SUPPLY

Global Oil Supply by Region

Regional Crude Oil Production 1980-2003

The Mideast

remains the largest

80.0

oil-producing

region, as shown in

the accompanying ^70.0

graph. Mideast

dominance in oil

60.0

reserves -- the

estimated amount

50.0

of oil that can be

produced from

known reservoirs -^40.0

- is even more pronounced: the ^30.0 region holds about two-thirds of the

20.0

one trillion barrels of global proved oil 10.0 reserves, so the region's critical role in world oil supply ^0.0

1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003

will continue and will grow. (The United States, by contrast, holds only 4 percent of global proved reserves.) Several core developments have shaped the pattern of regional oil production:

The higher oil prices of the 1970s and early 1980s (graph) afforded a strong economic incentive to explore for and produce oil, and production rose in many areas. At the same time, oil demand declined -- the expected response to the high prices. Saudi Arabia became the "swing supplier," reducing its production as necessary to balance supply and demand. Its rejection of that role in mid1985 -- its output had fallen to about 25 percent of its 1980 peak -- brought the full force of the supply/demand imbalance onto markets and resulted in the price collapse of 1986. Prices did not return to the pre-1986 level until the Persian Gulf conflict of 1990-91, and then only briefly. When, in 1998, Asian demand faltered with the region’s economies, and northern hemisphere demand faltered with the warm winter, the high production levels resulted in another price collapse. The

market reaction in 1998, however, was not the same as in 1986 –- demand did not recover as quickly and supply did not fall as quickly. Hence, the low price period lasted longer and showed lower prices in 1998 than in 1986. In early 2000, oil prices exceeded the levels of the Persian Gulf conflict in nominal terms. Sharp as the price increases were in early 2000, however, crude oil prices remained less than half of the early 1980s peak in terms of real buying power.

Million Barrels per Day

Saudi Arabia Crude Oil Production: Middle East 1980-2003 _{(graph), the}

market

25.0

balancer in the early 1980s, has been the

Other

world's largest

20.0

producer during

Oman

the 1990s. Not

Iraq

only did Saudi

Arabia increase

15.0

Kuwait

its production

United Arab Emirates

to fill the gap left by the loss

10.0

Iran

of Iraqi and Kuwaiti supplies after Iraq invaded

Saudi Arabia

5.0

Kuwait in 1990, but production declined in the

0.0

other two large producers, the United States and the Former Soviet Union.

Mideast production would have been higher throughout the 1990s if Iraq's production (graph) had not been constrained by the United Nations sanctions imposed after Iraq invaded Kuwait in 1990. The so-called "Humanitarian Oil Sales" have provided Iraq only limited and closely controlled reentry into world oil markets.

Mideast production also would have been higher at various times if it had not been for the market-balancing role played with varying degrees of success by the Organization of Petroleum Exporting Countries (OPEC). OPEC currently includes Algeria, Indonesia, Iran, Iraq, Kuwait, Libya, Nigeria, Qatar, Saudi Arabia, the United Arab Emirates and Venezuela. Ecuador and Gabon withdrew their membership at the end of 1992 and 1994, respectively.

Million barrels per day

1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003

Crude Oil Production: North America 1980-2003

14.0

12.0

10.0

Million barrels per day

8.0

6.0

4.0

2.0

0.0

1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003

North America (graph) is the second largest producing area after the Middle East. The United States, the second largest producing country in the world, accounts for almost 60 percent of the North American region’s total. Canada, the United States and Mexico all have long production histories, and production from mature fields has been declining. However, a new surge in technology has benefited both new field development and more complete production from existing fields.

North Sea production, off the United Kingdom and Norway, began in the late 1970s. In contrast to predictions from the early 1980s of

Crude Oil Production: North Sea

the imminent decline in the

7.0

region’s production, the

6.0

North Sea has yet to see its peak. The region's

5.0

success with new exploration and

Million barrels per day

4.0

production technology, and

hence its continuing volume

3.0

growth, has been a

central factor in world oil markets

2.0

1.0

for a decade.

0.0

Eastern Europe and Former USSR Oil Production

14.0

Former U.S.S.R. Former Czechoslovakia12.0

Czech Republic Bulgaria Belarus

10.0

Azerbaijan Albania Uzbekistan

8.0

Ukraine Turkmenistan Tajikistan

Slovakia Russia Romania Poland 6.0

4.0

Lithuania Kyrgyzstan Kazakhstan

2.0

Hungary Georgia

0.0

Production in the Soviet Union peaked at about 12 million barrels a day in the early 1980s when it was the top world oil producer. The region’s demand collapse, in combination with its aggressive production targets set to maintain foreign exchange, masked its rapid production decline in the late 1980s as the Soviet Union broke up. The former Soviet Union has recently been the second-ranked producer, after Saudi Arabia. One of the most visible new production prospects has been the Caspian Sea in Central Asia, in spite of the enormous logistical and political hurdles involved in getting the oil produced to world markets.

U.S. Oil Production

Because the United States is the world's largest importer, as discussed in the chapter on Trade, it is easy to forget that it:

is the oldest major global oil producer; is formerly the Number 1 global oil producer; is currently the Number 3 global oil producer; has produced more oil, cumulatively, than any other country (180 billion barrels from 1918 to 1999); has produced more oil, cumulatively, than the current reserves of any country but Saudi Arabia.

Million Barrels Per Day

Production in the United States has several unusual aspects. One is the private ownership of resource rights. In most major producing countries, the government owns the rights to develop resources. For privately owned property in the United States, the decision to explore for and produce oil is between the landowner and the producing company. The producing company compensates the landowner by the payment of a royalty on each barrel of oil produced. Early in the industry's development, there were few government restrictions. Now, there are overriding rules about well spacing and environmental standards. The only government agency to restrict production volume was the Texas Railroad Commission, which limited production in Texas depending on projected demand and production volumes in other areas of the United States. However, since the early 1970s, there have been no restrictions to production by any government agency.

The private ownership of resource rights contributes to two other aspects unique to production in the United States --the active participation of thousands of independent producers and the prevalence of the “stripper” well, one producing less than 10 barrels a day. As the industry was developing, many entrepreneurs with limited capital resources, but a high tolerance for risk, joined its ranks and, in fact, discovered some of the largest fields in the United States. Most of the time, their finds were less dramatic, but large enough for a small company to be a success. The company's success was, of course, the landowner's success as well. Many of the wells never flowed with very high volume and, as they aged, volume dropped. Nonetheless, stripper wells are likely to remain in production as long as the price of oil covers the production cost. They currently account for about 75 percent of all wells in production in the United States and produce somewhat less than 900,000 barrels per day, 15 percent of the total U.S. crude oil production.

Just as oil resources are not evenly distributed around the globe, neither are they evenly distributed throughout the United States. Given the way production data are reported, the biggest production region by far is the U.S. Gulf Coast, and the largest producing state is Texas (see graph). The Gulf Coast region is home to two of the most important producing provinces, the Permian Basin, located inland in West Central Texas and Eastern New Mexico, and the Federal Offshore portion of the Gulf of Mexico.

Texas has been the largest producing state since the late 1920s, when it surpassed California. For a time in the late 1980s, Alaska rivaled Texas, as the more mature Texas fields declined and production from the giant Alaskan North Slope fields, begun in 1977, was still approaching its peak level of about 2 million barrels per day. Since that time, however, production from the Alaskan North Slope has fallen rapidly.

Annual Oil Production for Texas and Federal Offshore (PADD 3)

Production 1,400 from the

Federal

now about

Federal Offshore (PADD 3) Texas

offshore,

equal to

the Alaskan

output from

1,200

North

Slope, is

1,000

limited by

policy to

California

western and

of Mexico.

production

“plays,” led

resurgence

Million Barrels Annually

and the

central Gulf

800

New

areas, or

600

to a

in activity in

the Gulf of ⁴⁰⁰

Mexico, the only area

with active new leasing. 200

Leasing, drilling,

production and the

numbers of

0

fields under

1981 1983 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003

development all set records in 1997, as the deepwater Gulf of Mexico became the place to be for almost any larger oil company, domestic or foreign. These new prospective oil producing areas are further offshore, in the much more challenging deepwater. The pace and timing of these deepwater plays, like all other upstream exploration, were impacted by 1998's low prices.

Federal Offshore

Production from the Federal offshore, now about equal to output from the Alaskan North Slope, is limited by policy to California and the western and central Gulf of Mexico. New production plays in the Gulf of Mexico, the only area with active new leasing, led to a resurgence in activity there. Leasing, drilling, production and numbers of fields under development all set records in 1997, as the deepwater Gulf of Mexico became the place to be for almost any larger oil companies, domestic or foreign.

The important characteristic of these new plays is their water depth. When production in the Gulf of Mexico peaked in the mid-1980’s, it came almost exclusively from the waters over the Continental Shelf. The new plays are further offshore, in the much more challenging deepwater. Production is already occurring in water depths of one mile. Recent discoveries suggest that this water depth record could be extended to a mile and a half in the next couple of years, by which time drilling could have moved out to waters two miles deep.

As noted throughout the Supply chapter, technology has been the key to opening up these new production plays. New deepwater production options such as tension leg platforms (TLP), spars, compliant towers, and subsea completions have allowed companies to do what was deemed impossible until quite recently -- operate in deep water, while three technological advances have been particularly important in making new discoveries economically viable: 3-D seismic, horizontal and directional drilling, and multi-lateral completions.

The number of discoveries that it makes sense to develop in the deepwater Gulf of Mexico has been further increased by royalty relief that is worth at least $2.00-$3.00 a barrel on initial production and by an unexpected bonus: an unusually high level of production per well for the United States. Instead of a stripper well’s 10 barrels, or even a Gulf of Mexico shallow water well’s 1,000 barrels, daily production rates of 10,000 barrels have been common and as high as 30,000 barrels have been achieved. As a result, the number of new fields coming onstream annually in the deepwater jumped to 15-20 from a lifetime average of 2.

This surge was widely expected to double deepwater Gulf of Mexico production to 2 million barrels per day by the year 2000 or shortly thereafter, turning the Gulf in total into the preeminent oil producing region of the United States. Such growth would slow or even temporarily halt the long term decline in United States production, curb the rate of growth of United States crude oil imports, and have a significant impact on crude markets throughout the Gulf Coast and the Midwest. The pace and timing of these deepwater plays, like all other upstream exploration, was impacted by 1998's low prices.

Consumption

This section reviews the ways we use petroleum and the data sources that depict its use. When petroleum products are burned to produce energy, they may be used to propel a vehicle, as would be the case with gasoline, jet fuel, or diesel fuel; to heat a building, as with heating oil or residual fuel oil; or to produce electric power by spinning a turbine directly or by creating steam to spin a turbine. In addition, of course, oil products may be used as a raw material (a "feedstock") to create petrochemicals and products, such as plastics, polyurethane, solvents, and hundreds of other intermediate and end-user goods.

Global Oil Consumption

The industrialized countries are the largest consumers of oil but until 1998 had not been the most important growth markets for some years. The countries of the Organization for Economic Cooperation and Development (OECD), for instance, account for almost 2/3 of worldwide daily oil consumption. In contrast, however, oil demand in the OECD grew by some 11 percent over the 199197 period, while demand outside the OECD (excluding the Former Soviet Union) grew by 35 percent. The Former Soviet Union presents a special case. The collapse of the Russian economy that accompanied the collapse of Communism led to a decline in oil consumption of more than 50 percent over the 1991-98 period.

The developed economies use oil much more intensively than the developing economies, and Canada and the United States stand almost alone in their consumption of oil per capita. For instance, oil consumption in the United States and Canada equals almost 3 gallons per day per capita. (The difference is these countries' transportation sectors, with their dependence on private vehicles to travel relatively long distances.) Oil consumption in the rest of the OECD equals 1.4 gallons per day per capita. Outside of the OECD, oil consumption equals 0.2 gallons per day per capita.

Regionally, the largest consuming area remains North America (dominated by the United States), followed by Asia Asia & Oceania (with Japan the

World Oil Consumption

Africa largest

Million Barrels Per Day

Eastern Europe & Former U.S.S.R. Western Europe Central & South America North America

consumer),90.000

Middle East

Europe (where consumption is

80.000

more evenly spread among

70.000

the nations), and then the other

60.000

regions. As the regional graphs

50.000 illustrate, Asia was the region with the fastest demand growth until the 1998

40.000

30.000

economic crisis in East Asia.

20.000

The region's economic

10.000

upheaval is a central reason

0.000

for the oil price 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 _{collapse of 1998.}

The United States and Canada use oil more for transportation than for heat and power, but the opposite pattern holds for most of the rest of the world: most regions use more oil for heat and power than for transportation. As a result, global demand for oil is highest in the Northern Hemisphere's cold months. There is a swing of 3-4 million barrels per day (some 5 percent) between the 4th quarter of the year, when demand is highest, to the 3rd quarter, when it is lowest. (The precise amount varies from year-to-year, depending on weather, economic activity and other factors.) While the 4th quarter is not the coldest in any region, estimated demand calculations are swollen by the traditional stock building that occurs during the period.

Demand for crude oil is derived from the demand for the finished and intermediate products that can be made from it. In the short-term, however, demand for crude oil may be mismatched with the underlying demand for petroleum products. This misalignment occurs routinely as a result of stock changes: the need to build stocks to meet seasonal demand, for instance, or the desire to reduce stocks of crude oil for economic reasons. In the longer term, blending non-petroleum additives into petroleum products (such as ethanol or other oxygenating agents into gasoline) can also reduce crude oil demand relative to demand for finished products.

U.S. Consumption by Sector

The use of petroleum products as vehicle fuels is classified as "transportation" use. In the United States, in contrast to other regions of the world, about 2/3 of all oil use is for transportation, as shown in the graph. (In most of the rest of the world, oil is more commonly used for space heating and

power generation than for transportation.) Gasoline, in turn, accounts for about 2/3 of the total oil used for transportation in the United States. Other petroleum products commonly used for transportation include diesel fuel (used for trucks, buses, railroads, some vessels, and a few passenger autos), jet fuel, and residual fuel oil (used for tankers and other large vessels).

In the years since the Arab Oil Embargo of 1973/74, transportation has become a more important component of oil demand, as price and policy encouraged the substitution where possible of other fuels for oil. In

non-transportation or "stationary" uses -- burning oil for space heating in buildings, such as homes, apartment buildings, stores, and schools, and burning oil for power to run factory equipment, or to generate electricity -- substitution of other energy sources for oil was possible, some of it immediately and some with the turnover of equipment. In transportation uses, in contrast, there is little fuel substitution possible in the short term and only limited potential in the longer term, given current technology. Consumption of oil in these stationary uses -- residential, commercial, industrial and electricity generation -- fell from a peak of 8.7 million barrels daily in 1978 (about 47 percent of total oil use) to a low of less than 6 million barrels per day in the late 1980's and early 1990's. Consumption in these sectors has been 6.5-7.0 million barrels per day more recently.

Thus, while oil continues to account for more than 95 percent of all the energy used for transportation in the United States, oil accounts for less than 20 percent of the energy consumed for other, stationary uses, down from 30 percent in 1973.

U.S. Consumption by Product

Gasoline is the perfect example of a consumer product: available everywhere, purchased often and in

easy transactions. Its consumption accounts for almost 45 percent of all oil use (see graph). The dominance of gasoline in the oil mix is not new; gasoline has been the most important oil product since the 1920's. The quest to maximize gasoline production has been the driver in the development of refinery technology and design in the United States, as discussed in the section on refining.

After the Arab Oil Embargo, the implementation of gasoline consumption standards for new passenger cars (the "Corporate Average Fuel Economy" or CAFE standards) was important in moderating gasoline demand growth, even while both the number of cars on the road and the miles they traveled

increased. Beginning in the early 1990's, however, the burgeoning popularity of pick-up trucks and sports utility vehicles (SUV's) for passenger travel has sparked new gasoline demand growth. These light trucks and SUV's are not as fuel efficient as standard automobiles and, as they have become more and more popular, have reduced the average fuel economy of cars on the road. (Whereas the fleet averages for light trucks and SUV's must be at least 20.7 miles per gallon, automobiles must average a minimum of 27.5 miles per gallon.)

Government mandates in recent years have created a variety of U.S. gasoline grades to meet different regional environmental records. So-called "reformulated gasoline," designed to control ground-level ozone, is largely a phenomenon of the Northeast and some large cities elsewhere in the country. In addition, California requires a special version of reformulated gasoline. Reformulated gasoline accounts for about 30 percent of nationwide gasoline consumption. "Oxygenated" gasoline is required during the cold months in areas where carbon monoxide levels are high. Even during the October - March gasoline season, the special gasoline for these areas accounts for less than 10 percent of the nationwide total. It is important to note that the mandate to supply these different grades regionally and seasonally imposed a significant reduction in distribution flexibility, because gasoline can no longer be interchanged from one region to another, or held over from winter to summer. This lack of flexibility was one of the important contributors to the gasoline price spike experienced during 2000.

Distillate fuel oil use ranks second behind gasoline. Unlike gasoline, which is used almost exclusively in the transportation sector, distillate fuel oil is used in every sector: for home heating fuel, for industrial power, for electric generation, as well as for diesel-fueled vehicles. The largest use of distillate is in the transportation sector. Diesel fuel used in vehicles on the highway -- trucks, buses, passenger cars -- must be low sulfur (no more than 0.05 percent sulfur by weight), an Environmental Protection Agency regulation implemented in late 1993. Distillate fuel oil used off the highway -- for vessels, railroads, farm equipment, industrial machinery, electric generation, or space heating -- is not subject to the low on-highway standard, but as a matter of course contains only a small amount of sulfur, commonly 0.2 percent sulfur by weight. (California has a more stringent standard, requiring that all distillate meet the current low highway specification.) The U.S. Department of the Treasury also requires that the non-highway product be dyed to distinguish it from the taxable on-highway diesel. These requirements also limit distribution flexibility for distillate fuels, requiring segregated storage and transportation, and preventing one product from easing shortages of the other.

The use of distillate fuel oil for home heating was once much more prevalent than it now is. The Mid-Atlantic and, more particularly, New England remain the two regions with an appreciable share of oil-heated single family homes. In other regions, older homes have been converted from oil heat to gas, and oil no longer accounts for a noticeable share of the new home construction market. Thus, the seasonal increase in inventories and demand is largely confined to the Northeast.

Jet fuel is the third-highest product in demand and, like gasoline, is largely confined to use in the transportation sector. (There is also limited use of jet fuel as a stationary turbine fuel, and occasionally it is used to blend into heating oil to stretch supplies during periods of peak demand.) The military formerly utilized a different, naphtha-based product for its planes, instead of the commercial, kerosene-based product. In recent years, however, the military has largely converted to kerosene-based jet fuel.

Residual fuel oil, the heavy fuel used to run boilers for power generation and to propel tankers and other large vessels, once accounted for as much as 30 percent of the oil burned in stationary uses, and 20 percent of all United States oil use. By 1997, those shares had fallen to 7 percent and 4 percent, respectively. Residual fuel oil's heyday, the 1970's, represented a particular time in energy markets. The natural gas supply was constrained by Federal regulation and, although U.S. refiners had little incentive to make the low priced heavy fuel oil, refineries in the Caribbean and Venezuela supplied the East Coast's residual fuel oil for electric power generation, urban space heating in large apartment

buildings, and industrial power. The market for residual fuel oil was eroded by a variety of factors, including price competition with (newly available) natural gas and environmental restrictions. Residual fuel oil's use for apartment building space heating is now confined largely to older buildings in New York City, and its use in electric generation is limited largely to a few utilities in Florida and the Northeast.

By now, the major product with the most pronounced seasonal pattern in its consumption is high sulfur distillate, the kind used for home heating, with high consumption periods during the winter months. Its use, concentrated in the Northeast, represents a relatively small share of

total consumption in the United States, however. Gasoline demand, which rises in the warmer months, exhibits a shallower swing between the "low" demand season and the "high" demand season. At the low end (generally January/February), estimated gasoline consumption is 7-8 percent below the annual average and, at the high end (July/August), it is some 4 percent above the annual average. (See graph.)

U.S. Consumption by Region

Different regions exhibit different oil consumption patterns. Population and regional economic activity are two important determinants, but the traditional availability of alternative fuels, petroleum transportation, geography, and a host of other factors are also important. The East Coast consumes the largest volume of oil of the five major regions of the country, as shown in the graph. For data gathering and analysis, the United States is divided into the five broad regions, the Petroleum Administration for Defense Districts or PADD's delineated in World War II. On a per capita basis, however, the East Coast, Midwest and the West Coast consume about the same amount, and less than the two other regions, the Gulf Coast and the Rockies. The Gulf Coast, the heart of the U.S. petroleum industry, presents an interesting case, because more than 25% of the Gulf Coast's "consumption" is not use of oil for energy but rather as a feedstock to make petrochemicals, and finally petroleum-based products such as a variety of plastics, polyurethane, and synthetic fibers. The Rockies are another interesting case: the sparsely populated region shows low

consumption on an absolute basis, but relatively high regional consumption per capita; high use of transportation fuels to travel long distances makes the difference.

Trade

This section looks at petroleum trade and transportation. The main oil producing areas are not the same as the main consuming areas. Hence, oil must be moved from regions where supply is greater than demand -- exporting regions -- to regions where demand is greater than supply -– importing regions. The "have/have not" balance results in oil flows from one international region to another, from one country to another, and from one region within a country to another. These flows, dictated by economics, logistics, and temporary imbalances in supply and demand, are central to the efficient operation of the oil market.

Regional Importers and Exporters

As one might expect, the world’s three largest consuming regions -- North America, Europe, and Asia-Pacific -- are all importers. All the other regions are exporters.

The Middle East still exports vastly more oil than any other region, despite the strong growth in production in other areas in recent years. This global dependence on Middle East oil makes the geopolitical importance of the Middle East readily understandable.

There is less variation among the importing regions. In the decade preceding its 1997-98 financial crisis, Asia-Pacific's economic boom propelled it into the Number 1 spot, with import growth more than double that of any other region’s. Even though the United States is the largest individual importer, both net and gross, North America as a region ranks third; because Canada and Mexico are two of the United States’ three top oil suppliers, their exports to the United States offset U.S. imports from these neighbors in the regional calculation. (Net imports are gross imports minus gross exports). This has kept North America’s import dependency down to not much over 30 percent, half that of the Asia-Pacific region at its 1997 peak. The latter’s import dependency, and even its import volume, have declined since then, but not by enough to threaten its position as the world’s top importing region.

Global Patterns of Oil Trade

Oil Trade: Highest Volume, Highest Value

There is more trade internationally in oil than in anything else. This is true whether one measures trade by how much of a good is moved (volume), by its value, or by the carrying capacity needed to move it. All measures are important and for different reasons. Volume provides insights about whether markets are over- or under-supplied and whether the infrastructure is adequate to accommodate the required flow. Value allows governments and economists to assess patterns of international trade and balance of trade and balance of payments. Carrying capacity allows the shipping industry to assess how many tankers are required and on what routes. Transportation and storage play a critical additional role here. They are not just the physical link between the importers and the exporters and, therefore, between producers and refiners, refiners and marketers, and marketers and consumers; their associated costs are a primary factor in determining the pattern of world trade.

Distance: The Nearest Market First

Generally, crude oil and petroleum products flow to the markets that provide the highest value to the supplier. Everything else being equal, oil moves to the nearest market first, because that has the lowest transportation cost and therefore provides the supplier with the highest net revenue, or in oil market terminology, the highest netback. If this market cannot absorb all the oil, the balance moves to the next closest one, and the next and so on, incurring progressively higher transportation costs, until all the oil is placed.

The recent growth in United States dependence on its Western Hemisphere neighbors is an illustration of this "nearer-is-better" syndrome. For instance, Western Hemisphere sources now supply over half the United States import volume (see graph), much of it on voyages of less than a week. Another quarter comes from elsewhere in the area called the Atlantic Basin, those countries on both sides of the Atlantic Ocean. This oil, coming especially that which comes from the North Sea and Africa, and takes just 2-3 weeks to reach the United States, boosts the so-called short-haul share of U.S. imports to over three-quarters. Most North Sea

and North and West African crude oils stay in the Atlantic Basin, moving to Europe or North America on routes that rarely take over 20 days. In contrast, voyage times to Asia for just the nearest of these, the West African crude oils, would be over 30 days to Singapore, rising to nearly 40 for Japan. Not surprisingly, therefore, most of Asia’s oil comes instead from the Middle East, only 20-30 days away.

Mexico and Venezuela have consciously helped the trend toward short-haul shipments. They pro-actively took the strategic decision to make as large and as profitable a market as possible for poor quality crudes, since their reserves are unusually biased toward those hard-to-place grades. Both countries therefore targeted their nearest markets, the U.S. Gulf Coast and the Caribbean, for joint venture refinery investments. They began with refineries that had traditionally run their crudes, and then with refineries that might be upgraded to do so. This policy has turned poor quality crudes into the preferred crude at these sites, significantly increasing the crude oil self-sufficiency of the Western Hemisphere.

A change in trade flow patterns can also be of critical importance to the shipping industry. For example, the Suez crisis of 1957 forced tanker owners back to using the much longer route around the Cape of Good Hope, and resulted in the development of Very Large Crude Carriers (VLCC’s) to reduce that voyage’s higher costs. The shift to short-haul routes in the 1990's was also critical. Using the growth in world trade volumes as a proxy for demand, tanker owners had been expecting a return to a strong tanker market. But the combination of the surge in short haul imports in the Atlantic Basin and the shift of Middle East exports from the longer United States to shorter Asian voyages led to a sharp decline in average voyage length. This decline was accelerated by the return of Iraqi crude exports, many of which move on the extremely short route from the Black Sea end of the Iraq-Turkey pipeline to the Mediterranean. The tanker owners' outlook was thus fading even before world trade volumes were undermined by the Asian crisis.

Quality, Industry Structure, and Governments

In practice, trade flows do not always follow the simple "nearest first" pattern. Refinery configurations, product demand mix, product quality specifications –- all three of which tie into quality -- and politics can all change the rankings.

Different markets frequently place different values on particular grades of oil. Thus, a low sulfur diesel is worth more in the United States, where the maximum allowable sulfur is 0.05 percent by weight, than in Africa, where the maximum can be 10 to 20 times higher. Similarly, African crudes --low in sulfur -- are worth relatively more in Asia, where they may allow a refiner to meet tighter sulfur limits in the region without investing in refinery upgrades. Such differences in valuing quality can be sufficient to overcome transportation cost disadvantages, as the relatively recent establishment of a significant trade in long-distance African crudes to Asia shows. The cost of moving oil into a particular market can be further distorted from the principle of nearest first by government policies such as tariffs, as discussed in the chapter on Prices.

In addition, both buyers and sellers may impose restrictions. For instance, the United States prohibits the importation of Iranian and Libyan oil, and the United Nations allows only limited sales of Iraqi oil. On the seller's side, Mexico formerly limited sales to the United States to 50 percent of its exports, reflecting concerns about dependence on the United States specifically and about dependence on one geographic market in general. Saudi Arabia's national security concerns, on the other hand, dictate that it maintain a very high profile as a supplier to the United States market, even at the cost of lower netbacks. Indeed, it was the top United States crude supplier in 1999.

Crude versus Products

Crude oil dominates the world oil trade. The risk-weighted economics clearly favor siting refineries close to consumers rather than close to the wellhead. This siting policy takes maximum advantage of the economies of scale of large ships, especially as local quality specifications are increasingly fragmenting the product market. It maximizes the refiner’s ability to tailor the product output to the market’s short-term surges such as those caused by weather, equipment outages, etc. In addition, this policy also guards against the very real risk that governments will impose selective import restrictions to protect their domestic refining sector.

As noted in the section on Refining, there are a limited number of refining centers that are at odds with this general rule, having been developed to serve particular export markets. These export refining centers -- Singapore, the Caribbean, and the Middle East -- give rise to some regular inter-regional product moves, but they are the exception. The inter-regional products trade is largely a temporary market-balancing function. Some inter-regional flows are extremely short lived, as when extremely cold weather in Europe causes the United States to export heating oil there. A longer-lived example arose when a large proportion of European drivers opted for diesel cars, leaving the region in the late 1990's with surplus capacity to produce gasoline for export to the United States.

Tankers and Pipelines

There are two modes of transportation for inter-regional trade: tankers and pipelines. Tankers have made global (intercontinental) transport of oil possible, and they are low cost, efficient, and extremely flexible. Pipelines, on the other hand, are the mode of choice for transcontinental oil movements.

Not all tanker trade routes use the same size ship. Each route usually has one size that is the clear economic winner, based on voyage length, port and canal constraints and volume. Thus, crude exports from the Middle East -- high volumes that travel long distances -- are moved mainly by Very Large Crude Carriers (VLCC’s) typically carrying over 2 million barrels of oil on every voyage. The VLCC's economies of scale outweigh the constraints imposed: they are too large for all the ports in the United States except the Louisiana Offshore Oil Port (LOOP). Thus, they must have some or all of their cargo transferred to smaller vessels, either at sea (lightering) or at an offshore port (transshipment). In contrast, ships out of the Caribbean and South America are routinely smaller and enter ports in the United States directly. Because of such ship size differences, a long voyage can sometimes be cheaper on a per barrel basis than a short one.

Pipelines are critical for landlocked crudes and also complement tankers at certain key locations by relieving bottlenecks or providing shortcuts. The only inter-regional trade that currently relies solely on pipelines is crude from Russia to Europe. Export pipelines are also needed for production from the Caspian Sea region, where the protracted commercial and political debate illustrates the greatest negative for pipelines crossing national boundaries: their political vulnerability.

Pipelines come into their own in intra-regional trade. They are the primary option for transcontinental transportation, because they are at least an order of magnitude cheaper than any alternative such as rail, barge, or road, and because political vulnerability is a small or non-existent issue within a nation's border or between neighbors such as the United States and Canada. (Pipelines are also an important oil transport mode in mainland Europe, although the system is much smaller, matching the shorter distances.)

The development of large diameter pipelines during World War II allowed the development of the vast pipeline network in North America that moves crude oil and product within Canada, from Canada into the United States, and within the United States. Domestically, the 200,000 miles of pipelines account for about two-thirds of all the oil shipments, when adjusted for volume and distance. They move domestic crudes from producing areas like California, the Rockies, and West Texas, and imported crudes from the receiving ports, and transport them to the refining centers. The United States also relies heavily on pipelines to transport petroleum products from refining centers, such as the Gulf Coast, to consuming regions, like the East Coast.

Fungibility is an important factor in transportation economics. Because the oil is broadly interchangeable (fungible), it can be mixed without a significant diminution in value. As environmental mandates have required different regional and seasonal qualities of gasoline, the required batching for transport and segregation for storage has increased substantially. Thus the logistics flexibility inherent in a product's fungibility -- the ability to substitute one shipment for another, to exchange between regions, for instance -- has disappeared. While this is invisible to consumers during normal times, it contributes to market upheavals and price spikes in times of surprises in demand or supply, as during the early driving season in 2000.

Import Dependency

As already noted, the United States continues to sit at the top of the national rankings of importers, now accounting for around a quarter of total world imports. Yet its import dependency, the percentage of demand met by imports, is significantly lower, at about 50 percent, than that of its international partners. Industrialized countries such as Japan and Germany have import dependency levels of 90-100 percent.

The Middle East has long been regarded as politically unstable and its oil supply, therefore, subject to disruptions. U.S. policy makers have viewed its increased dependence on Western Hemisphere supplies and its decreased dependence on the Middle East as a welcome development. (Again, an international contrast: the Asia-Pacific region now relies on the Middle East for almost 90 percent of its imports and hence 50 percent of its consumption.)

As the Middle East holds the majority of the world’s oil reserves, increasing U.S. dependence on this region had been viewed as the inevitable partner of import growth. In light of the shift toward Western Hemisphere, short-haul import sources, Saudi Arabia is the only significant Middle East supplier left, and then only because of its willingness to trade security for revenue as noted above. Yet, although U.S. dependence on the long-haul Middle East has fallen sharply, this has not made U.S. prices less vulnerable to a disruption in Middle East supplies. Since oil is a global market, the relevant measure for that vulnerability is not U.S. dependence, but world dependence on Middle East oil -- and that has not shrunk.

While interdependence in the Western Hemisphere has been a major United States policy objective, it is important to realize that this combination of size and geographic closeness creates its own short-term vulnerability. Take for instance the case of Hurricane Roxanne, which severely damaged a large part of Mexico’s production facilities in the Gulf of Mexico in late 1995. Some 40 million barrels of Mexico’s production was eliminated, the vast majority earmarked for refineries along the U.S. Gulf Coast. These refiners, less than a week’s sailing time away, had little time to compensate for this sudden hole in their planned supplies.

US Oil Imports by PADD Region		differences between different
		parts of the United States in
6,000		terms of their involvement in
	West Coast (PADD 5)	and dependence on
	Rocky Mountain (PADD 4)	international trade. Most of
4,000 5,000	Gulf Coast (PADD 3) Midwest (PADD 2) East Coast (PADD 1)	these differences are the direct result of the uneven distribution of both production and refining across the United
		States. Thus, as shown in the
3,000		graph , the East Coast imports over half of all the
		products that come to the
2,000		United States, because it is the largest consuming area in
		the United States but, for
1,000		historical reasons, it has only
		enough capacity to meet
		around 1/3 of those needs
0		from its own refining. It fills

U.S. Trade Flows

Crude Oil and Products Mix

Crude oil dominates U.S. imports just as it dominates world trade and for much the same reasons. Therefore, all of the U.S. leading suppliers are major crude producers. Imports of crude oil, having grown to replace declining domestic production and to meet growing demand, now account for around 80 percent of the total. Product import volumes have stayed relatively stable.

In spite of the seeming stability in product imports, there have been significant structural shifts over the last couple of decades in the mix of products that the United States imports. Residual fuel oil, for instance, formerly accounted for the majority of all product imports, but its share has shriveled into insignificance as utilities and industrial users have switched to other fuels, particularly nuclear and natural gas. In its place, the United States now imports a much higher proportion of petroleum products that are reprocessed or blended by the oil industry, such as the unfinished gasoline and gasoline blending components that are central to reformulated gasoline supply.

Canada is the one country that delivers oil to the United States by pipeline. (Only its relatively new offshore Eastern Canadian production, from fields like Hibernia, depends on tankers.) The vast majority of Canada’s crudes are landlocked and rely almost exclusively on trunk-lines from Western Canada that tie into the U.S. transcontinental network to reach their main export markets, which lie all across the Northern Tier of the United States. As domestic production has declined, these Canadian crudes have had a greater reach into the United States.

U.S. Exports

Since the United States is the world’s largest importer, it may seem surprising that it also exports around 1 million barrels a day of oil, predominantly petroleum products. Due to various logistical, regulatory, and quality considerations, it turns out that exporting some barrels and replacing them with additional imports is the most economic way to meet the market’s needs. For example, the Gulf Coast may export lower quality gasoline to Latin America while the East Coast imports higher quality gasolines from Europe. Exports in the 1990’s have been at record highs, the efficiency of the oil market has been increased, and consumers everywhere have benefited.

U.S. Regional Trade

There are significant

1999 2000 2001 2002 2003 2004

Million Barrels Annually

US Product Imports by PADD Region

1,200

the product gap with

West Coast (PADD 5) Rocky Mountain (PADD 4)

supplies from other parts of

Gulf Coast (PADD 3)

the United States,

1,000 Midwest (PADD 2)

particularly the Gulf Coast,

East Coast (PADD 1)

and with imports. Its limited volume of refining capacity

800

also keeps it a distant third as a crude importer. However, because its local

600

production is so insignificant, its crude import dependency is the highest of all, at

400

almost 100 percent.

The only other region that

200

imports significant amounts of products is the Gulf Coast. Its focus is not, like

0

the East Coast's, on

products that can be

supplied directly to the consumer, but on refinery feedstocks and blendstocks, to support its role as

the main U.S. refining and petrochemical center. That role, plus the need for all the Midwest’s non-

Canadian crude imports to move through the Gulf Coast’s ports and pipelines too, has also led to the

Gulf Coast being by far the most important crude oil importing region in the United States, accounting

for nearly two-thirds of the total.

The trade among regions of the United States is focused on the eastern half of the country. As shown in the graph, the Midwest and East Coast account for 90 percent of the inter-regional flow, the flow between Petroleum Administration for Defense Districts (see previous map above). The Gulf Coast is by far the largest supplier, accounting for more than 80% of the inter-PADD flow. In contrast, the Rockies and the West Coast are isolated, in petroleum logistics terms, from the rest of the country. The easy flow of petroleum from the Gulf Coast to the Midwest and the East Coast mean that incremental supply is more readily available to those markets in the event of a demand surge or supply drop.

In contrast, the West Coast, and the California market in particular, cannot so readily attract incremental supplies. Thus, the California refinery outages that occurred in the Spring of 1999, resulted in a large price increase as market players scrambled for additional supply, none of which was available close at hand, or cheaply. The California market's isolation is more than just geographic: the State imposes unique and stringent quality restrictions on both its gasoline and its off-highway diesel, making what otherwise might be available to augment California product supplies unsuitable.

This section focuses on refining, the complex series of processes that manufactures finished petroleum products out of crude oil and other hydrocarbons. While refining began as simple distillation, refiners must use more sophisticated additional processes and equipment in order to produce the mix of

Million Barrels Annually

products that the market demands. Generally, this latter effort minimizes the production of heavier, lower value products (for example, residual fuel oil) in favor of lighter, higher value products (for example, gasoline).

Refining

Simple Distillation

The core refining process is simple distillation, illustrated in a stylized fashion at the right. Because crude oil is made up of a mixture of hydrocarbons, this first and basic refining process is aimed at separating the crude oil into its "fractions," the broad categories of its component hydrocarbons. Crude oil is heated and put into a still -- a distillation column -- and different products boil off and can be recovered at different temperatures. The lighter products --liquid petroleum gases (LPG), naphtha, and so-called "straight run" gasoline -- are recovered at the lowest temperatures. Middle distillates -- jet fuel, kerosene, distillates (such as home heating oil and diesel fuel) -- come next. Finally, the heaviest products (residuum or residual fuel oil) are recovered, sometimes at temperatures over 1000 degrees F. The simplest refineries stop at this point. Most in the United States, however, reprocess the heavier fractions into lighter products to maximize the output of the most desirable products, as shown schematically in the illustration, and as discussed below.

Downstream Processing

Additional processing follows crude distillation, "downstream" (or closer to the refinery gate and the consumer) of the distillation process. Downstream processing is grouped together in this discussion, but encompasses a variety of highly complex units designed for very different upgrading processes. Some change the molecular structure of the input with chemical reactions, some in the presence of a catalyst, some with thermal reactions.

In general, these processes are designed to take heavy, low-valued feedstock --often itself the output from an earlier process -- and change it into lighter, higher-valued output. A catalytic cracker, for instance, uses the gasoil (heavy distillate) output from crude distillation as its feedstock and produces additional finished distillates (heating oil and diesel) and gasoline. Sulfur removal is accomplished in a hydrotreater. A reforming unit produces higher octane components for gasoline from lower octane feedstock that was recovered in the distillation process. A coker uses the heaviest output of distillation, the residue or residuum, to produce a lighter feedstock for further processing, as well as petroleum coke.

US Refinery Yields 1999 - 2004

As noted above and	120
in the section on
demand, U.S.
demand is centered	100
on light products,
such as gasoline.
As shown in the graph(Note –	80ield
yields exceed 100	al Y
percent as losses in processing	60 of Tot
have not been
taken into	Percent
consideration),	40
refiners in the
United States more
closely match the	20
mix of products
demand by using
downstream	0
processing to move
from the natural

yield of products from simple distillation, illustrated earlier, to the U.S. demand slate, illustrated here. After simple distillation alone, the output from a crude oil like Arab Light would be about 20 percent of lightest, gasoline-like products, and about 50 percent of the heaviest, the residuum. After further processing in the most sophisticated refinery, however, the finished product output is about 60 percent gasoline, and 5 percent residuum.

Crude Oil Quality

The physical characteristics of crude oils differ. Crude oil with a similar mix of physical and chemical characteristics, usually produced from a given reservoir, field or sometimes even a region, constitutes a crude oil "stream." Most simply, crude oils are classified by their density and sulfur content. Less dense (or "lighter") crudes generally have a higher share of light hydrocarbons -- higher value products -- that can be recovered with simple distillation. The denser ("heavier") crude oils produce a greater share of lower-valued products with simple distillation and require additional processing to produce the desired range of products. Some crude oils also have a higher sulfur content, an undesirable characteristic with respect to both processing and product quality. For pricing purposes, crude oils of similar quality are often compared to a single representative crude oil, a "benchmark," of the quality class.

The quality of the crude oil dictates the level of processing and re-processing necessary to achieve the optimal mix of product output. Hence, price and price differentials between crude oils also reflect the relative ease of refining. A premium crude oil like West Texas Intermediate, the U.S. benchmark, has a relatively high natural yield of desirable naphtha and straight-run gasoline. Another premium crude oil, Nigeria's Bonny Light, has a high natural yield of middle distillates. By contrast, almost half of the simple distillation yield from Saudi Arabia's Arabian Light, the historical benchmark crude, is a heavy residue ("residuum") that must be reprocessed or sold at a discount to crude oil. Even West Texas Intermediate and Bonny Light have a yield of about one-third residuum after the simple distillation process.

In addition to gravity and sulfur content, the type of hydrocarbon molecules and other natural characteristics may affect the cost of processing or restrict a crude oil's suitability for specific uses. The presence of heavy metals, contaminants for the processing and for the finished product, is one example. The molecular structure of a crude oil also dictates whether a crude stream can be used for the manufacture of specialty products, such as lubricating oils or of petrochemical feedstocks.

Refiners therefore strive to run the optimal mix (or "slate") of crudes through their refineries, depending on the refinery's equipment, the desired output mix, and the relative price of available crudes. In recent years, refiners have confronted two opposite forces -- consumers' and government mandates that increasingly required light products of higher quality (the most difficult to produce) and crude oil supply that was increasingly heavier, with higher sulfur content (the most difficult to refine).

Other Refinery Inputs

In addition to crude oil that runs through a simple distillation, a variety of other specialized inputs, usually to downstream units, enhance the refiner's capability to make the desired mix of products. Among these products might be unfinished (partly refined) oil, or imported residual fuel oil used as input to a vacuum distillation unit. The supply pattern for "reformulated gasoline" or RFG, the mandated low-pollution product first required in 1995, includes an important share of blending components that are classified as refinery inputs. These blending components include oxygenates but consist mainly of products that could be classified as finished gasoline in other jurisdictions or products that require little additional blending to be classified as finished gasoline. While they are counted as "refinery inputs," they are brought to saleable specifications in terminals and blending facilities, not in conventional refineries.

U.S. Refining Capacity

U.S. refining capacity, as measured by daily processing

US Refinery Runs by PADD Region

capacity of crude oil distillation

Million Barrels per Day

18 16 14 12 10 8 6 4 2 0

units alone, has appeared relatively stable in recent years, at about 16 million barrels per day of operable capacity. While the level is a reduction from the capacity of twenty years ago, the first refineries that were shut down as demand fell in the early 1980's were those that had little downstream processing capability. Limited to simple distillation, these small facilities were only economically viable while receiving subsidies under the Federal price control system that ended in 1981. Some additional refineries were shut down in the late 1980's and

during the 1990's, always, of course, those at the least profitable end of a company's asset portfolio. At the same time, refiners improved the efficiency of the crude oil distillation units that remained in service by "debottlenecking" to improve the flow and to match capacity among different units and by turning more and more to computer control of the processing. Furthermore, following government mandates for environmentally more benign products as well as commercial economics, refiners enhanced their upgrading (downstream processing) capacity. As a result, the capacity of the downstream units ceased to be the constraining factor on the amount of crude oil processed (or "run") through the crude oil distillation system. Thus crude oil inputs to refineries ("runs") have continued to rise, and along with them -- given the stability of crude oil distillation capacity --capacity "utilization" rose throughout much of the 1990's. Utilization -- the share of capacity filled with crude oil -- reached truly record levels in the last half of the decade, nominally exceeding 100 percent for brief periods.

As with most aspects of the U.S. oil industry, the Gulf Coast is by far the leader in refinery capacity, with more than twice the crude oil distillation capacity as any other United States region. (The difference is even greater for downstream processing capacity, because the Gulf Coast has the highest concentration of sophisticated facilities in the world.) As discussed in the section on Trade, the Gulf Coast is the nation's leading supplier in refined products as in crude oil. It ships refined product to both the East Coast (supplying more than half of that region's needs for light products like gasoline, heating oil, diesel, and jet fuel) and to the Midwest (supplying more than 20 percent of the region's light product consumption.)

There are seasonal patterns in refinery input. In the United States, refinery runs mirror the overall demand for products --lower in the colder months and higher in the warmer months. In addition, as they move out of the gasoline season in the early autumn and then as they move into the next gasoline season in the late winter, refiners routinely perform maintenance. The duration and depth of the cutback in refining activity during each maintenance season is affected by a variety of factors, including the relative strength of the market for refined products. Therefore, when stocks are high and demand slack, the refinery maintenance season is likely to be longer and deeper. Refinery activity will also respond to the market's need (and hence relative prices) for product, with changes in the level of crude oil throughput as well as emphasis on one product over another.

World Refining Capacity

Broadly speaking, refining developed in consuming areas, because it was cheaper to move crude oil than to move product. Furthermore, the proximity to consuming markets made it easier to respond to weather-induced spikes in demand or to gauge seasonal shifts. Thus, while the Mideast is the largest producing region, the bulk of refining takes place in the United States, Europe or Asia.

There have historically been a few exceptions, concentrations of refining capacity that were not proximate to consuming markets. A refining center in the Caribbean, for instance, supplied heavy fuel oil to the U.S. East Coast where it was used for power, heat, and electric generation. As the demand for this heavy fuel oil, or residual fuel oil, waned, so did those dedicated refineries. While the Caribbean refineries, as well as refineries in the Middle East and in Singapore, were built for product export, they are the exception. As such, most refineries meet their "local" demand first, with exports

providing a temporary flow for balancing supply and

US Crude Oil Refining Capacity and Inputs thru 2004

demand.

100

largest concentration of⁹⁰ refining capacity is in

80 North America (in fact,

70

United States),

Capacity Utilization %

accounting for about

quarter of the crude oil

distillation capacity

worldwide, as shown in

graph, and as discussed

60

50

40

fully below. Asia and

30

Europe follow as refining

20 centers. As also shown

the graph, North America ¹⁰ (again, the United 0 States) has by far the

1999 2000 2001 2002 2003 2004

largest concentration of downstream capacity -- the processing units necessary to maximize output of gasoline. The gasoline emphasis of course mirrors the demand barrel and hence refinery output in the different regions, since no other global region uses as much of its oil in the form of gasoline as North America does.

Refinery Profitability and Industry Structure

In general, refining has been significantly less profitable than other industry segments during the 1990's, as shown in the accompanying graph. Gross refinery margins -- the difference between the

cost of the input and the price of the output -- have been squeezed at the same time that operating costs and the need for additional investment to meet environmental mandates has grown, thus reducing the net margin even further. In addition, much of the investment made during the 1980's was designed to take advantage of the differential between the dwindling supply of higher quality crude oils and the growing supply of heavier and higher sulfur crudes. When that differential narrowed, however, the financial return on those investments declined. Refining margins peaked in the late 1980's.

During the 1990's the role of independent refiners (those without significant production) has grown substantially, largely as the result of refinery purchases from integrated companies (the "majors") seeking to streamline and realign their positions. Furthermore, the independent refiners, like the majors, are in a period of consolidation; the mergers and acquisitions are having a significant impact on refinery ownership (although not overall refined product supply).

week, in spite of the fact
that they provide only a
East Coast (PADD 1)		Year End US Oil Inventories	snapshot, based on preliminary information.
Midwest (PADD 2)
1,600 1,800	Gulf Coast (PADD 3) Rocky Mountain (PADD 4) West Coast (PADD 5)		The United States, with its huge and widely dispersed
			oil market, has by far the
1,400			largest commercial stocks,
			some one billion barrels.
1,200			The Gulf Coast holds the
1,000 Barrels			greatest part of the crude oil stocks, as shown in the
800 Million			accompanying graph, but
			the East Coast, with its
600			high consumption and
			limited local supply, has the
400			greatest finished product
			inventories.
200
0			Most of the world’s storage
	1999 2000	2001 2002 2003 2004	capacity is owned by the
			companies that produce,

Stocks

This section looks at stocks, another critical component in getting oil from producer to consumer and in balancing oil markets globally, regionally, and locally.

Why Stocks Are Important

According to the Energy Intelligence Group's 1997 report, "How Much Oil Inventory is Enough?," there are 7-8 billion barrels of oil tied up worldwide in industry and government stocks (inventories) at any given time. (The estimate excludes consumer stocks.) Why so much? Mostly, because stocks are needed to keep the global supply system operating. They can be thought of as a huge pipeline stretching from the wellhead to the consumer, filling the tankers, the pipelines, the railcars, and the road tankers, and linking all the markets and all the segments of the industry together. They are thus the key to the oil industry’s proven ability to deliver the right product to the right location at the right time.

Only around 10 percent of this vast stockpile is typically available to the industry to use as and when it pleases. Although minor in volume terms, these stocks -- sometimes described as "discretionary" -- can affect the industry in major ways, because this subset of total stocks indicates whether markets have too little, too much, or just the right amount of oil. Thus, when stocks are low in a particular market, prices there are likely to be relatively high, encouraging extra supply or reducing demand (whether through fuel switching or other means). Vice versa, when a region's stocks are high, prices are likely to be relatively low in that market. For example, if distillate is in short supply on the U.S. East Coast so that distillate stocks there are low, then the price for East Coast distillate rises relative to distillate prices in other markets, like Europe; relative to other products, like gasoline; and also relative to crude oil. Stocks, particularly projected stocks, are thus viewed as a leading indicator of prices and are one of the most closely watched aspects of the oil market.

It is hard for the industry to follow global stocks as closely as it would like, because the data have large gaps. The United States is the only country to publish comprehensive weekly stock data. The data’s uniqueness and timeliness make them market movers, albeit temporary ones, nearly every

refine, or market the oil. There is also a small but important proportion that is owned by independent operators, who make their living by renting it to third parties. These facilities are located predominantly at the world’s main trading hubs, like Rotterdam, Singapore, New York Harbor, and the Caribbean, and are an important element in making those hubs successful and viable. The volumes in independent storage can be a key indicator of what is happening to discretionary stocks. These data are, therefore, also greatly sought after by the industry but if they are outside the United States often lie outside the more formal data collection systems.

Stocks Are Seasonal

World oil stocks follow a seasonal pattern in which they are typically drawn down rapidly in the middle of the winter and re-built rapidly in the spring, creating a tendency for world oil prices to be strongest in the fall and weakest in the spring. This stock seasonality stems from world oil demand being much more seasonal than world production. Stock swings are most pronounced in those Northern Hemisphere heating fuels -- heating oil, propane, and kerosene -- that drive world oil demand seasonality. Crude stocks are also seasonal, being drawn when refiners push their runs up to peak levels and built when refiners schedule maintenance at their plants. But, since Asia’s refining system has its peak output in the winter, with maintenance scheduled for the summer, while North America’s system is summer-peaking, with maintenance scheduled for late winter or early fall, much of the regional seasonality in crude oil stocks cancels out at the world level. Thus, global product stocks tend to be much more variable than crude oil stocks. With refineries growing more flexible and demand becoming less seasonal, stocks are becoming less seasonal too.

Strategic Stocks

The Arab Oil Embargo of 1973 initiated efforts among oil import-dependent nations to build government-controlled stocks of oil –- known as strategic stocks -- as a buffer against severe supply interruptions. These strategic stockpiles, the largest of which is the U.S. Strategic Petroleum Reserve, or SPR, now account for a significant fraction of the world’s inventories. There has been only one strictly emergency use of strategic stocks, and it was small: during the 1991 Gulf Conflict, the United States sold 4 percent of its SPR stocks.

The International Energy Agency's oil-sharing rules, designed to share the burden of an oil supply shortage, require that each participating nation hold stocks equal to 90 days of imports. Most of the participants meet the requirement with industry-owned stocks that can be commandeered in an emergency. Only the United States, Japan, and a few other nations also hold government-owned stockpiles, stored separately.

Costs and Profits

Holding inventory costs money. How much it costs varies, depending on the type of oil being stored, how much storage is available, whether the storage is owned or has to be rented, the price of the oil, and the cost of borrowing money. In all cases, the cost of holding inventory can rapidly become significant compared to the average margins achieved by refiners, marketers, distributors, and other oil industry participants that might need or want to hold inventory. Based on average prices in the first half of the 1990’s, holding crude oil for a year would cost a company about $1.50/barrel if it had its own storage and $4/barrel if it had to rent storage tank space. For gasoline, the corresponding costs would be $2 and $6/barrel. Thus, storing gasoline in rented tank space costs roughly 1 cent per gallon per month. Companies, therefore, try to operate their supply and distribution systems in ways that keep their inventories as efficient as possible.

The trend in the more mature economies, like that of the United States, toward consolidation of the industry through mergers and acquisitions has helped in this regard. Every gas station, terminal, refinery, etc., must have some oil in inventory. As consolidation has led to facilities being closed, the minimum amount of oil needed to keep the system operating has fallen.

But stocks should not be viewed just as a cost of doing business. Stocks can also be a way to make money; they represent a profitable investment. Such stocks are truly discretionary stocks. They are built or drawn in response to prices, and particularly in response to the difference between today’s prices and expectations about where prices will be in the future -- the forward price curve. The widespread availability of financial instruments, like futures contracts, has greatly encouraged discretionary stock movements, partly by making the economic signals inherent in the forward price curve easy to see, but especially by reducing the risk of building stocks in a surplus market.

When prices for oil today are lower than prices for oil in the future –- a sign of oversupply -- the market is said to be in contango. If the contango is wide enough to cover the costs of holding stocks, namely storage and working capital, then a company can lock in a profit on the stocks if it, first, sells oil in the futures market while simultaneously putting the same volume of oil into storage in the futures contract’s delivery area, and then, subsequently either delivers the stored oil against the contract or sells the stored oil and buys an offsetting futures contract. Discretionary stockbuilding occurs disproportionately in the U.S. Northeast, particularly around New York, and in Northwest Europe, especially in the Antwerp-Rotterdam-Amsterdam (ARA) area. That is because the world’s two active families of product futures contracts are based on these delivery areas: the NYMEX on New York Harbor and the International Petroleum Exchange on the ARA area.

The opposite of a contango is backwardation. A backwardated market has prices for oil today that are higher than prices for oil in the future –- a sign that supplies are tight. Backwardation implies that oil in storage will be worth less later, even if holding it were cost-free. The situation, therefore, creates an incentive for companies to reduce their stocks, which adds supply to the market and helps to correct the indicated shortfall.

There are many other situations that also cause companies to adjust their discretionary stocks because the risk, although not as low as it can be with building on a contango, is judged to be much lower than the potential reward. Three examples: when prices are at unusual levels by historical standards; when prices are moving fast; and when governments’ oil-related fiscal policies are expected to change. In all three case, stocks can be viewed as a buffer that enables a company to change the timing of its purchases, with the high probability that this will lower its costs and, therefore, improve its bottom line. Consumers sometimes do the same thing. For example, if the tax on gasoline at the pump is expected to increase on January 1^st, motorists rush in on December 31^st and buy early.