Thu May 29, 2014 5:11am BST
By Timothy Gardner
WASHINGTON, May 29 (Reuters) - If U.S. lawmakers reverse a 40-year ban on oil exports it would add more than $1 trillion to government revenues through 2030, trim fuel prices, and add an average of more than 300,000 jobs a year, according to a report by an energy research group.
In one of the most optimistic assessments about unlocking U.S. crude exports, the IHS report said gasoline prices would fall some 8 cents a gallon because overturning the ban would pour crude onto oil markets and lower global fuel prices.
Government revenues from energy-related taxes and royalties would increase $1.3 trillion from 2016 to 2030. Jobs during that period, in both crude production and at oil field service companies, would rise an average of 340,000 a year and peak at an additional 964,000 in 2018, IHS said.
"This would be a significant economic stimulus that would be paid for by the private sector, not by the government - in fact the government would make a lot of money," Daniel Yergin, an energy historian and IHS vice chairman, said in an interview.
Only Congress can fully reverse the restraint on exporting crude. Congress put the ban in place after price shocks from the 1973 Arab oil embargo led to the notion that the United States was running out of oil.
But supply worries have evaporated in recent years as directional drilling and hydraulic fracturing, or fracking, have sparked an oil boom that promises to make the United States the world's biggest crude producer, ahead of both Saudi Arabia and Russia.
Some energy policy analysts say environmentalists, who have been galvanized by the Keystone XL oil sands pipeline project, could be a wild card in the move to free up U.S. crude exports, which would bring higher domestic oil output.
Yergin said opening up U.S. exports would not hurt the global environment because it would not add to the amount of oil produced around the world. It would simply shut in exports from countries in the Middle East and other regions, he said.
This year no major legislation has surfaced to overturn the ban and few expect lawmakers to introduce any measures before the Nov. 4 midterm elections. Backers of any reversal would have to placate lawmakers from Northeastern states, where refineries are profiting by processing new bounties of crude from North Dakota's Bakken region.
But Russia's annexation of Crimea, as well as the potential economic benefits to federal and state governments, have begun to grab the attention of U.S. lawmakers, Yergin said.
"The crisis in Ukraine has tilted the politics in a way that has caused a pivot," Yergin said. "It's realized now that the ability to export oil is an additional dimension to America's role in the world. It enhances our position and influence."
In the midst of Russia's confrontation with Ukraine - and the potential it has for cutting supplies of natural gas and crude to Europe - many U.S. lawmakers have been calling for quick approvals of more U.S. energy exports.
The report, paid for by energy companies including ExxonMobil Corp, Chevron and ConocoPhillips , can be seen here: www.ihs.com/crudeoilexport
(Reporting by Timothy Gardner; Editing by Tom Hogue)
HOUSTON, May 28
05/28/2014
By OGJ editors
In 2013, Mexico was the third-largest source of crude oil imports to the US, averaging 850,000 b/d, behind Canada and Saudi Arabia, according to the US Energy Information Administration. However, the volumes were the lowest since 1993, reflecting declining production of crude oil in Mexico. Meantime, US crude oil imports from Mexico have dropped by 47% in the last decade.
By contrast, US petroleum products exports to Mexico have increased 152% over the past 10 years. Last year, the US exported 527,000 b/d of petroleum products to Mexico, most of which was motor gasoline (46% of the total), distillate fuel oil (22%), and liquefied petroleum gases (10%).
“While the US is a net exporter of petroleum products to Mexico, the United States also imports some petroleum products from Mexico,” EIA said, adding that, as with crude oil, US imports of petroleum products from Mexico have declined in recent years.
In 2013, the US imported 68,000 b/d of products from Mexico, including residual fuel oil (41%), pentanes plus (24%), and naphtha (15%).
US commercial crude stocks rose 3.49 million barrels to 383.88 million barrels for the reporting week ended May 23, American Petroleum Institute data showed Wednesday. Analysts surveyed Tuesday had been looking for a 1 million-barrel build. The larger-than-expected build comes amid a rebound in imports, which surged 1.46 million b/d to 8.24 million b/d.
The bulk of this surge came in the US Gulf Coast, where imports rose 1.13 million b/d. This was enough to offset a 80,000 b/d increase in crude runs at USGC refineries, which rose to 8.36 million b/d. The combined higher imports and crude runs helped USGC crude stocks to soar 4.26 million barrels last week.
Total US crude runs rose 126,000 b/d to 15.997 million b/d; however, run rates held steady at 90.3% of capacity amid comparatively flat total refinery inputs, which include feedstocks other than crude. Analysts had been expecting a 0.6 percentage-point increase in US refinery utilization.
Crude stocks at Cushing, Oklahoma — delivery point for the NYMEX crude futures contract — fell 1.51 million barrels to 21.71 million barrels, API data showed.
US gasoline stocks, meanwhile, fell 1.44 million barrels to 212.97 million barrels last week, outpacing analysts’ expectations of a 200,000-barrel draw.
Stocks on the US Atlantic Coast — home to the New York Harbor-delivered NYMEX RBOB contract — jumped 2.64 million barrels to 58.74 million barrels.
The draw was centered in the Midwest and USGC, where stocks fell 1.32 million barrels and 1.92 million barrels, respectively.
US distillate stocks rose 821,000 barrels to 116.82 million barrels. Distillate stocks had been expected to rise by 290,000 barrels. Stocks on the USGC rose 425,000 barrels to 39.16 million barrels. USGC ULSD stocks rose 71,000 barrels to 31.31 million barrels.
The API data was delayed one day due to the Memorial Day holiday Monday.
Fewer West African barrels have been fixed to the US Atlantic Coast in May as the price of delivered Bakken crude fell below the price of delivered Nigerian Bonny Light, an analysis of Platts data showed Wednesday.
Bakken railed from North Dakota has averaged $4.03/ barrel below Bonny Light shipped from Nigeria so far this month. That’s compared to an average of 8 cents/b over Bonny in April. The premium was especially steep in the first half of the month, reaching $2.52/b over delivered Bonny April 8. The relatively high Bakken price coincided with a jump in crude imports into the US Atlantic Coast in the second half of April and early May.
For the four weeks ending May 9, USAC crude imports averaged 793,000 b/d, up from an average of 619,000 b/d for the four weeks ending April 11, according to the US Energy Information Administration. For the week ending May 16, imports fell back to 464,000 b/d.
The EIA does not publish regional imports by country of origin. But Platts cFlow vessel tracking software shows an increase in vessels leaving West Africa in April bound for the USAC, and a decline so far in May.
Eight vessels carrying crude left West Africa in April, while only three have exited the region bound for the USAC so far this month.
Other US Atlantic Coast oil observations: RAIL/ TERMINALS — The Pennsylvania Eddystone terminal unloaded its first 92-car train of crude in early May. It currently serves one customer with one 120-car unit train daily carrying about 85,000 b/d of crude.
There are plans to create a Philly Light crude benchmark out of Bakken and similar light sweet grades passing through the terminal. Storage at the facility will be increased to more than 1 million barrels and dock improvements are planned to increase marine traffic from one barge daily and add the capability to handle larger vessels from overseas.
Currently, articulated tug barges of up to 150,000 barrels are the largest vessels that can be handled.
Egyptian General Petroleum Corp. has increased the official selling prices for most of its crude grades loading May by $0.06-0.60/barrel compared with April, the company said Wednesday.
But EGPC left the OSP for its West Desert crude by unchanged at Dated Brent minus $0.90/b. The OSPs for Gulf of Suez, Ras al Behar and Zeit Bay were raised $0.60/b each to Dated Brent minus $3.95/b, minus $3.85/b and minus $3.85/b, while the OSPs for Ras Budran and as Gharib rose $0.15/b to Dated Brent minus $9.15/b and minus $9.20/b respectively.
The company also raised the OSP for Belayim by $0.06/b to Dated Brent minus $9.30/b.
Washington - May 28, 2014
The U.S. Energy Information Administration (EIA) on Thursday is expected to report a natural gas storage injection between 107 billion cubic feet (Bcf) and 111 Bcf for the week ended May 23, according to a Platts survey of analysts.
A number within that range would be higher than both the 88-Bcf build reported a year ago and the 93-Bcf five-year average, according to EIA data.
Beyond the consensus, the wider range of analysts’ expectations for Thursday’s report spanned from injections of 100 Bcf to 115 Bcf.
As of last week, stocks stood at 1.266 trillion cubic feet (Tcf), a 37.9% deficit the year-ago level and a 42.7% deficit to the five-year average of 2.209 Tcf. As a result, analysts continue to raise concerns about the market’s ability to refill storage adequately this summer.
"We keep hearing about record production, but we're also seeing record demand," said Phil Flynn, senior market analyst at Price Futures Group. "And we're also hearing more about tightness in pipeline capacity."
Producers "may want to produce a lot, but they can't get the pipeline capacity. The issues are still being worked out on capacity, and it's not going to be resolved this summer," Flynn said. "So in the longer-term scenario, it might not be as easy as some think to get production where it needs to be."
Analysts also noted that despite the expectation of a triple-digit injection in Thursday’s report, the forecast for next week is lower. "The bears in the market are looking for a biblical proportion kind of injection, but I'm not sure we have enough pipeline capacity to allow that to happen," said Tom Saal, broker at INTL FCStone.
To schedule an interview with a Platts or Bentek Energy natural gas expert about this survey or about supply/demand or policy developments in natural gas, contact Kathleen Tanzy at kathleen_tanzy@platts.com or 212-904-2860.
This analyst survey is conducted by the Platts editorial team in Washington, D.C., and is published every Wednesday morning, one day ahead of the 10:30 a.m. (ET) Thursday release of the weekly natural gas storage report of the U.S. Energy Information Administration. Platts has been conducting this survey since January 2007. The survey includes 15 to 25 analysts, some on a rotational basis.
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London (Platts)--28May2014/538 am EDT/938 GMT
Loading volumes for Republic of Congo's two main crude oil grades -- Djeno and N'Kossa -- are set to rise in July to a total of 7.42 million barrels from 6.47 million barrels in June, according to copies of preliminary loading schedules seen by Platts Wednesday.
The average daily loading rate will rise to 239,355 b/d in July from 215,667 b/d in June.
Djeno, the country's flagship grade, is set to load six 920,000-barrel cargoes in July, the same as for June.
N'Kossa loadings are scheduled to double, with two 950,000-barrel cargoes to be exported in July compared with only one 950,000-barrel export in June.
Djeno, a heavy medium-sweet crude grade with an API gravity of 28.1, is suitable for direct burning in power generation, according to the website of Total, which operates the Djeno terminal.
Djeno is a very popular grade among Chinese refiners, especially Unipec and Sinochem.
N'Kossa, a light sweet grade also loaded by Total from the Djeno terminal, has a gravity of 39.93 API and a sulfur content of 0.06%, according to the company.
The program for the country's third main grade, Azurite, has not been released, sources said.
--Eklavya Gupte, eklavya.gupte@platts.com
--Edited by Jonathan Fox, jonathan.fox@platts.com
Similar stories appear in Crude Oil Marketwire See more information at http://www.platts.com/Products/crudeoilmarketwir
Washington (Platts)--28May2014/300 pm EDT/1900 GMT
Despite pressure from US Senate Democrats and some of the world's largest oil and natural gas companies to unveil a financial disclosure rule quickly, the US Securities and Exchange Commission is not expected to propose the rule until 2015.
In an agenda for upcoming rulemakings released late Friday, the SEC said it is now aiming to propose the rule by March, a timeline that shows the rule has become a low priority for regulators, sources said.
The SEC's proposed agenda includes 42 rulemakings, a particularly busy schedule that also includes several other rules, such as crowdfunding, investor protection and money market rules it plans to work on ahead of the long-awaited financial disclosure rule.
"The US law was passed four years ago and an implementing rule is long overdue," said Brendan O'Donnell, the head of the oil team at Global Witness, a leading advocate for the rule.
An SEC spokeswoman did not respond to a request for comment.
The rule was mandated by the 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act and requires oil and gas companies listed on SEC-regulated exchanges to publicly disclose payments, including taxes, licenses and royalties, made to foreign governments.
O'Donnell said that it was "vital" for the SEC's rule to be equivalent to disclosure standards currently in place in the EU, a path on which some oil majors have pressed the Obama administration.
A previous disclosure rule finalized by the SEC was vacated by the US District Court for the District of Columbia, which claimed that Dodd-Frank did not require these payments to be publicly disclosed and questioned the agency's decision to prohibit any exemptions from the rule.
In recent letters to the SEC, Chevron, ExxonMobil and Royal Dutch Shell have all asked the SEC to quickly unveil a new proposed rule.
But some of these companies, backed by the American Petroleum Institute, have argued against a stringent rule pushed by transparency advocates and argued that full disclosures could reveal commercially sensitive information and confidential exploration and production plans.
Late last year, API proposed a plan to the SEC that calls for an automated filing system in which company identities would never be revealed publicly, and would exempt disclosure for projects in countries with non-disclosure laws.
API claims at least four countries -- Angola, Cameroon, China and Qatar -- have laws prohibiting such disclosures, a point disputed by transparency advocates.
--Brian Scheid, brian.scheid@platts.com --Edited by Annie Siebert, ann.siebert@platts.com
London (Platts)--28May2014/906 am EDT/1306 GMT
Ultra low sulfur diesel swaps in the Mediterranean have reached their lowest levels in over five years, as material from the US floods the market, with the influx of barrels expected to continue over the coming month, trade sources said Wednesday.
The front-month 10 ppm Med cargo swap was assessed by Platts Tuesday at a premium of $12.75/mt to the benchmark ICE gasoil futures contract, its lowest level since Platts began assessing the contract in January 2009, with a trade for June at $12/mt seen during Wednesday's morning trading. At least 500,000 mt of ULSD from the US Gulf coast has been delivered into the Mediterranean this month, with France's Fos-sur-mer and Italian ports absorbing the bulk of the barrels, according to Platts data and trading sources. Another 140,000 mt is en route to discharge by the end of the month, sources added.
--Alex Pearce, alex.pearce@platts.com
--Charles Goldner, charles.goldner@platts.com
--Robert Friend, robert.friend@platts.com
--Edited by James Leech, james.leech@platts.com
Similar stories appear in European Marketscan See more information at http://www.platts.com/Products/europeanmarketscan
London (Platts)--28May2014/903 am EDT/1303 GMT
Crude production in Libya is facing further setbacks this week, as loadings out of the 110,000 b/d Marsa al-Hariga crude terminal in Eastern Libya have stuttered to a halt.
Traders and shipping sources said that no there have been no recent vessel loadings at the terminal, recently the only one of the country's seven land-based terminals regularly exporting crude.
"Nothing's moving from Hariga at the moment," said a shipbroker. "The port is open but there doesn't seem to be oil flowing."
The Marsa al-Hariga terminal resumed operations in April after more than eight months of strikes and protests disrupted both export loadings at the terminal and production at the Mesla and Sarir crude fields which feed it.
However, traders said that the further deterioration of the security situation across Libya has carried in to Hariga, where guards have once again stepped in to prevent oil from leaving.
"The guards are preventing loading, so the tanks have topped out," a crude trader said. "The have been reducing production...[Tuesday] it was about 30-40,000 b/d, and it could stop [entirely.]" In recent weeks, there have been reports of a couple of fixtures from Hariga, but there still appears to be difficulties with loadings. The Alexia Aframax tanker was due to lift a 90,000-mt cargo for Total last week, but according to Platts' ship-tracking tool software cFlow, the vessel remains moored at Hariga.
A source at the ship manager confirmed the oil has not yet been loaded on to the vessel.
According to a report by a Mediterranean shipping company seen by Platts, the ports of Bouri, Jurf, Tripoli, Marsa el Brega, Marsa al Hariga and Zueitina are open. The ports of Mellitah and Zawiyah are open but crude oil is suspended, while the ports of Es Sider and Ras Lanuf are closed due to a strike.
Exports briefly resumed at the 70,000 b/d Zueitina terminal on the Gulf of Sidra in early-May, but soon halted after production failed to restart that the crude fields feed into the port, leaving Marsa al-Hariga as the only land-based terminal regularly exporting crude from the country.
"There are a lot of ships fixing and failing, we're not seeing many physical loadings take place," said a charterer active in the Mediterranean.
"The Libyans are trying to show the world that they can export but I think they need the oil internally to supply the Zawiyah terminal. There simply does not seem to be much oil coming out," said the charterer.
--Paula VanLaningham, paula.vanlaningham@platts.com
--John Morley, john.morley@platts.com
--Edited by Jonathan Dart, jonathan.dart@platts.com
Similar stories appear in Oilgram News See more information at http://www.platts.com/Products/oilgramnews
Washington (Platts)--28May2014/341 pm EDT/1941 GMT
US net natural gas imports fell 14% last year to 1,311 Bcf, the lowest level since 1989, as US production likely set a new record, the Energy Information Administration said Wednesday.
The agency said total imports in 2013 fell 8% to 2,883 Bcf from the 2012 level. Pipeline imports, almost all from Canada, declined 6% year on year to 2,786 Bcf, while LNG imports dropped 45% to 97 Bcf.
The agency attributed the drop in imports to increased domestic production. Based on preliminary data for 2013, EIA said domestic dry natural gas production rose 1% to 24,282 Bcf, a new record.
Total exports, which increased in all but two years from 1997 to 2012, decreased 3% to 1,572 Bcf in 2013. Pipeline exports decreased 1% to 1,569 Bcf, while LNG exports, already lower than 2% of total exports, decreased to 3 Bcf. For the first time, the US exported a small amount of CNG to Canada by truck, totaling 0.1 Bcf.
--Jeff Barber, jeff.barber@platts.com
--Edited by Jason Lindquist, jason.lindquist@platts.com
Cape Town (Platts)--28May2014/1214 pm EDT/1614 GMT
The Angola LNG plant is expected to resume production in mid-2015 after a rupture on a pipeline forced it to shut down, a spokesman for Angola LNG said Wednesday.
"Following investigation into the incident that took place at the plant in Soyo on April 10, 2014 Angola LNG will pull forward a planned shutdown to allow its contractor Bechtel to both correct items from the incident and -- in parallel -- address plant capacity issues," the spokesman said.
It is expected that this work will continue into next year, with the $10- billion project anticipated to restart in mid-2015.
The plant has yet to reach its nameplate capacity of 5.2 million mt/year since coming online in June 2013 due to technical issues. A planned maintenance shutdown for the plant has been repeatedly delayed due to a series of gas leaks on an onshore pipeline.
Shareholders in Angola LNG are Sonangol (22.8%), Chevron (36.4%), BP (13.6%), Eni (13.6%), and Total (13.6%).
--Jacinta Moran, jacinta.moran@platts.com
--Edited by Jonathan Dart, jonathan.dart@platts.com
By Grant Smith and Nayla Razzouk May 29, 2014 2:56 AM GMT+0700
Production forecasts for 2014 are getting less optimistic. The Oil Ministry’s official target is 4 million barrels a day by the end of the year. More likely it will be 3.75 million, Thamir Ghadhban, an adviser to the prime minister, said in an interview May 14. Or perhaps 3.4 million, about the same as last month, according to the average of six analyst estimates compiled by Bloomberg News.
Violence and conflict are pinching growth for OPEC’s second-biggest member. While Iraq added about 2 million barrels to daily production since 2003, the year of Saddam Hussein’s ouster, attacks on pipelines and an oil-revenue dispute with the semi-autonomous Kurdish region are diminishing the country’s dependability as a supplier. They’re also contributing to making oil more expensive, VTB Capital said.
“Iraq always seems to be the producer of the future,” Mike Wittner, head of oil market research at Societe Generale SA in New York, said by phone May 13. “The entire world has been upbeat on Iraq’s prospects for the last couple of years. But it’s not steady growth. They have to get the security situation sorted out, or that’s going to continue to hamper them.”
Iraq’s exports to Europe have been curbed since early March because of sabotage on its northern pipeline to Turkey. New supplies from the Kurdish region are mostly halted because of the dispute with the central government. Prime Minister Nouri al-Maliki may need to form a broad coalition to remain in power after last month’s parliamentary elections, potentially slowing oil-policy decisions.
Global Benchmark
Brent crude, a global benchmark, is trading above $100 a barrel for a 23rd consecutive month, the longest stretch in data starting in 1988. Prices will average more than $100 this year and in each of the next three years, according to analyst estimates compiled by Bloomberg. It ended today’s session at $109.81 a barrel.
Iraq’s production contracted 7 percent since reaching a 35-year peak of 3.6 million barrels a day in February, according to the International Energy Agency. The Basrah Oil Terminal in southern Iraq is scheduled to load 2.5 million barrels a day of crude for export this month and 2.7 million in June, according to loading programs obtained by Bloomberg News.
Shipments from the south, the only region exporting regularly, will probably stall at about 2.5 million barrels a day, unless work on storage tanks, pumping stations and other infrastructure is completed, the Paris-based IEA said in a report May 15.
“There are still lots of uncertainties regarding deliveries,” B.K. Namdeo, refineries director at Hindustan Petroleum Corp., said in Mumbai on May 13. “If the situation continues or worsens, we may have to cut Iraqi oil imports next year and switch to countries like Iran.”
Overtaking Iran
Iraq overtook Iran in 2012 to become the second-largest producer in the Organization of Petroleum Exporting Countries. It would need to produce about another 6 million barrels a day to top Saudi Arabia.
Iraq is seeking to overcome the constraints on exports, Ghadhban, the prime minister’s adviser, said in an interview in Dubai. That includes adding a third mooring point at the southern Basra oil terminal by July, which will increase capacity by 900,000 barrels daily, he said. Companies have been shortlisted to build a pipeline to Jordan’s Aqaba port, the government said in April. Another link crossing Iraq from north to south is under construction, providing an alternative route for crude from northern fields.
Iraqi crude is still sought after because the country is offering 60-day credit terms, compared with the 30 days typically available from Middle Eastern suppliers, according to Namdeo of Hindustan Petroleum. (HPCL) The refiner is increasing purchases by 8 percent this year to 3.25 million metric tons.
Huge Potential
More than 1 million barrels from Iraq’s Kurdish region were shipped from Turkey to Europe last week, according to Turkish Energy Minister Taner Yildiz and Kurdish authorities. Iraq’s government, which says the Kurds have no right to sell oil independently, tried to stop the shipment and asked the International Chamber of Commerce to intervene.
“Iraq has a huge amount of potential, and yes, there will be delays, but they will deliver,” Amrita Sen, chief oil market strategist at Energy Aspects Ltd. in London, said by e-mail on May 6. The consultant forecasts production of 3.3 million barrels a day this year, rising to 3.65 million in 2015.
Oil Exports
Even with the extra loading facilities at Basra, a lack of pumping capacity and onshore storage tanks will keep production growth in check, Miswin Mahesh, an analyst at Barclays Plc in London, wrote in a report April 30. Iraq can boost exports from West Qurna-2 or another of the fields being developed only by scaling back flows elsewhere, he wrote.
Some Asian refiners have complained about the presence of too much water in some cargoes from Iraq, the result of inadequate oil-treatment facilities, according to Mahesh. High sulfur content in the main Basrah Light grade has also been an issue, R.K. Mehra, head of international trade at Bharat Petroleum Corp., an Indian refiner, said in Abu Dhabi on May 7.
“We don’t see significantly more export capacity” this year, Alexander Poegl, an analyst at JBC Energy GmbH in Vienna, said by phone on May 13. “The volumes we’ve seen earlier in the year are kind of the maximum we would expect to happen. It’s a healthy development in Iraq, but we don’t see the big numbers others might sometimes suggest.”
To contact the reporters on this story: Grant Smith in London at gsmith52@bloomberg.net; Nayla Razzouk in Dubai at nrazzouk2@bloomberg.net
To contact the editors responsible for this story: Alaric Nightingale at anightingal1@bloomberg.net James Herron
By Zain Shauk May 29, 2014 1:54 AM GMT+0700
Exxon Mobil Corp. (XOM), which this month extended its partnership with Russia’s OAO Rosneft (ROSN), hasn’t had to change its business in the country amid Ukraine-related sanctions and said such steps are typically ineffective.
“We don’t find them to be effective unless they are very well implemented,” Chief Executive Officer Rex Tillerson said today during a shareholders meeting in Dallas. Authorities imposing the sanctions should consider “who are they really harming?”
Exxon is among American oil producers that ignored U.S. State Department recommendations to skip an energy forum in St. Petersburg last week as it extended a pact with Rosneft involving drilling for crude in the Arctic and Siberia. Exxon, through a 2011 deal with the state-run crude producer, owns drilling rights across 11.4 million acres of Russian land, including vast swaths of the Kara Sea.
U.S. and European nations have imposed sanctions to punish Vladimir Putin’s regime for its actions in Ukraine. Among those targeted was Rosneft Chief Executive Officer Igor Sechin. Measures from President Barack Obama’s administration included asset freezes and bans on travel to the U.S.
Travel Ban
The travel ban on Sechin has so far not affected collaboration with Exxon, which is currently working with Rosneft to drill an exploratory well in the Arctic this year, Tillerson said. The companies’ partnership gives Rosneft the ability to buy stakes in Exxon’s North American projects in exchange for Exxon’s access to the Russian Arctic.
“We have plenty of meetings with them in Russia,” Tillerson said. “It’s not impacted our ability to carry on the other business activities.”
The Irving, Texas-based producer is the biggest U.S. player in Russia, where it has a series of joint ventures with Rosneft.
To contact the reporter on this story: Zain Shauk in Houston at zshauk@bloomberg.net
To contact the editors responsible for this story: Susan Warren at susanwarren@bloomberg.net; Tina Davis at tinadavis@bloomberg.net Carlos Caminada, Steven Frank
By Christine Harvey May 29, 2014 2:26 AM GMT+0700
Gasoline futures gained in New York after the nation’s third-largest refinery shut a crude unit amid damage from a severe storm and power outage.
Marathon Petroleum Corp. (MPC)’s Garyville, Louisiana, plant may keep a crude unit shut while carrying out repairs to a cooling tower, the company said in an e-mail today. A second crude unit continues to operate. The time frame for work hasn’t been set.
“From the sound of these reports, the refinery is unlikely to be able to restart the crude unit for at least two months,” said Robert Campbell, New-York based head of oil products research for Energy Aspects Ltd.
June-delivery gasoline rose 1.07 cents to settle at $3.0059 a gallon on the New York Mercantile Exchange. Volume was 29 percent above the 100-day average at 3:06 p.m. The more actively traded July contract advanced 0.74 cent to $2.9881.
Gasoline’s crack spread relative to West Texas Intermediate crude widened $1.70 to $22.78 a barrel. The premium to European benchmark Brent rose 52 cents to $15.69.
Marathon exported about 223,000 barrels a day of petroleum products in the first quarter, 50,000 of them gasoline and the rest diesel, according to an earnings call on May 1. The company operates in Garyville and Texas’s Galveston Bay on the U.S. Gulf Coast, an export hub and home to half of the nation’s total refining capacity.
A tornado may have hit the Garyville plant, according to Shawn O’Neil, a meteorologist for the National Weather Service in Slidell, La.
Diesel Prices
“This tornado hitting Garyville is serious and has changed the market in a very big way,” said Tom Finlon, director of Energy Analytics Group Ltd. in Jupiter, Florida.
Ultra low sulfur diesel for June delivery slid 0.93 cent, or 0.3 percent, to end at $2.9306 a gallon. Volume was 16 percent above the 100-day average.
The fuel’s crack spread relative to WTI widened $1.01 to $20.36 a barrel. The premium to Brent shrank by 17 cents to $13.27.
The average U.S. pump price declined 0.3 cent to $3.654 a gallon, according to Heathrow, Florida-based AAA.
To contact the reporter on this story: Christine Harvey in New York at charvey32@bloomberg.net
To contact the editors responsible for this story: Dan Stets at dstets@bloomberg.net Charlotte Porter, Bill Banker
By Mark Drajem May 28, 2014 11:07 PM GMT+0700
445 Comments Email Print
The nation’s biggest business lobby says President Barack Obama’s plan to tackle climate change could cost the U.S. economy $50 billion a year. Supporters predict it will create jobs and lower power bills.
The U.S. Chamber of Commerce and Natural Resources Defense Council are both releasing economic impact studies this week, signaling that the political battle over the president’s plan will be fought over dollars and cents. For Obama, the risk is the plan gets labeled a job-killer just as campaigns heat up for an election that could determine control of the U.S. Senate.
In an analysis released today -- days before the Environmental Protection Agency unveils a proposal to cut carbon dioxide emissions from power plants -- the Chamber said that an ambitious pollution-control effort could force more than a third of the coal-fired power capacity to close by 2030, resulting in economic losses of $50 billion a year and the elimination of 224,000 jobs.
“This raises serious questions that need to be answered,” Karen Harbert, president of the Chamber’s Institute for 21st Century Energy, said in an interview. “Utilities will be faced with some very unappealing choices.”
State Flexibility
While the Chamber isn’t taking a position on the proposal before its release, the dire economic warnings in its analysis shows that that lobbying powerhouse is unlikely to back off opposition to the Obama administration’s efforts to fight climate change. Environmental groups such as the NRDC say that the EPA’s pledge to give states wide leeway will limit the costs, which could be offset by lower electric bills for consumers as utilities become more efficient.
The administration is focusing on an approach that would let states set up their own systems to achieve mandated cuts, including linking into existing cap-and-trade networks, or expanding the use of renewable energy, according to people familiar with the plan.
And the EPA, which said any details about the rule are speculation at this point, says the economic risks of not dealing with the threat of climate change are real as well.
“The cost of inaction on climate is the real drain on our economy,” Liz Purchia, an EPA spokeswoman, said in an e-mail. “In 2012, we saw the second-costliest year in U.S. history for natural disasters. Even the strongest sectors can’t escape the pressures of a changing climate, so it is time for us to lead.”
Health Costs
NRDC is set to release a report tomorrow showing that the rules could create hundreds of thousands of jobs and cut health-care costs and power bills.
“The costs are certainly quite modest,” said Starla Yeh, an NRDC fellow who helped develop and analyze its proposal. With efficiency programs, “the savings in fuel and maintenance you forgo balances out the costs.”
In fact, while the Chamber study predicts electricity costs will increase, especially in the coal-heavy states of the Midwest and South, the NRDC says efficiency gains will mean a drop in wholesale electricity prices, which has led some utilities to complain about “demand destruction,” Yeh said.
Obama has pledged to use his regulatory might to cut U.S. greenhouse gases about 17 percent by 2020 over 2005 levels, with deeper cuts to follow. Groups such as Resources for the Future say achieving those reductions requires the EPA to order cuts deeper than 17 percent in power-plant emissions. Power plants are the top source of carbon-dioxide, and the rules aimed at electricity generators could be followed by similar efforts for refineries, steelmakers and cement plants.
Future Targets
The Chamber hired the independent research firm IHS Energy to analyze a plan produced by the NRDC that people familiar with the deliberations say was considered by the Obama administration in developing its approach. The NRDC proposal, released in late 2012, calls for using a broad approach to achieve cuts of as much as 30 percent in emissions by 2020 compared with 2005. For its analysis, the Chamber extended those cuts out for another decade, to achieve reductions of 40 percent by 2030.
Under those assumptions, coal’s share of the generating mix would fall to 14 percent from about 40 percent now, while 114 gigawatts of coal-fired generating plants would shutter, it said. The compliance costs over that period would be $28 billion a year, with $17 billion of that passed on to consumers as higher electricity costs, the study said.
Dueling Forecasts
Those higher rates are “an issue of competitiveness with the rest of the world.” Harbert said.
The Chamber’s analysis differs from that of NRDC because it forecasts a steady increase in demand for electricity and predicts that the energy efficiency savings that NRDC forecasts aren’t possible.
And the costs come on top of the billions of dollars utilities are now spending to comply with the EPA’s mercury rule, which phases in by 2016. To be sure, a $50 billion cost represents 0.31 percent of the overall U.S. gross domestic product, and critics say business groups have a long history of overstating their predictions of what EPA rules will cost.
“Critics have tried for years to convince people that more pollution equals more jobs and a better economy, but history has proved them wrong over and over again,” EPA’s Purchia said. “Climate action sharpens America’s competitive edge and spurs innovation.”
Exelon, Entergy
And not all of what it counts as costs are universal negatives for companies. Nuclear-reliant power producers such as Exelon Corp. (EXC) and Entergy Corp. (ETR) say the EPA rules could help their struggling plants get a leg up in the competitive power markets.
Under the Chamber’s analysis, use of natural gas would increase to 46 percent of total generation by 2030 from about 27 percent now, which could be a boon for gas producers such as Exxon Mobil Corp. (XOM), and power generators with gas plants.
Also this week, companies such as OPOWER Inc. (OPWR), which helps consumers monitor and cut electricity bills, will showcase ways their technology could prosper under the EPA rules.
“We see EPA’s carbon rules as a huge opportunity to modernize our grid, and that will help the economy overall,” said Malcolm Woolf, the senior vice president for government affairs at Advanced Energy Economy, a business group that represents lower-carbon power suppliers and efficiency companies. “We see this as a real opportunity.”
To contact the reporter on this story: Mark Drajem in Washington at mdrajem@bloomberg.net
To contact the editors responsible for this story: Jon Morgan at jmorgan97@bloomberg.net Steve Geimann
By Ilya Gridneff May 28, 2014 10:47 PM GMT+0700
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(Corrects to remove reference in 12th paragraph to gum-arabic shipments in story published on May 23.)
As the former head of U.S. security company Blackwater USA, Erik Prince thrived in war zones like Iraq and Afghanistan. South Sudan, the world’s newest nation where violence erupted in December, is proving a little tougher.
Prohibitive costs, transport difficulties, political instability and growing insecurity have rendered the former U.S. Navy Seal’s plan to build an oil refinery in the north of the country unfeasible for the time being, said Sean Rump, a partner at Prince’s Frontier Resource Group. Talks this month with financiers failed to revive the project that was set to be completed by December, he said in an interview on May 18.
“We believe in the future of South Sudan,” Rump said. “If we thought it was going to be a failed state, we wouldn’t be here. But when will the trouble end and the refinery be built? We just don’t know.”
Fighting broke out in South Sudan after President Salva Kiir accused his former deputy, Riek Machar, of trying to stage a coup. At least 10,000 people have been killed and a million people are estimated to have fled their homes in the ensuing conflict, while oil production that funds 98 percent of the government’s budget has been cut by a third.
An attempt at a truce in January and another earlier this month failed to gain traction, with government and rebel forces accusing either side of violating the agreements. Parts of the country may be at risk of a famine because of a lack of funds and logistical hurdles to providing humanitarian relief, according to the United Nations humanitarian agency.
Diesel Refinery
Frontier, a private-equity firm based in Abu Dhabi, has a 12-year agreement with the South Sudanese government to build, own and then transfer to the state a 10,000–50,000 barrel per day refinery that will supply diesel to the domestic market. The landlocked nation currently imports all of its refined fuel.
“Producing 10,000 barrels per day of diesel for the domestic market is going to loosen up a lot of capital for South Sudan investment,” Rump said. “Their economy relies on importing diesel so this project will have an impact.”
The refinery is part of 44-year-old Prince’s new role as chairman of Hong-Kong listed Frontier Services Group Ltd. (500), a logistics and transport company that’s investing in Africa using cash injections from Asian investors including Citic Group, China’s largest state-owned conglomerate.
Frontier Resources has already spent $10 million on the project in partnership with Africana General Trading Ltd., a closely held South Sudanese company, and hired Pasadena, Texas-based Vintech Engineering International Ltd. to build the facility at Thiangrial, near the border with Sudan.
Viable Project
Africana Managing Director Obac William Olawo, one of South Sudan’s richest men and an economic adviser to Kiir, said he’s confident the refinery will be viable once the war ends.
Prince is “still committed to the investments, but let us get the conflict resolved,” Olawo said. “Once it is resolved we as partners are ready.”
Olawo, who runs South Sudan’s Toyota Motor Corp. (7203) dealership, said Africana has a 25 percent stake in the project. President Kiir personally supports the plan, he said.
Frontier Resource plans to focus on “pan-African logistics, aviation services and risk management,” according to its 2013 annual report. The company wants to tap Chinese funding to the continent that is expected to total $1 trillion over the next 12 years, it said.
Mobile Assets
In April, Frontier agreed to buy 49 percent of Phoenix Aviation in Kenya for $14 million. That followed the purchase of Kijipwa Aviation, based in the Kenyan port city of Mombasa, in November.
“Our business model is centered on aviation capabilities, which support logistics operations and security for fixed and mobile assets,” Prince said in the annual report.
Prince ran Blackwater from 1997 to 2010, when the company earned an estimated $1 billion in U.S. government contracts. The company, which has since been renamed Academi, faced a U.S. congressional committee hearing into an incident in September 2007, when the company’s guards killed 17 civilians in a firefight in Iraq’s capital, Baghdad. Blackwater denied any wrongdoing.
Prince didn’t respond to e-mailed requests sent by Bloomberg via Rump for an interview. Rump said Frontier has no connection to Blackwater.
“Prince sold his stake in 2010, there is no on-going relationship,” he said. “We’re investors, we do logistics and operate in tough conditions.”
(An earlier version of this story corrected the name of Africana General Trading Ltd. in the ninth paragraph.)
To contact the reporter on this story: Ilya Gridneff in Nairobi at igridneff@bloomberg.net
To contact the editors responsible for this story: Antony Sguazzin at asguazzin@bloomberg.net Paul Richardson, Karl Maier
By Mading Ngor May 28, 2014 11:32 PM GMT+0700
South Sudan borrowed $200 million from oil operators and postponed repayments on domestic loans after the country’s six-month-old conflict cut crude output, the government’s main source of revenue, Finance Minister Aggrey Tisa Sabuni said.
Loss of about a third of revenue led the government to seek advances from oil producers in South Sudan over the past five months, Sabuni said today in an interview in the capital, Juba. The government also asked to delay payments due on loans to commercial banks and shelved plans to improve the country’s infrastructure, he said.
The loans “helped to bridge the gap” and will be repaid “in the course of time,” Sabuni said, without naming the oil companies responsible. South Sudan’s government is living “hand to mouth” with crude revenue being used to pay salaries and maintain public services, he said.
Oil output in the world’s newest nation has fallen by at least a third to about 160,000 barrels per day since fighting erupted on Dec. 15 between factions loyal to President Salva Kiir and his former deputy, Riek Machar. The conflict has left thousands of people dead and forced more than a million to flee their homes, according to the United Nations.
The country’s “heavy dependence” on oil revenue is “a very highly risky situation to be in, but that’s the reality,” Sabuni said. Production at oil fields in Unity state remains frozen after a shutdown in late December, while output from Upper Nile, the only state still pumping crude, is down by as much as 35 percent since the conflict began, he said.
South Sudan’s crude is mainly pumped by China National Petroleum Corp., Malaysia’s Petroliam Nasional Bhd. and India’s Oil & Natural Gas Corp. (ONGC) The companies evacuated some staff from the country due to the conflict.
South Sudan has to “restore law and order” and stop the fighting to “create the required investment climate in order to move forward,” Sabuni said. “At the moment we’re still in the forest.”
To contact the reporter on this story: Mading Ngor in Juba at mngor@bloomberg.net
To contact the editors responsible for this story: Paul Richardson at pmrichardson@bloomberg.net Michael Gunn, Karl Maier
By Elena Mazneva May 29, 2014 3:14 AM GMT+0700
Russia and Ukraine remain at loggerheads over natural gas deliveries after a possible compromise put forward by the European Union to help avoid supply disruptions as soon as next month failed to win support.
Russia is ready to discuss price changes and also may withdraw a demand for advance payments once Ukraine starts paying for deliveries, officials in Moscow said yesterday. The government in Kiev is prepared to pay up once Russia lowers prices.
“We are ready to pay the market price for gas, but never the political one,” Ukrainian Prime Minister Arseniy Yatsenyuk said yesterday in Berlin.
Ukraine should pay down its debt before further talks are held, Russian President Vladimir Putin said in Moscow. “This situation cannot continue forever. This is simply not possible and everyone understands this,” he said.
Under the EU plan, announced on May 26 after trilateral talks in Berlin, Ukraine would pay $2 billion of its gas debt by May 30 and $500 million more by June 7. If OAO Gazprom gets the first tranche, Russia’s gas exporter will agree to continue supplies without prepayment and start price negotiations, according to the EU proposal.
Ukraine’s gas debt will have climbed to $5.2 billion by the June 7 deadline for May supplies, Alexey Miller, head of state-controlled Gazprom, said at a meeting with Putin yesterday.
Russia is also seeking about $1.7 billion in advance payments for June shipments. That’s due by June 2, and starting from the following day, Ukraine will only get what it pays for, Gazprom said earlier this month.
Past Disruptions
Ukraine carries about half of Russia’s EU-bound gas across its territory, or about 15 percent of Europe’s demand for the fuel, making it a linchpin in energy security. Gas price and debt disputes between Russia and Ukraine disrupted Europe’s deliveries during freezing weather in 2006 and 2009.
The governments of the former Soviet allies had a deadline set by the EU of midnight yesterday to accept the agreement.
“Russia and Ukraine are still far from a compromise given the recent statements,” said Ekaterina Rodina, an oil and gas analyst at VTB Bank in Moscow.
Russia is ready to discuss canceling the prepayment requirement and price changes once Ukraine resumes payments, Russia’s Energy Ministry said late yesterday in an e-mailed statement. The Ukrainian Energy Ministry’s press service didn’t return phone calls seeking comment.
“The European Commission is in contact with the parties involved with the aim to ensure that the trilateral talks will continue on Friday,” Sabine Berger, a spokeswoman for the Commission, said by e-mail.
Compromise Offer
“I hope that we won’t reach a situation where we have to move to prepayments,” Putin said yesterday in the Kremlin after Energy Minister Alexander Novak laid out the EU proposal. The debt plan “was proposed by the EU and Russia jointly as a compromise,” Novak said.
Ukraine has refused to pay any of its debt since Russia raised gas prices 81 percent in April after withdrawing discounts in place since 2010 and 2013.
The country will start paying only after Russia agrees to a temporary price of $268.50 per 1,000 cubic meters, the same as it charged for the fuel in the first quarter, Ukrainian Energy Minister Yuri Prodan said after Putin’s statement, according to Interfax.
Yatsenyuk cited yesterday a price range of $250 to $350 per 1,000 cubic meters for supplies.
Ukraine has been boosting gas imports from Russia since April 17, the day Putin first encouraged Gazprom to demand advance payments for fuel deliveries in a month unless its neighbor resumed payments.
Gas imports in May increased fivefold from year-earlier levels as Ukraine built up stocks in underground storage before the looming cutoff, according to data compiled by Bloomberg.
To contact the reporter on this story: Elena Mazneva in Moscow at emazneva@bloomberg.net
To contact the editors responsible for this story: Torrey Clark at tclark8@bloomberg.net Stephen Cunningham, Carlos Caminada
on May 29, 2014 / in News 12:06 am / Comments
BY EMMA UNA
Calabar—THE Chief of Naval Staff, Vice Admiral Jibrin Usman, yesterday, said his men had destroyed illegal refineries and boats in its fight against oil bunkering in the Niger Delta.
He said the Navy had in the past few months destroyed over 509 illegal oil refineries, 406 wooden boats and 10,086 auxiliary equipment used in pipeline vandalism and oil bunkering.
Usman, at the 2014 Navy Week Conference in Calabar, Cross River State, said that the destruction was carried out between January and April 2014, adding that, over 492 suspects were arrested and handed over to relevant agencies for prosecution.
He said: “The reduction in sea robbery and piracy on Nigeria waters is attributed to improved patrol by the Nigerian Navy and re-deployment of other assets to the identified flash and maritime choke points.”
According to him, between January and April 2014, about 602 oil tankers legally loaded with 61,584,599 metric tons of crude oil, left Nigeria’s maritime domain without any untoward incident.
“The Nigerian Navy under my leadership will continue to partner relevant agencies in the maritime sector, and in the areas of capacity building, and information and intelligence sharing. This will promote the well-being of the nation’s economic base.
“We shall continue to review our strategy and prioritise capacity building for maritime policing operations with a view to boosting efforts at curbing crude oil theft,” he said.
By Nick Cunningham | Wed, 28 May 2014 21:54 | 0
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The U.S. shale industry may be a lot less healthy than many people think. A new analysis from Bloomberg News found a startlingly high level of debt in the shale industry, with companies borrowing more and more money as revenues disappoint.
According to the report, debt among shale oil and gas companies has nearly doubled over the last four years. While drillers often need to borrow in order to expand, revenues have not kept pace, growing at a mere 5.6 percent over the same time period.
The problem is that many shale oil and gas wells offer an initial burst of production over the first year or two. After that, output drops precipitously, and if companies have not paid down debt, they may have much more difficulty in later years than they may have anticipated. They fall into a downward spiral in which a greater share of their revenue must go to paying down debt.
Bloomberg concluded that out of the 61 companies surveyed, around a dozen are spending more than 10 percent of their revenues on debt interest.
What’s the significance of so many shale drillers struggling to turn a profit? It means that the zeal with which investors poured money into so many shale companies may be at an end. The industry is due for a shakeout.
The companies in the worst shape – those that are highly leveraged without a growing production portfolio – could be heading towards bankruptcy. As the weakest links drop out, the industry will consolidate and leave only the strongest and healthiest producers.
A shakeout is normal in any industry when the hyper-growth phase begins to slow. But unlike in the tech industry, for example, the shale industry’s economic fortunes have ramifications far beyond individual companies, their employees and investors.
If drillers begin to go belly up, oil and natural gas production growth could slow or come to a halt. The Energy Information Administration projects in its latest Annual Energy Outlook that U.S. natural gas production will grow at a steady rate of 1.6 percent per year through 2040. That would mean that over the next 25 to 30 years, natural gas production would expand by an astonishing 55 percent.
But that may be wildly optimistic given the fact that so many companies are struggling to be profitable right now in the shale patch. Or put another way, production may not be sustainable at current price levels, and would have to rise in order for growth to continue.
Either way, a lower growth trajectory or higher prices would seriously alter the expectations about the U.S. energy picture. For example, if natural gas prices need to significantly rise in order to maintain growth, the opportunity to export significant volumes of liquefied natural gas (LNG) overseas may be smaller as well. That’s because U.S. companies would not be able to arbitrage American gas as easily by liquefying it and selling it at a higher price to hungry consumers in East Asia.
As a result, the companies investing money into building LNG export terminals that costs billions could begin to look a bit inflated.
A shale shakeout would also reverberate through the electric power sector since plateauing shale gas production would be a boon for renewable energy. Natural gas was expected to gobble up an ever-increasing share of electricity generation because prices were expected to remain stable even as production rose. But if those expectations turn out to be wrong, that leaves a lot of space for other forms of generation. And with coal and nuclear power becoming increasingly uncompetitive in 21st century America, that leaves an enormous opportunity for renewable energy.
As for oil, lower production from shale would also mean that the U.S. would continue to rely on imported oil instead of domestic production. While that does not mean much on its own, the fact that the oil industry can no longer offer trite promises of “energy independence” means that Congress may have to face up to the fact that the U.S. needs to find alternatives to oil for the long-term.
The shale revolution has been an opiate for many of the U.S.’s energy problems for several years now, but that could begin to change if the industry begins to falter.
Crude is flowing again at a rate of 200,000 b/d through Colombia’s Cano Limon Pipeline, two months after it was shut due to terror attacks and a native community’s refusal to permit repair crews on its reservation, an official at state-controlled Ecopetrol said Monday.
The source said pumping resumed Sunday over the 500-mile-line that stretches from Occidental Petroleum’s Cano Limon oil field in the eastern Arauca province to the Covenas oil depot on the Caribbean.
Although Occidental built the line in the 1980s with a maximum capacity of 220,000 b/d, the average throughput from Arauca at the time it was closed in March was about 72,000 b/d, the US company has said.
At the time of the closure, an additional 110,000 b/d was being fed into the line via the Bicentennial Pipeline, which was inaugurated last October and joins the Cano Limon at Banadia.
Crude from the Bicentennial line occupies the unused capacity that has developed as the Cano Limon field has been depleted. Cano Limon has been bombed at least 20 times so far this year, a reflection of the deterioration of oil field security in recent months, according to Bogota-based security consultant Orlando Hernandez.
Ecopetrol, which operates the pipeline through its wholly owned Cenit subsidiary, shut the line and declared a force majeure on some deliveries after the U’wa indigenous community refused to allow crews to repair the line on its lands in the North Santander province, pending government agreement to certain conditions.
Occidental subsequently closed several wells in Arauca and declared a force majeure on crude loadings. On May 2, the indigenous community and Ecopetrol announced they had reached an agreement to repair the line, but it took three weeks for crews to fix the various ruptures caused by the bombings, which are believed to have been carried out by the FARC leftist rebel group.
At the time of the agreement with the U’wa, Ecopetrol officials told news media that Colombia at that point had lost oil sales totaling 2.5 million barrels because of the pipeline’s shutdown. The Colombian government and FARC leaders are currently negotiating a peace agreement in Havana that if successful, could bring an end to 50 years of civil conflict and, presumably, the hundreds of rebel bombings on oil pipelines and other infrastructure over the years.
The negotiations, however, are not complete, and their future was thrown into doubt by the first round of presidential elections Sunday, in which the top vote-getter was Oscar Ivan Zuluaga who has said he opposes a negotiated settlement “at any cost” with the rebels.
Zuluaga will face the first round’s second place finisher, incumbent President Juan Manuel Santos, in a June 15 run-off election.
Unipec declared its second July-loading Oman cargo to Chinaoil in the Platts Market on Close assessment process Tuesday. The convergence was triggered as Chinaoil bought its 120th July cash Dubai partial from Unipec at $106.80/barrel.
In addition to the convergence cargo declared Tuesday, there have been eight other convergences earlier in May, with Unipec having declared a cargo of Oman on Monday to Chinaoil. Unipec has also declared four cargoes of Upper Zakum to Chinaoil earlier in May.
Unipec on Thursday also declared a single cargo of Upper Zakum to Trafigura and a single cargo of Oman to Vitol, while Mercuria on Thursday declared a cargo of Upper Zakum to Chinaoil. There have been 221 cash Dubai partials traded in May, in addition to 17 July partials traded during April.
A total of 16 convergence cargoes were declared during the Platts Market on Close process in April, consisting of a record 13 Upper Zakum cargoes and three Oman cargoes.
There were 14 convergence cargoes declared during the Platts Market on Close assessment process in March, comprising 11 Oman cargoes and three Upper Zakum shipments. There were 13 convergence cargoes in February, all Oman.
In March, there were 309 May cash Dubai partials traded and one Oman partial. Under the crude partials trading mechanism, two companies must trade a physical cargo when a total of 20 Dubai partials have been exchanged during the same month in the MOC process.
The seller has the option to declare delivery of Dubai, Oman or Upper Zakum crude upon convergence of the 20 partials. The buyer must accept the cargo nominated to it. In January, six March-loading Oman cargoes were declared, part of seven convergence cargoes traded during the month, including one Dubai.
There were 17 January-loading Oman convergence cargoes traded during the MOC in November, part of a record 24 convergence cargoes exchanged during the month. There were also six Upper Zakum cargoes declared, and one Dubai.
The UK’s Buzzard oil field contributed 49% to Forties crude blend output in the week to May 25, Forties pipeline operator BP said on its website Tuesday, compared to 43% the previous week.
This increases the sulfur content of Forties blend to 0.89% from approximately 0.83% previously, according to a BP conversion table, and raises its API to approximately 37.7.
For June, BP estimates Buzzard content within Forties Blend at 40.7%, rising to 44.2% in July
then dropping to 36.2% in August due to planned maintenance. The Buzzard field has a nameplate capacity of 220,000 b/d, but production averaged 156,591 b/d in 2012, according to UK Department of Energy and Climate Change data.
It is the UK’s single-largest oil field, and the largest feeding into the Forties blend, one of four grades forming the basis of the Dated Brent crude oil benchmark.
