Economic uncertainty trims plans for pipeline construction

Tight markets for refined products west of the Rocky Mountains and around El Paso are responsible for a flurry of petroleum product pipeline work under way in 1998 and 1999. Here, Four Four Construction, Farmington, N.M., lowers in a 17-mile, 10-in. segment near Mack, Colo., as part of an expansion of Tulsa-based Williams's NGL system in the Rocky Mountains. Start-up of the 412-mile loop expansion this summer will bring the system to 125,000 b/d from 75,000 b/d. In Texas last year, Longhorn Pipeline Co., Houston, converted an idle crude oil pipeline and extended it from the Permian basin to El Paso. Photograph by Ed Lallo, Dallas, courtesy of Williams.

• Pipeline Construction, 1999 and Beyond [165,127 bytes]

Global oversupply and reduced demand are hammering the world's energy markets as 1999 begins. And the effects are clear in reduced plans for new pipeline construction.

Plans for petroleum (oil, condensate, and natural gas liquids) and natural gas pipeline installation in 1999 show a decline of 28% compared with plans announced a year ago for 1998 (OGJ, Feb. 9, 1998, p. 37). Plans for construction beyond 1999 are off almost equally, 27.4%.

But the data published in 1998 were compiled before full effects of the Asian financial crisis had begun to emerge. For 1999 and beyond, more than 48,700 miles of crude oil, product, and natural gas pipeline are planned (see map, p. 37).

Despite effects of the economic downturn, Asia and Latin America expect to see addition of significant mileage in the near future. And in 1999-2000, major volumes of Canadian natural gas will begin to flow into U.S. Midwest and Northeast markets, possibly leading to a capacity surplus.

In both Latin America and Europe, gas-grid evolution continues.

These trends are evinced in the latest Oil & Gas Journal pipeline construction data derived from a survey of world pipeline operators, industry sources, and published information.

Bases, costs

For 1999 only see table 1 [119,033 bytes] companies reported plans to complete more than 16,000 miles of oil and gas pipeline worldwide at a cost of more than $20 billion. For 1998 only, companies had predicted more than 23,000 miles at more than $26 billion.

For projects completed after 1999 see table, [122,857 bytes] companies expect to spend another $39.8 billion to lay more than 32,000 miles of line. Last year, when these companies looked beyond 1998, they expected to lay more than 44,000 miles at a cost of $50 billion.

Projections for 1999 pipeline mile- age reflect only projects expected to be completed by yearend, including construction in progress at the first of the year. Projections for mileage in 1999 and beyond include construction that might begin this year but will be completed in 1999 or later. Some probable long-term projects are included, even if their sponsors break ground in 2000 or later.

Cost estimates are based on U.S. average cost per mile for onshore and offshore gas pipeline construction as found in Table 4 of OGJ's most recent Pipeline Economics report (OGJ, Aug. 31, 1998, p. 33).

Cost projections assume, based on historical analysis, that 90% of all construction will be onshore and 10% offshore. Pipelines of 32 in. OD or larger are assumed to be onshore projects. With these assumptions and OGJ pipeline-cost data, here is a breakout of costs by line size:

• Total onshore construction (15,558 miles) for 1999 only will cost $19.3 billion-$3 billion for 4-10 in., $5 billion for 12-20 in., $4.8 billion for 22-30 in., and $6.5 billion for 32 in. and larger.
• Total offshore construction (1,139 miles) for 1999 only will cost more than $1.4 billion-$334 million for 4-10 in., $556 million for 12-20 in., and $534 million for 22-30 in.
• Total onshore construction (29,941 miles) for beyond 1999 will cost $37.2 billion-$1.5 billion for 4-10 in., $10.4 billion for 12-20 in., $11.3 billion for 22-30 in., and nearly $14 billion for 32 in. and larger.
• Total offshore construction (2,082 miles) for beyond 1999 will cost more than $2.6 billion-$168.7 million for 4-10 in., $1.2 billion for 12-20 in., $1.3 billion for 22-30 in.

U.S., Canada action

The U.S. Energy Information Administration (EIA) noted the rapid growth of the U.S. gas pipeline grid in the decade and forecast more of the same.

Meanwhile, a combination of two of North America's largest pipeline companies in 1998 was a by-product of wrangling over one of the region's most significant projects in years, the 1,900-mile Alliance dense-phase gas pipeline from Alberta to near Chicago. Construction of that project will begin this year.

U.S. trends, growth

Throughout the 1990s, OGJ has reported North American-especially U.S.-pipeline firms' plans to add hefty new capacity. Those forecasts were borne out in a 1998 EIA report.

EIA said the U.S. gas pipeline industry's capacity to move gas reached more than 84 bcfd in 1997, up 15% from installed capacity reported in 1990. By 1996, gas shipments had increased 24% from 1990 levels, with a record 75% utilization of installed capacity.

In the near future, said the agency, some bottlenecks may develop in moving new Gulf of Mexico production beyond onshore Louisiana. But these potential bottlenecks can be partially or completely offset by planned new or expanded underground storage facilities. EIA also noted significant changes in traditional patterns of gas movement since 1990.

Gas from western and Rocky Mountain producing areas is increasingly moving away from western markets, and key projects have been built or are planned to accommodate this shift.

The most extensive development of new pipeline capacity during the next several years, said EIA, will occur along corridors connecting Canada to U.S. Midwest and Northeast markets to handle ever-growing Canadian imports (see related story, p. 40). Among these is the corridor being developed for gas from the Sable Island fields off the Canadian East Coast. Expansions could add as much as 8.6 bcfd to U.S. import capacity from Canada by 2001.

More recently, EIA predicted U.S. gas pipeline development and expansions could add as much as 16 bcfd of capacity during 1999-2000, at a total cost of about $9.5 billion. EIA said that, while more than 11 bcfd of capacity was added to the U.S. transmission network in 1998, costs were relatively low at $2.9 billion vs. $3.1 billion projected for 1999 and $6.3 billion for 2000.

The growth of Canadian imports into the U.S. Midwest will increase use of the Chicago hub market center as a transshipment point for supplies en route to a growing gas market in the U.S. Northeast, according to EIA. A market center near Leidy, Pa., where several pipelines serving the Northeast interconnect, also should grow significantly.

EIA said the pipeline sector growth is primarily the result of growing demand for gas as fuel for electric generating plants that are replacing coal and oil-fired units.

Canadian merger, exports

In a year of big mergers, 1998 saw the combination of Nova Corp. and TransCanada PipeLines Ltd., Canada's two largest pipeline companies. The merged company, with assets of $21 billion (Canadian) and revenues of $15.6 billion, became at midyear the fourth largest energy services company in North America, with a combined network of nearly 22,500 miles. Nova's Alberta pipeline unit became part of a wholly-owned unit of TransCanada. Both companies had international units in South America and elsewhere that were combined into TransCanada PipeLines International.

Consistent with EIA forecasts of increased Canadian exports to the U.S. in the near term is a flurry of construction under way or about to begin to hike Canadian export capacity.

Early this year, the Alliance Pipeline group will begin construction of its $3.7 billion (Canadian), 1,864-mile dense-phase line between Alberta production and U.S. Midwest processing and distribution. Planned completion is October 2000. Investors in the Alliance Pipeline LP include: Fort Chicago Energy Partners LP 26%, Enbridge Inc. (formerly Interprovincial Pipe Line Ltd.) 21.4%, Westcoast Energy Inc. 14.5%, Coastal Corp. 14.4%, Duke Energy Corp. 9.8%, Unocal Corp. 9.1%, and Tulsa's Williams 4.8%. Alliance has contracts to move up to 1.3 bcfd of gas.

But the other major export systems out of Alberta are also in the process of expansion.

Northern Border Pipeline Co., Omaha, completed its 390-mile, 36 and 30-in. Chicago project and began accepting nominations for the added 700 MMcfd of capacity. The $839 million project, which also added 303,500 hp of compression, expanded Northern Border's existing 1,213-mile, 1,675 MMcfd system.

The company, which moves about 25% of all Canadian gas imported into the U.S., is owned by Northern Border Partners LP 70% and units of Trans- Canada PipeLines Ltd. 30%.

In related action, Northern Border also hired Willbros Group Inc., Tulsa, to build a 94-mile, 36-in. Iowa pipeline from Harper to Davenport.

Not to be left in the dust, TransCanada let pipeline maintenance, looping, and compressor-station construction contracts worth a combined total of $430 million (Canadian) last year.

In addition, it filed with Canada's National Energy Board (NEB) to build a $161.8 million (Canadian), 61-mile, 36-in. natural-gas pipeline across Lake Erie to move gas to U.S. Northeast and Mid-Atlantic markets. TransCanada also expects to connect at St. Clair, Ont., with the proposed Millennium Pipeline in the U.S.

Initial capacity of the new line would be 700 MMcfd. The Lake Erie crossing and Millennium are expected to be in service by Nov. 1, 2000.

Millennium Pipeline Co. LP's schedule calls for a phased construction plan, with some portions of its 442-mile gas pipeline serving the Northeast U.S. to be completed in 1999 and the rest in 2000. Columbia Gas Transmission Corp., Reston, Va., is the project's developer and largest interest holder. The $650 million project will begin at the Canadian border on Lake Erie and extend across southern New York state to Westchester County. The system will include more than 30 connections to utility customers, pipelines, and gas storage facilities.

From the east

On the eastern side of the continent, activity was also pushing ahead to bring offshore gas to Canada's eastern provinces and states of the upper Northeast U.S.

Maritimes & Northeast Pipeline LP (M&NE) let a $300 million (Canadian) construction contract to an alliance of BFC Pipelines, Scarborough, Ont., a unit of BFC Construction Group Inc.; and Marine Pipeline Construction of Canada, a division of Murphy Pipeline Inc., East Moline, Ill. The alliance will lay M&NE's 350-mile pipeline from Goldboro, N.S., to St. Stephen, N.B., to move Sable Island gas to markets in Atlantic Canada and the U.S. Northeast. Construction is to begin this year, with first gas to flow by the fourth quarter.

M&NE also applied to NEB to lay gas pipeline laterals to Halifax, N.S., and St. John, N.B. The Halifax lateral will be 75 miles of 12-in. line from a main line near Stellarton, N.S., to a power-generating station at Tufts Cove. Estimated cost of the lateral is $74 million, and volume will be 60 MMcfd. The St. John lateral will be 63 miles of 16-in. line from M&NE's main line to St. John at a cost of $91 million to move nearly 131 MMcfd. Both laterals will be in service Nov. 1, 1999.

In other Canadian activity, Enbridge will begin natural gas shipments to the Chicago area by October 2000 on the $471-million (U.S.) Vector Pipeline system.

Construction of the 344-mile line from Chicago to Dawn, Ont., near Sarnia, will be completed in mid-2000. The line will have capacity of 1 bcfd into Chicago and interconnect with the Alliance pipeline project from Western Canada and with an extension of the Northern Border Pipeline system.

U.S. activity

In a project related to Alliance and south of the Canadian-U.S. border, four U.S. natural gas companies plan to develop a major pipeline for delivering gas to U.S. Midwest markets.

The $220-280 million Illinois-Wisconsin Express Project will move gas from Western Canada and major U.S. supply basins. The project will be a 36-in., 150-200 mile pipeline from Joliet, Ill., and ending near Fond du Lac, Wis. The pipeline is scheduled to be in service by November 2001 with initial capacity of 650 MMcfd.

The U.S. Gulf Coast continues to be a hot spot for gas line construction plans.

Last year, Koch Gateway Pipeline Corp., Houston, announced plans to expand with an interconnection near Grand Isle, La., and possibly double capacity in a second phase.

Koch would lay about 5 miles of 20-in. lateral line to connect its 36-in. Gulf Coast main line to a processing plant near Grand Isle. This would add 300 MMcfd of capacity. In a second phase, Koch would boost capacity by another 300 MMcfd by adding looping and compression.

Koch's plans would complement the planned Sea Star Pipeline LLC project, which will add 600 MMcfd of capacity from the South Pass Area and West Delta South Addition to processing at Grand Isle.

Columbia Gulf Transmission Co. wants to lay the 56-mile, 660 MMcfd gas line and expand its East Lateral system in southeastern Louisiana by 600 MMcfd. The project will consist of a 30-in. main line and two 24-in. laterals.

Also in the area, newly formed Tri-States NGL Pipeline LLC will build an NGL pipeline from Alabama and Mississippi to plants in Louisiana. The line will have an initial capacity of 80,000 b/d and final capacity of 150,000 b/d. Participating companies are Amoco Pipeline Co., Enterprise Products Co., Koch Pipeline Southeast Inc., a group led by Duke Energy Field Services Inc., Shell Oil Co.'s Tejas Natural Gas Liquids LLC unit, and a unit of Williams. The pipeline will link three gas processing plants under construction to new and expanded fractionation plants on the Mississippi River.

Williams, Amoco Oil Co., and Enterprise Products Operating LP are forming Wilprise Pipeline Co. LLC, a joint venture to build a 30-mile, 12-in., 100,000 b/d pipeline to deliver NGL from Kenner, La., to storage facilities in Sorrento, La. Kenner will be the terminus of Tri-States Pipeline.

Williams is also involved, via its Mid-America Pipeline Co. subsidiary, in expanding its NGL pipeline system in the Rocky Mountains to 125,000 b/d from 75,000 b/d. The expansion involves construction of a 412-mile pipeline from northeast Utah's Daggett County to Bloomfield, N.M. The new line will run parallel to the existing Mapco system.

Construction began in August 1998 and will be in service by March 1999.

Knitting the European grid

Two major systems started up last year as Europe's appetite for gas, especially from the northern North Sea, continues to grow.

U.K. to continental Europe

In October 1998, the Interconnector pipeline began moving gas between Bacton terminal in the U.K. and Zeebrugge terminal in Belgium. The $725-million, 150-mile, 40-in. line can deliver 700 bcf/year of gas to continental Europe.

Belgium's Distrigaz expanded its gas grid to allow Interconnector to deliver to other European countries through four border delivery points. At start-up, U.K. gas suppliers announced contracts amounting to only 280 bcf/year with European customers; further negotiations were under way. Almost half the gas is going to German distributors, with three industrial projects taking a combined 87.5 bcf/year, and to Dutch state distributor Gasunie taking 35 bcf/year beginning in April 1999.

Norway to Europe

Also in October, Norway's Statoil and partners started up the $1 billion, 522-mile, 42-in. NorFra gas line linking Europe via Loon Plage, France, near Dunkirk, to Troll field off Norway. The line accounts for 30% of France's gas imports, is the country's first direct link to a foreign natural gas field, and bolsters the country's position as a major distribution hub in Europe's newly liberalized natural gas market. It is owned by an 11-member group: operator Statoil, Norsk Hydro AS, Norske Shell AS, Esso Norge AS, Elf Aquitaine, Saga Petroleum AS, Norske Conoco AS, Total, Neste Oy, Mobil Exploration Norway AS, and Agip SpA. The landing terminal in France, owned 65% by the NorFra group and 35% by Gaz de France (GdF), can treat up to 1.75 bcfd.

To distribute the additional gas supplies, GdF invested 1 billion francs to construct one of France's largest gas pipelines, the 115-mile, 44-in. Artère des Hauts-de-France system. It links the Dunkirk terminal to GdF's transmission system near the underground storage terminal at Gournay-sur-Aronde, France.

In addition, to move gas that has crossed France to other markets, a gas pipeline called Les Marches du Nord-Est will traverse Switzerland on its way to Italy, where Snam SpA will take the gas. Half the gas coming from Norway will transit via GdF's network to Spain and Italy.

By 2005, France will be receiving about 525 bcf/year of gas from Norway-equal to about one third of French gas demand. At that time, Norway will be France's leading gas supplier, ahead of Russia and Algeria. And France will become Norway's second largest gas importer, behind Germany's Ruhrgas. For its part, Norway has developed an aggressive plan to increase gas exports. By 2005, it will be exporting to continental Europe about 2.625 tcf/year, up from 1.481 tcf in 1997. If needed, said Statoil Pres. Harald Norvik, Norway's five gas pipelines could be expanded with additional compression to ship 3.5 tcf/year.

Latin American network

Evolution of the South American gas network continues, as major supply routes are being established among Bolivia, Brazil, Argentina, Chile, and Uruguay.

Dedication

Feb. 9 will see the dedication of one of the most ambitious pipeline projects in years for South America: officials from Bolivia and Brazil will meet to dedicate the $2 billion, 1,978-mile Bolivia-Brazil natural gas export pipeline (BBPL).

The line, with 464 miles to be built in Bolivia, starts from Rio Grande, Bolivia, and passes through the Bolivian town of Puerto Suarez on the border with Brazil. It then extends to the Brazilian town of Corumba and crosses the states of Mato Grosso do Sul and Sao Paulo, up to the city of Campinas and on to Parana and Santa Catarina states, terminating at Porto Alegre, the capital of Rio Grande do Sul state.

It is designed to transport 280 MMcfd of Bolivian natural gas to southern Brazil. Later, pipeline capacity may be expanded to 560 MMcfd, depending on market demand.

The project is widely considered a cornerstone of efforts to establish an energy grid in the Southern Cone nations of South America.

Wood Mackenzie Consultants Ltd., Edinburgh, thinks Bolivia already has enough gas production capacity to meet the requirements of Brazilian customers supplied through BBPL until about 2011. Argentina is Bolivia's most serious competitor for gas supplies to Brazil.

Movements west, north

Wood Mackenzie estimates Argentina's reserves at 35 tcf of gas, but more than 32 tcf of gas is expected to be required to meet domestic demand and exports to Chile over the next 20 years.

Last year saw more Argentine activity in the direction of Chile: Two more projects to move gas were nearing completion as 1999 began.

In the north, Gasoducto Atacama Cia. Ltda. (GasAtacama) began laying a 300-MMcfd, 584-mile, 20-in. natural gas pipeline from Argentina to Chile in late 1997. It is the second line to bring Argentine gas to Chile; GasAndes (OGJ, Apr. 21, 1997, p. 61) started up in August 1997 supplying gas to Santiago and environs.

GasAtacama is a joint venture of four companies, including major shareholders CMS Energy Corp., Dearborn, Mich., and Chilean power generator Endesa, Santiago, each with 40%. Remaining ownership is split between two Argentine gas producers: Pluspetrol Energy 16% and Astra 4%. The pipeline will transport gas from gas fields in Argentina's Noroeste basin, near Salta, to Mejillones, Chile. The pipeline is set for completion sometime in first quarter 1999. Total cost of the pipeline and power plant near Mejillones will be about $750 million.

In late 1998, GasAtacama had secured contracts for 160 MMcfd of gas. Of that total, 127 MMcfd were to be shipped to the 740-MW combined-cycle plant being built at Mejillones by owner and operator Nor Oeste Pacífico Generación de Energía Ltda. (Nopel), the same partnership that makes up GasAtacama.

A portion of the 127 MMcfd of gas shipped to Mejillones will be transported further south to a 350-MW plant Endesa is building at Taltal, Chile. The 160-mile Gasoducto Taltal extension is expected to cost $30 million but is on hold for the foreseeable future.

In the south of Chile, construction of the 335-mile Gasoducto del Pacífico from Loma de la Lata in Argentina's Neuqu?n Province to Concepción-Talcahuano, in Region VIII in the south of Chile, will by yearend 1999 supply natural gas to the communities of Concepción, Talcahuano, Coronel, Penco, and Lirquen. When the second phase starts up in April 2000, gas will flow to Laja, Los Angeles, Nacimiento, Lota, Escuadrón, and Arauco. Gasoducto del Pacífico shareholders are TransCanada International, Calgary, 30%; Gasco, Chile, 20%; El Paso International, Houston, 21.8%; ENAP, Chile, 18.2%; and YPF, Argentina, 10%.

Total investment in GasPacífico amounts to $317 million (U.S.), divided between investment in Argentina ($127 million) and Chile ($190 million). Initial capacity is 134 MMcfd.

In another direction, Gasoducto Cruz del Sur SA, a 50-50 venture of BG plc and Pan American Energy LLC, is moving ahead with plans for the Buenos Aires-to-Montevideo pipeline.

The trunk line from Colonia, Argentina, is a 100-mile line of 18-in. OD pipe, with laterals to feed several cities. The laterals consist of 77-miles of 3-18 in. OD pipe. The line is part of an intended 528-mile, 24-in. line to Brazil via Uruguay. Intec Engineering, Houston, is performing the engineering and design work for the entire project.

Mexican distribution

Elsewhere in Latin America, the big story is the progress being made in Mexico in installing distribution systems in the country's major cities.

Kicking off one of the largest privatization projects of its kind in the world, Mexico's Comisión Reguladora de Energía (CRE) has awarded the rights to distribute natural gas in Mexico City and the adjacent Valle Cuautitl n-Texcoco region.

Proyecto de Energía de México (PEM), a consortium of Lone Star Gas International, Dallas, and Grupo Diavaz SA de CV and Controladora Comercial e Industrial, both of Mexico, will install Mexico City's system. The consortium Mexigas (Gaz de France and Mexico's Bufete Industrial) will install the Valle Cuautitlán-Texcoco system.

The Mexico City area distribution permits allow Mexigas and PEM to operate the distribution systems for 30 years, with a 15-year renewal option. The groups each have committed to investing at least $500 million in the next 10 years to expand the two gas distribution systems.

Future areas to contract out natural gas distribution will include the El Bajío region, a fast-growing industrial area northwest of Mexico City, Tijuana, Cuernavaca, Puebla, Guadalajara, and the La Laguna region around the cities of Gómez Palacios and Torreón.

Asia stumbles

Sagging energy demand and prices in 1998 have cast a pall over what had been a healthy burst of pipeline activity in Asia (see related story, p. 23). Projects related to the hot exploration and development plays around Thailand are being reexamined and, in many cases, delayed in the light of currency uncertainties and energy demand weaknesses.

Thailand delays

Late last year, Thailand's Petroleum Authority of Thailand (PTT) decided to slash $1 billion from its planned gas pipeline investment. For 1999, PTT decided to build only the Ratchaburi-Wang Noi line that will link Thailand's main grid to gas supplies from Myanmar.

Weakened demand is the culprit. Thailand's annual demand growth for natural gas since July 1997 has declined to 5% from 10%. Economic woes have also forced PTT to cut at least $750 million it had budgeted for gas supply procurement and new transmission projects.

Also at risk is a planned pipeline from the Malaysia-Thailand Joint Development Area (JDA) to Songkhla, Thailand, which, in late 1998, PTT put on the shelf for the foreseeable future.

PTT's revised gas transmission plans call for the cancellation of two projects and the delay and downsizing of at least three others.

China expands

In China, however, the prospects seemed somewhat brighter, if no nearer.

China's total estimated proven gas reserves totaled only 52.5 tcf, against resource pegged as high as 1.33 quadillion cu ft. In 1997, the country's gas production was only 735 bcf. It has targeted by 2010 a gas production level of 2.52 tcf and by 2020 about 3.3 tcf. To support such production goals, China aims to develop a national grid capable of moving 5.25 bcf/year. And it intends to develop storage capacity of 525-595 bcf.

Imports by pipeline from Russia and Central Asia also will meet some of China's gas demand. Of the projected import volumes of 1.05 tcf in 2010, 700 bcf would arrive by pipeline and 350 bcf as LNG. In 2020, those respective levels would double.

Ambitious plans are afoot for oil lines in China, specifically petroleum products.

China National Petroleum Corp. wants to lay two long-distance refined products pipelines in northeastern and southwestern China. The first, a 621-mile, 426-mm line, would be completed in 2010 to eliminate a long-standing transportation bottleneck that has plagued northern China. The latter, either 559-mile or 714-mile depending on origin, would move 200,000 b/d to ease supply shortages in southwestern China where there are no refineries. Feasibility studies have been completed.

These two projects speak to the larger problem of China's lack of a refined products system. The combined length of existing products lines is only 1,067 miles. The longest line, a 671-mile line from Golmud to Lhasa, has a capacity of only 29,000 b/d. The country moves 70% of its products by rail, 21% by road, 8% by waterborne barge or tanker, and only 1% by pipeline.

The other major story in Asia occurs on its western borders, as companies and governments posture and maneuver to find some middle ground between economics and politics in projects to export oil from Central Asia.

Copyright 1999 Oil & Gas Journal. All Rights Reserved.