The sharp upsurge in Saudi Arabia's crude exports to Japan to 10-year highs in April clearly signals one thing -- that the Middle East supplier is intensifying efforts to grab any incremental demand opportunity that comes from its key customers.

And it seems to be in no mood to deviate from its aggressive policy of doing all it can to boost market share, industry sources and analysts said, adding that its strategy was unlikely to change over the course of the year.

"The Saudi response [for incremental supplies] has improved in recent months," a Japanese refiner source said. "We feel that they are actively responding to requests for incremental supplies in a prompt manner."

Japan's crude imports from Saudi Arabia averaged 1.42 million b/d in April, the highest for the month since it imported 1.5 million b/d in April 2006, according to preliminary data released Tuesday by the Ministry of Economy, Trade and Industry.

Saudi Arabia's crude supplies to Japan in April surged 37.2% from 1.037 million b/d a year earlier, according to S&P Global Platts calculations based on METI data.

It includes 50% of imports from the Partitioned Neutral Zone, which lies between Saudi Arabia and Kuwait. METI lists it as a separate supply source.

Saudi Arabia's market share rose to 41% of Japan's total crude imports of 3.47 million b/d in April, from 31% a year ago.

Takayuki Nogami, chief economist at Japan Oil, Gas and Metals National Corporation said that Saudi Arabia's increased crude sales to Japan in April was not a coincidence at this level and was based on its market share strategy.

"Based on its market share strategy, the Saudis are trying to increase their share by selling larger volumes to secure their income," Nogami said. "They are expected to maintain this policy this year."

Saudi Arabia's oil policy is being closely watched as the kingdom recently appointed Khalid al-Falih as energy minister to replace the long-serving Ali al-Naimi.

Samer AlAshgar, president of Saudi Arabia's independent King Abdullah Petroleum Studies and Research Center said at an energy seminar in Tokyo on May 13 that he did not expect the kingdom to change its market share policy any time soon.

"I do not see any change from the current strategy that they have now," AlAshgar told the energy seminar hosted by the Institute of Energy Economics, Japan. "The policy has been working and is now being effective."

Despite this year being a leap year, Saudi Arabia's crude supplies to Japan showed a hefty increase during the first four months, when overall Japanese imports slid 2% year on year to an average 3.47 million b/d, according to Platts calculations based on METI data.

Saudi Arabia's crude supplies to Japan averaged 1.27 million b/d in January-April, accounting for 36% of the total imports in the four-month period.

Compared with the same period last year, that was 7.6% higher from the 1.18 million b/d levels and accounted for 33% of the 3.54 million b/d total imports.

Saudi Arabia's crude supplies to Japan spiked in April at a time when Japanese refiners had to make up for an expected shortfall in their procurements from Iran and the UAE, coupled with competitive Saudi official selling prices for March loading programs, industry sources said. Japan's crude imports from Iran dropped 71.9% year on year to 19,161 b/d in April.

http://www.platts.com/latest-news/oil/tokyo/analysis-saudi-arabia-reinforces-strategy-with-27599422

Exxon Mobil Corp. may invest more than $10 billion in Argentina’s Vaca Muerta shale formation in the next decades, Chairman and Chief Executive Officer Rex Tillerson said Thursday.

The oil giant has so far invested $200 million in the world’s second largest shale gas deposit, Tillerson said after meeting with Argentine President Mauricio Macri in Buenos Aires. Exxon has received approval to invest $250 million more for a pilot project in the coming months.

If the pilot project is successful, the company will start full development during a period of 20 to 30 years that could involve additional investment “that would be well in excess of $10 billion,” he said.

For Tillerson, Argentina’s vast Vaca Muerta shale region represents an opportunity to reverse production losses and add reserves after a $35 billion wrong-way bet on U.S. natural gas and a Russian exploration venture that was derailed by international sanctions. Exxon, the world’s largest oil explorer by market value, has designated Vaca Muerta as one of nine “key activity” areas in the Western Hemisphere and one of just four in South America, according to company data.

Macri has been courting international corporations from Total SA to Dow Chemical Co. to Coca-Cola Co. to invest in Argentina since taking office in December. Exxon, whose annual sales dwarf the economic output of all but about 45 of the world’s nations, is building a plant to strip impurities out of natural gas as well as a pipeline network to handle the output from its Vaca Muerta wells.

“I am very encouraged by the changes that have occurred here in Argentina, with the change in government,” Tillerson said, according to a statement from the Argentine government.

Exxon’s worldwide oil and gas output is lower than it was when Tillerson began his tenure as CEO a decade ago.

Last year, the company that traces its roots to the 1880s and John D. Rockefeller’s Standard Oil Trust failed to replace all the crude and gas it pumped with new discoveries for the first time in 22 years. In April, S&P Global Ratings stripped Exxon of the gold-plated credit rating it had held since the Great Depression.

Tillerson will reach Exxon’s mandatory retirement age of 65 in March. In a May 25 meeting with reporters after the company’s annual meeting in Dallas, he declined to say whether he would seek an extension of his tenure from the board.

Vaca Muerta, Spanish for Dead Cow, is one of the world’s top shale plays, covering an area the size of Belgium and considered key to restoring energy self-sufficiency in Argentina.

http://www.bloomberg.com/news/articles/2016-06-03/exxon-ceo-says-argentina-shale-investment-may-exceed-10-billion

BP Plc said it agreed to pay $175 million to settle claims by U.S. investors that its managers lied about the size of the 2010 Gulf of Mexico oil spill to prop up its stock price,
removing the company’s last major overhang from the disaster.

The investors, who blamed BP for massive losses when the true scope of the spill was revealed, had sought as much as $2.5 billion. The settlement averts a trial that was set for July in Houston federal court.

The settlement announcement Thursday came shortly after a ruling by U.S. District Judge Keith Ellison to narrow the evidence that could have been presented to a jury. The decision, which would have benefited BP at trial, limited the management statements that investors could claim affected the stock price.

BP shares plunged by more than 40 percent in the weeks after the April 2010 disaster, as it became clear the company couldn’t immediately contain the spill. More than 4 million barrels of oil escaped into the Gulf of Mexico during the 87 days London-based BP took to control the well.

The investors’ lawsuit, led by the public employee pension funds of New York and Ohio, revolved around statements made shortly after the Deepwater Horizon drilling rig blew up in April 2010. Those statements also were central to BP’s agreement in 2012 to pay $525 million to resolve claims by the Securities and Exchange Commission that the London-based company underestimated the size of the spill to bolster stock prices. BP also pleaded guilty to a felony count of obstruction of Congress related to spill estimates.

“Investors saw their stock prices plummet after the Deepwater Horizon explosion,” said Jennifer Freeman, a spokeswoman for the New York Comptroller’s Office. “This settlement helps compensate investors for their losses."

http://www.bloomberg.com/news/articles/2016-06-02/bp-to-pay-175-million-to-settle-claims-it-hid-spill-costs

U.S. diesel futures have soared about 40 percent in the last two months, prompting independent refiners to pounce, selling future output on the view that resurgent domestic demand and higher exports may turn out to provide only a brief boost.

The surprise rally in U.S. diesel futures has put prices on track for their biggest quarterly percentage gain in seven years. Money managers and hedge funds have invested heavily in the fuel as stronger-than-expected demand has helped draw down record inventories.

Diesel typically enjoys strong seasonal demand in these months from farmers fueling tractors and equipment during the spring planting season. But prices this year have gotten an extra boost from robust exports to Europe and Latin America.

Strikes in France have slashed European supplies for almost two weeks, boosting demand for U.S. diesel. But the announcement that one French refinery would restart hit U.S. diesel margins on Thursday. The distillate crack spread had jumped 7 percent, then gave up most of the day's gains.

Refiners such as Valero Energy Corp and Phillips 66 typically look for big price rallies to sell future output. These refiners were presented with a rare opportunity to lock in profits when diesel prices and margins popped in April and May.

Producer short positions in NY Harbor Ultra Low Sulfur Diesel (ULSD) have soared to levels not seen since November 2010, data from the Commodity Futures Trading Commission show.

Refining margins, represented by the U.S. diesel crack spread, have jumped by about 70 percent since early April and are on track for their biggest quarterly percentage gain since 2013. Margins widened to $14.94 on Thursday, their highest since mid-February, but then gave back most of the day's gains on the French refinery announcement.

Locking in $13 to $14 per barrel of profit through the rest of 2016 was better than the single-digit margins earlier this year, a trader at a U.S. East Coast refiner said. But they remain a far cry from the record hit in 2012, which exceeded $45 a barrel.

"Refiners are systematic, because they need to lock in margin," said John Saucer, vice president of research and analysis at Mobius Risk Group. "Anytime there's an uptick in a crack or a margin they're going to capitalize on it."

The rally could fade if hedging gathers pace and speculative buying wanes.

In a further sign of selling into next year, the average for the 12 futures contracts expiring in 2017, called the calendar strip, has not kept pace with gains in this year's prices.

Since early April, the 2017 strip has risen 21 percent to $1.64. Over the same period, the 2016 strip has gained about 29 percent, while the front-month contract has jumped about 40 percent.

The picture for refiners has improved dramatically since the bleak outlook this winter, after margins fell as low as $8 a barrel in late January. Soon after that, many refiners shut capacity due to weak profits because of a big glut in diesel.

But refiners are skeptical that margins will remain strong, because U.S. crude is on track for its biggest quarterly percentage gain since 2009. Fear for tighter margins going forward has encouraged them to hedge.

The heightened activity in diesel is surprising for this time of year, when typically the market buzz surrounds gasoline, heading into the busy summer driving season.

Speculative investors turned bullish on diesel early in May for the first time in about two years, after inventories that had been bloated by a mild winter started to decline.

http://www.reuters.com/article/us-usa-diesel-demand-idUSKCN0YP0CG

U.S. crude oil refinery inputs averaged 16.2 million barrels per day during the week ending May 27, 2016, 73,000 barrels per day less than the previous week’s average. Refineries operated at 89.8% of their operable capacity last week. Gasoline production increased last week, averaging over 9.9 million barrels per day. Distillate fuel production increased last week, averaging about 4.8 million barrels per day.

U.S. crude oil imports averaged over 7.8 million barrels per day last week, up by 524,000 barrels per day from the previous week. Over the last four weeks, crude oil imports averaged over 7.6 million barrels per day, 8.3% above the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 921,000 barrels per day. Distillate fuel imports averaged 69,000 barrels per day last week.

U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 1.4 million barrels from the previous week. At 535.7 million barrels, U.S. crude oil inventories are at historically high levels for this time of year. Total motor gasoline inventories decreased by 1.5 million barrels last week, but are well above the upper limit of the average range. Both finished gasoline inventories and blending components inventories decreased last week. Distillate fuel inventories decreased by 1.3 million barrels last week but are well above the upper limit of the average range for this time of year. Propane/propylene inventories rose 1.3 million barrels last week and are near the upper limit of the average range. Total commercial petroleum inventories decreased by 2.7 million barrels last week.

Total products supplied over the last four-week period averaged 20.4 million barrels per day, up by 2.2% from the same period last year. Over the last four weeks, motor gasoline product supplied averaged about 9.7 million barrels per day, up by 4.0% from the same period last year. Distillate fuel product supplied averaged about 4.1 million barrels per day over the last four weeks, up by 0.6% from the same period last year. Jet fuel product supplied is up 1.6% compared to the same four-week period last year.

Cushing drops 700,000 bbls

http://ir.eia.gov/wpsr/wpsrsummary.pdf

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                                               Last Week     Week before   Last Year

Domestic Production '000......... 8,735               8,767           9,586

http://ir.eia.gov/wpsr/overview.pdf

Kinder Morgan on Thursday said its units Elba Liquefaction and Southern LNG received approval from the Federal Energy Regulatory Commission for the Elba liquefaction and export project.

In its statement, Kinder Morgan informed its units have also received FERC certificates of public convenience and necessity for the EEC modification project and SNG Zone 3 expansion project, respectively.

The liquefaction project has a price tag of $2 billion and will be constructed and operated at the existing Elba Island LNG terminal near Savannah, Georgia.

The first of 10 liquefaction units is expected to be placed in service in the second quarter of 2018, with the remaining nine units coming online before the end of 2018. The project is supported by a 20-year contract with Shell, Kinder Morgan added.

The other expansion works that include additional compression and related work for north-to-south capacity expansions on Elba Express Pipeline that will supply additional gas to industrials and utilities in Georgia and Florida and to Elba Island for liquefaction.

Facilities for these pipeline projects are expected to be placed in service late in the fourth quarter of 2016.

The liquefaction project is expected to have a total capacity of approximately 2.5 million tons per year of LNG for export, equivalent to approximately 350,000 Mcf per day of natural gas.

http://www.lngworldnews.com/u-s-ferc-approves-elba-island-lng-export-project/

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Israel's government on Thursday approved the development of the controversial Leviathan natural gas field that will give Israel a second source of gas supply while potentially turning it into a gas exporter.

Leviathan, one of the largest offshore discoveries of the past decade, was found off Israel's Mediterranean coast in 2010. It has an estimated 622 cubic meters of natural gas (BCM) of reserves and is expected to become operational in 2019.

Texas-based Noble Energy, which holds a 40 percent stake in Leviathan, said the field would initially start production at 1.2 billion cubic feet a day and expand to 2.1 bcf.

"Leviathan is expected to provide a second source of supply and entry point into Israel's domestic natural gas transport system, while also delivering exports to regional countries," Noble said in a statement.

The site, however, will cost at least $5 billion to develop and it was not yet clear how the project will be financed.

"Strong momentum on the regulatory and marketing fronts represents major steps in advancing the Leviathan project towards final investment decision," said J. Keith Elliot, Noble's senior vice president for the Eastern Mediterranean.

Earlier this week, Leviathan signed a deal to supply up to 473 bcf to a new private power plant, IPM Be'er Tuvia, for 18 years. Noble estimated gross revenue from the deal at $2.5 billion.

In January Leviathan signed a $1.3 billion gas supply contract with Edeltech, Israel's largest private power producer.

Last week Israel's government approved a revised deal aimed at fast-tracking development of Leviathan, which has been mostly earmarked for exports.

The Leviathan project hit a major obstacle in March when Israel's Supreme Court blocked a previous agreement between the field's shareholders and the Israeli state, the terms of which would have stayed unchanged for 10 years.

It had been opposed by opposition parties and public advocacy groups on grounds that Noble and its partner Delek Group - which also own the adjacent Tamar field - would control too much of Israel's natural gas supply.

Tamar began production in 2013 and provides Israel with its current natural gas needs.

http://www.reuters.com/article/israel-natgas-leviathan-idUSL8N18U3Y9

When it comes to the North Sea, there is no such thing as an easy sale, even for oil giants Royal Dutch Shell and BP.

More than any other region in the world, the North Sea has suffered greatly over the past two years as a 60 percent drop in oil prices, high operating costs, dwindling reserves and a tough tax regime has hit operators hard.

As a result, producers ranging from Shell and France's Total to smaller regional players such as Enquest and Tullow Oil have put dozens of assets in the region on the block to boost their balance sheets.

But deals have been few and far apart. Buyers and sellers have found it hard to agree on the value of assets and how to share the costs of dismantling and cleaning up of obsolete fields, known as decommissioning.

With around 30 percent of fields operating at a loss in 2016 and others seeing razor thin margins, "almost all UK North Sea assets are up for sale," said Fiona Legate, senior UK upstream oil and gas analyst at consultancy WoodMackenzie.

"There is however a limited pool of buyers," she added.

BP has struggled to sell a stake in its Forties pipeline system, one of the region's oldest and the main source for the eponymous crude used to price the global Brent crude benchmark.

Talks with Swiss-based chemical giant Ineos recently collapsed after the sides could not agree on how to price the asset, sources close to the negotiations said.

The Forties pipeline has a capacity to deliver over 1 million barrels per day and serves over 50 offshore oil and gas fields in the central North Sea, according to BP's website.

But declining output has meant the pipeline operated at less than 40 percent of its capacity last year, WoodMackenzie says.

Ineos wanted BP and other producers using the pipeline to commit to a fixed capacity fee that would guarantee revenue even if output continued to decline, industry sources close to the talks told Reuters.

BP however sought to pay on a per-barrel basis, they said. "Buyers want something to protect them against a drop in throughput," one source said. The pipeline system remains on the market.

Shell is starting an ambitious three-year $30 billion global asset sale programme to pay for its $54 billion acquisition of smaller British rival BG Group in February.

In the North Sea, the company is planning to bundle several assets in packages that will include mature fields along with more attractive assets such as the Buzzard field and pipelines, banking sources said.

The Anglo-Dutch company held talks in recent months with Neptune, a North Sea-focused investment company headed by former Centrica boss Sam Laidlow and backed by private equity funds Caryle Group and CVC Partners.

Shell Chief Financial Officer Simon Henry remains confident it can meet its target within around three years. Shell will focus at first on selling infrastructure, refining and retail businesses that are less exposed to oil price fluctuations over production, or upstream assets, he said.

"If the oil price stays at $48 a barrel maybe (the sale programme) will take us a little bit longer. We are not chasing sales of upstream assets at $48."

Operating in the North Sea remains challenging even after Shell cut costs sharply in recent years, Henry said, adding that within the region, some areas are more profitable than others.

"We've taken our costs down hugely and improved our reliability and availability. So the performance today is much better than it was two years ago but it is still not good," Henry told reporters on May 24.

"In general it is high cost region in which you have to keep spending to stay in business and have significant decommissioning and restoration costs."

An extended period of low oil prices also leads to an earlier decommissioning of fields, he said.

WoodMackenzie estimates 142 fields will cease production over the next five years. Total UK North Sea decommissioning are expected to reach 55 billion pounds.

http://www.reuters.com/article/oil-ma-northsea-idUSL8N18S4NY

OPEC will stick to its policy of unfettered oil production after members failed to agree on a new output ceiling. Crude extended its decline in London.

The meeting didn’t produce a supply accord but did reach consensus on appointing Nigeria’s candidate as new secretary-general, Sudirman Said, Indonesia’s energy minister, said in Vienna. The Organization of Petroleum Exporting Countries’ de facto leader, Saudi Arabia, had previously discussed restoring a production target scrapped in December, according to delegates familiar with the matter.

Oil has rallied about 80 percent from the 12-year low reached in January as depressed prices take their toll on supplies. That suggests the Saudi-led decision in 2014 to maintain output amid a global glut is finally paying off, with higher-cost producers cutting back. While Saudi Arabia had shown willingness to mend divisions Thursday with cash-strapped members demanding a new group ceiling, Iran said it would only support individual country quotas that would be difficult to agree in a single meeting.

Iran has rejected any cap on production as it restores output following the removal of sanctions in January. The country’s refusal to participate in a production freeze proposed earlier this year prompted Saudi Arabia to block a deal between OPEC and Russia in April.

Although OPEC regularly ignores its own output targets and there was no suggestion anyone would cut production, even a token gesture could have showed renewed unity and boosted prices. 

Nigeria’s Mohammed Barkindo will assume the role of secretary-general, succeeding Abdalla El-Badri, who has been in the job for nine years. Barkindo was acting head of OPEC in 2006 and previously ran Nigerian National Petroleum Corp.

His appointment demonstrates that OPEC has at least overcome squabbles that scuppered consensus on the top job at previous summits. El-Badri, a 76-year-old Libyan, was originally due to step down in 2012 after serving the maximum two terms, but members weren’t able to agree on a replacement and his tenure was extended at successive meetings.

Barkindo, whose rival nominees for the job included Indonesia’s Mahendra Siregar, spent more than 23 years at NNPC, where he served in various capacities including deputy managing director of Nigeria LNG and head of the international trading unit. He also served for 15 years as Nigeria’s national representative to OPEC.

http://www.bloomberg.com/news/articles/2016-06-02/opec-said-to-keep-status-quo-after-failing-to-agree-output-limit

Iran oil min Zanganeh says pre-sanctions OPEC mkt share of 14.5% wld be "fair" quota. OPEC at ~32 mil b/d; that'd make 4.64 mil b/d for Iran

@HermsTheWord

Petroleo Brasileiro SA’s new Chief Executive Officer Pedro Parente said political interference has ended in the state-run oil producer and that fuel price decisions will now be made according to the company’s best interests.

A solution to Petrobras’s debt, the largest in the industry, includes selling part of its assets, he told reporters after his swearing-in ceremony in Brasilia, led by Acting President Michel Temer.

Parente is the best person to lead a recovery at the oil company that is at the center of Brazil’s biggest-ever corruption scandal, Temer said during the event.

Temer said he supports the two-year graft probe known as Carwash that has led to the arrest of former Petrobras executives, business leaders and politicians. Under a scheme that lasted about a decade, a group of suppliers bribed former officials to win contracts with the oil producer. The acting president reiterated Petrobras’s claim that it was a victim of bad practices.

"Everyone expects that you, in some time, will make us proud of our Petrobras again," Temer said at the ceremony, where heads of state banks were also sworn in. "No one will interfere in Carwash."

Parente, who has extensive experience in government and business, was confirmed as CEO by the board of directors on May 30. He will officially assume the post on Thursday in Rio de Janeiro, where Petrobras is based.

Parente was a member of Petrobras’s board for almost four years starting in 1999, and its chairman for nine months, while he was part of former president Fernando Henrique Cardoso’s cabinet. He was also the head of agribusiness giant Bunge Ltd.’s Brazil unit from 2010 to 2014. He is currently the chairman of BM&FBovespa SA, the operator of Latin America’s biggest securities exchange.

http://www.bloomberg.com/news/articles/2016-06-01/petrobras-ceo-says-no-more-political-interference-in-oil-company

As crude prices plummeted last summer, Steve Pruett, chief executive of a small west Texas oilfield developer, idled a drilling rig, opting to pay $21,000 a day to store it rather than dig more wells and risk bigger losses.

Now as oil prices rise again, the third-generation oil man is offering his only rig crew bonuses to drill wells as fast as they can, but says his company, Elevation Resources, will wait until next year to deploy a second rig.

"We're going to ease back into the activity, not stomp on the accelerator," Pruett said. "We've all sobered up."

Last year's rollercoaster when crude prices rallied in the first half of the year only to come crashing down in the second half, burned many producers and Pruett and his peers remain cautious.

But there are signs of guarded optimism that this time the industry has really seen the worst of the nearly two-year downturn that cost hundreds of thousands of jobs, pushed dozens of firms into bankruptcy and led to an investment slump so severe that it weighed on the whole U.S. economy.

With crude prices now nearly double their February lows near $26 per barrel, new wells in the Permian Basin - North America's richest source of shale oil - are again becoming profitable and producers are taking baby steps to crank up output again.

The number of rigs in the shale oil basin that spreads across more than 50 counties near the border with New Mexico rose by 17 to 146 on May 31 after bottoming in late April, according to data shared with Reuters by Drillinginfo, a consultancy.

The number of drilling permits - a leading indicator of future activity - issued for the Permian region in April, the latest month available, was the highest since October 2015. 

The Permian rig count remains far below its November 2014 peak of 467 rigs recorded by oil services company Baker Hughes, and many areas and new wells less productive than those in "sweet spots" will need prices to climb further to be profitable again. But the stirrings suggest some relief is on its way. Job losses in Midland and Odessa, the region's main cities, have slowed, local oil executives talk about plans to drill and some are already arranging new financing.

Keith Moore, president and CEO of West Texas National Bank, a local energy lender, says loan applications are starting to arrive again after a year-long pause. "People were sitting on their projects. It looks like we are on the edge of recovery."

Pruett says with oil near $50, wells on three of Elevation Resources' seven fields are already profitable and he expects prices to climb $60 next year, which would call for a second rig.

http://www.reuters.com/article/usa-energy-permian-idUSL2N18N1P0

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Indian firm Petronet, New Delhi, is reportedly in talks with ExxonMobil Corp. to renegotiate the price of LNG it signed for from the Gorgon-Jansz project on Barrow Island offshore Western Australia.

The original 20-year contract was signed in 2009 between the two companies for 1.4 million tonnes/year of LNG.

The talks follow Petronet’s successful renegotiation of the price of an LNG contract with Qatar’s RasGas in December 2015 on the back of low global LNG prices.

The revised Qatar contract uses a 3-month average figure for Brent crude instead of the original 5-year average of a basket of crude imported by Japan. Petronet sweetened the new deal with an undertaking to buy an additional 1 million tpy of Qatari LNG.

Petronet’s 2009 Gorgon-Jansz contract with ExxonMobil was also based on a Japanese crude basket.

Petronet is an Indian government-initiated joint venture of GAIL (India) Ltd., Oil & Natural Gas Corp., Indian Oil Corp. Ltd., and Bharat Petroleum Corp. established to import LNG and build receiving and gasification terminals in the country.

The first terminal was set up at Dahej, Gujarat; the second at Kochi, Kerala. A third is under construction at Gangawaram, Andhra Pradesh.

http://www.ogj.com/articles/2016/06/petronet-tries-to-renegotiate-gorgon-lng-price.html

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Woodlands-based Anadarko said Wednesday the company is “strongly committed” to its multi-billion Mozambique LNG project despite the debt crisis in the African country and the oil price downturn.

The Mozambican government has admitted in April to the existence of USD1.4bn in undisclosed loans by the Interior Ministry and state-owned security companies Proindicus and Mozambique Asset Management.

Mozambique is estimated to hold about 100 trillion cubic feet of proved natural gas reserves.

However, Anadarko and Eni, that are developing LNG export projects in the country have still not made a final investment decision.

“We continue to be strongly committed to the Mozambique LNG project – to taking it to FID and to building and commissioning a world-class facility,” Anadarko spokesman John Christiansen told LNG World News in an emailed statement on Wednesday.

“We are aware of Mozambique’s debt issues and as the Government works to address those, we are working hard to put in place a set of agreements with the Government that will provide the foundation for definitive sales agreements with LNG customers. Once those agreements and the financing arrangements are in place, we expect to be in a position to take FID at that time,” said Christiansen.

Anadarko and partners have discovered more than 75 Tcf of recoverable natural gas resources in Mozambique’s Offshore Area 1, which will be used to feed an onshore LNG terminal on the Afungi peninsula in Cabo Delgado province.

The reserves are sufficient to support two initial LNG trains, each with capacity of 6 million tonnes per annum, as well as to accommodate expansions, including additional trains capable of producing about 50 million tonnes of LNG per year, according to Anadarko. The Mozambique LNG project has more than 8 MMTPA of non-binding LNG offtake agreements already in place.

Anadarko also announced in December it had signed a unitization and unit operating agreement to develop natural gas resources straddling the Offshore Area 1 and Offshore Area 4 blocks in Mozambique.

The deal, which frames the cooperation between the government of Mozambique, Anadarko and Eni, the operator of the Offshore Area 4, enables the advancement of the Prosperidade and Mamba straddling reservoirs.

According to Anadarko, the Prosperidade and Mamba straddling natural gas reservoirs, which comprise the unit, will be developed in a separate but coordinated manner by the two operators until 24 trillion cubic feet of natural gas reserves (12 Tcf from each area) have been developed.

Anadarko’s partners in the Offshore Area 1 are National Oil Company Empresa Nacional de Hidrocarbonetos (ENH), Mitsui E&P, Beas Rovuma Energy, BPRL Ventures Mozambique, ONGC Videsh and PTTEP Mozambique.

Eni owns an indirect stake in the Offshore Area 4 through Eni East Africa. Other partners are Galp Rovuma, Kogas, ENH and CNOOC that also owns an indirect interest through Eni East Africa.

http://www.lngworldnews.com/anadarko-says-strongly-committed-to-mozambique-lng-project/

There’s an old saying that goes like this: “Success has many fathers, but failure is an orphan.” Not long ago MDN reported that Eclipse Resources had drilled what is believed to be the longest horizontal well (on land) in the world–the 3.5 mile “Purple Hayes” Utica Shale well.

It wasn’t but a day or two and one of the companies that worked on the well to help drill it, Nine Energy, popped up to say they had a hand in that recording-breaking well.

Last week MDN told you that “snubbing” company Deep Well Services, from Pennsylvania, also helped with drilling the well.

Drilling any well is truly a team effort with many companies involved. Yesterday yet another company stepped up to claim they played a major role in drilling the Purple Hayes–Halliburton…

http://marcellusdrilling.com/2016/06/halliburton-fracked-eclipses-3-5-mile-purple-hayes-utica-well/

Fantastic news! More Marcellus and Utica Shale gas will begin flowing to the Gulf Coast, beginning today.

Some of that gas will go to the Sabine Pass LNG (liquefied natural gas) export facility owned by Cheniere Energy–the first such facility to (recently) begin exporting natural gas to other countries.

In October 2014 Boardwalk Pipeline Partners filed a request with the Federal Energy Regulatory Commission (FERC) to reverse the flow on a 690-mile segment of their Texas Gas Transmission pipeline to begin carrying Marcellus and Utica Shale gas from the northeast to the south.

In September 2015 FERC approved the project, called the Ohio-Louisiana Access Project. Today the pipeline reverses and Sabine Pass is the foundation shipper–beginning to accept 300 million cubic feet per day (Mmcf/d) of yummy and wholesome Marcellus and Utica Shale gas…

http://marcellusdrilling.com/2016/06/626-mmcfd-of-northeast-shale-gas-begins-flowing-to-gulf-today/

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Chevron’s RMP 23 and RMP 24 wells in Nigeria have been blown up, according to a Twitter statement from the Niger Delta Avengers.

Niger Delta Avengers ‎@NDAvengers

With the heavy presence of 100 Gunboats, 4 Warships and Jet Bombers NDA blew up Chevron Oil Well RMP 23 and RMP 24 3:44am this Morning.

7:12 AM - 1 Jun 2016

 
•  852852 Retweets
 
•  265265 likes

 Follow Niger Delta Avengers ‎@NDAvengers

RMP 24 and RMP 23 are Chevron Swamp Highest producing Wells. #Boom

7:23 AM - 1 Jun 2016

Chevron was not immediately available to confirm the attack.

The Niger Delta Avengers claimed responsibility for an assault on Chevron’s Escravos terminal in Nigeria May 26.

NDA used explosives to damage the Escravos tank farm main electricity feed pipeline, which resulted in Chevron’s onshore activities in the Niger Delta being shut down.

The attack followed NDA’s warning to Chevron that no repair works should be carried out to facilities previously targeted by the group, until NDA’s demands are fully met. NDA claimed on its official website May 11 that it suspected Chevron was preparing to carry out repair works at the Okan Valve platform, which was blown up by the group at the start of the month.

In an emailed response to Rigzone last week, a Chevron spokesperson said that the company will not comment on the safety and security of its personnel and operations as a matter of long-standing policy.

- See more at: http://www.rigzone.com/news/article.asp?hpf=1&a_id=144830&utm_source=GLOBAL_ENG&utm_medium=SM_TW&utm_campaign=ARTICLE#sthash.Xn9DpaCY.dpuf

The oil market is heading for a “bumpy road” with prices close to levels that are profitable for U.S. shale producers, according to Patrick Allman-Ward, chief executive officer of Dana Gas PJSC, which produces natural gas in Egypt and Iraq.

U.S. shale producers can pump crude profitably at prices of about $40 to $45 a barrel, Allman-Ward said in an interview in Dubai Wednesday. Those levels will act as a floor as prices “firm up” in the second half, he said.

Brent crude has rallied 31 percent this year on signs of a dwindling glut, partly due to high-cost producers cutting back. Demand is rising and production is being disrupted because of outages in Nigeria and Canada, according to Allman-Ward.

“It will be a bit of a bumpy road going forward,” Allman-Ward said, with prices tending to “firm up” in the second half.

The drop in prices since then may mean Dana Gas has to wait longer than planned for overdue payments owed by the Egyptian government for past gas sales, Allman-Ward said. The company, which agreed to sell Egypt’s share of condensate to recover the back debt, may be able to collect all the overdue amounts only in 2019, he said. Dana Gas could still meet its target to get paid back by the end of 2018 if prices rise, Allman-Ward said.

Dana Gas has boosted production since the end of March to about 70,000 barrels of oil equivalent a day after completing a natural gas pipeline in Egypt, he said. The 17-kilometer (11-mile) link from the Balsam field in the Nile River delta to a processing plant in Egypt allowed the company to add about 10,000 barrels of oil equivalent a day of new production capacity since the end of March, Allman-Ward said.

The company finished the pipeline ahead of schedule, allowing it to beat its own end-of-year target of reaching 70,000 barrels. Additional improvements planned at the Egyptian processing plants will help add daily capacity of 10,000 to 15,000 barrels of oil equivalent by the end of the year or in early 2017, Allman-Ward said.

Dana Gas, which received part of a nearly $2 billion arbitration award related to its Iraq business last year, will use some of that cash to pay down debt Allman-Ward said. Reducing borrowings will help cut interest costs, he said.

“The prudent thing to do is delever,” he said. “It makes sense to take out a cost element from our balance sheet.”

http://www.bloomberg.com/news/articles/2016-06-01/dana-gas-ceo-expects-bumpy-road-for-oil-as-shale-sets-floor

Husky Energy Inc, Canada's No. 3 integrated oil company, said it expected to generate free cash flow and may reinstate a cash dividend as crude oil prices have rallied in recent weeks.

The company said it could generate about C$800 million ($611.48 million) in free cash flow if oil rises to $50 from $40 per barrel on an annualized basis.

The oil producer said it was on track to complete eight projects by the end of this year, which would contribute 90,000 barrels per day of new production once fully ramped up.

Husky, controlled by Hong Kong billionaire Li Ka-shing, produces oil and natural gas in Canada and Southeast Asia, and holds numerous exploration licenses offshore of Atlantic Canada.

The company had cut its budget and production outlook and suspended quarterly dividend in January, a few months after surprising investors by switching to a stock dividend from cash payments.

Husky Energy, which has reached agreements for asset sales worth about C$2.8 billion this year, said it expected to achieve its target of about two-times net debt-to-cash flow from operations.

http://www.reuters.com/article/huskyenergy-outlook-idUSL4N18T3SH

China issues draft rules for strategic oil reserves

China is planning changes to the way it handles oil reserves by allowing private companies to build and operate some of its strategic stockpiles, while also requiring companies to maintain compulsory inventories, potentially boosting its future imports.

Beyond allowing private companies to build and operate some strategic petroleum reserves (SPR), draft rules issued by the National Energy Administration (NEA) on Tuesday will also oblige companies to keep compulsory oil reserves.

These stocks must be kept separately from commercial reserves, and the draft states that such compulsory reserves could only be used at the direction of the state council or cabinet.

The government determines the size of such mandatory reserves based on oil consumption, the rules published on the NEA website said (www.nea.gov.cn).

Although no specific volumes were published and no implementation timetable given, traders said that such requirements would boost China's oil imports further, if implemented.

"Potentially it is supportive of the oil market as it may increase imports and reduce exports of products. However, the devil is in the detail so we need a clearer picture," said Oystein Berentsen, managing director for crude at oil trading firm Strong Petroleum in Singapore.

China is the world's second-biggest crude importer, importing 32.58 million tonnes (or around 8 million barrels per day) and challenging the United States' for top spot.

China is expected to add 70-90 million barrels to its strategic crude oil purchases in 2016 as it takes advantage of low prices, a Reuters survey has shown.

By mid-2015, China had stockpiled about 190.5 million barrels under its SPR programme, or roughly one month of net crude imports.

Beijing's goal is to stockpile reserves amounting to 90 days of net imports, which is the standard for SPRs in most western countries.

In the draft rules, the government defines the country's SPRs as including government stockpiling and companies' compulsory stockpiling reserves.

China's stockpiling programme has so far been led largely by state-owned energy giants Sinopec and CNPC, with ChemChina recently striking a deal with privately-run CEFC China Energy to lease out tanks in the southern island province of Hainan.

Approval to use strategic oil reserves must come from the state council, the draft rules stipulated.

Circumstances under which the reserves may be used include during an unexpected emergency when oil supplies are either blocked or significantly reduced, or when macro-economic adjustments are needed.

The strategic oil reserves include crude oil and oil products like gasoline, diesel and jet fuel.

The NEA is seeking public feedback on the draft rules until June 18.

http://www.reuters.com/article/china-energy-strategic-oil-reserves-idUSL4N18S3W0

Bermuda-based Golar LNG, the owner and operator of liquefied natural gas carriers on Tuesday posted a loss of $80.1 million in the first quarter of this year.

The shipping company’s adjusted operating loss was at $41.2 million in the first quarter as compared to $31.6 million in the fourth quarter of 2015.

“Although headline shipping rates remained relatively unchanged, utilisation fell from 42% in 4Q 2015 to 24% in 1Q and revenue dropped accordingly from $20.1 million in 4Q of 2015 to $16.6 million in 1Q,”  Golar LNG said on Tuesday.

Weak LNG freight market

Golar noted that the weak LNG freight market continued in the early part of 2016, with the majority of fixtures coming from the Pacific basin.

However, the Pacific basin fixtures were mostly for short periods, and the largest number of idle vessels is located in the basin.  The economics turned in favour of the charterers that took advantage of the overcapacity.

There were fewer vessels and fewer fixtures in the Atlantic basin, due to subdued reload activity in Europe.

“Middle Eastern activity was light during 1Q but has picked up as we approach mid-year when the Middle East and South American importers increase gas demand,” Golar said.

Slower than expected start-ups at Sabine Pass in the U.S., Gorgon in Australia and Angola LNG in Africa have had a negative effect on the shipping market, however, vessels for the projects have been taken off the spot market.

Enarsa of Argentina recently issued a tender for 35 cargoes which stimulated chartering activity in the early part of the second quarter, although whether this results in an improvement on the first quarter remains to be seen, according to Golar.

“A gradual recovery, hand in hand with the ramp up and start-up of projects should result in improving utilisation and charter terms, initially for newbuild TFDE tonnage, and then for modern steam vessels,” Golar said.

For its part, Golar LNG decided to lay up its spot traded Golar Viking and Golar Grand, as round-trip economics result in a lower effective rate, even though rates for newbuild TFDE vessels stay at US$25,000 to $30,000 per day.

All of Golar’s ten newbuilds are currently operating inside the Cool Pool.

http://www.lngworldnews.com/golar-posts-80-million-loss-in-q1-says-lng-shipping-market-remains-weak/

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Valvoline Inc., the second-largest U.S. operator of oil-change stores, filed to sell stock in an initial public offering as parent Ashland Inc. sharpens its focus on specialty chemicals.

The sale of as much as 20 percent of Valvoline shares is being targeted for the fourth quarter with the rest of the stock to be distributed later to Ashland shareholders, the Covington, Kentucky-based chemical maker said in a statement Tuesday. Subject to investor approval, Ashland will reincorporate in Delaware as Ashland Global Holdings Inc. to minimize separation-related taxes.

The Valvoline IPO, which was first announced in September, is the latest phase of a decade-long transformation in which Ashland has sold a stake in an oil refiner and disposed of a road-paving business and a chemical-distribution operation. The company, led since last year by Chief Executive Officer William Wulfsohn, has also bought makers of specialty chemicals such as those used in pharmaceuticals, hair gels and anti-wrinkle products.

Valvoline, which had net income last year of $196.1 million on sales of $1.97 billion, traces its history to the discovery in 1866 that crude oil makes a good lubricant, according to a filing. Valvoline was trademarked six years later and was subsequently recommended for use in the Ford Model T.

The company sells lubricants through 1,050 Valvoline branded quick-lube franchises and company-owned stores, more than 30,000 retailers and 12,000 car dealers, repair shops and competing quick lube outlets. Division President Sam Mitchell was named as Valvoline CEO in September when plans for the IPO were first announced.

The new company will be based in Lexington, Kentucky, and will trade under the ticker symbol VVV.

The IPO managers are Bank of America Corp., Citigroup Inc. and Morgan Stanley.

http://www.bloomberg.com/news/articles/2016-05-31/valvoline-files-for-ipo-as-parent-focuses-on-specialty-chemicals

Four tankers carrying over 2 million barrels of U.S. crude are stuck at sea and cannot discharge at a Caribbean terminal because Venezuela's PDVSA has not yet paid supplier BP Plc, according to two sources and Thomson Reuters vessel tracking data.

The cargoes are part of a tender Petroleos de Venezuela [PDVSA.UL], known as PDVSA, awarded in March to BP and China Oil. The deal was to import some 8 million barrels of West Texas Intermediate (WTI) crude so Venezuela could dilute its extra heavy crudes and feed its Caribbean refineries.

While three cargoes for this tender were delivered in April, seven other vessels, including BP's four hired ones, are waiting to discharge, leaving up to 3.85 million barrels of WTI in limbo.

The company's cash crunch, which also affected its oil imports late last year, have added to a backlog of tankers since March due to malfunctioning loading arms at Jose, Venezuela's main crude port.

PDVSA initially offered to pay for the imports with Venezuelan oil, but negotiations for those swaps failed as the proposed loading windows and crude grades did not work for BP, a source close to the talks said.

Amid low crude prices, declining exports and a brutal recession at home, PDVSA has since 2015 delayed payments to suppliers. As a result, service firms including Schlumberger, Halliburton and Petrex have curtailed operations in the OPEC country.

The payment delays are also raising questions about who will pay for demurrage, or the daily costs for delays. Three of the BP tankers have been anchored for over 30 days.

As China already lifts Venezuelan crude as part of broader oil-for-loans deals, its companies have agreed on swaps for this tender, the sources said.

Issues with loading arms to receive tankers at Jose port have doubled wait times for shippers since March.

PDVSA said in a statement that installation of replacement equipment in the port's southern dock were successfully concluded on Tuesday.

Some 30 dirty tankers are currently waiting around PDVSA's ports in Venezuela and Curacao.

PDVSA has become one of the largest buyers of U.S. crude since last month even with a narrow arbitrage that makes most exports unattractive, analysts have said, but payment delays could stymie its bid to continue imports.

http://www.reuters.com/article/us-oil-pdvsa-bp-idUSKCN0YM2OX

U.S. total oil demand rose for the second consecutive month in March, fueled in part by the continued strength in demand for gasoline, federal data released on Tuesday showed.

U.S. oil demand rose by 2 percent, or 378,000 barrels per day, from a year ago to 19.61 million bpd, data from the U.S. Energy Information Administration showed.

The March figures mark the fourth year-over-year increase in total oil demand in the last nine months, including February's growth of 1.5 percent, EIA data shows.

The demand growth was led by gasoline, which jumped 3.8 percent, or 344,000 bpd, from a year ago to 9.4 million bpd, according to the EIA's petroleum supply monthly report.

The gasoline demand numbers were strong enough to overcome weaker demand for distillates, which fell to 2.8 percent, or 113,000 bpd, versus last year.

The U.S. Department of Transportation released figures last week that showed motorists logged 5 percent more miles on U.S. roads in March than they did a year earlier, fueling a record pace in vehicle miles traveled for the first three months of the year.

The 5 percent increase resulted in 273.4 billion miles being driven in the month, an historic high for March.

http://www.reuters.com/article/usa-oil-eia-psm-idUSL1N18S1ET

OPEC's oil output fell in May from near a record high, a Reuters survey found on Tuesday, as attacks on Nigeria's oil industry and other outages outweighed increases in Iran and Gulf members.

A rise in supply from Saudi Arabia plus Iran suggests the group's top producers remain focused on market share, following the failure of an initiative in April between OPEC and non-OPEC producers to support prices by freezing output.

With OPEC meeting in Vienna on Thursday, outages are effectively achieving the supply restraint on which producers could not agree. Those disruptions are supporting oil prices, which are close to 2016 highs, and the rally has reduced the urgency of any new attempt at deliberate supply curtailment.

"There is a tiny chance of a bullish surprise but as things stand right now, the odds are the continuation of OPEC's market-share policy," said David Hufton, of oil brokers PVM.

Supply from the Organization of the Petroleum Exporting Countries fell to 32.52 million barrels per day (bpd) this month, from 32.64 million bpd in April, according to the survey, based on shipping data and information from sources at oil companies, OPEC and consultants.

OPEC output has surged since the group abandoned in 2014 its historic role of cutting supply to prop up prices, in a shift led by Saudi Arabia. There are more indications, however, that some producers are struggling to maintain supply.

May's biggest decline occurred in Nigeria due to militant attacks on the country's oil industry. The disruption has pushed output to its lowest in more than 20 years.

Libyan output declined further due to a blockage of shipments from the port of Hariga. Loading difficulties and other problems made a further dent in Venezuela's supply, sources in the survey said.

Iraq, the fastest source of OPEC production growth in 2015, also pumped less as power outages limited southern exports, which in April were at a near-record.

Of the countries boosting output, Iran managed a further increase after the lifting of Western sanctions in January.

At 3.55 million bpd, Iranian output has more than matched the 3.50 million bpd it pumped at the end of 2011 before sanctions were tightened, according to Reuters surveys. However, any further rises will be smaller, sources said.

"Getting back to pre-sanctions output was not a problem," said a source familiar with Iranian thinking. "Getting beyond that will be harder."

Saudi Arabian output edged up to 10.25 million bpd, compared with 10.15 million bpd in April, the survey found.

"Exports are higher," said an industry source who monitors Saudi output. "But production is not really changing very much."

Other increases came from the United Arab Emirates, following the end of maintenance on oilfields, and Kuwait as supply rebounded after a three-day workers' strike in April cut output.

http://www.reuters.com/article/us-opec-oil-survey-idUSKCN0YM239

Saudi Arabian Oil Co., the world’s largest crude producer, plans to increase the capacity of its main cross-country pipeline by 40 percent as the company expands oil fields in the eastern part of the nation and builds refineries on the western coast.

Capacity of the 1,200-kilometer (746-mile) East-West pipeline will increase to 7 million barrels a day by late 2018, from 5 million barrels a day now, the company said on its Twitter account on Tuesday. The pipeline starts near Saudi Aramco’s headquarters in Dhahran to Yanbu on the west coast near the Red Sea where it’s expanding refining and petrochemical plants.

“There’s no let up in Aramco’s plans for downstream expansion, so this would help in making sure they eliminate any bottlenecks in shipping crude,” Edward Bell, a commodities analyst at lender Emirates NBD PJSC, said by phone from Dubai. “There’s room for considerable demand growth both domestically and for export.”

Saudi Arabia’s main oil deposits, including Ghawar, the world’s largest, are in the eastern part of the country. Saudi Aramco is expanding capacity at the Shaybah oil field in the Rub Al-Khali desert in southeastern Saudi Arabia by 33 percent to 1 million barrels a day. It reached full production for its 900,000 barrel-a-day Manifa field offshore in Gulf waters in 2014.

The Manifa field produces the heavy crude grade that’s processed in Aramco’s joint venture refinery with China Petrochemical Corp. at Yanbu on the Red Sea. The company is building a refinery at Jazan along the southwest coast and is considering adding units to a separate crude-processing facility at Yanbu, according to its annual review released last week.

The country’s main crude export terminal is at Ras Tanura in the Persian Gulf. The East-West pipeline gives Saudi Arabia a potential alternative outlet for crude shipments in the event of an interruption in the Strait of Hormuz. The Strait at the mouth of the Persian Gulf is the world’s most important choke point for crude exports, with about 17 million barrels of oil passing through it daily, according to the U.S. Energy Information Administration.

http://www.bloomberg.com/news/articles/2016-05-31/saudi-aramco-plans-to-boost-capacity-on-oil-pipeline-to-red-sea

North Dakota saw the number of rigs actively exploring for or producing oil and gas increase by more than 10 percent from last week, state data show.

Data from the state government show 28 rigs in service early Tuesday, up 16 percentfrom last week. The increase follows a slow march toward $50 per barrel for West Texas Intermediate, the U.S. benchmark for the price of crude oil. WTI is up about 4 percent from last week.

Crude oil prices are still about 50 percent lower than they were two years ago, leaving energy companies with less capital to invest in exploration and production. Oil services company Baker Hughes reported no change last week in the total U.S. rig count. Year-on-year, however, the total U.S. rig count is 53 percent lower than it was for the same week in 2015. For North Dakota, the rig count for Tuesday is off by 65 percent from this date last year.

North Dakota, home to the Bakken shale oil reserve, last week broke a record low for rig counts set in July 2005 with 25 in service. The all-time low point for rigs in North Dakota is zero.

Rig counts serve as a loose barometer for the health of the oil and gas industry, which has been bruised by weak economics. Hess Corp., one of the more active players in North Dakota, said its first quarter spending on exploration and production was $544 million, down nevertheless 56 percent year-on-year.

Lynn Helms, the director of the state's oil and gas division, said energy companies working in the state are committed to running only a small number of rigs.

State data show oil production in March, the last full month for which figures are available, at 1.11 million barrels per day, a decline of about 1 percent from February. Natural gas production, however, reached an all-time high for the state last month at 1.7 million cubic feet per day.

http://www.upi.com/Business_News/Energy-Industry/2016/05/31/North-Dakota-rig-count-up-more-than-10-percent/3281464693852/

Russia's Gazprom sees no need to wage gas price wars in Europe to squeeze out rivals, including expected liquefied natural gas (LNG) from the United States, Deputy Chief Executive Alexander Medvedev said on Tuesday.

Gazprom provides a third of the gas used in the European Union but relations have soured over Ukraine, prompting the EU to look for alternatives to Russian energy imports.

One potential alternative for gas is LNG from the United States where exports are expected to rise sharply between now and 2019.

"There has been a lot of talk that LNG from the United States is a panacea (for those looking to switch away) from Russian gas... But at the moment there are more preferable destinations for U.S. LNG than Europe," Medvedev said.

"Price will determine the competitiveness of U.S. LNG. I don't see U.S. LNG flowing to Poland or Portugal."

Medvedev reiterated that Gazprom's exports to the EU and Turkey may exceed a record-high 165 billion cubic metres (bcm) per year, topping deliveries of 159 bcm in 2015.

Gazprom generates more than half of its revenue in Europe where Medvedev said sales would reach $28 billion this year.

Some analysts have said that in order to preserve its market share in Europe, Gazprom would have to cut prices.

"We don't see any need to wage a pricing war," Medvedev told reporters.

He said gas prices in the second quarter would be the lowest this year but would rise from the third quarter.

Last week, he said the company sees Russian gas prices in Europe this year averaging $167 to $171 per 1,000 cubic metres. That is down from about $240 in 2015, reflecting lower crude prices hitting indexed gas pricing.

"We don't need astronomically high gas prices, we need prices which allow us to do our job," Medvedev said.

He said that Gazprom's production costs are one of the industry's lowest at around $20 per 1,000 cubic metres.

http://uk.reuters.com/article/russia-gazprom-idUKL8N18S230

Liquefied natural gas spot prices will fall to $3 per million British thermal units by mid-2017 or 2018 as new projects worsen a global glut, according to energy consultant FGE.

A bevy of new export projects scheduled to start over the next few years will create more LNG than users around the world can burn, FGE Chairman Fereidun Fesharaki said in an interview Tuesday in Singapore. Most of the direct buyers of the supply are middlemen, not end users, and they will have to offer lower and lower prices to find customers.

LNG on the spot market near Singapore has fallen 68 percent since October 2014 to $4.43 per million Btu this week, according to Singapore Exchange Ltd. Prices will have to keep declining until they drop low enough to force some producers, probably in the U.S. or Australia, to reduce output, Fesharaki said.

“Some people are going to have to lose billions,” Fesharaki said.

LNG hasn’t been as cheap as $3 since July 1999, according to import data from LNG Japan Corp., which tracks both term and spot prices for imports by world’s largest buyer of the fuel. Global LNG production capacity is expected to rise to 420 million tons a year by 2020, up from 333 million this year, Goldman Sachs Group Inc. said in February. Demand by 2020 is only expected to be about 323 million tons a year, the bank forecast.

http://www.bloomberg.com/news/articles/2016-05-31/lng-glut-seen-by-fge-pushing-prices-to-3-as-soon-as-next-year

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French oil services company Technip has signed a deal worth $500 million with a consortium that includes Libya's National Oil Company and Italy's oil and gas major ENI to refurbish an offshore oil platform.

A statement from the French foreign ministry where a Libyan delegation was visiting on Tuesday, said the platform is for the Libya's Bahr Essalam oil field off Tripoli.

The deal was signed by NOC's chief executive Mustafa Sanalla and Technip's CEO Thierry Pilenko.

http://www.reuters.com/article/libya-technip-idUSP6N13V01M

Gazprom has announced that a working meeting has taken place in Sochi, Russia, between the Chairman of the Gazprom Management Committee, Alexey Miller, and the Chairman of the Board of Directors of China National Petroleum Corp. (CNPC), Wang Yilin.

The meeting focused on planned gas supplies to China through both eastern and western routes. It also looked at possibilities regarding cooperation in underground gas storage and gas-fired power generation, as well natural gas vehicles (NGVs).

An additional meeting was held between Miller and the President of China National Offshore Oil Corp. (CNOOC), Liu Jian. This meeting looked at the possibility for cooperation in hydrocarbon exploration and production, as well as in the LNG industry.

http://www.lngindustry.com/liquefaction/31052016/Gazprom-explores-cooperation-possibilities-with-CNOOC-and-CNPC-2518/

Japan's LNG imports reached 6.4 million mt in April, down 3.3% from a year ago, led by lower supply from Qatar and Nigeria, data released Friday by the Ministry of Finance showed.

On a month-on-month basis, LNG imports also dropped 21.7% from March as the country entered shoulder months.

Shipments from Australia reached 1.8 million mt in April, up 23.2% from a year ago.

It was the largest LNG supplier with its volume representing 28% of Japan's overall imports.

Malaysia came in second, supplying 1.18 million mt in April, rising 7% from a year earlier.

Imports from Qatar plunged 30.6% year on year to 841,520 mt in April, making Qatar the third-largest LNG supplier for the month.

Shipments from Nigeria also fell 22.3% from a year earlier to 143,347 mt in April.

Japan received no reloads from Europe and the number of exporting countries to Japan shrank to 10 in April, from 14 a year ago, with Yemen LNG shut since April 2015 amid increasing security concerns around the facility.

The Japan Customs Cleared crude oil price was $36.957/b in April, down 34.1% from a year earlier but rose 15.5% from March.

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 time to be reflected in LNG prices.

http://www.platts.com/latest-news/natural-gas/tokyo/japans-lng-imports-slip-33-on-year-in-april-qatar-27595284

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The decline in domestic oil rigs resumed, with two rigs out of the count compared to last week. Total U.S. rig count remained flat with an increase of two natural gas rigs. The most interesting development was the appearance of new rigs in some of the lesser oil plays, which probably signals that producers are getting comfortable with $50/bbl oil as the baseline going forward.

But there are some new rigs in lesser plays, which probably signals that producers are getting comfortable with oil staying at the $50 level.

One new rig in Arkoma, Woodford, which went from zero rigs, to one rig.
Two new rigs in Granite Wash.

Conclusion:

The oil rig count resumed its decline, with the domestic oil rig count down by two. There's some newfound confidence by producers, consistent with $50/bbl oil, as displayed by the appearance of new rigs in some of the lesser plays, which goes against the long term trend of moving rigs to the most productive regions. Overall, however, not that much new information in this report.

http://seekingalpha.com/article/3978383-weekly-u-s-oil-rig-count-rig-repositioning

Pipeline builder Arendal S de RL has become the latest casualty of Mexico’s state-owned oil producer.

The company defaulted on a $100 million bond that was due last week after Petroleos Mexicanos deferred plans to build two pipelines and delayed payments to suppliers. Arendal depends on Pemex, as the oil giant is known, for about 80 percent of its income. In February, Fitch Rating said that Pemex owed Arendal 1.8 billion pesos ($97.4 million).

Battered by low oil prices and sinking output, Pemex owed suppliers $7.2 billion at the end of the first quarter, more than any other company in Latin America. It has extended the amount of time it takes to pay suppliers to 180 days from 20 as it cuts costs in the wake of 14 straight quarterly losses. Pemex, which has $95 billion of debt, has also slashed the day rates it pays to rent rigs, a move that triggered a default by supplier Oro Negro last year. The notes of fellow rig operator Offshore Drilling Holding SA fell to a record 29.5 cents on the dollar May 23, signaling investors are concerned it will struggle to repay the debt.

“The delays in accounts receivable pressured their working capital,” Francisco Gutierrez, an analyst at S&P Global Ratings, said, referring to Arendal. “About 90 percent of Arendal’s projects are with Pemex, which shows how vulnerable they are.”

Pemex didn’t reply to a request for comment on Arendal’s default and its treatment of its suppliers. Arendal declined to comment.

On May 16, Pemex said it had cut its debt to suppliers by 92 billion pesos. The oil producer said it prioritized payments to companies it owed less than 85 million pesos each, which covered 90 percent of the companies it was indebted to.

http://www.bloomberg.com/news/articles/2016-05-30/pemex-turmoil-batters-bond-traders-again-as-supplier-defaults

Suncor Energy Inc. restarted oil-sands operations in the Regional Municipality of Wood Buffalo, an area in Canada that includes wildfire-ravaged Fort McMurray. It’s a move that enables thousands to return to work.

Suncor and other oil-sands operators took offline this month more than 1 million barrels a day of output, as wildfires spread in the region and forced evacuations and the shutdown of pipelines and power supplies. “Cooler weather and several days of precipitation” have improved conditions, Canada’s largest energy company said in a statement on Sunday.

Alberta lifted mandatory evacuation orders for the last of the accommodation and production sites on Monday, which started the process of inspections by forestry and health officials to make sure they’re safe. Officials say industry facilities are no longer at immediate risk as firefighters take advantage of better weather to keep the flames at bay.

Suncor said 4,000 employees and contractors are back in the region, including Fort Hills workers, with an additional 3,500 people likely to return in the coming week.

The company also reported operations are under way at the base plant mine and MacKay River, with initial production expected by the end of this week, according to the statement. No timeline was given for the joint venture with Syncrude Canada Ltd.

http://www.bloomberg.com/news/articles/2016-05-29/suncor-resumes-oil-sands-operations-after-wildfire-shutdown

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Iraq will supply 5 million barrels of extra crude to its partners in June, industry sources familiar with the issue said, joining other Middle East producers by lifting market share ahead of an OPEC meeting this week.

Iraq, which is the second-largest producer in the Organization of Petroleum Exporting Countries, had already been targeting record crude export volumes from southern terminals next month of 3.47 million barrels per day.

Saudi Arabia, Kuwait, Iran and the United Arab Emirates, also plan to raise supplies in the third quarter.

A recovery in global oil prices from 12-year lows to above $50 a barrel and rivalry between Saudi Arabia and Iran have dampened expectations that OPEC will rein in supplies at Thursday's meeting.

While additional exports could make up for shrinking output and supply disruptions elsewhere, the new supplies also risk delaying a re-balancing of a global market still awash with oil.

"OPEC is indeed increasing supplies, practicing their market share first strategy," said Victor Shum, managing director of downstream energy consulting at IHS, referring to a Saudi-led drive to boost OPEC's production to take back market share.

He said that additional oil from Saudi and Iraq may slow down a re-balancing of the global market, although this could be countered by supply disruptions from other places and strong seasonal demand.

https://twitter.com/EINOilGasNews

Oil States Expected To Stick With Saudis: OPEC Reality Check

OPEC members gathering in Vienna June 2 are expected to go along with a Saudi Arabia-led policy focused on squeezing out rivals amid signs the strategy is working. That means the meeting may be less fraught than the previous summit in December, which ended with public criticism of the Saudi position from Venezuela and Iran.

By allowing prices to fall, high-cost producers are being forced out, easing the supply glut and spurring a rally of 80 percent since January to about $50 a barrel. All but one of 27 analysts surveyed by Bloomberg said the Organization of Petroleum Exporting Countries will stick with the strategy. An alternative proposal -- to freeze output -- was finally rejected in Doha last month.

The group may also choose a secretary-general to replace Abdalla El-Badri, whose term has been extended after members failed to agree on a successor. In recent months, three new hopefuls have emerged to try and break the impasse: Nigeria’s Mohammed Barkindo, Indonesia’s Mahendra Siregar and Venezuela’s Ali Rodriguez.

- See more at: http://www.rigzone.com/news/oil_gas/a/144790/Oil_States_Expected_To_Stick_With_Saudis_OPEC_Reality_Check?utm_source=GLOBAL_ENG&utm_medium=SM_TW&utm_campaign=ARTICLE#sthash.zcDpvxR0.dpuf

In two simultaneous attacks late on Thursday, the Niger Delta Avengers (NDV) have targeted a state-run crude pipeline near the Batan oilfield.

The oil and gas pipeline is near the Batan oilfield in Warri, and is operated by the state-run Nigerian National Petroleum Corporation (NNPC).

African media suggest that the attack differed strategically from the series of attacks that preceded it because this pipeline was heavily guarded by state security forces and militants were demonstrating their reach and capabilities.

The NDA claimed responsibility for the attack via its Twitter feed, its established method.

"At 11:45pm on Thursday.@NDAvengers blew up other #NNPC Gas and Crude trunkline close to Warri. Pipeline that was heavily guarded by Military," the group tweeted.

The group rejected a meeting recently convened in Abuja by the federal government, warning of its readiness to carry out an attack that will "shock the whole world".

"The Niger Delta stakeholder's meeting is an insult to the people of Niger Delta. What we need is a Sovereign State not pipeline Contracts,” NDA said.

"To the IOC's, Indigenous Oil Companies and Nigeria Military. Watch out something big is about to happen and it will shock the whole world."

Related: Why Canada’s Oil Sand Producers Will Recover Quickly From The Wildfires

On Wednesday, the militant group blew up the main electricity feed pipeline at Chevron’s Escravos terminal, taking the terminal offline.

Nigeria’s oil production has plunged by 40 percent, falling to just 1.4 million barrels per day, the lowest level in decades

Last week, Italian oil giant Eni declared force majeure after another attack on its AGIP pipeline took oil offline. Earlier this month, Shell also declared force majeure on its exports of Bonny Light crude, evacuating staff from its Eja OML 79 production facility.

The first week of May saw militants attack one of Chevron’s offshore platforms, the Okan facility, disrupting 90,000 barrels per day of oil production. The Okan facility, which it operates in conjunction with the Nigerian National Petroleum Corp., is also a gathering point for production from several fields, so the attack knocked off output from all of them at once.

http://oilprice.com/Latest-Energy-News/World-News/Two-More-Militant-Attacks-on-Nigerian-Crude-Pipeline-More-Barrels-Offline.html?utm_source=twitterfeed&utm_medium=twitter&utm_campaign=Feed%3A+oilpricecom+%28Oil+Price.com+Daily+News+Update%29

Russia’s oil sector has shown a surprising resilience to low oil prices and western sanctions over the past two years. The country’s output repeatedly hit new record highs despite various negative outlooks.

This surprising pattern could well be repeated both this year and next should certain projects overcome delays and greenfields ramp up output.

Independent research group Vygon Consulting, in its May study, said oil production in Russia is likely to continue growing not only this year — as was forecast by many market observers — but also next year.

On top of this, the consultancy sees Russian crude production hitting the 11.3 million b/d level next year. If so, it will get close to Russia’s all-time high, recorded in 1987. This is well above other most optimistic estimates.

A general consensus sees Russia’s crude production continuing to grow this year by around 100,000 b/d or even slightly above this figure. The growth is supported by investments made in previous years.

Next year, however, output is expected to remain flat or even drop by around the same 100,000 b/d, as greenfields no longer compensate for growing natural decline at mature fields in West Siberia. This view is shared by many market experts both in Russia and abroad, although forecasted figures do differ somewhat.

Russian and international estimates are not directly comparable due to use of different conversion factors for Russian crude and condensate volumes reported in mt.

The International Energy Agency, for example, has warned that while Russia’s oil resource base is weakening, the commissioning of new fields is likely to be delayed in the coming years due to capex constraints and rising fiscal pressures, making it increasingly challenging for oil producers to maintain crude output.

Vygon Consulting, however, believes that several new projects that are scheduled for commission both this and next year are unlikely to be delayed as they are ready to launch and key capital investments have already been committed to them.

These projects include the Filanovskogo field in the Caspian Sea and the Messoyakha field in northern Siberia, set to come online by the end of this year and a number of new fields expected to start in 2017.

In addition, already commissioned greenfields, including in the Arctic, could increase output to become drivers of crude production growth next year.
 
As a result, the consultancy estimates, crude production from greenfields is likely to jump to nearly 1.5 million b/d, or 85%, in 2017, from its 2015 level, which would fully compensate for the natural decline elsewhere.

Indeed, this outlook is much higher than the level of natural decline at old fields in Russia, with different estimates putting output at between 100,000 b/d and 400,000 b/d in 2015.

The problem is that crude production in West Siberia is falling by around 3.5-4% a year, despite the sharp increase in drilling and wider use of enhanced oil recovery technologies seen last year. If those operations are reduced due to companies’ financial constraints, the natural decline could accelerate drastically.

So far, however, production drilling — including the drilling of horizontal wells — is still on the rise as oil companies’ operations are supported by flexible taxation and the forex rate of ruble to dollar, mitigating cuts in oil prices.

But there is the risk that Russia’s authorities could opt to increase the tax burden on oil companies to resolve budget problems.

And while at present governmental officials have said there are no plans to raise these taxes, a different approach might prevail when the government considers how to meet the 2017 budget in the autumn.

If the tax burden is increased, the outlook for Russia’s crude production could be quite different from that of current forecasts.

http://blogs.platts.com/2016/05/27/russia-crude-oil-output-surprise/?hootPostID=ab5a8fa890a7e61770e544073b40e3b8

Hercules Offshore Inc said it planned to file for prepackaged Chapter 11 bankruptcy, just six months after the rig contractor emerged from bankruptcy protection.

The company said it had entered into a restructuring support agreement with some lenders, which will eventually allow it to place all its unsold assets into a wind-down vehicle until they can be sold.

Hercules Offshore said its international units would not be included in the bankruptcy filing, but would be a part of the sale process.

The company said in February that it was considering strategic options, including selling itself.

Hercules filed for Chapter 11 bankruptcy protection in August 2015 and emerged from bankruptcy in November.

"Since this time, the ongoing decline in oil prices, the consolidation of its U.S. customer base and the addition of new capacity have negatively impacted dayrates and demand for Hercules's services," the company said in a statement.

http://www.reuters.com/article/hercules-offshre-bankruptcy-idUSL3N18O422