Journal Issue

Energy: Natural gas: an important but underexploited resource: Many LDCs could achieve a better energy balance by using natural gas

International Monetary Fund. External Relations Dept.
Published Date:
June 1986
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Philippe Bourcier and Mohsen Shirazi

Natural gas reserves exist in about 50 developing countries, including about 30 that currently import oil. In many of these countries, reserves of gas were found in the course of exploring for oil, but have not been fully evaluated, let alone developed, because incentives have been lacking. Developing countries consume only 0.5 percent a year of their 43 trillion cubic meters of known reserves, and only about half their gross production of natural gas is marketed—compared with 87 percent in the industrial market-economy countries, and 98 percent in Eastern Europe—the remainder being flared. (See Charts 1 and 2.) The issue in many countries that have gas is not the size of the reserve base, but how rapidly the resource can be developed. This depends on the costs of producing and delivering gas, relative to those of competing sources of energy, and, where costs are competitive, on how rapidly gas markets can be developed.

Studies by the World Bank suggest that the costs of developing natural gas are lower, and the potential demand in developing countries higher, than is commonly believed. The Bank’s projections indicate a potential fourfold increase in natural gas production in developing countries between 1980 and 1995 if the constraints on gas development can be removed. Only a few countries are considered potential exporters in this century; conventional thinking has also tended to underestimate the dampening effect of the recession on demand for gas in importing industrial countries.

A critical element in the decision to develop gas for domestic use is economic cost. A recent World Bank study estimated the cost of natural gas production and transport in ten countries with a variety of reserve and production characteristics at between $0.60 and $1.80 per thousand cubic feet, or $3.60 to $10.50 per barrel of oil equivalent, at the city gate (i.e., the point of entry to the city distribution network). Gas costs are expected to remain low and compete with those of most alternative fuels. On this basis the Bank expects developing countries’ domestic consumption of natural gas to grow at 8.5 percent a year—faster than any other energy source. As a result, the share of gas in their total commercial energy consumption would grow from 7 percent in 1980 to about 12 percent in 1995.

From 50 to 75 percent of this consumption is likely to be used as fuel in electric power and industry, another 20-40 percent as feedstock in fertilizer and petrochemicals, and 5–10 percent in the residential and commercial sectors. In most countries, the main initial use of gas will be to replace other fuels in existing markets. In countries using gas for the first time, the main gas markets will be for power generation, large industry, and fertilizer production—those markets which justify major investment in new infrastructure.

This article draws on a handbook, Managing the Development of Natural Gas, prepared for the Bank by its staff and consultants. The handbook is available free of charge from the Energy Department, World Bank, Washington, DC 20433, USA.

To achieve these large potential changes in the role of gas will require a strong commitment by governments to formulating policies, developing the necessary infrastructure, and strengthening institutions. This commitment is a crucial feature in any national gas development program because, unlike oil, natural gas is not readily marketable. The steps that must normally be followed to design and carry out a gas development program are described below.

Planning for gas development

Any petroleum exploration activity may result in the discovery of oil or gas or both. As Chart 3 shows, Phases I and II, which deal with exploration activities, are effectively the same for oil and gas. The development and commercialization of an oil field is a fairly well-established practice, and the steps to be taken by the operator are clearly defined in the contract made between the oil company and the state. In the case of an oil discovery, the commercial evaluation in Phase III can be made reasonably quickly once the main physical characteristics of. the field have been assessed. Once commercial viability has been established and there is agreement between the operator and the host country, the project moves to the development phase (Phase IV). Gas, unlike oil, is not readily transportable or tradable in international markets and cannot practicably be stored once produced. Whether a gas field is commercial thus cannot be established until the conditions for gas utilization and marketing have been defined, and until plans for the development of the field have been closely coordinated with plans for a downstream gas development program.

A downstream gas development program may be defined as the integrated chain of activities, succeeding the field development operations, for the commercial sale and delivery of natural gas or liquefied natural gas, or both, to domestic or foreign buyers. It provides for the design, construction, operation, and maintenance of the facilities necessary to receive, measure, treat, process, and transport natural gas from the field to domestic consumers or to buyers for export.

Embarking on the development of gas raises complex questions of gas allocation and investment. For example: should gas be used in electricity generation to replace imported fuel oil or coal, or should a gas-based fertilizer plant be built to replace imported urea? Would the high cost of installing a city gas network be justified by the high and growing cost of the kerosene and liquefied petroleum gases that gas could replace? If gas reserves are large, should the country try to attract commercial partners for an LNG export project, or should the gas be kept in the ground to satisfy future domestic markets? Such questions are more economic than technical in nature and they require choices about long-run sectoral strategy. Because gas is depletable, trade-offs over time, as well as tradeoffs between gas-using projects at a given point in time, must be explicitly considered.

Because of the close link between development of the gas field, the transmission and distribution network, and the market, there are a number of decision points at which studies and investments must be completed simultaneously before the next step can be decided upon. These are as follows.

Assessing availability and markets. Prospective markets need to be appraised at the same time as the production potential of the gas field. At this stage, producers will be reluctant to invest in appraisal or delineation until they have a satisfactory contract, but consumers cannot commit themselves to gas development because of the uncertainty of supply. This potential conflict, which has delayed gas development in several countries, can be avoided if a government:

• Systematically reviews the market for gas, as part of a periodic energy review, and assesses the range of costs that would be acceptable to major groups of consumers; and

• Provides a clear policy toward producer and consumer prices, linking them to the value of the energy source that gas is to displace.

Within this framework producers can at the time of discovery assess their future profitability and take the corresponding investment decisions more rapidly. Where a foreign oil company is the operator, the host government should include in the exploration and production agreement clauses that indicate clearly how the main variables that affect the economic viability of the development will be determined and what would be the major steps in the decision process leading to declaration of commerciality.

Chart 1Shares of world natural gas reserves, 1983

In trillion cubic meters (TCM)

Citation: 23, 2; 10.5089/9781616353650.022.A002

Source: World Bank

Chart 2Shares of world natural gas consumption, 1983

In billion cubic meters (BCM)

Citation: 23, 2; 10.5089/9781616353650.022.A002

Comparing schemes. With projections of demand and supply, the technical and economic feasibility of alternative schemes (e.g., using different technologies and different approaches to field development and infrastructure) can be compared under various assumptions about demand. At this stage the host country may choose to secure the assistance of an organization with operating experience that can advise on the planning, commercial, and technical decisions to be made. Judgment will also have to be passed on long-term policy issues which affect the viability of alternative schemes: for example, the speed of reserve depletion, the structure and duration of supply contracts, pricing policies, and, more generally, the regulatory framework within which the gas industry should operate. The analysis at this stage should clearly identify the effects of different choices on the feasibility of gas development over the long term and enable decision makers to evaluate the costs to the economy of alternative policies. Too often irrevocable decisions about the future are made on the basis of short-term considerations.

Selecting a market development plan. The analysis just described should result in the selection of a 10-15 year market development plan within which individual projects can be formulated. The plan should be flexible enough to accommodate new information on the availability of gas or the opening of new markets.

Individual projects. Once the market plan has been drawn up and adequate pricing policies, regulations, and incentive schemes have been designed, specific projects can be identified, prepared, and implemented. The coordinating steps can be very complex; for example, work on the component with the longest implementation period cannot normally start until financing has been secured for all investments in the chain.

Economic analysis

To evaluate gas-using projects and to design gas investments, a long-run sector framework is generally needed. Once enough reserves have been identified to indicate that gas could play a major role in a country’s energy sector, and before important decisions are made about the use of gas, a gas utilization study (GUS) should be undertaken to provide such a framework. Such a study reveals the sequence of investments that will yield the largest total benefit to the country from the use of its gas resources. These studies are similar to the project evaluation exercises that are routinely handled by economists and planners, but because gas is exhaustible, and its economic price therefore reflects not only its production (or extraction) cost but also the cost of future consumption forgone (sometimes called the depletion premium), the economic price of gas is itself a function of the set of projects selected.

Obviously different aspects of the analysis are more important in some countries than in others, but in essence it consists of the following steps. After calculating the long-run marginal cost of gas under various scenarios for demand (at various prices) and supply (under various reserve assumptions), the economic price path for gas is derived. Using these results, potential projects can be formulated and compared with one another, on the basis of their technical and economic characteristics. In the largest gas-using sectors (usually power and fertilizers) the aggregate demand analysis from the study’s first phase will already have indicated a sequence of projects; to these are added gas-using projects from other sectors and possibly for the export market, and net present values are calculated for the various trial packages. When a set of optimal project packages has been derived, sensitivity analyses are done to test the robustness of the results and to identify critical areas of uncertainty in the analysis.

Once the basic GUS framework has been set up it can become a simple and revealing tool for strategic planning in the gas sector. Its successful institutionalization requires the close involvement of local staff and managers in its initial development.

Institutional requirements

Experience shows that a single institution should be placed in charge of natural gas development. This is particularly important in countries that are just embarking on natural gas development and where several options can be considered for the export as well as domestic use of gas. The agency will need to take responsibility for negotiating contracts with producers, large domestic consumers, and any export market clients; for transporting, distributing, and marketing gas; and for implementing government policies in the gas sector. Some countries may need gas industry experts to assist the manager in organizing this institution, as well as in recruiting and training its staff.

If the gas development agency successfully develops a gas project, a permanent gas operating entity should be established. This entity can be privately or publicly owned, though the government will need to establish the financial and technical rules for its operation. There are two common organizational models:

• National monopolies, whereby all gas transmission and distribution activities are by law centralized in one organization. This system may be totally centralized, as in Algeria, Argentina, France, and Iran, or may delegate considerable autonomy to regional bodies.

• Public or private companies, each responsible for only part of the gas system. For example, transmission companies transmit gas from local production or import sources and sell it to large industries and city distribution networks, which are usually under independent companies or under the municipalities. This is the model used in the Federal Republic of Germany, the Netherlands, and the United States. These companies may be regulated.

Natural gas contracts

Exploration and production agreements made before petroleum exploration begins usually establish the broad principles under which a gas field would be developed, in the event of a commercial discovery. As indicated earlier, these provisions may in many cases be changed to take into account the differences between the economics of gas and oil developments. Once the commercial viability of a gas field is proven, it is usual to execute a long-term gas sales contract specifying precisely the price and quantity of gas to be delivered and purchased.

Sales contracts. Once reserves have been delineated, and before a field is developed, the contractor must negotiate a gas sales contract with a purchaser. In new gas developments, these sales contracts are usually made for 10-20 years; the difficulty of transporting gas ties the producer via pipeline or LNG plant to a single point of delivery, and this is usually the minimum period that would justify the large fixed investments to be made in field development, transmission, and gas-using facilities.

A gas sales contract provides market guarantees for the producer and supply assurances for the purchaser in the following basic clauses. Take or pay provisions are undertakings by the purchaser to take delivery of some minimum percentage (usually 70-90 percent) of the annual contract quantity, or if unable to do so, to pay for it anyway. High take-or-pay percentages can be difficult for the purchaser where the end-use demand for gas fluctuates, but producers need assurances that they can service their debt (usually secured by the cash flow that the take-or-pay provisions guarantee) and realize a reasonable profit on the investment. The gas price formula normally provides for a base price at the beginning of the sales contract and periodic price revisions, according to an agreed formula.

Chart 3A sequential comparison of gas and oil developments

The provisions of these contracts need to be worked out on the basis of a detailed financial model of the upstream and downstream investments, so that the risk/return implications of specific commitments can be carefully tested before the contract is finalized. Normally a natural gas sales contract is finalized only after a full-scale feasibility study of field development has been completed and after the characteristics of a specific gas market have been defined.

Developing natural gas for export

Despite a rapid advance in the 1970s, international trade in natural gas still represents only 12.5 percent of world marketed production. Seventy-eight percent of international gas trade is by pipeline, rather than as liquefied natural gas, and four countries (Algeria, Canada, Indonesia, and the Soviet Union) supply 94 percent of world natural gas exports. Given the importance of securing a market before embarking on an export project, an export market assessment is one of the critical prerequisites in any export plan.

LNG. Natural gas can be liquefied if its temperature is reduced to -160°C. LNG trade has much higher technological and investment requirements than pipeline trade. For exports of LNG, with its high costs of storage and large initial investment needs, exporters generally require 20-year contracts with buyers, and the market remains tightly controlled and rigid. To estimate the economic benefits from a potential LNG project it is necessary to consider:

• The minimum economic size of LNG projects and their investment cost;

• The minimum economic volume of gas exports;

• The prices of LNG exports; and

• Financing arrangements.

LNG projects need large proven reserves, of one to one and a half billion cubic meters to support them, and must operate at a high load factor and over a long period to justify the very large initial investments they require. Once a project is found feasible, it may take seven years before the first deliveries of LNG can be made.

Fertilizer. Fertilizer is in excess supply worldwide, but new plants are likely to be needed by the late 1980s. By the World Bank’s calculations, fertilizer production in new plants will be more economic for import substitution than for export in the coming decade.

Petrochemicals. The Bank projects that with world economic recovery, world demand for petrochemicals is likely to exceed currently committed production capacity before 1990. India is expected to add sufficient capacity to balance its supply and demand, while gas-rich countries—Canada and in the Middle East—are likely to become important exporters. The returns are likely to be best in countries that invest in world-scale plants to substitute for plastics imports or to replace nonplastic materials in domestic markets.

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