increasing light-heavy crude oil and product price differences increase incentives to add bottoms upgrading capacity, such as coking units, and destroy residual fuel oil supply. This balance between heavy product supply and demand will vary, and when crude oil prices return to $40, the light-heavy differentials could be higher or lower than occurred when prices were rising, depending on the strength of the demand or supply response to the price increase.
The relationship between margin and crude oil price is highly uncertain. While margins and crude oil prices have some relationship, there are other factors affecting margins as well, which is why the simple relationship shown in the scatter plot is not very good. But do not assume the missing explanatory variable is utilization. There has been no correlation between margin and utilization, and while high utilizations likely are having some effect, other factors seem to be at work. In general, when crude oil prices rise, markets are tightening, and margins rise as product prices precede crude oil prices. For prices to fall, markets have to loosen, and margins shrink. In the region above $40 per barrel, this scatter plot represents a time when prices are mainly rising. We don’t have the margin vs. price relationship as prices fall back from today’s levels to say $40 per barrel. We could see lower margins on average on the way down than on the way up depending on what is behind the loosening market. It is possible that margins may experience a larger impact from rising versus falling prices than light- heavy differentials. Then the scatter shown on the chart would increase in the higher price range, depicting greater uncertainty. Consider the case where crude prices settle in the future at some level such as $55 for some time. What margins might we plan on? Would they be proportionally higher on average than margins at the $20 crude oil prices seen in the 1990’s? We have no historical experience to answer this. If we contend that the margin strength this year is not mainly from refinery utilization, what can we say about the next 5 years if crude prices stay at higher levels?
In summary, the increase in crude oil price over the past several years, seems to be a critical driver of light-heavy differentials and probably even margins. That means that if crude oil price declines, we could expect differentials to narrow and margins to fall. The more interesting case is when prices settle at some high value, as the EIA short-term forecast currently shows. Margins may loose some of the boost that they may have received when prices were rising, but it seems they would still likely settle somewhat higher than margins seen in the 1990’s. In the case where prices settle at a high level, differentials should stay elevated. While new conversion capacity will shrink residual supply over what it would otherwise have been, residual fuel demand is declining, and may decline more rapidly in the future as sulfur restrictions on bunker fuel evolve. (Also keep in mind that some of that planned residual conversion capacity is simply to allow refiners to use heavier feedstocks, and would not result in a net reduction in residual fuel supply.)
This last section of the presentation will touch on several factors of particular interest today, in order to explore what impact they may have on future margins. As mentioned earlier, distillate has been growing more than gasoline on a world basis, and Europe is a primary driver of this trend. This growth in distillate may be the main reason behind the large increase in distillate crack spreads relative to gasoline crack spreads. Will this strength in distillate relative to gasoline continue? Concerns over greenhouse gas emissions and dependence on petroleum are resulting in policies to encourage more use of biofuels. And biofuels’ growth is affecting both the mix and volume of new refinery capacity that is needed. Last, we have seen many refinery expansion plans emerge, which has raised the question of whether the industry will overbuild and crush margins.
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 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. In spite of Europe’s success in reducing energy growth, it has not been able to meet its own CO 2 emission goals. This situation in Europe and a growing willingness in the U.S. to address greenhouse gases will likely result in both areas seeing more energy efficiency requirements in the future. The U.S. has been a good market for Europe’s excess gasoline. In fact those gasoline volumes available from Europe have kept U.S. refiners from having to expand capacity as much as they might otherwise have done. European gasoline exports have increased by 505 thousand barrels per day from 1999 to 2006, and U.S. imports have increased 520 thousand barrels per day over the same time period. The U.S. also has distillate growing more rapidly than gasoline, but the degree of change is much smaller than that seen in Europe. While both U.S. and Europe face the potential for greater efficiency requirements, efficiency changes impact demand slowly and provide time for the industry to react – such as delaying capacity expansion plans.
Europe’s interest in biofuels to help reduce greenhouse gas emissions has focused on biodiesel and ethanol. Biodiesel use should reduce Europe’s growing import needs for diesel. But ethanol use in Europe’s gasoline will add to its export volumes. In the U.S., biofuels interest is currently focused on ethanol use in gasoline. EIA and other analysts expect significant increases in ethanol volumes used in gasoline over the next 5 years, which will reduce the need for increases in gasoline supply from refineries. In addition, U.S. refiners will potentially see increased export volumes of gasoline available from Europe – both because of Europe’s continued gasoline demand decline and potentially because of increased ethanol use in Europe.
With the increases in margins and differentials – especially since 2003 – we are seeing many announcements for refinery capacity expansions. These expansions include distillation as well as downstream projects to use lower quality feedstocks, to increase light product yields, and to improve refinery performance. In Asia and the Middle East, capacity expansion is needed to meet rising demand. In Europe and the U.S., the focus is more on using heavy feedstocks, adjusting product yield mix, and improving competitive cost performance. In the U.S. there is an increased interest in achieving top quartile performance. (It seems about ¾ of refineries would like to achieve top quartile status.) A refiner can invest to reduce refinery energy cost, improve reliability, and make other operational improvements to achieve improved competitive cost structures. This approach will improve company income over what it would have been without the improvements, regardless of margin or differentials. However, energy cost is tied to crude price, and returns on reliability and operational improvements are margin dependent.
Three factors have been influencing plans to increase capacity: (1) increased refining profitability, (2) high light-heavy price differentials, and (3) increased cash and personnel availability as companies’ finish their low sulfur fuel investments. These numbers in the table reflect plans, and as such, not everything shown will occur. More enthusiasm currently exists for expansion than has occurred in decades. The total level of expansion shown above has a reasonable probability of occurring, even if the exact mix shown does not occur. Still, we saw plans shrink from last year in the face of rising costs and growing biofuel use. The detail on coking and other downstream units is lagging behind statements about distillation capacity expansions, but we expect most expansion to be in the higher complexity range, with much of it geared to heavier crude oils and accompanying bottoms upgrading, as demonstrated by the coking unit plans shown. Even less detail is available for FCC units than for coking or hydrocracking. This is not unusual, and means that the total FCC capacity shown on the slide is below what is likely to occur. It is important to note that additional U.S. coking capacity is being planned to process new Canadian-tar-sands-derived crude oil beyond that shown in this chart.
Most of the refinery expansions being announced are in the high demand growth regions of Asia and the Middle East. However, more of the expansions are scheduled towards the end of the 5-year period. Capacity additions include much complex capacity, with more interest in hydrocracking capacity compared to FCC capacity than has been the case historically – especially in Europe and Asia. Europe’s low distillation expansion reflects its low total petroleum growth. Europe’s challenge is product mix, which is why we are seeing the hydrocracking capacity announcements. U.S. growth reflects both a need to meet increasing demand as well as changing feedstocks.
This slide illustrates the growing complexity in world refining. The bars show downstream unit capacity as a percent of distillation capacity for the beginning of 2007 and the beginning of 2012. In almost all cases, the bars are increasing over time. As the prior slide showed, the large increases in distillation capacity in the Asia-Pacific region are being accompanied by large increases in downstream capacity. The downstream complex capacity being planned will push up this complex capability as a percent of distillation capacity in FCC, hydrocracking and coking. The Middle East has an increase in FCC capacity relative to distillation capacity to help meet the rapid gasoline demand growth within the region, while hydrocracking capacity expansion may be more for the export markets. Europe’s hyrdrocracking capacity may increase by 25% in this 5-year period, while the increase in coking is only 41 thousand barrels per day. However, there are other bottoms processing options (solvent extraction, gasification, residual hydrocracking that are being selected to reduce residual fuel production and increase diesel yield from the bottom of the barrel. The U.S. maintains its position as having the most complex refining capacity. Still, like other regions, it is a bit more focused on hydrocracking than FCC. Coking may increase further as tar sands refinery projects unfold.
This slide illustrates the potential balances between distillation capacity expansion and petroleum demand growth in the major regions. The slide implies that the U.S. could actually see capacity expansion stop product import growth, although some growth is still expected – particularly from Europe. Most of these plans will not be online for several years, so they could be delayed in many cases, should the investment environment turn sour. Europe will continue to need distillate imports and have extra gasoline to export. It could even see a net increase in its need for distillate product imports. The Middle East is likely to increase its ability to export product, while Asia, like the U.S., will likely see capacity and demand growth stay fairly close. The Middle East is talking about several large projects, of which not all are represented here. For the first time in many years, they are talking about investment for the export market. Where they sit between Europe’s need for diesel and Asia’s need for gasoline and distillate, they have a variety of options.
We have discussed aggregate expansion plans, but with all of this uncertainty, it is not surprising that expansion plans vary by company and by region. In the U.S. and Europe, the super majors, like BP and ExxonMobil, seem to be the least committed to refinery expansion. They will invest to maintain their refineries as “top quartile” performers, and may participate in projects in high growth Asian areas. The view publicly expressed by companies in this group is that the downstream markets are cyclical and profitability likely will return to lower levels. Other integrated companies (e.g., Chevron, ConocoPhillips, and Marathon in the U.S. and Total and ENI in Europe) mostly show a greater interest in investing in the refining side of their business than do the super majors. The companies that are exclusively in the refinery business have grown their portfolio of refinery assets and expanded capacity at those refineries by the largest percent. Consistent with these actions, this group expresses more optimism about a sustained improvement in refining margins. But continued steep cost escalation, biofuels growth, and availability of gasoline imports are shifting the focus of some from expansion to improving operations. In Asia and the Middle East, state-owned companies hold the majority of refining assets. These companies have expressed a strong need for new capacity and a belief that the current tight capacity situation will ensure higher margins. The Middle East refiners also see they can improve the value they receive from their heavy crude oil by refining it themselves.
On the question of over-expansion, the issue is always one of degree. But in general, barring calamities, plans don’t reflect an expansion boom that will drop utilizations much. In fact in the next few years, before much of that capacity comes on line, refining capacity it likely to remain tight. Regionally, the story may be different. The areas at highest risk for over-expansion are Asia and the Middle East. The Atlantic Basin, on the other hand, is not likely to over expand. Europe’s low total petroleum demand growth will keep its distillate capacity expansion to a minimum, and U.S. expansion plans don’t point towards an overhang. If demand continues to grow, and we have no major recessions or other demand damping events, refinery expansion plans may reduce overall utilization by several percentage points, but that should not have much affect on margins. The plans for bottoms upgrading also should not have a large impact on the light-heavy price differentials. Some of those plans are geared to use lower quality feedstocks such as tar sands. The upgrading investments that will reduce residual fuel demand will only help keep a generally declining market in balance. As more countries move to cleaner air standards, high sulfur residual fuel in particular becomes less attractive. Finally – companies adjust. We have already seen reductions on expansion plans in the U.S. from last year, as rising costs and increased short-term potential for biofuels grows.
Pulling this all together, a case was made for watching crude oil prices. EIA is forecasting crude oil prices will likely to stay high. They may settle down into a band that fluctuates perhaps between $60 and $70 or between $55 and $65, for example – but the average level is projected to be much higher than seen in the 1990’s. The rising crude oil market may have been giving margins an added boost as prices rose in advance of crude oil. If that is the case, we could see margins fall back some if crude prices stop rising. But the underlying tight market supporting these crude oil prices may still support higher margins than those seen in the 1990s. The higher prices should also support a higher light-heavy differential, which will continue to provide incentives for conversion capacity. This new bottoms conversion capacity is not likely to crush the spread. Demand for residual fuel oil is shrinking, and the new capacity will more likely help keep the market in balance. If the forecast for crude oil prices is incorrect, and crude oil prices fall, margins and differentials would both fall.
Turning to other factors that are affecting refiners plans, we noted that policy changes are affecting the potential growth in petroleum demand and the need for refining capacity. The increased interest in biofuels is affecting both mix of products needed from refineries and the volume of products from refineries. In the U.S. ethanol is reducing the need for increased gasoline capacity, but distillate capacity is still required. In Europe, biodiesel may help reduce the need for distillate imports, but increased use of ethanol in gasoline will only exacerbate the excess gasoline situation – providing more exports for the U.S. and other countries. Still apart from changes in refinery plans, that actual margin impact may be small. Gasoline margins would be affected more than distillate margins. More energy efficiency requirements are also likely in the future. But these changes impact the market slowly and provide the industry some time to adjust. The recent increases in margins and expectations for further demand growth has spurred an increase refinery capacity expansions, which as caused some concern over a potential supply glut evolving. But we already have seen U.S. plans shrink from last year. The largest potential for oversupply that might impacts Atlantic Basin margins is probably coming from the Middle East. But in general, it does not look like an over supply situation would develop that would crush margins.
It certainly looks like a better investment environment than we saw in the 1990’s lies ahead for awhile. However, the future investment environment may not be as attractive as experienced in 2006.
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Are Refiners Entering a Golden Age or a Short Cycle? Global Refining Strategies 2007 Barcelona, Spain April 2007 Joanne Shore John Hackworth Energy Information Administration www.eia.doe.gov
Short-Term Cycle or Golden Age? <ul><li>What has driven prices, margins, and light heavy price differentials to current high levels? </li></ul><ul><ul><li>How are these three variables related? </li></ul></ul><ul><ul><li>What are the main drivers? </li></ul></ul><ul><li>How long might prices, margins, & differentials stay elevated? </li></ul>Source: Bloomberg spot prices
Outline <ul><li>High Prices: Crude Oil </li></ul><ul><li>Drivers and Uncertainties Behind Margins and Differentials </li></ul><ul><li>Other Supply/Demand Factors Affecting Future Petroleum Markets </li></ul><ul><ul><li>Energy Efficiency </li></ul></ul><ul><ul><li>Biofuels </li></ul></ul><ul><ul><li>Surge in Capacity Expansion Plans </li></ul></ul>
The Main Factor Behind High Product Prices: Crude Oil Prices <ul><li>Strong Demand Growth </li></ul><ul><li>Less Supply Growth </li></ul><ul><li>Different Prospects for Future than seen in 1980 </li></ul>
Today: Little World Crude Oil Surplus Production Capacity Forecast Source: EIA Short Term Energy Outlook March 2007
Today: See Typical Economic Relationship Between Little Surplus Capacity and Price Source: Bloomberg WTI; EIA Calculations
Prospects for Demand Correction Different than Early 1980’s Correction <ul><li>Fuel oil decline will not ease market pressure today as in early 1980s </li></ul><ul><li>Easy fuel efficiency gains made in early 1980s </li></ul><ul><li>Large Asian economies account for more growth today </li></ul>Notes: World Excluding FSU, Gasoline includes aviation gasoline & light distillate feedstocks Source: BP World Statistical Review 2006
Today’s OPEC & Non-OPEC Production Requirements Different Than 1979-80 Source: EIA Annual & Monthly Energy Reviews.
Limited Prospects for Non-OPEC Crude Supply Increases in Short Run <ul><li>Fewer non-OPEC exploration prospects, field size declining </li></ul><ul><li>Most efficient companies have limited access to known reserves </li></ul><ul><li>Tar sands growth costly and slow </li></ul>Source: Data from Business Week Online Slide Show: Why the Oil Giants Look Weaker http://www.businessweek.com/magazine/content/06_20/b3984001.htm May 15, 2006 2004 1960s Known Reserve Access
Prices Expected to Remain Relatively High in Short Term <ul><li>Future uncertain but could stay relatively high </li></ul><ul><li>OPEC position has strengthened </li></ul><ul><li>Demand growth has moderated only slightly </li></ul><ul><li>No large surge in non-OPEC crude or other supply -- and costly </li></ul><ul><li>Only OPEC can build excess capacity </li></ul>Source: EIA Short Term Energy Outlook March 2007
Drivers & Uncertainties Behind Refinery Margins and Differentials <ul><li>Margins </li></ul><ul><ul><li>Growing, but volatile </li></ul></ul><ul><ul><li>Shift in gasoline and distillate contributions </li></ul></ul><ul><ul><li>Refining utilization – over-emphasized factor? </li></ul></ul><ul><li>Light-Heavy Differentials and the Importance of Crude oil Price </li></ul><ul><li>Future Considerations </li></ul>
3-2-1 Spread (Margin Indicator) Grew with Crude Price – But Not Smoothly WTI Spot 3-2-1 Spread Source: Bloomberg Spot Data: Gulf Coast Gasoline, No. 2 and WTI.
Distillate Cracks Increased More than Gasoline Source: Bloomberg spot prices – Gulf Coast Conventional & No. 2 minus WTI
World Utilization Up, But Atlantic Basin Utilization Not Changed Much Recently Source: BP World Statistics 2006 (crude runs/capacity) and EIA Annual Energy Review (gross inputs/capacity).
Light-Heavy Differentials Rose Since 2000, But Will They Remain High? <ul><li>Product markets drive light-heavy product prices </li></ul><ul><li>Impact of total product barrel value on crude value </li></ul><ul><li>Differential: Incentives for heavy-crude high-conversion refining </li></ul>
If WTI Drops from $70 to $40, Will Differential Drop by 40% ($17-$10)? Source Bloomberg WTI Cushing and Maya.
If WTI Drops from $70 to $40, Margin Relationship Less Certain Note: Three hurricane months excluded (Aug-Oct 2006) Source Bloomberg Gulf Coast product spot prices and WTI Cushing.
Bottom Line: Crude Price Important Indicator of Future Returns <ul><li>Rising price: Increasing margins, increasing differentials </li></ul><ul><li>Declining price: Decreasing margins, decreasing differentials </li></ul><ul><li>Price settles within a high price band </li></ul><ul><ul><li>Margins lose their boost from rising market dynamics, but may stay higher than seen in the 1990’s </li></ul></ul><ul><ul><li>Differentials remain high -- even with more conversion capacity </li></ul></ul>
Other Supply/Demand Factors Affecting Future Petroleum Markets <ul><li>Demand </li></ul><ul><li>Distillate/Gasoline Shift </li></ul><ul><li>Energy Efficiency </li></ul><ul><li>Supply </li></ul><ul><li>Biofuels Reducing Need for Some Capacity </li></ul><ul><li>Capacity Expansions – Oversupply? </li></ul>Source: BP World Statistics 2006.
Demand Factors Impacting Future Atlantic Basin Needs <ul><li>Europe’s growing imbalance between distillate & gasoline </li></ul><ul><li>U.S. continued growth in gasoline & distillate – with distillate growing more strongly </li></ul><ul><li>Potential increase in efficiency requirements (greenhouse gas, energy security, etc.) </li></ul><ul><ul><li>Europe’s potential mandates </li></ul></ul><ul><ul><li>U.S potential policy change </li></ul></ul><ul><ul><li>Slow impacts </li></ul></ul>Note: U.S. imports includes blending components. 2006 is based on January-October data. Source: IEA, EIA Petroleum Supply Monthly & Annual
Biofuels Changing Capacity Needs <ul><li>Europe’s biofuel interest increasing </li></ul><ul><ul><li>Biodiesel compatible with diesel capacity shortfall </li></ul></ul><ul><ul><li>Ethanol in gasoline exacerbates over-supply situation </li></ul></ul><ul><li>U.S. seeing diminishing need for new gasoline capacity </li></ul><ul><ul><li>Increase in ethanol </li></ul></ul><ul><ul><li>Increase in import availability from Europe </li></ul></ul>
Refinery Capacity Poised for Major Expansions <ul><li>Incentives resulted in capacity investment plans </li></ul><ul><li>Plans cover all areas </li></ul><ul><ul><li>Increased throughputs </li></ul></ul><ul><ul><li>Increased use of low-quality heavy feedstocks </li></ul></ul><ul><ul><li>Increased light product yields </li></ul></ul><ul><ul><li>Upgrade to top quartile </li></ul></ul>
Capacity and Complexity Increases Through Next 5 Years Note: Dist: Crude distillation; FCC: Fluid catalytic cracking; HC: Hydrocracking. Source: EIA, FACTS, company presentations, Oil and Gas Journal , Hydrocarbon Processing Boxscore.
Complexity is Increasing Down-Stream Capacity as Percent of Distillation Capacity Jan 1, 2007 and Jan 1, 2012 Note: FCC: Fluid catalytic cracking; HC: Hydrocracking .
Capacity and Consumption 5-Year Changes 2007 through 2011 Sources: Capacity see previous slides; Demand: EIA, BP World Statistical World Review 2006, FACTS, IEA
Not Surprising that Outlooks/Plans Vary Sources: Trade press articles, company presentations and press releases. Expand or upgrade operations "Golden Age of Refining“ but… U.S. Independent Refiners Rapid expansion existing & grassroots High demand growth, better margins India & China State & Private Expand for export, add bottoms upgrading Tight capacity & high light-heavy Middle East Export Refiners Heavy crude projects & cautious expansion Improved margins with cycles U.S. & Europe Majors with Large Downstream Maintain top-quartile performance , little expansion need Margins revert to historic All Super Majors Refinery Investment Strategy Future Market Expectations Regions Group
Potential for Over or Under Expansion – And Does it Matter? <ul><li>Barring calamities: </li></ul><ul><ul><li>In the next 2-3 years, capacity will likely remain tight </li></ul></ul><ul><ul><li>In next 5-10 years, not likely to see utilizations drop to levels seen in early 1980’s from expansion </li></ul></ul><ul><li>Expansion that reduces utilization several percentage points not likely to have much impact on margins </li></ul><ul><li>Regionally, the highest risk for oversupply that might impact Atlantic Basin margins is in Middle East; Atlantic Basin is not likely to over-expand </li></ul><ul><li>Decrease in residual fuel supply from bottoms upgrading not likely to be enough to push residual fuel prices much closer to crude oil price and significantly reduce differentials. (Demand for residual fuel is declining.) </li></ul><ul><li>Rising facility construction costs and biofuels use may reduce rate of facility expansion </li></ul>
Looking Ahead: Crude Price Factor <ul><li>Forecast: Fluctuate in band much higher than during the 1990’s (perhaps in the $60-$70 range?) </li></ul><ul><li>Margin impact: </li></ul><ul><ul><li>Lose the boost from being in a “rising” market </li></ul></ul><ul><ul><li>But still may support higher margins than in the 1990’s </li></ul></ul><ul><li>Light-Heavy differential impact: </li></ul><ul><ul><li>Remain elevated </li></ul></ul><ul><ul><li>Demand for residual fuel is shrinking (e.g., bunker fuel market) </li></ul></ul><ul><ul><li>Even with more conversion capacity destroying residual fuel supply, residual price not likely to rise more towards crude oil </li></ul></ul><ul><li>Uncertainty: If crude oil prices fall, margins and differentials fall </li></ul>
Looking Ahead: Other Supply/Demand Factors <ul><li>Policies affecting biofuels and energy efficiency </li></ul><ul><ul><li>Biofuels impact supply mix and volume </li></ul></ul><ul><ul><li>Ethanol use in U.S. reducing need for increased gasoline capacity, but U.S. still needs distillate capacity </li></ul></ul><ul><ul><li>Biodiesel in Europe may help slow growing diesel supply gap, but ethanol in Europe adds to already excess gasoline supply </li></ul></ul><ul><ul><li>Ultimate margin impact may be small – affecting gasoline cracks more than distillate </li></ul></ul><ul><ul><li>Energy efficiency improvements have slow impacts – can adjust </li></ul></ul><ul><li>Will refinery expansion plans result in capacity oversupply? </li></ul><ul><ul><li>Seeing U.S. capacity plans shrink </li></ul></ul><ul><ul><li>Largest potential for oversupply margin impact is in the Middle East, where could dampen European margins and thus Atlantic Basin margins some </li></ul></ul>
Short Cycle or Golden Age? Maybe a Bronze Age...