Ukraine’s imports of crude oil increased by 51.5% year-on-year to 305,200 metric tons in January through May from 201,400 mt in the same period of 2013, an energy and coal industry ministry official said Wednesday.
Ukraine imported 160,000 mt from Russia in the first two months of the year, but these supplies were suspended in late February. In January-May 2013, the country did not import crude oil from Russia, the official said.
Oil imports from Azerbaijan and Kazakhstan fell to 145,200 mt in January-May from 201,400 mt a year earlier. In May alone, Ukraine imported 51,300 mt of crude — mostly from Azerbaijan — up from 25,200 mt in May 2013, but down up from 51,700 mt imported in April.
Crude oil and gas condensate refining in Ukraine increased by 7.8% year-on-year to 1.38 million mt in the first five months from 1.28 million mt refined in January-May 2013, the official said.
Odessa Oil Refinery, Ukraine’s No. 3 oil refinery by capacity, resumed operation in autumn of 2013 after three years of stoppage. It refined 214,200 mt of crude in January-February. But the refinery again shut down indefinitely on February 25.
Ukraine’s largest oil refinery, the Kremenchuk-based UkrTatNafta, refined 955,900 mt of crude in January-May, down 7% year-on-year, the official said.
Shebelinka Gas Processing Plant, which refines mostly domestically extracted gas condensate, refined 206,600 mt of gas condensate in the period, down 17% year-on-year, the official said.
Ukraine extracted 1.03 million mt of oil and condensate in January-May, down 9.6% from 1.14 million mt a year ago, the official said.
In 2013, Ukraine produced 3.05 million mt of oil and condensate, down 7.3% year-on-year. At the same time, oil imports dropped 56.4% to 659,100 mt.
US commercial crude stocks rose 1.7 million barrels last week, boosted by a rise in imports, mainly to the Gulf Coast, data Wednesday from the US Energy Information Administration showed.
Crude stocks were at 388.1 million barrels for the June 20 reporting week, putting inventories at a 4.34% surplus to the EIA’s five-year average. The build in stocks was counter to analyst expectations, who had anticipated a 2 million-barrel draw.
US imports climbed 107,000 b/d to 7.34 million b/d. Imports to the Gulf Coast surged 506,000 b/d to 3.683 million b/d, but were largely offset by a 451,000 b/d-drop in imports to the East Coast.
Crude stocks rose, however, despite an uptick in US refinery utilization rates, which increased 1.4 percentage points to 88.5% of capacity. In the Gulf Coast, utilization rates surged 4.1 percentage points to 88.1% of capacity.
Motiva’s VPS-5 crude unit was reported to have returned to normal rates on June 18, according to Tim Evans, commodity analyst at Citi Futures Perspective. That was after rates were reduced June 12 due to unplanned work and a recent operational incident.
Earlier this month, Marathon Petroleum restarted a 256,000 b/d crude unit at its 522,000 b/d Garyville, Louisiana, refinery, which had been shut after a tornado damaged the plant May 28.
Crude stocks in the USGC accounted for the bulk of the overall rise in inventories, climbing 2 million barrels to 207.8 million barrels.
In the Midwest, crude stocks were up 1.5 million barrels last week to 91.4 million barrels, including a 400,000-barrel build at Cushing, Oklahoma, to 21.8 million barrels.
The build at Cushing — delivery point for the NYMEX futures contract — was the second in 11 weeks. Still, stocks at the hub were at a 45.2% deficit to the five-year average. EIA estimated that crude oil exports last week were at 273,000 b/d.
The total was up from an estimate of 74,000 b/d the week prior; however, the EIA noted that beginning with the June 20 report, the agency has modified the parameters in its model to better estimate US weekly crude oil exports.
Turkey’s refiner Tupras made a rare purchase of 500,000 barrels of Colombian Vasconia crude from Shell through a tender recently, Latin American crude market sources said Wednesday.
The 500,000-barrel cargo of that 24 API, 0.9% sulfur crude will load in early July for delivery in early August, market sources said.
The mid-grade South American crude was heard sold at around ICE minus $7.50/b, but this could not fully confirmed. Turkey is the latest buyer of Colombia’s Vasconia crude, which was typically exported primarily to the US Gulf Coast and occasionally to the US West Coast. However, increased supplies of light sweet crude from shale and heavy sour grades from Canada has reduced demand for Vasconia in the US Gulf Coast.
“Turkey has done a couple of tenders of Vasconia before, but as far as I know, they only purchased Vasconia once earlier,” said one supplier of South American grades of crude. “Turkey is definitely not a usual buyer of that crude,” said another participant in the South American crude market.
Tupras operates four refineries in the country and usually buys Russian Urals, Iraqi Basrah and Iraqi Kirkuk. However, with availabilities of the latter dwindling on the political situation in the region, Vasconia has become more attractive as an alternative grade.
In recent weeks greater availability of Russian Urals has pushed Vasconia out of Europe, which has left sellers looking for other markets. Chinese state refiner Unipec has been a recent buyer of additional volumes of Vasconia, taking Aframax-sized cargoes from Covenas to Aruba for loading on VLCCs to Asia.
By Zain Shauk and Dan Murtaugh Jun 26, 2014 6:07 AM GMT+0700 2 Comments Email Print
The U.S. could allow about 750,000 barrels a day of light crude oil to be exported, based on a new government stance defining what qualifies for overseas shipments.
Producers, refiners and pipeline companies are questioning exactly how much the Obama administration has relaxed its position on crude exports after the Commerce Department said June 24 it had categorized some lightly processed oil as exportable. The U.S. has prohibited most crude exports for four decades.
About 750,000 barrels a day of oil produced from U.S. shale plays is an ultra-light variety known as condensate, said Michael Wojciechowski, head of Americas downstream research for Wood Mackenzie Ltd. More than 70 percent of U.S. condensate comes from the Eagle Ford shale formation in Texas, where the majority of it goes through a heating process to burn off certain gases, Amrita Sen, chief oil economist for Energy Aspects Ltd. in London, said by phone.
The Commerce Department gave permission for condensates to be exported after going through the process, known as stabilizing, because then it can be considered a refined product. Though most raw crude oil exports are banned, refined products can be shipped abroad without limits.
Stabilizers at oil fields along the U.S. Gulf Coast may have a combined capacity of more than 200,000 barrels a day, according to Eric Lee, a commodities strategist for Citi Research.
August Exports?
“Processed condensate exports could begin as early as August,” Lee said in a research note. The U.S. could export 300,000 barrels of condensate per day by the end of the year, according to another Citi note.
Oil producers and refiners were unsure whether other types of crude might also qualify. Far more crude might be eligible for overseas shipments if any type of stabilized oil can qualify as a refined product, since the practice is widespread in the industry, said Charles Blanchard, an analyst for Bloomberg New Energy Finance.
Oil producer BHP Billiton Ltd. said it welcomed the approval of condensate exports “under limited circumstances. BHP Billiton will consider marketing opportunities that may apply to our condensate production in the Eagle Ford and Permian Basin,” Jaryl Strong, a BHP spokesman, said in an emailed statement.
As the industry figures out how to define the new rule, “that’ll really help companies on the downstream side better understand business opportunities and business impacts,” Dean Acosta, a spokesman for refiner Phillips 66 (PSX), said by phone.
Additional Markets
Producers are keen to find additional markets for crude as output from U.S. shale formations has surged, causing bottlenecks in some regions. Refiners that have benefited from access to oil at prices below the international benchmark saw their shares drop yesterday after the Commerce Department change was announced.
The U.S. produced almost 8.4 million barrels a day in May and annual output is forecast to reach 9.3 million barrels a day in 2015, the highest since 1972, according to the Energy Information Administration.
More than 80 percent of the Eagle Ford’s output goes through stabilizers, Energy Aspects’ Sen said. Pioneer Natural Resources Co. (PXD), one of the companies that asked the government for permission to export stabilized condensate, said this week that a large portion of its 43,000 barrels a day of Eagle Ford production is condensate that already undergoes the processing.
Simple Equipment
Stabilizers are relatively simple pieces of oilfield equipment sometimes positioned near wellheads. They heat oil enough to boil off some gases, separating those products from the rest of the crude mix, Blanchard said.
“A caveman could do it,” Blanchard said, comparing the process to heating oil in an oven.
The process is commonly performed before putting oil and condensate into pipelines. Stabilizing oil is far less complex than the process of splitting or refining crude, which involve more sophisticated devices that heat and separate fuels from oil. Stabilizers that qualify crude for export can cost as little as one-tenth that of more complex processing units, said Wojciechowski at Wood Mackenzie.
To contact the reporters on this story: Zain Shauk in Houston at zshauk@bloomberg.net; Dan Murtaugh in Houston at dmurtaugh@bloomberg.net
To contact the editors responsible for this story: Susan Warren at susanwarren@bloomberg.net Tina Davis
By Zain Shauk, Dan Murtaugh and Rakteem Katakey Jun 25, 2014 7:38 PM GMT+0700 89 Comments Email Print
The U.S. Commerce Department opened the door to more U.S. oil exports as long as the crude is lightly processed, tempering the impact of a law that’s banned most overseas petroleum shipments for the past four decades.
The department widened its definition of what’s traditionally been considered a refined product eligible for shipping to customers abroad. That means more of the oil being pumped from U.S. shale formations may be eligible for export after being run through small-scale processing units.
The Commerce Department issued its ruling after Pioneer Natural Resources Co. petitioned for approval to export a type of ultra-light oil that had been stripped of lighter gases to make it less volatile for transport -- a minimal level of processing known as stabilization. The ultra-light oil, known as condensate, has been abundant in shale formations during the drilling boom, leading to oversupplies on the Gulf Coast.
“It’s a crack in the door which has otherwise been shut for 40 years,” Harry Tchilinguirian, head of commodity markets strategy at BNP Paribas SA in London, said by phone. “If approvals for condensate exports are extended to more companies, it’ll benefit U.S. producers and processors in Asia, particularly in Singapore and South Korea.”
Distillation Exception
Any oil that has been processed through a distillation tower -- a preliminary form of refining -- is no longer defined as crude oil, and therefore is eligible for export, said Jim Hock, a department spokesman, in an e-mailed statement yesterday.
Pioneer uses a distillation unit to stabilize oil it produces in the Eagle Ford Shale of South Texas, most of which is condensate.
The Commerce Department “recently confirmed our interpretation that the distillation process by which our Eagle Ford Shale condensate is stabilized is sufficient to qualify the resulting hydrocarbon stream as a processed petroleum product eligible for export without a license,” Pioneer said in an e-mailed statement.
“It’s not exactly going to be a game changer but it’s certainly the next step in providing the market with some relief,” said Robert Campbell, head of oil products research at Energy Aspects Ltd., a London-based research firm.
West Texas Intermediate crude for August delivery climbed as much as $1.47, or 1.4 percent, to $107.50 a barrel in electronic trading on the New York Mercantile Exchange, before trimming gains to trade 0.4 percent higher at $106.43 at 12:26 p.m. in London. Brent oil futures slid 0.7 percent to $113.66.
Economic Forces
“There are certainly a lot of inexorable economic forces that suggest the U.S. is going to relax the export ban in the long term,” Ric Spooner, a chief strategist at CMC Markets in Sydney, said by phone.
Further applications for exports from the U.S. may follow this approval, Morgan Stanley analysts led by Adam Longson wrote in a report today. If more overseas sales are allowed, U.S. condensate could find its way to Asia, from which companies can produce naphtha used in the petrochemical industry, BNP’s Tchilinguirian said.
“A lot of condensate splitting capacity is in Asia and more will be added this year,” he said. “Some of the Asian processors would have been wondering where the condensate is going to come from.”
Restricted Exports
The U.S. has restricted most crude exports since 1975, in response to the Arab oil embargo. Shipments to Canada are an exception, and those averaged 246,000 barrels a day in March, the highest level since April 1999.
“It is certainly the first step towards the lifting of the ban on U.S. crude exports and will be welcomed by the oil world,” Ehsan Ul-Haq, senior market consultant at KBC Energy Economics in Walton-on-Thames, England, said by phone today. “It comes at a time when geopolitical skirmishes have added more than $10 a barrel of risk premium to oil prices.”
U.S. oil producers such as Continental Resources Inc. (CLR) and ConocoPhillips (COP) have been clamoring for an end to the restrictions as shale production has brought a surge in North American petroleum supplies. U.S. crude production has jumped 45 percent since the start of 2012, driven by horizontal drilling and hydraulic fracturing in places including North Dakota and Texas.
Supplies on the Gulf Coast rose to more than 215 million barrels in May, the highest level on record since 1990, according to Energy Information Administration data. Much of that supply has been in the form of lighter crude, and arrived after Gulf Coast refiners made expensive upgrades to their plants to process heavier crudes from places such as Canada and Mexico.
‘First Step’
The Commerce Department’s willingness to qualify more lightly processed crude for overseas shipments should lead to even wider approval of crude exports, said Senator Lisa Murkowski, Republican of Alaska. The decision “is a reasonable first step that reflects the new reality of our energy landscape,” she said.
It could also make plans for more complex processing plants, known as splitters, less economic. Several companies are building and planning condensate splitters that are designed to process lighter crudes from shale formations into products like naphtha, kerosene and gasoil, which are eligible for export.
The plants, built for one-tenth the cost of a complex, full-scale refinery, were also aimed at using minimum processing to qualify oil as a refined product for export.
The first of the units, a 50,000-barrel-a-day processing plant built by Kinder Morgan Energy Partners LP for use by BP Plc (BP/), is scheduled to come online in November. BP has signed a 10-year contract to use the facility, which will be expanded to 100,000 barrels a day in 2015. Several additional plants have been proposed by other pipeline or trading companies, and refiners including Valero Energy Corp. and Phillips 66 said they plan to add similar oil processing equipment.
Refined Product
The distillation towers that the Commerce Department says are needed to process oil into an export-eligible refined product aren’t defined by size, said Andy Lipow, president of Lipow Oil Associates LLC, a consulting firm in Houston. The towers could include equipment such as stabilizers that are used in oil fields to separate the lightest gases such as propane and butane from some condensate to prepare it for shipping, he said.
An eventual removal of the export ban would promote U.S. oil production, said Zak Cikanek, a spokesman for the oil industry trade group American Petroleum Institute, which said it hasn’t yet reviewed the Commerce Department ruling.
“Allowing the export of processed condensate would be a very small step toward a much more important goal, which is free trade,” Cikanek said.
Largest Refiner
While Phillips 66, the largest U.S. refiner by market value, has been supportive of lifting the crude export ban, refiners will probably reap lower profits if they are forced to pay higher prices to compete with international buyers for U.S. crude.
“We don’t think the current system needs to be changed,” saidBill Day, a spokesman for Valero Energy Corp. “The United States is still importing quite a bit of crude oil to satisfy our needs.”
Net U.S. crude imports were 7.16 million barrels per day as of June 13, down 24 percent over the last five years, according to data from the EIA.
The decision to allow a wider category of lightly processed oil provides a stronger base to argue for broader approval of crude exports, said Lipow, the Houston oil consultant.
“There’s cracks in the crude oil export dam,” he said.
To contact the reporters on this story: Zain Shauk in Houston at zshauk@bloomberg.net; Dan Murtaugh in Houston at dmurtaugh@bloomberg.net; Rakteem Katakey in New Delhi at rkatakey@bloomberg.net
To contact the editors responsible for this story: Susan Warren at susanwarren@bloomberg.net; David Marino at dmarino4@bloomberg.net; Jason Rogers at jrogers73@bloomberg.net James Herron, Bruce Stanley
By Kadhim Ajrash and Nayla Razzouk Jun 26, 2014 6:00 AM GMT+0700 0 Comments Email Print
June 25 (Bloomberg) -- Adam Ereli, former U.S. ambassador to Bahrain, discusses the conflict in Iraq, solving the crisis and the outlook for the country's Shiite Prime Minister Nouri al-Maliki. Ereli, speaking with Mark Barton on Bloomberg Television's "Countdown," also talks about U.S.-Russia relations. (Source: Bloomberg)
Iraq’s oil minister said the nation’s crude exports will accelerate next month, adding to signs that violence in the country’s north isn’t affecting the oil-rich south.
“Oil exports will witness a big increase, as recent events didn’t reflect negatively on Iraq’s crude output and exports,” Oil Minister Abdul Kareem al-Luaibi said in an interview in Baghdad yesterday. “International oil companies are working normally in Iraq.”
While violence in Iraq spurred companies including BP Plc (BP/) and Exxon Mobil Corp. to evacuate workers from the country, there are few signs so far that oil production is being affected. Iraq’s exports will be close to a record next month, according to loading programs obtained by Bloomberg. Luaibi said in the interview that he’s spoken to BP about increasing output at the Rumaila field, the nation’s largest. Toby Odone, a BP spokesman in London, declined to comment on the field.
Iraq, holder of the world’s fifth-largest crude reserves, produces and exports most of its oil from the Shiite-dominated south, which remains largely unaffected by the clashes. Gunmen yesterday seized the 20,000 barrels a day Ajeel oilfield, which remains inactive, in the northern oil hub of Kirkuk, according to a local police statement.
Brent crude, the global benchmark grade, fell as much as 1.2 percent to $113.23 a barrel in London by 5:38 p.m. in London yesterday. It’s still near a nine-month high. Luaibi said exports averaged more than 2.5 million barrels a day this month. He didn’t say what they will be in July.
No Infringements
Luaibi said government troops continue to control the state-run North Oil Co. and the Baiji refinery, the country’s largest. Baiji has been shut since June 15 after ISIL insurgents tried to seize the 310,000 barrels-a-day plant.
“The Iraqi Oil Ministry will not allow any party to infringe on its establishments or installations,” he said. “The Oil Ministry is working to regain control of any oil installation taken by gunmen.”
The northern Kirkuk oilfield is defended by troops from the self-governing Kurdistan Regional Government which controls 45 billion barrels of crude reserves. Iraq, excluding its Kurdish enclave, holds 150 billion barrels in proven crude reserves. Iraq is the largest oil producer, after Saudi Arabia, in the Organization of Petroleum Exporting Countries.
To contact the reporters on this story: Kadhim Ajrash in Baghdad at kajrash@bloomberg.net; Nayla Razzouk in Dubai at nrazzouk2@bloomberg.net
To contact the editors responsible for this story: Alaric Nightingale at anightingal1@bloomberg.net Grant Smith
By Dan Murtaugh and Joe Carroll Jun 26, 2014 4:54 AM GMT+0700 4 Comments Email Print
U.S. oil refiners dropped while producers and midstream companies advanced on speculation that easing restrictions on crude exports will raise prices for some of the crude fueled by the shale boom.
Investors reacted swiftly after Pioneer Natural Resources Ltd. and Enterprise Products Partners LP (EPD) said the U.S. Commerce Department gave them approval to export ultra-light crude processed at gathering facilities in the fields of south Texas. The ruling is seen as loosening a four-decade old prohibition against most crude shipments abroad.
“Yesterday, the market said there’s zero percent chance we’ll export crude oil,” David Pursell, an analyst at Tudor Pickering Holt & Co. in Houston, said in a phone interview. “Today we woke up and there’s a finite chance.”
Refiners were hit hardest. Increased exports of crude may reduce the price advantage U.S. plants have enjoyed in recent years as growing domestic production caused supply gluts within the country’s borders. U.S. benchmark West Texas Intermediate strengthened by 93 cents a barrel versus European Brent oil today.
Phillips 66 (PSX), the largest U.S. refiner by market value, tumbled 4.2 percent, the biggest drop in a year. Valero Energy Corp. (VLO) fell 8.3 percent and Marathon Petroleum Corp. (MPC) lost 6.3 percent, both the largest declines since November 2011.
Stabilized Condensate
Pioneer jumped 5.2 percent. The company said yesterday it produces about 43,000 barrels of oil-equivalent a day from South Texas’s Eagle Ford shale, and most of that is ultra-light condensate that must be stabilized in the field before being transported.
The company petitioned the Commerce Department that the stabilization method, which involves heating the condensate in a distillation tower to remove the most volatile hydrocarbons, should meet the legal definition of refining crude, which would make it eligible for export. The government confirmed that interpretation, Pioneer said in a statement.
The U.S. produces more than 1 million barrels a day of ultra-light condensate, most of which comes from the Eagle Ford, Amrita Sen, chief oil economist at Energy Aspects Ltd. in London, said in a telephone interview.
Most of that condensate goes through some sort of stabilization process, she said. What isn’t known is whether all forms of stabilization will meet Commerce’s approval, according to Sen.
Chesapeake, Anadarko
Other producers active in the Eagle Ford benefited from the idea that they could get global prices for barrels with a minimal amount of processing. EOG Resources Inc. (EOG) gained 2.7 percent, the most since May 6. Chesapeake Energy Corp. (CHK) rose 2.5 percent, and Anadarko Petroleum Corp. (APC) climbed 2 percent.
Enterprise, the largest midstream company by market capitalization, advanced 1.4 percent after receiving the same ruling from the government.
The company will be able to use its pipelines, storage terminals and docks on the Gulf Coast to keep processed condensate segregated from non-exportable crude while transporting it from oil fields to tankers, Houston-based spokesman Rick Rainey said by phone.
Once exported, the condensate could be used as feedstock for oil refining or petrochemical plants, as diluent to be mixed with heavy crude, or for power generation, Rainey said.
Midstream Companies
Other midstream companies with assets in south Texas benefited from the ruling. Magellan Midstream Partners LP (MMP) gained 0.6 percent, while Kinder Morgan Energy Partners LP (KMP) rose 0.4 percent to the highest level since Jan. 28.
“To the extent that additional condensate is produced in response to the private rulings, we may see additional shipments on the Double Eagle Pipeline system which transports condensate from the Eagle Ford to our terminal in Corpus Christi,” Bruce Heine, a Tulsa, Oklahoma-based spokesman for Magellan, said by e-mail. “With the terminal’s multiple existing ship berths that can accommodate large vessels, we are positioned to serve the export market if it develops.”
Magellan and Kinder are among companies building condensate splitters along the Texas Gulf Coast. Splitters are simple refineries, designed to separate condensate into products like naphtha, kerosene and gasoil that can be exported or processed further in the U.S.
Corpus Christi
Magellan’s Corpus Christi splitter is fully supported by a long-term contract with commodity trader Trafigura Beheer BV, and won’t be affected by the Commerce rulings, Heine said. Kinder, which declined to comment, has a contract with BP Plc (BP/) to purchase the feedstock and sell the products from its Houston Ship Channel plant, which will start operating in November.
Companies that are evaluating splitters but don’t have contracts will likely be deterred by the ruling, and expansions of the already-planned plants are probably now off the table, Michael Blum, a New York-based senior analyst for Wells Fargo Securities, said in a research note today.
“There is a risk you could have some stranded assets,” Michael Wojciechowski, head of Americas downstream research for Wood Mackenzie Ltd., said by telephone from Houston. “It does call into question the viability of and the need for these condensate splitters.”
To contact the reporters on this story: Dan Murtaugh in Houston at dmurtaugh@bloomberg.net; Joe Carroll in Chicago at jcarroll8@bloomberg.net
To contact the editors responsible for this story: David Marino at dmarino4@bloomberg.net Bill Banker
By David Wethe and Mike Dorning Jun 26, 2014 3:32 AM GMT+0700 67 Comments Email Print
The U.S. is preparing sanctions aimed at specific areas of the Russian economy, including energy and technology, as the Obama administration readies the next steps to pressure Russia over the Ukraine crisis, according to three people briefed on the plans.
The sanctions would apply to technology used to explore, produce, transport, or deliver natural gas, crude and their refined products, according to two of the people, who asked for anonymity, citing the sensitivity of the deliberations.
Further U.S. action may await the results of a European Union summit scheduled to begin tomorrow. President Barack Obama is counting on support from the EU, which has deeper economic ties with Russia than the U.S., to make any wider sanctions more effective.
Any U.S. move to target sectors of Russia’s economy would mark an escalation of penalties against Russian President Vladimir Putin’s government for fomenting turmoil in Ukraine. Putin yesterday asked lawmakers in Moscow to rescind the authorization they gave him on March 1 to use force in Ukraine, a conciliatory gesture that sent shares and the ruble higher.
White House press secretary Josh Earnest, while not addressing specific steps the U.S. may take, said the administration has “evaluated a range of responses” to get Russia to back down in Ukraine. Any sanctions will be more effective “if many of Russia’s trading partners are cooperating in that effort,” he said.
On Agenda
While some EU members have expressed concern about the impact of new sanctions on their economies, German Chancellor Angela Merkel told parliament today that broader penalties against Russia are “back on the agenda” if progress isn’t made to end the Ukrainian conflict. Germany is Russia’s largest trading partner.
The U.S. government has held discussions with Canada, the U.K. and Australia on this latest round of penalties, said one of the people.
The turmoil and threat of additional sanctions has taken a toll on Russia. Russia’s $2 trillion economy is facing stagnation this year, with the central bank forecasting growth of 0.4 percent in 2014, the least since a recession in 2009.
In Moscow, the Micex Index (INDEXCF) fell today from an eight-month high. The gauge plunged 2.4 percent to 1,481.95 in Moscow after jumping to the highest since Oct. 22 yesterday.
Business Lobbies
There is concern in the U.S. about an economic impact as well. Two of the largest U.S. business groups are preparing to break ranks with the Obama administration over any further penalties on Russia, citing potential damage to U.S. companies.
The U.S. Chamber of Commerce and National Association of Manufacturers are preparing to run newspaper advertisements tomorrow in the New York Times, Wall Street Journal and Washington Post, warning that more sanctions risk harming U.S. workers and businesses, said a person familiar with the plans, who asked not to be identified to discuss private deliberations.
Earnest said Obama is “mindful of not putting American companies” at a “significant competitive disadvantage.”
Linda Dempsey, vice president of international economic affairs for NAM, said the group is “heightening the level of communication right now” after months of discussion with the administration and longstanding opposition to unilateral sanctions that may hurt U.S. business without having the desired impact.
Industry Reaction
“A U.S.-only approach here is not going to increase security in the region,” Dempsey said. “Taking action for action’s sake is not the way forward.”
Sally-Shannon Birkel, a spokeswoman for the chamber, declined to comment.
Under the latest plans being considered by the U.S., product sales and transfers of technology covered by the sanctions would be subject to case-by-case reviews, said one of the people, with the government being allowed to approve, reject or delay any transactions.
One of the people briefed on the planning said that administration officials had portrayed that approach as one that would allow them to use a scalpel to target individuals and to ratchet pressure up and down as events in Ukraine unfold.
U.S.-based companies are the largest source of foreign investment in Russia, primarily in technology and financial services, according to a 2013 report by Ernst & Young. They include General Electric Co. (GE), Boeing Co. (BA), and Caterpillar Inc. (CAT)
The business associations’ advertisements assert that “the only effect” of additional sanctions would be “to bar U.S. companies from foreign markets and cede business opportunities to firms from other countries,” according to a copy provided by the person familiar with the plans.
The ads, written as a joint statement from Jay Timmons and Thomas Donohue, respectively the presidents of the manufacturers association and the chamber, don’t name Obama. They instead address actions under consideration by “some U.S. policymakers.”
To contact the reporters on this story: David Wethe in Houston at dwethe@bloomberg.net; Mike Dorning in Washington at mdorning@bloomberg.net
To contact the editors responsible for this story: Steven Komarow at skomarow1@bloomberg.net; Susan Warren at susanwarren@bloomberg.net Joe Sobczyk, Michael Shepard
By Joe Carroll Jun 26, 2014 1:04 AM GMT+0700 1 Comment Email Print
Aubrey McClendon, the U.S. shale wildcatter who’s raised $10 billion in capital since getting fired from Chesapeake Energy Corp. (CHK) last year, acquired a stake in an Oklahoma pipeline project.
An affiliate of McClendon’s American Energy Partners LP contributed natural gas lines in exchange for a minority interest in Tall Oak Midstream LLC’s planned 250-mile (1,600-kilometer) pipeline and processing network, Oklahoma City-based Tall Oak said in a statement today.
McClendon’s company also dedicated drilling prospects spread throughout six Oklahoma counties to the new network, according to the statement. Casey Nikoloric, a Tall Oak spokeswoman with the public-relations firm Ten 10 Group, said the size of the acreage commitment wasn’t disclosed.
American Energy, also based in Oklahoma City, has an option to increase its stake to as much as 50 percent. McClendon announced plans on June 18 to expand his growing shale empire into the pipeline business, with backing from buyout firm The Energy & Minerals Group.
McClendon, 54, has been amassing drilling rights from Appalachia to the Great Plains since forming American Energy during the waning days of his quarter-century reign at Chesapeake. On June 9, American Energy announced its largest deal so far with the $4.25 billion acquisition of prospects in West Virginia, Ohio and Texas.
(An earlier version of this story was corrected after a spokeswoman for the company said the statement incorrectly described McClendon’s acreage dedication.)
To contact the reporter on this story: Joe Carroll in Chicago at jcarroll8@bloomberg.net
To contact the editors responsible for this story: Susan Warren at susanwarren@bloomberg.net Robin Saponar, Will Wade
By Isis Almeida Jun 25, 2014 11:01 PM GMT+0700 1 Comment Email Print
Ukraine has “a few months” of natural gas reserves, meaning it will have to sign an agreement on prices with Russia to guarantee supplies during the winter, according to Bank of America Corp.
Gas inventories in Ukraine are currently about 15 billion cubic meters (530 billion cubic feet), more than half of the country’s annual imports, Vadim Khramov, a Ukraine economist at the bank, said today at a press conference in London. Ukraine will try to source more gas from Europe if no agreement with Russia’s OAO Gazprom is reached in the next three to four months and may eventually be forced to sign a deal, he said.
Russia cut supplies to Ukraine, which carries about 15 percent of Europe’s gas needs through its pipes, after a June 16 payment deadline expired, echoing disputes that disrupted flows to the region in 2006 and 2009. Ukraine owes Gazprom more than $4.4 billion for fuel deliveries in November, December, April and May, according to the Russian state-run company.
“Ukraine has gas for a few months,” Khramov said today in an interview. Without Russian gas, the country will need to “look for other solutions within the next three months.”
Russia raised gas prices for Ukraine by 81 percent to $485 per 1,000 cubic meters in April by canceling previous rebates. While Gazprom offered to lower prices by $100, Ukraine rebuffed the proposal, saying it was prepared to pay $326, a compromise proposed by the European Union. The bloc has been trying to broker a deal between the two nations since May 2.
Any price below $400 per 1,000 cubic meters is a “good deal” for Ukraine as Russia charges European buyers about $380 per 1,000 cubic meters, Khramov said.
Conflict Effect
Ukraine needs six billion cubic meters of gas to keep pressure on its transit pipes that carry Russian fuel to Europe, according to Khramov. The nation consumes about 1.7 billion cubic meters a month in summer, he said.
A conflict in the eastern regions, where most of the country’s industry is located, might mean demand is even lower, at about 1.5 billion cubic meters a month, Khramov said. Consumption will rise during winter and supplies from the EU via so-called reverse flows won’t suffice, he said. In the long term, Ukraine will need to cut its energy consumption, he said.
Militants in Ukraine, seeking closer ties with Russia, have continued to attack government forces, defying a week-long cease-fire supported by both Russian President Vladimir Putin and rebel leaders. Ukraine can get gas from neighboring countries including Poland and Slovakia by reversing flows from west to east. RWE AG, Germany’s second-biggest utility, started delivering gas to Ukraine from Poland in April.
To contact the reporter on this story: Isis Almeida in London at ialmeida3@bloomberg.net
To contact the editors responsible for this story: Lars Paulsson at lpaulsson@bloomberg.net Rob Verdonck, Dan Weeks
By Isis Almeida Jun 25, 2014 5:27 PM GMT+0700 0 Comments Email Print
European natural gas buyers that renegotiated supply contracts with Russia’s OAO Gazprom in the past 14 months got a price rebate of as much as 20 percent, the International Center for Natural Gas Information said.
Long-term contracts reviewed in the period account for about 60 billion cubic meters (2.1 trillion cubic feet) a year of gas, Cedigaz, as the Paris-based center is known, said today in a statement. That’s about a third of Gazprom’s deals in Cedigaz’s database of 185 long-term pipeline-gas supply contracts signed from 1965 to 2014. Buyers got discounts of 10 to 20 percent and a reduction of take-or-pay obligations, the center said.
“The active trend of price and volumes renegotiations has been continuing with an equal strength in the past 14 months,” Cedigaz said. Agreements on new terms highlight “an ongoing push towards more linkage to market prices,” it said.
European natural gas buyers are pushing to renegotiate long-term supply contracts after the premium of oil-linked fuel to that on hubs rose to the most since 2009. Gas for next month on Germany’s biggest hub costs 34 percent less than under long-term agreements linked to oil, the biggest gap since March 2009, according to Bloomberg’s gas contract calculator using the Bafa proxy for 2014. Long-term supply deals are usually based on the price of oil and oil products instead of gas trades on European hubs.
GDF Suez SA, France’s largest gas company, plans to agree new supply terms with OAO Gazprom next year, Vice Chairman Jean-Francois Cirelli said in a June 3 interview. Eni SpA, Gazprom’s largest client, renegotiated a contract last month, a move Stanford C. Bernstein said would boost operating profit at its gas and power unit by 560 million euros ($760 million).
Price Revisions
Buyers from EON SE to RWE AG have won price revisions with suppliers through talks or arbitrations after they posted losses selling gas into domestic markets and the cost price for the fuel used in heating diverged from oil. Italy’s Eni also renegotiated a contract with Norway’s Statoil ASA (STL) this year.
Milan-based Edison SpA expected its arbitrations with Gazprom and Eni to be completed “in a few months,” Pierre Vergerio, chief operating officer of the Italian gas arm of Electricite de France SA, said May 22.
“Gazprom was not the sole provider to face tough renegotiations of its long-term contracts,” Cedigaz said. “All major European suppliers were either brought to the negotiating table or subjected to arbitration.”
New long-term contracts accounting for 11.4 billion cubic meters a year were added to the database in the 14-month period, according to the statement. Those include nine for supplies from the BP Plc-led Shah Deniz project in Azerbaijan with European buyers. Cedigaz’s database includes 126 contracts in force for supplies of 449 billion cubic meters a year.
To contact the reporter on this story: Isis Almeida in London at ialmeida3@bloomberg.net
To contact the editors responsible for this story: Lars Paulsson at lpaulsson@bloomberg.net Rob Verdonck, Claudia Carpenter
Mark Finley, general manager of global energy markets and U.S. economics for BP, presents its 2014 Statistical Review of World Energy. Photo: Collin EatonPhoto By Collin Eaton Mark Finley, general manager of global energy markets and U.S. economics for BP, presents its 2014 Statistical Review of World Energy.
International oil supply disruptions in the Middle East have offset nearly every new barrel of oil goosed out of U.S. shale in the past three years - a tenuous balance that has kept prices steady, a BP economist says.
International benchmark Brent crude has averaged above $100 a barrel for three years, the longest span in the history of the oil industry and the most stable period for prices since 1970, said Mark Finley, BP's general manager of global energy markets and U.S. economics.
Without the surge in U.S. crude production, markets would have demanded higher prices, threatening the economic recovery, and the United States probably would have released oil reserves from its strategic stocks.
"But as it is, the market has settled on this eerie calm," said Finley, who presented BP's annual Statistical Review of World Energy at the University of Houston Tuesday evening.
Social unrest in Libya, international sanctions on Iran and other disruptions in the Middle East and North Africa pushed oil production from the region down by 3 million barrels per day in the fourth quarter of 2013, but new shale plays in the U.S. grew oil production by the same amount - nullifying the effects of both on global crude prices, according to BP data.
In addition to holding back extreme oil prices and potential economic turmoil, the U.S. shale energy boom is part of a wave of market forces starting to correct large global trade imbalances, according to the London-based oil company's report.
Finley said economists often point to the United States' heavy reliance on imported goods and China's high level of exports as among the biggest risks to the international economic system. But increased dependence on energy imports has cut China's trade surplus nearly in half, and the shale boom has allowed the U.S. to decrease its energy imports.
Energy, which accounts for about 15 percent of global trade, "is acting as a constructive force for the international economic system by helping work out some of these structural imbalances," Finley said.
Still, he added, there's a long way to go: Energy still accounts for about half of the U.S. trade deficit.
© Copyright 2014 Hearst Newspapers, LLC
Fracking boom, surpluses prompt US towards lifting ban on crude shipments
[WASHINGTON] The United States will allow two companies in Texas to export unrefined oil for the first time in four decades, taking steps to break a ban on crude exports.
The Wall Street Journal reported on Tuesday that the Commerce Department will permit the two companies - Pioneer Natural Resources of Irving and Enterprise Products Partners of Houston - to export the ultra-light condensate, which has grown in supply on the back of the boom in fracking-based exploration and production of natural gas.
"With relatively minimal processing, oil shipments could begin as early as August, according to one industry executive involved in the matter," the newspaper reported.
Pressure has been building for a year for the US government to end the 1970s ban on exports, an energy security measure long seen crucial in a country heavily dependent on oil imports to meet domestic needs.
Copyright © 2014 Singapore Press Holdings Ltd. Regn No. 198402668E
By JONATHAN FAHEY and DINA CAPPIELLO
The Associated Press
NEW YORK -- Companies are taking advantage of new ways to export oil from the U.S. despite government restrictions, and in the process helping the U.S. become an ever bigger exporter of petroleum on the world stage.
The Obama Administration has opened the door to more exports — without changing policy — by allowing some light oils to be defined as petroleum products like gasoline or diesel, which are not subject to export restrictions.
Although U.S. production has boomed in recent years, the nation still consumes far more crude oil than it produces and remains heavily dependent on imports. But the crude being produced by U.S. drillers in recent years includes types of oils that don't have a big market here. This has the oil industry and some politicians calling for an end to crude export restrictions, which were adopted after the 1973 Arab oil embargo.
Economists generally agree that lifting the restrictions would benefit the U.S. economy, but the ban remains a touchy political subject because of the fear — unfounded, most analysts say — that lifting the ban on exports will raise gasoline prices for U.S. drivers or compromise U.S. energy security. Most experts believe the restrictions will not be overturned this year because of the coming midterm elections.
In the meantime, companies have searched for ways to reach overseas buyers. Oil companies are increasingly exporting crude to Canada with special licenses from the Commerce Department. Other types of light oils known by names such as "diluent" and "condensate" are — or will soon be — finding their way overseas too.
"Add it all up and you get to 1.1 million barrels of potential exports of crude out of the U.S. without changing the law, without changing the system," said Ed Morse, head of commodities research at Citigroup.
That would make the U.S. a major oil exporter and add to its growing volume of fuel exports. The Energy Department reported earlier this month that U.S. crude exports reached 268,000 barrels per day in April, its highest level in 15 years. Last year the nation exported a record 2.7 million barrels of fuels per day, making the U.S. the world's largest exporter of gasoline, diesel and other fuels.
When an ultra-light oil called "lease condensate" comes out of the ground it is considered a crude oil by regulators. But companies must run the substance through distillation equipment that removes dissolved gases in the oil and stabilizes it for transportation through a pipeline. It then becomes something called "processed condensate."
The industry and regulators have also considered this a type of crude, because it must be further refined to be used to make chemicals or fuels, and it is not currently exported.
But the Commerce Department, in response to inquiries from Pioneer Natural Resources and Enterprise Products Partners, said that the processing required to prepare the oil for transport is enough to allow this process condensate to be considered a petroleum product, and therefore eligible for export without restriction.
Pioneer said in a statement Wednesday that the ruling, which is not public, "Confirmed our interpretation that the distillation process...is sufficient to qualify the resulting hydrocarbon stream as a processed petroleum product eligible for export without a license."
The Obama Administration said Wednesday there has been no change in its crude export policy. "We are closely studying the economic, environmental and security challenges" posed by oil exports and will evaluate changes to U.S. policy as needed in the future," said White House spokesman Josh Earnest.
Condensate is generally split into its specific chemical constituents, such as butane, ethane, and propane, and then sold to chemical companies to make into plastics, or to refiners as ingredients for fuels.
Condensates or other light oils from the U.S. are also expected to be exported through another means — as a substance called diluent that is mixed with heavy Canadian crude to make it match the requirements of overseas refiners.
Even large-scale exports of these condensates are expected to have little or no effect on fuel prices for U.S. consumers. Condensates aren't a major component of most fuel production, and prices for U.S. fuels are subject to global market forces because they can be exported freely.
"It's not credible to say that if we export more condensates that would cause a spike in prices at the pump," said Citi commodity strategist Eric Lee.
The American Petroleum Institute, a lobbying group that represents oil companies, said the rulings do not change its contention that the restrictions on crude exports should be lifted.
"It certainly doesn't address the major issue," said Kyle Isakower, vice president for regulatory and economic policy at API. "We still have this mismatch of crudes in the U.S., a glut of light sweet crude and no refining capacity to take it."
The rulings do affect one glut, however. The price of condensate is cheaper than global crude by $10 to $30 a barrel because so much of it is being produced by U.S. drillers working in shale formations, particularly in South Texas, and it has had nowhere to go — until now.
"These products need a home," said Enterprise Products Partners spokesman Rick Rainey.
Josh Lederman contributed to this story from Washington. Cappiello reported from Washington.
Copyright © The Sacramento Bee
BY ALEX DEMARBAN
alex@alaskadispatch.com
ConocoPhillips' chief executive said Tuesday that Alaska's LNG megaproject can be developed under the right conditions despite a growing field of competitors, but a state official said the global oil giant is the only one of five partners in the project that is not ready to sign an agreement to move it forward.
A company spokeswoman said ConocoPhillips is ready to sign an agreement that is fair to everyone. Other entities involved in the Alaska project are BP, Exxon Mobil, pipeline builder TransCanada and the state's Alaska Gasline Development Corp.
Ryan Lance, credited with putting Conoco's Alpine field into development in 2000 before moving out of state to manage projects around the world, told hundreds of people at the Resource Development Council's annual meeting in Anchorage Tuesday that he was glad to be returning home to his daughter's birth state.
During a talk about Alaska's role in the nation's oil and gas renaissance, he made no mention of potential offshore development in the U.S. Arctic, where Conoco holds leases but where Royal Dutch Shell has faced costly hurdles and made little progress in its own attempts to get drilling underway there.
ConocoPhillips is not pursuing anything in the Chukchi Sea right now, company spokeswoman Natalie Lowman said in an email.
Lance said the shale revolution in the Lower 48 has led to a natural gas boom and that numerous projects are seeking approval to export liquefied natural gas. Companies in the U.S. have filed plans with agencies to build 40 liquefied natural gas terminals, and other projects outside the U.S. are also in the works. The Department of Energy has permitted six terminals for non-free-trade-agreement exporting, but only one is under construction: Cheniere Energy's Sabine Pass project in Louisiana.
Not all of those projects will happen, in part because there is too much proposed supply, said Lance.
Alaska's $40 billion to $65 billion project -- calling for a roughly 800-mile pipeline from Alaska's North Slope, as well as a liquefaction facility at Nikiski to super-chill the gas to a liquid so it can be exported in tankers -- has not filed for permitting.
But it can move forward with reasonable fiscal terms and supply costs and beat out competitors, Lance said. Alaska's advantages include a more-than-40-year history of exporting LNG, as well as proximity to Asia, where gas prices are higher than in the U.S. and the United Kingdom.
Flat Alaska investment
The oil boom from shale rocks in the Lower 48 has also positioned the U.S. to become the world's top crude oil producer by 2025, he said. Because of that, global profits are flowing to U.S. projects.
But investment stayed flat in Alaska in recent years because of the previous "adverse" tax system, known as Alaska's Clear and Equitable Share, he said. With the tax cut taking effect in January, Conoco is investing 50 percent more this year than last, with capital investments set for $1.7 billion. That's twice the average annual investment between 2008 and 2012, Lance said. Because of the tax cut, Conoco is advancing projects that could result in 40,000 extra barrels of oil by 2018.
Critics of Senate Bill 21 have said those projects were already in the works under ACES.
Lance said the tax cut is important to ConocoPhillips because it removes the old system's progressive tax rates that increased with the price of oil, creating more "equitable" profits for oil producers and increasing the potential long-term income for new projects.
It also strengthens the oil industry, making an LNG project more competitive, he said.
That project is nearing an important juncture. Joe Balash, the state's Natural Resources director, said after the speech that a joint venture agreement between the state, oil companies and TransCanada was scheduled to be signed by the end of this month. The agreement would move the project ahead into what's known as the pre-FEED stage, meaning some hundreds of millions would be spent on preliminary engineering and design work.
If the project stays on track, more engineering and design work will come later, in another phase starting in 2016, assuming the Alaska Legislature still supports the project and all the companies are still on board.
Balash said that BP, Exxon Mobil, TransCanada and the state, through the Alaska Gasline Development Corp., said last week that they are ready to sign the agreement to move into the pre-FEED stage.
ConocoPhillips, however, is not ready to sign, Balash said. Asked to explain why, he said he did not understand Conoco's reasoning.
Conoco spokeswoman Natalie Lowman acknowledged in an email that the joint venture agreement is not finalized.
But, she said, "ConocoPhillips is ready to sign a (joint venture agreement) that provides for long-term commercial alignment and is subject to fair terms for all parties, which in turn will be good for the project and for the state of Alaska."
She said Conoco is "working with the other parties to finalize terms that are acceptable to all of us."
Copyright©adn.com
By Anna Shiryaevskaya Jun 25, 2014 4:52 PM GMT+0700 3 Comments Email Print
Koch Supply & Trading, a unit of Koch Industries Inc., will start buying and selling European electricity and expand its liquefied natural gas business to take advantage of a globalizing market for the fuel.
The trading unit of the second-largest closely held U.S. company by revenue is hiring one or two power traders in Geneva and plans to be ready for trading next year, Stephen Cornish, director of Koch Supply & Trading, said in a telephone interview from London. The company will expand into Turkey and the Caspian region in 2015 and open an office in Tokyo for its LNG business this year, he said.
Koch is expanding in power as companies from Bank of America Corp. to Cargill Inc. pull out of the market as prices trade near a nine-year low after the euro region’s longest recession cut demand. As many as 120 European power and gas traders lost or changed their jobs last year in the biggest shakeout of the industry since the collapse of Enron Corp. more than a decade ago.
“We don’t build our business based on whether the markets are up or down,” Cornish said. “There are a lot of counterparts out there that are re-evaluating their business models and are looking for high quality counterparts to do deals with. In that scenario we think we can add value.”
German year-ahead power, a European benchmark, fell to the lowest since 2005 in April and traded at 34.50 euros ($46.93) a megawatt-hour at 10:17 a.m. London time today, according to data from European Energy Exchange AG. Thirty-day volatility fell to 4.3 percent today, its lowest since June 2003.
Gas, LNG
Koch is looking to expand into mainland European power markets from Geneva, its base for gas trading and origination in Europe, the Middle East and Africa, after a separate London-based business focused on the U.K. exited the market in 2011, Deanna Altenhoff, a spokeswoman for Koch, said June 23 by e-mail. Koch Energy Europe Ltd. traded natural gas, power and emission credits, according to a company statement in 2010.
Koch started trading crude oil in 1969 and added global gas and LNG to its portfolio in 2012, according to the company’s website. As part of a large industrial conglomerate, which itself is a gas consumer, Koch benefits from dealing with industrials, which “want to talk to like-minded companies,” Cornish said.
“When it comes to power, we believe there should be an opportunity for us there too,” Cornish said by telephone from London on June 13. “We are getting requests to get involved in that market to map over the success that we have had in European natural gas.”
Koch Supply & Trading plans to enter Turkey and the Caspian region next year, he said. In addition to Geneva, the company has an Amsterdam office for its gas sourcing needs and a presence in Dusseldorf, Germany, for some of its marketing activity, he said.
‘Natural Need’
The company’s LNG business is based in London with trading and origination operations in Singapore and Houston and satellite offices in Rio de Janeiro and Dubai. The company may expand further in the Far East and in South America, if opportunities arise, he said.
Renewables, shale gas, the 2008 economic crisis and the Fukushima nuclear disaster in Japan have all impacted the market, Cornish said. While the global LNG market will remain tight through next year, trade will start to increase in 2016 as Australian projects now under construction start producing the super-chilled fuel and U.S. exports begin, the International Energy Agency said in its medium-term natural gas market outlook on June 10.
Koch has done LNG deals in both the Atlantic and Pacific regions, according to Cornish.
“We have a natural need to be in the market,” he said. “If you are a natural market participant with a global reach, a great balance sheet, and lots of physical activity, you have a significant role to play.”
To contact the reporter on this story: Anna Shiryaevskaya in London at ashiryaevska@bloomberg.net
To contact the editors responsible for this story: Lars Paulsson at lpaulsson@bloomberg.net Rob Verdonck, Claudia Carpenter
By Naureen S. Malik Jun 26, 2014 6:01 AM GMT+0700 0 Comments Email Print
Rising U.S. shale gas production is driving fear out of the futures market, says Goldman Sachs Group Inc., and will constrain prices for the next two decades.
Gone will be the near tripling of costs to $15.78 as in 2005 as traders remain confident the fuel will be there when needed. Natural gas will trade “largely” at $4 to $5 per million British thermal units for the next 20 years, says Goldman Sachs. Societe Generale SA sees prices at $5 through 2019. Bank of America Corp. forecasts $5.50 for 2017, while BlackRock Inc. projects $4 to $5 for the next decade.
Prices were four times more volatile in 2009 than they are today as production grows for the ninth straight year and new pipelines deliver the fuel to customers. Gas for use next winter costs 3.2 percent more than now, the smallest premium for the peak-demand period since 2000. Stockpiles will start the heating season at the lowest levels since 2008.
“The market is rightfully not that worried because you have so much supply that is coming online,” Jeffrey Currie, head of commodities research at Goldman Sachs in New York, said in a June 23 telephone interview. “We have enough flexibility in the supply system.”
Natural gas futures for July delivery rose 0.4 percent to $4.553 per million Btu yesterday on the New York Mercantile Exchange. The January contract gained 0.2 percent to $4.697, an 14.4 cent premium to July.
Government Forecast
The U.S. Energy Information Administration forecasts natural gas prices will average below $5 through 2023 and less than $6 until 2030. The fuel will average less than $5 through 2017, based on analyst estimates compiled by Bloomberg.
Fears of gas shortages have dissipated since 2005, when hurricanes Katrina and Rita damaged Gulf of Mexico production platforms. Offshore gas accounted for 5 percent of U.S. supplies last year, dropping from 17 percent in 2005, as shale-gas output, boosted by hydraulic fracturing, or fracking, surged from Pennsylvania to Texas.
U.S. output will increase 4 percent in 2014 to a record for the fourth consecutive year, according to the EIA, the Energy Department’s statistical arm.
Marcellus Production
Gross production from the Marcellus field in the Northeast, the country’s largest deposit, will average 15 billion cubic feet a day in July, up 26 percent from a year earlier and 10 times the output in 2009, EIA date show.
“Right now prices are close to or a bit below where the economics are needed to sustain volumes for the longer term,” Poppy Allonby, a portfolio manager at BlackRock’s Commodity Strategies Fund in London. Shale production will keep gas in the $4-$5 range for the next 10 years, though prices may jump with demand from time to time, she said.
The new complacency among gas consumers has reduced trading and lowered prices, Teri Viswanath, director of commodities strategy at BNP Paribas SA in New York, said in a June 19 telephone interview.
Open interest in Nymex gas was 1.05 million contracts on June 24, down 26 percent from a year earlier, according to futures market data compiled by Bloomberg.
“Prices are really depressed and they don’t reflect the demand story,” Viswanath said. “If there are enough of these customers who have not purchased their supplies ahead, we are likely going to see some price volatility.”
Open Interest
Open interest in gas futures, the number of outstanding contracts, rose to an all-time high of 1.59 million in April 2013, when a cold start to spring caused what was then a record stockpile deficit. On April 18 of that year, the December 2025 futures contract traded at $7.216, about $2.80 above the front month. Today, the spread is about $1.40.
The added ability to move the heating fuel to nearby consumers in the winter, when demand is highest, has kept futures prices trading within about 33 cents of $4.50 since early March even after inventories dropped to an 11-year low.
Based on the EIA’s estimates, stockpiles at the end of October will equal 43 days of normal winter demand. The 10-year average is 50 days.
Fewer days of supply “is a larger bet by the collective wisdom in the marketplace that maybe we need less gas in storage,” Martin King, an analyst with FirstEnergy Capital Corp. in Calgary, said in a June 17 telephone interview. “There is a real complacency with the view that supply will bail us out, no matter what.”
Gas Reserves
The U.S. had 2,431 trillion cubic feet of recoverable gas, more than any other country, a June 2013 government analysis showed. This represents a century’s worth of output and can support peak production at more than twice the 2013 level, according to Goldman Sachs.
Gas stockpiles will climb to 3.424 trillion by the end of October, which would be the lowest level at the start of a heating season since 2008, from 822 billion cubic feet in March, the least since 2003, according to EIA estimates.
TransCanada Corp.’s ANR Pipeline completed a project in April that began sending Marcellus gas west, according to the EIA. Spectra Energy Corp.’s Texas Eastern Transmission pipeline plans to bring 900 million cubic feet a day of capacity online to move gas out of Appalachia.
The Rockies Express Pipeline, which can carry 1.8 billion cubic feet of gas daily from Colorado to Ohio, is making part of the line bidirectional, giving the company the option of sending Marcellus gas west to Indiana and Illinois.
“Even if stockpiles end at 3.55 trillion, or something really low like that at the end of October, you have that continued flexibility” from new pipeline capacity, Goldman Sach’s Currie said. “People no longer have this fear of the future.”
To contact the reporter on this story: Naureen S. Malik in New York at nmalik28@bloomberg.net
To contact the editors responsible for this story: Dan Stets at dstets@bloomberg.net Bill Banker
Lagos (Platts)--25Jun2014/904 am EDT/1304 GMT
Nigeria, with reserves of over 180 trillion cubic feet of gas, is prepared to help meet the European Union's long term natural gas demands, Nigerian oil minister Diezani Alison-Madueke said, according to a statement from her office Wednesday.
Alison-Madueke held talks with Guenther Oettinger, the EU Energy Commissioner, on the sidelines of EU-OPEC Energy Dialogue Ministerial Meeting in Brussels, on how Nigeria could help ensure the EU's long-term security and diversification of gas supplies, the statement said.
"The discussions focused on the role Nigeria can play in supporting the EU's energy sector priorities," Alison-Madueke was quoted saying.
"The Federal Government restated its resolve to support the long term gas supply security for the European Union countries as part of measures to expand the nation's gas market," the minister said.
According to Alison-Madueke, Nigeria has over 180 Tcf of discovered gas reserves and up to 600 Tcf of undiscovered gas reserves, is currently the eighth largest gas producer in the world and sixth largest gas supplier to Europe.
Nigeria is planning significant investments to increase gas production and export capacity, particularly with the completion of new LNG projects, the minister said.
Europe is witnessing rising demand for natural gas following new projects, while at the same time the EU is aiming to reduce its energy dependence on Russia as a result of the Ukraine crisis.
Nigeria currently produces around 8.24 Bcf/day of gas and exports around 22 million tonnes of gas produced at the Bonny LNG plant.
The statement quoted Oettinger saying that the EU recognized the long-term potential of Nigeria's energy sector and would welcome further discussions to explore ways for greater collaboration between the EU and Nigeria.
--Staff, newsdesk@platts.com
--Edited by Jeremy Lovell, jeremy.lovell@platts.com
By Andy Tully | Wed, 25 June 2014 21:15 | 0
Benefit From the Latest Energy Trends and Investment Opportunities before the mainstream media and investing public are aware they even exist. The Free Oilprice.com Energy Intelligence Report gives you this and much more. Click here to find out more.For the first time in almost 40 years, the U.S. Commerce Department has given two American companies permission to export ultralight oil, known as condensate.
The beneficiaries of the move so far are Texas-based Pioneer Natural Resources Co. and Enterprise Products Partners LP. The decision, reported June 24 by The Wall Street Journal, is expected to prompt requests from other companies to export their oil.
Congress banned the export of most U.S. crude oil, except under special circumstances and with specific licensing, in response to the economically crippling Arab oil embargo on shipments of oil to Western countries that supported Israel during the Yom Kippur War of 1973.
Since then, only refined petroleum products such as gasoline and diesel could be exported. Exports of all crude or refined oil to Canada continued without interruption if an exporter had a special permit.
Today, though, so much U.S. oil is being extracted from shale that the price of ultralight oil has dropped appreciably, leading U.S. oil producers to petition for a relaxation of the export ban, arguing that foreign customers would pay more for their product than refiners in the United States.
Pioneer Natural Resources explains that ultralight condensate is minimally processed to remove only its much lighter components such as butane and therefore was refined enough to qualify it for export.
The Commerce Department’s hasn’t announced the reported decision – it said June 24 there had been “no change in policy on crude oil exports” – but already there’s been reaction in Congress, both pro and con.
Sen. Lisa Murkowski of Alaska, the ranking Republican on the Senate Energy Committee, said the decision represents “a reasonable first step that reflects the new reality of our energy landscape,” and she urged the administration to lift the ban altogether.
Sen. Edward Markey, D-Mass., criticized the decision, saying exporting oil puts the United States on a “slippery slope” at a time of great instability in Iraq and Libya and when tensions are high with Russia over its dispute with neighboring Ukraine over Russian gas.
“Congress put this oil export ban in place,” Markey said. “It should be Congress that decides when and how to change it, not through a private ruling by the Commerce Department without public debate.”
By Andy Tully of Oilprice.com
Houston (Platts)--25Jun2014/541 pm EDT/2141 GMT
US benzene production increased moderately to 101,760 b/d for the week ending June 20, a Platts analysis showed. The small increase in supplies came amid higher refining throughput, with the biggest jump in crude utilization occurring in the Gulf Coast, according to data released by the Energy Information Administration on Wednesday.
Total benzene demand was estimated by Platts at 138,670 b/d for the corresponding week. As a result, it is estimated that the US market was in a short position of roughly 36,910 b/d for the week ending June 20.
The supply deficit for the week ending June 20 is slightly less than the prior week when the shortage was estimated at 37,660 b/d. However, the estimated shortfall is far greater than the two months prior average when the supply deficit was estimated around 32,390 b/d.
The estimated deficit is derived prior to taking into account benzene imports. However, benzene imports were just over 85,000 b/d in April and around 75,000 b/d in March, data from the US International Trade Commission showed. May benzene trade data will be released by the USITC on July 3.
The current benzene deficit is expected to fall over the summer months as gasoline demand increases, which drives up reformate supply and reformate is a key feedstock for benzene. The shortage is forecast to drop to just under 35,790 b/d in July as forecasted refining run-rates reach their highest level on summer driving demand. Looking ahead, the supply deficit should begin increasing in October as crude utilization slows along with petrochemical utilization.
PRICES SURGE
USGC benzene prices continued rising over the last week, hitting a five-month high Tuesday and nearing record highs, while downstream benzene markets continued to be pressured higher.
US spot benzene pricing rallied 24 cents/gal ($71.83/mt) Tuesday, reaching a five-month high assessment at $5.35/gal ($1,601.25/mt) FOB US Gulf Coast, based on Platts data. US spot pricing was last seen above this level January 17, when assessed at $5.47/gal FOB USG, Platts data showed. Spot has risen 90 cents/gal ($269.10/mt) since June 4.
Sources have attributed recent gains to production hiccups, which are contributing to limited supply availability.
July benzene contracts could settle above $5/gal because of higher benzene pricing during June, sources said.
Market participants said prices could head even higher during the end of June, but anticipate lower prices in July as imports arrive from other regions and as production issues end.
MARGINS IN GREEN
Reforming margins remain strong on the Gulf Coast as the naphtha and reformate delta stands at a profitable level. Reformate demand should remain strong in the summer in connection with gasoline demand. Reformate run-rates have historically peaked in July, according to EIA data.
The spike in benzene prices has helped margins for aromatics extraction, as well as on-purpose benzene production from processes such as TDP and MSTDP over the past month. Aromatics extraction margins were at $59.72/mt on Tuesday, climbing out of the doldrums and doubling from where they stood a month ago. The TDP margin was at $218.70/mt, while the MSTDP margin was at $67.92/mt.
--Mike McCafferty, michael.mccafferty@platts.com --Edited by Katharine Fraser, katharine.fraser@platts.com
London (Platts)--25Jun2014/313 pm EDT/1913 GMT
BNSF is sending as many as 19 oil trains a week, each carrying at least 1 million gallons of crude, through Washington state, according to a disclosure the railroad filed with the state, including up to 13 trains through heavily populated King County, where Seattle is located.
The disclosure, required under an emergency order issued by the US Department of Transportation in May, was posted on the state's Emergency Management Division website late Tuesday.
Short-line railroad Portland and Western Railroad also disclosed moving three oil trains carrying at least 1 million gallons of crude each through Washington.
Washington is among a handful of states to post details about oil trains moving through them, despite requests by BNSF and other railroads to keep the routing information and crude-by-rail volume figures private for security reasons.
Montana is scheduled to post online its oil train information later Wednesday, while Virginia on Monday posted details about CSX's crude-by-rail movements through its state, as Platts previous reported.
Under an emergency order issued by US Transportation Secretary Anthony Foxx in response to several derailments and accidents involving oil trains, railroads are required to inform states about how many trains transporting more than 1 million gallons of crude are traveling through them and what routes they are using.
The information is to be shared with state emergency responders to allow them to better anticipate and respond to any incidents, particularly as concerns arise over the growing volumes of crude-by-rail shipments through heavily populated areas.
But several railroads, including CSX and BNSF, have asked states not to provide some of that information to the general public, in some cases threatening legal action against states if they do so, according to local media reports.
Some states, such as California, New Jersey and Colorado, have signed confidentiality agreements with the railroads, while others, including Washington, have not.
BNSF spokeswoman Roxanne Butler said in an emailed statement that the railroad would no longer legally fight with states to prevent public disclosures of its crude-by-rail movements, but stressed that such information is extremely sensitive.
In its disclosure filed with Washington, BNSF labeled each page with headers that said "Sensitive Security Information" and "Railroad Restricted Material."
"We think it is very important that those responsible for security and emergency planning have such information to ensure that proper planning and training are in place for public safety, but we also continue to urge discretion in the wider distribution of specific details," Butler said.
Washington on Tuesday had posted a disclosure from short-line railroad Tacoma Rail, which said it is moving three trains/week through Pierce County carrying between 2.5 million and 3.4 million gallons of crude each. The railroad said it receives unit train deliveries of Bakken crude from BNSF into its main terminal yard tracks in Tacoma.
--Herman Wang, herman.wang@platts.com --Edited by Jason Lindquist, jason.lindquist@platts.com
Singapore (Platts)--25Jun2014/704 am EDT/1104 GMT
Condensate buyers in Asia say they may consider taking US exports in the wake of a ruling that would allow US companies to send lightly processed condensates overseas.
Asian condensate users could seek U.S. supplies of condensates as demand in the region is expected to climb as new splitter capacity comes on line this summer.
"We don't mind if it's processed condensate or not," said a buyer with a South Korean refinery. "Some splitters can process even ultra-light crude. It's not a big deal."
The US Commerce Department granted two companies that produce shale condensate from the Eagle Ford formation -- Pioneer Natural Resources and Enterprise Products Partners -- licenses to export the condensate as long as it is processed through a distillation tower.
"I think [the condensate will come] here this way, Japanese and Koreans [will buy it]," said a Singapore-based trader.
The production of U.S. condensate -- very light hydrocarbons that have typically been re-blended with crude oil during production -- has dramatically increased amid the ongoing shale boom, and condensate production in the Eagle Ford has greatly outpaced blending capacity.
The US decision comes as three new condensate splitters are set to come online.
South Korea's SK Innovation is starting test runs on its two splitter towers, each with capacity of 100,000 b/d, at its refinery in Icheon, South Korea, in June.
Samsung Total, a joint venture between South Korea's Samsung Group and French major Total, plans to start production at its 150,000 b/d splitter at Daesan in July or August. The splitter is part of a new Won 1.66 trillion ($1.56 billion) aromatics plant.
Also, Singapore's Jurong Aromatics Corporation will bring its 75,000-100,000 b/d splitter online in June, which will see the production of aromatics as well as across-the-barrel oil products.
Other Asian countries may also be looking at US condensates. Japan's largest refiner JX Nippon Oil & Energy confirmed Wednesday that it is looking at importing US condensates, among other options.
"With a view to diversifying our supply sources, we are studying various possibilities of procurements, not just limited to the US or Canada," a JX spokesman said.
JX has a combined capacity of 98,500 b/d over two condensate splitters at its Mizushima and Kashima refineries in Japan.
South Korean buyers may be able to take advantage of a free trade agreement with the US. However, if the condensate is classified as a refined product leaving the US after being processed, that may negate the tax advantage, said the Korean buyer.
A US Commerce Department spokesman on Tuesday reiterated that there has been no change in US export policy on crude oil. "Consistent with the regulatory definition, crude oil that has been processed through a distillation tower which results in the crude becoming a petroleum product is no longer defined as crude oil," Commerce spokesman Jim Hock said. "Petroleum product can be exported without a license, except in very limited circumstances."
--Christian Schmollinger, christian.s@platts.com
--Takeo Kumagai, takeo.kumagai@platts.com
--Dan Colover, daniel.colover@platts.com
--Edited by Jonathan Fox, jonathan.fox@platts.com
Paris (Platts)--25Jun2014/525 am EDT/925 GMT
* A dozen European refineries could close in coming years
* France worst hit as capacity shrinks 30%
* Rising US product imports came as surprise
* Additional closures likely in Italy
Pressure for refinery closures in Europe is stepping up as competition from the US, the Middle East and Russia accelerates, with industry players predicting around a dozen closures in the next few years.
But many in the industry fear this will not be enough to save a sector in desperate need of cheaper energy sources to bring back their refineries to profitable levels.
The competitiveness of European refineries has been severely hit in recent years by overcapacity, falling demand, new capacity coming on stream in the Middle East and surging competition from US oil product exports.
Fourteen refineries have closed in Europe since 2007, bringing the total in 2013 to 87, with the highest number of closures taking place in France, where refining capacity has shrunk since 2008 by 30% to 1.4 million b/d.
"On the global picture there are many things pointing to a worse refining outlook for European refiners," said Jonathan Leitch, senior analyst with Wood Mackenzie. "We knew that new refineries in the Middle East would be coming on so that's not a shock but I don't think we could understand quite how much the increase in US domestic crude production was going to help US refiners."
Since summer 2008, The US has benefited from a boom in shale gas production, which has led to cheaper feedstocks for its refining industry and left the EU struggling to remain profitable globally.
Industry players say that more closures will be inevitable in the coming few years, with refining margins plunging to Eur15/mt ($2.78/b) so far in 2014, down from Eur18/mt in 2013 and Eur36/mt in 2012.
"European refining will not escape a new wave of restructuring," Jean-Louis Schilansky, head of France's oil industry lobby UFIP, told Platts.
"In France, a third of capacity has already closed, which is more than other European regions," he said, adding this did not mean France would necessarily escape more closures.
OVERCAPACITY
While France's refining capacity stands at 1.4 million b/d, demand is currently closer to 1.5 million b/d.
"This situation is related to the gasoline/diesel demand unbalance but it's also because three refineries have closed," Schilansky said. "In France we have switched from an overcapacity issue to one of competitiveness." Despite having some of the most efficient refineries globally, the EU has been struggling to halt a backslide in net profit margins against Asia and the US, as higher energy and personnel costs and smaller-scale plants take away their competitive edge.
Schilansky predicted that 12 refineries would close in the next six years in Europe, slashing the number of refineries on the continent to 75.
"The situation cannot last without operators taking action," he said, adding that the French sector had lost Eur700-800 million in 2013 and that this trend was set to worsen in 2014.
Overcapacity in Europe is pegged by the French oil industry at 1 million b/d, with that figure expected to climb to 1.5 million b/d by 2020, or the equivalent of six average size refineries, according to UFIP data.
Closures are likely to come from Italy, Schilansky said. Capacity there has shrunk by 10% over the past six years compared with 15% in Germany and 22% in the UK.
Leitch said throughputs in Europe needed to fall by 1.9 million b/d between 2012 and 2018.
"The difficulty is that it does not mean that there will be more closures because as we can see refineries continue to operate even at levels that are uneconomical," he said. "If you are a refiner and you close your refinery then you're out of business and if you're a major with exposure to national governments you may be under pressure not to close more refineries."
EXPORT OUTLETS
In the meantime, demand for oil products in Europe has slumped by 14% since 2008. Industry players and analysts say the downward trend will continue with car manufacturers increasingly building more efficient engines.
Another thorn in the side of Europe's refining sector is the loss of its traditional export outlets such as Africa.
The US refining industry is pushing its gasoline supply surplus to Africa at discount prices, they said.
"And this phenomenon is accelerating," Schilansky said.
Total, Europe's largest refiner, aims to continue cutting its exposure to the ailing refining and petrochemical sector in Europe. It cut 23% of its exposure between 2006 and 2011 and aims to cut another 20% between 2011 and 2017.
Total, which has focused its strategy on investing in its larger, integrated petrochemical and refining plants such as Gonfreville in northern France or Antwerp in Belgium, aims for integrated platforms to make up 75% of the branch's net results by 2017.
Meanwhile, the struggling refineries are those with a high yield of gasoline, generally on a coastal location, small and less complex plants, sector specialists say.
"Refineries will close based on their margins," said Leitch. "But I don't think we're going to see refineries closing enough to bring back a good operating margin for the rest of refiners."
--Muriel Boselli, newsdesk@platts.com
--Edited by James Leech, james.leech@platts.com
Washington (Platts)--25Jun2014/702 pm EDT/2302 GMT
The US House of Representatives voted 266-150 Wednesday to approve legislation aimed at speeding approvals for the shipments of LNG to countries that are members of the World Trade Organization.
The US Department of Energy would have 30 days, once an environmental review is completed, to make a final decision on an application to export LNG, under the bill introduced by Representative Cory Gardner, Republican-Colorado.
An amendment to the bill, authored by Gardner and Texas Democrat Gene Green and approved by voice vote, brought the legislation in line with DOE's proposal to skip the conditional approval step in authorizing the export of LNG to countries without free trade agreements with the US.
That proposal, which is subject to a 45-day public comment period that will end July 21, would mean DOE would not initiate public interest determinations on non-FTA export authorizations until after the Federal Energy Regulatory Commission has completed the environmental review of a project to site, construct and operate a LNG export terminal.
DOE makes public interest determinations for energy export projects, while FERC is responsible for the export facility design, engineering and environmental footprint -- a far more detailed and lengthy review process than DOE's.
The bill, or H.R. 6, would grant the US Court of Appeals for the circuit where an export facility is planned expedited judicial review if DOE fails to meet the 30-day deadline for issuing a final decision.
All destinations for exported LNG would also have to be publicly disclosed as a condition of DOE's approval of an export permit.
Bill Cooper, president of the Center for Liquefied Natural Gas, said in a statement Wednesday that passage of the legislation in the House "sends a strong signal that the United States is committed to its role as an energy leader on the world stage."
"With growing bipartisan and bicameral support, the right policies can be put in place to ensure that our wealth of natural gas will benefit the US trade balance, US foreign policy and the energy security of our trading partners around the world," Cooper said.
Many House Democrats, however, were not pleased with the bill's passage.
Representative Henry Waxman, the ranking member on the House Energy and Commerce Committee, said in a statement Wednesday that the bill would disrupt DOE's existing approval process for LNG export applications.
The California Democrat said the "bill's arbitrary deadlines would needlessly truncate DOE's public interest reviews, limiting DOE's ability to weigh the pros and cons of projects."
Passage of the bill was part of House Republicans' efforts to move forward with a number of energy bills this week aimed at increasing the flow of North American energy to help make energy more affordable and accessible.
Senator Mark Udall, Democrat-Colorado, introduced similar legislation June 18 that would require DOE to make a final national interest decision on pending LNG export applications within 45 days of FERC's completion of its environmental review of a project. The bill would also allow an expedited judicial review process if DOE fails to meet that deadline and require DOE to disclose which countries LNG will be exported to.
The legislation was co-sponsored by Senator Mary Landrieu, a Louisiana Democrat and chair of the Senate Energy and Natural Resources Committee.
The legislation faces a much tougher battle in the Democrat-led Senate, where lawmakers are split on whether increased trade of LNG would threaten US supplies and cause domestic natural gas prices to rise.
In the Senate Democratic caucus, the issue has pit lawmakers from manufacturing states against those from energy abundant states.
Cooper said on a call with reporters Tuesday that he remained optimistic that legislation putting a clock on DOE's LNG export approval process would be signed into law.
"It does not change the way DOE examines these applications at all," he said, noting that it just puts a timeline on action DOE would already intended to take.
Cooper added that the LNG global market will have a wealth of supply sources come online in the next few years from Australia, Mozambique, Tanzania and a host of other international players, while the number of "buyers that are creditworthy enough to underpin the development of [LNG export] projects" will remain limited.
"That's why we say the window of opportunity won't stay open forever," Cooper said. Buyers are "going to go where they think the reality is going to be that LNG exports are going to occur. The sooner the US signals that through the regulatory process, the better," he said.
--Jasmin Melvin, jasmin.melvin@platts.com
--Edited by Keiron Greenhalgh, keiron.greenhalgh@platts.com
Santiago (Platts)--25Jun2014/310 pm EDT/1910 GMT
Chile's state energy firm ENAP is negotiating the terms of a 10-year contract to supply natural gas to a power generator, the country's president said.
Speaking at an energy industry dinner in Santiago on Tuesday, Michelle Bachelet said that the gas, supplied from the Quintero regasification terminal in central Chile would allow the partial operation of a combined cycle plant in the region.
The Chilean government is promoting use of LNG as part of its agenda to increase electricity supplies and bring down high power prices by reducing reliance on more expensive diesel.
The contract will contribute to low the marginal generation costs, especially when rainfall is low, the president said.
ENAP CEO Marcelo Tokman said the firm is negotiating a contract for 1.1 million cubic meters/day of natural gas.
The deal will also promote open access to Quintero, by transferring part of ENAP's regasification capacity at the terminal to the generator company, Bachelet said.
ENAP shares control of Quintero with power generator Endesa Chile and gas distributor Metrogas.
US-controlled AES Corp. and locally-owned Colbun both operate combined cycle plants in central Chile.
The president added that work to expand capacity at Quintero to 15 million cu m/d is expected to conclude early next year while ENAP is promoting a further expansion to 20 million cu m/d. Bachelet said details of the process would be released during the third quarter of this year.
--Tom Azzopardi, newsdesk@platts.com
--Edited by Derek Sands, derek.sands@platts.com
Written by : Hannah Lucinda Smith
Iraq experiencing fuel shortages as ISIS consolidates control over oil infrastructure
Kirkuk, Asharq Al-Awsat—Iraq’s oil infrastructure was subjected to repeated sabotage and theft in the months before the fall of Mosul, an industry insider has told Asharq Al-Awsat.
“There was a sabotage on the pipeline from Baiji two weeks before the attack on Mosul,” said the source, who spoke to Asharq Al-Awsat on the condition of anonymity.
“The line was tapped at Al-Hadr [around 25 miles south of Mosul] and the stolen oil was loaded into tankers and smuggled out. There were three different types of insurgents in that area—ISIS, Ba’athists and criminals.”
The Islamic State of Iraq and Syria (ISIS) and its predecessor, Al-Qaeda in Iraq, have long targeted the country’s oil infrastructure in order to raise funds and create instability. The group now controls all the oil fields in eastern Syria’s Deir Ezzor province.
“ISIS have a lot of experts, including oil experts,” said the source. “The problem now is that most pumping stations in Iraq are under ISIS control.”
The collapse of the Iraqi Army has placed extra pressure on Iraq’s oil security. The army’s 12th Division was previously responsible for maintaining the security of some of the region’s pipelines.
The Baiji Oil Refinery, which supplies 60 percent of Iraq’s fuel, has been out of action since the city of Mosul slipped out of government control on June 10. ISIS insurgents and the Iraqi National Army have been locked in fierce clashes for control of the refinery, which lies near Saddam Hussein’s hometown of Tikrit. The town was captured by insurgents on June 11.
The line between Baiji and Kirkuk was set on fire on June 13, as the fighting around Baiji began.
As a fuel shortage grips the country, drivers in the Kurdish-controlled region of northern Iraq have been lining up overnight at gas stations to fill up their cars. Opening hours have been limited to 7 am to midday at government-controlled stations, and drivers are only allowed to purchase 8 gallons (30 liters) every other day.
At stations in Kirkuk, the city worst hit by the crisis, the line stretches to a couple of miles by late afternoon. One taxi driver in the city told Asharq Al-Awsat that he had been forced to wait in line for five hours to fill up his tank.
“The queues started right from the day that Mosul fell,” said Fazel Raza, the manager of a petrol station in the Rahimawa district of the city. “The government is always telling us that they have backup stocks, but people are not comfortable when they have empty tanks.”
Gas stations have been taking their supplies from government-controlled stores since the start of the crisis, but it is unclear how long those stocks will last.
“We think that they may be mixing the fuel to make it last longer,” said Raza. “The quality is not as good as it was before. We have been testing it on our own vehicles, and three of them have broken down.”
© Copyright 2013 Asharq Al Awsat
