Demand for natural gas in Europe through 2010 will grow substantially, particularly for power generation. Supplies, nevertheless, will remain adequate, possibly even in surplus in the near-to-medium term.
In the longer term, prices for natural gas must rise to support new supply projects. And Europe's import dependency will increase, causing gas companies and governments increasingly to focus on security of supply.
These are the major conclusions of a recent study conducted by Purvin & Gertz Inc., London, and presented by Michael Corke to a gathering earlier this year of the European gas processors in London.
In both near and longer term supply scenarios, key roles will be played by the producing regions of the former Soviet Union (FSU) and by Algeria.
Algeria and the FSU, he said, will likely remain key suppliers of imports to Europe with LNG projects from remote regions of the world providing only marginal supply volumes.
Total natural-gas demand in Western Europe will increase from 248 million tons of oil equivalent (MMTOE) in 1992 to around 410 MMTOE (around 500 billion cu m; bcm) by 2010.
Increases will occur in all sectors, but over the entire period, around 50% of the growth will occur in public and industrial-based power generation.
The total demand projection is for an average growth rate of
2.9%/year, compared with expected average growth in total primary
energy of only 1%/year.
Gas consumption will also increase in the countries of Eastern Europe despite stagnating demand for energy in total.
Displacement of oil products for heating purposes in industry and power generation and displacement of coal in all sectors for environmental and economic reasons will be the main elements of this growth.
Total gas consumption will increase from 58 MMTOE in 1991 to 84 MMTOE by 2010.
DEMAND SECTORS
Three major end-use sectors fuel natural-gas demand: residential/commercial, industrial, and electric-power generation. Through 2010, said Corke, energy-consumption growth in the West European residential sector will average slightly less than 1%/year.
Natural gas, gas oil, solid fuels, and electricity are all used for space heating, but natural gas and gas oil are the major competing fuels: Each currently accounts for approximately 30% of total energy consumed in the sector.
The sector prefers natural gas, regarding it as a clean and convenient fuel, and has overlooked so far its being more expensive than other fuels.
Gas use in Germany and the U.K. has been increasing, for example, despite high prices for gas relative to gas oil in both countries. Gas prices to residential/commercial consumers in the three other large West European markets-France, Italy, and The Netherlands-are lower relatively.
All these markets would grant considerable latitude in gas-price increases if they were necessary to pay for new and more expensive gas supplies.
In the future, total consumption of natural gas will grow at an average rate of 1.7%/year (compared with 0.9%/year for total energy), resulting in natural gas increasing its share of the West European residential /commercial energy market from 31 % in 1991 to 38% by 2010.
In Eastern Europe, residential energy prices have historically been heavily subsidized; interfuel competition has not existed.
Natural gas will increase its market share here because prices are likely to be competitive vs. oil products; coal use will be reduced by increasing costs and environmental restrictions.
INDUSTRIAL DEMAND
Western Europe's industrial sector's energy consumption will grow only slowly because of conservation and the comparatively poor performance of heavy energy-intensive industries.
As in the residential/commercial sector, interfuel competition occurs mainly between natural gas and oil, although primarily heavy fuel oil.
Industrial energy buyers are extremely price-sensitive, and in most West European countries gas prices to large industrial energy users are fairly close to thermal parity with heavy fuel oil.
Germany and the U.K. are again exceptions.
Relatively higher prices have historically existed because of limited competition and regulation and, in Germany, environmental constraints on the use of other fuels.
Interfuel competition in the industrial sector is further complicated by more than a third of energy used for heating purposes being accounted for by such direct-heat applications as the manufacture of glass and ceramics.
In direct heat applications, said Corke, the process is typically designed to use a specific fuel. Once the decision has been made on process design and fuel use, competition between fuels is no longer possible.
As implied earlier, environmental controls are increasingly important in limiting interfuel competition.
For a new large combustion plant, the European Union's (EU) large combustion plant directive effectively requires plants with heat input rated at more than 300 mw to be fitted with flue gas desulfurization. SO2-emission limits can be met by use of a fuel with a sulfur content less than 1.0 wt %.
These trends will continue to increase the value of gas in large parts of the industrial sector.
The price of gas sold as feedstock for manufacture of ammonia, methanol, and their derivatives will continue to be restricted by the competitive international markets for those products. In the expected absence of gas suppliers' willingness to subsidize these manufacturing operations, feedstock use of gas will stagnate.
A combination of competitive pricing and restrictions on the use of other fuels will cause substantial growth for gas in Western Europe's industrial sector.
While total energy use in the industrial sector grows at only 0.7%/year through 2010, natural-gas use will increase at 1.9%/year and increase its share of the industrial energy market from 24% in 1991 to 29% by 2010.
Industrial sector natural-gas demand will increase in Eastern Europe, as well. As in the residential/commercial sector, displacement of coal for economic and environmental reasons will be the main cause of this growth.
Total increases in gas demand, however, will be limited by declining or stagnating demand for all energy, as industrial restructuring occurs and energy-efficiency measures are introduced.
POWER-GENERATION DEMAND
Compared with coal, a gas-fired power station can be built less expensively and more quickly. It costs less to operate and has a higher thermal efficiency.
Major national European utilities comparing new combined cycle gas-turbine plants with new conventional coal-fired plants could pay a gas price of between $5 and $6/MMBTU before gas
became uneconomical.
Environmental and local planning considerations also tend to favor gas relative to coal or other options.
Gas supply, however, is not unlimited. And security and diversity of fuel supply are major considerations for many power utilities and governments.
In some countries, notably Germany strong lobbies are at work in support of the domestic coal industry. In several East European countries, coal is an indigenous resource which cannot be ignored.
Nevertheless, the use of natural gas in Western Europe for public and industrial-based power generation will surge from 36 million tons of oil equivalent (MMTOE) in 1992 to 115 MMTOE by 2010. Substantial increases are also envisioned in Eastern Europe.
NATURAL GAS SUPPLY
In 1992, said Corke, indigenous European production accounted for almost 70% of Western Europe's total gas supply with about 20% imported from the FSU and about 10% from Algeria as either LNG or pipeline gas.
LNG exports from Libya to Spain accounted for about 1% of total supply.
In Eastern Europe, imports from the FSU provided 45% of supply, with indigenous production adding about 55%. Contrary to some recent reports, a substantial increase in West European indigenous production will occur through the outlook period, as discussed presently (Fig. 1).
Increases will come principally from Norway and the U.K. with smaller gains from The Netherlands. Production from other countries is generally expected to decline as reserves are depleted.
Including eventual exports of 85 billion cu m/year (bcmy) from Norway, total indigenous production will increase from around 174 MMTOE in 1992 to around 230 MMTOE in the second half of the next decade. Despite this increase, requirements for imports will also increase substantially.
For Eastern Europe, depletion of reserves will lead to a gradual decline in indigenous production and increased import dependency, Algeria is currently expanding its export capacity substantially. Some of these increases are necessitated by increases in Algeria's contracted sales which currently peak at about 57 bcmy by 1999.
Contracted capacity increases include expansion of the Trans-Mediterranean Pipeline (OGJ, Jan. 17, p. 49), which will be capable of transporting about 9 bcmy to Morocco, Spain, and Portugal, said Corke.
Algeria's LNG facilities are also being refurbished from a current capacity of around 99 bcmy to around 34 bcmy in the late 1990s.
Further expansions of the Trans-Med and Maghreb pipelines to their ultimate capacities and completion of the LNG refurbishment program would leave Algeria with export capacity of 84 bcmy.
In practice, upstream investment requirements, reserve limitations, and domestic demand make it unlikely that such a high export rate will be possible. Export capacity of up to 70 bcmy beyond 2000, however, certainly appears viable, said Corke.
Contracted and potential spare capacities for Algerian supplies are shown in Fig. 2.
With regard to the FSU, Corke said the picture is less clear. Declining domestic consumption, however, is currently, making surplus gas available for export. Tentative assessments suggest that export availability could increase from the actual 99 bcm in 1992 to more than 140 bcm in 1995.
Spare export capacity through the Ukraine and the Transgas pipelines of former Czechoslovakia, however, is quite limited and would prohibit in this timeframe an additional 40 bcmy of exports, even if export markets required it.
Analyses of the potential energy demand in the FSU's republics and of likely production capabilities suggest that export availability could increase to around 260 bcmy by 2010 with production at that time at around 1,000 bcmy, including 90 bcmy from the Yamal peninsula, and domestic consumption of around 740 bcmy.
Several other gas-supply possibilities also exist for Europe, noted Corke.
Nigeria has contracted LNG sales to Italy, Spain, and France, although it remains uncertain whether the project to supply the volumes will go ahead. And Libya is currently selling comparatively small volumes of LNG to Spain but has the reserves to become a much more important supplier if political differences can in the future be resolved Farther afield, Qatar and Iran in the Middle East have huge reserves and the technical capabilities to be suppliers of pipeline gas or LNG to Europe. Formidable political and geographical barriers to a pipeline project exist, however, and as noted presently, Middle East LNG would be comparatively expensive.
The Caribbean is another possible source of supply.
Venezuela's possible Cristobal Colon project is actually closer to European Atlantic destinations than either the Nigerian or potential Middle East projects.
SUPPLY/DEMAND BALANCE
Corke said the Western European supply/demand balance indicates that indigenous production and contracted imports should be broadly in line with demand through 2000.
Requirements for additional gas will then increase to around 100 MMTOE (120 bcm) by 2010. About 45% of this requirement, however, could be made available by contract extensions and comparatively inexpensive expansions of existing transportation infrastructure.
With regard to the possible export capacity of Algeria and the FSU perhaps supplemented by LNG or even pipeline gas from other sources, the required gas supply appears no difficult target. The projected supply/demand balance is shown in Fig. 3.
Whether required new supply would move to Europe would depend partly on how gas supply costs compare with the market's ability to pay for gas.
The North Sea will provide comparatively inexpensive supplies in the future, with beach prices of around $2.50/MMBTU capable of generating a return in the region of 12.5% for a Troll-type project.
An Iranian pipeline project with an estimated investment requirement of around $9 billion would generate a return of around 15% at this same price level.
A new LNG project from, for example, Libya would generate a return of approximately 15% at prices of about $2.70/MMBTU into Italy or slightly more than $3/MMBTU into northwest Europe.
The most difficult area to assess, said Corke, are the costs of gas supply from the FSU, specifically from Russia. But a new Yamal-to-Germany project would cost approximately $13 billion and generate a 12.5% return at a price of just over $3/MMBTU at the German border. Although this return is not very high, such projects will only advance with Western financing once Russia has shown itself a willing and reliable business partner and gas supplier.
In this scenario, project loans could be made available with government funds or backed by government guarantees. Under these circumstances, such a return is acceptable. Gas prices at the European border required to support new supply projects are shown in Fig. 4.
The ranges there reflect the costs associated with alternative rates of return or, in the case of LNG projects, various destinations at a 15% rate of return. As shown, LNG from more remote sources is high-cost gas. Such projects could go ahead given favorable treatment by host governments and particularly if the buyer has spare regasification capacity.
The costs shown include both a resource-gas cost (host government take) of $0.50/MMBTU and the costs of a new regasification terminal, the capital element of which also amounts to around $0.50/MMBTU.
Copyright 1994 Oil & Gas Journal. All Rights Reserved.
