Monday, May 21, 2018

Conoco Aims To Seize Oil Cargoes Near Citgo's Aruba Terminal

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U.S. oil company ConocoPhillips has brought new court actions to seize two cargoes of crude and fuel near a terminal operated by PDVSA subsidiary Citgo Petroleum in Aruba, the Aruban government confirmed on Tuesday.

Conoco is moving aggressively to enforce a $2 billion arbitration award over the 2007 expropriation of two oil projects in Venezuela, creating unease in the Caribbean, where many islands depend on fuel produced by state-run PDVSA.

The Aruba refinery has said that an embargo on two Citgo oil cargoes was introduced last night. Citgo is claiming the crude as its own, and is fighting at court to demonstrate the product is not PDVSA’s,” said Prime Minister Evelyn Wever-Croes in a statement. “Independent of any outcome, this is not going to affect Aruba,” she said.

The cargoes seized included 500,000 barrels of crude oil on the Grimstad and about 300,000 barrels of jet fuel, gasoline and diesel on the Atlantic Lily, according to a source at the Aruba terminal and Thomson Reuters vessel tracking data.

Citgo, the U.S. refining unit of PDVSA, has leased the 209,000 barrel-per-day (bpd) Aruba refinery and its 13 million-barrel terminal from the government since 2016 to store Venezuelan and other crudes for supplying its U.S. refineries.

As the refinery remains idled since 2012 while a major refurbish project is underway, Citgo regularly supplies the island with imported fuel.

Wever-Croes told journalists government officials and the management of the refinery were organizing a contingency plan to avoid a situation similar to Curacao and Bonaire, where inventories were blocked by Conoco’s legal actions.

No fuel shortages have been reported in the Caribbean but officials are trying to import from other sources.

Conoco in recent days seized the 10-million-barrel BOPEC oil terminal owned by PDVSA in Bonaire and fuel inventories at the 335,000-bpd Isla refinery operated by the Venezuelan firm in Curacao. Both islands are in talks with Conoco to free fuel for domestic consumption.

What belongs to Citgo belongs to PDVSA, but a judge has to rule on it,” Wever-Croes said.

Daren Beaudo, a Conoco spokesman, said on Tuesday that the company sent representatives to the Caribbean this week to meet with local officials and address their concerns over Conoco’s efforts to enforce the arbitration award by the International Chamber of Commerce (ICC).

PDVSA did not immediately respond to a request for comment.

Last week, Curacao officials said the Isla refinery would have to halt refining operations once its available inventories were exhausted.

It is PDVSA that has failed to honor our award by ignoring the judgement of the ICC tribunal and other local court orders,” Beaudo said in a statement.

Conoco Chief Executive Ryan Lance on Tuesday said the firm is far from recovering all of the $2 billion ICC award. He said legal actions have been brought in Hong Kong and London to have the ruling recognized following a similar move last month in a New York court.

Friday, May 18, 2018

Tanker Markets - VLCC recycling continues

Image result for vlcc ship breaking pakistan


Following the official reopening of the Pakistani market for tankers, the offloading of the plethora of unsold tanker/VLCC tonnage continued at pace last week, as interested Pakistani Buyers eagerly filled their plots. 
 
There were further VLCC sales concluded, gradually bringing the total number of units sold through 2018 towards the 30 mark, a figure which looks likely to be reached before the end of May - not even halfway through the year - GMS said in its weekly report.

There is a noteworthy dissimilarity in pricing a VLCC versus MR/Aframax/Suezmax types, as very few end buyers in the Indian sub-continent are capable of opening such large US dollar value Letters of Credit (LC).

Under the current market conditions, this can easily amount to an around $18 mill LC on roughly 40,000 ldt unit, GMS said.

Given the limited number of capable end buyers who are able to do this (translating into a lower demand), VLCCs are discounted far more than the average tanker for which, a greater number of buyers are open/available to negotiate.

Moreover, VLCCs usually take between six to eight months to fully recycle, resulting in a significant exposure for the respective buyer who will likely endure multiple market peaks & troughs over this period. Only a recycler with a strong financial standing is generally willing/able to withstand these fluctuations.

Pakistan and Bangladesh - both of which have reached saturation point - tend to be the main buyers for large ldt tonnage, while Indian recyclers prefer smaller vessels that can be quickly dismantled, thus minimising there market exposure, due to the generally volatile nature of steel plate prices and currency fluctuations.

Finally, those owners who opt to sell their large ldt ships into India for Hong Kong Convention green recycling, such as Ridgebury Tankers last week, there is normally a large discount to contend with, compared to conventional recycling, GMS said.

The sale of the 1999-built VLCC ‘Ridgebury Pioneer’ for a reported $408 per ldt on the basis of ‘as is’ Khor Fakkan, gas free and with 300 tonnes of bunkers ROB was said to have been concluded at a $500,000 discount.

Other deals reported by brokers included the 2000-built VLCC ‘Greek Warrior’ sold to undisclosed interests for $430 per ldt, ‘as is’ Singapore, gas free for man entry and with 480 tonnes of bunkers ROB and the 2001-built VLCC ‘Silver Glory’ for $436.5 per ldt with delivery Indian sub/cont.

The 1997-built Aframax ‘Oil Runner’ was said to be sold to undisclosed interests for $470 per ldt, ‘as is’ Khor Fakkan with 70 tonnes of bunkers ROB and with various equipment, including two propellers.

In addition, the 1999-built LR1 ‘Amazon Guardian’ was reported committed for $455 per ldt to Pakistan recyclers, ‘as is’ Khor Fakkan, gas free for hot works and with 400 tonnes of bunkers ROB.
Finally, the 1991-built MR ‘Divine Mercy’ was reported sold to Pakistan interests for an undisclosed price.

GMS has supported the publication of a booklet entitled - ‘The Recycling of Ships’  - written by consultant Nikos Mikelis.

It contains a list of the world’s recycling facilities and chapters on the economic drivers behind the decision to recycle, sale & purchase with end-of-life ships, the Hong Kong Convention, EU Ship Recycling Regulation and standard improvements within the ship recycling industry.

The booklet is available to download as a pdf at www.gmsinc.net

Thursday, May 17, 2018

More Pain May Come for Nigeria's Loss-Making Oil Behemoth


  • Abuja-based NNPC made operating losses of $246 million in 2017
  • Financial woes contrast with state firms from Norway to Saudi
It’s meant to be a cash cow, but the state oil company of Africa’s biggest producer is bleeding money.

Nigerian National Petroleum Corp., the Abuja-based behemoth that dominates the OPEC member’s energy industry, has made losses for at least the last three years, statements on its website show. It will probably register another in 2018, according to Ecobank Transnational Inc., as its refineries and fuel-retailing arm fail to generate profit.

The pain for NNPC, which produces oil and natural gas in partnership with Royal Dutch Shell Plc, Exxon Mobil Corp. and Chevron Corp., comes even as national energy firms from Norway to Saudi Arabia thrive with crude prices recovering from their crash in 2014. And it lays bare President Muhammadu Buhari’s difficulty in fulfilling his pledge to modernize a company that’s been a byword for inefficiency and opacity since its creation in the 1970s.

With oil accounting for more than half of government revenue and 90 percent of export income, the company is a primary target of those seeking access to state funds and is vulnerable to political interference.

Tensions erupted last year between Emmanuel Kachikwu, the chairman of NNPC, and Maikanti Baru, the managing director, over how more than $20 billion of contracts were agreed.

“The very public power tussle shows the difficulties in reforming the organization,” Malte Liewerscheidt, an analyst at Teneo Intelligence, said in an email from Abuja. Until a pending but long-delayed law designed to overhaul the petroleum sector and split up parts of NNPC comes into effect, “political considerations will continue to interfere with vital business needs,” he said.

The state oil company doesn’t publish full financial results, though it releases limited numbers on its operating performance. These include earnings for core units, but exclude items such as taxes and dividends from a 49 percent shareholding in Nigeria LNG Ltd., one of the world’s biggest exporters of liquefied natural gas.

Those numbers show that NNPC made an 82 billion naira ($246 million) operating loss in 2017. That was an improvement from 2015 and 2016, but still far from the operating income it budgeted for of 600 billion naira. In each of the past three years, NNPC forecast a profit and finished in the red.

Higher oil prices have boosted exploration and production, the most profitable part of NNPC and which earned almost $600 million in 2017. But its ill-maintained refineries, which operate at a fraction of their combined capacity of 445,000 barrels a day, lost about $100 million. Even bigger shortfalls came in the fuel-retailing business, which has to contend with the government’s cap on gasoline prices, and the corporate headquarters unit, which lost almost $400 million, more than any other part of the company.

While NNPC’s extraction business will probably improve this year, the refineries and retailing subsidiaries will continue to be a drag, especially if the government maintains the ceiling of $0.40 a liter for gasoline, according to Ecobank. The bank predicts that NNPC will make an operating loss of as much as 80 billion naira in 2018.

Ndu Ughamadu, a spokesman for NNPC, said that while the refineries are struggling to make money, the company’s overall performance will probably be better this year. He declined to say if NNPC was forecasting a return to profit. It made a loss of 1.6 billion naira in January, the latest month for which results have been released.

The problems at NNPC offset the benefits to Nigeria’s struggling economy of Brent crude’s more than 50 percent rise in the past year to almost $80 a barrel. Still, there have been improvements within the company and the country’s overall oil sector, according to Moody’s Investors Service.
NNPC’s reduction of debts owed to joint-venture partners may help increase Nigerian oil production to around 2.5 million barrels a day by 2020 from 2 million today, said Aurelien Mali, an analyst at Moody’s.

“The clearing of arrears is a huge step forward that will unleash extra investment from international oil companies,” Mali said in an interview in Lagos, the commercial capital, on May 9. “NNPC is key for the government. It’s going in the right direction.”

It has some catching up to do. Its financial position contrasts with those of state oil firms in other major producers. Saudi Aramco is gushing cash, making net income of $34 billion in the first half of 2017 alone, according to numbers seen by Bloomberg. Brazil’s Petrobras, Mexico’s Pemex and Norway’s Statoil all improved their results in 2017 and made operating profits. So did Angola’s Sonangol in 2016, when it last published data.

Wednesday, May 16, 2018

Morgan Stanley Says a Shipping Revolution Has Oil Headed for $90

Morgan Stanley's lower global outlook rattles world markets

https://www.bloomberg.com/news/articles/2018-05-16/morgan-stanley-says-a-shipping-revolution-has-oil-headed-for-90

Forget Iran and OPEC -- there’s another issue that will keep oil prices supported for the next two years, according to Morgan Stanley.

Brent crude will reach $90 a barrel by 2020 as new international shipping regulations take effect, overhauling the types of fuels produced by refiners, the bank’s analysts said in a report.

The changes, which force vessels to consume lower sulfur fuels beginning in January of that year, will lead to a boom in demand for middle distillate products including diesel and marine gasoil, triggering the need for more crude, they said.

“We foresee a scramble for middle distillates that will drive crack spreads higher and drag oil prices with it,” wrote Morgan Stanley analysts including Martijn Rats.

While crude has already received a boost due to supply cuts by the Organization of Petroleum Exporting Countries and geopolitical events including the U.S. decision to reimpose sanctions on Iran, the rule changes add to the impact. Global benchmark Brent, which neared $80 a barrel earlier this week, is trading at the highest levels since late 2014. Futures for the January 2020 contract are at about $66.60 a barrel.

The rules from the International Maritime Organization call for ships to reduce the maximum sulfur content of their fuels to 0.5 percent, from 3.5 percent in most regions currently, in an effort to curb air pollution that has been linked to respiratory diseases and acid rain. The changes are expected to create an oversupply of high-sulfur fuel oil while sparking demand for IMO-compliant products, putting pressure on the refining industry to produce more of the latter fuels.

Repsol SA, Reliance Industries Ltd., Valero Energy Corp. and Tupras Turkiye Petrol Rafinerileri AS are among those who stand to benefit most, according to Morgan Stanley.

“The refining systems of these companies are highly geared towards middle distillates” and minimal high-sulfur fuel oil output, which is “the most advantageous combination after 2019,” the bank said in a related report.


Middle distillate markets are already showing signs of tightness. Diesel and gasoil stockpiles in key storage hubs in Europe, the U.S. and Asia are below their five-year seasonal averages. At the same time, middle distillate demand has grown at an annual rate of about 600,000 barrels a day since 2011, accelerating to 800,000 barrels a day in recent quarters, Morgan Stanley estimates.

Increased Demand

With the IMO ship-fuel regulations expected to boost demand by an additional 1.5 million barrels a day by 2020, traders will seek to get the right product supplies, which should boost crude prices, according to the bank. While global crude production will rise, it probably won’t increase by the 5.7 million barrels a day needed by 2020 to meet the additional demand for fuels, the analysts said.

“The last period of severe middle distillate tightness occurred in late-2007/early-2008 and arguably was the critical factor that drove up Brent prices in that period,” Rats wrote, referring to the period when crude oil approached levels close to $150 a barrel.

U.S. oil output, now at a record, likely won’t come to the rescue, since the crude pumped in America’s shale regions is light and not ideal for producing middle distillates, Morgan Stanley noted.
“We expect the crude oil market to remain under-supplied and inventories to continue to draw,” the bank said. “This will likely underpin prices.”

Tuesday, May 15, 2018

Crude oil futures rise again on risk, OPEC demand forecasts; July ICE Brent at $79.14/b, June NYMEX $71.61/b

https://s.tradingview.com/x/iRYjwfri/


Crude oil futures pushed higher again in European morning trading Tuesday, with geopolitical risk remaining elevated and the market still digesting OPEC's higher forecasts for global demand this year.

At 1100 GMT, ICE July Brent crude futures were trading at $79.14/b, up 91 cents from Monday's settle, while NYMEX June WTI crude futures were 65 cents higher at $71.61/b.

OPEC in its latest monthly report on Monday increased its world demand forecasts for 2018, with growth in consumption revised up by 25,000 b/d to 1.65 million b/d from the previous report.

OPEC also said OECD commercial crude oil stockpiles had declined in March to 9 million barrels above the five-year average.

The revised demand growth predictions come at a time when the global crude market is also facing other significant supply-side question marks, such as the impact of the imposition of US sanctions on Iranian output and the ongoing struggles of the Venezuelan oil sector.

Venezuela's production dropped 40,000 b/d to 1.44 million b/d in April, according to secondary sources.

While there are doubts over Iranian and Venezuelan production, US crude production has continued to rise in recent months. According to analysts, once certain logistical issues are solved in the US, its crude production can help fill the gap left by production declines elsewhere.

"The rapidly growing US shale oil production is currently helping to plug the supply gap to only a limited extent because pipeline bottlenecks are preventing some of the oil from reaching the refineries and export terminals on the US Gulf Coast," said Commerzbank analysts in a note.

"Once the pipeline problems have been resolved and supply is available again, this will have a dampening effect on prices."

In the short term, there are expectations of a further decline in US stockpiles for the week ended May 11. An S&P Global Platts survey of analysts indicates US crude stocks are expected to fall by 2.3 million barrels.

Official data on US crude and product stocks will be released by the Energy Information Administration on Wednesday. The American Petroleum Institute meanwhile will release its weekly inventory numbers later Tuesday.

--John Morley, john.morley@spglobal.com

--Edited by Alisdair Bowles, alisdair.bowles@spglobal.com

Monday, May 14, 2018

PDVSA Suspends Oil Storage, Shipping From Caribbean

http://energy-cg.com/OPEC/Venezuela/Venezuela_OilFieldIndexMap_ECG_Nov16_Image1x1_EnergyConsutlingGroup_web.png

State-run PDVSA has suspended oil storage and shipping from its Caribbean facilities following legal actions last week by ConocoPhillips to temporarily seize the Venezuelan firm's assets in four islands, according to a PDVSA source and Reuters data.


The Venezuelan company has begun concentrating most of its shipping operations for export at its main crude port, Jose, as two additional terminals in Venezuela are limited in receiving more vessels, the source said.

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Conoco Authorized to Seize $636 Million In Venezuela PDVSA Assets

Court house 
Curacao Court / Caribbean

A Curacao court has authorized ConocoPhillips to seize about $636 million in assets belonging to Venezuela’s state oil company PDVSA due to the 2007 nationalization of the U.S. oil major’s projects in Venezuela.

The legal action was the latest in the Caribbean to enforce a $2 billion arbitration award by the International Chamber of Commerce (ICC) over the nationalization.

The court decision, first reported by Caribbean media outlet Antilliaans Dagblad on Saturday, says Curacao can attach “oil or oil products on ships and on bank deposits.”

Conoco and PDVSA did not immediately respond to requests for comment on the decision, which was seen by Reuters and dated May 4.

Conoco earlier this month moved to temporarily seize PDVSA’s assets on Aruba, Bonaire, Curacao and St. Eustatius. That threw Venezuela’s oil export chain into a tailspin just as Venezuela’s crude production has crumbled to a more than 30-year low due to underinvestment, theft, a brain drain and mismanagement.

Reuters reported on Friday that PDVSA was preparing to shut down the 335,000 barrel-per-day Isla refinery it operates in Curacao amid threats by Conoco to seize cargoes sent to resupply the facility.
PDVSA is also seeking ways to sidestep legal orders to hand over assets. The Venezuelan firm has transferred custody over the fuel produced at the Isla refinery to the Curacao government, the owner of the facility, according to two sources with knowledge of the matter.

PDVSA transferred ownership of crude to be refined at Isla to its U.S. unit, Citgo Petroleum, one of the sources said.

For the time being, PDVSA has suspended all oil storage and shipping from its Caribbean facilities and concentrated most shipping in its main crude terminal of Jose, which is suffering from a backlog.

Friday, May 11, 2018

Oil Smuggling Activities / Risk of arrest off Libya

https://www.libyaherald.com/wp-content/uploads/2017/06/148-Militia-funding-UN-report-fuel-smuggling-by-sea-4-130617.jpg 

http://www.tankeroperator.com/ViewNews.aspx?NewsID=9673

Oil smuggling activities in waters off the Western Libya coast continue to pose risks to vessels sailing in these waters, insurance and P&I service provider Gard has warned. 
 
In an industry note, Gard advised tanker operators to warn their vessels’ crews of the situation and to carry out an assessment of the risks involved before engaging in voyages to these waters.

Over the last few years, nearly 300 crew members have been arrested and are being held in a Tripoli prison, awaiting trial for alleged oil smuggling, according to the company’s Libyan correspondent.

As a result of the fall of the Gaddafi regime and the subsequent formation of a UN recognised Government in the country, there has been an increase in illegal trade of government oil assets on the black market. The Government is clamping down on this illegal trade and the vessels involved, knowingly or unknowingly, may have their crew arrested for later trials.

According to Gard’s correspondent, tankers suspected of calling at certain loading areas in Western Libya risk being boarded by the Libyan Navy and the vessel and her crew could be detained for further investigations.

The loading areas currently at risk are mostly located offshore between Zawiya and the Tunisian border.

Once a vessel has been detained, investigations can take several years. The correspondent also warned that some of the crew members arrested for alleged oil smuggling have been in prison for over two years - with no real prospect of release in the foreseeable future. And while the crew members remain in the custody of the police, the vessel is kept at anchor as a ‘dead’ ship with negligible support from the port.

Gard advised owners and operators to instruct their ships to continue to exercise caution when entering Libyan ports and waters and follow the official sea navigation routes to any of the working Libyan ports.

For tankers trading to this region, the company’s Libyan correspondent recommended the following:

•             When contracting a vessel for a voyage to Libya, obtain a certificate of origin from the charterers indicating that the shippers are a national oil company (NOC) or an approved legal entity of the NOC. The Libyan NOC has the sole rights and control of all oil exports from the country. Most detentions related to oil smuggling, have been to tankers operating offshore and not in a port.

•             Charterers should establish the legitimacy of cargo interests and whether they can legitimately ship oil cargoes from Libya. The shippers should be able to provide a letter or document to prove that they are authorised by the NOC to ship the cargo. Gard’s correspondents will be able to verify the legitimacy of the documents and provide general guidance, if required.

•             Tankers delivering fuel oil to Libya, should, on completion of cargo operations and upon receiving port clearance, sail directly out of Libyan waters without deviation or delay, as deviations or delays may be construed as suspicious by the authorities.

•             Upon leaving the Libyan coast, vessels should avoid navigating close to the coast. It is recommended maintaining a distance of 40 nautical miles from the coast for safety. Most cases of detention have occurred within 25 nautical miles of the Libyan coast.

Thursday, May 10, 2018

Marathon Petroleum to Buy Andeavor in Biggest Oil Refining Deal

https://assets1.csnews.com/files/2018-04/Marathon%20Andeavor%20Merger_Sm_043018.jpg


Marathon Petroleum Corp. agreed to buy rival Andeavor for $23.3 billion in the biggest-ever deal for an oil refiner that would create the largest independent fuel maker in the U.S.

The offer, payable in either cash or shares, values Andeavor at about $152.27 a share, the companies said in a statement Monday. That represents a 24 percent premium over Friday’s closing price.

Marathon shares sank as much as 8.9 percent in early trading with analysts at RBC Capital Markets seeing the deal done at “peak refining bullishness.” Andeavor rose as much as 18 percent. Shares of Andeavor, Marathon and other independent refiners have soared to record highs this year.

Growing fuel demand, both in the U.S. and Latin America, and a shale boom that’s expanded access to relatively inexpensive domestic supply have given American refiners a leg up against foreign competitors.

“Why wouldn’t you do this deal?” Greg Goff, Andeavor’s chief executive officer, said on a conference call Monday. “The time is right now, because for this industry, the wind is behind our backs.”

Passing Valero

Marathon is focused in the Midwest and Gulf Coast, while Andeavor concentrates on the western U.S., including refineries and pipelines it acquired in last year’s merger with Western Refining Inc. The combination, which will use the name Marathon, would overtake Valero Energy Corp. as the biggest in U.S.-based oil refiner by capacity, generating about 16 percent of the nation’s total, according to Bloomberg calculations.

“Wow!” Matthew Blair, director of refining research at Tudor Pickering Holt & Co., wrote in a report. Blair called Andeavor a “big winner” in a deal that is “extremely positive.” As for Marathon, meshing the two giant companies will be key, Blair said, adding that regulatory problems should be minimal, “given the disparate geographical markets of each company.”

The companies said they expect annual cost and operating synergies of about $1 billion within the first three years. Given projected cash-flow generation, Marathon’s board also approved share buybacks of $5 billion. Gary Heminger, Marathon’s CEO, will be chief executive. Goff will become executive vice chairman.

The boards of both companies unanimously approved the deal, which is expected to close in the second half of this year, subject to regulatory and shareholder approvals.

Passing Phillips

Marathon’s shares were down 6.8 percent to $75.88 as of 12:17 p.m. in New York, while Andeavor jumped 13 percent to $138.72.

Findlay, Ohio-based Marathon is the third-largest U.S. refiner by market capitalization, valued at about $38.6 billion, according to data compiled by Bloomberg. Last year the company sold 5.8 billion gallons of fuel through its Speedway convenience store chain. The combined company would pass Phillips 66, valued at $51.9 billion, as the largest U.S. independent refiner by market capitalization.

San Antonio, Texas-based Andeavor, formerly known as Tesoro Corp., is the fourth-largest, worth $18.7 billion. The company’s assets also include 5,300 miles of pipelines and 40 marine, rail and storage terminals.

Last week, Andeavor announced two joint ventures to move crude oil from West Texas to the Gulf Coast.

Permian Access

The first venture, a pipeline project majority owned by Phillips 66, would haul as many as 700,000 barrels per day of crude from the Permian Basin to the Corpus Christi, Sweeny and Freeport area. The second is a stake in a new marine terminal under development by Buckeye Partners LP that would connect with the pipeline.

Marathon’s Galveston Bay refinery, which currently buys about 200,000 barrels a day of light domestic oil, could benefit from the pipeline connectivity, Heminger said in a conference call Monday.

Marathon’s natural gas processing capacity will also increase by about 20 percent under the deal, to more than 10 billion cubic feet per day.

The combined entity expects to be well-positioned to capitalize from upcoming regulations to reduce pollution from ships. Andeavor’s port assets in California, coupled with Marathon’s in the U.S. Gulf Coast, will give the combined company the ability to sell lower-sulfur ship fuel.
 
“Ports are the lifeblood to refining out in those markets,” Heminger said Monday.

— With assistance by Naureen S Malik, and Dan Murtaugh

Wednesday, May 9, 2018

Crude oil futures inch higher in Asia after US leaves Iran deal



Crude oil futures inched higher during the Asian early-afternoon trade Wednesday, as the market continued to digest news of President Trump's decision to withdraw US from the Iran nuclear deal.

Related feature -- Iran Sanctions: Global Energy Implications

OPEC's comments on remaining committed to its supply cuts despite the US' withdrawal from the deal as well as the larger-than-expected draw in US' weekly crude oil stocks had also lent support to the crude futures.

At 12:00 pm Singapore time (0400 GMT), July ICE Brent crude futures were up $1.84/b (2.46%) from Tuesday's settle to $76.74/b, while the NYMEX June light sweet crude contract was up $1.59/b (2.30%) from Tuesday's settle to $70.65/b.

The last time ICE Brent hit above $76/b was in November 26, 2014. As for NYMEX WTI, the last time it was above $70/b was on 27 Nov 2014.

Crude futures had settled lower during Tuesday's trading session, but bounced back to touch fresh highs during mid-morning trade in Asia Wednesday.

"The upward rally this morning is a natural reaction to Trump's announcement," Vanda Insights founder Vandana Hari said.

"The rally may however not last long enough for prices to hit say $80/b[for ICE Brent] as markets may pause to reassess the situation," Hari added.

"Post the initial knee-jerk reaction, markets will actually wait to see the fallout in exports and what stance the importing countries take," Hari said.

President Donald Trump announced Tuesday on the withdrawal of US from the Iran nuclear deal and that "powerful" economic sanctions "will be put into full effect."

However, he did not give any timing for when or how the US plans to restart the sanctions regime.

Reimposing US sanctions on Iranian oil buyers will likely have an immediate impact of less than 200,000 b/d and block less than 500,000 b/d after six months, most analysts surveyed by S&P Global Platts said. But some analysts expect a substantial supply disruption of up to 1 million b/d.

As it did from 2012-2015 before the nuclear deal, the US will consider allowing countries to continue importing Iranian crude as long as they demonstrate they are significantly reducing those volumes every 180 days, a Treasury Department fact sheet showed.

"Countries seeking such exceptions are advised to reduce their volume of crude oil purchases from Iran during this wind-down period," the notice said.

Market participants were convinced that the Iran sanctions bode well for prices, analysts said. "If the supply squeeze materialize [from the Iran sanctions], oil producing countries can increase production within the permissible limits. Market sentiments are already geared towards this." Phillip Futures' investment analyst Benjamin Lu said.

"Fundamentally, we can already see global inventories falling, if the OPEC report inventories hitting below the 5 year average, prices will get a boost again," Lu added.

"A six-month loss of 250,000b/d of Iran supply could support oil prices by $3.50/b above our summer $82.50/b Brent forecast if other OPEC members do not respond to offset it," a Goldman Sachs' report showed.

UAE Energy Minister Suhail al-Mazrouei on Tuesday indicated OPEC would remain committed to its production cuts, saying that "Working collaboratively with our partners, our joint efforts to re-balance the oil market and bring investment back into our industry are progressing well."

Separately, data from the American Petroleum Institute reported a draw of 1.85 million barrels in crude stocks for the week ending May 4, indicating an uptick in global demand as refineries come out from the maintenance slumber.

Analysts surveyed Monday by S&P Global Platts expected crude stocks to have fallen by 400,000 barrels for the same period.

As of 0400 GMT, the US Dollar Index was 0.04% lower at 93.015.

--Jing Zhi Ng, jz.ng@spglobal.com
--Avantika Ramesh, avantika.ramesh@spglobal.com
--Edited by Norazlina Juma'at, norazlina.jumaat@spglobal.com

Tuesday, May 8, 2018

U.S Gas Prices May be Fueling Renewed Interest in Electric Cars

Tesla publishes patents for ‘the advancement of electric vehicle technology’


Gas prices are up nearly 50 cents a gallon in the last year.   That may be fueling an increased interest in electric cars.

Michael Sperling took us for a spin in his new 2018 Mitsubishi Outlander. The SUV is his family's second electric vehicle. 

Reporter: "What excited you about electric?"

"The pure acceleration, that low-end torque," Sperling says. "It's just so smooth, so quiet and so fun to drive.

Michael pulled the plug on gas powered cars five years ago. He's part of a growing demand for electric.

According to a new AAA study, that interest is up 15 percent from last year.

"We found that one in five Americans are interested in an electric vehicle for their next purchase," says Greg Brannon, AAA's director of automotive engineering.

Brannon says the top reasons drivers give are: a concern for the environment (80%) and lower long term costs (67%). The cars don't need oil changes and have fewer moving parts so there's less to fix.

Even though electric and hybrid sales are on the rise they still make up just 3 percent of overall U.S sales. 

Brannon believes that number will only increase as more options become available and gas prices increase.

"As we look to the future, the future is electric."

Cars like the Nissan Leaf can get up to 150 miles on a single charge.

Michael's larger SUV only goes about 25 miles per charge. But is equipped with a gas-powered backup generator for longer trips.  

"I've only been to the gas station twice."

When asked how much money he's saved, Sperling says "I don't keep track, but I can tell you I don't know what the price of gas is."

And if electric is the future, Michael is happy to be along for the ride. 

The number of charging stations is also on the rise. AAA says there are more than 16,000 across the U.S

Monday, May 7, 2018

Conoco Moves to Take Over Venezuelan PDVSA's Caribbean Assets

c9a7b8_conocophillips-avanza-para-tomar-activos-de-pdvsa_w800.jpg

U.S. oil firm ConocoPhillips has moved to take Caribbean assets of Venezuela’s state-run PDVSA to enforce a $2 billion arbitration award over a decade-oil nationalization of its projects in the South American country, according to three sources familiar with its actions.

The U.S. firm targeted facilities on the islands of Curacao, Bonaire and St. Eustatius that accounted for about a quarter of Venezuela’s oil exports last year. The three play key roles in processing, storing and blending PDVSA’s oil for export.

The company received court attachments freezing assets at least two of the facilities, and could move to sell them, one of the sources said.

Conoco’s legal maneuvers could further impair PDVSA’s declining oil revenue and the country’s convulsing economy. Venezuela is almost completely dependent on oil exports, which have fallen by a third since its peak and its refineries ran at just 31 percent of capacity in the first quarter.

The Latin American country is in the grip of a deep recession with severe shortages of medicine and food as well as a growing exodus of its people.

PDVSA and the Venezuelan foreign ministry did not respond on Sunday to requests for comment. Dutch authorities said they are assessing the situation on Bonaire.

Conoco’s claims against Venezuela and state-run PDVSA in international courts have totaled $33 billion, the largest by any company.

Any potential impacts on communities are the result of PDVSA’s illegal expropriation of our assets and its decision to ignore the judgment of the ICC tribunal,” Conoco said in an email to Reuters.

The U.S firm added it will work with the community and local authorities to address issues that may arise as a result of enforcement actions.

PDVSA has significant assets in the Caribbean. On Bonaire, it owns the 10-million-barrel BOPEC terminal which handles logistics and fuel shipments to customers, particularly in Asia. In Aruba, PDVSA and its unit Citgo lease a refinery and a storage terminal.

On the island of St. Eustatius, it rents storage tanks at the Statia terminal, owned by U.S. NuStar Energy, where over 4 million barrels of Venezuelan crude were retained by court order, according to one of the sources.

NuStar is aware of the order and “assessing our legal and commercial options,” said spokesman Chris Cho. The company does not expect the matter to change its earnings outlook, he said.

Conoco also sought to attach PDVSA inventories on Curacao, home of the 335,000-barrel-per-day Isla refinery and Bullenbay oil terminal. But the order could not immediately be enforced, according to two of the sources.

Last year, PDVSA’s shipments from Bonaire and St Eustatius terminals accounted for about 10 percent of its total exports, according to internal figures from the state-run company. The exports were mostly crude and fuel oil for Asian customers including ChinaOil, China’s Zhenhua Oil and India’s Reliance Industries.

From its largest Caribbean operations in Curacao, PDVSA shipped 14 percent of its exports last year, including products exported by its Isla refinery to Caribbean islands and crude from its Bullenbay terminal to buyers of Venezuelan crude all over the world.

PDVSA on Friday ordered its oil tankers sailing across the Caribbean to return to Venezuelan waters and await further instructions, according to a document viewed by Reuters. In the last year, several cargoes of Venezuelan crude have been retained or seized in recent years over unpaid freight fees and related debts.

This is terrible (for PDVSA),” said a source familiar with the court order of attachment. The state-run company “cannot comply with all the committed volume for exports” and the Conoco action imperils its ability to ship fuel oil to China or access inventories to be exported from Bonaire.

At the International Chamber of Commerce (ICC), Conoco had sought up to $22 billion from PDVSA for broken contracts and loss of future profits from two oil producing joint ventures, which were nationalized in 2007 under late Venezuela President Hugo Chavez. The U.S. firm left the country after it could not reach a deal to convert its projects into joint ventures controlled by PDVSA.
A separate arbitration case involving the loss of its Venezuelan assets is before a World Bank tribunal, the International Centre for the Settlement of Investment Disputes.

Exxon Mobil Corp also has brought two separate arbitration claims over the 2007 nationalization of its projects in Venezuela.

Friday, May 4, 2018

VLCC terminal to be built at Ingleside

Ingleside

http://www.tankeroperator.com/ViewNews.aspx?NewsID=9649

US Engineering, pipeline and terminal operator, Buckeye Partners has set up a joint venture with Phillips 66 Partners and Andeavor to build a VLCC loading terminal at Ingleside, Texas. 
 
The South Texas Gateway terminal is to be built on a 212-acre waterfront site located at the mouth of Corpus Christi Bay and will serve as the primary outlet for crude oil and condensate delivered by the planned Gray Oak pipeline from the Permian Basin.

This new terminal, to be constructed and operated by Buckeye. It will initially have 3.4 mill barrels of crude oil storage capacity and two deepwater vessel berths, capable of handling VLCCs.

Going forward, the storage capacity could be expanded to over 10 mill barrels, as well as adding multiple berths and other inbound pipeline connections, the company said.

Buckeye said that initially the terminal will be supported by long-term minimum volume throughput commitments from Phillips 66 and Andeavor. The complex is scheduled to commence operations by the end of 2019.

Buckeye will own a 50% interest in the joint venture, while Phillips 66 Partners and Andeavor will each own a 25% stake in the project.

“The South Texas Gateway Terminal will serve as a premier open-access deepwater marine terminal in the Port of Corpus Christi,” said Khalid Muslih, Executive Vice President of Buckeye and President of Buckeye’s Global Marine Terminals business unit.

“This project expands our presence in the important Corpus Christi market, which we believe offers strong competitive advantages for waterborne shipments of crude oil and other petroleum products from the fast-growing Permian and Eagle Ford shale plays.

“Recently announced improvements to our existing flagship Buckeye Texas Partners terminal, which sits along the ship channel in the Port of Corpus Christi, have expanded its leading marine terminaling capabilities,” he said.

Elsewhere in the US Gulf, the VLCC ‘Nave Quasar’ arrived last week at Enterprise Products Partners Texas City terminal to test the facilities for future VLCC loadings.

However, the water depth needs to be increased to about 76 ft from 45 ft to enable  large tankers to fully load - a problem which exists along the US Gulf Coast and US East Coast ports.

Thursday, May 3, 2018

West African crude grades struggle against US oil in NWE despite high diesel cracks

West Africa Map


Nigerian sweet crude oil grades have struggled to find homes in the European market despite the relative strength of diesel cracks in Europe, as competition among the Atlantic Basin sweet crude grades has heightened in the last two months, sources said.

Refiners in Northwest Europe have seen more offers of US crudes of late, which are sweet grades that compete directly with Nigerian crudes, contributing to an overhang of Nigerian crudes and a sharp drop in pricing differentials of these sweet crudes since the start of March.

However, there was some hope of support emerging for the more distillate- rich grades in the future if diesel crack spreads hold.


WAF CRUDES STRUGGLE TO FIND HOMES


Europe is one of the key consumer markets for Nigerian crudes, followed by India, and distillate-rich grades such as Qua Iboe, Forcados and Bonny Light have met with limited buying interest from the European refiners, slowing down the sale of cargoes loading over May and June, sources said.

 "Overhang is dragging into the next month. May have to clear first and then we look at June...Depends on how long [it takes for May to clear]," a trader focused on West Africa said.

For the June programs, eight out of the 10 Forcados cargoes were still available, and around six out of the eight Qua Iboe cargoes were also unsold, according to one trader's estimates.

The influx of competing US sweet crudes has been stoked by the widening ICE WTI-Brent spread, which has risen $2.28/b since the start of March to $5.31/b spread on Wednesday.

As a result, the relative strength in European diesel cracks has failed to drive a substantial appetite for the Nigerian distillate-rich grades given the rising competition among the Atlantic basin's sweet crudes, and have driven pricing differentials for Nigerian sweet crudes lower over the last two months.

Since the beginning of March, Nigeria's Forcados has fallen by 70 cents to an 85 cents/b premium to Dated Brent on Wednesday, and Qua Iboe's has fallen to a similar extent even with a shorter program for May due to planned maintenance over the first week of May.

The whole Nigerian market had been hit by weak demand, not just the distillate-rich grades, also affecting the sales of the light sweet offshore grades, Agbami and Akpo, sources said.

These offshore grades would typically be snapped up early in the trading cycle, with traders saying that June cargoes were mostly unsold.

"More than 60% of Agbami program still available...and Akpo, almost all of it," the trader said.


DISTILLATE-RICH CRUDES MORE SUPPORTED


However, if diesel cracks remain high, some traders say they expect some support for certain Nigerian crudes to emerge, and a divergence between the distillate-rich Nigerian and light-end rich grades.

Diesel cracks were last assessed by S&P Global Platts at $12.91/b on Wednesday, higher than gasoline cracks, which lagged behind at $10.06/b, which is unusual for this time of year.

Typically, moving into the northern hemisphere's summer season, gasoline cracks would widen and move above the diesel cracks as consumption of gasoline rises over the summer driving season in the US.

However, this year, the European diesel market has held its relative strength to gasoline given the lack of arbitrage flows of diesel to Europe, which have been diverted to Latin America instead.

"I see Forcados/Erha/Bonga...about 20 cents/b up...[Europe's] refineries coming back from maintenance and the more normal spreads of those grades vs Bonny/Qua re-establishing themselves after a slack period...this cycle [for June] feels stronger than the last," a trader said.

The exception among the distillate-rich crude oil grades was Qua Iboe, the trader added, saying: "Qua has suffered somewhat from reliability...dates constantly getting pushed back."

In the latest Qua Iboe program for June seen by S&P Global Platts, the last May cargo, that was originally scheduled to load over May 28-29 had been pushed into June to load over May 31-June 1.

--Ahila Karan, ahila.karan@spglobal.com
--Edited by Jonathan Dart, jonathan.dart@spglobal.com

Wednesday, May 2, 2018

Traveling by car this summer? Get ready for the most expensive driving season in years

RV lineup at gas pump Quartzsite Arizona


Get ready for a little bit more pain at the pump this summer.

Crude oil prices are at the highest level in more than three years and expected to climb higher, pushing up gasoline prices along the way.

The U.S. daily national average for regular gasoline is now $2.81 per gallon. That’s up from about $2.39 per gallon a year ago, according to Oil Price Information Service. And across the U.S., 13 percent of gas stations are charging $3 per gallon or more, AAA said last week.

“This will be the most expensive driving season since 2014,” said Tom Kloza, global head of energy analysis for Oil Price Information Service.

The price of U.S. crude oil has been on a mostly steady incline since last June and last week hit $68.64, the highest since December 2014. Benchmark U.S. crude closed Friday at $68.10. Oil prices near $70 shouldn’t put the brakes on economic growth, however. While they’re boosting costs for some sectors of the economy, the energy sector and related industries have more money to spend on equipment and workers.

But higher oil prices are certainly an inconvenience for drivers, especially those with lower incomes.
“The good news is, both at the global level and the U.S. level, this is occurring at a time when growth is fairly robust,” said Nariman Behravesh, chief economist at IHS Markit. “But consumers as whole will be hurt, mostly because gasoline prices are going up.”

Kevin Lanke, a motion picture lighting technician in Redondo Beach, California, says he’s now paying about $3.39 per gallon to fill up the 25-gallon tank in his 2000 Land Cruiser SUV. That’s about 20 cents more per gallon than a couple of months ago.

“I would fill up my car and it would be $52 or $53,” said Lanke, 51. “Now it’s in the mid $60s for the same amount of gas.”

Lanke keeps the recent increase in perspective, noting that three years ago he and his fellow Californians were paying over $4 per gallon. But he’s already weighing his options, saying if gas goes to $4 a gallon he’ll buy a more fuel-efficient car to use as his main ride and drive the Land Cruiser only when he needs it.

Several factors have helped drive oil prices higher. A wave of global economic growth has driven up demand for oil. At the same time, production cutbacks initiated by OPEC last year have helped whittle down oil supplies.

In the U.S., oil supplies were running 1.1 million barrels lower at the start of this summer’s driving season, which runs from April through September, than a year ago, according to the U.S. Energy Information Administration.

That has amplified the typical increase in gas prices seen this time of year. Pump prices normally rise as demand increases from families going on vacation and taking to the highways on road trips. Already, U.S. consumer demand for gasoline hit a record high for the month of April, according to the EIA.

Drivers in Western states such as California, Oregon, Washington, as well as Alaska, Hawaii, Connecticut and Pennsylvania, are paying the most at the pump. The average retail price in those states is running from $2.95 to $3.61 per gallon.
Average retail gasoline prices are lowest in a swath of mostly East Coast states, including Florida, New Hampshire, Delaware and Georgia. They’re ranging from $2.68 to $2.80 per gallon.

Still, prices remain well off from 2008, when crude oil prices jumped above $130 per barrel and average retail gas prices surged to an all-time high of $4.11 per gallon.

“People forget very, very quickly,” Kloza said, noting that the average U.S. gasoline price remains well below where they stood five years ago at $3.60 per gallon.

“We’re seeing a higher price environment… but I don’t think we’re goig to look at really apocalyptic numbers,” he said.

The EIA projects that the U.S. retail price for regular gasoline will average $2.74 per gallon this summer, up from an average of $2.41 per gallon a year earlier. Gas prices to rise each spring through Memorial Day and slowly decline as the summer goes along.

For all of 2018, the agency expects that the national retail price for all grades of gasoline will average $2.76 a gallon. That would translate into an additional $190 spent on fuel by the average U.S. household this year compared to last, the agency said.

“At the higher income levels, this won’t really have much of an effect,” said Behravesh. “But it’s a bigger deal for lower-income families, because a bigger share of their budgets goes to things like gasoline.”

In broader economic terms, the rise in oil and gasoline prices will help crude producers in states like Texas and North Dakota and will likely boost capital spending industrywide. Spending by oil companies fell sharply as oil plunged below $30 a barrel in 2016, dragging on U.S. economic growth.
Industries that rely heavily on fuel, such as shipping companies, airlines, vehicle fleet operators and other transportation companies, are seeing rising costs, which eventually will be passed on to consumers. Diesel fuel hit its highest national average price in more than three years over the weekend at about $3.06 per gallon. American Airlines said it spent $412 million more on fuel in the recent first quarter than in the year-ago period.

At current levels, U.S. crude oil prices won’t noticeably hamper the economy, said Behravesh.
“You would have to get up into the $90-$100 range for it to really have a big impact on growth,” he said. “At these levels, it may shave off a tenth of a percentage point off global growth.”

One reason oil likely won’t get to that level is the emergence of the U.S. as a major global oil producer. Higher prices encourage U.S. oil companies to crank up output.

“That rise in U.S. production and further rises in U.S. production will put a cap or a damper eventually on higher oil prices,” Behravesh said.

Tuesday, May 1, 2018

Near-term pipeline plans nearly double, future slows

Home

https://www.ogj.com/articles/print/volume-116/issue-2/special-report-worldwide-pipeline-construction/near-term-pipeline-plans-nearly-double-future-slows.html


Planned pipeline construction to be completed in 2018 nearly doubled from the previous year, with expected crude and natural gas project completions more than making up for smaller projected products pipeline numbers. Future planned mileage slipped slightly overall as completion of some of the gas and crude projects moved into the current year.

Operators plan to complete installation of 14,657 miles in 2018 alone (Table 1), with natural gas plans (11,936 miles) making up more than 81% of the total, based on data collected by Oil & Gas Journal. By contrast, crude and products pipelines made up nearly 60.5% of total planned construction as recently as 2013.

As 2017 began, operators had announced plans to build more than 33,600 miles of crude oil, product, and natural gas pipelines extending into the next decade, a roughly 2.6% decrease from data reported the prior year (OGJ, Feb. 6, 2017, p. 62). The softer plans for beyond 2018 moderated the slide that occurred over the past 2 years, as the energy market seems to have found its bottom for the time being. Sharp reductions in long-term gas pipeline plans in the Middle East erased gains in other regions.

As a whole, combining both current-year and forward estimates (Fig. 1), increases in planned construction in the US, Europe, Asia-Pacific, and Africa outweighed decreases elsewhere.

Outlook

EIA forecast world liquid fuels consumption to increase by 18.9% through 2040 (using a 2015 baseline), a period that encompasses the long-term pipeline construction projections described here. This rate of growth was down sharply from EIA's year-earlier forecast, which called for a 34.4% increase from a 2012 baseline.

Demand growth will be strongest, according to its September 2017 International Energy Outlook (IEO), among non-OECD countries, growing at a base-case 1.3%/year rate compared with a 3% decrease in the OECD over the same period. This growth will be led by Asia, with its non-OECD countries making up 80% of the total worldwide demand growth, as both China and India experience rapid industrial expansion and increased transportation demand.

Transportation consumption of liquid fuels in China will grow 36% by 2040, according to EIA. India's transportation-driven demand will more than double, with 142% growth expected.

EIA raised its total Asian liquid fuels demand slightly to 46.6 million b/d from the 46.4-millon b/d previously forecast, all growth coming from the non-OECD countries. Through 2050, OECD Asia demand growth is expected to remain flat as the already larger non-OECD demand in the region expands by 1.7%/year. EIA expects liquid fuels demand in Japan to fall 0.9%/year between 2015 and 2050.

Non-OECD Asia GDP growth slipped to 3.9%/year (from 4.2%) through 2050. India's growth, though still the world's fasteset, slows to 5.0%/year through 2040 from 5.5% in the previous IEO, and to 4.3% through 2050. China's GDP is expected to grow by 4.3%/year through 2040, considerably slower than the 9.6% growth rate over the past 10 years. EIA expects a 3.0% global growth rate through 2040, down from 3.3% last year. The agency expects 2.8%/year global GDP growth through 2050.

The EIA Annual Energy Outlook (AEO) 2017 forecast relatively flat US petroleum consumption through 2040, remaining below its 2005 peak as improved energy efficiency offsets growth in transportation and industrial activity. Consumption of petroleum and other liquids reaches a peak of 20.19 million b/d in 2019 (from a 2015 base of 19.55), dropping to 18.96 million b/d in 2033 before rising to 19.34 in 2040 and a new peak of 20.57 million b/d in 2050.
EIA projects US crude production leveling off between 10 and 11 million b/d through 2040, despite higher prices, as recent productivity gains plateau. Production first reaches 10 million b/d in 2021 and peaks at 10.55 million b/d in 2029.

The agency projects US dry natural gas production to continue growing at nearly 4%/year through 2020, reaching 30.79 tcf that year, with growth tapering off to an average rate of 1%/year through 2040 as export growth moderates and efficiency gains occur. EIA predicts 2040 production of 37.74 tcf.

OGJ tracks applications for gas pipeline construction to the US Federal Energy Regulatory Commission (FERC). Applications filed in the 12 months ending June 30, 2017 (the most recent 1-year period surveyed), totaled fewer miles despite the general upturn in plans.

• 529 miles of gas pipeline were proposed for land construction. For the earlier 12-month period ending June 30, 2016, more than 2,470 miles were proposed for land construction.

• FERC applications for new or additional compression horsepower at the end of June 2017 also fell sharply, totaling almost 600,000 hp from more than 2.2 million hp in June 2016.

Bases, costs

For 2018 only (Table 1), operators plan to complete roughly 14,560 miles of oil and gas pipelines worldwide at a cost of nearly $95 billion. For 2017 only, companies had planned roughly 7,750 miles at a cost of more than $59 billion.

For projects completed after 2018 (Table 2), companies plan to lay more than 33,650 miles of line and spend roughly $215 billion. When these companies looked beyond 2017 last year, they anticipated spending roughly $264 billion to lay more than 34,500 miles of line. Land construction costs fell in the meantime from $7.65 million/mile to $5.94 million/mile.

• Projections for 2018 pipeline mileage reflect only projects likely to be completed by yearend 2018, including construction in progress at the start of the year or set to begin during it.

• Projections for mileage after 2018 include construction that might begin in 2018 but be completed later. Also included are some long-term projects judged as probable, even if they will not break ground until after 2018.

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 (14,189 miles) for 2018 only will cost roughly $84 billion:

-$690 million for 4-10 in.
-$8.0 billion for 12-20 in.
-$16.7 billion for 22-30 in.
-$58.8 billion for 32 in. and larger.

• Total offshore construction (477 miles) for 2018 only will cost more than $10.5 billion:
-$286 million for 4-10 in.
-$3.3 billion for 12-20 in.
-$6.9 billion for 22-30 in.

• Total onshore construction (32,710 miles) for beyond 2017 will cost more than $194 billion:
-$15.6 billion for 12-20 in.
-$34.9 billion for 22-30 in.
-$144 billion for 32 in. and larger.
• Total offshore construction (943 miles) for beyond 2018 will cost nearly $21 billion:
-$6.4 billion for 12-20 in.
-$14.5 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.

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 pipeline would transport 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 send it on tankers to US and international markets.

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.

The US Department of Energy (DOE) in November 2014 granted the project, now called Alaska LNG and including the Alaska Gasline Development Corp. (AGDC), authority for exports to countries covered by free-trade agreements (FTA), approving exports to non-FTA destinations like Japan, China, India, and Taiwan in May 2015.

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.

Chinese and Alaskan officials signed a five-party, $43-billion joint development agreement for the Alaska LNG project in November 2017. China Petrochemical Corp. (Sinopec), CIC Capital Corp., and Bank of China agreed to work with AGDC and the state government on LNG marketing, financing, investment modeling, and establishing China content in Alaska LNG.

Large gas pipeline projects in Canada, centered on shipping material from shale plays in Alberta and British Columbia to the Pacific coast for liquefaction and export, faltered as a number of LNG projects were cancelled.

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 pipeline which would move gas to the Kitimat LNG terminal. 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). A final investment decision on the plant was still pending as of December 2017, the pipeline's fate likely hanging in the balance.

Spectra Energy Corp., meanwhile, lost the basis for its 42-in. OD, 525-mile Westcoast Connector gas pipeline from northeast British Columbia to Royal Dutch Shell PLC's planned LNG plant in Prince Rupert, BC, when the major cancelled the project. Shell's cancellation was followed by Petronas halting development of Pacific Northwest LNG and Nexen stopping plans for its Aurora LNG plant, both of which were also planned for the Prince Rupert area.

TransCanada's proposed Prince Rupert Gas Transmission (PRGT) project to provide gas to Pacific Northwest LNG, however, was proceeding as of January 2018 despite the liquefaction project's cancellation, the pipeline company evaluating other options for the system. The 470-mile, 48-in. OD PRGT is designed to deliver 2.1 bcfd from TransCanada's Nova Gas Transmission Ltd. Operations could begin as early as 2019.

Projects to move natural gas liquids to market, meanwhile, faced headwinds in the US. Kinder Morgan Energy Partners LP (KMEP) 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, 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 municipal opposition along its route might cause this to be delayed.

FERC ruled in September 2017 that KMEP could proceed with abandonment of its gas line, a necessary regulatory step in the conversion process. New legal challenges, however, were filed in response, with FERC allowing the project to proceed in the meantime.

Project Mariner, announced in 2010 by Sunoco Logistics Partners LP and MarkWest Energy Partners LP to move Marcellus shale NGLs to market, began operations on Mariner West (shipping 65,000 b/d of ethane to Sarnia, Ont.) in 2013. The 70,000 b/d Mariner East segment began propane operations in fourth-quarter 2014 and ethane operations in first-quarter 2016, moving the liquids to the US Atlantic Coast for shipment to Gulf Coast chemical producers and European markets. The combined projects included just 85 miles of new pipeline, using existing Sunoco infrastructure for the balance of each route.

The company in late 2014 announced it had received sufficient shipper interest to move ahead with its 275,000 b/d, 306-mile Mariner East 2 pipeline, largely paralleling the route of the first line. Mariner East 2 will use parallel 20-in. and 16-in. OD pipelines in the same right of way, the latter dubbed Mariner East 2X. Mariner East 2 will carry propane, ethane, and butane; 2X all three of these as well as C3+, natural gasoline, and condensate, or any combination of these products.

Sunoco expects to put the 20-in. line in service second-quarter 2018 and complete work on the 16-in. line by yearend 2018. but this might be delayed by community and legal challenges. Pennsylvania's Department of Environmental Protection (DEP) in January 2018 ordered Sunoco to stop construction until it meets requirements of a DEP order addressing impacts to private wells, construction authorization, and controls to minimize inadvertent releases.

Natural gas pipeline projects in the northeast US also continued to face delays caused by community opposition. EQT Midstream Partners' Mountain Valley Pipeline (303 miles, 42-in. OD, northwestern West Virginia to southern Virginia) is scheduled for a fourth-quarter 2018 startup but as of January 2018 still faced landowner suits regarding property access. National Fuel Gas Supply Corp.'s Northern Access Project (96.49 miles, 24-in. OD, McKean County, Pa., to Erie County, NY), announced more than 2 years ago, remains in limbo following an April 2017 denial by New York's Department of Environmental Conservation of its water quality permits. National Fuel has asked FERC to determine whether it can proceed without the permits.

Enbridge in June 2017 withdrew its FERC application to complete Access Northeast (97 miles, expansion of existing system in New York, Connecticut, and Massachusetts) following opposition. Dominion's Atlantic Coast (600 miles, 42-in. OD, West Virginia to North Carolina) pipeline's erosion and sediment control plan was denied by North Carolina's Division of Energy, Mineral, and Land Resources in January 2018.

The Permian basin has been the area of most rapid growth in US hydrocarbon production over the past year, reflected by an accompanying scramble to build new pipelines between Permian developments and both consuming centers and export destinations.

Kinder Morgan Texas Pipeline LLC (KMTP), DCP Midstream LP, and an affiliate of Targa Resources Corp. will build the Gulf Coast Express Pipeline Project (GCX). About 85% of the project's 1.92-bcfd capacity is subscribed and committed under long-term, binding transportation agreements. GCX's mainline portion consists of roughly 82 miles of 36-in. OD pipeline and 365 miles of 42-in. pipeline starting at the Waha Hub near Coyanosa, Tex., in the Permian basin and ending near Agua Dulce, Tex. GCX's Midland Lateral includes about 50 miles of 36-in. pipeline and associated compression, connecting with the GCX mainline. KMTP expects GCX to be in service in October 2019, pending the receipt of necessary regulatory approvals. Construction is expected to begin this quarter.

Sempra LNG & Midstream and Boardwalk Pipeline Partners LP are planning the Permian-Katy Pipeline project (P2K). The roughly 470-mile, 42-in. OD natural gas pipeline is proposed to transport up to 2 bcfd from the Waha Hub in the Permian basin to Katy, Tex., and on to the Houston Ship Channel. A phased-in startup could begin as early as December 2019.

Epic Y Grade Pipeline LP, a subsidiary of Epic Y Grade Services LP and Epic Midstream Holdings LP, has agreed with BP Energy Co., a subsidiary of BP PLC, for the latter to anchor a 650-mile NGL pipeline liking the Permian and Eagle Ford regions to Gulf Coast refiners, petrochemical companies, and export markets (Fig. 2).

Construction already has begun on the Epic NGL Pipeline, which will have throughput capacity of at least 220,000 b/d with multiple origin points in the Delaware and Midland basins. Destinations will include interconnects near Orla, Benedum, and Corpus Christi, Tex., where Epic's affiliate plans to build a complex with multiple 100,000-b/d fractionators. Epic plans to reach full capacity in 2019.

Enterprise Products Partners likewise plans to have its 250,000 b/d Shin Oak NGL pipeline in service by 2019, running 571 miles of 24-in. OD pipe from the Permian to the US Gulf Coast.

Tellurian Inc. plans to develop a natural gas pipeline network consisting of the previously announced Driftwood Pipeline (DWPL) and two other lines. DWPL, a 96-mile, 48-in. OD pipeline, is expected to be in-service mid-2021, delivering 4 bcfd from Gillis, La., to Driftwood LNG. DWPL is in permitting with FERC.

Tellurian's Permian Global Access Pipeline would be a 625-mile, 42-in. OD pipeline transporting 2 bcfd from the Waha Hub in Pecos County, Tex., and Permian and associated shale plays around Midland, Tex. to interconnects near Gillis, La. Proposed delivery systems include the Creole Trail Pipeline, Cameron Interstate Pipeline, Trunkline Gas Co., Texas Eastern, Transco, Tennessee Gas Pipeline, Florida Gas Transmission, and DWPL, among others.

The company's Haynesville Global Access Pipeline would cross 200 miles with 42-in. OD pipeline, transporting an additional 2 bcfd to the same interstate pipelines near Gillis. Both of these lines are expected to enter in service during 2022.

NAmerico Partners LP's proposed Pecos Trail pipeline would ship more than 1.85 bcfd through 468 miles of 42-in. OD pipe from the Permian basin to Corpus Christi by 2020.

Crude

Enbridge Inc.'s $7.5-billion Line 3 Replacement (L3R) Program, which the company describes as its largest project ever, faces continued delays. L3R will replace the majority of Enbridge's existing 34-in. OD Line 3 crude pipeline with new 36-in. OD pipeline on both sides of the Canada-US border, a total of 1,031 miles, doubling its capacity to 760,000 b/d. Enbridge will decommission the existing Line 3 once the new line is complete.

On the Canadian side of the border Enbridge will replace most of the existing Line 3 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 the company in December 2017 described its start date as uncertain and perhaps as late as November 2019, given mounting resistance inside the US.

Canada also 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 planned to begin construction in September 2017 and place the expansion into service in late 2019. In January 2018, however, the company said the project could be as much as a year behind schedule due to permitting delays, moving its projected in-service date to as late as December 2020.

The company in October 2017 cancelled its Energy East pipeline project. Energy East plans called for 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 would have consisted of TransCanada PipeLines Ltd.'s converted Canadian Mainline natural gas pipeline, with the other 1,500 km new-build miles.

TransCanada concluded on open season for its long-sought (originally planned to enter operations in 2012) 830,000-b/d Keystone XL pipeline in January 2018, securing about 500,000 b/d of firm, 20-year commitments and describing the results as sufficient for the project to proceed. It plans to begin primary construction in 2019, pending a final investment decision.

US President Donald Trump issued a presidential permit for the project in March 2017. The Nebraska Public Service Commission in November 2017 approved Keystone XL's route. But land owners have filed suit against the state, protesting the new route, and outstanding permits remain.

The delays and cancellations of pipelines designed to move Canadian oil to market affected both Canadian crude prices and inventories at Cushing, Okla., according to the EIA. The Jan. 18, 2018, edition of its 'This Week in Petroleum,' the agency reported prices of Western Canada Select as trading at their deepest discounts to West Texas Intermediate in nearly 3.5 years and noted that crude stocks in Cushing had declined by 22 million bbl (34%) since the beginning of November 2017 and were 17% below their 5-year average as Jan. 12, 2018.

Permian basin growth inspired a flurry of crude pipeline development in addition to the NGL projects. Buckeye Partners LP subsidiary South Texas Gateway Pipeline LLC launched a binding open season for a 600,000 b/d pipeline from the Permian basin and Gardendale, Tex., to Corpus Christi, Ingleside, and Houston, Tex.

Phillips 66 and Enbridge Inc. are holding an open season for the Gray Oak Pipeline, a 385,000-b/d system that will carry Permian basin production for export and to Texas refineries in Corpus Christi, Freeport, and Houston. Shippers will have the option to select from origination stations in Reeves, Loving, Winkler, and Crane counties in West Texas. The companies expect Gray Oak Pipeline to have an initial capacity of 385,000 b/d and will evaluate expansion of the system based on shipper interest during the open season. The pipeline system is expected to enter service second-half 2019.
Epic is planning a Permian-to-Corpus Christi crude oil pipeline, largely paralleling the path of its Y-grade project (Fig. 2). The 700-mile line would carry as much as 550,000 b/d.


Magellan Midstream in December 2017 proposed a 645-mile, 24-in. OD pipeline from Crane, Tex., to Three Rivers to Corpus Christi, moving both Permian and Eagle Ford crude to the coast. The 350,000 b/d line would include a 200-mile branch from Three Rivers to Houston and is planned to enter service in 2019.

Plains All American's Cactus II pipeline would run 515 miles of 24-in. OD pipe from Wink, Tex., to McCamey and then from McCamey to Ingleside-Corpus Christi, expanding the current Cactus system's capacity to 575,000 b/d from 390,000 b/d.

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. 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 transport systems 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, carrying 886 MMcfd, is already operating. Tula-Villa de Reyes will start in 2018, moving 550 MMcfd across 174 miles through 36-in. OD pipe. The 220-mile, 42-in. Villa de Reyes-Aguascalientes-Guadalajara line is also scheduled to enter service in 2018.

Refined products shipments from the US to Mexico have also grown. 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.

Pampa Energia subsidiary TGS plans to build a more than 700 mile transmission pipeline system in Argentina to move natural gas produced in the Vaca Meurta shale by companies including YPF SA, Tecpetrol, Dow Argentina, ExxonMobil Corp., Chevron, and Statoil. The 4-million cu m/year pipeline is expected to enter service in 2019.

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 prices and a take-or-pay clause. Gas will be delivered via the 2,465-mile Power of Siberia trunk line (Fig. 3). Work on the 56-in. OD line began 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 in 2018 with the full line operational the following year. The project stalled mid-2017 due to disputes regarding the gas contract, though Gazprom says it remains on schedule.

Turkmengaz is leading the consortium of national governments planning to build, own, and operate the 1,800-km Turkmenistan-Afghanistan-Pakistan-India (TAPI) natural gas pipeline, designed to carry 33 bcmy by 2022.

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 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

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.

India said its interest remained strong as of August 2017, with Afghanistan saying construction could begin as early as 2018.

GSPL India Gasnet Ltd. is building a 2,052-km natural gas pipeline between Mehsana and Bhatinda. 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). The pipeline 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. Pipelay was underway as of November 2017.

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 1,128 km 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 refineries both there and 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 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. (SSGC) network. An 81-km leg from Gwadar to the Iranian border could complete the pipeline once the larger line has entered service. Pakistan has been slow to build its section of the line due to lack of funding. 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. The 42-in. OD, 683-mile pipeline would carry 1.2 bcfd north from the coast starting in 2018. The Pakistani government in July 2017 asked SSGC to build the section between Nawabshah and Karachi.

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 agreed to participate in building the two strings. Intertek was awarded a project inspection and expediting contract in December 2016. In April 2017, Allseas was contracted for pipelay.

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 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 as South Stream, 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, which had reached Turkish waters as of November 2017.

Partners in the Shah Deniz consortium made a final investment decision (FID) in December 2013 on Stage 2 development of the Caspian Sea 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. Project 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.

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. Service, slowed by Italian protestors, is now expected to begin in 2020. 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, some 70 km offshore Baku in the Azerbaijan sector of the Caspian Sea, includes two new bridge-linked production platforms; 26 subsea wells to be drilled with 2 semisubmersible rigs; 500 km of subsea pipelines built at 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, will enter service in 2021. The 28-in. OD pipeline would include 310-357 km of pipe 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, using 56-in. OD pipe to move 1-million b/d, will cross 422 miles inside Iraq with the balance in Jordan. Jordan will keep 150,000 b/d for domestic refining. Iraq is pursuing the project to decrease its dependence on the Persian Gulf as an oil export route.

Iraq decided in August 2017 to cancel a parallel gas pipeline, citing high costs and associated delays. The pipeline was to have fueled the crude line's pumps, with alternative power sources now being sought.

Saipem in February 2016 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) pipeline projects, which combined, would cover a distance of 1,800 km (OGJ, Feb. 2, 2015, p. 72). Saipem did not disclose details regarding timelines or estimated values for projects under the MOUs. The MOUs followed 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 will 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. Iran began construction in March 2017.

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 deliver gas from the IGAT VII pipeline to Kuhe Mubarak. The two countries reached agreement on the project in February 2017. 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 Tanzania plan to build the 897-mile, 24-in. OD heated East Africa Crude Oil Pipeline (EACOP), bypassing Kenya as it transits between fields in Uganda and the Tanzanian port of Tanga. The pipeline, engineered by Gulf Interstate Engineering Co., would transport roughly 300,000 b/d to the Indian Ocean for export.

Total SA suggested this route as an alternative to mitigate security concerns regarding a previously considered Kenyan passage. China National Offshore Oil Corp. Ltd. and Tullow Oil are developing the project with Total. The line is expected to enter service in 2021.

Ethiopia and Djibouti plan to build a 700-km, 40-in. OD natural gas pipeline to transport Ogaden basin gas to a floating LNG liquefaction plant offshore Djibouti. China's Poly-GCL is developing the project with a scheduled 2020 startup date. The 3-million tonnes/year (mtpy) plant, fed by the 2-billion cu m/year pipeline, would be sited at Damerjog port near the Djibouti-Somalia border and expandable to 10 mtpy.

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. A construction contract was signed in April 2017.