US condensate splitter plans move forward, but uncertainty remains
Pricey condensate splitter plans appear to be on track despite recent US rulings expected to create a surge in exports of condensate, which needs to be processed, but not through splitters. However, uncertainty over export policy could ultimately impact some plans. The splitter picture is “still developing,” Barclays analyst Michael Cohen said, adding that projects beyond 2015 may be the most at risk.
It remains unclear, Cohen said, how much market there is for splitter-made products such as propane and ethane, as opposed to demand for processed condensate, which a firm could export directly from a field condensate stabilizer. “Until there’s a little more clarity around the regulatory issue, in addition to the market issue, then I don’t think these projects are likely to continue to be put online at the pace people think,” Cohen said.
This uncertainty was on display during earnings calls, where company executives revealed that while they were still planning to build condensate splitters, those plans could be altered by the US Department of Commerce’s decision to allow Pioneer Natural Resources and Enterprise Products Partners to export processed condensate. Commerce ruled this condensate could be exported without a license because it was lightly refined in a distillation tower and no longer fell within the definition of crude oil.
“I think as far as future splitters are concerned, it’s going to make the potential people who utilize those splitters probably think carefully about whether they want to proceed,” Kinder Morgan CEO Richard Kinder said. He noted his company’s plans to build a 100,000 b/d splitter on the Houston Ship Channel are still on track.
Joe McCreery, a vice president with Martin Midstream Partners, said that due to the recent Commerce rulings, Midstream’s plans for a 50,000 b/d condensate splitter in the Corpus Christi, Texas, market “continues to evolve.” McCreery indicated that the splitter, estimated to cost $175 million-$200 million, is now being built to meet Commerce’s “exportable standard,” which the agency has not detailed publicly.
Citing national security concerns, Commerce has not made its condensate rulings public, and it remains unclear precisely how these firms are processing condensate through a distillation tower.
It is clear, however, that this distillation processing can be launched quicker and far more cheaply than through a condensate splitter, which splits light oil into components such as naphtha and distillates.
Saudi Arabia tells OPEC it hiked oil output above 10 mil b/d in July
Saudi Arabia has told OPEC it boosted crude production to 10.005 million b/d in July, up 225,000 b/d from July and the highest monthly level since September 2013, when Riyadh told the oil producer group it pumped an average 10.123 million b/d.
The July figure also marks the first time Saudi production has been above 10 million b/d since September last year. OPEC uses secondary sources to monitor crude production from its 12 member states but also publishes a table of figures provided directly by these countries.
On Friday, OPEC published a secondary source estimate of 9.813 million b/d for Saudi Arabia but did not publish a directly submitted figure. The 10.005 million b/d has been added subsequently. Saudi Arabia increases the volume of crude burned directly in power stations during the summer months.
Libya restarts loadings at Ras Lanuf, output still constrained
The first crude loading in nearly a year has begun at the Ras Lanuf terminal in Libya, a local port agent told Platts Monday, giving the beleaguered North African country a much needed boost.
Ras Lanuf, whose capacity is 220,000 b/d, was occupied by anti-government forces in August 2013, and was only handed back to state-owned NOC last month after rebels reached a deal with Tripoli.
Tanker owners have been cautious about sending vessels to Libya as rival militant groups and government forces continue to clash around the capital Tripoli and in the east of the country.
The Gemini Sun Aframax tanker, owned by Zodiac Maritime, is currently loading a cargo at the terminal, with the charterer said to be Austria’s OMV. “The Gemini Sun is loading Sirtica crude at Ras Lanuf and should complete the loading by tomorrow morning,” the agent said. “The charterer is OMV. This is the first loading since the terminal re-opened but
I believe there is another tanker coming as well,” he said. OMV declined to comment Monday.
According to the agent, the crude that is loading is storage barrels. “It’s an oil cargo from storage,” he said. Traders also expect the nearby Es Sider terminal — which has also been inoperational since August 2013 — to resume loadings in the coming days.
Earlier Monday, a senior NOC official said that it was proving difficult to ramp up Libya’s production because of the lack of exports from the North African country. This, the official said, meant its storage facilities at fields and at ports across its Mediterranean coast were filled to capacity.
Libya is currently producing between 450,000 b/d and 500,000 b/d of crude, but the official said the country could theoretically return output back to pre-crisis levels of around 1.5 million b/d.
“Libyan fields are ready to pump oil at its normal maximum capacity, and it doesn’t face any problems except that we can’t produce more since the storage tanks are full with crude oil,” the official said. “The storage tanks at Ras Lanuf and Es Sider have around 9 million barrels ready for companies to come and lift them,” he said.
Libya had hoped to be able to ramp up output across the country, including at its recently restarted fields of Sharara and Elephant in the southwest of the country, but exports have been slow out of its Mediterranean ports. This has prevented Libya from opening the taps further at its key producing fields. “Sharara is not producing at full capacity since storage tanks there are full,” the official said. “Sharara is producing around 200,000 b/d.”
Nigerian crude values weaken further as September overhang persists
Nigerian crude values continue to weaken as the September overhang remains substantial, putting further pressure on values amid weak demand, trading sources said Monday.
Sources said there were still about 20-25 million barrels of Nigerian September-loading crude cargoes unsold, a large quantity for this point of the monthly trading cycle.
From August there were also still about three Nigerian August-loading barrels unsold, sources said. Grades like Bonga, Forcados, Brass River and Escravos were particularly struggling but even sales for the flagship grades like Bonny Light and Qua Iboe had been slow.
Demand for Nigerian grades has been lackluster for September for a number of reasons, ranging from low refining margins, weak product cracks and tepid European demand. Even Indian demand, which has been a key driver for Nigerian crudes recently, has been sluggish, sources said.
Forcados was assessed at Dated Brent plus $0.78/b Friday, the weakest value seen since February 16, 2010, Platts data showed. Traders pegged the grade at similar levels Monday morning. “The market is very weak for lights. The medium grades have reached a bottom with the narrow Brent/Dubai spread,” said a trader. “Margins are better because there is too much crude around. The cracks have improved [slightly], led by crude weakness and not the strength in products,” the trader said.
Despite a slight improvement in refining margins, light sweet crudes like those from Nigeria are struggling as there is a lot of sweet crude on the market at the moment. And in the current environment, refining margins for medium and sour crudes are much better than sweets, thwarting demand for light sweet crudes, sources said.
By Terry Atlas and Zaid Sabah Aug 12, 2014 6:45 AM GMT+0700
The political crisis in Baghdad escalated as embattled Iraqi Prime Minister Nouri al-Maliki rejected a transition to Haidar al-Abadi as his successor and increased the presence of troops and militias in the capital.
In a late-night address on state TV yesterday, Maliki defied pressure from some fellow Shiite political figures and U.S. President Barack Obama to step aside. The refusal threatens to extend a three-month political stalemate that’s helped the militant Sunni fighters of the Islamic State seize swaths of the country.
A sense of crisis spread across Baghdad. In the Sunni Ameriya neighborhood, Ahmed al-Nidawi said by phone that people huddled in their homes throughout the day after armored vehicles and Iraqi soldiers with U.S.-supplied M4 carbines took up positions. In the mixed Sunni-Shiite Zayouna neighborhood, Saddam al-Bayati said soldiers and Shiite militiamen were patrolling “like I’ve never seen before.”
Maliki called President Fouad Masoum’s nomination of Abadi, the deputy speaker of the Parliament, “legally worthless.” Maliki demanded that he be designated to select the new cabinet and serve a third term.
“You, the Iraqi people, and the security forces are in a holy battle,” Maliki said. “Don’t panic. We will fix the mistakes.”
Blaming Maliki
As the U.S. continued limited air strikes against Islamic State militants in northern Iraq, Obama called the selection of Abadi a “promising step” and didn’t make even a mention of Maliki in brief remarks during his vacation in Martha’s Vineyard, Massachusetts.
“I urge all Iraqi political leaders to work peacefully through the political process in the days ahead,” he said.
The U.S. and some Iraqi leaders have blamed Maliki’s divisive policies for the success of the Sunni insurgents, and Obama has tied expanded U.S. military strikes to formation of a more inclusive government to ease sectarian and ethnic divisions. U.S. airstrikes so far are having only a “temporary effect” on thwarting the insurgents in northern Iraq, U.S. Lieutenant General William Mayville told reporters at the Pentagon yesterday.
“As I said when I authorized these operations, there is no American military solution to the larger crisis in Iraq,” Obama said. “The only lasting solution is for Iraqis to come together and form an inclusive government.”
U.S. Warning
Masoum earlier yesterday asked Abadi, who like Maliki is a Shiite and is a member of Maliki’s Islamic Dawa Party, to try to form a new cabinet. Masoum tapped Abadi hours after U.S. Secretary of State John Kerry publicly pulled support from Maliki, warning him not to hinder the political process while the country is under threat from the Islamic State.
Maliki said that Masoum violated the Iraqi constitution in not selecting him to form the cabinet because his State of Law bloc was the top vote-getter in the April parliamentary elections. Maliki, who came to power in 2006 with U.S. backing, remains prime minister and commander-in-chief of the security forces until a successor takes office.
“We are the largest bloc in the parliament and have the right to form the government,” Maliki said.
His rejection of Abadi could lead to strife and even violence within the country’s majority religious group even as the Sunni militants in the north push into Shiite and Kurdish areas of the country.
Maliki’s Control
“Maliki has consolidated control over the security apparatus by establishing extra-constitutional security bodies and creating a direct chain of command from commanders to his office,” Meda Al Rowas, senior Middle East analyst at IHS Country Risk, said in a note to clients. “This increases the risk of Maliki’s rivals, who have access to their own militias, using force to attempt to remove Maliki, raising the risk of Shia-Shia infighting within the capital, and subsequently civil war risks affecting southern provinces.”
Amid the tensions in Baghdad, Obama said he and Vice President Joe Biden called Abadi “to congratulate him and to urge him to form a new cabinet as quickly as possible, one that’s inclusive of all Iraqis.”
“The president emphasized that the United States stands ready to deepen political and security cooperation with Iraq as political leaders seek to implement political reforms,” according to a White House statement on the call.
More Airstrikes
The U.S. military conducted additional airstrikes against Islamic State targets near Erbil, the U.S. Central Command said in statements yesterday. The U.S. has carried out 19 targeted airstrikes since Aug. 8, using a combination of fighter jets and armed drones, according to the Pentagon.
The strikes haven’t been extensive enough to contain the militants or reduce their capabilities, said Mayville, who is director of operations for the U.S. Joint Chiefs of Staff.
“We’ve had a very temporary effect, and we may have blunted some tactical decisions” by Islamic State militants to move farther east toward Erbil, the Kurdish regional capital, Mayville said at his Pentagon briefing. There are no plans to expand air operations beyond the limited mission of protecting U.S. personnel on the ground in Erbil and aiding civilians facing a humanitarian crisis, Mayville said.
Emergency Supplies
The U.S. also has provided food and water to civilians, most of them members of the Yezidi religious sect, trapped on Sinjar mountain, near the Syrian border, who have been threatened with slaughter if they return to their homes.
The Defense Department has flown 14 successful missions over four nights, providing 16,000 gallons of water and 75,000 meals, Mayville said. Iraqi forces also have brought in supplies by helicopter and carried out some civilians.
Estimates of the number of civilians stranded on the mountain have ranged from thousands to tens of thousands, Mayville said. Airstrikes yesterday were concentrated on militant checkpoints near Sinjar mountain to aid displaced Yezidis, according to a statement from the U.S. Central Command.
Kurdish forces were able to retake the towns of Makhmour and Gwer, south of Erbil, where militants retreated after U.S. airstrikes, according to the Kurdish news agency Rudaw, citing officials.
A U.S. official, who spoke on condition of anonymity to discuss confidential arrangements, said the U.S., Turkey, Jordan, France, Britain and Gulf states have been discussing how to arm the Kurds and that some weapons already have been delivered.
Kurdish Arms
Kurdish military forces, known as peshmerga, have begun receiving small-arms ammunition directly from the U.S., instead of going through the central government in Baghdad, because their needs have become “pretty substantial,” Mayville said.
The Kurds have been outgunned in the fight because the Sunni insurgents have built up their forces with captured armored vehicles and heavy weapons that the U.S. had provided to the Iraqi Army.
European ambassadors to the European Union will meet today to discuss Iraq. France and Britain delivered humanitarian aid over the weekend, while for the moment saying they won’t join military action.
To contact the reporters on this story: Terry Atlas in Washington at tatlas@bloomberg.net; Zaid Sabah in Washington at zalhamid@bloomberg.net
To contact the editors responsible for this story: John Walcott at jwalcott9@bloomberg.net Larry Liebert, Justin Blum
By Grant Smith Aug 11, 2014 11:13 PM GMT+0700
Hedge funds cut bullish bets on Brent crude to the lowest level in six months last week, another signal that traders expect supplies from Iraq to remain safe from an Islamist insurgency in the north of the OPEC member.
Brent futures traded near a nine-month low in London today as U.S. air strikes against Islamic State militants in northern Iraq reassured investors that oilfields in the adjacent Kurdish region would stay unaffected. Supplies from southern Iraq, home to about 85 percent of the nation’s output, continue to flow undisturbed by violence in the north, with Oil Minister Abdul Kareem al-Luaibi saying that exports will exceed 2.5 million barrels a day in August.
“For me, it’s justified,” Torbjoern Kjus, an analyst at DNB ASA in Oslo said of the pull-back by traders. “I wouldn’t be putting on any new positions. It’s going to be a mess in Iraq for a long time, but that doesn’t necessarily translate into lost oil barrels.”
Hedge funds and other money managers reduced net bullish bets on Brent futures to 97,351 contracts in the week to Aug. 5, the lowest since Feb. 4, data from the London-based ICE Futures Europe exchange showed today. Brent for September settlement rose 14 cents to $105.16 a barrel on ICE at 4:30 p.m. London time. The contract closed at $104.59 on Aug. 6, the lowest level since November 2013.
Improved Confidence
The U.S. military destroyed yesterday part of an Islamic State vehicle convoy moving to attack forces defending Erbil, the capital of the Kurdish region, the U.S. Central Command in Tampa, Florida, said in an e-mailed statement today.
“The strikes have helped improve confidence on the Kurdish side,” Ole Sloth Hansen, an analyst at Saxo Bank A/S in Copenhagen, said by e-mail. “Given the U.S. commitment to bomb, if the Islamic State stick their neck out too far I would say the situation there is contained.”
Iraq’s President Fouad Masoum asked Haidar al-Abadi to replace embattled Prime Minister Nouri al-Maliki and form a new cabinet, in a bid to end the political deadlock that has hobbled the country’s efforts to roll back the insurgency.
Maliki, a Shiite Muslim whose policies have been blamed for pushing minority Sunni Muslims into an alliance with the radical Islamic State, earlier said he would challenge Masoum in court and then deployed troops on the streets of Baghdad.
Underestimating Dangers
Masoum tapped Abadi hours after U.S. Secretary of State John Kerry pulled support from Maliki, warning him not to hinder the political process. U.S. President Barack Obama has tied expanded military strikes against the al-Qaeda breakaway group to the formation of a more inclusive government that didn’t marginalize Sunnis and other minorities.
Traders exiting Brent are underestimating the dangers to supplies in Iraq and other politically unstable regions, according to Commerzbank AG. Selling of oil futures will probably abate as bullish positions have slipped below their long-term average, the bank estimates.
“We see no justification for the complacent attitude of players on the oil market given the geopolitical tensions and anticipate a rising oil price,” Carsten Fritsch, an analyst at the Frankfurt-based lender, said in a report.
To contact the reporter on this story: Grant Smith in London at gsmith52@bloomberg.net
To contact the editors responsible for this story: James Herron at jherron9@bloomberg.net; Alaric Nightingale at anightingal1@bloomberg.net Sharon Lindores
By Ilya Arkhipov, Kateryna Choursina and Volodymyr Verbyany Aug 12, 2014 4:01 AM GMT+0700
Aug. 11 (Bloomberg) -- Russia's relationship with the West has "fundamentally changed" following the eruption of fighting in Ukraine and the subsequent imposition of sanctions, according to Timothy Ash, chief economist for emerging markets at Standard Bank Group Ltd. in London. He speaks with Mark Barton and Caroline Hyde on Bloomberg Television's "Countdown." (Source: Bloomberg)
The Red Cross said it’s working on getting aid to rebel-held areas of east Ukraine, where government forces have encircled major cities, as the U.S. warned Russia not to use the mission to send in troops.
The situation in the city of Luhansk and other areas “is critical -- thousands of people are reported to be without access to water, electricity and medical aid,” Laurent Corbaz, the head of the International Committee of the Red Cross’s operations for Europe, said in an e-mailed statement late yesterday. Still, “the practical details of this operation need to be clarified before this initiative can move forward.”
The ICRC met with Ukrainian and the Russian authorities and passed on documents specifying the manner in which such an operation could take place, the Geneva-based organization said.One requirement is that all sides must guarantee the security of Red Cross staff and vehicles for the duration of the operation, because the ICRC does not accept armed escorts.
The U.S., the European Union and NATO all reiterated warnings yesterday to Russian President Vladimir Putin that the aid mission can’t be a pretext for military intervention in support of the pro-Russian separatists in the Donetsk and Luhansk regions. Putin spokesman, Dmitry Peskov, said the Russian army wouldn’t be involved, the RIA news service reported. Ukraine rejected a rebel offer of a cease-fire two days ago.
Attention may shift today to Ukraine’s parliament, where lawmakers will vote on imposing sanctions against Russian companies.
Deepest Rift
Still, the arrival of an aid mission may ease tensions after months of fighting between government forces and the rebels. The conflict has left hundreds dead and created the deepest rift between Russia and the U.S. and its allies since the end of the Cold War.
Ukraine’s military said yesterday it’s near the end of its operation to encircle the remaining separatist strongholds and called on civilians to leave Donetsk and Luhansk as government troops close in.
The fighting is causing havoc in the residential areas where it’s now concentrated. Luhansk, where about half of the 500,000 population remains, is completely isolated, with electricity cut off in the center and people without phone connections, food, medication or fuel, the city council said on its website. Encirclement of the rebels would shut off routes to the Russian border and sever their supply lines.
‘Emergency Operations’
“I hope that our western partners won’t put a spanner in the works and will think about the people who desperately need supplies of electricity and water to resume, elementary medicines to be available in hospitals so children can have emergency operations,” Russian Foreign Minister Sergei Lavrov told reporters in the Russian Black Sea resort of Sochi.
U.S. President Barack Obama backed the plan for an aid mission in a phone call, his Ukrainian counterpart, Petro Poroshenko, said in a statement on his website.
Russia’s Micex equities index rose 1.8 percent in Moscow yesterday, the most in six weeks on speculation the tension is easing.
Putin discussed the planned aid convoy with European Commission President Jose Barroso in a phone call yesterday.
“President Putin told President Barroso that the Russian side would cooperate with international humanitarian organizations to deliver the aid,” Michael Jennings, a spokesman for the Brussels-based commission, said in an e-mail.
‘Any Pretext’
The EU said in a statement that Barroso warned the Russian leader “against any unilateral military actions in Ukraine, under any pretext, including humanitarian.”
Barroso also “expressed concern at the gathering of Russian troops near the Ukrainian border, as well as the continuing flow of arms, equipment and militants from Russian territory, which run counter to efforts towards de-escalating the crisis,” according to the statement.
“We see the Russians developing the narrative and the pretext for such an operation under the guise of a humanitarian operation and we see a military buildup that could be used to conduct such illegal military operations in Ukraine,” North Atlantic Treaty Organization Secretary General Anders Fogh Rasmussen said in an interview with Reuters.
The massing of soldiers and the threats of unilateral humanitarian aid delivery are potentially very dangerous and destabilizing, a senior U.S. State Department official said yesterday on condition of anonymity, citing policy.
“Putin wants to liquidate Ukraine as an independent state and is looking for a good excuse for it,” Vadim Grechaninov, who heads the Atlantic Council of Ukraine, a military research group, said by phone. “But it seems now it’s not the best moment for him: a humanitarian mission does not provide the excuse.”
‘Pushing Ahead’
Inhabitants of Donetsk and Luhansk, which were home to 1.5 million people before the pro-Russian insurgency began, should leave via humanitarian corridors, Ukrainian military spokesman Andriy Lysenko told reporters in Kiev.
“The operation to encircle these cities is almost over,” he said. “The active operation continues day and night. We’re pushing ahead and aren’t stopping.”
As the crisis intensified, the government in Moscow responded to sanctions last week by banning Ukrainian, American and EU food imports.
Ukraine, which stopped receiving Russian gas in June though acts as a conduit for supplies to Europe, may hit back at the Russian sanctions with a “complete or partial” ban on energy shipments, Prime Minister Arseniy Yatsenyuk said last week.
State-owned NAK Naftogaz Ukrainy said in an e-mailed statement yesterday it may ban gas transit by certain companies, a step that might force European purchasers to buy natural gas at the Russian frontier. Russia has said it will retaliate if new measures against it are approved.
To contact the reporters on this story: Ilya Arkhipov in Sochi, Russia at iarkhipov@bloomberg.net; Kateryna Choursina in Kiev at kchoursina@bloomberg.net; Volodymyr Verbyany in Kiev at vverbyany1@bloomberg.net
To contact the editors responsible for this story: Balazs Penz at bpenz@bloomberg.net; James M. Gomez at jagomez@bloomberg.net Eddie Buckle
Chevron said Thursday it had reduced its expatriate staff in the northern Iraqi region of Kurdistan as the jihadist onslaught in Iraq by Islamic State fighters continued to gather pace, closing in on the Kurdish region. “We have reviewed the business-critical expatriate positions and as a consequence made a reduction in the total numbers of expatriates in the region,” a spokeswoman said in a statement. IS earlier Thursday seized Iraq’s largest Christian town and surrounding areas, sending tens of thousands of panicked residents fleeing, AFP reported. The onslaught saw the Sunni extremists extend their writ over northern Iraq and move within striking distance of autonomous Kurdistan, in one of the most dramatic developments of the two month-old conflict. Chevron is one of around 50 foreign oil companies with contracts to develop oil resources in Kurdistan. The US company made its first entry into the Kurdish oil sector in July 2012, buying out the Rovi and Sarta blocks from India’s Reliance Industries. It expanded its presence in the region in June last year, taking over the Qara Dagh block from Canada-listed Niko Resources. Shares in a number of Kurdish oil producers have slumped this week as fears that the IS onslaught would spread to Kurdistan intensified. Earlier Thursday, UK-listed Gulf Keystone Petroleum said its operations in Kurdistan were under no immediate threat (See story, 1448 GMT). But the company’s shares closed down more than 11% at GBP0.68.
Federal Energy Regulatory Commissioner John Norris Thursday said he would leave the commission later this month, following months of speculation about his early exit. “It has been a great honor to serve with all the exceptional professionals and public servants who make up the FERC family and so many dedicated energy stakeholders in the public and private sectors,” Norris said in a statement. Norris will resign effective August 20 and will then take a position as the minister counselor for the US Department of Agriculture in Rome, he said. Norris’ term was to end in June 2017. In April, he told Platts he had no “immediate plans to leave” despite his view that the politics around those who sit on the commission during critical periods were “immensely frustrating.” At the time, sources said he could leave as early as June or July. Last week, sources said that Norris’ departure could be imminent. At the time, an aide to Norris declined to comment on the matter. With Norris leaving, attention now turns to the soon-to-be-open seat at FERC, with early speculation that Colette Honorable, an Arkansas regulator and the current president of the National Association of Regulatory Utility Commissioners, is likely in the lead for that position. A spokesman for Honorable did not immediately respond to a request for comment.
Canadian Natural Resources will add 80,000 b/d of new oil sands production at its Kirby projects in Alberta by late 2016, and remains on track to more than double synthetic crude oil output from its Horizon project to 250,000 b/d by 2018, CEO Steve Laut said Thursday. The reservoir at Kirby South is responding as expected and output will reach full capacity of 40,000 b/d by the first quarter of 2015, he said on a webcast to discuss the company’s second quarter earnings. Output from Kirby South averaged 15,000 b/d in the second quarter, Laut said. For the 40,000 b/d Kirby North, detailed engineering work on the central processing facility is complete, with the company planning to inject first steam into the well pads in fourth quarter 2016, he said, adding the project will entail the construction of 56 well pairs. With a price tag of C$1.45 billion ($1.42 billion) or C$36,000/flowing barrel, Kirby North remains on schedule and within budget, he said. Flowing barrel includes construction costs and sustaining capital and operating expenditure. Kirby South and Kirby North projects are part of CNR’s plans to develop its greater Kirby area in northern Alberta, with the aim of ultimately producing 140,000 b/d in the longer-term. The company is also planning to develop yet another facility, called Grouse, with a capacity of 40,000 b/d, “We will be more cost-focused, rather than schedule-focused,” Laut said. “Capital costs are coming under slight pressure in Alberta, but the industry is learning to deal with an inflationary environment by carrying out projects in smaller size and capacity.” CNR is already reaping the benefits of adopting new project and construction management tools, with Phase 2A of its flagship Horizon oil sands and upgrader facility being completed ahead of schedule and within budget, Laut said without giving any figures. The project with a nameplate capacity of 110,000 b/d is being expanded to 250,000 b/d in stages at an estimated cost of C$2.5 billion. Overall, 42% of construction work on phases 2 and 3 is complete, Laut said, adding during the second quarter output from Horizon was 119,200 b/d.
Sunoco Logistics’ planned pipeline to transport crude from the Permian Basin east to Louisiana will use a mix of existing and new pipeline to give Gulf Coast refiners in Texas and Louisiana access to growing Permian Basin production, the company said Thursday. The 100,000 b/d Permian Longview and Louisiana Extension project, which will carry West Texas Sour and West Texas Intermediate, is expected to begin operations in the second half of 2016, according to an open season notice released Wednesday by Sunoco. The project will be comprised of Sunoco’s Mid-Valley pipeline to Garden City, Texas, and another Sunoco propriety line to Corsicana, Texas. The project will also build 75 miles of new pipeline between Corsicana and Tyler, Texas. From Tyler, the crude will flow along ExxonMobil’s North Line for distribution in Louisiana, Sunoco CEO Mike Hennigan said Thursday during the company’s earnings conference call. Additionally, the pipeline will provide Permian crude access to Texas Gulf Coast refiners via existing pipeline connections to the Nederland terminal near Port Arthur. Platts unit Bentek Energy projects August Permian crude production at 1.7 million barrels with pipeline capacity out of the region and local refinery needs at 2 million b/d. Open season for firm shipping commitments began Thursday, with Sunoco soliciting bids for five-, seven-, and 10-year term contracts. Companies must submit a confidentiality agreement to receive open season documents. While Sunoco specified no specific deadline for the open season, it recommends that shippers submit their confidentiality agreements by August 20. Shippers who commit during the open season are eligible for incentives like discount rates.
Argentine customs workers said Thursday they will go on strike Friday and then again for 48 hours next week, a measure that will halt the import and export of oil, liquid fuels, natural gas and biodiesel. The Unique Union of Argentine Customs Workers, or SUPARA, called the strike to demand higher wages in the face of 35% annual inflation after the government to respond to their demands following two strikes in July, according to a statement. The state employees will walk off the job Friday and again on August 14 and 15, leaving a minimum staff on call for emergency situations. The Argentine Chamber of Port and Maritime Activities said any strikes involving customs workers halts international trade, including of energy supplies. The labor tension with custom workers, who are employed by the state, comes as energy demand surges during the Southern Hemisphere winter, led by gas for heating. The country has been importing rising amounts of gas to compensate for sagging domestic production. The latest Energy Secretariat data shows gas imports rose 2.7% to 42.6 million cubic meters/d in June, or 34% of the 126 million cu m/d average consumption, from 41.5 million cu m/d in the year-earlier period. Of this, about 60% was liquefied natural gas and the rest came in by pipeline from Bolivia. Argentina also has been importing more crude, diesel and gasoline supplies to offset falling domestic production and limited refining capacity.
Horizontal rigs in the US jumped by another 19 for the week ended Friday to 1,317, besting the prior record of 1,298 set last week, Baker Hughes said in its weekly report. Directional rigs fell by five to 213, while vertical rigs rose by five to 378. Horizontal rigs are used mainly in unconventional and shale fields in North America. In the US, the Permian Basin of West Texas and southeastern New Mexico is expected to take up a large chunk of new state-of-the-art land rigs now under construction, but other fields where horizontal rigs are plentiful include the Eagle Ford Shale in South Texas, the Bakken Shale in North Dakota and Montana, the Niobrara Shale in Colorado, the Marcellus Shale in Pennsylvania and West Virginia, the Utica Shale in Ohio and many smaller emerging basins. The US oil and gas rotary rig count rose by 19 to 1,908 for the week ending Friday, up 130 from 1,778 in the comparable week a year ago. The number of US gas rigs operating in the most recent week rose by three to 316. The oil rig count rose by 15 for the week to 1,588. There are four miscellaneous rigs, up one from three the prior week, but down three from seven a year ago, according to Baker Hughes data. Canada’s rig count for the week fell by five to 387, which is up 29 from 358 in the corresponding week of last year. Canada’s oil rig total was 222, down four, while gas rigs were at 165, down one from the week before. There were no miscellaneous rigs in Canada, unchanged from the prior week and prior year.
Canadian independent Enerplus has raised its 2014 light oil and gas production target to 100,000 to 104,000 barrels of oil equivalent/day from the 96,000 to 100,000 boe/d it projected in February, CEO Ian Dundas said Friday. In a second-quarter earnings webcast, Dundas said the upward revision was based largely on record Q2 output of 103,987 boe/d, compared with 90,037 boe/d in the same period of 2013. Of the Q2 production, crude accounted for 39,863 b/d, NGL output was 3,636 b/d and natural gas production averaged 362,929 Mcf/d. Dundas said production from the company’s assets in North Dakota and Marcellus Shale were the main drivers of Q2 output. Enerplus said its average Q2 sale prices were $94.90/b for crude, $49.98/b for NGLs and C$4.02/MMBtu for natural gas, compared with C$82.95/b, C$45.64/b and C$3.70/MMBtu, respectively, in the year-ago period. The company holds about 75,000 acres of tight oil assets at Fort Berthold, North Dakota and Three Forks in the Bakken play spread over Alberta, Saskatchewan and Manitoba and 110,000 acres in the Marcellus. It also has working interests in the liquids-rich plays at Montney, Mannville and Duvernay in Alberta and British Columbia. In the second quarter, the company spent C$204 million to drill 14 wells, Dundas said, with oil and NGL output in Canada and the US. In the Marcellus, Enerplus said it is continuing to struggle with challenges posed by the lack of pipeline takeaway capacity, but is hoping the situation will improve, Eric Le Dain, Enerplus’ senior vice president for corporate development, said. He said the company expects that between late 2014 and 2016, pipelines will add 3.5 Bcf/d of capacity. Gerry Goobie, a principal with infrastructure consultant Gas Processing Management, on Friday said that with production of about 15 Bcf/d and growing, the Marcellus output will likely soon surpass that of Canada. But he said the lack of pipeline capacity is affecting the pricing dynamics of producers, including Enerplus.
Following a a recent turnaround at its 73,000 b/d Big Spring refinery in Texas, Alon USA Energy is now about to embark on a naphtha-gasoline blending project enable it to run more light, sweet West Texas Intermediate crude there, the company’s CEO said Friday. Cost of the project and when it will occur were not immediately available, although it shouldn’t have a “tremendously big” price tag, said CEO Paul Eisman during a quarterly earnings conference call. Big Spring “continues to benefit from weakness in Midland priced crude oil; in July and August we’ve seen discounts in excess of $8/b in Midland relative to WTI [West Texas Intermediate crude] at Cushing,” Eisman said. Refinery economics dictate the running of as much light, sweet crude as possible, he said. Due to the refinery’s West Texas location it has been running a lot of Midland-based crude from the Permian, where production of 1.7 million b/d has been surging in recent years. Coming out of the turnaround, which was concluded a month ago and increased the refinery’s throughput by 3,000 b/d, “we’re making a little less naphtha” because of an inability to process or reform that product, Eisman said. Alon deals with that currently by running a little more sour crude and a little less sweet, he said. “But we can debottleneck that by blending naphtha directly into gasoline, which allows us to run more WTI,” Eisman added. Going forward, Alon will look at other projects to allow it more flexibility for running light, sweet WTI, particularly from the Permian Basin where oil output is fast increasing and now stands at around 1.7 million b/d, about double what it was in mid-2007, he said. With the price differential between sweet and sour crudes in Texas, sweet is “really a disadvantaged crude,” Eisman added. “We’d like to take advantage of as much of it as possible.” Alon was making $20/b on each barrel it gets through the refinery, adding there is probably a $3/b-$5/b optimization around sweet to sour, Eisman said. In recent quarters, the company has run its most-ever sweet crude at Big Spring. But to get to a point of using 100% light, if the economics point that way, will require some investments in the refinery.
Horizontal rigs in the US jumped by another 19 for the week ended Friday to 1,317, besting the prior record of 1,298 set last week, Baker Hughes said in its weekly report. Directional rigs fell by five to 213, while vertical rigs rose by five to 378. Horizontal rigs are used mainly in unconventional and shale fields in North America. In the US, the Permian Basin of West Texas and southeastern New Mexico is expected to take up a large chunk of new state-of-the-art land rigs now under construction, but other fields where horizontal rigs are plentiful include the Eagle Ford Shale in South Texas, the Bakken Shale in North Dakota and Montana, the Niobrara Shale in Colorado, the Marcellus Shale in Pennsylvania and West Virginia, the Utica Shale in Ohio and many smaller emerging basins. The US oil and gas rotary rig count rose by 19 to 1,908 for the week ending Friday, up 130 from 1,778 in the comparable week a year ago. The number of US gas rigs operating in the most recent week rose by three to 316. The oil rig count rose by 15 for the week to 1,588. There are four miscellaneous rigs, up one from three the prior week, but down three from seven a year ago, according to Baker Hughes data. Canada’s rig count for the week fell by five to 387, which is up 29 from 358 in the corresponding week of last year. Canada’s oil rig total was 222, down four, while gas rigs were at 165, down one from the week before. There were no miscellaneous rigs in Canada, unchanged from the prior week and prior year.
Canadian independent Enerplus has raised its 2014 light oil and gas production target to 100,000 to 104,000 barrels of oil equivalent/day from the 96,000 to 100,000 boe/d it projected in February, CEO Ian Dundas said Friday. In a second-quarter earnings webcast, Dundas said the upward revision was based largely on record Q2 output of 103,987 boe/d, compared with 90,037 boe/d in the same period of 2013. Of the Q2 production, crude accounted for 39,863 b/d, NGL output was 3,636 b/d and natural gas production averaged 362,929 Mcf/d. Dundas said production from the company’s assets in North Dakota and Marcellus Shale were the main drivers of Q2 output. Enerplus said its average Q2 sale prices were $94.90/b for crude, $49.98/b for NGLs and C$4.02/MMBtu for natural gas, compared with C$82.95/b, C$45.64/b and C$3.70/MMBtu, respectively, in the year-ago period. The company holds about 75,000 acres of tight oil assets at Fort Berthold, North Dakota and Three Forks in the Bakken play spread over Alberta, Saskatchewan and Manitoba and 110,000 acres in the Marcellus. It also has working interests in the liquids-rich plays at Montney, Mannville and Duvernay in Alberta and British Columbia. In the second quarter, the company spent C$204 million to drill 14 wells, Dundas said, with oil and NGL output in Canada and the US. In the Marcellus, Enerplus said it is continuing to struggle with challenges posed by the lack of pipeline takeaway capacity, but is hoping the situation will improve, Eric Le Dain, Enerplus’ senior vice president for corporate development, said. He said the company expects that between late 2014 and 2016, pipelines will add 3.5 Bcf/d of capacity. Gerry Goobie, a principal with infrastructure consultant Gas Processing Management, on Friday said that with production of about 15 Bcf/d and growing, the Marcellus output will likely soon surpass that of Canada. But he said the lack of pipeline capacity is affecting the pricing dynamics of producers, including Enerplus.
Following a a recent turnaround at its 73,000 b/d Big Spring refinery in Texas, Alon USA Energy is now about to embark on a naphtha-gasoline blending project enable it to run more light, sweet West Texas Intermediate crude there, the company’s CEO said Friday. Cost of the project and when it will occur were not immediately available, although it shouldn’t have a “tremendously big” price tag, said CEO Paul Eisman during a quarterly earnings conference call. Big Spring “continues to benefit from weakness in Midland priced crude oil; in July and August we’ve seen discounts in excess of $8/b in Midland relative to WTI [West Texas Intermediate crude] at Cushing,” Eisman said. Refinery economics dictate the running of as much light, sweet crude as possible, he said. Due to the refinery’s West Texas location it has been running a lot of Midland-based crude from the Permian, where production of 1.7 million b/d has been surging in recent years. Coming out of the turnaround, which was concluded a month ago and increased the refinery’s throughput by 3,000 b/d, “we’re making a little less naphtha” because of an inability to process or reform that product, Eisman said. Alon deals with that currently by running a little more sour crude and a little less sweet, he said. “But we can debottleneck that by blending naphtha directly into gasoline, which allows us to run more WTI,” Eisman added. Going forward, Alon will look at other projects to allow it more flexibility for running light, sweet WTI, particularly from the Permian Basin where oil output is fast increasing and now stands at around 1.7 million b/d, about double what it was in mid-2007, he said. With the price differential between sweet and sour crudes in Texas, sweet is “really a disadvantaged crude,” Eisman added. “We’d like to take advantage of as much of it as possible.” Alon was making $20/b on each barrel it gets through the refinery, adding there is probably a $3/b-$5/b optimization around sweet to sour, Eisman said. In recent quarters, the company has run its most-ever sweet crude at Big Spring. But to get to a point of using 100% light, if the economics point that way, will require some investments in the refinery.
For the second time in two weeks a state judge in Colorado has overturned a city’s attempt to regulate hydraulic fracturing within its borders. In a Thursday decision in the District Court of Larimer County, Judge Gregory Lammons ruled that the city of Fort Collins’ five-year ban on the use of fracking and the storage of fracking waste was pre-empted by the state’s Oil and Gas Conservation Act. Lammons’ ruling comes in a case brought by the Colorado Oil and Gas Association, following a vote last November in which voters called for the city to impose a five-year moratorium on fracking and disposal of fracking waste within the city’s boundaries. On July 24, District Judge D.D. Mallard of the Boulder County District Court overturned a fracking ban that the city of Longmont had instituted, ruling that it was pre-empted by the Colorado Oil and Gas Conservation Act, which gives the state primary authority over oil and gas operations. The Fort Collins decision also come as Colorado’s political, business and civic leaders are grappling with a host of issues arising from the growing phenomenon of oil and gas drilling being conducted close to cities and towns. On Wednesday, Governor John Hickenlooper announced the creation of an 18-member task force to examine the issues and to recommend solutions to the state legislature. Hickenlooper’s actions came as part of a deal with environmental groups and community advocates to drop two statewide ballot initiatives that would have increased municipalities’ power to regulate oil and gas operations. As part of that deal, state officials also agreed to drop a lawsuit the state had filed against the city of Longmont, challenging that municipality’s oil and gas drilling regulations. In his decision, Lammons granted COGA’s motion for summary judgment, while denying a similar motion filed by Fort Collins’ attorneys. The ruling was “a clear and unequivocal victory for Coloradans,” COGA President Tisha Schuller said in a statement. Schuller said Lammons in his ruling “went even further than previous court rulings,” saying plainly that Fort Collins’ ban “substantially impedes the state’s significant interest in fostering efficient and equitable oil and gas production.”
State-owned Argentinian firm YPF is pushing ahead with a drilling program to boost hydrocarbon production and does not expect to seek new partners in the near term, chief financial officer Daniel Gonzalez said Friday. “We don’t need further shale partnerships at this stage,” he said in a conference call with investors. Gonzalez said talks are continuing with state-owned Malaysian oil company Petronas on a partnership for developing oil and natural gas resources in the giant Vaca Muerta shale play in southwest Argentina. But he added: “We are not in conversations for other shale partnerships.” Gonzalez said this is part of a strategy to farm out areas in the development stage and not sell acreage too early in the exploration process. YPF has already entered a $16 billion partnership with Chevron to develop shale resources in Vaca Muerta, where they produced an average of 23,200 b/d of oil equivalent in the second quarter of 2014. Of that, 13,600 b/d was crude, 4,900 b/d was natural gas liquids and 800,000 cu m/d natural gas. Smaller shale and tight play development joint ventures are under way with Dow Chemical and Argentina’s Pampa Petrolera and Pluspetrol. Concerns have swelled in recent weeks that a weakening economy could hurt investment in the oil sector and make it harder for YPF to meet targets of increasing its oil and gas production by 5% and 18%, respectively, this year compared with 2013. Argentina failed to complete a $539 million interest payment on bonds by the July 30 expiration of a 30-day grace period, pushing it into its second default in 13 years. The government could not complete the payment because a US court ordered it to pay plaintiff creditors at the same time. These plaintiffs won a lawsuit to be paid $1.5 billion on bonds left over from the 2001 default on $100 billion of debt, and the judge hearing the case said that if they are not paid then payments on Argentinian US-law bonds cannot be made. Analysts warn that a dragged-out default could depress the investment environment and push the country deeper into recession.
Prepared by James Bambino, Platts Oil Futures & Options Editor
New York - August 11, 2014
Platts Survey of Analysts
Crude oil stocks down 2 million barrels
Gasoline stocks down 1.5 million barrels
Distillate stocks up 250,000 barrels
Refinery utilization, or run rate, down 0.9 percentage point to 91.5% (EIA)
U.S. commercial crude oil stocks are expected to have fallen 2 million barrels during the reporting week ended August 8, according to a Platts analysis and survey of oil analysts Monday.
The American Petroleum Institute (API) will release its weekly report at 4:30 p.m. EDT (2030 GMT) Tuesday, and the U.S. Energy Information Administration (EIA) is scheduled to release its weekly data at 10:30 a.m.EDT Wednesday.
The drop in stocks is expected to be a product of still-strong crude oil runs, even as analysts expect utilization rates to have fallen by 0.9 percentage point. At 16.39 million barrels per day (b/d) the week ended August 1, a drop of near 1 percentage point would still keep runs above 16 million b/d for the seventh straight week.
Platts data shows a leak in a catalytic light ends unit at ExxonMobil's 584,000 b/d Baytown, Texas, refinery led to a slight production decline last weekend. This impact could be mitigated by the restarting of a fluid catalytic cracker at Citgo's 165,000 b/d East Plant refinery in Corpus Christi.
Crude oil imports, meanwhile, are unlikely to have rallied the week ended August 8, as both Canadian and Saudi barrels were at the upper range of recent activity for the week ended August 1. U.S. imports of Canadian crude oil were pegged at 2.78 million b/d, highest in four weeks. Strong coking margins for heavy Canadian grades will likely keep this figure elevated, though. U.S. Midwest coking margins for Western Canadian Select hit nearly $27per barrel (/b) Friday, more than $4/b above the 30-day moving average for the grade.
Platts margins reflect the difference between a crude oil's netback and its spot price. Netbacks are based on crude oil yields, which are calculated by applying Platts product price assessments to yield formulas designed by Turner, Mason & Co.
Meanwhile, imports of Saudi crude oil were around 1.23 million b/d, just below this summer's weekly high of 1.4 million b/d recorded the week ended July 11. Most Saudi barrels go on a term basis to the 600,000 b/d Saudi Aramco/Shell joint venture Motiva refinery in Port Arthur, Texas.
That said, if imports rallied, they would likely come from Mexico. Mexican imports were pegged at just 582,000 b/d for the week ended August 1, down from around 1 million b/d the week prior, EIA data shows.
Coking margins for Mexican Maya on the U.S. Gulf Coast (USGC) averaged just over $9/b the week ended August 8, in line with the 30-day moving average. However, margins did rise toward the end of the week, hitting $10.52/b Thursday, largely due to stronger product prices.
Platts cFlow ship-tracking software shows one Aframax -- Genmar Daphne -- entered the USGC the week ended August 8, laden with crude oil, from Mexico. The ship has a capacity of around 600,000 barrels.
Imports from Nigeria, meanwhile, have been nil for six out of the last seven reporting weeks, according to EIA data. And while cFlow does not show any signs of this having changed the week ended August 8, relatively strong USGC cracking margins for Nigerian crude oils could entice more imports should the economics hold up.
Cracking margins for Bonny Light and Brass River were $9.15/b and $5.88/b Friday -- both above their respective 30-day moving averages. But these numbers are still below comparable domestic grades like Bakken and Louisiana Light Sweet (LLS). Bakken cracking margins were more than $11/b Friday, while LLS margins were above $12.50/b.
GASOLINE SUPPLY TIGHT
U.S. gasoline stocks are expected to have fallen by 1.5 million barrels the week ended August 8, according to analysts. At nearly 214 million barrels the week ended August 1, U.S. gasoline stocks were almost 1 percent below the five-year average of EIA data.
With implied demand* pegged at 9.36 million b/d for that same reporting week, some analysts expect the remainder of the summer to be bullish for New York Mercantile Exchange (NYMEX) RBOB.
Stocks on the U.S. Atlantic Coast (USAC) -- home to the New York Harbor-delivered RBOB contract -- are tightening as well. At 58.42 million barrels, stocks are just 2% above the five-year average, but more than 3.2 million barrels below year-ago levels.
Weak prices, in both spot and futures, have disincentivized gasoline and blending component imports to the USAC this summer. Imports were pegged at just 412,000 b/d for the week ended August 1, the lowest since mid-April and down nearly 42% year-over-year. Front-month RBOB broke below $2.70 per gallon on August 5, the lowest-traded level since February, when RBOB was in its pre-summer ascendancy.
"The lower prices of gasoline are increasing the demand," Oil Outlooks President Carl Larry said. "We've spent so much time in the past decade talking about demand destruction. It's about time we get on with demand construction. We're into the home stretch of vacation demand that culminates at Labor Day, so retailers are stocking up."
Although cFlow shows no clean cargoes entered the USAC from Europe the week ended August 8, six tankers, laden or part-laden with clean products, are set to arrive late this week and next week. This could mitigate much of any increased tightness seen with a draw in USAC stocks in this week's data.
Meanwhile, analysts expect U.S. distillate stocks to have increased 250,000 barrels the week ended August 8. At 124.9 million barrels for the week ended August 1, U.S. distillate stocks are more than 14% below the EIA five-year average.
But inventories often tighten with increased exports. The EIA estimates U.S. distillate exports have been above 1 million b/d for the past seven weeks. The more accurate monthly data for May pegs exports at 1.17 million b/d.
* Implied demand is the amount of product that moves through the U.S. distribution system, not actual end consumption.
Libyan oil output highest since January
By Daniel J. Graeber | Aug. 8, 2014 at 10:07 AM | 0 Comments (Leave a comment)
VIENNA, Aug. 8 (UPI) -- Libyan oil production is at its highest level since the beginning of the year, the Organization of Petroleum Exporting Countries said Friday.
OPEC said in its latest monthly market report crude oil production from member states averaged 29.9 million barrels per day. Production fell primarily in member states Iraq and Angola, while production increased from Libya and Saudi Arabia.
Libyan Prime Minister Abdullah al-Thinni told U.S. Secretary of State John Kerry in Washington his government "has managed to solve" the oil crisis plaguing what was once one of North Africa's top oil producers.
OPEC said in its market report Libyan crude oil production has doubled since June.
"Libyan production rose past 500,000 barrels per day for the first time since January," the report said.
OPEC data show Libyan crude oil production reached a post-war peak of around 1.4 million bpd in 2013, before starting a precipitous decline toward the historic low of 213,000 bpd in March.
Libya's new parliament met for the first time Monday about 900 miles east of Tripoli, where pro-government forces are battling heavily armed militias.
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Business » ENERGY | August 11, 2014, Monday // 16:56| Views: 598 | Comments: 0
Bulgaria: Iran Ready to Bring Gas Supplies to Europe via Nabucco Photo by BGNES
Iran has expressed willingness to supply gas to Europe via the Nabucco gas pipeline.
Ali Majedi, Deputy Oil Minister in charge of International Affairs, announced that two European countries had already expressed interest in the project.
Majedi, as cited by ITAR-TASS, suggested that Iran, the country controlling the world's biggest gas reserves, could support Europe's attempts to diversify its energy supply sources by covering a part of its needs.
He added that Iran had discussed possible gas supply routes with two European delegations.
Majedi argued that there was a wide range of possible supply routes for Iranian gas to Europe, including via Turkey, Iraq, Syria, Caucasus and the Black Sea.
He insisted, however, that the best option involved a gas pipeline through Turkey.
He was adamant that the Nabucco gas pipeline would be useless without Iranian gas, adding that Turkey had already expressed interest in Iranian gas exports to Europe.
Nabucco shareholders include Austria's OMV, Hungary's MOL, Romania's Transgaz, Bulgaria's Bulgargaz, Turkey's BOTAS, and Germany's RWE.
All Rights Reserved © Novinite JSC., 2001-2014
Washington (Platts)--11Aug2014/522 pm EDT/2122 GMT
Pricey condensate splitter plans appear to be on track despite recent US rulings expected to create a surge in exports of condensate, which needs to be processed, but not through splitters.
However, uncertainty over export policy could ultimately impact some plans.
The splitter picture is "still developing," Barclays analyst Michael Cohen said, adding that projects beyond 2015 may be the most at risk.
It remains unclear, Cohen said, how much market there is for splitter-made products such as propane and ethane, as opposed to demand for processed condensate, which a firm could export directly from a field condensate stabilizer.
"Until there's a little more clarity around the regulatory issue, in addition to the market issue, then I don't think these projects are likely to continue to be put online at the pace people think," Cohen said.
This uncertainty was on display during earnings calls, where company executives revealed that while they were still planning to build condensate splitters, those plans could be altered by the US Department of Commerce's decision to allow Pioneer Natural Resources and Enterprise Products Partners to export processed condensate. Commerce ruled this condensate could be exported without a license because it was lightly refined in a distillation tower and no longer fell within the definition of crude oil.
"I think as far as future splitters are concerned, it's going to make the potential people who utilize those splitters probably think carefully about whether they want to proceed," Kinder Morgan CEO Richard Kinder said. He noted his company's plans to build a 100,000 b/d splitter on the Houston Ship Channel are still on track.
Joe McCreery, a vice president with Martin Midstream Partners, said that due to the recent Commerce rulings, Midstream's plans for a 50,000 b/d condensate splitter in the Corpus Christi, Texas, market "continues to evolve."
McCreery indicated that the splitter, estimated to cost $175 million-$200 million, is now being built to meet Commerce's "exportable standard," which the agency has not detailed publicly.
Citing national security concerns, Commerce has not made its condensate rulings public, and it remains unclear precisely how these firms are processing condensate through a distillation tower. It is clear, however, that this distillation processing can be launched quicker and far more cheaply than through a condensate splitter, which splits light oil into components such as naphtha and distillates.
A field condensate stabilizer, for example, would cost a few million dollars to build, have an operating cost of 50 cents-$1/barrel and can be built within a year, consultants Turner, Mason & Co. said. On the other hand, a condensate splitter could cost as much as $400 million, take nearly two years to build and have operating costs of $1-1.50/b.
While the US has only one dedicated condensate splitter facility, Total's 75,000 b/d splitter in Port Arthur, Texas, there are at least five projects proposed in Corpus Christi, Texas, and along the Houston Ship Channel.
Targa plans to bring a 35,000 b/d splitter online in 2016, and CEO Joe Bob Perkins said it expects to finalize permit details for that facility this quarter.
"Although we understand why outside interest is very high and we're getting questions about it, our splitter project is not impacted by the US Commerce Department's private letter rulings," Perkins said during an earnings call.
Still, the agency's orders have caused confusion within the refining industry and created a pause in investment decisions, Marathon Petroleum CEO Gary Heminger said. Marathon plans to build a 25,000 b/d condensate splitter in Canton, Ohio, and a 35,000 b/d splitter in Catlettsburg, Kentucky.
"We believe that our industry has the ability to handle much more of the light shale crude oil and condensate than is processed today," Heminger said during an earnings call. "But the investments to do so will not likely be made in the environment of uncertainty that has been created."
Michael Mears, CEO of Magellan Midstream Partners, said Magellan was ensuring the profitability of its planned 50,000 b/d Corpus Christi splitter amid export uncertainty through creative contracting.
"The nature of that contract provides customers the right to renew upon expiry at considerably lower rates, which we believe will be attractive regardless of our nation's stance on condensate export capabilities," Mears said on an earnings call, adding that while it was not seeking its own export approval, it was aware of potential customers seeking their own.
Several companies are waiting on similar rulings from Commerce like those that Pioneer and Enterprise received, and some are seeking assurances they can export their own condensate without a license.
The interest in exporting processed condensate may also create an increase in demand for more infrastructure to move this condensate as well as for new distillation units to meet Commerce's processing requirements.
"It hasn't yet come to the scale of materiality in what we see from a bookings perspective, I want you to be clear," Bradley Childers, CEO of midstream company Exterran Holdings, said during an earnings call. "But there definitely is a shift and some interest in those products, as a result of the possibility for export."
--Brian Scheid, brian.scheid@platts.com --Edited by Annie Siebert, ann.siebert@platts.com
New York (Platts)--11Aug2014/252 pm EDT/1852 GMT
* Refinery runs expected to have fallen 0.9 percentage point * But should still be over 16 million b/d for seventh-straight week * Strong WCS coking margins should keep Canadian imports flowing * Mexican imports could rally amid solid Maya coking economics * Gasoline stocks expected to slide 1.5 million barrels US commercial crude stocks are expected to have fallen 2 million barrels for the reporting week ended August 8, according to a Platts analysis and survey of oil analysts Monday.
The American Petroleum Institute will release its weekly report at 4:30 pm EDT (2030 GMT) Tuesday, and the US Energy Information Administration is scheduled to release its weekly data at 10:30 am EDT Wednesday.
The drop in stocks is expected to be a product of still-strong crude runs, even as analysts expect utilization rates to have fallen by 0.9 percentage point. At 16.39 million b/d for the week ended August 1, a near-1 percentage point drop would still keep runs above 16 million b/d for the seventh-straight week.
Platts data shows a leak in a catalytic light ends unit at ExxonMobil's 584,000 b/d Baytown, Texas, refinery led to a slight production decline last weekend. This impact could be mitigated by the restarting of an FCC at Citgo's 165,000 b/d East Plant refinery in Corpus Christi.
Crude imports, meanwhile, are unlikely to have rallied last week, as both Canadian and Saudi barrels were at the upper range of recent activity for the week ended August 1. US imports of Canadian crude were pegged at 2.78 million b/d, highest in four weeks. Strong coking margins for heavy Canadian grades will likely keep this figure elevated though. US Midwest coking margins for Western Canadian Select hit nearly $27/b Friday, more than $4/b above the 30-day moving average for the grade.
Platts margins reflect the difference between a crude's netback and its spot price. Netbacks are based on crude yields, which are calculated by applying Platts product price assessments to yield formulas designed by Turner, Mason & Co.
Meanwhile, imports of Saudi crude were around 1.23 million b/d, just under this summer's weekly high 1.4 million b/d for the week ended July 11. Most Saudi barrels go on a term basis to the 600,000 b/d Saudi Aramco/Shell joint venture Motiva refinery in Port Arthur, Texas.
That said, if imports were to rally they would likely come from Mexico. Mexican imports were pegged at just 582,000 b/d for the week ended August 1, down from near 1 million b/d the week prior, EIA data shows.
Coking margins for Mexican Maya on the US Gulf Coast averaged just over $9/b last week, in line with the 30-day moving average. However, margins did rise toward the end of the week, hitting $10.52/b Thursday, largely due to stronger product prices.
Platts cFlow ship-tracking software shows one Aframax -- Genmar Daphne -- entered the USGC last week, laden with crude, from Mexico. The ship has a capacity of around 600,000 barrels.
Imports from Nigeria, meanwhile, have been nil for six out of the last seven reporting weeks, according to EIA data. And while cFlow does not show any signs of this having changed last week, relatively strong USGC cracking margins for Nigerian crudes could entice more imports should the economics hold up.
Cracking margins for Bonny Light and Brass River were $9.15/b and $5.88/b Friday -- both above their respective 30-day moving averages. But these numbers are still below comparable domestic grades like Bakken and Louisiana Light Sweet. Bakken cracking margins were more than $11/b Friday, while LLS margins were over $12.50/b. GASOLINE SUPPLY TIGHT
US gasoline stocks are expected to have fallen by 1.5 million barrels last week, according to analysts. At nearly 214 million barrels for the week ended August 1, US gasoline stocks were almost 1 percent below the five-year average of EIA data.
With implied demand pegged at 9.36 million b/d for that same reporting week, some analysts expect the remainder of the summer to be bullish for NYMEX RBOB.
Stocks on the US Atlantic Coast -- home to the New York Harbor-delivered RBOB contract -- are tightening as well. At 58.42 million barrels, stocks are just 2% above the five-year average, but more than 3.2 million barrels below year-ago levels.
Weak prices, both spot and futures, have disincentivized gasoline and blending component imports to the USAC this summer. Imports were pegged at just 412,000 b/d for the week ended August 1, lowest since mid-April and down nearly 42% year-on-year. Front-month RBOB broke below $2.70/gal on August 5, the lowest traded-level since February, when RBOB was in its pre-summer ascendancy.
"The lower prices of gasoline are increasing the demand," Oil Outlooks President Carl Larry said. "We've spent so much time in the past decade talking about demand destruction, it's about time we get on with demand construction. We're into the home stretch of vacation demand that culminates at Labor Day, so retailers are stocking up."
Although cFlow shows no clean cargoes entered the USAC from Europe last week, six tankers, laden or part-laden with clean products, are set to arrive late this week and next week. This could mitigate much of any increased tightness seen with a draw in USAC stocks in this week's data.
Meanwhile, analysts expect US distillate stocks to have increased 250,000 barrels last week. At 124.9 million barrels for the week ended August 1, US distillate stocks are more than 14% below the EIA five-year average.
But inventories often tighten with increased exports. The EIA estimates US distillate exports have been above 1 million b/d for the past seven weeks. The more accurate monthly data for May pegs exports at 1.17 million b/d.
--James Bambino, james.bambino@platts.com --Edited by Richard Rubin, richard.rubin@platts.com
London (Platts)--11Aug2014/941 am EDT/1341 GMT
The first crude loading in nearly a year has begun at the Ras Lanuf terminal in Libya, a local port agent told Platts Monday, giving the beleaguered North African country a much needed boost.
Ras Lanuf, whose capacity is 220,000 b/d, was occupied by anti-government forces in August 2013, and was only handed back to state-owned NOC last month after rebels reached a deal with Tripoli.
Tanker owners have been cautious about sending vessels to Libya as rival militant groups and government forces continue to clash around the capital Tripoli and in the east of the country.
The Gemini Sun Aframax tanker, owned by Zodiac Maritime, is currently loading a cargo at the terminal, with the charterer said to be Austria's OMV.
"The Gemini Sun is loading Sirtica crude at Ras Lanuf and should complete the loading by tomorrow morning," the agent said.
"The charterer is OMV. This is the first loading since the terminal re-opened but I believe there is another tanker coming as well," he said.
OMV declined to comment Monday.
According to the agent, the crude that is loading is storage barrels. "It's an oil cargo from storage," he said.
Traders also expect the nearby Es Sider terminal -- which has also been inoperational since August 2013 -- to resume loadings in the coming days.
PRODUCTION LIMITS
Earlier Monday, a senior NOC official said that it was proving difficult to ramp up Libya's production because of the lack of exports from the North African country.
This, the official said, meant its storage facilities at fields and at ports across its Mediterranean coast were filled to capacity.
Libya is currently producing between 450,000 b/d and 500,000 b/d of crude, but the official said the country could theoretically return output back to pre-crisis levels of around 1.5 million b/d.
"Libyan fields are ready to pump oil at its normal maximum capacity, and it doesn't face any problems except that we can't produce more since the storage tanks are full with crude oil," the official said.
"The storage tanks at Ras Lanuf and Es Sider have around 9 million barrels ready for companies to come and lift them," he said.
Libya had hoped to be able to ramp up output across the country, including at its recently restarted fields of Sharara and Elephant in the southwest of the country, but exports have been slow out of its Mediterranean ports.
This has prevented Libya from opening the taps further at its key producing fields.
"Sharara is not producing at full capacity since storage tanks there are full," the official said.
"Sharara is producing around 200,000 b/d."
Libyan production has been ramping up from lows of just 150,000 b/d in June, though it remains well below the 1.5 million b/d Libya was producing before the current spate of unrest began in May 2013.
--John Morley, john.morley@platts.com
--Stuart Elliott, stuart.elliott@platts.com
--Sherif Elhelwa, newsdesk@platts.com
--Edited by Alisdair Bowles, alisdair.bowles@platts.com
London (Platts)--11Aug2014/707 am EDT/1107 GMT
Saudi Arabia has told OPEC it boosted crude production to 10.005 million b/d in July, up 225,000 b/d from July and the highest monthly level since September 2013, when Riyadh told the oil producer group it pumped an average 10.123 million b/d.
The July figure also marks the first time Saudi production has been above 10 million b/d since September last year.
OPEC uses secondary sources to monitor crude production from its 12 member states but also publishes a table of figures provided directly by these countries. On Friday, OPEC published a secondary source estimate of 9.813 million b/d for Saudi Arabia but did not publish a directly submitted figure. The 10.005 million b/d has been added subsequently.
Saudi Arabia increases the volume of crude burned directly in power stations during the summer months.
--Margaret McQuaile, margaret.mcquaile@platts.com
--Edited by Alisdair Bowles, alisdair.bowles@platts.com
London (Platts)--11Aug2014/705 am EDT/1105 GMT
Differentials for Azerbaijan's Azeri Light are hovering at more than three-and-a-half year lows as the prolonged overhang of sweet crudes in the Atlantic Basin continues to put pressure on levels in the region.
On Friday, CIF Augusta Azeri Light cargoes were assessed at a $1.80/barrel premium to the Mediterranean Dated Strip, their lowest level relative to the 13-25 forward Dated Brent curve since January 2011, Platts data shows.
In the Platts Market on Close assessment process, Vitol lifted a Socar offer for a 600,000-barrel Azeri Light cargo, ex-Ceyhan, loading August 19-23 CFR basis Augusta at Dated Brent plus $1.70/b.
Traders said the influx of sweet crude from Nigeria into the European market over the last two months has contributed to sharply weaker differentials across the broader sweet complex in the Mediterranean.
"There is a lot of oil around," a trading source said. "West African is being offered at a discounted price...The [Dated Brent] structure being in contango has helped refiners up profitability because it is easier for everyone to buy from ports where the voyage is long. WAF crudes are pricing better than they were three months ago, and premiums are much lower."
More than 25 million barrels of Nigerian crude are thought to still be available between the August and September Nigerian loading programs, with the majority of the crude expected to land in Europe where it has competed with more local sweet barrels in the Mediterranean and from the North Sea.
Azeri Light differentials have plunged $0.70/b in a little more than two weeks.
The grade's September loading program from the Turkish port of Ceyhan -- it's primary export location -- was released late in European trading on Friday, even as sources said several August cargoes are still available for purchase.
Azeri -- which because of its high distillate yield, is generally in demand from end-users, typically trading between 20 and 30 days forward -- has fallen well behind its normal trading cycle over the last several months, prompting differentials to hold increasingly lower levels.
Traders said weakening refinery margins in both Asia and Europe have also contributed to the drop-off in demand for the crude over the last several weeks.
"There is no demand from the East...and West African crudes are still available," a trader said. "Those have corrected more [than Azeri has], and margins in Asia and Europe [are weak]."
--Paula VanLaningham, paula.vanlaningham@platts.com
--Edited by Jonathan Fox, jonathan.fox@platts.com
The Associated Press
Mexico City • Mexican President Enrique Pena Nieto has signed into law the rules governing a historic opening of the state-run oil, gas and electricity industries to foreign and private companies.
Pena Nieto’s action on Monday follows congressional approval of the rules for production and profit-sharing contracts for private companies.
FILE - In this Nov. 22, 2013, file photo, the Centenario deep-water drilling platform stands off the coast of Veracruz, Mexico in the Gulf of Mexico. The administration of Mexico's President Enrique Pena has passed laws on Aug. 7, 2014, to open its oil, gas and electric industries to private and foreign investors after 76 years of state control. (AP Photo/Dario Lopez-Mills, File)
Pena Nieto said that by Wednesday, the government will let potential investors know which blocks of gas and oil fields will be open for them.
Mexico is hoping for tens of billions of dollars in outside investment in deep-water oil drilling and shale gas production.
Mexico’s oil and gas production peaked in 2004 at 3.4 million barrels a day. It has fallen steadily since to the current 2.5 million barrels.
11 Aug 2014, 3.26 am GMT
Rio de Janeiro, 11 August (Argus) — Brazil's state-controlled oil firm Petrobras posted a profit of $2.23bn in the April-June second quarter, a 2pc drop from the first quarter and down 25pc from the same period a year earlier. Slow growth in domestic production, costly fuel imports, and higher debt costs contributed to the decline. Profit for the first half was $4.5bn, a steep 34pc drop against a year previously.
Domestic oil production averaged 1.97mn b/d in April-June, up 2.6pc compared on the first quarter and up 2pc against a year earlier. Average oil production for the first half was 1.95mn b/d, a 1.6pc increase over the same period in 2013.
Delays in the start-up of offshore platforms stalled the company's plans for a domestic production surge in the first half of the year. But the company remains confident it will meet its goal of 7.5pc, plus or minus 1pc, over the 1.93mn b/d produced in 2013.
Record-setting output from sub-salt reservoirs also helped boost flow rates in the second quarter, with a promise of more growth in the second half of the year. The company set a new daily production record of 546,000 b/d on 13 July from sub-salt fields. The company is scheduled to add 300,000 b/d in sub-salt output from two floating production, storage and offloading vessels, Cidade de Ilhabela and Cidade de Mangaratiba, in the Sapinhoa and Lula sub-salt fields in the third and fourth quarters respectively.
Petrobras' natural gas production averaged 411,000 b/d of oil equivalent (boe/d) in the second quarter, a 2.8pc increase on the first quarter. The increase was attributed to increased production of associated gas from Santos basin fields.
Total domestic production, including oil and gas, reached 2.6mn boe/d, a 2.8pc increase over the first quarter and up just 1.7pc year-on-year. Total domestic production for the first half of the year averaged 2.56mn boe/d, up 1pc compared with the same period of 2013.
Overseas oil production averaged 91,000 b/d, up 5pc over the previous quarter, following increased output at the Cascade and Chinook fields in the US Gulf of Mexico.
The company continues to suffer downstream losses, the result of government-capped domestic fuel prices. Petrobras' downstream segment recorded a 3.8bn reals ($1.69bn) loss for the quarter, narrower by 20pc from the first quarter. The improvement was attributed to lower crude acquisition costs based on a depreciation of the US dollar and an increase in output of oil products in the quarter. Downstream losses for the first half widened by 13pc from a year earlier to $3.78bn.
The average utilization rate at the company's domestic refineries remained high at 98pc, 2pc higher than the previous quarter. The increase in refinery utilization helped reduce oil product imports to 407,000 b/d in the second quarter, a 4pc drop.
Slower growth in domestic output required the company to increase crude imports by almost 50pc to 534,000 b/d in the second quarter. Its crude exports dropped 29pc to 138,000 b/d in the second quarter. Oil exports reached 321,000 b/d in July.
The company's net debt for the first half of the year reached $139.7bn, 24pc higher against a year earlier.
Capital expenditure spending totaled $18bn for the first half, with $11.7bn spent on exploration and production, down 17pc on the same period in 2013.
Copyright © 2014 Argus Media Ltd - www.ArgusMedia.com - All rights reserved.
By Nick Cunningham | Mon, 11 August 2014 22:42 | 0
After several years of very little progress, Brazil is finally beginning to extract oil from ultra-deep water. It’s a welcome development for the South American country, which has experienced four years of flat oil production.
Brazil’s economy grew at an astounding pace from 2005 to 2010, thanks to a commodity boom that sent exports of things like soy, beef and iron ore soaring. Brazil had already been a major oil exporter for years, but things really took off after the discovery of a massive deposit of offshore oil in 2007. After that, the country set its sights on becoming one of the top producers in the world.
The discovery of billions of barrels of oil underneath a thick layer of salt presented significant engineering and financing challenges, but a wave of excitement swept through the country. The quasi-state-owned oil company Petrobras issued ambitious production targets -- predicting oil output would hit 5 million barrels per day by 2020, more than double the current rate.
Brazil began to fight over the riches before any oil was even pulled from the pre-salt. The government passed a law in March 2013 that allocated a greater share of revenue to non-oil-producing states. This angered the state government of Rio de Janeiro, because some of the biggest fields are located in its waters.
While the revenue fight played out on land, Petrobras soon ran into trouble offshore. Drilling through the salt crust beneath the seabed proved harder than it anticipated. The oil fields are located in ultra-deep water – nearly 20,000 feet below the surface of the sea. Once they reach that depth, operators must then drill through a layer of salt that can be more than a mile thick.
The extreme challenges of getting at the oil have forced Petrobras to invest billions in new equipment and advanced technology, and even still, it has run into delays. From 2010 onwards, Brazil’s oil production flattened out, after years of increases.
As costs ballooned and project deadlines slipped, Petrobras racked up enormous debt, so much so that it has been called the world’s most indebted major oil company.
Brazil’s economy stagnated around the same time, fueling discontent among the general population. Optimism gave way to unease and frustration as the cost of living continued to climb and consumer confidence plummeted. Petrobras’ problems became a symbol of the country’s broader woes.
Now Petrobras may be turning a corner. New data shows that production from the pre-salt jumped from essentially nil to 520,000 barrels per day in July. The turnaround is critical for the company, which has seen most of its other wells reach maturity. Many are already beginning to decline.
As the Wall Street Journal noted, Brazil’s largest oil field saw its output drop from 395,000 barrels per day in 2010 down to its current level of 256,200 barrels per day. Petrobras’ annual production slipped in both 2012 and 2013, but it expects to rebound this year.
Still, the target of 5 million barrels per day by the end of the decade is probably overly optimistic. Oil analysts project a more modest production level of 4 million barrels per day in that timeframe. But even reaching that level of output would be a notable achievement for the company, and it would be enough to make Brazil one of the world’s five largest oil producers.
Despite the news about rising production from the pre-salt, Petrobras will need to overcome a lot of hurdles to get there. The company has to sell gasoline at below market rates by government decree, in order to fight the effects of inflation. Mandates on the use of local content in drilling projects has raised costs and scared away investors. Petrobras’ stock price has dropped by around 75 percent since hitting a high in 2008, and it has declined each of the last five years as debt piled up.
But the biggest problem facing Petrobras is one of engineering. The pre-salt is arguably the most challenging environment to work in for any oil company. Still, there is finally some evidence that Petrobras is making progress.
By Nick Cunningham of Oilprice.com
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Mexico’s Congress have given final approval to a far-reaching energy reform bill that will open up the oil and gas sector to private investment for the first time in 75 years.
The historic opening, a central piece of Mexican President Enrique Pena Nieto’s agenda, will end the monopoly of state-owned oil company Pemex.
That could spell good news for major oil companies waiting to jump in. Mexico offers some of the same promising geology that is seen just north of the border, in Texas. The Eagle Ford shale in Texas is one of most productive in the U.S., and similar deposits of oil and gas are thought to extend south into Mexico. According to a rough estimate published by the Energy Information Administration, Mexico could hold 545 trillion cubic feet of natural gas trapped in shale, and much of that is concentrated in the Burgos basin in the northern part of the country.
Offshore in the Gulf of Mexico will also be a prime target for oil majors. Companies like Chevron, BP, Royal Dutch Shell, and Statoil are already operating in the Gulf close to Mexican waters. Known as the Perdido Fold Belt, some of Mexico’s best offshore oil reserves are located along the U.S.-Mexican maritime boundary. The region could hold up to 10 to 30 billion barrels of oil.
And oil companies are increasingly turning to offshore hydraulic fracturing, according to Bloomberg, which help them extract harder to reach reserves in the Gulf.
Both onshore and offshore oil fields are located near existing operations just across the border in U.S. territory – making it a small leap for many companies to expand southwards.
For Mexico’s part, it is anxious to attract international development because Pemex cannot access offshore oil and onshore shale resources with their current level of expertise. Nor can they marshal enough capital. But big multinational oil companies can help them on both fronts.
International investment could also prevent a further slide in Mexico’s oil production, which recently hit its lowest level in over 24 years.
And a new frontier in Mexico comes at a perfect moment, with major oil companies juggling a mess of violence around the world. From Iraq to Libya, Nigeria to Russia, the largest international oil companies are running into above-the-ground problems that are affecting operations. Most recently, Chevron and ExxonMobil announced on August 7 that they were evacuating personnel operating in Kurdistan, as the Sunni jihadist group Islamic State moved within striking distance of the regional capital of Erbil.
That has some oil companies casting an eye back towards North America, hoping to avoid the risk that comes with operating in troubled territory.
But Mexico isn’t risk-free, itself. Drug violence still plagues parts of the country, including in areas that hold shale oil and gas. For example, Tamaulipas in eastern Mexico at times resembles a “war zone.” Some oil workers have to be escorted to and from work sites by the Mexican military. Lingering pockets of violence could keep international companies – still smarting from drilling campaigns affected by violence elsewhere – from jumping in too quickly.
The political situation is also uncertain, although to a lesser degree. President Pena Nieto has racked up a lot of wins in his first two years, pushing major reforms through Congress on everything from banking, to education, telecommunications, and energy. Ending Pemex’s 75 year monopoly over energy is a notable feat.
But precisely because it is a radical departure from the past has made it highly controversial. The Mexican public is frustrated, and many are skeptical of the benefits of handing over control of Mexico’s natural resources to foreign companies. Should President Pena Nieto’s PRI party lose control in 2018, an incoming administration could roll back some of the reforms that are now being put into place. That presents another element of risk to international companies pondering billion dollar investments.
Nevertheless, it is hard to imagine any of the interested parties will stay away. With many of their other projects literally located in war-ravaged regions, Mexico looks easy by comparison. Companies like ExxonMobil, BP, and Chevron will probably move in as quickly as they can.
By Nick Cunningham of Oilprice.com
LONDON: OPEC trimmed its 2014 global oil demand growth forecast for a second consecutive month and said the group managed to increase output in July despite violence in Iraq and Libya, pointing to more comfortable global supplies.
In a monthly report, the Organization of the Petroleum Exporting Countries trimmed its projection for growth in global demand this year to 1.10 million barrels per day (bpd), down 30,000 bpd, citing weaker-than-expected US demand.
"The slow and uneven global recovery continues," OPEC said in the report.
In 2014, "US oil demand remains strongly dependent on the development of the US economy, however the risk is skewed to the downside compared to the previous month."
OPEC's report points to even less pressure on supplies in 2015 as partly due to the US shale boom the need for OPEC crude will fall, despite faster growth in global demand. The report made no change to 2015's global demand forecast.
This year, the lower demand forecast and a higher expectation for non-OPEC supply will reduce the forecast global demand for OPEC crude to 29.61 million bpd, down 70,000 bpd from the previous estimate, OPEC said. It left next year's forecast unchanged at 29.36 million bpd.
The report also showed OPEC's crude output in July rose.
According to secondary sources cited by the report, output increased by 170,000 bpd to 29.91 million bpd, led by higher supply in Libya and Saudi Arabia.
That puts OPEC output close to the group's target of 30 million bpd. Protests and unrest in Libya, Western sanctions on Iran and fighting in Iraq took their toll on production in earlier months, keeping OPEC output sometimes below the target.
Although Iraq's northern exports have been disrupted since March, southern exports which are its main outlet to world markets have not been affected by fighting in other parts of the country. The prospect of a further rise in Libya looks uncertain given worsening fighting, say analysts.
World oil demand will rise by 1.21 million bpd in 2015, OPEC said, unchanged from last month. OPEC trimmed its forecast of next year's growth in non-OPEC supply by about 40,000 bpd but still expects an expansion of 1.27 million bpd, with the US leading the way.
Two other reports on global supply and demand are due next Tuesday, from the International Energy Agency which advises industrialized countries, and the US government's Energy Information Administration.
© Copyright of Arab News 2013
By Andy Tully | Mon, 11 August 2014 22:39 | 0
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Ukraine is planning to impose sanctions on Russia that might include an effort to starve its larger and richer neighbor of income by stopping the flow of Russian gas through Ukraine to customers in Western Europe.
Ukrainian Prime Minister Arseniy Yatsenyuk told reporters on Aug. 8 that his government is proposing sanctions against 172 citizens from Russia and other countries, as well as 65 Russian companies “for financing terrorism” by supporting the efforts of Russian separatists in eastern Ukraine.
Other options being considered include closing Ukrainian air space to Russian aircraft, reducing cooperation between the countries’ defense industries, and restrictions on Russian ships in Ukrainian waters. And he mentioned a “partial or full ban on the transit” of resources from Russia through Ukraine.
Asked if that could include Russian gas shipped to Western Europe via Ukrainian pipelines, the prime minister replied, “I spoke about all the measures which could be included in the [proposed] law. This includes the possible halting of all types of transit, from air flights to transit of resources.”
These proposals bring Ukraine into a growing tit-for-tat sanctions war being fought for the past several months by the European Union, the United States and Russia over the Ukraine crisis. Two rounds of EU and U.S. sanctions have limited travel for several influential Russians and denied Russian oil companies access to Western capital and technology.
Russia has responded by banning produce from Poland, an EU member, and said it is considering bans of other foods from the West, citing food safety. Russia is the EU’s biggest customer of fruit and vegetables, buying more than 2 billion euros worth of produce from the bloc each year. It has previously been accused of such bans from countries with which it has had political disputes.
Yatsenyuk said he expects more of the same from Moscow. “There’s no doubt that Russia will continue its course – started a decade ago – aimed at banning imports of Ukrainian goods, limiting cooperation with Ukraine, pressure and blackmail.”
And the costs, he acknowledges, could be high for Ukraine. “In the most negative scenario for Ukraine, losses during the first year may reach $7 billion, not only because of sanctions but also because of the Kremlin’s aggressive policy.”
But a complete shutoff of oil and gas flowing through Ukraine also could hurt Russia. In 2013, Moscow reports, Russia used Ukrainian pipelines to transport 86.1 billion cubic meters of its gas and 15.6 million metric tons of oil. That includes about half of Russia’s annual exports of gas, though less than 7 percent of its oil exports.
Also at risk, of course, is Western Europe, which receives about 30 percent of its gas from Russia, half of it piped through Ukraine. Twice, in 2006 and 2009, that flow has been interrupted. Gas flows to Europe through Ukraine are intact today despite the fighting in Ukraine, but a shutoff of the pipelines to punish Russia would hurt Ukraine’s Western supporters, as well.
By Andy Tully of Oilprice.com
World Aug. 12, 2014 - 06:35AM JST ( 0 )
Mexican president signs landmark energy reform bills View of a tank with processed oil at Mexican state-owned petroleum company PEMEX refinery in Tula, Hidalgo state, Mexico on March 8, 2011 AFP
Mexican President Enrique Pena Nieto signed a package of landmark energy reform bills Monday, ending the 76-year-old state monopoly on oil drilling and reopening the sector to foreign companies.
“This represents a historic change that will accelerate the economic growth and development of Mexico in the coming years,” the president told hundreds of guests at a ceremony in the capital.
The signing comes five days after the Mexican Senate gave final approval to the laws, the centrist leader’s most ambitious political project and the centerpiece of his efforts to kick-start Latin America’s second-largest economy.
Pena Nieto argues the nine new laws and 12 amendments will fuel growth, create jobs and modernize state energy firm Pemex, whose oil production has fallen from 3.4 million barrels per day in 2004 to 2.5 million today.
But the leftist opposition accuses the president of gutting Pemex, the country’s main source of tax revenue, and betraying the legacy of the 1938 nationalization of the oil industry.
The president rejected that criticism Monday, saying the reforms “preserve and assure our national property.”
Having won the legislative battle, Pena Nieto’s administration must now write new regulations for the energy sector, a project the president said would be finished in October.
He also said officials would announce on Wednesday the results of the so-called “Round Zero” rights allocation that will determine which oil and gas fields Pemex keeps and which will be up for international bidding.
“That will allow potential national and foreign investors to begin preparing now to take part in the first round of bidding, whose guidelines will be published in the first quarter of next year,” said Pena Nieto.
Foreign energy firms including ExxonMobil and BP have been keenly watching the reforms, hiring lawyers and consulting tax experts in anticipation of a return to Mexico—though analysts say there is also wariness over high taxes, corruption and drug violence in the oil- and gas-rich north.
© 2014 AFP
HOUSTON, Aug 11 (Reuters) - U.S. refiner Axeon Specialty Products will not buy or accept delivery of any cargoes of disputed Kurdish crude oil for its Paulsboro, New Jersey, refinery, according to a company news release received on Monday.
The tanker Minerva Joy, loaded with an estimated 300,000 barrels of Kurdish crude at the Turkish port of Dortyol, arrived to Paulsboro on Monday as scheduled, but it has not been unloaded and is currently anchored, according to Reuters tracking data.
Several cargoes of Kurdish Shaikan crude have recently reached the United States and Iraq's central government has moved to block independent exports of crude by the Kurdistan Regional Government.
"In light of the dispute over the rights to sell crude oil originating from the Kurdish region of Iraq, Axeon will not purchase or accept delivery of any of the affected crude oil until the matter is appropriately resolved," the company said.
Axeon Specialty Products said previously it received a separate cargo of Kurdish Shaikan crude in June.
Two weeks ago, refiner LyondellBasell NV, confirmed it recently bought "modest quantities" of what public records show is Kurdish Shaikan crude and said it would scrap further purchases of the disputed oil for the time being. (Reporting By Terry Wade and Marianna Parraga. Editing by Andre Grenon)
Copyright © 2014 Thomson Reuters Foundation
9 August 2014, 12:10 (GMT+05:00)
By Dalga Khatinoglu - Trend:
Iran's crude oil production (excluding gas condensates and natural gas liquids) declined by 9, 800 barrels per day and stood at 2.762 million barrels per day in July, compared to June.
Iran's crude oil output increased by 86,000 bpd in 2Q14 compared to 4Q13, according to a monthly report based on secondary sources, released by OPEC Aug. 8.
Iran and the six world powers including the U.S., the U.K, France, Germany, Russia and China reached an interim nuclear deal Nov.23, 2013. The agreement entered into force Jan.20, 2014 and extended by Nov.23, 2014.
Some restrictive measures on Iran, including the United States' pressure on Iran's customers to cut more Iranian oil purchase every 180 days have stopped un accordance with the accord.
Iran produced 3.247 mbpd of oil (including the 0.4 mbpd of gas condensate and 0.1 mbpd of NGLs) in first four months of 2014, increased by 131,000 bpd, compared with that of last year, according to the U.S. Energy Information Administration's (EIA) report, published July 28.
Iran's crude oil export has increased by 0.1 mbpd in 1H14, according to the International Energy Agency's latest monthly report, published in July.
OPEC also said that in total, OPEC's crude oil production averaged 29.91 mbpd in July, according to secondary sources, up 0.17 mbpd from the previous month.
Preliminary figures indicate that the global oil supply increased by 0.08 mbpd in July to average 90.98 mbpd. Non-OPEC supply saw decline of 0.09 mbpd, while OPEC crude production increased by 0.17 mbpd
http://www.trend.az/media/pictures/2014/08/09/grafik_090814_01.jpg
OPEC says that the OPEC Reference Basket fell by $2.28 and stood at $105.61 per a barrel in July, compared to the previous month. Iran's heavy crude oil price decreased by -$1.24 and amounted to $106.21 in July.
http://www.trend.az/media/pictures/2014/08/09/grafik_090814_02.jpg
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Baku, Azerbaijan, June 9
By Elena Kosolapova- Trend:Kazakhstan plans to expand cooperation with the Organization of Petroleum Exporting Countries (OPEC), the country's Permanent Representative in the International Organizations in Vienna Kairat Sarybay said, Kazakh Foreign Ministry reported on June 9.
Sarybay made such a statement at the meeting with Secretary General of OPEC Abdalla El-Badri.
During the meeting the parties discussed Kazakhstan's role in the global energy cooperation, the prospects of bilateral cooperation, the activities of OPEC aimed at stabilization of the oil market and current situation in the global energy market.
Abdullah El-Badri noted that OPEC would maintain oil production level at 30 million barrels per day and expressed interest in establishing a dialogue between Kazakhstan and OPEC in the field of global energy cooperation.
Sarybay in turn noted that Kazakhstan is a reliable strategic partner in the energy sector. He invited OPEC's Chief to visit Kazakhstan in order to attend 25th meeting of the Energy Charter Conference on November 27, 2014 in Astana and to discuss perspectives of cooperation with Kazakhstan. Sarybay also positively assessed OPEC's activities on maintaining stability of oil prices and oil supply.
Edited by C.N.
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Kuwait expects the Organization of Petroleum Exporting Countries to keep the oil production ceiling unchanged so as not to alter prices, the wealthy Gulf country's oil minister said on Tuesday, AFP reported.
Asked if he believes the OPEC cartel will decide to maintain current output at its regular meeting in Vienna this week, Ali al-Omair said: "I think yes."
"I think that all parameters lead to keeping the production as it is and this, of course, will be reflected in [oil] prices" remaining unchanged, Omair told reporters outside parliament before leaving for Vienna.
He said he believes that by not changing the oil output ceiling, there will be no "big changes" in crude prices.
The 12-member OPEC, which supplies about one third of the world's crude, is pumping around 30 million barrels of oil daily.
OPEC is also satisfied with current price levels at around $100 a barrel.
Oil prices extended their gains in Asia on Tuesday as investors cheered robust economic data from the United States, China and Japan, with the breakdown of initial Ukraine-Russia talks to avert a gas cut-off also boosting prices.
U.S. benchmark West Texas Intermediate (WTI) for July gained 39 cents to $104.80 a barrel in afternoon trade after jumping $1.75 in New York on Monday.
Brent North Sea crude was up 14 cents to $110.13 for its July contract after leaping $1.38 in London trade.
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