Pipeline construction plans shrink

As 2017 began, operators had announced plans to build more than 34,500 miles of crude oil, product, and natural gas pipelines extending into the next decade, a roughly 6.7% decrease from data reported the prior year (OGJ, Feb. 1, 2016, p. 71). The softer plans for beyond 2017 continued the slide started last year, even as the energy market seems to have found its bottom. Sharp reductions in long-term gas pipeline plans in the US, Canada, and Latin America, more than erased a second straight year of increased plans in Europe. Natural gas pipeline plans in the Middle East and Africa also rebounded.

As a whole, combining both current-year and forward estimates (Fig. 1), decreases in planned construction in Canada, the US, and Latin America outweighed increases everywhere else.

Outlook

EIA forecast world liquid fuels consumption to increase by 34.4% through 2040 (using a 2012 baseline), a period encompassing the construction projections stated here.

Demand growth will be strongest, according to its May 2016 International Energy Outlook (IEO), among non-OECD countries, growing from 50% of world liquid fuels consumption in 2012 to 62% in 2040. This non-OECD growth will be led by Asia. Of the total 17.4 million b/d increase expected in the region by 2040, 6.2 million b/d will come from China, driven by its transportation sector.

India's predicted liquid fuels demand in 2040 rose sharply from earlier projections to 8.3 million b/d, up from 6.8-million b/d. The country's 2012 demand was 3.6-million b/d.

EIA boosted its total Asian liquid fuels demand to 46.4 million b/d from the 43.5-millon b/d previously forecast, but all of this growth came from the non-OECD countries. OECD Asia demand growth is expected to slip 0.3%/year at the same time that already larger regional non-OECD demand is expanding by 2.1%/year. EIA expects liquid fuels demand in Japan to continue to fall between 2012 and 2040 as use for power generation returns to levels more typical before the March 2011 Fukushima earthquake and tsunami.

Non-OECD Asia GDP growth slipped to 4.2%/year (from 5.3%) through 2040, despite India's growth rebounding slightly to 5.5%/year, from 5.4% in the previous IEO. EIA expects a 3.3% global growth rate, down from 3.5%.

The combination of lower interest rates and moderate inflation supports India's expected economic growth in the shorter term. EIA lists the need to end regulatory impediments to the consolidation of labor-intensive industries and reform labor markets and bankruptcy terms as among the keys to sustained longer-term growth.

China's economic growth in 2014 was its lowest in 24 years, according to EIA. Factors such as an aging population and shrinking work force continue to weigh on China's GDP, expected to grow by 4.7%/year through 2040. The fate of its large number of nonperforming loans and the extent to which reforms influence state-owned companies are key variables in determining the course of China's future growth, EIA said.

The EIA Annual Energy Outlook (AEO) 2016 forecast relatively flat US liquid fuels consumption through 2040; reaching 20.11 million b/d by 2020 (from 19.6 million b/d in 2014) and 20.14 million b/d by 2040 with a slight dip in between. The 2015 AEO had consumption peaking at 19.65 million b/d in 2020.

EIA projects US crude and lease condensate production climbing about 29% from 8.71 million b/d in 2014 to 11.26 million b/d in 2040.

Projected US natural gas production continued to rise despite low or moderately rising prices. The agency predicted 55% 2015-2040 growth in US dry natural gas production in the 2016 AEO, growing to 42.1 tcf from 27.2 tcf. The 42.1 tcf projection for 2040 was up 18.6% from the 2015 AEO.

An expected 113% increase in production from shale gas and tight oil drives natural gas production growth, with gas sourced from these resources growing to 69% of total US output in 2040 from 50% in 2015.

The 2016 outlook projects the US becoming a net exporter of natural gas in 2018, 1 year later than AEO 2015. In its reference case, EIA expects US net exports of natural gas to total 7.5 tcf in 2040, a 34% jump in the export volumes projected just one year earlier. Almost half the growth comes before 2021 as LNG. After 2021 the EIA forecasts natural gas exports to grow at 4%/year. Net pipeline imports from Canada continue through 2040 but at lower levels, offsetting a gradual decline in net pipeline exports to Mexico after 2020.

OGJ tracks applications for gas pipeline construction to the US Federal Energy Regulatory Commission (FERC). Applications filed in the 12 months ending June 30, 2016 (the most recent 1-year period surveyed), showed continued strength in US pipelines despite the larger energy downturn.

• More than 2,470 miles of gas pipeline were proposed for land construction. For the earlier 12-month period ending June 30, 2015, nearly 2,200 miles were proposed.

• FERC applications for new or additional horsepower at the end of June 2016 increased sharply for the second straight year, reaching more than 2.2 million hp, from more than 1.7 million hp in June 2015, and more than 700,000 hp in 2014.

Bases, costs

For 2017 only (Table 1), operators plan to build roughly 7,750 miles of oil and gas pipelines worldwide at a cost of more than $59 billion. For 2016 only, companies had planned nearly 10,700 miles at a cost of more than $57 billion.

For projects completed after 2017 (Table 2), companies plan to lay more than 34,500 miles of line and spend roughly $264 billion. When these companies looked beyond 2016 last year, they anticipated spending roughly $197 billion to lay more than 37,000 miles of line. Land construction costs rose in the meantime to $7.65- from $5.2-million/mile.

• Projections for 2017 pipeline mileage reflect only projects likely to be completed by yearend 2017, including construction in progress at the start of the year or set to begin during it.

• Projections for mileage after 2017 include construction that might begin in 2017 but be completed later. Also included are some long-term projects judged as probable, even if they will not break ground until after 2017.

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 (7,324 miles) for 2017 only will cost roughly $56 billion:

-$1.9 billion for 4-10 in.

-$10.8 billion for 12-20 in.

-$16.7 billion for 22-30 in.

-$26.7 billion for 32 in. and larger.

• Total onshore construction (33,604 miles) for beyond 2017 will cost more than $257 billion:

-$26 billion for 12-20 in.

-$40 billion for 22-30 in.

-$192 billion for 32 in. and larger.

An absence of new offshore construction filings in the 12 months ending June 30, 2016, combined with the sharp rise in onshore construction costs, prevented projection of offshore costs.

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.

US, Canada activity

Gas, NGL

TransCanada Alaska, the state's licensee to build a natural gas pipeline from Alaska's North Slope, received state clearance May 2, 2012, to change the project's focus to a large-diameter pipeline to an Alaska tidewater site for in-state use, liquefaction, and export. The move came after TransCanada Corp. and the North Slope's three major producers-BP PLC, ConocoPhillips, and ExxonMobil Corp.-announced Mar. 30, 2012, that they would work together to commercialize ANS gas by focusing on large-scale exports from south-central Alaska as an alternative to a pipeline through Alberta to markets in the US Lower 48. The four companies completed the project's concept selection phase in February 2013.

TransCanada was awarded rights to build a North Slope gas pipeline under the Alaska Gasline Inducement Act in January 2008. In June 2009 TransCanada agreed with ExxonMobil Corp. affiliates to work together on the pipeline. The Alaska Pipeline Project the two companies formed presented two alternatives for assessment by potential shippers, only one of which would move forward. One option would have transported 4.5 bcfd of gas from Alaska's North Slope about 1,700 miles across Alaska to Alberta, Canada, where it could be sent on existing pipelines to North American gas markets. The second option called for shipping an estimated 3-3.5 bcfd of gas about 800 miles to Valdez, Alas., where shippers could liquefy the gas in a plant constructed by others and ship it on tankers to US and international markets.

This option, now called Alaska LNG and including the Alaska Gasline Development Corp. (AGDC), is transitioning from a partnership between the State of Alaska and North Slope gas producers-ExxonMobil, BP, and ConocoPhillips-to a solely state-led effort, managed by AGDC. Alaska bought TransCanada's share of the project in November 2015 and the producing companies told the state in 2016 that weak market conditions did not warrant proceeding with the US Federal Energy Regulatory Commission (FERC) application and costly design work in 2017. Alaska Gov. Bill Walker said the state would take over the project to keep it on schedule while seeking to reduce costs and searching for both investors and customers.

Negotiations toward this transition are underway. Agreements have been reached to provide AGDC with project information prepared over the past 4 years by the producer team and requiring producers to notify FERC to remove their names from the Alaska LNG docket.

The US Department of Energy (DOE) in November 2014 granted Alaska LNG authority for exports to countries covered by free-trade agreements (FTA). Exports to non-FTA countries were approved in July 2015. Transfer of this authority to AGDC is still being negotiated as is access to and an option on the almost 650 acres of Nikiski land planned for use as the plant and terminal site.

Large gas pipeline projects in Canada centered on shipping from shale plays in Alberta and British Columbia to the Pacific coast for liquefaction and export. In early 2013, Chevron Canada Ltd. bought 50% of Kitimat LNG and the proposed Pacific Trail Pipeline. Pacific Trail is a 290-mile, 36-in. OD line which would move gas to Kitimat LNG. The British Columbia government in July 2013 extended Chevron and partner Apache's window to start construction on the line to 2018. Woodside bought Apache's interest in Kitimat LNG in late 2014 (OGJ Online, Dec. 15, 2014).

Spectra Energy Corp., meanwhile, is planning with BG Group PLC to develop the 42-in. OD, 525-mile Westcoast Connector gas pipeline from northeast British Columbia to BG's potential LNG plant in Prince Rupert, BC. The line would move 4.2 bcfd of gas from the Horn River and Montney developments to the coast for liquefaction and export. Canada's National Energy Board (NEB) in late-2013 approved a 25-year natural gas export license to BG, but subsequent new BC-government tax proposals prompted the company to delay its final investment decision (FID) on the project to 2017 (OGJ, Apr. 7, 2014, p 120). BG's merger with Royal Dutch Shell PLC further weakened the project's standalone potential, Shell seeming to favor its LNG Canada partnership with Korea Gas Corp., Mitsubishi Corp., and PetroChina Co. Ltd.

Progress Energy Canada Ltd. in August 2013 signed firm transportation agreements for an interconnection with TransCanada's proposed Prince Rupert Gas Transmission (PRGT) project to provide gas to the proposed Pacific Northwest (PNW) LNG export plant near Prince Rupert. PNW LNG is owned by Petronas (77%) and Indian Oil Corp. Ltd. (IOC, 10%) in partnership with Progress. Delivery of 2.1 bcfd from TransCanada's Nova Gas Transmission Ltd. system to the 470-mile, 48-in. OD PRGT would begin in 2019.

TransCanada in October 2015 received final permits for PRGT from the BC Oil & Gas Commission (BCOGC), giving regulatory approval for its construction and operation. The permits cover the line's entire route from just north of Hudson's Hope, BC, to Lelu Island, off Port Edward. The permits also approve construction of three compressor stations and a meter station where the gas is to be delivered to PNW LNG. The LNG project received a positive decision from the federal government under the Canadian Environmental Assessment Act 2012. First Nations agreements, however, were still being signed as recently as November 2016.

Projects to move natural gas liquids to market faced increasing headwinds in the US. Kinder Morgan Energy Partners LP and MarkWest Utica EMG LLC's proposed Utica Marcellus Texas Pipeline (UMTP) Y-grade transportation project from the Utica and Marcellus shales to Mont Belvieu, Tex., would have an initial design capacity of 150,000 b/d and be expandable to 430,000 b/d. The first 964 miles of the line would consist of converted Tennessee Gas Pipeline system, with 200 miles of new-build between Natchitoches, La., and Mont Belvieu, and 120 miles of laterals to provide basin connectivity. The companies are targeting a fourth-quarter 2018 in-service date but a combination of growing municipal opposition along its route and narrowing NGL margins might cause this to be delayed.

Project Mariner, announced in 2010 by Sunoco Logistics Partners LP and MarkWest Energy Partners LP, transports Marcellus shale ethane to the US Atlantic Coast for shipment to Gulf Coast chemical producers and European markets. Mariner West, a 65,000-b/d expansion of Project Mariner, began moving ethane to Sarnia, Ont., in 2013.

The combined projects include just 85-miles of new pipeline construction, using existing Sunoco infrastructure for the balance of each route. MarkWest is building ethane storage in the Philadelphia, Pa., and Nederland, Tex., areas as part of the project, using existing storage in Sarnia.

Project Mariner East began propane operations in fourth-quarter 2014 and ethane operations first-quarter 2016. The 70,000-b/d system uses Sunoco's existing 8-in. OD pipeline between Delmont, Pa., and Philadelphia, with new pipe between Houston, Pa., and Delmont.

The company in late 2014 announced it had received sufficient shipper interest to move ahead with its 275,000 b/d Mariner East 2 pipeline, largely paralleling the route of the first line. Sunoco expects to put the 300-mile, 16-in. OD Mariner East 2 in service first-half 2017, but this might be delayed at least slightly by community and legal challenges.

Energy Transfer Partners LP's Rover pipeline would transport 3.25 bcfd of natural gas 800 miles, from processing plants and interconnections in northwest West Virginia, western Pennsylvania, and eastern Ohio to the hub near Defiance, Ohio, multiple delivery points in Michigan, and the Union Gas Hub near Sarnia, Ont. (Fig. 2). Rover also will interconnect with ETP's Panhandle Eastern Pipe Line, allowing shippers to deliver gas to Gulf Coast markets. Environmental groups have protested Rover, which awaits final FERC construction approval while purchasing easements and securing other permits.

Natural gas pipeline projects in the northeast US also faced delays caused by increasingly strident opposition. Williams' Constitution (124 miles, 30-in. OD, Marcellus shale to New York citygate) and Kinder Morgan's Northeast Energy Direct (415 miles, 30 and 36-in. OD, connecting Troy, Pa., Wright, NY, and Dracut, Mass.) were both cancelled outright since the last edition of this report.

Algonquin's Access Northeast (97-mile expansion in New York, Connecticut, and Massachusetts), Dominion's Atlantic Coast (600 miles, 42-in. OD, West Virginia to North Carolina), and Williams' Atlantic Sunrise (183 miles, 42-in. OD, connecting existing Williams Transco lines in Pennsylvania) are among the next projects facing vigorous opposition.

Crude

Energy Transfer Equity LP, Energy Transfer Partners LP, and Phillips 66 formed joint ventures to build two crude oil pipelines that together would connect the Bakken-Three Forks play in North Dakota to the US Gulf Coast. Dakota Access LLC was planned to run roughly 1,100 miles, linking North Dakota and the hub at Patoka, Ill., and delivering at least 450,000 b/d via 30-in. OD pipe to various points in the Midwest. In late 2016 the US Army Corps of Engineers denied Dakota Access an easement to cross under Lake Oahe (OGJ Online, Dec. 19, 2016). The administration of US President Donald Trump has said it would revisit Dakota Access's permitting. The second pipeline, Energy Transfer Crude Oil Co. LLC, would deliver from Patoka to Nederland, Tex., converting existing natural gas lines to crude service, assuming Dakota Access is eventually completed.

Enbridge North Dakota Pipeline Co. LLC indefinitely deferred its 612-mile Sandpiper Pipeline Project, citing insufficient North Dakota crude production. Sandpiper was designed to transport light crude from Enbridge's Beaver Lodge Station, near Tioga, ND, through Clearbrook, Minn., to an existing terminal in Superior, Wisc.

Enbridge is also undertaking its $7.5-billion Line 3 Replacement (L3R) Program. L3R will replace the majority of Enbridge's existing 34-in. OD Line 3 with new 36-in. OD pipeline on both sides of the Canada-US border, a total of 1,031 miles.

On the Canadian side of the border Enbridge will replace most of the existing line between its Hardisty Terminal in east-central Alberta and Gretna, Man. In the US, Enbridge will replace Line 3 between Neche, ND, and Superior, Wisc.

Canada's federal government approved L3R construction in late 2016 (OGJ Online, Nov. 30, 2016). Enbridge originally expected the new line to enter service second-half 2017, but this timing has likely slipped given mounting resistance inside the US. Enbridge will decommission the existing Line 3 once the new line is complete.

Plains All American Pipeline LP (PAA) and Valero Energy Corp. plan to build the 440-mile, 20-in., Diamond crude oil pipeline that will carry as much as 200,000 b/d of sweet crude from PAA's Cushing, Okla., terminal to Valero's Memphis refinery. Diamond also will provide access to Valero Energy Partners' Collierville line and is underpinned by a long-term shipping agreement with Valero and a related contract for storage and terminalling services at the PAA Cushing terminal.

Arkansas' Public Safety Commission approved the project in September 2016. The pipeline is unlikely to be completed before 2018.

Canada's federal government approved TransCanada's Trans Mountain Expansion project (TMEP) to move crude west from Alberta. The project would use 36-in. OD pipe to twin 980 km of its existing Trans Mountain pipeline. Even while granting the approval, however, Prime Minister Justin Trudeau said "we are under no illusion that the decision will [not] be bitterly disputed," recognizing the likelihood of continued protests and litigation (OGJ Online, Nov. 30, 2016).

TMEP will add 300,000 b/d of the Trans Mountain pipeline system, bringing total capacity to 890,000 b/d. The Westridge marine terminal at Trans Mountain's end in Burnaby, BC, will be expanded with three new berths. Storage additions will include 14 new tanks at an existing terminal in Burnaby and five new tanks at an existing terminal in Edmonton. TransCanada plans to begin construction in September 2017 and place the expansion into service in late 2019.

Work for both TMEP and L3R primarily will occur in already existing rights-of-way. The same was not the case for Enbridge's Northern Gateway Pipeline, which would have been laid across virgin acreage to transport 525,000 b/d of crude from near Edmonton, Alta. 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 have shipped 193,000 b/d of condensate from the coast to Alberta. Northern Gateway was not approved.

TransCanada announced the Grand Rapids Pipeline project in 2012, a 468-km system consisting of mostly 20-in. OD pipe to transport crude oil and diluent between the producing area northwest of Fort McMurray and the Edmonton-Heartland region. The system will deliver 900,000 b/d of crude and 330,000 b/d of diluent by second-half 2017. The project's September 2016 update showed construction completed on five of eight spreads and underway on the other three. But a First Nation's lawsuit against the project was also revived in September 2016.

Pembina Pipeline Corp. in 2013 reached binding commercial agreements to move ahead with its $2-billion Phase III Pipeline Expansion. Pembina expects the 540-km expansion to enter service by mid-2017. Phase III will follow and expand certain segments of Pembina's existing pipeline systems from Taylor, BC, southeast to Edmonton, Alta., with priority placed on areas in need of debottlenecking. The core of the expansion will entail building a 270-km, 24-in. OD pipeline from Fox Creek, Alta., to the Edmonton area.

The project will provide initial additional capacity of 320,000 b/d, expandable to more than 500,000 b/d. Once complete, Pembina will have three distinct pipelines in the Fox Creek-to-Edmonton corridor, with a combined capacity of as much as 885,000 b/d. The expansion will also increase pipeline interconnectivity between Edmonton and Fort Saskatchewan, including Pembina's Redwater and Heartland Hub sites and third-party delivery points in those areas.

TransCanada's Energy East project includes 4,500 km of pipeline capable of shipping 1.1-million b/d of crude from Hardisty, Alta., and Moosomin, Sask., to refineries in eastern Canada and marine terminals in Cacouna, Que., and Saint John, NB. About 3,000 km of the pipeline will consist of TransCanada PipeLines Ltd.'s converted Canadian Mainline natural gas line, with the other 1,500 km new-build miles. TransCanada expects the project to enter service in 2020.

TransCanada in 2016 reached agreement with Canadian labor unions and the Pipe Line Contractors Association of Canada to use members for building the project (OGJ Online, July 15, 2016). Canada's National Energy Board cancelled a Montreal hearing on the project after it was disrupted by protestors. The project faces opposition from politicians, environmentalists, and First Nations groups.

Latin America

Substantial growth of US gas exports to Mexico has prompted rapid construction of new transmission capacity both between the countries and inside Mexico (Fig. 3). Infraestructura Marina del Golfo (IMG)-TransCanada Corp.'s joint venture with Sempra Energy subsidiary IEnova-will build, own, and operate the 42-in. OD, 497-mile Sur de Texas-Tuxpan natural gas pipeline in Mexico. A 25-year gas transportation service contract for 2.6 bcfd with Comision Federal de Electricidad (CFE), Mexico's state-owned power company, supports the project, expected to enter service in late 2018. The pipeline will begin offshore in the Gulf of Mexico at the border point near Brownsville, Tex., and extend along the coast to Tuxpan, Veracruz, Mexico. It will connect with Cenegas's pipeline system in Altamira and with TransCanada's Tamazunchale and Tuxpan-Tula pipelines, among other transporters in the region.

Sur de Texas will be supplied by gas from the 2.6-bcfd Valley Crossing Pipeline, to be built by Spectra Energy under a CFE contract. Valley Crossing will extend 168 miles from Agua Dulce hub in Nueces County, Tex., to Brownsville.

TransCanada will own 60% of the $2.1-billion Sur de Texas-Tuxpan project and operate it. IEnova will own the other 40%. Spectra is sole owner of the $1.5-billion Valley Crossing line.

TransCanada previously won bids to build and operate the Tuxpan-Tula (OGJ Online, Nov. 11, 2015) and the Tula-Villa de Reyes (OGJ Online, Apr. 11, 2016) lines. The 36-in. OD, 155-mile Tuxpan-Tula pipeline will carry 886 MMcfd starting in 2017. Tula-Villa de Reyes will follow one year later, moving 550 MMcfd across 174 miles through 36-in. OD pipe.

La Laguna-Aguascalientes (372 miles, 42-in. OD) is another large CFE-sponsored natural gas pipeline project in Mexico, designed to supply the company's power generation plants in Durango, Zacatecas, and Aguascalientes states as well as other portions of central and western Mexico. The project will interconnect with the El Encino-La Laguna and Villa de Reyes-Aguascalientes-Guadalajara gas pipelines, delivering 1.15 bcfd by December 2017 or early 2018.

El Encino-Laguna (262 miles, 42-in. OD) will enter service later this year, carrying gas that originated in Waha, Tex., to northwestern Mexico. The 220-mile, 42-in. Villa de Reyes-Aguascalientes-Guadalajara line is scheduled to enter service in 2018.

Refined products shipments from the US to Mexico have also grown, leading to at least two cross-border pipeline projects. Howard Midstream's Dos Aguilas pipeline will carry clean products 287 miles from Corpus Christi, Tex., to Monterrey, Mexico. Its four 12-in. OD sections comprise the Border Express pipeline from Corpus to Laredo, Tex., the Borrego from Laredo to the international border crossing (a total of 151 miles), Poliducto Frontera from the border to Nuevo Laredo, Mexico, and Poliducto del Norte from Nuevo Laredo to Monterrey (136 miles). Service is expected in 2018.

A second products pipeline, this one built by NuStar Logistics LP and Petroleos Mexicanos (Pemex), will parallel an existing line carrying NGLs from Edinburg, Tex., to Pemex's Burgos gas plant near Reynosa, Mexico. The 46-mile pipeline will use 10-in. OD pipe.

Petrobras hired Allseas to lay 298-km of natural gas export lines from the offshore Santos basin to the Comberj petrochemical complex. The Rota 3 project includes 143 km of 24-in. OD pipe, 155 km of 20-in. OD pipe, and 20 subsea structures. Allseas Calamity Jane and Solitaire will perform the work.

Asia-Pacific

OAO Gazprom and China National Petroleum Corp. (CNPC) in 2014 signed a 30-year natural gas supply contract reportedly worth $400 billion. The contract stipulates that 38 billion cu m/year (bcmy) will be supplied from Russia to China. It includes provisions for a price formula linked to oil and a take-or-pay clause. Gas will be delivered via the 2,465-mile Power of Siberia trunk line from Chayanda and Kovyktin fields. Work on the 56-in. OD line began in Yakutsk in September 2014, with construction of the Chinese section beginning June 2015.

The companies in December 2015 agreed on design and construction of the pipeline's cross-border section under the Amur River. They expect to commission the pipeline's first stage from Yakutia to Vladivostok in 2018 with the full line operational the following year.

Rosneft and Transneft agreed in September 2012 to jointly build a branch off the Eastern Siberia Pacific Ocean (ESPO) oil pipeline. linking it to Rosneft's Komsomolsk-on-Amur refinery. Installation and welding of the 8-million tpy segment began in 2016. Crude currently arrives at the refinery by rail. Transneft is financing the project, scheduled for 2017 completion, using long-term fees paid by Rosneft as part of a separate shipment agreement.

Turkmengaz is leading the consortium of national governments planning to build, own, and operate the Turkmenistan-Afghanistan-Pakistan-India (TAPI) natural gas pipeline. The group had been seeking an international company to lead the project, planned to carry 33 bcmy by 2018.

The Asian Development Bank (ADB) in 2005 estimated TAPI's cost at $7.6 billion, making the pipeline profitable only at throughputs of 30-33 billion cu m (bcm)/year. The estimated cost was nearly triple ADB's 2002 estimate of $2.6 billion. Persistent delays have since raised TAPI's projected cost to $10 billion.

TAPI would run 1,800 km, 200 km through Turkmenistan (starting from Galkynysh gas field in Turkmenistan's eastern Mary province), 773 km through Herat and Kandahar provinces, Afghanistan, and 827 km through Multan and Quetta, Pakistan, to end at Fazilka in northern Punjab province, India (Fig. 4).

The pipeline would carry 90 million standard cu m/day (MMscmd) of natural gas from the 16-tcf Galkynysh field (formerly South Yolotan-Osman) under 30-year commitments with India, Pakistan, and Afghanistan originally set to have received 38, 38, and 14 MMscmd, respectively. Afghanistan, however, has reduced its requirement to just 1.5-4 MMscmd, opening the possibility of India and Pakistan's share growing to as much as 44.25 MMscmd each.

GSPL India Gasnet Ltd. is building a 2,460-km natural gas pipeline between Mehsana and Jammu. The project received its environmental permits from the Indian government in May 2013. GSPL expects the 42-in. OD pipeline to enter service in 2018 with a capacity of 30-million cu m/day (mcmd).

Sister-company GSPL India Transco Ltd. is building a 1,585-km pipeline between Mallavaram and Bhilwara. The pipeline will use pipes between 18- and 36-in. OD, also moving 30 mcmd but by 2017. Both pipelines will carry production and imports from India's east coast to consumers in central and northern parts of the country.

GAIL (India) Ltd. plans by 2018 to build a 1,825-km gas pipeline from Surat to Indian Oil Corp.'s (IOC) 15 million tonne/year refinery in Paradip. The 36-in. OD west-to-east line passing through Maharashtra and Chhattisgarh includes five spur lines totaling 124 km.

Construction began in July 2015 on the first phase of GAIL's Jagdishpur-Haldia natural gas pipeline. The 2,050-km pipeline-922 km of 36-in. OD trunkline and 1,028 miles of 12-30 in. spur and feeder lines-will connect eastern India to the national grid. The initial phase will ship 7.4 million cu m/day (cmd), with total capacity reaching 16 million cmd.

The pipeline will cross Bihar, Jharkhand, West Bengal, and Uttar Pradesh states. It will pass through 13 districts in Bihar, supplying both a refinery in Barauni. It will also supply local gas networks in Barauni, Gaya, and Patna. It is expected to enter service in 2018.

IOC plans to build a nearly 2,000-km LPG pipeline to ship cooking gas from Kandla port and a refinery at Koyali east to consumers in Gorakhpur by 2020. The line would use 10.75 and 12.75-in. OD pipe to move 3.75 million tonnes/year.

The long-discussed Iran-Pakistan-India (IPI) natural gas pipeline has been given a new lease on life by the need to link a planned LNG terminal at Gwadar, Pakistan, with consuming markets. A 700-km, 42-in. OD pipeline would run from Gwadar LNG east to Nawabshah and access to the Sui Southern Gas Co. network (Fig. 4). An 81-km leg from Gwadar to the Iranian border could complete IPI, now more likely just including Iran and Pakistan, once the larger line has entered service. CNPC affiliate China Petroleum Pipelines Bureau will build the pipeline, expected to enter service in 2018. The Iranian section of the line is built.

Russia, meanwhile, has agreed to build a pipeline in Pakistan connecting an LNG terminal in Karachi with Lahore (Fig. 4). The 42-in. OD, 683-mile pipeline would carry 1.2 bcfd north from the coast starting in 2018.

Europe

Gazprom and Germany's BASF SE in August 2015 signed a memorandum of intent stipulating cooperation on building the Nord Stream II gas pipeline. The companies would build strings No. 3 and No. 4, connecting the Russian and German coasts under the Baltic Sea and doubling the line's 55-bcmy capacity by 2019. E.On, Shell, and OMV AG each previously had agree to participate in construction of the two strings. Intertek was awarded a project inspection and expediting contract in December 2016.

Russia in late 2014 decided against building the 930-km South Stream natural gas pipeline across the Black Sea from Russia to Bulgaria, citing delays on the part of the European Union in taking the steps necessary to move forward. Gazprom Chief Executive Alexei Miller and Mehmet Konuk, chairman of Botas Petroleum Pipeline Corp., signed a memorandum of understanding Dec. 1, 2014, on instead building an offshore gas pipeline from the Russkaya compressor station (also South Stream's starting point), under construction in the Krasnodar Territory, across the Black Sea to Turkey (OGJ Online, Dec. 2, 2014).

The new pipeline, TurkStream, would have the same 63 bcm/year overall capacity, with 14 bcm/year to be used in Turkey and the balance shipped to a border crossing with Greece. The 448-Mw Russkaya station will provide as much as 28.45 MPa of pressure, enough to have shipped gas on South Stream to Bulgaria without intermediate compression.

Gazprom in 2016 received permits both for construction and to conduct survey work in Turkey's territorial waters on TurkStream's first two strings. The line's offshore section will consist of four 15.75-billion cu m/year strings. Gazprom hired Allseas Pioneering Spirit to conduct the 900-km offshore pipelay.

Partners in the Shah Deniz consortium made a final investment decision (FID) in December 2013 on Stage 2 development of the natural gas field offshore Azerbaijan, triggering plans to expand the South Caucasus Pipeline (SCP) through Azerbaijan and Georgia, build the Trans Anatolian Gas Pipeline (TANAP) across Turkey, and begin work on the previously selected Trans Adriatic Pipeline (TAP) for shipment into Europe.

SCP expansion will twin the existing Baku-Tbilisi-Ceyhan (BTC) pipelines through Azerbaijan and Georgia, as well as adding two compressor stations to boost capacity by 16 bcmy. Plans call for 441 km of new 56-in. OD pipe; 385 km through Azerbaijan and another 56 into Georgia, at which point the expansion will connect to the existing SCP. The first additional compressor station will be 3 km inside Georgia, collocated with an existing BTC station near Rustavi. The second new station will be at a greenfield site on the existing line 139 km downstream, west of Tsalka Lake, Georgia. SCP's current capacity is 7 bcmy. BP expects work to be completed by end-2018.

TANAP will run 1,800 km at an estimated cost of at least $7 billion. The 48- and 56-in. OD pipeline will move as much as 30 bcm/year by 2018, coinciding with first gas from Shah Deniz II. Construction was roughly 55% complete as of November 2016. GE is scheduled to deliver compressors in 2017.

The Shah Deniz II consortium in June 2013 selected the Trans Adriatic Pipeline (TAP) as the project's European transport option. TAP will transport as much as 20-billion cu m/year of natural gas from Shah Deniz II through Greece and Albania to Italy, from where it can be shipped further into Western Europe.

The project will use 36- and 48-in. OD pipe, with service also expected to begin in 2018. The 36-in. pipe will make up the line's 115-km offshore section, with the 48-in. pipe used onshore. Total planned length is 800 km.

Shah Deniz II will add 16 bcmy of gas production to the roughly 9 bcmy of Shah Deniz Stage 1. Field development, 70 km offshore Baku in the Azerbaijan sector of the Caspian Sea, will include two new bridge-linked production platforms; 26 subsea wells to be drilled with 2 semisubmersible rigs; 500 km of subsea pipelines built in up to 550 m of water; the 16 bcmy upgrade to SCP; and expansion of the Sangachal Terminal.

The Poland-Lithuania Gas Interconnector (GIPL), designed to connect the Polish and Lithuanian gas transmission systems, is still planned but was delayed for 2.5 years by Poland, pushing completion to 2021. The 28-in. OD pipeline would run 310-357 km between Holowczyce, Poland, and the Lithuanian border, and another 177 km from the border to Jauniunai, Lithuania.

Middle East

Iraq began technical work in 2014 on twin 1,043-mile pipelines- one crude oil, one associated fuelgas-running from Basra to the Red Sea at Aqaba, Jordan. The oil pipeline would use 56-in. OD pipe and the gas line 36-in. OD, with respective capacities of 1-million b/d and 258 MMcfd. The pipeline would cross 422 miles inside Iraq with the balance in Jordan.

Jordan will keep 150,000 b/d of oil for domestic refining and use roughly 100 MMcfd of the natural gas, with the rest burned in the oil pipeline's pump stations. Iraq is pursuing the project to decrease its dependence on the Persian Gulf as an oil export route. An invitation to bid on Phase 1 of the pipeline, carrying 2.25 million b/d from Basra to Najaj, Iraq, opened in December 2016.

Saipem signed a memorandum of understanding (MOU) with National Iranian Gas Co. (NIGC) for possible cooperation on NIGC's proposed Iran Gas Trunkline IX (IGAT 9) and Iran Gas Trunkline XI (IGAT 11) projects, which combined would cover 1,800 km (OGJ, Feb. 2, 2015, p. 72). Saipem did not disclose details regarding timelines or estimated values for projects under the MOUs, which follow the recent suspension of long-standing international sanctions on Iran that prohibited US and many European firms from participating in development of the country's energy sector.

NIGC plans to build the 300-km Iranshahr-Chabahar pipeline by 2018. The pipeline would use 240 km of 56-in. OD line and 60 km of 36-in. OD line, delivering natural gas to power the Chabahar free trade and industrial zone.

The National Iranian Gas Export Co. (NIGEC) in 2016 hired Iranian Offshore Engineering and Construction Co. (IOEC) and Pars Consultant Engineering Co. to perform survey and basic engineering work on a 380-km pipeline intended to carry Iranian gas to Oman. IOEC will complete the offshore study and Pars the onshore.

The onshore section of the pipeline would use 200 km of 56-in. OD pipe in Iran, with the offshore section running 180 km of 36-in. OD pipe from Kuhe Mubarak, Iran, to Sohar Port, Oman. The onshore pipe would move gas from the IGAT VII pipeline to Kuhe Mubarak. Delivery of 28 million cu m/day to Oman would begin in 2019.

Oman Gas Co. (OGC) plans to build a 221-km, 36-in. OD pipeline to deliver natural gas from Saih Nihayda in central Oman to an industrial and maritime hub being developed in Duqm. OGC signed Petrojet as contractor in late 2016 and expects the 25-mcmd pipeline to enter service in 2019.

Africa

Uganda and Kenya plan to build a 930-mile, 24-in. OD heated crude oil pipeline (UKCOP) from fields in Uganda and western Kenya to the Kenyan port of Lamu. The pipeline would transport roughly 300,000 b/d. This could be expanded by 130,000 b/d to include South Sudan's participation. The World Bank in 2014 pledged $600 million to help build the pipeline. The countries awarded a design contract to Toyota Tsusho in November 2014, with design work completed in 2015.

Total SA, however, has suggested an alternate route, stretching from Hoima, Uganda, via northern Tanzania to the Port of Tanga on the Indian Ocean, bypassing Kenya completely. While this proposal was initially ignored by both Kenya and Uganda, Uganda is now exploring the possibility of such a pipeline with Tanzania. The two countries in November 2016 agreed to accelerate study of this route. Only one of these lines will be built, with completion of either not expected before 2020.

Ethiopia and Djibouti plan to build a 550-km, 20-in. OD multi-product pipeline from a port site in Damerjog, Djibouti, to storage in Awash, central Ethiopia. Black Rhino Group and South Africa-based Mining Oil & Gas Services (MOGS) signed a framework agreement in early 2016 to build the 240,000-b/d line and expect it to be operational by fourth-quarter 2018.

The greenfield port at Damerjog will include an import terminal and 950,000 bbl of storage. The pipeline will replace truck transport of petroleum products.

Bulk Oil Storage and Transportation Co. Ltd. (BOST) in late 2015 awarded a front-end engineering and design contract to Penspen for development of Ghana's Natural Gas Interconnected Transmission System (NGITS). The planned 750-km Phase 1 buildout would run from Aboadze to Tema, and from Prestea to Buipe, via Kumasi. The project will use 24-in. OD pipe with completion expected in 2018.