Opec and the temporary redressing of market equilibrium After the counter-shock of 1986, Opec experienced a decade of great internal difficulties.
The precarious discipline of production reasserted in 1987 - constantly undermined by the fact that many members sold amounts exceeding their quotas - did not succeed in giving the Opec countries revenues in line with their expectations.
It did, however, make it possible to keep oil prices throughout the 1990s within a fairly steady band ($15-20 a barrel for Brent crude), compatible with the investments made by international oil companies in non-Opec areas (where production costs were higher).
Opec members' hard-won sacrifices therefore resulted in a steady erosion of their market share, to the benefit of non-Opec (particularly North Sea) producers.
In vain, in those years, did Opec try to convince the governments of the consumer companies and the private oil companies to share responsibility for the stability of the market, the former by forgoing part of the substantial tax levy on the crude oil barrel (a $20 barrel of Brent normally carries a tax of $70, especially in the European countries), and the latter by giving up the policy of over-production in non-Opec areas.
This strategy of dialogue encountered a limit: the need, especially for the companies listed on the stock exchange, to grow constantly, increasing production and reserves where they are available.
Of course, the Gulf countries, above all Saudi Arabia, are the ones that have paid the highest price in terms of market share and development. Only in the middle of the decade did the consolidation of the strong increase of oil demand in south-east Asia produce an outlet for Gulf production.
In 1990 the oil produced in the Gulf was exported equally in both hemispheres, but by the end of 1996 two thirds of these exports were going to south-east Asia.
Meanwhile, some members of Opec became totally undisciplined with respect to the quota system, jeopardizing the very nature of the cartel. The most obvious case was that of Venezuela, whose production levels rose almost 1 mb/d above the level set by Opec: in 1996 the country embarked upon a development program intended to double oil production within a decade.
It was in this context that the Opec countries, under pressure from the Saudis, decided at their Jakarta summit in November 1997 to raise their total production ceiling by 10 percent, to adapt it better to reality and to enable the Gulf countries to increase their exports to south-east Asia, keeping pace with the local increase in demand.
Unfortunately, Opec's decision came at the very time when the Asian crisis that had been blowing up since August burst into gale force. The lower demand determined by the crisis and the increased supply decided upon by Opec were the factors mainly responsible, in the autumn and winter of 1997-98, for the subsequent price collapse, which brought Brent crude down to less than $10 a barrel (at the beginning of 1999).
In 1998, while Opec was striving to reach an internal agreement to cut production again, Saudi Arabia began to outline a prospect of reopening its upstream to foreign investment, and asked leading international companies to present across-the-board development projects (including the gas, refining and petrochemicals sectors, as well as oil) to the Saudi government.
This prospect probably influenced Opec's attitude to no small extent: being the world's biggest producer and holder of reserves, by freeing all its potentialities Saudi Arabia would have shattered any attempt at controlling prices, making them fall to levels unsustainable for many countries and companies (the Kingdom produces crude oil from only about 10 of the 80 available fields, and in the last twenty years for every barrel of oil produced it has discovered three completely new ones - according to official statements by the Saudi oil minister - with estimated discovery costs in the region of 10 cents per barrel and production costs of $1.50 per barrel).
For months this hypothesis formed the backdrop for the negotiations on a substantial production cut; these led to the Opec agreement of March 1999, in which Opec members undertook to bring their total production down to 23 million b/d.
The respect of the limits set, and the parallel decision of non-Opec countries such as Norway, Mexico, Oman and Russia to make smaller cuts, made prices pick up rapidly and then soar to over $30 per barrel (for Brent crude) by the end of March 2000.
The success of Opec's cuts was rather unexpected, because of the scant internal discipline and lack of cohesion on objectives that have characterized the Organization in the last 20 years.
Opec's task in the coming years will be particularly difficult. It must succeed in keeping prices high enough to sustain its members' minimum budget requirements; at the same time, those prices must be low enough to foster the growth of world demand and cancel the production prospects of other parts of the world, so that Opec's market share can start to grow again and its members can increase the volume of their sales, and hence their income.
In this scenario, it is possible to envisage a gradual, balanced opening of the Gulf countries to upstream investments by international companies; indeed, to some extent this is already happening.
The technological factor and the rise of non-Opec production
Technology has played a major part in the steady erosion of Opec's contractual power.
Innovations like 3D seismic, which has made it possible to identify with greater certainty the existence of fields in the exploration phase, horizontal drilling, which has increased their recovery rate, and the use of vessels with greater operational flexibility for oil extraction and production in deep waters, instead of the conventional fixed platforms, have radically changed the potential of the oil and gas industry, by starting a technological revolution in the 1980s.
Generally speaking, this technological leap forward has made it possible to:
increase the average recovery rate of the world's fields from just over 20 percent in 1970 to the current 35percent;
identify fields with greater certainty and exploit them with greater precision and at lower cost;
reduce the time taken to develop the fields. At the beginning of the 1970s, it took on average 15 years to develop a North Sea oil and gas field; today the majority of fields are developed in 2-3 years at the most.
The West African deep offshore is now becoming the frontier zone, where the application of the latest technologies has already cut the development time to 18 months.
Other technologies, such as production systems that can be used in deep waters, are playing a role that was unthinkable in the past.
Oil company strategies, past and present
The two oil shocks of the 1970s, when the price of crude climbed to over $40 a barrel, and the counter-shock of 1986, when it plummeted to below $10, profoundly changed the way in which international oil companies operate.
The most far-reaching restructuring of the oil companies began in the USA in the second half of the 1980s and in Europe in the 1990s.
The cardinal points of the revolution in the oil industry were:
the concentration of the core business and the disposal of non-strategic assets;
increased efficiency;
cost-cutting, organizational streamlining and reduction of hierarchical levels;
reduction of geographical diversification and concentration on core areas;
outsourcing of non-core activities;
streamlining of logistics and stocks;
emphasis on technology.
Even so, analyses of listed companies in the USA show that between 1984 and 1994 (roughly the period of the big restructuring operations) the oil industry did not create value, and its appreciation in terms of market value was far lower than that of many other industries, primarily food and beverages and pharmaceuticals, which were then overtaken by the hi-tech sector.
The main oil companies reacted to this situation by considering the strategic lines adopted in the restructuring phase as permanent elements in their way of doing business and by emphasizing ambitious objectives for the increase of production and reserves.
The latter is closely connected to the need to halt the constant decline of the reserves/production ratio that occurred between 1980 and 1996. In the last three years before the crisis (1995-97) all the main international companies set production growth targets in the order of 4-5 percent per annum and embarked upon substantial investment programs in exploration and the acquisition of reserves already discovered.
This expansionist policy, however, came up against the scarcity of promising mineral assets existing in the world. As they were excluded from exploring in the Arabian Gulf and many of the Opec countries, oil companies have had to concentrate on the Caspian (which some of the first newcomers left after years of useless waiting), West Africa and the US Gulf, as well as China, Latin American and other areas with less attractive geological prospects and higher costs.
The "thirst for reserves" led to fierce competition: in 1997, for example, the first tenders for marginal fields in Venezuela (a member of Opec that up till then had excluded foreign competitors from its upstream) were won by small companies (the Chinese National Petroleum Co., Lasmo and Repsol) desperately needing reserves, at prices far higher than those offered by the majors.
Consequently, while the contractual terms offered by the producing countries became less favorable for the companies, the costs of reconstituting the reserves in the most accessible areas increased.
At the same time, the big effort begun by the oil industry in the mid-1990s revealed some structural problems of the non-Opec oil market:
exploration has shown how difficulty it is to find large assets. With few exceptions, the fields discovered in the 1990s were small or medium-sized, whereas hardly any giants were found.
The result is that less than a quarter of what the world consumes every year is replaced by new reserves;
production in the North Sea - the area of the oil industry's greatest development in the 1990s, is destined to decline;
the productivity of recently discovered fields - especially in proportion to their size - tends to be lower than that of fields discovered earlier.
the new frontiers discovered by the industry - the Caspian and the deep offshore of West Africa and the US Gulf - have big political, legal, technological and financial drawbacks;
continuous pressures in the downstream sector, due to environmental concerns, surplus production and narrow margins, have occasioned ongoing rationalization and concentration measures.
Even before prices started their steep descent in 1998, the need to cope with difficult growth strategies and constantly to cut costs and increase efficiency, drove the oil companies to seek ways of becoming more competitive. This is how John Browne, the head of BP,
explains the decision to acquire Amoco, which he dates back to BP's first talks with Amoco in 1996, when crude oil prices were high.
Mergers and acquisitions
Concentration of an intensity and on a scale unique in the history of the oil industry began only in August 1998, however, with the announcement of the BP-Amoco merger (see Table 3).
Tab. 3 Main mergers and acquisitions in the
oil industry since 1998
Acquirer Prey Date (announcement) Value ($bn)
BP Amoco 8-1998 56
Exxon Mobil 12-1998 77
Total *(1) Petrofina 12-1998 12
Repsol *(2) YPF 2-1999 15
4-1999
BP-Amoco Arco 3-1999 27
Norsk-Hydro *(3) Saga 5-1999 2.6
TotalFina Elf 9-1999 52
(1) Total acquired 47 of Fina's capital.
(2) Repsol initially acquired a 15 percent share in YPF put up for sale by the Argentine State. It subsequently launched a public acquisitions offer for the residual capital.
(3) An offer made by NH was countered by a Statoil offer. NH eventually won, but 44 percent of Saga's capital is still in the hands of the State (Norway).
The operations in question (which were followed by others of different sizes) revolutionized the set-up of the world oil industry, creating a big gap, in terms of capitalization, income, production and reserves, between the first three groups and the other oil companies listed on the stock exchange (see Table 4).
Tab. 4 The main listed
Oil companies
Company Reserves
(bn boe) Production
(bn boe) Market Cap. (1)*
($bn)
Exxon-Mobil 20,95 4,4 279
Shell 20,45 3,7 213
BP-Amoco (2) 19,5 4 195
TotalFina-Elf 9,4 2 96
Chevron 6,3 1,5 57
Eni 5,22 1,03 44
Texaco 4,7 1,37 30
Repsol-YPF 4,44 1,01 25
*(1) Resulting (or pro-forma) at 12.31.99
*(2) Arco is not included, because of the problems that arose with the US Antitrust.
This process was motivated by the will to reduce costs by making scale economies, to increase production and reserves, to improve strategic positioning in global terms, to gain access to new areas and, last but not least, to reduce competition in key geographical areas.
The size of a company seems to be closely correlated to the level of the unitary cost of reconstituting its reserves (i.e., the finding and development costs): the bigger the companies, the lower the cost per barrel reconstituted or developed.
The concentration under way is the final phase of the rationalization begun in the last decade, and represents a qualitatively different reaction to the structural problem of the relative scarcity of good mineral assets.
Conclusions: the basic problems of the oil industry
The oil industry finds itself in a very complex situation, which cannot be dealt with by mergers and acquisitions on their own. The maturity of the sector and its limited possibilities for growth and creating value are problems that have characterized the oil industry for years, as is shown by an analysis of the market performance and value added indexes of various industrial sectors.
To attribute the market's luke-warm attitude to the oil industry today to the boom of hi-tech and telecommunications industries might create dangerous illusions. Although the latter phenomenon may be largely due to speculative and irrational factors, the problems of the oil industry are of earlier date and destined to remain, even if the boom leaves room for an inversion of trend in the markets.
Indeed, they will probably increase, under the impulse of liberalization, excessive competition, the entry of dynamic new commercial operators, environmental issues and so on.
Not surprisingly, investors are pressing the oil industry to adopt a strict discipline of the use of capital, spending only where the return on invested capital is sure to be in line with market expectations, or refraining from spending and opting for the return of its large cash flows to the investors, in the form of extraordinary dividends or share buy-backs.
To prevent these pressures from becoming irresistible, the oil sector (and gas too), must show the market that it can exploit the capital entrusted to it better than individual investors can. But following this course requires courageous, radical rethinking of the structure of the industry, its sphere of action and its more immediate possibilities for using the available capital, and the potential of integrating industrial and financial strategies, even when they seem to be separate.
Qualities of crude
Not all crude is the same. Its quality depends on its lightness (lower density) and sulfur content. Lightness is measured in API (American Petroleum Institute) degrees: the higher the API degrees, the lower the density and the lighter the crude. The API scale ranges from just under 10° (e.g. heavy Venezuelan crude oils, similar to bitumen) to more than 60°.
Heavy crudes range from 10° to 25° API; medium and light crudes go from 26° to 40°; and extra-light crudes start at 41° and continue upwards.
Examples of light crude are Brent (30° API), Western Texas Intermediate (WTI) (39°), Nigerian Bonny Light (36°) and Saudi Arabian Light (34°).
The sulfur content makes it possible to identify three categories of crude: sweet (sulfur less than 0.5 percent of weight), medium sour (sulfur between 0.5 percent and 1.5 percent) and sour (sulfur greater than 1.5 percent).
These categories date back to the early days of oil exploration in the USA, when oil was literally tasted. As a greater degree of sulfur makes the taste sourer, oil men started to use the terms sweet and sour to indicate the quality of the crude discovered. In terms of sulfur content, Libyan crude is one of the best in the world and is also extra-light.
Broadly speaking, with various exceptions, light and sweet crudes are found in the Middle East, North America and the North Sea. Former USSR crudes are medium-heavy and Latin American crudes are heavy.
Differences in quality are very important for the finished products to be obtained from them (gasoline, gas oil, fuel oil, kerosene, etc.) and hence for the refining industry.
In general, light crudes with a low sulfur content give better yields in terms of light products, such as gasoline.
Source: ENI.
© 2000 Mena Report (www.menareport.com)
