Russia’s Rosneft has announced a major oil and gas discovery in the Arctic Kara Sea following drilling of the northernmost well in the world amid concerns that ExxonMobil’s expected departure from the project due to US sanctions would strike a serious blow to Russian operations in the Arctic.
“According to preliminary results, the resource base of the first hydrocarbons trap discovered through the drilling [in the East-Prinovozemelsky 1 block] is estimated to hold 338 billion cubic meters of gas and over 100 million mt (730 million barrels) of crude,” Rosneft’s CEO Igor Sechin said in a statement Saturday.
“This is light crude comparable to the Siberian Light blend, according to the initial tests,” he added.
The announcement came weeks after the US imposed new sanctions against Russia over its role in the Ukrainian crisis. Under the latest round of sanctions, any US entities and citizens had to “wind down” Russian projects focused on development of deepwater, Arctic and shale oil reserves before September 26.
But US authorities moved the deadline for ExxonMobil operations in the Kara Sea to October 10 to provide more time for the company to complete its work safely and avoid any potential environmental risks.
The sanctions raised concerns that if ExxonMobil as well as some Western service companies were to halt the drilling, it would lead to significant delays to Russian plans to explore its Arctic waters.
The partners, however, completed the drilling “in record-breaking time — in one and a half months — in compliance with all the technological and ecological standards and requirements,” Rosneft said.
Amid increasing pressure from Western countries on Russia’s energy sector aimed at forcing the Kremlin to cease its involvement in the political crisis in Ukraine, Sechin has said that he prized highly the joint efforts with Western companies in receiving “outstanding results” of making a discovery through the drilling of the first exploratory well in the new area.
“This is our united victory, it was achieved thanks to our friends and partners from ExxonMobil, North Atlantic Drilling, Schlumberger, Halliburton, Weatherford, Baker, Trendsetter, FMC,” he said. “We would like to name this field Pobeda (Victory).”
The well, estimated to cost around $600 million by some experts, was drilled to a depth of 2,113 meters in open-water conditions 250 km off the Russian coast, Rosneft said.
As a result of the drilling, a significant volume of new geological data has been gathered and further interpretation will allow more precise evaluation of field’s resource base, Sechin said.
Sechin has said earlier that the companies were hoping to discover a major oil province in the Kara Sea, with reserves comparable to Saudi Arabia’s.
US crude imports rose 569,000 b/d in July, though imports of Nigerian crude fell to zero for the first time on record, data from the US Energy Information Administration showed Monday.
US imports rose to 7.623 million b/d, up from 7.054 million b/d in June. Despite being at their highest since December 2013, imports are down from 8.058 million b/d in the same month a year ago.
Imports from Nigeria fell to zero in July, down from 89,000 b/d in June — all of which had gone to the US Atlantic Coast. The one refinery that accounted for all of the June Nigerian imports turned to Azerbaijan in July, EIA data shows.
Philadelphia Energy Solutions brought in 2.088 million barrels of light sweet Azerbaijani crude, likely Azeri, in July. US Atlantic Coast refiners have been increasingly turning away imported light sweet crudes in favor of domestically produced barrels, mostly railed from North Dakota.
While the EIA data does not include crude shipped by rail, it does show USAC imports at just 59% of gross crude inputs in July, down from 70% in July 2013, and 100% in July 2004.
US Atlantic Coast refining margins largely favored Bakken crude in July, although with more light sweet crudes getting backed out into the Atlantic Basin, spot prices for imported crudes have fallen, boosting margins.
The USAC cracking margin for Bakken averaged $5.31/barrel in July, according to Platts data, a bit under the $5.65/b average for Nigerian Bonny Light, but over the $2.91/b average for Hibernia. The Bakken cracking margin has averaged $10.99/b so far in September, while Bonny has averaged $14.01/b and Hibernia $12.09/b.
Platts margin data reflects the difference between a crude’s netback and its spot price. Netbacks are based on crude yields, which are calculated by applying Platts product price assessments to yield formulas designed by Turner, Mason & Co. Platts does not publish margins for Azeri on the USAC, although Azeri spot price differentials were already under downward pressure.
Azeri averaged at a $2.37/b premium to Dated Brent in July, down from an average of $3.31/b in January. Azeri has averaged a $1.35/b premium so far in September.
Platts cFlow shiptracking software shows two recent vessels carrying crude from Ceyhan bound for the USAC. The Matala is scheduled to arrive in Philadelphia September 30, and the Rio Grande in Philadelphia October 13. Platts cFlow shows just two vessels entering the USAC from West Africa in September, down from five in August.
Libya’s 230,000 b/d Zawiya export terminal resumed loadings over the weekend, after militia fighting near the terminal and 120,000 b/d refinery prompted state-owned National Oil Corp. to close the port.
The Dugi Otok Aframax tanker loaded an 80,000-mt crude cargo from Zawiyah over the weekend, according to a local port agent and the shipowner.
“The ship loaded and sailed on Saturday. It was an OMV cargo,” said the port agent.
This was confirmed by a source at the shipowner Tankerska. Production at the 340,000 b/d Sharara crude field, which feeds both the export terminal and the refinery, resumed on September 22 Monday after output was halted shortly after activity at terminal and refinery was suspended in mid-September.
“They have loaded at least one vessel at least,” a trading source said of the Zawiya terminal. “The entire [loading program] for October has also been finalized.”
Trading sources said production at the field has risen since resuming last week and is now averaging around 200,000 b/d, with the bulk of production directed toward the export terminal. The refinery has also resumed production (See story 1416 GMT).
According to shipbroker reports, Total is due to load an Aframax with an October 4-5 laycan, but no further details were immediately available.
US crude oil imports from Colombia and Mexico decreased in July but increased from Argentina and Ecuador, according to monthly information published Monday by the US Energy Information Administration.
Imports from Colombia totaled 197,000 b/d in July, down from 203,000 b/d in June and 574,000 b/d in July 2013, the EIA said. Imports of Colombia’s heavy sour crude Castilla Blend and mid-grade Vasconia have been declining due to additional imports of Canadian crudes.
Imports from Canada totaled 2.8 million b/d in July, up from 2.75 million in June and 2.53 million barrels in July 2013.
Imports from Mexico totaled 714,000 b/d, down from 730,000 b/d in June and 852,000 b/d in July 2013. Imports from Argentina totaled 50,000 b/d in July, up from 22,000 b/d in June. The EIA recorded no crude imports from Argentina in July 2013.
Argentina imports primarily Escalante crude, 24 API and 0.25% sulfur, into the US West Coast. Imports of Escalante fell dramatically after BP sold its 275,000 b/d Carson, California, refinery to Tesoro. July’s 50,000 b/d all went to the US West Coast, or PADD V, the EIA said.
Imports from Ecuador increased to 214,000 b/d in July, up from 138,000 b/d in June and 192,000 b/d in July 2013. The increase was surprising as Ecuadorean Oriente and Napo crude imports have been seriously curtailed in the US West Coast due to large imports of Iraqi Basrah and Canadian exports from Vancouver, British Colombia.
For the US West Coast, Ecuadorean imports totaled 135,000 b/d in July, up from 102,000 b/d in June. For the US Gulf Coast, Ecuadorean imports totaled 79,000 b/d, up from 36,000 b/d in June.
Statoil has restarted production from its Asgard A unit in the Norwegian North Sea, a company spokesman said Monday, after it was shut last week due to a staff reduction as a safety precaution during bad weather.
Spokesman Morten Eek said in an email that normal operations began on Saturday. Nearly 70 crew had to be moved to nearby installations because of the extreme weather conditions. As well as Asgard A, the Norne ship and the three platforms Statfjord A, B and C had some precautionary manning reductions during the same period, Statoil said, but with no production impact there.
The Asgard Field is on the Halten Bank about 200 km (124 miles) offshore mid-Norway, Statoil said. The Asgard A — a Floating Production, Storage and Offloading vessel — arrived at the field February 8, 1999, and became operational May 19 of that year, according to Statoil. The field is comprised of the Midgard, Smorbukk and Smorbukk South discoveries.
ConocoPhillips (COP) is shipping a cargo of Alaska North Slope crude to Asia, making rare use of a Bill Clinton-era exemption to U.S. oil export restrictions.
Conoco, Alaska’s largest oil producer, will deliver the cargo to Asia in the fourth quarter, Houston-based company spokesman Daren Beaudo said by e-mail. The shipment was first reported by Louisville, Kentucky-based Genscape Inc., an energy intelligence firm.
The Polar Discovery, a 140,000-deadweight ton oil tanker, left the oil port of Valdez in Alaska on Sept. 26 after filling with cargo, according to vessel tracking data compiled by Bloomberg. The ship reported today that its destination is Yeosu, South Korea. It’s scheduled to arrive Oct. 10.
“ConocoPhillips has the capability to export a limited amount of its Alaska North Slope (ANS) crude oil production to non-U.S. customers as allowed by law,” Beaudo said. “This will enable the state of Alaska and ConocoPhillips to potentially realize a higher value for this important natural resource.”
ANS traded for $95.32 a barrel at 4:14 p.m. today, according to data compiled by Bloomberg. That’s 51 cents less than ESPO, a crude of similar quality that Russia exports out of Siberia. ESPO traded at $10.47 a barrel more than ANS in November.
The U.S. bans most exports of unprocessed crude, based on a 1975 law passed after the Arab oil embargo. In 1996, Clinton amended the law to allow exports of crude from the North Slope that traveled on the Trans-Alaska Pipeline System to Valdez.
Alaskan crude exports must be transported by ships built and flagged in the U.S. and crewed by American sailors. The Polar Discovery was built in Avondale, Louisiana, in 2003, at a shipyard that Huntington Ingalls Industries Inc. (HII) is closing.
The U.S. hasn’t exported crude to South Korea since a 24,000-barrel shipment was sent there in September 2006, according to Energy Information Administration data.
WASHINGTON, Sept. 29 (UPI) -- Oil production from the Eagle Ford shale play should increase with improved drilling efficiency, though the area is prone to declines, analysis Monday finds.
The U.S. Energy Information Administration, a division of the Energy Department, said the increase in drilling and improvements in drilling efficiency have led to more oil from the Eagle Ford shale region in southern Texas.
"These increases have occurred despite the region's relatively high well decline rates," an EIA briefing said. "However, by offsetting the natural declines through the use of new recovery techniques, further production increases are possible."
The Texas government said oil production in July, the last full month for which data are available, increased more than 25 percent year-on-year to around 2.15 million barrels per day thanks in part to production from Eagle Ford.
Eagle Ford is one of the most prolific shale basins in the United States. A separate report last week from energy consultant group Wood Mackenzie found enhanced oil recovery, a pioneering extraction method for shale basins, could add between 1.5 million and 3 million barrels per day in oil production by 2030.
For conventional hydraulic fracturing, EIA said operators are using more sand and other materials to keep shale open. That's lead to a rise in initial production rates, but is met by a steeper drop off.
TEHRAN, Sept. 29 (UPI) -- Iranian Oil Minister Bijan Zanganeh said Monday oil exports from the Islamic republic were "acceptable" and revenue was on the rise.Iran, under the terms of a November 2013 agreement with Western powers, secured relief from some of the sanctions targeting its energy sector in exchange for a pledge to cut back on its nuclear research activity. The U.S. Treasury Department in July extended that relief through November.
Iran can export around 1 million barrels of oil per day under the deal.
"Iran's oil exports are acceptable and growing currently, and revenues are higher than the previous estimates," the oil minister said.
The International Monetary Fund in April said inflation and unemployment are both high in the Iranian economy and the outlook was "highly uncertain." Constraints on oil revenues as a result of Western economic pressure means the Iranian economy is expected to continue contracting at least through the rest of this year, the bank said.
Zanganeh offered no specifics in terms of revenue in his latest remarks. His comments come as Tehran and members of the international community continue to discuss breaking a long-standing impasse over Iran's controversial nuclear program.
Last month, Tehran said oil production increased 11 percent in the four months since the March 21 start of the Iranian calendar year. This in turn helped to contribute to export earnings of around $7.9 billion.
MOSCOW, Sept. 29 (UPI) -- Russia is ready to respond should its Ukrainian or European Union partners renege on trilateral energy agreements, a Kremlin spokesman said Monday.
Kremlin spokesman Dmitry Peskov said the Russian government is operating under guidelines spelled out last week during trilateral talks in Berlin.
"Russia is guided by the agreements reached at the three-party talks, but at the same time is ready to defend its position," he said.
Negotiating partners last week outlined the terms of an interim agreement that sees Ukraine paying the $3.1 billion it owes Russian energy Gazprom. Ukraine, in return, gets a price discount and assurances of adequate winter natural gas supplies.
European Energy Commissioner Gunther Oettinger said that, with both sides sparring over contracts in international courts, an interim deal is necessary for short-term energy security.
Russia sends most of its gas for European consumers through the Soviet-era transit network in Ukraine. Contractual disputes in 2006 and 2009 between Kiev and Gazprom resulted in brief gas shortages in Europe, and ongoing crises in eastern Ukraine have exposed the European community to additional energy risks.
CALGARY, Alberta, Sept. 29 (UPI) -- Canadian energy company Encana Corp. said Monday it acquired Texas rival Athlon Energy to become one of the largest oil players in the Permian shale basin.
"This transformative acquisition further accelerates our strategy and provides us with a prime position in what is widely acknowledged as one of North America's top oil plays," Encana President and Chief Executive Officer Doug Suttles said in a statement.
Ecanana paid cash for the acquisition, giving the Canadian company control over 140,000 net acres in the Permian shale basin in Texas.
Permian production increased 58 percent from 2007 to reach 1.35 million bpd last year, which represents 18 percent of total U.S. crude oil production.
In a July brief, the U.S. Energy Information Administration said the Permian basin has exceeded production from offshore Gulf of Mexico since 2013.
Encana said the transaction will add about 30,000 barrels of oil equivalent to its portfolio. The company said it could drill as many as 5,000 wells in the Permian acquisition area.
"During our strategic review last year, we carefully studied North America's premier basins and identified the massive horizontal, multi-zone, development potential in the Permian," Suttles said.
MOSCOW, Sept. 29 (UPI) -- Russian oil company Rosneft said the discovery of oil in an arctic license area came as the result of a united effort with its Western energy partners.
Rosneft estimates the discovery at an area in the Prinovozemelskiy-1 license area in the Kara Sea holds at least 700 million barrels of oil.
"This is an outstanding result of the first exploratory drilling on a completely new offshore field," Rosneft Chief Executive Officer Igor Sechin said in a statement Saturday. "This is our united victory; it was achieved thanks to our friends and partners from ExxonMobil, Nord Atlantic Drilling, Schlumberger, Halliburton, Weatherford, Baker Hughes, [and others]."
The company said the entire area could hold as much as 87 billion barrels of oil.
Greenpeace activists this year trailed some of the international rigs headed to arctic waters to raise awareness about the risks they see to the arctic environment.
Rosneft said the operations in the Kara Sea were concluded in compliance with all ecological standards and requirements.
The oil discovery announcement comes as Rosneft copes with a string of sanctions filed against the Russian companies from Western powers frustrated with Russia's actions in eastern Ukraine.
SHARJAH, United Arab Emirates, Sept. 29 (UPI) -- Emirati energy company Dana Gas said Monday it was the successful bidder for two onshore license areas in the Nile Delta region onshore Egypt.
Regional subsidiary Dana Gas Egypt was awarded the rights to operate in the North el-Salhiya and el-Matariya onshore areas in the Nile Delta.
"We are extremely pleased to have been awarded these two new blocks," Dana Gas Chief Executive Officer Patrick Allman-Ward said in a Monday statement. "The area is particularly well known to Dana Gas, given its long-term commitment to the Nile Delta."
Dana is the sixth largest energy company working in Egypt. Overall, its share of production has reached 39,100 barrels of oil equivalent per day.
Dana will hold 100 percent of the interest in the North el Salhiya area and work on a parity basis with BP at el-Matariya.
"We are delighted to be partnering with BP, a leader in deep well drilling in the Nile Delta," Allman-Ward said.
Dana gave no estimate of the reserve potential. The two blocks have a six-year exploration period for the Emirati company.
KUALA LUMPUR, Malaysia, Sept. 29 (UPI) -- Malaysian oil company Petronas said it signed agreements with its Mexican and Argentine partners to expand its footprint in the Americas.
Petronas, Mexican oil company Petroleos Mexicanos, known also as Pemex, and Argentine oil company YPF signed a trilateral memorandum of understanding on exploration and production.
Petronas President Tan Sri Dato' Shamsul Azhar Abbas said the Latin American companies were the right partners to have for regional growth.
"These memoranda will hopefully provide a strategic platform for growth to complement and provide optionality to our North American resource base," he said in a Saturday statement.
Petronas and Pemex agreed separately to exchange information for activities related to deepwater explorations, extraction of heavier crude oils and the potential for the development of natural gas infrastructure.
Pemex wants a role in developing the vast oil deposits in the Vaca Muerta shale oil region of Argentina and sent experts there last year to review the prospects.
Pemex itself is working under a state privatization agenda that envisions production of 3.5 million barrels of oil per day by 2025, which would be a 40 percent increase from 2013 levels.
New York (Platts)--29Sep2014/347 pm EDT/1947 GMT
US crude imports rose 569,000 b/d in July, though imports of Nigerian crude fell to zero for the first time on record, data from the US Energy Information Administration showed Monday.
US imports rose to 7.623 million b/d, up from 7.054 million b/d in June.
Despite being at their highest since December 2013, imports are down from 8.058 million b/d in the same month a year ago.
Imports from Nigeria fell to zero in July, down from 89,000 b/d in June -- all of which had gone to the US Atlantic Coast.
The one refinery that accounted for all of the June Nigerian imports turned to Azerbaijan in July, EIA data shows. Philadelphia Energy Solutions brought in 2.088 million barrels of light sweet Azerbaijani crude, likely Azeri, in July.
US Atlantic Coast refiners have been increasingly turning away imported light sweet crudes in favor of domestically produced barrels, mostly railed from North Dakota.
While the EIA data does not include crude shipped by rail, it does show USAC imports at just 59% of gross crude inputs in July, down from 70% in July 2013, and 100% in July 2004.
US Atlantic Coast refining margins largely favored Bakken crude in July, although with more light sweet crudes getting backed out into the Atlantic Basin, spot prices for imported crudes have fallen, boosting margins.
The USAC cracking margin for Bakken averaged $5.31/barrel in July, according to Platts data, a bit under the $5.65/b average for Nigerian Bonny Light, but over the $2.91/b average for Hibernia.
The Bakken cracking margin has averaged $10.99/b so far in September, while Bonny has averaged $14.01/b and Hibernia $12.09/b.
Platts margin data reflects the difference between a crude's netback and its spot price. Netbacks are based on crude yields, which are calculated by applying Platts product price assessments to yield formulas designed by Turner, Mason & Co.
AZERI DISCOUNT ATTRACTIVE
Platts does not publish margins for Azeri on the USAC, although Azeri spot price differentials were already under downward pressure. Azeri averaged at a $2.37/b premium to Dated Brent in July, down from an average of $3.31/b in January.
Azeri has averaged a $1.35/b premium so far in September.
Platts cFlow shiptracking software shows two recent vessels carrying crude from Ceyhan bound for the USAC. The Matala is scheduled to arrive in Philadelphia September 30, and the Rio Grande in Philadelphia October 13. Platts cFlow shows just two vessels entering the USAC from West Africa in September, down from five in August.
And while the rise of Bakken has appeared to spell doom for grades like Bonny Light, USAC refiners did import from Angola, Chad, and Congo Brazzaville.
Angolan imports fell to 65,000 b/d from 97,000 b/d. Nearly all Angolan barrels went to Phillips 66's 238,000 b/d Bayway refinery in Linden, New Jersey. Bayway also took in two cargoes from Congo Brazzaville.
Chad imports at 61,000 b/d, like the Azeri, went almost entirely to PES. This doubled Chad's USAC supply from around 32,000 b/d over April, May and June.
Imports from Iraq to the USAC were down to 55,000 b/d from 85,000 b/d, while Saudi barrels rose to 68,000 b/d from 31,000 b/d. All of the Saudi and Iraqi crude went to PBF's 180,000 b/d Paulsboro, New Jersey, refinery.
Paulsboro also took all of the Venezuelan imports to the region. Imports from Venezuela rose to 25,000 b/d from just 2,000 b/d.
USGC IMPORTS UP
Imports to the US Gulf Coast accounted for most of July's gains, up 476,000 b/d to 3.553 million b/d. USGC imports were last higher in April at 3.596 million b/d.
Saudi imports to the region rose to 868,000 b/d in July from 672,000 b/d in June. The Saudi Aramco/Shell joint venture Motiva refinery in Port Arthur, Texas, took around 386,000 b/d, while ExxonMobil took around 162,000 b/d across its USGC refineries. Marathon imported around 207,000 b/d of Saudi crude for its USGC refineries in Garyville and Galveston Bay, as well as its Catlettsburg, Kentucky, facility.
Venezuelan imports to the USGC rose to 826,000 b/d in July, up from 699,000 b/d in June. That is the highest Venezuelan imports have been since the 843,000 b/d imported in July 2012.
Citgo took in around 189,000 b/d between its Lake Charles and Corpus Christi refineries. Phillips 66 imported around 176,000 b/d of Venezuelan crude for its Sweeny refinery.
Imported crude is making up a lower percentage of total crude supply, as US production rises. US imports accounted for 45% of gross crude inputs in July, down from 49% in July 2013, and 63% in July 2004.
Canada remained the number one supplier of foreign crude to the US. Imports from Canada climbed 50,000 b/d to 2.8 million b/d, while imports from Saudi Arabia rose 214,000 b/d to 1.23 million b/d. Venezuela took third place at 852,000 b/d.
The bulk of the Canadian crude -- 1.94 million b/d -- went to the US Midwest. Outside of Canada, US refiners are now dependent on foreign oil for just 29% of gross inputs, down from 53% 10 years ago.
US crude production at 8.54 million b/d in July was up from 5.49 million b/d 10 years ago.
Moscow (Platts)--29Sep2014/1056 am EDT/1456 GMT
Russia's Rosneft has made a major oil and gas discovery in the Arctic Kara Sea following the drilling of the northernmost well in the world in the East-Prinovozemelsky 1 block, which it explores together with ExxonMobil, the company said Saturday.
"According to preliminary results, the resource base of the first hydrocarbons trap discovered through the drilling is estimated to hold 338 billion cubic meters of gas and over 100 million mt (730 million barrels) of crude," Rosneft's CEO Igor Sechin said in a statement.
"This is light crude comparable to the Siberian Light blend, according to the initial tests," he added.
The announcement came days after the US imposed new sanctions against Russia over its role in the Ukrainian crisis. Under the latest round of sanctions, any US entities and citizens had to "wind down" Russian projects focused on development of deepwater oil reserves, Arctic and shale oil reserves before September 26.
But the US authorities moved the deadline for ExxonMobil operations in the Kara Sea to October 10, to provide more time for the company to complete its work in a safe mode to avoid any potential environmental risks.
The sanctions raised concerns that if ExxonMobil as well as some Western service companies were to halt the drilling, it would lead to significant delays to Russian plans to explore its Arctic waters.
Sechin has said earlier that the companies were hoping to discover a major oil province in the Kara Sea, with reserves comparable to that in Saudi Arabia.
The partners, however, completed the drilling "in record-breaking time -- in one and a half months -- in compliance with all the technological and ecological standards and requirements," Rosneft said. It was initially expected that the drilling would continue for around two months, during the ice-free season that lasts from August through mid-October.
Sechin has said that he prized highly the joint efforts with Western companies in receiving "outstanding results" of making a discovery through drilling of the first exploratory well in the new area.
"This is our united victory, it was achieved thanks to our friends and partners from ExxonMobil, Nord Atlantic Drilling, Schlumberger, Halliburton, Weatherford, Baker, Trendsetter, FMC," he said. "We would like to name this field Pobeda (Victory)."
The well was drilled to a depth of 2,113 meters in open-water conditions, 250 km off the Russian coast, according to Rosneft.
As a result of the drilling, "a significant volume of new geological data is received, its (further) interpretation would allow to evaluate more precisely the resource base of the discovered field," Sechin said.
Rosneft owns 66.67% in the project, with ExxonMobil owning the remaining 33%. The agreement provides for joint work at three East Prinovozemelsky blocks in the Kara Sea, where some 30 structures were found. The combined resource base of the three blocks is estimated at 87 billion barrels or 13 billion mt of oil equivalent, according to Rosneft.
Rosneft said that prior to the start of operations in the Kara Sea, the West Alpha drilling rig, operated and owned by the Nord Atlantic Drilling, was heavily upgraded, which, among other things, was needed to guarantee ecological safety.
The rig was equipped with two groups of blowout preventers and an independent submarine locking device, which, in case of minor risks would seal the well. The rig was held at the drilling site by an anchoring positioning system, consisting of eight anchors. This guaranteed an elevate rig stability. Most of the platform was out of the reach of the waves, which could disturb its operations. The rig was capable of drilling to a depth of up to 7 km.
London (Platts)--29Sep2014/840 am EDT/1240 GMT
Market fundamentals in the FOB Mediterranean gasoline cargo market for the low-Reid Vapor Pressure, 60 kPa, summer-spec gasoline and the higher-RVP, 80 kPa gasoline, are diverging, with a strong market on summer-grade and a longer market for the cheaper winter-spec, as the region transitions to winter-grade gasoline.
Summer-grade gasoline has seen ample strength throughout September, on the back of tight supply following the refinery turnaround season and sustained demand from North Africa and an open arbitrage to the Persian Gulf.
"Most of the demand is at 60 kPa...we believe this strength will continue into first half of October," a trading source said, pointing to North Africa and the Persian Gulf as the main centers of demand for Mediterranean gasoline, where 60 kPa summer-spec gasoline is imported throughout October.
Looking at winter-grade gasoline, demand is currently confined to Europe, with no arbitrage open for the 80 kPa specification from the Mediterranean, sources said.
An 80 kPa cargo on prompt dates (loading October 6-10) was offered lower and traded in the Platts Market On Close assessment process Friday with the FOB Med gasoline cargo market assessed at $877.75/mt at a $9.25/mt discount to the front-month swap.
This was down from $897.25/mt assessed Thursday, when the discount to the front-month swap was at $1.75/mt.
Platts reflects 80 kPa gasoline for cargoes loading in October.
"An 80 kPa cargo for the end of the month is OK because you can use it in November," a source said.
"[But] one at the beginning of the month -- once you've exhausted the few existing shorts of EN228 at 80/90kPa...you can only send it to the AG for re-blending [to low-RVP]," the source said, pointing to the relative length on winter grade as demand for high-RVP gasoline remained weak.
Singapore (Platts)--28Sep2014/1153 pm EDT/353 GMT
Australian independent ROC Oil and partner Horizon Oil announced Monday, September 29, they have discovered oil at well WZ12-10-1 in Beibu Gulf Block 22/12, offshore China.
The well, the first of two exploration wells scheduled to be drilled on the block, was drilled to a depth of 1,406 meters (4,612 feet) and "discovered oil in the very top of the Jiaowei (T42) formation over an interval of 5.5 meter, with a high porosity net oil pay of 4.2 meter," ROC said in a statement to the Australian stock exchange Monday.
A sidetrack well was then drilled and confirmed oil in T42 with a thicker oil pay of 5.5 meters, the company added.
"This discovery will be evaluated on how best to integrate it into the Beibu project," and a rig will soon be moved to the site to drill the second and final exploration well in the program, ROC said.
Well WZ12-10-1 is located 4.7 km (2.9 miles) northeast of the WZ12-8W platform and 2.7 km west of the WZ12-8E discovery wells, ROC said.
"This oil discovery adds potentially valuable incremental oil to the Beibu project. The location of the oil discovery allows ROC and the joint venture to evaluate alternative development scenarios, particularly integration with the Beibu WZ12-8E oil discovery," ROC CEO Alan Linn said.
In the exploration phase, ROC has a 40% operated stake in the Beibu Gulf project alongside fellow Australian independents Horizon Oil and Petsec which have a combined 55%, while South Korea's Majuko has the remaining 5% stake.
Horizon and ROC were planning a merger of equals before China's Fosun International in August made a A$474 million ($420 million) cash takeover offer for ROC.
If the new find is deemed commercial and goes into production, China's state owned CNOOC assumes operatorship with a 51% share during the development and production phase, reducing ROC's share to 19.6%, Horizon and Petsec to 26.95% and Majuko to 2.45%.
In addition to its 19.6% share in the Beibu Gulf oil project, which produced 11,769 b/d in the quarter ended June 30, ROC has interests ranging from 11.7%-39.2% in the Zhao Dong oil fields in Bohai Bay, which produced 16,239 b/d in the same period.
The all-cash bid for ROC was Hong Kong-listed Fosun's first move into the oil industry.
The diversified Shanghai-based company lists its main businesses as insurance, industrial operations, investment and asset management.
In mid-September, Fosun was one of 25 Chinese companies that invested a total of Yuan 107.1 billion ($17.4 billion) to jointly buy a 29.99% stake in China's state owned Sinopec Marketing Company.
Fosun paid Yuan 2.153 billion for a 0.603% share of Sinopec Marketing.
Tokyo (Platts)--29Sep2014/447 am EDT/847 GMT
Japan's LNG imports came in at 7.05 million mt in August, falling 2.7% from a year ago and the lowest volume for the month since August 2010, data released by the Ministry of Finance data Monday showed.
On a month-on-month basis, August LNG imports declined 10.1% as cool weather and major typhoons in July and August dampened demand.
The largest supplier was Australia, shipping 1.52 million mt of LNG, slipping 7.4% from a year ago and down 23.1% from July.
Malaysia was the second largest supplier, sending 1.36 million mt of LNG in August, up 3.8% year on year and jumping 36% from the previous month.
Qatar came in third, at 1.11 million mt but the volume was 20.3% lower from a year ago and down 17.1% from July.
Shipments from Papua New Guinea, where the first cargo to Japan landed in June, fell 15% from July to 352,134 mt in August while those from Yemen grew more than three times from a year ago to 184,804 mt.
Japan took a 54,141-mt cargo from the US at a delivered price of $836.38/mt ($16.084/MMBtu).
According to Platts vessel tracking software cFlow, the LNG tanker Excel arrived at Sakai LNG terminal on August 20 from Kenai.
Spain sent a 52,156-mt cargo at $815.16/mt ($15.676/MMBtu).
Meanwhile, preliminary data released Monday by the MOF showed that the Japan Customs Cleared crude oil price was $110.526/barrel in August, down 1% from July but rising 3.2% from a year ago.
Some of Japan's long-term LNG contracts are linked to the JCC crude price but with a lag of a few months, so fluctuations in oil prices typically take some time to be reflected in LNG prices.
Hedge fund bets on Brent down 80% since June
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[LONDON] Hedge fund bets on Brent crude have fallen to a two-year low and are down more than 80 per cent since hitting a record level in June, data from ICE showed on Monday, illustrating a sharp reversal by money managers as oil has slumped.
Brent has fallen from more than US$115 a barrel in June to a two-year low just above US$95 a barrel last week, as violence in Iraq and Syria has had a limited impact on supplies and as output from Libya has returned.
Over the same time period, hedge funds have slashed their bets on Brent from a record high equivalent to more than 240 million barrels of oil to less than 44 million as of Sept 23, in another sign oil prices may remain under pressure.
In the latest week to Sept 23, data from the IntercontinentalExchange showed funds had cut their net long position in Brent by 22,113 futures and options contracts last week to 43,559. In late June they held a net long of 242,201 futures and options contracts.
Copyright © 2014 Singapore Press Holdings Ltd. Regn No. 198402668E
By Nidaa Bakhsh Sep 30, 2014 6:01 AM GMT+0700 - Comments Email Print
North Sea oil operators’ surging costs risk scaring away the more than 1 trillion pounds ($1.6 trillion) of investment needed to meet their production goals, according to industry lobby Oil & Gas UK.
The country needs that investment if it hopes to recover the equivalent of more than 20 billion barrels of oil, it said today in a statement. Production has dropped 40 percent in the past three years as fields mature, while unit operating costs are about 60 percent higher than as recently as 2011.
“The U.K. has to compete for each and every pound of that investment,” Malcolm Webb, chief executive officer of the industry group, said today in the statement. “If the current trend of rising cost continues, the U.K. Continental Shelf will cease to provide a healthy return on investment.”
A review by Ian Wood, former head of engineering company John Wood Group Plc (WG/), this year estimated there were 12 billion to 24 billion barrels yet to be extracted from the North Sea.
“We need a lighter tax burden, a simpler and more predictable system of field allowances and fiscal support for exploration,” said Michael Tholen, director of economics at Oil and Gas UK. The government is expected to announce the results of its Fiscal Review in December.
29 Sep 2014, 10.00 pm GMT
Bogota, 29 September (Argus) — US independent Vetra is in the process of restoring oil production of around 17,000 b/d from its Suroriente block in southern Colombia after a deal was reached to lift a 70-day community blockade.
Vetra told Argus that Suroriente output fell to around 7,500 b/d because of the blockade, and that production levels will likely return to normal within a week.
Output at the block was impacted on 13 July amid a series of regional blockades. An agreement to lift the blockade in the area of the Suroriente oil fields was ratified by local and national government and community representatives on 19 September, Vetra´s Canadian partner Petroamerica said in a 25 September statement.
The Suroriente block accounts for about 30pc of some 50,000 b/d of total oil production in restive Putumayo province. Operator Vetra and Petroamerica together hold a 52pc stake. Colombia´s state-controlled Ecopetrol holds the remaining 48pc stake.
Protests and community blockades at the Puerto Vega-Teteye road corridor in Puerto Asis municipality reduced Suroriente oil production for around two months as part of a province-wide strike. Local community leaders contend that oil development has exacerbated Colombia´s armed conflict and harmed the environment with little socio-economic benefit for communities.
Routine rebel attacks on oil infrastructure, including pipelines and tanker truck convoys, have caused oil spills and environmental damage in Putumayo, which in turn has contributed to community discontent.
The 19 September agreement stipulates that energy, environment and interior ministry officials, farmers and indigenous leaders will review a 2010 decree that permits the development of the Quinde, Cohembí and Quillasinga oil fields, which make up the Suroriente block.
Community groups have recently appealed to local courts to try to block further oil development in Putumayo.
Petroamerica said expanded development of the Suroriente block faced such an appeal of its environmental permit, but the court action was unsuccessful and the new project permit was ratified on 5 September.
But legal risk remains a concern for oil companies in the province. Early this month, a high administrative court, Colombia's State Council, ruled to indefinitely suspend government decree 934, which permits federal courts to review and overturn local rulings on oil and gas activity.
The government of President Juan Manuel Santos has pledged to increase oil exploration in Putumayo and tighten security for producers. A provincial official has said that there are plans to quadruple production to around 200,000 b/d over the next three years.
Copyright © 2014 Argus Media Ltd - www.ArgusMedia.com - All rights reserved.
29 Sep 2014, 9.32 pm GMT
Houston, 29 September (Argus) — Nigerian crudes vanished from monthly US import data for the first time in nearly 30 years, according to the Energy Information Administration, another sign of how surging US crude is changing the global markets.
US refiners reported no barrels of crude imports from the west African nation in July, ending the light, sweet crude's steady presence since 1986, the oldest available EIA data.
The rise of North American crude production has steadily eroded light, sweet imports. US Gulf coast refiners have cut total imports of the crude to an average 14,247 b/d in the first seven months of this year, down from 1mn b/d in the same period of 2009.
Nigeria oil output grew from about 2.212mn b/d in 2009 to 2.371mn b/d in 2013, according to the EIA. The International Monetary Fund expects Nigerian oil production to gorw to 2.46mn b/d by 2015.
US Atlantic coast refiners, which have struggled more to access new North American production, were the only reliable importers of Nigerian crude this year. Imports to the region averaged 65,400 b/d in the first seven months of the year, compared to 158,452 b/d in the same period of 2009.
Overall US crude imports rose by roughly 568,000 b/d to 7.622mn b/d in July on an increase in imports to the US Gulf and US west coasts.
Copyright © 2014 Argus Media Ltd - www.ArgusMedia.com - All rights reserved.
29 Sep 2014, 9.35 pm GMT
Houston, 29 September (Argus) — Mexico´s government is working to consolidate 169 onshore and offshore blocks that it plans to offer in its historic upstream bidding round in November.
"We will know about the consolidation as we announce the terms and conditions for each of the areas. We are working on this," deputy oil minister Lourdes Melgar told Argus at the end of an oil conference in Cancun on 26 September.
"We have petroleum engineering firms looking at the different blocks and helping the CNH to define what makes the most sense," Melgar said, referring to Mexico´s upstream regulator, the National Hydrocarbons Commission.
Senior oil executives attending the conference said the blocks, particularly in the deepwater Gulf of Mexico, would be more attractive if they were larger and contiguous.
"It´s not necessarily that we want more acreage. It´s just that if we find 200mn bl, it might not be enough to develop in a remote area," one executive said.
But the government has heard different perspectives on the topic, Melgar said. "We have noticed, depending on the type of company, you get an argument for and against the size of the blocks," she said.
Melgar added that 2-D and 3-D seismic studies have been conducted on most of the Mexican blocks. And at least one exploration well has been drilled on many of them, so the acreage is generally not considered frontier.
The first stage of the tender will feature a package of shallow water blocks. Subsequent packages, to be released monthly, will cover extra-heavy, Chicontepec and unconventional, onshore and deepwater blocks located in the Perdido Fold Belt near the border with the US and southern areas of the Gulf of Mexico.
Awards for deepwater blocks, the most coveted acreage for big oil companies looking for a step change in their reserves, will be issued in September 2015.
Copyright © 2014 Argus Media Ltd - www.ArgusMedia.com - All rights reserved.
The fragile ceasefire and negotiations between Ukraine and Russia have revived hopes that the months-long violent conflict in Eastern Europe is nearing its end. However, many questions remain unanswered, as hostilities and distrust between the confronted parties continues to plague a potential peaceful solution.
With the Ukrainian conflict unresolved and winter in sight, the EU will not only have the grand task of preparing the continent for the possibility of energy shortages, but also to define its long-term energy goals.
Most East European EU members depend heavily on natural gas supplies from Russia. Despite the last mild winter and efforts to stockpile additional gas reserves, these countries will not be able to survive the winter on their own, should Russia decide to shut off the valves. Currently only Latvia has enough storage capacity to survive the winter without replenishing its reserves.
At the moment, there are no signs that cut-offs will actually occur. Moscow has publicly rejected such a scenario, and recent reports on the reduction in gas supplies to some Eastern European countries are more related to Russia’s efforts to control gas supplies to Ukraine via reverse gas flow, rather than its intention to use gas as a political tool against the West.
Russia has strong financial reasons to be pragmatic when it comes to gas supplies to Europe. Its revenues heavily depend on gas exports to the continent. According to the US Energy Administration, natural gas exports to Europe accounted for $73 billion, or 14 percent of the country’s total export revenues in 2013. Brussels was careful enough not to target Europe’s key gas supplier Gazprom with sanctions for an equally pragmatic reason, despite the fact that heavy sanctions were imposed on other energy giants with close ties to the Kremlin.
However, should the shortages occur, Europe does not have too many cards up its sleeve in the short-term. In spite of the relatively well-developed LNG terminal network, only 20 percent of its capacity is currently in use due to high liquefied natural gas (LNG) market prices and strong Asian demand. Following the Fukushima disaster in 2011, and the shutdown of Japan’s 54 nuclear reactors, most global LNG was redirected towards Asia. It pushed the prices up by 55 percent, and made the LNG option in Europe unattractive, compared with other alternatives such as cheap US coal and Russian gas.
As a consequence, currently there is not enough LNG on the global markets to replace Russian imports. According to energy analysts, any attempt to fully replace Russian gas with LNG in the short-term would force a 127 percent hike in Europe’s natural gas prices.
In the mid and long-term, Europe will continue to make steps to increase its energy security and reduce reliance on Russia. In May, the European Council adopted the new European Energy Security Strategy (EESS,) with a particular emphasis on reshuffling its energy relations with Russia. This will not only include natural gas, but also nuclear fuel and oil imports, as well as building additional infrastructure to ease Eastern European energy dependency.
The biggest and most demanding task will however remain to define and develop a reliable pipeline system that will diversify natural gas sources. In this context, following the Russian incursion into Ukraine, the Gazprom-backed South Stream project has a small chance of becoming operational.
Interested countries, such as Bulgaria and Serbia, were put under strong EU and US pressure to halt any activities related to the project, and the European Parliament recently adopted a resolution urging the EU “to regulate third-party businesses in the areas of gas storage, interconnectors and flow-back facilities, and urge the EU countries to cancel planned energy sector agreements with Russia, including the South Stream gas pipeline.”
The most likely alternative will be the development of the Southern Corridor Pipeline System. This project involves the construction of the TANAP-TAP pipeline from Azerbaijan and Turkmenistan through Turkey, Greece, Albania and Italy, with extensions towards France, Spain, and the Eastern Europe.
Although the Southern Corridor will not solve the problem of the European energy dependency on Russia completely, the realisation of this project, along with the likely kill-off of the South Stream and the provisions of the EESS, will inevitably be seen by Kremlin as a major blow to Russia’s efforts to strengthen energy influence over the continent.
In the light of new geopolitical realities following the Ukrainian conflict, such a situation can create new instabilities and conflicts between the West and Russia, not only in Europe, but also in Caucasus and Central Asia, an area which Moscow, similarly to Ukraine, traditionally regards as part of its sphere of influence.
By Dr. Ante Batovic
Last week, the largest U.S. energy company, ExxonMobil, bowed to Western sanctions against Russia and withdrew from a joint venture with the Kremlin-owned oil giant Rosneft in the Russian Arctic, but not before it discovered what may be a vast amount of oil.
Rosneft CEO Igor Sechin said Sept. 27 that the finding shows the Arctic Ocean’s Kara Sea north of Russia could become one of the world’s richest sources of crude oil. Before Exxon was forced to withdraw, he said a well containing around 1 billion barrels of oil was found. He added that neighboring geological formations may contain more oil than in the U.S.-controlled area of the Gulf of Mexico.
Sechin told Bloomberg News that the discovery “exceeded our expectations.” He said the well could begin production in as soon as five years, and that the field, now called Universitetskaya, would be renamed Pobeda, or “Victory” in Russian.
Exxon’s reaction was more measured. “We have encountered hydrocarbons, but it is premature to speculate on any potential outcome,” Alan Jeffers, an Exxon spokesman, told The Wall Street Journal.
The European Union and United States have imposed economic sanctions on Russia for what they see as Moscow’s aggressive involvement in the affairs of neighboring Ukraine, unilaterally annexing the Crimean peninsula in March and reportedly providing support in personnel and equipment to Ukraine’s pro-Russian separatists.
The sanctions forbid Western banks to provide long-term financing to Russian oil companies and bar the sale of Western technology to Russian firms. As a result, Rosneft and Exxon can conduct no further drilling, leaving development of the Kara Sea field in limbo.
The Arctic is one of the last regions to be exploited for energy, even though it’s estimated to hold among the largest deposits of gas and oil. In 2011, Exxon and Rosneft agreed to work together to explore a sector of the Russian Arctic larger than Texas at a cost of more than $3.2 billion, most of it to be paid by Exxon.
The first joint drilling project was the Universitetskaya well. But regardless of the amount of oil that may or may not have been found there, and regardless of the Western sanctions, neither Rosneft nor Exxon will feel the brunt of the field lying fallow. Under the best of circumstances, it would be years before the two companies could begin extracting useful quantities of oil or gas.
Still, the well has long-term importance for both companies. Exxon needs new sources of oil to make up for the vast amounts it’s already pumped from older wells, which are now becoming depleted.
As for Russia, developing access to the potentially huge energy resources of the Arctic would only strengthen its strategy to increase domestic oil and gas production, the key to its economy and its international influence.
By Andy Tully of Oilprice.com
Saudi Arabia has proven oil reserves of 266 billion barrels and a current estimated spare production capacity of 2.7 million barrels a day.
With uncertainties about the global oil market outlook stemming from the strength of the global recovery, the path of US oil production and the extent of supply outages in other countries, the importance of this role need not be overemphasized.
The current period of low oil prices clearly serves as a reminder of the temporary nature of the hydrocarbons wealth of the GCC economies.
They underscore the need to tackle the long-term structural decisions that must be made to lay the foundation for sustainable growth on the basis of a diverse economic structure.
Brent crude was stuck below $97 a barrel having hit its lowest in 26 months recently. It is, however, important to bear in mind that the volatility in oil prices is nothing new.
Some of it right now is likely to be purely seasonal in nature. Moreover, whatever the challenges of the market today, the world still needs oil in growing quantities.
And the marginal cost of extracting it is going up in a way that is likely to make any price correction temporary in nature.
Saudi Arabia’s economy has grown very strongly in recent years, benefiting from high oil prices and output.
Nonetheless, it is clear that the long period of high oil prices has fueled government spending growth and created expectations, which must begin to be tackled.
Even if oil prices rebound, there is a need to begin to restructure government spending and reduce the dependency on the government-led growth paradigm. In that sense, a price correction may serve as a welcome reminder of the need to tackle these issues.
Saudi Arabia’s economy is heavily dependent on oil, which accounts for around 90 percent of fiscal revenues and 80 percent of current account revenues.
Although large and growing buffers are strong at present, providing macroeconomic policies with scope to respond to shocks, they can temper the impact of swings in oil revenues. This could ultimately lead to creating a more diversified economy posing a likely challenge despite the Kingdom’s vast oil resources.
According to the International Monetary Fund, the Saudi government is making considerable efforts to lay the groundwork for further diversification by upgrading infrastructure, strengthening education and skills, boosting access to finance for SMEs, and improving the business environment.
Even granting all this is true, the resultant challenges and the manner in which they could be overcome will need to be analyzed in their entirety.
Email: khalil@arabnews.com
© Copyright of Arab News 2014
By Nick Cunningham | Mon, 29 September 2014 20:18 | 0
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To the delight of American drivers, gasoline prices are continuing to slide downwards. The national average price of gasoline hit $3.35 per gallon at the end of September, which is about 14 cents lower than at the same time a year ago, according to the U.S. Energy Information Administration (EIA).
In recent years it has become commonplace for many drivers to see a gallon sell for well over $4 per gallon. Why have gas prices dropped to such low levels all of a sudden?
There are a complex set of factors that determine the price at the pump, but the largest contributor is the global price of crude oil. Oil prices have plummeted by more than 17 percent since peaking in June of this year, when the Islamic State, also known as ISIL, overran much of Iraq and sparked fears of major disruptions in oil supplies. But with the advance of the Sunni jihadist group slowed, if not contained, concerns over oil eased and prices pulled back from their highs.
And there were also positive contributions to global oil supply. For example, after violence that kept most of its oil production offline for over a year, Libya’s oil fields have suddenly roared back to life. Although exact data is murky, and instability could yet plunge Libya’s oil sector back into a state of despair, Libyan officials are reporting that the country is now pumping around 900,000 barrels per day (bpd).
Of course, the largest supply shock comes from the United States, which continues to reach record levels of production. The U.S. is now producing over 8.8 million (bpd), the highest rate since the mid-1980’s. The EIA projects that the upward trajectory will continue, with output reaching 9.5 million bpd in 2015.
Then there are demand issues. Europe and China are reporting disappointing economic figures, suggesting their economies are slowing down. In August, China’s industrial growth slowed to its lowest level since the financial crisis in 2008. A sluggish economy results in less oil being consumed.
The U.S. economy has fared better. In fact, the U.S. is coming off of its strongest quarter in over two-and-a-half years. Even still, the U.S. consumes around 19 million bpd of petroleum products, which, while highest in the world, has essentially been flat since 2008.
That is largely due to increased efficiency in the nation’s auto fleet. New cars sold in the U.S. average about 36 miles per gallon, compared to the 31.5 miles per gallon new cars achieved in 2008. Federal standards on fuel efficiency will continue to ratchet up efficiency over the next decade, setting up the possibility for a decline in fuel demand even while the overall economy continues to grow.
Taken together, the supply and demand pictures support lower oil prices, which trickle down to the price at the pump.
So what can we expect from gasoline prices in the coming months? Futures prices for Brent – the international benchmark for crude oil – are not much different than today’s prices, indicating that the markets do not expect a substantial change in prices for the months ahead.
OPEC has flirted with the idea of cutting back on oil production in order to boost prices. Iran, whose economy is largely dependent on oil exports, is growing concerned about the situation. “Considering the downward trend in prices, OPEC members should try to temper production to avoid further price instability,” Iran’s oil minister, Bijan Zanganeh, said on a government website.
But OPEC has not yet made a decision, and in any case, a cutback would not occur until next year at the earliest.
Iran is also negotiating with Europe and the United States over its nuclear program. While progress has stalled, if the West and Iran can reach a deal before the November deadline, it could lead to a thaw in relations. Consequently, Iran could see some of its oil exports return to the global market. Iran has seen its exports more than halve since 2012, and the prospect of a return of more than 1 million bpd to the market would send oil prices even lower. Still, the chances of such a sweeping deal are considered slim.
Nevertheless, autumn months bring a more predictable change to the fuel supply. That is when refiners switch from their summer to winter blends of gasoline, which tend to be cheaper. Also, people tend to drive less as summer vacations end. As a result, gasoline prices tend to fall beginning in September.
With supplies continuing to rise and demand flat, lower gasoline prices could stick around for a while.
By Nick Cunningham of Oilprice.com
(Reuters) - South Korea's GS Caltex Corp will receive 800,000 barrels of Alaskan crude oil on October 10 after the country's second biggest refiner bought it on the spot market at competitive prices, a company source said on Tuesday.
Yet the source who declined to be identified due to the sensitivity of the matter did not elaborate on the price. A GS Caltex spokesman declined comment.
Shipping data showed on Monday that the first U.S. export of Alaskan crude to South Korea in over a decade set sail this weekend, marking another milestone as booming shale oil output forces domestic producers to seek new customers. (Reporting by Meeyoung Cho; Editing by Michael Perry)
Total to decide French refinery plan by next spring - sources
* GS Caltex finds US condensate is satisfactory -sources
* Other Korean refiners are considering US condensate
* Also tapping oil suppliers in Africa, Europe and Russia
By Meeyoung Cho
SEOUL, Sept 29 (Reuters) - South Korean refiners faced with weak margins want to cut costs by diversifying away from their traditional crude suppliers in the Middle East, and U.S. condensate could be an attractive option now that a long-standing U.S. export ban has been eased.
South Korea has the fourth-largest refining capacity in Asia Pacific at 2.9 million barrels per day (bpd) but crude operating rates have been cut this year to cap refining losses, while secondary units that use much cheaper fuel have produced more.
Earlier this month the country's second-largest refiner, GS Caltex Corp, received the first cargo of ultra-light oil, or condensate, from the United States since the softening of the ban. Top refiner SK Energy Co Ltd is also expecting U.S. condensate soon.
A source at GS Caltex and other refining industry sources told Reuters GS Caltex had found U.S. condensate had a satisfactory yield of light oil products.
"We are processing it now ... Using U.S. condensate is expected to stabilise overall costs at lower levels," a source at GS Caltex said, declining to be identified. "We will continue to consider it if the economics remain attractive."
A spokesman at GS Caltex, a joint venture between GS Holdings and Chevron Corp, declined comment.
Seoul imported 612.5 million barrels of crude in the first eight months of this year, up just 0.2 percent from a year earlier, data from state-run Korean National Oil Corp showed.
Imports from the Middle East accounted for 84 percent of the total at 513.8 million barrels, down 0.8 percent from the same period last year. European cargoes rose 11 percent to 20.6 million barrels and shipments from Africa more than quadrupled to 16.2 million barrels.
Washington is facing growing pressure to ease its ban on crude oil exports, with South Korea and Mexico joining the European Union in pressing the case, but it has held back from issuing more export licences while the issue is debated by domestic producers and consumers.
A spokeswoman at SK Innovation Co Ltd, which owns SK Energy, said the company wanted to diversify crude because of the difficult business climate.
"Our African oil imports have been greatly buoyed by our diversification efforts. We are also raising European oil imports," she said. "Canadian oil is too heavy to refine at our units, leaving the United States as the only option in North America.
She said SK Energy's Middle Eastern crude imports had fallen to a record low of just above 70 percent of the total this year, compared with around 85 percent for South Korea traditionally.
S-Oil Corp, the third biggest of South Korea's four refiners, whose main shareholder is Saudi Aramco, imports almost all of its crude from Saudi Arabia.
Another Seoul-based refining source said: "We'll definitely consider U.S. condensate imports if tendered, as we expect prices to come under pressure if cargoes flood the market."
"Local refiners are looking everywhere, from Africa to North and Latin America, where they haven't imported much oil from, in order to diversify," he said. "Local companies are even looking as far as Russia."
South Korea imposes no import tariffs on oil from the United States, Canada and Europe because of free trade agreements. (Reporting by Meeyoung Cho; Editing by Alan Raybould)
LONDON, 2 days ago
Iran has urged Opec members to make joint efforts to keep oil prices from falling further, highlighting a split with other members such as Saudi Arabia who face lower budget pressures despite a slide in prices towards $95 a barrel.
Oil has fallen from $115 in June, pressured by concern about slowing global demand and higher supplies as Libyan output recovers, raising concern among some oil exporters of lower revenues.
"Considering the downward trend in prices, Opec members should try to temper production to avoid further price instability", Iran's oil minister, Bijan Zanganeh, was quoted by the Iranian oil ministry website Shana as saying on Friday.
Iran has among the highest oil-price needs within the 12-member Organization of the Petroleum Exporting Countries and often supports measures likely to boost prices. Saudi Arabia and other Gulf Opec producers have lower pain thresholds.
But Opec's Gulf Arab producers, so far, remain unruffled. Saudi Arabia's oil minister, in New York this week, appeared to downplay the price drop, while delegates have stopped short of calling for price-supporting action.
"I am still relaxed," said a delegate from one of Opec's Gulf members this week, referring to the oil market situation.
Besides lower-than-expected demand, a key factor behind the drop in prices has been a recovery in Libyan output to around 925,000 barrels per day (bpd) now from just 200,000 bpd in June.
Other Opec members, mainly Saudi Arabia, had informally pumped more to make up for lower Libyan output and other outages and Opec sources have said they could pare back the extra supply if needed to support prices.
Saudi Arabia, the world's top exporter, cut its output by around 400,000 barrels per day in August. But the amount of crude supplied to the market - both domestically and for export - was 9.688 million bpd, compared to around 9.66 million bpd in July, indicating no change in Saudi oil supply.
Industry sources in Saudi Arabia have said the prospect of any significant change in output this year is unlikely.
"As we approach winter and with the end of the refinery maintenance season, global demand is likely to pick up therefore Saudi oil production is not expected to see a major change," an industry source said on Thursday.
Still, Opec's next meeting, on Nov. 27, will likely see a debate on whether its output target of 30 million bpd is appropriate for 2015, given that Opec and other forecasters expect a further drop in global demand for Opec crude.
The Opec secretary general said last week he expected Opec production to be around 29.50 million bpd in 2015, not 30 million bpd. But the United Arab Emirates, a core Gulf Opec producer, said it was too early to predict a cut in the Opec target.
"There may be different levels of concern, but what they are all saying is we'll look closely at the market in November," said an Opec source.-Reuters
CAIRO, 19 hours, 10 minutes ago
Egypt plans to invest $14.5 billion in developing its refining and petrochemicals sectors over the next five years, its oil minister said, as part of efforts to overcome an energy crisis that has led to near-daily power cuts and hit company profits.
It is also considering floating stakes in some state-owned oil companies on the Egyptian stock exchange.
Sherif Ismail told Reuters in an interview that Egypt was trying to boost its output of refined oil products by 5-10 per cent each year, hoping to reduce its dependence on costly imports.
"Total investments that will be implemented over the next five years will be around $14.5 billion and include $12.5 billion in the refining sector and $1.9 billion in the ETHYDCO project," Ismail said, referring to a new complex that will produce ethylene and other petrochemicals.
Egypt has struggled to curb its swelling budget deficit whilst meeting soaring energy demands, resulting in daily electricity cuts around the country of 86 million people.
Lines at petrol stations and a shortage of gas that transformed Egypt from net gas exporter to net importer in recent years at huge cost to the state, were among the public grievances against former President Mohamed Mursi of the Muslim Brotherhood.
Oil-producing Gulf countries have come to Egypt's aid since the army, prompted by mass protests, ousted Mursi last year, pumping billions of dollars in cash and oil products into the biggest Arab nation.
The government also took the politically sensitive step of introducing deep cuts to energy subsidies in July, which should help curb the deficit but have resulted in price rises of up to 78 per cent on fuel and electricity.
Ismail said Egypt was hoping to produce 5.4 billion cubic feet per day of gas and 695,000 barrels per day (bpd) of oil and condensates in the current 2014-15 financial year, and to import about 6.5 million tonnes of gas and petroleum products annually.
Most of the planned investments will be implemented by state-owned companies and be self-financed or part-financed by local banks, he said.
The oil ministry was also working with local investment banks to look at the potential for offering stakes in state oil companies on the Egyptian stock exchange as part of an effort to overhaul them and improve their finances, Ismail said.
He declined to give the names of the companies or of the banks involved but said the ministry could begin with about five companies, with the first being listed in 2015.
PETROCHEMICALS AND REFINING PUSH
Among the largest projects in progress is ETHYDCO, which is set to produce 460,000 tonnes a year of ethylene and 400,000 tonnes of polyethylene when it comes online at the end of 2015.
The complex in Alexandria on the Mediterranean coast will be the largest producer of ethylene and polyethylene in Egypt and will save the country more than $500 million a year that it currently spends on imports, Ismail said.
Ethylene and polyethylene are used in the production of plastics and chemicals.
Egypt is also expanding the Midor refinery, boosting its capacity from 100,000 bpd to 160,000 bpd with the additional output expected to come online at the end of 2017, Ismail said.
The minister predicted that Egypt's diesel output would increase by 4.5 million tonnes a year once the Midor expansion and an upgrade at the Egyptian Refining Company were complete, covering the country's domestic diesel needs.
Egypt currently produces about 8 million tonnes of diesel a year. It consumes 500,000 tonnes of diesel a month, 300,000 tonnes of LPG, 150,000 tonnes of gasoline and 500,000 tonnes of fuel oil, according to official figures
"The Midor expansion will contribute to providing 20,000 tonnes of gasoline a year and 1.8 million tonnes of diesel in addition to liquefied petroleum gas and jet fuel," Ismail said.
Egypt has other projects under way aimed at boosting gasoline production, he added.
It is building a plant in Alexandria to produce 500,000 tonnes of gasoline a year at a cost of $220 million. It is also adding a unit at the Assiut plant that will produce 400,000 tonnes of gasoline a year and cost about $258 million, helping to supply Upper Egypt in the south.
Egypt is also building a new oil complex in Suez that will replace an existing and ageing plant at a cost of $430 million to begin operating in the second quarter of 2018, Ismail said.
EXPLORATION AND DISCOVERY
The country needs to boost its oil and gas output to meet growing demand but exploration companies have been hesitant to develop untapped gas finds in Egyptian waters partly because the amount the government pays them hardly covers their investment costs.
Egypt has also fallen behind on payments to foreign oil and gas companies, further discouraging them from making the billions of dollars in investments required to tap some of the larger offshore finds or to explore in deep water.
Egypt's oil and gas production from maturing fields in the Nile Delta and Gulf of Suez has declined since the mid-1990s though smaller discoveries have helped to compensate.
Ismail said that investments in exploration and discovery reached $8.2 billion last year and should exceed $8.3 billion in the current year.
"There are developments in the pipeline networks ... There are projects to produce gas in the future period such as the third phase of Desouk and 9B at the start of 2016 and 9A West Delta deepwater with BG," he said, naming other projects in Port Said and the western desert that are due to come onstream.
"The cornerstone of the petroleum sector is exploration and discovery." - Reuters
SHARJAH, 19 hours, 29 minutes ago
Dana Gas Egypt, a subsidiary of UAE-based Dana Gas, a top private sector natural gas company, has been awarded two onshore concessions in the Nile Delta as part of the 2014 EGAS bidding round held recently in Egypt.
The concessions include the North El Salhiya (Block 1) and El Matariya (Block 3), a company statement said.
Dana Gas Egypt will operate the Block 1 Concession Area on a 100 per cent basis. It is expected that exploration success and future production from conventional gas reservoirs in the Block, utilising Dana Gas Egypt's existing infrastructure.
Dana Gas Egypt will participate in the Block 3 Concession Area on a 50 per cent basis with BP as partner and operator. Under the terms of the agreement, BP will fund all of the cost (including Dana Gas’s share) of one exploration well up to an agreed maximum limit. In the event that the well proves commercial, BP has the option to back into 50 per cent of the deep potential of Dana Gas’ adjacent Development Leases.
BP also has the option to back into 50 per cent of the deep potential of Dana Gas Egypt’s other Development Leases and Block 1 Concession Area by drilling and funding all of the costs of a second exploration well in either the Development Leases or Block 1 up to an agreed maximum limit.
Dr Patrick Allman-Ward, CEO, Dana Gas, said: “We are extremely pleased to have been awarded these two new blocks. The area is particularly well known to Dana Gas, given its long-term commitment to the Nile Delta.”
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The two blocks are located adjacent to the Company’s existing Development Leases. Together with BP, the Company will look to explore the multi-TCF gas potential of the Oligocene reservoirs that have proven successful to date in the offshore and which extend into Dana Gas Egypt's existing Development Licenses.
The first Oligocene exploration well is scheduled to be drilled in 2016. In case of exploration success, an early development system is envisaged to allow rapid production of the wells located close to the existing El Wastani plant.
The two blocks have a six-year exploration period, comprised of two phases of three years each. A 20-year development lease period will be granted to each block, based on approved commercial discovery.
The two concessions, which cover 1,527 sq km and 960 sq km respectively, were awarded as part of the EGAS international bid round in August. Ratification of the two new concessions is expected to take place following the completion of the necessary approvals. – TradeArabia News Service
PARIS, 17 hours, 22 minutes ago
French oil company Total has been awarded a licence to explore for natural gas in the Nile Delta, a source in the state-run Egyptian Natural Gas Holding company (Egas) said on Monday.
"France's Total won the bid to explore in Sector 2 in the Delta region," the source told Reuters on condition of anonymity.
The Egyptian General Petroleum Corporation (EGPC) and Egas announced an international tender for oil and gas drilling concessions last December.-Reuters
BENGHAZI, 13 hours, 11 minutes ago
Libya's oil output has fallen by 25,000 barrels per day (bpd) to 900,000 bpd because of a strike at its Jalo oilfield, a spokesman for state-run National Oil Corp (NOC) said.
Output is still nine times more than several months ago when nationwide strikes crippled the industry. Libya reported it was producing 925,000 a day. -- Reuters
