2013-06-

10 | FICC Oslo 1

2013-06-

10 | FICC Oslo 1 1

SEB Commodity

Research

Setting the price of crude oil

May 2013 Bjarne Schieldrop

Head of SEB Commodities Research

Bjarne.schieldrop@seb.no

+47 9248 9230

2013-06-

10 | FICC Oslo 2

Crude oil - Not one commodity but more than 300! Thus not one price, but many! Huge variety qualities, locations, regulations,…

2013-06-

10 | FICC Oslo 3

1940 to 1970 - The Seven Sisters period Oligopol pricing, no free market, no OPEC power. The Concession market

Seven Sisters dominated

Total control of crude oil supply

The Concession system

Posted prices a fiscal instrument

No link between price and market

No functioning spot market

Transfer prices – tax

minimization

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10 | FICC Oslo 4

1965 to 1973 – The end of the Concession system Seven sisters looses control and OPEC is formed in a soft spot of prices

Late 1950s - independent oil companies were

able to gain access to upstream crude oil

Libya, Venezuela, Iran and Saudi Arabia granting

concessions to non-majors

Increasing competitive pressure led the majors to

cut the posted prices in 1959 and 1960

1960 - OPEC formed to counter decline in prices.

Strong demand growth from 1965 to 1973. OPEC

increased production from 14 mb/d to 30 mb/d

1970 – Libya pushed for better deals and soon all

OPEC members pushed for same deals.

1973 – Demand for revision of Teheran deal with

large increase in posted price. Majors said no.

1973, October 16 – OPEC unilaterally announces

an increase in posted price for Arab Light from

$3.65/b to $5.1/b and then to $11.65/b

OPEC combines oil production with geopolitics and announces

a 5% production reduction per month until Israeli forces are out of Arab territory

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10 | FICC Oslo 5

1970 to 1975 – The Buy-back Pricing System The first steps of a new pricing regime, but highly confusing and inefficient

Along with increasing negotiation power from

the mid 1960s host countries were able to

negotiate increasing equity shares in oil

Iran, Iraq and Kuwait opted for

nationalization of their oil production

activities

Need for host countries to sell its oil to third

parties led to Official Selling Prices (OSP)

and Government Selling Price (GSP)

Limited marketing experience and inability to

integrate into the downstream market led host

countries to mostly sell its equity share of oil

back to the operating oil companies

1970 to 1975 – The Buy-back system. Highly

inefficient pricing system with several different

prices: Posted prices, Official selling prices

and Buyback prices. No mechanism for

convergence. Buyers could buy at different

prices.

The system broke down in 1975

OPEC conference in Vienna in 1974

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10 | FICC Oslo 6

1974 to 1986 – OPEC Administered Pricing System De-integration of market as majors lost access to oil. Strong rise in spot deals

A complete shift in pricing power to OPEC

New system centered around Marker price

Saudi Arabia’s Arab Light the elected marker

OPEC continued to publish OSPs but now as the

differential to the marker price

Differentials was a result of the different crude

qualities which gave different refining economics

Setting of differentials were very flexible which

made setting the marker price very difficult

1979 – Iranian crisis. The new Iranian regime

canceled all agreements with oil companies

OPEC became marketer of its own oil and the

majors became buyers like any other

Majors lost access to huge amounts of oil. Forced

into the market as buyers. De-integration of

market. Rapid development of competitive

market. Strong rise in spot transactions.

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10 | FICC Oslo 7

1979 to 1986 - End of OPECs administered pricing Declining demand and increasing non-OPEC production

Iranian revolution 1979 -> oil price up 2 to 3 times by 1981 ->

Global recession and oil demand decline.

Increasing non-OPEC oil production in mid 1980s amid

recession

Non-OPEC producers with exess oil undercut OPECs prices

A high Marker price -> loss of market share for Saudi Arabia

while it was good with a high marker price for the other OPEC

members who sold at a differential

OPEC dissagreement started to emerge

OPEC market share: 51% in 1973 and 28% in 1985

Demand for Saudi Arabian oil fell from 10.2 mb/d in 1980 to only

3.6 mb/d in 1985!

The net-back pricing system. A desperate measure that failed.

In order to hold on to its market share Saudi Arabia guaranteed

refineries a margin. Rest of OPEC followed suite. Refineries ran

flat out and floded the market with oil products. Crude prices

chased product prices lower.

In 1986/87 Saudi Arabia gave up on the adminstered pricing

system and joined the more flexible market related pricing

system that many oil exporting countries had gradually

developed.

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10 | FICC Oslo 8

1986 – A market based pricing system A complex structure of interlinked markets with dealing at arm’s length

Non-OPEC producers

Refiners

Swing producers - OPEC

Consumers

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10 | FICC Oslo 9

Physical market Contractual dealing The contractual dealing is strongly shaped by the market’s physical characteristics

A rise of independent crude buyers and sellers along with increasing non-OPEC production

A rise in arm’s length dealing

Spot crud transactions, an element of “forwardness”, as much as 45 to 60 days

Price fixing at the date of agreement or loading?

Long-term contracts - OTC

A series of shipments over one to two years

Contracts specify: Volumes, delivery schedule, default clauses and not least the price

calculating methodology to be applied

The pricing methodology links the price of the cargo in the contract to a crude oil spot price

The Gross Products Worth (GPW) – Different crude oils have different values

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10 | FICC Oslo 10

Formula pricing – the heart of today’s oil market Applies to both spot, forward and long term contracts

Today most crude oils are priced as a differential D to a few benchmark crudes.

P_x = P_b + - D

The differential D is often set at the time of agreement. The benchmark P_b left floating

Differentials for different crudes are usually set

Independently by each of the oil producing countries or by

Price Reporting Agencies

Competing crudes have competing differentials (Saudi Arabia Light and Iranian Light)

Buyers market: CIF

Sellers market: FOB

Advantage of formula pricing

Pricing set close to delivery

Price discovery in differentials and a few benchmarks

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10 | FICC Oslo 11

Benchmark prices – The heart of pricing formulas A few key crude oil benchmarks sets the price level – the rest set by differentials

Gulf of Mexico: WTI – US, Cushing Oklahoma

The Gulf: ASCI – Argus Sour Crude Index

The Gulf: Oman, Dubai – Gulf crude oil index

North Sea: Dated Brent / Dated North Sea Light / North Sea Dated / Dated BFOE

North Sea: BWAVE – The weighted average price of Brent futures trades during a day

Formula prices may be based on the “physical” benchmarks such as Dated Brent or on the financial

layers surrounding these benchmarks such as BWAVE

Choice of Benchmark is extremely important for revenue and pricing

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Brent crude minus US WTI

US

D/b

diff

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10 | FICC Oslo 12

Choice of benchmark depends on export destination ..,but Brent crude is gaining ground as the global benchmark

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10 | FICC Oslo 13

Why do we need Price Reporting Agencies? Price assessments are needed in opaque and illiquid markets

Physical benchmarks are not trading in real time

Illiquid, opaque with a few large chunky transactions

Sometimes no transactions at all, only bids and offers

No obligations to report physical transactions

Platts and Argus: Assess the price level

Assessment methodology vary from market to market

Actual transactions – the highest form of proof

Often have to settle for second best – bids and offers

Assessments are always an interpretation

Methodologies change over time due

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Some basic features of Benchmark crudes Large differences between benchmarks

Global base of physical

benchmarks

3 mb/d or 3.5% of global

prod

Financial layers have

developed around these

benchmarks: OTC: Forwards

and swaps. Exchanges:

Futures and options

Financial layers have grown

in size and sophistication and

has now in them selves

become part of the oil price

identification process

Note: In the table it should say “KBPD” and not “MBPD”

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10 | FICC Oslo 15

Brent crude – Contract in constant change Declining production demanded a constant refill of new crudes

1980s – Dated Brent spot market and an informal physical forward market. It was a mixture of crudes produced at different fields,

collected through main pipelines and transported to terminal Sullom Voe. Physical base was 885 kb/d in mid 1980s

1990 – Name changed to Brent Blend. Brent production at 366 kb/d. Ninian North Sea crude added (total prod: 856 kb/d)

2002 – Name changed to BFO. Brent Blend production down to 400 kb/d being only 20 cargoes per month. Fortis (UK North) and

Oseberg (Norway) added to Platts definition and were thus deliverable into the Brent forward contract. Fortis is a mixture of fields

delivered to Hound point UK and Oseberg is a mixture of fields delivered to Sture terminal. This created the Brent – Fortis – Oseberg

or BFO benchmark.

Distribution of cargoes across a wider range of companies. Non with a dominant position. Volume 1200 kb/d (63 cargoes/mth)

2007 – BFO volume down to less than 1000 kb/d (48 cargoes/mth). Ekofisk was added to the physical spot market: BFOE, 1.5 mb/d

Ekofisk crude is a mixture of fields delivered to the Teesside terminal UK

BFOE production has fallen from 1.5 mb/d in 2007 to less than 1 mb/d in 2012

The BFOE contract is likely to be enlarged in the future as physical volumes decline further

Brent: Sullom Voe Shetland Fortis: Hound Point, Scotland Oseberg: Sture terminal, Bergen Ekofisk: Teesside UK

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10 | FICC Oslo 16

Brent Forwards – the first layer – 21 day BFOE Trading of oil cargoes with known delivery month, but unknown delivery date

Started for tax spinning purposes

Physical crude oil loading structure - Example

By early June the latest all producers nominate preferred loading dates for July

By June 10 all producers are allocated individual 3 day slot times for loading in July

=> producers get a minimum 21 day notice for loading date

Once the 21 day notice day expires the cargo starts to trade as a Dated Brent cargo

Physical cargoes (600 kb) often bought and sold many times in the Forward market (known month)

The Chain of buyers and sellers

Then the cargoes are often bought and sold many times as Dated Brent cargoes (know dates)

Dated Brent cargoes rarely trade less than 10 days ahead of delivery

Dated Brent Index or Dated BFO Spot Index

The average of all traded Dated Brent cargoes over a day with delivery dates 10 to 21 days ahead

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Brent crude futures market

Launched on IPE in 1988. Trades today at ICE

The December contract expires the 15th of November if it is a business day

It is cash settled, but with an option for physical delivery through (EFP)

In 2010 the daily average traded ICE Brent volume exceeded 400 mb (5x global demand)

ICE Brent is settled against the ICE Brent Futures Index – The Brent Index

The Brent Index is calculated on the basis of transaction in the Brent Forward market

ICE Brent is thus settled against a forward market and not a pure physical spot

EFP - Exchange For Physical - OTC

An EFP contract switches a futures position to a 21 day BFOE Forward contract

EFP’s are usually quoted as a differential to Brent futures

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Price level for Brent crude is set in the Futures market Everything else is set by differentials.

Brent Futures BWAVE Brent Futures

Forwards 21d BFOE Dated Brent

EFP

CFD

Dated Brent Index

Dated Brent Index

Forward 21d BFOE (July) = Brent Future (July) + EFP (July)

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10 | FICC Oslo 19

•

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