CAPITAL LIMITATIONS, ENVIRONMENTAL MOVEMENTS MAY INTERFERE WITH EXPANSION PLANS

Ibrahim A.H. Ismail
Organization of the Petroleum Exporting Countries (OPEC)
Vienna, Austria

Obtaining capital is a critical element in the production expansion plans of OPEC member countries. Another issue that may impact the plans is the environmental taxes that may, reduce the call on Opec oil by 5 million b/d in 2000 and about 16 million b/d in the year 2010.

This concluding part of a two part series (Part 1, OGJ, May 2, p. 95) discusses the expansion possibilities of non Middle East OPEC members, OPEC's capital requirements, and environmental concerns.

NON MIDDLE EAST OPEC

Non Middle East OPEC includes Algeria, Gabon, Indonesia, Libya, Nigeria, and Venezuela. Venezuela, because of a substantial resource base, has the best possibility for substantially upping production capacity.

ALGERIA

Algeria's proved oil reserves are estimated at 9.2 billion bbl.

The country currently produces 0.75 million b/d from the giant Hassi Messoud oil field and several medium to-small fields. Annual production peaked at 1.16 million b/d in 1978, declining to a low of 0.63 million b/d in 1987 before reaching 0.75 million b/d at the end of 1992 and in 1993.

To boost production and increase recoverable oil reserves, the Algerian Energy Ministry has confirmed that Algeria intends to vigorously pursue a policy of cooperation with foreign oil companies to systematically exploit the country's hydrocarbon potential. Such a partnership will enable Algeria both to explore its territory more thoroughly for new fields able to take advantage of the latest technology, for enhancing recovery from existing fields.

The country expects that a combination of joint ventures with foreign firms and efforts from its national oil company, Sonatrach, will increase crude oil production by 25% in 1996 and by 50% in 2000. If this is realized, the production capacity could reach about 1 million b/d in 1996 and about 1.20 million b/d by 2000.

Because its oil consumption may double in 20 years, some estimates suggest that, unless additional reserves are developed quickly Algeria could become a net oil importer by 2010 2015. The reserve additions could come either from enhanced oil recovery in existing fields or by discovering new oil fields.

Algeria revised its petroleum law in 1986 and several amendments have since been added to attract foreign investment and technology.

Algeria could reach its objectives through foreign partners, enhanced recovery methods in older oil fields such as Hassi Messoud, continued gas recycling in Hassi R'Mel field, the development of Hamra field condensate, and the discovery of new oil fields. The cost of increasing Algeria's production capacity an additional 400,000 b/d by, 2000 could be as high as $4 5 billion.

GABON

At the end of 1992, Gabon's proved oil reserves were estimated at 2.4 billion bbl. Oil production at the end of 1992 and during 1993 was about 0.30 million b/d.

The average monthly production during 1993 was reasonably stable and ranged between 291,700 b/d in September and 302,500 b/d in December. Gabon is expanding its production capacity to 350,000 b/d by 1995 through development of new discoveries and also through efforts to recover more oil from existing fields, such as the expansion of Rabi and other oil fields. After 1995, the prospects depend on how successful Gabon is in developing new reserves or maintaining production from existing fields. The production capacity by 2000, therefore, could either be the same as in 1995 or decline to slightly less than 300,000 b/d.

INDONESIA

Indonesia's estimated proved recoverable crude oil reserves were 10.8 billion bbl at the end of 1992. Production averaged about 1.38 million b/d in 1992 and 1.33 million b/d in 1993.

The proved reserves reached 10 billion bbl in 1975, falling to 8.5 billion bbl in 1985 before recovering to 10.8 billion bbl at the end of 1992. Intensive exploration activities since 1989 led to this recovery (Table 1).

Indonesia has welcomed foreign equity participation in its upstream oil industry. In 1988, to attract more foreign upstream investment, the Indonesian government reduced from 58 to 48% the tax and royalty rate on revenues earned by producers. Moreover, in 1989, Pertamina revised the ratio of oil production equity between the government and producer from 85:15 to 80:20 on new discoveries. This new incentive has boosted upstream activities.

Production capacity is set to grow during the 1990s due to the development of the new oil discoveries. Intan/Widuri fields will add substantial production capacity. Also, the Duri steam flood and the Minas waterfloods will peak in the mid1990S.

The Belida field, inaugurated in December 1992 with initial production of 20,000 bld, could reach peak production of about 85,000 b/d in the mid 1990s. This field, one of the largest discoveries so far within the South Natuna block, South China Sea, is expected to produce oil for about 15 years.

Within the Natuna area are several large discoveries for which development has been delayed because of high carbon dioxide (CO2) content in some reservoirs. Development requires sophisticated and costly technology; however, Pertamina and its production sharing contractors are moving ahead for development in the 1990s.

Among possible Natuna developments are Sembilang, Belanak, and a cluster of small fields (Tembang, Bawal, Hiu, Belut, North Belut, Buntal, and Kerisi). These could be exploited through a link up with the Belida facilities. These fields have the capacity to generate a combined production of 94,000 b/d by 1994 and 111,000 b/d in 1996.

Development cost of the Natuna fields is extremely high. The Director General of Oil and Gas in Indonesia's Ministery of Mines & Energy estimated this cost at $17 billion, of which more than 40% is needed for special technology, to remove and reinject C02. The budget for exploration including drilling in 1992 increased to about $5 billion from $3.8 billion in 1991.

If the new developments and other expansion programs materialize, Indonesia's production capacity could increase from the present 1.40 million b/d to 1.55 million b/d in 1995 before falling slightly to 1.30 million b/d by 2000.

Because of its sharply increasing domestic consumption, some reports and announcements from Indonesian officials suggest that Indonesia could become a net oil importer before 2000. However, some other officials from Pertamina's exploration and production department believe a shift for domestic consumption to natural gas and coal will maintain Indonesia as an important oil exporter beyond 2000.

LIBYA

Proved estimated recoverable crude oil reserves at the end of 1992 in Libya were 22.8 billion bbl. Its average monthly, crude oil production during 1993 fluctuated from a minimum of 1.35 million b/d to a maximum of 1.47 million b/d. The current sustainable crude production capacity is estimated at around 1.50 million b/d.

Plans are to increase the capacity to 2 million b/d by 1994. An additional increase of about 200,000 is possible by 1995. By 2000, the production capacity will either be maintained or will slightly increase before starting to fall (Table 1).

The onshore Sarir and offshore Bouri are giant fields with proved oil reserves estimated at 5 billion bbl each. The proved oil reserves of the onshore Amal and Murzuk fields are 3.5 billion bbl and 2.0 billion bbl, respectively. Other fields, over 100, have each less proved oil reserves.

The main production capacity expansion, in the 1990s, will be from the Sarir and Masla water injection projects. These are designed to increase production by over 200,000 300,000 b/d in 1995.

The development of Murzuk field by Romania's Rompetrol is set to increase production from 20,000 to 160,000 b/d by 1995. Also, the development of AI Kabir field could add another 10,000 b/d.

Libyan officials believe workovers or additional equipment in about 250 development wells could add another 180,000 200,000 b/d to production capacity.

The offshore Bouri field, operated by Italy's Agip, is also set to double production through further development.

The cost of these capacity expansion programs is considerable. The Libyan Oil Minister announced in June 1992 that the budget for the capacity increase program for the fiscal year 1992 1993 is $3.5 billion. However, substantial further investments will be needed to reach the planned capacity for 1995 and 2000.

Libya relies heavily on foreign firms for investments to ensure production capacity increases. Most of its fields have been producing for about 20 years and some are nearly depleted. Moreover the numerous small fields require a large investment to maintain production.

The current partial embargo, if continued, could hinder Libya from meeting its objectives.

NIGERIA

Nigeria's proved crude oil reserves at the end of 1992 were 20 billion bbl. Crude production during 1993 ranged between a minimum of 1.87 million b/d and a maximum of 1.99 b/d.

Production, after peaking at 2.30 million b/d in 1979, declined to a low of 1.24 million b/d in 1983 before recovering in 1992. In 1990, Nigeria announced that it would embark on an ambitious capacity expansion program to increase sustainable capacity from just under 2 million b/d to 2.5 million b/d by 1995. Also, it aimed to increase proved oil reserves to 20 billion bbl, which was achieved at the end of 1991 by adding 3 billion bbl.

In December 1992, the Nigerian Minister of Petroleum announced that oil production capacity would reach 2.5 million b/d in mid 1993 and he estimated Nigeria's sustainable capacity at just over 2 million b/d. The Chairman of the Board of Directors of Nigerian National Petroleum Corp. (NNPC) also announced in September 1992 that Nigeria had set a new target of proved oil reserves of 25 billion bbl by 1995.

Nigeria has attracted substantial investment from foreign firms. In mid 1991, to encourage further foreign investment, NNPC concluded a "Memorandum of Understanding" with Shell, Elf, Agip, Chevron, Mobil, and Texaco, all current operators in the country. The memorandom's aim is to increase recoverable reserves and hike production capacity by offering new, attractive terms to the current operators (Table 1).

Exploration activities, both onshore and offshore, have intensified since the oil price collapse of 1986. The number of exploration wells rose from 29 wells in 1986 to 68 wells in 1990. Development wells increased to 51 from 29 wells during that same period. The exploration effort has discovered several new fields that, when developed, will add substantial production capacity.

Since 1989, the development of major oil fields such as Edop, lyak, Obagi, Agbard, and Afremo his helped increase the production capacity by about 350,000 b/d. An additional potential 200,000 b/d in the 1990s will come from production increases in the Edop and Iyak fields.

Further development of the offshore Oso condensate field, inaugurated in December 1992 with initial production capacity estimated at 100,000 bo/d and initial production of 10,000 b/d, could increase Nigeria's production capacity by 500,000 b/d in 1994.

The cost of expanding Nigeria's production capacity to 2.5 million b/d by 1995 is estimated at around $7 billion and at least an additional $8 billion will be required to maintain production at around 2.30 million b/d by 2000. The cost of developing the offshore Oso condensate field is $1 billion.

VENEZUELA

Venezuela's proved crude oil reserves at the end of 1992 reached 63.3 billion bbl, up 0.7 billion bbl from 1991. Oil production peaked at 3.71 million b/d in 1970, falling to a low of 1.56 million b/d in 1985 before recovering to an average of 2.32 million b/d in 1993.

The Venezuelan national petroleum company Petroleos de Venezuela S.A. (Pdvsa), in 1990 came out with an expansion program aimed at increasing oil production capacity (including crude, condensates, and natural gas liquids) to 4 million b/d by 2000. The project, estimated to cost $8 billion, would have relied on Venezuela's own sources for financing. However, recently, it was reported that Venezuela is reappraising this ambitious plan by stretching out the time for implementation but keeping the same objectives. The original plan was aimed at raising production capacity by an annual average of about 50,000 b/d. This is an annual increase of about 650,000 b/d to overcome the annual decline rate which has been estimated at 600,000 b/d.

Venezuela has been seeking the participation of international oil companies for the reactivation of a number of depleted and marginal oil fields. If this effort is successful, output capacity may increase by about 100,000 b/d of light crude.

On July 31, 1992, two 20 year contracts were signed between Pdvsa and two foreign firms. The two firms will drill about 300 new wells and restore 70 existing ones in five fields over the next 10 years in northern Venezuela. The two contracts call for investment of some $280 million, of which $80 million will be spent in the first 3 years. In the five fields, a total of 670 new wells will be drilled and 250 others restored, for a total investment of $720 million over the contract period.

Officials estimate the five fields could add about 5,000 b/d by the end of 1992 and up to 90,000 b/d by 2000.

Venezuela plans to add up to 1 million b/d of new capacity by 2000, mainly by developing new light oil discoveries in eastern Venezuela (Monagas State, Southeast Lake Maracaibo, and Arauca River area). Furthermore, if crude prices improve and the oil supply becomes tight, further devdlopment of Orinoco bitumen into orimulsion could add 200,000 b/d in 1995 and 500,000 b/d in 2000.

Sustainable crude oil capacity of Venezuela can be substantially improved in the future because of the large resource base. This could increase production capacity by an additional 400,000 b/d to 2.80 million b/d in 1995 and another 200,000 b/d to 3.00 million b/d by 2000.

The cost required for this expansion is substailtial. Pdvsa announced, in late 1991, a huge $48.2 billion investment plan for the oil industry for the period 1991-1996. The upstream share of this investment to maintain and raise the sustainable production capacity. (crude + condensates + NGLS) to 3.5 3.6 million b/d by the end of that period is estimated at around $20 billion (Table 1).

INVESTMENT AND FINANCING

The Gulf crisis undoubtedly gave financial and economic impetus to expand production capacity in most OPEC countries. This is clearly reflected in the expansion programs discussed previously, particulary in the OPEC Middle Ea@t region.

By 2000, these expansion programs call for an increase in capacity of more than 8 million b/d over current capacity. About $108 billion will be needed for these programs.

Nearly 6.5 million b/d, or 75% of the net capacity addition in OPEC, is expected from the Gulf region, with required investment of about $50 billion by 2000. A large proportion, estimated at two thirds, or $72 billion,of the total capital required to be invested in the 1990s is expected to come from within the oil industries of OPEC members. The rest, about $36 billion, will be contributed from foreign firms, banks, and financial institutions.

Also, 60% of the $108 billion, or $65 billion, will be required to maintain production from existing fields.

Despite a huge demand for capital elsewhere, particularly in the former Soviet Union, multinational oil companies and other oil industry firms in OPEC's regions are expected to expand. In attracting the capital needed, OPEC must compete with oil industries elsewhere.

OPEC has about two thirds of the world's proved oil reserves. These can be exploited at relatively low cost; however, additional incentives by OPEC members could attract investment which otherwise would go elsewhere.

In recent years, upstream capital investments have shifted away from the mature oil province of U.S. and Canada to other areas where better incentives and more opportunities are available. The U.S. onshore is the most heavily explored and drilled area in the world.

High finding costs and environmental concerns have helped divert exploration and production investment away from the U.S. Major oil companies in the U.S. are slowing domestic exploration and selling domestic properties to raise funds for international operations. Some independents are following the same path.

While the U.S. is placing environmental and economic pressure on the oil industry, the rest of the world is improving production sharing contracts and tax structures to attract more investment.

In spite of the petroleum potential of the former U.S.S.R., particularly Russia, the present political, economic, and social unrest creates frustrations and uncertainties for international oil companies trying to enter the area.

Western Europe is still attractive for some oil companies, and upstream investment is continuing in spite of no major discoveries in recent years. Most of the current North Sea investment is for developing small and marginal oil fields by tying them into the existing infrastructure.

Against this background, OPEC members must compete in attracting the required investment to expand their production capacities. But OPEC's prospects are highly promising.

For both OPEC and international oil companies, the price of oil is essential for determining capacity expansion investment. A low oil price means reduced income for OPEC members and, consequently, insufficient capital for production capacity expansion. For international oil companies, a low oil price indicates decreased demand for oil (or over supply of oil) and less revenue. Therefore, they might defer investing in production capacity expansion in the OPEC area.

With a low oil price, the projects discussed previously may not be fully realized. On the other hand, if the price of oil is high, OPEC members may accelerate the investment. In Table 2, oil prices, as measured by the OPEC basket, are assumed at a constant level (in real terms) of $17/bbl during 1993 2000. From 2001 onwards, the real price of crude is assumed to increase by 3.5%/year, so that the price in real terms by 2010 is $24/bbl.

Beyond 2000, OPEC, and particularly the OPEC Middle Eastern region, will be even more important because non OPEC supply will continue declining and, consequently, the demand for OPEC supply undoubtedly will grow.

More capacity expansion and investment are, therefore, required after 2000 to meet the world's growing demand. It is projected that OPEC capacity could expand to 40.6 million b/d and 41.0 million b/d by 2010 and 2020, respectively (Table 3).

FUTURE DEMAND GROWTH

Most energy analysts expect that demand for energy will grow substantially in the medium and long term. The growth is necessary to fuel the expanding world economy, particularly in newly industrialized and developing countries.

World economy expansion is largely driven by population growth, particularly in developing countries. Both developing and industrialized countries will require more energy to improve the quality of life.

The growth measured by the world's gross domestic product (GDP) is not expected to reverse the trend of the last few decades and, consequently, energy and oil demand will increase. Fig. 1a shows the strong relationship between the GDP and energy and oil demand.

Reduction in the various energy sources because of conservation and efficiency is illustrated in Fig. 1b. Fig. 1c reveals the demand growth of these energy sources during the past four decades (Table 3).

The projected energy growth will not only involve fossil fuel sources but also other commercial and noncommercial forms such as hydro, nuclear, renewables, and biomass. Because oil resources are large and available and can easily be exploited at relatively low cost, oil will remain as a substantial source of energy.

World oil demand by 2000 could range from 69 to 78 million b/d, and by 2010 the figure could be 76 93 million b/d (Table 4).

ENVIRONMENTAL IMPACT

In recent years, concern about the environment has led to measures that will curb pollutants. The two main current environmental issues are:

1. Pollution of the environment

2. Climate change (global warming).

Environmental pollution is a local issue usually of concern to only one or a few countries. On the other hand, climate change is a global issue, requiring involvement of all nations, particularly industrial countries. Although the protection of the environment from pollutants that may damage air, water, and soil is of utmost importance, the emphasis has gradually shifted towards climate change, global temperature increases, and sea level changes. These are linked to fossil fuel use and net emissions of carbon dioxide. Because of incomplete understanding of sources and sinks of greenhouse gases that affect predictions of future concentrations, many scientific uncertainties remain regarding the theory magnitude, tinting, and regional distribution of climatic change. Uncertainties also exist on the effect of:

• Clouds, which strongly influence the magnitude of climatic change.

• Oceans, which influence the timing and pattern of climatic change.

• Polar ice sheets, which affect predictions of sea level rise.

Despite these uncertainties, carbon dioxide (CO2), which is emitted from fossil fuels, has been singled out as the main greenhouse gas (GHG) that could cause global warming. Fiscal and regulatory measures, such as carbon and energy taxes, have been proposed to curtail CO2 emissions.

Other GHGs such as methane (CH4), nitrous oxide (N2O), chlorofluorocarbons (CFCs), and tropospheric ozone (03), which collectively have the same effect as CO2 and even have more serious global warming potential than CO2, are not dealt with in the same serious manner (apart from CFCs). CO2 even has one of the lowest annual growth rates compared to other greenhouse gases.

But because many believe that CO2 emission is the main source that could cause global warming the emphasis to reduce fossil fuel demand, particularly oil, has become dominant. Measures to reduce CO2 emissions include efficiency improvement, conservation, tradable emission permits, enhancement of afforestation, and reduced deforestation. But the one measure attracting the most attention is the energy/carbon tax particularly oil taxes.

A tax that discriminates against oil, however, is not only unfair to oil producing countries, but also is unlikely to be efficient for reducing CO2 emissions because the probable energy substitute is coal, an emitter of high levels Of CO2.

Although the Unced framework convention on climate change failed to produce a global commitment to curtail GHG emissions, some governments, particularly in industrialized countries, have adopted policies aimed at curbing CO2 emissions. These policies will undoubtedly affect the prospects of fossil fuel, and in particular oil consumption.

To illustrate the impact on oil supply and demand, two scenarios are proposed:

1. The business as usual scenario assumes the continuation of the past, that is, no CO2 tax.

2. The environmental scenario assumes an energy/carbon tax similar the European Community (EC) proposal that would be implemented in the Organization for Economic Cooperation and Development (OECD) countries. The tax is divided into two equal portions, 50% on energy content and 50% on carbon content of different energy sources. The proposed tax aims to stabilize CO2 emissions at the 1990 level by the year 2000 and reduce it by 20% in 2010.

This tax was planned to be introduced in January 1993 for the EC (actually all OECD countries) at $3/bbl of oil equivalent (BOE) and increasing by $1/BOE each year until reaching $10/BOE by 2000.

The EC made the implementation dependent on the adoption of similar policies by the U.S. and Japan. A similar approach has emerged in the U.S. The original proposals would have added roughly $3.5/bbl, more than twice the tax proposed for coal and uranium.

The tax was originally planned to be phased in over 3 years, starting from July 1994 and would be about $3.5/bbl by July 1996. However, the bill tax was dropped and replaced by a plan to combat global warming using a mix of voluntary programs, government regulations, and support for renewable energy. Under this plan, the U.S. greenhouse gas emissions would be cut to 1990 levels by the year 2000. This plan is part of a longterm strategy to obtain a downward trend of emissions.

In both scenarios, the oil price (OPEC basket of crude) is assumed constant in real terms at the level of $17/bbl in 1993 dollars to 2000. That is, in real terms, oil price in 2000 will be the same as in 1993. Also, an annual energy efficiency improvement of 1 2% has been assumed until 2010 and the energy sector of eastern Europe, particularly in former U.S.S.R., is assumed to gradually recover after 1996, thereby bringing energy prices in line with Western Europe by 2000.

The economies of the world and OECD are assumed to grow by 3.0 and 2.5%/year, respectively for the business as usual scenario during the period 1995 2010. Average OECD annual inflation during the same period is assumed at 4.33%. For the environmental scenario, world and OECD average GDP growth is assumed at 2.9 and 2.4/year, respectively. Average OECD annual inflation is assumed at 4.55%.

The business as usual scenario predicts that total world oil demand will grow from 65.1 million b/d in 1992 to 72.5 million b/d and 79.5 million b/d in 2000 and 2010, respectively. The call on OPEC oil will rise from 25.6 million b/d in 1992 to 35 million b/d in 2000 and 41.8 million b/d by 2010. Hence, the capacity utilization by 2000 and 2010 according to this scenario will be 96 and 103%, respectively (Table 5). This capacity utilization seems very tight and may be needed to stabilize the oil market in case of oil supply disruption.

Under the environment scenario world demand for oil will be reduced by about 2.6 million b/d and 5.3 million b/d in the respective years 2000 and 2010. The call on OPEC oil, consequently, is expected to be reduced by the same proportion (Table 5). Therefore, the capacity utilization is reduced now to 89 and 90% in 2000 and 2010, respectively.

However, the EC proposal for an energy/carbon tax of $3/BOE increasing to $10/BOE is not enough to achieve stabilized CO2 emission by 2000 at 1990 levels, and consequently more severe measures are required to reach this objective.

The impact of these severe environmental measures on the need for OPEC oil and capacity, utilization beyond 2000 will be tremendous. These measures will substantially reduce the call on OPEC oil, and consequently substantial OPEC capacity, will be left idle particularly if the 20% reduction in CO2 emission from the 1990 level is implemented by 2010 (Table 5).

The call on OPEC oil could be reduced by 5 million b/d if CO2 emissions are to be stabilized in 2000 and reduced by 20% from 1990 levels. Idle capacity is estimated at around 6 million b/d and 14 million b/d by 2000 and 2010 respectively, and consequently capacity utilization is reduced to 83% and 65% during these periods.

Editor's note: The views expressed in this article are those of the author and may not necessarily represent the view of OPEC.

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