Dundee University Morten Frisch Paper 24 Feb 2010

CURRENT EUROPEAN GAS PRICING PROBLEMS:
SOLUTIONS BASED ON
PRICE REVIEW AND PRICE RE-OPENER PROVISIONS

24 FEBRUARY 2010

Morten Frisch
Senior Partner
Morten Frisch Consulting

Morten Frisch Consulting
6 Holmwood Close
East Horsley
Surrey KT24 6SS
United Kingdom

Tel: +44-1483-284248
Fax: +44-01483-285099
Email: office@mfcgas.com
Web: www.mfcgas.com

Morten Frisch Consulting accepts no liability for commercial decisions based on the content of this paper. Although the paper is copyright of Morten Frisch
Consulting, quotes from the paper are permitted, provided full references to the paper and Morten Frisch Consulting are made. Onwards transmission or copying
of the paper is allowed in its original form only.

Current European Gas Pricing Problems: Solutions Based on Price Review and Price Re-opener Provisions
Morten Frisch, 24 February 2010

Table of Contents

Table of Contents.................................................................................................................................... 2
Table of Figures ...................................................................................................................................... 2
About the Author .................................................................................................................................... 3
Abbreviations .......................................................................................................................................... 4
Executive Summary................................................................................................................................. 5
Europe’s Two Level Gas Price System ....................................................................................................... 6
Market Forces Behind the Two Level Price System .................................................................................... 7
European Gas Trading Hubs and Their Developments........................................................................ 7
LNG and the North American Gas Market Connection ........................................................................ 9
Market Forces and Gas Flow Patterns across Europe ........................................................................13
Price Review and Price Re-opener in a Changing Market...........................................................................15
Methodology of Price Review and Price Re-opener Clauses Explained ................................................15
Price and Price Indexation Solutions ........................................................................................................18

Table of Figures

Figure 1: Average German Gas Import Prices vs. NBP and NCG Month Ahead Prices ................................... 6
Figure 2: Continental European Gas Pricing Formula ................................................................................. 7
Figure 3: NW European Gas Trading Hubs and Pipeline Routes .................................................................. 8
Figure 4: European Gas Hub Developments in 2009 .................................................................................. 9
Figure 5: Additional LNG Liquefaction Capacity.........................................................................................10
Figure 6: US Unconventional Gas Reserve Potential..................................................................................11
Figure 7: Forecast of US Net LNG Imports ...............................................................................................11
Figure 8: US AEO 2010 LNG Demand Projection (Base Case) ....................................................................12
Figure 9: UK LNG Imports.......................................................................................................................13
Figure 10: North West European Natural Gas Infrastructure......................................................................14
Figure 11: Two Tests in the Price Review and Reopener Process...............................................................16
Figure 12: Buyer’s Profitability Test - Decision Diagram ............................................................................17

Keywords: 1. European gas prices. 2. Gas price review. 3. Gas price indexation. 4. Gas price clauses.
5. Shale gas. 6. Unconventional gas. 7. LNG. 8. European gas market. 9. European gas supply and
demand.

© 2010 Morten Frisch Consulting 2


About the Author

Morten Frisch, Senior Partner, Morten Frisch Consulting (MFC)
Morten Frisch’s career developed in parallel with the gas industry in his home country of Norway. He has
more than 35 years of hands-on experience addressing strategic, commercial and operational issues along
the entire value chain for LNG and pipeline gas. This experience stems from work for the Norwegian
Government, multinational oil companies and as a consultant since 1990.
The first time Morten Frisch led a gas sale negotiation was in 1976, the year his first dealings with LNG
receiving terminals (Everett and Cove Point terminals, USA) also took place. His first LNG marketing work
was conducted in 1980 (for the then Phillips Petroleum’s Bonny LNG project in Nigeria).
In 1977 as part of gas price indexation formulae design work, Morten Frisch was instrumental in the
development and drafting of the Norwegian and Swiss law Price Review and Price Re-opener clauses, now
universally used in long - term gas sales and purchase contracts for the supply of gas to Continental Europe.
In 1993 together with Freshfields solicitors in London he converted this language to English and New York
law. The resulting Price Review and Price Re-opener clauses are now commonly used in long term Atlantic
Basin LNG supply agreements.
Since 1990 Morten Frisch has conducted extensive work related to natural gas in the Middle East, Iran,
Russia, and Central and Western Europe. He has also provided consulting services to clients or projects in
North and West Africa, Japan, Australia and New Zealand. His consulting practice deals with a variety of gas
issues although a high number of assignments have been to address gas pricing issues, commercial
optimisation, risk mitigation strategies and methods, for operations in rapidly changing gas market
environments. He has been called upon as an expert witness in arbitrations and court cases dealing with gas
contract related issues, particularly in disputes involving price review/price re-opener clauses. He has acted
as a lead negotiator in gas sales and purchase negotiations for clients. In the past he has also advised
governments on international gas issues.
Morten Frisch also advises clients on the organisational structure and staffing of gas-related projects, and he
has acted as a mentor for their novice commercial gas staff. He is an established provider in the field of gas
training.
Morten Frisch is a chartered engineer (Sivil Ingeniør) in his home country of Norway and an economist
(degrees from University of Newcastle upon Tyne, UK and Massachusetts Institute of Technology (MIT),
Mass., USA). He is a member of the Society of Petroleum Engineers (SPE) (since 1975), the International
Association of Energy Economics (IAEE) and the British Institute of Energy Economics (BIEE). He has
published a number of articles addressing strategic and commercial gas issues. He is frequently invited to
give presentations at major international gas and energy conferences and appears regularly as a guest on
major TV stations’ business programmes.



Abbreviations

BAFA = Bundesamt für Wirtschaft und Ausfuhrkontrolle is the name for the German Federal Office of
Economics and Export Control. Monthly average unit cost of imported natural gas across all border points is
published by this Federal Office on a monthly basis in €/TJ.
BBL = BBL pipeline transmits natural gas from Balgzand in the Netherlands to Bacton in the United
Kingdom. The pipeline is currently able to carry physical flow only in the direction from The Netherlands to
the UK.
Bcm = Billion cubic meters (106).
CEGH = the Central European Gas Hub at Baumgarten, established by OMV Gas & Power GmbH. OMV and
Gazprom have recently signed a Cooperation Agreement to jointly develop the hub with the aim of it
becoming the largest trading platform in Continental Europe (Press Release of 25 January 2010)
EIA = The Energy Information Administration of the United States Department of Energy.
€c = Euro cents.
GASPOOL = joint company which operates the market area cooperation of DONG Energy Pipelines GmbH,
Gasunie Deutschland Transport Services GmbH, ONTRAS – VNG Gastransport GmbH and WINGAS
TRANSPORT GmbH & Co. KG.
GO = Gas Oil.
Henry Hub (HH) = Henry Hub is the pricing point for natural gas futures contracts traded on the New York
Mercantile Exchange (NYMEX). It is also a physical point on the natural gas pipeline system in Erath,
Louisiana.
Interconnector (IC UK) = Interconnector UK is the bi-directional physical natural gas pipeline link
between Bacton, UK and Zeebrugge, Belgium.
LSFO = low sulphur heavy fuel oil with sulphur content of 1% or less. Frequently referred to as Low Sulphur
Fuel Oil.
Mmbtu = Million British Thermal Units
Mt = million tonnes.
MWh = Megawatt hours; 1 MWh is equal to 3.4121 mmbtu.
NBP = the virtual National Balancing Point in the United Kingdom’s pipeline network.
NCG/EGT = a joint company which operates the market area cooperation of Bayernets GmbH, Eni Gas
Transport Deutschland S.p.A., E.ON Gastransport GmbH, GRTgaz Deutschland GmbH, GVS Netz GmbH. After
its most recent expansion, it is now referred to as simply NCG (Net Connect Germany). In January 2010 it
became the largest trading hub after TTF in Continental Europe.
PEG-Nord = the virtual trading point in the North of France, created in 2009 when the three zones (PEG
OUEST, PEG EST, PEG NORD) merged into one.
PSV = Punto di Scambio Virtuale, is the name of the Italian Virtual Trading Point established by Snam Rete
Gas.
Sm3 = a standardized cubic meter of pipeline-quality gas with gross calorific value of 39 MJ.
Tcm: Trillion cubic meters (109).
ToP = Take-or-Pay, referring to purchase commitments in gas sales agreements.
TTF = the Title Transfer Facility, the virtual national balancing point in the Dutch pipeline network and in
January 2010 the largest trading hub in Continental Europe.
ZEE Hub = Physical gas trading hub at Zeebrugge which was the first major gas trading hub in Continental
Europe.

Note: Asterisk [*] denotes an explanation, while numbered footnotes [1, 2 etc.] provide sources and
references.



Executive Summary
A two tier price system developed for gas in Continental Europe in late 2008, consisting of the price
generated by oil-indexed pricing formulae in long-term Take or Pay gas supply contracts and prices resulting
from commercial activities at European gas trading hubs. Up until the end of December 2009 prices at
trading hubs represented a reduction of between 24 and 54 per cent of the average comparable gas price
under German long-term gas import contracts. This situation has now caused problems for the operation of
long term Take-or-Pay contracts for the supply of pipeline gas as well as LNG delivered to North West
Continental European markets under term gas supply arrangements.
The market forces which have caused this two tier gas pricing system to develop in Europe are as follows:
Gas demand destruction in Continental Europe caused by oil indexed gas prices; increased LNG supply world
wide coupled with decreased LNG demand in North America due to unconventional gas production and a
rapidly increasing LNG receiving terminal capacity in North West Europe; the recession which has caused
both pipeline gas and LNG demand to be reduced in most countries of the world; and finally the fact that
Continental European gas markets are becoming increasingly liberalised.
The clause in most, if not all, Continental European term contracts which should facilitate providing a
solution to the current gas pricing problem either through negotiation or, if this fails, by submitting the
dispute for resolution by arbitration, is the Price Review and Price Re-opener Clause. The paper examines
the operation of this latter clause. The overriding principle this clause is based on, is the fact that no gas
buyer can purchase large quantities of gas over an extended period of time, if the price of gas under the
term contract concerned is such that gas can only be resold at a loss.
Although it is understood that some gas market players have argued that the current two-tier gas price
system in Continental Europe is of a transient nature and that no changes to current oil-indexed price
arrangements are required, it has been observed that a number of negotiations addressing this very subject
currently are taking place between major gas suppliers and Continental European gas wholesalers buying
gas under term contracts with Take or Pay provisions. It is also understood that a number of Price Re-
opener arbitration notices have been issued as result of the two-tier gas price situation.
Term contracts in Continental Europe have gas pricing based on a base price (Po) and an additive gas price
adjustment formula which contains large elements of Gas Oil and Low Sulphur Fuel Oil with price data
frequently taken from inland, normally German, energy markets. The future relevance of pricing gas based
on Gas Oil and Low Sulphur Fuel Oil benchmarks or “proxies” has been debated for some time. The question
which is now arising is how the price arrangements under term contracts should be changed to the
satisfaction of buyers and sellers in the current Continental European gas market environment.
Replacing Gas Oil and Low Sulphur Fuel Oil values from German inland markets with price data for the same
products from the liquid and transparent markets in Rotterdam appears to be one solution. Another solution
would be to replace Gas Oil and Low Sulphur Fuel Oil with crude oil values and/or the value of coal. Since
European gas markets are becoming increasingly liberalised, there are also schools of thought advocating
that price series from liquid gas trading hubs should be included, either in part or in full, when gas price
arrangements are being revised. Amongst solutions being discussed are month- ahead price indexation and
monthly gas price indices such as those published by ICIS Heren, Argus, Platts, or the London’s Energy
Broker’s Association (LEBA) and others.
Reliability of price data is the main concern related to the use of hub generated gas price series in the pricing
formulae of term contracts for the supply of gas. Oil products have traditionally played the role of the gas
price “proxy” or benchmark. An important reason for their use has been the fact that oil product markets
have significant depth with forward pricing curves extending many years. This allows market participants to
hedge their gas supply positions. Coal markets will offer the same sophistication and hedging opportunities.
In contrast, European gas trading hubs do not yet display the same level of liquidity and forward trading as
crude oil, oil products and coal. Gas futures quotes for longer periods may be observed in the markets, but
are usually not traded every day or by a large number of players, hence these price instruments may not be
representative of the market at large.
The two-tier price system that has developed for gas in Continental Europe has unleashed market forces that
must be dealt with. The big challenge in solving the price problem that has arisen will be to find reliable
alternatives to the oil-price indexation elements currently used in pricing formulae. The way the market is
evolving, the adopted solution should also allow forward hedging of gas supply positions under term
contracts for large gas volumes supplied over an extended period of time.



Europe’s Two Level Gas Price System

In Europe gas pricing systems based on spot markets and oil price indexed gas price formulae have been in
co-existence for more than ten years. Up until the fourth quarter of 2008 these two pricing systems
normally reflected the same price levels for gas with the exception of seasonal variations.
Spot prices tended to be lower than the price generated by oil price indexed gas price formulae during
summer periods and peak above this price level during cold winter months. With the onset of the global
recession in late 2008 this pattern has changed as can be seen in Figure 1 below entitled “Average German
Gas Import prices vs. NBP and NCG Month Ahead Prices”.

Figure 1: Average German Gas Import Prices vs. NBP and NCG Month Ahead Prices
40

35

30

25
Price, €/MWh

Zeebrugge
expansion
20

15 NBP Month Ahead
Isle of Grain
NCG Month Ahead Phase II
10
BAFA monthly average

5 South Hook LNG
Dragon LNG
© 2010 Morten Frisch Consulting
0
Jan-08 Apr-08 Jul-08 Oct-08 Jan-09 Apr-09 Jul-09 Oct-09 Jan-10

It is evident from this figure that a two-tier price system for gas has developed in Europe. One price system
is generated by virtual trading hubs such as the NBP in the United Kingdom or the German Virtual Trading
Point Net Connect Germany (VTP NCG or simply NCG)*. This pricing system can also be based on physical
trading hubs such as the Zeebrugge hub in Belgium. The other pricing system is based on prices resulting
from the operation of price clauses within term gas supply contracts that frequently include Take or Pay
provisions. Most Continental European gas supplies are bought under this type of contract which normally
has duration of five to twenty five years, although examples of contracts for a supply period of forty years
have been observed.
The pricing arrangements in Continental European term contracts are normally based on a base price (Po)
that has been agreed between buyer and seller or determined by an arbitration panel. The applicable price
(P) is derived by adjusting Po by the application of an additive price indexation formula. A generic example
of this formula as it originally appeared now some 30 years ago is shown in Figure 2 below, entitled
“Continental European Gas Pricing Formula”.
As can be seen from Figure 2 the two indexation elements originally used were Gas Oil (GO) and Low
Sulphur Fuel Oil (LSFO). The Gas Oil element in the formula was meant to represent the domestic and
commercial gas market segments while Low Sulphur Fuel Oil represented industrial and feedstock

*
The extended market cooperation between the network companies Bayernets GmbH, Eni Gas Transport Deutschland S.p.A., E.ON Gastransport
GmbH, GRTgaz Deutschland GmbH and GVS Netz GmbH under the roof of NetConnect Germany GmbH & Co. KG (NCG) which started on 1
October 2009. Graph data in figure 1 before October 2009 are from the former E.ON Gas Transport (EGT) virtual trading point, which NCG has now
replaced.



applications. Gas was not normally used as a power station fuel in Europe at the time this gas pricing
formula was introduced. Gas Oil and Low Sulphur Fuel Oil price series were taken from German inland
markets for which the best and most up to date data was available. Many of these formulae have today
been modified also to include elements of coal prices and inflation. The exception to the above arrangement
were the contracts serving the French market which included a 25 per cent inflation or retail electricity price
indexation element since the introduction of this type of gas pricing formula. This element was introduced to
represent the widespread use of nuclear electricity in the French energy economy.

Figure 2: Continental European Gas Pricing Formula

Market Forces Behind the Two Level Price System

European Gas Trading Hubs and Their Developments
A prerequisite for large and increasing hub trading is to have a liberalised gas market. The advances in gas
market liberalisation currently being implemented in Europe at large, but in Germany in particular are playing
an important part in creating the changes in the European gas market environment which can now be
observed. In the case of Germany this includes a substantial lowering of grid fees or transportation charges
effective 1 October 2009. This regulator-induced market change has been given increased significance by
the fact that the largest operator in the German gas market, E.On, in December 2009 decided to put 54 per
cent of its contracted import capacity on the market1. This step is likely to help boost competition within gas
markets in Continental Europe. Another change which would likely enhance the gas market liberalisation
process further would be the introduction of a better system for allocation of short term firm gas
transportation capacity. Such a change could be implemented in 2010.
Figure 3 below entitled “NW European Gas Trading Hubs and Pipeline Routes” indicates the location of the
major gas trading hubs in North West Europe, while Figure 4 below entitled “European gas hub
developments in 2009” shows the current level of hub “tradability” *.
According to the European trade press NCG registered an increase in traded gas volumes of 83 per cent from
October to December in 2009, while Gaspool recorded an increase of 460 per cent over the same period2.
The large increase in Gaspool’s traded volumes is not necessarily a sign of liquidity.

1
Europe’s gas hubs look to Germany, article in ICIS Heren European Gas Markets, issue 28 January 2010, p.6.
*
Tradability indicating a market where there is liquidity, high number of participants and products, hence it is tradable, aka “preferred”
by gas traders and gas marketers.
2
Ibid Note 1.



Figure 3: NW European Gas Trading Hubs and Pipeline Routes3

According to gas traders most activities on Gaspool have been realised by already established players within
the large geographical gas market area that the pool covers as well as local companies (Stadtwerke)
supplementing their day-to-day gas needs. It does, however, signal the hub’s future potential for when more
foreign players decide to join trading activities on Gaspool. Signs that this is happening can already be
observed. When more flexible gas transportation arrangements have been introduced, Continental European
hub trading is likely to increase further.
Even prior to the global recession there was evidence of gas demand destruction in key European energy
markets. This was caused by high oil-indexed gas prices when compared to the price level of alternative
fuels for use in stationary applications. As a result, increasing volumes of gas without a firm end user
market have been available in Continental European markets for a period going back up to four years. This
development has been augmented by the onset of the global recession during the fourth quarter of 2008.
The combined effect of gas demand destruction and the recession has led to sharp declines in the demand
for gas, particularly in the industrial and feedstock sectors. Buyers of gas have, as a result, faced difficulties
in meeting their Take or Pay commitments under term gas supply contracts, commitments normally set at a
level of 85-90 per cent of the Annual Contract Quantity (ACQ).

3
RWE Facts & Figures, Update December 2009, page 143.



Figure 4: European Gas Hub Developments in 20094

Figure note: Tradability* rated out of 20 during Q4 2009.

LNG and the North American Gas Market Connection
Since the onset of the recession North West Europe has also seen the commissioning and start-up of
substantial new LNG terminal import capacity as shown in Figure 1. The Zeebrugge expansion in Belgium
together with the UK terminals Isle of Grain Phase II, South Hook LNG and Dragon LNG, will, before the end
of 2010, add a total LNG import capacity equivalent to 43.5 bcm a year of pipeline quality gas. To put this
into perspective, this additional import capacity exceeds total gas demand in the Netherlands. In 2011 LNG
import capacity of a further 18 bcm per year of pipeline quality gas will be added through the start-up of the
Isle of Grain Phase III in the UK and the Gate terminal in Rotterdam in The Netherlands. All this North West
European LNG receiving and regasification capacity is coming on stream at a time of unprecedented
oversupply of gas from traditional sources.
The large increase in North West European LNG import capacity has coincided with the start-up of a number
of world class LNG liquefaction plants around the world. Figure 5 entitled “Additional LNG Liquefaction
Capacity” provides an overview of the growth in such capacity over the period 2008-2012 expressed in bcm
per year of pipeline quality gas. The table also adjusts LNG liquefaction capacity additions by an estimated
reduction in LNG production caused by feedgas problems in some of the more traditional LNG exporting
countries. It can be seen that when LNG production already committed under term contracts has been
subtracted from the available additional capacity, large quantities of uncommitted LNG are available
worldwide in 2010 and later years. By end 2010 uncommitted LNG quantities are likely to total some 42 bcm
of pipeline quality gas. If these volumes are produced, they are likely to put a severe downward pressure on
LNG spot prices. However, it must be noted that during the first half of 2009 physical LNG production was
reduced by some 3 bcm when compared to production during the same period in 2008. This reduction was
observed although large additions to the worldwide liquefaction capacity were brought on stream during the
same period. The reduction in LNG production when compared to available capacity was the result of
technical problems, feedgas problems, domestic market competition, delayed start-up of plants and price-
driven management decisions.

4
Ibid Note 1.
*
Ibid Note (*) on page 7.



Figure 5: Additional LNG Liquefaction Capacity

LNG expressed as bcm of pipeline quality gas per year 2008 2009 2010 2011 2012

Total anticipated additional LNG capacity [1] 11.5 36.9 101.5 132.8 139.5
Reduction in LNG production due to feedgas problems [2] 0.0 13.5 17.1 19.6 22.0

Anticipated incremental LNG availability [3] 11.5 23.4 84.4 113.2 117.5

Volumes of new LNG commited under term contracts [4] 0.9 27.4 59.7 74.5 81.2

Estimated uncommited volumes [5] 10.7 -4.0 24.7 38.7 36.3

Source: MFC estimates
[3]=[1]-[2]
[5]=[3]-[4]

During the Northern Hemisphere winter of 2008/09 new liquefaction capacity was augmented by a sharp
reduction in the import of LNG by the traditional markets in Japan, South Korea and Taiwan. These
countries normally are active buyers of LNG spot cargoes during this seasonal gas demand period. In the
winter of 2008/09 they nominated minimum LNG cargoes under their term contracts and as a result released
cargoes to the spot market lowering LNG spot prices and also charter rates for LNG tankers worldwide.
Based on preliminary estimates for 2009 Asian LNG demand totalled 165.8 bcm of pipeline quality gas. This
represented a demand reduction of only 2.1 bcm expressed as pipeline quality gas. Although the traditional
import countries of Japan, South Korea and Taiwan, all experienced declines in LNG demand in that year, the
demand reduction from these countries was to a large extend offset by increases in demand from China and
India. Although LNG demand revived in the markets of South Korea and Taiwan during the fourth quarter of
2009, which also helped ease the total demand reduction for the region in the same year, and although the
two countries have been active in the spot market for supplies during first quarter of 2010, it is not expected
that LNG demand in Asia will increase significantly in the current year. Demand in Japan is predicted to be
soft due to increased availability of nuclear generating capacity, while Chinese demand growth is likely to
slow down since only one new term contract for LNG supply is coming into operation in 2010 compared with
three new term contracts in 2009. In India LNG demand growth will be curtailed by the ramping-up of
substantial new domestic gas production.
Global LNG demand in 2010 is projected to be equivalent to some 285 bcm of pipeline quality gas,
representing an increase of some 36 bcm when compared to 2009. With reference to Figure 5 it can be
seen that total anticipated incremental LNG availability has been estimated at 84.4 bcm of pipeline quality
gas for 2010. This leaves an annual equivalent of nearly 50 bcm of LNG without a market. From this it can
be concluded the international LNG liquefaction industry also in 2010 is likely to exert downward price
pressure in gas markets such as those of Europe.
A factor with substantial contribution to the global LNG surplus has been the rapid increase in production
from unconventional gas resources in North America. Already 15 years ago gas exploration of tight sands
and coal bed methane resources showed signs of gaining significance in the US lower 48 states. New drilling
techniques and hydraulic fracturing methods first tested on shale gas formations, have been developed and
applied over the last three years. These techniques have in particular boosted production of shale gas,
although they have also proved valuable when applied to tight gas formations.
Figure 6 entitled “US Unconventional Gas Reserve Potential” and showing potentially recoverable gas
reserves by type as of end 2007, points to the fact that the US based on current technology could have in
excess of 20 tcm of recoverable gas reserves. When US gas reserve numbers, particularly for shale gas, are
revised in the future, they are expected to increase substantially above this level.



Figure 6: US Unconventional Gas Reserve Potential5

Potentially recoverable gas by type as of end of 2007

Conventional (tcm) 2.4
Tight sands (tcm) 4.9
Coalbed Methane (tcm) 1.8
Gas shales (tcm) 10.9

Total recoverable reserve potential 20.1

As a result of the unconventional gas production not only in the USA but also in Canada, North America can
today be self-sufficient in natural gas on an average annual basis. Based on current gas supply and demand
projections, North America in the future might need LNG supplied to high price markets in New England.
These high price markets are the result of gas transmission systems bottlenecks which can be removed. It is
also possible that limited quantities of LNG might be needed to supply seasonal demand peaks6, as has
happened in early 2010 when cold weather spells boosted gas prices in New England to more than double
Henry Hub prompt price levels and attracted incremental LNG cargoes7.

Figure 7: Forecast of US Net LNG Imports8
200
180 AEO2004
2005
160 AEO2005
AEO2006
140 2004
AEO2007
120 AEO2008 2006
Bcm/y

100 AEO2009 2007
2008
Actual demand
80
AEO2010
60 2010
40
2009
20
0
2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025

Figure 5 above showed new LNG liquefaction capacity coming on stream in the period 2008-2012. A large
proportion of this liquefaction capacity, equivalent to some 70 bcm a year of pipeline gas, was originally
destined for the United States and Canada. The investment decisions for the liquefaction projects meant to
supply North American markets were made in the period 2005-2006. As can be seen in Figure 7 above,
entitled “Forecast of US Net LNG Imports”, projections for US LNG imports have been significantly reduced
since these investment decisions were made.

5
Availability, Economics and Production Potential of North American Unconventional Gas Supplies, prepared for the INGAA Foundation,
Inc by ICF International, report number F-2008-03, November 2008. Conventional gas figures from the US Department of Energy’s
Energy Information Administration’s Annual Energy Outlook 2009, Reference Case.
6
Turbulent LNG Prices, Changing Markets and High Costs: Will the LNG Industry Cope?, presentation given by Morten Frisch in Session
5 (FOCUS) “New Commercial Frontiers and Challenges”, Gas Tech 2009, Abu Dhabi UAE, Tuesday 26th May 2009.
7
US LNG imports in January double year-ago level, article in Reuters UK, Wednesday 10 February 2010.
8
US Department of Energy’s Energy Information Administration’s Annual Energy Outlook 2004 to 2010 inclusive, base cases for LNG
demand.



Figure 8: US AEO 2010 LNG Demand Projection (Base Case)
20 45

18 Net LNG import volumes 40
Net LNG imports as % of US gas demand
16
35
% of US gas demand

14
Actual Forecast

LNG, bcm/year
30
12
25
10
20
8
15
6
10
4

2 5

0 0
2007 2009 2011 2013 2015 2017 2019 2021 2023 2025

Figure 8, entitled “US AEO 2010 LNG Demand Projection (Base Case)”, shows the US Energy Information
Administration’s Annual Energy Outlook’s 2010 Early Release Base Case projection for US LNG demand. It is
likely that US LNG demand will be reduced further and below the levels shown in Figure 8. When looking at
the North American LNG demand situation, it is observed that Canada is now planning an LNG liquefaction
plant on its West Coast. The possibility that additional liquefaction plants will be built on the West Coast of
Alaska is today tangible. It is even possible that liquefaction plants will be built on the US Gulf Coast. Some
of the new large LNG receiving terminals, now in operation on the US Gulf Coast, have obtained regulatory
clearance to operate in an export as well as in an import mode. It is unlikely now that LNG will be required
in large quantities in North America. In relation to the USA, net LNG imports are now more likely to remain
at a level of 2 to 4 per cent of total gas demand.
This US gas market situation has already resulted in a large number of LNG cargoes being released into the
Atlantic Basin and hence becoming available for import into the UK, Belgium, France and Italy, in Europe.
This trend is projected to continue in 2010 and future years. The source of such LNG deliveries is likely to
be Qatar and Yemen in the Middle East, Equatorial Guinea and Egypt in Africa and Europe’s own Norway in
addition to the more traditional suppliers of Algeria, Nigeria and Trinidad and Tobago.
The deep recession on the Iberian Peninsula together with additional future gas pipeline imports directly
from Algeria to Spain through the Medgaz pipeline has made Spain and Portugal oversupplied with LNG. This
is leading to the diversion of cargoes from the Iberian Peninsula, cargoes that can be delivered to North
West European LNG terminals.
The Atlantic Basin developments outlined above together with surplus cargoes from Japan, South Korea and
Taiwan, have resulted in a large increase in the imports of LNG into the UK and Belgium in 2009. Figure 9
entitled “UK LNG Imports” shows an estimate of LNG imported to the UK market in 2009, which is likely to
have totalled in excess of 9 bcm corresponding to some 11 per cent of total UK gas demand. This number is
likely to increase substantially already in 2010 when further LNG import terminal capacity will become
operational.



Figure 9: UK LNG Imports

2009 2008
(bcm) % of total (bcm)

Qatar 5.2 57% 0.12
Trinidad 1.6 17% 0.47
Algeria 1.5 16% 0.37
Egypt 0.5 5% 0.08
Norway 0.3 3% 0.0
Australia 0.1 1% 0.0
Total 9.2 100% 1.04

Source: MFC estimates and Cedigaz 2008
historical import data.

The UK is in the position to both directly and indirectly export regasified LNG to Continental European
markets. Market players are able to flow gas through two existing physical pipeline connections to
Continental Europe, the bi-directional Interconnector from Bacton in the UK to Zeebrugge in Belgium and the
one-directional BBL pipeline transporting gas from Balgzand in The Netherlands to Bacton. Additionally, the
UK gas market and markets in Continental Europe are indirectly connected through the Norwegian offshore
pipeline gas export system in the North Sea. Norwegian gas producers can direct gas between Continental
European terminals and terminals in the UK depending on gas market conditions.
In parallel with the increase in UK LNG imports, Zeebrugge LNG imports also more than doubled in 2009
compared to 2008, adding directly to the gas surplus in Continental Europe. Direct import of gas in the form
of LNG will increase noticeably in Continental Europe when further capacity becomes available in Zeebrugge
and when the new Gate LNG import terminal in Rotterdam becomes operational.

Market Forces and Gas Flow Patterns across Europe
From Figure 1 entitled “Average German Gas Import Prices vs. NBP and NCG Month Ahead Prices” it can be
concluded that Germany has for more than a year now been experiencing a two-tier gas price system. As of
end November 2009 the maximum price differential recorded between the then applicable NCG Month Ahead
price and the corresponding BAFA monthly average German import price was 9.12 €/MWh. This price
differential represented a 54 per cent reduction of the applicable BAFA monthly average import price. The
corresponding minimum price differential was 4.28 €/MWh representing a 24 per cent reduction of the
applicable BAFA monthly average import price.
It can be seen from Figure 1 that the NBP Month Ahead price and the NCG Month Ahead price, while the
latter has been available, have been converging when these prices are compared in units of €/MWh (daily
£/€ exchange rates have been applied). This has been the case, although the markets represented by NBP
and NCG are still very different. The NBP is today a liquid trading hub, operating in the most liberalised gas
market in Europe, while the markets currently served by NCG are still in an early stage of liberalisation.
Additionally the NBP market is priced in Pounds Sterling, while NCG is priced in Euro, and the exchange rate
between the two currencies experienced high volatility in 2009.
Figure 10 entitled “North West European Natural Gas Infrastructure” shows the location of LNG receiving
terminals and the pipeline systems linking markets in North West Europe. Bearing in mind the pipeline links
between UK and the gas markets of the Continental Europe described in detail in the previous section, it is
also evident from Figure 10 that as gas flows between the UK and Germany, it always crosses more than one
national border to reach its final destination. Looking at Figure 10 and Figure 1 together, one may interpret
the convergence of the NBP and NCG Month Ahead price series as the result of unconstraint cross-border
gas flows, since it is well known that price differentials between two gas markets will normally collapse as
market participants from either side flow gas across to make the most of arbitrage opportunities. A
necessary condition for the collapse of the price spread is, of course, the existence of a physical pipeline link
with firm, available capacity.



Such cross-border capacities between the national gas markets in Continental Europe have in the past been
reserved by national incumbents transporting their gas under term import contracts. New market entrants
have found that booking such capacities for various time periods is neither easy nor cheap. The development
of secondary capacity platforms, voluntary border point capacity auctions as well as forced capacity releases
imposed by the national regulators, has come into effect to address this problem. However, this
development is still of a limited scale and cannot, on its own, explain the convergence of prices. In fact, for
the past year, remaining pipeline constraints and bottlenecks across Europe have become a secondary issue
due to the clear oversupply of gas both in the UK and in Continental Europe.

Figure 10: North West European Natural Gas Infrastructure

It appears that a number of market participants have found themselves with substantial “long positions”.
Location swaps of gas between markets, time swaps between markets and within markets and sub-letting of
capacities are seen as a way to “release” some of this gas which is effectively trapped within national
markets in the absence of strong domestic demand. Physical capacity between markets is not always
deemed necessary. Trading hubs have been effectively operating for the most part as if free, unconstraint
physical cross-border gas flows existed for all players. It is this oversupply of gas in conjunction with the
ongoing liberalisation process which has brought the inter-linked markets closer together. It is worth
mentioning that since it first started trading; NCG has traditionally been priced off TTF in The Netherlands
due to the proximity of the two markets and their physical link. TTF was priced off NBP for similar reasons.
With NCG now seeing its premium to TTF in the winter disappearing, and TTF being priced off NBP
witnessing similar changes, it is no surprise that NCG price levels are more and more approaching those of
NBP, even if there is always at least one other national market between the two trading hubs.
Hence, oversupply in the gas market environment of Continental Europe has a similar effect to capacity
release measures. The presence of both explains the observed market price convergence. It can be argued,
however, that if and when the oversupply comes to an end, the price curves will diverge again, and price
levels at NCG will again reflect the price under oil indexed term gas supply arrangements for delivery at
German border points. The proponents of this view will state that markets are less liberalised than what they
currently seem because of deep systemic factors.
The market players which have adopted this view no doubt will claim that the two-tier price system observed
throughout Continental European gas markets since fourth quarter 2008 represents a transient market



situation. They are likely to argue that no changes are required to the current pricing arrangements under
term contracts with oil indexed pricing. However, based on the high number of negotiations currently taking
place between buyers and sellers under these contracts together with an increasing number of arbitration
notices also served between such buyers and sellers, there is a clear indication that the current two-tier
pricing situation has unleashed market forces that require attention.

Price Review and Price Re-opener in a Changing Market

A major consequence of the aforementioned two-tier pricing situation is that it has caused buyers to invoke
Price Review and Price Re-opener clauses in Continental European term contracts for the supply of Dutch,
Norwegian and Russian gas, as well as domestically produced gas in countries such as Germany. Similar
considerations will apply to term contracts for the supply of LNG to Continental European markets when such
contracts have Price Review and Price Re-opener clauses. To demonstrate how such a process works, the
operation of Price Review and Price Re-opener clauses in Continental European term contracts and similar
term contracts for LNG supply is examined below.
Historically, Price Review and Price Re-opener clauses were introduced into Continental European term
contracts in the early 1980’s. During the late 1970’s the price adjustment mechanisms in gas contracts had
failed to capture fully the rapid increase in the value of liquid hydrocarbons products. At the same time both
gas producers and their customers observed that price adjustment clauses normally functioned as planned
for no more than some three years. They recognised the potential need to adjust or possibly change the
base price and also the indexation in price adjustment formulae at regular intervals during the life of term
gas supply arrangements. The oil price crash in the second half of 1986 drove home this point, as situation
repeated in 2009 due to the recession.
By the end of the 1980’s price review mechanisms had been introduced into new as well as existing term gas
supply arrangements in Continental European markets. Originally Price Review and Price Re-opener clauses
could only be triggered every three years but many contracts have now reduced this period to two years due
to rapidly changing market conditions. It is understood that some gas buyers and sellers even have agreed
to annual price reviews.
To protect the continuity of the seller’s operations as well as the buyer’s gas supply, term gas contracts
stipulate that a price review and/or price re-opener recognition or arbitration shall not in any way disrupt the
flow of gas under a gas sales agreement. Delivery nominations and the supply of gas take place in
accordance with normal operations under a contract even if the buyer and seller should disagree about the
price or go to arbitration.

Methodology of Price Review and Price Re-opener Clauses Explained
Continental European price review clauses are normally based on three main principles. The first of these
principles relates to the economic condition or circumstances in the buyer’s market area for gas and how
these conditions change over time. This first principle applies universally to all gas and its value in the
buyer’s market area.
The first main principle results in the following two price review tests. It must be demonstrated that:
(1) economic conditions have changed significantly in the buyer’s market area when compared to
when the price adjustment provisions were last agreed; and

(2) the changes outlined in (1) above are beyond the control of both the buyer and the seller.

Satisfying both tests would entitle either the buyer or the seller to an adjustment of the price provisions in
the term gas supply contract or other commercial terms in lieu of changes to the price provision. In practice
the first test has prompted parties to revisit the previous price agreements, with some arguing that the last
price negotiation or arbitration result did not reflect prevailing market conditions accurately. Figure 11
entitled “Two Tests in the Price Review and Reopener Process” shows the various steps of the process.



Figure 11: Two Tests in the Price Review and Reopener Process

Have there been significant changes in the buyer’s market area
since the price adjustment provisions were last agreed?

Yes No
Test 1
Were the prevailing market No price re-opener.
conditions when the price
adjustment provisions were last No Re-adjust the contract baseline
agreed properly reflected in the and return to Test 1.
contract?

Yes
Were the changes in the market
No
conditions beyond the control of No price re-opener.
both the buyer and the seller?
Test 2
Yes
Proceed to Test 3

The second main principle relates to the gas delivered under the term gas supply contract in question (the
Sales Gas). This principle has been adopted to protect the buyer’s market position since no company can
operate a term contract for gas supply at a loss over an extended period. It gives rise to the following three
tests. It must be demonstrated that:

(3) the applicable price resulting from the operation of the price adjustment provisions of the term
gas supply contract in question allows the buyer to economically market the Sales Gas delivered
under the contract in his natural gas market area;

(4) the buyer shall, in particular, be able to undertake the economic marketing of Sales Gas under
(3) above in competition with all competing sources of energy including natural gas available in
the end user market within his natural gas market area; and

(5) the buyer’s gas marketing practices and physical gas operations are sound and efficient when
measured against general business standards in the buyer’s country as well as against gas
companies in the geographic region in which the buyer’s natural gas operations are located.

The outcome of the tests which are defined in (3), (4) and (5), overrides the tests as defined in (1) and (2)
above.
Test (4) is essentially a more specific restatement of test (3). Older term contracts did not include the third
test, and therefore did not state explicitly whether the need to market natural gas economically referred to
potential competing sources of natural gas, as opposed to other energy sources. Commercial practice
emerged to include the insertion of the fourth test as a clarification. If the buyer can demonstrate that the
Sales Gas fails tests (3) and (4) while the buyer satisfies test (5), then the buyer is entitled to an adjustment
of the price provisions and/or other commercial provisions in the gas sales agreement that together will
rectify the unsatisfactory position of the Sales Gas in the buyer’s market. Figure 12 entitled “Buyer’s
Profitability Test - Decision Diagram” outlines the operation of tests (3), (4) and (5).
The third main principle relates to changes in the tax regime for gas and/or competing fuels in the buyer’s
market. Taxes and associated tax levels levied on energy are part of the economic conditions or
circumstances in the buyer’s market. Test (1) would therefore appear to cover taxes, but Continental
European gas buyers have in some contracts managed to extract separate tax-based price review provisions
from their gas suppliers.



Figure 12: Buyer’s Profitability Test - Decision Diagram

Do the price adjustment provisions of the gas
sales agreement allow the buyer to sell gas
Tests 3 profitably, in competition with all competing Yes No price re-opener as a
and 4 sources of energy available in the market result of buyer’s claim.
(including natural gas)?

No
Are the buyer’s natural gas
operations sound and efficient? No Erode or possibly nullify
(so that the seller does not have a buyer’s claim for
to subsidise an inefficient buyer). adjustment.
Test 5
Yes
Negotiate price re-opener
settlement and/or go to
arbitration for determination.

A buyer can request a separate price review upon demonstrating that a change in the tax regime for gas
and/or its competing fuels has significant negative economic consequences. If tax changes have the
opposite effect in the buyer’s market—improving the buyer’s trading position and/or profit level from the re-
sale of Sales Gas, then the seller can request a separate price review.
Some term gas supply contracts with Continental European buyers contain a fourth main price review
principle. This fourth principle specifies that the buyer and the seller of the Sales Gas shall share the
economic rent generated by the production and sale of such Sales Gas on an equitable basis. This provides
a guarantee to the buyer as well as the seller. If the first five tests above have been met in full, then the
fourth principle can prevent one party from making an undue profit relative to the other under the gas sales
agreement.
Price review based on an equitable sharing of economic rent can be very valuable to the seller during periods
of low energy prices. This principle, if adopted, in a term contract, will prevent the buyer from receiving a
guaranteed margin on the Sales Gas at the same time as the seller operates at a loss. To be of maximum
effectiveness for the seller, price review provisions based on this principle must override or be allowed to
offset the contract specific tests set out in (3) and (4) above concerning the buyer’s need to market natural
gas economically.
The normal definition of economic rent excludes all taxes and imposts levied against the Sales Gas. The
government of the buyer’s country can therefore introduce a gas tax that reduces the economic rent
available for sharing between the buyer and the seller, which could therefore reduce the price that the buyer
has to pay for the Sales Gas. It is important to tie the tax-based price review provisions of a term gas
supply contract to the treatment of a gas tax and/or similar impost under any provisions dealing with
economic rent principles.
Experience has shown that Price Review and Price Re-opener clauses in Continental European term contracts
are most effective during periods of gas oversupply and falling prices. The Buyer’s Profitability tests, the
operation of which are outlined in Figure 12 above, have proved a very powerful tool for gas buyers in the
lowering of gas prices in the past. Gas producers and sellers have only infrequently used these clauses
successfully to raise prices during periods of scarcity and rising market prices.
When price-review and price-reopener clauses were introduced into term gas supply contracts these clauses
formed an important part of the risk sharing arrangement between buyer and seller. At the time, term
contacts contained restrictions on the geographic areas in which the buyer could distribute in and sell on the



Sales Gas, the so-called “Destination Clause”. The area in which the buyer could freely sell the Sales Gas
was defined as the buyer’s market area or the buyer’s market. As part of the Destination Clause restriction,
the buyer could not resell the Sales Gas to another wholesaler operating outside the buyer’s market area,
without the consent of the seller.
These contract restrictions can normally no longer be applied as a result of changes in EU and national laws.
Their effective removal has changed the way the five Price Review and Price Re-opener tests outlined above
are conducted. Buyer’s market area would, today, be defined as the gas market into which the buyer of the
gas can demonstrate that he normally conducts commercial gas supply operations. When the buyer is a
large wholesaler this could mean a geographic area covering a large part of Europe.

Price and Price Indexation Solutions

When it has been agreed or determined as a result of the application of Price Review and Price Re-opener
provisions that the applicable price or price arrangement under term contract needs to be modified, then
there are many ways of effecting this. It is important to remember that the price charged for a gas supply
delivered under a term contract in addition to reflecting the value of the gas as a commodity in the market,
should also reflect the supply conditions and other commercial terms included in the term contract.
Changes to supply conditions are often made as part of a price-renegotiation. A contract with high supply
flexibility, whether this is hourly, daily, weekly, monthly, quarterly, seasonal or annual flexibility or a
combination of these, will normally be of higher value to the buyer than a baseload contract with a high
Take or Pay obligation. The gas price under such flexible term contracts normally carries a price premium
when compared to less flexible base load type of contracts. There are cases where Price-Reopener
negotiations have resulted in increased flexibility with respect to gas delivery nomination procedures and
flexibility in changing existing nominations as part of a re-pricing solution. Another commonly applied
contract change is variations to the Take or Pay level under the term contract in question.
A commercial term that in some cases has been changed during a price renegotiation is the payment terms
for the gas supply. For a gas wholesaler or distributor serving seasonal markets extended payment terms
for gas supply can have a high value.
However the most common changes resulting from a price re-negotiation are changes to the base price (Po)
and/or the price adjustment formula. Figure 2 entitled “Continental European Gas Pricing Formula” shows
the generic form of the Continental European additive gas price adjustment formula. In the current market
situation with the two-tier gas price system in operation, it could be expected that the gas buyer would
request a reduction of the base price (Po) in order to better reflect the value of gas observed, for example,
in the NCG Month Ahead price. Although the movements of the NCG Month Ahead price seem to emulate
the BAFA monthly average gas import price into Germany, it is also possible that a request for changes to
the price adjustment formula would be made as part of any price re-negotiation.
The future relevance of Gas Oil (GO) and Low Sulphur Fuel Oil (LSFO) price series taken from inland,
normally German, markets has been questionable for some time. The use of Gas Oil and Low Sulphur Fuel
Oil in stationary applications in European markets has fallen dramatically over the last ten years. As a result
price statistics for these products have become less reliable. This development has caused some buyers of
gas under term contracts to switch from price statistics for inland deliveries to the price of Gas Oil and Low
Sulphur Fuel Oil in the Rotterdam traded market which is a market with greater depth and transparency.
European Gas Oil values are today strongly influenced by the very large increase in the use of auto-diesel in
the region, a petroleum product, of which Europe can experience shortages and which it has to import from
other parts of the world. European crude oil and petroleum product values have been until the onset of the
recession in late 2008 to a large extent indirectly set by the US motoring market through the export of Brent
crude to the USA and also by the export of surplus petroleum (gasoline) from European refineries to US
markets9. This indirect pricing arrangement is currently in the process of changing, since the physical
production of Brent and related North Sea crudes is falling at the same time as the European petrol exports
to the US are declining. If US petrol demand recovers, and large scale petrol imports are again required,
such imports are in the future likely to be supplied by large modern refinery complexes in Asia.

9
Assessing the Changing Drivers of Past, Present and Future Oil Prices; What Are the Prospects for Gas to Gas Pricing?, presentation
given by Morten Frisch at the FLAME 2006 Gas Conference in Amsterdam, The Netherlands., 9 March 2006.



With the decline in North Sea crude production, Europe has increasingly become supplied with crude oil
produced in Russia. The refining of Russian crudes likely will change European refineries’ product yields and
as a result could change the price structure for petroleum products in European energy markets.
One question that has surfaced during a number of arbitrations dealing with Price Review and Price Re-
opener clauses has been which energy product could be used as a benchmark or a “proxy” for gas, if Gas Oil
and Low Sulphur Fuel Oil values are no longer suitable in such a role. Term LNG contracts frequently use
crude oil values instead of petroleum products. There are examples of Asian utilities abandoning the,
traditionally pricing formulae used in LNG term contracts, the price of the Japanese Customs Cleared Crude
Cocktail (JCC) in favour of Brent crude oil. The latter is a physically and financially traded commodity. A gas
contract price based on Brent crude can be hedged in financial markets, something that cannot be done
directly with a contract based on JCC pricing, since this crude cocktail has neither uniform quality nor a
financial market.
Electricity retail prices, inflation and coal as a proxy for electricity prices have already been adopted as price
indexation elements in some contracts. Of late the question of replacing part or all of the oil indexation
elements in Continental European gas price adjustment formulae with gas price data from trading hubs (both
financial and physical) has emerged. Discussions have taken place with regards to several options. Amongst
those discussed are month - ahead price indexation and monthly gas price indices such as those published
by ICIS Heren, Argus, Platts or the London’s Energy Brokers Association (LEBA) and others.
The NBP trading hub traded volumes for gas are the highest in Europe and price data based on NBP trading
has been used for the pricing under UK gas supply contracts for a number of years. As discussed above,
there is also now an increasing number of Continental European trading hubs such as TTF and NCG, where
trading volumes have risen substantially over the last two years. However, many market participants would
be reluctant to use price data from these hubs in term agreements as their liquidity and depth are
considerably lower than NBP and they are still deemed to provide unreliable price indicators.
Reliability of pricing data is the main concern related to the use of hub-generated price data in the pricing
formulae of term contracts. In the Continental European price adjustment formulae oil products have
traditionally played the role of the gas price “proxy” or benchmark. The reasoning behind their use is that oil
product markets have significant trading depth. Buyers can observe a price for Gas Oil or Brent crude oil
many years ahead in the future. Despite the development of European gas trading hubs, this is not yet the
case for most of the European gas price prompt and curve data. Even if quotes for futures contracts for 3
years or more ahead are observed in the market, they are unlikely to trade every day and they will only be
traded by a limited number of players. Oil products on the other hand provide the “depth” which the gas
markets can not yet ensure. Market participants can hedge their gas purchase obligations for many years
forward using oil and also coal futures, without sometimes even having to enter into physical positions. The
Continental European gas markets are not yet developed to the point that such pricing and hedging
possibilities will be either available or, if they are available, will have a reliability acceptable to both buyer
and seller under term arrangements.
The two-tier price system that has developed for gas in Continental Europe has unleashed market forces that
must be dealt with. The big challenge in solving the price problem that has arisen will be to find reliable
alternatives to the oil-price indexation elements in pricing formulae. The way the market is evolving, the
adopted solution should also allow forward hedging of gas supply positions under term contracts for gas
supply extending over many years.

Morten Frisch Consulting accepts no liability for commercial decisions based on the content of this paper. Although the paper is copyright of Morten Frisch
Consulting, quotes from the paper are permitted, provided full references to the paper and Morten Frisch Consulting are made. Onwards transmission or
copying of the paper is allowed in its original form only.


Dundee University Morten Frisch Paper 24 Feb 2010

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Dundee University Morten Frisch Paper 24 Feb 2010