Friday, September 29, 2017

Average U.S. Gas Price Drops 7 Cents as Refineries Bounce Back

A customer prepares to fuel her vehicle at a Road Ranger gas station in Princeton, Illinois, U.S., on Tuesday, June 17, 2014. Gasoline in the U.S. climbed this week, boosted by a surge in oil, and is expected to reach the highest level for this time of year since 2008.

The average price of a gallon of regular-grade gasoline fell 7 cents nationally over the past two weeks, to $2.62.

Industry analyst Trilby Lundberg of the Lundberg Survey said Sunday that the drop comes as flooded refineries continue to come back online after devastation caused by Hurricane Harvey.

Lundberg says she expects prices will continue to fall in the next few weeks.

Gas in San Francisco was the highest in the contiguous United States at an average of $3.18 a gallon. The lowest was in St. Louis at $2.19 a gallon.

The U.S. average diesel price is $2.51, down 2 cents from two weeks ago.

Thursday, September 28, 2017

State-owned NPDC now Nigeria’s fifth largest oil producer – Official

The Nigerian National Petroleum Corporation, NNPC, on Monday named its upstream oil exploration and production subsidiary, the Nigerian Petroleum Development Company, NPDC, as the fifth largest oil producer in Nigeria.

The NPDC Managing Director, Yusuf Matashi, said in Benin that the company which currently produces 180,000 barrels per day, bpd, plans to grow its equity production to 300,000 bpd by 2018; 400,000 bpd by 2019 and 500,000 bpd by 2020.

“Having attained the position as fifth largest Exploration and Production Oil Producer in the Nigeria, due to the ongoing transformation in NNPC, I am confident the NPDC will efficiently manage its portfolios to achieve the new targets,” he said.

Mr. Matashi did not mention the four companies ahead of NPDC. 

Industry data list Shell Petroleum Development Company, SPDC as accounting for Nigeria’s highest oil production capacity among the joint venture operating companies with the NNPC, over 900,000 bpd.

The others include Exonmobil Corporation, with about 600,000bpd; Chevron Nigeria Limited, CNL, with over 400,000 bpd and Nigerian Agip Oil Company, NAOC, with about 250,000 bpd.

The NPDC, he pointed out, controls 55 per cent equity in nine Oil Mining Leases, OMLs in the country, namely 4, 26, 30, 34, 38, 40, 41, 42 and 55, apart from non-equity operations in three oil blocks of selected NNPC Joint Venture fields.

Besides, there are also 60 per cent participatory interest in four OMLs, including 60, 61, 62 and 63, in addition to 100 per cent ownership of seven OMLs, including 11, 13, 64, 65, 66, 111 and 119.
This brings to its involvement in a total of 29 oil concessions, comprising 22 OMLs and seven Oil Prospecting leases, OPLs.

The NPDC, he said, with varied interests in seven deep-water concessions, also successfully executed a Global Memorandum of Understanding, GMoUs, with communities in OMLs 30 and 34.

Again, he said the company achieved a major feat recently by successfully drilling and completing five horizontal wells in nine months, in OML 26, leading to the production of an additional 7,000 bpd.

Other achievement included successful turnaround of OML 40 asset from zero to 12,000 bpd to underline the company’s rising profile as the seventh largest owner and operator of Floating Production Storage and Offloading, FPSO in Nigeria, with FPSO Mystra having 1.03 million of crude production capacity.

In addition, Mr. Matashi said the NPDC also carried out some intervention activities which led to the peak production of approximately 10,000 bpd in OML 65 in June 2017.

In the gas sector, he said the NPDC at the moment was not only the country’s largest gas producer but also the highest supplier to the domestic market.

“NPDC aggressive gas pursuit since 2009 has also raised its profile as the highest single supplier of gas to the domestic market with an average of 700 million standard cubic feet per day,” Mr. Matashi said.

“With the recent completion of the Utorogu non-Associated Gas 2 plant, about 150 million standard cubic feet of gas per day, mmscf/d added to the system; the Oredo 2 gas plant also added 100 mmscfd, while the successful re-entry of Odidi gas plant brought additional 40 mmscfd of gas,” he said.

Wednesday, September 27, 2017

Rising Demand Will Continue To Drive The Rally In Crude Oil Prices

A worker, wearing a hardhat featuring a Union Flag, also known as a Union Jack, stands near the drill rig at the Preston New Road pilot gas well site, operated by Cuadrilla Resources Ltd., near Blackpool, U.K., on Tuesday, Sept. 19, 2017. Cuadrilla started drilling the pilot well that is expected to reach depth of 3,500 meters, a core sample will be taken from the well and examined to determine where to drill the horizontal well it intends to frack. Photographer: Matthew Lloyd/Bloomberg

As the rally in oil prices gathers steam, it's important to place the quoted prices in context.  The price most frequently quoted for "crude oil" is the front-month West Texas Intermediate contract.  So, today's oil price of "$52 per barrel" is the value of the contract for delivery at the hub in Cushing, OK by November 30th, a contract that settles on October 20th. The lag between the settlement date and the delivery date represents the necessity to transport the physical commodity.

So, there's really no "spot" price for crude in the Western world, as it doesn't settle on a day of/cash basis.  U.S. oil producers are compensated for their output based on the value of the futures contract for the month corresponding to the delivery of the oil.  Of course those producers use futures along the forward curve to hedge production in upcoming periods.

That type of market doesn't necessarily exist around the world.  Saudi Arabia, for instance, sells its crude to China on a price that it sets monthly with an eye on oil futures, specifically for Brent crude. Other, less-developed oil nations sell at prices that more closely resemble a true spot market price.

This has given rise to a theory, propagated most widely by Goldman Sachs, that OPEC is trying to engineer backwardation, a situation in which future month oil contracts trade at lower values than current ones.  In the past week's rally the oil futures curve has indeed moved into backwardation, albeit slightly so, as the October 2018 contract is trading 17 cents below the November 2017 contract as of this writing.  As oil is physical commodity that has a storage cost, the curve is usually upward-sloping  (a situation known as contango) and as U.S producers hedge future production based on the curve, lower future prices hurt hedgers more than those who sell in the spot market.

One might wonder if September's move in oil futures is a product of a Saudi-led drive to restrain U.S. oil production by getting American producers to lock in future production prices at lower prices than current ones.  Goldman has been pushing this theory, but as I noted in this column, I often take the other side of Goldman's commodity calls.  My move into extremely bullish positions on stocks of oil producers at the end of August was at odds with Goldman's Post-Harvey analysis and has been a very lucrative one for my clients.

Quite simply, oil prices are rising because demand is increasing.  Commodities analysts can navel-gaze about the shape of the forward curve ad nauseum, but those same analysts have consistently underestimated demand for oil and its refined products.   The International Energy Administration last week increased its global oil demand forecast for 2017 for the third time in three months.  It receives much less publicity, but this week's petroleum supply report from the U.S. Energy Information Administration showed motor gasoline product supplied rose 0.6% on a year-on-year basis  last week.  Product supplied is the closest indicator to actual U.S. gasoline consumption, and after running at or slightly below zero growth for much of 2017 that indicator has turned solidly positive in recent weeks.

So, the IEA confirms that growth outside the U.S. is rising and the EIA confirms that U.S. demand for petroleum products is rising.  That's bullish, and if traders haven't figured out that this demand increase is going to last more than a month or two eventually they will have to.  Then the oil markets will move back into contango, and there really is nothing stopping a move in U.S. crude to $60/barrel, a level nearly reached by international benchmark Brent crude this week.

I'll have stock plays for this rising environment in my next Forbes column.

Monday, September 25, 2017

Life After Steel in the UK's Most Polluted Town: Rule Britannia

Oil Traders Empty Key Crude Storage Hub

Oil traders are emptying one of the world’s largest crude storage facilities, located near the southernmost tip of Africa, as the physical market tightens amid booming demand and OPEC production cuts.

Total SA, Vitol Group and Mercuria Energy Group Ltd. are selling crude they hoarded in Saldanha Bay, South Africa, during the 2015-2016 glut when the market effectively paid traders to store oil, according to people familiar with the matter, who asked not to be named discussing private operations.

Crude demand is now seasonally outstripping supply, tightening the physical market for some crude varieties to levels not seen in the last two years and encouraging traders to sell their stored oil.

“The market is selling inventories from everywhere,” Mercuria Chief Executive Officer Marco Dunand said in an interview in Geneva.

Although largely unknown outside the oil trading industry, Saldanha Bay is one of the world’s largest crude storage facilities, with the capacity to hold 45 million barrels in just six gigantic, partially-buried concrete tanks.

By comparison, Cushing, the better-known U.S. oil storage center in Oklahoma that serves as the pricing point for the West Texas Intermediate oil benchmark, can hold about 75 million barrels in more than 125 tanks.

Saldanha Storage

Mercuria, which operates a blending operation at the South African terminal, has been offering cargoes from the facility, with China the likeliest destination, according to traders with knowledge of matter. Total has also been seeking tankers primarily to load Nigeria’s Escravos crude from its tank in Saldanha Bay. In addition, Vitol has been unwinding its crude stores at both Saldanha Bay and in northwest Europe, the traders said.

Vitol and Mercuria declined to comment on their Saldanha operations. Total didn’t immediately respond to a request for comment.

The structure of the Brent crude oil market has strengthened into so-called backwardation -- when near-term prices are more expensive than those in later months, indicating tighter supply. For most of 2015, 2016 and earlier this year, the Brent market was in the opposite condition, known as contango, which encourages stockpiling. Contango allows traders to buy crude, put it into storage and lock-in a profit for a future sale by hedging forward.

“Backwardation is going to increase a bit,” Dunand said in the Sept. 15 interview. “We are seeing a reduction in global inventories, although we can see another build-up in the first quarter of next year,” he added.

Brent futures for the nearest month have risen to a premium of about 30 cents a barrel to those the following month, meaning that timespread is in backwardation. In early July, that spread was in a contango of about 30 cents a barrel. Other key timespreads, including the price difference between the December 2017 and December 2018 contracts -- a popular yardstick for measuring market conditions -- have also moved into backwardation.

Market Re-balancing

The shift of the Brent curve toward backwardation is "proof that the oil market is re-balancing," said Amrita Sen, chief oil analyst at consultant Energy Aspects Ltd. in London. "Physical crude differentials are strong globally."

Mercuria’s Dunand said he expects oil prices to move "in a $50-to-$60 a barrel price range" for the time being. He added that in addition to the stockpile build-up in the first quarter of next year, there could be another one in the second quarter.

OPEC officials, along with other big oil producers including Russia, are gathering this week for a meeting to review progress on production curbs agreed last year. The review will help OPEC and non-OPEC oil ministers when they meet in Vienna on Nov. 30 to decide whether to extend their production cuts beyond March 2018.

After months of pessimism, some oil traders see the potential for higher prices next year. Asked at an industry conference in Geneva last week whether he would buy or sell Brent at $60 a barrel on average next year, Trafigura Group Chief Financial Officer Christophe Salmon said: “I will buy that.” - Research, Market and Expand Your Presence within the Tank Storage Industry

Friday, September 22, 2017

VLCCs- bearish Winter outlook

VLCC freight rates have fallen to year-to-date lows in recent weeks, as this tanker sector remains awash with tonnage, despite growing demand for cargo shipments.
For the remainder of the year, we are likely to see weakness, relative to previous years, persist through the seasonally stronger winter period, McQuilling Services said in a report.

Rates out of the Arabian Gulf to the East (TD3, TD1) remained pressured by an oversupply of tonnage, as OPEC cuts removed demand and cargoes to the West remained below previous years.

Year-to-date, TD1 freight payable by charterers has fallen 33% from 2016 levels to average $2.1 mill, while TD3 has fallen a more modest 23% to average $2.3 mill. The Caribbean/Singapore route has dropped by just below $1 mill (20%) year-on-year to average $3.8 mill.

Far East refinery crude intake is poised to grow by 360,000 barrels per day year-on-year, supported by stronger utilisation and a 100,000 barrels per day expansion in crude capacity. Chinese refinery intake is on track to average 11.5 mill barrels per day during the last four months of this year, supporting VLCC trading to the East.

We note that intake fell to a nine month low in August, following a typical seasonal trend and pressured by weaker refinery margins and re-start issues after maintenance. Up to now, government oversight within this sector has been limited; however, a recent fatal incident at a petrochemicals plant has caused the shutdown of refineries in the Shandong area.

JBC Energy has estimated that 570,000 barrels per day of primary crude distillation capacity is offline, as a result of inspections while an additional 310,000 barrels per day of primary refining capacity has been implicated in having violated safety codes. Inspections are likely to continue until October.

In addition, we have observed demand pressures stemming from the delayed start of two refineries with a combined 460,000 barrels per day of crude capacity. Over the remainder of the year, we expect these developments, as well as a slowdown in Chinese SPR building to pressure tanker demand, McQuilling said.

In its base case, the consultancy expected SPR levels to rise about 75 mill barrels by December, 2018, which combined with refinery demand, implies imports around 8.4 mill barrels per day for the remainder of 2017 and 8.7 mill barrels per day for 2018.

The largest demand generator for the VLCC sector, Middle East/Far East, is expected to experience marginal growth this year, as the pace of demand growth in the East far exceeds supply growth in the Middle East.

Middle Eastern crude supply will continue to be pressured by OPEC productions cuts, falling 535,000 barrels per day this year and opening the door for more Atlantic Basin flows to the East, as pricing arbitrages open up.

West African crude supply is projected to rise by 130,000 barrels per day year-on-year; however, export growth from these two regions (ME and WAF) is expected to trail Asian and Indian demand growth.

McQuilling forecast a deficit of about 350,000 barrels per day over the final four months of the year , supporting its view that Atlantic Basin barrels will balance this deficit with a strong preference for US, European and Brazilian crudes.

The US Energy Information Administration (EIA) put domestic crude production at an average of 9.6 mill barrels per day through the remainder of the year, while 2018 production is expected at an average of 9.9 mill barrels per day.

EIA also expects net imports (imports-exports) to average 6.3 mill barrels per day over the final four months of the year. Using this information, McQuilling has developed a short-term US crude export forecast, which calls for export volumes to average around one million barrels per day over the final four months of the year.

In February, we observed a surge in US crude exports, which correlated with higher US Gulf/Caribbean liftings, as VLCCs were seen to be co-loading US and Caribbean crude for discharge in the East. We noted that some US Gulf port delays from Hurricane Harvey may impede the flow of export cargoes in the near-term; however, recent reports show conditions were improving within the region and were likely to support a peak in US crude export during October’s lifting period, McQuilling said.

Interest to source US crude is primarily arbitrage driven and is likely to remain high, as the WTI/Brent spread has widened well above the $5 per barrel mark this month, which may support higher US crude export volumes as operations in the Gulf resume to normal levels.

The consultancy forecast around 50 US VLCC cargoes out of the Gulf this year; however, this will not fill the imbalance, therefore volumes will likely be sourced from Brazil, which is projected to add about 200,000 barrels per day of crude output this year, although short-term supply crunches may stem from increased refinery intake.

Additional support for tanker demand has stemmed from a recent rise in both Northern and Southern European barrels to the East amid higher crude supply in the Black Sea and Mediterranean.

Looking forward, McQuilling expected VLCC rate bifurcation (splitting between AG and Atlantic Basin) during the winter months, as fundamentals in the Atlantic Basin were likely to prove beneficial for rates on West loadings.

While we expect this market to fare a bit better than the Arabian Gulf, we must keep in mind that the rate upturn for this Winter season is likely to remain below previous years, as the market remains over-supplied with tonnage, despite the recent increase in scrapping activity, as another 16 vessels are left to join the fleet this year, McQuilling said.

We forecast TD3 to average WS69 in December, which on a lumpsum basis would equate to about $2.8 mill in freight, a 33% drop year-on-year. On the TD15 West Africa trade, December freight is expected to fall by a more modest 26% to $4.1 mill basis WS74. For owners looking to the Caribbean, we expect freight rates for discharge in Singapore to remain relatively unchanged year-on-year at around $4.9 mill in December, McQuilling concluded.

Thursday, September 21, 2017

Oil rangebound as unease builds ahead of OPEC meeting
The Philadelphia Energy Solutions oil refinery owned by The Carlyle Group is seen at sunset in Philadelphia March 26, 2014. Picture taken March 26, 2014. REUTERS/David M. Parrott/File Photo

Oil prices were largely steady on Thursday as traders waited to see whether oil-producing countries set to meet in Vienna would extend production limits that have helped reduce the global crude glut. 

Ministers from the Organization of the Petroleum Exporting Countries, Russia and other producers meeting in Vienna on Friday, will discuss a possible extension of a deal to cut 1.8 million barrels per day (bpd) of supply to support prices and will consider monitoring exports to assess compliance. 

While many analysts expect them to extend the deal that currently lasts until March, many also said prices at current levels could encourage some countries to boost production. 

Even if the deal is extended, “compliance looks to be a bit of an issue” if prices rise much from current levels, said John Kilduff, partner at Again Capital LLC in New York. 

He noted that oil prices have surged more than 15 percent over the last three months as global supply has tightened. 

“The bull run in the oil market is running out of steam as unease builds ahead of tomorrow’s OPEC/non-OPEC meeting,” said Stephen Brennock, analyst at London brokerage PVM Oil Associates. 

By 12:23 p.m. ET (1623 GMT), global benchmark Brent crude LCOc1 had dipped 5 cents a barrel, or 0.09 pct, to $56.24 a barrel. U.S. crude CLc1 was down 14 cents, or 0.28 percent, at $50.55 a barrel.
“We’re a little rangebound and choppy, not too much of a direction,” said Tariq Zahir, a trader with Tyche Capital Advisors in New York. 

After a strong rise in prices over the last three months, he said, there were signs that output was rising especially among U.S. shale producers. 

OPEC’s output cuts have boosted prices enough to encourage higher production elsewhere. U.S. shale production, especially, has been growing to record highs. 

Hurricanes in the Gulf of Mexico have also pushed up crude inventories in some parts of the United States as refineries have been shut by flooding. 

U.S. crude production has reached 9.51 million bpd, up from 8.78 million bpd after Hurricane Harvey hit the U.S. Gulf. 

Rising U.S. production is “a reminder to the market that OPEC has a significant problem on its hands from the continued rise in shale output,” Kilduff said. 

Front-month Brent futures have risen sharply in recent months, much more than forward prices and the contango, a symptom of an oversupplied market, has gradually disappeared from most crude markets to be replaced by backwardation, a sign of tightness.

Brent futures have traded in a sustained backwardation, where the back months are cheaper than the front month contract, for the first time since oil prices started slumping in July 2014. 

Brent’s backwardation, initially confined to the contracts nearest expiry, now extends throughout the whole of next year. 

Additional reporting by Christopher Johnson in London, Henning Gloystein in Singapore; Editing by Marguerita Choy and Alexander Smith

Our Standards:The Thomson Reuters Trust Principles.

Wednesday, September 20, 2017

The Mexican Market for U.S. Petroleum Grows 
 Oil company investments in Mexico have been growing, and firms such as Exxon, Chevron, and BP are planning to open direct-sale service stations in Mexico.

For U.S. oil companies, there is a growing belief that there is gold to be made in Mexico, partly because of energy reforms in Mexico and an ending of the U.S. ban on petroleum exports in December 2015.

Joe Gorder, the CEO of San Antonio-based Valero Energy Corporation, last week told a free trade group that his company is “aggressively pursuing” new business opportunities in Mexico. The energy reforms will not only allow foreign companies a greater opportunity to export oil to Mexico, but also will allow them to directly serve Mexican consumers.

“Valero does a lot of business in Mexico, but with the reforms that have been implemented, we can now not only sell the barrels to Mexico but we can control the barrels and own the barrels in Mexico and move them further inland,” Gorder said, according to the San Antonio Business Journal.

President Trump in June announced that the Department of Energy had given the green light to the construction of NuStar Energy LP’s New Burgos Pipeline to haul 108,000 barrels a day of gasoline and diesel fuel from Edinburg to Pemex’s Burgos processing play in Reynosa, replacing tanker trucks that currently do the job. While the pipeline is only 46 miles long, it is expected to improve the flow of petroleum products to Mexico.

In an aside, Trump joked about the pipeline crossing his proposed wall with Mexico. “My administration has just approved the construction of a new petroleum pipeline to Mexico, which will further boost American energy exports, and that will go right under the wall, right?” Trump said, making digging motions. “Have it go down a little deeper in that one section.”

U.S. crude oil and petroleum exports to Mexico hit a low of 6.3 million barrels a month in April 2009. The lowest monthly export number to date in 2017 has been 26.5 million barrels. In 2016 the U.S. export value was more than twice the value of energy imports from Mexico, according to the U.S. Energy Information Administration.

Oil company investments in Mexico have been growing, and firms such as Exxon, Chevron, and BP are planning to open direct-sale service stations in Mexico. Also, major offshore discoveries have been made in the past year. But much of the change has come from President Enrique Peña Nieto’s energy reforms, and he is due to leave office next year. The leading candidate to replace him at the moment is Andrés Manuel López Obrador, who is promising to hold a referendum on the energy reforms. López Obrador complains that the energy reforms have not reduced fuel or electricity prices as promised.

Tuesday, September 19, 2017

Trelleborg Fluid Handling Solutions: For floating LNG Terminals

Cryogenic floating hoses open up frontiers in LNG transfer

Vincent Lagarrigue, Director, Trelleborg Oil and Marine explains how a rapidly diversifying LNG market requires transfer solutions to evolve to keep pace

While global demand for LNG (liquefied natural gas) shows little sign of slowing, demand patterns are changing, requiring increasing flexibility from those who transport and transfer this fuel. According to a recent study, global demand for LNG is projected to increase by a factor of 50% by 2020, compared to 2014. While traditional import hubs such as India and China are leading this charge, several new LNG importers including Poland, Jordan, Malta, and Pakistan have emerged in the last two years. In addition, remote, developing regions in Indonesia and the Philippines are looking to LNG to fill the energy gap where access to the main grid is limited or unreliable, or where power generation capabilities are restricted.

In delivering LNG to these more remote areas, the fuel needs to be split into smaller load parcels to reach regions that are not connected to an existing pipeline grid. This is driving diversification in the global LNG-carrying fleet, with a growing segment of smaller vessels emerging and a greater need for options in ship-to-shore transfer. Today, the live LNG fleet of around 500 vessels includes 26 FSRUs and 33 small-scale LNG ships of 30,000m³ or less – and the number in this smaller fleet is increasing.

Offshore elements remain vital. FLNG (Floating LNG) projects are picking up, and FSRU (Floating Storage and Regasification Units) continue to be essential links in the LNG supply chain. As the LNG network expands, ship-to-ship loading and offloading continues to push into remote locations, deeper waters and harsher conditions.

These trends are accompanied by the rise of LNG’s use as a marine fuel. Over 100 vessels are now running on LNG – and demand will only grow in line with regulations such as the 2020 global sulphur cap and the expansions of emissions control areas (ECA). This again requires more flexible transport of LNG in smaller packages, and an expansion of ship-to-ship and ship-to-shore transfer options to ensure safe LNG bunkering that will not impact already congested ports.

The combination of these factors means we need to rethink LNG transfer. Traditional thinking has been that LNG vessels would moor at the dockside and use a jetty platform for ship-to-shore transfers, or use bridging arms for ship-to-ship transfers. While effective in certain situations, the trends outlined above mean that LNG transfer must take place in environments where this type of infrastructure would be prohibitively expensive, either due to harsh conditions, or because waters are too deep or shallow to allow a jetty to be constructed. In addition, many existing terminals set up for larger carriers, may not be equipped to handle transfer to and from smaller vessels.

This is where the latest LNG hose technology holds the key to unlocking a wider range of transfer possibilities. Because LNG needs to be transported at a temperature of -163 degrees Celsius, LNG transfer solutions require specialised cryogenic hosing to safely transfer LNG to regasification plants, and as such, considerable research has gone into the development of cryogenic hoses. Cryogenic floating hoses in particular enable a range of new transfer options.

Composite LNG hoses typically consist of multiple, unbonded, polymeric film and woven fabric layers encapsulated between two stainless steel wire helices – one internal and one external. Essentially, the film layers provide a fluid-tight barrier to the conveyed product, with the mechanical strength of the hose coming from woven fabric layers. The number and arrangement of multiple polymeric film and woven fabric layers is specific to the hose size and application. The polymeric film and fabric materials are selected to be compatible with the conveyed product and the operating temperatures likely to be encountered.

Additionally, insulated hoses - such as Trelleborg’s Cryoline range - can reduce boil-off by as much as 60%, equating to a saving of 10 billion btu’s of energy over the course of 500 transfers. The outer protective hose draws on flexible rubber-bonded hose technology, which is well-known for its high resistance to fatigue and its ability to withstand harsh environmental conditions.

The flexibility and high flow rates achievable by cryogenic hose technology increase the economic feasibility of power generation, terminal, and marine bunkering projects which are located away from existing infrastructure – particularly in areas where jetty-based transfer would be unfeasible because of harsh conditions or environmental concerns. A major advantage of hose-in-hose technology is that it can negate the need for large scale fixed onshore infrastructures; a concrete platform onshore combined with Cryoline hose transfer solutions offers an alternative in locations where fixed onshore infrastructure costs would be prohibitive.

The options further expand when combined with a floating platform. This increases the operability of the terminal, as the hose and platform can be retracted when not needed, or when harsh weather conditions would present hazards. They can function either as standalone units, or enhance a larger terminal’s ability to handle deliveries from smaller vessels.

Similarly, in offshore environments, cryogenic hose technology allows transfer to occur in deeper seas and in more challenging conditions. Cryogenic floating hoses can be used in a tandem configuration, significantly increasing the distance between the vessels involved – by approximately 100 – 150 metres for FLNG to carrier transfers, and 300-500 metres for carrier to FSRU offloading transfers. These extended distances play an important role in mitigating the risk of collision – as does the fact that the high flow rates afforded by the hose technology significantly reduce the length of the transfer operation, further lowering risk.

As LNG evolves and its uses diversify it must shift from a niche power source to a ubiquitous part of the global energy mix. If LNG is to reach its full potential, it is vital that transfer technology keeps pace; cryogenic hose technology is demonstrating that transfer innovations can match the ubiquity and flexibility of the fuel itself.

A video about Trelleborg’s range of cryogenic hoses is available here

Monday, September 18, 2017

Evidence of spills at toxic site during floods

The U.S. government received reports of three spills at one of Houston's dirtiest Superfund toxic waste sites in the days after the drenching rains from Hurricane Harvey finally stopped. Aerial photos reviewed by The Associated Press show dark-colored water surrounding the site as the floods receded, flowing through Vince Bayou and into a ship channel.

The reported spills, which have been not publicly detailed, occurred at U.S. Oil Recovery, a former petroleum industry waste processing plant contaminated with a dangerous brew of cancer-causing chemicals. On Aug. 29, the day Harvey's rains stopped, a county pollution control team sent photos to the Environmental Protection Agency of three large concrete tanks flooded with water. That led PRP Group, the company overseeing the ongoing cleanup, to call a federal emergency hotline to report a spill affecting nearby Vince Bayou.

Over the next several days, the company reported two more spills of potentially contaminated storm water from U.S. Oil Recovery, according to reports and call logs obtained by the AP from the U.S. Coast Guard, which operates the National Response Center hotline. The EPA requires that spills of oil or hazardous substances in quantities that may be harmful to public health or the environment be immediately reported to the 24-hour hotline when public waterways are threatened.

The EPA has not publicly acknowledged the three spills that PRP Group reported to the Coast Guard. The agency said an on-scene coordinator was at the site last Wednesday and found no evidence that material had washed off the site. The EPA says it is still assessing the scene.

The AP reported in the days after Harvey that at least seven Superfund sites in and around Houston were underwater during the record-shattering storm. Journalists surveyed the sites by boat, vehicle and on foot. U.S. Oil Recovery was not one of the sites visited by AP. EPA said at the time that its personnel had been unable to reach the sites, though they surveyed the locations using aerial photos.
Following AP's report, EPA has been highlighting the federal agency's response to the flooding at Superfund sites. EPA Administrator Scott Pruitt reiterated that safeguarding the intensely-polluted sites is among his top priorities during a visit Friday to the San Jacinto River Waste Pits, one of the sites AP reported about two weeks ago.

Pruitt then boarded a Coast Guard aircraft for an aerial tour of other nearby Superfund sites flooded by Harvey, including U.S. Oil Recovery.

Photos taken Aug. 31 by the National Oceanic and Atmospheric Administration shows dark-colored water surrounding the site two days after the first spill was reported to the government hotline. While the photos do not prove contaminated materials leaked from U.S. Oil Recovery, they do show that as the murky floodwaters receded, they flowed through Vince Bayou and emptied into a ship channel that leads to the San Jacinto River. The hotline caller identified Vince Bayou as the waterway affected by a spill of unknown material in unknown amounts.

Thomas Voltaggio, a retired EPA official who oversaw Superfund cleanups and emergency responses for more than two decades, reviewed the aerial photos, hotline reports and other documents obtained by AP.

"It is intuitively obvious that the rains and floods of the magnitude that occurred during Hurricane Harvey would have resulted in some level of contamination having been released to the environment," said Voltaggio, who is now a private consultant. "Any contamination in those tanks would likely have entered Vince Bayou and potentially the Houston Ship Channel."

He said the amount of contaminants spread from the site during the storm will likely never be known, making the environmental impact difficult to measure. The Houston Ship Channel was already a polluted waterway, with Texas state health officials warning that women of childbearing age and children should not eat fish or crabs caught there because of contamination from dioxins and PCBs.

PRP Group, the corporation formed to oversee the cleanup at U.S. Oil Recovery, said it reported the spills as legally required but said subsequent testing of storm water remaining in the affected tanks showed it met federal drinking water standards. The company declined to provide AP copies of those lab reports or a list of specific chemicals for which it tested, saying the EPA was expected to release that information soon.

U.S. Oil Recovery was shut down in 2010 after regulators determined operations there posed an environmental threat to Vince Bayou, which flows through the property in Pasadena. Pollution at the former hazardous waste treatment plant is so bad that Texas prosecutors charged the company's owner, Klaus Genssler, with five criminal felonies. The German native fled the United States and is considered a fugitive. Genssler did not respond to efforts to contact him last week through his social media accounts or an email account linked to his website address.

More than 100 companies that sent hazardous materials and oily waste to U.S. Oil Recovery for processing are now paying for the multimillion-dollar cleanup there through a court-monitored settlement, including Baker Hughes Oilfield Operations Inc., U.S. Steel Corp. and Dow Chemical Co.
Past sampling of materials at the site revealed high concentrations of hazardous chemicals linked to cancer, such as benzene, ethylbenzene and trichloroethylene. The site also potentially contains toxic heavy metals, including mercury and arsenic.

A 2012 EPA study of the more than 500 Superfund sites across the United States located in flood zones specifically noted the risk that floodwaters might carry away and spread toxic materials over a wider area.

Over the past six years, remediation efforts at U.S. Oil Recovery have focused on the northern half of the site, including demolishing contaminated structures, removing an estimated 500 tons of sludge and hauling away more than 1,000 abandoned containers of waste.

PRP Group said the southern portion of the site, including the three waste tanks that flooded during Harvey, has not yet been fully cleaned. Over the years workers have removed more than 1.5 million gallons of liquid waste — enough to fill nearly three Olympic-sized swimming pools.

AP began asking the EPA whether contaminated material might have again leaked from U.S. Oil Recovery last week, after reviewing the aerial photos taken Aug. 31. The EPA said it visited the site on Sept. 4, nearly a week after site operators reported an initial spill, and again the following week. The EPA said that its staff saw no evidence that toxins had washed away from the scene during either visit.

"Yesterday, an EPA On-scene coordinator conducted an inspection of Vince Bayou to follow up on a rumor that material was offsite and did not find any evidence of a black oily discharge or material from the U.S. Oil Recovery site," an EPA media release said on Thursday.

PRP Group said the spills occurred at the toxic waste site on Aug. 29, Sept. 6 and Sept. 7. One of the EPA's media releases on Sept. 9, more than 11 days after the first call was made to the hotline, made reference to overflowing water at the scene, but did not describe it as a spill.

The company said it reported the first spill after Harvey's floodwaters swamped the three tanks, filling them. The resulting pressure that built up in the tanks dislodged plugs blocking a series of interconnecting pipes, causing the second and third spills reported to the hotline the following week.

The company does not know how much material leaked from the tanks, soaking into the soil or flowing into nearby Vince Bayou. As part of its post-storm cleanup workers have vacuumed 63 truckloads holding about 315,000 gallons from the tanks.

The Superfund site is located just a few hundred yards from the Pollution Control Services offices for Harris County, which includes Houston. Its director, Bob Allen, says his team took pictures of the flooding on Aug. 29, when the area that includes the three big tanks was still underwater. Allen said his staff did not note any black water or oily sheen on the surface at the time.

"We knew that the water probably got into the plant, probably washed out some of the stuff that was in the clarifier," Allen said, referring to one of the old concrete tanks once used to store toxic waste. Allen's team did not collect samples Aug. 29. He said the EPA later sampled the area to determine whether there was contamination.
"Once they get done with the assessment of that site and the other Superfund Harris County sites, then they'll probably let us know, let the public know, what's been going on," Allen said.

Biesecker reported from Washington. Associated Press reporters Reese Dunklin in Dallas and Jeff Horwitz in Washington contributed to this reporting.

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Oil Lingers Below $50 With Refiners Slowing, Producers Hedging

Oil hit a wall again, failing to sustain a rally above $50 a barrel for a third straight session. 

That’s partly because demand typically drops this time of year as many crude-processing plants shut down in the fall for maintenance. But it’s also because producers are coming to the futures market whenever West Texas Intermediate prices approach $50 to lock in profits. While that protects them against a slump, it also makes it more difficult for futures to rise further. Meanwhile, for the third time this month, a hurricane is heading toward the Caribbean.

“We are moving into the autumn period and that typically is a weaker period seasonally for oil demand,” Harry Tchilinguirian, head of commodity markets strategy at BNP Paribas SA in London, said by telephone. At the same time, “$50 is pretty much the magic number which oil producers come in and hedge. The price of WTI is up against a wall, a producer hedge wall, and it’s going to be difficult to overcome that.”
While oil’s peaks above $50 have so far failed to stick, futures have gained some strength after the Organization of Petroleum Exporting Countries and the International Energy Agency boosted their forecasts for global demand last week. In the U.S., shale producers are set to churn a record 6.08 million barrels a day in October, according to the Energy Information Administration.

WTI for October delivery rose 2 cents to settle at $49.91 a barrel on the New York Mercantile Exchange. Total volume traded was about 18 percent below the 100-day average.

Brent for November settlement fell 14 cents to end the session at $55.48 a barrel on the London-based ICE Futures Europe exchange. The global benchmark crude traded at a premium of $5.13 to November WTI.

U.S. refineries, including Phillips 66’s plant in Ponca City, Oklahoma, and Total SA’s Port Arthur, Texas, facility will start seasonal maintenance this month. Other plants that were knocked offline by Hurricane Harvey, including the nation’s largest, are still working to reach normal operating levels.

“We’re going to see some recovery in Texas but we’re also going to see some reductions in refining activity in the rest of the country,” Bill O’Grady, chief market strategist at Confluence Investment Management in St. Louis, said by telephone. “Demand for crude will probably stay pretty weak.”

Hurricane Maria

Hurricane Maria intensified into a major hurricane on Monday and is expected to continue strengthening as it closes in on the Leeward Islands, the National Hurricane Center said in an advisory. Maximum sustained winds approached 125 miles (201 kilometers) an hour, and Maria is not forecast to weaken as she rakes islands already devastated by Irma.

Puma Energy plans to shut its petroleum terminal in St. Thomas, U.S. Virgin Islands ahead of Hurricane Maria, according to the company. Ports in Puerto Rico and the U.S. Virgin Islands are scheduled to shut Tuesday in preparation for the hurricane, according to the U.S. Coast Guard.
Oil-market news:
  • Cushing, Oklahoma crude stockpiles increased by 900,000 barrels in the week ended Sept. 15, according to a forecast compiled by Bloomberg.
  • Permian shale basin drillers, once the darlings of the U.S. oil industry, now look like fat targets for acquisitions and activist investors, analysts at Stifel Nicolaus & Co. said.
  • Saudi Arabian crude shipments dropped in July to their lowest level in almost three years as the world’s biggest oil exporter intensified efforts to curb supply to counter a global glut.
— With assistance by Ben Sharples, and Grant Smith

Exclusive Interview with Founder of Ethereum Vitalik Buterin

Venezuela Meets with Algeria
President Nicolas Maduro (R) meets Algerian Senate speaker Abdelkader

Venezuelan President Nicolas Maduro paid a visit to Algeria this week and met with Algerian Senate speaker Abdelkader Bensalah to discuss oil policies. The Algerian presidency said Maduro and his hosts were to review the situation on world oil markets.

APS, Algeria’s official news agency, reported that the Algerian Prime Minister Ahmed Ouyahia and Energy Minister Mustapha Guitouni were also at the meeting.

The Venezuelan presidency said the talks covered a 2016 OPEC deal to cut oil production in a bid to boost low crude prices. Following the meeting, Maduro said there was “a climate favorable to the policy of a fair price for black gold”.

It said oil sector cooperation between Algiers and Caracas was also on the agenda.

Last week Maduro revealed that Venezuela planned to “start selling oil, gas and all other products that Venezuela sells with new currencies, including the Chinese yuan, the Japanese yen, the Russian ruble, the Indian rupee among others.

“An economy free from the US imperialist system is possible,” he said during a television

Nigeria Requires $16.5bn To Achieve 40bn Barrels Oil Reserves Target

To achieve the set target of 40 billion barrels crude oil reserves by 2020, the hydrocarbon industry will require between $13 and $16.5billion over the next five years, the Chief Operating Officer, Gas and Power, Nigerian National Petroleum Corporation (NNPC), Saidu Mohammed, has said.

According to Mohammed in the current edition of NNPC Newsletter, under the infrastructure and power plants, there are investment opportunities of over $11billion in the country.

He added that the country also require about $6 billion to revamp the country's refineries. He disclosed: "In the upstream segment, NNPC plans to increase its oil reserves base to 40 billion by 2020. Based on its upstream growth plan, the corporation would raise $13 to $16billion over the next five years.

"For the refineries, our plan is to rehabilitate, and revamp existing four refineries. On successful rehabilitation and revamp, our plans is to upgrade their combined nameplate capacity from 445,000 barrels per day to 700,000 barrels per day within the next few years. We would require investments of between $6million," he added.

Mohammed unveiled opportunities in the construction of new crude and product pipelines, pumping station upgrades, revamp of Liquefied Petroleum Gas (LPG) plants, construction of new LPG storage tanks, filling stations, and equipment supply.

He noted that the provision of coastal vessels and tugboats and other ancillary support services are equally areas that would yield high return on investments of about $3billion.

He added that opportunities exist for the establishment of pipe mills, equipment leasing and operations. "Others in this aspect are construction of gas storage/compressed natural gas and LPG fillings as well as development of multi-specialist hospitals," he said.

The Minister of State for Petroleum Resources, Ibe Kachikwu, said the Federal Government has resorted to the use of local security contractors, who have lot of synergies with the communities, to achieve effective protection and monitory of the facilities.

He added that the refineries were producing almost on continuous basis to support the fuel imports. "Essentially, we are producing on the average of about 60 per cent throughout of the units that are running. We don't have all the units running at the same time for obvious reasons; otherwise, we may have to shut-down or run out of crude oil.

Friday, September 15, 2017

‘Harvey’ and ‘Irma’ impacts remain

The US Department of Energy (DoE) released a summary on the impacts of Hurricanes ‘Harvey’ and ‘Irma’ in the middle of this week.
Widespread electrical outages continued, but more refineries are in operation, although at reduced capacity and more ports are opening.

As of 12th September, four refineries in the Gulf Coast region were closed, according to public reports. These refineries have a combined refining capacity of 734,300 barrels per day, equal to 7.6% of total Gulf Coast (PADD 3) refining capacity and 4% of total US refining capacity.

Six refineries were in the process of restarting after being shut down. This process may take several days or weeks to start producing product, depending whether any damage is found during restart. Production should be assumed to be minimal until restart is completed.

These refineries have a combined capacity 1,919,399 barrels per day, equal to 19.8% of total Gulf Coast (PADD 3) refining capacity and 10.4% of total US refining capacity

At least five refineries in the Gulf Coast region were operating at reduced rates, according to public reports. These refineries have a combined total capacity of 1,724,500 barrels per day, equal to 17.8% of total Gulf Coast (PADD 3) refining capacity and 9.3% of total US refining capacity. However, actual crude throughput (production) reductions are lower than the total combined capacity.

In the US Gulf Coast region, 11 ports are closed or open with restrictions. In the US Southeast and Caribbean, ports in eight sectors are either closed or open with restrictions.

For example, the Ports of Tampa Bay and Port Canaveral reported that product tankers were being discharged and more were expected.

McQuilling Services said in a note on 8th September that as a result of ‘Harvey’, the impact on tanker markets was felt in both the clean and dirty segments. There was a complete closure of 15 refineries, ranging from Corpus Christi to Port Arthur, representing 25% of total US capacity.

In addition, both land-based and offshore crude oil production was disrupted, limiting the level of available supply for domestic consumption and exports. Refined products pricing structure turned bullish, due to declining supply amid heightened demand, while crude pricing felt downward pressure, as a result of collapsing refinery runs.

Tankers loading clean product cargoes in the US Gulf were put on hold, necessitating the need for US Gulf export markets, including Mexico, to source barrels from alternative regions, such as Europe, but also East Coast Canada and surprisingly New York.

The Mexican market doubled its demand for European refined products, namely gasoline in the week of 28th August - 1st September; however, the most significant increase in European exports was for the US Atlantic Coast, which according to McQuillings fixture database recorded 909,000 tonnes of clean product imports booked during the days of ‘Harvey’. As a result of the increasing volumes out of Europe, the position list in the region tightened, supporting a week-on-week increase in TC2 rates.
For the trading week of 28th August, TC2 averaged WS 199, with spot cargoes trading up to as high as WS 245, before retreating back down to WS 150 during the current week.

The impacts from ‘Harvey’ were also felt on the crude trade, both into and out of the US Gulf. For example, Aframaxes carrying Caribbean loaded crude faced delays discharging at Texas ports, while the short term closure of LOOP and suspended lightering operations, delayed a couple of VLCCs from discharging.

McQuilling counted about 20 Aframaxes waiting to discharge into ports impacted by ‘Harvey’ between 25th August and 5th September, reducing vessel supply to load new Caribbean cargoes. The consultancy identified five Suezmax fixtures from the Caribbean for US Gulf discharge, compared to just three Aframaxes during the first week of September.

TD9 rates remained reasonably firm, due to vessel delays in the US Gulf, at around WS 160, more than 50 points higher than reported during the week of 21st August.

VLCCs were largely unaffected, as the US Gulf is importing less MEG crude die to the OPEC cuts and increased US production. However, some disruption was noted in crude exports.

McQuilling also said that with no US ports able to load directly onto VLCCs, reverse lightering using Aframaxes requires the smaller tankers to load crude in Texas ports for ship-to-ship transfers in offshore lightering areas.

It was also noted that around 10-12 VLCCs were ballasting into the Atlantic following an East discharge with an estimated arrival window of the end of September/first week of October. It was likely that the spot price for WTI widening to a $5 per barrel or more discount to Brent had led to Asian consumers purchasing crude for subsequent exports in the coming month.   

As a result, McQuilling said that it expected VLCC rates to firm slightly, mitigated by the shear number of vessels bypassing the beleaguered MEG market in search of higher freights.

To discuss the weather phenomena, experts will gather at the Royal Institution in London on 7th November, 2017 to discuss how ocean observations can improve weather and climate predictions and enable better decisions to be made at sea, on land and in the air.

Oceans of Knowledge 2017’ is being organised by IMarEST, together with the Partnership for Observation of the Global Oceans (POGO), which serves as a forum to promote global oceanography and implement international global ocean observing systems.

The conference is sponsored by the Met Office, Stormgeo, Planet Ocean and BMT Group and supported by the Society for Underwater Technology and the National Oceanic and Atmospheric Administration (NOAA).

It will look at the impact of improved ocean observations on ocean and weather services, including medium range forecasting.

Thursday, September 14, 2017

US crude rallies to hit $50 for first time in 5 weeks as demand outlook improves

Brad Quick | CNBC
An oil worker stands by a rig near Williston, North Dakota.

U.S. crude topped $50 a barrel for the first time in five weeks on Thursday, building on recent gains after forecasts for stronger oil demand by the International Energy Agency. 

Benchmark Brent crude was up 56 cents, or 1 percent, at $55.72 a barrel by 9:24 a.m. ET (1324 GMT). The contract was trading at its highest levels since April, after rising 89 cents or 1.6 percent on Wednesday.

U.S. West Texas Intermdediate crude rose 75 cents, or 1.5 percent, to $50.05, after gaining 2.2 percent in the previous session. WTI popped above its 200-day moving average level of $49.55 earlier in the session. It has not breached that level on an intraday basis since Aug. 10.

Brent has now climbed by more than $10 a barrel over the past three months and is close to where it was at the beginning of the year, trading between about $55 and $57.

"By breaking $55 a barrel, Brent is moving back to the price range of January/February," said Olivier Jakob, analyst at energy markets consultancy Petromatrix in Zug, Switzerland.

Oil demand growth is strengthening: IEA 
Wednesday's gains followed an IEA report which raised its estimate of 2017 world oil demand growth to 1.6 million barrels per day (bpd) from 1.5 million bpd.

The IEA said a global oil surplus was beginning to shrink due to stronger-than-expected European and U.S. demand growth, as well as production declines in OPEC and non-OPEC countries.

"Stronger demand and supply restrictions from OPEC and Russia are the main reasons for the oil price upsurge," said analyst Fawad Razaqzada.

The supply side of the equation also looks promising, Barclays Research said.

"Unrest in Iraq and Venezuela should keep output there in check, regional crude oil contangos have dissipated, and stocks are gradually declining," it said.

That said, "a softer market balance is in store for next year, which should ensure an OPEC/non-OPEC deal remains in place beyond March 2018", Barclays added.

The Organization of the Petroleum Exporting Countries and other producers, including Russia, have agreed to reduce crude output by about 1.8 million bpd until next March in an attempt to support prices.

This week's gains came despite U.S. data showing another big build in U.S. crude inventories due to Hurricane Harvey. 

Data from the Energy Information Administration shows a build in U.S. crude inventories last week of 5.9 million barrels, exceeding expectations.

U.S. gasoline stocks slumped by 8.4 million barrels, the largest weekly decline since the data was first recorded in 1990. U.S. gasoline futures extended declines on Thursday, with demand expected to slip because of the impact of Hurricane Irma on Florida and Georgia.

U.S. distillate stocks fell by 3.2 million barrels.

ExxonMobil Corp said it was restarting its 362,300-barrels-per-day Beaumont, Texas, refinery for the first time since it was shut by Harvey. 

— CNBC's Tom DiChristopher and Gina Francolla contributed to this report.

Wednesday, September 13, 2017

Higher gasoline prices boost U.S. producer inflation

U.S. producer prices rebounded in August, driven by a surge in the cost of gasoline, and there were also signs of a pickup in underlying producer inflation. 

The Labor Department said on Wednesday its producer price index for final demand increased 0.2 percent last month after slipping 0.1 percent in July. In the 12 months through August, the PPI rose 2.4 percent after advancing 1.9 percent in July. 

Economists said the uptick in producer prices was unlikely to assuage Federal Reserve policymakers’ concerns about low inflation as the increase was largely due to a 9.5 percent increase in the cost of gas. That was the largest rise since January and followed a 1.4 percent decline in July. 

Though gas prices could rise further in September in the wake of Hurricane Harvey, which disrupted oil refinery production in Texas, a reversal was expected because of ample crude supplies. 

“Energy price gains, which will likely dominate the September inflation reports in the aftermath of Hurricanes Harvey and Irma, will likely be viewed as having a temporary impact on inflation by the Fed,” said John Ryding, chief economist at RDQ Economics in New York.  

Economists had forecast the PPI gaining 0.3 percent last month and accelerating 2.5 percent from a year ago. 

A key gauge of underlying producer price pressures that excludes food, energy and trade services rose 0.2 percent last month after being unchanged in July. The so-called core PPI increased 1.9 percent in the 12 months through August after a similar gain in July. 

Prices of U.S. Treasuries were trading lower, while the dollar rose against a basket of currencies. U.S. stock indexes were little changed after hitting record highs on Tuesday.


Inflation is being closely watched for clues on the timing of the next Fed interest rate increase. Economists expect the U.S. central bank will announce a plan to start reducing its $4.2 trillion portfolio of Treasury bonds and mortgage-backed securities at its Sept. 19-20 policy meeting. 

The Fed is expected to delay raising rates until December. 

August’s consumer inflation report scheduled for release on Thursday is expected to show gasoline prices helped push up the Consumer Price Index by 0.3 percent after a 0.1 percent rise in July, according to a Reuters survey of economists. 

Last month’s increase in the PPI is unlikely to translate into a similar gain in the Fed’s preferred inflation measure, the personal consumption expenditures (PCE) price index excluding food and energy. 

The annual increase in the core PCE has consistently undershot the central bank’s 2 percent inflation target since mid-2012. The core PCE rose 1.4 percent in July, the smallest year-on-year increase since December 2015. 

The cost of food fell 1.3 percent as wheat prices recorded their biggest drop since April 2008. The decrease in food prices last month was the largest since February 2015 and followed an unchanged reading in July. There were also declines in the prices of fresh vegetables, fruits and meat. 

Core goods prices rose 0.2 percent last month after slipping 0.1 percent in July. The cost of services edged up 0.1 percent after falling 0.2 percent in July. A 1.7 percent surge in the cost of consumer loans accounted for more than half of the increase in the price of services last month. 

The cost of healthcare services increased 0.3 percent after a similar gain in July. 

“This morning’s producer price gains for August are a step in the right direction,” said Scott Anderson, chief economist at the Bank of the West in San Francisco. “However, they are not yet quite as strong or as broad-based as the Federal Reserve would like to see to help push core consumer price inflation back up to the Fed’s 2 percent target.”

OPEC ups 2017 call on its crude oil to 32.7 mil b/d, 2018 to 32.8 mil
OPEC Countries

OPEC's analysis arm on Tuesday issued a bullish outlook in its closely watched monthly oil report, raising its forecasts of 2017 and 2018 demand for the producer group's crude on expectations of a more robust global economy.

The report comes as oil ministers are mulling an extension of output cuts to maintain their handle on the market. Demand for OPEC crude this year will average 32.67 million b/d, OPEC said, a rise of 200,000 b/d from August's estimate, while 2018 demand will grow to 32.83 million b/d, a 400,000 b/d increase from August's forecast.

That compares with OPEC's August output of 32.76 million b/d, as estimated by OPEC's secondary sources, the report showed.

OECD commercial stocks fell 18.7 million barrels in July and stand 195 million barrels above the five-year average, according to the report, down from close to 340 million barrels at the beginning of the year.

"It is clear that the rebalancing process is underway," OPEC Secretary General Mohammed Barkindo said in a speech at Oxford University on Monday, before the report was released. "Destocking, both onshore and offshore, is clearly evident."

OPEC ministers have held a flurry of bilateral meetings in recent days, discussing, among other things, potentially extending the OPEC/non-OPEC production cut agreement past its March expiry, as backed by Saudi Arabia and Russia.

A monitoring committee, composed of ministers from Algeria, Kuwait, Oman, Russia and Venezuela, was scheduled to meet September 22 in Vienna to discuss the agreement. Saudi energy minister Khalid al-Falih, who holds the rotating OPEC presidency, may also attend.

Falih and UAE counterpart Suhail al-Mazrouei "agreed that an extension of the declaration beyond March 31, 2018, may be considered in due course as fundamentals unfold," the Saudi energy ministry said in a statement after their meeting Monday.


The deal, which went into force in January, calls on OPEC and 10 non-OPEC producers, led by Russia, to cut a combined 1.8 million b/d from the market, to hasten the drawdown of oil stocks to their five-year average.

For OPEC, that includes a notional ceiling of 31.9 million b/d, when Indonesia, which suspended its membership in November, is taken out, and Equatorial Guinea, which joined in May, is added in.

OPEC's August output, as estimated by secondary sources in the report, was far above that, reflecting growth from Libya and Nigeria, which were exempted from the cuts as they recovered from civil unrest.

Libya produced 890,000 b/d in August, according to the report, a 112,000 b/d fall from July as some fields were shut in by militants, but a 360,000 b/d rise from October, the benchmark month from which OPEC determined its cuts.

Nigeria produced 1.86 million b/d in August, the report said, a 140,000 b/d rise from July and a 230,000 b/d increase from October.

Representatives from Libya and Nigeria have been invited to the monitoring committee meeting to provide production outlooks, as some OPEC members have begun to urge their inclusion in output cuts.

Saudi Arabia, which continues to lead the producer group in compliance with its quota under the deal, produced 10.02 million b/d in August, according to secondary sources, while the kingdom self-reported August output of 9.95 million b/d. Both figures are below its quota of 10.058 million b/d.

Iraq, among the least compliant of the participants, produced 4.45 million b/d in August, according to secondary sources, though it self-reported a figure of 4.38 million b/d. It has a quota of 4.351 million b/d.

Third-largest producer Iran, which has a quota of 3.80 million b/d, produced 3.83 million b/d in August, according to secondary sources, while self-reporting a figure of 3.85 million b/d.


OPEC's analysts kept their forecast for 2017 non-OPEC oil supply unchanged from last month at 57.80 million b/d, growth of 780,000 b/d from 2016.

For 2018, non-OPEC oil supply was revised down 100,000 b/d from July's estimate to 58.80 million b/d, up 1 million b/d from 2017.

The report cited "the currently improving price environment, which is more suitable for the shale producers, the start-up of giant projects such as Kashagan, the increasing number of active rigs in North America and the proportionally remarkable investment in upstream projects," as reasons for its projected growth in non-OPEC supply for 2017.

However, it noted that non-OPEC supply growth will taper in the second half of 2017, which "suggests the possibility of more market rebalancing in 1H18."

On the demand side, OPEC revised upward its forecasts of total world oil demand for 2017 by 50,000 b/d from last month to 96.77 million b/d, a rise of 1.42 million b/d from 2016.

For 2018, OPEC also revised up its estimate from last month, by 70,000 b/d to average 98.12 million b/d, an increase of 1.35 million b/d from 2017.

The increased demand forecasts come despite Hurricane Harvey, which OPEC's analysts said would have a "relatively minor" impact on US economic growth and oil demand.

But the report also noted that Hurricane Irma and other storms that could follow may have knock-on effects for the oil market.

"In response, OPEC reiterates its commitment to working together with other stakeholders for the stability and security of the oil market," it said.

--Herman Wang,

--Edited by Jonathan Dart,