Natural gas is the fastest growing primary energy source in the IEO2000 forecast. The use of natural gas is projected to more than double between 1997 and 2020, providing a relatively clean fuel for efficient new gas turbine power plants.
World natural gas consumption continues to grow, increasing its market share of total primary energy consumption. In the International Energy Outlook 2000 (IEO2000), natural gas remains the fastest growing component of world energy consumption.
Over the IEO2000 forecast period from 1997 to 2020, gas use is projected to more than double in the reference case, reaching 167 trillion cubic feet in 2020 from the 1997 level of 82 trillion cubic feet .
Over the 1997-2020 period, the role of natural gas in energy use is projected to increase in all regions except the Middle East and Africa, where its share remains relatively stable.
The developing countries of Asia and of South and Central America will see the strongest growth rates in gas demand. Large incremental increases are also projected for industrialized countries, including the United States, and for the former Soviet Union (FSU).
In the IEO2000 reference case, a slowly increasing share of world gas consumption is used in the electric power sector (rising from 29 percent in 1997 to 33 percent in 2020), and natural gas accounts for the largest increment in electricity generation (increasing by 33 quadrillion Btu).
Not only do combined-cycle gas turbine power plants offer some of the highest commercially available plant efficiencies, but natural gas is also attractive for environmental reasons.
When it is burned, natural gas releases less sulfur dioxide, less particulate matter, and less carbon dioxide than does oil or coal.
For the industrialized countries, natural gas—compared with other fuels—is expected to provide the greatest incremental increase in energy consumption among the major fuels and has the fastest average annual growth in the forecast (2.1 percent per year, compared with 1.0 percent for oil).
The percentage of gas used for power generation also grows from 20 percent in 1997 to over 30 percent in 2020. In 1997, natural gas consumption in the developing countries was a smaller portion of total energy use (14 percent) than the world average (22 percent).
From that starting point, gas consumption in developing countries grows at a faster rate in the reference case than any other fuel (an average of 5.6 percent per year, compared with 3.1 percent for both oil and coal).
Increments in gas use in the developing countries are expected to supply both power generation and other uses, such as town gas and fuel for industry.
In Central and South America, the power sector currently relies heavily on hydroelectric power, which accounts for about 12 percent of primary energy use (compared with a 2.5-percent share in the global energy mix in 1997).
Because dependence on hydroelectric resources in the region has led to problems in maintaining electricity supply during times of drought, fuel diversification is now being pursued.
In developing Asia, gas use is also desirable for environmental reasons and to diversify the energy mix away from heavy reliance on oil imports. The problem has been complicated, however, by greater distances between gas resources and market centers, leading to a combination of liquefied natural gas (LNG) and pipeline trade in the region.
There are also new efforts to develop natural gas use in the Middle East, although the projected growth rates and incremental increases there are smaller than in Asia or the Americas.
Domestic resources may supply some of the increase in gas use in the Middle East (for example, in Saudi Arabia), but trade will also be important.
In addition to Turkey and Israel, both Oman and the United Arab Emirates may become gas importers, using pipeline imports from Qatar to meet domestic demand while sustaining their own LNG export commitments.
Some important gas market developments in 1999 include:
The completion of several major international pipelines and firming of plans for other new pipelines in Europe and South America.
Steady growth in pipeline infrastructure is leading to increased trade, which can facilitate a more transparent (and mature) gas market. The 1999 completion of the Europipe II from Norway to Germany will lead to an expanded role for North Sea gas in Germany. On the southern side of Europe, Italy moved forward with plans to build a new pipeline for imports of Libyan gas.
In South America, pipelines from Bolivia to Brazil and from Argentina to Chile (the GasAtacama and the Norandino) were completed in 1999.
Completion in Asia of several major international pipelines and plans for additional lines. In Asia, the new pipeline from Myanmar to Thailand began building up deliveries to contracted volumes, more than a year behind schedule.
Contracts were signed for two new pipelines that would carry Indonesian gas exports to Singapore, and plans moved forward for a pipeline from Papua New Guinea to Australia, with finalization of gas sales contracts.
The completion of several LNG facilities. Three grassroots natural gas liquefaction facilities came on stream in 1999 in Trinidad and Tobago (Atlantic LNG), Nigeria (Bonny), and Qatar (Rasgas).
An expansion, Indonesia’s eighth train (“Train H”) at its Bontang facility is also starting operations at the end of 1999 or early in 2000. Qatar has concluded agreements with India for the sale of 7.5 million metric tons of LNG with deliveries starting in 2003.
Reserves:
Global gas reserves have more than doubled over the past 20 years, outpacing the 62-percent growth in oil reserves over the same period.
Oil & Gas Journal estimated proven world gas reserves as of January 1, 2000, at 5,146 trillion cubic feet, an increase of 1.5 trillion cubic feet over the previous year’s estimate.7 Over the past 20 years, reserve estimates have grown rapidly in the FSU and in developing countries in the Middle East, South and Central America, and the Asia-Pacific region.
The largest incremental increases in reserves over the past year were nearly 4 trillion cubic feet for the Asia-Pacific region and more than 33 trillion cubic feet for Africa, mostly in Algeria and Egypt.
Those reserve expansions were offset, however, by reported decreases in all other regions. Reserves in Mexico were reported to decline by more than 50 percent (from 63 to 30 trillion cubic feet), and reserves in the United States and Western Europe also declined by 3 and 2 trillion cubic feet, respectively.
Gas reserves reported by Oil & Gas Journal are compiled from voluntary survey responses and do not always reflect most recent changes. Some significant gas discoveries made in 1999, for example in Asia and the Middle East, are not reflected in the most recent estimates.
In regional terms, world gas reserves are more widely distributed than oil reserves. The Middle East, which holds nearly 65 percent of global oil reserves, accounts for only 34 percent of gas reserves.
Thus, some regions with limited oil reserves hold a greater portion of global gas stocks. The FSU, in particular, accounts for around 6 percent of world oil reserves but nearly 40 percent of proven gas reserves, most of which (33 percent of world reserves) is located in the Russian Federation.
The Russian reserves are the largest in the world, more than double the second-largest reserve volume in Iran. Gas reserves are also more widely distributed than oil reserves within the Middle East, where Qatar, Iraq, Saudi Arabia, and the United Arab Emirates all have significant gas volumes .
Reserve-to-production (R/P) ratios exceed 100 years in the Middle East and Africa and are next highest in the FSU at 83.4 years. South and Central America also has a high ratio (71.5 years), but in North America and Europe R/P ratios are relatively low at 11.4 years and 18.3 years, respectively. The R/P average for natural gas in the world is 63.4 years, compared with 41 years for oil [1].
Regional Activity:
North America:
In the IEO2000 reference case, natural gas consumption is projected to grow by 1.6 percent per year between 1997 and 2020 in Canada and the United States and by 2.4 percent in Mexico.
Fuel use for electric power generation is largely responsible for the increases in all three countries. In the United States alone, natural gas consumption for electricity generation (excluding cogenerators) is projected to grow from 3.4 trillion cubic feet in 1997 to 9.3 trillion cubic feet in 2020.
In projections from EIA’s Annual Energy Outlook 2000 (AEO2000), nearly 90 percent of new electricity generating capacity between 1997 and 2020 is combined-cycle or combustion turbine technology fueled by natural gas or both oil and gas; and while increases are also expected in the other U.S. demand sectors, the growth in gas use in the electric utility sector is by far the most significant [2].
For Canada, the Canadian Energy Research Institute (CERI) estimates that gas demand for electricity generation could nearly triple in the next decade, assuming the continued restructuring of the electricity sector that is currently either underway or anticipated in many provinces.
In 1998, approximately 55 percent of Canada’s natural gas production was exported to the United States, and Canadian gas accounted for about 14 percent of U.S. consumption.
Canada’s exports have been growing steadily in response to increasing demand in the United States, more than tripling since 1985. By 2005, AEO2000 projects that Canada’s share of end-use consumption in the U.S. gas market will increase to 18.4 percent.
Currently, significant pipeline construction both within Canada and between the United States and Canada is underway to accommodate U.S. import demand.
By the end of 2000, five major new natural gas pipeline projects and an upgrade on a sixth (Alliance, Millennium, NOVA, Northern Border, TransCanada, and Maritimes Northeast) are expected to be complete, allowing a considerable increase in trade between the two countries [3].
Most of the construction will provide access to supplies in western Canada, and the Maritimes and Northeast project will transport supplies from Canada’s offshore Atlantic Sable Island fields to markets in New England.
Gas fields with more than 6 trillion cubic feet of combined reserves near Sable Island and at Terra Nova are under development, and Cambridge Energy Research Associates has indicated that natural gas reserves off Nova Scotia may be five times what has already been discovered, with approximately 53 trillion cubic feet possible [4].
Considerable pipeline construction is also under way in the United States. Several major projects will provide access to new sources of both supply and demand and increase capacity along corridors where utilization rates are high during peak periods.
Recently completed projects include Interstate’s Pony Express project, the Trailblazer system expansion, the Transwestern Pipeline expansion, and the El Paso Natural Gas system expansion.
The first two provide access to Wyoming and Montana production regions, and the last two provide access to New Mexico’s San Juan Basin. Further expansions are underway that will increase flows from these areas to markets on the east and west coasts. U.S. pipeline capacity expansion is expected to slow after 2001, however, to less than 1 percent a year.
Overall utilization of pipeline capacity is expected to increase significantly after 2001 as demand for natural gas to fuel electricity generation leads to increased flows during the summer months.
LNG imports are also becoming more economical for the United States. LNG imports are expected to increase more than fivefold between 1997 and 2020, from 0.08 trillion cubic feet per year to 0.39 trillion cubic feet per year.
In the past, U.S. LNG imports have come predominantly from Algeria. New sources of supply include Australia, Trinidad and Tobago, and Qatar, and Abu Dhabi and Norway are potential sources.
Additions to U.S. LNG import capability include a 50-percent increase in offloading capacity at the Everett, Massachusetts, port facility; a projected reopening of the Southern Natural Gas Company LNG terminal at Elba Island, Georgia; and a potential reopening of Columbia LNG’s Cove Point, Maryland, facility.
Both Elba Island and Cove Point were closed over 15 years ago when LNG became too costly to compete with other sources of natural gas in the United States. Cove Point subsequently reopened in the early 1990s for peak-period service storage only.
Preliminary approval to reopen Elba Island was granted by the Federal Energy Regulatory Commission (FERC) in December 1999, and Southern plans to begin importing up to 0.8 trillion cubic feet of LNG per year from Trinidad in 2002 [5].
Anticipating increased demand for LNG shipments, especially in the Northeast, Columbia LNG is hoping to recommission its Cove Point, Maryland, facility to provide LNG tanker unloading services.
The terminal can deliver up to 1 billion cubic feet per day to Columbia’s main system. If response is sufficient to a planned open season for customers to bid on capacity, as Columbia expects it to be, Cove Point will file with the FERC for authorization to recommission [6].
Although Mexico has considerable resources that could be developed, production is not expected to keep pace with rising internal demand, and Mexico is expected to remain a net importer of natural gas.
As in the United States and Canada, most of the projected growth in demand is for electricity generation. A recent forecast by the Mexican government indicates that natural gas demand will grow by 9.2 percent a year between 1998 and 2007, with consumption for electricity generation increasing by 20 percent a year.
Another area of significant growth in Mexico’s gas consumption is expected to be manufacturing and assembly plants located close to the U.S. border, where U.S. producers are in a much better position to satisfy the demand [7].
Although considerable investment is currently being made in the expansion of pipeline infrastructure, Mexico continues to have the problem, at least in the near term, of not being able to transport natural gas from southern producing regions to northern consuming regions in quantities sufficient to meet demand.
AEO2000 projects U.S. exports to Mexico to grow from 0.05 trillion cubic feet in 1997 to 0.24 trillion cubic feet in 2020, in the wake of Mexico’s recent elimination of a 4-percent import tariff and an increase in pipeline capacity between the two countries.
Western Europe:
Europe’s gas reserves, which account for less than 5 percent of global resources, are located predominantly in the Netherlands, Norway, and the United Kingdom.
Production in those three countries currently surpasses production in other regions with greater reserves, such as the Middle East.
Nearly one-third of Europe’s gas demand is met by supplies from outside the region, particularly pipeline imports from the FSU and Algeria, as well as LNG primarily from North Africa.
Recent demand increases reflect rising gas use for power generation as well as in the industrial sector. Demand growth has been particularly strong in Greece, Portugal, Italy, Spain, Finland, Belgium, and Denmark. IEO2000 projects growth in Western Europe’s gas use averaging 2.9 percent per year, reaching 25.9 trillion cubic feet by 2020.
European investments in infrastructure in 1998 included the completion of the Interconnector and at least four other significant pipeline projects, and 1999 saw the on-schedule completion and commissioning of the Europipe II. The 420-mile Europipe II, operated by Statoil, links Norway’s west coast to Dornum in northwest Germany.
With its commissioning, imports from Norway could supply up to 30 percent of Germany’s natural gas use by 2010 [8]. In IEO2000, German gas consumption is expected to rise by an average of 2.9 percent per year, nearly doubling in 2020 from the 1997 level of 3.4 trillion cubic feet.
Elsewhere in Europe, pipeline projects such as a Swiss line scheduled for completion in October 1999 will improve and increase north-south gas flows. Future construction in Switzerland could eventually double capacity by 2003.
A new leg of the Yamal-Europe pipeline was also completed in Germany in September. Financed by Wingas and Gazprom investment, the 209-mile section stretches from Frankfurt-on-Oder to Rueckersdorf, Thueringen, and will transport up to 990 billion cubic feet of gas per year to German and West European consumers [9].
Germany’s Ruhrgas started construction of a 71-mile pipeline from Mittelbrunn in Saarland to Esch in Luxembourg. With deliveries scheduled to start mid-2000, the $45 million project will transport 20 billion cubic feet of gas annually to a gas and steam power plant under a 15-year contract signed with Soteg [10].
In addition to the announced and planned mergers of such large international corporations as BP, Amoco, and ARCO and Mobil and Exxon, Europe also saw important mergers in 1999. TotalFina and Elf Aquitaine agreed in September to a friendly merger that would rival BP Amoco (which plans to merge with ARCO) in European gas production and marketing.
In October, however, the European Union announced an investigation into the merger, citing concerns about potential dominance in the liquid petroleum gas (LPG) market [11].
In Germany, Veba and Viag will merge to create a group with electricity, natural gas, and water businesses and with the stated goal of pursuing growth abroad through targeted acquisitions [12].
Strong gas market growth continues in Italy and Spain. Italy’s Eni announced that final agreements were reached with Libya’s National Oil Corporation (NOC) to import gas via a new undersea pipeline.
Plans call for imports of some 280 billion cubic feet per year starting as soon as 2003, with Italy now in the stage of awarding contracts [13].
Regional approval has been given to Edison-Mobil plans for a new Italian LNG receiving terminal in the northern Adriatic Po Delta to be built on an artificial island; approval by the national government is still required. The terminal could be operational as early as 2003, with Egypt as the potential supplier of LNG [14].
Spain has agreed to buy more LNG from Shell-led facilities in Nigeria, enabling Shell to go forward with expansion plans there. Spanish gas demand is expected to grow rapidly after 2000, when a series of gas-fired, combined-cycle power plants are due for commissioning [15].
Competition has been increasing in the Spanish gas and power markets with the government’s announcement of new operators allowed in each market. Five more companies now able to trade in gas include Enagas, Gas de Asturias, Gas de Euskadi, Iberdrola, and BP Amoco [16].
In Portugal, plans continue to develop the country’s first LNG receiving terminal, to be sited on the Atlantic coast near the Sines oil terminal. Transgas Atlantico is seeking a turnkey contractor for the project and has issued an invitation to tender. Construction could begin by the end of 2000.
Eastern Europe and the Former Soviet Union:
In most of Eastern Europe, natural gas consumption continued to decline in 1998, although there were increases in some countries.
The Russian Federation continued to dominate world trade movements of natural gas, exporting 4.2 trillion cubic feet to Europe and to other FSU countries. The only other exports of natural gas from the FSU were 63.5 billion cubic feet delivered to Iran from Turkmenistan [17].
Nonpayment for gas supplies continues to be an issue throughout the FSU, both within and between countries, and barter continues to be an accepted form of payment. Uzbekistan threatened to stop deliveries to Kyrgyzstan on November 15, 1999, if the mounting debt was not paid.
Because of problems with Kyrgyzstan’s hard currency, Uzbekistan had agreed to take partial payment for gas supplies in flour, but Kyrgyzstan had fallen considerably behind even in its “flour debt.” As a result, the Uzbek gas transport company Uztransgaz indicated that it had no option but to cut off supplies [18].
Deliveries were temporarily halted but resumed in mid-December after the payment of $3 million, partly in cash and partly in goods. The gas currently being received is roughly half the amount received during 1998, and it is going mainly to homes in the northern part of the country [19].
Belarus, in debt to the Russian gas monopoly Gazprom, has major internal problems with consumers not paying their gas bills, which in turn make it difficult for the Belarusian government to pay Gazprom.
The government gave internal consumers until January 1, 2000, to pay gas debts, and the state-owned gas transport company Beltranshaz proposed that partial payment of the debt to Gazprom be made in agricultural equipment [20].
The situation is similar in Ukraine, which owes Russia more than $1 billion for natural gas purchases. Ukraine’s internal nonpayment problem is significant, with consumers owing Naftogaz Ukrainy about $3 billion.
In an effort to secure payment from domestic customers, the government has been cracking down on nonpaying customers by curtailing supplies. A total of 13,700 were disconnected in 1998, including 3,650 industrial customers.
After some initial problems involving cutoffs during the cold winter months, the government pledged to forbid cutoffs during the winter. Cutoffs resumed in the spring, however, and at the beginning of April 1999, 378 debtor firms were disconnected from natural gas supplies [21].
Ukraine has resorted to barter to satisfy its external debt, agreeing to deliver to Russia 11 bombers and 500 cruise missiles, valued at $285 million, by the end of 1999 as partial payment of the debt owed to Gazprom.
The first of the bombers, all of which were inherited after the breakup of the Soviet Union, were delivered to Russia in November 1999 [22]. Ukraine is also in debt to Turkmenistan for gas supplies delivered as far back as 1993, and Turkmenistan cut off supplies in June 1999.
The debt has since been restructured, with payments to be completed in December 2001. In October 1999, the debt exceeded $300 million [23].
Russia has also threatened to take action against Ukraine for reasons other than nonpayment. Ukraine is the main transit route for Russian gas to reach European markets, and Russia has long accused Ukraine of siphoning off gas during transit.
Itera, the main supplier of Russian gas to Ukraine, threatened to stop supplying gas to Ukraine by October 1, 1999, pending payment of debt. Gas exports are a major source of revenue for Russia, and over 90 percent of gas exported by Russia passes through Ukraine.
According to a Gazprom spokesman, since ceasing gas flow to Ukraine would entail giving up the European market, it is unlikely that gas shipments to and through Ukraine will cease anytime soon [24].
Although Russian natural gas trade with Europe is currently dependent on Ukraine, Russia expects new export routes to be developed in the next few years.
The first section of the Yamal-Europe pipeline, through Belarus and Poland, went into operation in 1999, and a second parallel section is in the planning stages.
The new pipeline allows Russia to eliminate Ukraine from its route to Western Europe, which currently receives 25 percent of its natural gas from Gazprom. Gazprom is eager to increase exports to Western European customers, who pay on time and in U.S. dollars, in sharp contrast with domestic customers, who make only 20 percent of their payments in cash, if at all [25].
Although still awaiting final approval, the Blue Stream pipeline, which would traverse the Black Sea bed and transport Russian gas to Turkey and Southeast Europe, is expected to become operational in 2001.
A third project under consideration is the construction of a pipeline through the Baltic Sea to Germany. If these projects are built and become fully operational, shipments of Russian gas through Ukraine will decline by about one-third [26].
The Blue Stream project to supply Russian gas to energy-hungry Turkey is in competition with another project, the Trans-Caspian project, which would supply Turkey and western markets with gas from Turkmenistan and Azerbaijan.
Although it was initially intended to ship supplies from Turkmenistan alone, Azerbaijan entered the pictured after the discovery earlier this year of large volumes of natural gas at its offshore Shakh Deniz field.
Reserves are said to be between 14 and 25 trillion cubic feet, and geologists have indicated that additional finds are likely.
Given that Azerbaijan has indicated that this discovery alone would allow them to export 0.6 to 0.7 trillion cubic feet per year, it is doubtful that they will elect to play solely a transport role in the Trans-Caspian project.
Azerbaijan is also exploring the possibility of exporting gas to Iran by way of an existing pipeline. As of late November 1999, Turkey had still not made the decision whether to support the Blue Stream project or the U.S.-supported Trans-Caspian project.
Turkey has indicated that it does not feel that the two projects are in competition with, or alternatives to, each other, because the amount of gas proposed from both sources will still fall short of satisfying Turkey’s projected natural gas demand.
The Trans-Caspian line would carry 0.6 trillion cubic feet of gas per year from Turkmenistan, and possibly Azerbaijan, to Turkey. According to its sponsors, it could ultimately gain another 0.5 trillion cubic feet of capacity to serve international markets. The Blue Stream pipeline would have an ultimate capacity of 1.1 trillion cubic feet.
Turkey has projected that it will need 1.9 trillion cubic feet of gas by 2010, and needs to find and purchase as much natural gas as it can as soon as possible [27].
Even as Russia hopes to reduce its dependence on Ukraine, Ukraine wants to diversify its gas sources so that it is less dependent on Russia. Ukraine currently produces just about 25 percent of the gas it consumes, with most of the balance coming from Russia.
Ukrainian officials met with a delegation from Afghanistan in September 1999 to discuss the possibility of receiving gas from Afghanistan [28], and Ukraine has announced plans to conduct talks with Kazakhstan about purchasing 0.2 trillion cubic feet of natural gas in 2000 [29], representing roughly 10 percent of the amount currently imported from Russia.
Another major consumer seeking to lessen its dependence on Russia is Poland. In the past Russia has met nearly all of Poland’s natural gas needs. As a move towards diversification, however, Poland signed a 5-year gas supply contract with Norway in December 1999 for supplies beginning in 2001.
Talks to determine how the gas might be transported to Poland are only at an initial stage, however [30]. Poland is anticipating large increases in natural gas demand between now and 2020 and is dependent on imports to meet most of the new demand.
Natural gas industry restructuring, which will facilitate gas purchases from countries such as Norway, Holland, and Germany, is in the works, with an anticipated start date sometime in 2001. Accompanying the restructuring is a move toward privatization, which the government expects to be completed in 2005.
In spite of the uncertainties and problems currently facing the EE/FSU, IEO2000 projects significant future growth in the region’s natural gas markets. Consumption in the FSU is projected to grow at a rate of 2.1 percent a year between 1997 and 2020, with the strongest growth at the end of the forecast period from 2015 to 2020.
The projected increase in Eastern Europe is steadier but considerably higher, at an overall rate of 5.6 percent per year. Total EE/FSU consumption nearly doubles, from 22.3 trillion cubic feet in 1997 to 41.2 trillion cubic feet at the end of the forecast period.
The considerable effort, both internally and via foreign investment, that is going into the development of the region’s natural gas infrastructure will be a significant factor in increasing future production, consumption, and export capabilities for natural gas.
Central and South America:
Central and South American gas markets are small in terms of total volumes handled, but they continue to show strong growth with active upstream and downstream development. Between 1990 and 1997, the region’s gas consumption grew by an average of more than 5 percent per year.
Estimated reserves in the region account for less than 5 percent of global gas reserves, but much of the area has been underexplored, and discoveries are accompanying recent exploration activity.
Production, consumption, and trade are also limited. Production and consumption of natural gas in the region were at about 2.9 trillion cubic feet in 1997. In 1999, natural gas trade extended outside the region with initiation of LNG exports from Trinidad and Tobago. The only international pipelines in the region before 1999 operated from Bolivia to Argentina and from Argentina to Chile.
The IEO2000 reference case projects that the region’s gas use, facilitated by additional pipelines, will grow to 15.3 trillion cubic feet by 2020, at an average annual growth rate of 7.5 percent.
On the production side, a new LNG facility in Trinidad and Tobago came on stream in 1999, loading the first Atlantic Basin export cargoes in April [31]. Starting in 2000, the U.S. LNG company Cabot will take 1.8 million metric tons of LNG per year from the facility, some of which will be delivered to Puerto Rico.
A new receiving terminal now under construction in Puerto Rico will enable increased use of gas in power generation. BP Amoco and Repsol are promoting plans to add two more LNG trains in Trinidad and Tobago, with Spain lined up as a buyer for at least some of the increased output and Cabot also expected to take more gas [32].
Much of the gas market growth in South America involves Brazil, a large country with large projected gas demand. In the IEO2000 reference case, gas use in Brazil grows from 0.2 trillion cubic feet in 1997 to 2.5 trillion cubic feet in 2020. A new Bolivia-Brazil pipeline began operating in July 1999 after years of negotiation.
Initially, the line was expected to begin carrying about 78 million cubic feet per day to Brazil, rising to 200 million cubic feet per day by the end of 1999 and then to 318 million cubic feet per day in 2000, when a take-or-pay contract begins. By 2006, volumes could exceed 1 billion cubic feet per day, worth about $400 million per year.
Ranging only around 22 to 53 million cubic feet per day due to a significant rise in Brazilian gas prices. Prices are linked via formulae to fuel oil prices (which were rising) and were also affected by a 40-percent devaluation of the Brazilian real. Pipeline operators are estimating the associated financial loss at about $500,000 per month [33].
A second line to Brazil is now under consideration following significant gas discoveries in Bolivia, but construction is not anticipated before 2001.
In addition, an Enron project involving a 390-mile pipeline from Bolivia to Cuiaba in Brazil has received approval from the U.S. Overseas Private Investment Corporation (OPIC) for a $200 million credit, despite objections from environmentalists.
Protestors opposed the pipeline route through what may be the world’s largest intact dry forest (called Chiquitana). Backers of the project have emphasized planned environmental mitigation measures (including a partial rerouting to avoid the most environmentally sensitive areas and a pledge of $20 million over 15 years for conservation efforts) as well as benefits of new gas supplies replacing diesel use and local firewood demand.
A 490-megawatt Cuiaba power plant and the pipeline together amount to a $570 million effort involving Shell and Bolivian firm Transredes (50 percent owned by Enron and Shell) [34].
In addition, a pipeline to Brazil from Argentina is under construction to enable the first imports of Argentine gas. The 272-mile Transportadora de Gas del Mercosur, SA (TGM) pipeline from Parana in Entre Rios, Argentina, to Uruguaiana, Brazil, will connect to Argentina’s existing domestic line, Transportadora de Gas del Norte (TGN). CMS Energy holds equity in both pipelines.
TGM’s other owners include Canada’s TransCanada Pipelines, Argentina’s CGC and Techint, and Malaysia’s Petronas. The pipeline is scheduled for completion in 2000 and will initially transport about 100 million cubic feet per day, with capacity expandable up to 425 million cubic feet per day [35].
To address higher gas prices in Brazil and encourage gas-related investment, particularly in the power sector, the government announced that it may control prices in some regions.
In southern, southeastern, and central western states as well as the Brasilia Federal District, power projects signing 20-year contracts could have a price ceiling equivalent to $2.26 per million Btu (in 1999 dollars). In Brazil’s northeast, where gas will initially be domestically supplied, there is a proposed price ceiling for the first 5 years of $1.94 per million Btu and $2.26 for the remainder of the 20-year period.
As many as 23 power plants with a combined capacity of 7,400 megawatts could benefit from the price control policy. The move is welcome by foreign investors and will facilitate project funding, because it fixes long-term contracts in dollars rather than the more volatile Brazilian real [36].
Elsewhere in South America, the GasAtacama pipeline began operating in mid-1999, sending gas from Argentina to Chile. It is the second pipeline linking the two countries, after TransCanada’s GasAndes pipeline in central Chile, which started operation in 1997.
The $400 million GasAtacama line was built by CMS Energy and Chilean generator Endesa in a project that includes a $350 million, 370-megawatt power plant.
A parallel and rival line, Norandino, backed by Belgian Tractabel and Southern Energy, began operation at the end of 1999. The 585-mile GasAtacama has a capacity of 300 million cubic feet per day but will operate significantly below that at first.
Because the project’s associated long-term electricity sales contract with Chilean Emel and its distribution companies (via the Nopel power plant) does not begin until 2002, it will sell power on the spot market at first. A pipeline extension is being planned to reach other power plants [37].
A pipeline has also been proposed for transporting Colombian gas into Central America. Backed by local firm Promigas (operated by Enron) and supported by state oil company Ecopetrol, such a project could supply gas to Panama, Costa Rica, and Nicaragua.
Conceived to find markets for Colombia’s abundant known and potential reserves, the line could face a possible competing or complementing project from Mexico [38]. Venezuela has also expressed an interest in exporting gas to Central America and/or forming a strategic alliance with Ecopetrol [39].
In Peru, the government repeatedly postponed bidding deadlines in 1999 for the sale of the $2 billion Camisea natural gas project.
Although the delays purportedly were to give interested parties more time, they followed the resignation of energy and mines minister Daniel Hokama, as well as reports of disagreement within the government’s Camisea committee.
Potential investors have complained that the terms of the project are not sufficiently attractive and that gas prices should be set by the market, while the government has maintained that set prices are needed as incentive to potential power producers [40].
Venezuela’s election of populist president Hugo Chavez has led to turmoil and power struggles for Petroleos de Venezuela (PDVSA), one of Latin America’s biggest companies.
The president of PDVSA, Roberto Mandini, has resigned, to be replaced by Hector Ciavaldini, who is said to back reforms promoted by Venezuelan President Chavez including a government effort to control the oil industry. PDVSA has been described as the economic backbone of Venezuela, the largest producer and consumer of natural gas in South and Central America [41]. Reorganization at PDVSA includes the establishment of a Natural Gas Division, reflecting a government preference to emphasize gas resource development.
Although PDVSA will no longer pursue plans with Shell for an offshore Cristobal Colon LNG project because of poor economics, it is still looking for potential LNG or pipeline projects to commercialize gas reserves. Several domestic pipeline projects will also be prioritized [42].
Asia:
Gas market activity in Asia during 1999 reflected ongoing recovery in the region from the Asian financial and economic crisis. Demand growth recovered, most notably in South Korea and Thailand, and new projects moved forward. In the IEO2000 reference case, the growth rate for natural gas use through 2020 in the whole of Asia (both industrialized and developing) averages 5.6 percent per year, increasing consumption to 31.5 trillion cubic feet from 8.9 trillion cubic feet in 1997. The projected demand growth in developing Asia is much higher than in the industrialized countries of the region.
Source: United States Energy Information Administration
