Analysis of cost structure and functions in oil transport and refining

2.3.1. Oil transport
The various methods of transport
It is enough just to glance at a map
showing the locations of the world’s
oil-producing and oil-consuming regions to
appreciate that massive quantities of
oil have to be transported over enormous
distances (Fig. 1).
Oil-producing regions are in most cases a
long way from the industrialized countries,
which are the biggest consumers of oil.
In 2003, nearly 2.3 billion tonnes of crude oil
and refined products were transported over great
distances. Crude oil accounted for 78%
of this tonnage. And this enormous
volume is constantly increasing (ϩ19% since
1996, ϩ7% since 2000) as world oil
consumption rises. In short, some half of all the
85VOLUME IV / HYDROCARBONS: ECONOMICS, POLICIES AND LEGISLATION
2.3
Analysis of cost structure
and functions in oil transport
and refining
UNITED STATES - CANADA
LATIN AMERICA
production
2002 crude and
LNG
crude and
petroleum
product flow
refining
capacity (as of
1 January, 2003)
consumption
2002
EUROPE FORMER USSR
CHINA
AFRICA
MIDDLE
EAST
1015375
485 935 985
515
data in million tons
400 295
165
120
200
560
220
215
110
155
185
120
200
130
210
210
465
320
840
755
425
170 810
730
280
260
170
330
OTHER ASIA
OCEANIA
120150
100
10
3030
30
35
15
15
10
50
60
35
50
25
80
10
90
20
15
75
7510
60
40
30
10
20
Fig. 1. Petroleum worldwide in 2002.

crude oil produced in the world is transported a
very long way (Table 1).
An examination of maritime transport of
hydrocarbons as a proportion of total world
maritime trade reveals that oil represents a
significant, though decreasing, share of all trade.
Oil currently accounts for 30% of total
tonne/miles covered (Fig. 2).
Oil is a liquid pollutant and its vapours are
combustible, so it presents certain transport
problems. Sea transport of oil requires special
ships. Oil pipelines can eliminate the need for sea
transport, but the amount of investment they
require and the permanence of their installation
mean that they are only justifiable for large,
long-term volumes.
86 ENCYCLOPAEDIA OF HYDROCARBONS
BASIC ECONOMICS OF THE HYDROCARBONS INDUSTRY
Gt/miles
0
8,000
6,000
4,000
2,000
10,000
12,000
14,000
16,000
18,000
20,000
22,000
24,000
all goods
crude oil
petroleum products
year
1968
1970
1972
1974
1976
1978
1980
1982
1984
1986
1988
1990
1992
1994
1996
1998
2000
2002
Fig. 2. World marine
trade.
* 10 million tonnes non unidentified.
Table 1. Oil imports and exports
(Oil trade 2002 in million tonnes)
To
From
USA Canada
Latin
America
Europe Africa China Japan
Other
Asia
Rest
of the
World
Total
USA – 4,9 15,9 10,7 0,5 1,1 4,0 5,2 1,0 43,3
Canada 95,5 – 0,2 0,5 – – 0,2 0,1 0,2 96,7
Latin America 195,4 6,4 8,4 23,2 0,6 0,9 0,9 7,6 4,7 248,1
Western Europe 57,0 24,6 3,5 – 10,0 3,6 0,7 5,4 2,3 107,1
CIS 9,8 – 7,4 214,6 0,5 8,1 1,2 10,4 2,5 254,5
Middle East 114,7 6,9 14,5 161,1 36,9 38,9 195,4 324,1 3,2 895,7
North Africa 13,6 5,1 6,2 87,3 4,0 0,3 3,6 5,7 – 125,8
West. Africa 55,5 1,0 9,9 35,2 2,7 9,5 3,8 38,3 – 155,9
Other Africa – – – – – 6,4 1,5 0,8 – 8,7
Australasia 2,9 – – – – 1,6 4,4 11,6 0,3 20,8
China 1,3 – 0,5 0,3 – – 4,1 10,3 – 16,5
Japan 0,3 – – 0,1 – 1,6 – 2,2 0,6 4,8
Other Asia Pacific 8,3 0,1 – 4,5 0,3 28,4 28,3 32,0 – 101,9
Unidentified 6,7 2,5 – 49,9 – – 2,4 1,3 – 61,8
Total 561,0 50,5 66,5 587,4 55,5 100,4 250,5 455,0 14,8 2151,6*

Each form of transport (tanker and pipeline)
has its own advantages and drawbacks. Safety and
the environment are of increasing importance
nowadays and are among the principal criteria by
which such pros and cons are measured. Pipeline
transport is clearly safer, even though pipelines
can rupture or be sabotaged. Much progress has
been made in sea-transport safety in recent years;
despite such progress, however, the fact remains
that it takes only one tanker accident and the
resulting pollution to give an extremely negative
image of the sea transport of hydrocarbons.
Fortunately, such accidents are extremely rare in
proportion to the volume of traffic (Table 2).
In any event, most buyers of crude oil have no
choice with regard to the mode of transport,
which is determined at the outset by the existing
supply infrastructure. Sea transport is the least
costly, most flexible and most common method
(and in many cases it is the only option). Oil
produced in the North Sea, in most African
countries and in the majority of Middle Eastern
states is transported by sea.
In certain cases, however, the buyer does have
a choice between sea-only transport and a
combination of sea and pipeline. For example,
Saudi crude can be transported to Europe either
via tankers circumnavigating Africa by way of the
Cape Point or via Egypt’s Sumed pipeline, which
links the Red Sea with the Mediterranean.
Another major exporter of crude, Russia, uses
various pipeline/sea combinations, including
pipeline plus sea transport from the Baltic and
North seas, and pipeline only through Eastern and
Central Europe to the former East German
Republic (Deutsch Demokratische Republik,
DDR) via the Druzhba pipeline.
As a further example, a refinery in the
Stuttgart region in southern Germany has three
pipelines at its disposal to pump crude from
Mediterranean ports: the South European Pipeline
(Fos-Strasbourg-Germany), the TAL (Transalpine
Line, Trieste-Austria-Bavaria) and the CEL
(Central European Line, Genoa-Southern
Germany).
Most countries where oil consumption has
reached a certain level have developed their own
refining industries, which are capable of meeting
most of their needs. Therefore, and despite the
existence of huge export refineries in countries
such as Saudi Arabia and Venezuela, the transport
of refined products over considerable distances is
relatively insignificant in comparison with the
transport of crude. However, because of regional
imbalances between supply and demand for
refined products (disparities which are becoming
more acute with rising imports by the United
States and China), the transport of refined
products is still significant: in 2003, transport of
refined products (requiring transport ships
smaller than the tankers used for carrying crude)
represented 22%, or nearly 500 million tonnes, of
total oil transport.
Refined products are generally transported
over shorter distances, but the dispersal of end
consumers and the diversity of the products
transported pose specific problems: for example,
the holds of transport ships must be cleaned
between each product batch, and ships or
pipelines specially built for carrying refined
products cannot always be used. Furthermore,
pipelines carrying refined products are relatively
rare: they are largely confined to the US and, to a
lesser extent, Europe. Even markets whose
significance in terms of unit consumption is tiny
require refined products in all their different
forms: solid (bitumen), liquid (fuel oils, gasoline
fuels) and gas (Liquified Petroleum Gas, LPG).
ANALYSIS OF COST STRUCTURE AND FUNCTIONS IN OIL TRANSPORT AND REFINING
Table 2. Tankers versus pipelines
Tankers Pipelines
Investments Limited
Major
(geopolitical implications)
Operating Costs Planned, negotiable Low
Flexibility Very flexible Not adaptable
Volumes handled 100-400 kt/cargo 10 to 100 Mt/year
Implementation time 2-3 years Long to very long
Security/Environment
Upgrading in progress
(impacts on image)
Very good

Each of these products has to conform to certain
standards and specifications, and the risk of
contamination across product lines means that
transporting or storing them in the same
receptacle is out of the question.
Aside from ship and pipeline, the most
commonly used methods for transporting refined
products are barges, rail tankers and tanker
trucks, the latter two being the only methods
capable of bringing products directly to the end
consumer
Sea transport
The various types of ship used
Three principal types of ship are used for
carrying oil, classified according to their dwt
(deadweight tonnage), i.e. the amount of cargo
that the ship can carry in addition to its own fuel
and supplies. To these three principal categories
can be added the largest of all supertankers, the
Ultra-Large Crude Carriers (ULCCs), as well as
Panamax-class carriers:
• Ultra-Large Crude Carriers (ULCCs) have a
dwt of between 325,000 and 600,000. Very
few of these giant ships are currently active.
• Very Large Crude Carriers (VLCCs), with a
dwt of over 160,000, are used on routes from
the Persian Gulf westwards to the Caribbean,
US and Europe, and eastwards to Southeast
Asia (Japan, Korea and Singapore). The
largest VLCC tankers are used for supplying
Europe and the US. When empty, these ships
can negotiate the Suez Canal.
• Suezmax, with a dwt of between 100,000 and
160,000, is specially designed to be able to
use the Suez Canal when loaded. Suezmax
vessels are also used for transporting crude
from West Africa to the Caribbean, the US and
Europe.
• Aframax ships, which have a dwt of between
80,000 and 100,000, are used in regional traffic
(North Sea, Mediterranean, Caribbean/US).
This is the largest carrier-class allowed to enter
American ports when fully loaded.
• Panamax carriers are used on certain routes
only. Their size (60,000 dwt or less) means
that they can use the Panama Canal (serving
such routes as California/the Gulf of Mexico
or the Pacific coast of South America/the US
eastern seaboard).
The world oil-tanker fleet-capacity peaked at
about 330 million dwt in the late 1970s before
falling to under 250 million dwt with the oil
crisis of 1986. Since then, it has been rising
steadily, reaching some 300 million dwt in 2004.
Requirements in terms of transport capacity
fluctuate in line with world oil demand, while
the emergence of non-OPEC (the Organization
of the Petroleum Exporting Countries)
production in regions nearer to consumption
markets has also helped to dampen capacity
requirements. Slowdown in demand can force
shipowners to mothball many of their larger
tankers, something that happened in the early
1980s when charter rates were so low that
shipowners were unable to operate their fleets
profitably. Economic growth since 2000, in Asia
especially, has sparked renewed chartering
demand.
Most (two-thirds) of the world tanker fleet is
independently owned, while the other third
belongs to the oil companies themselves; of these,
ownership by national companies is growing at
the expense of the majors. The fleet mainly
comprises large tankers and is currently
undergoing refurbishment in the wake of new
safety regulations.
The different types of shipping charter
Three types of tanker charter exist:
• Bareboat charters: the tanker is placed at the
disposal of the charterer for a specific period
of time. The tanker is equipped by the
charterer, which also pays its operating costs.
The charter hire rate (paid monthly) reflects
the capital costs of the tanker. Bareboat
charters are therefore similar to leasing
agreements, and generally incorporate a
purchase option.
• Time charters: the tanker is placed at the
disposal of the charterer for a specific period
of time (anything from six months to several
years) and operating costs are borne by the
ship-owner.
• Spot or voyage charters: the shipowner agrees to
transport cargo from one designated port to
another and applies a cargo tariff per tonne of
cargo transported, with all costs included. Spot
charters can cover consecutive stages on the
same itinerary. Although they were practically
unheard-of in the early 1970s, these are now the
most frequent form of charter agreement.
The cost of sea transport
For shipowners, costs per tonne transported
are a key factor, as owners are unable to operate
for long under a certain threshold without having
to lay up part of their fleet. These costs comprise
two components: depreciation of the tankers

(which is connected to investment costs), and
operating costs, including port duties and fuel.
Depreciation of tankers. The price of tankers
depends partly on construction costs and partly on
market equilibrium. While the life expectancy of
a tanker is theoretically quite long, in many
countries the legal depreciation period is eight
years. Furthermore, tanker life expectancy is
reduced as a result of rapid obsolescence due to
advances in technology and tighter safety
regulations.
Construction costs fell in the 1960s, mainly
due to the trend set by Japanese shipyards:
reduced steel consumption, productivity drives
leading to faster construction times, new
technology and more. But while progress in this
area has continued, costs have since risen
markedly as a result of ever-stricter construction
regulations.
For a 280,000 dwt double-hulled VLCC, the
2005 order price is in the region of $300 per dwt.
Construction costs per dwt decrease with size up
to 200,000 dwt; a tanker of just 80,000 dwt, for
example, costs about $500 per dwt. Hull costs rise
at a rate that is less than proportional to tonnage.
The cost of propulsion gear is proportional to
power, which is a function of the square root of
tonnage. Beyond 200,000 dwt, costs per
deadweight tonne vary little as there are few dry
docks big enough to accommodate tankers of this
size, which also need a double propulsion system.
Since the oil fleet occasionally finds itself in
periods of overcapacity, the market for
second-hand tankers is very active. Prices and
write-downs relative to new tankers are expressed
in dollars per dwt; of course, they also depend on
the age and condition of the tanker, as well as on
market conditions.
The lowest price limit on the second-hand
market is the scrapping price, at which ships are
sold for scrap to special breaking yards.
Operating costs. Most operating costs remain
the same regardless of the voyage; of these,
tanker-depreciation and capital costs, repair,
maintenance and inspection duties can all be
directly charged to the tanker, while general
company costs are harder to break down.
Other operating-cost components vary,
depending on the voyage: salaries and associated
social security expenses as well as supply and
provision costs all rise as the length of the voyage
increases; port dues, canal charges, and piloting and
tug duties depend on the route; and consumption of
bunkers (fuel oil, diesel fuel) and lubricants
depends on distance, tonnage and speed.
Thus the consumption of fuel oil, which can
be expressed as a function of speed3, rises steeply
as speed increases, while for most other costs the
greater the speed, the lower the cost per tonne
(and the quicker the voyage). Bunker prices per
tonne depend on the refuelling port and on
provisioning agreements.
Port and canal duties are fixed costs charged
in proportion to tonnage. Port duties vary greatly
from one port to another. The principal canals
used by oil tankers are the Suez, the Panama and
the Kiel (which serves the Baltic Sea market).
Canal authorities publish tariffs of their
applicable transit duties at regular intervals
(usually once per year).
Personnel costs have significantly decreased
in recent years due to reductions in crew size,
but crews cannot be cut much further for
reasons of safety (and the bigger the tanker, the
higher the level of safety required). Tankers
also have to undergo port maintenance, the
costs of which can rise steeply if the tanker’s
crew is too small to carry out part of the
maintenance work while the tanker is at sea.
Tankers of over 100,000 dwt have crews of
about 30. Total personnel costs also depend on
the nationality of the crew and the country in
which the tanker is registered: social security
charges, for instance, are much higher for
European- and North American-registered
tankers than for open-registry tankers.
Then there are demurrage charges, or
penalties for exceeding time allowances; in
certain cases, these can be applied on top of port
duties in oil terminals that are particularly
congested and which consequently assign time
limits for tankers to load and unload. These costs,
stated in dollars per day in excess of the
contractual limit, can be significant.
It is difficult to give precise indications of
transport costs per deadweight tonne as these
clearly depend on a large number of factors. We
can, however, assign approximate shares to the
principal operating cost items for tankers (Fig. 3).
We can also compare daily operating costs for
different types of tanker and trace recent cost
trends; costs in the early years of the present
decade ranged from $6,000 per day for a ‘large’
(80,000 dwt) tanker carrying refined products, to
over $11,000 per day for a VLCC.
The price of sea transport
This is the price of transport as paid by the
buyer, a rate generally negotiated between the
shipowner and the charterer. As in every

market, oil transport prices vary in accordance
with demand and supply and can fluctuate
greatly, occasionally diverging significantly
from actual costs. The setting of tariffs for
voyage charters operates according to a
free-market model whereby the law of supply
and demand enjoys carte blanche. Deals are
struck by brokers, who are based in London and
New York for the most part.
Of all the different indices used for setting
spot and time-charter prices, the most widely
used is the Worldscale index; this is reviewed
regularly (usually every 1 January) by the
London-based Worldscale Association, in
accordance with changes in certain costs, such
as bunkers and port dues. This index gives
nominal transport prices for every possible
combination (or route) between port of loading
and port of unloading.
The published Worldscale rate (flat, or level
100) represents typical transport costs for a given
voyage (or route). It is expressed in dollars per
tonne for a ship with a capacity of 75,000 tonnes
sailing fully loaded at a speed of 14 knots,
making a return trip between the designated port
of loading and the port of unloading, in standard
conditions of size, speed, consumption and time
spent in ports of call.
If the shipowner and charterer negotiate a
price at Worldscale 85, this means that
transport costs for the charterer are 85% of the
flat rate. For example, the flat rate for a voyage
between Quoin Island and Augusta via the
Cape was set at $18.24 dollars per metric tonne
for 2003; so, in the instance cited, the cost
would be $15.50 per metric tonne. The flat rate
for the same voyage via Suez was only $7.60
dollars, but Suez Canal charges would have
had to be factored in. Transport prices
expressed as a Worldscale percentage
obviously vary greatly depending on the size of
the ship used, and therefore on the amount of
cargo transported. For VLCC-class tankers,
rates usually remained well below Worldscale
100 until the early years of the present decade;
by the end of 2004, however, they had reached
200%. Rates for small tankers carrying refined
products can be as high as 300 or 400% of
Worldscale flat.
Spot-chartering rates are particularly
volatile since they are extremely sensitive to
fluctuations in supply and demand (Fig. 4).
insurance
37% 13% 14% 25% 11%
administration
supply and stocks
repairs and maintenance
manpower
Fig. 3. Breakdown of VLCC
operating costs.
Worldscale
Mediterranean-North-West Europe
25,000-30,000 dwt (products)
Arabian Gulf-Europe 200,000-300,000 dwt
Arabian Gulf-East
70,000-100,000 dwt
0
50
100
150
200
250
300
350
400
450
year
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
Fig. 4. Spot rates.

They are susceptible to seasonal variations and
are also influenced by the occurrence (or
anticipation) of other phenomena: war,
political tensions, changes in crude prices, and
new regulations. Time chartering rates are less
volatile.
Chartering transactions are performed by
brokers, whose duties include an obligation to
ensure transparency in dealings. Average
chartering prices, expressed as percentages of the
Worldscale index, are regularly published by
various bodies.
When entering into a chartering agreement,
shipowners have to weigh the freight rate against
their operating and capital costs, which are
directly proportional to the time elapsed and can
therefore be expressed in dollars per day; they are
measured against the Daily Net Return (DNR),
which expresses the daily margin against variable
costs (Fig. 5).
In case of spot chartering, variable costs refer
to bunker charges, port dues and so on, which are,
keep in mind, paid by the ship-owner.
DNR can vary considerably for the same
chartering rate, depending not only on bunker
costs but also on the age of the ship, as a new ship
consumes much less fuel than an old one. If a
chartering agreement gives a DNR higher than
the sum of daily costs (operating costs plus
capital costs), the difference represents the
shipowner’s profit.
Transport prices and costs
Margins as defined above have frequently
been negative since the 1990s, which means
transport costs were usually higher than transport
selling prices. While costs are relatively stable,
selling prices depend on market conditions and
fluctuate considerably.
The market itself is equally volatile and
has changed considerably since the beginning
of the present decade; it is now
predominantly a seller’s market, with many
tankers laid up as a result of the introduction
of drastic safety regulations, fewer new
tankers and increased traffic; furthermore,
average charter rates are often higher than
those employed in the 1990s. With a strong
increase in demand for oil and a consequent
increase in sea traffic, rates in 2004 were
higher than they had been for many years: the
average rate for VLCCs was Worldscale 150.
The introduction of new tankers in 2005 has
eased demand on the tanker fleet and thus
reduced rates.
Transport by pipeline
Overview
The use of pipelines for carrying hydrocarbons
in liquid and gas form was first adopted on a
significant scale in the US and is now common
worldwide. The total length of the global trunkline
network (i.e. pipelines not including gathering
lines, storage systems and final distribution) is
well in excess of 1.2 million km. Gas pipelines
account for over half of this figure.
Among the many active pipelines worldwide,
the foremost include:
• In the US, the Trans-Alaska crude-oil pipeline
linking the Prudhoe Bay oil fields to the
Pacific seaboard, and the Capline, which runs
roughly parallel with the eastern bank of the
Mississippi.
• Also in the US, three major US pipelines
carrying refined products: the Plantation, the
Colonial and the Explorer.
• In Canada, three major Canadian crude-oil
pipelines: the Interprovincial, linking
Edmonton to Toronto, the Mackenzie Valley
and the Kitimat-Edmonton.
• In Eastern Europe, the Russian pipeline network,
operated by Transneft, a state-owned company
with a monopoly on the pipeline transport of
crude oil. Via its subsidiary Transnefteproduct, it
also has a monopoly on the piping of refined
products. Crude-oil pipelines link the Urals to
Central and Eastern Europe (the Druzhba
system), to Novorossijsk on the Black Sea and to
Primorsk on the Baltic. The Ventspils terminal in
Latvia, formerly the mouth of a major pipeline, is
no longer used by Transneft. In the same region
we should also mention the Eastern
Europe-Russia network, linking the Siberian
refineries with Angarsk, and the Caspian
crew, maintenance and repairs, oil and supplies,
insurance and management costs
economic depreciation
DNR ($/d)
(freight charge given by the spot market-minus variable costs )
margin
ϩ
ϩ
ϭ
Fig. 5. DNR: the shipowner’s
margin.

Petroleum Consortium (CPC) pipeline, which
links Kazakhstan to Novorossijsk via Russia.
There are very few refined-product pipelines in
this region. Among the most significant of this
type are the Samara-Briansk-Leninvaros
(Hungary) pipeline and another serving the Baltic
(the Transnefteproduct system).
• In Western Europe, major crude pipelines
include the north-south system linking the
North Sea ports with Germany and Belgium,
and the south-north system, which links the
Mediterranean ports to Central Europe (South
European Pipeline, TAL and CEL). Western
Europe also has some major refined-product
pipelines, such as the Trapil system in France,
the Mediterranean-Rhone pipeline, the
Rotterdam-Venlo-Ludwigshafen pipeline and
the Spanish network.
• In the Middle East, major crude oil pipelines
include the Tapline, which links Abqaiq and
Sidon (partially closed), the Kirkuk-Tripoli
pipeline (also closed), the Sumed pipeline
(which enables the transport of oil from the
Gulf states to the Mediterranean without using
the Suez Canal) and the Abqaiq-Yanbu
pipeline in Saudi Arabia. Most of the oil
pipelines from Iraq and Saudi Arabia have
been closed for political reasons, as they
represent obvious targets for sabotage.
The principal constraints on pipeline transport
Oil pipelines work in conjunction with sea
transport as one more link in the crude-oil supply
chain. Relatively few pipelines directly link the
place of production to the refinery; and, as we
saw above, pipelines carrying refined products
are relatively rare except in the US, where they
were first used in about 1930. We also examined
the comparative advantages and disadvantages of
pipeline and tanker transport above.
One important consideration here is that the
notion of ‘capacity’ in the transport of
hydrocarbons via pipelines is not a totally reliable
parameter: it depends on many factors, such as
the viscosity of the product being pumped. Initial
capacity can be considerably augmented by the
installation of secondary pumping facilities.
The key advantages of pipelines relative to
other modes of oil transport (coastal shipping via
small tankers, river navigation, railway and road)
include low operating costs, direct routes and
immunity to climatic conditions. However,
pipelines require heavy investment, with
enormous infrastructure responsibilities for the
oil companies and absolutely no flexibility of use.
So what are the principal technical and
operational constraints in pipeline transport?
In the case of crude oil, the principal
constraints are those imposed upon the
transporter by the refiner:
Preservation of the quality of the crude during
transport. The risk of contamination, although
lower for crude than for refined products, is
nevertheless real. Crude oils of different qualities
can become mixed during storage at the terminal
prior to pumping, while the risk of contamination
is also present in the pipeline itself between
successive batches of crude. This problem does
not arise when the entire storage and pipeline
system handles only one class of crude, which in
fact is often already a blend of specific quality;
this is the case, for example, with the Urals Blend
that is pumped from Russia via the Druzhba
pipeline.
Preservation of quantities. This requires
accurate and reliable metering methods at the
upstream terminal, the destination refinery and
the downstream terminals. Maximum admissible
loss rates are contractually established. Barring
major incidents on the pipeline, most losses occur
during storage.
Logistical and batch-sequencing constraints.
As an example of this, it takes an average of 15
days for the Société du Pipeline Sud Européen
(SPLSE) to pump a batch of oil from the
Mediterranean (Lavéra) to Karlsruhe.
Refined products are usually pumped via
multi-product pipelines of smaller diameter than
those used for carrying crude. These pipelines are
capable of carrying practically every kind of
refined product (including LPG under certain
conditions) with the notable exception of heavy
fuel oils. In the rare event that they are
transported by pipeline, heavy fuel oils are only
pumped over very short distances, usually via
special pipelines that are heated to a temperature
of about 90°C.
In Europe, refined-product pipelines have a
diameter of 32" and pump 15 million tonnes per
year. The capacity of a pipe depends not only on
its diameter but also on the viscosity of the
product being transported and the power of the
pumping stations; for example, using the same
plant, a given pipeline can pump twice as much
petrol as liquid fuel oil.
In the more common instances where two or
even three light-refined products are transported
(i.e. gasoline, kerosene/jet fuel and diesel), the
different products are sent by batches following
certain procedures that regulate, for instance, the

sequence in which the products are pumped.
Since refined products must meet precise
specifications (density, sulphur content and
water content), precautions have to be taken to
prevent contamination at interfaces.
Contaminated products can either be returned to
the refinery for recycling to the required
specifications or mixed with a lower-grade
finished product.
Pipeline transport costs
Contrary to the situation with sea transport,
pipeline transport makes it difficult to draw a
distinction between the pipeline transport selling
price, or transport tariff, and cost price. In the
case of crude oil, the companies that produce or
refine the oil are in most instances the owners of
the infrastructure by which the oil is transported.
There are exceptions however: the Sumed
pipeline linking the Red Sea and the
Mediterranean, for example, and the
state-owned pipelines of oil producing/exporting
countries.
Despite these exceptions, the companies in
charge of managing pipeline infrastructure can
generally be regarded as overseeing an asset
whose purpose is not to generate its own
profitability but rather to ensure the profitability
of related upstream and downstream activities.
Oil pipeline transport costs break down into
two main components: the depreciation of
investment and the operating costs.
Capital expenditure and depreciation. Laying
a pipeline involves a whole series of operations
that are straightforward in essence; however, they
must be carefully planned and sequenced if
operations are to proceed quickly enough to
prevent the accumulation of crippling capital
expenditure costs.
Investment comprises materials, pipe-laying,
right-of-way and damage compensation to
landowners, sundry expenses and pumping
stations. In some cases, it also includes the
terminal (storage) costs associated with the
construction of the line.
Equipment depreciation periods vary. The pipe
itself generally has a depreciation term of 20-25
years. The real deterioration of the pipe generally
takes much longer, thanks to such highly effective
anti-corrosion methods as cathodic protection.
Pumps and metering gear depreciate fairly
quickly due to technological progress and the
modernization that results.
Operating costs. In addition to fixed costs
such as depreciation and financial expenses, we
must also consider the costs incurred in keeping
the pipeline working. However, operating costs
such as those for personnel are not really
variable because, unless the pipeline is closed
for extended periods, staff members remain
employed.
These costs tend to vary in line with the
installed capacity of the pipeline rather than its
real throughput. Although pipelines require little
in the way of labour, the latter is highly
specialized and therefore costly. Automation and
remote management are deployed to the full in an
attempt to reduced labour costs.
Energy bills can account for up to one-third of
operating costs. This percentage depends on the
number of pumping stations, i.e. on the
throughput and geology of the pipeline. Energy
consumption per tonne pumped varies with the
square of the pipe’s throughput. Consumption
rises in areas where head loss is significant
(mountainous regions, an arrival point at a higher
altitude than the departure point and so on) and
when, for a given throughput, the product being
pumped is more viscous.
Modern pipelines require practically zero
maintenance. However, the greater the automation
of the line, the higher the maintenance costs for
pumping stations and metering apparatus. Among
other cost items, we can also cite insurance costs,
administrative expenses and rent charges.
Tariffs
While the tariffs proposed (or imposed) by
the companies operating oil pipelines take into
account costs classified as fixed (capital
depreciation, personnel and maintenance costs)
and variable (mainly energy), they also
comprise elements that are wholly commercial.
These depend on the location-related
advantages enjoyed by the oil pipeline, i.e. the
extent to which it can offer significant savings
on sea transport. The Sumed pipeline, for
example, obviates the need for a long and
costly voyage around the African continent by
tankers that are too big to use the Suez Canal
(Table 3).
Other forms of transport
All other means of transporting liquid
hydrocarbons – cabotage (home trade, coastal
shipping), inland navigation, and rail and road
transport – almost exclusively involve refined
products, though there are exceptions like Russia,
where substantial volumes of crude oil are
transported by rail.

Table 4 provides a comparison of four methods
of transporting refined products, indicating
relative cost elements for each method and the
constraints affecting each.
Cabotage (home trade, coastal shipping)
It is difficult to make a clear distinction
between cabotage and general maritime traffic.
The definition of cabotage (trade or transport in
coastal waters) and its etymology (navigation
from cape to cape) point to short-haul coastal
traffic. As this suggests, cabotage generally takes
place within view of the coast or within one
country’s territorial waters, as opposed to long-
haul (i.e. open-sea) voyages. The role played by
cabotage varies in line with regional geography.
Cape-to-cape navigation is especially suitable
as a method of transporting refined products in
countries with exceptionally rugged coastlines.
Cabotage is thus widely practised as a means of
distribution in Japan and the Philippines, while in
the US it is hardly practised at all outside the Gulf
of Mexico and the eastern seaboard.
The situation in Europe falls somewhere
between these two extremes. Many areas are
particularly suited to this kind of transport: the
Pyrenees, several regions of Italy, the Dalmatian
coast and the refineries of the
Amsterdam-Rotterdam-Anvers (ARA) zone, the
last of which serve the major ports of Germany,
Britain and France.
Coastal tankers are capable of carrying all
types of refined product, from LPG to bitumens,
in vessels specially designed for specific cargoes.
Some of these ships are multi-product tankers,
with separate holds for different refined products.
Oil companies often own their own coastal fleets
and charter additional freight requirements from
specialist companies. Coastal ships range in size
from a few thousand to tens of thousands of
tonnes.
Transport tariffs for international cabotage are
among the highest on the Worldscale index. As
for national cabotage, many countries require
ships to be locally registered and rates vary
greatly according to the regularity of traffic.
Transport by inland navigation
In river transport, the slower the barge travels,
the lower the cost of transport: fuel consumption
is extremely sensitive to speed. Inland navigation
is therefore perfectly suited to the transport of
heavy products that do not require special
handling and whose economic feasibility is
scarcely affected by considerations of time.
Cost-effectiveness is therefore increased with the
transport of less-expensive products. Inland
navigation is ideal, for example, for the transport
of fuel oil as long as a considerable distance is
involved. As it is less cost-effective for the
transport of white products, however, inland
navigation is becoming less and less significant,
even though two-thirds of global storage capacity
are connected to a waterway.
The vessels used on canals and rivers range in
size from self-propelled barges with capacities of
between 300 and 1,500 tonnes to the large pusher
convoys of the Mississippi, which can be as big as
40,000 tonnes, and the 5,000-tonne barges that
ply the Rhine between Rotterdam and Basle.
In Europe, inland navigation is most intense
on the Rhine, via which barges carry supplies to
Table 3. Pipeline transportation costs
Construction costs (Cap Ex)
Pipes, valves, piping equipment
Installation cost
Acquisition of right-of-way, compensation, reimbursement of damage
Surveys and control
Base: 5 €/in/m
15 €/m
Pumping stations
Terminals
1 to 5 M €
2 to 4 M €
Operating costs (Op Ex)
Salaries and wages, energy costs, maintenance
Other charges: rents - telecommunications, insurance, overheads

Germany, North-eastern France and Switzerland.
However, traffic on the Rhine, and therefore the
provisioning of all the regions it serves, is
vulnerable to fluctuations in water levels.
Rail transport
Rail transport remains the main way of
supplying depots that are not connected to the
source of production either by a network of
pipelines or by sea or waterway. Although the rail
companies offer reduced tariffs, rail remains, in
general, a costly mode of transportation.
Compared with other bulk-transport methods, it is
especially costly in Europe, but somewhat more
competitive in Canada and Russia, where tariffs
are significantly lower; in fact, a significant
proportion of refined product is transported by
rail in Russia.
In Europe, the longest trains can carry up to
2,500 tonnes, while certain products such as LPG
and lubricants can be delivered in single-wagon
consignments of between 30 and 80 m3. Price
greatly depends on the volume to be transported,
and, once tonnage reaches significant levels,
construction of a pipeline becomes feasible.
Road transport
Nearly all terminal transport of refined
products takes place by road, as does some bulk
transport between refineries and depots. Most
heavy products (such as bitumen and fuel oil) that
cannot, except in special circumstances, be
transported by pipeline, are also transported by
road. Tanker trucks are ideal for bringing small
volumes to almost any destination, making them
an extremely flexible means of transport.
Road transport also includes the supply of
retailers like service stations and fuel pumps, and
the delivery of domestic fuel to end consumers
via smaller trucks equipped with pump meters.
In the case of bulk transport, the vehicle most
often used is a semi-articulated tanker truck with
a capacity of 40 tonnes. These trucks cover an
average of 100,000 km per year, cost over
$120,000 to buy, and are usually owned by
specialist transport firms. As for terminal
Table 4. Comparison of methods of transport
Road Rail River Pipeline
Investment
Low by unit, high
overall
Moderate by unit,
high overall
High by unit
if sound
cost-effectiveness
is required
(push boat)
Very high and made
over a short period
Infrastructure costs –
Mainly borne
by State
Toll duties
High, and borne
entirely by company
Personnel costs Very high Fairly high
High for
self-propelled barges,
low for push boats
Low (personnel ϭ
high in skills but low
in numbers)
Maintenance costs Very high
High except when volumes justify collective
installations and automation
Very low
Return costs Empty return Empty return Return in ballast Nil
Length of route
Outward, practically
everywhere; natural
obstacles impose
significant detours
Fairly dense and
limited by natural
obstacles
The most circuitous
route, where it exists
The most direct
Climactic conditions during
transit
Very sensitive Not very sensitive Sensitive Not affected
Flexibility of use Very high Very limited Very limited Nil

transport, this is generally carried out by tanker
trucks with a capacity of 20 tonnes or even less in
certain regions.
2.3.2 Oil refining
Technical background
Introduction
Refining is a vital link in the oil industry. In
fact, absolutely no one consumes crude oil; we
consume refined products only, as used in
transport, domestic and industrial applications,
and the petrochemical sector. The refined
products most often consumed are gasoline,
diesel and fuel oil. The fastest-growing refined
products in terms of consumption are jet fuel and
diesel; consumption of fuel oil is declining.
Worldwide consumption of refined products,
refinery fuel included, is currently in excess of
3.6 billion tonnes per year, or 80 million barrels
per day. According to International Energy
Agency figures, annual consumption in 1973 was
a mere 2.75 billion tonnes.
The purpose of refining is to transform the
various kinds of crude oils into finished products
that meet certain precise specifications (Fig. 6).
For the present purposes, we shall not examine
upgrader plants, whose job is not to create finished
products, but rather to transform ultra-heavy crude
into so-called synthetic crudes using conversion
units. The resulting synthetic crude is of much
higher quality and is therefore easier to market.
Venezuela has a few plants of this type.
Oil refining, i.e. the transformation of crude
into end products, used to be a perfectly
straightforward affair: a simple distillation
process was enough to separate out useful
fractions such as lubricants. The modern
refining industry did not really come into being
until the construction of the world’s first
distillation unit in Boston in 1863. Its purpose
was to produce lamp oil, the only petroleum
product consumed at the time. Then the car was
invented, sparking a rapid expansion in
consumption of petrol and diesel. At the same
time, new techniques such as continuous
distillation and thermal cracking emerged; these
were followed by thermal reforming and then,
just before the Second World War, by the
introduction of catalysis in transformation
processes.
At present, the principal refining operations
fall into four categories: a) separation of crude oil
into various cuts; b) enhancement of the qualities
of certain cuts; c) transformation of heavy cuts
into lighter cuts (conversion); d) final preparation
of finished products through blending (Fig. 7).
Refineries comprise a number of distinct
parts: a) the processing plant proper, where the
crude is separated into cuts, certain cuts are
enhanced and heavy cuts are converted into
lighter ones; b) utility works, i.e. facilities
producing the energy (fuel, electricity, steam,
etc.) needed for refining processes; c) tank farms;
d) reception and dispatching facilities, and
blending units.
Processing facilities
Every crude oil on the market is unique,
depending on the deposit it comes from. The most
common crudes have a density of between
0.8 g/cm3, i.e. around 45°API, and 1.0 g/cm3, i.e.
10°API (the API, or American Petroleum Institute
degree, is the standard unit of measurement of
crude density). Light crudes yield higher
quantities of light products (motor fuels) while
heavy crudes yield heavier fractions like heavy
fuel oil.
Atmospheric distillation or topping separates
the crude into different cuts ranging from lighter
Middle East
crude oil main petroleum products
liquefied petroleum gases
gasoline
jet fuels
heavy fuel oils
bitumen
other products
naphthas, special gasoline
(white spirit, aviation gasoline),
kerosene, light marine diesel,
special fuel oils, lube base stocks,
paraffins-waxes
diesel fuel, home-heating fuel
propane, butane,
LPG automotive fuel
regular, premium, unleaded
normal, low sulphur content,
very low sulphur content
Saudi Arabia, Iraq,
Iran, Kuwait, UAE
Africa
Nigeria, Gabon, Congo,
Angola, Algeria, Lybia
North Sea
other countries
CIS (ex USSR)
Venezuela, Mexico
Fig. 6. Refining target.

fractions through to petrol, kerosene cuts, diesel
cuts and finally atmospheric residue. In the
condition yielded by distillation, these cuts cannot
generally be used without further processing.
Atmospheric residue, for example, is generally
reprocessed in a vacuum-fractioning tower to
separate a light fraction (vacuum distillate) and a
heavy fraction (vacuum residue). The vacuum
distillate can then be used as feedstock for the
production of lighter cuts by processes such as
catalytic cracking, while the vacuum residue can
be used as the base for making bitumen or fuel
oil. Similarly, since the octane rating of the heavy
gasoline produced by this phase of refining is too
low for it to be used as the base for motor
gasoline, it is further processed in a
catalytic-reforming unit. Another process also
designed to increase the octane rating (of
high-gravity gasoline) is isomerization.
Additional processing is increasingly
required nowadays to eliminate the sulphur
content from refined products. Fuels now have
to comply with extremely strict regulations on
sulphur content (in Europe, 50 ppm of sulphur
for petrol and diesel as from 2005; in the US,
30 ppm for the same products as from 2006).
Most cuts are therefore processed in
hydrodesulphuration units.
Most modern refineries also include
conversion units, in which heavy hydrocarbon
molecules are cracked to yield lighter
molecules. We can distinguish between various
types of cracking: thermal cracking (viscosity
breaking or vacuum residue coking); catalytic
cracking (of which the most common process
is Fluid Catalytic Cracking, FCC);
hydrocracking, where a vacuum-distilled
charge is treated by high-pressure hydrogen in
one or more catalysts.
The refining sequence to be used largely
depends on the kind of crude being processed and
on market requirements in terms of finished
products (volume and quality). As an example,
FCC cracking is better suited for yielding
gasoline bases, while hydrocracking is ideal for
producing high-quality diesel and, in some cases,
jet fuel.
Utilities, storage, blending and dispatch
Utilities such as fuel, electricity, steam,
compressed air and cooling water are largely
produced within the refinery. In many cases,
however, refineries have to import part of their
electricity needs from the grid.
End products are obtained by blending the
intermediate and semi-finished products (which
are also called bases) proceeding directly from
the refining units. Blends are calibrated to meet
the specifications and requirements of
commercial products.
Storage areas occupy significant amounts of
space: some tanks can hold over 100,000 m3 of
oil. The tanks used for storing end products are
smaller. Refineries must also be equipped with
facilities for discharging crude oil and
dispatching products.
Types of refinery
Refineries can be classed into three
categories, depending on their sophistication:
• Topping or hydroskimming refineries, which
essentially comprise atmospheric fractioning
towers as well as, in most cases, a catalytic
reforming unit and hydrodesulphuration units
for middle distillates.
• So-called complex refineries, which are also
equipped with conversion units ranging in
nature from catalytic cracking (FCC) to
hydrocracking and visbreaking (Fig. 8).
• So-called ultra-complex refineries, which also
feature standard and deep conversion
installations capable of directly processing
residues to yield value-realizable products
(light refined products, gas, electricity and so
on). Ultra-complex refineries are still fairly
rare, unless we include simple coking
processes in this category. A number of
ultra-complex refineries are to be found in the
US, where they are specially designed for
processing heavy crudes.
light
heavy
conversion
separation
blending
improvement
quality
Fig. 7. Refining principles.

Economic factors
The global refining situation
Global refining capacity, expressed in terms
of atmospheric distillation capacity, was on the
order of 4.1 billion tonnes per year, or
approximately 82 million barrels per day, in 2004.
In 1950, capacity was a little over 1 billion
tonnes, but from that point rose quickly to reach
the 4 billion tonne mark by 1980. The apparent
stagnation in capacity between 1980 and 2004
conceals the fact that capacity had in fact fallen to
under 3.6 billion tonnes in 1985 in the wake of
the second energy crisis, only to rise again after
the oil-price slump of 1986 (Fig. 9).
This apparent stability since 1980 in terms of
global capacity also conceals some considerable
geographic disparities. Roughly speaking, we can
say that North America (which remains the
world’s leading refining region) has seen its
capacity remain practically unchanged since
1980, while Western Europe has lost 30% of its
capacity in the same period. Most new refineries
have been built in the Middle East and Asia;
furthermore, plans to build new refineries are
essentially focused on Asia.
In total, there are just over 700 refineries
worldwide. Average refinery capacity is thus on
the order of 6 million tonnes per year or 120,000
barrels per day. However, the largest refineries
can handle over 25 million tonnes per year
(500,000 barrels per day) while many small
refineries with capacity of 1 million tonnes per
year are to be found in oil-producing countries
such as the US and in countries where
consumption is low.
This expansion of refining capacity has been
accompanied by an even faster proliferation of
secondary processing capacity (reforming,
cracking etc.) in attempts to augment yields and
improve the quality of light and medium
distillates (fuels) while simultaneously reducing
the production of heavy fuels, for which demand
has collapsed.
The real challenge facing the refining industry
is how to keep up with changes in the market.
While the decline in demand for heavy fuel oil
and the solid growth in consumption of fuels are
hardly new phenomena, some recent
developments in requirements on product quality
have had a major impact on refining:
• The elimination of lead from petrol: the
octane index is a key indicator of petrol
quality as it indicates the fuel’s resistance to
self-ignition, the phenomenon that causes
knocking in spark-ignition engines. The higher
the octane index, the higher the resistance to
knocking. To improve the octane index, lead
compounds were traditionally added to petrol.
The prohibition of lead has brought about the
emergence of new processing techniques
designed to produce high-octane petrols that
are lead-free.
• Reduction in the sulphur content of fuels
(gasolines and middle distillates), achieved
through the construction of desulphuration
units and the conversion of existing plants.
• The introduction of new restrictions on fuel
quality, such as limitations on olefin and
aromatics content in fuels, which has led
refiners to rethink conventional production
processes.
reformer
light naphtha
1 Mt/y
heavy
naphtha
gas oil
vacuum distillate
atmospheric residue
3,5 Mt/y
vacuum residue
1,5 Mt/y
1,8 Mt/y
8Mt/y
1,8 Mt/y
visbreaking
HDS
gas
C3 LPG
C4 LPG
gasoline
naphtha
jet fuel
diesel oil/
heating oil
fuel oil
(20%)
catalytic
cracker
atmosphericdistillation
LCO
HCO
iC4
gasoline
vacuum
distillation
Fig. 8. Refining
scheme-conversion.
HCOϭHeavy Cycle Oil;
LCOϭLight Cycle Oil.

Refining costs
Investment
The construction of a new refinery is a long,
costly and complex operation. Some three years
elapse between the decision to build the refinery
and its opening; this period is preceded by
months, if not years, of preliminary research. The
scale of investment involved in the construction
of a refinery depends mainly on its size, its
complexity and its location.
Size and complexity. In general, it is
estimated that a refinery built in Europe with a
capacity of 160,000 barrels per day (8 million
tonnes per year), equipped with catalytic
cracking, visbreaking and gasoline units, would
currently cost some $1.5 billion. This cost could
rise considerably with the addition of
exceptionally restrictive anti-pollution
regulations that address not only the immediate
environs of the refinery (waste) but also the
quality of products.
In the case of a slightly smaller (5 million
tonnes per year) simple refinery (atmospheric
distillation with catalytic reforming and
hydrodesulfuration plants), the cost would be less
than half of the figure for the larger refinery
above. Conversely, a refinery equipped with a
deep conversion unit, such as fluid coking with
coke gasification or residue hydrocracking, would
cost at least a billion dollars more than a refinery
equipped with a conventional (e.g. FCC)
conversion plant (Table 5).
Complexities notwithstanding, size generates
some significant economies of scale: if we double
the charge processed by a reactor, the quantity of
steel necessary for the construction of this reactor
(and its cost) increases roughly by only two-thirds
(in fact, the quantity of steel needed is
proportional to the surface area of the reactor,
which increases with the square of the
dimensions; volume increases with the cube of
the dimensions). These economies are confined,
however, by the limitations on the size of certain
units. The maximum capacity of an atmospheric
distillation unit will, for example, be some 12
million tonnes per year, so refineries with larger
capacities will therefore have two atmospheric
distillation columns.
Location. Equipment transport and assembly
costs are significant factors in total construction
costs. A refinery that is built at a great distance
from the factories that produce its principal
components (columns, reactors etc.) will
therefore be more expensive than an identical
refinery built near its equipment suppliers (which
is the case in the leading industrialized countries).
Shortages of qualified local labour mean that
external technicians have to be sent in, and this
too has a significant impact on costs. Finally,
severe climactic conditions (as in Siberia and the
far north of North America) can also add to
equipment costs.
Other factors. Since off-sites (utilities,
storage, loading and discharging areas) can
account for over half the investment costs of a
North America
South and
Central America
Africa and
Middle East
1,089
1,031
734 689
357
335
4,068 Mt/y1980 4,102 Mt/y2004 135 Mt/yprojects
14
275
484
18
528
1,002
627
11
75
1,019
11
Asia
Western
Europe
Eastern Europe
and other former
Soviet countries
capacity in Mt/y (at 01/2004)
Fig. 9. Refining
capacities in 1980 and 2004
and projects.

simple refinery, the configuration of the refinery
has an important impact on investment. For
example, autonomy of electrical energy (bought
from the grid or produced locally) and the size of
the tank farm, as well as the size of the loading
and discharging areas and the methods employed,
all affect costs. In certain cases, the refinery can
be designed to handle special crudes such as sour
crude, and this significantly increases reactor
costs.
Breakdown of costs
Costs are traditionally broken down into:
variable costs, which are directly proportional to
the amount of crude processed; fixed outlay costs,
which are process-independent; capital costs.
Variable costs. These include the price of
chemicals and catalysts, and the financial
expenses associated with the immobilization of
crude and products during production and
storage.
Chemical products have accounted for limited
variable costs since the virtual disappearance of
tetraethyl lead, formerly used as a fuel additive.
However, other additives are increasingly
incorporated into refined products to improve
their properties (but this does not always take
place at refinery level).
Catalysts are used in many refinery processes
such as reforming, cracking, isomerization,
alkylation and hydrodesulphuration. The
catalysts used in reforming contain precious
metals, and their price can reach several hundred
dollars per kilogramme or even higher. The
catalyst is then regenerated (continuously, in
modern units), and at the end of the process
cycle the precious metals are recovered and
re-used. In catalytic cracking, however, the spent
catalyst is continuously removed from the unit
and new catalyst introduced. Total catalyst costs
can come to several dollars per tonne of crude
processed.
To highlight immobilization costs, we can
look at a typical European refinery that processes
crude from the Middle East. It takes some 40 days
to transport the crude to the refinery; before it is
processed, the crude is stored for several weeks to
allow impurities to settle out and to ensure
sufficient reserves for avoiding stock outages and
meeting legal requirements on emergency stocks.
Processing is rapid, but the end products then
spend a further few weeks in storage. In all,
weeks or even months elapse between the
purchase of the crude and the sale of the products
it yields. In the meantime, the cost of the crude,
already paid for but with no value realized on it,
has to be covered: by a loan, for example.
Immobilization costs can therefore be over two
dollars per tonne of crude processed.
Fixed outlay costs. These costs include
personnel and maintenance costs, insurance,
charges and general expenses, all of which are
largely unaffected by the quantities refined.
Personnel costs are the same whether or not the
refinery is working to full capacity. The number of
employees in a refinery varies enormously. A
simple refinery will employ a minimum of 200 to
250 people. However, personnel numbers depend
much more on the complexity of the refinery than
on its size. A large, fairly complex refinery in
Europe can employ up to 1,000 people. Other
factors can also lead to increased personnel needs,
such as the presence of several small units in the
same refinery or an extensive social services
infrastructure (as in the refineries of the former
USSR).
Table 5. Refinery investment cost (M$)
Basic refinery
5 Mt/y
Upgraded refinery
8 Mt/y
Deeply upgraded refinery
8 Mt/y
Process units
(excl. cracking)
230 360 360
Cracking complex
(FCC, Alkyl., visbreak.)
– 375 375
Deep conversion complex – – 700
Offsites (Utilities production
units, storage, shipping facilities)
550 740 1,020
Total 780 1,475 2,455

Maintenance costs are more or less
proportional to initial investment and can
represent between 3 and 4% of investment
annually.
General expenses include charges, insurance
and miscellaneous operating expenses.
Capital costs (recovery and returns). Capital,
whether the initial investment cost of a new
refinery, the costs of revamping an existing one or
of constructing a new plant in an existing
refinery, has to be recouped. It also has to
produce revenue. If an investment is financed
entirely by loan, the corresponding capital costs
include yearly repayments and interest. If the
investment is fully self-financed, the refiner has
to recover its capital and generate revenue.
To return to the example of the refinery with
an annual capacity of 8 million tonnes and
costing 1,5 billion dollars, imagine that the
capital investment is financed entirely by loan
with a repayment period of 10 years and an
interest rate of 8%: the average annual cost will
be about 200 million dollars for the first 10 years
of the refinery’s life, then nil in subsequent years.
This figure breaks down as follows: capital ϩ
interest ϩ (with the refinery working to full
capacity) a charge of $25 per tonne of crude
processed.
Total cost and attendant factors. Refining
costs depend, as we have seen, on a great many
factors, and this makes it difficult to give accurate
cost estimates. Fixed costs can represent up to
80% of the total cost of processing every tonne of
crude. Of these fixed costs, capital charges are
particularly significant. This means global costs
can vary greatly depending on whether or not the
installation has reached payback point.
If we take the case of the new refinery
equipped with a conventional conversion plant as
described earlier, total costs per tonne of crude
processed are on the order of $35 or more – on
condition, that is, that it is working to its full
annual capacity of 8 million tonnes. Costs per
tonne, of course, increase significantly if the
refinery is working well under capacity.
If, on the other hand, we take the example of a
refinery whose investment has been largely
recouped (which is the case with most refineries
in operation in the principal refining regions),
costs are much lower, even as low as $15 per
tonne. But these refiners too are subject to
expenses resulting from investment in necessary
modernizations, even if only to improve the
quality of their products or reduce the
environmental impact of the refinery.
Expressed in terms of tonnes or barrels of
crude processed, these costs are comparable to the
refining margins obtained by the operators
(margins that fluctuate with market conditions).
Other factors, aside from capital costs, play a
more or less-significant role; the foremost of
these is capacity utilization rate. In a refinery
working at 66% of its capacity, unit-fixed costs of
processing are 50% higher than for a refinery
working at 100%. In theory, therefore, it is in the
refiner’s interest to work at the highest possible
capacity. Practices may differ in cases where
excess output in a given refining region can flood
the market and therefore reduce the margins
achieved; in this situation, it may be more in the
refiner’s interest to reduce its capacity utilization
rate, at least temporarily.
As we saw, according to the law of economies
of scale, the larger the refinery the smaller the
unit investment and, consequently, the lower the
capital costs. Furthermore, for a given operating
capacity rate, the larger the refinery is, the lower
the unit processing costs, minus capital. The size
of the refinery has very little bearing on
personnel costs and general expenses, and
maintenance costs rise at a rate far slower than
increases in size; hence the notion of a minimum
cost-effective threshold, which is on the order of
5 million tonnes per year (100,000 barrels per day)
for atmospheric distillation. At present, except in
some very special cases, no smaller refineries
exist.
The complexity and the location of the
refinery influence not only its capital costs but
also costs relating to labour, maintenance and
other issues. As we shall see in the next section,
complex refineries are capable of obtaining
higher margins than simple refineries, which
enables them to cover higher refining costs.
Refining margins
Definitions
The (gross) refining margin for each tonne of
crude processed is the difference between the
ex-works value of the products obtained and the
cost of the crude entering the refinery; the value
realization of the products is calculated by
multiplying their price by their respective yields,
which vary from one refinery to another.
The net margin is equal to the gross margin
minus variable costs, which include chemical
products, catalysts and carrying charges related to
the immobilization, especially the storage, of
crude and products.

To reach break-even point, gross margin must
cover total processing costs; to put it another way,
net margin must cover fixed costs, i.e. all outlay
costs and capital costs. The result is thus equal to
net margin minus fixed costs.
We should note that the value realized on
products takes into account the net (i.e. sold)
output of the refinery, that is, after deduction of
internal consumption of refinery gas and fuel oil
for the utilities. This consumption is not
insignificant: in a refinery equipped with a
conventional conversion plant, it represents some
5-6% of the crude processed. For the present
purposes, although it is classified as a variable
cost, we shall not include this consumption in
processing costs as compared against margins.
Typical margins for typical refineries, known
as margin indicators, are published by oil
companies and trade journals. In Europe, margin
indicators typically refer to an imaginary refinery
located in Rotterdam and operating in a highly
competitive environment.
It is also possible to calculate a per-unit
margin, equal to the difference between the value
of the products yielded by the unit and the value
of the feedstock. Unlike finished products,
feedstock and intermediate products do not yet
have any market value. We can however evaluate
the prices of these feedstocks and intermediary
products on the basis of their potential uses; to do
so, we use an opportunity cost, i.e. the price that
the feedstock or product would command if put to
an alternative use.
Per-unit margins are of great interest to
refiners as they indicate which units are
profitable, which have to work at maximum
capacity and which should work at a slower rate.
These economic imperatives are frequently
unworkable owing to technical constraints,
however.
Factors that influence margins
The gross margin obtained by a refinery
essentially depends on its degree of complexity. A
refinery equipped with cracking units for
high-octane gasoline bases produces lighter
products (fuels) that meet extremely strict
specifications and have a higher market value.
Furthermore, a sophisticated refinery can
more readily process heavy or sulphur-rich
crudes, putting its conversion plant to maximum
use. These crudes offer price differentials that are
often substantial in relation to lighter, low-sulphur
crudes, and with higher oil prices, price
differentials widen further.
A better margin does not necessarily mean
greater profitability, as the costs for a complex
refinery are higher than those for a simple
refinery. In reality, the margins obtained are
sometimes considerably higher than the published
margins. There are a number of reasons for this.
The published margins refer to the principal
products only (such as motor fuels and fuel oil)
but not to specialist products (oils, bitumens,
LPG, petrochemicals and so on), which are often
a more lucrative activity. For example, stock oils,
which are obtained via increasingly complex
refining processes, and even in some cases
finished oils, generally offer attractive returns.
Some refineries play this situation to their
advantage by producing for niche markets.
Similarly, a refinery that is part of a
petrochemical complex is better positioned to
realize value on certain cuts (naphtha, etc.) and
benefit from lower raw-material rates.
More generally, prices (even prices of the
major products) are often higher than those
applied in margin-indicator calculations where the
refinery has a favourable geographic location: a
refinery located inland, and moreover in an
oil-importing region, will sell its products at
prices higher than those given by the international
indices (Rotterdam, US Gulf, Singapore, etc.).
Changes in margins
Until the mid-1970s, margins had remained at
levels that were broadly satisfactory for the
industry. Increasing consumption of refined
products ensured margins that were capable of
covering long-run marginal costs, including the
recovery of invested capital and the returns
generated. The principal concern of the oil
companies (and of many governments) was how
to satisfy demand. In the larger European
countries, this meant building one new refinery,
or installing the equivalent new capacity, every
year.
Over the decade as a whole, prices for a
typical refinery remained at an average of $2 per
barrel. Taking into account monetary erosion, this
figure would be about $7 per barrel in today’s
money.
At the turn of the decade, though, the situation
changed drastically and margins fell right across
the board. Increases in crude prices in 1973 (as a
result of the Yom Kippur war) and in 1979-80
(with the Iranian revolution) caused consumption
to level out and then to decrease. The enormous
surpluses of fuel oil caused by a decline in
demand and the lack of conversion capacity had

the effect of widening the gap between fuel-oil
prices, which were already very low, and those of
light products.
At the same time, refining capacity began to
far outstrip supply, especially in Europe and the
US. This overcapacity had two consequences:
since marginal processing costs per barrel were
very low, more and more refiners began to
process more crude, and therefore to add to the
surplus of products (a short-term gain with long-
term consequences). The ultimate result was a fall
in margins.
As total refinery costs had to be spread across
quantities of products far in excess of the optimal
volumes owing to overcapacity, unit costs grew
significantly.
This ‘scissor effect’, in conjunction with
stagnation in consumption in the 1980-85 period,
made itself felt in the form of low profitability,
which forced refiners to reduce their capacity. In
the US, this reduction occurred rapidly and to a
relatively limited extent; however, with the
restructuring of the refining industry, many
smaller, independent refineries closed down. In
Europe it came later but with far more drastic
effect: of 150 refineries, some 50 had to close
down. Also, many of the refineries that survived
saw their distillation capacity slashed as a result
of the closure of older plants; there was even, in
some cases, the conversion of distillation plants
into visbreaking units. In Japan, restructuring was
more limited in scope as the country was a major
importer of products (primarily from Singapore
and the Persian Gulf) and had no excess capacity
problems.
This drive to reduce capacity came to an end
around 1985, at the time of the oil crisis (OPEC
production quota policy and crude oil prices
based on netback agreements). The sharp drop
in crude oil prices that resulted from this policy
relaunched product consumption, which was
also stimulated by new demand from emerging
economies. The fall in the value of the dollar in
the same period was another contributing
factor.
The situation by this time was the reverse of
the 1970s crisis. Margins increased until the end
of the 1980s, reaching levels that, for the first
time in a decade, were entirely satisfactory to
operators.
Margins remained moderate throughout the
1990s at no more than a few dollars per barrel –
far lower than total costs for a new refinery.
There were a number of reasons for this: on the
one hand, world consumption of refined
products taken as a whole was growing very
slowly (1-2% per year) during this period; on the
other hand, refinery capacity-utilization rates,
always a key factor for margin trends, were low,
although they were improving towards the end
of the decade.
While capacity was significantly reduced in
most regions (with the notable exception of the
former USSR, which on the very eve of its
demise and the ensuing collapse in demand
found itself with a gigantic overcapacity
problem that, even today, has not yet been fully
absorbed), the mismatch between the supply
structure of the refineries and the demand
structure of the economy persisted for years. In
their efforts to reduce fuel oil surpluses
associated with the lack of conversion capacity,
some refiners found themselves forced to cut
back on their output.
Here, it is worth noting an aggravating factor
in times of overcapacity: real refining capacity is
often higher than the published or stated capacity.
There are several reasons for this:
• Some indicators underestimate real capacity,
and some countries only take into account
distillation capacity necessary for supplying
cracking units. In the former USSR, the real
capacity of most of these units was well above
the design capacity.
• Mothballed capacity can be quickly
reactivated.
• Major progress has been made in addressing
stoppage times for maintenance work.
Intervals between stoppages have stretched
from every two or three years to every five
years; this means a refinery can now operate
more than 95% of the time.
• The phenomenon known as ‘capacity creep’:
the tendency to step up capacity from initial
design capacity caused by limited investments
by refiners in certain units
(‘de-bottlenecking’) that have not yet been
factored into estimates.
So far this decade, the situation has changed
from one year to another: the significant rise in
margins in 2000 was followed by a decrease in
2001, which became more accentuated in 2002, to
be followed by a net improvement with high
margins since 2003.
The reason for this rise in margins is the
significant increase in world demand, driven
mainly by the US and by such emerging
economies as China. This rise in demand is also
the cause of the extremely high
capacity-utilization rate of refineries in many

regions. It is no longer any exaggeration to
speak of saturation in the refining sector,
especially in conversion units, with the United
States worst affected. Worldwide refining
capacity, not including the persistent
overcapacity in the former USSR (which is
currently on the order of 3 million barrels per
day), can be estimated at a little less than 81
million barrels per day. According to the
International Energy Agency, global production
of crude oil and liquid natural gas reached a
similar level in 2004, at slightly over 81 million
barrels per day (a uneasy equilibrium that is the
perfect illustration of the tension that grips
today’s oil market).
Moreover, major oil consumers such as the US
and Europe (Figs. 10 and 11) are becoming
increasingly dependent on imports for supplying
their oil-product demands (Japan has always been
a major importer).
Margins according to region
Margins vary greatly from one region to
another in the United States, but in general they
are still much higher than in Europe. The lowest
margins are those obtained by complex FCC-type
refineries in the Gulf of Mexico region. This is a
highly competitive, import-intensive region where
margins are affected by refined products arriving
principally from Europe and South America.
$/bbl
Ϫ4
Ϫ2
0
2
4
6
8
10
Arabian Light
crude cost: CIF Europe
products cost: FOB Rotterdam
Brent Blend
12
year
82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 00 01 02 03 04
Fig. 10. Gross refining
margin (refinery with
cracking – North West
Europe).
Ϫ3
Ϫ1
1
3
5
7
$/bbl
Singapore-Tapis-hydroskimming
Singapore-Dubai-hydrocracking
95 96 97 98 99 00 01 02 03 04
Ϫ4
Ϫ2
0
2
4
6
8
$/bbl
US Gulf-LLS-cracking
95 96 97 98 99 00 01 02 03 04
Ϫ3
Ϫ1
1
3
5
7
$/bbl
Rotterdam-Brent-hydroskimming
Rotterdam-Brent-cracking
95 96 97 98 99 00 01 02 03 04
Fig. 11. Development of net refining margins. In the legends: refining centre, crude type, refinery type.
LLSϭLight Louisiana Sweet.

Margins are much higher in the Midwest and even
more so in California, due partly to the better
balance between supply and demand and partly to
higher prices for products. Californian motor fuel
specifications (the California Air Resources
Board, CARB, regulations) are more stringent
than federal requirements, and this situation is
reflected in prices. In refining regions like the
Gulf of Mexico and California, where many
refineries are equipped to handle heavier crude
oils, refiners can enjoy particularly high margins
when the price differential between heavy and
light crudes widens significantly. This has been
the case since 2003.
In Asia, the situation was favourable until
mid-1997. Margins often reached 3 or $4 per
barrel due to heavy demand and protectionist
measures in certain markets. Serious shortages in
refining capacity made Asia a major importer,
mainly from the Middle East. Margins collapsed
in 1997 as a result of the economic crisis that
swept the region at this time and the simultaneous
introduction of new and significant refining
capacity.
In Europe, the margins of a typical complex
refinery located in Rotterdam remained extremely
low throughout the 1990s (on the order of 1 or $2
per barrel) but recovered early this decade.
Bibliography
Favennec J.-P. (sous la coordination de) (1998) Exploitation
et gestion de la raffinerie, in: Le raffinage du pétrole,
Paris, Technip, 1994-1999, 5v.; v.V.
Masseron J. (1991) L’économie des hydrocarbures, Paris,
Technip.
Olivier Appert
Jean-Pierre Favennec
Centre for Economics and Management
IFP School
Rueil-Malmaison, France

Analysis of cost structure and functions in oil transport and refining

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