Special Report; Pipeline construction plans slow for 2010

Looking forward, to 2010 and beyond, for the second consecutive year less mileage is planned in all pipeline categories than had been the case the year prior, as an uncertain economic recovery and regulatory environment constrain infrastructure development plans.

The increasing globalization of natural gas markets despite current softness in demand drove long-term natural gas pipeline plans (2010 and beyond), with continued strength seen in planned capacity additions in the Asia-Pacific and expanded mileage plans in both the Middle East and Africa.

Larger crude plans in both Europe and Africa kept the 2010 slide in miles expected to be completed in that sector at 8.5% from global totals the prior year.

Plans for construction of product pipelines in 2010 slipped the least of any of the segments, supported by petrochemical pipeline construction in the Middle East and new clean products pipelines in the US.

As 2010 began, operators had announced plans to build nearly 67,000 miles of crude oil, product, and natural gas pipelines beginning this year and extending into the next decade (Fig. 1), a more than 14% decrease from data reported last year (OGJ, Feb. 9, 2009, p. 54) in this report and the second consecutive year during which plans contracted. The vast majority (nearly 79%) of these plans is for natural gas pipelines, an increase from the previous year as expansions in that segment's future proportion of plans outweighed the near-term contraction.

Outlook

The downturn in worldwide pipeline construction trends reflects the current economic unrest, but run counter to US Energy Information Administration energy consumption forecasts, which show continued growth, even if at a slower rate than predictions from a year ago.

EIA forecast world marketed energy consumption to increase by 44% through 2030 (using a 2006 baseline), a period that encompasses the long-term pipeline construction projections stated here.

Energy demand growth will be strongest, according to the midyear 2009 analysis, among non-OECD countries. This non-OECD growth will be led by China and India, where combined energy use will nearly double over the projection period to 28% of world energy consumption. US demand share will contract during the same period from 21% to 17%.

Fuelling this energy demand growth is projected gross domestic product growth in non-OECD Asia of 5.7%/year through 2030—led by China at 6.4%/year, the highest projected growth rate in the world—compared with 3.5% worldwide. Each of these levels are flat or slightly lower than EIA projections from a year earlier, reflecting continued economic uncertainty.

Structural issue that have implications for medium to long-term growth in China include the pace of reform affecting inefficient state-owned companies and a banking system carrying a large number of nonperforming loans, according to the EIA. The development of domestic capital markets to help macroeconomic stability and ensure China's large savings are used efficiently supports medium-term growth projections, according to the EIA.

EIA described the medium-term prospects for India's economy as positive, as it continues to privatize state enterprises and increasingly adopt free-market policies. EIA projects 5.6% annual GDP growth in India 2005-2030.

In December 2009 the EIA forecast a 16% increase in total US liquid fuels consumption, including both fossil liquids and biofuels to an average 22 million b/d in 2035 from 19 million b/d in 2008. The agency said biofuels made up almost all of the growth, with essentially flat consumption of petroleum-based liquids reducing reliance on imported oil.

EIA projects US oil production climbing 20% from 5 million b/d in 2008 to more than 6 million b/d in 2027, maintaining that level through 2035, with production increases stemming from both enhanced oil recovery efforts onshore and increased offshore activity. The agency said US natural gas production would grow 13% from 20.6 tcf in 2008 to 23.2 tcf in 2035, including a 6 tcf shale gas contribution (OGJ Online, Dec. 17, 2009).

The 2010 outlook projects considerably higher US natural gas imports by pipeline than did the updated Annual Energy Outlook 2009, citing increased unconventional production in Canada as outweighing declining conventional production. The 2010 outlook also pushed projected start-up of an Alaska natural gas pipeline back 1 year to 2023, citing lower wellhead prices.

The 2009 outlook projected the US would be a net pipeline exporter by 2030. The 2010 outlook, however, sees imports remaining in play, albeit having shrunk from 2.7 tcf in 2008 to 0.9 tcf in 2030. EIA projects delayed liquefaction projects leading to a US LNG imports peak of 1.5 tcf in 2021 compared with a 1.4 tcf peak in 2018 in the updated 2009 outlook.

OGJ has for more than 50 years tracked applications for gas pipeline construction to what is now called the Federal Energy Regulatory Commission. Applications filed in the 12 months ending June 30, 2009 (the most recent 1-year period surveyed) showed continued health in US interstate pipeline construction.

• More than 2,180 miles of pipeline were proposed for land construction, and no miles for offshore work. For the earlier 12-month period ending June 30, 2008, nearly 900 miles were proposed for land construction.

• FERC applications for new or additional horsepower at the end of June 2009 rose even more sharply, reaching almost 645,000 hp, all onshore, compared with 238,500 hp of new or additional compression applied for a year earlier.

Bases, costs

For 2010 only (Table 1), operators plan to build more than 11,500 miles of oil and gas pipelines worldwide at a cost of nearly $44.3 billion. For 2009 only, companies had planned more than 15,250 miles at a cost of nearly $61.5 billion.

For projects completed after 2010 (Table 2), companies plan to lay nearly 55,200 miles of line and spend roughly $207 billion. When these companies looked beyond 2009 last year, they anticipated spending roughly $225.5 billion to lay more than 62,500 miles of line.

• Projections for 2010 pipeline mileage reflect only projects likely to be completed by yearend 2010, including construction in progress at the start of the year or set to begin during it.

• Projections for mileage in 2010 and beyond include construction that might begin in 2010 and be completed in 2010 or later.

Also included are some long-term projects judged as probable, even if they will not break ground until after 2010.

US average cost-per-mile for onshore pipeline construction (Table 4, OGJ, Sept. 14, 2009, p. 66) on FERC applications submitted by June 30, 2009, was $3.73 million. There were no offshore applications submitted.

US average cost-per-mile for offshore construction (Table 7, OGJ, Sept. 1, 2008, p. 62) on projects completed in the 12 months ending June 30, 2009, was $5.37 million.

Based on historical analysis and a few exceptions and variations notwithstanding, these projections assume that 90% of all construction will be onshore and 10% offshore and that pipelines 32 in. OD or larger are onshore projects.

Following is a breakdown of projected costs, using these assumptions and OGJ pipeline-cost data:

• Total onshore construction (10,940 miles) for 2010 only will cost more than $40.8 billion:

—$1.1 billion for 4-10 in.

—$9.8 billion for 12-20 in.

—$10.35 billion for 22-30 in.

—$19.5 billion for 32 in. and larger.

• Total offshore construction (635 miles) for 2010 only will cost nearly $3.5 billion:

—$177 million for 4-10 in.

—$1.6 billion for 12-20 in.

—$1.7 billion for 22-30 in.

• Total onshore construction (54,248 miles) for beyond 2010 will cost more than $202 billion:

—$1.5 billion for 4-10 in.

—$11.3 billion for 12-20 in.

—$18.9 billion for 22-30 in.

—$170 billion for 32 in. and larger.

• Total offshore construction (948 miles) for beyond 2010 will cost more than $5 billion:

—$241.5 million for 4-10 in.

—$1.8 billion for 12-20 in.

—$3 billion for 22-30 in.

Action

What follows is a quick rundown of some of the major projects in each of the world's regions.

Pipeline construction projects mirror end users' energy demands, and much of that demand continues to center on natural gas, with the industry remaining focused on how to get that gas to market as quickly and efficiently as possible. The following sections look at both natural gas and liquids pipelines.

North America activity

Gas, NGL

BP PLC and ConocoPhillps have joined resources to build a 4 bcfd natural gas pipeline (Denali) extending from Alaska's North Slope to market in Canada and the US at an estimated cost of $20 billion. The companies plan to have spent $600 million preparing for an open season slated for April 2010. After the open season, the companies will file to obtain certification from the US Federal Energy Regulatory Commission and Canada's National Energy Board for authorization to move forward with construction of the project.

The Denali partners selected Argonne National Laboratory in May 2009 as a third-party contractor for environmental impact statement preparation. Denali earlier awarded Bechtel Corp. an engineering contract for the project's mainline.

TransCanada Alaska meanwhile began the prefiling process on its own Alaskan natural gas pipeline. TransCanada was awarded rights to build a North Slope gas pipeline under the Alaska Gasline Inducement Act in January 2008. AGIA requires TransCanada to meet certain requirements that will advance the project in exchange for a license providing up to $500 million in matching funds.

In June 2009 TransCanada agreed with ExxonMobil Corp. affiliates to work together on an Alaska gas line, the Alaska Pipeline Project. ExxonMobil will share expenses in advancing the project's technical, commercial, regulatory, and financial aspects, while TC Alaska remains the AGIA licensee. The project filed its open season plan with FERC in January 2010.

TransCanada already has NEB authorization for its project. TransCanada has also committed to include an option for transporting gas from Prudhoe Bay to Valdez for export as LNG as part of its open season (Fig. 2).

Both proposals are for 48-in OD pipelines running from ANS to the Alberta hub, Denali with 4 bcfd capacity and TC Alaska with 5 bcfd.

Alaska's Natural Gas Development Authority is continuing to develop plans for intrastate gas pipelines, including a 460-mile system of various diameters from Beluga in southern Alaska to Fairbanks that would be used initially to transport gas from Cook Inlet, but eventually connect to either Denali or TC Alaska's line to bring ANS gas south.

In Canada, the proposed Mackenzie Valley pipeline would stretch more than 750 miles to transport Mackenzie River Delta gas to Alberta and beyond. Plans call for initial capacity of 1.2 bcfd, expandable to 1.9 bcfd. Canada's Joint Review Panel, examining the environmental and socioeconomic impacts of the $16.2 billion (Can.) project, approved the project in December 2009.

In addition to the Aboriginal Pipeline Group, other pipeline partners are Imperial Oil Ltd. 34.4%, ConocoPhillips Canada 15.7%, Shell Canada, 11.4%, and ExxonMobil Canada 5.2%

Costs include $7.8 billion for the Mackenzie Valley mainline, $3.5 billion for the gas gathering system, and $4.9 billion for anchor-field development.

Canada's NEB will start hearing final arguments on the pipeline in April 2010.

Large domestic natural gas pipeline projects designed to move Midcontinent supplies to market centers continued to progress, with new projects also proposed. The Rockies Express pipeline, running 1,679 miles of 42 in. pipe from northwestern Colorado to eastern Ohio, entered service in November 2009. It is the largest new US pipeline project in 20 years. Kinder Morgan Energy Partners LP operates the pipeline and owns 50%. Sempra Pipeline & Storage, a unit of Sempra, and ConocoPhillips each own a 25% stake.

Alliance Pipeline Inc. and Questar Overthrust Pipeline Co. held an open season on their Rockies Alliance Pipeline project in June 2008. Initial support totaled 500,000 dekatherms/day from both Rockies producers and Midwest markets. The pipeline will take delivery of natural gas from Opal, Meeker, and Wamsutter and terminate at Alliance Pipeline delivery points in the Chicago area.

The 1,080-mile, 42-in. OD pipeline does not yet a have a time line for completion, but is designed to have capacity of 1.3 bcfd, expandable to 1.7 bcfd with extra compression. Alliance's current system connects to the Guardian, Vector, Peoples, Nicor, ANR, NGPL, and Midwestern pipeline systems.

Alliance says a detailed time line will be available once commercial contracts have been secured.

TransCanada proposed a competing Rockies-to-Midwest project, Pathfinder, consisting of 673 miles of 36-in. OD pipe running from Meeker, Colo., to an interconnection with the Northern Border Pipeline Co. system for delivery into the Ventura and Chicago area markets.

Changes in natural gas supply growth, however, have prompted TransCanada to consolidate the Pathfinder pipeline project into its Bison project. Bison will consist of 302 miles of 30-in. OD natural gas pipeline and related pipeline system facilities extending northeastward from the Dead Horse region near Gillette, Wyo., through southeastern Montana and southwestern North Dakota where it will interconnect with Northern Border Pipeline Co.'s system near Northern Border's Compressor Station No. 6 in Morton County, ND.

Bison's design capacity is 477 MMcfd with potential expandability up to 1 bcfd. TransCanada expects the line to enter service in November 2010.

The US Federal Energy Regulatory Commission issued its final environmental impact statement on Jan. 8, 2009, for El Paso Corp.'s proposed $3 billion Ruby Pipeline connecting Rockies reserves to western US markets, saying any adverse environmental impacts could be effectively mitigated. The pipeline includes 670 miles of 42-in. OD pipe beginning at the Opal hub in Wyoming and terminating at a Malin, Ore., interconnect near California's northern border. Ruby will have an initial capacity of 1.5 bcfd.

Pipeline rights-of-way will cross four states: Wyoming, Utah, Nevada, and Oregon. El Paso has proposed four compressor stations totaling 160,500 hp: one near Opal hub in southwestern Wyoming; one south of Curlew junction, Utah; one at the project midpoint, north of Elko, Nev.; and one in northwestern Nevada.

Pending full permitting, construction could begin in 2010, with an estimated in-service date of March 2011.

Crude

TransCanada Corp. received permitting from the US Department of State in March 2008 to begin construction of border crossing facilities for its 2,148-mile Keystone oil pipeline project, which will transport oil from Canada to the US Midwest. ConocoPhillips is TransCanada's partner in the project.

In addition to 1,379 miles of new-build US line, Keystone includes additions to existing Canadian pipelines and mainline flow reversals. It can deliver 435,000 b/d of crude oil from Hardisty, Alta., to the US at Wood River and Patoka, Ill. Line fill began fourth-quarter 2009 and TransCanada expects it to be complete first-quarter 2010.

TransCanada plans to expand Keystone's capacity to 590,000 b/d and extend the line to Cushing, Okla., starting in late 2010. The project has secured firm long-term contracts totaling 495,000 b/d for an average of 18 years.

TransCanada announced plans in July 2008 for the Keystone Gulf Coast Expansion Project (Keystone XL), providing additional capacity of 500,000 b/d from western Canada to the US Gulf Coast by 2012. The expansion would boost the system's total capacity to 1.1-million b/d at a total capital cost of about $12.2 billion. Keystone XL has secured additional firm, long-term contracts for 380,000 b/d for an average of 17 years from shippers.

Keystone XL includes 1,980 miles of 36-in. OD line starting in Hardisty, Alta., and extending to a delivery point near existing terminals in Port Arthur, Tex. XL will also include 41 pump stations—33 in the US and 8 in Canada—at roughly 50-mile intervals. Each station will use two to three 6,500 hp electric pumps, providing a total of up to 19,500 hp/station. Each station could be expanded to 32,500 hp as part of boosting the combined Keystone system's throughput to 1.5 million b/d.

TransCanada anticipates starting construction in 2010, pending regulatory approvals, and intends to start the line in 2012

Enbridge Energy Partners LP plans its own pipeline expansion to deliver 450,000 b/d of crude oil to the US. The Alberta Clipper pipeline will run between Hardisty, Alta., and Superior, Wis. Initial capacity can be expanded to as much as 800,000 b/d.

The 672-mile Canadian portion of the pipeline from Hardistry to Gretna, Man., is mechanically complete. Restoration work is under way according to Enbridge but poor weather conditions have delayed completion along some portions of the right-of-way. Enbridge expects all remaining cleanup and restoration work to be completed beginning in spring 2010 and the line to enter service in mid-2010 after the US portion is complete.

Four environmental and Native American groups, however, sued US Secretary of State Hillary R. Clinton and other federal officials on Sept. 3, 2009, to protest US Department of State approval of the pipeline.

Altex Energy is pursuing a completely newbuild 36-in. pipeline running directly from northern Alberta to the US Gulf Coast. The line's initial capacity would be 425,000 b/d, but the company says expansion to 1 million b/d is possible as demand warrants. The pipeline project has been delayed by a lack of oil sands supply growth, according to Altex, which is working with Canadian National Railway on a short-term option to instead use rail for transport of undiluted (or underdiluted) bitumen.

Enbridge has renewed plans to build the Northern Gateway Pipeline to transport 525,000 b/d of oil sands crude from near Edmonton to a tanker terminal in British Columbia for shipment to China, other parts of Asia, and California. A line running parallel to the crude line would ship 193,000 b/d of condensate from the coast to Alberta.

Enbridge expects to build Northern Gateway in 2012-14, pending regulatory approval of filings made in 2009. Commissioning and start-up would occur 2014-15. Enbridge would also operate the Kitimat terminal. The terminal would have 2 mooring berths, 14 storage tanks for petroleum and condensate, and be called on by roughly 225 ships/year.

Products

Colonial Pipeline Co. has delayed a proposed additional pipeline from Jackson, La., to Austell, Ga., running alongside the two current main lines to the extent possible. The 460-mile Project ExCEL, prompted by announced Gulf Coast refinery expansions, represented a more than $2 billion investment, with Colonial citing weakened consumer demand for petroleum products in announcing the decision.

Kinder Morgan Energy Partners LP is continuing the development of its $400 million CALNEV pipeline expansion. Expansion of the 550-mile pipeline involves construction of a 16-in. pipeline from Colton, Calif., to Las Vegas, Nev., and will increase the system's capacity to 200,000 bpd, transporting products for the military at Nellis Air Force Base. A further capacity increase to more than 300,000 bpd is possible with the addition of pump stations.

The new pipeline will parallel existing utility corridors between Colton and Las Vegas. Following its completion, the existing 14-in. line will be transferred to commercial jet fuel service for McCarran International Airport and any future airports planned in Las Vegas, with the 8-in. pipeline that currently serves the airport purged and held for future service.

Start-up of the line is scheduled for late 2012.

Holly Corp. and Sinclair Transportation Co. plan to jointly build a products pipeline extending from Wood Cross, Utah, refineries to terminals north of Las Vegas. The UNEV Pipeline project includes construction of associated terminal facilities in Cedar City, Utah, and northern Las Vegas.

The 400 mile, 12-in. line will cost about $300 million and have an initial capacity of 62,000 b/d, expandable to 120,000 b/d. It will serve refineries and shippers along its route and interconnect to the Pioneer Pipeline. Holly calls for construction to begin January 2010 for an in-service date of October-November 2010.

Latin America

Brazil's 862-mile Southeast-Northeast Interconnection Gas Pipeline (GASENE) will connect the existing southeastern gas system to the northeastern gas system, creating a common gas market and allowing gas imports at Bahia. GASENE connects Cabiunas terminal in Rio de Janeiro to Catu, Bahia. It will create a common gas market in Brazil and allow gas import from Bahia.

Construction on the final 605-mile stretch of the pipeline, between Cacimbas and Catu started in May 2008. The 28-in. OD pipe, using one compressor station, is scheduled to enter service in 2010. Sinopec is building the pipeline, financed by China Development Bank.

The 1,252 km, 48-in. OD Gasoducto del Noreste will deliver 3.2 bcfd of Bolivian gas to Argentina as early as 2015 (Fig. 3). The Bolivian government, Argentine-state Enersa, and Gazprom are developing the $2.67 billion project. Argentina approved a 70-km extension to the line's original 1,182-km length in January 2010. Engineering and construction bids on the project were to have been submitted to Enersa by Dec. 30, 2009.

Camisea II is a gas export project featuring a 253-mile, 34-in. natural gas pipeline connecting Camisea Block 56 to a liquefaction plant being built on the coast 106 miles south of Lima. Peru LNG (Hunt Oil Co., 50%; SK Energy Co. Ltd., 30%; Repsol YPF, 20%) expects the project to enter service in 2010.

The International Finance Corp's Environmental and Social Review of the project says natural gas will travel through the existing Camisea-Lima Pipeline Transportation System to kilometer post 211 at Huayahura, where it will enter the new pipeline. The pipeline will be designed to transport 677 MMcfd at a pressure of 147 barg (2,160 psig). About 300 km of the pipeline will cross the Andes at altitudes up to more than 5,000 m above mean sea level. The pipeline will receive high-pressure natural gas from the Malvinas Gas Separation Plant, according to the IFC review. The pressure differential between Malvinas and the LNG plant will allow natural gas to reach the delivery point.

Asia-Pacific

PetroChina expects to bring its second West-East Pipeline (WEPP II) into service in late 2010 or early 2011. The pipeline is part of the larger Asian Gas Pipeline, running from Turkmenistan to eastern China. The Chinese trunkline section covers 3,400 miles, connecting Xinjiang province to Guangzhou and Shanghai and is expected to be completed in 2010. The development also calls for 1,240 miles of branch lines. WEPP II will carry 30 billion cu m/year from Central Asia to consuming centers in China.

The Chinese section of WEPP II will use 1.1 million tonnes of X80 42-in. OD UO pipe and 3.2 million tonnes of X80 18-in. OD spiral pipe. PetroChina let contracts to both GE Oil & Gas and Rolls Royce to supply compression for the western Chinese section of the pipeline, running from the Kazakhstan-China border to Zhongwei.

Turkmenistan completed construction of its 117-mile section in October 2009. The line, which starts at the Turkmen gas fields near the Amu Darya river before entering Uzbekistan at Olot and continuing through southern Kazakhstan to China, was commissioned in December 2009. In addition to gas from Turkmenistan and Uzbekistan, the line will be supplied by gas from Kazakhstan's Karachaganak, Tengiz, and Kashagan fields. China National Petroleum Corp. has signed a 30-year agreement for supply of 30 billion cu m/year of gas through the line.

The first stage of the 4,700-km East-Siberia Pacific Ocean oil pipeline, including construction of a 2,400-km oil pipeline from Taishet to Skovorodino near the Chinese border and of a rail oil terminal at Kozmino on Perevoznaya Bay at a combined cost of $14.1 billion, was inaugurated in December 2009. The second stage involves construction of a pipeline link between Skovorodino and Kozmino and will replace the rail line in 2012.

The first phase of the line can carry up to 30 million tonnes/year of oil, about half of it earmarked for China via a 67-km spur from Skovorodino to the Chinese border and the other half shipped to Kozmino. The full ESPO line will eventually carry 80 million tonnes/year.

The branch pipeline would supply the oil hub of Daqing in northern China.

The 50 million tonnes/year shipped along the Skovorodino-Kozmino route would largely be exported to Japan, but hinge entirely on the combination of continued development of the Siberia's other fields and Russia's continued desire to export to Japan.

Myanmar awarded China National Petroleum Corp. exclusive rights to construct and operate the proposed Myanmar-to-China crude oil pipeline. This line and a companion natural gas pipeline would transport hydrocarbons from the Bay of Bengal across Myanmar to southwestern China. Plans call for the 771-km crude pipeline between Maday Island in western Myanmar and Ruili in China's southwestern Yunnan province to initially carry 12 million tonnes/year.

CNPC began building a large oil import port at Kyaukpyu, Myanmar, in October 2009 to serve as the pipeline's input point. The port will be able to receive vessels up to 300,000 dwt and will have storage capacity of 600,000 cu m. The line will eventually carry more than 230,000 b/d to China.

The natural gas pipeline is scheduled to begin carrying 12 billion cu m/year to southwestern China in 2012. The crude line will transport oil carried by tanker from the Middle East, while the gas line will carry material from Myanmar's offshore A-1 and A-3 blocks.

Total estimated project costs amount to $1.5 billion for the oil pipeline and $1.04 billion for the gas pipeline.

The new pipelines will give China better access to Myanmar's resources and will speed deliveries and improve China's energy security by bypassing the congested Malacca Strait, through which most of China's imported crude oil currently travels.

Europe

Work started in early December 2005 on the Russian onshore section of the Nord Stream pipeline in Babayevo. This 56-in. segment will stretch 917 km to the Baltic Sea coast near Vyborg, linking existing gas pipelines from Siberia to the project. Seven compressor stations will provide the necessary pressure. The pipeline will cross the Baltic, making landfall near Greifswald, Germany. This section will be 1,220 km in length with a 48-in. OD.

The full system is scheduled to start operations in fourth-quarter 2011 at a capacity of 27.5 billion cu m/year. The project includes building a second, parallel pipeline, doubling capacity to about 55 billion cu m/year. This second pipeline is planned to come on stream in 2012.

A joint venture consisting of Gazprom (51%), Wintershall AG (20%), E.ON Ruhrgas AG (20%), and NV Nederlandse Gasunie (9%) is building the pipeline. Gazprom has said GDF Suez SA will receive a 9% share in the project from Wintershall and E.ON. Suez expects to complete the deal early in 2010. For the two-leg option, the total cost for the offshore project will amount to more than €7 billion, with Gazprom investing an additional €1.3 billion in the onshore section.

Russia began production at Yuzhno Russkoye oil and gas condensate field in December 2007. Gas from this field will be shipped through Nord Stream once it is completed.

Finland approved the pipeline in July 2009, but said more information on potential environmental damage must be supplied. The German government approved the line in December 2009. All other countries through which waters Nord Stream will pass have approved the project.

Gazprom and Eni SPA agreed in December 2007 to build the 560-mile South Stream gas pipeline under the Black Sea and through Bulgaria. Bulgaria and Russia reached agreement in January 2008. On completion, the $10 billion line could distribute gas to northern and southern Europe, with an estimated capacity of 30 billion cu m/year. Participants plan to deliver first gas through South Stream by 2013.

Electricite de France (EDF) signed a memorandum of understanding with OAO Gazprom in December 2009 for "at least 10%" of the consortium in charge of building South Stream. EDF's involvement in South Stream is seen a blow to the Nabucco gas line, due on stream in 2014—a year after South Stream. However, the French government also backs Nabucco for diversification of gas supply routes to Europe.

Austria's OMV AG continues to advance the 56-in. Nabucco pipeline, which will bring some combination of Central Asian, Caspian, and Middle Eastern gas to the Baumgarten hub in Austria near the Slovakian border at a rate of 31 billion cu m/year, before moving it on to Western Europe.

Feasibility studies have led to a two-stage construction plan. The first phase, starting in 2011, calls for 2,000 km of pipe between Ankara, Turkey, and Baumgarten, allowing 8 billion cu m/year of gas from the existing Turkish pipeline network to be transported through the line by 2014. Second-stage construction would begin in 2012 and build eastward from Ankara to the Iranian and Georgian borders, bringing total pipeline length to 3,300 km. Turkey wants Iranian gas for Nabucco.

The US supports construction of Nabucco, citing the need to move gas into Europe though economically viable and secure routes.

The European Union, as represented by the governments of Bulgaria, Romania, Hungary, and Austria, signed an intergovernmental agreement in July 2009 authorizing the Nabucco natural gas pipeline project with Turkey. The project, which is expected to cost around $11 billion, will eventually have a capacity of 31 billion cu m/year. Nabucco has six shareholders: Turkey's Botas, Bulgaria's Bulgargaz, Romani's Transgaz, Hingary's MOL, Austria's OMV, and Germany's RWE.

To deliver gas from Bovanenkovo field—eventual projected production 140 billion cu m/year, with production starting in 2011—Russia is building a multiline gas transmission system connecting the Yamal Peninsula and central Russia. Construction calls for 1,420-mm OD pipes designed to work at higher pressures than existing Russian lines.

Total pipeline length will exceed 2,400 km, consisting of the Bovanenkovo-Ukhta pipeline (1,100 km, 140 billion cu m/year) and the Ukhta-Torzhok gas pipeline (1,300 km, 81.5 billion cu m/year). Connection to the Ukhta hub will allow shipment through the Yamal-Europe pipeline.

Gazprom began building the 72 km subsea section of the Bovanenkovo-Uktha line, crossing Baidarate Bay, in August 2008. Construction of the main trunkline began in December 2008.

Plans to export Algerian gas via Italy also progressed. Galsi SPA and Snam Rete Gas SPA signed a memorandum of understanding in November 2007 to construct the Italian section of the planned 8 billion cu m/year Galsi natural gas pipeline, which will deliver Algerian gas to Italy via Sardinia.

Galsi shareholders are Sonatrach, Edison SPA, Enel SPA, Hera Trading, Regione Sardegna, and Wintershall AG.

The project envisions four pipeline segments: 640 km onshore between Hassi R'mel gas field in Algeria and El Kala on the Algerian coast; 310 km between El Kala and Cagliari on Sardinia in water as deep as 2,850 m; 300 km between Cagliari and Olbia on the northern Sardinian coast; and 220 km between Olbia and Pescaia, southeast of Florence, in water as deep as 900 m.

Sonatrach will deliver 3 billion cu m/year into the system, Enel, 2 billion cu m/year, and Hera Trading, 1 billion cu m/year.

Work on the line was under way in January 2009, with service expected by 2012-13.

Middle East

Iran and Pakistan continued laying the groundwork toward building the long-contemplated gas export line from Iran during 2009. The $7 billion project would transport as much as 2.2 bcfd of natural gas from the South Pars field in the Persian Gulf through 1,850 km of 56-in. OD line (Iran, 1,100 km; Pakistan, 750 km).

India had difficulties reaching economic terms for its participation in the project, which combined with US pressure to not participate and security concerns regarding having such a major energy artery running through Pakistan to remove it from participation for the time being.

The Iran-Pakistan pipeline would be an extension of Iran Gas Trunkline (IGAT) 7, currently under construction and expected to be completed in 2010-11. Running 900 km from Asalouyeh to Iranshahr in Iran's Sistan-Baluchistan province, the 56-in. OD line will have a capacity of 5.3 bcfd. A 400-km branch line from Iranshahr to the Pakistani border would have an initial capacity of 750 MMcfd, according to FACTS Global Energy Group, expandable to as much as 2.1 bcfd.

FACTS said the pipeline will enter Pakistan in southern Baluchistan, running to Sindh province where the country's main pipeline hub lies. From Sindh, gas would travel through SSGC's existing distribution network.

Iranian gas entering Pakistan will be used by independent power producers, according to FACTS. Iran and Pakistan agreed in June 2009 to a price formula linked 79% to the Japan crude cocktail (JCC) price. At JCC of $60/bbl Pakistan would pay around $8.20/MMbtu, said FACTS.

Two stages of the IGAT system remain under development. IGAT VII will move South Pars 9-10 gas to the Shar-Khoon refinery and onward to Sistan and Baluchistan provinces and export to Pakistan.

IGAT IX, slated for 2014 completion and also termed the Europe Gas Export Line, will move South Pars 9-10 gas 1,863 km from Asalouyeh to the Turkish border. Construction on the stretch from Asalouyeh to Bidbolyand was completed as of June 2008.

Iran has expressed interest in finding an international partner on a build-own-operate basis for the balance of IGAT IX, which could link with either the proposed Trans-Adriatic pipeline or the proposed Nabucco pipeline for exports further west.

Iran is also building a 2,163-km ethylene pipeline from Asalouyeh in southern Iran to the country's northwestern provinces. The pipeline will transport ethylene to meet the feed requirements of new petrochemical complexes in Gachsaran, Khoramabad, Kermanshah, Sanandaj, and Mahabad.

Construction of the pipeline began in 2003 and is targeted for completion in 2010. The West Ethylene Pipeline was initially to transport 1.5 million tonnes for 1,500 km to feed five planned petrochemical complexes. The Iranian Parliament, however, instructed the Petroleum Ministry to build five more complexes in the cities of Andimeshk, Dehdasht, Hamedan, Kermanshah, and Miyandoab as a means to boost production in the less-developed parts of the country. The pipeline's length, therefore, was extended to 2,163 km and capacity increased to 2.8 million tonnes.

An eleventh plant was added to the plan in June 2008. Olefin plants in Asalouyeh and the Bandar Imam special economic petrochemical zone in Mahshahr City will supply the ethylene; one set for completion in 2010 and the other in 2013.

Bakhtar Petrochemical Co., which is constructing the pipeline, is a private joint stock holding company.

Africa

Nigeria, Algeria, and Niger hope to start gas exports via the proposed 18-25 billion cu m/year Trans-Sahara gas pipeline in 2015. Once built, the 4,300-km line would transport gas from the Niger Delta in southern Nigeria through Niger and into Algeria and Europe. Cost estimates for the project are $13 billion.

According to the feasibility report published by engineering company Penspen Consulting, TSGP would comprise a 48-56-in. pipeline from Nigeria to Algeria's Mediterranean coast at Beni Saf and subsea pipelines of 20-in. between Beni Saf and Spain.

Nigeria's militant Movement for the Emancipation of the Niger Delta (MEND), reiterating its long-standing demands that international oil companies leave the oil-producing Niger Delta, threatened in July 2009 that it would attack the Trans-Saharan gas pipeline, just days after Algeria, Niger, and Nigeria signed an agreement to start the process of constructing the TSGP.

The warnings also followed a decision by Russia's OAO Gazprom to invest in the TGSP through a 50-50 joint venture, called Nigaz, with state-owned Nigerian National Petroleum Corp. Gazprom said Nigaz intends to explore for gas and to develop infrastructure for its development and transport—even including a section of pipeline that could form part of a proposed Trans-Sahara pipeline to export gas directly to Europe.

No date has yet been given for the start of work on the TSGP.

South Africa's New Multi-Products Pipeline (NMPP) project will move diesel, gasoline, and jet fuel from an import terminal in Durban roughly 525 km northwest to the inland Gauteng region. Transnet Ltd. received the final environmental impact report for NMPP in November 2008, with the report submitted at the same time to the Department of Environmental Affairs and Tourism for a decision.

NMPP will include as many as 10 pump stations, with four planned at start-up and others added as needed to meet demand. The 24-in. OD pipeline will supplement the existing 12-in. Durban-Johannesburg Pipeline (DJP), completed in 1965 and already operating at capacity. Transnet plans commissioning for late 2010.

ABB won a contract to supply engineering services and electrical equipment to the pipeline in November 2009.

Algeria's Sonatrach plans to build a 585-km natural gas pipeline, GK3, from Hassi R'mel to an LNG terminal at Skikda. The 48-in. OD pipeline would run 275 km from Hassi R'mel to Chaiba and then 310 km from Chaiba to Skikda. Gas from the line would go into power generation and the planned Galsi pipeline in addition to being used for LNG at Skikda. Sonatrach intends to complete the pipeline in 2011.

Saipem won an EPC contract for Lot 3 of the pipeline in June 2009 encompassing a 48-in. line section from Mechtatine to Tamlouka in northeast Algeria, then connecting the latter to Skikda and El-Kala, located on the northeastern coast of the country, for a total length of about 350 km.

Sonatrach also plans to the complete the 532-km GR4 pipeline from Rhourde Nouss field near the Libyan border to Hassi R'mel in 2010.

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