Angola’s Sonangol was heard to have allocated nine crude oil cargoes for July loading to five regular term buyers, compared with 13 stems allocated the previous month, traders said Wednesday.
Traders said Unipec was allocated five cargoes on term, while BP, Cepsa, CNOOC and Petrogal were each allocated one cargo, traders added.
The allocated cargoes consisted of two cargoes each of Nemba, Hungo and Dalia and a stem each of Cabinda, Pazflor and Saturno. Unipec will be allocated a stem each of Cabinda, Pazflor, Saturno, Nemba and Hungo, traders added.
Petrogal will be allocated a Nemba, CNOOC will be allocated a Dalia, BP will get a Hungo parcel, and Cepsa will get a Dalia, traders said.
Loadings of Angolan crude oil in July are set to plunge to 46.1 million barrels, a more than 9% drop in exports from 50.685 million barrels scheduled in June, according to a copy of the provisional loading schedule.
On a daily average basis, loadings in July will be 1,487,097 b/d, down from the final average daily loading rate of 1,635,000 b/d seen in June. Sonangol typically allocates 10-12 cargoes a month to companies holding term-supply contracts.
In addition, some other Angolan lifters other than Sonangol allocate cargoes on a term basis. Sonangol was not immediately available for comment.
US commercial crude stocks fell 7.2 million barrels last week, led by a decline on the Gulf Coast as imports to the region fell sharply, US Energy Information Administration data showed Wednesday.
Total crude stocks at 391.3 million barrels for the May 16 reporting week were about 4.1% above the EIA’s five-year average. The draw was much larger than analysts had expected.
A Platts survey of analysts Monday showed stocks were expected to have fallen 300,000 barrels. USGC crude stocks fell 5.7 million barrels last week to 209.99 million barrels — that’s off of a record high of 215.7 million barrels the week prior.
Last week’s draw puts USGC crude stocks at a 12.2% surplus to the five-year average. By comparison, stocks were at a 1.37% surplus to the average in early February. Crude stocks draws in the Midwest of 1.1 million barrels and also 1.1 million barrels on the Atlantic Coast contributed to the overall stock decline.
At the NYMEX delivery hub at Cushing, Oklahoma, crude stocks fell 200,000 barrels to 23.2 million barrels last week. That puts stocks at the hub at a 43.3% deficit to the five-year average. In the USGC, a sharp 516,000 b/d drop in crude imports was likely behind the stock decline. Overall, imports of crude fell 658,000 b/d to 6.47 million b/d last week, led by a 706,000 b/d drop in Saudi Arabian imports.
Iraqi imports fell 398,000 b/d to 93,000 b/d. The import plunge was tempered by a 253,000 b/d increase in Kuwaiti imports to 324,000 b/d and a 119,000-b/d rise in Angolan imports to 232,000 b/d.
Crude imports into the USAC also declined, down 272,000 b/d to 464,000 b/d. Imports to that region had been on the rise in previous weeks, reaching 878,000 b/d for the April 18 reporting week. Refiners in the USGC lowered utilization rates by 2.3 percentage points to 88.3% of capacity last week.
The decline in total US refinery utilization rates was less severe, declining just 0.1 percentage point to 88.7% of capacity, below expectations of a 0.5 percentage point rise. US gasoline stocks rose 1 million barrels to 213.4 million barrels. Analysts polled by Platts were anticipating a smaller 150,000-barrel build in gasoline stocks.
NYMEX July crude futures came off an intra-day high early Wednesday following the release of US Energy Information Administration data showing a 7.23 million-barrel draw in US crude stocks for the week ended May 16.
July crude was driven higher in overnight trade, rising to $103.50/barrel, after the American Petroleum Institute Tuesday evening reported a 10.3 million-barrel draw. Following the release of the EIA data, July crude slipped back to trade around $103.19/b before popping back up to trade around $103.37/b at 1452 GMT, up $1.04/b day-on-day.
The bulk of the crude stock draw — 5.71 million barrels — was in the US Gulf Coast, the EIA data showed, as USGC crude inputs edged up 67,000 b/d while imports into the region slumped 516,000 b/d.
Crude stocks at Cushing, Oklahoma — the delivery point for NYMEX crude — fell 225,000 barrels to 23.22 million barrels. The EIA data appeared bearish for NYMEX refined products, with a 1.25 million-barrel increase in gasoline stocks and 402,000-barrel increase in ULSD stocks seen on the US Atlantic Coast, home of the New York delivery point for NYMEX RBOB and NYMEX ULSD.
US distillate stocks climbed 3.4 million barrels, with 1.97 million barrels of that seen in the USGC. NYMEX June RBOB and ULSD were slightly lower following EIA data release, with RBOB trading around 4 points lower at $2.9636/gal at 1452 GMT, and ULSD 33 points lower at $2.9459/gal.
Crude stocks at Cushing, Oklahoma, declined again last week, boosting speculation that the delivery hub could be reaching its minimum operating level, although that level remains unclear.
Cushing crude stocks fell 200,000 barrels to 23.2 million barrels for the May 16 reporting week, according to data Wednesday from the US Energy Information Administration. That puts stocks at the hub at a 43.3% deficit to the five-year average.
However, historical data for Cushing — delivery point for the NYMEX futures contract — shows that stocks were at just 14.4 million barrels during the same reporting week in 2004 — the year the EIA began tracking stocks at the hub.
Analysts at BNP Paribas said in a recent research report that as Cushing stocks decline, “concerns are increasingly voiced that the hub may soon reach its minimum operating levels.”
But that level remains unclear. “There is some debate about the actual minimum operating level, as different people assume different percentages for tank bottoms. We do not have an exact figure in mind, but sub-20 million barrels,” said Harry Tchilinguirian, global head of commodity markets strategy at BNP Paribas. “The difficultly in having an exact number is related not only to the percentage represented by tank bottoms, but also the minimum amount of crude necessary to settle and the physical delivery of crude on expiry of a given contract if that contract goes to physical delivery,” Tchilinguirian said.
BNP analysts said that as Cushing remains the delivery point for the NYMEX crude contract, the scarcity of crude at the hub has been supporting the prompt futures price and curve structure. “Nonetheless, we believe the market will eventually need to come to terms with the fact that the US is not short of crude,” Tchilinguirian said.
US crude stocks were at 391.3 million barrels last week, putting inventories about 4.1% above the EIA’s five-year average. Mike Fitzpatrick of the Kilduff Report said there has been a lot of speculation as to whether inventories will remain enough for the futures contract to function sufficiently. “The CME and others have said that [inventories] will be sufficient.
China’s state-owned refiners lowered planned crude runs in May to an average 81%, down from 82% in April, a Platts monthly survey showed Tuesday.
The 24 refineries surveyed planned to process a combined 17.74 million mt (4.19 million b/d) of crude oil in May. Last month, 23 refineries were surveyed. The May survey covered Sinopec’s 13 refineries, PetroChina’s 10 refineries and China National Offshore Oil Corp.’s Huizhou refinery. The 24 refineries surveyed have a combined capacity of 265.70 million mt/year.
The survey does not include PetroChina’s new 10 million mt/year Pengzhou refinery in southwest Sichuan province, which is still undergoing test runs, according to a refinery source. It also does not include state-owned trading house Sinochem’s 12 million mt/ year Quanzhou refinery in southeast China’s Fujian province, which started commercial operations in mid-April.
The refinery’s current crude throughput rate is still not known. Average runs at PetroChina’s refineries fell to 66% in May from 72% in April, while run rates at Sinopec’s surveyed refineries dropped to 85% from 87% last month.
LOWER CRUDE RUNS DUE TO TURNAROUNDS IN MAY
Sources attributed lower crude runs to turnarounds in May. PetroChina’s 20.5 million mt/year Dalian Petrochemical in northeast China’s Liaoning province has been shut for scheduled maintenance since April 10 and is expected to restart May 25.
As a result, the refinery planned to process 200,000 mt of crude in May, accounting for 11% of its nameplate processing capacity, and down further from 27% seen last month.
In addition, the 10 million mt/year Dalian West Pacific Petrochemical in the same province planned to cut its crude runs to 74% from April’s 88%, processing around 630,000 mt of crude in May.
The refinery is owned by PetroChina (28.4%), Sinochem International (25.2%), Total (22.4%), Sinochem Group (8.4%), and Dalian Construction Investment Corp. (15.5%). The rates were cut because the refinery shut a 2 million mt/year atmospheric residue de-sulfurizer unit on May 14 for 21 days to replace catalysts, Platts reported earlier.
In addition, PetroChina’s 11 million mt/year Fushun Petrochemical, 5.5 million mt/year Daqing Refining, and 10.5 million mt/year Lanzhou Petrochemical, all planned to lower their run rates by three to five percentage points in May, the survey showed.
The total inventory of oil products at PetroChina’s refineries is currently high, and the company plans to trim output by decreasing run rates. PetroChina will cut gasoline output by 400,000 mt across its refineries in May, said a source with the company’s 10.5 million mt/year Lanzhou Petrochemical refinery in northwestern Gansu province.
By Mark Shenk May 22, 2014 12:59 AM GMT+0700
U.S. crude imports dropped to a 17-year low last week as the shale boom bolstered output, moving the nation closer to energy independence.
Arrivals slid 658,000 barrels a day to 6.47 million, the fewest since January 1997, the Energy Information Administration said today. Output rose 6,000 barrels a day to 8.43 million in the seven days ended May 16, the most since October 1986.
The combination of horizontal drilling and hydraulic fracturing, or fracking, has unlocked supplies from shale formations in the central U.S., including the Bakken in North Dakota and the Eagle Ford in Texas.
The U.S. met 87 percent of its energy needs in 2013 and 90 percent in December, the most since March 1985, according to the EIA, the Energy Department’s statistical arm. Imports peaked at 11.3 million barrels a day in July 2004.
Crude supplies have fallen in two of the past three weeks after reaching 399.4 million barrels April 25, the most since the EIA began publishing weekly data in 1982.
West Texas Intermediate crude for July delivery increased $1.56, or 1.5 percent, to $104 a barrel at 1:58 p.m. on the New York Mercantile Exchange.
To contact the reporter on this story: Mark Shenk in New York at mshenk1@bloomberg.net
To contact the editors responsible for this story: Dan Stets at dstets@bloomberg.net Bill Banker
By Pietro D. Pitts May 22, 2014 4:47 AM GMT+0700
Petroleos de Venezuela SA, the country’s state oil company, signed financing deals worth $2.2 billion with oil service companies Schlumberger Ltd (SLB), Halliburton Co. (HAL) and Weatherford International Ltd.
PDVSA, as the Caracas-based company is called, renewed a $1 billion credit line with Schlumberger, while the Halliburton and Weatherford arrangements are for $600 million each, Oil Minister Rafael Ramirez told reporters today at a conference in the city of Maracaibo.
“The companies will increase their activity in the country, in some cases doubling,” Ramirez said.
PDVSA is planning to invest $24 billion this year to boost capacity as it seeks to keep production at about 3 million barrels a day to comply with its OPEC quota, Ramirez said. Company officials from Repsol SA (REP) and Eni SpA (ENI) are planning to visit the country next month to sign a deal related to the Perla 3X offshore natural gas well, he added.
The company intends to start natural gas exports to Colombia in July, Ramirez said.
PDVSA first signed the $1 billion rolling credit line with Schlumberger in May last year. It can be renewed each year, Ramirez said at the time.
For Related News and Information:
To contact the reporter on this story: Pietro D. Pitts in Caracas at ppitts2@bloomberg.net
To contact the editors responsible for this story: James Attwood at jattwood3@bloomberg.net Nathan Crooks
By Elena Mazneva, Stepan Kravchenko and Henry Meyer May 22, 2014 3:00 AM GMT+0700
Alexey Miller, chief executive officer of OAO Gazprom, Russia’s biggest company, signed... Read More
Russia’s $400 billion deal to supply natural gas to China after more than a decade of negotiations is tilting the world’s largest energy exporter toward Asia as ties worsen with the U.S. and Europe.
Russian President Vladimir Putin is turning eastward as sanctions imposed by the U.S. and the European Union because of the standoff over Ukraine batter the Russian economy. The increasing alienation makes trade with China, the country’s largest trading partner after the two-way volume surged sevenfold in the past decade to about $94 billion last year, even more important.
“Russia needed this deal, not just because of the fear of losing European markets, but the broader geopolitical situation,” Bobo Lo, an associate fellow at the Chatham House research group in London, said by phone. “Russia can manage bad relations with the U.S. and the EU, but it can’t manage that and an uncertain relationship with China.”
Putin yesterday in Shanghai called the signing an “epochal event.” While the price wasn’t disclosed, he said its satisfies both countries. The deal to supply gas through a new pipeline was completed after a decade of negotiations, mostly because of a disagreement over the price.
The ruble strengthened 0.3 percent to 34.415 per dollar by 7:39 p.m. in Moscow, gaining for a third day. OAO Gazprom (GAZP) shares advanced 0.8 percent to 146.58 rubles.
The accord between the world’s largest energy exporter and the biggest consumer will allow state-run gas producer Gazprom to invest $55 billion developing giant gas fields in eastern Siberia and building the new pipeline, Putin said.
Gazprom Chief Executive Officer Alexey Miller signed the deal with Zhou Jiping, chairman of China National Petroleum Corp. The agreement is for 38 billion cubic meters of gas annually over 30 years, or about 20 percent of its sales to Europe, Miller said. While he declined to give a price, he said the total value would be about $400 billion.
“This is the largest ever contract for Gazprom,” Miller said, adding the deal was clinched at 4 a.m. Shipments will start in four to six years, he said.
Russia will use the contract as additional leverage during gas talks with the EU and Ukraine that resume May 26, Andy Liu, an analyst at Teneo Intelligence, said in an e-mailed report.
Even if China can’t immediately replace Europe as Russia’s main market for gas exports, “Moscow will likely try to gain an upper hand in the run up to the negotiations, presenting the new contract with China as another sign that Europe needs Russia more than vice versa,” Liu wrote in the report.
Advance Payments
China may make as much as $25 billion in advance payments under the contract to invest in the necessary infrastructure, Russian Energy Minister Alexander Novak told reporters yesterday. The government in Beijing, responsible for a pipeline on its territory, will spend at least $20 billion on its construction, Putin said.
Russia and China will start talks on a second pipeline to the west of the initial route, Miller said.
Gazprom supplies about 30 percent of Europe’s gas, at an average price of $380.5 per thousand cubic meters last year. The price in the contract with China is more than $350, Interfax reported, citing a person it didn’t identify.
“The price seems to be at the level of European exports,” Anvar Gilyazitdinov, who manages a $10 million portfolio of Russian stocks at Rye, Man & Gor Securities, said by phone from Moscow. “It’s adequate. Gazprom will be able to make money at that price.”
Still, the fact that the price wasn’t made public will feed suspicions that “there is nothing to brag about for Russia,” said Masha Lipman, an analyst at the Carnegie Moscow Center.
The deal also raises concerns that over-dependence on China will reinforce Russia’s focus as an exporter of natural resources and hold back the development of high-technology areas of the economy, Lipman said.
“There are significant risks for Putin,” Lipman said. “Instead of the West, China now will develop significant leverage in Russia. And the more Russia relies on China rather than the West as an economic partner, the less chance there will be for Russia to modernize its economy. Russia is stuck with being a resource-based economy now.”
To contact the reporters on this story: Elena Mazneva in Moscow at emazneva@bloomberg.net; Stepan Kravchenko in Shanghai at skravchenko@bloomberg.net; Henry Meyer in Moscow at hmeyer4@bloomberg.net
To contact the editors responsible for this story: Balazs Penz at bpenz@bloomberg.net; Will Kennedy at wkennedy3@bloomberg.net Paul Abelsky
By Pablo Gonzalez May 22, 2014 2:04 AM GMT+0700
Argentina is benefiting from the experience of the world’s largest oil companies as it develops shale deposits in a bid to gain energy independence, said a board member of a provincial oil company.
Exxon Mobil Corp. (XOM)’s Argentina unit and provincial-run Gas & Petroleo del Neuquen SA, or GYP, yesterday reported their largest shale discovery in southern Argentina’s Vaca Muerta formation. The Bajo del Choique X-2 horizontal well is producing 770 barrels of oil a day in its first flow test, Exxon said in a statement. Exxon operates the block and has an 85 percent stake while GyP owns the remaining 15 percent.
“We are betting on developing the horizontal technology along with Exxon because we are convinced that is the way to get greater output despite being costly,” said GyP Director Gustavo Nagel in an e-mailed response to Bloomberg questions.
Vaca Muerta’s oil production more than tripled in the first quarter from a year earlier, according to data compiled by Bloomberg Industries, boosted primarily by a joint venture between YPF SA (YPF), Argentina’s largest company, and Chevron Corp. (CVX) YPF’s output from the Loma Campana area in Vaca Muerta rose to 12,800 barrels a day from 4,200 barrels after investing $1.2 billion in a pilot year with San Ramon, California-based Chevron.
GyP has partnerships with 18 additional foreign oil companies to develop shale in Vaca Muerta, Nagel said. Vaca Muerta is a mostly untapped 30,000 square-kilometer (11,600 square-mile) region, which holds at least 23 billion barrels of oil, according to a survey by Ryder Scott. Vaca Muerta has 350 wells, of which 160 are commercially producing, Nagel said.
Argentina will need $300 billion to develop Vaca Muerta over a six-year period to make the country energy independent starting in 2020 and keep it producing for as many as 40 years, Royal Dutch Shell Plc (RDSA) Argentine unit President Juan Aranguren said on Dec. 10. Argentina posted a record $6.1 billion energy deficit last year after 20 years of surpluses through 2010.
Shell tripled its investment budget to $500 million this year for Vaca Muerta, the world’s second-largest shale gas formation and the world’s fourth-largest shale oil deposit.
Exxon, Shell and Chevron are the three biggest oil companies by market value.
To contact the reporter on this story: Pablo Gonzalez in Buenos Aires at pgonzalez49@bloomberg.net
To contact the editors responsible for this story: James Attwood at jattwood3@bloomberg.net Robin Saponar
By Isis Almeida and Anna Shiryaevskaya May 21, 2014 11:16 PM GMT+0700
Europe will struggle to reduce its dependence on Russian natural gas after prices fell to the lowest in more than three years, making the continent an unattractive destination for supplies from new projects.
U.K. gas, a European benchmark, fell to the lowest since 2010 yesterday on the ICE Futures Europe exchange in London as the region’s mildest winter in seven years and rising Russian flows left European storage more than half full. Current prices make it unlikely that projects including U.S. liquefied natural gas shipments will make it to the continent, potentially increasing reliance on Russia, according to Societe Generale SA.
Russia supplies about 30 percent of Europe’s gas needs, with half of that transported through pipelines crossing Ukraine. Tensions between the two nations, which disrupted flows in 2006 and 2009, are raising concerns about Europe’s energy security. The European Union will by June prepare a road map on how to cut reliance on Russia and boost supply security.
“My personal expectation is that we will not see those kind of disruptions,” Stefan Judisch, chief executive officer of RWE Supply & Trading said yesterday at the Flame conference in Amsterdam. “Everybody would have too much to lose.”
Front-month U.K. gas fell 35 percent this year and touched 43.6 pence a therm ($7.37 a million British thermal units) yesterday on ICE, the lowest since September 2010. The contract rose 0.7 percent to settle at 44.6 pence a therm.
Northwest European prices will be below year-earlier levels in the second half of 2014, 60 percent of respondents in a panel attended by about 170 people said at Flame yesterday. Thirty percent said they would be at least 10 percent below the 25 to 28 euros a megawatt-hour in the second half of 2013.
“I’m on the bearish side,” Thierry Bros, an analyst at Societe Generale, said yesterday at Flame. “It seems to me that there’s quite a pessimistic view. The elephant in the room is Ukraine and political interference could have an impact.”
The European Union has limited options to overcome a cutoff of Russian gas in the coming winter and might have to add more storage or form a common reserve, according to a draft document from the European Commission, the bloc’s executive arm.
Stockpiles in the 28-member states of the EU were 57 percent full as of May 19, the highest level for this time of the year since at least 2007, data from Gas Infrastructure Europe, a lobby group in Brussels showed.
Russia’s pipeline-gas export monopoly OAO Gazprom (GAZP) exported 42.7 billion cubic meters to Europe in the first quarter, up from 41.7 billion a year earlier, Sergei Komlev, the company’s head of contract structuring and price formation, said today in Amsterdam.
Russia’s deal to supply 38 billion cubic meters of gas to China signed today will have a limited impact on Europe in the medium term, Vadim Khramov, an economist at Bank of America Corp.’s Merrill Lynch unit, said by e-mail. Europe consumes about 500 billion cubic meters, more than 170 billion of which is imported from Russia, he said.
“The Russians aren’t looking at demand in Europe, they are looking at their exports to Europe and their exports into Europe are growing,” Bros said. “Not only are they growing but they will be growing even faster.”
That will “kill competition” from potential new projects before they even start, Bros said. Russia also wants to have European storage filled in case of a supply disruption to Ukraine, he added.
U.S. LNG exports, expected to start in the first quarter of 2016, cannot replace Russian supplies, Jean Abiteboul, president of Cheniere Supply & Marketing Inc., said in a May 19 interview in Amsterdam.
“Whether it’s done to kill the U.S. projects, I’m not sure,” he said. “They probably also have an issue of reliability of supply with the Ukrainian crisis so they have to appear as a good supplier for Europe, which by the way they have been so far. It’s true that at a certain level, the long-term price export from U.S. could become less attractive.”
To contact the reporters on this story: Isis Almeida in London at ialmeida3@bloomberg.net; Anna Shiryaevskaya in London at ashiryaevska@bloomberg.net
To contact the editors responsible for this story: Lars Paulsson at lpaulsson@bloomberg.net Rob Verdonck, Rachel Graham
By Naureen S. Malik and Zain Shauk May 21, 2014 11:25 PM GMT+0700
The Energy Information Administration slashed its estimate of recoverable reserves from California’s Monterey Shale by 96 percent, saying oil from the largest U.S. formation will be harder to extract than previously anticipated.
“Not all reserves are created equal,” EIA Administrator Adam Sieminski told reporters at the Financial Times and Energy Intelligence Oil & Gas Summit in New York today. “It just turned out it’s harder to frack that reserve and get it out of the ground.”
The Monterey Shale is now estimated to hold 600 million barrels of recoverable oil, down from a 2012 projection of 13.7 billion barrels, John Staub, a liquid fuels analyst for the EIA, said in a phone interview. A 2013 study by the University of Southern California’s Global Energy Network, funded in part by industry group Western States Petroleum Association, found that developing the state’s oil resources may add as many as 2.8 million jobs and as much as $24.6 billion in tax revenues.
Environmental groups and some communities have challenged the use of hydraulic fracturing, or fracking, to access the oil because of concerns it may foul drinking water. They’ve called on Democratic Governor Jerry Brown to ban the practice, which involves injecting a mix of water, sand and chemicals underground to open fissures in the shale rock.
Risk-Reward
“This downgrade fundamentally changes the risk-reward calculation when it comes to unconventional oil development in our state,” Jayni Foley Hein, executive director of the Berkeley Center for Law, Energy and the Environment, said in a statement from the group CAFrackFacts. “Given that the industry’s promised economic benefits are not likely to materialize, the state should take a hard look at the impacts that oil development has on public health, safety and the environment.”
The revised figures come from new evidence accumulated by the EIA and the U.S. Geological Survey, Sieminski said. Occidental Petroleum Corp. (OXY), based in Los Angeles, controls 2.3 million acres in California -- an area 12 times the size of New York City -- including vast portions of the Monterey Shale that have so far frustrated attempts to extract commercial quantities of crude.
The company announced in February plans to spin California operations off into a separate publicly traded company, a move likely hastened by poor results in the Monterey, said Leo Mariani, an Austin, Texas-based analyst for RBC Capital Markets.
Early Optimism
“They’ve certainly made comments that it wasn’t working out like they thought and they weren’t getting the economics and returns that they had once hoped for,” said Mariani, who rates the company at the equivalent of a hold. “Certainly several years ago there was a lot of hope for these assets.”
Occidental referred questions on the revised reserves estimate to the Western States Petroleum Association.
“What is lost in the conversation, at times, is the fact that all the oil is still there and we always have believed and continue to believe that the members of our association possess all the necessary experience and knowledge to figure out how to unlock that,” Tupper Hull, a spokesman for the group, said in a phone interview. “When that happens, no one knows.”
Occidental Chief Executive Officer Stephen Chazen’s early optimism about the Monterey’s potential bucked the conventional wisdom of industry stalwarts such as Chevron Corp.’s John Watson and Continental Resources Inc. founder Harold Hamm, who doubted the formation could be cracked.
As recently as May 2011, Occidental was trading at a record $115.74 on analysts’ predictions the company’s discovery held 10 billion barrels of oil. Since then, the stock has dropped by almost one-fifth. Occidental gained 1.4 percent to $96.76 at 12:24 p.m. in New York.
The EIA revised the Monterey estimate before, dropping it from 15.4 billion barrels to 13.7 billion in 2012. The formation was ranked the largest source of recoverable shale oil reserves in the U.S., exceeding the Bakken in North Dakota.
New production methods may eventually unlock the formation and make it possible to economically extract the resources, Sieminski said. “The rock is there, the technology isn’t there.”
To contact the reporters on this story: Naureen S. Malik in New York at nmalik28@bloomberg.net; Zain Shauk in Houston at zshauk@bloomberg.net
To contact the editors responsible for this story: Susan Warren at susanwarren@bloomberg.net Tina Davis, Robin Saponar
By Moming Zhou May 22, 2014 4:39 AM GMT+0700
Rig hands thread together drilling pipe at a hydraulic fracturing site located atop the... Read More
The U.S. crude market is the steadiest it’s been in at least eight years, driving investors away from exchange-traded products that profit from changes in oil prices.
“Low volatility is a disincentive for investors,” John Hyland, chief investment officer of United States Commodity Futures Funds, an Alameda, California-based ETP manager, said in a phone interview on May 14. Big price swings, with oil more expensive now than in the future, make a perfect scenario for ETP investors, he said.
Only part of Hyland’s dream picture has become a reality. In January, as the southern leg of the Keystone XL pipeline began moving oil to Gulf Coast refineries from the hub in Cushing, Oklahoma, the market for West Texas Intermediate crude, the North American benchmark, slid into backwardation. That’s when shorter-term prices for upcoming delivery are higher than those in the more distant future.
As Hyland points out, investors also need prices that fluctuate, and that hasn’t happened. Implied volatility for WTI crude options expiring in three months, a measure of expected future price movement, fell yesterday to the lowest level since Bloomberg started tracking the data in November 2005. As a result, total shares outstanding in the six largest U.S.-traded oil (UCO) ETPs have declined 29 percent in the past year.
Such domestic stability is due in part to a rise of 15 percent from a year earlier in U.S. crude production as a combination of horizontal drilling and hydraulic fracturing, or fracking, unlock supplies in shale formations. Growing domestic inventories, now close to 400 million barrels, the highest level in government weekly data going back to 1982, have shielded the U.S. market from political tensions in Ukraine and supply curtailments in Libya.
Front-month WTI futures, or contracts for crude delivery that expire in the near-term, rose 1.7 percent to $104.07 a barrel on the New York Mercantile Exchange, bringing this year’s advance to 5.7 percent. The United States Oil Fund, managed by Hyland’s company and the biggest crude ETP, rose 0.4 percent to $37.52 yesterday for a gain this year of 6.2 percent.
“USO is used by a lot of folks whose holding period is measured in days or, at the longest, weeks,” Michael Johnston, a managing director at Chicago-based ETF Database, which analyzes exchange-traded funds, said by phone May 16. “They are taking their toys and playing elsewhere right now where they expect more volatility.”
Backwardation allows USO to buy more barrels of crude each month as it sells the expiring futures and rolls over to the less expensive second-month contract. The asset value of the fund (DBO) increases if the price of the second-month futures rises.
WTI was mostly in contango in the past 10 years, a pattern in which prices for later deliveries are higher than nearby contracts.
Total assets of the six biggest oil ETPs declined 24 percent to $1.63 billion on May 19 from $2.14 billion in mid-January.
Shares outstanding of the eight-year-old USO dropped to 13.4 million on Feb. 14, the lowest level since October 2008. The total was 13.8 million yesterday. Assets declined to $517.2 million from more than $1 billion in January.
The total asset value of the PowerShares DB Oil Fund was $310.6 million on May 19, down from this year’s high of $318.6 million on April 21. The value of the iPath S&P GSCI Crude Oil Total Return Index ETN (OIL) was $251.3 million, from this year’s peak of $269.4 million on Jan. 23.
ProShares Ultra DJ-UBS Crude Oil, which seeks results corresponding to twice the performance of the underlying index, advanced 13 percent this year. Total assets declined to $96.1 million yesterday from as high as $237.8 million on Jan. 16.
ProShares UltraShort (SCO) DJ-UBS Crude Oil and PowerShares DB Crude Oil Double Short ETN (DTO), the two so-called inverse funds that seek a drop in crude prices, also had declines in the value of their assets.
Trading volumes in Nymex WTI futures also slid, with a daily average of 527,000 contracts this month, the lowest level since February.
U.S. crude production climbed to 8.43 million barrels a day in the week ended May 9, the highest since 1986, according to the government’s Energy Information Administration. Stockpiles reached as high as 399.4 million on April 25.
“We have a glut of oil sitting here,” Stephen Schork, president of the Schork Group Inc. in Villanova, Pennsylvania, said by phone on May 16. “Ukraine hasn’t impacted WTI much. Why would anyone worry about WTI when you have record high inventories here?”
To contact the reporter on this story: Moming Zhou in New York at mzhou29@bloomberg.net
To contact the editors responsible for this story: Dan Stets at dstets@bloomberg.net Bob Ivry
By Claude Salhani | Wed, 21 May 2014 21:16 | 0
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At the Eurasian Media Forum in Kazakhstan last month, former Israeli Prime Minister Ehud Barak advised his audience not to make political predictions, because, he said, it’s too risky.
The former prime minister was referring to political predictions about the Middle East, no doubt, a highly volatile part of the world. However, his caution could just as easily apply to Central Asia, the Caspian and the Caucasus. Though not quite as volatile as the Middle East, this region of the world isn’t lacking its share of upheaval.
Indeed, making predictions of any sort, unless one can see into the future – and there has been an acute shortage of such prophets for a couple of thousand years – is risky at the best of times, because things often go awry, and especially so in parts of the world where political stability is not always a given. With that in mind, Oilprice.com made the following (correct) prediction, only last week.
Reporting on the possibility of sanctions imposed on Russia by the United States and its European allies, we wrote that in the event that Russian natural gas becomes unavailable as a result of sanctions imposed by the West in retaliation for Moscow's actions in Crimea and Ukraine, “In the immediate future, the only two countries able to provide the amount of gas needed to replace Russia in Europe are Turkmenistan and to a lesser degree, Azerbaijan.”
And as we also noted, Turkmenistan’s gas would need to pass through the Caspian Sea, via the Trans-Caspian pipeline, through Azerbaijan and onto Georgia and Turkey before continuing on to its final destinations.
Less than a week later, the European Union has said it is of the same mind.
On May 19, the head of an EU delegation to Azerbaijan told journalists that the implementation of the Trans-Caspian gas pipeline will be a good opportunity to diversify energy supplies to EU countries.
Malena Mard said that, given the high demand for gas, the EU would like to import gas from Turkmenistan. "The EU supports the Trans-Caspian gas pipeline project," Mard said during her visit to Baku.
Negotiations between the European Union and Azerbaijan and Turkmenistan on the Trans-Caspian gas pipeline began in September 2011, long before the crisis in Ukraine. But recent events in the region have renewed the need to speed up the project, as European countries are now eager to diversify their supply sources.
A framework agreement for cooperation on deliveries of Turkmen natural gas to Turkey and further on to Europe was signed between the governments of Turkmenistan and Turkey in July, 2013 after a series of high level talks in the Turkmenistan capital, Ashgabat.
The project will require the laying of some 300 kilometers of pipeline to transport the gas under the Caspian to the shores of Azerbaijan. This is believed to be the best option available to deliver Turkmen resources to European markets. This would also allow European countries to end most of their dependence on Russian gas.
The exact laws affecting the laying of pipelines under the Caspian Sea are still a work in progress. Some countries, such as Turkmenistan, believe that under international law, the consent of the two countries concerned -- itself and Azerbaijan -- would suffice.
For its part, Azerbaijan has said it is ready to allow the pipeline traverse its territory and to offer transit opportunities and infrastructure for the implementation of the project.
Given the two countries’ willingness, and the EU’s approval, the project has a good chance of succeeding.
And that’s as much predicting as one can make for now
By Claude Salhani of Oilprice.com
"I don't personally think that Russia signing a deal with China for gas that they have been working on for 10 years has any impact on what is about to happen in Ukraine," Kerry said during a visit to Mexico - PHOTO: EPA
[MEXICO CITY] US Secretary of State John Kerry on Wednesday downplayed the impact of a massive energy deal between Russia and China, saying it has no repercussions in the Ukraine crisis.
Mr Kerry said the US$400 billion deal was "not a sudden response" to events in Ukraine, adding that the ex-Soviet state was in a "constructive moment" that could allow Ukrainians to determine their futures.
"I don't personally think that Russia signing a deal with China for gas that they have been working on for 10 years has any impact on what is about to happen in Ukraine," Mr Kerry said during a visit to Mexico.
Earlier, the presidents of Russia and China witnessed the signing of gas deal at a time that the Ukraine crisis threatens Russian energy exports to Europe.
Russia can't go it alone in drilling for oil and gas off the coast of Crimea, Cunningham writes, and it will have a hard time attracting Western partners that don't recognize Crimea as a legal part of Russia.
By Nick Cunningham, Guest blogger / May 21, 2014
Russian President Vladimir Putin speaks at a navy parade marking the Victory Day in Sevastopol, Crimea earlier this month.
Russia’s seizure of Crimea has led to speculation that a major motivating factor was to acquire potentially vast energy resources in the Black and Azov Seas. I wrote back in March on the eve of the Crimean vote to secede from Ukraine about reports that Russia was eyeing the oil and gas reserves off the coast of Crimea.
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But taking control of territory rich in oil and gas is different from being able to successfully pull those energy resources from the ground. The New York Times published an article on May 17 that suggested that Russian President Vladimir Putin quietly achieved a massive windfall – acquiring “rights to underwater resources potentially worth trillions of dollars.”
The Black and Azov Seas could certainly hold a huge bounty, potentially up to almost 10 billion barrels of oil and 3.8 trillion cubic feet of natural gas. The most promising field is the Skifska field just southwest of the Crimean coastline. Early estimates suggest that Skifska holds 200 to 250 billion cubic meters of natural gas.
However, just because Russia now controls this territory does not mean they will be able to take advantage of it, at least not anytime soon. Although there are rough estimates of significant reserves of oil and gas, the area is still relatively unexplored. Ukraine had trouble attracting any bidders for two of its four blocks off the coast of Crimea, despite heavy salesmanship by the government in Kiev. (Related Article: Russia’s Weakened Hand Could Pay Off For Beijing In Major Gas Deal)
Also, Russian energy companies still do not have a thorough understanding of the geology in Crimean waters. LUKoil, one of Russia’s largest oil companies, was outbid in an auction for the Skifska field by an international consortium led by ExxonMobil. The consortium had been in talks with the Ukrainian government under Viktor Yanukovych over a deal for the Skifska field right up until the annexation of Crimea. The oil companies had plans to spend $735 million to drill two wells. The deal was never finalized and ExxonMobil and its partners obviously shelved those plans when things took a turn for the worse a few months ago.
Presumably, with Russia now moving in, Russian companies will have to redo some of the preliminary exploratory work that the private consortium had already done.
But, more importantly, offshore oil drilling is highly technical, and requires enormous upfront capital. Russia has often teamed up with international oil companies – like ExxonMobil, BP and Royal Dutch Shell -- to tackle some of the extraordinarily difficult-to-reach oil fields, as Russia’s companies can’t always do it on their own. That’s why Russia has sought partners for offshore oil drilling in the Arctic, constructing LNG terminals in Sakhalin, and for tight oil drilling in Western Siberia.
But in Crimea – which much of the world does not recognize as Russian territory – finding international partners, should Russia need them, will be extremely difficult to do.
For example, on April 30, Shell’s Chief Financial Officer Simon Henry ruled out new Russian ventures for the foreseeable future. “I don't think we'll be jumping into new investments (in Russia) anytime soon,” he said. With Crimea in international legal limbo, other companies won’t invest, either. (Related Article: Russia Showing Interest In Natural Gas Investment In Turkey)
Even if Russia can go it alone in the Black Sea – and since the waters are shallower and less remote than some of its other major new projects, they probably will try to – it will take years before any oil and gas will come online.
In the meantime, Russia is paying the price for its international isolation. The economy will probably enterrecession in the second quarter, according to Russia’s economy minister. Capital flight from Russia reached $63.7 billion in the first three months of this year, exceeding last year’s total. The ruble is also down 6 percent against the dollar so far this year, pushing up inflation, which hit an annual rate of 7.2 percent.
Moreover, in the long-term, Russia may have severely damaged its reputation as a place for doing business. That will hurt the economy for years to come and is much harder to rectify than playing with interest rates or money supply, which can be used for short-term fixes. The darkening economic climate is inflicting real costs on Russia, and that flies in the face of headlines describing Russia’s takeover of Crimea’s oil and gas reserves as a major strategic triumph.
EBR Staff Writer Published 21 May 2014
Saudi Arabian petroleum and natural gas firm Saudi Aramco would invest more than $100bn in downstream over the coming years amid oil products demand surge.
Saudi Aramco CEO Khalid Al-Falih made the announcement at the ongoing Middle East Petrotech 2014, a Middle East refining and petrochemicals conference and exhibition, held in Bahrain.
Al-Falih said, "Globally, these investments will exceed $100 billion over the next decade alone and that is premised on our belief in the long term sustainability of oil demand."
"As a result of both global demographic growth and rising standards of living in the developing world, we see global demand for oil growing by a quarter over the next 25 years."
Aramco has been seeking to strengthen its presence in the petrochemicals segment, and it is currently carrying out two major projects.
The company, in a joint-venture with Dow Chemical, is constructing a $20bn Sadara petrochemical complex in Jubail, which is scheduled to commence operations in the second half of 2015.
Aramco is expanding the PetroRabigh petrochemical complex, which is jointly owned with Sumitomo Chemical.
"That will take our total chemicals participate production capacity to more than 15 million tonnes per year," Falih continued.
May 21 (Reuters) - Argentina's state-controlled energy company YPF has made the first shale oil and gas discovery in the Patagonian province of Chubut, according to a company presentation seen by Reuters on Wednesday.
The discovery, in the San Jorge basin, is located more than 1,000 kilometers southeast of the Vaca Muerta mega field in Neuquen Province.
It was the first discovery at El Trebol field in the D-129 shale formation in Chubut.
Vaca Muerta, Spanish for "dead cow," field is thought to be one of the world's biggest shale reserves and could double Argentina's energy output within a decade.
The country needs foreign investment to develop the formation and has signed one major Vaca Muerta deal, a $1.24 billion joint venture with U.S.-based Chevron Corp.
Earlier on Wednesday, U.S. energy major Exxon Mobil Corp said it has made its first discovery of non-conventional gas and crude oil in Vaca Muerta. (Reporting by Alejandro Lifschitz, writing by Hugh Bronstein; editing by Andrew Hay)
Alison Ciaccio, Platts Markets Editor
New York - May 21, 2014
U.S. commercial crude oil stocks fell 7.2 million barrels the week ended May 16, led by a decline on the U.S. Gulf Coast (USGC) as imports to the region fell sharply, U.S. Energy Information Administration (EIA) data showed Wednesday.
Total crude oil stocks at 391.3 million barrels for the May 16 reporting week were about 4.1% above the EIA's five-year average.
The draw was much larger than analysts had expected. A Platts survey of analysts Monday showed stocks were expected to have fallen 300,000 barrels.
USGC crude oil stocks fell 5.7 million barrels the week ended May 16 to 209.99 million barrels – from a record high of 215.7 million barrels the week ended May 9. Last week's draw puts USGC crude oil stocks at a 12.2% surplus to the five-year average. By comparison, stocks were at a 1.37% surplus to the average in early February.
Crude oil stock draws of 1.1 million barrels each in the U.S. Midwest and the U.S. Atlantic Coast (USAC) regions contributed to the overall stock decline.
At the New York Mercantile Exchange (NYMEX) delivery hub at Cushing, Oklahoma, crude oil stocks fell 200,000 barrels to 23.2 million barrels the week ended May 16. That puts stocks at the hub at a 43.3% deficit to the five-year average.
However, historical data for Cushing -- delivery point for the NYMEX crude oil futures contract -- shows that stocks were at just 14.4 million barrels during the same reporting week in 2004 -- the year the EIA began tracking stocks at the hub.
On the USGC, a sharp 516,000 barrels per day (b/d) drop in crude oil imports was likely behind the stock decline. Overall, imports of crude oil fell 658,000 b/d to 6.47 million b/d the week ended May 16, led by a 706,000 b/d drop in Saudi Arabian imports. Iraqi imports fell 398,000 b/d to 93,000 b/d. The import plunge was tempered by a 253,000 b/d increase in Kuwaiti imports to 324,000 b/d and a 119,000 b/d rise in Angolan imports to 232,000 b/d.
Crude oil imports into the USAC also declined, down 272,000 b/d to 464,000 b/d. Imports to that region had been on the rise in previous weeks, reaching 878,000 b/d during the April 18 reporting week.
Refiners on the USGC lowered utilization rates by 2.3 percentage points to 88.3% of capacity the week ended May 16. The decline in total U.S. refinery utilization rates was less severe, declining just 0.1 percentage point to 88.7% of capacity, below expectations of a 0.5 percentage-point rise.
U.S. GASOLINE STOCKS UP, USAC IMPORTS NEAR 2 1/2-YEAR HIGH
U.S. gasoline stocks rose 1 million barrels to 213.4 million barrels. Analysts polled by Platts were anticipating a smaller, 150,000-barrel build in gasoline stocks.
Gasoline stocks on the USAC -- home to the New York Harbor-delivered NYMEX RBOB gasoline contract -- rose 1.3 million barrels to 56.8 million barrels as imports to the region jumped to 979,000 b/d, up 120,000 b/d.
The surge on the USAC puts imports there at their highest level since January 27, 2012.
Platts cFlow ship-tracking software had showed at least 12 clean cargoes from Northwest Europe refining centers bound for the main USAC gasoline input port at Bayonne, New Jersey, by May 18.
Platts cFlow does not identify the cargoes beyond calling them clean, refined products, but the cargoes originated at ports where refineries typically ship gasoline to the U.S.
Overall, gasoline stocks rose amid a slight dip in demand. Implied demand* for the fuel fell 17,000 b/d to 9.17 million b/d. Still, demand is 384,000 b/d above year-earlier levels.
Tim Evans, commodity analyst at Citi Futures Perspective, said that although the notion is that the summer driving season starts with Memorial Day, demand numbers are usually relatively soft in the first half of June.
"The real period of peak offtake is much shorter, typically only beginning just ahead of July 4 and running through the first week of September," Evans said.
U.S. distillate stocks rose 3.4 million barrels to 116.3 million barrels the week ended May 16, counter to expectations of a 250,000 barrel decline.
Distillate demand sank 479,000 b/d to 3.8 million b/d the week ended May 16 and down 429,000 b/d from a year earlier.
USAC combined low- and ultra-low sulfur diesel stocks were at 24.38 million barrels for the week ended May 16, a 4.6% deficit to the EIA five-year average. That's narrowed from a deficit of more than 34% nine weeks earlier. Stocks rose 357,000 barrels from the week ended May 9.
On the USGC, combined stocks were at 33.65 million barrels the week ended May 16, up 1.5 million barrels on the week. Stocks are now at a 8.2% deficit to the five-year average, down from 13.5% five weeks ago.
1. Unplanned supply outages, particularly in Africa are likely to continue to support Brent crude prices during 2014. Morgan Stanley sees supply outages remaining in the range of 1.5-2 million b/d with Libya likely to account for around 1 million b/d. As we discussed in an earlier article this is likely to be an underestimate as complex oil fields located in increasingly unstable countries means the probability of disruption is likely to rise. Analysts were increasingly optimistic about Libyan oil output as rebels started to return occupied crude export terminals to the government. However signs of a split in the government led by a rogue general point to further turmoil in the OPEC oil exporter. Meanwhile discontent in Nigeria stirred by oil wealth inequality and Islamic militants could well lead to further oil outages and an increased risk premium for companies operating in the region.
2. Although tensions between Ukraine and Russia appear to have eased for now, or at least Putin is making a tactical retreat ready for his next move, the prospect of further unrest in the region and sanctions against Russian oil companies is likely to remain a risk for oil prices. The next key dates are 25 May, when elections take place in Ukraine and then 3 June, the date Gazprom has said it may halt natural gas shipments to Ukraine unless the country pays in advance for its supplies.
3. The Chinese appear to have been aggressively filling their strategic oil stockpiles since the start of 2014. One reason they may have brought their stockpiling forward is in case of any disruption due to unrest between Ukraine and Russia. Although China’s record imports of 6.78 million b/d in April give the impression that oil demand is roaring ahead in reality some 360 thousand b/d has gone into stockpiles – totaling 43.5 million barrels so far this year. Barclay’s estimates that China may fill an additional 15 million barrels during 2014. According to Deutsche Bank the Chinese are dipping into the market whenever Brent falls near £105 per barrel. Although the Chinese are likely to keep on buying later in the year the level of support is unlikely to be as strong as in the past five months.
4. US crude stockpiles are near 400 million barrels, the highest level since the Energy Information Administration began publishing weekly data in 1982. This is likely to be as high as it gets though in 2014. As the US heads into the summer driving season however demand from refineries is likely to start picking up calling on crude stockpiles and leading to higher oil prices during the second and third quarter (see article on seasonal crude price patterns).
5. Stronger global economic growth means oil demand is likely to grow strongly in 2014. According to the IEA OPEC will need to hike production by 900 thousand b/d in the third quarter from April levels in order to balance the increase in demand. While OPEC producers can potentially do this the ongoing issue of unplanned outages may prevent this increase in output being achieved (see point 1).
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By Carla Mozee
LONDON (MarketWatch) -- Citigroup on Wednesday raised its estimates on oil prices, and said "earnings headwinds for the [oil] sector look considerably less than they have for some time." Citi raised its Brent forecast to $109 a barrel from $103 a barrel for 2014, and to $105 a barrel from $95 a barrel in 2015. The upgrades primarily reflect continuing tight supply through 2014 "exacerbated by a heightened sense of supply fragility due to escalating violence in Nigeria and Iraq as well as ongoing disruption in Libya." The ongoing Russia/Ukraine crisis has introduced a "large, completely unexpected source of geopolitical risk" to a market that was stuck in neutral to bearish territory, Citi added. Per-share earnings estimates for integrated oil firms were raised by an average of 4% this year, and 9% in 2015. Top equity picks remain Total SA FR:PAR -1.01% , BG Group PLC UK:BG -0.71% , Galp Energia PT:GALP +0.51% and Repsol SA ES:REP +1.80% , said Citi.
21 May 2014 14:23 (Last updated 21 May 2014 14:27)
Experts debate whether a deterioration in security will halt the flow of Libyan oil to drive up prices
by Selen Tonkus
ANKARA
Libya may resume high volume oil production which will drive prices down, if national reconciliation can be reached, say experts as political turmoil shakes the country.
75 people have died in the conflict between forces loyal to renegade General Khalifa Haftar and the Libyan army in Benghazi in the east since last Friday.
The conflict has spread to the capital, Tripoli on Sunday, when fighters stormed the parliament and kidnapped several lawmakers.
Amid the escalating conflict, the price of oil reached above US$110 a barrel on Tuesday after gaining nearly two percent last week, as the threat of further violence threw into question the country's ability to export.
Libya has begun exporting oil from two of its four terminals only recently.
Rebels composed of ex-port guards and some Libyan tribes seized four ports in the east last July, and demanded autonomy and a fairer distribution of oil revenue.
Libya's oil production, estimated at 1.4 million barrels a day before the beginning of the crisis, fell sharply to about a fifth of its previous volume by the end of February.
The country was expected to resume producing oil in large amounts after rebels reached an agreement with the Libyan government last month.
No structural damage to oil fields yet
Paul Michael Wihbey, President of the Global Water and Energy Strategy Team (GWEST LLC) - a consultation firm in Washington - said the geopolitical risk factor of the ongoing Libyan crisis has already been taken onboard with the Brent benchmark for global oil prices, which has fluctuated between $100-110 a barrel over the last year.
With 70-80 percent production, 1.3 millions barrel a day of Libyan oil exports have been sold off-market. Since 2013 the current crisis has had minimal impact on the oil market and prices. This will be the case even if the crisis deepens, since current exports are at historical lows.
When asked about future provisions, Wihbey said, "the status quo will be maintained until either political stabililty returns and full production in Libya resumes which could depress global prices by US$5-8 a barrel, or Libya's oil infrastructure - ports, refineries, storage tanks,and rigs are so seriously damaged that prices would spike upward by as much as US$5-10 a barrel."
He added that, at present, there are no indications that the critical infrastructure components are being targeted by any of the opposing sides in Libya.
Libya oil can be replaced
Mattia Toaldo, London based European Council for Foreign Relations policy fellow, said, "Libya's crude is of very good quality but it can be replaced. In fact, Europe has done without it during a part of 2011 because of the war and again since last summer because of the oil strikes."
He stressed that resumption of production rests on political deals which are more difficult in the current situation.
The deal struck in April with the seccessionists has led only to the partial re-opening of one of the four ports in Cyrenaica, in the eastern coast.
Resuming production in the west will depend on co-operation from the Zintan militia - one of those fighting alongside General Haftar who attacked parliament on Sunday in Tripoli, he said, and added that unless a national united government is formed, production will not resume.
OPEC data suggests that Libya is the largest oil country on the African continent with 48 billion barrels of proved reserves - the ninth in the world. Europe buys 10 percent of its oil from Libya.
By Erin Banco
on May 21 2014 3:40 PM
http://s1.ibtimes.com/sites/www.ibtimes.com/files/styles/v2_article_large/public/2011/02/26/68842-a-view-of-a-damaged-production-unit-after-a-bomb-attack-at-baiji-oil-r.jpg
Iraqi Prime Minister Nouri al-Maliki's apparent success in gaining a third term in office, a move that could escalate already high tensions with Sunni militant groups in the country but will have little effect on the country’s massive oil sector -- provided al-Maliki handles Iraq's Kurdish leaders carefully.
The Iraqi electoral commission announced Monday that al-Maliki’s State of Law bloc had won the most seats in the April 30 parliamentary elections, falling short of a majority. This week Iraqi officials have struggled to confront how the country will move forward politically. While the country braces for what is expected to be a tumultuous future in forming a new government, experts say the country will most likely not suffer from investment shortfalls in the oil sector — its main source of revenue. Rather, it is the sector’s internal ability to increase capacity and technical expertise that will determine its fate, experts say.
“Changes in the sector will come as a function of the demand for Iraq to develop its fields,” Denise Natali, a fellow at the National Defense University in Washington, said. "The question is whether they even have the capacity to move forward.”
Following the beginning of the war in Iraq, many oil technocrats left the country. Thousands of engineers fled to places like Dubai and Jordan. As a result, the country’s oil industry is now playing catch up. It is unclear whether, despite the immense amount of oil Iraq can access, the country can extract, produce and export efficiently.
Nearly two years ago the International Energy Agency (IEA) predicted Iraq’s oil production would double by 2020, but that it would depend on a number of factors, including the country’s overall stability and security.
“What we did is looked into Iraq as a whole,” Maria van der Hoeven, executive director of the IEA, said in an interview with Bloomberg in October 2012. “But as I mentioned before it is of the upmost importance that the political stability is there, that the regulatory framework is there, that security is there. But what we can see for instance from incidents in the last few months, the last year, is that the incidents in the south and the north are less.”
In November 2012, the International Monetary Fund (IMF) echoed the IEA’s prediction, claiming that Iraq could gain almost $5 trillion in revenues from oil exports before 2035.
Since then, more than 15,000 civilians have been killed in the country, according to the Iraq Body Count website, as a result of increasingly violent clashes between government forces and the Islamic State of Iraq and the Levant (ISIL), a predominantly Sunni group, in regions such as Anbar Province and Fallujah.
The oil industry has not escaped the increasing tensions in the country, either. Last month Amer Shawwal, director of the Haditha refinery in central Iraq, was kidnapped on his way to the Baiji refinery. He is still missing.
And on a larger scale, the Iraqi government is still working to quell tensions with Kurdistan regarding oil stockpiles in the north. The relationship between al-Maliki and Kurdistan continues to deteriorate as Kurdistan negotiates oil contracts with Turkey.
Since 2011, Ankara has worked toward economic integration with the Iraq's Kurdish administrators, agreeing to sell oil produced in the Kurdish region of Iraq via Turkey’s Ceyhanli port to foreign markets. The Kirkik-Yumurtalik (Ceyan) pipeline has about a 70 million-barrel capacity. The Kurdish government built another pipeline that connects to Ceyan and oil was expected to begin moving through it in January. But, the Iraqi constitution requires permission from the Baghdad government before the oil is sold and Hussain al-Shahristani, deputy prime minister of energy, has yet to sign off on the deal.
“The Kurds may have over stepped themselves. They will have to cut a deal,” Natali said. “They have to indicate or show the investors that the contracts will be honored.”
Despite the violence and the political tensions in the country, the Iraqi oil sector has continued to grow.
According to a report published in March by FGM, an emerging market research group, Iraq has tripled its oil production in the last decade and posted an annual gross domestic product growth rate of around 10 percent.
May 21, 2014 by Ibrahim Khalil
http://www.iraqinews.com/wp-content/uploads/2014/05/Naft-Iran-logo-490x480.jpg
Follow-up (IraqiNews.com) Iran assured that its transportation of natural gas to Iraq will start on March 2015 with 5 million cubic meters per day.
The Iranian transportation of gas to Iraq were scheduled next September 2014 according to announcement of the Iranian Ministry of Petroleum last April.
The Iranian Deputy Minister of Petroleum, Ali Majidi, said in a press statement “Iran will start exporting gas to Iraq on March 20th 2015 after completing the pipelines project.”
Majidi justified the delay in exporting Iranian gas to Iraq by “Not completing the project of extending pipelines to transport gas into Iraq.”
It is worth to mention that the length of the pipelines of transporting gas from Iran to Iraq is about 100 km which will start from the Iranian Jarmillah city to end in Naft Shaher border city with Iraq.
