Crude running low at Libya’s Zueitina, production yet to restart
Crude is running low at Libya’s recently re-opened 70,000 b/d Zueitina export terminal on the Gulf of Sidra and production at the fields that feed it has yet to resume, traders and shipping sources said Wednesday.
“Only barrels from tank have been lifted,” a crude trader said. The Aframax tanker Valfolglia
is set to load an 80,000-mt crude cargo, reportedly for Saras, from the eastern Libyan port of Zueitina on Thursday, according to a Libyan port agent and a source at the shipowner Navigazione Montanari.
The agent said production issues at the port could mean this is the last cargo to load from Zueitina in the short term. The agent added that the tanker would load from crude that was in storage rather than from production. “This could be the last cargo to load until production restarts; there may be problems at the terminal,” the agent said. “This cargo is from storage, not production.”
Platts cFlow ship-tracking software showed that the ship was off the coast of Libya, bound for Zueitina, and the shipowner said the vessel would berth at the port Wednesday. Libya’s state-owned National Oil Corp. lifted force majeure on loadings out of Zueitina late in April after reaching an agreement with the protesters holding the terminal.
Trading sources said approximately 3 million barrels of crude -- a mix of Zueitina and Abu Attifel -- was available at the terminal in storage, but that production had not resumed at either of the two fields that feed the terminal.
According to the agent, this latest cargo will mark the fifth to load from Zueitina since the force majeure on the port was lifted April 28. Information from Platts cFlow indicates that the Seafalcon, the Zuma, the Keros Warrior and the Ottoman Tenacity have also loaded from the port in May.
By contrast, traders said loadings from the 110,000 b/d Marsa al-Hariga terminal in the northeastern corner of the country were ongoing, fed by crude supply from the Sarir field in the east.
Shipping sources said the Aframax Alexia is scheduled to load a 90,000-mt cargo from the Hariga terminal on May 21. Recent estimates have put Libyan production at close to 250,000 b/d.
Buzzard May 5-11 share of Forties crude output rises to 50%
The UK’s Buzzard oil field contributed 50% to Forties crude blend output in the week to May 11, Forties pipeline operator BP said on its website Wednesday, up 6 percentage points from the previous week.
This proportion of sour Buzzard crude increases the sulfur content of Forties blend to 0.90% and lowers its API to 37.6, according to a BP conversion table.
For May as a whole, BP estimates Buzzard content within Forties Blend slightly lower at 48.2%, and for June at 40.7%.
The Buzzard field has a nameplate capacity of 220,000 b/d, but production averaged 156,591 b/d in 2012, according to Department of Energy and Climate Change data.
It is the UK’s single-largest oil field, and the largest feeding into the Forties blend, one of four grades forming the basis of the Dated Brent crude oil benchmark.
NYMEX crude settles 67 cents higher; RBOB boosted by stock draw, demand pop
NYMEX June crude settled 67 cents higher at $102.37/barrel, while RBOB futures rallied on a decline in domestic gasoline inventories and a jump in demand ahead of the summer driving season.
June RBOB settled 3.91 cents higher at $2.9693/gal. The front-month contract reached a two-week high of $2.9752/gal during the session. ICE June Brent settled 95 cents higher at $110.19/b; NYMEX June ULSD settled 1.86 cents higher at $2.9626/gal.
The rally in RBOB was sparked by weekly US Energy Information Administration data that showed US gasoline stocks fell 800,000 barrels to 212.4 million barrels last week, as implied demand for the fuel rose 471,000 b/d to 9.19 million b/d.
The draw was near analyst expectations of a 1 million-barrel decline. But analysts at BNP Paribas contend the demand reading was too high, too soon. “While unemployment in the US has dropped a notch and retail prices remain contained relative to a year-ago, this week’s reading of demand seems prematurely high, and more commensurate with the peaks reached at the height of the driving season. We expect a correction in the data next week,” the analysts said in a note.
On the US Atlantic Coast, an influx of gasoline imports, which rose 325,000 b/d to 861,000 b/d, sent stocks in that region to 55.5 million barrels, up 1 million barrels from the week prior.
Still, the market found other upside support from news that Phillips 66 will shut its No. 29 fluid catalytic cracker at the joint venture Borger, Texas, refinery for maintenance May 14-21 (See story, 0537 GMT).
Gene McGillian, analyst at Tradition Energy, said traders were looking ahead
to an expected increase in gasoline demand with the US Memorial Day holiday in the coming weeks. NYMEX crude was supported by another decline in crude stocks at Cushing, Oklahoma -- the deliver point for the NYMEX crude futures contract.
Stocks there dropped 600,000 barrels last week to 23.4 million barrels, putting inventories at the hub at a 41.6% deficit to the five-year average.
Pemex boosts June European Maya crude differential, cuts Asian K factor
Mexico’s Pemex will increase the constant term -- or “K factor” -- for its price formula for June deliveries of Maya crude to Europe, decrease the K factor for deliveries to Asia and leave factor for deliveries in the Americas unchanged, the state-owned firm’s trading arm, PMI, said Wednesday.
The differential for Maya deliveries in the Americas in June was left unchanged at minus 45 cents/barrel, PMI said. Pemex’s exports of Maya crude to the Americas, apart from the US West Coast, are usually priced at a premium or discount to a formula based on the values of similar regional crudes.
The US Gulf Coast and European formulas for Maya also reflect fuel oil values, due to Maya’s sizable fuel oil yield. Maya has a 22 API gravity and 3.3% sulfur content. The Maya differential for June-loading cargoes to Europe was increased by 65 cents to a discount of 85 cents/b to PMI’s European regional formula.
For Asian deliveries, the Maya differential was decreased 30 cents to a discount of $9.65/b to the PMI formula for the region. Meanwhile, the Isthmus crude differential for deliveries to the Americas rose 5 cents to a premium of $1.10/b.
For deliveries to the US West Coast, the Isthmus K factor rose 25 cents to a premium of $2.40/b to the Pemex price formula.
For European deliveries, the differential for Isthmus fell 10 cents for a discount of 5 cents/b to the Pemex price formula for Europe. The Isthmus differential for Asian deliveries fell 30 cents to a discount of 30 cents/b to the formula.
Pemex also decreased the differential for Olmeca crude deliveries to the Americas by 10 cents to a premium of $2.25/b to the applicable formula in the region. For European deliveries, the differential for Olmeca decreased by 20 cents to a discount of $2.20/b to the Pemex price formula.
Changing West Coast crude slate leads to higher fuel oil production
The changing crude slate of refiners on the US West Coast is boosting refining margins, but also producing more fuel oil, a negative-margin product that is increasingly being exported.
West Coast fuel oil production has been steadily rising of late and reached a more than two-year high of 156,000 b/d during the week ended May 9, data from the US Energy Information Administration showed Wednesday.
Furthermore, West Coast fuel oil production as a percentage of total US production is at its highest level since August 2010. This comes as West Coast refiners increasingly switch to Canadian and Iraqi crudes, which are available in greater quantities and at lower cost than South American crudes, but whose higher sulfur content tends to produce more high sulfur products such as residual fuel oil.
The weighted average sulfur content of crude oil input to West Coast refiners was a record-high 1.39% last year, EIA data shows. “Rail deliveries of light Bakken and heavy, sour Canadian crudes are finding eager producers in the area, and there is still a market globally for heavy fuel oil,” said Richard Hastings of Global Hunter Securities.
NEW CRUDE SLATE HIGHER IN SULFUR
California refiners have typically been buyers of Ecuadorean grades of crude Oriente, with a 24 API and 1.4% sulfur, and Napo, (19 API and 2% sulfur). Those heavy sour grades are transported to California refiners in 360,000-barrel capacity Panamax-sized vessels.
However, cheaper and higher sulfur crudes in larger volumes from Canada and Iraq have pushed the South American barrels out of the region this year. “Iraqi production is increasing and they need to find a market,” an international crude supplier said. Iraqi Basrah, which has a gravity
of 30.5 API and 2% sulfur, was assessed Tuesday at $102.99/barrel, $8.19/b higher than Oriente.
But Basrah cargoes load in much larger parcels, with Chevron and Valero both loading 2 million-barrel VLCCs to their California refineries this year. Additionally,
the coking netback margin for Oriente on the West Coast has fallen precipitously since April 25, dropping $12.30/b to 18.855/b. Platts’ margins reflect the difference between a crude’s netback and its spot price.
U.S. Crude Oil Supplies Up 0.2%
By Justin Loiseau | More Articles | Save For Later
May 14, 2014 | Comments (0)
U.S. crude oil supplies expanded 0.9 million barrels (0.2%) for the week ending May 9, according to an Energy Information Administration report (link opens a PDF) released today.
After falling 1.8 million barrels the previous week, this latest report puts oil back on the expansion streak it had been following since early April. This most recent increase comes from both a decrease in refinery inputs (down 237,000 barrels per day) and an increase in imports (up 242,000 barrels per day). Overall inventories have expanded 0.9% in the past 12 months.
Gasoline inventories declined 0.8 million barrels (0.4%) after expanding 1.6 million barrels the week before. Demand for motor gasoline over the last four-week period is up a seasonally adjusted 3.2%. In the last year, supplies have contracted 2.4%.
Over the past week, average retail gasoline pump prices fell $0.016 to $3.668 per gallon.
Distillates supplies, which include diesel and heating oil, fell 1.1 million barrels (1%) for the second week of declines. Distillates demand for the last four weeks is up a seasonally adjusted 12.7%. In the past year, distillates inventories have fallen 5.8%.
Moscow (Platts)--14May2014/242 pm EDT/1842 GMT
Russian natural gas flows to Europe cannot be replaced with supplies from elsewhere, including exports of shale gas-derived LNG from the United States, Mohammed Hossein Adeli, Secretary-General of the Doha-based Gas Exporting Countries Forum, said Wednesday.
Adeli, a former governor of Iran's Central Bank, did not rule out a few "symbolic" cargoes, but said volumes would not be enough to substitute the Russian supplies, not least because US exporters would likely prefer to sell into the higher-priced markets of Asia.
"Shale gas cannot replace [Russian gas]," Adeli said in a question-and-answer session, while speaking at the Moscow Foreign Relations Institute.
European Gas Daily is a flagship Platts publication that delivers crucial competitive intelligence across the entire European gas marketplace. It keeps you ahead of critical price changes and their effects on the industry -- to help you make informed market decisions.
"Europe has no shale gas, and you don't think that the US has that much gas to export, do you?" he said.
"First of all, it's not the government, it's companies who will export gas," Adeli said, adding that US companies would choose to send their gas to premium Asian markets where gas prices are higher than in Europe.
Europe "might have some symbolic exports of one or two tankers to one or two points" but the talk is about major supplies, he said.
"I think that economics would prevail," he said.
US Energy Secretary Ernest Moniz has made similar comments about the economics of exporting US LNG.
The US, which currently does not export LNG, has approved seven projects that would have the capacity to supply around 96 billion cubic meters/year, Moniz noted earlier this month on the sidelines of a G7 energy ministers' meeting in Rome, which was called to discuss the Ukraine crisis.
However, Moniz added, "the [authorization] process does not determine where cargoes go. What happens at the end of the decade depends on where the markets are."
The US and EU have stopped short of imposing direct energy sanctions on Russia because of its annexation of Ukraine's Crimean Peninsula but have highlighted the intention to reduce Europe's dependence on Russian gas. Russia supplied 163 billion cubic meters of gas to Europe in 2013, about one third of its needs.
--Nadia Rodova, nadia.rodova@platts.com
--Editing by Margaret McQuaile, margaret.mcquaile@platts.com and Keiron Greenhalgh, keiron.greenhalgh@platts.com
Associated Press Updated: May 14, 2014 at 3:32 pm • Published: May 14, 2014 • 0
SAN ANTONIO (AP) — Valero Energy Partners reported a 28 percent drop in first-quarter net income on Wednesday, as a rough winter curbed demand for the petroleum products that flow through its pipelines.
The San Antonio company, spun out of Valero Energy Corp. last year, reported net income of $10.5 million, or 18 cents per unit, in its first full quarter as a publicly traded company. That's a sharp fall from the $14.5 million in net income the company reported in the same period of last year.
Higher costs were partly to blame. Total expenses rose 29 percent over the prior year to $5.8 million. Operating revenue shrank to $21.5 in the first quarter from $23.5 million the previous year. The company said "harsh winter weather" weighed on demand for its refined petroleum products.
On average, analysts expected Valero Energy Partners LP to post earnings of 18 cents per unit and revenue of $22.5 million.
The San Antonio company was formed by the refinery operator Valero Energy Corp. to own and operate pipelines, terminals and other assets. It owns properties in the Gulf Coast and Midwest that support Valero's refineries in Texas and Tennessee. Valero Energy Partners makes money by charging for transporting crude oil and refined petroleum products.
Shares of the oil pipeline owner were up 14 cents to $43.70 in afternoon trading on Wednesday. The company went public in December at $23 a share.
By Mark Shenk May 15, 2014 1:58 AM GMT+0700 26 Comments Email Print
Photographer: Matthew Staver/Bloomberg
The combination of horizontal drilling and hydraulic fracturing, or fracking, has... Read More
U.S. crude production climbed to a 28-year high last week as the shale boom moved the world’s biggest oil-consuming country closer to energy independence.
Output rose 78,000 barrels a day to 8.428 million, the most since October 1986, according to Energy Information Administration data. The combination of horizontal drilling and hydraulic fracturing, or fracking, has unlocked supplies from shale formations in the central U.S., including the Bakken in North Dakota and the Eagle Ford in Texas.
“This is an incredible phenomena that looks set to continue,” John Kilduff, a partner at Again Capital LLC, a New York-based hedge fund that focuses on energy, said by phone. “There’s a long way to go before we explore and exploit all of the shale deposits out there.”
The U.S. met 87 percent of its energy needs in 2013, and 90 percent in December, the most since March 1985, according to the EIA, the statistical arm of the Energy Department.
Crude output will average 8.46 million barrels a day this year and 9.24 million in 2015, up from 7.45 million last year, the EIA said in its monthly Short-Term Energy Outlook on May 6. Next year’s projection would be the highest annual average since 1972.
The EIA forecasts that the gain in production at shale fields will be augmented by greater offshore output this year and next. Crude output in the waters of the Gulf of Mexico will climb by 150,000 barrels a day in 2014 and by an additional 240,000 barrels in 2015, following four consecutive years of declines, according to the May 6 report.
Export Ban
U.S. Energy Secretary Ernest Moniz said yesterday that the mismatch between rising production of light oil in the U.S. and the country’s refining ability is driving the debate over whether to lift a ban on crude exports. The crude unlocked from shale deposits is too low in density to be absorbed entirely by the U.S. refining system, Moniz told reporters in Seoul.
“The driver, or the consideration, is that the nature of oil we are producing may not be well matched to our current refinery capacity,” Moniz said.
The remarks highlighted pressure to overturn 1975 legislation that bars exports while U.S. production rises and inventories swell. Senator Lisa Murkowski of Alaska, the senior Republican on the Energy and Natural Resources Committee, said in a Jan. 7 speech that she supports changing the export rules.
“This increases the pressure on the U.S. to finally allow for the export of crude,” Kilduff said. “The U.S. could be a major player in global export market.”
Stockpile Gains
Production gains helped send U.S. inventories to 399.4 million barrels in the week ended April 25, the most since the EIA began reporting weekly data in 1982. Stockpiles increased 947,000 barrels to 398.5 million barrels in the week ended May 9, according to the agency.
Inventories along the Gulf Coast, known as PADD 3, grew 2.33 million barrels last week to 215.7 million, the most in EIA data going back to 1990. Supplies there have been growing since January as the southern leg of the Keystone XL pipeline began moving oil to Gulf Coast refineries from Cushing, Oklahoma, the largest U.S. storage hub.
Futures rose after today’s EIA report showed supplies at Cushing, the delivery point for WTI, dropped for the 14th time in 15 weeks. Inventories fell 592,000 barrels last week to 23.4 million, the lowest level since Dec. 5, 2008.
West Texas Intermediate crude for June delivery increased 67 cents, or 0.7 percent, to settle at $102.37 a barrel today on the New York Mercantile Exchange. It was the highest closing price since April 21.
To contact the reporter on this story: Mark Shenk in New York at mshenk1@bloomberg.net
To contact the editors responsible for this story: Dan Stets at dstets@bloomberg.net Margot Habiby, Bill Banker
Moscow (Platts)--14May2014/242 pm EDT/1842 GMT
Russian natural gas flows to Europe cannot be replaced with supplies from elsewhere, including exports of shale gas-derived LNG from the United States, Mohammed Hossein Adeli, Secretary-General of the Doha-based Gas Exporting Countries Forum, said Wednesday.
Adeli, a former governor of Iran's Central Bank, did not rule out a few "symbolic" cargoes, but said volumes would not be enough to substitute the Russian supplies, not least because US exporters would likely prefer to sell into the higher-priced markets of Asia.
"Shale gas cannot replace [Russian gas]," Adeli said in a question-and-answer session, while speaking at the Moscow Foreign Relations Institute.
"Europe has no shale gas, and you don't think that the US has that much gas to export, do you?" he said.
"First of all, it's not the government, it's companies who will export gas," Adeli said, adding that US companies would choose to send their gas to premium Asian markets where gas prices are higher than in Europe.
Europe "might have some symbolic exports of one or two tankers to one or two points" but the talk is about major supplies, he said.
"I think that economics would prevail," he said.
US Energy Secretary Ernest Moniz has made similar comments about the economics of exporting US LNG.
The US, which currently does not export LNG, has approved seven projects that would have the capacity to supply around 96 billion cubic meters/year, Moniz noted earlier this month on the sidelines of a G7 energy ministers' meeting in Rome, which was called to discuss the Ukraine crisis.
However, Moniz added, "the [authorization] process does not determine where cargoes go. What happens at the end of the decade depends on where the markets are."
The US and EU have stopped short of imposing direct energy sanctions on Russia because of its annexation of Ukraine's Crimean Peninsula but have highlighted the intention to reduce Europe's dependence on Russian gas. Russia supplied 163 billion cubic meters of gas to Europe in 2013, about one third of its needs.
--Nadia Rodova, nadia.rodova@platts.com
--Editing by Margaret McQuaile, margaret.mcquaile@platts.com and Keiron Greenhalgh, keiron.greenhalgh@platts.com
US crude oil imports are down by 23 percent since 2008. Industry officials and experts are considering lifting a decades-old ban on US oil exports.
By Daniel J. Graeber, Guest blogger / May 14, 2014
A Whiting Petroleum Co. pump jack pulls crude oil from the Bakken region of the Northern Plains near Bainville, Mont. in 2013. Domestic refiners have been influencing the debate on whether the US should position itself as an energy powerhouse.
US crude oil imports are down 23 percent since production from tight oil plays started to increase in 2008. While some industry officials and observers wonder if the U.S. should position itself as an energy superpower, the debate may be influenced in large part by domestic refiners.
"The issue of crude oil exports is under consideration," US Energy Secretary Ernest Moniz said from a two-day energy summit in South Korea.
US oil exports are restricted by legislation enacted in response to an oil embargo from Arab members of the Organization of Petroleum Exporting Countries (OPEC) in the 1970s.
OPEC, in its May market report, said total US crude oil imports dropped from an average 10.08 million barrels per day in January 2008 to 7.76 million bpd in December, 2013. That decline is in part a response to the increase in crude oil production from shale reserve areas in the United States. Of the six most prolific shale basins in the United States, only the Haynesville play is expected to hold its production level steady; the other five should see an increase.
The US Energy Information Administration (EIA) said the Eagle Ford basin in southern Texas and the Permian basin, which straddles the Texas border with New Mexico, should post a combined 48,000 bpd production increase in June. Next month, the Bakken play, which sits on the border between North Dakota and Montana, should see production increase by 22,000 bpd to reach 1.07 million bpd, EIA said.
Six shale basins -- Permian, Eagle Ford, Bakken, Niobrara, Haynesville and Marcellus -- accounted for almost 90 percent of oil production growth since 2011. OPEC, in its market report, said North American oil production has increased five years in a row and US oil production is now at its highest rate since 1972.
With oil output accelerating, strong cases have been made for and against reversing the ban.
In April, Erik Milito, director of upstream operations for the American Petroleum Institute, said oil exports would make the United States a "global energy superpower." But Leo Gerard, president of the United Steelworks lobby, said the previous month that lifting the ban would harm domestic refiners who may be forced to pay higher prices for domestic oil.
Right now, US refiners who utilize regional crude enjoy a lower price than for oil sourced from overseas markets. Since January, when TransCanada's Marketlink pipeline came online, the gap between the price for West Texas Intermediate, the US benchmark, and Brent, the overseas benchmark, has narrowed, however, and that discount in price is now lower.
US oil production is on pace to increase, though the forecast for WTI is uncertain. As of May 13, it was holding steady about $100 per barrel. Moniz, the US energy secretary, said several agencies are studying what role US oil should play on the international stage. For now, however, it may be more of a downstream concern.
"A driver for this consideration is that the nature of the oil we're producing may not be well matched to our current refinery capacity," he said.
So while global influence is always a concern for Washington, issues closer to home may be the deciding factor for policymaking in the shale era.
HOUSTON • Repsol will test the first batches of Canadian crude at its Spanish refineries later this month as the oil major takes advantage of a provision that allows Canadian crude to be re-exported through U.S. ports, said a source with knowledge of the deal.
Repsol has bought a cargo of Western Canada Select (WCS) heavy blend crude that will arrive in the European country at the end of May to be used as a test for several refineries, the source said.
“The 600,000 barrels of WCS were loaded at Freeport [Texas] after obtaining the licence to export them from the United States. Mexican Maya was also loaded to optimize the freight,” the source added.
To export Canadian crudes from the United States such as the WCS, a heavy sour blend with 20 API degrees made of more than a dozen Canadian crudes, the seller needs to ask to the U.S. Department of Commerce for a license for every cargo. The export of U.S. crudes, however, is banned in almost all cases.
Repsol was not available to comment.
Repsol writes down Canaport by $1.3B after failing to sell LNG terminal in blockbuster Shell deal
The company has been increasing purchases of heavy crudes, primarily Latin American grades, through supply contracts with Venezuela’s PDVSA for Morichal 16, Colombia’s Ecopetrol for Castilla and Mexico’s PEMEX for Maya crude.
After being chartered by Repsol, the Suezmax oil tanker Aleksey Kosygin was on Wednesday going out from the U.S. Gulf Coast and it is scheduled to arrive to Bilbao, Spain, on May 29, according to Reuters vessel tracking data.
The company plans to keep buying this crude type if the tests are successful, the source added.
Repsol owns five industrial and refining complexes in Spain with a joint capacity of 896,000 barrels per day. It also operates the 102,000-bpd La Pampilla refinery in Peru.
The agreed price and seller were not disclosed.
“The WCS is a good quality crude. It is at the same level than Colombian or Venezuela heavy grades,” the source said.
PDVSA has scheduled two 600,000-barrel deliveries of Morichal 16 crude for Repsol’s refineries La Coruna and Cartagena in Spain, according to the Venezuelan state-run company’s exports plan.
U.S. oil producers are not allowed to export domestic crude overseas, but refining firms are increasing sales of finished products and most exploration and production companies favor lifting the export ban that was introduced in 1973 in reaction to the Arab oil embargo.
© Thomson Reuters 2014
Alison Ciaccio, Platts Markets Editor
New York - May 14, 2014
U.S. refiners lowered utilization rates the week ended May 9, while imports of crude oil climbed, sending U.S. commercial crude oil stocks 900,000 barrels higher, U.S. Energy Information Administration (EIA) data showed Wednesday.
At 398.5 million barrels for the May 9 reporting week, U.S. crude oil stocks were at a 6% surplus to the EIA five-year average. Analysts polled by Platts were expecting a 1.5 million-barrel draw in crude oil inventories.
Domestic refinery run rates fell an unexpected 1.4 percentage points to 88.8% of capacity the week ended May 9. At the same time, U.S. crude oil production rose to 8.43 million barrels per day (b/d) from a previous 8.35 million b/d.
Analysts were anticipating a 0.5 percentage-point rise in rates to 90.7% of capacity as several refiners were said to be returning from maintenance, including Philadelphia Energy Solutions -- the largest refiner on the U.S. East Coast (USEC) -- which restarted three units in the Point Breeze section of its 330,000 b/d Philadelphia refining complex May 7.
USEC run rates did rise 0.8 percentage point the week ended May 9 to 86.7% of capacity, but that was offset by a large drop by U.S. Gulf Coast refiners. Runs on the USGC -- home to over half of U.S. operable capacity -- fell 2.3 percentage points the week ended May 9 to 90.6% of capacity.
Imports of crude oil rose 242,000 b/d to 7.13 million b/d, led by a 587,000 b/d increase in Saudi Arabian imports to 1.87 million b/d. Mexican imports rose 232,000 b/d to 876,000 b/d. The increases, however, were partially offset by a 234,000 b/d drop in Kuwaiti imports and a 111,000 b/d drop in Angolan imports to 113,000 b/d.
USGC STOCKS RISE, CUSHING DOWN AGAIN
USGC crude oil stocks rose 2.3 million barrels to 215.7 million barrels -- a record for the region. The builds have been the norm for the region as more oil flows from the U.S. Midcontinent to the USGC via pipelines.
The movement of crude oil has worked to narrow key spreads, including the Brent-WTI spread, which settled at $7.54 per barrel (/b) on Tuesday -- down from $12.38/b at the start of 2014. The Light Louisiana Sweet-WTI spread was assessed by Platts at $1.85/b on Tuesday, down from a year ago when the spread was $8.80/b.
U.S. Midwest crude oil stocks fell 800,000 barrels to 92.1 million barrels the week ended May 9, including a draw in Cushing, Oklahoma, stocks.
Crude oil stocks at Cushing -- delivery point for the New York Mercantile Exchange (NYMEX) crude oil futures contract -- fell 600,000 barrels the week ended May 9 to 23.4 million barrels. The draw puts stocks at the hub at a 41.6% deficit to the five-year average.
GASOLINE STOCKS DIP; DEMAND POPS, OUTPUT JUMPS
U.S. gasoline stocks fell 800,000 barrels to 212.4 million barrels the week ended May 9, as implied demand* for the fuel rose 471,000 b/d to 9.19 million b/d.
Analysts had estimated a 1 million-barrel draw in stocks.
Production of the fuel pushed higher, rising 614,000 b/d to 9.61 million b/d. That put gasoline production more than 670,000 b/d higher than a year earlier.
Citgo restarted the No. 2 fluid catalytic cracker (FCC) in the east section of its 165,000 b/d Corpus Christi, Texas, refinery May 3, according to a Platts report. The unit was shut for repairs May 1 after a leak was found in a catalyst return line. Also, BP restarted a 150,000 b/d FCC at its 413,000 b/d refinery in Whiting, Indiana, the week ended May 9 after planned maintenance that began March 1.
In addition to higher production, imports of gasoline to the U.S. Atlantic Coast (USAC) surged, rising 325,000 b/d to 861,000 b/d.
Platts cFlow ship-tracking software had showed at least 12 clean cargoes from Northwest Europe refining centers bound for the main USAC gasoline input port at Bayonne, New Jersey, by May 18.
U.S. West Coast gasoline stocks fell 900,000 barrels the week ended May 9, while U.S. Midwest inventories declined 500,000 barrels, offsetting a 1 million-barrel rise in USAC gasoline stocks.
U.S. distillate stocks fell 1.1 million barrels the week ended May 9, counter to expectations of a 1 million-barrel build. Demand for the fuel fell 54,000 b/d to 4.27 million b/d.
USAC combined low- and ultra-low-sulfur diesel stocks stood at 24.02 million barrels for the week ended May 9, a 6.8% deficit to the EIA five-year average. That's narrowed from a deficit of more than 34% nine weeks earlier. Stocks fell 901,000 barrels from the previous week.
PUBLISHED ON MAY 14, 2014 11:52 PM 0 96 0 0
MOSCOW (REUTERS) - China and Russia's Gazprom are making a final push to clinch a long-delayed natural gas deal but have yet to iron out price differences, a Beijing official said on Wednesday, ahead of next week's state visit by Russian president Vladimir Putin.
Amid rising tensions with the West and a threat of deeper sanctions in protest at Moscow's annexation of Crimea, Putin could yet clinch the gas deal next week and reinforce his repeated assertions that Russia wants to divert some oil and gas flows from European markets towards growing Asian nations.
Gazprom generates about 80 per cent of its revenue from gas sales to Europe and has so far been only a marginal player in Asia because of a lack of eastbound pipelines and its relatively small liquefied natural gas (LNG) business.
Some analysts said they believe that a deal with China is imminent and that the two countries have probably agreed a price acceptable to both sides.
