Saudi Arabia trims exports to a 21-month low in February as local refineries took advantage of more abundant supplies and processed a record amount of crude.

(Bloomberg) -- Saudi Arabia, the world’s largest crude shipper, trimmed exports to a 21-month low in February as local refineries took advantage of more abundant supplies and processed a record amount of crude.

Oil exports fell to 6.95 million barrels a day, the lowest since May 2015, from 7.7 million a day in January, according to data published Tuesday on the Riyadh-based Joint Organisations Data Initiative website. The kingdom boosted production to 10 million barrels a day from 9.7 million a day, the data show.

Saudi Arabia is bearing the brunt of the output cuts that members of the Organization of Petroleum Exporting Countries pledged to make in the first six months of this year. It committed to pump no more than 10.058 million barrels a day, as OPEC and other major producers sought to rein in global oversupply and support prices.

Saudi refineries increased the amount of crude they processed in the month by 26 percent to 2.67 million barrels a day, the highest in JODI data going back to January 2002. The amount of crude used directly as fuel in power plants and other facilities also rose, as did volume in storage. Stockpiles increased to 264.7 million barrels at the end of February from almost 262 million barrels in January.

Saudi Arabian Oil Co. was planning an 80-day maintenance work at its Riyadh refinery starting in late February to last through mid-May, according to two people with knowledge of the situation. The refinery has capacity to process 120,000 barrels of crude a day, according to data compiled by Bloomberg.

“It seems that Aramco is preparing for the long shutdown of the Riyadh refinery by increasing production from other refineries as they need to keep some products in stocks while the refinery is closed,” said Mohamed Ramady, an independent London-based analyst. “The amount of crude not being processed at the Riyadh refinery is reflected in the oil stockpiles in February as they increased from January.”

The country plans to double refining capacity to as much as 10 million barrels a day within 10 years, Saudi Energy Minister Khalid Al-Falih has said. Saudi Arabian Oil Co., the state producer known as Saudi Aramco, expects to start operating a 400,000 barrel-a-day refinery next year at Jazan on the Red Sea, adding to two other plants of the same size that have come online since 2013.

http://www.rigzone.com/news/oil_gas/a/149763/Saudi_Oil_Exports_Drop_to_2015_Low_as_Kingdom_Sticks_to_Cuts?utm_source=GLOBAL_ENG&utm_medium=SM_TW&utm_campaign=FANS

China is inching closer to imposing a consumption tax on mixed aromatics, light cycle oil and bitumen blend, a move that will likely curb inflows of those products and stem surging oil product exports by Asia's biggest oil consumer.

The planned policy change will also likely increase China's imports of lighter crudes for gasoline production to offset the squeeze in the blending pool if consumption taxes are imposed, market participants told S&P global Platts.

Beijing is widely expected to levy consumption taxes on mixed aromatics and light cycle oil. Although there has been no official confirmation, market participants expect details to be released some time between May 1 and July 1.

Sources with knowledge of the matter said the consumption taxes for mixed aromatics, LCO and bitumen blend would use the current consumption taxes on gasoline, gasoil and fuel oil as a reference; these currently stand at Yuan 1.52/liter, Yuan 1.20/liter and Yuan 1.20/liter respectively.

"This means importers will have to pay Yuan 1,000-2,000/mt more for importing those products, which is expected to largely curb inflows of these grades, just like what happened to fuel oil a few years ago," a market source said.

China's fuel oil imports have fallen dramatically since Beijing imposed the consumption tax in 2008.

Mixed aromatics is the main blending material for gasoline, and LCO for gasoil. Bitumen blend is a mixture of fuel oil and heavy crude, which can be used as a refining feedstock.

"Blending profit will immediately be eliminated due to the consumption tax," said one Guangzhou-based importer.

China's imports of mixed aromatics and LCO have surged in recent years, as both are currently free of consumption tax. China's mixed aromatics imports jumped 81.4% year on year to 11.7 million mt in 2016, while LCO imports soared 135% to 4.46 million mt, General Administration of Customs data showed.

The mixed aromatics inflows in 2016 translated roughly into 39 million mt of gasoline supply from the blending pool, in addition to the official output of 129.32 mt from refineries. LCO inflows resulted in an additional 10 million mt of gasoil supply on top of the 179.18 million mt output from refineries.

The impact on bitumen blend import volumes from a consumption tax is expected to be softer as imports of the grade have been sliding since 2015, when independent refineries started using crude oil as feedstock. China imported around 3.69 million mt of bitumen blend in 2016, down 72.5% year on year, according to customs data.

OIL PRODUCT EXPORTS TO SLOW

According to Platts China Oil Analytics, huge imports of blending components into China resulted in "hidden demand" last year as blended fuels were not captured by official production data.

"We estimate that gasoil and gasoline demand last year was understated by at least 290,000 b/d and this did not include finished grades produced by independent fuel blenders, which is difficult to quantify," it said in a report issued April 11.

The additional supply from the blending pool was responsible for pushing up China's gasoline and gasoil exports by 64% and 114% year on year respectively in 2016 to 9.7 million mt and 15.4 million mt.

When the consumption tax takes effect, China's exports of gasoline are expected to drop, as refineries would need to boost supply to the domestic market to make up for the supply cut from oil blenders, sources said.

"Once the import window for mixed aromatics is closed, less gasoline will be available for export out of China," said a Beijing-based analyst.

A Singapore-based market observer said gasoil exports would be somewhat sustained as LCO accounted for a relatively smaller portion of the gasoil pool. Mixed aromatics makes up a crucial portion of the gasoline pool.

However, China is unlikely to have adequate gasoline or gasoil inflow to compensate for the supply reduction from blenders, because Beijing has suspended issuing import quotas for these products in 2017, except for a small volume with special specifications for car racing.

"Despite pushing for deregulation in the refining sector by encouraging more players into the market to compete on a level playing field, the theme is veering toward control and consolidation, with the government now appearing to take an active stand to curb exports," Platts China Oil Analytics said in the report.

TRICKLE-DOWN IMPACT ON FREIGHT

Plans to impose consumption taxes on mixed aromatics and light cycle oil are already taking a toll on freight rates for Medium Range tankers, brokers across East and North Asia said.

Large numbers of mixed aromatic cargoes are shipped out of Singapore to China in MR tankers. These tankers then load distillates for delivery to Singapore, the Philippines and South Korea, among other destinations.

The proposed consumption tax, refinery turnarounds and lower export quota volumes for oil products from China have started to hurt freight rates for MRs across the region.

"The MR market is collapsing," said a broker in Seoul.

The lump sum freight on the South Korea-Japan route was assessed last Friday at $290,000, down 27% from $395,000 at the start of the year, Platts data showed.

The South Korea-Hong Kong and the Singapore-Hong Kong rates were assessed at $250,000 and $260,000 respectively, down from $325,000 and $320,000 at the start of the year, the data showed.

"Exports [of distillates] from China have been slow from end March," said an MR broker in Singapore. Prompt ships are in oversupply, he added.

Meanwhile, domestic refineries in China, especially state-owned refineries, are expected to benefit from the move, as the heavy tax on mixed aromatics and LCO would eliminate competition from oil blenders, sources said. "Once China imposes consumption taxes on mixed aromatics and LCO, the country's gasoline and gasoil needs have to be increasingly met by refineries, especially state-owned refineries," a source with a Singapore trading house said.

"Independent refineries are also expected to benefit from less competition from oil blenders," the source added.

A source with state-owned Sinopec Guangzhou refinery said: "Our domestic sales of gasoline will increase if the news turns out to be true. We will raise output too."

http://www.platts.com/latest-news/oil/singapore/analysis-china-seen-moving-swiftly-to-rein-in-27815627

Brazilian state-owned oil company Petrobras has said that its total production of oil and natural gas in March was 2.74 million barrels of oil equivalent per day (boed), of which, 2.61 million boed produced in Brazil and 130,000 boed produced abroad.

Average oil production in the country was 2.12 million barrels per day (bpd). This volume represents a 3% drop compared to February, mainly due to maintenance stoppages on FPSO Cidade de Angra dos Reis, located in Lula field, in the Santos Basin pre-salt, and on P-37, in Marlim field, in the Campos Basin. The company’s domestic oil output was also down in February for a similar reason, the stoppage of the FPSO Cidade de Paraty.

In March, the production of natural gas in Brazil, excluding the liquefied volume, was 77.7 million m³/d, 3% lower than in the previous month due to the mentioned stoppages.
 
Pre-salt production
 
In March, the production of oil and natural gas operated by Petrobras in the pre-salt layer, own portion and that of partners, was 1.50 million boed, volume 2% lower than in the previous month due to the stoppage on FPSO Cidade de Angra dos Reis.

Compared to March 2016, there was a 36% production increase mainly due to the beginning of production on FPSO Cidade de Saquarema, in the Lula Central area, and on FPSO Cidade de Caraguatatuba, in Lapa field, in addition to the production increase on FPSO Cidade de Marica, in the Lula Alto area, during the period.
 
Production of oil and natural gas abroad
 
In March, oil production in overseas fields was 66,000 bpd, volume 4% higher than in the previous month. This performance resulted mainly from the return to production after stoppages in Lucius and Hadrian South fields, in the US, which took place in February.

Natural gas production was 11.0 million m³/day, a 31% increase over the volume produced in February 2017. This increase resulted from a greater demand of gas production in Bolivia and from the resumption of production in Lucius and Hadrian South fields.

http://www.offshoreenergytoday.com/petrobras-oil-output-suffers-due-to-fpso-stoppage/

A Brazilian court is blocking the transfer of Petrobras’ stake in the BM-S-8 offshore exploration block, which contains the Carcará oil field, to the Norwegian oil company Statoil.

According to a Monday statement by the Brazilian oil giant, the 2nd Federal District Court, Sergipe state, granted an injunction to suspend the transfer of the stake to Statoil and the exploration of the field, until further court deliberation.

The Brazilian and the Norwegian oil company agreed last July for Statoil to acquire Petrobras’ 66% operated interest of the BM-S-8 offshore license in Brazil’s Santos basin for $2.5 billion. The acquisition included a substantial part of the Carcará oil discovery, which Statoil claimed to be one of the largest discoveries in the world in recent years.

Statoil estimated the recoverable volumes within the BM-S-8 license to be in the range of 700 to 1,300 million boe. BM-S-8 holds exploration upside that may significantly increase its resource base. The license was in its final exploration phase with one remaining exploration commitment well to be drilled by 2018.

On completion of the transaction in November, Statoil paid Petrobras $1.25 billion, which is half of the total consideration, with the remainder paid at the passage of certain future milestones.

In the statement on Monday, Petrobras also noted that this transaction had already been finalized after the fulfillment of all the precedent conditions set forth in the contract, with no restrictions, such as approval by the Administrative Council for Economic Defense (Cade) and by the National Agency of Petroleum, Natural Gas and Biofuels (ANP).

Furthermore, the Brazilian company stated that the amount received after the closing of the transaction was used in full for early settlement of part of the financing contract between Transportadora Associada de Gás S.A. (TAG), a wholly-owned Petrobras subsidiary, and the National Bank for Economic and Social Development (BNDES), where such a measure was adopted to reduce its indebtedness.

Petrobras added that it will take the appropriate legal action on behalf of its investors and own interests.

Sale ‘result of competitive process’

Offshore Energy Today has reached out to the Norwegian oil company seeking further details about the suspension and the company’s course of action.

A spokesperson for Statoil confirmed the court suspended the Carcará sale process and all activities related to it.

When asked about the reason behind the suspension, the spokesperson said: “We cannot speculate in the reason for this decision, but are confident that Brazilian institutions will confirm the legality of the transaction and Statoil will take appropriate actions to support this.

“The deal was a result of a competitive process as part of Petrobras’ divestment plan and the deal was closed on 22 November 2016. It has been approved by the Brazilian anti-trust agency (CADE), the National Petroleum Agency (ANP) as well as the partners in the license.

“Statoil was also named in the decision and we are currently evaluating our next steps.”

Further regarding the reason for the suspension, Reuters reported that the National Federation of Oil Workers said it had filed the lawsuit because Petrobras, as a state-controlled enterprise, is required to hold an open bid for any asset sale.

http://www.offshoreenergytoday.com/brazilian-court-suspends-petrobras-field-sale-to-statoil/

Australian LNG player Woodside said its Karratha gas plant had suffered an unexpected production outage on Saturday.

“At approximately 11.30am on Saturday 15 April, Karratha gas plant experienced a production outage. No injuries were sustained during the incident and everyone is accounted for,” Woodside said in a statement trough its social media channels.

“People in the Karratha area will have seen black smoke from the KGP flare towers. This is a safety function used during a production outage,” the company added.

Woodside said that the cause of the outage was being investigated. The company did not provide any additional information.

The Karratha gas plant is located some 1260 kilometres north of Perth, Western Australia. It is a part of the North West Shelf project facilities.

The Karratha gas plant facilities include five LNG processing trains, two domestic gas trains, six condensate stabilisation units, three LPG fractionation units as well as storage and loading facilities.

It has an annual LNG export capacity of 16.9 mtpa which is supplied mainly to companies in the Asia Pacific region.

Woodside operates these facilities on behalf of the NWS project participants. Other NWS JV partners are BHP Billiton, BP, Chevron, Japan Australia LNG (MIMI) and Shell.

http://www.lngworldnews.com/woodsides-karratha-gas-plant-suffers-production-outage/

US-based energy giant Chevron began restart activities at its Gorgon LNG project’s second liquefaction train.

“Restart activities are underway on Gorgon train 2. We continue to produce LNG from trains 1 and 3 and load LNG cargoes,” Chevron’s spokeswoman told LNG World News.

No exact deadline for the Train 2 production restart has been given.

Chevron suspended production at its second liquefaction train at the Gorgon LNG plant at the end of last month to carry out maintenance to “improve the train’s capacity and reliability.”

The $54 billion Gorgon LNG project is operated by Chevron that owns a 47.3 percent stake, while other shareholders are ExxonMobil (25 percent), Shell (25 percent), Osaka Gas (1.25 percent), Tokyo Gas (1 percent) and Chubu Electric Power (0.417 percent).

http://www.lngworldnews.com/chevron-begins-gorgon-lng-train-2-restart/

ConocoPhillips is negotiating with potential buyers for the company's mothballed liquefied natural gas plant at Nikiski, on the Kenai Peninsula south of Anchorage, a company spokeswoman said Monday.

The plant, which has a capacity to manufacture up to 1.5 million mt/year of LNG, was built in 1968 by Phillips Petroleum and made regular shipments of LNG to Tokyo Gas and Tokyo Electric under long-term contracts until 2012, when the contracts expired.

Periodic shipments have been made to Japan and South Korea since then on a spot-sale basis, the last being in 2015.

ConocoPhillips put the plant up for sale in November and also recently sold the North Cook Inlet gas field, which supplies gas to the plant.

"We had requested that initial bids be submitted by March 17. The data room that was set up to market the Kenai LNG Facilities is closed and we have received interest," company spokeswomen Amy Jennings Burnett said in a statement.

"We are currently evaluating the bids to determine next steps. We believe the plant is a strategic asset that offers good opportunities for the right buyer," she said.

Although LNG prices in Asia are currently low the plant does provide a potential market for companies now exploring and developing new gas discoveries in Cook Inlet. The regional utility market is now supplied by contracts extending beyond 2025 and unless there is a way to market new gas, such as through LNG exports, future development may be stymied, state officials have said.

Phillips and Marathon Oil built the LNG plant in the 1960s as a way of marketing Cook Inlet gas discoveries that were stranded at the time. When exports began these were the world's first long-distance shipments of LNG and Japan's first imports of LNG.

http://www.platts.com/latest-news/natural-gas/anchorage-alaska/conocophillips-has-potential-buyers-for-lng-plant-21463831

The Platts JKM for May LNG averaged $5.454/MMBtu over the March 16 to April 13 assessment period, down 10.3% from the previous month.

Oversupply concerns added to the downward pressure earlier in the assessment period but following supply outages at the Pacific Basin's Sakhalin 2 and Gorgon projects, it recouped some of the losses. Higher oil prices also helped provide support.

UK National Balancing Point hub front-month gas futures averaged $4.977/MMBtu over the JKM May assessment period and the JKM-NBP spread narrowed to $0.488/MMBtu from $0.630/MMBtu a month earlier.

Production at the Sakhalin-2 LNG plant was suspended after an accident at one of its platforms.

Sources said Japanese utilities with long-term volumes tied to the Sakhalin and Chevron-operated Gorgon projects were encouraged to pick up some shipments in case of long cargo delays and continued cold weather at home.

Sporadic demand was also observed from South Korea and India.

India's IOC issued a two-cargo buy tender for H1 and H2 June while its peer Gail also launched a tender looking for an early May cargo. In South Korea, SK E&S was looking for at least two May cargoes.

In Asia, some end-users were said to have relatively low stocks and so might look for spot cargoes, although it was not clear how firm their requirements would be.

In the Atlantic, production at Angola LNG appeared robust and since March 27, Angola has launched four tenders.

Supply was ample in the Atlantic, thanks to volumes from the Sabine Pass liquefaction project on the US Gulf Coast, although traders said not many of them had been directed to Asia as yet.

In the Middle East, Egypt's Egas was said to be trying to defer 2017 cargoes to 2018 due to increased domestic gas production, particularly from the North Alexandria Concession controlled by BP.

The number of cargoes that would be affected was unclear, with sources saying that 10 to more than 20 cargoes would be rolled into next year.

http://www.platts.com/latest-news/natural-gas/tokyo/jkm-monthly-may-delivery-lng-averages-5454mmbtu-27814408

ExxonMobil plans to ramp up natural gas production from the Vaca Muerta shale play in Neuquen, Argentina, the governor of that province said.

Neuquen Governor Omar Gutierrez said he met with senior executives of Exxon and its XTO unit in Houston, Texas, last week during a road show to promote a series of tenders for 56 blocks in the southwestern province, according to a statement Monday.

The Irving, Texas-based company "is evaluating the potential of gas development in the Los Toldos 1 Sur block," and is poised to request a 35-year production license for the block, Gutierrez said.

Exxon's focus is to be on developing gas from Vaca Muerta, among the world's most promising shale plays, where the company will have invested $750 million by the end of this year, the governor added.

Exxon was not available for immediate comment on the governor's statement.

The focus on gas has been driven by an extension of pricing incentives this year through 2021, as the quicker a company can get a block into production, the more they can profit from the higher prices, Gutierrez said.

The incentives are designed to pay producers $7.50/MMBtu for output through 2018 and then gradually decline to $6/MMBtu in 2021, before free-market pricing takes effect in 2022, when prices are expected to average $4/MMBtu, or about $1/MMBtu less than current market averages.

The pricing incentives, which started in 2013, have led a rise in output from Vaca Muerta and several tight plays to 123 million cu m/d in 2016, up 8.2% from a 10-year low of 113.7 million cu m/d in 2014, according to Energy Ministry data.

Gutierrez said Exxon plans to enter into the production phase in May, without specifying on what block. The company will drill horizontal wells with laterals of 2,500-3,000 meters (8,202-9,843 feet), he added.

By tapping into its experience in US shale plays and using advanced technology, Exxon and XTO expect to "accelerate gas production" to reach 5 million cu m/d in the next two to three years from the blocks it operates or has stakes in, according to the statement.

Last year, XTO launched a pilot project on the combined blocks of Bajo del Choique and La Invernada with an investment of about $250 million. If the results prove promising, an additional $13.8 billion will be invested in the development of the combined block by drilling 556 horizontal wells, each with 2,500-meter legs and 25 frac stages, according to the company's investment plan approved by the Neuquen government in 2015.

Exxon is part of a new wave of investment in Vaca Muerta that gained speed this year after the governments of Argentina and Neuquen reached an agreement with companies and labor unions to extend the gas pricing incentives, cap tax pressure, improve labor productivity and expand infrastructure capacity. The aim is to bring down drilling and completion costs, helping to boost profit potential.

Tecpetrol, a leading local producer, recently announced a $2.3 billion investment to ramp up gas production to 10 million cu m/d from a Vaca Muerta block over the next three years.

Gutierrez has said he expects more companies to come forward with investment plans this year, initially with a focus on gas.

The country expects to close a 30% gas deficit by 2021-22, allowing it to resume exports to the region.

Neuquen produces 20% of the country's 510,000 b/d of oil and 48% of its gas, according to data from the Argentina Oil and Gas Institute, an industry group.

http://www.platts.com/latest-news/natural-gas/buenosaires/exxon-plans-to-boost-shale-gas-output-in-argentina-21478331

Venezuela's state-run oil company, PDVSA, sent a tanker in October to the Caribbean with the expectation that its cargo of crude would fetch about $20 million - money the crisis-stricken nation desperately needs.

Instead, the owner of the tanker, the Russian state-owned shipping conglomerate Sovcomflot, held the oil in hopes of collecting partial payment on $30 million that it says PDVSA owes for unpaid shipping fees.

Despite a longstanding alliance between Venezuela and Russia, Sovcomflot sued PDVSA in St. Maarten, a Dutch island on the northeast end of the Caribbean.

"The ship owners ... imposed garnishment on the aforementioned oil cargo," reads a March decision by the St. Maarten court.

Five months after crossing the Caribbean, the NS Columbus discharged its cargo of crude at a storage terminal on St. Eustatius, an island just south of St. Maarten, under a temporary decision by the court. Another tribunal in England will decide if Sovcomflot will ultimately take the oil.

The dispute, which is being heard by the United Kingdom Admiralty Court, highlights how shipping companies are becoming increasingly aggressive in pursuing PDVSA's debts.

It also shows that political allies such as Russia are losing patience with delinquent payments from Venezuela, whose obsolete tankers are struggling to export oil and even to supply fuel to the domestic market.

PDVSA also owes millions of dollars to Caribbean terminals - including the one in Saint Eustatius, which is owned by U.S. NuStar Energy, according to a PDVSA executive and an employee at one of the facilities.

NuStar and a lawyer representing subsidiaries of Sovcomflot declined to comment. The Russian conglomerate PDVSA did not respond to requests for comment.

PDVSA did not respond to written questions regarding its tanker fleet or its debts to shipping companies.

PDVSA's tangled web of payment disputes now spans the globe, from unpaid shipyards in Portugal and half-built tankers in Iran and Brazil to the seized cargo in tiny St. Eustatius, whose strategic location in the Caribbean made it an 18th century colonial-era trading hub.

DEBTS TO RUSSIA

The oil price crash starting in 2014 hit Venezuela particularly hard. Once a paradise of oil-fueled consumption, the OPEC nation is now a Soviet-style economy of empty supermarket shelves and snaking food queues.

Russia has consistently supported President Nicolas Maduro with financing arrangements and oilfield investments. State-run oil firm Rosneft has lent money to PDVSA since 2016 and last month was in talks to help PDVSA make a hefty bond payment, according to Venezuelan government and banking sources.

But problems had been brewing for months between Venezuela and Sovcomflot, which provides about 15 percent of vessels that PDVSA charters to ship crude to its clients amid a steady deterioration of its own fleet, according to a captain and two shipbrokers working with PDVSA.

Debts to Sovcomflot had by 2016 swelled enough that company's top brass complained in person to PDVSA President Eulogio Del Pino in the Russian city of Sochi, according to source from PDVSA's trade department with knowledge of the meeting.

Del Pino agreed to a payment schedule proposed by his trade and fleet executives and accepted by Sovcomflot, the source said. But PDVSA - saddled with heavy bond payments and billions of dollars in unpaid bills to oilfield services providers - was unable to make sufficient payments to avoid Sovcomflot's unusually public debt-collection gambit.

A PDVSA representative denied that Del Pino was confronted by Sovcomflot in Sochi, saying the account was false, without elaborating.

Detentions of oil cargoes have been unusual because creditors rarely have sufficiently detailed information on tanker movements to obtain timely court orders.

Venezuela also tends to ensure that any cargoes that leave its ports legally belong to the clients rather than to PDVSA, meaning they are rarely in a position to be seized.

The Sovcomflot dispute was different in that the creditors are the tanker owners. Although the crude onboard the NS Columbus had already been sold to Norway's Statoil, the cargo was being carried in a tanker navigating with a bill of lading under PDVSA's name, according to two inspectors and a representative of one of the companies involved.

http://www.reuters.com/article/venezuela-oil-tankers-seizure-idUSL1N1HQ03Q

Oil prices fell on Tuesday, then slid more in post-settlement trade after an industry group reported that U.S. crude stockpiles fell less than expected in the latest week while gasoline stockpiles grew unseasonably.

U.S. crude prices were down more than 1 percent at $52.32 a barrel in post-settlement trade after the American Petroleum Institute released its weekly data, indicating that crude stockpiles declined less than analysts had forecast.

Oil futures fell during the trading session, touching their lowest in 11 days as the U.S. government reported that shale oil output in May was expected to post the biggest monthly increase in more than two years.

The oil market has been caught in a tug-of-war, with OPEC production cuts supporting prices while signs of rising U.S. production have pressured crude on concerns about a glut. On Tuesday, U.S. West Texas Intermediate crude touched a low of $52.10 before bouncing on suggestions that Saudi Arabia is holding crude off the market.

"We're right at the battle ground: the bulls and the bears are facing off against each other, trying to make their last stand," said John Kilduff, Partner at Again Capital in New York.

Global benchmark Brent crude futures swooned as low as $54.61, the lowest since April 7, then settled down 47 cents at $54.89 a barrel.

U.S. WTI futures settled at $52.41 a barrel, down 24 cents. U.S. crude's intraday low was also the weakest since April 7.

At a time when OPEC and other producing nations have been trying to cut output, government drilling data showed U.S. shale production next month was set to rise to 5.19 million barrels per day (bpd). Output from the Permian play, the country's largest shale region, was expected to reach a record 2.36 million bpd.

Members of the Organization of the Petroleum Exporting Countries are cutting oil production 1.2 million bpd from Jan. 1 for six months, the first reduction in eight years.

"The battle between the 'sheiks and the shale oil producers' is far from decided ... with all attempts by OPEC to achieve a lasting production deficit on the oil market being torpedoed by non-OPEC producers – first and foremost the U.S.," analysts at Commerzbank wrote.

The energy minister of OPEC member the United Arab Emirates predicted healthy oil demand growth this year and said inventories would fall, but it would take time.

OPEC leader Saudi Arabia tightened February crude oil exports to the lowest since mid-2015, official data showed.

"We've fought to a draw today and the inventory report will help break us out of this logjam," Kilduff said.

The market will watch Wednesday morning to see if U.S. government data confirms the API report. A Reuters poll showed analysts expected data to show U.S. crude stocks fell in the week to April 14.

http://www.reuters.com/article/us-global-oil-idUSKBN17K046

Philadelphia Energy Solutions Inc, the largest refiner on the U.S. East Coast, will not be taking any rail deliveries of North Dakota's Bakken crude oil in June, a source familiar with delivery schedules said on Tuesday - a sign that the impending start of the Dakota Access Pipeline is upending trade flows.

At its peak, PES would have routinely taken about 3 miles' worth of trains filled with Bakken oil each day. But after the $3.8 billion Dakota Access Pipeline begins interstate crude oil delivery on May 14, it will be more lucrative for producers to transport oil to refineries in the U.S. Gulf Coast.

The long-delayed pipeline will provide a boost for Bakken prices and unofficially end the crude-by-rail boom that revived U.S. East Coast refining operations several years ago.

"It's the new reality," said Taylor Robinson, president of PLG Consulting. "Unless there's an unforeseen event, like a supply disruption, there will be no economic incentive to rail Bakken to the East Coast."

PES declined to comment for this story.

The 1,172-mile (1,885-km) Dakota Access line runs from western North Dakota to a transfer point in Patoka, Illinois. From there, the 450,000 barrel per day line will connect to large refineries in the Nederland and Port Arthur, Texas, area.

The project became a focus of international attention, drawing protesters from around the world, after a Native American tribe sued to block completion of the final link of the pipeline through a remote part of North Dakota.

The Standing Rock Sioux tribe said the pipeline would desecrate a sacred burial ground and that any oil leak would poison the tribe's water supply.

But after U.S. President Donald Trump took office in January, one of his first acts was to sign an executive order that reversed a decision by the Obama administration to delay approval of the pipeline. The tribe also lost several lawsuits aimed at stopping the project led by Energy Transfer Partners LP.

PES has scheduled just five rail deliveries of crude for May and none for June at its facility in Philadelphia, according to the source familiar with the plant's operations, who spoke on condition of anonymity because they are not authorized to speak about company operations. Deliveries are often scheduled months in advance to manage logistics like storage and manpower.

In recent months, PES was getting roughly one unit train per day, the equivalent of 75,000 barrels a day. During the boom years between 2013 and 2015, PES would routinely receive three trains a day of Bakken.

PES and other refiners built large rail terminals on the East Coast in recent years to accommodate cheap Bakken flowing from North Dakota. The PES refinery terminal, which opened in 2013, was able to handle roughly 280,000 barrels a day, making it the largest on the U.S. East Coast.

Rail volumes of Bakken crude peaked at 420,000 bpd, resulting in bumper profits for those refiners. But Bakken crude's discount to U.S. crude slowly eroded as pipeline capacity out of North Dakota expanded, increasing competition for the heavy oil.

That forced the East Coast to rely more heavily on foreign, waterborne crude. Currently, Bakken barrels at the delivery point in Nederland, Texas, in June are trading around $1.25 to $1.50 a barrel over U.S. crude futures. Higher rail costs would boost those barrels to $7 to $8 more than U.S. crude.

The East Coast has averaged roughly 100,000 bpd of crude rail deliveries in recent weeks, according to energy industry intelligence service Genscape.

Monroe Energy, a subsidiary of Delta Air Lines, stopped receiving Bakken by rail for its 185,000 bpd refinery outside Philadelphia in January of last year. East Coast refineries operated by Phillips 66 and PBF Energy are still receiving modest volumes of Bakken crude.

"At this point, there are no good reasons to rail crude to the East Coast," said Sarah Emerson, a managing principal at ESAI Energy LLC, a consultancy.

http://www.reuters.com/article/us-north-dakota-pipeline-pes-idUSKBN17L0BJ

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