Energy Production
Committee
Understanding the Petroleum Industry
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- Refineries turn crude into products, ideally while simultaneously meeting
both the quality and quantity needs of the local market. Distillation, the simplest of all
refinery processes, just separates crude into its natural proportions of light products,
e.g. gasoline, of medium products, e.g. jet fuel and diesel, and of heavy products, e.g.
residual fuel oil. Based on the average quality of world crude, distillation alone would
result in a mix of products that would be around 45% residual fuel oil. A refinery with
little more than a distillation unit is a simple refinery.
- As the proportion of lighter products that are consumed has increased and
the quality requirements for all products have been tightened, it has become necessary to
augment distillation with an increasing array of additional processing units, collectively
referred to as downstream units. These predominately either convert heavy streams
into more desirable, lighter ones, or remove pollutants, like sulfur. Refineries with many
downstream units, and so capable of producing a high proportion, or yield, of
light, high quality products, are complex refineries.
- Complex refineries have substantially higher capital costs, and somewhat
higher operating costs than simple refineries. These are offset, to a greater or lesser
degree, by the higher revenues from the higher proportion of higher quality products. In
oil’s transparent, commodity-style market, it is the marginal operation that sets the
prices and differentials for everyone. Thus, the tendency for upgrading to be less than
the market needs has allowed the complex refiner to make an adequate return on his high
cost investments. However, as soon as upgrading is surplus, this profitability vanishes.
Upgrading becomes the marginal operation, and it is then the complex refiner that is
struggling to make any contribution to his fixed costs at all.
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- The problem presented to refiners by the gasoline/diesel tug-of-war is
that gasoline and diesel have distinctly different product characteristics. Thus, a
refiner will invest in a different combination of downstream units depending on which of
the two he sees as the fuel of the future.
- If the refiner guesses wrong, it has a major impact on the price
differential between the two products. For example, European refiners invested for
gasoline, but dieselization produced a gasoline surplus. This forced the refiners to
discount the price for their gasoline, so that the cost of moving the surplus to an
overseas market could be recovered. This discounting caused the price of gasoline relative
to that of diesel to be much lower than expected, undermining the value of the
refiners’ gasoline-oriented investments.
- Guessing wrong between gasoline and distillate does not just hurt those
that made the error. For example, European refiners, caught out by
dieselization, have
mainly placed their surplus gasoline on the U.S. East Coast. In recent years, this
European gasoline has been the prime contributor to the pool of gasoline turned into RFG
for East Coast markets. Thus profits have been squeezed for East and Gulf Coast refiners
as well as for the Europeans that created the problem, while consumers have been shielded
from the predicted higher prices of RFG.
- Guessing wrong can also impact the availability, and therefore also the
price, of other products, such as jet fuel, naphtha and kerosene, since all of these
products include streams that could help to handle a shortfall in one or other of the two
products. Thus the failure to build appropriate downstream capacity for such a
distillate-oriented future means the airlines are paying the equivalent of a surcharge for
their fuel.
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Top
- See also, The
Distillate/Gasoline Tug-of-War, from the Demand Side
- The moves to require specialty products, like RFG or low sulfur diesel,
have forced refiners to invest substantial, additional amounts of capital, at least if
they want to stay in business in the areas affected. This capital is additional, because
it is directed toward making the products cleaner, whereas the refiners’
discretionary capital investment is directed at increasing the proportion of light
products that can be produced from a barrel of crude.
- Illustrating the significance of the capital involved, Californian
refiners spent over $3 billion to be able to supply CARB 2 gasoline when it was introduced
in 1996. Almost all of this investment went toward meeting the quality specifications; the
volume gain was minimal.
- CARB gasoline has proved to be unique among the specialty products. Its
specifications are the world’s most restrictive, and therefore unusually costly.
This, plus experience with other specialty products like RFG, led refiners to be extremely
cautious over the volumes of qualifying gasoline they would be able to supply. As a
result, it has frequently been necessary to turn to out-of-state sources to ensure all
demand is met. The hard-to-meet product specification and the high cost of transportation
to California necessarily make these additional supplies expensive. Consequently, refiners
have seen their investment in making CARB gasoline make commercial sense.
- This has rarely been the case with other specialty products. Take low
sulfur diesel in the U.S. Except for when it was first introduced, the differential
between low and high sulfur diesel has covered little more than the out-of-pocket costs of
1-2 c/gal for producing the former rather than the latter. Yet for over half the refiners
in the U.S., the capital cost of being able to meet the low sulfur diesel specification
was a further 4-8 c/gal.
- One conclusion to draw from these examples is that the more specialized
the mandated product, the more limited the market, and therefore the fewer the number of
regular suppliers. Hence, the more specialized the mandated product, the more vulnerable
the consumers of that product are to volatile, high prices or to suffering a breakdown in
supplies.
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Top
- See also, Specialty
Products and Market Fragmentation, from the Demand Side
- See also, Specialty
Products and Market Fragmentation, from the Trade/Import Side
- See also, Specialty
Products and Market Fragmentation, from the Inventory Side
- Two of the important ways in which refiners have been able to cut their
own unit costs directly, and thus become more efficient, are by debottlenecking and by
raising their utilization rates.
- Refinery units usually have one element that is limiting throughput. It
is often possible to adjust this one element at a relatively low cost, and so raise the
throughput of the entire unit. This is known as debottlenecking. Debottlenecking is
a prime reason why U.S. refinery capacity was barely 100 thousand B/D lower in 1997 than a
decade earlier, even though there were 55 fewer refineries.
- Debottlenecking is also one of the factors behind higher utilization
rates. As residual fuel oil demand has shrunk in the industrialized countries, refinery
throughputs have often been set at the level that allows maximum utilization of the
downstream units, even when this meant underutilized distillation. Debottlenecking the
downstream units then means higher distillation throughputs, and thus higher utilization
rates.
- Refiners have been able to extend the time between maintenance closures
of their units, just as the manufacturers have extended the time between services on
automobiles. Most units in the U.S. and Europe, but not generally elsewhere yet, can now
operate continuously for 4-5 years instead of 1-2. Fewer turnarounds mean higher
utilization rates.
- With the advent of futures markets, refiners have been able to flatten
out the seasonality of their runs, and therefore run at a higher level overall –
incidentally, limiting product trade flows at the same time. Previously, when stocks of
the seasonal products, gasoline and heating oil, started to build in their off-seasons,
refiners would often have to cut runs. Now, hedging allows stocks to be built at little or
no financial risk.
- The result is global utilization rates that have averaged 83% in the
1990’s, 6 percentage points above their highs before capacity nose-dived after 1981.
These rates would be even higher were it not for the drag from the Former Soviet Union,
where painfully slow closures have cut utilization rates to a pitifully low 45%. Even so,
in 1997, refiners were able to meet demand that was 11 million B/D higher than when global
refinery capacity peaked.
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Top
Chart: Global
and regional refinery utilization rates
- The BP/Mobil Alliance, which joined the two companies’ European
refining and marketing operations, rewrote the rules for the refining sector worldwide
when it was announced in 1996. The combined $5 bn in assets, $20 bn in sales, 1.1 million
B/D of refining capacity, 9000 gas stations and 12% European market share gave the
Alliance the critical mass and economies of scale necessary for success in what has become
an increasingly cutthroat, commodity-style business.
- The lesson was seized on with the most enthusiasm in the United States.
Alliances were not the only approach chosen, although there have been some significant
ones, such as those between Shell Oil, Texaco and the Texaco/Saudi Arabian joint venture,
Star, that created both Equilon and Motiva. Diamond 66, a new entrant to the list of the
Top Ten U.S. Refiners, is the product of a series of transactions: first, a merger,
between Diamond Shamrock and Ultramar to form UDS, then an acquisition, of Total’s
American operations, and finally a joint venture, between UDS and the refining, marketing
and pipeline operations of Phillips 66. Tosco has made it onto the same list solely
through acquisition.
- The result has been a rapid increase in concentration in ownership in
U.S. refining, although not to a point that threatens competition. The largest refiner,
Chevron (it may become BP/Amoco, depending on FTC provisions attached to the proposed
merger), has less than 7% of the market, and the Top Ten have under 60%. But those Top Ten
are now larger and much more homogeneous. Between 1994 and 1998, the average capacity of a
Top Ten refiner increased by 100 thousand B/D and the capacity spread between No.1 and No.
10 dropped to 300 thousand B/D from well over 900 thousand B/D.
- The list of top U.S. refiners used to be a replica of the list of top
multi-nationals. The majority of the leading refiners are now either Independents
(companies that don't produce crude oil), like Tosco, or joint ventures that are being
operated as stand-alone entities, like Equilon. This strongly suggests that competition in
the sector will be stronger, not weaker, than in the past - which also suggests that
corporate restructuring via mergers, acquisitions, joint ventures and alliances is not yet
complete.
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- Production in Venezuela and Mexico is biased toward very heavy, high
sulfur crudes, and is expected to become even more so in the future. Without a coker or an
asphalt plant, these crudes are extremely difficult, if not impossible, for refiners to
handle. This was being reflected in their prices, which were heavily discounted.
- To expand the market segment that did find these crudes attractive, first
Venezuela and then Mexico adopted the strategy of building new coking capacity via joint
ventures with refiners. They have been highly successful with their prime targets,
refiners on their own doorstep, i.e. in the Caribbean or U.S. Gulf Coast. Venezuela
already has JV’s with Citgo, Lyondell, Coastal, Phillips, Mobil and Amerada Hess,
while Mexico has them with Shell Oil and Clark.
- By using a JV rather than investing alone, the refiners have gained more
cost-effective coking capacity at lower risk. Some have also, to their relief, diluted
their equity stake in refining. The benefits to Venezuela and Mexico are greater. They
have raised the value of all their heavy crudes, are sharing in the coking margin, and
have locked in outlets in their preferred markets, making it increasingly difficult for
the Middle East producers to retain market share.
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