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: [email protected]

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

© 2010 Morten Frisch Consulting

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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.



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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.



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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.



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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.



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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

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NCG Month Ahead

BAFA monthly average

Dragon LNGSouth Hook LNG

Isle of Grain

Phase II

Zeebrugge

expansion


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.



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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.



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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.



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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.



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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.



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Figure 6: US Unconventional Gas Reserve Potential5

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

Potentially recoverable gas by type as of end of 2007

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

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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.



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

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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.



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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.



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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



15

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.



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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?

Were the prevailing market conditions when the price

adjustment provisions were last agreed properly reflected in the

contract?

Were the changes in the market conditions beyond the control of both the buyer and the seller?

Proceed to Test 3

Re-adjust the contract baseline and return to Test 1.

No price re-opener.

Yes

Yes

No

No

No price re-opener.

NoTest 1

Test 2Yes

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

Were the prevailing market conditions when the price

adjustment provisions were last agreed properly reflected in the

contract?

Were the changes in the market conditions beyond the control of both the buyer and the seller?

Proceed to Test 3

Re-adjust the contract baseline and return to Test 1.

No price re-opener.

Yes

Yes

No

No

No price re-opener.

NoTest 1

Test 2Yes

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.



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Figure 12: Buyer’s Profitability Test - Decision Diagram

Do the price adjustment provisions of the gas sales agreement allow the buyer to sell gas profitably, in competition with all competing sources of energy available in the market

(including natural gas)?

Are the buyer’s natural gas operations sound and efficient? (so that the seller does not have to subsidise an inefficient buyer).

Negotiate price re-opener settlement and/or go to

arbitration for determination.

No

Yes

No price re-opener as a

result of buyer’s claim.

Yes

Erode or possibly nullify a buyer’s claim for adjustment.

No

Test 5

Tests 3 and 4

Do the price adjustment provisions of the gas sales agreement allow the buyer to sell gas profitably, in competition with all competing sources of energy available in the market

(including natural gas)?

Are the buyer’s natural gas operations sound and efficient? (so that the seller does not have to subsidise an inefficient buyer).

Negotiate price re-opener settlement and/or go to

arbitration for determination.

No

Yes

No price re-opener as a

result of buyer’s claim.

Yes

Erode or possibly nullify a buyer’s claim for adjustment.

No

Test 5

Tests 3 and 4

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



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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.



19

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.

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Dundee University Morten Frisch Paper 24 Feb 2010