Commission Decision

of 29 September 1999

declaring a concentration compatible with the common market and the EEA Agreement

(Case No IV/M.1383 - Exxon/Mobil)

(notified under document number C(1999) 3093)

(Only the English text is authentic)

(Text with EEA relevance)

(2004/284/EC)

THE COMMISSION OF THE EUROPEAN COMMUNITIES,

Having regard to the Treaty establishing the European Community,

Having regard to the Agreement on the European Economic Area, and in particular Article 57 thereof,

Having regard to Council Regulation (EEC) No 4064/89 of 21 December 1989 on the control of concentrations between undertakings(1), as last amended by Regulation (EC) No 1310/97(2), and in particular Article 8(2) thereof,

Having regard to the Commission decision of 9 June 1999 to initiate proceedings in this case,

Having given the undertakings concerned the opportunity to make known their views on the objections raised by the Commission,

Having regard to the opinion of the Advisory Committee on Concentrations(3),

Whereas:

(1) On 3 May 1999, the Commission received notification of a proposed concentration by which the US undertakings Exxon Corporation and Mobil Corporation were to merge their activities worldwide.

(2) On 2 June 1999, the United Kingdom notified the Commission in accordance with Article 9(2)(b) of Regulation (EEC) No 4064/89 (hereinafter referred to as the Merger Regulation) that it considered that the concentration affected competition in the northwest of Scotland in the retail motor fuel sector. On 26 July 1999, the Commission issued a statement of objections identifying, inter alia, competition concerns in the market for motor fuel retailing in the whole of the United Kingdom. On 10 August 1999 the Commission informed the United Kingdom that in those circumstances and in accordance with Article 9(4)(b) of the Merger Regulation there were no grounds for referring the case to its authorities.

(3) By decision dated 9 June 1999, the Commission found that the notified operation raised serious doubts as to its compatibility with the common market. The Commission accordingly initiated proceedings in this case pursuant to Article 6(1)(c) of the Merger Regulation.

I. THE PARTIES AND THE OPERATION

(4) Exxon Corporation (Exxon) is a diversified company active worldwide in the exploration, development, production and sale of crude oil and natural gas, the refining and sale of refined petroleum products the development, production and sale of various chemical products, the production and sale of coal and minerals and power generation. Mobil Corporation (Mobil) is a diversified company active worldwide in the exploration, development, production, and sale of crude oil and natural gas, the refining and sale of refined petroleum products and the development, production and sale of various chemical products. Mobil and British Petroleum (BP) regrouped all their refining and retailing activities in Europe into a jointly controlled joint venture, BP/Mobil(4).

(5) This notification concerns a full merger within the meaning of Article 3(1)(a) of the Merger Regulation. Exxon and Mobil signed an agreement and plan of merger on 1 December 1998. Pursuant to this agreement, Mobil will merge with a wholly owned subsidiary of Exxon, with Mobil as the surviving corporation. As a result, Exxon will hold 100 percent of Mobil's issued and outstanding voting securities. Holders of Mobil common stock will receive 1,32015 shares of Exxon common stock for each share of Mobil common stock that they own at the time of closing. Exxon shareholders will own approximately 70 % of the combined Exxon Mobil entity, while Mobil shareholders will own approximately 30 %.

II. COMMUNITY DIMENSION

(6) As the Parties' combined aggregate worldwide turnover(5) exceeds EUR 5 billion (Exxon: EUR 121 billion; Mobil: EUR 47 billion), each of Exxon's and Mobil's Community-wide turnovers exceeds EUR 250 million (Exxon: EUR [...](6) billion; Mobil: EUR [...]* billion) and neither Exxon nor Mobil achieves more than two thirds of its aggregate Community-wide turnover within one and the same Member State, the concentration has a Community dimension pursuant to Article 1(2) of the Merger Regulation. The turnover of each of Exxon and Mobil exceeds EUR 250 million in the EFTA territory (Exxon: EUR [...]* billion; Mobil: EUR [...]* million). Therefore, the case is an EFTA cooperation case.

III. COMPETITIVE ASSESSMENT

(7) The oil industry is generally divided into the upstream oil and gas sector (i.e. exploration, development and production of crude oil and natural gas), the downstream sector (refining and marketing of fuels, distribution of natural gas, manufacture of lubricants) and the various petrochemical activities.

(8) The concentration does not raise competition concerns in the markets for exploration, development and production of crude oil and natural gas and with regard to the various petrochemical activities where the parties' businesses overlap. Both parties are active in the exploration, development and production of crude oil and natural gas and the Commission had expressed in the Article 6(1)(c) decision serious doubts on these markets. In the Article 6(1)(c) decision, the Commission had also expressed serious doubts on the "gas-to-liquid" market. However, there are, for the reasons indicated in sections A and B below, no competition concerns on these markets.

(9) For the reasons indicated below, the concentration would have given rise to the creation or strengthening of a dominant position in the following markets:

- wholesale transmission of natural gas in the Netherlands (Section C),

- long-distance wholesale transmission of natural gas in Germany (Section C),

- underground storage facilities for natural gas servicing the south of Germany (Section C),

- group I base oils in the EEA (Section D),

- motor fuel retailing in Austria, Germany, Luxembourg, Netherlands and the United Kingdom (Section E),

- motor fuel retailing on toll motorways in France (Section E),

- aviation lubricants worldwide (Section F),

- aviation fuels at Gatwick Airport (Section G).

A. EXPLORATION, DEVELOPMENT AND PRODUCTION PROCESS

(10) Upstream activities comprise three types of commercial activity: the finding of new reserves, the development and the commercial exploitation of those reserves. The finding of new reserves is generally described as "exploration". Development concerns the setting up of adequate infrastructure for future production (oil platforms, pipelines, terminals, etc.). The exploitation of reserves is called "production and sales". Previous Commission decisions(7) focused primarily on the impact of the then notified transactions on the production and sales segment.

(11) Exploration and development is a time and capital-intensive activity, which includes a number of successive steps. Firstly, countries which believe that hydrocarbon reserves could be discovered on their territory (such a country is called the "host country") organise bids to grant exploration licences. The bidding processes vary from public auctions in the USA to situations where bidders are pre-selected by the host country. This pre-selection can be based to varying extents on technical capability, financial strength or other considerations (lobbying, cultural affinities, etc.).

(12) Often, companies bid together in order to spread risks or to bring complementary skills. In some circumstances, host countries may require that some bidders join together in order to get the licence for exploration. Host countries may also require that their national oil companies be granted a share in any discovery made in the block under licence. In all cases when the licence is granted jointly to a number of companies, an operator for the block is named. The role of the operator is to manage technically and financially the exploration and possibly the development and production phases of the project. Most of the important decisions require unanimity from all the partners in the project.

(13) The total time between the granting of a licence and actual production typically ranges from five years to 15 years. Costs of exploration and development projects can reach the region of EUR 7 billion for projects in the "frontier areas". The split of expenditures between the exploration stage and the development stage is typically respectively 15 and 85 %.

(14) It must also be mentioned that when production is started in a new area, infrastructure needs to be developed. This includes notably oil platforms, pipelines and terminals. Smaller fields, which would not be economical to develop on their own, can then be exploited through using the infrastructure already put in place for the bigger field. Such smaller fields are sometimes called "satellite fields". Exploration in the North Sea has typically followed that process.

RELEVANT PRODUCT MARKETS

(15) It is often argued that exploration, development and production and sale are too closely inter-linked for more than one distinct product market to be defined. It may however be argued that exploration constitutes a separate product market. Indeed, it could be argued that a firm engaged in exploration has two categories of clients: the host country, to which it has generally undertaken to provide a future flow of resources in case oil or gas is found, and the subsequent producers and sellers of oil and gas that may buy it out or join in the development and production. The transfer of rights over blocks is a widespread practice in the industry.

(16) Since the possible contents of the underground are not known at the time of exploration, the Commission considers that it is not justified to make a distinction between exploration for oil and exploration for natural gas. As regards the development, production and sales product markets, since gas and crude oil have differing applications and are subject to varying pricing behaviour as well as cost constraints, the Commission considered it appropriate at the stage of the decision initiating proceedings to define one relevant product market for the development, production and sales of crude oil and another relevant product market for the development, production and sales of natural gas.

(17) The parties have contested the existence of an exploration market arguing that it is too closely linked to the subsequent steps of the production process to make it a possible product market. As will be explained in the section on effects of the merger on competition, it is not necessary for the appraisal of the effects on competition of the notified operation to define precisely the relevant product markets according to the various stages of the exploration, development, production and sales of crude oil and natural gas, respectively.

RELEVANT GEOGRAPHIC MARKETS

(18) The Commission considers that the exploration market is worldwide in scope and agrees with the parties that from a European-demand perspective the relevant geographic markets are worldwide in scope for development, production and sales of crude oil and probably include the EEA, Algeria and Russia for gas.

(19) The Commission examined whether smaller geographic areas could constitute relevant markets. Some purchasers of gas make, for security of supply reasons, a distinction in their purchasing policy as to the origin of the gas on the basis of the perceived political risks and their influence on the security of supply with regard to Russian and Algerian gas (Russia accounted for approximately 17 % of total western European supply and Algeria for 12 %). The most explicit example of this is the Spanish legislation ordering that not more than 60 % of the natural gas demand can come from the same country. It is, however, unlikely that a price increase of gas produced in the EEA would not be defeated by a small increase in the proportion of gas purchased from Russia and Algeria. In any case, the precise definition of the relevant geographic market can be left open, as this does not alter the conclusion of the competitive assessment.

MARKET PLAYERS

(20) Traditionally, companies involved in the exploration, development and production and sales business were grouped in three categories with different profiles, strategic objectives and future exploration and development capabilities. The categories are: (i) the State-owned (mainly OPEC and some OECD-based companies such as Statoil) producers, (ii) the "majors", that is, vertically integrated oil companies with international activities and (iii) a multitude of substantially smaller oil companies, most of which are non-integrated upstream explorers and/or producers.

(21) The competition concerns identified by the Commission were raised mainly by the fact that, as a result of the notified transaction, as well as of that notified by BP Amoco and Arco, a distinct (fourth) tier of players might prevail on the exploration and development activities. This group of "super majors" would be composed of Exxon-Mobil, BP Amoco-Arco and Shell.

POSITION OF THE PARTIES IN THE MARKET

Exploration

(22) There is no widely available or accepted indicator of market power for the exploration market. Measurement of market power could be carried out on the basis of the number of blocks where licences have been granted, the number of blocks where a given company is the operator, net acreage, total acreage under operatorship, capital expenditure in exploration, etc. There is wide agreement that proxies based on number of blocks or acreage would not be reliable as they cover widely varying situations.

(23) On the basis of capital expenditures, Exxon-Mobil, BP Amoco-Arco and Shell would represent together, with roughly equivalent shares, between 30 and 40 % of the total capital expenditures in exploration, development and production scheduled for 1999. The next largest player would represent one third of the average size of the three main players.

(24) The parties have contested the adequacy of this measure of market power for the following reasons. First, capital expenditures vary according to the sites explored. This biases downwards the market share of national oil companies in low-cost OPEC areas. Secondly, capital expenditures often do not reflect the correct share of ownership of the licence or of the output. This is because State companies often pay a share which is disproportionately lower than their licence interest or take of crude oil output. Thirdly, capital expenditures often include expenditure on investments such as gas liquefaction and infrastructure rather than sums invested purely in exploration.

(25) Another possible way to measure market power would be to calculate the share of expected production of these companies (since current exploration and purchase of third party rights will translate into future production). On the basis of the market investigation, the combined market share of the three super majors of the non-OPEC production, in some 10 years from now, would again be in the 30 to 40 % range.

Production and sales

(26) Exxon and Mobil would have together around [0 to 10]* % and [10 to 20]* % of, respectively, the worldwide production crude oil and the European production of natural gas in 1998. These numbers would be 3,7 % and 8,4 % for a combined BP Amoco-Arco and 3,3 % and 13,9 % for Shell. These numbers have not materially changed over the years. Of the total natural gas production in the EEA, the three super majors account for almost [30 to 40]* %. However, of the natural gas consumed in the EEA, the three super majors account for less than [20 to 30]* %.

(27) The industry often refers to proven reserves as a proxy for market power. On this basis, the parties would hold approximately [0 to 10]* % and [10 to 20]* % of, respectively, the worldwide proven reserves crude oil and European wide proven reserves of natural gas. However, it may be argued that proven reserves are not a relevant indicator of future production. Proven reserves as stated by the oil companies have just a stock function and, as any other private company, private oil companies need to limit their stocks as much as possible. By means of its proven reserves, a company indicates that it is (or is not) able to replace the foreseeable depletion of existing oil fields and thereby to remain a viable player on the market. However, national oil companies do not need to justify further exploration and development investments to their shareholders since they benefit from the national reserves, which usually largely exceed their needs. Therefore, such an indicator involves an upward bias in favour of national companies.

(28) Currently and for the foreseeable future, the OPEC producers collectively enjoy substantial market power in crude oil production. They control a substantial amount of production and proven reserves (approximately 40 % and 75 %, respectively, whereas Saudi reserves account for more than one third of OPEC reserves). OPEC has been able in a number of instances in the past to influence(8) crude oil prices up to a certain level.

(29) Gazprom (17 %) and Sonatrach (11 %), the national Russian and Algerian suppliers, account for approximately 30 % of EEA sales of natural gas and their reserves account for 88 % (Gazprom 81,5 %) of the combined proven reserves that can be sold in the EEA.

EFFECTS OF THE MERGER ON COMPETITION

(30) The Commission raised the following serious doubts as to the effect on competition in the markets for exploration, development, production and sales of crude oil and natural gas. The notified acquisition together with the BP Amoco-Arco merger could lead to the creation of a fourth tier of competitor in the industry composed of Exxon-Mobil, BP Amoco-Arco and Shell. Whatever the parameter retained (market capitalisation, oil and gas production, proven reserves, etc.) there is now a material gap between these three super majors and the remaining majors.

(31) It was considered whether it would be possible that the three super majors would in the future be in a privileged position to find and develop new important reserves compared to the other players in the market. This could come from their increased financial strength that would now enable them to hold a portfolio of risks of increased size. On the contrary the other competitors would have to pick and choose the areas where they intend to become active. Because of their less favourable access to capital and capacity to spread risks, smaller companies would, if they wanted to continue developing important fields, have to become smaller partners to the super majors to benefit from their combination of resources. Their only other alternative would be to become niche players focused on exploration. This may result in the super majors controlling the access by other explorers to the new frontier areas first at the time of the granting of the first licences and then for further surrounding blocks since the super majors will have built the necessary infrastructure.

(32) Since the typical time lapse between the first stages of exploration and the start of production varies between five and 15 years, in this scenario there would be a possibility that within some 10 years, new non-OPEC reserves and production would be influenced to a significant extent by the super majors.

(33) This could affect the production and sales markets in the following way. The competitive constraints limiting OPEC's ability to function as a cartel would be lessened. These three companies would have the same interests as OPEC and would be likely to align themselves on the OPEC decisions by limiting output to a certain level without fearing that others would take advantage of this. This would translate into the strengthening of OPEC's dominant position in the crude oil market through the creation of an oligopolistic structure combining both OPEC and the three super majors, thus creating incentives for alignment on OPEC's commercial strategies. OPEC would then be in a position to raise and sustain prices at the highest price threshold above which new exploration would be triggered.

(34) On the basis of the foregoing, the Commission concluded that the operation raised serious doubts as to its compatibility with the common market and the functioning of the EEA Agreement, which should be further explored in an in-depth investigation.

(35) The parties contested the Commission's serious doubts on mainly two grounds. First, the super majors would still be facing competitive constraints from smaller oil companies. Secondly, host countries control oil and gas production and in any case would have no incentives to let oil companies restrict production.

(36) The market investigation confirmed that small explorers do not seem to believe that the emergence of a new class of super majors would threaten their position. Because of size differences they would not compete for the same type of exploration rights and they would not be dependent on the bigger explorers to sell their oil. In addition, majors such as Chevron, Texaco, Elf or Total would all seem to have unchanged capacity to explore and develop fields anywhere in the world. The parties have provided numerous examples of the involvement of majors in current projects all over the world.

(37) Second, the market investigation confirmed that typical concession contracts between governments and explorers-producers prohibit the latter from limiting their output (and leave such a decision to the discretion of the government).

(38) As for natural gas, it is unlikely that the parties together with the other super majors could control EEA production and therefore that competition would be affected. Even if such a market did exist (in view of the perceived political risk attached to the gas production in Russia and Algeria), no collective dominance between the super-majors can be argued in view of the strong position of Norwegian gas delivered by competitors. In addition, producers of natural gas face very concentrated demand in the hand of the national wholesale gas transmission companies such as SNAM (Italy) or Transgas (Portugal).

(39) Therefore, the Commission concludes that the concentration will not lead to the creation or strengthening of a dominant position on the markets for the exploration, development, production and sale of crude oil and natural gas.

B. GAS-TO-LIQUIDS TECHNOLOGY

(40) The Commission expressed serious doubts in its Article 6(1)(c) decision that the notified transaction creates a dominant position with regard to gas-to-liquids technology.

(41) Gas-to-liquids technology (GTL) is a process of conversion of natural gas into finished fuels. GTL technology enables the conversion of natural gas into liquid form at the site of exploration and production, and thus facilitates the commercial development of gas reserves and transportation of natural gas from remote locations that are not accessible by pipelines. In addition, it has the advantage of producing high-purity products.

(42) At present GTL processes cannot produce economic substitution products for conventional refining products. Customers' demands for GTL products are expected to come first from the lubricants and petrochemical industries, due to the high purity and molecular arrangement of feedstock generated by GTL technology. Subsequent demands may include the other petroleum products.

(43) There are two GTL pathways at present, that is Fischer-Tropsh (F-T) and methanol, or methanol-to-gasoline process (MTG), which Exxon and Mobil have each developed respectively. Information collected in the market indicated that Exxon has developed the single largest patent portfolio directed to the F-T process, and holds foreign and US patents directed essentially to every significant step in the pathway. Industry sources stated that [...]*.

(44) Other oil and gas companies have limited patent positions in one or the other, or sometimes both, processes. However, none of these companies have positions that cover all of the essential steps of either pathway.

(45) The patent positions of Exxon and Mobil currently represent alternative, although not substitutable, positions. Post-merger, the strong patent position of the parties would create disincentives to any potential new entrant. Finally, the substantial financial resources necessary to compete in GTL (for example: currently a F-T plant costs [between USD 1 and 3]* billion to build) would prevent both expansion by incumbents and entry by potential competitors.

(46) In response to the Commission's serious doubts, the parties explained that GTL technology did not constitute a market in itself and that the quantities of petroleum products that such a technology could enable to produce in the next decade would be minute compared to those produced through the traditional refining process. In addition, other companies would hold patent portfolios sufficient to enable them to develop the technology.

(47) The Commission agrees with the parties that the notified concentration, even assuming that they would hold an essential portfolio of GTL patents, will not give rise to any dominant position given the small impact it would have on petroleum products markets.

C. NATURAL GAS

INTRODUCTION

Description of the "gas column"

(48) The natural gas that streams from the well contains elements that need to be removed before the gas reaches pipeline quality, composed almost entirely of methane and ethane, and can be injected into the high-pressure distribution pipelines. This gas is sold to the wholesale transmission companies that, in turn, sell the gas to the end consumers

(49) There are two levels of gas wholesale transmission companies. There are the "long-distance" wholesale transmission companies and the "short-distance" wholesale transmission companies. Long-distance wholesale transmission companies purchase gas from gas producers and transport this gas over long-distances through high-pressure pipelines. They then either sell to other more local wholesalers, namely the short-distance wholesale transmission companies, or directly to end customers or provide international long-distance transit services to other long-distance wholesale transmission companies located in other countries.

(50) In addition to the supply of gas, the services offered to the end customers include:

- the provision of "swing": consumption of gas is not evenly spread around the year. This is particularly important for the local distribution companies (LDCs) that supply via their low-pressure pipeline grid the households who require, for their heating purposes, a lot of gas in the winter and much less in the summer. A key element to provide swing is access to storage, mostly in the form of underground storage facilities,

- the provision of other services such as quality control (ensuring that the gas provided is within the agreed specifications), balancing (ensuring that the input of gas in the pipelines is in line with the required output), back-up (agreements with other wholesalers and/or producers interconnected with the own pipeline network in which they guarantee supply if the proprietary supply falls out) and metering.

(51) The end customers can be grouped in three categories: power generators, (firm or interruptible) industrial customers and LDCs. These customers differ in the following way:

(52) There are important price differentials between the different customer categories, even when their gas demand is the same. This is so because prices are traditionally based upon the value of the customer's alternative energy source (Anlegbarkeitsprinzip). This refers to the alternative energy source to which a customer might switch: heating oil for households, heavy fuel for industrial users and, to a certain extent, nuclear energy or coal for power generators.

(53) There are also qualitative differences when considering the supply to the different customer categories. In this respect, reference is made to the" swing" requirement for supplies to LDCs and the difference between firm (their gas supply cannot be interrupted) and interruptible industrial consumers. These aspects equally have an impact on the price.

(54) The last difference is the legal framework resulting from Directive 98/30/EC of the European Parliament and of the Council(9) (hereinafter "the Gas Directive") and national implementation measures (liberalisation). The Gas Directive requires Member States to open up their markets before 10 August 2000 so that by then gas-fired power generators, irrespective of their annual consumption level, and final customers consuming more than 25 million cubic metres (MCM) per year on a consumption site basis, are free to contract for natural gas ("eligible customers"). The total opening of the market must be at least 20 %, increasing to 28 % in 2005 and 33 % in 2010. The threshold for eligible customers will be reduced to 15 MCM in 2005 and 5 MCM in 2010.

(55) For the organisation of access to the system, the Member States may choose between two procedures which must operate in accordance with objective, transparent and non-discriminatory criteria. The first procedure concerns the "negotiated access" whereby natural gas undertakings and eligible customers negotiate voluntary commercial agreements and whereby the relevant gas undertakings have to publish the terms of use of their system before 10 August 2001 and on an annual basis thereafter. The second procedure is the "regulated access" whereby natural gas undertakings must give access on the basis of published tariffs set by a relevant authority in the Member State.

(56) The Directive allows for an important conditional derogation procedure whereby the Commission can accept, under certain conditions, that gas undertakings can refuse access if this would cause them serious economic and financial difficulties because of take-or-pay commitments accepted in one or more gas purchase contracts.

(57) In the Netherlands, the recently introduced proposal for a new gas law goes considerably further than the minimum requirements of the Gas Directive. Consumers with an annual consumption of 10 MCM (accounting for 44 % of total annual Netherlands consumption) are already free to purchase gas. As from January 2002, clients with an annual consumption of between 170000 m3 up to 10 MCM will be free. As from January 2007 all consumers (including households) will be able to source their gas freely. There is no special regime for power generators. The Netherlands has opted for the "negotiated access" and Gasunie has published its TPA tariffs in August 1998.

(58) In Germany, the wholesale transmission companies traditionally had regional monopolies and had concluded regional demarcation agreements, i.e. agreements whereby the wholesale transmission companies agreed not to undertake wholesale activities in each other's designated territory. This is forbidden since 29 April 1998, the date of the entry into force of the Energy Industry Act. The Act makes 100 % of the German market open, i.e. all customers are "eligible customers". The act also stipulates that municipalities have to make available rights of way for the construction of pipeline grids. The new competition act stipulates that network operators must not deny third parties access to networks without justified, objective reasons. In case of a refusal, the matter can be submitted to the competition authority or directly before the administrative court. Since February 1999 the industry associations are negotiating the "Verbändevereinbarung Gas" which should lay down the criteria whereby (negotiated) third-party access is going to be given, together with indicative prices.

Contractual framework

(59) The European gas industry has operated on the basis of long-term contractual arrangements between buyers and sellers. The parties have indicated that in order to achieve the finance necessary for the investment in the production and distribution infrastructure, the gas producers had to conclude long-term agreements with their buyers. A gas field would only be taken in production if a buyer for the gas, typically one or more national wholesale transmission companies, has been found.

(60) On the basis of such agreements, investments would also take place in the necessary distribution infrastructure (terminals and pipelines). Contracts are concluded sufficiently in advance of the actual production start to allow the necessary infrastructure to be built. In turn, the wholesale transmission companies conclude contracts with their clients whereby they endeavour to match their aggregated buying volume with long-term contracts with their clients. It can be said that traditionally the wholesale transmission companies balanced the demand with the supply.

(61) Typical features of the long-term contracts are the take and/or pay commitments for the volumes. The contractual price on each level is typically constructed as a netback price minus an agreed margin for the client. A contract will also provide for three-yearly price-reopeners whereby the price might be reviewed if there is a material change in the market of the buyer (gas-to-gas competition, change in alternative energies and so forth). The contracts also contain a parallel sales clause whereby the buyer is entitled to lower his take obligations with the volume that the seller sells directly in the buyers' territory. The gas companies [i.e. the buyers]* argue that this is necessary to avoid the producers selling their gas twice (once to the wholesale transmission company and a second time directly to the wholesale transmission company's client). On the other hand, such agreements are an important element of stability in the gas distribution chain as it maintains a certain hierarchy of producer - wholesale transmission company - end consumer.

(62) The policy to price gas by means of the alternative energies of the buyer's clients, also called the market value principle, is in the view of the European gas companies the key element to explain the building and expansion of a European gas infrastructure and, at the same time, allows the consumers to benefit from competitive prices. Maximising the income stream from gas sales in this way and maintaining the acceptance by all gas players of this principle is thus a key concern for the incumbent gas operating companies.

(63) [...]*

Brief overview of the gas column in the Netherlands and Germany

(64) The Netherlands is one of the largest gas-producing countries in the EEA. It is a net exporter of gas. The largest equity producers in the Netherlands are NAM, a joint venture (JV) between Exxon and Shell, and EBN, the Dutch State's oil and gas company. Exxon and Shell and the Dutch State (via EBN and directly) own Gasunie, the wholesale distribution company to which almost all Dutch gas is sold. Gasunie sells [80 to 90]* % of the gas consumed in the Netherlands and owns the total Dutch gas wholesale infrastructure (with the exception of one pipeline). Gasunie has concluded long term exclusive supply agreements with all the regional distribution companies concerning sales to clients with an annual demand [below a certain level]*.

(65) There is gas production in Germany. This accounts for approximately 20 % of the German gas demand. The main producers are BEB, the German production and distribution JV between Exxon and Shell, and Mobil. Around 80 % of the gas consumption is imported from Norway, Russia and the Netherlands. The most important importer and wholesale transmission company in Germany is Ruhrgas. Exxon, Shell, Mobil and BP together with German coal and steel producers are the owners of Ruhrgas. Other importers are BEB, Thyssengas (where Exxon and Shell each have a 25 % interest and RWE-DEA has 50 %; together these companies control Thyssengas) and VNG (the eastern German wholesale transmission company, where BEB and Ruhrgas are shareholders). Mobil and EWE, a company in which the parties do not have an interest, also import some gas for German consumption. All of the above are the traditional long-distance wholesale transmission companies whose position has been challenged by Wingas, a JV between BASF and Gazprom (the Russian gas producer), by means of their newly constructed pipeline network.

(66) Gas is sold by the German producers and importing wholesale transmission companies (referred to as "long-distance wholesale transmission companies") to a series of regional wholesale transmission companies (referred to as "short-distance wholesale transmission companies"). The around 19 long and short-distance wholesale transmission companies sell on the gas to around 700 LDCs who in turn supply the households.

WHOLESALE TRANSMISSION MARKETS

Relevant product market

(67) The parties consider that the distribution and marketing of natural gas can be divided into a wholesale transmission segment and a local distribution segment. Wholesale transmission companies aggregate gas from producers. They then sell it to a mix of a second tier of wholesale companies (the German short-distance wholesale transmission companies), local distributors and large end-users. Transmission companies utilise high-pressure pipeline systems and storage facilities to deliver gas at the location and volumes required by their customers. Local distributors sell on the gas to end-users (such as households).

(68) The parties consider that the suppliers at the wholesale and local distribution levels of trade tend to be different. The parties have no direct presence in the local distribution segment.

(69) In addition to the distribution and marketing of natural gas, the parties qualify in the notification "natural gas transportation - pipelines and LNG shipping" and "natural gas storage" to be separate markets. The Commission agrees with the parties that natural gas transportation and natural gas storage constitute distinct product markets.

(a) Wholesale transmission versus local distribution market

(70) Long-distance and short-distance wholesale transmission companies sell gas via high-pressure pipelines to industrial customers, power generators and local distribution companies. Local distribution companies sell on the gas to end-users such as households and residential customers via their extensive (street-by-street) low-pressure pipeline network grid. Local distribution companies buy from the wholesale companies the swing and other related services. The Commission therefore agrees with the parties that local distribution constitutes a distinct product market. As the parties are not directly active on this market, this product market is not further assessed in the scope of the present procedure.

(b) Long-distance versus short-distance wholesale transmission market: long-distance wholesale is a distinct product market where entry depends on the goodwill of the incumbents or on a very high sunk-cost investment

(71) As explained above, the German gas wholesaling industry is characterised by a two-tier structure: long-distance transmission companies sell gas that they have imported directly from foreign producers and transported over long-distance pipelines to the short-distance companies. It needs to be assessed whether this type of service could be easily substituted by the short-distance companies in case of a hypothetical increase in the prices charged to short-distance companies. In such circumstances, the only way short-distance companies could defeat a price increase would be to get directly the gas from the producers, i.e. to integrate upwards in the vertical chain. To do so, short-distance companies (or possibly the end customers) would need to get similar pricing conditions from gas producers to those enjoyed by long-distance companies and be able to transport the gas over long-distance. From its market investigation, the Commission concludes that even in the face of a price increase the short-distance companies would lack the incentives to by-pass long-distance companies.

(72) [...]*

(i) The parties' view: everybody can import gas

(73) The parties consider that the relevant market consists of the sales of German and imported gas by the around 19 long-distance and short-distance wholesale transmission companies to industrial customers, power generators and local distribution companies. The parties consider that the specific activities of the long-distance transmission companies is nothing more than a technical complication as everybody is able to bring gas to the German border.

(74) First, the parties indicate that imports of small volumes are possible. They refer to a couple of small-volume import contracts such the ones [...]*.

(75) Second, the parties consider that the cost of entering into the business by means of investment in reception facilities, pipelines and storage is a natural feature of a long-term capital intensive industry and does not constitute a barrier to entry. Specific reference is made to the investment made by Wingas to illustrate that it remains profitable to invest in German gas infrastructure. The parties also point out that investments are not needed to import gas [...]*.

(76) Third, the parties refer to the provisions of the new German Energy Law and the legal obligation for pipeline owners to offer spare capacity to third parties. Therefore, sales to end consumers in Germany are a realistic possibility and reference is made to the decisions of a certain number of local distribution companies to purchase directly from the producers and the fact that industrial groups purchase centrally.

(ii) This is not corroborated by the Commission's market investigation

(77) The market investigation has not corroborated the parties' opinion that importing gas is merely a "technical complication". The following statements have been made by some of the 11 German short-distance wholesalers:

- "To achieve interesting prices by way of an import contract, one is required at present to buy very big quantities with buying obligations as well as, amongst others, own investments or financial participations in projects or companies. Such an activity is hence typical for companies that bundle a big demand and have large financial means to bear the import-related cost risk. When importing, the supply security by way of diversification of the supply sources plays an important role."

- "To import, one would require a parallel pipeline network to the producers (or to the transmission points at the border) or TPA. The short-distance wholesaler could not estimate the necessary costs and time involved."

- "It is difficult to sell additional import quantities in Germany to the clients as these quantities can only go to regional distributors. Marketing of gas directly to end consumers is only possible with considerable efforts and proves to be unrealistic at present."

(78) In their reply to the statement of objections (the reply), the parties have re-stated that purchasing small volumes is possible, that the costs for importing are readily available (by means of own research or via available consultant firms), that the costs for import infrastructure are typically less than [0 to 5]* % and that supplies and customers are accessible (demand is growing and existing contracts expire). The Commission recognises that the costs for importing can be calculated. The other points will be dealt with further below.

(79) It can be noted that the Bundeskartellamt has in a recent procedure(10) concluded that the long-distance wholesale transmission market constitutes a distinct relevant product market.

(iii) German gas cannot challenge a price increase of imported gas

(80) German gas is all sold in Germany, where it competes with imported gas. However, German gas production accounts currently for around 20 % of total consumption and is expected to decrease to [less than 15]* % by 2010. Wholesale transmission companies that want to satisfy their demand therefore require increasing access to imported gas, i.e. to the services of the long-distance wholesale transmission companies.

(81) In addition, German gas is committed to a very large extent to the long-distance wholesale transmission companies so that, in general, the availability of German gas for other companies is too limited to challenge a price increase of imported gas. German gas production and reserves are held for around [70 to 80]* % by the long-distance wholesale transmission companies BEB ([40 to 50]* %) and Mobil ([20 to 30]* %). The remaining [20 to 30]* % of German production (thereby accounting for about [0 to 10]* % of German demand) is done by RWE-DEA with around 7,5 %, Wintershall and Preussag with each around 5,5 % and Erdöl-Erdgas Gommern with around 4,5 %. RWE-DEA commit to sell 60 % of their annual production to Ruhrgas and Preussag commits to sell 45 % of its annual production to Ruhrgas. The largest part of Erdöl-Erdgas Gommern's production is sold via VNG, another long-distance wholesale transmission company.

(iv) Access to foreign gas at competitive conditions is not and will not be feasible post merger: the potential entrants in the long-distance wholesale transmission market depend on the services of the incumbent companies

(82) The day-to-day business of any short-distance wholesaler depends, to a significant extent, on the pipeline network, storage facilities and other services provided by the long-distance transmission companies. To upset such essential suppliers through by-passing them for part of their services would be a risky decision in view of the scope for retaliation from the long-distance wholesale transmission suppliers.

(83) However, there is one short-distance wholesale transmission company that does not depend on the wholesale transmission services of long-distance transmission companies. This is Erdgas Münster (EGM), a company that sells German gas produced by its shareholders, the most important German gas producers: BEB ([20 to 30]* %), Mobil ([20 to 30]* %), Wintershall ([20 to 30]* %), Preussag ([10 to 20]* %) and RWE DEA ([0 to 10]* %). The shareholders are obliged to sell their whole production in a specific part of Northwest Germany via EGM (accounting for [less than 10 %]* of total German gas consumption) and, in this way, the company is assured of its gas supplies [...]*.

(84) [...]*, BEB and Mobil would, after the concentration, control the strategic decisions of EGM. Such decisions include the position of EGM in a future liberalised market environment (see further below). The parties claim that they would not control EGM as [...]*. This reasoning cannot be accepted. Exxon exercises joint control in the sense of the Merger Regulation over BEB and, in addition, it would make economic sense for Shell to agree to [...]* as, thereby, Shell would also benefit from the advantages of being able to control EGM.

(85) Although both Mobil and BEB are long-distance wholesale transmission companies, Mobil's position on that market is substantially smaller than that of BEB. Therefore, Mobil would have an interest, pre-merger, to maintain the possibility to use EGM as an instrument in a future liberalised market environment. There is, therefore, not necessarily an alignment of interest between BEB and Mobil. This ability to be a potential competitor would be suppressed post-merger through the establishment of a formal control on EGM.

(86) The parties have also made some references to direct calls for tenders to foreign suppliers by a couple of relatively minor local distribution companies. In the call for tender, the local distribution companies, all of them Wingas customers, request quotes for supplies to the German border and indicate that they would organise the transport within Germany themselves. Another example mentioned by the parties is the decision of Stadtwerk (SW) Viernheim to purchase directly. However, it results from the Commission investigation that these calls for tender were not successful.

(87) The fact that there may be sporadic calls for tenders does not mean that the local distribution companies consider that it is feasible to transport themselves the gas within Germany. It therefore does not mean that they consider that they act in competition with the incumbents.

(88) The producers that would want to enter the market do not only rely on the German companies to sell their gas in Germany, but they also rely to a varying extent on the incumbents for their transit of gas to other export markets. For instance, Dutch gas transits the pipelines of the German incumbents to reach Switzerland and Italy (and possibly even Poland), Norwegian gas transits Germany to reach Switzerland and Russian gas transits Germany to reach France.

It is unlikely that smaller companies could get interesting prices or volumes or that traditional suppliers would by-pass the incumbents

(89) The long-term (10, 20 or 30 years) take and/or pay contracts whereby the off-take obligation of the wholesale transmission company is reduced by the amount that the producer sells directly (or via other companies) in the area of the transmission company (also called "parallel sales clauses"), increases the barriers for other companies to obtain supplies.

(90) Furthermore, the suppliers have no interest in by-passing their traditional clients if this would lead to gas-to-gas-competition (GTGC) reducing the prices obtainable in the market. And if the supplier is not willing to offer lower prices, there is no reason for the customer to switch. GTGC and price reduction is therefore the most likely outcome. As the producer receives net-back prices, such a price reduction would affect all gas sales. Selling to newcomers therefore puts the producers at risk of possible damaging price competition. [...]*

(91) According to [...]*, parallel sales clauses stimulate the wholesale transmission company and the supplier to compete for the same end-user and are thus pro-competitive. However, such competition is only likely to happen if the profit made by the supplier on its direct sales more than compensates both the short-term loss of net-back value on the totality of the remaining contracted sales volume to the wholesale transmission company and the long-term loss of risking to lose sales to the wholesale transmission company when the existing contract ends. This is unlikely to happen so that parallel sales clauses also act as a barrier to entry.

(92) The Commission also notes that three of the most important German long-distance wholesalers have purchased a substantial part of their non-German origin gas from Norwegian, Danish and Russian producers in common (Ruhrgas [...]* %, BEB [...]* % and Thyssengas [...]* %). By combining their demand, the consortia should be able to get, via long-term contracts, better prices than any other company that would negotiate the contract on a stand-alone basis. The parties disagree with this and indicate that purchase prices are unrelated to volume, but are set by alternative fuels' prices. The Commission cannot agree to this argument as, if it were taken to its logical extreme, it would imply that no price competition is possible within the European gas industry as everybody would charge the same price, namely the alternative fuels' price. This is clearly not correct as parties have a wide freedom to assess the parameters of the gas price, even using links to alternative fuel indexes.

(93) It also has to be noted that buying in common reduces the incentive of the producer to by-pass the wholesale transmission companies in selling directly or indirectly to others in the their territory. This is so because, when several companies combine their purchases, the producer risks losing all of his/her clients even if he/she would only by-passes one of them.

(94) And even if, as the parties argue, other incumbents such as VNG and Mobil can purchase gas directly and individually at similar prices, this does not imply that the same may be possible for newcomers. The incumbents will endeavour to use their position and influence vis-à-vis the producers to push them not to supply to competitors. Wingas has indicated that it had concluded a number of years ago a supply agreement for Norwegian gas, but that the GFU (the Norwegian gas sales organisation) had refused this. In addition, [...]* has stated that "[...]* will continue to try to prevent that [...]* is able to buy [...]* gas."

(95) Even if new volumes might be contracted, the long-distance wholesale transmission companies have concluded long-term (take or pay) supply agreements with the most important customers (short-distance supply companies, local distribution companies and so forth). It may therefore be difficult to sell the volume so that these long-term agreements form an additional barrier to entry in the long-distance market. The Commission recognises that these contracts all end one day and that gas demand is growing by 2 to 3 % per year. These contracts are, therefore, not an insurmountable barrier to entry, but they undeniably make entry more difficult than in a market where there are no long-term commitments between buyers and sellers.

(96) Finally, the German long-distance wholesale transmission companies have spent a lot of money in recent years and will probably continue to do so in downstream vertical integration by buying equity participations in short-distance wholesale transmission companies and in local distribution companies. [The Commission considers that]* this is aimed at maintaining the current supply structure. This will further increase the barriers to entry into the market.

(v) Access to the infrastructure or duplication are no options

Duplication of infrastructure would involve excessive sunk costs

(97) The important capital investments of the incumbents in reception facilities, pipelines, storage and quality adjustment cannot be used for any other purpose although some gas pipelines might be converted against a substantial cost in oil pipelines. The investment can therefore be considered to be, for a very substantial part, a sunk cost.

(98) The parties indicate that the cost of entering the gas business cannot be reasonably construed as a barrier to entry as the cost of the import infrastructure is typically less than [...]* of the value of the gas purchased. However, the import infrastructure is not the only infrastructure required (the most important part might be the long-distance pipeline network) and it remains that the important capital investment is, for a very substantial part, a sunk cost.

(99) In addition, it is always cheaper and quicker for the incumbents to increase their capacity of pipeline transport by adding compressors than it is for a newcomer to build a new pipeline.

(100) It is, therefore, not expected that a newcomer to the market will start constructing a new, major high-pressure pipeline network in Germany. In other words, the "Wingas experience" is not likely to be repeated. Wingas is a sort of a "lucky combination" between a very big (probably even the largest) German industrial gas consumer that was not happy with the prevailing prices and a very big Russian producer that had a conflict of interest with the incumbents. This conflict of interest will be further explained in the competitive assessment part.

(101) In addition, the net-back that the supplier can expect to achieve from renewing the contract with the original wholesale transmission company is greater than the expected net-back from a newcomer who has to make new investments (and therefore requires a higher margin). Furthermore, such a newcomer would have to "fight" to get his volumes sold, which will lead to price reductions for all players on the market and this is again reflected in a reduced net-back price for the producer.

The industry-proposed third-party access will have a limited impact on the ability of customers to directly import gas in competition with the long-distance transmission companies

(102) For the purpose of this decision, the Commission is not satisfied that the possible conclusion of the Verbändevereinbarung Gas (VV Gas) will lead to market entry by means of third-party access. This conclusion is based on the current state of play, namely the proposal by the German gas industry within the VV Gas negotiations.

(103) The VV Gas is an initiative of four trade federations: (a) BGW, the association of the German gas and water industry; (b) VKU, the association of the local distribution companies; (c) BDI, the German industry association (industrial consumers) and (d) VIK, the German Power Generation Association. Germany has chosen, in the context of the Gas Directive, for a "negotiated TPA" and the VV Gas wants to set the guidelines for such a negotiated TPA. The German competition authority and/or the Commission will have to assess the VV Gas when adopted. The aim of the VV Gas is, as indicated in a common letter of the four federations to the German Minister for Economic Affairs, "to set a signal to the political environment that no further regulation for natural gas is required. The VV Gas shall fulfil the criteria of market-oriented, competitive, fair, transparent and simple and thereby it has to help in the development of a natural gas stock exchange. The VV Gas shall contain the basic principles and rules for access to the network as well as a simple calculation of the tariffs. The VV Gas shall be concluded before the end of 1999."

(104) Despite this common declaration, it does not seem, on the basis of the "reference case" developed by the gas industry, possible to conclude that by means of this type of TPA it will be possible to import gas in competition with the incumbents.

(105) The first element is that the reference case stipulates that TPA is only possible if pipeline capacity is available and that long-term take or pay contracts shall be taken into consideration. It results from the market investigation that it is difficult to assess whether capacity is available and the incumbents have contracted up to 100 % of their demand by means of long-term take or pay contracts. The VV Gas will therefore not fundamentally endanger the situation of the incumbents.

(106) The second element is that the reference case indicates that the third-party gas has to be compatible with the gas specification in the relevant pipeline network of the pipeline owner. This is defined in such a way that "the specification of the gas is so that it can be taken in the pipeline without adaptation by the transporter; that it has a pressure that enables to take the gas without adaptation by the transporter and that it has a specification that allows usage together with other gas in the network." These might not be easy criteria to fulfil in view of the different gas specifications currently traded in Germany (see the discussion below on LCV/HCV gas and the fact that both LCV and HCV gas is currently sold in Germany within several distinct specifications). Natural gas is thus not a fully homogeneous product and the nature and practicability of TPA for electricity and telecom is different from TPA for gas. Or, as indicated in a document submitted by the parties, "a main difference with the VV Electricity is that for gas a distinct agreement is necessary with each pipeline operator and that the different gas specifications and the pressure differences at the starting and ending point complicate the concrete organisation."

(107) A third element is that the duration of a transport agreement has to be at least a year, with two starting dates every year (1 October and 1 April). It can be noted that, therefore, the TPA contracts will always include the winter peak utilisation so that there is all the more chance that the pipelines will be running at full capacity. In addition, it is the express aim of this requirement to prevent the development of a spot market. The relevance of this is that the development of a spot market would unbalance the traditional system. The role of the wholesale transmission companies would be especially endangered as a spot market would facilitate a direct contact between the end consumer and the producer with reduced margin for the wholesaler as a consequence. [...]* Nothing of this kind is foreseen by the VV Gas.

(108) A fourth element is that "[...]*".

(109) Finally, the VV Gas does not provide for access to storage, for access to quality adjustment services (conversion of LCV/HCV) nor for back-up.

(110) The parties point out in the reply that the final agreement on the VV Gas will require the support of end-users, the German cartel office and the German Government. With so many stakeholders involved in the process, the parties fail to understand the Commission's speculation that the end result will not facilitate both TPA and competition. The Commission has to make its assessment on the basis of the information that it has available. This information is the gas industry's reference case. Hence, to base an assessment on anything else would be speculation.

Conclusion

(111) The Commission concludes that the German long-distance wholesale transmission market constitutes a separate product market.

Low calorific value and high calorific value gas

(112) During the course of the investigation, several third parties have argued that in assessing the impact of the operation on the European gas markets a distinction should be made between "low calorific value" (LCV) and "high calorific value "(HCV) gas. The Commission agrees with the parties that LCV and HCV gas is part of an overall natural gas market. The Commission has reached this conclusion of the basis of demand-side substitution. In other words, a relative price increase of LCV gas of between 5 to 10 % would become unprofitable in view of the fact that consumers in the relevant area in Germany(11) could switch to HCV gas.

(113) The distinction between LCV and HCV gas has its origin in the discovery (1959) and exploitation (1963) of the massive LCV Groningen gas field in the Netherlands, the largest gas field in Europe and one of the largest in the world. This field meant the start of the natural gas industry in Europe. The whole consumption of natural gas was thus oriented on gas having the specifications of the Groningen field. However, the classification of LCV gas contains a broader spectrum than below or up to the Groningen calorific value. Based upon the definition for low calorific gas used in Germany (DVGW-code of practice G 260/I - Gas Quality) LCV gas is defined as having a Wobbe Index of up to 13 kWh/m3.

(114) The specifications of Groningen or LCV gas have an impact on the total downstream "gas column". High-pressure pipeline transmission (carrying gas over long-distances), underground storage facilities, low-pressure pipeline transmission (enabling the gas to be supplied at the appropriate low pressure for the burners used by households) and the installation by which the gas was consumed by the final consumer have been designed and can only run either uniquely for LCV or HCV gas.

(115) Later gas discoveries were of a different quality with a higher calorific value as the gas contains less inert nitrogen. In fact, LCV gas was only found in other onshore fields in the Netherlands and northwest Germany. Today, there are still specific LCV gas columns in the Netherlands, northwest Germany, a part of Belgium (in the provinces Antwerp and Limburg) and a part of France (Nord - Pas de Calais).

Demand-side substitutability: switch of the gas column from LCV compatible to HCV compatible

(a) A relative permanent price increase of LCV gas will speed up the ongoing substitution

(116) The parties have provided charts illustrating the continuous ongoing substitution of LCV gas consumption by HCV gas in Germany since 1975 based on industry statistics indicating both the absolute and relative volume of the different types of gas (HCV, LCV, coke-oven and other gas).

(117) Against this background, the question to be investigated is what the reaction of a wholesale transmission company would be to a price increase by LCV gas producers. The reaction of the wholesale transmission company will be influenced by its possibility to switch itself to an HCV producer and by the incentives coming from the possibility for its customers to switch to another wholesale transmission company that might supply cheaper HCV gas.

(118) Whereas it is technically easy to switch a whole LCV pipeline network to HCV, the main constraint on a wholesale transmission company to change its infrastructure is underground storage. This poses the problem that one needs to change the LCV gas in the storage to HCV gas. According to the parties, the conversion is simple and straightforward. According to Wingas, such a conversion takes time (typically three storage cycles and thus two years for the relevant facilities) and is costly (in view of the varying calorific content of the extracted gas when HCV gas is injected in a LCV facility).

(119) However, already before the end of the third storage cycle the extracted gas may be of HCV quality. Moreover, all wholesale transmission companies have the knowledge of "blending gas" (adding LCV gas to HCV gas to obtain a HCV gas of lower calorific value but within the HCV gas range, or vice versa) to achieve the desired specification. It may therefore be relatively easy for them to adjust the gas that they extract from their storage facilities during the conversion period by means of simple blending to keep it within the LCV or HCV specification. One can imagine that at the start they would be able to add LCV gas to keep the extracted gas within the LCV range, and that gradually they would add HCV gas to bring it to HCV specification. This would probably reduce the costs of the conversion considerably.

(120) On the basis of the above information, the Commission concludes that faced with a permanent relative price increase of LCV gas compared to HCV gas, the technical restrictions faced by the German LCV storage owners are not such that this would stop them switching. Therefore, the relative price increase contributes to the acceleration of the conversion that will have to take place sooner or later.

(b) The customers of the LCV gas supplying wholesale transmission companies have alternatives in the relevant German area to switch to HCV supplies by Wingas

Industrial customers and power generators switching

(121) The market investigation has confirmed that the switching costs for most industrial customers and power generators to adjust their burners are low as a percentage of their annual gas bill. It could, therefore, be economically feasible for an important industrial consumer or power generator to have a new specifically dedicated pipeline built linking the customer to a nearby (up to 50 km at most) HCV high-pressure pipeline. The question therefore is whether there are HCV pipelines in the neighbourhood that are owned by other companies than those that have an interest in LCV distribution. If this is the case, the risk of losing such clients to another wholesale transmission company will make the "incumbent" LCV wholesale transmission company more inclined to undertake the switch itself (if the price was increased by the producer) or would make a price increase by the wholesale transmission company unprofitable.

(122) With regard to industrial demand for gas, a distinction has to be made between Nordrhein-Westfalen (NRW) and Lower Saxony. In NRW, the gas sales per square kilometre are around three times higher than in Lower Saxony and the number of industrial clients per square kilometre is 2,5 times higher. In NRW, the Wingas "Wedal" and "Midal" pipelines are therefore probably in reach of a sufficient number of clients to make a switch possible. In addition, Wingas' underground storage facility is situated in Rehden, on the NRW/Lower Saxony border, thereby enabling the company to provide the necessary swing to its clients in NRW/Lower Saxony. In Lower Saxony, Wingas also has its HCV high-pressure pipeline network. It seems that the only important area that might not be in reach of this network is the Hannover area. However, the available scope is probably enough to make a price increase unprofitable.

(123) It remains, however, that a specifically dedicated pipeline needs to be built from the Wingas high-pressure HCV pipeline to the industrial customer. This takes time and costs money and has, in practice, only proven profitable if the client agrees to an exclusive supply arrangement with a duration of between five and 10 years. The incumbent supplier of the LCV gas is therefore in a position to increase his price over the prevailing HCV price by a margin up to the incremental costs of the new infrastructure. However, such agreements are not unusual in the industry so that the cost of the additional pipeline can be offset profitably as has proven the Wingas experience in other regions.

(124) Wingas argues that in Lower Saxony only a few customers with significant demand are located within reasonable distance of its high-pressure HCV pipeline so that its experience in other regions does not apply in what Wingas considers to be a distinct geographic market, namely the northern German LCV gas area.

(125) The Commission acknowledges that switching costs are not always low for industrial customers. [A company]* has indicated that industrial consumers that use natural gas as a feedstock for a chemical process may face costs of more than EUR 20 million. However, the Commission is not aware of such clients in the relevant German area.

(126) Overall, the Commission concludes that a sufficient number of German LCV industrial customers and power generators have the possibility to switch their demand to Wingas when faced with a permanent price increase of LCV gas to contribute to make such a price increase unprofitable.

LDCs switching

(127) LDCs supply households and other residential customers. They therefore require suppliers that are able to offer them high swing. They would only consider a switch if their new supplier is able to offer them HCV high swing gas. Wingas has its Rehden storage facility in the area and is, therefore, able to supply the swing.

(128) It remains that the distributor and/or the supplier must also absorb the costs involved in switching the households. These costs are estimated to be around EUR 60 per household on the basis of a detailed cost estimate provided, via the parties, by an experienced "household switching" company. On the basis of a typical household consumption of 80 MBTU/year, a local distributor price of EUR 3,4/MBTU and a typical household gas price of EUR 8/MBTU, a price increase of 5 % for LCV gas supplied by the LCV wholesale transmission company reduces the margin of the local distributor by EUR 13,5. A price increase of 10 % reduces the local distributor's margin by EUR 27. Therefore, the switching costs would be totally recouped by the local distributor within two to four years. As the typical duration of a supply contract between a wholesale transmission and a local distribution company is between 10 and 20 years, the 5 to 10 % price increase would be made unprofitable by LDCs switching to an alternative HCV gas supplier. Furthermore, once a household has been switched to HCV, it can safely run on the LCV gas until HCV enters the local distribution grid. The consequence is a temporary and marginal loss of efficiency; however, if this switch takes place in the summer months, the efficiency loss will be minimised.

(129) It has been argued that even if a switch from LCV to HCV gas would be possible, a LDC would not switch if it would become, by doing so, an "HCV island" in an LCV area. This would have important security-of-supply consequences that the customer might not be willing to take. Wingas considers this as the main reason why, despite offering discounts of 5 to 8 % (information from the parties) compared to the existing price level, it persuaded fewer than five local distributors (Stadtwerke) in Germany to switch from LCV to the HCV.

(130) This argument cannot be accepted in the present situation of a permanent relative price increase. In such a situation, the incentives for all the clients to switch would be the same so that, in the end, there would be no island situation anymore.

(c) The alternatives of the incumbent wholesale transmission company's customers will further increase the incentives for the incumbent to switch

(131) When facing a price increase of LCV gas relative to HCV gas, it is normal rational behaviour for a wholesale transmission company that concludes that a substantial part of its customers have the possibility to switch to a competing wholesale transmission company to defend its position. The company will therefore ensure that it itself is also able to offer the cheaper HCV gas. Therefore, the "incumbent" wholesale transmission company will speed up the switch itself.

Conclusion with regard to demand-side substitutability

(132) For the purposes of this procedure, the Commission concludes that a permanent relative price increase of LCV gas would be unprofitable in view of the fact that (a) sooner or later the LCV gas chain has to be converted on HCV gas, (b) that such a price increase will speed up the conversion, (c) that there are alternatives in the relevant German area in the form of HCV supplies by Wingas and (d) that this knowledge will further increase the incentives for the LCV wholesale transmission companies to switch themselves their consumption area.

(133) However, it remains that the costs of switching represent a competitive advantage of the transmission company that is able to offer the prevailing specification as it increases the threshold to change to another supplier.

Relevant geographic market

(134) The parties consider that, in general, the wholesale transmission markets are national. They indicate that distribution has traditionally been organised largely on a national basis through national or regional operators. However, the parties consider that the trend towards cross-border purchases following the advent of the Gas Directive cannot be ignored. The parties consider that attempts to increase post-merger prices in individual Member States would be defeated not only by competition at the national level, but also by increased cross-border purchases by wholesale transmission companies, local distribution companies, power generators and large industrial users.

(135) As the ownership of the infrastructure is still organised on a largely national basis and as the conditions for third-party access will remain essentially fixed on a national basis, the Commission considers that the markets will remain in the near future at most national.

(a) Netherlands

(136) For the reasons indicated in the previous point, the Commission agrees with the parties that the Dutch wholesale transmission market is national.

(b) German long-distance wholesale transmission market(s)

(137) With regard to Germany, there are indications that, at present, the markets may still be regional. The regions would be defined by (a) the previous existing, but now illegal, demarcation agreements such as those that Ruhrgas had concluded with BEB and Thyssengas, and (b) the ownership of the long-distance high-pressure transmission pipelines. Despite the fact that the demarcation agreements are illegal since April 1998, only two agreements with a German client outside the long-distance transmission company's own regional territory have been concluded, both by Ruhrgas for annual supplies of [...]* MCM each and via the construction of a new pipeline. [...]*

The old demarcation regions are still relevant in view of the fear of retaliation

(138) The internal documents of [...]*, [...]* and [...]* confirm the continuing relevance of the old demarcation regions in view of the fear of retaliation.

(139) [...]*

(140) [...]*(12)

(141) [...]*

(142) [...]*

(143) [...]*

(144) [...]*(13)

(145) [...]*

(146) [...]*

Definition of the regions

(147) The regions would thus consist of the "Thyssengas"-region (western part of Northrhine-Westphalia along the Belgian/Dutch border), "BEB"-region (Hamburg, Schleswig-Holstein and parts of Bremen and Lower Saxony), "VNG"-region (Mecklenburg-Vorpommern, Brandenburg, parts of Saxony and Saxony-Anhalt - a region where Ruhrgas does not have its own pipeline network) and the "Ruhrgas"-territory (the remainder of the "Alte Bündesländer" and the parts of Saxony and Saxony-Anhalt serviced by a short-distance wholesale transmission company that is jointly owned by Ruhrgas and VNG).

Position of some other long-distance wholesale transmission companies

(148) Mobil has never had an "own region" nor high-pressure pipelines, but was able to reach its customers by way of third-party access agreements with [...]*.

(149) Wingas competes, by means of its own pipeline network, in each of these territories and most short-distance wholesale companies are in reach of its pipeline network (corridor of at most 50 km). However, on that basis, it cannot be concluded that the competitive conditions within the whole country are equal. [...]* the respective long- and short-distance wholesalers differentiate their prices depending on the fact whether or not the customer has an alternative in the form of supplies by Wingas.

The proposed German industry TPA regime (VV Gas reference case) will not influence the geographic setting of competitive conditions

(150) It results from the description of the VV Gas in the product market section that the Commission does not consider that the VV Gas will make it possible to import gas in competition with the incumbents.

(151) For the reason indicated in that section with regard to the built-in limitations of the VV Gas concept and the reference case of the gas industry such as (a) the general difficulty to assess whether capacity is available, (b) the fact that with a minimum duration of one year the winter peak is always taken into account when assessing the free capacity in a pipeline, (c) the difficulties resulting from the specifications of the gas (caloric value, pressure and so forth) and (d) the limited scope of the services offered, the Commission considers that the VV Gas is not sufficient to consider, from a prospective analysis point of view, that the market is national. In addition, the Commission takes into account that in case of a dispute between a party that requests TPA and a party that refuses TPA, the procedures before the competition authorities and/or the courts might take several years before a "precedent" case is settled.

Conclusion

(152) On the basis of the above, the Commission considers that the wholesale transmission markets in Germany might still be regional, following the former demarcation lines. However, it may not be necessary, for the purpose of the present decision, to decide the geographic definition of the long-distance wholesale transmission market within Germany as the concentration also leads to the strengthening of a (collective) dominant position if the long-distance wholesale transmission market were national.

(153) The parties have stated in the reply that the market is national, not regional. They indicate that gas prices are determined by competing fuel, not regional location. However, this is in contradiction with the information obtained by the Commission in the market investigation that prices differ also on the basis whether or not a client has an alternative supplier (gas to gas competition). The parties also state that a forward-looking analysis must take account of the recent elimination of demarcation and the impending industry agreement on negotiated third-party access. However, there remain too many uncertainties to conclude that the final agreement would lead to a national market where competitive conditions are the same.

Position of the market participants

(a) The Dutch wholesale transmission market

1. Relationship between Dutch gas producers and Gasunie

(154) In 1947, Exxon and Shell formed a 50/50 JV, called Nederlandse Aardolie Maatschappij (NAM), with the object of exploring and producing hydrocarbons within the Netherlands. Following NAM's discovery of the large Groningen gas field in 1959, the Netherlands Government organised the Dutch gas industry to reflect the Groningen field's strategic importance for the Netherlands economy. To this end, the Netherlands Government in 1963 entered into an agreement with Exxon, Shell and NAM, under which NAM is assigned the responsibility to develop and produce the Groningen concession for the account of the Groningen partnership in which NAM has 60 % and the Netherlands Government, via EBN, 40 %. In addition, Exxon, Shell and the Netherlands Government formed a company called Gasunie, which was entrusted with the marketing of all Groningen gas. The Netherlands Government holds a 50 % equity interest in Gasunie (10 % direct - 40 % via EBN), while Exxon and Shell each hold 25 %. Finally, the Netherlands Government entered into a private law agreement with Gasunie under which Gasunie must seek the Government's approval for certain commercial decisions.

(155) Since 1959 NAM has obtained production licences for other Dutch on and off-shore gas fields and roughly 50 % of its current production comes from these other "small" fields (compared to Groningen). The parties have indicated that most of these concessions are also produced for the benefit of partnerships in which EBN generally has a 40 to 50 % participation. The gas of these fields has been sold to Gasunie. In addition, all future discoveries by NAM must be sold to Gasunie as a consequence of [...(14)]*. In total, NAM accounts for 75 to 80 % of total Dutch gas production (in view of EBN's equity interest in NAM's production, NAM accounts for about 45 % of production on a net equity basis). EBN has also consistently marketed all its equity interests via Gasunie. [...]*.

(156) Until 1994, Dutch producers were obliged to sell all gas that was destined for the Dutch market to Gasunie. Dutch producers could sell themselves to the export market, although the prices were and are still controlled by the Government. Furthermore, Gasunie is obliged to buy gas from the small fields prior to production at financial conditions fixed at the start if the producer has chosen to offer the gas to Gasunie. [...]*

(157) It appears that, in general, the Netherlands Government would not give its approval on the price in an export contract of Dutch gas if this price were below the Gasunie "net-back" price, called the "norm inkoop prijs" (NIP or normative buying price). In this way, the Government ensures that it receives its share of the "gas cake".

(158) [...]*(15)

(159) NAM owns two of the three Dutch underground storage facilities (depleted gas fields) which it has leased for 100 % to Gasunie. The third facility, operated by BP Amoco, is also leased totally to Gasunie. Therefore, only Gasunie is able to offer underground storage facilities in the Netherlands. Whereas there are a couple of depleted Dutch gas fields that could be turned into underground storage facilities servicing the Dutch market, it is not likely that these facilities will be developed by others in view of the risks involved. Such risks relate to the required investment and to the fact that Gasunie could always lower its tariff, thereby making such investment unprofitable. It is also noted that [...]*.

2. Gasunie's corporate governance structure

(160) Gasunie is owned 50 % by the Dutch State and 25 % each by Exxon and Shell. Decisions are taken with [...]* majority voting. There are no specific shareholder agreements. Therefore Exxon has no de jure control over Gasunie within the meaning of the Merger Regulation.

(161) As to de facto control, the parties argue that there is no common interest between Exxon and Shell. [...]*. However, for the reasons indicated below, it is not necessary to decide whether or not Exxon has de facto control over Gasunie within the meaning of the Merger Regulation.

3. Gasunie's gas selling position in the Dutch market

(162) Gasunie is the dominant Dutch transmission company with around [...]* % of total sales. Gasunie explicitly recognises its dominant position in the introduction of its new tariff system. [...]*(16). Furthermore, according to Gasunie's "Plan of Gas sales 1999", Gasunie will supply [...]*.

(163) Gasunie owns or has exclusive rights to (a) the whole Dutch high-pressure pipeline grid (with the exception of one line in the south of the Netherlands by which British gas is imported), (b) all processing and blending facilities, (c) all (underground and Liquid Natural Gas) storage capacity.

(164) It also appears from several [documents]* that Gasunie faces and will continue to face little competition. These documents, quoted in the following points, support Gasunie's internal assessment that it is a company with a dominant position.

(165) [...]*

(166) [...]*

(167) [...]*

(168) [...]*

(169) [...]*

4. Mobil's position on the Dutch market

(170) Mobil is one of three actual competitors. It has, according to the parties, a [less than 5]* % share on the total market. Statoil (or the Norwegian joint negotiation committee that markets all Norwegian gas) has an estimated 4 % market share by means of its supply contract to an important power generating plant. EnTrade, a trading company of the Dutch RDC Pnem/Mega, is the other competitor with a 4 % market share resulting from the sale of British gas to industrial consumers and a power generator within the reach of its partly owned Zebra HCV pipeline in the South of the Netherlands. It has a TPA transport agreement with Gasunie for the supply to one customer.

(171) Mobil's position in the Netherlands stems from its European gas sales strategy [...]*. This European strategy will be described in the following paragraphs. This description is also of relevance for the assessment of the position of Mobil on the German market

Mobil's European gas sales strategy

(172) [...]*

(173) [...]*

(174) [...]*

(175) [...]*

(176) [...]*

Mobil in the Netherlands

(177) [...]*(17)

(178) [...]*

(179) [...]*

(180) [...]*

(b) The German long-distance wholesale transmission market(s)

Market participants

(181) In the product market definition section, the Commission has reached the conclusion that the long-distance wholesale transmission market is a separate product market where the entry depends on the goodwill of the incumbents. It has also been concluded that new entry by means of a new own infrastructure investment is not likely to occur.

(182) The incumbents are those companies that (a) purchase gas from foreign producers, (b) are able to transport this to their customers by means of a high-pressure pipeline network, (c) are able to provide swing and (d) are able to provide other related services. They either perform these services on the basis of their own investments or because they have received for parts of them third-party access of the others.

(183) Ruhrgas, BEB, VNG, Thyssengas and Wingas are the most important players on the market. They all perform the above services by means of their own investment.

(184) Exxon is an active player on the German market by means of its long-standing 50/50 JV with Shell, BEB. Exxon acknowledges that it has joint control together with Shell over BEB within the meaning of the Merger Regulation. Exxon is also active on the relevant market by way of its 25 % share of Thyssengas. The remainder of the shares is held by Shell (25 %) and RWE (50 %). Exxon acknowledges that it has joint control with RWE and Shell over Thyssengas within the meaning of the Merger Regulation.

(185) Ruhrgas is the most important German long-distance transmission company. Both Exxon, through BEB, and Mobil are shareholders of Ruhrgas. BEB's shareholding accounts for 29,5 %. The largest part of the voting rights attached to this shareholding, (25 %) is voted directly; the remainder (4,5 %) is part of the "Schubert pool" within Ruhrgas. The Schubert pool accounts for 15 % of the votes in Ruhrgas. Members of the pool are Mobil (7,4 % share), BEB (4,5 %), BPAmoco (0,5 %) and Preussag (2,6 %). The votes must be expressed as one block and the Schubert pool rules stipulate that no member can have more than [...] % of the voting rights within the pool. It is claimed by the parties that, as a consequence of these rules, the current voting rights of BEB in the Schubert pool would be attributed, post-merger, to BPAmoco and Preussag. It has to be noted that the Schubert shareholders have contracted to supply [...]* % of their proven domestic reserves additions to Ruhrgas. These supplies to RG are transported by [...]*.

(186) Ruhrgas is formally controlled by the "Bergemann pool", a shareholder pool representing 59,76 % of the votes. The pool groups the 25 % shareholding of BPAmoco together with the votes held by a group of German coal and steel producers (that are also very often active in electricity production and distribution). These complicated rules must prevent that Ruhrgas would be controlled by multinational oil and gas groups.

(187) [...]*(18)

(188) Furthermore, in view of the shareholders agreement between BEB and Ruhrgas, a [...]* % vote is required if a question is "essential to BEB". This gives BEB therefore a veto for all questions that are essential to it. The parties have indicated that this clause has never been invoked. [...]*

(189) [...]*. It therefore seems that, despite the absence of de jure control, the oil companies have de facto influence on Ruhrgas.

(190) Verbundnetz Gas (VNG) is a long-distance wholesale transmission company active in the new German Länder. It was founded in the 1960s and privatised after the German re-unification. Its current shareholders are Ruhrgas (36,8 %), Wintershall (15,8 %), local communes (15,8 %) and BEB (10,5 %). In addition, Statoil, Erdöl-Erdgas Gommern, PreussenElektra and Gazprom each hold 5,2 %. It follows that all VNG's shareholders with the exception of the local communes are gas producers and/or long-distance wholesale transmission companies.

(191) Wingas is a 65/35 % JV between Wintershall (a BASF subsidiary) and Gazprom.

(192) [...]*

(193) EWE is de facto a short-distance wholesale transmission company as it is not in the business of re-selling imported or own-produced gas to other companies operating a high-pressure grid (long and short-distance wholesale transmission companies). However, it imports directly from Gasunie a substantial part of its gas sales via its own high-pressure (LCV) pipeline. It is, therefore, considered to be a long-distance wholesale transmission company.

Market position

(a) Local

(194) BEB has indicated that it has a market share of [40 to 50]* % in northern Germany (Schleswig-Holstein, Hamburg, Bremen and Lower Saxony. However, this "Northern Germany" region is larger than the BEB demarcation region that only comprises parts of Bremen and Lower Saxony. The remainder is "Ruhrgas territory", whereby Ruhrgas had concluded in turn a demarcation agreement with Erdgas Münster. It therefore results that the BEB market share in its demarcation region is in excess of [40 to 50]* %.

(195) [...]*

(196) [...]*

(197) RG's strategy paper from October 1998 indicates that as a consequence of GTGC, it cannot maintain its 100 % share in its area. Although no precise data are available, the fact that RG accounts for around [+ 50 %]*of the supplies to the short-distance wholesale transmission companies operating in its area is the best available proxy for its market share.

(198) VNG has, even according to the parties' reply to an Article 11 request, a [9 to 100]* % market share in 1997. TG has according to the parties [70 to 80]* % in 1997. [...]*

(b) On the German market

(199) All sales data in this section refer to 1997. Total gas imports in Germany account for 75,6 billion cubic metres (BCM).

(200) BEB produces half of the German gas accounting for [...]* BCM of production. It also purchases another [...]* BCM from Gasunie, Gazprom, DONG (the Danish state's oil and gas company), from the GFU (the Norwegian gas sales entity) and a small share of other German producers. Thyssengas imports [...]* BCM. Mobil imports [...]* BCM of its Dutch equity production and from Norway. Mobil is also a German gas producer (some [...]* % of German production, accounting for [...]* BCM). Ruhrgas imports [...]* BCM from the Netherlands, Norway, Denmark and Russia. It purchases [...]* BCM of German-produced gas. VNG imports [...]* BCM. Wingas imported 6,9 BCM. EWE imports, as indicated above, gas from Gasunie. This volume accounts for [...]* BCM.

(201) The abovementioned import figures give the long-distance wholesale transmission companies the following market shares: RG [50-60]* %, BEB [10 to 20]* %, VNG [10 to 20]* %, Wingas [0 to 10]* %, TG [0 to 10]* %, Mobil [0-10]* % and EWE [0 to 10]* %.

Mobil's German strategy

(202) Mobil has described in its European strategy paper its position in Germany as follows:

[...]*

(203) [...]*

(204) [...]*

Competitive assessment

(a) Dutch wholesale transmission market

The parties and Gasunie acknowledge in their internal documents that Gasunie is dominant and will remain so

(205) On the basis of the documents described in the section on the position of the parties in the market, it can be concluded that Gasunie is dominant and will remain so (its current market share - [80 to 90]* % - is likely to remain at the same level for the next [...]* years).

The competition pressure of the other actual competitors remains limited

(206) Apart from Mobil, there are two other actual competitors, Statoil and Entrade. Statoil has indicated that "its policy in the Dutch (and German) gas wholesale distribution markets can in short be characterised as a 'wait and see' approach." [...]*.

(207) The "direct sales" by Statoil to the Eems plant is the only sales contract ever done directly by Statoil so that, on the basis of the above, the Commission considers that, overall, Statoil cannot be considered as a competitor that will remain active on the market. [...]*.

(208) The other actual competitor is Entrade. Entrade has contracted [...]*. Entrade's sales potential along its pipeline seems to be more or less exhausted. The potential to increase further the sales via TPA with Gasunie seems to be limited [...]*.

(209) Mobil has annual gas sales of [...]* under contract. Around [...]* is of British origin, the remainder from Mobil's north Friesland concession (Anjum). One of these contracts is a [...]*. Mobil has indicated that it has no more uncommitted high swing of own production.

Potential competition

(210) [...]*

(211) The parties refer to the proximity of the existing Zeebrugge LNG terminal with spare capacity and connecting pipelines that make immediate entry of LNG possible into the Netherlands and indicate, in their reply, that Sonatrach, the Algerian gas company, could thereby enter the Dutch market. The parties did not provide data concerning the existing spare capacity in the Zeebrugge terminal and connecting pipelines. However, new LNG gas supplies are much more expensive (cost of 16 to 19 ct (HFL)/m3) than pipeline supplies and there is no indication of vertical integration by Sonatrach in any other European gas market. Therefore, potential entry of Sonatrach in the Netherlands is not considered to be very likely.

(212) The parties also indicate that the recent TPA agreement that Gazprom secured with Ruhrgas facilitates the possible entry of Gazprom into the Dutch market. Whereas this agreement might facilitate the possible entry, it does not make such an entry more likely. [...]*. In the reply, the parties have indicated that the potential relief from the parallel sales agreement is only for direct marketing by Gazprom to an existing Gasunie customer. However, all customers except those of Statoil, Entrade and Mobil (representing [80 to 90]* % of the market) are Gasunie's existing customers, so that the protection is substantial.

(213) In the reply, the parties indicate that large continental wholesale transmission companies possess gas at various points along the Dutch border. Distrigaz, Thyssengas, Wingas, SNAM, Gaz de France, BEB and Ruhrgas all have supplies which can be potentially sold into the Dutch market, and no parallel sales agreements exist between Gasunie and these companies for such sales in the Dutch market. It is true to say that all these companies possess gas at various points along the Dutch border as all of them except Wingas purchase gas from Gasunie. Even if the contract would allow these companies to re-sell the Gasunie gas in the Netherlands or even if they have access to nearby gas from other sources to sell in the Netherlands, it is unlikely that these companies would "attack" their supplier in view of the risk for retaliation by Gasunie [...]*.

(214) Even if it cannot be excluded that one or more of the above companies or any other companies might enter the Dutch market, the Commission can conclude that the scope for development of potential competition is quite minimal as Gasunie itself does not expect to lose much more market share anyway [...]*. This estimate was made in the full knowledge of the own TPA tariff structure and the Netherlands Government's liberalisation plans.

(215) With regard to the Gasunie tariff, the Commission recognises that all possible services necessary to operate a gas business in the Netherlands are included in the tariff. In this way, the scope of the tariff contrasts with the rather limited "pipeline transport-only" approach taken by the German gas industry in the ongoing VV Gas. However, these tariffs do not make such an entry more likely. The tariff is based upon the customer's alternative cost to provide the service itself and is thus calculated on Gasunie's replacement costs for the infrastructure. Whereas the Commission recognises that the tariff passes Gasunie's economies of scale on to the customer, [...]*.

(216) [...]*

(217) [...]*

Mobil is in a unique position

(218) [...]*

(219) The parties argue that Mobil has no unique strengths to compete in the Dutch market and that any new entrant can replicate and exceed Mobil's Dutch market position. The parties indicate that any Dutch producer with uncommitted reserves has several marketing options: export, sell to a trader, to a Dutch end-user, an RDC or to Gasunie. Whilst this is true, it has to be noted that all current reserves are and have been committed to Gasunie except a part of the reserves of Mobil. Mobil has [...]* BCM of proven reserves in the Netherlands of which [...]* BCM are not yet committed. In addition, Mobil has another [...]* BCM of probable reserves. [...]*. Again, this makes Mobil "unique".

(220) In addition, reference is made to Mobil's strategy which clearly indicates [...]*.

The merger will eliminate Mobil as a competitor

(221) A merger between Mobil and Exxon would in normal circumstances lead to a greatly diminished incentive for Mobil to compete against Gasunie. Exxon has an important and lucrative stake in Gasunie and would suffer from lower returns resulting from price competition between two of its ventures. However, in view of the contractual arrangements on which Gasunie has been founded, Mobil will not be allowed to continue competing against Gasunie.

(222) Exxon's 1963 agreement with Shell and the Netherlands Government requires the sale of all Exxon's Dutch gas to Gasunie. Therefore, Exxo