Chinese oil major Unipec has provisionally hired an ultra large crude Carrier possibly to store crude around Singapore, market participants said Thursday.
The 442,000-dwt and 2002 built, TI Europe, has been taken on a six-month time charter by Unipec at a daily rate of $25,600, brokers, shipowners and charterers said. There is an option to extend the time charter period by another six months at $28,600/day, they said.
The TI Europe was earlier used for floating storage of fuel oil by Litasco and St Shipping, which is trading house Glencore’s shipping arm, according to the sources. “There is a contango in the [Brent] market, so putting two plus two together, it has to be for crude storage,” said a source with a VLCC owner.
Sources at Unipec declined to comment. There is an open contango in oil markets that has made storage a profitable option and can potentially tighten the supply of super tankers in the spot market, Norwegian bank DNB said in a recent report.
The contango developed last month mainly due to surplus crude in the Atlantic basin because of weak demand in Europe and the US, continuing growth in US shale crude output, and the return of exports from Libya. “The spread between the front-month and three-month forward Brent crude is $12/mt. This implies $25,390 of potential daily profit from storage,” the report had said adding the contango would have to fall 96 cents/barrel to close the spread.
The spread has now shrunk below $8/mt, according to the latest market data, making some market participants skeptical of the viability of taking VLCCs for floating storage. “If I was them [Unipec] I would put West African crude [as] it has got the highest returns right now,” a trader of Middle Eastern sour crudes said.
Qua Iboe, Nigeria’s flagship grade was assessed at Dated Brent plus $1.10/b on Tuesday, higher than five-year low of 65 cents/b at the end of July, but well below the $2.27/b premium the grade was assessed at on average for the first six months of this year.
West African crudes have come under intense pressure from a combination of lower demand from the US as domestic crude production has risen and the return of Libyan light sweet crude exports.
“Unipec may trade one [crude] shipment from Rotterdam to Europe and then store it to wait for a good oil price,” said a VLCC broker in China.
“We are looking for opportunities to give our ships for floating storage if inquires come by,” said a source with a VLCC owner in Singapore.
Nevertheless, if demand for such floating storage picks up, it will potentially push up the spot market rates of VLCCs, which in turn will support the time charter rates, making such future storage less attractive, the same source said.
Norway’s Statoil said Thursday it is buying stakes in two licenses
Statoil will buy a 10% stake in the Tayrona license operated by Petrobras and a 20% stake in the Guajira Offshore 1 license operated by Repsol. The company was awarded a stake in a third Colombian license with Repsol and ExxonMobil in July. The Tayrona license includes the Orca-1 exploration well, which Petrobras is currently drilling.
Statoil, Petrobras and Repsol are partners in several Brazilian licenses and participated in the Pao de Acucar discovery in Brazil’s Campos basin in 2012, estimated at 700 million barrels of oil.
“Statoil is well positioned in deep-water offshore Colombia. We are gaining access to a vast underexplored frontier area through early access at scale, which is in line with Statoil’s exploration strategy,” Statoil’s senior vice president for western hemisphere exploration, Nick Maden, said.
The license acquisitions are subject to approval by Colombia’s hydrocarbons agency.operator Nexen said Thursday. “Buzzard production will ramp up over the next week, as planned,” a Nexen spokeswoman said in a statement. Buzzard was taken offline on August 30, just days after having been recommissioned following a prolonged maintenance period from the end of July at the field, the largest contributor to Forties Blend crude oil.
As a result of Buzzard’s stop-start return from maintenance, Forties cargo F0916, due to load September 26-28, has been dropped from the loading program. Nexen’s announcement Thursday has partially relieved uncertainty in the market this week.
“The change is that production is going up and has started, which was unclear yesterday,” one crude oil trader said. “[But] I’m not sure what the ramp-up profile looks like.”
Buzzard accounted for 9% of Forties Blend in the week finishing August 31, having not featured at all in the other three full weeks in August. If last week’s content is maintained, then the API for Forties is approximately 42.1 degrees and the sulfur content is 0.42%, according to data published by BP.
From Friday, the last day before Buzzard went offline, to Monday the Forties differential jumped $0.22/b to minus $0.23/b to forward Dated Brent. Forties is one of the four grades underpinning the Dated Brent benchmark. After news that Buzzard had been taken offline on Saturday filtered around the North Sea market, Forties shifted into backwardation on uncertainty over near-term availability. Buzzard has a nameplate capacity of 220,000 b/d.
Iraq’s oil ministry plans to file legal proceedings in the coming days against a Greek shipping firm for its role in the export of crude oil by the semiautonomous Kurdistan Regional Government, to the tune of more than $318 million.
In a statement late Thursday, the ministry said it will submit its filing at the Court of Piraeus in Greece against Marine Management Services for its role in the management of several oil tankers involved in what the ministry considers the illegal export of Iraqi crude. According to the statement, MMS operates five vessels — the United Leadership, United Emblem, United Kalavrvta, United Carrier and United Dynamic — which have been involved in transporting crude on behalf of the KRG.
“MMS has actively facilitated the KRG’s illegal export scheme, repeatedly ignoring warnings that the crude oil it was carrying does not belong to the KRG,” the statement said. The oil ministry also accuses the company of declaring false destinations, switching off the ships’ Automatic Identification System transponders and undertaking nighttime ship-to-ship transfers of crude oil on the high seas, all to avoid detection. MMS did not immediately return a call seeking comment Thursday.
The lawsuit is the latest attempt by the Iraqi central government, which said it will take legal action against any entity that buys crude produced in the Iraqi Kurdistan region. It is to submit a revised claim against the sale of a 1 million-barrel cargo of Kurdish crude currently off the coast of Texas after a US judge rejected its claim to the cargo, which sits on board the United Kalavrvta.
The MMS-managed vessel has been in legal limbo in international waters offshore Galveston for nearly a month. No buyer of the cargo has stepped forward. It is the latest to load from the Turkish port of Ceyhan since May, in defiance of Baghdad’s claim that it, solely, has the right to sell oil produced within its borders. The KRG has maintained its right to sell crude produced on its land and has stepped up efforts to export and sell Kurdish crude to the international market since early June.
Russian oil giant Rosneft said Thursday it has launched commercial production at its North Chayvo field, offshore the Far East island of Sakhalin.
Rosneft started exploration drilling at the field in May and the launch is in line with timeframes given previously by company officials. Rosneft CEO Igor Sechin said during the launch ceremony that the field is expected to reach peak production of 1.5 million mt/year (30,000 b/d) of crude, according to a company statement.
Previous company estimates of peak production at the field ranged from 1.25 million mt/year to 1.6 million mt/ year by 2017. Sechin added that North Chayvo holds reserves of over 15 million mt of crude and around 13 billion cubic meters of gas during the ceremony Thursday. Peak gas production at the field is expected in 2027.
Rosneft is planning to utilize infrastructure at the nearby Sakhalin 1 project to support development of North Chayvo, which is an extension of the Chayvo field included in Sakhalin 1. Sakhalin 1, which also includes the Odoptu and Arkutun-Dagi fields is led by ExxonMobil, which controls a 30% stake. Rosneft holds 20% in the project, with Japanese consortium Sodeco controlling 30%, and India’s ONGC the remaining 20%.
ExxonMobil initially tried to include the newly discovered oil reserves in the Sakhalin 1 license area on the basis that they are an extension of the Sakhalin 1 fields. But in 2006 the Russian authorities ruled out the possibility of an automatic expansion of the license area if new hydrocarbon reserves were found at Chayvo and Odoptu.
In 2011, Rosneft won a tender for North Chayvo and is financing and developing the project independently. Russia’s Far East is a strategic priority for Rosneft. The company plans to launch a number of upstream projects in the region, as well as a 5 million mt/year LNG plant — which it expects to build in partnership with US giant ExxonMobil — and the 30 million mt/year FEPCO petrochemical and oil refining facility.
By Pietro D. Pitts Sep 4, 2014 11:13 PM GMT+0700
The removal of President Nicolas Maduro’s main policy maker improves Venezuela’s chances of tapping more of the world’s largest crude reserves, according to Barclays Plc and Medley Global Advisors LLC.
While Rafael Ramirez’s exit from the posts of vice president for economy and energy minister dims hopes for economic reform, it may give his successor at Petroleos de Venezuela SA the opportunity to focus more on the job of pumping oil. Besides running PDVSA, Ramirez oversaw the exchange system and housing programs among other non-oil duties.
His deputy on the PDVSA board, Eulogio Del Pino, will take over as part of a series of government changes unveiled by Maduro on Sept. 2. With a master’s degree in exploration from Stanford University, Del Pino oversaw the company’s operations and coordinated agreements with international oil firms as head of Corporacion Venezolana del Petroleo, or CVP.
“The appointment of Del Pino to PDVSA is marginally positive,” Barclays analysts Alejandro Arreaza, Alejandro Grisanti and Donato Guarino wrote in an e-mailed note yesterday. “This increases the chances of increasing production.”
Active army general Rodolfo Marco Torres replaced Ramirez as the economy vice president, with Asdrubal Chavez, the cousin of the late leader Hugo, named oil minister.
Chavez’s appointment is neutral, according to Barclays. “We doubt Chavez could hinder any plan Del Pino might have.”
Political Clout
Even so, PDVSA’s capacity to invest may be constrained by Del Pino’s lesser political clout, they wrote. Venezuelan bonds tumbled in the past two days as the overhaul brings into question the status of a proposed lowering of fuel price subsidies and PDVSA’s planned sale of U.S. refineries.
While Del Pino’s appointment is positive for industry, “political constraints and PDVSA’s strained finances will likely limit any potential upside,” Eurasia Group analyst Risa Grais-Targow said in an e-mail. “In a context where Maduro is hesitant to make any significant policy shifts, it would likely be challenging to implement a coherent oil policy.”
Venezuela’s oil production peaked under Ramirez’s tenure as president of PDVSA in 2008 at 3.2 million barrels a day, never approaching his goal of 5.8 million by 2012.
PDVSA, based in Caracas, plans to invest $302 billion through 2019 in partnership with local and international oil companies to reach 6 million barrels a day from about 2.9 million in 2013, according to its annual report. The company also wants to increase gas and condensate output, build six new oil upgraders and increase domestic refining capacity.
Less Risk
Del Pino graduated from Venezuela’s Central University, or UCV, in 1979, obtained a master’s from Stanford in 1985 and has worked in the upstream oil business for more than three decades.
“The replacement choice of Del Pino is the best possible outcome in a negative policy environment,” Luisa Palacios, managing director and head of Latin America research at Medley, said by telephone from New York. “The person that knows the most about production at PDVSA is now the head of PDVSA. That should mean that the downside risk to production has declined.”
His appointment comes at a time when the government of Maduro, Chavez’s handpicked replacement, faces a dwindling supply of dollars that has left shortages of everything from birth control pills to baby food, as well as the world’s highest inflation rate.
Maduro is considering divesting PDVSA’s U.S.-based refining and marketing subsidiary, Citgo Petroleum Corp. and raising the price of gasoline for the first time in 18 years, among other initiatives to shore up a cash shortage.
Refinery Spending
The oil industry is in need of foreign capital and know-how to assist PDVSA lift stagnant production at mature fields in the Lake Maracaibo region as well as in the Orinoco Heavy Oil Belt. The company bought its first cargo of light-sweet Algerian grade crude to dilute heavy Orinoco crude for sale to refineries, four people with knowledge of the matter said this week. A lack of investment and maintenance reduced its ability to produce diluents in Venezuela.
PDVSA signed a financing agreement with an unnamed international lender for about half of a project valued at $3 billion to expand the Puerto La Cruz refinery in eastern Venezuela, it said yesterday.
The company is increasing the refinery’s capacity to 180,000 barrels a day of heavy crude oil to cover national and export demand for products including gasoline, jet fuel and diesel, the company said in an e-mailed statement.
“Del Pino has a clearer understanding than most regarding the urgent need to boost production and, most importantly, he knows how to do it,” David Voght, managing director of IPD Latin America consultancy, said in an e-mailed response to questions. “One of his biggest challenges will be to now prove himself in the political arena.”
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 Philip Sanders
Company sees production growing across the board.
Marathon says shale offering returns in spades. UPI/Gary C. Caskey
NEW YORK, Sept. 4 (UPI) -- Marathon Oil Corp. said it was focusing its strategies on U.S. shale basins after achieving a 20 percent increase in reserves since the end of 2013.
The company said its unconventional 2P reserves, or proven plus probable, in Oklahoma, North Dakota and Texas increased 20 percent compared with year-end 2013 to 3 billion barrels of oil equivalent.
"Associated with the resource growth, Marathon Oil's well inventory for future drilling opportunities has increased to more than 4,600 net well locations across the Eagle Ford, Bakken and the Oklahoma resource basins," Chief Executive Officer Lee Tillman said Wednesday at an energy conference in New York.
New drilling technologies for shale basins have made the United States one of the largest oil producers in the world. Tillman said his company aims to increase drilling across the so-called SCOOP basin in Oklahoma, the Bakken reserve area in North Dakota and the Eagle Ford shale in Texas to 4,650 wells.
"More resource equals more inventory, which supports more drilling activity in our highest return opportunities," Tillman said. "This increased drilling activity will give us a 'fast start' on 2015 growth as we continue to position for further acceleration."
Summer travel season ends, pushing seasonal demand lower.
WASHINGTON, Sept. 4 (UPI) -- With the Labor Day holiday in the past, the summer driving season is over and U.S. travelers can look forward to lower gasoline prices, AAA said.
The official summer driving season runs from Memorial Day through Labor Day. On Sept. 15, U.S. refiners can switch to a winter blend of gasoline, which is less expensive to produce.
In the days leading up to the refiner deadline, gasoline supplies can get limited, but motor club AAA said prices should continue to drop through the season.
"The big crunch in summer travel is done and most of us can look forward to lower gas prices during the next few months," AAA spokesman Avery Ash said in a statement Wednesday.
AAA says the national average price for gasoline is $3.43. AAA said prices could drop by as much as 20 cents by October and some gasoline retailers could post prices below $3 per gallon.
Gasoline prices are a reflection of oil prices, which typically rise and fall in response to global geopolitical tensions. AAA in past reports said oil prices have shrugged off ongoing conflict in Iraq and Ukraine because actual supply disruptions were limited.
Company among largest lease holders in the region.
Statoil to move drilling rig after coming up dry in Gulf of Mexico prospect. UPI/A.J. Sisco..
HOUSTON, Sept. 4 (UPI) -- Norwegian energy company Statoil said it would reposition a rig in the Gulf of Mexico after coming up dry in the deep water Martin prospect.
Statoil said it completed operations at the Martin well, coming up only with a small discovery the company said had no commercial prospects. Once abandonment operations are completed, the company said it would reposition the Maersk Developer drilling rig to the Persues project in the Gulf of Mexico.
Statoil says it's one of the largest lease holders in the Gulf of Mexico, describing the area as "among the most attractive in the industry." From an office in Houston, the company said it handles about 30,000 barrels of oil equivalent from the Gulf of Mexico, a level it says is on pace for a steady increase.
In July, the company, one of the largest in the world, said it was cutting as many as 1,400 positions in an effort to trim costs. In terms of production, Statoil said it put out about 1.8 billion barrels of oil equivalent during the second quarter, a 9 percent decrease from the same time last year.
The company added it had similar disappointing results from operations off the coast of Angola.
Offshore region considered frontier territory.
STAVANGER, Norway, Sept. 4 (UPI) -- Norwegian energy company Statoil said Thursday it agreed with Spain's Repsol to buy an interest in a license area off the coast of Colombia.
"We are gaining access to a vast underexplored frontier area through early access at scale, which is in line with Statoil's exploration strategy," Nick Maden, a senior vice president for Statoil's exploration activities in the Western Hemisphere, said in a statement.
Statoil in July made its debut in Colombia in a deal with Repsol and the Colombian subsidiary of Exxon Mobil.
Much of the country's oil is focused inland in the foothills of the Andes and in the Amazonian jungle. Colombia holds an estimated 2.4 billion barrels of crude oil reserves, though offshore is considered frontier territory.
While no reserve potential was available, Repsol has already conducted seismic surveys offshore to get a better understanding of the license area.
Company already prepared for "volatility."
MOSCOW, Sept. 4 (UPI) -- Russian media reported Thursday state-owned oil company Rosneft could shed as much as 25 percent of its staff as early as next month.
Rosenft's staff has swelled in recent years, growing at a steady clip after the company paid more than $50 billion last year to take on TNK-BP, a former joint venture between Russian billionaires and British energy company BP.
Russian business daily Kommersant said as many as 1,000 employees could lose their jobs as early as October as part of a cost-saving initiative.
Rosneft is the target of Western economic sanctions imposed in response to Russian policies in eastern Ukraine, where pro-Russian separatists are gaining a foothold. Igor Sechin, its chief executive officer, is also the target of punitive economic measures.
Sechin in August asked the Kremlin to use a national welfare fund to support its growing debt. The company's total production, meanwhile, is down to its lowest level in more than a year.
Rosneft recently secured deals to work alongside Norwegian energy company Statoil. Norway and Russia are the top oil and gas suppliers to the European market, though Statoil said recently sanctions are complicating its relationship with Rosneft.
TEL AVIV, Israel, Sept. 4 (UPI) -- An Israeli company operating the offshore Leviathan natural gas field revealed it signed a letter of intent to send natural gas from the project to Jordan.
Israel's Delek Group signed the letter with the National Electric Power Co. of Jordan.
"The estimate scope of the binding agreement [outlined in the letter] is for the supply of an overall amount of 45 billion cubic meters [1.6 trillion cubic feet] over a period of 15 years," the Israeli company said.
Jordan in the past has struggled to find a reliable source of natural gas in part because of downstream problems in Egypt. In February, Jordanian companies Arab Potash and Jordan Bromine secured a total gross quantity of 66 billion cubic feet of natural gas from the Tamar field, also located off the Israeli coast
Leviathan, with an estimated 18 trillion cubic feet of gas, should go onstream in 2016. Much of the reserves from the offshore field are already designated for exports to regional customers.
Tamar is estimated to hold as much as 10 trillion cubic feet of natural gas.
Delek said the letter is not the same as a formal agreement. Gas prices will be pegged to the price of Brent crude oil.
Thu Sep 4, 2014 11:34am EDT
By Humeyra Pamuk
(Reuters) - Oil output in Iraq's Kirkuk has slumped to 30,000 barrels a day since June, 90 percent down on earlier this year, and a federal pipeline to the Turkish port of Ceyhan may be out of action for over a year due to sabotage, Kirkuk's governor said on Thursday.
Islamic State (IS) fighters have seized swathes of territory in lightning offensives in the arid but oil-rich north of the country, and have repeatedly attacked oil installations.
In February this year Iraqi oil production hit record highs of 2.8 million bpd nationwide, with an estimated 300,000 bpd coming from the northern province of Kirkuk.
"There have been no exports since March and the only production in Kirkuk has been the 30,000 bpd to a small refinery and enough gas to get our electrical grid going since June 8," Najmaldin Karim, Kirkuk's governor told reporters at an industry conference in Istanbul.
"I don't think there will be exports from Kirkuk to the Ceyhan pipeline any time soon. It has been sabotaged continuously and to get it all back would take at least a year or more," he added.
The federal pipeline from Kirkuk to Ceyhan has a capacity of 1.6 million bpd but has for years been operating at around a third of that, and recently even less, a Turkish official said.
Damage to the pipeline is a further blow to the beleaguered authorities in Baghdad, but will not affect the Kurdistan Regional Government (KRG), which began exporting oil in May via its own pipeline, which links to the federal Iraqi pipeline at Turkey's border, and has not been sabotaged.
Kurdistan's oil production is expected to rise to 400,000 bpd in 2014 from 250,000 bpd, according to Tony Hayward, chief executive of Anglo-Turkish Genel Energy, the region's largest producer.
Baghdad has repeatedly expressed its anger at the KRG's agreement to export oil independently through Turkey and has launched a series of legal cases to try to halt its sale.
But the Iraqi authorities have been largely powerless to stop the flow of oil through Ceyhan, which has now exceeded 10 million barrels since May, according to Turkish Energy Minister Taner Yildiz. Some $188 million had been paid into Turkish Halkbank by the Kurdish authoritiesYildiz said on Thursday in the Turkish capital, Ankara.
KURDISH PROTECTION
Iraqi government forces and Kurdish fighters have been struggling to stem the rapid advance of IS militants, and the beheading of two U.S. journalists by the group, formerly known as ISIS, has sparked growing alarm in Western capitals.
The prominent role Kurdish peshmerga fighters have played in combating IS militants has added a further twist to already complex power dynamics in the region, with Kirkuk now protected by an estimated 24,000 peshmerga troops, according to Karim.
"With the peshmerga we feel completely confident, (they) will be in Kirkuk as long as it is necessary," he said, dismissing Iraq's regular troops as a "checkpoint army".
Karim also suggested Kirkuk's oil could be channelled through the KRG pipeline, if both sides agree.
"We Kirkuk citizens, we want the oil production to continue and we can help to bring the two sides (Baghdad and Arbil) together," he said.
During recent fighting, IS has repeatedly tried to seize and hold Baiji Refinery, the largest in Kirkuk.
Damage to the facility, which was producing around 170,000 bpd before it was closed due to the violence, could take more than a year to repair, according to the Kurdistan RegionalGovernment's (KRG) Natural Resources Minister Ashti Hawrami, who was speaking at the same conference.
Around 60 world leaders gathered on Wednesday for the start of the NATO summit in Wales, where the threat posed to Middle Eastern security by IS is expected to be discussed.
Speaking on Wednesday, President Barack Obama said the U.S. would "degrade and destroy" the group. American airstrikes recommenced in Iraq in August for the first time since the pullout of U.S. troops in 2011. (Additional reporting by Ozge Ozbilgin in Ankara; Writing by Jonny Hogg; Editing by Ece Toksabay and David Evans)
DUBAI Thu Sep 4, 2014 4:06pm BST
(Reuters) - Iran's central bank has received a total of $1 billion (608 million pounds) of previously frozen oil revenue from Japan under the terms of an extended nuclear agreement with six world powers, state news agency IRNA reported on Thursday.
Iran and the United States, China, France, Germany, Britain and Russia agreed in July to extend a six-month interim accord until Nov. 24 after they failed to meet a July 20 deadline for reaching a long-term deal to end their nuclear dispute.
In return for continuing action to curb its nuclear programme, Iran would receive $2.8 billion during the four-month extension of its funds held in foreign banks, in addition to $4.2 billion paid during the January-July period.
U.S. officials say more than $100 billion of Iran's funds are held abroad and are difficult to access because of tightening sanctions on the major oil producer in recent years.
The U.N. nuclear agency confirmed on Aug. 20 that Iran was moving to meet the requirements of the extended agreement, paving the way for some of the money to be released.
Citing the Iranian central bank's public relations office, IRNA said Japan's central bank deposited the funds in two instalments at the Iranian central bank's account in Oman.
Japan, China, India and South Korea are the biggest buyers of Iranian crude. Japan, along with South Korea and India, cleared some of its oil dues earlier under the payment schedule agreed with the six powers in the interim agreement.
The nuclear negotiations are due to resume later this month in New York. The six powers want Iran to significantly scale back its uranium enrichment programme to make sure it cannot produce nuclear bombs. Iran says the programme is peaceful.
Under the interim deal that was reached in Geneva in November and took effect in January, Iran agreed to halt its most sensitive nuclear activity in exchange for some sanctions easing. It was designed to buy time for talks on a long-term settlement.
(Reporting by Michelle Moghtader; Editing by Sonya Hepinstall)
By Business News Americas staff reporter - Thursday, September 4, 2014
Chile's state oil company Enap announced plans to triple annual investment to US$800mn and double hydrocarbons production to 32,000boe/d by 2020.
The goals are part of a seven-pillar strategy for 2014-25 under which the NOC plans to meet 100% of oil and gas demand for 20 years in southernmost Magallanes region.
logo-bna E-mail Start a Free Trial
Enap will prioritize unconventional exploration and development in Magallanes and push for expanded use of natural gas in power generation, the company said in a release.
As part of a goal to provide 940MW of capacity for Chile's interconnected grid by 2025, Enap will work toward expanding the Quintero LNG terminal's daily regasification capacity to 20Mm3. A project is currently underway to increase capacity to 15Mm3 from 10Mm3.
Enap's strategy also includes plans to construct the first geothermal power plant in South America, and to boost crude oil refining capacity by improving and expanding refineries in regions Valparaíso (V) and Bío Bío (VIII).
The company will invest US$400mn in environmental impact mitigation and social development projects by 2020, the statement said.
Enap said it will prioritize safety and energy efficiency in its operations, and that it is revamping its human resources department to improve worker relations.
4 Sep 2014, 10.14 pm GMT
Santiago, 4 September (Argus) — Chile´s state-owned Enap plans to invest $800mn a year through 2020 under a 2014-2025 strategic plan approved by its board.
The unprecedented long-term plan substantially boosts investment, which averaged just $286mn a year over the past five years, the company said.
The company plans to more than double production to 32,000 b/d of oil equivalent (boe/d) by 2020, from a current 15,000 boe/d, with a focus on developing unconventional potential in the deep south Magallanes region.
The company also plans to expand its current 220,000 b/d of total refining capacity at its two main refineries, without giving specifics.
The new plan has a strong focus on electricity and natural gas, a division that was recently added to Enap´s traditional upstream and downstream units.
The company plans to add 940MW of new thermal generating capacity by 2025. Enap is promoting the proposed expansion of the Quintero LNG terminal to 20mn m³/d.
The firm is also working on the development of a geothermal plant, the first in South America.
Enap, which regularly earns a meagre profit or even loses money, plans to double its earnings before interest, taxes, depreciation and amortization (Ebitda) to 1.45bn in 2019, from $678mn in 2013.
The new plan is an initiative of Enap chief executive Marcelo Tokman, the former energy minister who was appointed by President Michelle Bachelet this year to revive the struggling company.
Copyright © 2014 Argus Media Ltd - www.ArgusMedia.com - All rights reserved.
OSLO: Norwegian oil firm Statoil has drilled dry wells in two areas in which it had high expectations, off Angola and in the US Gulf of Mexico, hitting its shares and raising questions over whether its successful exploration run is coming to an end.
Statoil was the most successful offshore explorer last year, discovering more oil and gas resources than any other oil company in the world. It has great hopes for drilling in the pre-salt formations off Angola, where it said billion-barrel discoveries were possible. It was also hopeful that it could find hydrocarbons in the Martin prospect in the Gulf of Mexico.
Both wells were estimated to contain a total of more than 250 million barrels of oil equivalent (boe), or 100 million boe net to Statoil. But on Thursday the firm said both wells were disappointing.
“Not an exploration rock star anymore?” Swedbank analyst Teodor Sveen Nilsen said in a note to clients. “We must admit 2014 has been disappointing this far with poor results both in the Barents Sea, Gulf of Mexico (GoM) and Angola.”
Statoil shares were down 1.43 per cent, lagging the European oil and gas index, down 0.17 per cent.
“It is affecting somewhat the share at the moment,” said Kjetil Bakken, an analyst at brokerage Carnegie. “It is fair to say that the Angola well could have been something big had they found something.”
The Angola Dilolo 1 well, drilled in Block 39 in the Kwanza Basin, was the first of eight attempts Statoil plans to make in order to strike oil in the country’s pre-salt geology.
Similar formations offshore Brazil, on the opposite side of the Atlantic Ocean, have yielded large oil discoveries.
“In this first well hydrocarbons were not encountered, but the operation did provide a valuable calibration for other prospects in the area. Further studies are needed in order to fully understand the well results,” Statoil said in a statement.
It will now move the Stena Carron drillship to the neighbouring Block 38 to drill a new well.
Statoil holds a stake of 37.5 per cent in Block 39 and 45 per cent in Block 38. In Block 39, it partners with Total, WRG, Ecopetrol and state firm Sonangol, while WRG, Ecopetrol and Sonangol are partners in Block 38.
It is also participating in two more wells in the Kwanza basin in Angola, in block 25 with a well operated by Total and in block 22 in a well operated by Spain’s Repsol.
Statoil did make a small discovery in the Martin prospect in the US Gulf, but said it was not considered commercially viable and that the Maersk Developer rig would move on to a new location.
The Norwegian company holds a 42.5 per cent stake in Martin, with Calgary-based Nexen and LLOG as partners.
In its update, Statoil also said it now plans for an 18-month drilling campaign on the east coast of Canada following its earlier Bay du Nord oil discovery and to drill off Brazil in the Campos Basin in a well operated by Spain’s Repsol.
Meanwhile, Shell CEO says US should export oil to stablise global markets. US policymakers should gradually lift the country’s decades-old ban on crude oil exports because allowing the shipments would make the global energy system and fuel prices more stable, the head of Royal Dutch Shell said.
Reuters
By Reuters
Kuwait Petroleum Corp (KPC) aims to pick up a significant stake in Indian Oil Corp's Paradip refinery and supply about 60 percent of the oil needs of the plant, set to start up later this year, three sources with knowledge of the matter said.
Gulf oil producers want to lock in customers in Asia, which is experiencing a wave of refinery expansion, as the US shale boom has hit demand for their oil in Western economies.
India, the world's fourth largest oil consumer, imports about 80 percent of its oil needs and plays a growing role as a regional refining hub.
The South Asian nation imports around 16 million tonnes of crude a month - more than it consumes - and exports about a third of that as refined products.
State-run IOC, the country's biggest refiner, aims to start crude processing at its 300,000 barrels per day (bpd) coastal refinery in the eastern state of Orissa by the end of this year.
"Kuwait has sought a 50-percent stake in the refinery and the proposed petrochemical plant, along with marketing rights for fuels," said one of the sources, adding that IOC might settle for a smaller stake and keep control of the refinery.
This source said KPC wanted to reserve the right to later sell a part of its stake in the Indian project to any international oil company.
The sources who spoke to Reuters declined to be identified because of the sensitivity of the topic.
IOC Chairman B Ashok did not respond to telephone calls from Reuters seeking comment, while a KPC spokesman could not immediately be reached for comment.
Kuwait wants to strengthen its role in India's oil gas sector and wants to lease a part of its strategic storage, being built to hedge against energy security risks. Kuwait was India's fourth biggest oil supplier in fiscal 2013/14, supplying about 409,000 bpd.
"KPC has several interests and opportunities in India and this is one of the main ones," said a second source. "India is always on the radar. KPC is interested in Paradip but both sides haven't agreed on the details yet."
IOC, along with subsidiary Chennai Petroleum, controls about a third of India's oil refining capacity of 4.3 million bpd.
KPC and IOC officials had a meeting in India during the last week of August to discuss KPC's participation, two of the sources said. KPC will acquire a stake through its overseas downstream subsidiary, Kuwait Petroleum International.
Kuwait wants a potential joint venture with IOC to sign a deal for long-term crude supply with KPC, they said.
The new refinery will cater to rising demand for fuel as India is keen to boost the share of manufacturing in its economic expansion.
Paradip is IOC's most complex refinery and capable of handling cheaper grades that are more difficult to handle. The refinery will have a potential to produce about 6.3 million tonnes of diesel and 3.6 million tonnes of petrol, which will largely be absorbed by the domestic market.
James Bambino, Platts Oil Futures & Options Editor
New York - September 04, 2014
U.S. commercial crude oil stocks fell 905,000 barrels to 395.57 million barrels during the reporting week ended August 29, U.S. Energy Information Administration (EIA) data showed Thursday.
Analysts surveyed by Platts on Tuesday had been expecting a larger, 2 million-barrel draw.
U.S. West Coast (USWC) stocks fell the most, down 1.7 million barrels to 51.8 million barrels the week ended August 29 amid a 56,000 barrels per day (b/d) increase in crude oil runs, which rose to 2.5 million b/d last week.
The draw comes amid a 117,000 b/d rally in USWC imports, which rose to 1.25 million b/d.
Despite the outright decline, crude oil stocks on the U.S. Gulf Coast (USGC) rose 659,000 barrels to 189.75 million barrels the week ended August 29, marking the first weekly increase since the reporting week ended August 8.
USGC crude oil runs fell 150,000 b/d to 8.6 million b/d, coming off a record 8.75 million b/d for the week ended August 22, EIA data shows. The USGC accounts for more than 50% of total U.S. operable capacity.
The cut in USGC runs helped push regional refinery utilization rates 0.6 percentage point lower to 95.6% of capacity. Total U.S. run rates fell 0.2 percentage point to 93.3% of capacity.
Analysts had been expecting a 0.7 percentage-point decline.
Weaker imports likely limited the build on the USGC, where imports fell 172,000 b/d to 3.51 million b/d. Imports from Saudi Arabia were largely flat, up 8,000 b/d to 840,000 b/d, but continue to trend lower. Saudi imports have fallen steadily from the near-2 million b/d seen in early April, EIA data shows.
Meanwhile, imports from Canada continued to soar the week ended August 29, rising 125,000 b/d to 2.96 million b/d, a record for weekly data. The previous high was 2.95 million b/d in the week ended August 8.
Most Canadian barrels head to the U.S. Midwest, where crude oil stocks rose 399,000 barrels to 86.82 million barrels despite a slight uptick in runs of 25,000 b/d to 3.65 million b/d the week ended August 29.
Stocks at Cushing, Oklahoma -- delivery point for the New York Mercantile Exchange (NYMEX) crude oil futures contract -- fell 385,000 barrels to 20.28 million barrels.
U.S. GASOLINE STOCKS FALL
U.S. gasoline stocks fell 2.32 million barrels to 210 million barrels the week ended August 29, in line with analysts' expectations.
Implied demand* for U.S. gasoline jumped 380,000 b/d to 9.48 million b/d. The four-week moving average shows implied demand held above 9 million b/d for the fifth consecutive reporting week.
Stocks on the U.S. Atlantic Coast (USAC) -- home to the New York Harbor-delivered NYMEX RBOB contract -- fell 590,000 barrels the week ended August 29. But at 56.96 million barrels, USAC stocks are still relatively well-supplied, sitting more than 2% above the EIA five-year average.
USAC imports rose 258,000 b/d to 700,000 b/d, the highest since the week ended May 30, EIA data shows.
USGC gasoline stocks tightened the week ended August 29, having fallen 1.74 million barrels to 73.46 million barrels. USWC gasoline stocks fell 725,000 barrels to 26.38 million barrels, putting them more than 5.5% below the five-year average.
U.S. distillate stocks rose 605,000 barrels to 123.4 million barrels the week ended August 29, counter to analysts' expectations of a 1.2 million-barrel draw.
The build comes despite a 302,000 b/d increase in implied demand, which rose to 3.95 million b/d.
USGC combined low- and ultra-low-sulfur diesel (ULSD) stocks fell 322,000 barrels to 33.35 million barrels, while stocks on the USAC held largely flat.
At just over 32 million barrels, USAC low- and ULSD stocks are more than 10% above the five-year average.
By John Kingston | We hadn’t written about the monthly EIA statistics on US oil supply and demand for a while because they’d gotten kind of dull. The big movements recorded month after month, particularly in product export growth and net import dependence, had fallen into a bit of a predictable range.
That changed in June. The EIA released numbers from that month today.
US petroleum import dependence in June dropped to 4.659 million b/d. That’s only the second time in the post-shale era that number had been less than 5 million b/d. And the last time the US recorded a number that low was back in 1986. But not all import dependence is equal; the US certainly would view Canada or Mexico as a supplier less prone to disruption than many other countries. So once you take away US net import dependence with Canada, that number slips to 2.282 million b/d. Take away Mexico and you’re down to 1.962 million b/d. Those numbers are easily the lowest ever recorded by the EIA. So in essence, that 1.962 million b/d of net import dependence is the figure for the rest of the world outside North America. In 2005, that US net import dependence figure after Canada and Mexico were taken out regularly recorded numbers in excess of 9 million b/d.
The main reason for that? US crude oil exports to Canada were 384,000 b/d. Total crude exports were 396,000 b/d after the EIA somehow recorded 6,000 b/d going to Singapore and 5,000 b/d to Switzerland. That total amount has only been exceeded once in history: March 1957, when exports spiked to 455,000 b/d. (Economist Phil Verleger wrote in to note that an earlier post that questioned what might have happened in March 1957 to spur such a surge overlooked the fact that it was the occasion of the Suez Canal crisis.) We know that by rail or by ship, the US is sending an increasing amount of crude oil exports to Canada, which faces far more limited US export restrictions. In fact, the surge may be a problem for a significant new pipeline project designed to get Canadian oil out of Alberta, particularly if Keystone XL is blocked; Canada’s biggest newspaper wrote about the issue yesterday.
Other export statistics were strong, but few records were recorded. Total products exports were 2.733 million b/d; that’s actually the second-lowest figure this year. Distillate exports were strong at 964,000 b/d, but the record is 1.131 million b/d, set last September. LPG exports at 683,000 b/d were the third-highest ever, but a long way from May’s record of 727,000 b/d.
The talk through much of late last year and into this year was the strong increase in demand being recorded in the US. But the EIA data isn’t showing that trend—if it ever was one—continuing. Products supplies were 18.833 million b/d; that’s a whopping 27,000 b/d more than June 2013. In June 2010, when the economy was in far worse shape, products supplied were 19.537 million b/d. And gasoline consumption was just 9.034 million b/d, down slightly from the corresponding month a year ago. With Chinese demand flat, where’s the increase in demand going to come from to drive prices higher?
North Dakota’s 1.093 million b/d crude production was a record. Texas produced 3.074 million b/d, a post-shale record. Federal offshore production of 1.43 million b/d remains below the levels in place when the Macondo moratorium was put in place in April 2010. It was 1.531 million b/d in May of that year.
By Takeo Kumagai | September 4, 2014 06:25 AM Comments (1)
Japan and Australia are increasingly importing more oil products as a result of a series of refinery closures in their respective countries.
On the surface, the consequences of the drop in refining capacity in the two countries look similar in the short term. But fundamentally, the two nations are taking different routes for energy security.
Japan, on the one hand, is essentially rebalancing its surplus refining capacity against domestic oil demand amid a series of regulatory requirements. The Australian government, by contrast, appears to be relaxed about the energy security implications of the country becoming dependent on imports for more than 50% of its transport fuel demand.
On July 31, METI enforced a new regulation that could result in trimming the country’s installed refining capacity to around 3.55 million b/d by the end of March 2017. The expected reduction amounts to about 400,000 b/d or 10% of the current installed capacity of 3.95 million b/d if refiners decide to respond to the policy by cutting their CDUs.
Regardless of the country’s boost in oil product imports in the short-term, and even with the mandated reductions in capacity, going forward Japan will not be as heavily reliant on these imports as Australia, as it works toward striking a consumption-refining capacity balance instead. Moreover, Tokyo also does not intend to have increased exposure for petroleum product imports for its energy security, given that it is already nearly 100% dependent on crude imports for its refinery input.
But Japan’s long standing post-war policy, for refining and consuming in the country—which has led to a refining sector built on the expectation that it would fuel the country’s economic growth–may need to be reviewed given the world’s increasingly ample availabilities of oil products from new refineries in Asia and the Middle East.
Japan, for instance, hiked imports of oil products during the country’s first refinery turnaround season over May-June as a consequence after hefty cuts in refining capacity at the end of March. Traditionally Japanese refiners have been reluctant to imports oil products they can produce. (One exception: heavily import-dependent naphtha.)
Japan, the third largest oil consumer in the world, had slashed its refining capacity to 3.95 million b/d at the end of March as local refiners responded to a government regulation, which required an increase in their residual cracking ratio over crude distillation unit capacity. That’s a drop of 19% from its 10-year peak of 4.89 million b/d in early April 2008, and was down 12% just in the last year. That drop has come due to a combination of regulatory response, of which most refiners responded by scrapping CDUs, and corporate decisions in the face of diminishing domestic demand.
Australia, meanwhile, is relatively a small crude producer and consumer but a major natural gas producer in the Asia Pacific region. Its refining and marketing sector has undergone significant restructuring in recent years.
The Australian refining industry is characterized by aged, small-scale facilities, and all four domestic refiners have struggled to compete with new, larger plants operating in the region. As a result, Australia is becoming increasingly reliant on imported transport fuels due to the closure of two of the country’s remaining six refineries over the coming year.
So like Japan, it has increased imports. But the trend isn’t the same. In Australia, the government has stayed on the sidelines while the four big refiners –BP, Caltex, ExxonMobil and Shell–have rationalized their portfolios in response to competitive pressures. Those pressures have been both external , in the form of stiff competition from worldscale refineries elsewhere in Asia, and internal, as the majors have baulked at allocating additional investment in their aging Australian plants.
The recent increase in Japanese product imports during turnaround season turned it into a net importer of gasoline over May-June. During that period, imports by refiners and importers averaged 43,842 b/d, against average gross exports of 21,191 b/d, an analysis of data from the Ministry of Economy, Trade and Industry shows. Japan earlier had flipped back into a regular net gasoline exporter in November 2013, after turning net importer in the aftermath of the devastating earthquake and refinery outages in March 2011.
In July, Japan remained a net importer of gasoline for the second straight month. But gross imports of 33,078 b/d in July–while 31% higher from a year ago–were down 43.2% from 58,198 b/d in June, while gross exports surged 88.6% from 12,172 b/d in June, to average 22,957 b/d in July, up 44% from a year ago. Signs of a slowdown in domestic gasoline demand could have contributed to the unusual lower month-on-month imports in July, with industry sources attributing sluggish sales to retail gasoline prices, which were at their highest since September 2008.
But that “reversion to the norm” coming out of turnaround season is more like what will be expected of Japan in the future. A similar reversion would not be expected in Australia, where the import level will be expected to be whatever it turns out to be
By Brian Scheid | September 3, 2014 10:49 AM Comments (0)
Shortly after she was named chairman of the powerful Senate Energy and Natural Resources Committee earlier this year, Senator Mary Landrieu, a Louisiana Democrat, held a press conference to stress her strong support for the Jones Act.
“The Jones Act is a jobs act, pure and simple,” Landrieu said of the nearly 100-year-old law which requires all vessels shipping cargo between two US locations to be US built, majority US-owned and at least 75% of the crew to be US citizens.
Surrounded by shipping industry representatives, Landrieu criticized the Obama administration for attempts to weaken the act’s purpose. “Waiving the Jones Act literally hands over work to foreign shippers,” she said.
Perhaps most surprising about the press conference, one of the few Capitol Hill press events Landrieu has hosted since taking helm of the energy committee, is that it was not in response to new legislation aimed at weakening the Jones Act, nor was it in response to another potential waiver to the act.
Temporary Jones Act waivers have been issued following Hurricanes Katrina and Rita in 2005 and superstorm Sandy in 2012. In August 2011, the Obama administration waived Jones Act requirements to move about 25 million barrels of Strategic Petroleum Reserve crude on foreign-flag tankers to refineries throughout the US.
But, Landrieu conceded, the administration had given no indication it was even thinking about another waiver. The press conference, Landrieu made clear, was meant to show that the Democrat-controlled senate committee would not be moving to weaken the Jones Act.
But even if Republicans take control of the Senate in November’s mid-term election and, as expected, Senator Lisa Murkowski, an Alaska Republican, is named chairman, the committee is unlikely to look at weakening the Jones Act. Despite her strong support for loosening US restrictions on crude exports, Murkowski has backed the Jones Act.
“The US maritime industry, supported by the Jones Act, provides vital services necessary for Alaska’s economy and quality of life,” said Murkowski in March.
Despite the appearance of, at best, limited supported for weakening the Jones Act on Capitol Hill, petroleum marketers and refiners are planning a substantial effort to get Congress to change the law which they claim is driving up motor fuel and heating oil prices and severely inhibiting the flow of crude between US ports amid the ongoing domestic oil boom.
These efforts may include a push for new waivers to get the rising tide of light sweet crude from the Gulf of Mexico to east coast refineries or modifying rules on the percentage of a vessels’ crew must be US citizens.
“I’m not naive enough to think that Congress will repeal this thing,” said Charles T. Drevna, president of the American Fuel & Petrochemical Manufacturers, said in a recent interview with Platts. “But, I think after 94-plus years now it’s time to take a look at this thing and see how the Jones Act… and the economic realities of 1920, fit in with the economic realities of 2014.”
Rob Underwood, director of government relations with the Petroleum Marketers Association of America, called the Jones Act “outdated” and a “protectionist policy” but also conceded that repeal was unattainable considering its support within the US maritime industry.
He said instead petroleum marketers were pushing for a US Government Accountability Office report on the impacts of the Jones Act. He said other changes may be possible, such as new allowances for waivers to ship the glut of light sweet crude in the Gulf to refineries in the mid-Atlantic.
The Jones Act was originally put into place largely to help the US government resell many of the cargo ships it built during World War I, according to a July 21 Congressional Research Service report on shipping US crude oil by water.
Costs of US-built tankers can be as much as four times the costs of those built in Korean, Chinese and Japanese shipyards, while the daily operating costs of a US-flagged ship, crewed by US citizens, is nearly four times that of a foreign-flag tanker, according to the US Transportation Department’s Maritime Administration.
In addition, charter rates for Jones Act-compliant tankers are averaging between $75,000-$100,000/d, up from an average of $50,000/d two years earlier, according to the CRS report. Charter rates for foreign-flagged tankers are averaging $10,000/d for spot charters and $15,000/d for annual charters, the report states.
Shipping crude from the Gulf Coast to US ports can cost between $5-6/b, compared to the $2/b its costs to ship it on foreign-flag tankers from the Gulf to eastern Canada, according to the CRS report.
By Elizabeth Bassett |
When we began the Oil Big Five posts, we had an idea of featuring brand-new items every single month. But that whole saying about people forgetting history being doomed to repeat it?
It came to mind this month when we were soliciting suggestions from our Platts oil editors and analysts for this month’s listing. Big issues don’t go away quickly, and in an industry as large and complicated as global oil, it’s doubly true.
That said, we do have several new issues on the list this month, as well as some follow-ups to previous topics. Be sure to comment here, on Facebook or on Twitter (use the hashtag #oilbig5), and we look forward to featuring your comments. Tell us what you’re thinking about, and here’s what we’re most focused on at the moment:
1. Libya’s return to production and exports
Our very first Oil Big Five listing included the topic of Libyan exports, and this time we’re looking at its crude production. Earlier this year, the country seemed on the path toward zero production, but in late August a spokesman for state-owned National Oil Corp. said production was reaching 630,000 b/d. Not all oil fields are back in operation yet, but the increases since July and the return of export terminals to state control could be a signal a turnaround. There is still considerable turmoil in the country, though, meaning the future of oil production there will remain an unanswered question for at least a while longer.
2. Oil basis WTI
August was not an easy month if you were long basis WTI, which opened the month around $100/b and closed near $93. The roughly 7% drop over the course of the month is significant—political turmoil from various parts of the globe (including Oil Big Five repeat offender Russia) and being right around the corner from maintenance season has put a lot of downward pressure on WTI. Despite the geopolitical climate, one analyst pointed out, there’s no supply disruption, just weak underlying fundamentals. Will maintenance season do anything to reverse the slide?
3. The price of Dubai
The contango between first and third-month cash Dubai topped the $1/b mark this August, the first time since September 14, 2010, when it was at $1.25/b. On August 21, the contango was assessed at $1.21/b, up 29 cents/b on the day, widened as the sour Middle Eastern crude market followed structural weakness in the Brent market. Compounding that, Asian refiners have had lackluster demand for sour Middle Eastern crude due to other competing grades to pick from. And to add insult to injury, front-month cash Dubai had fallen 69 cents/b just a couple of days before, on August 19, dropping below the $100/b mark for the first time in 13 months and assessed at $99.80/b. What will September bring for the Dubai market?
4. Mexico: Ahead of schedule
Pemex is busy with Round Zero of its extensive energy industry reforms, and in mid-August the Mexican energy ministry awarded the state oil and gas monopoly most of the producing fields and exploration prospects it wanted before opening other fields to private enterprise. The announcement came a month earlier than expected, but President Ernesto Pena Niento said the timetable was sped up to more quickly provide results to citizens. Another news item out of Mexico in August: Pemex revised its annual production target for this year to its lowest level for three decades, down to 2.35 million b/d from 2.44 million b/d, and revised production data for the first half of the year due to miscalculations. And on August 29, Pemex announced its crude output target for 2015 will be 2.4 million b/d. We’re eager to see production numbers evolve, as well as the results of Round One in 2015, which will mark the first open upstream bidding round for licenses since the country’s nationalization of its oil industry in 1938.
5. US imports from Kurdistan
This is a sort of follow-up to last month’s United Kalavrvta topic (still floating in international waters off the coast of Texas, according to Platts vessel tracking software cFlow and shipping sources). In August, a US judge rejected the Iraqi central government’s claim to the ship’s cargo, and ruled the US does not have the jurisdiction to block the sale of Kurdish oil. In practical terms, it appears the US would not prevent any sale of Kurdish crude in the US. Now the question remains whether a US buyer will emerge, or if the cargo (or future cargoes of Kurdish crude) will end up at a US refinery. Anyone want to wager a guess?
