By Mark Shenk Jul 1, 2014 3:10 AM GMT+0700
OPEC crude production climbed for a second month in June as gains in Saudi Arabia and Nigeria made up for the loss of Iraqi barrels, a Bloomberg survey showed.
Production by the 12-member Organization of Petroleum Exporting Countries rose by 278,000 barrels a day to 30.223 million, according to the survey of oil companies, producers and analysts. Last month’s total was revised 43,000 barrels a day lower to 29.945 million because of changes to the Kuwaiti, Libyan and Ecuadorian estimates.
Violence flared in Iraq, OPEC’s second-biggest producer, this month as a militant group seized Mosul, the country’s biggest northern city, and advanced south toward Baghdad. Fears that the upsurge may ignite a civil war sent prices higher.
“There was panic when the first headlines came from Iraq,” said Bob Yawger, director of the futures division at Mizuho Securities USA Inc. in New York. “There may have been an overreaction elsewhere. Things have stabilized and it doesn’t appear that all of those additional barrels will be needed.”
Brent crude for August settlement dropped 94 cents, or 0.8 percent, to close at $112.36 a barrel on the London-based ICE Futures Europe exchange. Brent, the benchmark for more than half the world’s oil, reached $115.71 on June 19, the highest level since Sept. 9. West Texas Intermediate oil fell 37 cents, or 0.4 percent, to settle at $105.37 on the New York Mercantile Exchange.
Iraqi Output
Iraqi production tumbled 400,000 barrels a day to 2.9 million this month, according to the survey. It was the biggest drop in June and left the country pumping the least oil since September.
The fighting hasn’t spread to southern Iraq, home to about three-quarters of the nation’s oil output.
The production cuts occurred in the north, where the pipeline from Kirkuk to Ceyhan on Turkey’s Mediterranean coast has been shut since March because of sabotage. The missing output would have supplied Iraqi needs. The 310,000-barrel-a-day Baiji refinery, Iraq’s biggest, has been closed since militants first attacked it on June 15.
“It looks like Iraq will continue to pump between 2.5 and 3 million barrels a day as long as the situation doesn’t get a lot uglier,” Yawger said. “The missing oil was mostly meant for domestic use anyway.”
Saudi Boost
Saudi Arabia, the group’s biggest producer, boosted output by 230,000 barrels a day to 9.9 million. That was the highest level since September, when the desert kingdom pumped 10 million barrels a day, the most in monthly data going back to 1989.
Fuel consumption in the Arabian peninsula peaks in the summer months, when high temperatures lead to increased use of air conditioners.
“They usually produce more in the summer to directly burn for electricity that’s needed for air conditioning,” said Mike Wittner, the head of oil market research at Societe Generale SA in New York. “I also expect them to keep increasing production to meet global demand.”
Saudi Arabia is pumping additional oil for storage to keep the market comfortable about supply. The country holds 2.6 million barrels a day of spare crude production capacity, according to data compiled by Bloomberg.
“We are going to see new records from the Saudis in the months ahead,” Wittner said. “They will have to pump at least 10.2 million barrels a day or more in the third quarter. They can easily attain this.”
Highest Output
Nigeria’s production rose 200,000 barrels a day to 2.15 million in June, the second-biggest gain in the survey. It was the highest output since September. Figures for Africa’s biggest producer are volatile because of unrest and theft in the Niger River delta, the main oil-producing region.
Crude production in the United Arab Emirates climbed by 100,000 barrels a day to 2.8 million this month, the most since October. Output climbed on higher exports to Asia to meet summer demand there.
OPEC ministers kept their output target unchanged at 30 million barrels a day on June 11 in Vienna. The group next meets on Nov. 27.
To contact the reporter on this story: Mark Shenk in New York at mshenk1@bloomberg.net
To contact the editors responsible for this story: David Marino at dmarino4@bloomberg.net Richard Stubbe, Bill Banker
By Peter Millard and Rodrigo Orihuela Jul 1, 2014 4:57 AM GMT+0700
Petroleo Brasileiro SA is the world’s largest producer in waters deeper than 1,000 feet.
Petroleo Brasileiro SA (PETR4), the biggest crude producer in ultra-deep waters, is offering more than $2 billion in drilling-service contracts, some under revised terms after suppliers complained about the original agreements, said two people with direct knowledge of the bidding process.
Petrobras, as the Rio de Janeiro-based company is known, is reissuing a drilling services contract after a reduction in the company’s rig fleet eroded suppliers’ margins, the people said, asking not to be identified because the process hasn’t been made public. The state-run producer is also offering wireline and well completion contracts, they said.
Halliburton Co. (HAL), Baker Hughes Inc. and Schlumberger Ltd. probably will participate, one of the people said. Petrobras’ press department in Rio didn’t respond to requests for comment made by telephone and e-mail. Halliburton, Baker Hughes and Schlumberger didn’t reply to e-mails and phone calls.
Shares of Halliburton gained 0.8 percent to $71.01 in New York, while Baker Hughes reversed losses and rose 0.7 percent to $74.45 and Schlumberger closed up 0.1 percent after falling as much as 0.7 percent. Petrobras rose 0.5 percent to 17.29 reais in Sao Paulo.
Petrobras pumps 90 percent of Brazil’s oil and gas, giving it leverage over service companies in the country. Petrobras’ contracts often allow for revisions even after they are awarded. Halliburton CEO David Lesar said Jan. 21 that all service companies in Brazil were “seeking relief” and that deep-water drilling activity was below expectations.
Containing Costs
Suppliers including Baker Hughes and Halliburton have cut staff in Brazil over the past year to adjust to lower-than-expected demand for services as Petrobras seeks to contain costs. The company trimmed its five-year business plan to $220.6 billion earlier this year.
Spending on new refineries has surpassed expectations and production has missed targets in recent years, curbing profits. Petrobras also subsidizes fuel imports, contributing to the largest cash-flow deficit and highest debt levels of any publicly traded oil producer.
To contact the reporters on this story: Peter Millard in Rio de Janeiro at pmillard1@bloomberg.net; Rodrigo Orihuela in Madrid at rorihuela@bloomberg.net
To contact the editors responsible for this story: James Attwood at jattwood3@bloomberg.net Carlos Caminada
By Nidaa Bakhsh Jul 1, 2014 12:13 AM GMT+0700
Scotland may have billions of barrels of shale oil buried under its most densely populated areas, geologists said today.
Scotland’s central belt, running between Glasgow and Edinburgh, may have 6 billion barrels of oil in place, according to a report by the British Geological Survey. While only a fraction of the resource will end up being viable, the deposits could supplement the U.K.’s 3 billion barrels of proven oil reserves, held mostly in North Sea fields off Scotland.
The oil and gas industry is central to the debate on Scotland’s independence ahead of a referendum in September. The Scottish government says existing fields in the North Sea will underpin the economy of an independent nation while opponents say declining production from offshore reserves leaves the region vulnerable.
Creating Europe's Newest Sovereign State
“This report will give reassurance to investors who wish to explore for oil and gas onshore in Scotland,” said Ken Cronin, chief executive officer of the U.K. Onshore Operators Group, an industry lobby. The resources “can help replace the U.K.’s growing dependency on imports and balance the decline of the North Sea.”
Bowland Shale
As well as oil, Scotland’s central belt has shale gas in place of 80.3 trillion cubic feet, according to the middle estimate in today’s report. That compares with 1,300 trillion cubic feet in the Bowland shale in northwest England, according to research published last year by the British Geological Survey, or BGS.
Though the figure is a fraction of the Bowland basin, it’s enough to prevent the region from becoming a gas importer in 7 to 8 years, according to an explorer with a license in Scotland’s central belt.
“80 tcf is a lot,” Graham Dean, director of Reach Coal Seam Ltd., said in an e-mail. “Even if only 10 percent is developed, there is more producible gas onshore than offshore Scotland,” where North Sea gas reserves amount to 4.3 trillion cubic feet.
Exploiting the U.K.’s shale resources has been opposed by environmental campaigners and property owners concerned that drilling techniques, including hydraulic fracturing, risk polluting water supplies. Britain’s greater population density will likely make production more difficult than in the U.S., where a shale boom has reversed declining oil and gas output.
Tax Breaks
“We are taking a balanced, evidence-based approach to the development of unconventional gas,” Fergus Ewing, Scotland’s energy minister, said in a statement. “No operator can undertake hydraulic fracturing unless they first gain explicit planning consent for that activity.”
The U.K. government is offering tax breaks to shale drillers to spur development of the resource as North Sea reserves dwindle. The Bowland basin may supply local natural gas demand for half a century at extraction rates of 10 percent, similar to U.S. fields, according to a 2013 report.
Last month, the BGS published a report on the prospects for shale oil in southern England, estimating the Weald basin may hold 2.2 billion to 8.6 billion barrels. The highest estimate in today’s report for Scotland was 11.2 billion barrels and the lowest 3.2 billion barrels.
“Only the broad shoulders of the U.K. can attract investment in new energy sources and maintain the U.K.’s position as one of the world’s great energy hubs,” U.K. Energy Minister Michael Fallon said.
To contact the reporter on this story: Nidaa Bakhsh in London at nbakhsh@bloomberg.net
To contact the editors responsible for this story: Will Kennedy at wkennedy3@bloomberg.net Randall Hackley
By Alaa Shahine Jun 30, 2014 11:18 PM GMT+0700
June 30 (Bloomberg) -- Georgetown professor Paul Sullivan explains what the declaration of a caliphate by the ISIL means in the fight for Iraq and how the rest of the Middle East may respond as Russia sends jets and aid to the nation to help combat militants. He speaks on “Bloomberg Surveillance.”
The al-Qaeda breakaway group fighting in Iraq and Syria declared an Islamic caliphate in areas under its control, an assertion of authority meant to consolidate power over a swath of territory that straddles the two nations.
The insurgent movement defined its state as stretching from Aleppo in northern Syria to the eastern Iraqi province of Diyala, according to an audio recording purportedly by its spokesman posted on websites and forums linked to radical Islamists. The group named its leader, Abu Bakr al-Baghdadi, as the head of state.
The announcement, which security and political analysts say is unlikely to sway the conflict in the group’s favor, comes after the militants seized Iraq’s biggest northern city this month, raising the specter of a sectarian civil war. The movement, which has changed its name to the Islamic State from the Islamic State in Iraq and the Levant, is also battling forces of Syrian President Bashar al-Assad as well as other rebels seeking to end his rule.
Yesterday’s declaration marks the third rebranding since 2006 of a group consisting of the “same people, same leader,” said Mustafa Alani, an analyst at the Geneva-based Gulf Research Center.
“Without declaring a political entity to support their control on the ground, it won’t have any meaning,” Alani said in a phone interview. “They want to say that the victory isn’t only about occupying the land, but it is about developing the occupation.”
Pledge Allegiance
Sunni Islamist militants usually invoke references to the caliphate to refer to times when Muslim empires ruled over territories across the Middle East, Europe and Asia. The last great caliphate was formally abolished in 1924 after the collapse of the Ottoman Empire.
In the decades leading up to that event, colonial powers, mainly Britain and France, had already occupied Arab lands such as Algeria and Egypt. They carved out Iraq and Syria as states during World War I.
Meet al-Qaeda's Heirs Fighting to Reshape the Arab World
Al-Baghdadi has lured Islamic fighters to the region with a call for holy war to abolish the colonial-era borders. His group, though, has sometimes been incapable of sustaining alliances. In April, 2013, it split from the al-Qaeda-affiliated Al-Nusra Front, part of a Sunni-dominated insurgency in Syria that has been trying to oust Assad for three years.
Violent Clashes
Violent clashes between the Islamic State fighters and Nusra units, backed by other Islamist gunmen, erupted last night in al-Bukamal, a Syrian town on the Iraqi border, the Britain-based Syrian Observatory for Human Rights said on its Facebook page. The Islamic State sent reinforcements to the area, the group said.
In the audio recording, the group declared the rule of any other movement as illegitimate and called on Muslims to pledge allegiance to the Iraqi-born al-Baghdadi. It said that it has appointed “emirs and courts” and imposed taxes in territories under its control.
The “announcement of a caliphate doesn’t change anything on the ground,” said Volker Perthes, head of the Berlin-based German Institute for International and Security Affairs, which advises Chancellor Angela Merkel’s government. “It’s real events on the ground that change things. It means that they think they’re strong enough to rule territory.”
Kikrit Killings
After capturing Mosul this month, the group imposed rules on residents of the northern Iraqi city that included a ban on smoking, drinking and drugs. Prayer times should be respected, it said. Women must stay indoors, or, if they have to go out, then respectable, baggy clothes must be worn. Thieves would have their hands amputated.
In a report last week, advocacy group Human Rights Watch said ISIL fighters had executed as many as 190 men in the contested city of Tikrit, saying the real figure may be higher. Other rights groups, including Amnesty International, have reported atrocities by both the militants and government forces since fighting erupted.
“They are killing people and planting flowers at the same time,” said Perthes of the insurgents. “Wherever they are in charge, they have to do it by terror and extortion.”
To contact the reporter on this story: Alaa Shahine in Dubai at asalha@bloomberg.net
To contact the editors responsible for this story: Alaa Shahine at asalha@bloomberg.net Mark Williams, Andrew Atkinson
By Nayla Razzouk Jun 30, 2014 8:29 PM GMT+0700
Kurdish crude oil is poised to gain acceptance after the semi-autonomous region delivered a cargo and received a payment, according to Deutsche Bank AG.
“We expect trading houses to become increasingly comfortable handling Kurdistan Region of Iraq crude and steady-state exports to emerge,” analysts led by Lucas Herrmann wrote in an e-mailed report dated today.
The Kurdistan Regional Government started to export crude to Turkey’s Mediterranean port of Ceyhan through its own pipeline last month, without approval from Iraq’s central government. Four tankers have so far loaded cargoes of Kurdish crude in Ceyhan, with one shipment sold, according to Turkish Energy Minister Taner Yildiz.
Turkey’s Turkiye Halk Bankasi AS, or Halkbank, received $93 million for a shipment, Yildiz said on June 23. The destination of the crude isn’t of interest to Turkey, the minister said.
“Despite regional conflict and the threat of legal action from Baghdad, significant milestones have been achieved,” Hermann said.
Iraq’s government has warned that it will prosecute any buyers of the Kurdish oil and sought arbitration at the International Chamber of Commerce. The Kurdistan Regional Government says it’s abiding by the Iraqi constitution.
The Kurdistan Regional Government controls 45 billion barrels of oil reserves, according to its estimates.
To contact the reporter on this story: Nayla Razzouk in Dubai at nrazzouk2@bloomberg.net
To contact the editors responsible for this story: Alaric Nightingale at anightingal1@bloomberg.net Rachel Graham, James Herron
Morgan Stanley Sees No Flood of U.S. Condensate on Export Ruling
By Ramsey Al-Rikabi Jun 30, 2014 6:15 PM GMT+0700
U.S. approval for exporting some of its ultra-light crude after minimal processing only broadens the definition of refined products and won’t mean a sudden jump in overseas shipments, according to Morgan Stanley.
While some producers are interested in exports, the ruling to allow Pioneer Natural Resources Ltd. and Enterprise Products Partners LP to ship condensates that have been run through a distillation tower won’t significantly increase U.S. shipments or limit supplies, Adam Longson, a New York-based analyst at the bank, said in an e-mailed report today.
Anadarko Petroleum Corp. (APC), Marathon Oil Corp. (MRO) and Devon Energy Corp. (DVN) also have access to similar technology and are looking at the opportunity, Longson said, citing discussions with the companies.
“Our conversations don’t suggest a significant amount of underutilized distillation capacity is available to drive up exports anywhere near some of the estimates we have seen in the press,” he said. “We are skeptical about reports of 500,000 to 1 million barrels a day of potential exports by year end.”
Shipments could be challenged by limited infrastructure, unattractive economics and uncertainty about the quality of processed condensates, Longson said.
Limited pipeline connections and port capacity may restrict volumes, and refining and exporting condensates may cost at least $4 to $5 a barrel, leaving domestic use as the best option, Longson said. Processing will affect the quality as propane, butane and other light hydrocarbons, which are “key” parts of traditional condensates, will be missing, he said in the report.
Distillation Tower
Crude that has been processed through a distillation tower to make petroleum products is no longer raw oil and can be exported without a license, Jim Hock, a U.S. Commerce Department spokesman, said June 24 in a written statement. The U.S. prohibits most exports of unprocessed crude.
A distillation tower is traditionally used to heat crude or condensate to remove fuels as they boil off at different temperatures. It can also be used for condensates to remove volatile hydrocarbons for safer storage and transport.
U.S crude production has boomed in recent years, spurred by horizontal drilling and hydraulic fracturing in shale fields. Output has risen 46 percent since the start of 2012 to almost 8.5 million barrels a day. Inventories reached 399.4 million barrels in April, the highest since the Energy Information Administration began publishing weekly data in 1982.
U.S. benchmark West Texas Intermediate crude has this year traded at an average discount of $8.11 a barrel to Brent in London, the international marker. Even with “large scale” exports from the U.S., WTI will still trade at a discount of $5 to $8 a barrel to Brent, Longson said.
To contact the reporter on this story: Ramsey Al-Rikabi in Tokyo at ralrikabi@bloomberg.net
To contact the editors responsible for this story: Pratish Narayanan at pnarayanan9@bloomberg.net Mike Anderson
By James Paton Jun 30, 2014 3:45 PM GMT+0700
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Puma Energy Holdings Pte acquired InterOil Corp. (IOC)’s oil refinery, service stations and fuel terminals in Papua New Guinea for $526 million, marking its first investment in the Pacific nation.
Singapore-based Puma Energy, whose largest shareholder is commodity trader Trafigura Beheer BV, is also seeking to expand in Indonesia and build new fuel terminals in Myanmar, Ray Taylor, its general manager for Australia and Papua New Guinea, said today in a phone interview.
“We’re in growth mode for sure, particularly in this region,” Taylor said. “We are open to new market entries and organic growth.”
The deal with InterOil will allow Puma Energy to tap Papua New Guinea’s growth and link the country’s fuel market to its global operations, according to a statement from the company. Puma became Australia’s biggest independent fuel retailer after acquisitions valued at more than $800 million last year and has said it plans to add storage and service-station networks.
InterOil said it will use the proceeds to fund its natural gas exploration business as it eyes a second export project in Papua New Guinea with partner Total SA of France.
The sale follows an unsolicited approach by Puma, InterOil said in a separate statement. The businesses include the Napa Napa refinery in Port Moresby that processes about 28,000 barrels a day, 52 service stations, and 30 fuel depots, terminals and aviation sites, according to its statement. The purchases will be funded by existing bank facilities and cash.
Puma wants to make further investment in the Papua New Guinea oil refinery and views it “as something in the portfolio for the long term,” Taylor said.
Puma Energy, formed in 1997 and active in about 45 countries, and Vitol Group, the world’s biggest independent oil trader, are seeking to develop fuel-storage facilities and retail businesses in neighboring Australia as companies such as Royal Dutch Shell Plc close refineries.
To contact the reporter on this story: James Paton in Sydney at jpaton4@bloomberg.net
To contact the editors responsible for this story: Jason Rogers at jrogers73@bloomberg.net Abhay Singh
Washington (Platts)--30Jun2014/616 pm EDT/2216 GMT
The near-term effects of a recent US decision granting two Eagle Ford players legal standing to export processed condensate will likely be severely limited, analysts said Monday.
Infrastructure constraints, high shipping costs and an expected increase in competition amongst foreign producers will likely mute the impact of the US Commerce Department's decision regarding US condensate exports.
"This latest ruling is not a panacea," said Morgan Stanley analyst Adam Longson in a report. "Taken at face value, the latest ruling has little direct impact on the current US crude balance, given the limited scope."
Last week, Commerce confirmed that both Enterprise Product Partners and Pioneer Natural Resources would be allowed to export crude condensate since it is processed through distillation towers and is considered a petroleum product not subject to the crude export restrictions in place for the past 40 years.
While initial estimates of US condensate exports climbed as high a 1 million b/d, Longson said these forecasts vastly overstated the significance of the decision, which was an interpretation of existing statute rather than a change in current law.
While the decision gives Enterprise and Pioneer legal certainty that their stabilization and distillation processes are enough to meet Commerce's threshold for crude to become a petroleum product, Longson said there are several hurdles ahead of a big ramp up in US condensate exports.
Infrastructure challenges, including limited refining capacity, pipeline interconnectivity and port capacity, remain, while the processing and export will cost at least $4-5/b, "which may leave blending and domestic sale as the best option, particularly as exports and prices rise."
Barclays analyst Michael Cohen estimated Eagle Ford condensate is priced between $108-109/b, compared to South Pars and Qatari condensate, which falls in the range of $109-113/b, and Senipah condensate from Indonesia at $112-113/b.
Cohen used the Platts Eagle Ford Marker assessment for this estimate, but that represents the gross product weight of a 47 API Eagle Ford crude barrel adjusted for spot values. Pioneer has said it defines its condensate as an "ultra-light hydrocarbon generally characterized as having an API gravity of 50 degrees or higher."
Cohen said his $108-109/b price estimate for Eagle Ford condensate offers a best guess estimate, which would likely not change too dramatically if assessments of higher API gravity hydrocarbons existed.
The South Pars, Qatari and Senipah condensates would be the most likely near-term competition for Eagle Ford condensate in the Asian market, particularly in India and China, which are nearing completion of roughly 400,000 b/d of incremental splitting capacity which could take this processed condensate.
Cohen pegs condensate shipping costs from the Middle to Asia at $1.50-2.50/b and $1-2/b from Indonesia to other Asian destination, while costs from the US to Asia would be $4-6/b. This would leave "only marginal economic justification for a delivered Eagle Ford condensate barrel in Asia," he said.
Still, Cohen said the economics could favor US condensate more going forward if condensate production climbs as expected due to its export potential.
Longson, however, pointed out that questions remain over the processed nature of the Eagle Ford condensate, which could remove liquefied petroleum gas and other light ends, and whether that would inhibit Asia's appetite for the product.
"These changes may create an incomplete crude with distillation issues that is less attractive for some export markets," he wrote. "From a crude standpoint, the odd distillation curve, low distillate yield and high paraffin nature of Eagle Ford condensate may limit the appetite from global refiners."
Pioneer and Enterprise have both declined to discuss their export plans in detail and Commerce has repeatedly declined to discuss its decision beyond an initial statement from an agency spokesman who stressed that allowing export of crude processed through a distillation was not a shift in policy.
John Auers, a refining consultant with Turner & Mason, said that stabilization and distillation were key to this ruling, although Commerce has no formal definition of what a crude distillation tower is.
"It is pretty broad," Auers said. "They're taking a very light, high vapor pressure condensate stream and separating out the light ends, removing enough light ends so that it's safe for transport and storage."
Auers said the ruling is significant since it outlines just how much processing of crude is required before it can be transformed into a product eligible for export.
--Brian Scheid, brian.scheid@platts.com --Edited by Derek Sands, derek.sands@platts.com
London (Platts)--30Jun2014/818 am EDT/1218 GMT
West African crude values have been falling steadily as a sizeable overhang of cargoes loading July and August has built amid weak refining margins, trading sources said Monday.
"The WAF market is in a dire situation. It is an ugly market out there," said a trader. "For the east, I believe there are alternatives out there...like ESPO and regional grades."
Strong values for Dated Brent have lessened the attraction of crudes priced off it, such as West African grades. That, and strong domestic stocks has weakened demand from China in the past few months. China is, typically, Angola's biggest buyer.
Angola's Cabinda was assessed at Dated Brent minus $1.49/barrel Friday, the weakest value seen since February 22, 2011, Platts data showed, while Nigeria's Bonny Light was assessed at Dated Brent plus $1.25/b, the lowest since October 25, 2012.
Besides the term allocations and a little bit of activity seen on and Cabinda and Dalia, minimal spot trading has been seen for the Angolan August loading program.
"It is very quiet, people are still waiting before buying for August now. Fundamentals have not changed much in the last few weeks. Chinese demand remains weak on low refining margins and rising crude stocks," a refiner said.
Grades like Girassol, Nemba, Pazflor and Saturno were really struggling to attract buying interest, sources said.
"On Nemba, I see most of the program is still unsold. The sentiment is as weak as you like. I have never seen a market this poor in a very long time," said a trader. "There are still [approximately] 15 million barrels of July to clear. It is miserable."
On Nigeria, sources said the situation was also one of oversupply, with 10 million barrels of July crudes still available, and spot trading for August cargoes also tepid.
--Eklavya Gupte, eklavya.gupte@platts.com
--Edited by Dan Lalor. daniel.lalor@platts.com
Moscow (Platts)--30Jun2014/816 am EDT/1216 GMT
Increasing natural gas exports to Asia and the potential effects of the Ukrainian crisis on exports to Europe are topping the international agenda of Russian gas giant Gazprom, CEO Alexei Miller suggested Friday at a news conference following the company's annual shareholders' meeting.
With the $400 billion, 38 billion cubic meter/year contract to supply China with East Siberian gas in hand, Gazprom has begun talks on supplies via the so-called western route, Miller said.
"The talks on the western route have begun immediately after the signing of the contract on the gas deliveries via the eastern route," he said, adding that the deal, which envisions supplies of up to 30 billion cubic meters/year of gas to China, may be signed "in the near future."
The western route talks began during Russian President Vladimir Putin visit to China in late May when the eastern route deal was reached, he said.
Putin last month said pipeline gas supplies to China from Western Siberia may begin even sooner than eastern route deliveries and could commence in the 2018-2020 period, should China express an interest.
Gazprom also is looking to expand cooperation Japan and by year's end expects to sign binding agreements with leading Japanese energy companies on supplies from the planned Vladivostok LNG export project, Miller said, providing no further details.
He also said the company expects to choose partners for the Vladivostok LNG project by the end of the year and said Gazprom is talking about the project with potential Chinese partners.
ROUTE TO INDIA
In addition, Miller discussed media reports about potential extension of the future Cino-Russian gas route to the border of India and China, calling the idea potentially interesting for Gazprom, but technically challenging because the pipeline would have to run through high-mountain areas.
Earlier this week, Indian newspaper the Financial Express reported India is set to begin talks with Russia over extending the East Siberia-to-China pipeline to the Indian border.
According to the newspaper, the possibility of such an extension will be discussed by Chinese, Indian and Russian officials during a July summit of Brazil, Russia, India and China, the so-called BRIC countries, and during a scheduled visit to India by Putin later this year.
Of the newspaper report, Miller said that "[s]o far, it is just an idea, a brave and beautiful idea."
"Were such an idea discussed at a practical level, it could be of interest for us," Miller said, adding that the possibilities of pipeline gas supplies to the rapidly developing Indian market are significantly larger than those for LNG.
Gazprom has already inked a deal to supply 2.5 million mt/year of LNG to India and talks are under way to increase that amount by as much as 1 million mt/year. The first deliveries are expected in 2019.
While Gazprom has shown an increased interest in Asian Pacific markets, the future of its European exports has emerged as a concern because of weaker demand, potential energy sanctions and Russian disagreements with Ukraine, which is a key transit country for Russian gas supplies to Europe.
UKRAINE RISKS
Commenting on the standoff between Gazprom and Ukraine over Kiev's multi-billion-dollar gas debt and gas prices, Miller warned that the dispute could have a direct impact on Gazprom's supplies to its European customers, who might consider re-exporting Russian gas to Ukraine.
"Supplies to companies that would deliver [gas] via reverse routes may be limited," he said.
Gazprom considers any reverse supplies "a con scheme," under which Russian gas does not actually even cross Ukraine's border with European countries, Miller said.
Ukraine is able to import 7-10 billion cu m/year of gas via Poland and Hungary, according to national energy company Naftogaz. Ukraine also hopes to arrange imports of up to 30 billion cu m/year from Europe through Slovakia, although Slovakia has so far not agreed to the transit.
Miller also did not rule out that Ukraine may siphon off gas volumes destined for European consumers in autumn when its domestic demand rises.
"At present, the problem is not obvious as gas consumption in Ukraine remains at a low level in the summer, but in the autumn we may hear about Ukraine taking [transit] gas [destined for Europe]," Miller said.
So far, Russian gas shipments through Ukraine are stable, despite a halt in deliveries to Ukraine. Gazprom stopped deliveries to its western neighbor after the parties failed to agree on the gas price and Ukraine failed to pay for already delivered gas to this country.
Ukraine's owes Gazprom $4.5 billion for 11.5 billion cu m of gas, Miller said, adding that these are "astronomic figures."
Naftogaz is looking to renegotiate its contract with Gazprom to lower the gas price, but recent media reports quoted Naftogaz CEO Andriy Kobolev as saying that Ukraine wants to reconsider the transit contract as well.
Naftogaz is looking to pay $268/thousand cu m for Russian gas, the price set for the first quarter of this year, while Gazprom insists that Ukraine must first repay its debt, before a cut in gas prices can be discussed. Gazprom has indicated it's ready to reduce the price to $386/thousand cu m from $486/thousand cu m now.
But Miller said Gazprom is unaware of Naftogaz's desire to renegotiate the transit deal. "Naftogaz has not raised this issue to Gazprom, neither in talks nor in written form," Miller said at the briefing. He added, however, that any such plan would be "very bad news."
Ukraine last year accounted for roughly a half of Russia's 162.7 billion cu m of exports to Europe.
Miller also said "Gazprom is not in any way interested in participating in the consortium to run Ukraine's gas transportation system. The moment has been lost," he said.
Ukraine has been considering a joint venture with EU and US companies to run the gas network, but has no current plans to invite Russia to participate.
But several years ago establishing a consortium of Russia, Ukraine and the EU to run the gas network was high on the agenda.
--Nadia Rodova, nadia.rodova@platts.com and Dina Khrennikova, dina.khrennikova@platts.com
--Edited by Jeff Barber, jeff.barber@platts.com
London (Platts)--30Jun2014/819 am EDT/1219 GMT
Two vessels loaded crude from Libya's Mellitah terminal and one from Marsa al-Hariga over the weekend, according to traders and Platts data, further strengthening expectations of a return to stable output from the country.
Total confirmed that its chartered vessel the EBN Battuta had loaded crude on Saturday, while a second chartered vessel, the Lorelei, sailed from Mellitah on Sunday destined for Rotterdam, according to Platts data. Litasco was said to have previously fixed the Lorelei although it declined to comment on the fixture.
In addition, the Phoenix Beacon loaded from Marsa al-Hariga Friday, according to traders, after a month spent waiting at the port. The Libyan port agent and traders confirmed that Clearlake was the charterer of the tanker.
The Aframax had entered the port in late May but had been unable to load a cargo for a month due to a strike. The departure of the vessel marks the first loading from the 110,000 b/d Marsa al-Hariga oil terminal in Tobruk since Libya's National Oil Corp. officially reopened it on June 21.
At the beginning of last week, an NOC spokesman said Libyan output was some 300,000 b/d following a restart of the 130,000 b/d capacity Elephant field, which had been shut in for months because of protests and strikes.
The restart on June 16 had boosted Libya's production from recent lows of around 150,000 b/d.
Elephant crude can be exported from the 160,000 b/d Mellitah terminal on Libya's Mediterranean coast or refined in the northern Zawiya refinery.
The recent loadings from Mellitah represent the second and third from the terminal since production from the field restarted, with the Scorpio having loaded at Mellitah on June 21 bound for Trieste.
--Alex Pearce, alex.pearce@platts.com
--John Morley, john.morley@platts.com
--Edited by Jonathan Fox, jonathan.fox@platts.com
By Paul Tugwell Jul 1, 2014 6:00 AM GMT+0700
Increased U.S. exports of liquefied petroleum gas amid higher shale oil production will boost demand for ships that carry gases such as propane, butanes and ethane, Paris Kassidokostas-Latsis, director of Athens-headquartered Latsco Shipping Ltd., said.
Shipments of LPG from the U.S. rose to a record 506,000 barrels a day in April, up 65 percent from a year earlier, Energy Information Administration data show. Production of the gases has grown as high oil prices and improvements in horizontal drilling and hydraulic fracturing techniques have allowed producers to tap into crude and gas trapped in layers of shale rock more than a mile beneath the Earth’s surface.
“The U.S. shale oil revolution is the main game-changer for the LPG market,” Kassidokostas-Latsis said in an interview in the Greek capital. “We are very optimistic on further growth of demand for LPG ships, especially from the U.S. on the back of shale.”
LPG in the U.S., used for cooking and heating and as a feedstock for the petrochemicals industry, is mostly produced as a byproduct of natural gas. U.S. crude output reached 8.48 million barrels a day in the week ended June 13, the highest since October 1986, while natural gas output is forecast to hit a record for the fourth straight year. The ample supply of gases has depressed prices along the U.S. Gulf Coast, benefiting petrochemical manufacturers and encouraging exports.
That has increased demand for the largest ships hauling LPG, known as VLGCs, that can hold about 80,000 cubic meters (2.8 million cubic feet).
Ship Orders
Latsco ordered 12 ships in 2013, including four VLGCs from South Korea’s Hyundai Heavy Industries Co., three long-range product tankers from Hyundai Samho Heavy Industries Co. and five medium-range product tankers from Hyundai Mipo Dockyard “worth just under $700 million,” Kassidokostas-Latsis said.
Product tankers carry refined petroleum products.
“The long-term fundamentals are strong for the products market in general,” he said.
The EIA projects the U.S. will be a net exporter of LPG through 2040, because of continued increases in natural gas and oil production. Shale gas production in the U.S. will grow to 19.8 trillion cubic feet in 2040 from 9.7 trillion cubic feet in 2012, according to the EIA.
Robust Rates
Freight rates for ships carrying LPG are set to “remain robust through the summer,” Arctic Secrities said April 29, citing “seasonal strength in exports of U.S. LPG.” The total fleet of such vessels is about 160 ships.
“We took delivery of the first long-range product tanker this month and all other vessels will be in the water by 2016,” Kassidokostas-Latsis said. The Latsis family contributed equity and added some “traditional bank financing from abroad,” he said.
Latsco already operates four VLGCs, each with a carrying capacity of 82,000 cubic meters, seven medium-range product tankers with total capacity of 343,815 deadweight tons and four long-range product tankers, including this month’s addition, with combined capacity of 335,654 deadweight tons.
Recently there’s been a build-up in the LPG order book with the number of vessels scheduled for delivery in 2015 and 2016 set to increase the fleet by 50 percent, Kassidokostas-Latsis said. “In any other sector that would be a red flag, but these new ships will be absorbed by extremely buoyant export growth, primarily from the U.S.”
Panama Canal
Latsco doesn’t fear the long-term effects of the expansion of the Panama Canal on VLGC rates. The widening of the waterway linking the Atlantic and Pacific Oceans will cut the number of LPG carriers needed to transport the fuel as round-trip voyages between Tokyo and Houston will be shortened by around 17,000 miles. Construction to expand the canal was 76 percent complete of May 31, according to the Panama Canal Authority.
“Once the expanded canal opens, we may see a slowdown in freight rates for VLGCs as the distance to the Far East from the U.S. Gulf will be shorter, but in the long term this will make LPG more attractive and competitive compared with other commodities and that will lead to an increase in demand and a readjustment of rates,” Kassidokostas-Latsis said.
To contact the reporter on this story: Paul Tugwell in Athens at ptugwell1@bloomberg.net
To contact the editors responsible for this story: Jerrold Colten at jcolten@bloomberg.net David Marino, Marco Bertacche
Mexico exported 763,891 b/d of crude to the US in May, an increase of 19.4% compared with the 640,003 b/d exported in May 2013, according to the energy ministry. The trade ministry previously said Mexico’s overall crude exports were 1.116 million b/d in May, an increase of 8.5% compared with 1.029 million b/d in May 2013.
Spain imported the next largest amount of Mexican crude in May at 193,542 b/d, slightly up from 192,643 b/d a year earlier, the energy ministry said.
Canada received 22,004 b/d in May, down from 40,164 b/d a year earlier. India received 41,949 b/d, down from 122,482 b/d. The Netherlands received 17,443 b/d in May but received none at all between May 2013 and March 2014, the energy ministry said over the weekend.
China received 16,147 b/d of crude in May, just over half the 32,255 b/d it imported a year earlier.
The 11 countries of Central America and the Caribbean that receive discounted supplies under the San Jose Accord imported 17,755 b/d of Mexican crude in May. A year earlier, they imported 1,795 b/d.
Heavy Maya crude accounted for 900,913 b/d of Mexico’s total exports in May, down from 914,608 b/d in the same month of last year.
Exports of light Isthmus crude rose to 122,286 b/d from 26,329 b/d in the year-ago period.
Exports of extra-light Olmeca crude nudged up to 93,065 b/d in May from 88,404 b/d in May 2013.
The average price of Mexican crude exports to the US in May was $95.687/b, down 3.5% from $99.20/b a year earlier.
In the rest of the Americas, the price was $100.007/b, compared with $98.322/b in May 2013, the ministry said.
The average price in Europe in May was $100.466/b, up from $99.303/b a year earlier.
In Asia, the average price was $95.543/b, down from $95.804/b a year earlier, it said.
By Jim Polson Jul 1, 2014 3:18 AM GMT+0700
Linn Energy LLC (LINE) agreed to buy oil and natural gas-producing acreage across six U.S. states from Devon Energy Corp. (DVN) for $2.3 billion, its largest purchase since acquiring Berry Petroleum Co. last year.
The 896,000 net acres in the Rocky Mountains, Gulf Coast and Mid-Continent region produce the equivalent of 275 million cubic feet of gas a day and have proved reserves of 1.242 trillion cubic feet, Oklahoma City-based Devon said in a statement today. Linn, which has interim financing for the acquisition, plans to fund the purchase ultimately by selling its holdings in the Granite Wash and Cleveland plays in Texas and western Oklahoma.
The Devon assets have “significant operational overlap” with Linn’s existing acreage, the Houston-based company said in a presentation posted on its website. Linn was formed to buy already producing oil and gas fields and seek to boost output. LinnCo LLC (LNCO), a limited liability company that owns units in Linn, in December bought Berry Petroleum for $2.72 billion after having to raise the bid because of a drop in its stock price. Ownership in Berry was later transferred to Linn in exchange for units.
“They’re basically building a fortress around their dividend,” said Kevin Smith, a Houston-based analyst for Raymond James Financial Inc. (RJF) who rates Linn at buy, LinnCo at strong buy and owns neither. “It advances their cash flow and they don’t have to spend as much money to maintain production.”
Linn gained 1.4 percent to $32.35 at the close in New York. LinnCo rose 2.6 percent to $31.29 and Devon fell 10 cents to $79.40.
Decline Rate
About 80 percent of the output from the Devon assets is gas. The decline rate, a measure of how much must be spent to maintain production, is 14 percent for the Devon assets, Linn said. The company last month swapped 26,000 acres in the oil-rich Permian Basin with Exxon Mobil Corp. (XOM) for gas wells with a 4 percent decline rate.
“Linn is driving strategy and valuation based on acquiring assets that they perceive to have long life,” said Fadel Gheit, a New York-based analyst for Oppenheimer & Co. who rates Devon at buy and doesn’t own the shares. “That fits their financial structure and their strategy.”
The company plans to sell assets that produce the equivalent of 230 million cubic feet of liquids-rich gas a day over about 147,000 net acres.
Devon Sales
Linn has burned through $6.5 billion of free cash in the past four years, leading Kevin Kaiser, an analyst at Hedgeye Risk Management in Stanford, Connecticut, to rate it a sell.
“Nothing really changes,” Kaiser said today. “Linn’s distribution is not financed with free cash flow or earnings. It’s financed with equity raises and debt raises. I think Linn Energy eventually collapses under the weight of this debt burden.”
Today’s deal “may push that day of reckoning out,” Kaiser said.
Linn Energy didn’t immediately return a voicemail and e-mail seeking a response to Kaiser’s comment.
The deal ends a round of asset sales announced last year by Devon, which is seeking to transform itself from a gas producer into an oil company.
“Upon completion of this transaction we will have reduced our net debt by more than $4 billion this year,” John Richels, chief executive officer of Devon, said in the statement.
The transaction is expected to close in the third quarter, with an April 1 effective date.
Jefferies Group LLC was lead financial adviser to Devon on the transaction, with Credit Suisse Group AG (CSGN) also providing financial advice. Vinson & Elkins LLP gave legal advice to Devon. Scotia Waterous advised Linn.
To contact the reporter on this story: Jim Polson in New York at jpolson@bloomberg.net
To contact the editors responsible for this story: Tina Davis at tinadavis@bloomberg.net Steven Frank
Mon Jun 30, 2014 4:04am EDT
* CDU capacity could be cut by as much as 400,000 bpd
* New goals to demand further streamlining by March 2017
* Proposed rules to foster industry reorganisation (Adds details)
By Osamu Tsukimori
TOKYO, June 30 (Reuters) - Japan may cut crude refining capacity by as much as 10 percent, or 400,000 barrels per day (bpd), by March 2017, under a new round of reductions set to be forced on the country's refiners amid forecasts for declining demand for oil products.
Cuts mandated by the government in 2010 pushed refineries to axe nearly 1 million bpd of capacity by March this year, but the industry ministry sees demand for oil products falling further by 2018, due to population decline and fuel efficiencies.
The ministry outlined proposals on Monday that would mandate more cuts. The plan will be released for public comment on Tuesday and refiners would have until Oct. 31 to say how they would meet the proposed cuts.
Japan's refining capacity stood at 3.95 million bpd as of April 1 this year, down nearly 20 percent from 2008.
The industry ministry said it was important to make the industry more efficient to strengthen its competitiveness, given razor thin profit margins and the difficulty of passing on rising costs to wholesale prices.
The move is similar to the previous plan that required refineries to either scrap older crude units or invest in heavy residue crackers to produce more higher-end, light products such as diesel and jet fuel. The new plan would also allow refiners to partner with rivals.
Yasushi Kimura, head of the Petroleum Association of Japan and chairman of the nation's biggest refiner JX Holdings , said he welcomed that the proposals would allow each firm to make voluntary decisions on reorganisation and boosting competitiveness.
IMPROVED EFFICIENCY
The proposal calls for improving the overall ratio of residue cracking capacity to crude distillation unit (CDU) capacity from 45 percent at present to 50 percent, closer to the world's best of about 55 percent.
If refiners simply cut crude refining capacity, CDU capacity will fall by as much as 400,000 bpd, the ministry said. The plan would mean a rise in Japan's refinery run rate to nearly 90 percent, it said.
The previous mandate only counted cokers, residue fluid catalytic cracking (RFCC) units and residue hydrocracking units (RHCU), but the new goals would also include fluid catalytic cracking unit (FCC), solvent de-asphalting unit (SDA) and residue desulphurisation unit as residue cracking units.
Under the proposal, refiners with the worst ratio would need to make the most improvement, based on current ratio of residue cracking units to crude refining capacity.
Refineries with a ratio of less than 45 percent would need to improve by 13 percent, refineries with a ratio of 45-55 percent would need to improve by 11 percent and refineries with a ratio of 55 percent and above would need to boost their performance by 9 percent.
If two refiners decide to combine operations of their plants in the same industrial area and scrap one of the CDUs at the complex, both firms can share credit for scrapping the CDU.
Ministry officials said they expect to finalise the goals after seeking feedback via public comment.
(Reporting by Osamu Tsukimori; Editing by Aaron Sheldrick and Richard Pullin)
* Trade in Aug-loading Basra Light muted
* Potential buyers say worried about risk of supply disruptions
* But conflict still a long way from Basra
* Weak refining margins also sapping demand for crude
By Florence Tan and Meeyoung Cho
SINGAPORE/SEOUL, June 30 (Reuters) - Many Asian refiners say they are shying away from buying the flagship grade of Iraqi crude in spot markets, worried that the militant insurgency in the country could spread to the area where the oil is churned out and exported.
Although the mounting conflict that has swept parts of Iraq is still hundreds of kilometres away from the southern region which produces and ships Basra Light crude, Asian buyers say they are concerned about possible supply disruptions.
"The Iraqi situation is unpredictable, which makes it hard for us to buy Iraqi crude on the spot markets," said a Seoul-based refining source. He declined to be named as he was not authorised to speak with media.
"To a refiner, stable crude supply is the priority."
Trade in August-loading Basra Light has been muted this month as risk-averse refiners in Asia have sated their need for crude by buying oil originating in other Gulf producers such as Saudi Arabia and Abu Dhabi, market participants said.
That is unlikely to have any short-term impact on volumes of Iraqi exports, set to hit a record this month, as they are all shipped via term contracts agreed between buyers and Iraq's State Oil Marketing Organisation (SOMO), with some then being resold in spot markets.
But it could impact negotiations for future term contracts if spot resales look likely to be more tricky.
SOMO has term agreements to sell nearly 1.7 million barrels per day (bpd) of Basra Light to refiners and trading firms in Asia this year.
Asia typically imports more than half the output of the grade, with China and India the main buyers in the region so far in 2014.
Fears of supply disruption due to the insurgency have pushed up prices for global benchmark Brent crude by 3.4 percent so far in June - its best monthly showing since August.
ALTERNATIVES
Taiwanese refiners Formosa Petrochemical and CPC Corp have opted for Oman for August instead of Basra Light, sources said, while an Indian refiner said he may replace the Iraqi grade with West African crude.
Demand for spot cargoes has also been hit as any purchases made now will arrive in September, a low-season for oil product usage, and as many refiners have scaled back production as excess capacity in the sector has squeezed their profits.
Spot trade could also be dwindling as sellers wait until July 10 for SOMO to inform them what volumes they will be entitled to in August.
But some traders said refiners would buy Basra Light if prices were low enough.
"I don't think there is any big risk to physical disruption but risk is risk ... That's why refiners may try to buy at a level that takes care of this risk," said a Singapore-based trader.
August-loading cargoes may eventually be sold at discounts to the grade's official selling price (OSP), down from a single-digit premium for July, traders said, in light of the sharp fall for differentials of comparative grades such as Oman that have traded for August. (Additional reporting by James Topham in Tokyo; Editing by Joseph Radford)
* Deal includes assets onshore Gulf Coast, Rockies, mid-continent
* Assets being sold produce 275 mmcfe gas per day (Adds details from statements, background)
(Reuters) - Devon Energy Corp said it would sell its remaining non-core gas-rich properties to peer Linn Energy LLC for $2.3 billion to focus on more lucrative oil assets and cut debt.
This is Linn's biggest deal since it bought Berry Petroleum Co in December through a holding company set up for acquisitions.
The asset sale by Devon includes about 900,000 net acres spread across the Rockies, onshore Gulf Coast and some mid-continent regions, including all or parts of Kansas, Oklahoma, Texas, Arkansas and Louisiana.
These assets produce 275 million cubic feet of gas equivalent per day, about 80 percent of which is natural gas. They contributed about 7 percent to Devon's total oil and gas output in the first quarter.
Devon and many other North American oil and gas producers have been selling off their natural gas holdings to focus on more profitable crude oil assets. Prices of natural have slumped after a shale boom in the United States.
Encana Corp, Canada's largest natural gas producer , said last week it would sell its Bighorn gas properties in Alberta, properties in Wyoming's Jonah natural gas field and about 90,000 net acres in east Texas.
Devon itself has raised more than $5 billion from the sale of non-core assets over the past few quarters.
It sold off some natural gas assets in Canada late last year and bought oil-producing assets in the Eagle Ford shale region of south Texas.
The company said on Monday it expects to have reduced its net debt by more than $4 billion this year after the completion of the deal, likely by the end of the third quarter.
"With this sale, we now see a new Devon emerging with fourth quarter as the first clean quarter for the clean, go forward portfolio that is expected to deliver on peer leading growth," Global Hunter Securities analysts wrote in a note.
Oil and natural gas liquids are expected to account for about 60 percent of Devon's output by year-end, Chief Executive John Richels said, adding that the company was targeting multi-year oil production growth of more than 20 percent.
Linn said it would fund the deal by selling its Granite Wash assets spread over Texas Panhandle and western Oklahoma as well as other non-producing acreage. It has also secured a $2.3 billion loan.
Devon's shares were little changed at $79.49 in afternoon trading on the New York Stock Exchange. Linn's shares were up nearly 2 percent at $32.44 on the Nasdaq.
Jefferies LLC and Credit Suisse Securities (USA) LLC were financial advisers to Devon. Vinson & Elkins LLP was its legal adviser. Scotia Waterous was the financial adviser for Linn. ($1 = 1.0664 Canadian Dollars) (Reporting by Anannya Pramanick in Bangalore; Editing by Don Sebastian and Saumyadeb Chakrabarty)
* Supply falls by 70,000 bpd, led by Iraq
* Output edges higher in Saudi Arabia, Libya
* OPEC output back below supply target of 30 million bpd
By Alex Lawler
LONDON, June 30 (Reuters) - OPEC's oil output has fallen in June from May's three-month high, a Reuters survey found on Monday, as fighting in Iraq closed its largest oil refinery and technical problems slowed its southern exports.
The slight decline underlines how unrest and outages in the Middle East and Africa are taking their toll on OPEC supply, just as the International Energy Agency is highlighting a greater need for OPEC oil in the rest of the year. [D:nL5N0OU1KF]
Supply from the Organization of the Petroleum Exporting Countries has averaged 29.93 million barrels per day (bpd), down from 30.00 million bpd in May, according to the survey based on shipping data and information from sources at oil companies, OPEC and consultants.
The decline puts OPEC output back below the group's nominal target of 30 million bpd, which oil ministers decided at a June 11 meeting in Vienna to maintain for the rest of 2014.
OPEC pumps a third of the world's oil. In June, output has declined in Iraq and Iran, offsetting a modest increase in top exporter Saudi Arabia and smaller rises elsewhere in the group.
The largest decline came from Iraq, where production declined by 170,000 bpd according to the survey. Domestic crude use fell because of the closure of the Baiji refinery, which was attacked by militants.
Also, Iraq's southern exports fell. Shipments in the first three weeks of June were steady, but slowed to 2.43 million bpd over the whole month because of technical issues, from May's 2.58 million bpd.
At Iraq's southern terminals, one single point mooring is undergoing repairs to fix a broken mooring chain, while a berth at the Basra oil terminal is also undergoing maintenance, according to shipping sources.
The sale of three cargoes of crude by Kurdistan, in defiance of the central government, limited the decline in Iraqi exports, which in February had reached a record high of 2.8 million bpd.
Iranian crude exports also edged lower in June from May's elevated levels, the survey found. Higher exports since late 2013 following a softening of Western sanctions on Iran over its nuclear work have boosted OPEC supplies.
Nigerian supply declined slightly. Export schedules initially pointed to little change, but Royal Dutch Shell Plc declared force majeure at its EA field for repairs.
Of the countries which have boosted output, Saudi Arabia raised supply modestly, in part because of a higher need for crude in domestic power plants, industry sources said. Output also edged up in the United Arab Emirates.
Libyan supply rose by 30,000 bpd to a monthly average of 220,000 bpd, the survey found. Strikes and protests are still keeping output at a fraction of the country's potential. (Editing by William Hardy)
